capital; interest. Partner interest. interest. interest. until November 1, 2020. During the Partnership’s $500 million Senior Credit Facility. and TC Energy. Natural Gas Infrastructure Our pipeline systems include: its affiliates as disclosed under Note 17-Related party transactions within Part IV, Item 15. “Exhibits and Financial Statement Schedules,” which information is incorporated herein by reference. 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 See Part I, Item 1. “Business- Recent Business Developments-Other Business Developments” for more information. 2032. 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. area, and gas from the Rocky Mountains that is delivered into the Midwest must compete with gas sourced from the Bakken and Western Canada. available that meet our pipeline TC Energy. 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. 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). rates in effect by March 1, 2023. loss of North Baja’s tax allowance. Matters advocacy groups as well as state and local governments. For example, the EPA made the controversial decision in 2020 to retain, without revision the National Ambient Air Quality Standards (NAAQS) for ground level Ozone and Particulate Matter, that were established in 2015 by former President Obama's administration. The decision to not make these standards more stringent were highly criticized by environmental advocacy groups as well as state and local governments and are currently being challenged in federal court. President Biden's administration is likely to reconsider the rulemaking and could make the standards more stringent. There was similar opposition to EPA’s November 2020 withdrawal of the “Once in Always in” policy requiring sources of hazardous air pollutants (HAPs) that were once considered a “major source” of HAPs to be subject to the more stringent emissions standards even if the source reduces its emissions below the “major source” threshold later. These EPA actions are very beneficial to industry since they reduce our regulatory burdens and compliance-related costs, however the rules, in their current form, may not be permanent with the pending litigation challenging the rules and President Biden's aggressive climate protection agenda. These air regulations are subject to review under the January 20, 2021 EO. companies under President Biden, particularly on the basis of climate change, will likely materially increase compliance-related costs, costs to litigate regulatory actions, and more. Finally, Matters 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. Such developments could have an adverse effect on our assets, liabilities, business, financial condition, results of operations and cash flow. Even if we complete ” affirmative vote of a majority of the shipper contracting practices. $0.65 per common unit. environmental hazards, or injuries to persons and property. For further discussion on pipeline safety matters, see Part I, Item 1 “Government Regulation” – “Pipeline Safety Matters.” 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. directors and cannot remove our General Partner without its consent. 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 at the entity level. unitholders. 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. our unitholders. 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. 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. 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. “TCP.” ) 2019 periods. 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. higher net income before taxes. operational costs related to our pipeline systems' compliance programs; Facility at February 24, 2021 and (4) if needed, subject to customary lender approval upon request, an additional $500 million capacity that is available under the Senior Credit Facility's accordion feature, are sufficient to fund our short-term liquidity requirements, including distributions to our unitholders, ongoing capital expenditures, required debt repayments and other financing needs such as capital contribution requests from our equity investments without the need for additional common equity. 2019 Westbrook XPress expansion projects. 2018 2018. 2019 The commercial IT system purchase will reduce future operating costs and overall, these maintenance capital expenditures will increase our pipelines’ respective rate bases and we anticipate will generate a return on and of capital in future rates 2019 due to our continued spending on PXP and initial costs incurred on our GTN XPress, Iroquois’ ExC and Westbrook XPress projects. 2018 2019. 29, 2021. 26, 2021. January 29, 2021. March 24, 2021. The Partnership expects to make a $4 million contribution in 2021 to Iroquois to fund growth projects. the existing facility including the potential to increase the size of the facility to include the financing required for Tuscarora XPress. Schedules.” debt. Adjusted Earnings and Adjusted Earnings per Common Unit It measures our net income before deducting interest, depreciation and amortization and taxes. Partnership’s definitions of such measures. will apply to any calendar year during which distributions payable in respect of common units for such calendar year do not equal or exceed $3.94 per common unit. capacity. Please read the Capital spending section for more information regarding the the agreement were not met. Beginning in 2021, we expect the impact of Class B distribution on our distributable cashflow to be significantly lower compared to previous periods. 2019 generated by GTN. reference. Please read Part II Item 7A- "Quantitative and Qualitative Disclosures About Market Risk." for information about LIBOR phase-out. 2020. 2021. capital expenditures. Schedules.” 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. Schedules." 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. operating and maintenance costs, exceed the net cash inflows that management currently considers probable and estimable. reference. or cash flows. incorporated herein by reference. pipeline assets. reasonable assurance that the information required to be disclosed by the Partnership in the reports that it files or submits under the identified. TC 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 & Young. 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. July 14, 2020. 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. financially literate. TC Energy. us exceeded $100,000. committee member retainer. The amounts presented here represent Mr. Mirosh's prorated share in 2020. $80,000. ” 2020. for its operating needs. At December 31, Schedules,” which information is incorporated herein by reference. Schedules,” which information is incorporated herein by reference. 2019. Opinions (LOSS) CASH FLOWS 2018. The Partnership is considered to have a variable interest in Great Lakes, which is accounted as an equity investment since the Partnership is not the primary beneficiary (Refer to Note 5 for more details). Pipeline facilities and compression equipment have an estimated useful life of 20 to 68 years and metering and other equipment ranges from 5 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. Amounts included in construction work in progress are not depreciated until transferred into service. During the years ended December 31, 2020, 2019 and 2018, the Partnership incurred depreciation expenses of $88 million, $78 million and $97 million, respectively. Refer to Note 7 for further details regarding our Property, plant and equipment balance. impairment. 2019. 2020 method investments. 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. 2020 for Northern Border's 7.50% Senior Notes (December 31, 2019 - NaN), net of unamortized debt issuance costs and debt discounts. At December 31, 2020, Northern Border was in compliance with all of its financial covenants. a Lakes amounting to $10 million representing cash calls from Great Lakes to make scheduled debt payments (2019 - $10 million 2018 - $9 million) assets. TC Energy). 2020 (December 31, 2019 - no longer recoverable. The operations. March 15, 2021. 2020. 2020. 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, 2020 is 40.8 percent. For the year ended December 31, 2020, there was 0 Class B Distribution as the thresholds noted above were not exceeded. For the years ended December 31, costs amounting to approximately $2 million each year ended December 31, 2020, 2019 and 2018. trade accounts receivable. 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 TC Energy. 2018 and 2019. The building was sold to a third party in the third quarter of 2019. $75 million (2019 - $76 million; 2018 - $76 million). On November 20, 2020, this contract was revised. Effective November 1, 2021 the original contract rate will be reduced with no changes in the contracted volume. Additionally, after November 20, 2020, the Canadian Mainline shall have the right to reduce the contracted volume or terminate the full contract, effective November 1st of the applicable year, provided that 349 days’ prior written notice has been given to Great Lakes. As of February 24, 2021, no further changes to this contract have been made. The future revenue reduction on Great Lakes from the revised contract is not expected to have a material impact on the Partnership's expected distributions from Great Lakes. are included in the "Impact on Partnership's income" tabular summary above. Refer to Note 7 for additional information. 2019. 29, 2021. 26, 2021. January 29, 2021. its non-controlling interest owner on January 29, 2021. 19, 2021 COMPREHENSIVE INCOME CASH FLOWS 2020 and 2019 effective January 1, 2020 settlement. 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. 2024. valuation For the year ended December 31, 29, 2021. 26, 2021. LLC 22, 2021 2020 and 2019 Corporation. Certain prior year amounts have been reclassified to conform to the current year presentation. balance sheets as regulatory assets and regulatory liabilities. The following table presents the Partnership’s regulatory 2019. and net realizable value. 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 Capitalized AFUDC equity amounts are included as other income in the statements of income. Debt amounts capitalized during the years ended December 31, 2020, 2019 and 2018 were $0.2 million, $0.1 million and $0.2 million, respectively. Equity amounts capitalized during the years ended December 31, 2020, 2019 and 2018 were $0.8 million, $0.4 million and $0.3 million, respectively. Amounts included in construction work in progress are not amortized until transferred into service. these financial statements. Costs CHANGES 2020 31, 2020. dollars): RELATED PARTIES respectively, in which the net activity is treated as investing activity on the Cash Flow Statements in accordance with ASC 230 Statement of Cash Flows. services. three, was a direct benefit from TC Energy’s long-term fixed price service on its Canadian Mainline that was launched in 2017. On November 20, 2020, this contract was revised. Effective November 1, 2021 the original contract rate will be reduced with no changes in the contracted volume. Additionally, after November 20, 2020, the Canadian Mainline shall have the right to reduce the contracted volume or terminate the full contract, effective November 1st of the applicable year, provided that 349 days’ prior written notice has been given to the Partnership. As of February 22, 2021, no further revisions to this contract have been made. January 29, 2021.Page No.Page No. Business72542Properties424243PART II4445Management's467274747475PART III7580838488PART IV90Signatures952017 2020 32013 AcquisitionAcquisition of an additional 45 percent membership interest in each of GTN and Bison by the Partnership to increase ownership to 70 percent on July 1, 2013
2013 Term Loan Facility
TC PipeLines, LP'sLP’s $500 million term loan credit facility under a term loan agreement as amended on September 29, 20172015 GTN AcquisitionPartnership's acquisition of the remaining 30 percent interest in GTN on April 1, 2015
2015 Term Loan Facility
TC PipeLines, LP'sLP’s $170 million term loan credit facility under a term loan agreement as amended on September 29, 20172016 PNGTS AcquisitionPartnership's acquisition of a 49.9 percent interest in PNGTS, effective January 1, 2016
2017 AcquisitionPartnership'sPartnership’s acquisition of an additional 11.81 percent interest in PNGTS and 49.34 percent in Iroquois on June 1, 20172017 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, 20182017 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, 20182017 Tax Act H.R.1, originallyPublic Law No. 115-97, commonly known as the Tax Cuts and Jobs Act, enacted on December 22, 2017.2017AFUDC2018 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 Adjusted EBITDA EBITDA, less (1) earnings from our equity investments, plus (2) distributions from our equity investments, and plus or minus (3) certain non-recurring items (if any) that are significant but not reflective of our underlying operations AFUDC Allowance for funds used during construction ASCANR ANR Pipeline Company ASC Accounting Standards Codification ASUAccounting Standards Update
ATM program
At-the-market Equity Issuance ProgramBisonBIA Bureau of Indian Affairs Bison Bison Pipeline LLC C2C Contracts PNGTS'PNGTS’ Continent-to-Coast Contracts with several shippers for a term of 15 years for approximately 82,000 Dth/dayCanadian Mainline TransCanada'sTC Energy’s Mainline, a natural gas transmission system extending from the Alberta/Saskatchewan border east to QuebecCarty LateralGTN lateral pipeline in north-central Oregon that delivers natural gas to a power plant owned by Portland General Electric Company
Certificate Policy Statement NOIFERC Notice of Inquiry issued on April 19, 2018 Class B Distribution Annual distribution to TC Energy based on 30 percent of GTN’s annual distributions as follows: (i) 100 percent of distributions above $20 million through March 31, 2020; and (ii) 25 percent of distributions above $20 million thereafter 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 PNGTSCOVID-19 Coronavirus 2019 Delaware Act
Delaware Revised Uniform Limited Partnership ActDOTDOT U.S. Department of Transportation DSUs Deferred Share Units Dth/day
Dekatherms per dayDSUsDeferred Share Units
EBITDA
Earnings Before Interest, Tax, Depreciation and AmortizationEPAEPA U.S. Environmental Protection Agency FASBExC 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 FERCFERC Federal Energy Regulatory Commission GAAPGAAP U.S. generally accepted accounting principles General Partner
TC PipeLines GP, Inc.GHGGHG Greenhouse Gas 4 TC PipeLines, LPAnnual Report2017Great Lakes
Great Lakes Gas Transmission Limited PartnershipGTNGTN Gas Transmission Northwest LLC HCAsGTN XPress GTN's projects designed to both increase the reliability of existing transportation service including 100,000 Dth/day of existing transportation service on GTN and provide for a total of 150,000 Dth/day of incremental transportation capacity, primarily through facility replacements and additions of existing brownfield compression sites. HCAs High consequence areas IDRsIDRs Incentive Distribution Rights IRSIroquois Iroquois Gas Transmission System, L.P. IRS Internal Revenue Service Joint Facilities
Pipeline facilities jointly owned with MNE on PNGTSKPMGKPMG LLPLDCsKPMG
KPMG LLPLDCs Local Distribution Companies LIBORLIBOR London Interbank Offered Rate LNGLNG Liquefied Natural Gas MNEMLPs Master limited partnerships MNE Maritimes and Northeast Pipeline LLC, a subsidiary of Enbridge Inc. MNOCMNOC M&N Operating Company, LLC, a wholly owned subsidiary of MNE NGAMoody's Moody's Investors Service NGA Natural Gas Act of 1938 North Baja
North Baja Pipeline, LLCNorth Baja XPress North Baja 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 CompanyNYSENYSE New York Stock Exchange Our pipeline systems
Our ownership interests in GTN, Northern Border, Bison, Great Lakes, North Baja, Tuscarora, PNGTS and IroquoisPartnershipPartnership TC PipeLines, LP, including its subsidiaries, as applicable Partnership Agreement ThirdFourth Amended and Restated Agreement of Limited Partnership of the PartnershipPHMSAPHMSA U.S. Department of Transportation Pipeline and Hazardous Materials Safety Administration PNGTSPNGTS Portland Natural Gas Transmission System PXPPXP 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 SECRevised 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'sLP’s senior facility under revolving credit agreement as amended and restated, dated September 29, 2017TQMS&P Standard & Poor's TC Energy TC Energy Corporation, formerly known as TransCanada Corporation TC Energy Merger Agreement TC Energy's definitive agreement with the Partnership to acquire all outstanding common units of the Partnership not beneficially owned by TC Energy via stock exchange whereby the Partnership's common unitholders would receive 0.70 common shares of TC Energy for each issued and outstanding publicly-held Partnership common unit. TC Energy Merger The merger of TCP Merger Sub, LLC with and into the Partnership, with the Partnership continuing as the sole surviving entity and an indirect, wholly owned subsidiary of TC Energy. TQM TransQuebec and Maritimes Pipeline TransCanadaTransCanada Corporation and its subsidiariesTransCanada PXP ExpendituresTuscaroraTransCanada's latest estimate of $107 million of upstream capacity capital expenditures that PNGTS may be responsible for in the event the Portland Express Project does not proceed.Tuscarora
Tuscarora Gas Transmission CompanyTuscarora SettlementStipulation and Agreement of Settlement for Tuscarora regarding its rates and terms and conditions of service approved by FERC on September 22, 2016U.S.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 serviceUnaffiliated TCP Unitholders Holders of the outstanding Partnership common units, other than TC Energy and its affiliates U.S. United States of America WCSBWCSB Western CanadaCanadian Sedimentary BasinWholly-ownedWestbrook XPress Westbrook XPress Project of PNGTS that is part of a coordinated offering to transport incremental Western Canadian Sedimentary Basin natural gas supplies to the Northeast U.S. and Atlantic Canada markets through additional compression capability at an existing PNGTS facility Wholly owned subsidiaries
GTN, Bison, North Baja, and TuscaroraWHO World Health Organization "we," "us," "our"“we,” “us,” “our”, TC PipeLines and "the“the Partnership."” We use "our“our pipeline systems"systems” and "our pipelines"“our pipelines” when referring to the Partnership'sPartnership’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).2017 5 2020statements.statements, including statements regarding the potential TC Energy Merger and the Partnership, such as any statements regarding the expected timetable for completing the transaction. Forward-looking statements are identified by words and phrases such as: "anticipate," "estimate," "expect," "project," "intend," "plan," "believe," "forecast," "should," "predict," "could," "will," "may,"“anticipate,” “assume,“ “estimate,” “expect,” “project,” “intend,” “plan,” “believe,” “forecast,” “should,” “predict,” “could,” “will,” “may,” and other terms and expressions of similar meaning. The absence of these words, however, does not mean that the statements are not forward-looking. These statements are based on management'smanagement’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.performance by therefusal or inability of our customers, shippers ofor counterparties to perform their contractual obligations on our pipeline systems;the impact of the 2017 Tax Act enacted on December 22, 2017 on our future operating performance;•the elimination of pass-through taxation or tax deferred distributions;shippers;•our ongoing ability to grow distributions through acquisitions, accretive expansionsshippers or other growth opportunities, including the timing, structure and closureavailability of further potential acquisitions;TransCanadaTC Energy Corporation (TC Energy) and us;6 TC PipeLines, LPAnnual Report2017expected impactimplementation of future accounting changes and ultimate outcome of commitments and contingent liabilities (if any);TransCanada; andincluding(including the indebtedness of our pipeline systems, increasesystems), increases in interest rates, our level of interest rates,operating cash flows and the availability of capital."Risk“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.GeneralTCP."TCP". We were formed by TransCanada CorporationTC Energy and its subsidiaries (TransCanada) 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.wholly-ownedwholly owned subsidiary of TransCanada.TC Energy. At December 31, 2017,2020, subsidiaries of TransCanada ownTC Energy owned approximately 24.224 percent of our common units, 100 percent of our Class B units, 100 percent of our incentive distribution rights (IDRs) and an effectivehold a two percent general partner interest in us. See Part II, Item 5. "Market“Market for Registrant'sRegistrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities"Securities” for more information regarding TransCanada'sTC Energy's ownership in us.Recent Business DevelopmentsCash Distribution – Our annual cash distribution declared perunit increasedunits not beneficially owned by six percent from $3.71 perTC Energy, or its affiliates, in exchange for common unit in 2016shares of TC Energy. Under the initial proposal, holders of the outstanding TC PipeLines common units, other than TC Energy and its affiliates, (the Unaffiliated TCP Unitholders) would receive 0.65 common shares of TC Energy for each issued and outstanding publicly-held Partnership common unit. $3.94 per common unit in 2017.On April 25, 2017, the board of directors of the General Partner (TC PipeLines Board). As the general partner of the Partnership is an indirect wholly owned subsidiary of TC Energy, a conflicts committee composed of independent directors of the TC PipeLines Board (the Conflicts Committee) was formed to consider the offer pursuant to the Fourth Amended and Restated Agreement of Limited Partnership of the Partnership (Partnership Agreement).Partnership'sPartnership’s first quarter 20172020 cash distribution in the amount of $0.94$0.65 per common unit, payablewhich was paid on May 15, 201712, 2020 to unitholders of record as of May 5, 2017.1, 2020. The declared distribution totaled $68$47 million and was paid in the following manner: $65$46 million to common unitholders (including $5$4 million to the General Partner as a holder of 5,797,106 common units and $11$7 million to another subsidiary of TransCanadaTC Energy as holder of 11,287,725 common units) and $3$1 million to our General Partner which included $1 million for its effective two percent general partner interest and $2 million in respect of its IDRs.20, 2017,23, 2020, the board of directors of our General PartnerTC PipeLines Board declared the Partnership'sPartnership’s second quarter 20172020 cash distribution in the amount of $1.00$0.65 per common unit, payablewhich was paid on August 11, 201714, 2020 to unitholders of record as of August 1, 2017.3, 2020. The declared distribution totaled $74$47 million and was paid in the following manner: $69$46 million to common unitholders (including $6$4 million to the General Partner as a holder of 5,797,106 common units and $11$7 million to another subsidiary of TransCanadaTC Energy as holder of 11,287,725 common units) and $5$1 million to our GeneralTC PipeLines, LPAnnual Report2017 7 which included $2 million for its effective two percent general partner interest and $3 million in respect of its IDRs.24, 2017,21, 2020, the board of directors of our General PartnerTC PipeLines Board declared the Partnership'sPartnership’s third quarter 20172020 cash distribution in the amount of $1.00$0.65 per common unit, payablewhich was paid on November 14, 201713, 2020 to unitholders of record as of November 3, 2017.2, 2020. The declared distribution totaled $74$47 million and was paid in the following manner: $70$46 million to common unitholders (including $6$4 million to the General Partner as a holder of 5,797,106 common units and $11$7 million to another subsidiary of TransCanadaTC Energy as holder of 11,287,725 common units) and $4$1 million to our General Partner which included $1 million for its effective two percent general partner interest and $3 million in respect of its IDRs.23, 2018,19, 2021, the board of directors of our General PartnerTC PipeLines Board declared the Partnership'sPartnership’s fourth quarter 20172020 cash distribution in the amount of $1.00$0.65 per common unit, payablewhich was paid on February 13, 201812, 2020 to unitholders of record as of February 2, 2018. ThisJanuary 29, 2020. The declared distribution totaled $47 million and was paid in the following manner: $46 million to ourcommon unitholders (including $4 million to the General Partner includedas a $2holder of 5,797,106 common units and $7 million distributionto another subsidiary of TC Energy as a holder of 11,287,725 common units) and $1 million to the General Partner for its effective two percent general partner interest and an IDR payment of $3 million for a total distribution of $5 million.ThirdFourth Amended and Restated Agreement of Limited Partnership of the Partnership (as amended, the Partnership Agreement). The Partnership paid a total of $10 milliondistributions declared during 2020 did not reach the specified levels for any period and, therefore, the General Partner did not receive any distributions in respect of theits IDRs to our General Partner on the distributions declared from the first to the fourth quarter of 2017.in 2020. See Part II, Item 7 "Management's“Management’s Discussion and Analysis of Financial Condition and Results of Operations – Cash Distribution Policy of the Partnership"Partnership” for further information regarding the Partnership'sPartnership’s distributions.Pipeline updatesContracting501-G Proceeding - On May 11, 2020, FERC terminated Great Lakes’ 501-G proceeding and Settlement – On April 24, 2017,ruled that Great Lakes had complied with the one-time reporting requirement, designated as FERC Form No. 501-G related to the rate effect of the Tax Cuts and Jobs Act (2017 Tax Act). Additionally, FERC also stated that rate reductions provided for in Great Lakes' 2017 settlement and the 2.0% rate reduction from the Limited Section 4 Rate Reduction proceeding have provided substantial rate relief for Great Lakes’ shippers and as a result, FERC will not exercise its right to institute a NGA Section 5 investigation to determine if Great Lakes is over-recovering on its current tariff rates.termsproject. The proceeds received by Iroquois were distributed to its partners, of which the Partnership's proportionate share was approximately $24 million. The proceeds received by the Partnership were treated as a newreturn of capital and used for general partnership purposes.capacity contractagreement with its affiliate, TransCanada. The contract, which was subject to Canada's National Energy Board (NEB) approval, isTC Energy’s Canadian Mainline (Canadian Mainline) that commenced on November 1, 2017 for a term of 10 years andten-year period that allows TransCanada the abilityTC 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 from the Manitoba/U.S. border to the U.S. border near Dawn Ontario. On September 21, 2017, TransCanada received approval from the NEB and assystem. This contract contained a result, the contract commenced on November 1, 2017. The contract contains volume reduction optionsoption up to full contract quantity beginning in year three.latter half of 2017 andfourth quarter, the early part of 2018, Great Lakes sold all of its available 2017-2018 firm winter capacity. This level of contracting is significantly higher than that seen on this pipeline in recent years, and indicates a favorable shift in market dynamics for this asset.On October 30, 2017, Great Lakes filed a rate settlement with FERC to satisfy its obligations from its 2013 rate settlement for new rates to be in effect by January 1, 2018 (2017 Great Lakes Settlement). The 2017 Great Lakes Settlement, which was approved by FERC on February 22, 2018, decreased Great Lakes' maximum transportation rates by 27 percent effective October 1, 2017. Great Lakes expects that, notwithstanding the decrease in rates, the impact from other changes, including: the recent long-term transportation contract with TransCanada as described above, other revenue opportunitiesCanadian Mainline requested an extension on the system and the elimination of the revenue sharing mechanism with its customers, will more than offset the full year impact of thevolume reduction in Great Lakes' rates beginning in 2018. The 2017 Great Lakes Settlement does not contain a moratorium provisionoption deadline and Great Lakes extended the option expiry to November 16, 2020 and then again until November 20, 2020.requiredreduced with no changes in the contracted volume. Additionally, after November 20, 2020, the Canadian Mainline shall have the right to filereduce the contracted volume or terminate the full contract, effective November 1st of the applicable year, provided that 349 days’ prior written notice has been given to Great Lakes. As of February 24, 2021, no further changes to this contract have been made. The future revenue reduction on Great Lakes from the revised contract is not expected to have a material impact on the Partnership's expected distributions from Great Lakes.rates no later than March 31, 2022, with new ratesSeries A Senior Notes do not require any principal payments until maturity on June 1, 2030. Proceeds from the Series A Senior Note issuance were used to be effective October 1, 2022.Northern Border Contracting – Northern Border revenues are substantially supportedrepay the outstanding balance of the 5.29 percent Senior Notes and to fund the GTN XPress capital expenditures through the balance of 2020. GTN expects to draw the remaining $75 million available under the 3-year private shelf agreement for an additional $75 million of Senior Notes (GTN Private Shelf Facility) by firm transportation contracts through the end of 2020. The continued successful renewals of these contracts provide a strong indication of Northern Border's competitive position.GTN Incremental Contracting – GTN had successful open seasons during late 2017 and2023, the early part of 2018 generally in line with increasing available upstream capacity following the debottlenecking activities on TransCanada's pipelines. As a result, GTN has sold all its available firm capacity beginning mid-2020. GTN continues to provide a key8 TC PipeLines, LPAnnual Report2017transportation service delivering natural gas out of Western Canada to downstream markets in the Pacific Northwest and California.Continent to Coast (C2C) Project – In the fourth quarter of 2017, PNGTS filed to increase its FERC-certificated capacity to accommodate the period during which the approximately 82,000 Dth/day of long-term contracts (C2C contracts) overlap with certain of its original contracts which mature in 2019. On November 28, 2017, PNGTS received the approval from FERC to increase its capacity up to approximately 210,000 Dth/day effective December 1, 2017. The C2C contracts were effective December 1, 2017 and they mature in 2032.Portland XPress Project – PNGTS has executed precedent agreements (PAs) with several local distribution companies (LDCs) in New England and Atlantic Canada (PXP contracts) to re-contract certain system capacity set to expire in 2019 as well as construct incremental compression facilities within PNGTS' existing footprint in Maine (Portland Xpress Project or "PXP"). The PXP contracts, together with the C2C contracts, will provide transportation service of natural gas in the New England area of up to 0.3 Bcf/d by November 1, 2020, effectively utilizing all of PNGTS' expanded capacity through 2032. The in-service dates of PXP will be phased-in over a three-year period beginning November 1, 2018.PNGTS expects the capital cost of PXP to be approximately $80 million, which PNGTS expects to finance through a new credit facility. Concurrently with PXP, TransCanada will perform upstream capacity expansions of approximately $107 million (TransCanada PXP Expenditures), the majority of which is expected to be incurred following the anticipated receipt dates of required regulatory approvals. In connection with the TransCanada expansions, PNGTS signed a precedent agreement with TransCanada that contemplates the execution of a firm transportation agreement for each of the three phases of PXP, which will be assigned to the LDCs at theestimated completion of each phase. Prior to assignment of the TransCanada transportation agreements to its customers, PNGTS is obligated for the TransCanada PXP Expenditures in the event PXP does not proceed as anticipated.Northern Border Settlement – Northern Border's 2013 settlement agreement required Northern Border to file for new rates no later than January 1, 2018. On December 4, 2017, Northern Border filed a rate settlement with FERC which precluded the need to file a general rate case by January 1, 2018 (2017 Northern Border Settlement). The 2017 Northern Border Settlement, which was approved by FERC on February 23, 2018, provides for tiered rate reductions effective January 1, 2018, with no change to the underlying rate design. The 2017 Northern Border Settlement does not contain any moratorium and unless superseded by a subsequent rate case or settlement, recourse rates in effect at December 31, 2017, will decrease by 5.0% on January 1, 2018; by an additional 5.5% on April 1, 2018; and by a further 2.0% beginning January 1, 2020 through December 31, 2023, when Northern Border will be required to establish new rates. This equates to an overall rate reduction of 12.5% by January 1, 2020 from the recourse rates in effect at December 31, 2017.Acquisitions and FinancingDebt Offering – 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.2017 Acquisition – On June 1, 2017, the Partnership completed the acquisition of a 49.34 percent interest in Iroquois from subsidiaries of TransCanada and an option to acquire a further 0.66 percent interest in Iroquois, together with an additional 11.81 percent interest in PNGTS that results in the Partnership owning a 61.71 percent interest in PNGTS. The total purchase price of the 2017 Acquisition was $765 million plus final purchase price adjustments amounting to approximately $50 million. The purchase price consisted of: (i) $710 million for the Iroquois interest (less $164 million, which reflected the Partnership's 49.34 percent share of Iroquois' outstanding debt at the time of the 2017 Acquisition); (ii) $55 million for the additional 11.81 percent interest in PNGTS (less $5 million, which reflected our 11.81 percent share in PNGTS' outstanding debt at the time of the 2017 Acquisition); (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 (discussed below) on Iroquois' balance sheet. The Partnership funded the cash portionTC PipeLines, LPAnnual Report2017 9of the 2017 Acquisition through a combination of proceeds from the May 25, 2017 public debt offering and borrowing under its Senior Credit Facility.As of the date of the 2017 Acquisition, there was significant cash on Iroquois' balance sheet. Pursuant to the Purchase and SaleGTN XPress Project. The GTN Private Shelf Agreement associated with the acquisition of the Iroquois interest, as amended, the Partnership agreed to pay $28 million plus interest to TransCanada 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 Iroquois' balance sheet post-closing. The Partnership expects to receive the $28 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 26, 2018 the Partnership has received approximately $7.8 million of the expected $28 million, of which $5.2 million was received in 2017 and $2.6 million was received on February 1, 2018.Tuscarora Refinancing – On August 21, 2017, Tuscarora refinanced all of its outstanding debt by amending its existing Unsecured Term Loan Facility and issuing a new $25 million variable rate term loan that will require yearly principal payments beginning September 1, 2018 and will mature on August 21, 2020. Tuscarora's Unsecured Term Loan contains a covenant that requires Tuscaroralimits total debt to maintain a debt service coverage ratio (cash available from operations divided by the sum of interest expense and principal payments) ofno greater than or equal to 3.00 to 1.00. As65 percent of December 31, 2017, the ratio was 11.09 to 1.00.2013GTN’s total capitalization.Facility – On September 29, 2017, the Partnership's variable rate $500 million Term loan facility that was due on July 1, 2018August 21, 2020 was amended to extend the maturity period throughdate to August 20, 2021 under generally the same terms.2, 2022. As8, 2020, PNGTS entered into a resultNote Purchase and Private Shelf Agreement whereby PNGTS issued $125 million of this extension,10-year Series A Senior Notes with a coupon of 2.84% per annum and entered into a three-year private shelf agreement for an additional $125 million Senior Notes. The PNGTS Series A Notes do not require any principal paymentsPartnership implementedSeries A Senior Note issuance were used to repay the outstanding balance of PNGTS' revolving credit facility and for general partnership purposes including funding of growth capital. PNGTS expects to draw the remaining $125 million available under the 3-year private shelf agreement for an interest rate hedging strategy duringadditional $125 million of Senior Notes (PNGTS Private Shelf Facility) by the fourthend of third quarter of 2021 to refinance amounts funded on its revolving credit facility for costs associated with the Westbrook XPress Project. The PNGTS Private Shelf Facility contains a covenant that limits total debt to no greater than 65 percent of PNGTS’ total capitalization and hedgedrequires PNGTS to maintain a leverage ratio of no greater than 5.00 to 1.00.entire $500 million untilrevision of TC Energy's outlook to stable from negative.October 2, 2022 maturity using forward starting swaps atincreased long-term contracting levels.average rate of 3.26 percent. At December 31, 2017, the 2013 $500 million Term loan facility was hedged by fixed interest rate swap arrangements at an effective interest rate of 2.31 percent, expiring Julyimprovement in PNGTS' financial risk profile resulting from placing is PXP Phase II Project in-service on November 1, 2018.2015 Term Loan Facility2019.29, 2017,3, 2020, S&P affirmed Northern Border’s credit rating at BBB+ and upgraded the outlook from Stable to Positive based on strong recontracting, continued stable cash flows, conservative leverage, solid shipper base and strong sponsors.$170 million Term loan facility that was due on October 1, 2018 was amendedBBB/Stable credit rating. S&P continues to extendconsider the maturity period through October 1, 2020.2017 US Tax Reform – On December 22, 2017,Partnership's business risk profile to be a key strength underpinned by its highly contracted, long-term, take-or-pay contracts with creditworthy counterparties. S&P further recognizes the President ofPartnership's strong basin diversification and benefits associated with its strategic relationship with TC Energy despite the United States signed into law H.R. 1 (the "Tax Cuts and Jobs Act" or the "2017 Tax Act"). The 2017 Tax Act resulted in major changes to U.S. tax law, including a decrease in the U.S. corporate federal tax rate from 35 percent to 21 percent effective January 1, 2018. Although we are not a federally taxable entity, we expect the lower tax rates to impact future rate-setting processes on our pipeline systemsexpected higher leverage due to the FERC-regulated naturefunding of our business.its growth projects. On October 30, 2020, Moody's also affirmed the Partnership's credit rating at Baa2/Stable.FERC approves our pipelines' rates on a cost-of-service basis which includes a recovery of our ultimate taxable owners' income tax expense as a componentCreditwatch reflects S&P's opinion that TC Energy's offer to acquire all of the rates chargedoutstanding units will increase the level of parental support from TC Energy. Tuscarora was also placed on Creditwatch Positive.customers. Over time, we expect these changes will impact our future performance through changes inredeem the Unsecured Senior Notes on March 15, 2021 at a redemption price equal to 100% of the principal amount of the notes then outstanding, plus unpaid interest accrued to March 15, 2021. Partial funding for the redemption is expected to be provided using cash flows generated by our subsidiarieson hand, and distributions from our equity investments.Please refer also to Note 4borrowings under the Partnership's consolidated financial statements included in Part IV within Item 15. "Exhibits and Financial Statement Schedules" and Part II- Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations-Critical Accounting Estimates for more information.)investour unitholders by investing in long-life critical energy infrastructure that provides reliable transportationdelivery of energy to customers.10 TC PipeLines, LPAnnual Report2017PipelineInfrastructure Businesspipelines moveinfrastructure moves natural gas from major sources of supply or upstream pipelinesgathering facilities to downstream pipelines or locations or markets that use natural gas to meet their energy needs. PipelineInfrastructure 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. pipeline 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).pipeline'spipeline’s rates of return are just and reasonable. SometimesIn some cases, a settlement or agreement with the pipelinepipeline’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.pipelineinfrastructure projects are typically supported by long-term contracts. The term of the contracts is dependent on the individual developer'sdeveloper’s appetite for risk and is a function of expected rates of return, stability and certainty of returns. Transportation contracts expire at varying times and underpin varying amounts of capacity. As existing contracts approach their expiration dates, efforts are made to extend and/or renew the contracts. If market conditions are not favorable at the time of renewal, transportation capacity may remain uncontracted, be contracted at lower rates or be contracted on a shorter-term basis. Unsold capacity may be recontracted if and when market conditions become more favorable. The ability to extend and/or renew expiring contracts and the terms of such subsequent contracts will depend upon the overall commercial environment for natural gas transportation and consumption in the region in which the pipeline is situated.pipelineinfrastructure network has been developed to connect supply basins to market. Use and growth of this infrastructure isthe systems are affected by changes in the location, relative cost of natural gas supply and changing market demand.TC PipeLines, LPAnnual Report2017 11pipeline systems together with those of our General Partner TransCanada Corporation.
significantly over the next decade and over the long-term for a number of reasons, including the following:12 TC PipeLines, LPAnnual Report2017shipper'sshipper’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.Alberta'sthe 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;Pipeline Systems10.411.3 billion cubic feet per day of natural gas from producing regions and import facilities to market hubs and consuming markets primarily in the Western, Midwestern and Eastern U.S. All of our pipeline systems, except Iroquois and the pipeline facilities jointly owned with Maritimes and Northeast Pipeline LLC (MNE) on PNGTS joint facilities,(Joint Facilities), are operated byTransCanada.TC Energy. The Iroquois pipeline system is operated by Iroquois Pipeline Operating Company, a wholly owned subsidiary of Iroquois. The PNGTS Joint Facilities (see below) are operated by MNOC, M&N Operating Company, LLC (MNOC),a subsidiary of MNE. MNE is a subsidiary of Enbridge Inc.TC PipeLines, LPAnnual Report2017 13PipelineLengthDescriptionOwnership
PipelineLength Description Ownership Gas Transmission Northwest LLC (GTN)GTN1,377 miles Extends betweenfrom 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 Pipeline LLC (Bison)303 miles Extends from a location near Gillette, Wyoming to Northern Border'sBorder’s pipeline system in North Dakota. Bison can transport natural gas from the Powder River Basin to Midwest markets.100 percent North Baja Pipeline, LLC (North Baja)86 miles Extends betweenfrom an interconnection with the El Paso Natural Gas Company pipeline near Ehrenberg, Arizona andto 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 Gas Transmission Company (Tuscarora)305 miles Extends betweenfrom 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 Pipeline Company (Northern Border)1,412 miles Extends betweenfrom 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 Partners, L.P.Northern Border Pipeline Company Holdings LLC owns the remaining 50 percent of Northern Border.50 percent Portland Natural Gas Transmission System (PNGTS)PNGTS295 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 Maritimes and Northeast Pipeline LLC (MNE).MNE. The Joint Facilities extend from Westbrook, Maine to Dracut, Massachusetts and PNGTS owns approximately 32%32 percent of the undivided ownership interest based on contractually agreed upon percentages.Joint Facilities.61.71 percent (a)Great Lakes Gas Transmission Limited Partnership (Great Lakes)2,115 miles Connects with the TransCanadaTC 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. TransCanadaTC Energy owns the remaining 53.55 percent of Great Lakes.46.45 percent Iroquois Gas Transmission System, L.P (Iroquois)416 miles Extends from the TransCanadaTC 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 TransCanadaby: TC Energy (0.66 percent), Dominion Midstream (25.93Berkshire Hathaway Energy (Berkshire Hathaway) (50 percent) and Dominion Resources (24.07 percent).49.34 percent (b)(a)On June 1, 2017, the Partnership acquired an additional 11.81 percent interest from TransCanada resulting in 61.71 percent ownership in PNGTS. (Refer to Note 7 of the Partnership's consolidated financial statements included in Part IV within Item 15. "Exhibits and Financial Statement Schedules")(b)Effective June 1, 2017 (Refer to Note 7 of the Partnership's consolidated financial statements included in Part IV within Item 15. "Exhibits and Financial Statement Schedules")14 TC PipeLines, LPAnnual Report2017
LDCs,Local Distribution Companies (LDCs), major natural gas marketers, producing companies and other interstate pipelines, including affiliates. Our pipelinessystems 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"Risk“Risk Factors."One”Anadarko Energy Services Company accounted forwithin 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 ourits revenue from TC Energy and comprised 11 percent of the Partnership's revenues in 2017.GTN'sGTN’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-termTC PipeLines, LPAnnual Report2017 15contracting under a variety of contract terms. A portion of GTN's contract portfolio is contracted by industrial shippers and producers. We expect GTN to continue to be an important transportation component of these diversified portfolios. Incremental transportation opportunities are based on the difference in value between Western Canadian natural gas supplies and deliveries to Northern California.Currently, GTN is benefitting from an increase in the volumes of natural gas it transports asactivities occur on upstream pipeline systemsTC Energy's NGTL System, which deliverdelivers natural gas to GTN. These upstream activities are continuing and as a result, we are in the process of signingGTN, has allowed GTN to sign over 700,000 Dth/day in long-term contracts of which 348,000 Dth/day will result in additional volumes flowing onto GTN as early as mid-2018 with the remainder from 2019 toin-service dates between 2018 and 2020. The majority of these contracts have terms of at least 15 years.and is fully contracted with its revenues substantially supported by firm transportationa weighted average remaining contract length of approximately 5 years. Northern Border contracts through the end of 2020. Northern Border's contractsthat 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.TransCanadaTC 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. During the latter half2017 and the early part of 2018, Great Lakes sold all ofLakes’ total contract portfolio is contracted by its available 2017-2018 firm winter capacity. This level of contracting is significantly higher than that seen on this pipeline in recent years, indicative of a favorable shift in market dynamics for Great Lakes.During 2017, Great Lakes benefited from TransCanada's new long-term fixed price service onaffiliates including its Canadian Mainline. Concurrent with the launch of this new service, Great Lakes entered into a long-term transportation agreement with TransCanada'sTC Energy’s Canadian Mainline for 0.711 billion of cubic feet that commenced on November 1, 2017 for a ten-year period and contains volume reduction optionsthat allows TC Energy to transport up to fullabout 0.711 billion cubic feet of natural gas per day on the Great Lakes system. This contract quantity beginningwas a direct benefit from TC Energy’s long-term fixed price service on its Canadian Mainline that was launched in year three. This2017. TC Energy’s long-term fixed price service provides long-term capacity to TransCanada'sTC Energy’s shippers for the transportation of WCSB natural gas to markets in Eastern Canada and the U.S.PNGTS'PNGTS’ revenues are primarily generated from transportation agreements with LDCs throughout New England.England and Canada’s Atlantic provinces. The majority of PNGTS'PNGTS’ current revenue stream is supported by long-term contracts.contracts entered into via a series of open seasons for long-term capacity held by PNGTS in recent years. Long-term contractcontracts with several shippers involving commitments of approximately 82,000 Dth/day from thePNGTS’ Continent-to-Coast Contracts for a term of 15 years (the C2C open seasonContracts) began December 1, 2017, necessitating an increase in PNGTS'PNGTS’ certificated capacity up to approximately 210,000 Dth/day. The C2C contractsContracts mature in 2032 and replaced some expiring short-term and long-term contracts.contracts,Contracts, in 2017, as a result of its PXP open season, PNGTS executed 20-year PAsprecedent 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 to bring its certificated capacity up tosystem. PXP Phases I, II and III were placed into service during the fourth quarter of 2018, 2019 and 2020, respectively. The total final volume of the project is approximately 0.3 Bcf/183,000 Dth/day: 40,000 Dth/day by November 1, 2020, effectively utilizing allfrom Phase I, 118,400 Dth/day from Phase II, which includes re-contracting and renewal of PNGTS' expanded capacity through 2032.PXP will proceed concurrently with upstream capacity expansions on the Trans Quebec & Maritimes Pipeline (TQM)expiring contracts, and TransCanada's Canadian Mainline systems. The in-service dates of PXP are being phased-in over a three-year period beginning November 1, 2018.24,600 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.16 TC PipeLines, LPAnnual Report201720182021 and 20262032 and extends from TransCanada'sTC 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 2017,2020, Iroquois earned approximately 1112 percent of its revenues from discretionary services.BisonNaturalThe 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.currently not flowing on the Bison system in response to the recent relative cost advantage of WCSB-WCSB and Bakken -sourcedsourced gas versus Rockies production. From its in-service date in 2011 up to the fourth quarter of 2018, Bison has not experienced a decrease in its revenue as it iswas fully contracted on a ship-or-pay basisbasis. 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 2018.2021.Other PipelinesBison’s property, plant and equipment at December 31, 2018 and concluded that the entire amount was no longer recoverable, resulting in a non-cash impairment charge during the fourth quarter of 2018. We continue to explore alternative transportation-related options for Bison and we believe commercial potential exists to allow natural gas transported on Bison to flow in both directions, with the southwest direction involving deliveries onto third party pipelines and ultimately connecting into the Cheyenne hub. In any event, Bison will continue to incur costs related to property tax and operating and maintenance costs of approximately $6 million per year. See also Part II, Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Critical Accounting Estimates” for more information.North Baja and TuscaroraTuscarora’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.2020additional compression capability at an existing Tuscarora facility. Tuscarora XPress is 100 percent underpinned by a 20-year contract and beyond.TransCanada's FoothillTC Energy's Foothills systems, and Great Lakes and Iroquois, through their respective connections with TransCanada'sTC 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.area.Baja'sBaja’s southbound pipeline capacity competes with deliveries of LNG received at the Costa Azul terminal in Mexico. WhenIf LNG shipments are received at Costa Azul, North Baja'sBaja’s northbound capacity competes with pipelines that deliver Rocky Mountain area, Permian and San Juan basin natural gas into the Southernsouthern California area.TransCanada'sTC 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 TransCanada'sTC 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.TC PipeLines, LPAnnual Report2017 17systems'systems’ investment hurdles or projects that proceed with lower overall financial returns.TransCanadaTransCanadaTC Energy2017,2020, owns, through its subsidiaries, approximately 24.224 percent of our common units, 100 percent of our Class B units, 100 percent of our IDRs and an effectivehas a two percent general partner interest in us. TransCanadaTC 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. TransCanada'sTC Energy’s business is primarily focused on natural gas and oilliquids transmission and power generation services. TransCanadaservices, delivering the energy millions of people rely on to power their lives in a sustainable way. TC Energy consists of investments in 57,100approximately 58,000 miles of natural gas pipelines, approximately 3,000 miles of wholly-owned oilliquids pipelines and 653535 billion cubic feet of natural gas storage capacity. TransCanadaTC Energy also owns or has interests in over 6,100approximately 4,200 megawatts of power generation.TransCanada TC Energy operates most of our pipeline systems and, in some cases, contracts for pipeline capacity. We have purchased assets from TransCanada and jointly participated with TransCanada in acquiring assets from third parties, including acquisitions that we would have been unable to pursue on our own. TransCanada viewsas a core element of its strategythe General Partner, TC Energy, TC Northern, TC PipeLine USA, and considersMerger Sub, entered into the dropdown of assetsTC Energy Merger Agreement. Pursuant to the TC Energy Merger Agreement, Merger Sub will be merged with and into the Partnership, with the Partnership continuing as the sole surviving entity and an indirect, wholly owned subsidiary of TC Energy.financing option as it executestime of the TC Energy Merger, each common unit representing a fractional part of the limited partner interests in the Partnership issued and outstanding immediately prior to the effective time of the TC Energy Merger, other than common units owned by TC Energy and its capital growth program, subject to actual funding needs and market conditions. There can be no assurance as to when and on what terms these assets affiliates,offered to the Partnership.cancelled in exchange for 0.70 shares of TC Energy common shares. See also Part III,I, Item 13. "Certain Relationships and Related Transactions, and Director Independence"1. “Business- Recent Business Developments - Planned Merger with TC Energy" for more information on our relationshipMerger Agreement with TransCanada.Natural Gas Act of 1938 (NGA)NGA and Energy Policy Act of 2005, which gives FERC jurisdiction to regulate virtuallyeffectively all aspects of our business, including:systems'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'spipeline’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 to18 TC PipeLines, LPAnnual Report2017RegulatoryRate Proceedings2018 FERC Actions Impact on Maximum Rates Moratorium, Mandatory
Filing Requirements and
Other ConsiderationsGreat Lakes 2.0% rate reduction effective February 1, 2019 No moratorium in effect; comeback provision with new rates to be effective by October 1, 2022 GTN A refund of $10 million to its firm customers in 2018; 10.0% rate reduction effective January 1, 2019; additional rate reduction of 6.6% effective January 1, 2020 through December 31, 2021; these reductions will replace the 8.3% rate reduction in 2020 agreed to as part of the last settlement in 2015 Moratorium on rate changes until December 31, 2021; comeback provision with new rates to be effective by January 1, 2022; Settlement agreement reflected an elimination of income tax allowance and ADIT Northern Border 2.0% rate reduction effective February 1, 2019 to December 31, 2019 extended until July 1, 2024 unless superseded by a subsequent rate case or settlement No moratorium in effect; comeback provision with new rates to be effective by July 1, 2024 Bison No rate changes proposed No moratorium or comeback provisions Iroquois 3.25% rate reduction effective March 1, 2019; additional 3.25% rate reduction effective April 1, 2020 Moratorium on rate changes until September 1, 2020; comeback provision with new rates to be effective by March 1, 2023 PNGTS No rate changes No moratorium or comeback provisions North Baja 10.8% rate reduction effective December 1, 2018 No moratorium or comeback provisions; approximately 90 percent of North Baja’s contracts are negotiated; 10.8% reduction is on maximum rate contracts only Tuscarora 1.7% rate reduction effective February 1, 2019; additional rate reduction of 10.8% effective August 1, 2019 Moratorium on rate changes until January 31, 2023; comeback provision with new rates to be effective by February 1, 2023; Settlement agreement reflected an elimination of income tax allowance and ADIT operates underfiled an uncontested settlement with FERC to address the changes proposed by the 2018 FERC Actions on its rates established pursuantvia 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).settlementmoratorium 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 June 2015. Effective Julyrates along with ADIT for rate-making purposes.2015,2019, a 3.25 percent rate reduction and (ii) effective April 1, 2020, an additional 3.25 percent rate reduction, which will conclude the rates were reducedtotal 6.5 percent rate reduction from the 2016 settlement rates. The 2019 Iroquois Settlement, which was approved by three percent. In JanuaryFERC on May 2, 2019, preserved the 2016 GTN's rates decreased by asettlement moratorium on further 10 percent and will continue in effect through December 31, 2019.rate changes until September 1, 2020. Unless superseded by a subsequent rate case or settlement, GTN's rates will decrease an additional eight percent for the period January 1, 2020 through December 31, 2021 when GTNIroquois will be required to establishhave new rates. On October 30,Great Lakes operates under a settlement approved by FERC effective January 1, 2018 (the 2017 Great Lakes filed a rate settlement with FERC to satisfy its obligations from its 2013 rate settlement for new rates to be in effect by January 1, 2018.Settlement). The 2017 Great Lakes Settlement which wasdid 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.on February 22, 2018, decreased Great Lakes' maximum transportation rates by 27 percent effective October 1, 2017. The 2017 Great Lakes Settlement does not contain any moratorium and Great Lakes will be required to file for new rates no later than March 31, 2022, with new rates to be effective October 1, 2022.Northern Border – Northern Border's 2013 settlement agreement required Northern Border to file for new rates no later than January 1, 2018. On December 4, 2017, Northern Border filed a rate settlement with FERC precluding the need to file a general rate case by January 1, 2018 (2017(the 2017 Northern Border Settlement). The 2017 Northern Border Settlement which was approved by FERC on February 23, 2018, providesprovided for tiered rate reductions beginningfrom January 1, 2018 with no change to the underlyingDecember 31, 2019 that equate to an overall rate design.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 doesdid not contain a moratorium provision 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 recourse rates in effect at December 31, 2017, will decrease by 5.0% on January 1, 2018; by an additional 5.5% on April 1, 2018;agreement and by an additional 2.0% beginning January 1, 2020 through December 31, 2023, when Northern Border will be required to establish new rates. This equates to an overallBorder’s 501-G proceeding was terminated. The removal of ADIT increased net recoverable rate reductionbase and mitigated the loss of 12.5% by January 1, 2020 from the recourse rates in effect at December 31, 2017.Bison – Northern Border’s tax allowance.continues to operate–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 – continues to operate–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. On January 6, 2017, North Baja notified FERC that current market conditions do not support the replacement of the compression that was temporarily abandoned in 2013 and requested authorization to permanently abandon two compressor units and a nominal volume of unsubscribed firm capacity.Effective December 1, 2019, FERC approved the permanent abandonment request on February 16, 2017. The requested abandonments will not have any impact on existing firm transportation service.Tuscarora – Tuscarora operates under rates establisheda 10.8 percent rate reduction and elimination of its tax allowance and ADIT liability from rate base pursuant to a settlement approved by FERC in September 2016. UnderNorth Baja’s limited NGA Section 4 filing. The removal of ADIT increased net recoverable rate base and partially mitigated the settlement, Tuscarora's system-wide unit rate initially decreased by 17 percent, effective August 1, 2016. Unless superseded by a subsequent rate case or settlement, this rate will remain in effect until July 31, 2019, after which time the unit rate will decrease by an additional seven percent from August 1, 2019 through July 31, 2022. The settlement does not contain a rate moratorium provision and requires Tuscarora to file to establish new rates no later than August 1, 2022.continues to operateoperates under the rates approved by FERC in PNGTS'PNGTS’ most recent rate proceeding, effective December 1, 2010. PNGTS has no requirement to file a new rate proceeding.Iroquois – Iroquois operates underestablished pursuantshould be determined by averaging the results of the Discounted Cash Flow model and the Capital Asset Pricing Model. FERC determined that it will not use the Risk Premium Model. Our pipelines are subject to a settlement approvedrate regulation by FERC and any future rate cases we file are subject to the determinations in October 2016. Under the settlement, Iroquois rates decreased ratably during the phase-in period from September 2016 through 2018 with an overall reduction of approximately 20 percent beginning September 2018. The settlement also containsthis Policy Statement. We do not expect changes in this policy to affect us in a rate moratorium until September 1, 2020. Unless superseded by a subsequent rate case or settlement, Iroquois will be required to establish new rates no latermaterially different manner than September 1, 2022.TC PipeLines, LPAnnual Report2017 19The 2017 Tax Act and FERC's Income Tax Recovery InquiryOn December 22, 2017, the President ofother similarly sized natural gas pipeline companies operating in the United States signed into law the Tax Cuts and Jobs Act. This legislation provides for major changes to U.S. tax law with the most significant change being the reduction of the corporate federal income tax rate from 35 percent to 21 percent. As mentioned in the section Narrative Description of Business – General and Note 2 of the Partnership's consolidated financial statements included in Part IV within Item 15. "Exhibits and FinancialStates. Schedules", we are a non-taxable master limited partnership, and income taxes owed as a result of our earnings are the responsibility of our partners. However, all of our pipeline systems are regulated by the FERC, which approves the systems' rates on a cost-of-service basis and includes a recovery of our ultimate taxable owners' income tax expense as a nominal component of the maximum allowable rates that may be charged to customers. Ultimate rates charged to customers are typically reached through negotiation without ascribing specific elements of costs of service such as income taxes.In December 2016, Regarding the Commission'son April 19, 2018 (Certificate Policy for RecoveryStatement NOI), thereby initiating a review of Income Tax Costs (Docket No. PL17-1-000) requesting Initial Comments regarding how to address any double recovery resulting from FERC's current income tax allowance and rate of return policies that are in effect since 2005.Docket No. PL17-1-000 is a direct response toUnited Airlines, Inc., et al. v. FERC, a decision issued by the U.S. Court of Appeals for the District of Columbia Circuit in July 2016 in which the D.C. Circuit directed FERC to explain how a pass-through entity such as a master limited partnership receiving a tax allowance and a return on equity derived from the discounted cash flow (DCF) methodology did not result in double recovery of taxes.Various comments have been received by FERC and most recently, comments on how the 2017 Tax Act will affect the income tax recovery allowed on regulated pipelines.There is not likely to be a definitive resolution of these issues for some time. The ultimate outcome of Docket No. PL17-1-000 is not certain and could result in changes going forward to FERC's treatment of income tax allowances in the cost of service or to the discounted cash flow return on equity. Depending upon the resolution of these issues, the cost of service rates of any of our interstate natural gas pipelines could be affected to the extent the pipeline proposes new rates or changes to its existing rates or if its rates are subject to complaint or challenged by FERC which would ultimately impact our future operating performance.Review of FERC Natural Gas Pipelines PolicyThe current FERC Chairman announced in December 2017 that FERC will review its policies on certification of natural gas pipelines, including an examination of its long-standing Policy Statement on Certification of New Interstate Natural Gas Pipeline Facilities, issued in 1999, that is used to determine whether to grant certificates for new pipeline projects. We are unable to predict what, if any, changes may be proposed as a result of the Certificate Policy Statement NOI that will affect our natural gas pipeline business or when such proposals, if any, might become effective. No further action has occurred since the Certificate Policy Statement NOI was issued. We do not expect that any changechanges in this policy wouldto affect us in a materially different manner than any other similarly sized natural gas pipeline entitycompanies operating in the United States.pipelinesassets are subject to a variety of stringent and complexU.S. federal, tribal, state and local environmental laws and regulations governing environmental protection, includingrelating to air emissions,quality, biodiversity, wastewater discharges, waste management, water management, and water quality. SuchThese laws and regulations generally require natural gas pipelinespipeline companies to obtain and comply with a wide variety of environmental registrations,approvalsauthorizations required for construction and operations. Certain violationsConsequences 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. Failure to comply with these lawsregulations may result in the assessment of sanctions, including administrative, civil and/or criminal penalties, the imposition of investigatory, remedial and corrective action requirements, the occurrence of delays or restrictions in the permitting or performance of projects and/or the issuance of orders limiting or prohibiting operations in affected areas.20 TC PipeLines, LPAnnual Report2017The following is a discussion of some of the applicableRegulationsrelate tomost significantly impact our business.The – The CAA and comparable state laws regulate emissions, which regulates air pollution on a national level by restricting the emission of air pollutants from various industrialstationary and mobile sources including compressor stations, and impose variousimposes 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;in some cases, control requirements. Such lawsfederal waters and regulations may require pre-approval forestablishes the construction or modification of certain facilities expectedextent to produce air pollutants or result in an increase of existing air pollutants. Such facilities must also comply with air permits containing various emission and operational limitations, or requiring the use of emission control or abatement technologies, which could result in the imposition of substantial costs on our operations.•The Endangered Species Act (ESA) – The ESA restricts activities that may affect endangered or threatened species or their habitats. The presence of threatened or endangered species, including the designation of previously unidentified or threatened species, could cause us to incur additional costs or become subject to operating restrictions or bans in the affected areas.•Solid Wastes and Hazardous Substance and Wastes Statutes – The operations of our pipeline systemswaterways are subject to federal jurisdiction and analogous state statutes that regulaterulemaking as protected “Waters of the handling, management, storageUnited States” (WOTUS);disposaloperators of solid wastes, including hazardous wastesvessels, onshore facilities, and hazardous substances. These include the Resource Conservationpipelines, as well as lessees or permittees of areas in which offshore facilities are located, to liability for removal costs and Recovery Act the Solid Waste Disposal Act and damages arising from an oil spill in WOTUS;federal levelResource Conservation and comparable state statutes. These statutes subject our operations to rigorous waste managementRecovery Act (RCRA), which governs the generation, treatment, storage, transport, and disposal practices to ensure compliance. In addition, of solid wastes, including hazardous wastes;improper disposal or a release of wastes or hazardous substance could result in the imposition of investigatory or remedial obligations.• – The TSCA addresses,mixtures. These includemixtures, including polychlorinated biphenyls (PCBs), asbestos, radon, and lead-based paint.The Clean Water(CWA)(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;Oil PollutionEndangered Species Act of 1990 (OPA) – The CWA, OPA(ESA), which restricts activities that may affect federally identified endangered and comparable state laws impose strict controls with respect to the discharge of pollutants, including spills and leaks of oil and other substances, intothreatened species or adjacent to state waters and waters of the U.S. The discharge of pollutants into regulated waters is generally prohibited, except in accordance with the terms of a permit issuedtheir habitats by the EPAimplementation of operating restrictions or a delegated statetemporary, seasonal, or federal agency. The CWApermanent ban in affected areas; and federal regulations also prohibit discharge of dredge and fill material into regulated waters, including wetlands, unless authorized by an appropriately issued permit. The EPA and the U.S. Army Corps of Engineers (Corps) released a final rule in May 2015 that attempted to clarify federal jurisdiction under the CWA over waters of the U.S. This interpretation by the EPA may constitute an expansion of federal jurisdiction over waters of the U.S. Implementation of the rule has been stayed nationwide, and in January 2017, the U.S. Supreme Court accepted review of the rule to determine whether jurisdiction over the challenge to the rule rests with the federal district or appellate courts. In February 2017, President Trump issued an executive order directing the EPA and the Corps to review and, consistent with applicable law, initiate a rulemaking to rescind or revise the rule. The EPA and the Corps proposed in June 2017 to repeal the June 2015 rule, announced their intent to issue a new rule defining the CWA's jurisdiction, and published a proposed rule in November 2017 that would stay implementation of the June 2015 rule for two years. The Supreme Court ruled in January 2018 that jurisdiction to decide challenges to the rule rests with federal district courts. Consequently, while implementation of the 2015 rule remains stayed, the previously-filed district court cases challenging the scope of rule will be allowed to proceed. As a result of these developments, future implementation of the June 2015 rule is uncertain at this time, but to the extent that this rule or any subsequent replacement rule expands the scope of the CWA's jurisdiction, pipeline construction and expansion projects could face increased costs and delays with respect to obtaining permits for dredge and fill activities in wetland areas.•National Environmental Policy Act (NEPA) – Natural gas transportation activities over federally-managed land or involving federal approval can be subject to review underor analogous state requirements. NEPAwhich requires federal agencies including the Department of the Interior or FERC, to evaluate governmentalthe environmental effects of major agency actions having the potential to significantly impact the environment. In the course of such evaluations, an agency willand prepare anTC PipeLines, LPAnnual Report2017 21Environmental Assessment that addresses the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare aenvironmental assessments (EAs) or more detailed Environmental Impact Statementenvironmental impact statements (EISs) that ismay be made available for public review and comment. The current activitiespipeline systems, as well as any proposed plansprojects 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 future activities, on federal lands are subjectcitizens’ suits or other forms of opposition to new developmental projects or the requirementsexpansion of NEPA in connection with any new approval that is required for construction, operation or use on or of federal lands. NEPA reviews can take a significant amount of time and are subject to challenge and appeal by environmental groups, who have frequently used the NEPA process to challenge pipeline construction projects over the past several years, and therefore,existing projects. These factors all have the potential to substantially restrict or delay currentproject permitting, development, or expansion of projects and future naturalincrease costs to gas transportation activities.•National Historic Preservation Act (NHPA) – The NHPA restricts activities that may affect culturalpipeline companies, including the Partnership, in the process. historic resources through the implementation of procedural protections that require identificationfederal and protection of cultural and historic resources of national, state tribal and local significance. The presence of cultural and historic resources, including the designation of previously unidentified resources or sites have the potential to delay current and future natural gas transportation activities.We have not incurred and do not anticipate incurring material costs to comply with existing environmental laws and regulations, judicial decisions interpreting those laws and regulations, enforcement policies as well as the issuance of executive actions at all levels of government can also significantly increase operational or compliance costs for gas pipeline companies. Uncertainty surrounding the interpretation of certain laws and regulations due to conflicting rulings on environmental issues in a given court system may be an added burden on operations and compliance-related decision-making.WeSpecifically, the EO directed EPA to review its recent methane technical amendment to the NSPS for stationary sources and to propose revisions to existing source standards by September 2021.accruedminimal, the regulated community may need to apply for anythe more time-consuming and burdensome individual permits that evaluate discharge activities on a case-by-case basis. Historically, NWP 12 has been specifically used by utilities, including oil and gas pipelines, telecommunications lines, sewage lines, water lines, and more. The CWA Section 404 NWP Program has been under the national spotlight since April 15, 2020, when a Montana federal District Court ruled against TC Energy’s use of an allegedly invalid NWP 12 for its Keystone XL project and enjoining the USACE from issuing NWP 12s for utility activities nationwide. The Court believed the USACE violated the ESA when it renewed NWP 12 in 2017 and remanded NWP 12 back to the USACE to remedy the identified issue. The U.S. Supreme Court granted an emergency stay of the district court’s order, except as it applied to Keystone XL, while the decision’s merits were being appealed in the Ninth Circuit Court of Appeals by the federal defendants. This ongoing litigation has created tremendous uncertainty within the pipeline industry regarding the scope of pipeline activities still allowed to use NWP 12 and concern over the potential material, long-term harms to pipeline projects throughout the country if the appeal of the district court’s order in the Ninth Circuit is unsuccessful. In response to the uncertainty, many pipeline companies, including ourselves, had to reconsider permitting strategies for projects that were depending on the use of NWP 12. For example, companies have incurred additional costs and project delays by switching to alternative nationwide permits or the significantly more time-consuming individual permits. In some cases, companies have had to assume some risk in continuing to use NWP 12, particularly for those projects already in the construction phase. Other pipeline companies have also been challenged in federal courts throughout the country on similar NWP 12 grounds, indicating an increasing litigation risk to the Partnership’s continued use of NWP 12, and potentially other NWPs.liabilities.Climate Regulationpublic, governmentalattention in the U.S. and scientific attention. Asthroughout the globe. The spotlight on GHG regulation as a result, numerous proposals have been made and are likelymeans to combat climate change is expected to continue to be made atincrease compliance, construction, and operating costs for pipeline companies, including the international, national,Partnership, particularly under President Biden's aggressive climate changestate levels of governmentlocal governments are using tools like executive orders, legislation, regulatory actions, and more to regulate emissions of greenhouse gases (GHGs).GHGs. At the federal level, no comprehensive climate change legislation has been implemented to date, but thefor example, EPA has determined that emissions of GHGs present an endangerment to public health and the environment and subsequently has adopted regulations under existing provisions of the CAA that, among other things, establish construction and operating permit reviews regarding GHGs for certain large stationary sources that are already potential major sources of conventional pollutant emissions. The EPA has also promulgated regulations requiring the monitoring and reporting of GHGs and limiting GHGs directly from certain sources of emissions. Governmental, scientific, and public concern over GHG emissions from amongthe oil and gas industry, in particular, is growing considerably. President Biden’s new executive orders included a pause on new oil and gas leasing on federal lands, a revocation of the Keystone XL Presidential Permit, and more. Furthermore, while the EPA has historically been the sole federal regulator of GHGs, on December 27, 2020, former President Trump signed into law the 2020 PIPES Act, which notably made PHMSA another federal regulator of methane emissions from pipeline facilities. While we cannot predict the extent of the impact on the Partnership and the rest of the oil and gas industry from the increased GHG regulation, we can be sure that it will be material.certain onshoreof air emissions. The policy amendments, (Methane Policy Rule), effective September 14, 2020, notably removed the transmission and storage sector from the regulated source category and rescinded methane and VOC requirements for the remaining sources that were established by former President Obama's administration. The technical amendment included changes to fugitive emissions monitoring and repair schedules for gathering and boosting compressor stations and low-production wells, recordkeeping and reporting requirements, and more. The Partnership sees the amendments as positive for the industry since it eliminates NSPS for natural gas transmission pipelines. However, it is important to note that the Partnership is still committed to many of the NSPS requirements for pipelines. This is important because, as expected, the amendments were immediately challenged in federal court. Moreover, President Biden's January 20, 2021 EO for Protecting Public Health and storage facilities, including gatheringthe Environment and boosting facilitiesRestoring Science to Tackle the Climate Crisis specifically directed EPA to review the technical amendment by September 2021. A reconsideration of the more controversial policy amendment is expected to follow. The same EO directed EPA to also propose existing source standards by September 2021. The extent to which these directives will impact the Partnership remains unknown.blowdownspredictability in GHG emissions legislation, regulation and policies at the federal level, state and local governments have increasingly and more aggressively pursued GHG regulation within their own jurisdictions. This trend is likely to continue to grow under President Biden's leadership. A bipartisan coalition of natural gas transmission pipelines between compressor stations ingovernors from twenty-five states and U.S. territories have established the U.S. on an annual basis.Additionally, whileClimate Alliance to combat climate change through the implementation of state policies that are consistent with the U.S. Congress has from timegoal of the Paris Agreement. Many of these policies are currently affecting or expected to time consideredaffect our assets residing in those specific states and increase our compliance-related costs, the extent of which is yet unknown.emissions ofand regulate GHGs in the absencestate through the establishment of any significant activitynew annual GHG emissions reduction goals that must be met through the development of a new carbon cap and reduce program and enhanced clean fuel standards, which take effect no later than January 1, 2022. Rulemaking to implement the executive order has been ongoing since Spring 2020. The Northwest Gas Association, a trade organization of the Pacific Northwest Gas Industry, is representing the interests of interstate pipeline company members, including TC Energy, on the Rulemaking Advisory Committee for the development of the program. The extent to which GTN assets in Oregon will be impacted remains unknown, as the program is not expected to be proposed until Summer 2021. Additionally, the Washington Department of Ecology began rulemaking in 2020 to implement the Governor’s order to strengthen and standardize the consideration of climate change risks, vulnerability, and impacts in environmental assessments for certain major industrial and fossil fuel projects. During Washington’s 2020 legislative session, legislators also passed a law committing the State to becoming carbon-neutral by Congress2050 and strengthening intermediate reduction goals. In addition to California’s climate change plan that includes a GHG cap-and-trade program and methane leak regulations for oil and gas sites, the Governor issued an executive order in recent yearsSeptember 2020 requiring all new cars and light trucks sold in the state to adoptbe zero emission by 2035 and heavy and medium trucks to be zero emission by 2045. The promotion of electrification and use of legal tools for GHG regulation is also gaining traction at the local level. For example, in November 2020 a carbon tax was proposed to the Portland City Commission and in December 2020, the Governor of Washington and Mayor of Seattle followed in the footsteps of local government in California by introducing proposals that would cut demand for natural gas through buildinglegislation,the increasing state and local GHG regulation and promotion of electrification may materially affect our business, financial condition, demand for our systems and services, operations, compliance-related costs, and more.state and regional efforts have emerged that are aimed at tracking and/or reducing GHG emissions by means of cap and trade programs.Recent federal rulemakings have focused on the emission of methane, which is considered by the EPA as a GHG. In June 2016, the EPA published New Source Performance Standards, known as Subpart OOOOa, that require certain new, modified or reconstructed facilities in the oil and natural gas sector to reduce these methane gas and volatile organic compound emissions. These Subpart OOOOa standards will expand previously issued New Source Performance Standards published by the EPA in 2012, known as Subpart OOOO, by using certain equipment-specific emissions control practices, requiring additional controls for modified pneumatic controllers and pumps as well as compressors and imposing leak detection and repair requirements for natural gas compressor and booster stations that are modified through an increase in horsepower. However, over the past year the EPA has taken several steps to delay implementation of the methane rules. In June 2017, EPA proposed to stay the Subpart OOOOa standards for a period of two years and a separate 90-day stay of the standards to provide time for the 2-year stay to take effect while EPA reconsiders implementation of the Subpart OOOOa standards in their entirety. The EPA has not yet finalized the June 2017 proposed rulemaking and, as a result, the June 2016 rule remains in effect but future implementation of the 2016 rules is uncertain at this time.In November 2017, the EPA published two Notices of Data Availability (NODAs) for Subpart OOOOa in the Federal Register and initiated a 30-day public comment period. One NODA relates to the June 2017 two year stay to reconsider the rule and the other NODA relates to the EPA's 90-day stay to cover the 60-day time-period between final publication of the 2-year stay in the Federal Register and the time the proposed 2-year stay takes effect. We do not believe that complianceexecutive actions, starting with the Subpart OOOOa regulations will have a material adverse effect on our operations even if the stay is ultimately vacated in court and the rule is fully implemented. However, given the uncertainty of policy and rulemaking regarding this rule the future effects on our pipelines cannot be predicted.22 TC PipeLines, LPAnnual Report2017 On an international level, in June 2017, the U.S. Federal government announced its intent to withdraw from the 2015 international climate change agreement known asrejoining the Paris Agreement, the largest international effort to combat climate change, which former President Trump had officially withdrawn the U.S. from on November 4, 2020. Similarly, President Biden issued an executive order on January 27, 2021, directing the Secretary of the Interior to pause, to the extent consistent with applicable law, the issuance of new oil and gas leases on federal public lands and offshore waters pending completion of a comprehensive review and reconsideration of federal oil and gas permitting and leasing practices. President Biden's robust climate change plan includes a pledge to achieve a clean energy economy by 2050 by implementing a number of initiatives through executive orders, legislation, and regulations. His climate agenda includes methane regulation, promotion of electrification, and more. The political risk to the Partnership's business is further increased by climate change-related pledges made by candidates seeking public office at the local, state, and federal levels. During former President Trump's administration, Democratic Party-sponsored legislative initiatives, such as the Clean Leadership and Environmental Action for our Nation’s (CLEAN) Future Act and the U.S. State Department formally notifiedClimate Crisis Action Plan, were proposed in 2020 but did not advance beyond the United Nations in August 2017House. Now, the likelihood of passing comprehensive climate change legislation at the United States' intentfederal level has significantly increased. President Biden's climate agenda could require us or our customers to withdraw from the agreement. The Paris Agreement requires member countriesincur increased, potentially significant, costs to review and "represent a progression" in their intended nationally determined contributions, which setcomply with new, more stringent GHG emission reduction goals every five years beginning in 2020. Following the U.S. Federal government announcement to withdraw fromregulations. Additionally, entry into the Paris Agreement a number of U.S. State governments announced their commitment to the Paris Agreement. It is not possible at this time to predict how legislation or new regulations that may be adopted to address GHG emissions would impact our business. However, any such future laws and regulations that limit emissions of GHGs could adversely affect demand for the production of oil and natural gas that exploration and, production operators produce, some of whom are our customers, which could therebythus, reduce demand for the services we provide to our naturalcustomers.transportation services. it should be noted that many scientists have concluded that increasing concentrations of GHGs in the Earth's atmosphere may produce climate changesclimatic events like storms and floods which may have a material adverse effect on the financial condition and results of operations on us and our customers.significant physical effects,been used for natural gas pipeline operations for many years. Additionally, some of our properties have been operated by third parties or by previous owners or operators whose treatment and disposal of hazardous substances, wastes, or petroleum hydrocarbons was not under our control. Under environmental laws such as increased frequencyTSCA, CERCLA, and severityRCRA, we could incur strict joint and several liability due to damages to natural resources as well as for remediating hydrocarbons, hazardous substances or wastes disposed of storms, droughtsor released by us or prior owners or operators. For example, during routine maintenance activities of our pipelines and floodsrelated facilities, we may discover historical hydrocarbon or PCB contamination. Discovery of such contaminants would require prompt notification to the appropriate governmental authorities and corrective actions to timely mitigate the contamination. Moreover, an accidental release of materials into the environment during our operations may cause us to incur significant costs and liabilities. Remedial costs, penalties from governmental agencies, and other climatic events. Significant changesdamages could have a material adverse effect on our liquidity, results of operations, and financial condition. We also could incur costs related to the clean-up of third-party sites to which we sent regulated substances for disposal and for damages to natural resources or other claims related to releases of regulated substances at or from such third-party sites.temperaturesignificant costs associated with installing and other weather eventsmaintaining 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.many effectsa 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 ranging from an impact on demand, availability and commodity prices, to efficiency and output capability.U.S. Department of Transportation operational results.and Hazardous Materials Safety Administration (PHMSA)PHMSA.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. Pursuant to the authority granted under the NGPSA, PHMSA has promulgated regulations governing pipeline design, installation, testing, maximum operating pressures, pipeline patrols and leak surveys, minimum depth requirements and emergency procedures, as well as other matters intendedfacilities to ensure adequate protection for the public and to prevent accidents and failures. The PSI Act established mandatory inspections for all U.S. natural gas transportation pipelines, and some gathering lines in high consequence areas (HCAs), which are areas where a release could have the most significant adverse consequences, including high population areas. The PIPES Act required mandatory inspections for certain natural gas transmission pipelines in HCAs and required that rulemaking be issued for,Pursuant to this act, PHMSA has promulgated regulations governing, among other things, maximum operating pressures, pipeline control room management. Pursuant to the authority granted under the NGPSA, as amended,patrols and leak surveys, public awareness, operation and maintenance procedures, operator qualification, minimum depth requirements and emergency procedures. Additionally, PHMSA has established a series of rulespromulgated regulations requiring pipeline operators such as our operator, TransCanada, Iroquois and MNOC 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 naturalgas 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.HCAsOctober 2019. The October 2019 final rule relates specifically to gas transmission pipelines and, among other things, updates reporting and records retention standards for covered pipelines and expands the level of required integrity assessments that requiremust be completed on certain pipeline segments outside of high consequence areas (HCAs). The October 2019 final rule also requires operators to review maximum allowable operating pressure records and perform specific remediation activities where records are not available. The Partnership will continue to assess the performanceoperational and financial impact related to the October 2019 final rule over its 15-year implementation window that began July 1, 2020 and seek to optimize recovery of frequent inspectionsthose costs. The remaining rulemakings comprising the Gas Mega Rule are expected to be issued in 2021. On January 11, 2021, PHSMA finalized a published June 2020 proposed a rulemaking that would seek to ease regulatory burdens on gas transmission, distribution and other precautionary measures. PHMSA may assess penalties for violations of these and other requirements imposed by its regulations. The 2011gathering lines. However, we expect President Biden's administration to reconsider this rulemaking or possibly have it withdrawn.also increaseswhich reauthorized PHMSA’s hazardous liquid and gas pipeline programs only through federal Fiscal Year 2019. On December 27, 2020, the maximum penalty2020 PIPES Act was signed into law and authorizes general funding for violationPHMSA as well as prescribes a number of priorities for PHMSA through federal fiscal year 2023. Key items include: additional due process protections for operators during enforcement proceedings; updating the federal safety standards for the operation and maintenance of large-scale liquefied natural gas facilities; clarifying the applicability of the pipeline safety regulations to idle pipelines; and reviewing each operator’s operation and maintenance plan within two years. The 2020 Pipes$100,000the National Transportation Safety Board, and to $200,000 per violation per dayreduce the consequences of violationlarge-volume, uncontrolled releases of natural gas pipeline ruptures. Specifically, the NPRM seeks to set requirements for the placement, function, and maintenance of automatic shut off and/or remote-control mainline valves to mitigate the effects of a pipeline rupture. The NPRM also seeks to set time requirements for the identification of, and response to, pipeline ruptures.$1 milliona Class 1 location to $2 milliona Class 3 location. Through required periodic assessments, repair criteria, and other extra preventive and mitigative measures, PHMSA expects this alternative approach would provide long-term safety benefits consistent with the current natural gas pipeline safety rules while also providing cost savings for pipeline operators.related series of violations. Effective April 27, 2017, to account for inflation, those maximum civil penalties were increased to $209,002 per violation per day,material effect on our costs.a maximum of $2,090,022 for a series of violations.The ongoingexisting pipeline safety laws and implementing regulations could cause our pipeline systems to incur significant and unanticipated capital and operating expenditures for repairs or upgrades deemed necessary to ensure their continued safe and reliable operation and to comply with the federal pipeline safety statutes and regulations.Additional rule makings The promulgation of new laws and rulemaking regarding pipeline safety are likely. In June 2016,likely and, despite compliance with applicable laws and regulations, our pipelines may experience leaks and ruptures that could impact the 2016 Pipeline Safety Act was passed, extending PHMSA's statutory mandate through 2019surrounding population and among other things, requiring PHMSA to complete certain of its outstanding mandates under the 2011 Act. As aenvironment. This may result in May 2016, PHMSA proposed new rules for natural gas transmissioncivil and/or criminal fines and gathering lines that would, if adopted, impose more stringent inspection, reporting,penalties or third-party property damage claims and integrity management requirements on operators. However, to date, no further action has been taken with respect to thisTC PipeLines, LPAnnual Report2017 23proposed rulemaking. The safety enhancement requirements and other provisions of the 2011 Pipeline Safety Act as further amended by the 2016 Pipeline Safety Act, as well as any implementation of PHMSA rules or any issuance or reinterpretation of guidance by PHMSA or any other state agencies with respect thereto, could require usadditional testing or upgrades on the pipeline system unrelated to install newthe incident. It is possible that these costs may not be covered by insurance or modified safety controls, pursue additional capital projects, conduct maintenance programs on an accelerated basis, or result in a temporary or permanent reduction in maximum allowable operating pressure, which would reduce available capacity on our pipelines, any or all of which could result in our incurring increased operating costs that could be significant, and have a material adverse effect on our results of operations or financial condition.From time to time, despite compliance with applicable rules and regulations, our pipelines may experience incidents that result in leaks and ruptures that may impact the surrounding population and environment. This may result in enforcement by regulatory agencies that may seek civil and/or criminal fines and penalties or third party property damage claims, and could require our pipelines to conduct testing of the pipeline system or upgrade segments of a pipeline unrelated to the incident which costs may not be covered by insurance or recoverable through rate increases.also subject to the requirementsa number of the OSHA and other federal and state agencies that address employee healthlaws and safety. In general, we believe that TransCanada's, Iroquois'regulations, including the federal Occupational Safety and MNOC's programsHealth Act and costs incurred are addressing the OSHA requirements and protectingcomparable state statutes, whose purpose is to protect the health and safety of employees. Basedworkers. 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.new regulatory developments,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. However,standards, such increases in costs of compliance, and the extent to which they might be recoverable through our pipeline'spipeline’s rates, cannot be estimated at this time.TransCanada,TransCanadaAlthough TC Energy also has insurance which covers reasonably foreseeablemay cover losses due tofrom physical damage to our facilities and losses incurred by others, as a result of a cyber security event. These polices do not, however, cover losses that may result from a cyber security event, that prevents TransCanada from operating our facilities butthe insurance does not resultcover all events in any physical damage.all circumstances. There is no certainty that costs incurred related to securing against these threats will be recovered through rates.24 TC PipeLines, LPAnnual Report2017EMPLOYEESWeWhile human capital is necessary for us to operate our business, we are managed and operated by our General Partner.Partner, therefore we do not directly make decisions regarding our service providers. Subsidiaries of TransCanadaTC Energy operate most of our pipelines systems pursuant to operating agreements, with the exception of the Iroquois pipeline system and the PNGTS joint facilities.Joint Facilities. The Iroquois pipeline system is operated by a wholly owned subsidiary of Iroquois. The PNGTS joint facilitiesJoint Facilities are operated by MNOC, a wholly owned subsidiary of MNE. MNE is a subsidiary of Enbridge Inc."Corporate“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.of the information contained in this report, including the following discussion of risks when making investment decisions relating to our Partnership.Our ability to make cash distributions is dependent primarily on our cash flow, financial reserves and working capital borrowings. amount of cash we can distribute on our units principally depends upon the amount of cash we generate from our operations, which will fluctuatefluctuates based on, among other things:Significant changes in energy prices could impact supply and demand balances for natural gas.cancould result in supply and demand imbalances that impact availability of natural gas for transportation on our pipeline systems.positive impact on demand but canprolonged period of low crude oil and natural gas prices would negatively impact exploration and development of new crude oil and natural gas supplies thatsupplies. In response to the sharp decline in oil and natural gas prices, many producers have announced cuts or suspension of exploration and production activities and some state regulators are considering mandating the proration of production of hydrocarbons. A drilling reduction could impact the availability of natural gas to be transported by our pipelines. 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'counterparties’ creditworthiness that could impactand their ability to meet their transportation service cost obligations.do notcannot successfully identifyfinance and complete expansioncapital projects or make and integrate acquisitions that are accretive, we may not be able to continue tomaintain or grow our cash distributions.Our strategy is to continue to grow the cash distributions on our common units by expanding our business. Our ability to grow depends on our ability to undertake acquisitions and organic growth projects, the ability of our pipeline systems to complete expansion projects and make and integrate acquisitions that result in an increase in cash per common unit generated from operations. Our ability to complete successful, accretive expansion projects or acquisitions is dependent upon many factors, including our ability to secure necessary rights-of-way or regulatory approvals, our ability to finance such expansion projects or acquisitions on economically acceptable terms and the degree to which our assumptions about volumes, reserves, revenues, costs and customer commitments materialize. In addition, many U.S. environmental laws provide for citizen suits, and environmental groups frequently use these provisions to challenge environmental reviews and permits issued in connection with pipeline infrastructure projects, resulting in costly delays. Acquisitions may not be available to the Partnership or occur at the prices, terms, with the same structure or on the schedule consistent with historical transactions.TransCanada may offer to sell its assets to the Partnership, subject to TransCanada's funding needs and market conditions. There can be no assurance, however, as to when and on what terms these assets will be offered to the Partnership.In addition, we face competition for acquisitions from investment funds, strategic buyers and commercial finance companies. These companies may have higher risk tolerances or different risk assessments that permit them to offer higher prices that we may be unwilling to match.Expansion projects or future acquisitions that appear to be accretive may nevertheless reduce our cash from operations on a per unit basis.expansioncapital projects or make acquisitions that we believe will be accretive, these expansioncapital projects or acquisitions may nevertheless reduce our cash from operations on a per-unit basis. Any expansioncapital project or acquisition involves potential risks, including:expansioncapital 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;26 TC PipeLines, LPAnnual Report2017expansioncapital projects or acquisitions reduce our cash from operations on a per unitper-unit basis, our ability to make distributions may be reduced.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, 2017, $435 million of our total $2,415 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, 2017, the $500 million 2013 Term Loan Facility was hedged by fixed interest rate swap and 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."Partnership'sPartnership’s current or future debt could have significant consequences to the Partnership including the following:then we could experience an increase in our borrowing costs, face difficulty accessing capital markets or incurring additional indebtedness, be unablelack 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.2017 27 2020 33expansioncapital projects or future acquisitions, our ability to make quarterly cash distributions may be diminished or our financial leverage could increase.The prolonged low oil and natural gas prices in the energy industry and will likely continue to make it difficult for some entities to obtain funding. In order to fund our expansionsome capital project expenditures, we willmay 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 expansion 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.Ananour goodwill, long-lived assets or equity investment, a long-lived asset or goodwill couldinvestments will reduce our earnings orand could negatively impact the value of our common units.GAAP,U.S. Generally Accepted Accounting Principles (GAAP), we evaluate our goodwill for impairment at least annuallyannually. Our long-lived assets and our equity investments, and long-lived assets, 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, as a whole, 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 noncashnon-cash charge to earnings with a correlativecorresponding effect on equity and balance sheet leverage as measured by debt to total capitalization.As an example, in 2015, we recognized an impairment charge on our equity investment in Great Lakes amounting to $199 million and in 2016, our analysis on Tuscarora's goodwill balance indicated that the excess of its fair value over the carrying value, including goodwill was less than 10 percent.There is a risk of future impairments related to our equity investments, goodwill or long-lived assets. If assumptions relied upon change, there can be no assurance no future impairment charge will be made with respect to our equity investments, goodwill and long-lived assets."Management's"Management’s Discussion and Analysis of Financial Condition and Results of Operations – Critical Accounting Estimates –- Impairment of Equity Investments, Goodwill, and Long-Lived Assets –and Equity Investments."Equity Investmentsequity investments in Northern Border, Great Lakes and Iroquois, which limits our ability to control these assets.Equity Investmentsequity 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 and including us. These management committees generally require at least the28 TC PipeLines, LPAnnual Report2017partners'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 electeddo not to,elect or wereare unable to make a capital contribution to these assets;assets, our ownership interest would be diluted.The valueMajority of our pipeline systems’ revenue is generated from long-term, fixed fee transportation services dependsagreements. Depending on a shipper's demandmarket conditions at the time of contract expiration and renewal, shippers may be unwilling to renew their contracts for pipeline capacity and the price paid for that capacity.long terms or at favorable rates. The inability of our pipelinespipeline 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 priorexisting contracts, depends on many factors beyond our control, including:pipeline'spipeline’s ability to contract for transportation services;systems'systems’ relative competitiveness;services;services on a long-term fixed fee basis; andregulatory developments.Natural gas on Bison is currently not flowing as a resulta change inregulations, public policy and consumer demand for its services. There can be no assurance that we will be able to replace Bison's existing contracts and maintain its current revenues which could significantly reduce our earnings and cash flows.Natural gasrenewal energy on Bison is currently not flowing in response to the relative cost advantage of WCSB – and Bakken-sourced gas versus Rockies production. Bison has not experienced a decrease in its revenue as it is fully contracted on a ship-or-pay basis through January of 2021. However, we may not be able to renew or contract for this capacity if this market condition continues to persist.While we are currently working on other strategic alternatives to maximize the value of this asset which include discussions with producers in the area to determine the best use for Bison, including if the asset can be reversed, redirected or repurposed, there is a risk that options available at this time will not bring back the same level of revenue Bison currently generates. More importantly, Bison's revenues comprise approximately 19 percent of our consolidated revenues and if we are unsuccessful in securing contracts for Bison in the future or the options available to us do notTC PipeLines, LPAnnual Report2017 29materialize, there could be a significant reduction in our earnings and cash flows and ultimately, an impairment on Bison's long lived assets.theirthe ability to recover all costs of capital and operations and negatively impact their rate of return, results of operations and cash available for distribution.virtuallyeffectively 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(see Item 1. "Business – Government Regulation")such as refusing to honor existing moratoria on rate changes, could adversely affect our pipeline systems'systems’ ability to recover all of their current or future costs and could negatively impact their rate of return, results of operations and cash available for distribution.For example, in December 2016, FERC issued a Notice of Inquiry Regarding the Commission's Policy for Recovery of Income Tax Costs (Docket No. PL17-1-000) requesting Initial Comments regarding how to address any double recovery resulting from FERC's current income tax allowance and rate of return policies that are in effect since 2005.Various comments have been received by FERC and most recently, comments on how the 2017 Tax Act will affect the income tax recovery allowed on regulated pipelines. While the outcome of the inquiry is still pending, we believe that there is not likely to be a definitive resolution of these issues for some time. However, the outcome This could result in changes going forward to FERC's treatment of income tax allowances in the cost of service or to the discountedlower than anticipated distributable cash flow return on equity that could have an impact on the rates of any of our interstate natural gas pipelines.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 supplynecessitate a distribution reduction 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, availabilitycurrent quarterly level 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 TransCanada 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,30 TC PipeLines, LPAnnual Report2017reputational 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."rate base"“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.systems'systems’ indebtedness and commitments may limit their ability to borrow additional funds, make distributions to us or capitalize on business opportunities.systems'systems’ respective debt levels and commitments could have negative consequences to each of them and the Partnership, including the following:systems'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.In the event the PXP project does not proceed, PNGTS may be responsible for the reimbursement of TransCanada's upstream capital expenditures on the related Canadian system expansions, which could have a negative impact on PNGTS' ability to make cash distributions to its partners.In connection with PXP, PNGTS has entered into an arrangement with TransCanada regarding the construction of certain facilities on its system that will be required to fulfill future contracts on the PNGTS' system. In the event the TransCanada expansions terminate prior to the in-service date of the final phase of PXP, PNGTS could be required to reimburse TransCanada for up to the amount of TransCanada PXP Expenditures incurred to date of termination, the majority of which is expected to be incurred following the anticipated receipt dates of required regulatory approvals, prior to the end of phase II of the project. As of December 31, 2017, the total incurred was approximately $3 million. If PNGTS were required to reimburse TransCanada for TransCanada PXP Expenditures, it would reduce cash available for distributions to us and therefore reduce our cash available for distributions to unitholders. A project construction plan is in place to minimize expenditures until certain regulatory approvals are received.See also Part I, Item 1. "Business-Recent Business Developments" for further information on the PXP Project.including, among other events,such as, ruptures, earthquakes, adverse weather conditions, and other natural disasters;disasters, terrorist activity, civil disobedience or acts of aggression; damage to a pipeline by a third party;aggression, third-party activity, and pipeline or equipment failures. Eachfailure. Any of these risks could result incause damage to one of our pipeline systems, business interruptions, a release of pollution or contaminants into the environment andor otherTC PipeLines, LPAnnual Report2017 31These risksThe Partnership could cause us to suffer a substantial loss of revenue and incur significant costs to the extent they are not covered by insurance under our pipeline systems'systems’ shipper contracts, as applicable. In addition,Additionally, if one of our pipeline systems was to experience a serious pipeline failure, a regulator could require our pipelinesus to conduct testing of the pipeline system or upgrade segments of a pipeline unrelated to the failure, whichresulting in potential costs may not be 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.pipelines could be subjectpipeline systems may experience significant costs and liabilities related to penalties and fines if they fail to complycompliance with FERC regulations and pipeline safety laws and regulations.subjectedsubject to substantial penalties and fines if FERC findsin 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 NGPAthe Natural Gas Policy Act of 1978 to impose penalties for violations of up to approximately $1.2$1.31 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.Ourwhichthat require pipeline operators to develop integrity management programs.Thecompliance with stringent operational and safety standards. For example, the ongoing implementation of the pipeline integrity management programs could cause our pipeline systems to incur significant and unanticipated capital and operating expenditures for repairs or upgrades deemed necessary to ensure their continued safe and reliable operation andoperation. 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 the federal pipeline safety statutes and regulations. Additionally, any failure to comply with PHMSA'sPHMSA’s regulations could subject our pipeline systems to penalties, fines or restrictions on our pipeline systems'systems’ operations. New legislation or regulations adopted by PHMSA may impose more stringent requirements applicable to integrity management programs and other pipeline safety aspects of our operations, which could cause us to incur increased operating and capital costs and result in operational delays and costs of operations. For example,delays. has adopted or proposed pipeline safety regulations in 2011 and, more recently, in 2016 in response to legislation passed by the U.S. Congress that, among other things, increased the penalties for safety violations, established additional safety requirements for newly constructed pipelines and required studies of safety issues that could result in the adoption of new regulatory requirements by PHMSA for existing pipelines, and empowered PHMSA to address imminent hazards by imposing emergency restrictions, prohibitions and safety measures on owners and operators of regulated pipeline facilities without prior notice or an opportunity for a hearing.The cost of new PHMSA regulations to our pipeline systems 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 regulated by federal, state and local laws and regulations that could impose costs for compliance with environmental protection requirements.Each of our pipeline systems is subject to federal, state and local environmental laws and regulations that could impose significant compliance-related costs and enforcement policies. Potential liabilities, may arise relatedor make the execution of our growth projects uneconomic or impossible.protectionthe nature of the environment and natural resources. New environmental laws, regulations or enforcement policies could be implemented that significantly increase our pipeline systems' compliance costs. As an example, under the Clean Air Act the 2015 revisionsoperations, we are subject to the National Ambient Air Quality Standards for ozone may result in the addition of non-attainment designations in additional counties in which our pipeline systems operate. States have submitted their initial non-attainment designations to the EPA and the agency expects to issue final non-attainment designation in 2018. Depending upon State Implementation Plans and the outcome of any legal challenges to such designations, additional permitting delays and expenditures for pollution control equipment could occur. This example illustrates the uncertainty to which proposed laws, regulations or reforms, if any, will be adopted and what impact they might ultimately have on our operations or financial results.32 TC PipeLines, LPAnnual Report2017Under certainstringent environmental laws and regulations we maythat compel compliance with numerous obligations that are applicable to our operations including acquisition of permits or other approvals before conducting regulated activities, restrictions on the types, quantities and concentration of materials that can be exposedreleased into the environment; limitation or prohibition of construction and operating activities in environmentally sensitive areas such as wetlands, urban areas, wilderness regions and other protected areas; requiring capital expenditures to comply with pollution control requirements, and imposition of substantial liabilities for pre-existing contamination that arisepollution resulting from our operations. Failure to comply with these laws and regulations or any newly adopted laws or regulations may result in assessment of sanctions including administrative, civil and criminal penalties, the imposition of investigatory, remedial and corrective action obligations or the incurrence of capital expenditures; the occurrence of restrictions, delays or cancellations in the permitting or performance of projects, and the issuance of orders enjoining or conditioning performance of some or all of our operations in a particular area. Environmental compliance and enforcement costs and liabilities in connection with our past or current operations. For example, during routine maintenance activities, we may discover historical hydrocarbon or polychlorinated biphenyl contamination, which may require notification to the appropriate governmental authorities and corrective action to address.There also exist legal initiatives directly affecting our customers that could indirectly affect our operations by reducing the need for our services. Such developments could cause our customers to incur potentially significant added costs to comply with such requirements and experience delays or curtailment in the pursuit of exploration, development or production activities, which subsequently could reduce demand for our transportation services.Current and future emissions regulation legislation or regulations restricting emissions of GHG could result in increased operating costs.There have been a number of legislative initiatives to regulate GHG emissions; however, uncertainty exists regarding the impact of new and proposed GHG laws and regulations. Moreover, implementation of GHG regulations is the subject of significant litigation which has created uncertainty in compliance requirements with both the regulatory agencies and industry. Recent federal rulemakings have focused on the emission of methane, which is considered by the EPA as a GHG. For example, in June 2016, the EPA published New Source Performance Standards, known as Subpart OOOOa, that require certain new, modified or reconstructed facilities in the oil and natural gas sectorpipelines may come, for example, from air emissions and product-related discharges, impacts to reduce these methane gasregulated water bodies and volatile organic compound emissions. These Subpart OOOOa standards will expand previously issued New Source Performance Standards published by the EPA in 2012 and known as Subpart OOOO, by using certain equipment-specific emissions control practices, requiring additional controls for modified pneumatic controllers and pumpsthreatened or endangered species as well as compressorshistorical industry operations and imposing leak detectionwaste disposal practices. For example, an accidental release from one of our facilities could subject us to substantial liabilities arising from environmental cleanup and repair requirementsrestoration costs, claims made by neighboring landowners and other third parties for personal injury, natural gas compressorresource and booster stations that are modified through an increase in horsepower. However, overproperty damages and fines or penalties for related violations of environmental laws or regulations. Moreover, the past year the EPA has taken several steps to delayadoption and implementation of these methane standards,new environmental laws, regulations, judicial decisions, and enforcement policies could potentially increase our compliance-related costs, particularly in the realm of climate change and GHG regulation. Some high-profile federal environmental laws and regulations that may impose significant compliance related costs and make the execution of our pipeline projects more difficult include the uncertainty surrounding the use of the USACE’s NWPs, specifically NWP 12, for utility construction, maintenance, repair, and relocation activities affecting WOTUS. The ever-changing definition of WOTUS, amendments made to the CWA Section 401 water quality certification process, the criminalization of the “incidental take” of migratory birds, its nests, or its eggs under the MBTA, policy and technical amendments made to NSPS for stationary sources of air emissions, the “Once in Always in” HAPs policy, and the agency proposed a rulemakingnew authority given to PHMSA to regulate methane emissions from pipelines are additional examples of federal actions that will likely impose additional compliance-related costs and make project execution more difficult.June 2017Oregon due to stay the requirements for a period of two years and revisit implementation of the Subpart OOOOa rulesEPA’s Regional Haze Rule. In 2020, the State of Oregon identified two GTN Stations as significant sources of regional haze precursor emissions to Class I areas in their entirety. The EPA has not yet published a final rule and the June 2016 rule remains in effect, but future implementationOregon. This identification was made as part of the 2016 Subpart OOOOa standardsState’s development of its 2021 air quality protection plan implementing the federal Regional Haze Rule that requires states to improve visibility in national parks and wilderness. The Rule required ODEQ to identify sources of emissions that could be reduced with reasonable control methods to improve visibility in Class I areas under its state plan. The identification of the two GTN stations triggered the need to submit a four-factor analysis for five turbines at the stations. A four-factor analysis under the Regional Haze Rule is uncertain at this time. Although itused to determine if there are “reasonable” controls available for reducing the visibility impairing emissions, primarily Nitrogen Oxides (NOx) for the GTN facilities. Based on the four-factor analyses ODEQ removed one turbine from consideration for additional controls. If GTN is not possible at this timeultimately required to predict how legislation or new regulationsinstall NOx controls on the four remaining units under review in Oregon’s final state implementation plan, the capital expenditures that maywill be adopted to address GHG emissions would impact our business, any such future laws and regulationsincurred by GTN could result in increasedbe material.or additional operating restrictions,the incurrence of remedial costs, penalties from governmental agencies, and other damages could have a material adverse effect on our liquidity, results of operations, and financial condition. For further discussion on environmental matters, see Part I, Item 1 “Government Regulation” – “Environmental Matters”.financial condition, results of operations and cash flows.The Cap and Invest Legislation (HB 4001 and SB 1507) that is scheduled to be proposed during the 2018 Oregon legislative session could result in higher cost of operating the GTN pipeline systemThe Oregon Legislature is considering several GHG proposals that would regulate GHG emissions through a "cap-and-invest" program. The Cap and Invest Legislation (HB 4001 and SB 1507) is scheduled to be proposed during the 2018 Oregon legislative session that, in its current form, would provide GHG allowances to be allotted and sold by various entities. The information provided has not allowed us to reasonably anticipate or estimate the outcome of this proposed legislation at this time. Additionally, the Oregon Department of Environmental Quality are considering proposed rules to amend existing air quality rules. Comments to the proposed "Cleaner Air Oregon" rulemaking was scheduled for early 2018. At this time, we cannot reasonably estimate the impact of the proposed amended rules in its final form; however, it is expected that these rules will become finalized in 2018.Recent pipeline safety legislation and proposed regulations could result in more stringent requirements on our facilities and systems that could trigger significant capital and operating costs.The 2016 Pipeline Safety Act requires that PHMSA publish periodic updates on the status of those mandates outstanding from the 2011 Pipeline Safety Act, of which numerous initiatives remain to be completed. The mandates yet to be acted upon include requiring certain shut-off valves on transmission lines, mapping all high consequence areas, and shortening the deadline for accident and incident notifications.TC PipeLines, LPAnnual Report2017 33In March 2016, PHMSA announced a proposed rulemaking that would impose new or more stringent requirements for certain natural gas lines and gathering lines. Additional requirements proposed by this proposed rulemaking would increase PHMSA's integrity management requirements for natural gas pipelines. To date, no further action with respect to this proposed rulemaking has been taken. We continue to monitor proposed rulemaking developments and evaluate its potential impact, if any, of 2016 Pipeline Safety Act, in light of the many PHMSA initiatives and mandates. At this time, we cannot predict the ultimate impact of this legislation, and subsequent revisions to regulations on our operations; however, the adoption of any new legislation or regulations regarding increased pipeline safety could cause us to incur increased capital and operating costs, which costs could be significant.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 results 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 the Partnership’s business and operations. For further discussion on environmental matters, see Part I, Item 1 “Government Regulation” – “Legal Initiatives to Combat Climate Change and Restrict Greenhouse Gas (GHG) Emissions”.We do not own thewhich could result in higher costs and disruptionsis leased pursuant to our operations, particularly with respect to easements and rights-of-way across Indian tribal lands.We do not own the majority of the land on which our pipeline systems are located. We obtain easements, rights-of-way and other land use rights to construct and operate our pipeline systems from individual landowners, Native American tribes, governmental authorities and other third parties. Someparties, the majority of these rights expire after a specified period of time. As a result, wewhich are subject to the possibility of more onerous termsperpetual and increased costs to renew expiring easements, rights-of-way and other land use rights. While we generally are able to obtain these rightsobtained through agreementagreements with land owners or legal process, if necessary, rights-of-way across Indiannecessary. Certain rights, however, are subject to renewal and, with respect to tribal land require approval of the applicable tribal governing authority andheld in trust by the Bureau of Indian Affairs (the "BIA"). If efforts(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 retain existing land use rightsrenew a right-of-way on tribal land at a reasonable cost are unsuccessful, ourcould require capital expenditures for removal and relocation of portions of pipeline systems could also be subject to a disruption of operations and increaseddisrupt operations. Such costs to re-route the applicable portion of our pipeline system located on tribal land. Increased costs associated with renewing or obtaining new easements or rights-of-way and any disruption of operations could negatively impact the results of operations and cash available for distribution offrom our pipeline systems.Our Great Lakes pipeline system has rights-of-way expiring duringonrights-of-way expired for approximately 7.6 miles of our Great Lakes pipeline acrosson tribal land located within the Fond du Lac Reservation (Fond Du Lac) and Leech Lake Reservation (Leech Lake) in Minnesota and the Bad River Reservation (Bad River) in Wisconsin. WeGreat Lakes subsequently received a demand letter in April 2019 from the Fond Du Lac Tribal Chairman to immediately cease operation of the Great Lakes pipeline and begin the process of removing all infrastructure from tribal land. Following receipt of the demand letter, Great Lakes executed a Memorandum of Agreement with Fond Du Lac relating to the negotiation of a new right-of-way. Great Lakes continues to negotiate with Fond Du Lac and are negotiatingin advanced discussions with Bad River. In late 2020, Great Lakes has reached an agreement with Leech Lake subject to renewfurther approval from the rights-of-way withBIA.tribal authorities.renewal process, we cannot predict the full outcome of these negotiations. If we are unable to reach agreement regarding these rights-of way prior to expirationobtain new easements or rights-of-way across all or a portion of the existing easements, we expect to continue operating thetribal lands at reasonable rates, or at all, Great Lakes pipeline while continuing good faith negotiations with the tribal authorities to obtain the necessary rights. If these discussions ultimately are unsuccessful, we couldmay be required to remove pipe fromacquire the tribal landsnecessary rights at significant cost or remove and re-route the applicable portionportions of the Great Lakes pipeline system. While the outcome of these negotiations or the abilityat significant capital expense and disruption to reach agreement prior to expiration of the existing rights is uncertain, the impact of a disruption of operations or significantly increased costs to renew the rights-of-waythat could have a material adverse effect on our financial condition, results of operations and cash flows.34 TC PipeLines, LPAnnual Report2017directors.Common unitholders cannot remove General Partner without its consent.Our General Partner may not be removed except by the vote of the holders of at least 66TransCanada'sTC Energy's ownership of 24.2approximately 24 percent of our outstanding common units at December 31, 2017,2020, has the practical effect of making removal of our General Partner difficult.unitholders'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.unitholders'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.TC PipeLines, LPAnnual Report2017 35unitholders'unitholders’ liability may not be limited if a court finds that unitholder action constitutes control of our business."control"“control” of the Partnership'sPartnership’s business.2017,2020, the General Partner and its affiliates own approximately 24.224 percent of our outstanding common units.partner'spartner’s fiduciary duties to holders of our common units with contractual standards governing its duties.36 TC PipeLines, LPAnnual Report2017TransCanadaTC Energy could adversely affect our credit ratings and profile.TransCanadaTC 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 TransCanada,TC Energy, including the degree of their financial leverage and their dependence on cash flows from us to service their indebtedness.20172020, we paid fees and reimbursements to our General Partner in the amount of $4 million (2016(2019 and 2015 – $3 million)2018- $4 million each). Our General Partner, in its sole discretion, determines the amount of these expenses. In addition, our General Partner and its affiliates may provide us with services for which we will be charged reasonable fees as determined byTransCanada'sTC Energy’s costs or their cost allocation practices could have an effect on our results of operations, financial position and cash flows.Partnership'sPartnership’s pipeline systems operated by TransCanadaTC Energy are allocated certain costs of operations at TransCanada'sTC Energy’s sole discretion. Accordingly, revisions in the allocation process or changes to corporate structure may impact the Partnership'sPartnership’s operating results. TransCanadaTC 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.purposes, as well as us not being subject to a material amount of entity-level taxation by individual states.purposes. If the Internal Revenue Service (IRS)we were to treat usbe treated as a corporation for U.S. federal income tax purposes, or if we were tootherwise become subject to a material amount of entity level taxation for U.S. federal, state and local tax purposes, then our cash available for distribution wouldto unitholders and the value of our common units could be substantially reduced.unlessif the Internal Revenue Service (IRS) were to determine that we fail to satisfy a "qualifying income"“qualifying income” requirement. Based upon ourTC PipeLines, LPAnnual Report2017 37aany 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 as an entity.BecauseIn the event of a tax imposed upon us as a corporation, the cash available for distribution to our unitholders wouldcould be substantially reduced. Any tax treatment of us as a corporation wouldreduced and result in a material reduction in the anticipated cash flow and after-tax return to unitholders, and thuswhich in turn would likely result inhave a substantial reduction innegative impact on the value of theour common units.reflect the impact of that law on us.From time to time, membersMembers of the U.S. Congress have frequently proposed and considered substantive changes to the existing U.S. federal income tax laws that would affect publicly traded partnerships, including proposals that would eliminate our ability to qualify for partnership tax treatment.AlthoughThere can be no assurance that there is no current legislative proposal, a prior legislative proposal would have eliminated the qualifying income exception for all publicly traded partnerships upon which we rely for our treatment as a partnership forwill not be further changes to U.S. federal income tax purposes.In addition, on January 24, 2017, final regulations (the Final Regulations) regarding which activities give rise tolaws or the Treasury Department’s interpretation of the qualifying income within the meaning of Section 7704 of the Internal Revenue Code of 1986, as amended (the Code) were publishedrules in the Federal Register. We do not believe the Final Regulations affecta manner that could impact our ability to be treatedqualify as a partnership for U.S. federalin the future. We believe the income tax purposes.However, anythat we treat as qualifying satisfies the requirements under current regulations.of these changes or other proposals will ultimately be enacted. Any suchfuture legislative changes could negatively impact the value of an investment in our common units.anyour treatment as a partnership for U.S. federal income tax matter affecting us.purposes. The IRS may adopt positions that differ from the positions we take. It may be necessary to resort to administrative or court proceedings in an effort to sustain some or all of the positions we take. Any contestA court may not agree with some or all of the IRS, and the outcome of anypositions we take. Any contest with the IRS may materially and adversely impact the market for our common units and the price at which the common unitsthey trade. In addition,withbetween us and the IRS will result in a reduction in our cash available for distribution to our unitholders and thus will be borne directly or indirectly by the unitholders and the General Partner.38 TC PipeLines, LPAnnual Report2017unitholders'unitholders’ behalf. in us 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'unitholders’ behalf. These rules are not applicable for tax years beginning on or prior to December 31, 2017.theirits 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."business interest" is“business interest” may be limited to the sum of our business interest income and 30% of our "adjusted“adjusted taxable income."” For the 2020 taxable year, the CARES Act generally increases the 30% adjusted taxable income limitation to 50%. For the purposes of this limitation, adjusted taxable income is computed without regard to any business interest expense or business interest income, and in the case of taxable years beginning before January 1, 2022, any deduction allowable for depreciation, amortization, or depletion. Althoughdepletion 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 certain regulated pipeline businesses application ofand, therefore, we believe that our interest expense is fully deductible. If the interest limitation to tieredTC PipeLines, LPAnnual Report2017 39businesses like ours that hold interests in regulated businesses is not clear. PendingIRS contests this position or if further guidance specificis issued contrary to this issue, we are not able to determine the impactpositions taken, the limitation could have on our unitholders'unitholder’s ability to deduct ourthis interest expense but it is possible that our unitholders' interest expense deduction willcould be limited.Further, with respect to taxable years beginning after December 31, 2017, a tax-exempt entity with more than one unrelated trade or business (including by attribution from investment in a partnership such as ours that is engaged in one or more unrelated trade or business) 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.Unitholdersunitholders will be subject to U.S. taxes and withholding with respect to their income and gain from owning our common units.business ("effectively connected income").business. Income allocated to our unitholders and any gain from the sale of our common units will generally be considered to be "effectively connected"“effectively connected” with a U.S. trade or business. As a result, distributions to a Non-U.S.non-U.S. unitholder will be subject to withholding at the highest applicable effective tax rate and a Non-U.S.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.The 2017 Tax Act imposes a withholding obligation of 10% ofamount realized upon a Non-U.S. unitholder's sale or exchangetransferee of an interest in a partnership that is engaged in a U.S. trade or business. However, duebusiness is generally required to challengeswithhold 10% of administeringthe amount realized by the transferor unless the transferor certifies that it is not a foreign person. While the determination of a partner’s amount realized generally includes any decrease of a partner’s share of the partnership’s liabilities, recently issued Treasury regulations provide that the “amount realized” on a transfer of an interest in a publicly traded partnership, such as our common units, will generally be the amount of gross proceeds paid to the broker effecting the applicable transfer on behalf of the transferor, and thus will be determined without regard to any decrease in that partner’s share of a publicly traded partnership’s liabilities. The Treasury regulations further provide that withholding obligation applicableon a transfer of an interest in a publicly traded partnership will not be imposed on a transfer that occurs prior to open market trading and other complications, the IRS has temporarily suspended the application of this withholding rule to open market transfersJanuary 1, 2022. For a transfer of interests in a publicly traded partnerships pending promulgation of regulationspartnership that is effected through a broker on or other guidance that resolvesafter January 1, 2022, the challenges. Itobligation to withhold is not clear if or when such regulations or other guidance will be issued. Non-U.S.imposed on the transferor’s broker. Prospective foreign unitholders should consult atheir tax advisor before investingadvisors regarding the impact of these rules on an investment in our common units.unitholders'unitholders’ tax returns.40 TC PipeLines, LPAnnual Report2017"short seller"“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.unitholders'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'unitholders’ tax returns without the benefit of additional deductions.TC PipeLines, LPAnnual Report2017 41states. Manystates, many of these stateswhich 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.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.We believe that we hold satisfactory rights, titleinterests ina map showing the properties owned or used bylocations of our pipeline systems. With respect to real property, our pipeline systems own or lease sites for compressor stations, meter stations, pipeline field offices and microwave towers. Our pipeline systems are constructed and operated on landproperty owned by individuals, governmental authorities, Native American tribes (as further discussed below) and other third parties pursuant to leases, easements, rights-of-way, permits and licenses, the majority of which are perpetual. Our pipeline systems also own or lease land for compressor stations, meter stations and pipeline field offices. Certain land use rights, in particular rights-of-way on tribal land held in trust by the BIA, are subject to periodic renewal.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' properties are adequatesystems and suitable forconduct our business and that such periodic renewals, rental payments, encumbrances and restrictions should not materially detract from the conductvalue of our pipeline systems or materially interfere with the operation of their business in the future.Northern Border – Approximately 90 miles of our Northern Border pipeline system is located within the boundaries of the Fort Peck Indian Reservation in Montana. Northern Border has a pipeline right-of-way lease 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, Northern Border also obtained right-of-way access across allotted lands located within the reservation boundaries. With the exception of one tract subjectbusiness.a right-of-way grant expiring in 2035, the allotted lands are subjectOur Pipeline Systems” for further information regarding risks related to a perpetual easement granted by the Bureau of Indian Affairs (BIA) for and on behalf of the individual allottees.Great Lakes – Approximately 74 miles of our Great Lakes pipeline system is located within the boundaries of three Indian reservations: the Leech Lake Reservation and the Fond du Lac Reservation in Minnesota, and the Bad River Reservation in Wisconsin. Great Lakes has right-of-way access across allotted and tribal lands located within each reservation's boundaries that expire in the second quarter of 2018. Great Lakes is in discussions with tribal authorities for the renewal of approximately 7.6 miles of rights-of-way access prior to their expiration. The Great Lakes pipeline also crosses approximately 1,000 feet in two tracts under perpetual easement located within the Chippewa Indian Reservation in Lower Michigan.aremay be involved in various legal proceedings from time to time that arise in the ordinary course of business, as well as proceedings that we consider material under federal securities regulations.business. Information regarding our pipeline systems'systems’ rate proceedings is described in Item 1. "Business – Government Regulation – Regulatory and Rate Proceedings" is incorporated herein by reference. We are also a party to the followingInformation on our legal proceeding:Great Lakes v. Essar Steel Minnesota LLC, et al.proceedings can be found under Note 2 – On October 29, 2009, Great Lakes filed suit in the U.S. District Court, District of Minnesota, against Essar Minnesota LLC (Essar Minnesota)Contingencies within Part IV, Item 15. “Exhibits and certain Foreign Essar Affiliates (collectively, Essar) for breach of its monthly payment obligation under its transportation services agreement with Great Lakes. Great Lakes sought to recover approximately $33 million for past and future payments due under the agreement. On September 16, 2015, following a jury trial, the federal district court judge entered a judgment in the amount of42 TC PipeLines, LPAnnual Report2017$32.9 million in favor of Great Lakes. On September 20, 2015, Essar appealed the decision to the United States Court of Appeals for the Eighth Circuit (Eighth Circuit) based on an allegation of improper jurisdiction and a number of other rulingsFinancial Statement Schedules,” which information is incorporated herein by the federal district judge. Essar was required to post a performance bond for the full value of the judgment pending appeal. The Eighth Circuit heard the appeal on October 20, 2016. A decision on the appeal was received in December 2016 and the Eighth Circuit vacated Great Lakes' judgment against Essar finding that there was no federal jurisdiction. Great Lakes filed a Request for Rehearing with the Eighth Circuit and it was denied in January 2017. Before the Circuit Court issued its decision, Essar Minnesota filed for bankruptcy in July 2016. The Foreign Essar Affiliates have not filed for bankruptcy. Following the Circuit Court's decision, the performance bond was released into the bankruptcy court proceedings. Great Lakes filed a claim against Essar Minnesota in the bankruptcy court and its case against the Foreign Essar Affiliates in Minnesota state court remains pending. In April 2017, after Great Lakes agreement with creditors on an allowed claim, the bankruptcy court approved Great Lakes' claim in the amount of $31.5 million. On May 20, 2017, the federal district court awarded Essar Minnesota approximately $1.2 million for costs, including recovery of the performance bond premium, to be paid by Great Lakes. Great Lakes filed a motion with the bankruptcy court to offset the $1.2 million award of costs against its claim against Essar Minnesota in the bankruptcy proceeding but was unsuccessful. As a result, Great Lakes accrued the $1.2 million in its books. Great Lakes is unable to estimate the timing or the extent to which its claim will be recoverable in the bankruptcy proceedings.Registrant'sRegistrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities22, 2018,19, 2021, there were approximately 3526 holders of record of our common units. Our common units trade on the NYSE under the symbol "TCP".22, 2018,19, 2021, the Partnership had 71,306,396 common units outstanding, of which 54,221,565 were held by non-affiliates and 17,084,831 common units were held by subsidiaries of TransCanada,TC Energy, including 5,797,106 common units held by our General Partner. Additionally, TransCanada,TC Energy, through our General Partner, owns 100 percent of our IDRs and an effectivea two percent general partner interest in the Partnership. TransCanadaTC 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.The following table sets forth, for the periods indicated, the high and low sale prices per common unit, as reported by the NYSE, and the amount of cashdeclared per common unit with respect to the corresponding periods. Cash distributions are paid within 45 days after the end of each quarter to unitholders of record as of the record date.
Price Range Cash Distributions
Declared per High Low Common Unit 2017 First Quarter $65.03 $57.02 $0.94 Second Quarter $61.74 $51.06 $1.00 Third Quarter $59.30 $49.83 $1.00 Fourth Quarter $55.59 $48.55 $1.00
2016
First Quarter $55.00 $34.25 $0.89 Second Quarter $60.48 $46.50 $0.94 Third Quarter $58.66 $50.24 $0.94 Fourth Quarter $59.12 $47.12 $0.94 On February 13, 2018, we paid a cash distribution of $76 million to common unitholders and the General Partner, representing a cash distribution of $1.00 per common unit for the quarter ended December 31, 2017. The distribution was allocated in the following manner: $71 million to the common unitholders as of the close of business on February 2, 2018 (including approximately $17 million to TransCanada as holder of 17,084,831 common units), and $5 million to the General Partner, which included $2 million for its effective two percent general partner interest and $3 million for its IDRs. In 2017, the Partnership made cash distributions to common unitholders and the General Partner that amounted to $284 million compared to $250 million in 2016.Cash Distribution PolicyPursuant 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. Our quarterly cash distributions to the unitholders comprise all of our Available Cash. Available Cash is defined in the Partnership Agreement and generally means, with respect to any quarter, all cash on hand at the end of a quarter less the amount of cash reserves that are 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 anticipated credit needs);•comply with applicable laws or any debt instrument or other agreement to which we are subject; and44 TC PipeLines, LPAnnual Report2017•provide funds for cash distributions to unitholders and the General Partner in respect of any one or more of the next four quarters.Incentivecan be found under Note 14-Cash DistributionsThe incentive distribution provisions of the Partnership Agreement provide that the General Partner receives 15 percent of quarterly amounts distributed in excess of $0.81 per common unit, and a maximum of 25 percent of quarterly amounts distributed in excess of $0.88 per common unit, provided the balance has been first distributed to unitholders on a pro rata basis. The amounts that trigger incentive distributions at various levels are subject to adjustment in certain events, as described in the Partnership Agreement.Incentive distributions are paid to our General Partner if quarterly cash distributions on the common units exceed levels specified in the Partnership Agreement. 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 IDRs.In 2017, we paid incentive distributions to our General Partner of approximately $10 million (2016 – $6 million).Distributions to Class B unitsOn January 23, 2018, the board of directors of our General Partner declared distributions to Class B unitholders in the amount of $15 million which amount was paid on February 13, 2018. In 2017, the Class B distribution was $22 million. The Class B distribution represents an amount based upon 30 percent of GTN's distributable cash flow exceeding certain annual thresholds.Please read Notes 7, 10, 13 and 14 within Part IV, Item 15. "Exhibits“Exhibits and Financial Statement Schedules" for more detailed disclosures on the Class B units."Management's“Management’s Discussion and Analysis of Financial Condition and Results of Operations."(millions of dollars, except per common unit amounts) 2017 2016(a) 2015(a) 2014(a) 2013(a)(b) Income Data (for the year ended December 31) Transmission revenues 422 426 417 410 410 Equity earnings(c) 124 97 97 88 67 Impairment of equity-method investment(d) – – (199 ) – – Net income 263 263 58 241 221 Net income (loss) attributable to controlling interests 252 248 37 195 174 Basic and diluted net (loss) income per common unit $3.16 $3.21 (e) $(0.03) (e) $2.67 (e) $2.13 (e) Cash Flow Data (for the year ended December 31) Cash distribution declared per common unit $3.94 $3.71 $3.51 $3.33 $3.21 Balance Sheet Data (at December 31) Total assets 3,559 3,354 3,459 (f) 3,802 (f) 3,867 (f) Long-term debt (including current maturities) 2,403 1,911 1,971 (f) 1,778 (f) 1,679 (f) Partners' equity 1,068 1,272 1,391 1,818 2,013 (millions of dollars, except per common unit amounts) 2020 2019 2018 2017 2016 (a) Income Data (for the year ended December 31) Transmission revenues 399 403 549 (d) 422 426 170 160 173 124 97 — — 59 — — — — 537 — — Net income (loss) 301 297 (165) 263 263 Net income (loss) attributable to controlling interests 284 280 (182) 252 248 Basic and diluted net (loss) income per common unit $ 3.90 $ 3.74 $ (2.68) $ 3.16 $ 3.21 (e) Cash Flow Data (for the year ended December 31) Cash distribution declared per common unit $ 2.60 $ 2.60 $ 2.60 $ 3.94 $ 3.71 Balance Sheet Data (at December 31) Total assets 3,145 2,853 2,899 3,559 3,354 Long‑term debt, net 1,768 1,880 2,072 2,352 1,859 Partners’ equity 833 760 699 1,068 1,272 for all periods presented as a result of an additional 11.81 percent in PNGTS that was acquired from a subsidiary of TransCanadaTC Energy on June 1, 2017. Prior to this transaction, the Partnership owned a 49.9 percent interest in PNGTS that was acquired from TransCanadaTC 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"TC PipeLines, LPAnnual Report2017 45(b)Recast information to consolidate GTN and Bison for all periods presented as a result of additional 45 percent membership interests in each of GTN and Bison that were acquired from subsidiaries of TransCanada in 2013 resulting in a 70 percent ownership in each. Please read Note 2,Policies – Basis of Presentation section of the Notes to the Consolidated Financial Statements included in Part IV Item 15. "Exhibits“Exhibits and Financial Statement Schedules"(c)investee'sinvestee’s earnings and do not include any impairment charge on our equity investments.(d)During the fourth quarter of 2015, we recognized an impairment charge on our investment in Great Lakes amounting to $199 million. No other impairment was recognized during the periods presented. The equity earnings as presented in 2015 did not include this impairment charge. 5-Equity Investments,4 – Goodwill and Regulatory, Notes to the Consolidated Financial Statements included in Part IV Item 15. "Exhibits“Exhibits and Financial Statement Schedules"recast.(f)As a resultrecastManagement'sManagement’s Discussion and Analysis of Financial Condition and Results of OperationsWe 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, 20172020 audited financial statements and notes included in Part IV, within Item 15. "Exhibits“Exhibits and Financial Statement Schedules".Schedules.” Our discussion and analysis includes the following:BASIS OF PRESENTATION;•BASIS OF PRESENTATIONSee Note 2 of the Partnership's consolidated financial statements included in Part IV within Item 15. "Exhibits and Financial Statement Schedules", for important information on the content and comparability of our historical financial statements.The initial acquisition of a 49.9 percent interest in PNGTS on January 1, 2016 and additional 11.81 percent on June 1, 2017 (collectively, the PNGTS Acquisitions) were accounted for as transaction between entities under common control, which are required to be accounted for as if the PNGTS Acquisitions had occurred at the beginning of the year, with financial statements for prior periods recast to furnish comparative information. Accordingly, the accompanying historical financial information has been recast, except net income (loss) per common unit, to consolidate PNGTS for all periods presented.Also, on June 1, 2017, the Partnership acquired from subsidiaries of TransCanada a 49.34 percent interest in Iroquois (Refer to Note 7 of the Partnership's consolidated financial statements included in Part IV within Item 15. "Exhibits and Financial Statement Schedules"). This transaction was accounted prospectively and formed part of the accompanying financial information effective June 1, 2017.46 TC PipeLines, LPAnnual Report2017Netwas $252of $284 million or $3.16$3.90 per common unit compared to $280 million or $3.74 per common unit in 20172019income of $248$280 million or $3.21$3.74 per common unit in 2016. Net income attributable to controlling interests increased by $4201920172020, respectively compared to 2016. Cash$460 million and $517 million in 2019, respectivelydeclaredtotaling $2.60 per common unit, increased by six percent from $3.71or $0.65 per quarter, for both 2020 and 2019in 2016 to $3.94 per common unit in 2017.Our EBITDA increased by three percent to $445 million and Distributable cash flow decreased by one percent to $310 million. Please see "Non-GAAP Financial Measures: EBITDA, Adjusted EBITDA and Distributable Cash Flow"Flows.Outlook of Our BusinessTransCanada, the ultimate parent company of our General Partner, is currently advancing CAD $23 billion of near-term capital projects, together with a number of other larger, commercially secured initiatives. TransCanada continues to view us as a core element of its strategy and we continue to expect to play a meaningful role in funding a portion of TransCanada's near-term capital growth program depending on market conditions and TransCanada's financing needs.Our focus remains on the optimization of our asset portfolio and may include organic growth over time. We will continue to advance business opportunities over time that fit within our geographic footprint and invest in the ongoing safe and reliable operations of our pipeline assets.Over the near term, we expect our assets to perform consistently due to high contract levels, positive market fundamentals and regulatory stability. The recent long-term contract between Great Lakes and TransCanada provides long-term contract stability for Great Lakes. Other opportunities for recontracting and expansion exist throughout our portfolio, including further benefits on GTN from upstream debottlenecking activities on related TransCanada pipelines. Continued high rates of utilization of our pipelines may require somewhat higher levels of investment in maintenance compared to recent years, but we expect that these investments will be reflected in rates in future years. operating cash flow and current operating profitability. It measures our earnings from our pipeline systems before certain expenses are deducted.earningsEarnings and Adjusted earningsEarnings per common unitDuring 2015, we have evaluatedour investment in Great Lakes recognized during Bison’s remaining balance of property, plant and equipment; andfourth quarter 2015. $59 million impairment charge related to Tuscarora’s goodwill.itthis is not reflective of the results ofour underlying operations during the period.periods presented. Therefore, in 2015, we have presented Adjusted EBITDA, Adjusted earnings and Adjusted earnings per common unit as non-GAAP financial measures that excludedexclude the impact2018 impacts of the $199$596 million non-cash impairment charge.Forcharges and the years ended December 31, 2017 and 2016, we do not have anyone-time $97 million revenue item relating to Bison’s contract terminations. We had no similar adjustments in EBITDA, earnings or earnings per common unit. Accordingly, for the years ended December 31, 20172020 and 2016, our EBITDA is the same as Adjusted EBITDA and our GAAP earnings and GAAP earnings per common unit were not adjusted.TC PipeLines, LPAnnual Report2017 47"Non-GAAP“Non-GAAP Financial Measures: EBITDA, Adjusted EBITDA and Distributable Cash Flow"Flow” for more information. we have 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.20172020 Compared with the Year Ended December 31, 2016(unaudited)
(millions of dollars, except per common unit amounts) 2017 2016(a) $
Change(d) %
Change(c) Transmission revenues 422 426 (4 ) (1 ) Equity earnings 124 97 27 28 Operating, maintenance and administrative (103 ) (92 ) (11 ) (12 ) Depreciation (97 ) (96 ) (1 ) (1 ) Financial charges and other (82 ) (71 ) (11 ) (15 ) Net income before taxes 264 264 – – Income taxes (1 ) (1 ) – – Net Income 263 263 – – Net income attributable to non-controlling interests 11 15 4 27 Net income attributable to controlling interests 252 248 4 2 Net income per common unit 3.16 3.21 (b) (0.05 ) (2 ) (unaudited) $ % (millions of dollars, except per common unit amounts) 2020 2019 Transmission revenues 399 403 (4) (1) Equity earnings 170 160 10 6 Operating, maintenance and administrative (100) (105) 5 5 Depreciation (89) (78) (11) (14) Financial charges and other (73) (83) 10 12 Net income (loss) before taxes 307 297 10 3 Income taxes (6) 1 (7) * Net income (loss) 301 298 3 1 Net income attributable to non‑controlling interests 17 18 (1) (6) Net income (loss) attributable to controlling interests 284 280 4 1 284 280 4 1 Net income (loss) per common unit 3.90 3.74 0.16 4 3.90 3.74 0.16 4 Financial information was recast to consolidate PNGTS for all periods presented. Please see "Basis of Presentation" section for more information.(b)Net incomepriorare non-GAAP financial measures for which reconciliations to recast.(c)Netincreased by $4and adjusted earnings of $284 million to $252 million in 2017 compared to $248$280 million for the same period in 2016,2019, resulting in a net income per common unit during the year of $3.16 after allocations$3.90 compared to the General Partner and to the Class B units. Overall, 2017 is comparable to 2016$3.74 per common unit in 2019. This increase was primarily due to the net effect of:Transmission– from its PXP Phase II and Westbrook XPress Phase I projects, both of which entered into service in November 2019, and from PXP Phase III, which entered into service in November 2020 partially offset by lower discretionary services sold by PNGTS in 2020 compared to 2019 due to more moderate weather conditions in early 2020;$4$10 million increase was largely due to the followinglower contracted and discretionary revenues on PNGTS and lower transportation rates on Tuscarora as a result of the settlement reached with its customers effective August 1, 2016decrease in TC Energy's allocated costs related to personnel partially offset by higher discretionary revenues on short-term services sold byoperating costs related to our pipeline systems' compliance programs and costs incurred related to the planned TC Energy Merger.North Baja.Equity earnings – negative salvage allowance recorded for PNGTS during the period.$27$10 million decrease was primarily attributable to the following:the addition of equity earnings from Iroquois, effective June 1, 2017.48 TC PipeLines, LPAnnual Report2017Operating, maintenance and administrative costs – The $11 millionan increase was mainly attributable to higher pipeline integrity costs on GTN and overall higher allocated management and operational expenses on our pipeline systems as performed by TransCanada.Financial charges and other – The $11 million increase was mainly attributable to additional borrowings to finance the 2017 Acquisition.Net-income attributable to non-controlling interests – The Partnership had a net decrease amounting to $4 million primarilyin PNGTS' deferred taxes due to lower earnings from PNGTS as a result ofchange in New Hampshire's Business Profits Tax rate effective in 2021 and an increase in PNGTS' current income taxes due to its lower revenues.20162019 Compared with the Year Ended December 31, 2015(unaudited)
(millions of dollars, except per common unit amounts) 2016(a) 2015(a) $
Change(d) %
Change(d) Transmission revenues 426 417 9 2 Equity earnings 97 97 – – Impairment of equity-method investment – (199 ) 199 100 Operating, maintenance and administrative (92 ) (97 ) 5 5 Depreciation (96 ) (95 ) (1 ) (1 ) Financial charges and other (71 ) (63 ) (8 ) 13 Net income before taxes 264 60 204 * Income taxes (1 ) (2 ) 1 50 Net Income 263 58 205 * Net income attributable to non-controlling interests 15 21 6 29 Net income attributable to controlling interests 248 37 211 * Adjusted earnings(b) 248 236 12 5 Net income (loss) per common unit(c) 3.21 (0.03 ) 3.24 * Adjusted earnings per common unit(b) 3.21 3.03 0.18 6 (a)Financial information was recast to consolidate PNGTS. Please see "Basis20182019 2018 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 * 280 317 (37) (12) Net income (loss) per common unit 3.74 (2.68) 6.42 * 3.74 4.18 (0.44) (11) for below.(c)Net income (loss) per common unit prior to recast.(d)Netincreased by $211of $280 million to $248 million in 2016 compared to $37a loss of $182 million for the same period in 2015,2018, resulting in a net income per common unit during the year of $3.21 after allocations$3.74 compared to the General Partner and to the Class B units. This increasea loss $2.68. The loss in 2018 was primarily the result ofdue to the recognition of a $199non-cash impairments relating to Bison’s property, plant and equipment and Tuscarora’s goodwill partially offset by the $97 million non-cash impairment charge to our investmentrevenue proceeds from Bison’s contract terminations in Great Lakes inthe fourth quarter 2015 which lowered our net income attributable to controlling interests in 2015. (Seeof 2018. See Part II, Item 7. "Management’s Discussion and Analysis of Financial Condition and Results of Operations – Critical Accounting Estimates – Impairment of Equity Investments, Goodwill, and Long-Lived Assets –and Equity InvestmentsInvestments" section for more information.)TC PipeLines, LPAnnual Report2017 49The Partnership's details.were higherwas lower by $12$37 million in 2016 compared to 2015, an increasefor the year ended December 31, 2019, a decrease of $0.18$0.44 per common unit mainly due to the following:Transmission revenues – increase of $9 millionunit. This decrease was primarily due to the net effect of:•higher discretionaryGTN from short-term services sold to its customers;•lower discretionary revenues on PNGTS from short-term services sold to its customers;•full year of revenues from GTN's Carty lateral system which was placed into service in October 2015; and•lower transportation rates on GTNour pipelines as a result of the settlement reached with its customers effective July 1, 2015.Operating, maintenance and administrative – generally lower expenses in 20162018 FERC Actions were primarily offset by increased discretionary revenue as a result of lower operational costs onstrong natural gas flows mainly out of WCSB and solid contracting across our consolidated entities. Additionally, dropdown costs were incurred in 2015 related to the acquisition of the initial 49.9 percent interest in PNGTS.Financial charges and otherConsolidated Subsidiaries. See also Part I, Item 1. “Business – $8Government Regulations – 2018 FERC Actions.”increasedecrease was primarily due to the net effect of:•additional borrowings to fund a portion of our recent acquisitionslower interest incurred by PNGTS2016 principal payments onrevenue. 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; andlong term debt•no interestrevenue 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 incurredan increase in 2016 on PNGTS' rate refund liability dueits operating costs related to the payment of all of PNGTS' outstanding rate refund liability on April 15, 2015. (Referits compliance programs, estimated costs related to Note 2right-of-way renewals and an increase in TC Energy's allocated management and corporate support functions expenses and common costs such as insurance.Significant Accounting Policies – Revenue Recognition section, Notes to Consolidated Financial Statements includedThe increase in Part IV within Item 15. "Exhibitsoperation and Financial Statement Schedules")Net income attributable to non-controlling interests – $6 million decreasemaintenance expenses was primarily due to the Partnership's 100 percent ownershipoverall net impact of the following:GTN effective April 1, 2015.Reconciliation of Net income attributable to controlling interests to Adjusted earnings(millions of dollars)
Year ended December 31 2017 2016 2015 Net income attributable to controlling interests 252 248 37 Add: Impairment of equity-method investment – – 199 Adjusted earnings 252 248 236 Reconciliation of Net income per common unit to Adjusted earnings per common unitYear ended December 31 2017 2016 2015 Net income (loss) per common unit-basic and diluted(b) 3.16 3.21 (a) (0.03 )(a) Add: per unit impact of impairment of equity-method investment(c) – – 3.06 Adjusted earnings per common unit 3.16 3.21 3.03 (a)Net income per common unit prior to recast.50 Reconciliation of Net income (loss) attributable to controlling interests to Adjusted earnings (millions of dollars) Year ended December 31 2020 2019 2018 Net income attributable to controlling interests 284 280 (182) Add: Impairment of goodwill — — 59 Add: Impairment of long-lived assets — — 537 Less: Revenue proceeds from Bison’s contract terminations — — (97) Adjusted earnings 284 280 317 2017 2020 51Reconciliation of Net income (loss) per common unit to Adjusted earnings per common unit Year ended December 31 2020 2019 2018 3.90 3.74 (2.68) Add: per unit impact of impairment of goodwill — — 0.81 (b) Add: per unit impact of impairment of long-lived assets — — 7.38 (c) Less: per unit impact of revenue proceeds from Bison’s contract terminations — — (1.33) (d) Adjusted earnings per common unit 3.90 3.74 4.18 1314 of the Partnership'sPartnership’s consolidated financial statements included in Part IV. Item 15. 'Exhibits"Exhibits and Financial Statement Schedules"Schedules” for details of the calculation of net income (loss) per common unit.(c)$199$59 million impairment charge, after deduction of amounts attributable to the General Partner with respect to its effective two percent interest, by the weighted average number of common units outstanding during the period.public offerings of debt and equity, term loans and our bank credit facility.facilities. The Partnership funds its operating expenses, debt service and cash distributions (including those distributions made to TransCanadaTC Energy through our General Partner and as holder of all our Class B units) primarily withfrom operating cash flow. Long-term capital needs may be met through the issuance ofequity. Overall,refinance the current portion of our long-term debt.that our pipeline systems' ability to obtain financing at reasonable rates, together with a history of consistent cash flow from operating activities, provide a solid foundation to meet future liquidity and capital requirements. We expect to be ablewe are well positioned to fund our liquidity and capital resource requirements, includingobligations as required.distributions and required debt repayments, at the Partnership level over the next 12 months utilizing our(1) cash flow and, if required, our existing Senior Credit Facility. The following table sets forth theon hand, (2) operating cash-flows, (3) $500 million available borrowing capacity under the Partnership'sour Senior Credit Facility:(unaudited)
(millions of dollars)
December 31 2017 2016 2015 Total capacity under the Senior Credit Facility 500 500 500 Less: Outstanding borrowings under the Senior Credit Facility 185 160 200 Available capacity under the Senior Credit Facility 315 340 300 systems'systems’ principal sources of liquidity are cash generated from operating activities, long-term debt offerings, bank credit facilities and equity contributions from their owners. OurExcept as noted below, our pipeline systems have historically fundedexpect to fund their respective expansion projects primarily with debt. Except as noted below, our pipeline systems' normal recurring operating expenses, maintenance capital expenditures, debt service and cash distributions toare primarily funded with their owners primarily with operating cash flow. However, sinceflows.owners. Additionally, on September 1, 2017,owners and we have contributed approximately $10 million each for 2020 and 2019 and $9 million for 2018.Northern BorderIroquois of $83 million.approximately $2 million and $4 million, respectively. This amount representsrepresented the Partnership's 50Partnership’s 49.34 percent share of a onecash call from Iroquois to cover costs of regulatory approvals related to their ExC Project.$166 millionto time, Northern Border requests equity contributions from or makes returns of capital contribution requestdistributions to its partners to manage its preferred capitalization levels. In June 2019, we received a return of capital distribution from Northern Border amounting to reduce$50 million and used those proceeds to partially repay our 2013 Term Loan Facility due in 2021.outstanding balanceflow of its revolver debtnatural gas on Bison in both directions, with the southwest direction involving deliveries onto third party pipelines and ultimately connecting into the Cheyenne hub. In any event, Bison will continue to increase its available borrowing capacity.Capitalincur costs related to property tax and operating and maintenance costs of approximately $6 million per year.including cash generated from operating activities, borrowings under bank credit facilities, issuance of senior unsecured notes or equity contributions from our pipeline systems' owners.as noted above. The ability of our pipeline systems to access the debt capital markets under reasonable terms depends onupon their financial positioncondition and generalprevailing market conditions.Partnership'sPartnership’s pipeline systems monitor the creditworthiness of their customers and have credit provisions included in their tariffs which, although limitedgoverned by FERC, allow them to request a certain amount of credit support as circumstances dictate.TC PipeLines, LPAnnual Report2017 51Year Ended December 31,
(millions of dollars) 2017 2016(a) 2015(a) Net cash provided by (used in): Operating activities 376 417 260 Investing activities (761 ) (230 ) (326 ) Financing activities 354 (178 ) (32 ) Net increase in cash and cash equivalents (31 ) 9 (98 ) Cash and cash equivalents at beginning of the period 64 55 153 Cash and cash equivalents at end of the period 33 64 55 (a)Financial information was recast to consolidate PNGTS. Please see "Basis of Presentation" section for more information.2020 2019 2018 Net cash provided by (used in): Operating activities 413 412 540 Investing activities (262) (32) (35) Financing activities (34) (330) (505) Net increase in cash and cash equivalents 117 50 — Cash and cash equivalents at beginning of the period 83 33 33 Cash and cash equivalents at end of the period 200 83 33 20172020 compared to Same Period in 2016Net cash provideddecreasedof equity investments. The slight decrease in distributions from operating activities of equity investments was due to the net impact of the following:$41additional surplus cash distribution received from Iroquois in the third quarter of 2019 as a result of the cash it accumulated during the previous year's earnings.20172020 compared to a net debt repayment of $106 million for the same period in 2016 primarily due to:•lower cash generated from operating activities of our subsidiaries primarilythe prior year, largely due to its lower revenues and higher operating costs as discussed in "Results of Operations" section;•higher financing costs incurred as a result ofexecuted for the 2017 Acquisition; and•lower distributions from Great Lakes and Northern Border in 2017 partially offset by distributions received from Iroquois, resulting from the addition of Iroquois to our portfolio of assets effective June 1, 2017. Distributions received in the first quarter of 2016 from Great Lakes were higher than distributions received in the first quarter of 2017 on a run-rate basis due to the resolution of certain regulatory proceedings in the fourth quarter of 2015 which inflated its results during that period and resulted in higher cash flow. The increase in cash flow was paid to the Partnership in the first quarter of 2016 and was not applicable in the first quarter of 2017. Additionally, the Partnership received lower distributions from Northern Border in 2017 compared to the same period in 2016 primarily due to higher maintenance capital expenditures during the current 2017 period together with the change in Northern Border's distribution policy during 2016 from a lagged quarterly distribution to a more timely monthly distribution that resulted in a larger distribution in the second quarter of 2016.Investing Cash FlowsNet cash used in investing activities increased by $531 million in the twelve months ended December 31, 2017 compared to the same period in 2016. On June 1, 2017, we invested $593 million to acquire a 49.34 percent interest in Iroquoison our GTN XPress, PXP and $53 million to acquire an additional 11.81 percent of PNGTS. Additionally, on September 1, 2017, we contributed $83 million to Northern Border representing our 50 percent share of a requested capital contribution to reduce the outstanding balance of its revolving credit facility. During 2017, we also received a $5 million distribution from Iroquois as a return of surplus cash on their balance sheet. Together, these transactions resulted in the net increase of $531 million compared to 2016 where we invested $193 million on January 1, 2016 to acquire a 49.9 percent interest in PNGTS.Financing Cash FlowsThe net change in cash from our financing activities was approximately $532 million in the twelve months ended December 31, 2017 compared to the same period in 2016 primarily due to the net effect of:•$552 million increase in net issuances of debt in 2017 primarily to finance the 2017 Acquisition;•$34 million increase in distributions paid to our common units and to our General Partner in respect of its two percent general partner interest and IDRs;52 TC PipeLines, LPAnnual Report2017•$10 million increase in distributions paid to Class B units in 2017 as compared to 2016;•$9 million increase in our At-the-market (ATM) equity issuances in 2017 as compared to 2016;•$7 million decrease in distributions paid to non-controlling interest due to lower revenues on PNGTS compared to the previous periods; and•$8 million decrease in distributions paid to TransCanada as the former parent of PNGTS primarily due to the Partnership's acquisition of a 49.9 percent interest in PNGTS effective January 1, 2016 and additional 11.81 percent effective June 1, 2017.20162019 compared to Same Period in 2015Netincreaseddecreased by $157$128 million compared to the same period in 2018 primarily due to the net effect of:20162019 compared to the same period in 20152018 primarily due to the net effect of:higher earnings as discussedmore detailnet debt repayments;the "Results of Operations" section.•higher distributed earnings received from equity investments in 2016distributions paid to common unitholders as a result of additional revenues from new contracts with ANR Pipeline Company (ANR), a related party•payment of all of PNGTS' outstanding rate refund liabilitylower per unit declaration beginning in 2015, including interest as a result of its rate case settlement approved by FERC on February 2015. Total refunds accumulated to $114 million, including $8 million of interest, and were paid to customers on April 15, 2015. (Refer to Note 2 – Significant Accounting Policies – Revenue Recognition section, Notes to Consolidated Financial Statements includedsecond quarter 2018 in Part IV within Item 15. "Exhibits and Financial Statement Schedules") and•timing of working capital changes. The majority of the timing impact relatesresponse to the settlement of our accounts payable and accrued liabilities.Investing Cash FlowsNet cash used in investing activities decreased by $96 million in the twelve months ended December 31, 2016 compared to the same period in 2015 as we invested a lesser amount on our initial 49.9 percent acquisition of interest in PNGTS compared to our investment during the same period in 2015. In 2015, we paid $264 million to acquire the remaining 30 percent interest in GTN compared to $193 million paid for the acquisition of a 49.9 percent interest in PNGTS in 2016. Additionally, we had higher capital expenditures in 2015 due to expenditures related to the construction of the Carty Lateral.Financing Cash FlowsNet cash used in financing activities increased by $146 million in the twelve months ended December 31, 2016 compared to the same period in 2015 primarily due to the net effect of:254 million decrease in net issuances of debt in 2016 as compared with 2015;•$123 million increase in our ATM equity issuances in 2016 as compared with 2015;•$228 million increase in distributions paid to our common units including our General Partner's effective two percent share and its related IDRs;122 million ofdecrease in distributions paid to Class B units in 2016;940 million decrease in distributions paid to non-controlling interest due to the Partnership's 100 percent ownershipcash from equity issuances in GTN effective April 1, 2015; and•$10 million decrease in distributions paid to TransCanada2019 as the former parentAt-the-market Equity Issuance program (ATM program) was suspended during the first quarter of PNGTS due to the Partnership's acquisition of a 49.9 percent interest in PNGTS effective January 1, 2016.TC PipeLines, LPAnnual Report2017 53Partnership'sPartnership’s share in capital spending for maintenance of existing facilities and growth projects was as follows:Year Ended December 31
(millions of dollars)
(unaudited) 2017 2016(a) 2015(a) Maintenance 63 31 21 Growth 3 5 54 Total(b) 66 36 75 (a)Financial information was recast to reflect our 61.71 percent shareYear Ended December 31 (millions of dollars) (unaudited) 2020 2019 2018 Maintenance 156 76 60 Growth 165 26 7 321 102 67 Partnership'sPartnership’s proportionate share of maintenance and growth capital expenditures of the Partnership'sPartnership’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.20172020 Compared with the Year Ended December 31, 2016$32$80 million in 20172020 compared to 20162019 mainly due to overhaulsincreased normal-course maintenance spending at GTN along with the one-time purchase of a commercial IT system by several of our pipelines. The increased maintenance capex at GTN on its compressor fleet resulted from higher throughput, operating hours and pipeline integrity projects on GTN in addition to continuingstrong demand for natural gas transportation. Additionally, there were also higher normal course compressor station overhauls that began in 2016overhaul spending on Northern Border.were comparableincreased by $140 million between 20172020 and 2016.20162019 Compared with the Year Ended December 31, 2015$10$16 million in 20162019 compared to 20152018 mainly due to increases in major equipment overhauls conducted in 2016and 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 and Great Lakes andBorder. Additionally, in 2018, PNGTS incurred costs relatedon upgrading one of its existing meter communication systems to pipe integrity on Great Lakes and North Baja.In 2015, The Partnership incurred significant spending related to the construction of Carty Lateral.meet current commercial pressure obligations. No such significant project occurred in 2016.20172020 distribution of $15$16 million on January 8, 2018,15, 2021, of which the Partnership received its 50 percent share or $7$8 million on January 31, 2018.20182021 distribution of $17$18 million on February 14, 2018,16, 2021, of which the Partnership will receive its 50 percent share or $9 million on February 28, 2018.20172020 distribution of $20$23 million on January 10, 2018,13, 2021, of which the Partnership received its 46.45 percent share or $9$11 million on February 1, 2018.20172020 distribution of $29$22 million on January 22, 2018,February 18, 2021, of which the Partnership receivedwill receive its 49.34 percent share or $14$11 million on February 1, 2018.$9$14 million contribution in 20182021 to Great Lakes to fund debt repayments of Great Lakes which is consistent with prior years.54 TC PipeLines, LPAnnual Report20172018,2021, our pipeline systems expect to invest approximately $76$145 million in maintenance ofcapital for existing facilities, of which the Partnership’s share will be $109 million. The Partnership’s estimated capital maintenance costs do not include any costs related to our GTN XPress Project (see further discussion below). Maintenance capital expenditures are added to our pipelines’ respective rate bases and are expected to earn a return on and of capital over time through the regulatory rate-making process.$27$306 million in growth projects in 2021, of which the Partnership'sPartnership’s share wouldwill be $53$265 million. 2021 growth capital expenditures will include an estimated $145 million of Phase I GTN XPress Project costs, which are reliability and horsepower replacement expenditures expected to be fully recoverable in GTN’s recourse rates commencing in 2022, along with other ongoing growth projects as discussed in Part 1, Item 1. “Business - Recent Business Developments.” As of December 31, 2020 and 2019, we have incurred approximately $83 million and $15$5 million, respectively. respectively of Phase 1 GTN XPress Project costs, which were included in the tabular summary above.$4$86 million as of December 31, 20172020 in connection with various maintenance and general plant projects over the next two years.23, 2018,19, 2021, the board of directors of our General Partner declared the Partnership'sPartnership’s fourth quarter 20172020 cash distribution in the amount of $1.00$0.65 per common unit which was paid on February 13, 201812, 2021 to unitholders of record as of February 2, 2018.January 29, 2021. The total amount of cash distribution paid to common unitholders and General Partner was $76$47 million.23, 2018,19, 2021, after reviewing GTN's 2020 distributable cashflows, the board of directors of our General Partner declaredTC PipeLines Board did not declare distributions to Class B unitholders in the amount of $15 million which was paid on February 13, 2018.as certain thresholds for a distribution to be made were not exceeded. The Class B distribution represents an amount equal to 30 percent of GTN'sGTN’s distributable cash flow during the year ended December 31, 20172020 less the threshold level of $20 million. For 2018,million and other adjustments that would further reduce the threshold levelamount attributed to Class B unitholders. Beginning in 2021, we expect the impact of the Class B distribution on our cashflows to be significantly lower compared to previous periods.samePartnership’s $500 million Senior Credit Facility.anticipate such thresholdexpect any outstanding balance will be exceeded inrepaid if the third quarterTC Energy Merger closes, or refinanced or extended prior to maturity if the TC Energy Merger does not close.2018.7,8, 10, 13 and 14, Notes to Consolidated Financial Statements included in Part IV, within Item 15. "Exhibits“Exhibits and Financial Statement Schedules".approximately $80 million PXP project,majority of the capital for our growth projects as further discussed in Part 1, Item 1. Business-Recent Business Developments,the "Investing Cash Flow Outlook" section above is expected to be financed through a new credit facility at PNGTS.and Distributable Cash Flow,income. It measures our earnings before deducting interest, taxes, depreciation and amortization,income, which includes net income attributable to non-controlling interests, and it includes earnings from our equity investments.in 2015 excludes the 2018 impact of the $199following non-recurring items:non-cashrecognized as revenue during the fourth quarter of 2018;we recognized on our investment in Great Lakes. to Bison’s current carrying value; andthe charge isthese items are significant but not reflective of our underlying operations. For the years ended December 31, 20172020 and 2016,2019, we do not have any similarnon-recurring adjustments in our Adjusted EBITDA. Accordingly,yearstwelve months ended December 31, 20172019 and 20162018 was recast to conform with the current presentation. The Partnership believes the revised presentation more closely aligns with similar non-GAAP financial measures presented by our EBITDA ispeers and with the same as Adjusted EBITDA.EBITDAplus:Distributions from our equity investments less:AFUDC,
Earnings from our equity investments,•Equity allowance for funds used during construction (Equity AFUDC),•IncomeDistributions to TransCanada as former parent of PNGTS, and•TC PipeLines, LPAnnual Report2017 55effective two percent interest plus, if applicable, an amount equal to incentive distributions. Distributions allocable to the Class B units in 2020 equal 30 percent of GTN'sGTN’s distributable cash flow forless $20 million, the yearsresidual of which is further multiplied by 43.75 percent. (Class B Distribution) (2019 and 2018 - less $20 million only).20172020, 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 December 31, 2016, less $20 million (2015 – less $15 million).performance.informationresults prepared in accordance with GAAP. Additionally, these measures as presented may not be comparable to similarly titled measures of other companies.56 2017 2020 57Year Ended December 31
(unaudited)
(millions of dollars) 2017 2016(a) 2015(a) Net income 263 263 58 Add: Interest expense(b) 84 73 68 Depreciation and amortization 97 96 95 Income taxes 1 1 2 EBITDA 445 433 223 Impairment of equity investment – – 199 ADJUSTED EBITDA 445 433 422 Add: Distributions from equity investments(c) Northern Border 82 91 91 Great Lakes 38 34 40 Iroquois 41 (d) – – 161 125 131 Less: Equity earnings: Northern Border (67 ) (69 ) (66 ) Great Lakes (31 ) (28 ) (31 ) Iroquois (26 ) – – (124 ) (97 ) (97 ) Less: Equity AFUDC – – (1 ) Interest expense(b) (84 ) (73 ) (68 ) Income taxes (1 ) (1 ) (2 ) Distributions to non-controlling interests(e) (14 ) (18 ) (29 ) Distributions to TransCanada as PNGTS' former parent(f) (2 ) (6 ) (30 ) Maintenance capital expenditures(g) (38 ) (16 ) (16 ) (139 ) (114 ) (146 ) Total Distributable Cash Flow 343 347 310 General Partner distributions declared(h) (18 ) (12 ) (8 ) Distributions allocable to Class B units(i) (15 ) (22 ) (12 ) Distributable Cash Flow 310 313 290 2020 2019 2018 Net income (loss) 301 298 (165) Add (Less): 83 85 94 Depreciation and amortization 89 78 97 Income tax expense (benefit) 6 (1) 1 EBITDA 479 460 27 Add (less): Non-recurring items Impairment of goodwill — — 59 Impairment of long‑lived assets — — 537 Bison contract terminations — — (97) Less: Equity earnings: Northern Border (76) (69) (68) Great Lakes (56) (51) (59) Iroquois (38) (40) (46) (170) (160) (173) Add: Northern Border 90 93 85 Great Lakes 43 55 66 46 69 56 179 217 207 ADJUSTED EBITDA 488 517 560 Less: AFUDC (11) (2) (1) (83) (85) (94) (3) (1) (1) (22) (21) (20) (110) (56) (36) (229) (165) (152) Total Distributable Cash Flow 259 352 408 (4) (4) (4) — (8) (13) Distributable Cash Flow 255 340 391 Financial information was recast to consolidate PNGTS. Please see "Basis of Presentation" section for more information.(b)PNGTS'PNGTS’ derivative instruments and does not include amortization of debt issuance and discount costs (Refer to Notes 12 and 19, Notes to Consolidated Financial Statements included in Part IV, within Item 15. "Exhibits“Exhibits and Financial Statement Schedules"Schedules”).(c)entities' quarterlyentities’ distributable cash during the current reporting period.TC PipeLines, LPAnnual Report2017 57(d)fromfor the second to fourth quartercurrent reporting period and excludes any distributions received that are considered return of 2017 andinvestment. It also includes our 49.34 percent share of the Iroquois unrestricted cash distribution amounting to approximately $8$10 million for the seven monthsboth years ended December 31, 2017.2019 and December 31, 2018 (2020 - none). In 2020 and 2019, we also received an additional distribution of $4 million and $15 million, respectively related to the increase in the cash Iroquois generated from its higher income in 2017 (post acquisition) to 2020. (Refer to Notes 5 and 7, Notes to Consolidated Financial Statements included in Part IV, within Item 15. "Exhibits“Exhibits and Financial Statement Schedules"Schedules”).entities'entities’ distributable cash not owned by us during the periods presented.Distributions to TransCanada as PNGTS' former parent represent TransCanada's respective share of PNGTS' distributable cash not owned by us during the periods presented.(g)Partnership'sPartnership’s maintenance capital expenditures include expenditures made to maintain, over the long term, our assets'assets’ operating capacity, system integrity and reliability. Accordingly, this amount represents the Partnership'sPartnership’s and its consolidated subsidiaries'Consolidated Subsidiaries’ maintenance capital expenditures and does not include the Partnership'sPartnership’s share of maintenance capital expenditures on our equity investments. Such amounts are reflected in "Distributions“Distributions from equity investments"investments” as those amounts are withheld by those entities from their quarterly distributable cash.Partnership'sPartnership’s total proportionate share of maintenance capital expenditures from our consolidated entities and equity investments.(h)2017 included an2020, 2019 and 2018 did not include any incentive distribution of approximately $12 million (2016 – $7 million; 2015 – $3 million).(i)During the twelve months ended December 31, 2017, 30 percent of GTN's total distributions was $35 million; therefore, the distributionsdistributions.was $15 million, representing the amount that exceeded the threshold level of $20 million. During the twelve months ended December 31, 2016,is based on 30 percent of GTN's total distributions was $42 million; therefore,GTN’s distributable cashflow during the distributions allocable to the Class B units was $22 million, representing the amount that exceeded the threshold level of $20 million. During the twelve months ended December 31, 2015, 30 percent of GTN's total distributions was $27 million; therefore, the distributions allocable to the Class B units was $12 million, representing the amount that exceeded the threshold level of $15 million. The Class B distribution is determinedcurrent reporting period but declared and payable annually.On January 23, 2018, the board of directors of our General Partner declared distributions to Class B unitholderspaid in the amount of $15 million which was paid on February 13, 2018. The 2016 Class B distribution amounting to $22 million was paid by the Partnership on February 14, 2017. Please read Notes 7,10,13 and 14, Notes to Consolidated Financial Statements forsubsequent reporting period. During the year ended December 31, included2020, no distributions were declared as certain thresholds in Part IV within Item 15. "Exhibits and Financial Statement Schedules".20172020 Compared with the Year Ended December 31, 2016and Adjusted EBITDA was $12higher for the year ended December 31, 2020 compared to the same period in 2019. The $19 million higherincrease was primarily due to the addition oflower operating costs and higher equity earnings, from Iroquois effective June 1, 2017partially offset by lower revenues and an increase in operational costs on ourrevenue from consolidated subsidiaries as discussed in more detail under the "Results“Results of Operations"Operations” section.fordecreased by $85 million during the twelve monthsyear ended December 31, 2017 was comparable2020 compared to the same period in 20162019 due to the net effect of:additionfunding of a commercial IT system purchase by GTN, Tuscarora and North Baja from a TC Energy affiliate on August 1, 2020. These expenditures will reduce future operating costs and increase our 49.34 percent sharepipelines’ respective rate bases and we anticipate will generate a return on and of distributions declared by Iroquois from the second to fourth quarter of 2017;•lower revenues from our subsidiaries and increasescapital in their operational costs as previously discussed above in "Results of Operations";financing costsmaintenance capital expenditures at GTN as a result of increased spending on major equipment overhauls at several compressor stations and certain system upgrades.2017 Acquisition;GTN's pipeline system;•lower distributable cash flow from Northern Border primarily due to its higher operating costs and higher maintenance capital expenditures;•higher distributions declared in respect of our IDRs during 2017; and•lower distributions allocable to the Class B units during 2017.58 TC PipeLines, LPAnnual Report2017Year Ended December 31, 2016 Compared with the Year Ended December 31, 2015EBITDA increased by $210 million to $433 million in 2016 compared to $223 million in 2015. The increase was primarily the result of the recognition of a $199 million non-cash impairment charge in 2015 to our investment in Great Lakes which lowered EBITDA in 2015 accordingly (See Critical Accounting Estimates – Impairment of Equity Investments, Goodwill and Long-Lived Assets – Equity Investments section for more information.)Adjusted EBITDA increased by $11 million compared to the same period in 2015 mainly due to higher transmission revenues as discussed in more detail in the Results of Operations section.Distributable cash flow increased by $23 million in the twelve months ended December 31, 2016 compared to the same period in 2015 primarily due to the net effect of:•the cash impact of higher Adjusted EBITDA;•lower distributable cash flow from our equity investmentsGTN as a result of higher maintenance capital in 2016 as discussed in more detail on the "Capital Spending" section;distributions paid to non-controlling interestsinterest expense due to the Partnership owning 100 percentfull repayment of GTN effective April 1, 2015;allocable to TransCanada as the former parent of PNGTS due to the Partnership's acquisition of 49.9 percent interest in PNGTS from TransCanada effective January 1, 2016;•higher interest expense related to higher borrowings as a result of the recent acquisitions offset by;•higher General Partner distributions due to higher IDRs in the current period; and•higher distributions allocable to the Class B units during the current period.TC PipeLines, LPAnnual Report2017 59Partnership's Contractual ObligationsThe Partnership'sPartnership’s contractual obligations as of December 31, 20172020 included the following:
Payments Due by Period (unaudited)
(millions of dollars) Total Less than
1 Year 1-3
Years 4-5
Years More than
5 Years Weighted
Average
Interest
Rate for the
Year
Ended
December 31,
2017 TC PipeLines, LP Senior Credit Facility due 2021 185 – – 185 – 2.41% 2013 Term Loan Facility due 2022 500 – – 500 – 2.33% 2015 Term Loan Facility due 2020 170 – 170 – – 2.22% 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) Unsecured Term Loan Facility due 2019 55 20 35 – – 2.02% PNGTS 5.90% Senior Secured Notes due 2018 30 30 – – – 5.90% (a) Tuscarora Unsecured Term Loan due 2020 25 1 24 – – 2.27% 2,415 51 329 1,035 1,000 Payments Due by Period Total 1‑3 Years 4‑5 Years Weighted Average Interest Rate for the Year Ended December 31,
2020TC PipeLines, LP Senior Credit Facility due 2021 — — — — — — 2013 Term Loan Facility due 2022 450 — 450 —�� — 1.87 % 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 5.69% Unsecured Senior Notes due 2035 150 — — — 150 5.69 % (a) 3.12% Unsecured Senior Notes due 2030 175 — — — 175 3.12 % (a) PNGTS Revolving Credit Facility due 2023 25 — 25 — — 1.88 % 2.84% Unsecured Senior Notes due 2030 125 — — — 125 2.84 % (a) Tuscarora — — — — — Unsecured Term Loan due 2021 23 23 — — — 2.13 % North Baja Unsecured Term Loan due 2021 50 50 — — — 1.70 % Partnership (TC PipeLines, LP and its subsidiaries) 428 71 112 93 152 Operating leases 1 1 — — — 2,627 495 587 443 1,102 Raterate debtInterestfloating-rateour fixed rate debt are based on scheduled maturities. Future interest payments on floating rate debt are estimated using debt levels and interest rates effective as of December 31, 2017.TC PipeLines, LPOn November 10, 2016, the Partnership's Senior Credit Facility was amended to extend the maturity period through November 10, 2021. The Facility consists of a $500 million senior revolving credit facility with a banking syndicate, under which $185 million was outstanding at December 31, 2017 (December 31, 2016 – $160 million), leaving $315 million available for future borrowing.At the Partnership's option, the2020 and are therefore subject to change beyond 2020. Future interest payments on floating rate debt do not include potential obligation related to our interest rate onswaps.outstanding borrowings under the Senior Credit Facility may be 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 the60 TC PipeLines, LPAnnual Report2017portion of the borrowings to be covered by specificPartnership’s debt and 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 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 2.62 percent at December 31, 2017 (December 31, 2016 – 1.92 percent).On July 1, 2013, the Partnership entered into a term loan agreement with a syndicate of lenders for a $500 million term loan credit facility (2013 Term Loan Facility). On July 2, 2013, the Partnership borrowed $500 million under the 2013 Term Loan Facility, to pay a portion of the purchase price of the 2013 Acquisition, maturing originally on July 1, 2018. On September 29, 2017, the Partnership's 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 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.As of December 31, 2017, the variable interest rate exposure related to 2013 Term Loan Facility was hedged by fixed interest rate swap arrangements and our effective interest rate was 2.31 percent (2016-2.31 percent). Prior to hedging activities, the LIBOR-based interest rate was 2.62 percent at December 31, 2017 (December 31, 2016 – 1.87 percent).On September 30, 2015, the Partnership entered into an agreement for a $170 million term loan credit facility (2015 Term Loan Facility). The Partnership borrowed $170 million under the 2015 Term Loan Facility to refinance its Short-Term Loan Facility which matured on September 30, 2015. On September 29, 2017, the Partnership's 2015 Term Loan Facility that was due on October 1, 2018 was amended to extend the maturity period through October 1, 2020. The LIBOR-based interest rate on the 2015 Term Loan Facility was 2.51 percent at December 31, 2017 (December 31, 2016 – 1.77 percent).The 2013 Term Loan Facility and the 2015 Term Loan Facility (Term Loan Facilities) and the Senior Credit Facility require the Partnership to maintain a certain leverage ratio (debt to adjusted cash flow [net income plus cash distributions received, extraordinary losses, interest expense, expense for taxes paid or accrued, and depreciation and amortization expense less equity earnings and extraordinary gains]) 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 4.70 to 1.00 as of December 31, 2017.The Senior Credit Facility and the Term Loan Facilities 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 Term Loan Facilities may become immediately due and payable.On March 13, 2015, the Partnership closed a $350 million public offering of senior unsecured notes bearing an interest rate of 4.375 percent maturing March 13, 2025. The net proceeds of $346 million were used to fund a portion of the 2015 GTN Acquisition (refer to Note 7) and to reduce the amount outstanding under our Senior Credit Facility. The indenture for the notes contains customary investment grade covenants.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 7). The indenture for the notes contains customary investment grade covenants.TC PipeLines, LPAnnual Report2017 61PNGTSPNGTS' Senior Secured Notes are secured by the PNGTS long-term firm shipper contracts and its partners' pledge of their equity and a guarantee of debt service for six months. PNGTS is restricted under the terms of its note purchase agreement from making cash distributions unless certain conditions are met. Before a distributionswaps can be made, the debt service reserve account must be fully fundedfound under Note 8 - Debt and PNGTS' debt service coverage ratio for the precedingCredit Facilities and succeeding twelve months must be 1.30 or greater. At December 31, 2017, the debt service coverage ratio was 1.72 for the twelve preceding monthsNote 19 - Fair Value measurements, respectively within Part IV, Item 15. “Exhibits and 1.53 for the twelve succeeding months. Therefore, PNGTS was not restricted to make any cash distributions.GTNOn June 1, 2015, GTN entered into a $75 million unsecured variable rate term loan facility (Unsecured Term Loan Facility),Financial Statement Schedules,” which requires yearly principal payments until its maturity on June 1, 2019. The variable interestinformation is based on LIBOR plus an applicable margin. The LIBOR-based interest rate on the Unsecured Term Loan Facility was 2.31 percent at December 31, 2017 (December 31, 2016 – 1.57 percent). GTN's Unsecured Senior Notes, along with this new Unsecured Term Loan Facility contain a covenant that limits total debt to no greater than 70 percent of GTN's total capitalization. GTN's total debt to total capitalization ratio at December 31, 2017 is 44.6 percent.TuscaroraOn August 21, 2017, Tuscarora refinanced all of its outstanding debtincorporated herein by amending its existing Unsecured Term Loan Facility and issuing a new $25 million variable rate term loan that will require yearly principal payments and will mature on August 21, 2020. 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, 2017, the ratio was 11.09 to 1.00.The LIBOR-based interest rate on the Tuscarora's Unsecured Term Loan Facility was 2.49 percent at December 31, 2017 (December 31, 2016 – 1.90 percent).Partnership (TC PipeLines, LP and its subsidiaries)At December 31, 2017, 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 fair value of the Partnership's long-term debt is estimated by discounting the future cash flows of each instrument at estimated current borrowing rates. The estimated fair value of the Partnership's long-term debt at December 31, 2017 was $2,475 million. As of February 26, 2018, the Partnership had $170 million outstanding under the Senior Credit Facility.62 TC PipeLines, LPAnnual Report2017Border'sBorder’s Contractual ObligationsBorder'sBorder’s contractual obligations as of December 31, 20172020 included the following:
Payments Due by Period(a)(unaudited)
(millions of dollars) Total Less than
1 Year 1-3
Years 4-5
Years More than
5 Years 7.50% Senior Notes due 2021 250 – – 250 – $200 million Credit Agreement due 2020 15 – 15 – – Interest payments on debt 74 20 39 15 – Other commitments(b) 53 3 5 5 40 392 23 59 270 40 Total $200 million Credit Agreement due 2024 130 — — 130 — 250 250 — — — 20 15 4 1 — 47 3 6 6 32 447 268 10 137 32 Border'sBorder’s contractual obligations.$7$15 million as of December 31, 20172020 in connection with various pipeline, metering and overhaul projects.At December 31, 2017, the aggregate estimated fair value of Northern Border's long-term debt was approximately $294 million (2016 – $464 million). In 2017, interest expense related to the senior notes was $19 million (2016 – $23 million; 2015 – $25 million).Border'sBorder’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, 2017,2020, Northern Border was in compliance with all of its financial covenants.Border'sBorder’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, 2017, $152020, $130 million was outstanding leaving $185 million available for future borrowings.on this facility. At Northern Border'sBorder’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'sBorder’s long-term unsecured credit ratings. The interest rate on Northern Border'sBorder’s credit agreement at December 31, 20172020 was 2.121.28 percent (2016(2019 – 1.902.82 percent). At December 31, 2017,2020, Northern Border was in compliance with all of its financial covenants.Lakes'Lakes’ Contractual ObligationsLakes'Lakes’ contractual obligations as of December 31, 20172020 included the following:
Payments Due by Period(a)(unaudited)
(millions of dollars) Total Less than
1 Year 1-3
Years 4-5
Years More than
5 Years 6.73% series Senior Notes due 2016 to 2018 9 9 – – – 9.09% series Senior Notes due 2016 to 2021 40 10 20 10 – 6.95% series Senior Notes due 2019 to 2028 110 – 22 22 66 8.08% series Senior Notes due 2021 to 2030 100 – – 20 80 Interest payments on debt 120 20 34 26 40 379 39 76 78 186 Total 9.09% series Senior Notes due 2021 10 10 — — — 6.95% series Senior Notes due 2021 to 2028 88 11 22 22 33 8.08% series Senior Notes due 2021 to 2030 100 10 20 20 50 66 14 22 16 14 Right-of-way commitments 1 — — — 1 265 45 64 58 98 Lakes'Lakes’ contractual obligations.TC PipeLines, LPAnnual Report2017 63$3$6 million as of December 31, 20172020 in connection with compressor overhaul projects.Lakes'Lakes’ outstanding debt securities are senior unsecured notes with similar terms except for interest rates, maturity dates and prepayment premiums.$139$107 million of Great Lakes' partners'Lakes’ partners’ capital was restricted as to distributions as of December 31, 2017 (2016 – $1502020 (2019 - $118 million). Great Lakes was in compliance with all of its financial covenants at December 31, 2017.The aggregate estimated fair value of Great Lakes' long-term debt was $335 million at December 31, 2017 (2016 – $354 million). The aggregate annual required repayment of senior notes is $19 million for 2018, $21 million for each year 2019 and 2020, $31 million for 2021 and $21 million for 2022. Aggregate required repayments of senior notes thereafter total $146 million. In 2017, interest expense related to Great Lakes' senior notes was $21 million (2016 – $22 million; 2015 – $24 million).OtherGreat Lakes has a cash management agreement with TransCanada whereby Great Lakes' funds are pooled with other TransCanada 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, 2017 and 2016, Great Lakes has an outstanding receivable from this arrangement amounting to $64 million and $27 million, respectively.Iroquois'Iroquois’ Contractual ObligationsIroquois'20172020 included the following:
Payments Due by Period(a)(unaudited)
(millions of dollars) Total Less than
1 Year 1-3
Years 4-5
Years More than
5 Years 6.63% series Senior Notes due 2019 140 – 140 – – 4.84% series Senior Notes due 2020 150 – 150 – – 6.10% series Senior Notes due 2027 39 4 9 7 19 Interest payments on debt 43 19 18 3 3 Transportation by others(b) 15 3 6 6 – Operating leases 7 1 3 1 2 Pension contributions(c) 1 1 – – – 395 28 326 17 24 Total 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 26 5 7 8 6 141 13 26 25 77 6 3 3 — — Operating leases 10 1 2 2 5 1 1 — — — 474 23 38 35 378 Iroquois'Iroquois’ contractual obligations.20182020 levels. Beyond 2018,2021, demand rates are subject to change.(c)2018. of $2 million as of December 31, 20172020 relative to procurement of materials on its expansion project.During the third quarter of 2017, Iroquois' partners adopted a distribution resolution to address the surplus cash on Iroquois' balance sheet. Under the terms of the resolution, Iroquois is expected to distribute approximately $57.6 million of unrestricted cash to its partners over 11 quarters, which began with Iroquois' second quarter 2017 distribution on August 1, 2017. As of February 26, 2018, Iroquois has distributed approximately $15.7 million of the expected $57.6 million, of which our proportionate share was approximately $7.8 million. Please read Note 7, Notes to Consolidated Financial Statements included in Part IV within Item 15. "Exhibits and Financial Statement Schedules"64 TC PipeLines, LPAnnual Report201775%75 percent and the debt service coverage ratio must be at least 1.25 times for the four preceding quarters. At December 31, 2017,2020, the debt/capitalization ratio was 47.4%57.7 percent and the debt service coverage ratio was 5.527.08 times, therefore, Iroquois was not restricted from making any cash distributions. and IDRs, and assume our General Partner has contributed any additional capital necessary to maintain its two percent general partner interest. The distributionpercentage interest distributions to the General Partner illustrated below other than in its capacity as a holder of 5,797,106 common units that are in excess of its effective two percent general partner interest representsrepresent the IDRs.
Marginal Percentage
Interest in Distribution Total Quarterly Distribution
Per Unit Target Amount Common
Unitholders General
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% The following table provides information aboutMinimum 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 % (in millions, except per unit distributions amounts)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). Limited Partners General Partner
Declaration
Date
Payment
Date
Per Unit
Distribution
Common
Units
Class B
Units(c)
2%
IDRs(a)
Total Cash
Distribution 1/22/2015 2/13/2015 $0.84 $54 $– $1 $– $55 4/23/2015 5/15/2015 $0.84 $54 $– $1 $– $55 7/23/2015 8/14/2015 $0.89 $56 $– $2 $1 $59 10/22/2015 11/13/2015 $0.89 $57 $– $1 $1 $59 1/21/2016 2/12/2016 $0.89 $57 $12 (d) $1 $1 $71 4/21/2016 5/13/2016 $0.89 $58 $– $1 $1 $60 7/21/2016 8/12/2016 $0.94 $62 $– $1 $2 $65 10/20/2016 11/14/2016 $0.94 $63 $– $1 $2 $66 1/23/2017 2/14/2017 $0.94 $64 $22 (e) $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 (b) 2/13/2018 (b) $1.00 $71 $15 (f) $2 $3 $91 (a)paiddeclared during 2020 did not reach the year ended December 31, 2017 included incentive distributions tospecified levels for any period and, therefore, the General Partner did not receive any distributions in respect of $10 million (2016 – $6 million, 2015 – $2 million).(b)On February 13, 2018, weits IDRs in 2020. To date, there has been no annual Class B distribution for 2021. In 2020, the Class B distribution paid a cash distribution of $1.00 per unit on our outstanding common units to unitholders of record at the close of business on February 2, 2017. Please readwas $8 million. For more information, please see Note 14 Notes to Consolidated Financial Statements included in Part IV within Item 15. "Exhibits and Financial Statement Schedules"TC PipeLines, LPAnnual Report2017 65(c)The Class B units issued by us on April 1, 2015 represent limited partner interests in us and entitle TransCanada to an annual distribution which is an amount based on 30 percent of GTN's annual distributions after exceeding certain annual thresholds. Please read Notes 7, 10 and 13, Notes to Consolidated Financial Statements included in Part IV within Item 15. "Exhibits and Financial Statement Schedules".(d)On February 12, 2016, we paid TransCanada $12 million representing 30 percent of GTN's total distributable cash flows for the nine months ended December 31, 2015 less $15 million. Please read Notes 7, 10 and 13- Cash Distributions within Part IV, Item 15. "Exhibits“Exhibits and Financial Statement Schedules" for more detailed disclosures on the Class B units.(e)On February 14, 2017, we paid TransCanada $22 million representing 30 percent of GTN's total distributable cash flows for the year ended December 31, 2016 less $20 million Please read Notes 7, 10 and 13, Notes to Consolidated Financial Statements included in Part IV within Item 15. "Exhibits and Financial Statement Schedules".(f)On February 13, 2018, we paid TransCanada $15 million representing 30 percent of GTN's total distributable cash flows for the year ended December 31, 2017 less $20 million Please read Notes 10 and 25, Notes to Consolidated Financial Statements included in Part IV within Item 15. "Exhibits and Financial Statement Schedules".partner'spartner’s ownership percentage, approximately one month following the end of a quarter. Our pipeline systems'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'systems’ cash distribution policies requires the unanimous approval of their respective management committees.Baja'sBaja’s distribution policies require the pipelines to distribute 100 percent of distributable cash flow based on earnings before depreciation and amortization less allowance for funds used during construction (AFUDC)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.Tuscarora'sPNGTSIroquoisPNGTS 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'PNGTS’ and Iroquois'Iroquois’ debt repayments are not funded with cashcapital calls to their owners, PNGTS and Iroquois have historically funded scheduled debt repayments by adjusting cash available cash for distribution, which effectively reduces the amount of cash available for distributions.Border'sBorder’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.Lakes'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.66 TC PipeLines, LPAnnual Report2017"Exhibits“Exhibits and Financial Statement Schedules".systems'systems’ accounting policies conform toAccounting Standards Codification (ASC) 980 – Regulated Operations. As a result, our pipeline systems record assets and liabilities that result from the regulated ratemakingrate-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 ratemakingrate-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.ratemakingrate-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.2017,2020, our equity investees have regulatory assets amounting to $17$14 million (2016 – $15(2019 - $13 million).2017,2020, our equity investees have regulatory liabilities amounting to $28$45 million (2016 – $27(2019 - $39 million).At December 31, 2017, the Partnership had nil million regulatory assets reported as part of other current assets on the balance sheet representing volumetric fuel tracker assets that are settled with in-kind exchanges with customers continually (2016 – $1 million). 2017,2020, the Partnership had regulatory liabilities of $26$38 million mostlylargely related to estimated costs associated with future removal of transmission and gathering facilities or allowed by FERC to be collected by FERC in depreciation rates (also known as "negative salvage"“negative salvage”) (2016(2019 - $29 million).$25 million).The 2017 Tax ActOn December 22, 2017,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 Presidentgoodwill might be impaired and, if we conclude that there is not a greater than 50 percent likelihood that the fair value of the United States signed into lawreporting unit is greater than its carrying value, will then perform the 2017 Tax Act.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.legislation provides for majoranalysis included the interim assessment of the impact of COVID-19 to our reporting units. Through this interim analysis, no triggering events were identified. Additionally, our annual impairment analysis on goodwill, resulted in a conclusion that there was a greater than 50 percent likelihood that both Tuscarora’s and North Baja’s estimated fair values would continue to exceed their carrying values. Therefore, no impairment exists on our goodwill. Adverse changes to U.S. corporate federal tax law. As mentionedour key considerations could, however, result in the section "Narrative Description of Business-Generalfuture impairments on our goodwill. See Item 1. "Business – Recent Business Developments – COVID-19" and Note 2 of the Partnership's consolidated financial statements included in4- Goodwill within Part IV, within Item 15. "Exhibits“Exhibits and Financial Statement Schedules", we are a non-taxable limited partnership,Schedules” which information is incorporated herein by referenceincome taxes owedEquipment – 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 a resultconsidered necessary.earnings arelong-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 responsibilityestimated 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:partners, thereforeConsolidated statement of operations.have beenreceived were recorded in revenue in 2018 and the Partnership's financial statementscash payments were used by the Partnership, together with other cash to pay in full its 2015 Term Loan Facility.2017 Tax Act.Our pipeline systems are regulated by the FERC, which approves the systems' rates onrelative cost advantage of WCSB and Bakken sourced gas versus Rockies production. Since its inception in January 2011, Bison has not experienced a cost-of-service basis and provides for a recoverydecrease in its revenue as its original ten-year contracts included ship-or-pay terms that resulted in payment to Bison regardless of our ultimate taxable owners' income tax expense and related balance sheet accounts as components of the maximum recourse rates that may be charged to customers. As a non-taxable entity,gas flows. In 2018, the Partnership does not recognize federal income tax expense nor has it established the related federal deferred income tax assets or liabilities. Income tax related expenses, benefits, assets, and liabilities attributable to regulated operations are the responsibility of the ultimate taxable owners of the Partnership and any adjustment to income tax accounts following the 2017 Tax Act must be evaluated by those owners.TC PipeLines, LPAnnual Report2017 67Any changes to the maximum recourse rates charged by our pipeline systems following the 2017 Tax Act will be reflected as those rates are revised through future rate proceedings individually unless superseded through other possible future action by the FERC. The Partnership cannot predict the ultimate impact of the 2017 Tax Act on future revenues of our pipeline systems.At December 31, 2017, the Partnership considers its assessment of the impact of the 2017 Tax Act to be its best interpretation of available guidance. Should additional guidanceexpected a significant erosion on the impact of the 2017 Tax Act on non-taxable partnerships be provided by regulatory, tax and accounting authorities or other sourcescash 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.reviewcontinue to maintain Bison to stand ready for redevelopment and has concluded that the approach usedremaining obligations of Bison, primarily in the form of property tax obligations and adjust as appropriate. Goodwill and Long-Lived AssetsEquity Investmentsis dependent on internal forecasts, estimatesare determined using the same factors we consider in our annual impairment test of the long-termgoodwill such as: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. action or settlement.Northern BorderNorthern Border's 2013 settlement agreement required Northern Border to file for new rates no later than January 1, 2018. On December 4, 2017, Northern Border filed a rate settlement with FERC which precluded the need to file a general rate case by January 1, 2018. The 2017 Northern Border Settlement, which was approved by FERC on February 23, 2018, provides for tiered rate reductions beginning January 1, 2018, with no change to the underlying rate design. The 2017 Northern Border Settlement does not contain any moratorium and unless superseded by a subsequent rate case or settlement, recourse rates in effect at December 31, 2017, will decrease by 5.0% on January 1, 2018; by an additional 5.50% on April 1, 2018; and by an additional 2.0% beginning January 1, 2020 through December 31, 2023, when Northern Border will be required to establish new rates. This equates to an overall rate reduction of 12.5% by January 1, 2020 from the recourse rates in effect at December 31, 2017.The 2017 Northern Border Settlement will provide Northern Border with rate stability over the longer term. We do not believe that the rate reduction as described above will have a material impact on the Partnership's results and, therefore, we do not believe the settlement outcome has negatively impacted the underlying value of our investment in Northern Border. The overall long-term market fundamentals of Northern Border continue to be positive due to its strategic footprint. Northern Border remains a key competitive pipeline and continues to operate at full capacity connecting major supply basins with communities in the Midwestern U.S. Accordingly, no impairment has been identified on our investment in Northern Border.68 TC PipeLines, LPAnnual Report2017Great LakesDuring the fourth quarter of 2015, we recorded an impairment charge of $199 million on our investment in Great Lakes. The impairment charge was the result of our determination that our investment in Great Lakes' long-term value had been adversely impacted by the changing natural gas flows in its market region and that other strategic alternatives to increase its utilization or revenue were no longer feasible. The impairment charge reduced the difference between the carrying value of our investment in Great Lakes and the underlying equity in the net asset to $260 million, and the difference represented the equity method goodwill remaining in our investment in Great Lakes relating to the Partnership's February 2007 acquisition of a 46.45 percent general partner interest in Great Lakes.On October 30, 2017, Great Lakes filed a rate settlement with FERC to satisfy its obligations from its 2013 rate settlement for new rates to be in effect by January 1, 2018. The 2017 Great Lakes Settlement does not contain a moratorium provision and Great Lakes will be required to file for new rates no later than March 31, 2022, with new rates to be effective October 1, 2022. The 2017 Great Lakes Settlement, which was approved by FERC on February 22, 2018, decreased Great Lakes' maximum transportation rates by 27 percent effective October 1, 2017. At December 31, 2017, the estimation of fair value on our remaining equity investment in Great Lakes was completed and we concluded the fair value of our investment in Great Lakes has not materially changed from 2015.The assumptions we used in the analysis related to the estimated fair value of our remaining equity investment in Great Lakes included the reduction in Great Lakes' rates effective October 1, 2017. The reduction in rates was offset by expected cash flows from the long-term transportation contract with the TransCanada, other revenue opportunities on the system and the settlement's elimination of the revenue sharing mechanism with its customers. Although evolving market conditions and other factors relevant to Great Lakes' long term financial performance have been positive, 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.Our key assumptions could be negatively impacted by near and long-term conditions including:•future regulatory rate action or settlement,•valuation of Great Lakes in future transactions,•changes in customer demand at Great Lakes for pipeline capacity and services,•changes in North American natural gas production in the major producing basins,•changes in natural gas prices and natural gas storage market conditions,•discount rates and multiples used, and•changes in other long-term strategic objectives.2017,2020, no impairment charge has been recorded related to any of our other equity investments.GoodwillWe test goodwill for impairment annually based onASC 350 See also Item 1. "Business – IntangiblesRecent Business Developments – GoodwillCOVID-19" and Other, or more frequently if events or changes in circumstances lead us to believe it might be impaired. We assess qualitative factors to determine whether events or changes in circumstances indicate that goodwill might be impaired,Note 5- Equity Investments within Part IV, Item 15. “Exhibits and if we do not conclude that itFinancial Statement Schedules” which information is more likely than not that the fair value of the reporting unit is greater than the carrying value, we use a two-step process to test for impairment:1.First, we compare the fair value of the reporting unit, including its goodwill, to its book value. If the fair value is less than book value, we consider our goodwill to be impaired.2.Next, we measure the amount of the impairmentincorporated herein by calculating the implied fair value of the reporting unit's goodwill. We do this by deducting the fair value of the tangible and intangible net assets of the reporting unit from the fair value calculated in the first step. If the goodwill's carrying value exceeds its implied fair value, we record an impairment charge.TC PipeLines, LPAnnual Report2017 69We 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.At December 31, 2017 and 2016, we had $130 million of goodwill recorded on our consolidated balance sheet related to the North Baja and Tuscarora acquisitions. No impairment of goodwill existed at December 31, 2017.Long-Lived AssetsWe assess our long-lived assets for impairment based onASC 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, but are not limited to, demand, competition, contract renewals and other factors.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 statement of income.As of December 31, 2017, there were no indicators of impairment for our long-lived assets.70 TC PipeLines, LPAnnual Report2017systems'systems’ accounting for contingencies covers a variety of business activities, including contingencies forthat 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 withASC 450 – Contingencies.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 pipeline systems'estimates or additional facts and circumstances cause us to revise our estimates resulting in an impact, positive or negative, on earnings and cash flow.CONTINGENCIESLegalVarious legal actions or governmental proceedings involvingpipeline systemsequity investees are not aware of any contingent liabilities that have arisen in the ordinary course of business are pending. Our pipeline systems believe that the resolution of these issues will not have a material adverse impact on their results of operations or financial position. Please read Part I, Item 3. "Legal Proceedings" for additional information.EnvironmentalWe do not believe that compliance with existing environmental laws and regulations willwould have a material adverse effect on our pipeline systems. Becausetheir financial condition, results or operations or cash flows.inherent uncertainties as to the final outcome of proposed environmental regulations and legislation, we cannot estimate the range of possible costs, if any, from the proposals. Please read Part I, Item 1. "Business – Government Regulation" for additional information.Greenhouse Gas RegulationThrough the EPA, the U.S. Government has imposed various measures related to GHG emissions, including emission monitoring and reporting requirements, preconstruction and operating permits for certain large stationary sources. The EPA has also proposed rules requiring the control of methane emissions from and leak detection and repair requirements for certain oil and natural gas production, processing, transmission and storage activities, though future implementation of these rules is uncertain at this time as a result of the recent change in U.S. Presidential Administrations. In any event, several states are also pursuing measures to regulate the emissions of GHGs, including implementation of cap and trade programs or carbon taxes. These final and proposed rules, as well as additional legislation or regulations for the control of GHG emissions could materially increase our operating costs, including our cost of environmental compliance by requiring us to install additional equipment and potentially purchase emission allowances or offset credits. The regulation or restriction of GHG emissions could also result in changes to the consumption and demand for natural gas. This could have either positive or adverse effects on our pipeline systems, ourPartnership’s financial position,condition, results of operations and future prospects. Please read Part I, Item 1. "Business – Government Regulation" for additional information."Certain“Certain Relationships and Related Transactions, and Director Independence"Independence” and Note 17 within Part IV, Item 15. "Exhibits“Exhibits and Financial Statement Schedules"Schedules” for more information regarding related party transactions.TC PipeLines, LPAnnual Report2017 71instruments'instruments’ gains and losses may offset the hedged items'items’ related results in earnings for a fair value hedge or be deferred in accumulated other comprehensive income for a cash flow hedge.2017,2020, the Partnership'sPartnership’s interest rate exposure resulted from our floating rate Senior Credit Facility, 2015 Term Loan Facility, GTN's Unsecured Term Facilityon North Baja’s unsecured term loan facility, PNGTS’ revolving credit facility and Tuscarora's Unsecured Term Facility, Tuscarora’s unsecured term loan facility, under which $435$98 million, or 184 percent, of our outstanding debt was subject to variability in LIBOR interest rates (2016 – $405(December 31, 2019 - $112 million or 216 percent).2017,2020, the variable interest rate exposure related to our 2013 Term Loan Facility was hedged by fixed interest rate swap arrangements and our effective interest rate was 2.313.26 percent. If interest rates hypothetically increased (decreased) on these facilities by one percent 100(100 basis points,points), compared with rates in effect at December 31, 2017, The Partnership's2020, our annual interest expense on its remaining debt with variable interest exposure would increase (decrease) and net income would decrease (increase) by approximately $4$1 million.2017, $152020, $130 million, or 634 percent, of Northern Border'sBorder’s outstanding debt was at floating rates (2016 – $181 million or 42 percent).rates. If interest rates hypothetically increased (decreased) by one percent 100(100 basis points,points), compared with rates in effect at December 31, 2017,2020, Northern Border'sBorder’s annual interest expense would increase (decrease) and its net income would decrease (increase) by approximately nil$1 million.GTN's Unsecured Northern Border's and Iroquois' Senior Notes, and all of Great Lakes'Lakes’ and GTN' s Notes, and the PNGTS' Series A Notes, represent fixed-rate debt;debt, and are therefore they are not exposed to market risk due to floating interest rates. Interest rate risk does not apply to Bison, and North Baja, as they currently doBison does not have any debt.72 TC PipeLines, LPAnnual Report2017–- contractual agreements between two parties to exchange streams of payments over time according to specified terms.–- 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 For details regarding our current interest rate swaps are structured such that the cash flows of the derivative instruments match those of the variable rate of interest on the 2013 Term Loan Facility. The Partnership hedged interest payments on the variable-rate 2013 Term Loan Facility with interest rate swaps maturing July 1, 2018, at a weighted average fixed interest rate of 2.31 percent. At December 31, 2017, the fair value of the interest rate swaps accounted for as cash flow hedges was an asset of $5 million (on both gross and net basis). At December 31, 2016, the fair value of the interest rate swaps accounted for as cash flow hedges was an asset of $1 million and a liability of $1 million (on a gross basis) and an asset of nil million (on a net basis). The Partnership did not record any amounts in net incomeother agreements related to ineffectiveness formitigation of impact on changes in interest rate hedges for the years ended December 31, 2017, 2016 and 2015. The net change in fair value of interest rate derivative instruments recognized in other comprehensive income was a gain of $5 million for the year ended December 31, 2017 (2016 - gain $2 million, 2015 – nil million). In 2017, the net realized loss related to the interest rate swaps was nil, and was included in financial charges and other (2016 – $3 million, 2015 – $2 million).As discussed inrates, see Note 819- Fair Value Measurements within Part IV, Item 15. Exhibits“Exhibits and Financial Statement Schedules, the Partnership's 2013 Term Loan that was due July 1, 2018, was amended to extend the maturity period through October 2, 2022. As a result of this extension, the Partnership implemented an interest rate hedging strategy after the extension of maturity period and hedged the entire $500 million until its October 2, 2022 maturity using forward starting swaps at an average rate of 3.26 percent.The Partnership has no master netting agreements, however, 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 net asset of $5 million as of December 31, 2017 and there would be no effect on the consolidated balance sheet as of December 31, 2016.In anticipation of a debt refinancing in 2003, PNGTS entered into forward interest rate swap agreements to hedge the interest rate on its Senior Secured Notes due in 2018. These interest rate swaps were used to manage the impact of interest rate fluctuations and qualified as derivative financial instruments in accordance with ASC 815,Derivatives and Hedging. PNGTS settled its position with a payment of $20.9 million to counterparties at the time of the refinancing and recorded the realized loss in AOCI as of the termination date. The previously recorded AOCI" which information is currently being amortized against earnings over the life of the PNGTS' 5.90% Senior Secured Notes. At December 31, 2017, our 61.71 percent proportionate share of net unamortized loss on PNGTS included in AOCI was $1 million (2016 – $2 million). For the year ended December 31, 2017, 2016 and 2015, our 61.71 percent proportionate share of the amortization of realized loss on derivative instruments was $0.8 million for each year.TC PipeLines, LPAnnual Report2017 73institutions. However, we cannot predict to what extent our business would be impacted by uncertainty in energy commodity prices, including possible declines in our customers' credit worthiness.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 ourinstitutions, reviews accounts receivable regularly and, recordif needed, records allowances for doubtful accounts using the specific identification method. At December 31, 2017,hadare not incurred any significantable to predict with certainty the extent to which our business could be impacted by the uncertainty surrounding the COVID-19 pandemic or the prolonged impact of low commodity prices, including possible declines in our counterparties' creditworthiness. Refer to Note 16 - 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.had no significant amounts past due or impaired. At December 31, 2017, we hadFinancial Statement Schedules”. The Partnership believes the factors as described above are considered to have a credit risk concentration on onenegligible impact considering the portfolio of counterparties in connection with our customers, Anadarko Energy Services Company, who owed us $4 million. This amount represented approximately 10 percent of our trade accounts receivable.Our approach to managingWe manage our liquidity risk isby continuously forecasting our cash flow on a regular basis to ensure that we always have sufficientadequate cash balances, cash flow from operations and credit facility availabilityfacilities to meet our operating, financing and capital expenditure obligations when due, under both normal and stressed conditions, without incurring unacceptable losses or damageconditions. Refer to "Liquidity and Capital Resources" section for more information about our reputation. liquidity.2017,2020, the Partnership had a Senior Credit Facility of $500 million maturing in 2021 with anno outstanding balance. At December 31, 2020, PNGTS has a $125 million Revolving Credit Facility maturing in 2023 and has outstanding balance on this facility of $185 million. In addition,$25 million and, finally, at December 31, 2017,2020, Northern Border had a committed revolving bank line of $200 million maturing in 20202024 and $15$130 million was drawn. Both the Partnership'sThe Partnership’s Senior Credit Facility, PNGTS' revolving credit facility and the Northern Border $200 millionBorder’s credit facility have accordion features for additional capacity of $500 million, $50 million and $100$200 million respectively, subject to lender consent.Partnership'sPartnership’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'sPartnership’s disclosure controls and procedures as of the end of the year covered by this annual report were effective to provide74 TC PipeLines, LPAnnual Report2017Securities Exchange Act, of 1934, as amended (the "Exchange Act"), is (a) recorded, processed, summarized and reported within the time periods specified in the SEC'sSEC’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.quarteryear ended December 31, 2017,2020, there was no change in the Partnership'sPartnership’s internal control over financial reporting that has materially impacted or is reasonably likely to materially impact our internal control over financial reporting.MANAGEMENT'SSecurities Exchange Act of 1934.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, including2017 to provide2020 at providing reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with GAAP. ThereNo material weaknesses were no material weaknesses.Partnership'sPartnership’s internal control over financial reporting. KPMG has issued an attestation report concurring with management'smanagement’s assessment, which is included starting on page F-2 of the financial statements included in this Form 10-K.PartPartnership. Each director holds office for aPartnership as of February 24, 2021. Directors are appointed by the General Partner’s sole stockholder to serve one-year termterms or until his or her successor is earliertheir 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 TransCanada.PipeLines, LPAnnual Report2017 75
Energy.NameAgeName Age Position with General Partner Karl JohannsonStanley G. Chapman, III55 57Chair and Director Jack F. Stark 70 67Independent Director Malyn K. Malquist 68 65Independent Director Walentin (Val) MiroshPeggy A. Heeg61 72Independent Director Brandon M. AndersonNathaniel A. Brown44 45President, Principal Executive Officer and Director M. Catharine DavisNadine E. Berge48 53Director Joel E. HunterGloria L. Hartl48 51Director Janine M. Watson 51 48Vice-President and General Manager NathanielAlisa Williams37 Vice-President, Taxation Jon A. BrownDobson54 41SecretaryBurton D. Cole 46 Controller William C. Morris 58 Principal Financial Officer, Nancy F. Priemer59Vice-President, TaxationJon A. Dobson51SecretaryWilliam C. Morris55Vice-President and Treasurer Johannson was appointedChapman has served as a director and Chair of the Board of Directors of the General Partner in March 2013.since January 1, 2019. Mr. Johannson'sChapman’s principal occupation is Executive Vice-President and President, CanadaU.S. and Mexico Natural Gas Pipelines andof TC Energy, for TransCanada a positionwhere he has heldled the U.S. natural gas business since May 1, 2017.April 2017 and the Mexico natural gas business since September 2020. He is accountableresponsible for TransCanada'sall pipeline operations and commercial activities across TC Energy's FERC-regulated transmission and storage assets as well as certain unregulated businesses. Mr. Chapman joined TC Energy as part of its acquisition of the Columbia Pipeline Group (Columbia) in July 2016 and served as Senior Vice President and General Manager of TC Energy’s FERC-regulated US natural gas pipelines and natural gas storagepipeline business in Canada and Mexico. Sincefrom July 2016 to April 2017. Prior to joining TransCanada in 1994,TC Energy, Mr. Johannson hasChapman held several other positions of increasing responsibility,at Columbia from December 2011 to July 2016, most recently as Executive Vice-President and President, Natural Gas PipelinesChief Commercial Officer. Before joining Columbia, Mr. Chapman held various positions of increasing responsibility with El Paso Corp and Tenneco Energy and was responsible for TransCanada from November 2012 to May 2017. Mr. Johannson has extensive senior management experience in the pipelinesvarious marketing and energy industriescommercial operations, as a result of his servicewell as an executive of TransCanadasupply, regulatory, business development and its affiliates.optimization activities. His experience in his prior roles at TransCanada provides him with intimate knowledge of the Partnership, including its strategies, operations and markets. Mr. Johannson's industry knowledge, management experience and leadership skills are highly valuable in assessingdeveloping and implementing our business strategies and assessing accompanying risks.was appointedhas served as a director and member of the audit and conflicts committee of the board of directors of the General Partner insince 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 plansplants, 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 currently serves on the board of directors of ASUS,AltaGas Services (U.S.) Inc. (ASUS), a wholly-ownedwholly owned subsidiary of Alta Gas Services.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 Compensationcompensation and Audit Committeesaudit 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'sStark’s prior audit committee experience further enhances his qualifications to serve as a member of our Board and our Audit Committee. His valuable management and financial expertise includes an understandingaccountingaudit committee and financial matters thatmember of the Partnership and industry address on a regular basis.Mr. Malquist was appointed a directorconflicts committees of the board of directors of the General Partner insince April 2011. Mr. Malquist is an executive with more than 30 years of experience serving in a variety of business, operations and financial roles. Mr. Malquist served on the Boardboard of Directorsdirectors and Audit Committeeaudit committee of Headwaters Incorporated ("Headwaters")(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, Mr. Malquist served as Executive Vice-President of Avista Corporation (Avista), energy production, transmission and distribution company. He also served as Chief Financial Officer of Avista from November 2002 to September 2008 and Treasurer from February 2004 to January 2006 and Senior Vice-President from September 2002 to May 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 and76 TC PipeLines, LPAnnual Report2017includesinclude an understanding of the accounting and financial matters that the Partnership and industry address on a regular basis. In addition, Mr. Malquist'sMalquist’s experience in the energy industry is beneficial to the service he provides to the Board of Directors.Mr. Miroshin 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 (a commodity chemicals and plastics company). From July 2003 to April 2008, Mr. Mirosh was President of Olefins and Feedstocks, a division of NOVA Chemicals Corporation. Mr. Mirosh is also a director of Superior Plus Income Fund (energy services, specialty chemicals and construction products distribution) and 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, complemented by an engineering and legal educational background, enable Mr. Mirosh to provide the Board of Directors and Audit Committee with executive counsel on a full range of business, financial, technical and professional matters.Mr. Anderson was appointed President, Principal Executive Officer and a Director of the General Partner in January 2016. Mr. Anderson's principal occupation is Senior Vice President, U.S. Commercial for TransCanada and has main accountability on marketing, business development, rates, commercial operations, regulatory strategy, gas storage and asset optimization of all U.S Natural Gas assets. From July 2016- April 2017, Mr. Anderson was Senior Vice-President and General Manager, U.S. Natural Gas Storage, Midstream for TransCanada. From July 2015 to July 2016, Mr. Anderson was Senior Vice-President and General Manager, U.S. Natural Gas Pipelines for TransCanada. Mr. Anderson has over 20 years of energy industry experience and, since joining TransCanada in 2002, has held a variety of leadership positions in energy marketing and trading, business development, electricity, gas storage and TransCanada's Mexico pipeline operations. Mr. AndersonMay 1, 2018. He previously served as Senior Vice President and General Manager, Mexico Gas and Power from May 2013 to July 2015, Senior Vice President, Western Power and Gas Storage from January 2011 to May 2013 and Vice President, Gas Storage from March 2006 to January 2011.Ms. Davis was appointed a director of the General Partner in April 2014. Ms. Davis' principal occupation is Vice-President, Law, Natural Gas Pipelines for TransCanada, a position she has held since October 2015. Ms. Davis is responsible for the regulatory, compliance, commercial, safety, environment, and business development law services provided to TransCanada's existing and proposed natural gas pipelines in Canada, the U.S., and Mexico. She is Chief Compliance Officer for the TransCanada Mainline and NGTL systems. From November of 2012 to October of 2015, Ms. Davis was the Vice-President, Law, Canadian Pipelines, Corporate Services Division for TransCanada, responsible for the regulatory, commercial, Aboriginal, land, safety, and environment law services provided to TransCanada's existing and proposed oil pipelines both in Canada and the U.S., and to its existing and proposed Canadian natural gas pipelines. From February 2007 to November 2012, Ms. Davis was Chief Compliance Officer and Associate General Counsel, and later Vice President, U.S. Pipelines Law for TransCanada's U.S. natural gas pipelines and storage companies. Prior to joining TransCanada in February 2007, Ms. Davis held various legal positions at Great Lakes Gas Transmission Company, most recently as Associate General Counsel and Chief Compliance Officer. Prior to 1992, she worked in the Federal Energy Regulatory Commission's Office of Administrative Law Judges, as a law clerk.Mr. Hunter was appointed a director of the General Partner in April 2014. Mr. Hunter's principal occupation is Senior Vice-President, Capital Markets for TransCanada, a position he had held since December 2017. In his current position, Mr. Hunter is responsible for Corporate Finance, Corporate Planning, Trading and Financial Risk Management, Cash Management, Investor Relations and Financial Communication, and Treasury. Since joining TransCanada in 1997, Mr. Hunter has held a number of positions of increasing responsibility, most recently as Vice-President, Finance and Treasurer from July 2010 to December 2017 and Director of Corporate Finance from January 2008 to July 2010.TC PipeLines, LPAnnual Report2017 77 Ms. Watson was appointed Vice-President and General Manager for the General Partner in October 2015. Her principal occupation is Director, LP Management & Pricing for TransCanada, a position she has held since October 2015. Ms. Watson has served in progressively senior positions in the natural gas pipeline and energy business segments of TransCanada since 1997. Prior to joining TransCanada, Ms. Watson was an attorney at the Calgary office of McCarthy Tétrault and clerked at the Alberta Court of Appeal.Mr. Brown was appointed the Controller and Principal Financial Officer of the General Partner infrom May 2014.2014 to May 2018. His principal occupation is Vice-President, U.S. Natural Gas Pipelines Financial Services of TransCanada in whichUSA 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 TransCanada'sTC 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 accountingAccounting for TransCanada'sTC Energy’s U.S. Pipelines West from November 2009 to May 2014 and as Director of Financial Services for TransCanada's U.S. Pipelines from May 2014 to February 2018. In that capacity, Mr. Brown was responsible for accounting, financial reporting, planning and budgeting. He also provided regulatory accounting support for rate filings, settlement negotiations, and other regulatory proceedings.2014. Prior to joining TransCanada,TC Energy, Mr. Brown spent eight years in public accounting, most recently as an audit manager for Grant Thornton LLP and Ernst &Young.PriemerBerge 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.in February 2016. Ms. Priemer'ssince July 2019. Her principal occupation is Director, U.S. Natural Gas PipelinesIncome Taxation of TransCanada, a positionTC USA, in which role she has held sinceleads 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 2009. Prior to this position Ms. Priemer2018 as the Manager of Tax Reporting until she was a Taxappointed Director, of an affiliate locatedUS Taxation in Michigan, a position she held since 1998.July 2019. Prior to joining TransCanada,TC Energy, Ms. PriemerWilliams spent 18 yearsmore than a decade in both public accounting and industry.was appointedhas served as Secretary of the General Partner insince May 2014, prior to which he served as Assistant Secretary of the General Partner sincefrom April 2012. Mr. Dobson'sDobson’s principal occupation is Director, U.S., Governance and Corporate and Securities Law of TC USA and Corporate Secretary for TransCanada'sTC Energy’s U.S. subsidiaries. Prior to joining TransCanadaTC Energy in January 2011, Mr. Dobson spent 18 years practicing law in various 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.was appointedhas 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 infrom November 2017. Mr. Morris served2017 to February 2018 and as Treasurer of the General Partner since 2012.from 2012 to November 2017. Mr. Morris'Morris’ principal occupation is Director, Finance and Assistant Treasurer of TransCanada,TC Energy, a position he has held since November 2015,2012. In this role, he is responsible for the development, execution and previous to that as Director, Corporate Finance since November 2012. From 2001 to 2012,monitoring of TC Energy’s financing strategy. Mr. Morris wasjoined TC Energy in 1996 and has held various positions of increasing responsibility, including manager, Risk Management, and Director of Risk Management for TransCanada and Manager, Risk Management for TransCanada for the previous five years.Management. Prior to joining TransCanada,TC Energy, Mr. Morris spent 12 years in both the public accounting and banking industries.'controlled company'‘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'sPartner’s board of directors.ThisThe most recent certification was provided to the NYSE on March 29, 2017."audit“audit committee financial experts,"” are "independent"“independent” and are "financially sophisticated"“financially sophisticated” as defined under applicable SEC rules and NYSE Corporate Governance Standards. The board'sboard’s affirmative determination for both Malyn Malquist and Jack Stark was78 TC PipeLines, LPAnnual Report2017TransCanada'sTC 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.transcanada.com.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'sPartnership’s website or filed in a report on Form 8-K.Partnership'sPartnership’s website or filed in a report on Form 8-K.committeeAudit Committee are Malyn Malquist, as Chair, Jack Stark and Walentin (Val) Mirosh.Peggy Heeg. All members of the Audit Committee meet the criteria for independence as set forth under the rulesand experience requirements of the SECNYSE and those of the NYSE.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 able to read and understand fundamental financial statements, including a company's balance sheet, income statement and cash flow statement.Partnership'sPartnership’s audit report, that the committeeAudit 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 committeeAudit Committee has adopted TransCanada'sTC Energy’s Ethics Help-Line in fulfillment of its responsibility to establish a confidential and anonymous whistle blowing process. The toll freetoll-free Ethics Help-Line number and the audit committee'sAudit Committee’s charter are published on the Partnership'sPartnership’s website at www.tcpipelineslp.com.management.management and non-independent directors. Jack Stark serves as the presiding director at those executive sessions. Persons wishing to communicate with the General Partner'sPartner’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, or via fax at 1.508.871.7047.TC PipeLines, LPAnnual Report2017 79SECTION 16(a) BENEFICIAL OWNERSHIP REPORTING COMPLIANCESection 16(a) of the Exchange Act, as amended, requires the General Partner's directors and executive officers, and persons who beneficially own more than ten percent of the common units, to file reports of ownership and changes in ownership with the SEC and to furnish us with copies of all such reports. Based solely upon a review of the copies of the reports received by us, we believe that all such filing requirements were satisfied during 2017.TransCanada.TransCanadaTC Energy govern the types and amount of compensation granted to each of the named executive officers. Since these policies and philosophy are those of TransCanada,TC Energy, we refer you to a discussion of those items as set forth in the Executive Compensation"Executive Compensation" section of the TransCanada "ManagementTC Energy “Management Information Circular"Circular” on the TransCanadaTC Energy website at www.tcpipelineslp.com.www.tcenergy.com. The TransCanada "ManagementTC Energy “Management Information Circular"Circular” is prepared by TransCanadaTC 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;Act; 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 total amount we are chargedcosts allocated to us for managerial, administrative and operational support provided by TransCanadaTC Energy and its affiliates, including our General Partner. We are allocated and reimburse TransCanadaTC Energy for a percentage of the compensation, including base salary and certain benefit and incentive compensation expenses related to the officers of our General Partner and employees of TransCanadaTC 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 TransCanadaTC Energy and its other affiliates. The Board of Directors of our General Partner specifically approves the percentage allocation to the Partnership of the compensation of the executive officers of the General Partner on an annual basis. Please read Part III, Item 13. "Certain“Certain Relationships and Related Transactions, and Director Independence"Independence” for more information regarding this arrangement.Compensation"Compensation Discussion and AnalysisAnalysis" set forth above and based on this review and discussion has approved it for inclusion in this Form 10-K. Brandon Anderson M. Catharine Davis JoelHunter Karl R. Johannson
Bergeallocatedand benefits charged to the Partnership in 2020, 2019 and paid by us in 2017, 2016 and 20152018, as applicable, for the individuals serving as our President and Principal Executive Officer, Controller andOfficers during 2020, Vice President, Principal Financial Officer and Treasurer and other executive officers of our General Partner for whom the salaries and benefits of more than $100,000 were allocatedallocations to us.
Name and Principal Position
Year
Approximate
Percentage of
Time Devoted to
the Partnership
Total
Compensation
allocated to the
Partnership(a)
(in US dollars) Brandon Anderson(b) 2017 30% 209,135 President and Principal Executive Officer 2016 30% 199,920 Janine Watson(c)(d) 2017 50% 170,244 Vice-President and General Manager 2016 50% 155,782 Nathan A. Brown 2017 35% 121,737 Controller and Principal Financial Officer 2016 35% 112,663 2015 35% 114,098 Jon A. Dobson 2017 60% 253,793 Secretary 2016 60% 239,226 2015 50% 208,051 William C. Morris(d) 2017 50% 163,891 Vice-President and Treasurer 2016 50% 152,956 2015 50% 162,881 Name and Principal Position Year Approximate
Percentage of
Time Devoted to
the Partnership2020 35 % 176,594 President and Principal Executive Officer 2019 35 % 177,755 2018 35 % 156,986 2020 50 % 167,318 Vice‑President, Principal Financial Officer and Treasurer 2019 50 % 172,165 2018 50 % 169,280 2020 50 % 180,388 Vice‑President and General Manager 2019 50 % 185,613 2018 50 % 182,504 Jon A. Dobson 2020 53 % 229,372 Secretary 2019 60 % 238,074 2018 60 % 268,024 2020 35 % 133,216 Controller and Principal Accounting Officer 2019 35 % 134,693 2018 — — Partnership's allocated portionamount of compensation paidreimbursement made by TransCanadathe Partnership to TC Energy representing base salary and benefits rate allocations from TC Energy to the named executive officerPartnership for the year indicated and is based on the percentage of the applicable officer’s time devoted to the Partnership.2016.Vice – PresidentVice-President, Principal Financial Officer and Treasurer effective May 1, 2018. The total compensation allocated to the Partnership in October 2015.
For the year ended December 31, 2017
(in dollars)
Cash
Deferred
Share Unit
Awards(b)
Total Malyn K. Malquist(c) – 177,500 177,500 Jack F. Stark(d) 107,500 70,000 177,500 Walentin (Val) Mirosh(e) 92,500 70,000 162,500 Fees Earned
or Paid in
CashTotal 95,000 80,000 175,000 95,000 80,000 175,000 47,609 47,778 95,387 23,261 23,261 46,522 Karl R. Johannson, Brandon Anderson, M. Catharine Davis and Joel E. Hunter.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 theTC PipeLines, LPAnnual Report2017 81directors' 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.(DSU)s(DSUs) granted during 20172020 under the DSU Plan.TC PipeLines GP, Inc. Deferred Share Unit Plan for Non-Employee Directors (2013) (DSU Plan). All of the DSUs granted to Messrs. Malquist, Stark and MiroshHeeg were outstanding at December 31, 2017.2017,2020, Mr. Malquist, Mr. Stark and Mr. MiroshMs. Heeg held 13,028, 20,39724,381, 33,687 and 13,778809 DSUs, respectively. The fair market value of the DSUs held by Mr. Malquist, Mr. Stark and Mr. MiroshMs. Heeg at December 31, 20172020 was $691,766, $1,083,075$718,014, $992,076 and $731,615,$23,838, respectively. Amounts alsoThese amounts include amountsdistribution like payments credited to each independent director'sdirector’s DSU account equal to the distributions payable on the Partnership’s common units multiplied by the number of DSUs previously granted or credited.in the director’s account. In this regard, Mr. Malquist was credited 7401,668 DSUs, Mr. Stark was credited 1,3062,352 DSUs, and Mr. Mirosh was credited 8651,199 DSUs and Ms. Heeg was credited 3 DSUs. All DSUs credited during 20172020 were outstanding at December 31, 2017.elected to receive DSUs in lieu ofinclude the $55,000$70,000 annual cash retainer, the $15,000 Audit Committee Chair cash retainer and cash meeting attendance fees in 2017.$55,000$70,000 annual cash retainer, $15,000 Conflicts Committee Chair retainer and $22,500$10,000 of meeting attendance fees.$55,000$70,000 annual cash retainer and $22,500$10,000 of meeting attendance fees.2017,2020, each director who was not an employee of TransCanada,TC Energy, the General Partner or its affiliates (independent director) was entitled to a directors'directors’ retainer fee of $125,000$150,000 per annum, of which $70,000$80,000 was automatically granted in DSUs (see DSUsDeferred Share Units section below). The independent director appointed as Lead Independent Director and chairChair of the Conflicts Committee and the independent director appointed as chairChair of the Audit Committee were each entitled to an additional fee of $15,000 per annum, respectively.annum. Each independent director was also paid a feecommittee member retainer of $1,500$5,000 for attendance atparticipating in each meeting of the board of directors and a fee of $1,500 for attendance at each meeting of a committee of the board.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.2017,2020, as part of the retainer fee, each independent director received anquarterly automatic grantgrants of DSUs withvalued at $20,000 each for a total annualized grant value of $70,000, which was paid quarterly.aone common unit of the Partnership at the time the independent directorDSU is credited withto the units.independent director’s account. The value of a DSU when redeemed is equivalent to the market value of aone 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 at their option. DSUs redeemed for common units would be purchased by the Partnership in the open market.82 TC PipeLines, LPAnnual Report2017
market through a broker at their option.22, 201819, 2021 regarding the (i) beneficial ownership of our common units and shares of TransCanadaTC Energy by the General Partner'sPartner’s directors, the named executive officers and directors and 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 TransCanada Corporation
Name and Business Address
Number of
Units(a)
Per cent
of Class(b)
Common
Shares
Per cent
of class TransCan Northern Ltd(c)
450-1st Street SW
Calgary, Alberta T2P 5H1 11,287,725 15.8 – – TC Pipelines GP, Inc.(d)
450-1st Street SW
Calgary, Alberta T2P 5H1 5,797,106 8.1 – – OppenheimerFunds, Inc.(e)
Two World Financial Center
225 Liberty Street
New York, NY 10281 9,005,426 12.89 – – ALPS Advisors, Inc.(f)
1290 Broadway, Suite 1100
Denver, CO 80203 4,378,065 6.27 – – First Trust Portfolios LP(g)
120 East Liberty Drive, Suite 400
Wheaton, Illinois 60187 4,040,374 5.78 Energy Income Partners, LLC(h)
10 Wright Street
Westport, Connecticut 06880 5,752,864 8.2 Malyn K. Malquist(i) 14,281 * – – Jack F. Stark(j) 21,083 * – – Walentin (Val) Mirosh(k) 14,046 * 995 * Karl R. Johannson(l) – – 580,758 * Brandon M. Anderson(m) – – 120,575 * M. Catharine Davis(n) – – 36,533 * Joel E. Hunter(o) – – 65,562 * Nathaniel A. Brown – – – * Jon A. Dobson(p) – – 376 * William C. Morris(q) – – 18,254 * Janine M. Watson(r) – – 2,547 * Directors and Executive officers as a Group(s) (11 people) 49,410 * 825,600 * Amount and Nature of Beneficial Ownership TC PipeLines, LP TC Energy Corporation Name and Business Address Common
SharesPer cent
of class17,084,831 24.0 — — 6,072,740 8.52 — — 6,004,796 8.42 7,888,173 11.0 — — 5,474,826 7.7 — — 3,594,992 5.0 25,381 * — — 33,977 * — — 809 * — — — — 217,504 * — — 363 * — — 12,803 * — — 18,078 * — — 62 * — — 376 * — — 20,660 * — — 354 * 60,167 * 270,200 * TC PipeLines, LPAnnual Report2017 83TransCanada.(d) is a wholly-owned indirect subsidiary of TransCanada and also, 5,797,106 common units, as well as 11,287,725 common units which TransCan Northern Ltd. owns an effective two percent general partner interest of the Partnership.(e)5, 2018 by OppenheimerFunds, Inc. In this Schedule 13G/A, OppenheimerFunds, Inc. disclaims beneficial ownership, and has shared power to vote and to dispose of the 9,005,426 common units.(f)Based on a Schedule 13G/A filed with the SEC on February 6, 20189, 2021 by ALPS Advisors, Inc. In this Schedule 13G13G/A ALPS Advisors, Inc. disclaims beneficial ownership, and has shared power to vote and to dispose of the 4,378,0656,072,740 common units.(g)13G13G/A filed with the SEC on January 26, 201825, 2021 jointly by First Trust Portfolios LP,L.P., First Trust Advisors L.P. and The Charger Corporation. In this Schedule 13G, First Trust Portfolios LP, First Trust Advisors L.P. and The Charger Corporation have shared power to vote 4,036,8365,991,341 common units and shared power to dispose of 4,040,3746,004,796 common units, and First Trust Portfolios L.P., First Trust Advisors L.P. and The Charger Corporation. disclaim beneficial ownership of all of said common units.(h)14, 201816, 2021 by Energy Income Partners, LLC. In this Schedule 13G,13G/A, Energy Income Partners LLC has shared power to vote and to dispose of the 5,752,8647,888,173 common units.13,28124,381 DSUs and 1,000 common units of the Partnership.20,79333,687 DSUs and 290 common units of the Partnership.14,046 DSUs and 995 TransCanada common shares.549,018184,062 options exercisable within 60 days for TransCanadaTC Energy common shares and 31,740 TransCanada33,442 TC Energy common shares held directly by Mr. Chapman.Share SavingsStock Purchase Plan account.(m)Includes 111,030 options exercisable within 60 days for TransCanada common shares, 6,014 TransCanadaaccount and 1,700 TC Energy common shares held directly and 3,531 TransCanadaby Mr. Brown.Share SavingsStock Purchase Plan accounts.(n)35,968 options exercisable within 60 days for TransCanada common shares and 565 TransCanada common shares held in her TransCanada 401(k) and Savings Plan.(o)Includes 64,621 options exercisable within 60 days for TransCanada common shares, 441 TransCanada376 TC Energy common shares held in his Employee Share SavingsStock Purchase Plan accounts and 500 TransCanada shares held by Mr. Hunter's parents.(p)376 TransCanada common shares held in his TransCanada 401K and Savings Plan account.(q)Includes 8,724 TransCanada10,844 TC Energy common shares held in his Employee Share Savings Plan account and 9,530 TransCanada9,816 TC Energy common shares held jointly with his spouse.(r)793 TransCanada354 TC Energy common shares held in her Employee Share Savings Plan account and 1,754 TransCanada common shares held by her spouse.(s)48,12058,877 DSUs and 1,290 common units of the Partnership, 7,009 TransCanada35,142 TC Energy common shares held directly, 9,530 TransCanada9,816 TC Energy common shares held with a spouse, 760,637208,112 options exercisable within 60 days for TransCanadaTC Energy common shares, 2,254 TransCanada common shares owned by immediate family members of which beneficial ownership of no common shares is disclaimed, and 45,229 TransCanada14,567 TC Energy common shares held in the TransCanadaTC Energy Employee Share Savings Plan, and 941 TransCanada474 TC Energy common shares held in the 401KTC Energy Employee Stock Purchase Plan, 1,060 TC Energy common shares indirectly held in a Registered Retirement Savings Plan and Savings1,029 TC Energy common shares indirectly held in a 401(k) Plan.22, 2018,24, 2021, subsidiaries of TransCanadaTC Energy own 17,084,831, or 23.96approximately 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 an effectivea two percent general partner interest in the Partnership through which it manages and operates the Partnership. TransCanadaTC Energy also owns 100 percent of our Class B units. For more details regarding the Class B units, see Notes 7,Note 10 13 and 14 within Part IV, Item 15. "Exhibits“Exhibits and Financial Statement Schedules."84 TC PipeLines, LPAnnual Report2017TransCanada,TC Energy, in connection with the ongoing operation and, if applicable, upon liquidation of the Partnership. These distributions and payments were determined by and among affiliated entities and, consequently, are not the result of arms-length negotiations.Operational Stage
Operational StageWe 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 2two percent to our General Partner. Additionally, the Class B units entitle TransCanadaTC Energy to receive an annual distribution based on 30 percent of GTN'sGTN’s annual distributions exceeding certain thresholds.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“incentive distribution rights".rights.” For further information about distributions, please read Part II Item 5. "Market“Market for Registrant'sRegistrant’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 StageLiquidationUpon 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. 2017.TransCanadaTC Energy whereby its funds are pooled with other TransCanadaTC Energy affiliates. The agreement gives Great Lakes the ability to obtain short-term borrowings to provide liquidityTC PipeLines, LPAnnual Report2017 8520172020 and 2016,2019, Great Lakes has anhad outstanding receivablereceivables from this arrangement amounting to $64$27 million and $27$34 million, respectively.Great LakesGreat Lakes earns significant transportation revenues from TransCanada and its affiliates, some of which are provided at discounted rates, negotiated rates and some at maximum recourse rates. Most recently, during 2017, Great Lakes signed a significant long-term contract with TransCanada that would allow TransCanada the abilityRelated Partytransport up to 0.711 billion cubic feet of natural gas per day on the Great Lakes system from the Manitoba/U.S. border to the U.S. border near Dawn Ontario beginning November 1, 2017. (Please see Part 1, Item 1. Business – "Recent Business Developments" for further details).For the year ended December 31, 2017, Great Lakes earned 57 percent of its transportation revenues from TransCanada and its affiliates (2016 – 68 percent; 2015 – 71 percent). Additionally, Great Lakes earned approximately one percent of its total revenues as affiliated rental revenue in 2017 (2016 – 1 percent and 2015 – 1 percent).At December 31, 2017, $20 million was included in Great Lakes' receivables in regards to the transportation contracts with TransCanada and its affiliates (December 31, 2016 – $19 million).In 2017, Great Lakes operated under a FERC approved 2013 rate settlement that includes a revenue sharing mechanism that requires Great Lakes to share with its customers certain percentages of any qualifying revenues earned above certain ROEs. A refund of $7 million was paid to shippers in 2017 relating to the year ended December 31, 2016, of which approximately 86 percent was made to affiliates of Great Lakes. For the year ended December 31, 2017, Great Lakes has recorded an estimated revenue sharing provision amounting to $40 million and Great Lakes expects that a significant percentage of the 2017 revenue sharing refund will be to its affiliates.Under the terms of the 2017 Great Lakes Settlement, beginning 2018, the revenue sharing was eliminated. Additionally, effective October 1, 2017, Great Lakes still charged customers rates in effect prior to the 2017 Great Lakes Settlement but only recognized revenue up to the amount of the new rates in the 2017 Great Lakes Settlement. The difference between these two amounts was recognized as a provision for rate refund (liability) on Great Lakes' balance sheet amounting to $8 million. Great Lakes expects that a significant percentage of the provision for rate refund will be to its affiliates as well. See Note 5 on Part IV within Item 15. "Exhibits and Financial Statement Schedules").PNGTSIn connection with the PXP project, PNGTS entered into a precedent agreement with TransCanada for capacity on its mainline system. Please see Part 1, Item 1. Business – "Recent Business Developments" for further details.AcquisitionsWe have participated in several business acquisitions with TransCanada that were accounted for as transactions between entities under common control. For more details regarding the transactions' size, structure and terms, see Notes 717 within Part IV, Item 15. "Exhibits“Exhibits and Financial Statement Schedules."TransCanadaTC Energy and its affiliates pursuant to operating agreements. Under these agreements, our pipeline systems are required to reimburse TransCanadaTC 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.86 TC PipeLines, LPAnnual Report20172017, 20162020, 2019 and 20152018 by TransCanada'sTC Energy’s subsidiaries and amounts payable to TransCanada'sTC Energy’s subsidiaries at December 31, 20172020 and 20162019 are summarized in Note 17 within Part IV, Item 15. "Exhibits“Exhibits and Financial Statement Schedules."TransCanada.TC Energy. In addition, each of our pipeline systems currently has other routine agreements with TransCanadaTC Energy that arise in the ordinary course of business, including agreements for services and other transportation and exchange agreementagreements and interconnection and balancing agreements.TransCanadaTC Energy and Conflicts of Interest ResolutionTransCanada,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."sole“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'sPartner’s actions must be made in its reasonable discretion."fair“fair and reasonable"reasonable” to the Partnership. In determining whether a transaction or resolution is "fair“fair and reasonable"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.TC PipeLines, LPAnnual Report2017 87Partner'sPartner’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."Directors,“Directors, Executive Officers and Corporate Governance"Governance” for additional information."Directors,“Directors, Executive Officers and Corporate Governance"Governance” for information about the independence of our General Partner'sPartner’s board of directors and its committees, which information is incorporated herein by reference in its entirety.Year ended December 31(thousands of dollars) 2017 2016 2015 Audit Fees(a)(b)(c) 861 1,071 1,067 Audit Related Fees – – – Tax Fees(d) – – – All Other Fees – – – Total 861 1,071 1,067 2020 2019 Audit Fees 994 1,185 Audit Related Fees — — — — All Other Fees — — Total 994 1,185 $200 thousand of the 2017 audit fees relate to ATM equity financing (2016 – $320 thousand and 2015 – $200 thousand).(b)$65 thousand of the 2017 audit fees relate to issuance of senior unsecured notes (2016 – none, 2015 – $150 thousand)(c)$26 thousand of 2015 audit fees related to advisory services for Class B issuance.(d)2017, 20162020 or 2015.88 TC PipeLines, LPAnnual Report20172017 89 2020 79"Index“Index to Financial Statements"Statements” set forth on Page F-1.90 TC PipeLines, LPAnnual Report2017TC PipeLines, LPAnnual Report2017 9192 TC PipeLines, LPAnnual Report201710.11*No.
Description10.2* 10.11.1*10.2.1* 10.2.2* 10.12*10.3 10.4 12.1Computation of Ratio of Earnings to Fixed Charges.21.110.521.1
Registrant (Incorporated by reference to Exhibit 21.1 to TC PipeLines,LP's Annual Report on Form 10-K for the year ended December 31, 2019).23.123.1 23.223.2 23.323.3 31.131.1 31.231.2 32.132.1 TC PipeLines, LPAnnual Report2017 93
32.299.1*99.1* 99.2* 99.3* 99.4* 99.2*No. Description 99.5* 99.6 99.7
1, 2021.99.3*Transportation Term Sheet between Great Lakes Gas Transmission Limited Partnership and TransCanada PipeLines Limited (Incorporated by reference to Exhibit 99.3 to TC PipeLines, LP's Form 10-Q filed on May 4, 2017).99.4*99.899.5*Transportation Service Agreement FT18659FT18150 between Great Lakes Gas Transmission Limited Partnership and ANR Pipeline Company, effective date April November 1, 2017. (Incorporated by reference from Exhibit 99.3 TC PipeLines, LP's Form 10-Q filed August 3, 2017).2021.99.6*99.9 99.10 99.11 99.12 99.13 99.14 99.15 99.16 99.17 99.18 99.19 99.20 99.21 101 The following materials from Exhibit 99.1 to TC PipeLines, LP'sLP’s Annual Report on Form 10-Q filed November 6, 2017).10-K for the year ended December 31, 2020 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)101.INSNo.XBRL Instance Document.
Description101.SCHXBRL Taxonomy Extension Schema Document.101.CAL104
Cover Page Interactive Data File (embedded within the Inline XBRL Taxonomy Extension Calculation Linkbase Document.101.DEFXBRL Taxonomy Definition Linkbase Document.101.LABXBRL Taxonomy Extension Label Linkbase Document.101.PREXBRL Taxonomy Extension Presentation Linkbase Document.
document)94 2017 2020 832624th day of February 2018.2021.TC PIPELINES, LP
(A Delaware Limited Partnership)
by its General Partner, TC PipeLines GP, Inc.By:
By:/s/ Brandon AndersonBrandon Anderson
Nathaniel A. BrownNathaniel A. Brown
President
TC PipeLines GP, Inc. (Principal Executive Officer)By:By: /s/ Nathaniel A. BrownNathaniel A. BrownController
William C. MorrisWilliam C. Morris
Vice President and Treasurer
TC PipeLines GP, Inc. (Principal Financial Officer)SignatureTitleDate
Signature
Title
Date/s/ Karl R. JohannsonKarl R. JohannsonChairFebruary 26, 2018
/s/ Brandon AndersonBrandon AndersonStanley G. Chapman IIIPresident and Principal Executive OfficerChair
February 26, 201824, 2021
Stanley G. Chapman III/s/ Nathaniel A. Brown Principal Executive Officer and President February 24, 2021 Nathaniel A. Brown Controller and /s/ William C. Morris Principal Financial Officer, Vice President and Treasurer
February 26, 201824, 2021/s/ M. Catharine DavisM. Catharine DavisWilliam C. MorrisDirectorFebruary 26, 2018/s/ Joel E. HunterJoel E. HunterDirectorFebruary 26, 2018
/s/ Walentin (Val) MiroshWalentin (Val) MiroshNadine E. Berge
Director
February 26, 201824, 2021
Nadine E. Berge/s/ Gloria L. Hartl Director February 24, 2021 Gloria L. Hartl /s/ Peggy A. Heeg Director February 24, 2021 Peggy A. Heeg /s/ Jack F. Stark Director February 24, 2021 Jack F. Stark DirectorFebruary 26, 2018/s/ Malyn K. Malquist Director February 24, 2021 Malyn K. Malquist DirectorFebruary 26, 20182017 95 2020Page No.Page No. CONSOLIDATED FINANCIAL STATEMENTS OF TC PIPELINES, LP F-2F-3F-4F-5F-6F-7F-8FINANCIAL STATEMENTS OF NORTHERN BORDER PIPELINE COMPANY F-35F-36F-37F-37F-38F-39F-40FINANCIAL STATEMENTS OF GREAT LAKES GAS TRANSMISSION LIMITED PARTNERSHIP F-51F-52F-53F-54F-552017 2020F-1REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRMTheand Unitholders
of TC PipeLines GP, Inc., the General Partner of TC PipeLines, LP, and Partners20172020 and 2016,2019, the related consolidated statements of income,operations, comprehensive income (loss), changes in partners'partners’ equity, and cash flows for each of the years in the three-year period ended December 31, 2017,2020, and the related notes (collectively, the consolidated financial statements). We also have audited the Partnership'sPartnership’s internal control over financial reporting as of December 31, 2017,2020, based on criteria established inInternal Control – Integrated Framework (2013)issued by the Committee of Sponsoring Organizations of the Treadway Commission.20172020 and 2016,2019, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2017,2020, 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, 2017,2020 based on criteria established inin Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.OpinionPartnership'sPartnership’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'sManagement’s Annual Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Partnership'sPartnership’s consolidated financial statements and an opinion on the Partnership'sPartnership’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.company'scompany’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 company'scompany’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 company; (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 company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company'scompany’s assets that could have a material effect on the financial statements./s/ KPMG LLPPartnership'sPartnership’s auditor since 2011.Texas
TX26, 2018F-2 24, 202120172020
December 31 (millions of dollars)
2017
2016(a) ASSETS Current Assets Cash and cash equivalents 33 64 Accounts receivable and other (Note 20) 42 47 Inventories 8 7 Other 7 7 90 125 Equity investments (Note 5) 1,213 918 Plant, property and equipment, net (Note 6) 2,123 2,180 Goodwill 130 130 Other assets 3 1 3,559 3,354
LIABILITIES AND PARTNERS' EQUITY
Current Liabilities Accounts payable and accrued liabilities 31 29 Accounts payable to affiliates (Note 17) 5 8 Accrued interest 12 10 Distributions payable 1 3 Current portion of long-term debt (Note 8) 51 52 100 102 Long-term debt (Note 8) 2,352 1,859 Deferred state income taxes (Note 24) 10 10 Other liabilities (Note 9) 29 28 2,491 1,999 Common units subject to rescission (Note 10) – 83
Partners' Equity (Note 10)
Common units 824 1,002 Class B units 110 117 General partner 24 27 Accumulated other comprehensive income (loss) (AOCI) (Note 11) 5 (2 ) Controlling interests 963 1,144 Non-controlling interest 105 97 Equity of former parent of PNGTS – 31 1,068 1,272 3,559 3,354 2020 2019 ASSETS Current Assets Cash and cash equivalents 200 83 40 43 0 14 Inventories 11 10 Other 6 6 257 156 1,070 1,098 1,747 1,528 71 71 TOTAL ASSETS 3,145 2,853 LIABILITIES AND PARTNERS’ EQUITY Current Liabilities Accounts payable and accrued liabilities 46 28 7 8 Accrued interest 11 11 423 123 487 170 1,768 1,880 10 7 47 36 2,312 2,093 Common units 637 544 Class B units 95 103 General partner 16 14 (13) (5) Controlling interests 735 656 Non–controlling interest 98 104 833 760 TOTAL LIABILITIES AND PARTNERS' EQUITY 3,145 2,853 (Note 22)Variable Interest Entities (Note 23)
(Note 2)(Note 25)
(Note 21)(a)Recast to consolidate PNGTS (Refer to Notes 2 and 7).2017 F-3 20202020 2019 2018 399 403 549 170 160 173 0 0 (537) 0 0 (59) Operation and maintenance expenses (64) (71) (67) Property taxes (26) (26) (28) General and administrative (10) (8) (6) Depreciation and amortization (89) (78) (97) (73) (83) (92) Net income (loss) before taxes 307 297 (164) (6) 1 (1) Net Income (loss) 301 298 (165) Net income attributable to non-controlling interests 17 18 17 Net income (loss) attributable to controlling interests 284 280 (182) Common units 278 267 (191) General Partner 6 5 (4) Class B units 0 8 13 284 280 (182) $ 3.90 $ 3.74 $ (2.68) 71.3 71.3 71.3 71.3 71.3 71.3
Year ended December 31 (millions of dollars except per common unit amounts)
2017
2016(a)
2015(a) Transmission revenues 422 426 417 Equity earnings (Note 5) 124 97 97 Impairment of equity-method investment (Note 5) – – (199 ) Operation and maintenance expenses (67 ) (58 ) (61 ) Property taxes (28 ) (27 ) (27 ) General and administrative (8 ) (7 ) (9 ) Depreciation (97 ) (96 ) (95 ) Financial charges and other (Note 12) (82 ) (71 ) (63 ) Net income before taxes 264 264 60 Income taxes (Note 24) (1 ) (1 ) (2 ) Net Income 263 263 58 Net income attributable to non-controlling interests 11 15 21 Net income attributable to controlling interests 252 248 37 Net income attributable to controlling interest allocation (Note 13) Common units 219 211 (2 ) General Partner 16 11 3 TransCanada and its subsidiaries 17 26 36 252 248 37 Net income per common unit (Note 13) – basic and diluted(b) $3.16 $3.21 $(0.03 ) Weighted average common units outstanding(millions) – basic and diluted 69.2 65.7 63.9 Common units outstanding, end of year(millions) 70.6 67.4 64.3 2020 2019 2018 Net income (loss) 301 298 (165) Other comprehensive income (loss) Change in fair value of cash flow hedges (Notes 11 and 19) (16) (13) (2) 7 (1) 5 Amortization of realized loss on derivative instrument (Notes 11 and 19) 0 0 1 1 1 (1) Comprehensive income (loss) 293 285 (162) Comprehensive income attributable to non-controlling interests 17 18 17 Comprehensive income (loss) attributable to controlling interests 276 267 (179) F-42017 2020COMPREHENSIVE INCOME
Year ended December 31 (millions of dollars)
2017
2016(a)
2015(a) Net income 263 263 58 Other comprehensive income Change in fair value of cash flow hedges (Notes 11 and 19) 5 3 – Reclassification to net income of gains and losses on cash flow hedges (Note 11) – (2 ) – Amortization of realized loss on derivative instrument (Notes 11 and 19) 1 1 1 Other comprehensive income on equity investments (Note 11) 1 – – Comprehensive income 270 265 59 Comprehensive income attributable to non-controlling interests 11 16 21 Comprehensive income attributable to controlling interests 259 249 38 (a)Recast to consolidate PNGTS (Refer to Notes 2 and 7).(b)Net income per common unit prior to recast (Refer to Note 2).2020 2019 2018 Cash Generated from Operations Net income (loss) 301 298 (165) Depreciation and amortization 89 78 97 0 0 537 0 0 59 Amortization of debt issue costs reported as interest expense 2 2 2 0 0 1 (170) (160) (173) 196 200 188 Change in other long-term liabilities 1 (1) (2) Equity allowance for funds used during construction (10) (2) (1) 4 (3) (3) 413 412 540 Investing Activities (10) (10) (9) (2) (4) 0 0 50 0 29 8 10 Capital expenditures (278) (75) (40) Other (1) (1) 4 (262) (32) (35) Financing Activities (189) (189) (218) (8) (13) (15) Distributions paid to non-controlling interests (23) (22) (14) 0 0 40 385 30 219 (199) (136) (516) Debt issuance costs 0 0 (1) (34) (330) (505) Increase/(decrease) in cash and cash equivalents 117 50 0 Cash and cash equivalents, beginning of year 83 33 33 Cash and cash equivalents, end of year 200 83 33 Interest payments paid 75 87 94 State income taxes paid 1 2 1 Supplemental information about non-cash investing and financing activities Accrued capital expenditures, net 8 4 2 2017 F-52020F-7CONSOLIDATED STATEMENTS OF CASH FLOWS
Year ended December 31 (millions of dollars)
2017
2016(a)
2015(a) Cash Generated From Operations Net income 263 263 58 Depreciation 97 96 95 Impairment of equity-method investment (Note 5) – – 199 Amortization of debt issue costs reported as interest expense (Note 12) 2 2 1 Amortization of realized loss on derivative instrument (Note 19) 1 1 1 Accrual of costs related to acquisition of 49.9% interest in PNGTS (Note 7) – – 2 Equity earnings from equity investments (Note 5) (124 ) (97 ) (97 ) Distributions received from operating activities of equity investments (Note 5) 140 153 119 Provision for deferred state income taxes (Note 24) – – 4 Provision for rate refund-PNGTS (Note 2) – – (101 ) Equity allowance for funds used during construction (1 ) – (1 ) Change in operating working capital (Note 15) (2 ) (1 ) (20 ) 376 417 260 Investing Activities Investment in Northern Border (Note 5) (83 ) – – Investment in Great Lakes (Note 5) (9 ) (9 ) (9 ) Distribution received from Iroquois as return of investment (Note 5) 5 – – Acquisition of a 49.34 percent in Iroquois and an additional 11.81 percent in PNGTS (Note 7) (646 ) – – Acquisition of 49.9 percent interest in PNGTS (Note 7) – (193 ) – Acquisition of the remaining 30 percent interest in GTN (Note 7) – – (264 ) Capital expenditures (29 ) (29 ) (54 ) Other 1 1 1 (761 ) (230 ) (326 ) Financing Activities Distributions paid (Note 14) (284 ) (250 ) (228 ) Distributions paid to Class B units (Note 10 and 14) (22 ) (12 ) – Distributions paid to non-controlling interests (5 ) (12 ) (21 ) Distributions paid to former parent of PNGTS (1 ) (9 ) (19 ) Common unit issuance, net (Note 10) 176 84 44 Common unit issuance subject to rescission, net (Note 10) – 83 – Equity contribution by the General Partner (Note 7) – – 2 Long-term debt issued, net of discount (Note 8) 802 209 618 Long-term debt repaid (Note 8) (310 ) (270 ) (425 ) Debt issuance costs (2 ) (1 ) (3 ) 354 (178 ) (32 ) Increase/(decrease) in cash and cash equivalents (31 ) 9 (98 ) Cash and cash equivalents, beginning of year 64 55 153 Cash and cash equivalents, end of year 33 64 55 Interest payments paid 79 66 59 State income taxes paid 2 2 2
Supplemental information about non-cash investing and financing activities
Accrued capital expenditures 9 – 10 Issuance of Class B units to TransCanada (Note 10) – – 95 (a)Recast to consolidate PNGTS (Refer to Notes 2 and 7).The accompanying notes are an integral part of these consolidated financial statements.F-6 TC PipeLines, LPAnnual Report2017TC PIPELINES, LPPARTNERS'PARTNERS’ EQUITY
Accumulated
Other
Comprehensive
Income
(Loss)(a)(c)
Limited Partners
(millions of units)
(millions of dollars)
General
Partner
Non-Controlling
Interest(d)
Total
Equity(d)
PNGTS(c)(d) Common Units Class B Units Partners' Equity at
December 31, 2014(d) 63.6 1,325 – – 29 (5 ) 323 146 1,818 Issuance of Class B Units (Note 7 and 10) – – 1.9 95 – – – – 95 Net income (loss)(d) – (2 ) – 12 3 – 21 24 58 Other Comprehensive Loss, net(d) – – – – – 1 – 1 ATM Equity Issuance, net (Note 10) 0.7 43 – – 1 – – – 44 Acquisition of the remaining interest in GTN (Note 7) – (124 ) – – (3 ) – (232 ) – (359 ) Equity Contribution (Note 7) – – – – 2 – – – 2 Distributions(d) – (221 ) – – (7 ) – (21 ) (19 ) (268 ) Partners' Equity at December 31, 2015(d) 64.3 1,021 1.9 107 25 (4 ) 91 151 1,391 Net income(d) – 211 – 22 11 – 15 4 263 Other Comprehensive Income, net(d) – – – – – 2 1 – 3 Common unit issuance subject to rescission, net(b) (Note 10) 1.6 81 – – 2 – – 83 Reclassification of common unit issuance subject to rescission, net(b) (Note 10) – (81 ) – – (2 ) – – – (83 ) ATM Equity Issuance, net (Note 10) 1.5 82 – – 2 – – – 84 Acquisition of 49.9 percent interest in PNGTS (Note 7) – (72 ) – – (1 ) – – (73 ) Distributions(d) – (240 ) – (12 ) (10 ) – (10 ) (4 ) (276 ) Former parent carrying amount of PNGTS(d) – – – – – – – (120 ) (120 ) Partners' Equity at
December 31, 2016(d) 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 10) 3.2 173 – – 3 – – – 176 Reclassification of common units no longer subject to rescission (Note 10) – 81 – – 2 – – – 83 Acquisition of interests in PNGTS and Iroquois (Note 7) – (383 ) – – (8 ) – – (32 ) (423 ) Distributions – (268 ) – (22 ) (16 ) – (3 ) (1 ) (310 ) Partners' Equity at
December 31, 2017(d) 70.6 824 1.9 110 24 5 105 – 1,068 Limited Partners General
PartnerNon-Controlling
InterestTotal
EquityCommon Units Class B Units (millions of units) (millions of dollars) (millions of units) (millions of dollars) (millions of dollars) (millions of dollars) (millions of dollars) (millions of dollars) Partners’ Equity at December 31, 2017 70.6 824 1.9 110 24 5 105 1,068 Net income — (191) — 13 (4) — 17 (165) Other comprehensive income — — — — — 3 — 3 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 (loss) — 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 Net income — 278 — 0 6 — 17 301 Other comprehensive income — — — — — (8) — (8) Distributions — (185) — (8) (4) — (23) (220) Partners' Equity at December 31, 2020 71.3 637 1.9 95 16 (13) 98 833 LossesAOCIaccumulated other comprehensive income (loss) (AOCI) and expected to be reclassified to net income in the next 12 months are estimated to be $2a loss of $9 million. These estimates assumeThis estimate assumes constant interest rates over time; however, the amounts reclassified will vary based on actual value of interest rates at the date of settlement.(b)These units are treated as outstanding for financial reporting purposes.(c)Equity of Former Parent of PNGTS.(d)Recast to consolidate PNGTS (Refer to Notes 2 and 7).2017 F-7 2020wholly-ownedwholly owned subsidiary of TransCanadaTC Energy Corporation (TransCanada(TC Energy Corporation together with its subsidiaries collectively referred to herein as TransCanada)TC Energy), to acquire, own and participate in the management of energy infrastructure assets in North America.The Partnership owns interests in the following natural gas pipeline systems through three intermediate limited partnerships (ILPs), TC GL Intermediate Limited Partnership, TC PipeLines Intermediate Limited Partnership and TC Tuscarora Intermediate Limited Partnership:PipelineLengthDescriptionOwnership
PipelineLength Description Ownership Gas Transmission Northwest LLC (GTN)GTN1,377 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 Pipeline LLC (Bison)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 percentNorth Baja Pipeline, LLC (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 percentTuscarora Gas Transmission Company (Tuscarora)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 percentNorthern Border Pipeline Company (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 Partners, L.P.Northern Border Pipeline Company Holdings LLC owns the remaining 50 percent of Northern Border.
50 percentPortland Natural Gas Transmission System (PNGTS)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 a 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%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(a)Great Lakes Gas Transmission Limited Partnership (Great Lakes)
2,115 miles
Connects with the TransCanadaTC 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. TransCanadaTC Energy owns the remaining 53.55 percent of Great Lakes.
46.45 percentIroquois Gas Transmission System, L.P (Iroquois)Iroquois 416 miles
Extends from the TransCanadaTC 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 TransCanadaby: TC Energy (0.66 percent), Dominion Midstream (25.93 percent) and Dominion Resources (24.07Berkshire Hathaway (50 percent). Iroquois is maintained and operated by a subsidiary of Iroquois.
49.34 percent(b)(a)On June 1, 2017, the Partnership acquired an additional 11.81 percent from TransCanada resulting in 61.71 percent ownership in PNGTS. (Refer to Note 7).(b)Effective June 1, 2017 (Refer to Note 7).F-8 TC PipeLines, LPAnnual Report2017wholly-ownedwholly owned subsidiary of TransCanada.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 IDRsIncentive Distribution Rights (IDRs) and an effective twoa 2 percent general partner interest in the Partnership at December 31, 2017. TransCanada2020. TC Energy also indirectly holds an additional 11,287,725 common units, for a total ownership of 24.2approximately 24 percent of our outstanding common units and 100 percent of our Class B units at December 31, 20172020 (Refer to Note 10).United StatesU.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, 20172020 and 20162019 and the results of its operations, cash flows and changes in partners'partners’ equity for the years ended December 31, 2017, 20162020, 2019 and 2015.variable interestits interests in entities (VIEs) forover which it is consideredable to be the primary beneficiary as well as voting interest entities in which it has a controlling financial interest.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.TransCanadaTC Energy are considered common control transactions. When businesses that will be consolidated are acquired from TransCanadaTC Energy by the Partnership, the historical financial statements are required to be recast, exceptwith the exception of net income (loss) per common unit, to include the acquired entities for all periods presented.TransCanada,TC Energy, which will be accounted for by the equity method, the financial information is not required to be recast and the transaction is accounted for prospectively from the date of the acquisition.On June 1, 2017, the Partnership acquired from a subsidiary of TransCanada an additional 11.81 percent interest in PNGTS, resulting in the Partnership owning 61.71 percent in PNGTS (Refer to Note 7). As a result of the Partnership owning 61.71 percent of PNGTS, the Partnership's historical financial information was recast, except net income (loss) per common unit, to consolidate PNGTS for all the periods presented in these consolidated financial statements. Additionally, this acquisition was accounted for as transaction between entities under common control, similar to pooling of interests, whereby the assets and liabilities of PNGTS were recorded at TransCanada's carrying value.Also, on June 1, 2017, the Partnership acquired from subsidiaries of TransCanada a 49.34 percent interest in Iroquois (Refer to Note 7). Accordingly, this transaction was accounted for as a transaction between entities under common control, similar to pooling of interest, whereby the equity investment in Iroquois was recorded at TransCanada's carrying value and was accounted for prospectively.On January 1, 2016, the Partnership acquired a 49.9 percent interest in PNGTS (2016 PNGTS Acquisition) from a subsidiary of TransCanada. The 2016 PNGTS Acquisition was accounted for as a transaction between entities under common control, similar to a pooling of interests, whereby the equity investment in PNGTS was recorded at TransCanada's carrying value and the total excess purchase price paid was recorded as a reduction in Partners' Equity. Accordingly, the equity investment on PNGTS is being eliminated as a result of consolidating PNGTS for all periods presented. Refer to Note 7 for additional disclosure regarding the PNGTS Acquisition.On April 1, 2015, the Partnership acquired the remaining 30 percent interest in GTN from a subsidiary of TransCanada. This acquisition resulted in being wholly-owned by the Partnership. Prior to this transaction, the remaining 30 percent interest held by a subsidiary of TransCanada was reflected as non-controlling interest in the Partnership's consolidated financial statements. The acquisitions of this already-consolidated entity was accounted as a transaction between entities under common control, similar to a pooling of interests, whereby the acquired interests were recorded at TransCanada's carrying value and the total excess purchase price paid was recorded as a reduction in Partners' Equity. Refer to Note 7 for additional disclosures regarding these acquisitions.TC PipeLines, LPAnnual Report2017 F-9Partnership'sPartnership’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) (e) pipelines'pipelines’ tariff.(f) market.(g)net realizable value.Property and EquipmentPlant, propertyPipeline facilities and compression equipment have an estimated useful life of 20 to 77 years and metering and other equipment ranges from 5 to 77 years. Depreciation is calculated on a straight-line composite basis over the assets' estimated useful lives. Repair and maintenance costs are expensed as incurred. Costs that are considered a betterment are capitalized.Partnership'sPartnership’s subsidiaries capitalize a carrying cost on funds invested in the construction of long livedlong-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 property and equipment on the balance sheets. Amounts includedconstruction workthe Consolidated Statements of Operations and broken out further in progress are not amortized until transferred into service.(h) Note 12. Capitalized AFUDC equity amounts during the years ended December 31, 2020, 2019 and 2018 were $10 million, $2 million and $1 million, respectively. Capitalized AFUDC Debt during the year ended December 31, 2020 was $1.3 million (2019 and 2018 - less than $1 million). Refer to Note 12.(i) property 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.F-10 20172020F-11(j) Partners' Equity(k) Transmissioninratably over the period in whichterm 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 provided. Whenperformed. The Partnership utilizes the practical expedient of recognizing revenue as invoiced. Revenues are invoiced and paid on a rate casemonthly basis. The Partnership’s pipeline systems do not take ownership of the natural gas that is pending finaltransported for customers. Revenues from contracts with customers are recognized net of any taxes collected from customers, which are subsequently remitted to governmental authorities.approval,regulations and, as a result, a portion of the revenuerevenues collected ismay be subject to possible refund. As of December 31, 2017,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 Partnership has not recognized any transmission revenue that is subject to possible refund.For the years ended December 31, 2014facts and in January 2015, as required by FERC, PNGTS was charging customers rates applied for in its 2008 and 2010 rate cases. Due to the uncertainty in the outcome of its two outstanding rate cases, PNGTS was only recognizing revenue up to the amountcircumstances of the interim FERC approved rates. The difference between these amounts wasproceeding. Any allowances that are recognized during the proceeding process are refunded or retained, as a provision (liability) for rate refund in the consolidated balance sheet. On February 19, 2015, FERC approved PNGTS' final rates and PNGTS was required to refund the customers within sixty days of the issuance of the final rates, including interestapplicable, at the quarterly average prime interest rate as prescribed by FERC. Total refunds accumulatedtime a regulatory decision becomes final. Refer to $114.3 million, including $8.0 million of interest, and were paid to customers on April 15, 2015.(l) Note 6 for detailed disclosures regarding the Partnership’s revenues.Debt issuancesConsistent with debt discount, debt issuance costs are presented in the balance sheet as a direct deduction from the carrying amount of debt liabilities, consistent with debt discount and premiums.liabilities. The amortization of debt issuance costs is reported as interest expense.(m) FederalPartnership'sPartnership’s taxable income or loss, which may vary substantially from the net income or loss reported in the consolidatedConsolidated statement of income,operations, is includable in the U.S. federal income tax returns of each partner. The aggregate difference in the basis of the Partnership'sPartnership’s net assets for financial and income tax purposes cannot be readily determined because all information regarding each partner'spartner’s tax attributes related to the partnership is not available.asset – liabilityasset-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.(n) for impairment or more frequently if any indicators of impairment are evident. The Partnership can initially assessesassess qualitative factors to determine whether events or changes in circumstances indicate that the goodwill might be impaired. The factors the Partnership considers include, but are not limited to, macroeconomic conditions, industry and market considerations, cost factors, historical and forecasted financial results, and events specific to that reporting unit. If the Partnership doesconcludes there is not concludea greater than 50 percent likelihood that it is more likely than not thatthe fair value of the reporting unit is greater than its carrying value, the first stepPartnership will then perform the quantitative goodwill impairment test. The Partnership cantwo-stepquantitative goodwill impairment test for any of its reporting units. If the quantitative goodwill impairment test is performed, by comparingthe Partnership compares the fair value of the reporting unit to its bookcarrying value, which includesincluding its goodwill. If the fair value is less than book value, an impairment is indicated and a second step is performed to measure the amount of the impairment. In the second step, the implied fair value of goodwill is calculated by deducting the recognized amounts of all tangible and intangible net assets of the reporting unit from the fair value determined in the initial assessment. If the carrying value of a reporting unit including its goodwill exceeds its fair value, goodwill impairment is measured at the calculated impliedamount by which the reporting unit’s carrying value exceeds its fair value.impairment charge is recorded.At December 31, 2017 and 2016, we had $130 million of goodwill recorded on our consolidated balance sheet related to the North Baja ($48 million) and Tuscarora ($82 million) acquisitions. No impairment of goodwill existed at December 31, 2017.TransCanada,affiliates under TC Energy, also known as "dropdowns",“dropdowns,” as transactions between entities under common control. Using this approach, the assets and liabilities of the acquired entities are recorded at TransCanada'sTC Energy’s carrying value. In the event recasting is required, the Partnership'sPartnership’s historical financial information will be recast, exceptwith 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.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.TC PipeLines, LPAnnual Report2017 F-11(o) Partners’ equity.Considerable judgmentJudgment is required in developing these estimates.(p) For all hedging relationships, the Partnership formally documents the hedging relationship and its risk management objective and strategy for undertaking the hedge, the hedging instrument, the hedged transaction, the nature of the risk being hedged, how the hedging instrument's effectiveness in offsetting the hedged risk will be assessed prospectively and retrospectively, and a description of the method used to measure ineffectiveness. The Partnership also formally assesses, both at the inception of the hedging relationship and on an ongoing basis, whether the derivatives that are used in hedging relationships are highly effective in offsetting changes in cash flows of hedged transactions. For derivative instruments that are designated and qualify as part ofIn a cash flow hedging relationship, the effective portionchange in the fair value of the gain or loss on thehedging 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. Gains and losses onearnings or is reclassified immediately to net income when the derivative representing either hedge ineffectivenesshedged item is sold or hedge components excluded from the assessment of effectiveness are recognized in current earnings.The Partnership discontinues hedge accounting prospectivelyterminated early, or when it determinesbecomes probable that the derivative is no longer effective in offsetting cash flows attributable to the hedged risk, the derivative expires or is sold, terminated, or exercised, the cash flow hedge is de-designated because a forecasted transaction is not probable of occurring, or management determines to remove the designation of the cash flow hedge.In all situations in which hedge accounting is discontinued and the derivative remains outstanding, the Partnership continues to carry the derivative at its fair value on the balance sheet and recognizes any subsequent changes in its fair value in earnings. When it is probable that a forecastedanticipated transaction will not occur,occur.Partnership discontinuesderivatives do not meet the specific criteria for hedge accounting and recognizes immediatelytreatment. In these instances, the changes in earnings gains and losses that were accumulatedfair value are recorded in other comprehensivenet income related toin the hedging relationship.(q) period of change.systemsystem’s assets have indeterminate lives and, accordingly, has recorded no0 asset retirement obligation as of December 31, 20172020 and 2016.(r) Government RegulationPartnership's subsidiariesPartnership and its pipeline systems are subject to regulation by FERC. Under regulatoryvarious legal proceedings in the ordinary course of business. Our accounting principles, certain assetsfor contingencies covers a variety of business activities, including contingencies for legal and environmental liabilities. The Partnership accrues for these contingencies when the assessments indicate it is probable that a liability has been incurred or liabilities that result from the regulated ratemaking process may be recorded that wouldan asset will not be recorded under GAAP for non-regulated entities. The timingrecovered, and an amount can be reasonably estimated in accordance with ASC 450, Contingencies. Wecertain revenues and expenses in our regulated businessthe ultimate outcome or resolution. Actual results may differ from estimates resulting in an impact, positive or negative, on earnings and cash flow. Contingencies 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. might result in a gain are not accrued in our consolidated financial statements.2017,2020, the Partnership had regulatory assets amounting to nil reported as partis not aware of other current assets inany contingent liabilities that would have a material adverse effect on the balance sheet representing volumetric fuel tracker assets that are settled with in-kind exchanges with customers continually (2016 – $1 million). Regulatory liabilities are included in other long-term liabilities (refer to Note 9). AFUDC is capitalized and included in plant, property and equipment.F-12 TC PipeLines, LPAnnual Report2017
Partnership’s financial condition, results of operations or cash flows.2017InventoryJuly 2015, the FASB issued new guidance on simplifying the measurement of inventory. The new guidance specifies that an entity should measure inventory within the scope of this update at the lower of cost and net realizable value. Net realizable value is the estimated selling price in the ordinary course of business, less reasonably predictable costs of completion, disposal and transportation. This new guidance was effective January 1, 2017, was applied prospectively and did not have a material impact on the Partnership's consolidated balance sheet.Equity method and joint venturesIn MarchJune 2016, the FASBFinancial Accounting Standards Board (FASB) issued new guidance that simplifies the transition to equity method accounting.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 eliminatesamends the requirement to retroactively applyimpairment 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 equity method of accounting when an increase in ownership interest in an investment qualifies for equity method accounting.amortized cost basis. The new guidance isbecame effective January 1, 20172020 and was applied prospectively.using a modified retrospective approach. The applicationadoption of this new guidance did not have a material impact on the Partnership'sPartnership’s consolidated financial statements.2016,2018, the FASB issued new guidance on consolidation relatingfor determining whether fees paid to decision makers and service providers are variable interests for indirect interests held through related parties that are under common control. TheThis new guidance amends the consolidation requirements such that if a decision maker is required to evaluate whether it is the primary beneficiary of a variable interest entity (VIE), it will need to consider only its proportionate indirect interest in the VIE held through a common control party. The guidance wasbecame effective January 1, 2017,2020, and was applied retrospectively andon a retrospective basis. The adoption of this new guidance did not resulthave a material impact on the Partnership’s consolidated financial statements.any changeresponse to our consolidation conclusions.Future accounting changesRevenuethe expected cessation of the London Interbank Offered Rate (LIBOR) from contracts with customersIn 2014,late 2021 to mid-2023, the FASB issued new optional guidance on revenue from contracts with customers.that eases the potential burden of accounting for reference rate reform. The new guidance requiresprovides optional expedients for contracts and hedging relationships that an entity recognize revenue in accordance with a prescribed model. This model is used to depict the transfer of promised goods or services to customers in an amount that reflects the total consideration to which it expects to be entitled during the termare affected by reference rate reform, if certain criteria are met. Each of the contract in exchange for those goods or services. The new guidance also requires additional disclosures about the nature, amount, timing and uncertainty of revenue and the related cash flows. The Partnership will adopt the new standard on the effective dateexpedients can be applied as of January 1, 2018. There are two methods in which the new standard can be adopted: (1) a full retrospective approach with restatement of all prior periods presented, or (2) a modified retrospective approach with a cumulative-effect adjustment2020 through December 31, 2022. For eligible hedging relationships existing as of the date of adoption. The Partnership will adopt the guidance using the modified retrospective approach with the cumulative-effect of the adjustment recognized at the date of adoption, subject to allowableJanuary 1, 2020 and elected practical expedients.Theprospectively, the Partnership has identified all existing customer contracts that are withinapplied the scope of the new guidance. The Partnership has completed its analysis and has not identified any material differences in the amount and timing of revenue recognition as a result of implementing the new guidance. The Partnership will not require a cumulative-effect adjustmentoptional expedient allowing an entity to opening partners' equity on January 1, 2018.Although consolidated revenues will not be materially impacted by the new guidance, the Partnership will be required to add significant disclosures based on the prescribed requirements. These new disclosures will include information regarding the significant judgments used in evaluating when and how revenue is recognized and information related to contract assets and deferred revenues. In addition, the new guidance requiresassume that the Partnership's revenue recognition policy disclosure includes additional detail regarding the various performance obligations and the nature, amount, timing and estimateshedged forecasted transaction in a cash flow hedge is probable of revenue and cash flows generated from contracts with customers. The Partnership has developed draft disclosures required in the first quarter 2018 with a particular focus on the scope of contracts subject to disclosure of future revenues from remaining performance obligations. The Partnership has addressed system and process changes necessary to compile the information to meet the recognition and disclosure requirements of the new guidance.LeasesIn February 2016, the FASB issued new guidance on the accounting for leases. The new guidance amends the definition of a lease requiring the customer 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 in order for the arrangement to qualify as a lease. 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 thanTC PipeLines, LPAnnual Report2017 F-1312 months. Leases will be classified as finance or operating, with classification affecting the pattern and classification of expense recognition in the income statement. The new guidance does not make extensive changes to lessor accounting.The new guidance is effective on January 1, 2019, with early adoption permitted. A modified retrospective transition approach is required for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements, with certain practical expedients available. Theoccurring.The Partnership is continuing to identify and analyze existing lease agreements to determine the effect of adoption of the new guidancereference rate reform on its consolidated financial statements.statements The Partnership is also addressing systemwill continue to evaluate the timing and process changes necessarypotential impact of adoption of other optional expedients when deemed necessary.compileTuscarora and North Baja for impairment at least annually or more frequently if indicators of impairment are evident.information to meet the recognition and disclosure requirements of the new guidance. The Partnership continues to monitor and analyze additional guidance and clarification provided by FASB.Goodwill ImpairmentIn January 2017, the FASB issued new guidance on simplifying the test for goodwill impairment by eliminating the requirement to calculate the impliedestimated fair value of Tuscarora not exceeding its carrying value, including goodwill that primarily resulted from the 2019 Tuscarora Settlement as part of the 2018 FERC Actions. As a result, we recorded a goodwill impairment charge amounting to measure the impairment charge. Instead, entities will record$59 million against Tuscarora’s goodwill balance of $82 million.charge based on the excess$71 million of a reporting unit's carrying amount over its fair value. This new guidance is effective January 1, 2020 and will be applied prospectively, however, early adoption is permitted.Hedge AccountingIn August 2017, the FASB issued new guidance on hedge accounting, making more financial and nonfinancial hedging strategies eligible for hedge accounting. The new guidance amends the presentation requirements relatinggoodwill related to the change in fair value ofTuscarora ($23 million) and North Baja ($48 million) reporting units.derivative and additional disclosure requirements include cumulativequarterly basis adjustments for fair value hedgesduring 2020, we evaluated changes within our business and the effect of hedging on individual statement of income line items.external environment including considerations regarding whether such changes are permanent, to determine whether a triggering event had occurred. This new guidance is effective January 1, 2019 with early adoption permitted. The Partnership has elected to apply this guidance effective January 1, 2018. The Partnership has completed its analysis and does not expectincluded the application of this guidance to have a material impact on its consolidated financial statements.NOTE 4 THE 2017 TAX ACTOn December 22, 2017, the President of the United States signed into law the 2017 Tax Act. This legislation provides for major changes to U.S. corporate federal tax law. As mentioned in Note 2, we are a non-taxable limited partnership, and income taxes owed as a result of our earnings are the responsibility of our partners, therefore no amounts have been recorded in the Partnership's financial statements as a result of the 2017 Tax Act.Our pipeline systems are regulated by the FERC, which approves the systems' rates on a cost-of-service basis and provides for a recovery of our ultimate taxable owners' income tax expense and related balance sheet accounts as components of the maximum recourse rates that may be charged to customers. As a non-taxable entity, the Partnership does not recognize federal income tax expense nor has it established the related federal deferred income tax assets or liabilities. Income tax related expenses, benefits, assets, and liabilities attributable to regulated operations are the responsibility of the ultimate taxable owners of the Partnership and any adjustment to income tax accounts following the 2017 Tax Act must be evaluated by those owners.Any changes to the maximum recourse rates charged by our pipeline systems following the 2017 Tax Act will be reflected as those rates are revised through future rate proceedings individually unless superseded through other possible future action by the FERC. The Partnership cannot predict the ultimate impact of the 2017 Tax Act on future revenues of our pipeline systems.At December 31, 2017, the Partnership considers itsquarterly assessment of the impact of COVID-19 on our North Baja and Tuscarora reporting units. Through our quarterly analysis, no triggering events were identified.2017 Tax ActPartnership's Tuscarora and North Baja reporting units:be its best interpretationthe last quantitative model. The multiples and discount rates identified for the current year, used in our qualitative model, are reflective of available guidance. Should additional guidancethe long-term outlook for Tuscarora and North Baja, in line with their underlying asset lives;impact$71 million of goodwill related to the 2017 Tax ActTuscarora ($23 million) and North Baja ($48 million) acquisitions. Adverse changes to our key considerations could, however, result in future impairments on non-taxable partnerships be provided by regulatory, tax and accounting authorities or other sources in the future, the Partnership will review the approach used and adjust as appropriate.our goodwill. 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 TransCanada.TC Energy. The Iroquois pipeline system is operated by Iroquois Pipeline Operating Company, a wholly owned subsidiary of Iroquois. The Partnership uses the equity method of accounting for its interests in its equity investees. The Partnership's equity investments are held through our ILPs that are considered to be variable interest entities (VIEs). Refer to Note 23, Variable Interest Entities.F-14 TC PipeLines, LPAnnual Report2017
Equity Earnings(b)
Equity Investments
Year ended December 31
December 31
Ownership
Interest at
December 31,
2017(millions of dollars)
2017
2016(c)
2015
2017
2016(c) Northern Border(a) 50.00% 67 69 66 512 444 Great Lakes 46.45% 31 28 31 479 474 Iroquois 49.34% 26 – – 222 – 124 97 97 1,213 918 Ownership
Interest atEquity Investments December 31,
2020Year ended December 31 December 31 (millions of dollars) 2020 2019 2018 2020 2019 50.00 % 76 69 68 407 422 Great Lakes 46.45 % 56 51 59 509 491 Iroquois 49.34 % 38 40 46 154 185 170 160 173 1,070 1,098 Partnership'sPartnership’s acquisition of an additional 20 percent in April 2006.investee'san 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, no0 impairment charge was recorded by the Partnership on its equity investees for all the periods presented here excepthere.$199 millioncarrying amounts may not be recoverable. We performed a qualitative analysis to determine if there was a non-temporary decline in our equity investments' fair value and no triggers were identified. As a result, we continue to believe no impairment recognized in 2015exists on our investmentequity investments. There is a risk that adverse changes in Great Lakes as discussed below.(c)Recastour analysis could result in additional quantitative steps to eliminateevaluate our equity earnings from PNGTS and consolidate PNGTS (Refer to Notes 2 and 7).As a result of adoption of FASB ASU 2016-15,Statement of Cash Flows: Classification of Certain Cash Receipts and Cash Payments, the Partnership changed its method of accounting for the classification of distributions received from equity investments from cumulative earnings approach to nature of distributions approach effective January 1, 2014, as it is more representative of the nature of the underlying activities of the investees that generated the distributions. As a result, distributions received from equity method investees in 2015, amounting to $25 million, have been reclassified from investing activities to cash generated from operations in the consolidated statement of cash flows.20172020 were $145$225 million (2016 – $153(2019 - $258 million; 2015 – $1192018 - $198 million) of which $5$29 million (2016(2019 - $58 million and 2015 – none)2018 - $10 million) was considered a return of capital and is included in Investing activities in the Partnership'sPartnership’s consolidated statement of cash flows. The return of capital was related to our investment in Northern Border and Iroquois (see further discussion below).The Partnership, through its interest in Intermediate Limited Partnership owns a 50 percent general partner interest in Northern Border. The other 50 percent partnership interest in Northern Border is held by ONEOK Partners, L.P., a publicly traded limited partnership.TC PipeLines Intermediate Limited Partnership, as oneLP Annual Report 2020F-15general partners, may be exposed to the commitments and contingencies of Northern Border. The Partnership holds a 98.9899 percent limited partnership interest in TC PipeLines Intermediate Limited Partnership.On September 1, 2017,year ended December 31, 2020, the Partnership made an equity contribution toreceived distributions from Northern Border amounting to $91 million (2019 - $144 million; 2018 – $83 million. This amount representsmillion) The $144 million received in 2019 included the Partnership's 50 percent share of a $166 million capital contribution request fromthe Northern Border to reduce the outstanding balance of its$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 to increase its available borrowing capacity.no0 undistributed earnings from Northern Border for the years ended December 31, 2017, 20162020, 2019 and 2015.2018. At December 31, 20172020 the Partnership had a $115 million (December 31, 2016 – $1162019 - $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'sPartnership’s investment in Northern Border relating to the Partnership'sPartnership’s April 2006 acquisition of an additional 20 percent general partnership interest in Northern Border.Northern Border's 2013 settlement agreement required Northern Border to file for new rates no later than January 1, 2018. On December 4, 2017, Northern Border filed a rate settlement with FERC which precluded the need to file a general rate case by January 1, 2018. The 2017 Northern Border Settlement, which was approved by FERC on February 23, 2018, provides for tiered rate reductions beginning January 1, 2018, with no change to the underlying rate design. The 2017 Northern Border Settlement does not contain a moratorium provision and, unless superseded by a subsequent rate case or settlement, recourse rates in effect at December 31, 2017, will decrease by 5.0% on January 1, 2018; by an additional 5.50% on April 1, 2018; and by an additional 2.0% beginning January 1, 2020 through December 31, 2023, when Northern Border will be required to establish new rates. This equates to an overall rate reduction of 12.5% by January 1, 2020 from the recourse rates in effect at December 31, 2017.TC PipeLines, LPAnnual Report2017 F-15The 2017 Northern Border Settlement will provide Northern Border with rate stability over the longer term. We do not believe that the rate reduction as described above will have a material impact on the Partnership's results and, therefore, we do not believe the settlement outcome has negatively impacted the underlying value of our investment in Northern Border. The overall long-term market fundamentals of Northern Border continue to be positive due to its strategic footprint. Northern Border remains a key competitive pipeline and continues to operate at full capacity connecting major supply basins with communities in the Midwestern U.S. Accordingly, no impairment has been identified in our investment in Northern Border.December 31 (millions of dollars)
2017
2016 Assets Cash and cash equivalents 14 14 Other current assets 36 36 Plant, property and equipment, net 1,063 1,089 Other assets 14 14 1,127 1,153 Liabilities and Partners' Equity Current liabilities 38 38 Deferred credits and other 31 28 Long-term debt, net(a) 264 430 Partners' equity Partners' capital 795 659 Accumulated other comprehensive loss (1 ) (2 ) 1,127 1,153 Year ended December 31 (millions of dollars)
2017
2016
2015 Transmission revenues 291 292 286 Operating expenses (78 ) (72 ) (70 ) Depreciation (59 ) (59 ) (60 ) Financial charges and other (18 ) (21 ) (22 ) Net income 136 140 134 2020 2019 Assets Cash and cash equivalents 31 21 Other current assets 38 37 Property, plant and equipment, net 977 989 Other assets 12 12 1,058 1,059 Liabilities and Partners’ Equity Current liabilities 52 42 Deferred credits and other 42 39 380 364 Partners’ equity Partners’ capital 584 615 Accumulated other comprehensive loss 0 (1) 1,058 1,059 2020 2019 2018 Transmission revenues 308 300 289 Operating expenses (77) (82) (78) Depreciation (62) (62) (60) Financial charges and other (18) (18) (15) Net income 151 138 136 No2017 or 2016.through its interest in TC GL Intermediate Limited Partnership, ownsis considered to have a 46.45 percent general partnervariable interest in Great Lakes. TransCanada ownsLakes, which is accounted for as an equity investment as we are not its primary beneficiary. A variable interest entity is a legal entity that either does not have sufficient equity at risk to finance its activities without additional subordinated financial support, is structured such that equity investors lack the other 53.55 percent partnership interest. TC GL Intermediate Limited Partnership, as oneability 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 general partners, may be exposedentity.commitments and contingenciesPartnership's consolidated statement of cash flows.Lakes. The Partnership holds a 98.9899 percent limited partnership interest in TC GL Intermediate Limited Partnership.no0 undistributed earnings from Great Lakes for the years ended December 31, 2017, 2016,2020, 2019, and 2015.The Partnership made2018.contributionsmethod goodwill related to Great Lakes amounted to $260 million (December 31, 2019 - $260 million). The equity method goodwill relates to the Partnership’s February 2007 acquisition of $4 million and $5 million in the first and fourth quarter of 2017, respectively. These amounts represent the Partnership'sa 46.45 percent sharegeneral partnerto make scheduled debt repayments.During the fourth quarter of 2015, we recorded an impairment charge of $199 million on our investment in Great Lakes. The impairment charge was the result of our determination that our investment in Great Lakes' long-term value had been adversely impacted by the changing natural gas flows in its market region and that other strategic alternatives to increase its utilization or revenue were no longer feasible. The impairment charge reducedis the difference between the carrying value of our investment in Great Lakes and the underlying equity in theGreat Lakes’ net assets, to $260 million and the difference represented the equity method goodwill remaining in our investment in Great Lakes relating to the Partnership's February 2007 acquisition of a 46.45 percent general partner interest in Great Lakes.On October 30, 2017, Great Lakes filed a rate settlement with FERC to satisfy its obligations from its 2013 rate settlement for new rates to be in effect by January 1, 2018. The 2017 Great Lakes Settlement does not contain a moratorium provision and Great Lakes will be required to file for new rates no later than March 31, 2022, with new rates to be effective October 1, 2022. The 2017 Great Lakes Settlement, which was approved by FERC on February 22, 2018, decreased Great Lakes' maximum transportation rates by 27 percent effective October 1, 2017. At December 31, 2017, the estimation of fair value on the remaining equity investment in Great Lakes was completed and we concluded the fair value of our investment in Great Lakes has not materially changed from 2015.F-16 TC PipeLines, LPAnnual Report2017The assumptions we used in the analysis related to the estimated fair value of our remaining equity investment in Great Lakes included the reduction in Great Lakes' rates effective October 1, 2017. The reduction in rates was offset by expected cash flows from the long-term transportation contract with the TransCanada other revenue opportunities on the system and the settlement's elimination of the revenue sharing mechanism with its customers. Although evolving market conditions and other factors relevant to Great Lakes' long term financial performance have remained positive, 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.Our key assumptions could be negatively impacted by near and long-term conditions including:•future regulatory rate action or settlement,•valuation of Great lakes in future transactions,•changes in customer demand at Great Lakes for pipeline capacity and services,•changes in North American natural gas production in the major producing basins,•changes in natural gas prices and natural gas storage market conditions,•discount rates and multiples used, and•changes in other long-term strategic objectives.December 31 (millions of dollars)
2017
2016 Assets Current assets 107 66 Plant, property and equipment, net 701 714 808 780
Liabilities and Partners' Equity
Current liabilities 75 40 Long-term debt, net(a) 259 278 Other long term liabilities 1 – Partners' equity 473 462 808 780 Year ended December 31 (millions of dollars)
2017
2016
2015 Transmission revenues 181 179 177 Operating expenses (66 ) (69 ) (59 ) Depreciation (29 ) (28 ) (28 ) Financial charges and other (20 ) (21 ) (23 ) Net income 66 61 67 2020 2019 Assets Current assets 66 72 Property, plant and equipment, net 716 685 782 757 Liabilities and Partners’ Equity Current liabilities 38 33 198 219 Other long-term liabilities 9 6 Partners’ equity 537 499 782 757 2020 2019 2018 Transmission revenues 239 238 246 Operating expenses (70) (79) (68) Depreciation (33) (32) (32) Financial charges and other (15) (16) (18) Net income 121 111 128 $19$31 million as of December 31, 20172020 (December 31, 2016 – $192019 - $21 million).On June 1, 2017, the Partnership, through its interest in TC PipeLines Intermediate Limited Partnership acquired a 49.34 percent interest in Iroquois. 2017, The2020, the Partnership received distributions from Iroquois amounting to $27$86 million (2019 - $55 million: 2018 - $56 million) which includes the Partnership'sPartnership’s 49.34 percent share of the Iroquois unrestricted cash distribution as part of its 2017 acquisition agreement with Iroquois amounting to approximately $5 million (Refer to Note 7)(2019 - $8 million) . This amount isdistributions received asa return of investment in the Partnership'sPartnership’s consolidated statement of cash flows.no0 undistributed earnings for the period from June 1, 2017, acquisition date throughyears ended December 31, 2017.2020, 2019 and 2018. At December 31, 2017,2020 and 2019, the Partnership had a $41$39 million and $40 million difference, respectively, between the carrying value of Iroquois and the underlying equity in the net assets primarily from TransCanada'sTC Energy’s carrying value and is due to theirthe fair value assessment of Iroquois'Iroquois’ assets at the time of its acquisition of interests from third parties (refer to Note 2-Acquisitions2 - Acquisitions and Goodwill for our accounting policy on acquisitions from TransCanada)PipeLines, LPAnnual Report2017 F-17for the period from the June 1, 2017 acquisition date through December 31, 2017which is not considered a significant equity investee under Regulation SX-3-09, is as follows:(millions of dollars)At December 31,2017ASSETSCash and cash equivalents86Other current assets36Plant, property and equipment, net591Other assets8721LIABILITIES AND PARTNERS' EQUITYCurrent liabilities17Net long-term debt, including current maturities(a)329Other non-current liabilities9Partners' equity366721Period of 7 months ended December 31 (millions of dollars)2017 Transmission revenues110 Operating expenses(32)Depreciation(17)Financial charges and other(9)Net income52 2020 2019 ASSETS Cash and cash equivalents 25 43 Other current assets 36 36 Property, plant and equipment, net 506 570 Other assets 20 16 587 665 LIABILITIES AND PARTNERS’ EQUITY Current liabilities 20 34 314 317 Other non-current liabilities 21 20 Partners’ equity 232 294 587 665 2020 2019 2018 Transmission revenues 183 180 194 Operating expenses (59) (58) (57) Depreciation (30) (29) (29) Financial charges and other (15) (11) (14) Net income 79 82 94 $4$5 million as of December 31, 2017. PROPERTY AND EQUIPMENT property and equipment of our consolidated entities:
2017
2016(a)
Accumulated
Net Book
Accumulated
Net Book December 31 (millions of dollars)
Cost
Depreciation
Value
Cost
Depreciation
Value Pipeline 2,577 (962 ) 1,615 2,540 (879 ) 1,661 Compression 533 (165 ) 368 519 (148 ) 371 Metering and other 182 (54 ) 128 205 (61 ) 144 Construction in progress 12 – 12 4 – 4 3,304 (1,181 ) 2,123 3,268 (1,088 ) 2,180 2020 2019 Cost Accumulated
DepreciationNet Book
ValueCost Accumulated
DepreciationNet Book
ValuePipeline 1,910 (982) 928 1,907 (929) 978 Compression 730 (210) 520 584 (202) 382 208 (58) 150 180 (56) 124 Construction in progress 149 — 149 44 — 44 2,997 (1,250) 1,747 2,715 (1,187) 1,528 Recastconsolidate PNGTS (Refer to Notes 2 and 7).NOTE 7 ACQUISITIONS2017 AcquisitionOn June 1, 2017, the Partnership acquired from subsidiaries of TransCanada a 49.34 percent interest in Iroquois, including an option to acquire a further 0.66 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 adjustmentsour consolidated entities 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 additionalF-18 TC PipeLines, LPAnnual Report201711.81 percent interest in PNGTS (less $5 million, which reflected our 11.81% proportionate share in PNGTS' outstanding debt on June 1, 2017) (iii) final working capital adjustments for Iroquois and PNGTS amounting to $19$26 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 TransCanada's remaining 0.66 percent interest in Iroquois. The Partnership funded the cashdoes not include our portion of the 2017 Acquisition through a combinationcapital expenditure related to our equity investment in Great Lakes, amounting to $12 million.proceeds fromBison’s long-lived assetsMay 2017 public debt offeringPartnership performed an impairment analysis on Bison’s long-lived assets in connection with the termination of certain customer transportation agreements (refer to Note 8)6 - Revenues).borrowing under our Senior Credit Facility.At the datepersistence of unfavorable market conditions which inhibited systems flows on the 2017 Acquisition, there was significant cash on Iroquois' balance sheet. Pursuant topipeline during the Purchase and Sale Agreement associated with the acquisitionfourth quarter of the Iroquois interest, as amended, the Partnership agreed to pay $28 million plus interest to TransCanada 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. The Partnership expects to receive the $28 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 26, 2018, the Partnership has received approximately $7.8recognized an impairment charge of $537 million relating to the remaining carrying value of the expected $28 million, of which $5.2 millionBison’s property, plant and equipment after determining that it was received in 2017 and $2.6 million was received on February 1, 2018 (Refer to Note 25).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 Iroquoisimpairment charge was recorded at TransCanada's carrying value andunder Impairment of long-lived assets line on 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)593Less: TransCanada's carrying value of Iroquois at June 1, 2017223Excess purchase price(b)370(a)Total purchase priceConsolidated statement 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 TransCanada's carrying value and the Partnership's historical financial information, except net income per common unit, was recast to consolidate PNGTS for all periods presented.The PNGTS purchase price was recorded as follows:(millions of dollars)Current assets25Property, plant and equipment, net294Current liabilities(4)Deferred state income taxes(10)Long-term debt, including current portion(41)264Non-controlling interest(100)Carrying value of pre-existing Investment in PNGTS(132)TransCanada's carrying value of the acquired 11.81 percent interest at June 1, 201732Excess purchase price over net assets acquired(a)21Total 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.2017 2020F-192016 PNGTS AcquisitionOn January 1, 2016, the Partnership acquired a 49.9 percent interest in PNGTS from a subsidiaryTable of TransCanada. The total purchase price of the PNGTS Acquisition was $228 million and consisted of $193 million in cash (including the final purchase price adjustment of $5 million) and the assumption of $35 million in proportional PNGTS debt.The Partnership funded the cash portion of the transaction using proceeds received in 2015 from our ATM Program and additional borrowings under our Senior Credit Facility. The purchase agreement provides for additional payments to TransCanada ranging from $5 million up to a total of $50 million if pipeline capacity is expanded to various thresholds during the fifteen-year period following the date of closing.The acquisition was accounted for as a transaction between entities under common control, whereby the equity investment in PNGTS was recorded at TransCanada's carrying value and the total excess purchase price paid was recorded as a reduction in Partners' Equity.The net purchase price was allocated as follows:(millions of dollars)Net Purchase Price(a)193Less: TransCanada's carrying value of PNGTS' net assets at January 1, 2016120Excess purchase price(b)73(a)Total purchase price of $228 million less the assumption of $35 million of proportional PNGTS debt by the Partnership.(b)The excess purchase price of $73 million was recorded as a reduction in Partners' Equity.2015 GTN AcquisitionOn April 1, 2015, the Partnership acquired the remaining 30 percent interest in GTN from a subsidiary of TransCanada (2015 GTN Acquisition), which resulted in GTN being wholly-owned by the Partnership. The total purchase price of the 2015 GTN Acquisition was $446 million plus the final purchase price adjustment of $11 million, for a total of $457 million. The purchase price consisted of $264 million in cash (including the final purchase price adjustment of $11 million), the assumption of $98 million in proportional GTN debt and the issuance of 1,900,000 new Class B units to TransCanada valued at $50 each, representing a limited partner interest in the Partnership with a total value of $95 million.The Partnership funded the cash portion of the transaction using a portion of the proceeds received on our March 13, 2015 debt offering (refer to Note 8). The Class B units entitle TransCanada to a 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. Under the terms of the Third Amended and Restated Agreement of Limited Partnership of the Partnership (Partnership Agreement), the Class B distribution was initially calculated to equal 30 percent of GTN's distributable cash flow for the nine months ended December 31, 2015, less $15 million.Prior to this transaction, the remaining 30 percent interest held by a subsidiary of TransCanada was reflected as a non-controlling interest in the Partnership's consolidated financial statements. The 2015 GTN Acquisition of this already-consolidated entity was accounted as a transaction between entities under common control, similar to a pooling of interests, whereby the acquired interest was recorded at TransCanada's carrying value and the total excess purchase price paid was recorded as a reduction in Partners' Equity.The net purchase price was allocated as follows:(millions of dollars)Net Purchase Price(a)359Less: TransCanada's carrying value of non-controlling interest at April 1, 2015232Excess purchase price(b)127(a)Total purchase price of $457 million less the assumption of $98 million of proportional GTN debt by the Partnership.(b)The excess purchase price of $127 million was recorded as a reduction in Partners' Equity.Our General Partner also contributed approximately $2 million to maintain its effective two percent interest in the Partnership.F-20 TC PipeLines, LPAnnual Report2017
Contents(millions of dollars) 2017 Weighted Average
Interest Rate for the
Year Ended
December 31, 2017 2016(b) Weighted Average
Interest Rate for the
Year Ended
December 31, 2016(b) TC PipeLines, LP Senior Credit Facility due 2021 185 2.41% 160 1.72% 2013 Term Loan Facility due 2022 500 2.33% 500 1.73% 2015 Term Loan Facility due 2020 170 2.22% 170 1.63% 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) – – 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 55 2.02% 65 1.43% PNGTS 5.90% Senior Secured Notes due 2018 30 5.90% (a) 53 5.90% (a) Tuscarora Unsecured Term Loan due 2020 25 2.27% 10 1.64% 3.82% Series D Senior Notes due 2017 – – 12 3.82% (a) 2,415 1,920 Less: unamortized debt issuance costs and debt discount 12 9 Less: current portion 51 (d) 52 (c) 2,352 1,859 (millions of dollars) 2020 Weighted Average Interest Rate for the Year Ended December 31, 2020 2019 Weighted Average Interest Rate for the Year Ended December 31, 2019 TC PipeLines, LP Senior Credit Facility due 2021 0 0 0 0 2013 Term Loan Facility due 2022 450 1.87 % 450 3.52 % 4.65% Unsecured Senior Notes due 2021 350 4.65 % (a) 350 4.65 % (a) 4.375% Unsecured Senior Notes due 2025 350 4.375 % (a) 350 4.375 % (a) 3.90% Unsecured Senior Notes due 2027 500 3.90 % (a) 500 3.90 % (a) GTN 5.29% Unsecured Senior Notes due 2020 0 0 100 5.29 % (a) 5.69% Unsecured Senior Notes due 2035 150 5.69 % (a) 150 5.69 % (a) 3.12% Series A Senior Notes due 2030 175 3.12 % (a) 0 0 PNGTS Revolving Credit Facility due 2023 25 1.88 % 39 3.47 % 2.84% Series A Senior Notes due 2030 125 2.84 % (a) 0 0 Tuscarora Unsecured Term Loan due 2021 23 2.13 % 23 3.39 % North Baja Unsecured Term Loan due 2021 50 1.70 % 50 3.34 % 2,198 2,012 Less: unamortized debt issuance costs and debt discount 7 9 Less: current portion 423 (b) 123 1,768 1,880 Recast to consolidate PNGTS (Refer to Notes 2 and 7).(c)PNGTS portionPartnership's 4.65% Unsecured Senior Notes due June 15, 2021, Tuscarora’s Unsecured Term Loan due August 20, 2021 and North Baja's Unsecured Term Loan due December 19, 2021.December 31, 2016 amounting to $5.5 million that was paid on January 3, 2017.(d)Includes the PNGTS portion due at December 31, 2017 amounting to $5.8 million that was paid on January 2, 2018.On November 10, 2016, the Partnership's Facility was amended to extend the maturity period through November 10, 2021. The Facility consists of a $500 million senior revolving credit facility with a banking syndicate, under which $185 million was0 borrowings were outstanding at December 31, 2017 (December 31, 2016 – $160 million),2020, leaving $315$500 million available for future borrowing.Partnership'sPartnership’s option, the interest rate on the outstanding borrowings under the Senior Credit Facility may be the lenders'lenders’ base rate or the London Interbank Offered Rate (LIBOR)LIBOR plus, in either case, an applicable margin that is based on the Partnership'sPartnership’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 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 2.62 percent at December 31, 2017 (December 31, 2016 – 1.92 percent).On July 1, 2013, the Partnership entered into a term loan agreement with a syndicate of lenders for a $500 million term loan credit facility (2013 Term Loan Facility). On July 2, 2013, the Partnership borrowed $500 million under the 2013 Term Loan Facility, to pay a portion of the purchase price of the 2013 Acquisition, maturing originally on July 1, 2018. Partnership's 2013Partnership’s term loan credit facility under a term loan agreement (2013 Term Loan FacilityFacility) was amended to extend the maturity period through October 2, 2022. The 2013 Term Loan Facility bears interest based, at the Partnership'sPartnership’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'sBank’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'sPartnership’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.TC PipeLines, LPAnnual Report2017 F-212017,2020, the variable interest rate exposure related to 2013 Term Loan Facility was hedged by fixed interest rate swap arrangements and our effective interest rate was 2.313.26 percent (2016(2019 – 2.313.26 percent). Prior to hedging activities, the LIBOR-based interest rate was 2.621.40 percent at December 31, 20172020 (December 31, 20162019 – 1.872.94 percent).On September 30, 2015, the Partnership entered into an agreement for a $170 million term loan credit facility (2015 Term Loan Facility). Partnership borrowed $170 million under the 2015 Term Loan Facility to refinance its Short-Term Loan Facility which matured on September 30, 2015. On September 29, 2017, the Partnership's 2015 Term Loan Facility that was due on October 1, 2018 was amended to extend the maturity period through October 1, 2020. The LIBOR-based interest rate on the 2015 Term Loan Facility was 2.51 percent at December 31, 2017 (December 31, 2016 – 1.77 percent).The 2013 Term LoanSenior Credit Facility and the 20152013 Term Loan Facility (Term Loan Facilities) and the Senior Credit Facility require the Partnership to maintain a certain leverage ratio (debtdebt to adjusted cash flow [net income plus cash distributions received, extraordinary losses, interest expense, expense for taxes paid or accrued, and depreciation and amortization expense less equity earnings and extraordinary gains])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 4.703.85 to 1.00 as of December 31, 2017.FacilitiesFacility 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'sPartnership’s subsidiaries and distributions to unitholders. Upon any breach of these covenants, amounts outstanding under the Senior Credit Facility and the 2013 Term Loan FacilitiesFacility may become immediately due and payable.On March 13, 2015, the Partnership closed a $350 million public offering of senior unsecured notes bearing an interest rate of 4.375 percent maturing March 13, 2025. The net proceeds of $346 million were used to fund a portion of the 2015 GTN Acquisition (Refer to Note 7) and to reduce the amount outstanding under our Senior Credit Facility. The indenture for the notes contains customary investment grade covenants.Acquisition (Refer to Note 7).acquisition of a 49.34 percent interest in Iroquois, together with an additional 11.81 percent interest in PNGTS. The indenture for the notes contains customary investment grade covenants.Senior Secured Notes are securedSeries A Note issuance were used to repay the outstanding balance of PNGTS' revolving credit facility and for general partnership purposes including funding growth capital expenditures. PNGTS expects to draw the remaining $125 million available under the PNGTS Private Shelf Facility by the end of the third quarter of 2021 to refinance amounts funded on its revolving credit facility for costs associated with the Westbrook XPress Project. The PNGTS long-term firm shipper contractsPrivate Shelf Facility and its partners' pledgePNGTS Series A Notes contain a covenant that limits total debt to no greater than 65 percent of their equityPNGTS’ total capitalization and requires PNGTS to maintain a guaranteeleverage ratio of no greater than 5.00 to 1.00. The ratio of debt service for six months. PNGTS is restricted underto capitalization was 37 percent and the termsleverage ratio was 1.99 to 1.00 as of its note purchase agreement from making cash distributions unless certain conditions are met. Before a distribution can be made, the debt service reserve account must be fully funded and PNGTS' debt service coverage ratio for the preceding and succeeding twelve months must be 1.30 or greater. At December 31, 2017, the debt service coverage ratio was 1.72 for the twelve preceding months and 1.53 for the twelve succeeding months. Therefore, PNGTS was not restricted to make any cash distributions.2015,2020, GTN's $100 million 5.29% Unsecured Senior Notes became due and were refinanced through a Note Purchase and Private Shelf Agreement whereby GTN issued $175 million of 10-year Series A Senior Notes (GTN Series A Notes) with a coupon rate of 3.12% per annum and entered into a 3-year private shelf agreement for an additional $75 million unsecured variable rate term loan facility (Unsecured Term Loanof Senior Notes (GTN Private Shelf Facility), which requires yearly. The GTN Series A Notes do not require any principal payments until its maturity on June 1, 2019.2030. Proceeds from the GTN Series A Note issuance were used to repay the outstanding balance of the 5.29% Unsecured Senior Notes and the remaining proceeds is being used to fund the GTN XPress capital expenditures. GTN expects to draw the remaining $75 million available under the GTN Private Shelf Facility by the end of 2023, the estimated completion date of GTN XPress. The variable interest is based on LIBOR plus an applicable margin. The LIBOR-based interest rate on the Unsecured Term LoanGTN Private Shelf Facility was 2.31and GTN Series A Notes contain a covenant that limits total debt to no greater than 65 percent at December 31, 2017 (December 31, 2016 – 1.57 percent).of total capitalization. GTN's Unsecured Senior Notes along with this new Unsecured Term Loan Facility contain a covenant that limits total debt to no greater than 70 percent of GTN'sGTN’s total capitalization. GTN'sGTN’s total debt to total capitalization ratio at December 31, 2017 is 44.62020 was 36.8 percent.August 21, 2017, Tuscarora refinanced all of its outstanding debt by amending its existingJuly 23, 2020, Tuscarora's $23 million variable rate Unsecured Term Loan Facility and issuing a new $25 million variable rate term loan that will require yearly principal payments and will mature on(Unsecured Term Loan) was amended to extend the maturity date to August 21, 2020. Tuscarora's20, 2021 under generally the same terms. 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, 2017,2020, the ratio was 11.0931.16 to 1.00.the Tuscarora's Unsecured Term Loan Facilitythis term loan facility was 2.491.23 percent at December 31, 20172020 (December 31, 2016 – 1.902019 - 2.77 percent).2017,2020, 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.F-22 TC PipeLines, LPAnnual Report2017(millions of dollars) 2018 51 2019 36 2020 293 2021 535 2022 500 Thereafter 1,000 2,415 (millions of dollars) 2021 423 2022 450 2023 25 2024 0 2025 350 Thereafter 950 2,198
December 31 (millions of dollars)
2017
2016 Regulatory liabilities 26 25 Other liabilities 3 3 29 28 2020 2019 Regulatory liabilities 38 29 Other liabilities 9 7 47 36 "negative salvage"“negative salvage”) and recognizes regulatory liabilities in this respect inon 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 ASCAccounting Standards Codification (ASC) 410,Accounting for Asset Retirement Obligations.Obligations. (Refer to Note 2)PARTNERS'PARTNERS’ EQUITY2017,2020, the Partnership had 70,573,42371,306,396 common units outstanding, of which 53,488,59254,221,565 were held by non-affiliates and 17,084,831 common units were held by subsidiaries of TransCanada,TC Energy, including 5,797,106 common units held by our General Partner. Additionally, TransCanada,TC Energy, through our General Partner, owns 100 percent of our IDRs and an effective twoa 2 percent general partner interest in the Partnership. TransCanadaTC Energy also holds 100 percent of our 1,900,000 outstanding Class B units.ATMAugust 2014,2018, the Partnership launchedissued 0.7 million common units under its $200 million ATM program pursuant toprevious At-the-Market Equity Issuance Program (ATM Program), which allowed the Partnership may from time to time to offer and sell, through sales agents, common units representing limited partner interests.On August 5, 2016, the Partnership entered into a new $400 million Equity Distribution Agreement (EDA) with five financial institutions (the Managers). Sales of the common units will be issued pursuant to In 2018, the Partnership's shelf registration statement on Form S-3 (Registration No. 333-211907), which was declared effective by the SEC on August 4, 2016.In 2017, the Partnership issued 3.2 million common units under the ATM Program generatinggenerated net proceeds of approximately $173$39 million, plus an additional $3$1 million from the General Partner to maintain its effective two2 percent interest. The commissions to our sales agents were approximately $2 million.immaterial. The net proceeds were used to repay a portion of the borrowings under the Senior Credit Facility and for general partnership purposes.2016, the Partnership issued 3.1 million common units underAugust 2019, the ATM Program generating net proceedsexpired with 0 common unit issuances in 2019.approximately $164 million, plus an additional $3 million from the General PartnerClass B unitsmaintain its effective two percent interest. The commissions to our sales agents were approximately $2 million. The net proceeds were used to repayfinance a portion of the borrowings underPartnership’s acquisition of the Senior Credit Facility for the 2016 PNGTS Acquisitionremaining 30 percent interest of GTN from TC Energy represent a limited partner interest in us and for general partnership purposes. The 3.1entitles 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 common units issued include the 1.6through March 31, 2020; and (ii) 25 percent of distributions above $20 million common units subjectthereafter, which equates to rescission as discussed below.In 2015, the Partnership issued 0.743.75 percent of distributions above $20 million common units under the ATM Program generating net proceeds of approximately $43 million, plus an additional $1 million from the General Partner to maintain its effective two percent interest. The commissions to our sales agents were approximately $0.4 million. The net proceeds were used for general partnership purposes.TC PipeLines, LPAnnual Report2017 F-23Common unit issuance subject to rescissionIn 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.At December 31, 2016, $83 million was recorded as common units subject to rescission on the consolidated balance sheet. The Partnership classified the 1.6 million common units that were sold under its ATM program from March 8, 2016 up to and including May 19, 2016, which may have been subject to rescission rights, outside of equity given the potential redemption feature which was not within the control of the Partnership. These units were treated as outstanding for financial reporting purposes.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 of these rights, the $83 million was reclassified back to partners' equity. At December 31, 2017, there were no outstanding common units subject to rescission on the Partnership's consolidated balance sheet.Issuance of Class B unitsOn April 1, 2015, we issued Class B units to TransCanada to finance a portion of the 2015 GTN Acquisition. The Class B units entitle TransCanada to an annual distribution which is an amount based on 30 percent of cash distributions from GTN exceeding certain annual thresholds (refer to Note 7).2020. 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.units'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.excess of 30 percent of GTN's distributions over“Class B Distribution,” less the annual threshold“Class B Reduction,” if any, and until such amount is declared for distribution and paid everyin the first quarter of the subsequent year.2017, 20162019 and 2015,2018, the Class B units'units’ equity account was increased by $15 million, $22$8 million and $12$13 million, respectively. These amounts equal 30 percent of GTN's total distributable cash flow above the $20 million threshold in 2017 and 2016 and the $15 million threshold in 2015 (refer(Refer to Notes 13 and 14).accumulated other comprehensive income (loss) (AOCI)AOCI by component are as follows:
(millions of dollars)
Cash flow
hedges(a)
Equity
Investments
Total Balance at December 31, 2014 (5 ) – (5 ) Change in fair value of cash flow hedges – – – Amounts reclassified from AOCI – – – PNGTS' amortization of realized loss on derivative instrument (Note 19) 1 – 1 Net other comprehensive income 1 – 1 Balance at December 31, 2015 (4 ) – (4 ) Change in fair value of cash flow hedges 3 – 3 Amounts reclassified from AOCI (2 ) – (2 ) PNGTS' amortization of realized loss on derivative instrument (Note 19) 1 – 1 Net other comprehensive income 2 – 2 Balance at December 31, 2016 (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 19) 1 – 1 Other comprehensive income – effects of Iroquois' retirement benefit plans – 1 1 Net other comprehensive income 6 1 7 Balance as of December 31, 2017 4 1 5 (a)Recast to consolidate PNGTS (Refer to in Notes 2 and 7). Additionally, AOCI as presented here is net of non-controlling interest on PNGTS.F-24 TC PipeLines, LPAnnual Report2017(millions of dollars) Cash flow
hedgesEquity
InvestmentsTotal Balance at December 31, 2017 4 1 5 Change in fair value of cash flow hedges (2) 0 (2) Amounts reclassified from AOCI 5 0 5 1 0 1 Other comprehensive income - effects of Iroquois’ retirement benefit plans 0 (1) (1) Net other comprehensive income 4 (1) 3 Balance at December 31, 2018 8 0 8 Change in fair value of cash flow hedges (13) 0 (13) Amounts reclassified from AOCI (1) 0 (1) Other comprehensive loss - effects of Iroquois’ retirement benefit plans 0 1 1 Net other comprehensive income (loss) (14) 1 (13) Balance as of December 31, 2019 (6) 1 (5) Change in fair value of cash flow hedges (16) 0 (16) Amounts reclassified from AOCI 7 0 7 Other comprehensive income - effects of Iroquois’ retirement benefit plans 0 1 1 Net other comprehensive income (loss) (9) 1 (8) Balance as of December 31, 2020 (15) 2 (13)
Year ended December 31 (millions of dollars)
2017
2016(a)
2015(a) Interest expense(b) 83 69 65 Net realized loss related to the interest rate swaps – 3 2 PNGTS' amortization of realized loss on derivative instrument (Note 19) 1 1 1 Other (2 ) (2 ) (5 ) 82 71 63 2020 2019 2018 78 88 95 Net realized loss (gain) related to the interest rate swaps 7 (1) (2) 0 0 1 AFUDC - Equity (10) (2) (1) (2) (2) (1) 73 83 92 Recast to consolidate PNGTS (Refer to Notes 2 and 7).(b)costs.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.Partner's effective twoPartner’s 2 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(Refer to Note 14).20172020 equals an amount based upon 30 percent of GTN'sGTN’s distributable cash flow during the year ended December 31, 20172020 less $20 million, (2016 –the residual of which is further multiplied by 43.75 percent. This amount is further reduced by the estimated Class B Reduction for 2020, an approximately 35 percent reduction applied to the estimated annual Class B Distribution (December 31, 2019 and 2018 - $20 million; 2015 – $15million less Class B Reduction). During the year ended December 31, 2020, 0 amounts were allocated to the Class B units as the annual threshold was not exceeded (2019 - $8 million, 2018 - $13 million).
(millions of dollars, except per common unit amounts)
2017
2016
2015 Net income attributable to controlling interests(a) 252 248 37 Net income attributable to PNGTS' former parent(a)(b) (2 ) (4 ) (24 ) Net income allocable to General Partner and Limited Partners 250 244 13 Incentive distributions attributable to the General Partner(c) (12 ) (7 ) (3 ) Net income attributable to the Class B units(d) (15 ) (22 ) (12 ) Net income (loss) allocable to the General Partner and common units 223 215 (2 ) Net income allocable to the General Partner's two percent interest (4 ) (4 ) – Net income (loss) attributable to common units 219 211 (2 ) Weighted average common units outstanding(millions) – basic and diluted 69.2 65.7 (e) 63.9 Net income (loss) per common unit – basic and diluted(f) $3.16 $3.21 $(0.03 ) (millions of dollars, except per common unit amounts) 2020 2019 2018 Net income (loss) attributable to controlling interests 284 280 (182) 0 (8) (13) Net income (loss) allocable to the General Partner and common units 284 272 (195) Amounts attributable to General Partner's 2 percent interest (6) (5) 4 Net income (loss) attributable to common units 278 267 (191) 71.3 71.3 71.3 Net income (loss) per common unit – basic and diluted $ 3.90 $ 3.74 $ (2.68) Recast to consolidate PNGTS for years ended December 2016 and 2015 (Refer to Note 2).(b)Net income allocable to General and Limited Partners excludes net income attributed to PNGTS' former parent as it was allocated to TransCanada and was not allocable to either the general partner, common units or Class B units.(c)Under the terms of the Partnership Agreement, for any quarterly period, the participation of the incentive distribution rights (IDRs) is limited to the available cash distributions declared. Accordingly, incentive distributions allocated to the General Partner are based on the Partnership's available cash during the current reporting period, but declared and paid in the subsequent reporting period.(d)TransCanadaTC Energy to a distribution which is an amount based on 30 percent of GTN'sGTN’s distributions after exceeding certain annual thresholds.thresholds and Class B Reduction. The distribution will be payable in the first quarter with respect to the prior year'syear’s distributions. ConsistentThere was 0 Class B Unit distribution declared for 2020. However, consistent with the application of Accounting Standards Codification (ASC) Topic 260 – "Earnings“Earnings per share",share,” the Partnership allocated the Class B units a distribution in an amount equal to 30 percent of GTN'sGTN’s total distributable cash flows during the year ended December 31, 20172019 less the threshold level of $20 million (2016 –(2018 - less $20 million; 2015 –million) and less $15 million). During the year ended December 31, 2017, 30 percent of GTN's total distributable cash flow was $35 million. As a result of exceeding the threshold level ofTC PipeLines, LPAnnual Report2017 F-25$20 million, $15 million of net income attributable to controlling interests was allocated to the Class B units at December 31, 2017 (2016 – $22 million; 2015 – $12Reduction (2019 - $4 million, 2018 - $7 million) (Refer to Note 10).(e)Includes the common units subject to rescission. These units are treated as outstanding for financial reporting purposes (Refer to Note 10).(f)Net income (loss) per common unit prior to recast.Available Cash,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.two2 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.twoIDRs and 2 percent general partner interest and IDRs, and assume our General Partner has contributed any additional capital necessary to maintain its two2 percent general partner interest. The distributionpercentage interest distributions to the General Partner illustrated below other than in its capacity as a holder of 5,797,106 common units that are in excess of its effective two2 percent general partner interest representsrepresent the IDRs.
Marginal Percentage
Interest in Distribution
Total Quarterly Distribution
Per Unit Target Amount
Common
Unitholders
General
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% Marginal Percentage
Interest in DistributionTotal Quarterly Distribution
Per Unit Target AmountCommon
UnitholdersGeneral
PartnerMinimum 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 % Limited Partners General Partner
Declaration Date
Payment Date
Per Unit
Distribution
Common
Units
Class B
Units(c)
2%
IDRs(a)
Total Cash
Distribution 1/22/2015 2/13/2015 $0.84 $54 $ – $1 $– $55 4/23/2015 5/15/2015 $0.84 $54 $ – $1 $– $55 7/23/2015 8/14/2015 $0.89 $56 $ – $2 $1 $59 10/22/2015 11/13/2015 $0.89 $57 $ – $1 $1 $59 1/21/2016 2/12/2016 $0.89 $57 $12 (d) $1 $1 $71 4/21/2016 5/13/2016 $0.89 $58 $ – $1 $1 $60 7/21/2016 8/12/2016 $0.94 $62 $ – $1 $2 $65 10/20/2016 11/14/2016 $0.94 $63 $ – $1 $2 $66 1/23/2017 2/14/2017 $0.94 $64 $22 (e) $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 (b) 2/13/2018 (b) $1.00 $71 $15 (f) $2 $3 $91 Limited Partners General Partner Declaration Date Payment Date Per Unit
DistributionCommon
Units2 % Total Cash
Distribution1/23/2018 2/13/2018 $ 1.00 $ 71 $ 15 $ 2 $ 3 $ 91 5/1/2018 5/15/2018 $ 0.65 $ 46 $ 0 $ 1 $ 0 $ 47 7/26/2018 8/15/2018 $ 0.65 $ 46 $ 0 $ 1 $ 0 $ 47 10/23/2018 11/14/2018 $ 0.65 $ 46 $ 0 $ 1 $ 0 $ 47 1/22/2019 2/11/2019 $ 0.65 $ 46 $ 13 $ 1 $ 0 $ 60 4/23/2019 5/13/2019 $ 0.65 $ 46 $ 0 $ 1 $ 0 $ 47 7/23/2019 8/14/2019 $ 0.65 $ 46 $ 0 $ 1 $ 0 $ 47 10/22/2019 11/14/2019 $ 0.65 $ 46 $ 0 $ 1 $ 0 $ 47 1/21/2020 2/14/2020 $ 0.65 $ 46 $ 8 $ 1 $ 0 $ 55 4/21/2020 5/12/2020 $ 0.65 $ 46 $ 0 $ 1 $ 0 $ 47 7/23/2020 8/14/2020 $ 0.65 $ 46 $ 0 $ 1 $ 0 $ 47 10/21/2020 11/13/2020 $ 0.65 $ 46 $ 0 $ 1 $ 0 $ 47 $ 0.65 $ 46 $ 0 $ 1 $ 0 $ 47 20172020 and 2019 included 0 incentive distributions to the General Partner of $10 million (2016 – $6 million, 2015 – $2(2018 - $3 million).On February 13, 2018, we paid a cash distribution of $1.00 per unit on our outstanding common units to unitholders of record at the close of business on February 2, 2018 (refer to Note 25).F-26 TC PipeLines, LPAnnual Report2017
The Class B units issued by us on April 1, 2015 represent limited partner interests in us and entitle (c)TransCanadaTC Energy to an annual distribution which is an amount based on 30 percent of GTN'sGTN’s annual distributions after exceeding certain annual thresholds and adjustments (refer to Note 7 and 10).(d)2016,2021, we paid TransCanada $12 million representing 30 percenta cash distribution of GTN's total distributable cash flows for$0.65 per unit on our outstanding common units to unitholders of record at the nine months ended December 31, 2015 less $15 million.(e)On February 14, 2017, we paid TransCanada $22 million representing 30 percentclose of GTN's total distributable cash flows for the year ended December 31, 2016 less $20 millionbusiness on January 29, 2021 (refer to Note 10 and 25)21).(f)On February 13, 2018, we paid TransCanada $15 million representing 30 percent of GTN's total distributable cash flows for the year ended December 31, 2017 less $20 million (refer to Note 10 and 25).
Year Ended December 31 (millions of dollars)
2017
2016(b)
2015(b) Change in accounts receivable and other 4 (4 ) 6 Change in other current assets 2 (4 ) (1 ) Change in accounts payable and accrued liabilities (7 )(a) 5 (a) (2 ) Change in accounts payable to affiliates (3 ) – (15 )(a) Change in state income taxes payable – – (5 ) Change in accrued interest 2 2 (3 ) Change in operating working capital (2 ) (1 ) (20 ) 2020 2019 2018 Change in accounts receivable and other 1 9 (6) Change in inventory (1) (2) 0 Change in other current assets 0 0 (1) 5 (11) 3 Change in accounts payable to affiliates (1) 2 1 Change in accrued interest 0 (1) 0 Change in operating working capital 4 (3) (3) dropdown costs.(b)Recast to consolidate PNGTS (Refer to Notes 2 and 7).The following table shows revenues fromPartnership's major customers comprisingyear ended December 31, 2020 and 2019, no customer accounted for more than 10 percent of the Partnership's totalour consolidated recasted revenues (refer to Note 2) for the years ended December 31, 2017, 2016revenue and 2015:
Year Ended December 31 (millions of dollars)
2017
2016
2015 Anadarko Energy Services Company (Anadarko) 48 48 48 Pacific Gas and Electric Company (Pacific Gas) 33 (a)(b) 36 (a) 42 2017 and 2016, Anadarko2018, Tenaska owed the Partnership approximately $4 million, which iswas approximately 10 percent of our consolidated recasted trade accounts receivable (Referreceivable. 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 Note 2).
revenues.(a)Less than 10 percent of trade accounts receivable(b)Less than 10 percent ofterminate its contract. For the year ended December 31, 2018, revenues from both Anadarko and Tenaska amounted to $144 million, which was approximately 36 percentof our consolidated revenuewerewas $4 million for the year ended December 31, 2017 (2016 – $3 million, 2015 – $32020 (2019 - $4 million; 2018 - $4 million).joint facilities) TransCanada's(the Joint Facilities)), TC Energy’s subsidiaries provide capital and operating services to our pipeline systems. TransCanada'sTC Energy’s subsidiaries incur costs on behalf of our pipeline systems, including, but not limited to,TC PipeLines, LPAnnual Report2017 F-27PNGTS joint facilitiesJoint Facilities are operated by MNOC. Therefore, Iroquois and the PNGTS joint facilitiesJoint Facilities do not receive capital and operating services from TransCanada.2017, 20162020, 2019 and 20152018 by TransCanada'sTC Energy's subsidiaries and amounts payable to TransCanada'sTC Energy's subsidiaries at December 31, 20172020 and 20162019 are summarized in the following tables:
Year ended December 31 (millions of dollars)
2017
2016
2015 Capital and operating costs charged by TransCanada's subsidiaries to: Great Lakes(a) 36 30 30 Northern Border(a) 43 32 36 PNGTS(a)(b) 9 8 8 GTN(a)(c) 34 27 30 Bison 6 2 4 North Baja 4 4 5 Tuscarora 4 5 4 Impact on the Partnership's net income attributable to controlling interests: Great Lakes 15 13 13 Northern Border 16 12 14 PNGTS(b) 5 5 5 GTN(c) 29 24 25 Bison 6 3 4 North Baja 4 4 5 Tuscarora 4 4 4
December 31 (millions of dollars)
2017
2016 Amount payable to TransCanada's subsidiaries for costs charged in the year by: Great Lakes(a) 3 4 Northern Border(a) 4 4 PNGTS(a)(b) 1 1 GTN 3 3 Bison 1 1 North Baja – 1 Tuscarora – 1 2020 2019 2018 Capital and operating costs charged by TC Energy’s subsidiaries to: 66 47 44 39 39 36 6 7 9 GTN 68 45 34 Bison 2 2 6 North Baja 7 5 4 Tuscarora 6 4 4 Impact on the Partnership’s net income attributable to controlling interests: Great Lakes 16 20 19 Northern Border 16 18 16 PNGTS 3 4 5 GTN 29 33 28 Bison 2 2 6 North Baja 3 4 4 Tuscarora 3 4 4 2020 2019 Amount payable to TC Energy’s subsidiaries for costs charged in the year by: 3 5 2 4 1 1 GTN 4 5 Bison 0 0 North Baja 0 1 Tuscarora 1 0 (b)Recast to consolidate PNGTS for years ended December 31, 2016 and 2015 (Refer to Note 2).(c)In 2015, the Partnership acquired the remaining 30 percent interest in GTN (Refer to Note 7).TransCanadaTC Energy and its affiliates, some of which are provided at discounted rates, negotiated rates and some at maximum recourse rates.affiliates. For the year ended December 31, 2017,2020, Great Lakes earned 5773 percent of its transportation revenues from TransCanadaTC Energy and its affiliates (2016(2019 – 6873 percent; 20152018 – 7173 percent). Additionally, included in Great Lakes earned approximately oneLakes’ other revenues for 2018 and 2019 were cost recovery charges to affiliates for the use of office space in the building owned by Great Lakes. These revenues comprised less than 1 percent of its total revenues as affiliated rental revenue in 2017 (2016 – 1 percent; 2015 – 1 percent).2017, $202020, $17 million was included in Great Lakes'Lakes’ receivables in regardsregard to the transportation contracts with TransCanadaTC Energy and its affiliates (December 31, 20162019 – $19 million).In 2017, Great Lakes operates under a FERC approved 2013 rate settlement that includes a revenue sharing mechanism that requires Great Lakes to share with its customers certain percentages of any qualifying revenues earned above certain ROEs. A refund of $7 million was paid to shippers in 2017 relating to the year ended December 31, 2016, of which approximately 86 percent was made to affiliates of Great Lakes. For the year ended December 31, 2017, Great Lakes has recorded an estimated revenue sharing provision amounting to $40 million and Great Lakes expects that a significant percentage of the 2017 revenue sharing refund will be to its affiliates.F-28 TC PipeLines, LPAnnual Report2017Under the terms of the 2017 Great Lakes Settlement, beginning 2018, the revenue sharing was eliminated (refer to Note 5. Additionally, effective October 1, 2017, Great Lakes still charged customers rates in effect prior to the 2017 Great Lakes Settlement but only recognized revenue up to the amount of the new rates in the 2017 Great Lakes Settlement. The difference between these two amounts was recognized as a provision for rate refund (liability) on Great Lakes' balance sheet amounting to $8 million. Great Lakes expects that a significant percentage of the provision for rate refund will be to its affiliates as well.TransCanadaTC Energy whereby Great Lakes'Lakes’ funds are pooled with other TransCanadaTC Energy affiliates. The agreement also gives Great Lakes the ability to obtain short-term borrowings to provide liquidity for Great Lakes' Lakes’20172020 and 2016,2019, Great Lakes has anhad outstanding receivablereceivables from this arrangement amounting to $64$27 million and $27$34 million, respectively.Effective2014, Great Lakes executed contracts with an affiliate, ANR Pipeline Company (ANR), to provide firm service in Michigan and Wisconsin. These contracts were at the maximum FERC authorized rate and were intended to replace historical contracts. On December 3, 2014, FERC accepted and suspended Great Lakes' tariff records to become effective May 3, 2015, subject to refund. On February 2, 2015, FERC issued an Order granting a rehearing and clarification request submitted by Great Lakes, which allowed additional time for FERC to consider Great Lakes' request. Following extensive discussions with numerous shippers and other stakeholders, on April 20, 2015, ANR filed a settlement with FERC that included an agreement by ANR to pay Great Lakes the difference between the historical and maximum rates (ANR Settlement). Great Lakes provided service to ANR under multiple service agreements and rates through May 3, 2015 when Great Lakes' tariff records became effective and subject to refund. Great Lakes deferred an approximate $9 million of revenue related to services performed in 2014 and approximately $14 million of additional revenue related to services performed through May 3, 2015 under such agreements. On October 15, 2015, FERC accepted and approved the ANR Settlement. As a result, Great Lakes recognized the deferred transportation revenue of approximately $23 million in the fourth quarter of 2015.On April 24, 2017 Great Lakes reached an agreement on the terms of a new long-term transportation capacity contract with its affiliate, TransCanada. The contract, which was subject to Canada's National Energy Board (NEB) approval, is for a term of 10 yearsten-year period and allows TransCanada the abilityTC Energy to transport up to 0.711 billion cubic feet of natural gas per day on the Great Lakes system from the Manitoba/U.S. border to the U.S. border near Dawn Ontario. On September 21, 2017, TransCanada received approval from the NEB and as a result, thissystem. This contract, commenced on November 1, 2017. This contractwhich contains volume reduction options up to full contract quantity beginning in year three.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, 2017,2020, the total reservation revenue earned by Great Lakes on this contract was $13 million.2017, 20162019 and 2015,2018, PNGTS provided transportation servicesservice to a related party. Revenues from TransCanada Energy Ltd., a subsidiary of TransCanada, for 2017, 2016TC Energy and 2015 were approximatelyearned revenues of less than $1 million $2 million and $3$1 million, respectively. At December 31, 2017,2020 and 2019, PNGTS had nil million0 outstanding receivables from TransCanada Energy Ltd. in the consolidated balance sheets.anticipated future commercial opportunities,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 beare required to fulfill future contracts on the PNGTS'PNGTS system. In the event the anticipated developments do not proceed,expansions are terminated prior to their in-service dates, PNGTS willwould be required to reimburse its affiliates for any costs incurred related to the development of these facilities. In November 2020, the last phase of PXP (Phase III) was placed in service. As a result of December 31, 2017,placing the TC Energy facilities associated with the Phases I, II and III volumes in service, PNGTS' reimbursement obligation to TC Energy relating to this project has been extinguished.incurred by these affiliates was approximately $3 million.TC PipeLines, LPAnnual Report2017 F-2920172020 and 2016:
Quarter ended (millions of dollars except per common unit amounts)
Mar 31
Jun 30
Sept 30
Dec 31 2017 Transmission revenues 112 101 100 109 Equity earnings 36 24 27 37 Net income 83 55 55 70 Net income attributable to controlling interests 77 55 54 66 Net income per common unit $1.05 $0.73 $0.61 $0.77 Cash distribution paid to common units(a) 68 68 74 74 Cash distribution paid to Class B units 22 – – – 2016 Transmission revenues(b) 111 101 103 111 Equity earnings(b) 33 20 22 22 Net income(b) 81 57 60 65 Net income attributable to controlling interests(b) 74 55 58 61 Net income per common unit(c) $1.10 $0.76 $0.65 $0.70 Cash distribution paid to common unit(c) 59 60 65 66 Cash distribution paid to Class B units 12 – – – Mar 31 Jun 30 Sept 30 Dec 31 2020 Transmission revenues 101 95 99 104 Equity earnings 55 29 39 47 Net income (loss) 94 61 68 78 Net income (loss) attributable to controlling interests 88 57 65 74 Net income (loss) per common unit $ 1.21 $ 0.78 $ 0.90 $ 1.01 47 47 47 47 Cash distribution paid to Class B units 8 0 0 0 2019 Transmission revenues 113 93 93 104 Equity earnings 54 30 31 45 Net income 100 57 59 82 Net income attributable to controlling interests 93 55 56 76 Net income per common unit $ 1.28 $ 0.75 $ 0.76 $ 0.95 47 47 47 47 Cash distribution paid to Class B units 13 0 0 0 partner's effective twopartner’s 2 percent share and IDRs.(b)Recast to consolidate PNGTS for the year ended December 31, 2016 (Refer to Note 2).(c)Historical net income per common unit was not recasted.management'smanagement’s best estimate is used.cash"cash and cash equivalents, accounts" "accounts receivable and other, accounts" "accounts payable and accrued liabilities, accounts" "accounts payable to affiliates, accrued interestaffiliates" and short-term debt"accrued interest" approximate their fair values because of the short maturity or duration of these instruments, or because the instruments bear a variable rate of interest or a rate that approximates current rates. The fair value of the Partnership's long-termPartnership’s debt is estimated by discounting the future cash flows of each instrument at estimated current borrowing rates. The fair value of interest rate derivatives is calculated using the income approach, which uses period-end market rates and applies a discounted cash flow valuation model.20172020 and December 31, 20162019 was $2,475$2,388 million and $1,963$2,111 million, respectively.F-30 TC PipeLines, LPAnnual Report2017The common units subject to rescission as presented in the December 31, 2016 balance sheet, as discussed more fully in Note 10, were measured using the original issuance price, plus statutory interest and less any distributions paid. This fair value measurement is classified as Level 2.Partnership'sPartnership’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.Partnership hedgedfixed weighted average interest paymentsrate on these instruments is 3.26 percent. On June 26, 2019, in conjunction with the variable-ratePartnership's $50 million repayment on its 2013 Term Loan Facility, withthe Partnership also terminated an equivalent amount in interest rate swaps maturing July 1, 2018,that were used to hedge this facility at a weighted average fixed interestan unwind rate of 2.31 percent. 2.81 percent (See also Note 8).2017,2020, the fair value of the interest rate swaps accounted for as cash flow hedges was an asseta liability of $5$15 million (on both gross and net basis). At December (December 31, 2016, the fair value of the interest rate swaps accounted for as cash flow hedges was an asset of $1 million and a2019 - liability of $1 million (on a gross basis) and an asset of nil million (on a net basis). The Partnership did not record any amounts in net income related to ineffectiveness for interest rate hedges for$6 million), the years ended December 31, 2017, 2016 and 2015. The net change in fair value of interest rate derivative instrumentswhich is recognized in other comprehensive income was a gain of $5 million forincome. For the year ended December 31, 2017 (2016 – gain of $2 million, 2015 – nil). In 2017,2020, the net realized loss related to the interest rate swaps was nil,$7 million and was included in financial charges and other (2016 – $3(2019 - $1 million 2015gain, 2018 – $2 million)million gain). Refer to Note 12 – Financial Charges and Other.As discussed in Note 8, the Partnership's $500 million 2013 Term Loan that was due July 1, 2018, was amended to extend the maturity period through October 2, 2022. As a result of this extension, the Partnership implemented an interest rate hedging strategy during the fourth quarter of 2017 and hedged the entire $500 million until its October 2, 2022 maturity using forward starting swaps at an average rate of 3.26 percent.agreements,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 net asset of $5 million as of December 31, 2017 and there would be no effect on the consolidated balance sheet as of December 31, 2016.In anticipation of a debt refinancing in 2003, PNGTS entered into forward interest rate swap agreements to hedge the interest rate on its Senior Secured Notes due in 2018. These interest rate swaps were used to manage the impact of interest rate fluctuations2020 and qualified as derivative financial instruments in accordance with ASC 815,Derivatives and Hedging. PNGTS settled its position with a payment of $20.9 million to counterparties at the time of the refinancing and recorded the realized loss in AOCI as of the termination date. The previously recorded AOCI is currently being amortized against earnings over the life of the PNGTS Senior Secured Notes. At December 31, 2017, our 61.71 percent proportionate share of net unamortized loss on PNGTS included in AOCI was $1 million (2016 – $2 million). For the year ended December 31, 2017, 2016 and 2015, our 61.71 percent proportionate share of the amortization of realized loss on derivative instruments was $0.8 million for each year.2017,2020, we had not incurred any significant credit losses and had no0 significant amounts past due or impaired. At December 31, 2017, we had a credit risk concentration on one of our customers and the amount owed is greater2020, no customer accounted for more than 10 percent of our tradeconsolidated revenues and accounts receivable, respectively (refer also to Note 16)16 for more details).measurement onmeasurements used in any of our equity investment in Great Lakes isimpairment analyses 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 flowsrates which involved significant assumptions and estimates as discussed more fully in Note 5.TC PipeLines, LPAnnual Report2017 F-31
estimates.
December 31 (millions of dollars)
2017
2016(a) Trade accounts receivable, net of allowance of nil 40 44 Imbalance receivable from affiliates 1 2 Other 1 1 42 47 (a)Recast to consolidate PNGTS (Refer to Notes 2 and 7).NOTE 21 REGULATORYGTN – GTN operates under rates established pursuant to a settlement approved by FERC in June 2015. Beginning in January 2016, GTN's rates decreased by 10 percent and will continue in effect through December 31, 2019. Unless superseded by a subsequent rate case or settlement, GTN's rates will decrease an additional eight percent for the period January 1, 2020 through December 31, 2021 when GTN will be required to establish new rates.Tuscarora – Tuscarora operates under rates established pursuant to a settlement approved by FERC in September 2016. Under the settlement, Tuscarora's system-wide unit rate initially decreased by 17 percent, effective August 1, 2016. Unless superseded by a subsequent rate case or settlement, this rate will remain in effect until July 31, 2019, after which time the unit rate will decrease by an additional seven percent from August 1, 2019 through July 31, 2022. The settlement does not contain a rate moratorium and requires Tuscarora to file to establish new rates no later than August 1, 2022.Bison – Bison continues to operate 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 continues to operate under the rates approved by FERC and has no requirement to file a new rate proceeding. On January 6, 2017, North Baja notified FERC that current market conditions do not support the replacement of the compression that was temporarily abandoned in 2013 and requested authorization to permanently abandon two compressor units and a nominal volume of unsubscribed firm capacity. FERC approved the permanent abandonment request on February 16, 2017. The requested abandonments will not have any impact on existing firm transportation service.PNGTS – PNGTS continues to operate under the rates approved by FERC in February 2015 (Refer to Note 2 – Significant Accounting Policies – Revenue Recognition). PNGTS has no requirement to file a new rate proceeding.NOTE 22 CONTINGENCIESThe 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 withASC 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.Below is a material legal proceeding that might have a significant impact on the Partnership:Great Lakes v. Essar Steel Minnesota LLC, et al. – On October 29, 2009, Great Lakes filed suit in the U.S. District Court, District of Minnesota, against Essar Minnesota LLC (Essar Minnesota) and certain Foreign Essar Affiliates (collectively, Essar) for breach of its monthly payment obligation under its transportation services agreement with Great Lakes. Great Lakes sought to recover approximately $33 million for past and future payments due under the agreement. On September 16, 2015, following a jury trial, the federal district court judge entered a judgment in the amount of $32.9 million in favor of Great Lakes. On September 20, 2015, Essar appealed the decision to the United States Court of Appeals for the Eighth Circuit (Eighth Circuit) based on an allegation of improper jurisdiction and a number of other rulings by the federal district judge. Essar was required to post a performance bond for the full value of the judgment pending appeal. The Eighth Circuit heard the appeal on October 20, 2016. A decision on the appeal was received in December 2016 and the Eighth Circuit vacated Great Lakes' judgment against Essar finding that there was no federal jurisdiction. Great Lakes filed a Request for Rehearing with the Eighth Circuit and it was denied in January 2017. Before the Circuit Court issued its decision, Essar Minnesota filed for bankruptcy in July 2016. The Foreign Essar Affiliates have not filed for bankruptcy. Following the Circuit Court's decision, the performance bond was released into the bankruptcy court proceedings. Great Lakes filed a claim against Essar Minnesota in the bankruptcy court and its case against the Foreign Essar Affiliates inF-32 TC PipeLines, LPAnnual Report2017Minnesota state court remains pending. In April 2017, after Great Lakes agreement with creditors on an allowed claim, the bankruptcy court approved Great Lakes' claim in the amount of $31.5 million. On May 20, 2017, the federal district court awarded Essar Minnesota approximately $1.2 million for costs, including recovery of the performance bond premium, to be paid by Great Lakes. Great Lakes filed a motion with the bankruptcy court to offset the $1.2 million award of costs against its claim against Essar Minnesota in the bankruptcy proceeding but was unsuccessful. As a result, Great Lakes accrued the $1.2 million in its books. Great Lakes is unable to estimate the timing or the extent to which its claim will be recoverable in the bankruptcy proceedings.NOTE 23 VARIABLE INTEREST ENTITIESIn 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 analysis, the Partnership continues to consolidate all legal entities in which it has a variable interest and for which it is considered to be the primary beneficiary. VIEs where the Partnership is not the primary beneficiary, but has a variable interest in the entity, are accounted for as equity investments.Consolidated VIEsThe Partnership's consolidated VIEs consist of the Partnership's ILPs that hold interests in the Partnership's pipeline systems. After considering the purpose and design of the ILPs and the risks that they were designed to create and pass through to the Partnership, the Partnership has concluded that it is the primary beneficiary of these ILPs because of the significant amount of variability that it absorbs from the ILPs' economic performance.The assets and liabilities held through these VIEs that are not available to creditors of the Partnership and whose investors have no recourse to the credit of the Partnership are held through GTN, Tuscarora, Northern Border, Great Lakes, PNGTS and Iroquois due to their third party debt. The following table presents the total assets and liabilities of these entities that are included in the Partnership's Consolidated Balance Sheets:
(millions of dollars)
December 31,
2017
December 31,
2016(b) ASSETS (LIABILITIES)(a) Cash and cash equivalents 19 14 Accounts receivable and other 30 33 Inventories 6 6 Other current assets 5 6 Equity investments 1,213 918 Plant, property and equipment 1,133 1,146 Other assets 1 2 Accounts payable and accrued liabilities (24 ) (21 ) Accounts payable to affiliates, net (42 ) (32 ) Distributions payable (1 ) (3 ) Accrued interest (2 ) (2 ) Current portion of long-term debt (51 ) (52 ) Long-term debt (308 ) (337 ) Other liabilities (26 ) (25 ) Deferred state income tax (10 ) (10 ) (a)North Baja and Bison, which are also assets held through our consolidated VIEs, are excluded as the assets of these entities can be used for purposes other than the settlement of the VIE's obligations.(b)Recast to consolidate PNGTS for the year ended December 31, 2016 (Refer to Note 2).TC PipeLines, LPAnnual Report2017 F-33NOTE 24 INCOME TAXESThe state of New Hampshire (NH) imposes a business profits tax (BPT) levied at the PNGTS level. 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, 2017, 2016 and 2015 relate primarily to utility plant. For the years ended December 31, 2017, 2016 and 2015, the NH BPT effective tax rate was 3.8 percent for all periods 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)
2017
2016(a)
2015(a) State income taxes Current 1 1 (2 ) Deferred – – 4 1 1 2 (a)Recast to consolidate PNGTS (Refer to Notes 2 and 7).2020 2019 Trade accounts receivable, net of immaterial allowance for doubtful accounts 36 37 Receivable from affiliates 1 0 Other 3 6 40 43 2521 SUBSEQUENT EVENTS26, 2018,24, 2021, 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.23, 2018,19, 2021, the board of directors of our General Partner declared the Partnership's fourth quarter 20172020 cash distribution in the amount of $1.00$0.65 per common unit and was paid on February 13, 201812, 2021 to unitholders of record as of February 2, 2018.January 29, 2021. The declared distribution totaled $76$47 million and was paidis payable in the following manner: $71$46 million to common unitholders (including $6$4 million to the General Partner as a holder of 5,797,106 common units and $11$7 million to another subsidiary of TransCanadaTC Energy as holder of 11,287,725 common units) and $5$1 million to ourthe General Partner which included $2 million for its effective two2 percent general partner interest and $3 million of IDRs payment.On January 23, 2018, the board of directors of ourinterest. The General Partner declareddid 0t receive any distributions to Class B unitholders in respect of its IDRs for the amountfourth quarter 2020.20172020 distribution of $15$16 million on January 8, 2018,15, 2021, of which the Partnership received its 50 percent share or $7$8 million on January 31, 2018.20182021 distribution of $17$18 million on February 14, 2018,16, 2021, of which the Partnership will receive its 50 percent share or $9 million on February 28, 2018.20172020 distribution of $20$23 million on January 10, 2018,13, 2021, of which the Partnership received its 46.45 percent share or $9$11 million on February 1, 2018.20172020 distribution of $29$22 million on January 22, 2018, of whichFebruary 18, 2021, and the Partnership receivedwill receive its 49.34 percent share or $14$11 million on February 1, 2018. The $14March 24, 2021. Additionally, on March 24, 2021, the Partnership will make a $1 million includes our proportionatecapital contribution to Iroquois representing the Partnership's 49.34 percent share of Iroquois' unrestricteda cash amountingcall from Iroquois to $2.6cover costs related to their ExC Project.(referon January 13, 2021, of which $5 million was paid to Note 7).PNGTSJanuary 2, 2018, PNGTS paidFebruary 12, 2021, the amount duePartnership exercised its option to redeem the Unsecured Senior Notes on December 31, 2017 on its 2003 Senior Secured Notes amountingMarch 15, 2021, at a redemption price equal to $6 million representing $6 million in principal and nil in interest pursuant to the terms100% of the Note Purchase agreement. Underprincipal amount of the agreement, any principalnotes then outstanding, plus unpaid interest accrued to March 15, 2021. Partial funding for the redemption is expected to be provided using cash on hand, and interest that is due on a date other than a normal business day shall be made onborrowings under the next succeeding business day without additional interest or penalty.F-34Partnership’s $500 million Senior Credit Facility.2017 2020NORTHERN BORDER PIPELINE COMPANYINDEPENDENT AUDITORS' REPORTReport on the Financial Statements(the Company), which comprise the balance sheets as of December 31, 20172020 and 2016,2019, and the related statements of income, comprehensive income, changes in partners'partners’ equity, and cash flows for each of the years in the three-year period ended December 31, 2017,2020, and the related notes to the financial statements.Management'sAuditors'auditors'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'sentity’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'sentity’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.20172020 and 2016,2019, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2017,2020 in accordance with U.S. generally accepted accounting principles.16, 20182017 F-352020F-31
December 31, 2017 and 2016 (In thousands)
2017
2016 Assets Current assets: Cash and cash equivalents $ 14,010 13,535 Accounts receivable 24,738 23,484 Related party receivables 3,049 3,503 Materials and supplies 5,216 5,727 Prepaid expenses and other 3,761 3,482 Total current assets 50,774 49,731 Property, plant and equipment: In service natural gas transmission plant 2,605,625 2,584,065 Construction work in progress 5,692 1,409 Total property, plant and equipment 2,611,317 2,585,474 Less: Accumulated provision for depreciation and amortization 1,548,635 1,496,860 Property, plant and equipment, net 1,062,682 1,088,614 Other assets: Regulatory assets 13,994 14,773 Other 7 7 Total other assets 14,001 14,780 Total assets $1,127,457 1,153,125
Liabilities and Partners' Equity
Current liabilities: Accounts payable $ 9,737 9,568 Related party payables 4,154 3,507 Accrued taxes other than income 19,609 20,286 Accrued interest 4,691 4,707 Other 243 196 Total current liabilities 38,434 38,264 Long-term debt, net 264,056 429,545 Deferred credits and other liabilities Regulatory liabilities 27,031 24,473 Other 4,336 3,931 Total deferred credits and other liabilities 31,367 28,404 Total liabilities 333,857 496,213 Partners' equity: Partners' capital 794,869 658,466 Accumulated other comprehensive loss (1,269 ) (1,554 ) Total partners' equity 793,600 656,912 Total liabilities and partners' equity $1,127,457 1,153,125 December 31, 2020 and 2019 (in thousands) 2020 2019 Assets Current assets: Cash and cash equivalents $ 31,174 20,667 Accounts receivable 23,180 24,418 Related party receivables 4,877 4,391 Materials and supplies 6,472 5,706 Prepaid expenses and other 3,483 2,783 Total current assets 69,186 57,965 Property, plant and equipment: In-service natural gas transmission plant 2,668,642 2,633,800 Construction work in progress 9,308 1,601 Right of use asset 133 156 Total property, plant and equipment 2,678,083 2,635,557 Less: Accumulated provision for depreciation and amortization 1,701,463 1,646,711 Property, plant and equipment, net 976,620 988,846 Other assets: Regulatory assets 11,657 12,436 Other 221 — 11,878 12,436 Total assets $ 1,057,684 $ 1,059,247 Liabilities and Partners' Equity Current liabilities: Accounts payable $ 10,899 3,663 Related party payables 4,198 4,421 Accrued taxes other than income 18,811 18,369 Accrued interest 4,831 4,986 Customer advances for construction 13,404 10,517 Other current liabilities 23 22 Current maturities of long-term debt 250,000 — Total current liabilities 302,166 41,978 Long-term debt, net 129,769 364,352 Deferred credits and other liabilities Regulatory liability 36,115 33,219 Other 5,659 5,280 Total deferred credits and other liabilities 41,774 38,499 Total liabilities 473,709 444,829 Partners' equity: Partners' capital 584,255 615,052 Accumulated other comprehensive loss (280) (634) Total partners' equity 583,975 614,418 Total liabilities and partners' equity $ 1,057,684 1,059,247 F-362017 2020
Years ended December 31, 2017, 2016, and 2015 (In thousands)
2017
2016
2015 Operating revenue $291,396 291,642 285,510 Operating expenses: Operations and maintenance 54,374 47,652 47,260 Depreciation and amortization 59,426 58,813 59,571 Taxes other than income 23,480 24,200 22,826 Operating expenses 137,280 130,665 129,657 Operating income 154,116 160,977 155,853 Interest expense: Interest expense 22,257 25,433 26,591 Interest expense capitalized (176 ) (100 ) (76 ) Interest expense, net 22,081 25,333 26,515 Other income (expense): Allowance for equity funds used during construction 573 297 243 Other income 3,936 4,151 4,722 Other expense (238 ) (113 ) (420 ) Other income, net 4,271 4,335 4,545 Net income to partners $136,306 139,979 133,883 NORTHERN BORDER PIPELINE COMPANYSTATEMENTS OF COMPREHENSIVE INCOME
Years ended December 31, 2017, 2016, and 2015 (In thousands)
2017
2016
2015 Net income to partners $136,306 139,979 133,883 Other comprehensive income: Changes associated with hedging transactions 285 264 245 Total comprehensive income $136,591 140,243 134,128 December 31, 2020, 2019, and 2018 (in thousands) 2020 2019 2018 Operating revenue $ 307,803 300,221 289,418 Operating expenses: Operations and maintenance 54,215 60,428 54,576 Depreciation and amortization 62,109 61,588 60,492 Taxes other than income 23,098 22,539 23,892 Operating expenses 139,422 144,555 138,960 Operating income 168,381 155,666 150,458 Interest expense: Interest expense 21,766 21,727 19,943 Interest expense capitalized (195) (37) (101) Interest expense, net 21,571 21,690 19,842 Other income (expense): Allowance for equity funds used during construction 1,169 318 623 Other income 2,918 3,805 4,505 Other expense (79) (357) (37) Other income, net 4,008 3,766 5,091 Net income to partners $ 150,818 137,742 135,707 2017 F-372020F-33CASH FLOWSYears ended December 31, 2017, 2016, and 2015 (In thousands)
2017
2016
2015 Cash flows from operating activities: Net income to partners $ 136,306 139,979 133,883 Adjustments to reconcile net income to partners to net cash provided by operating activities: Depreciation and amortization 59,426 58,813 59,571 Allowance for equity funds used during construction (573 ) (297 ) (243 ) Changes in components of working capital (1,411 ) 217 (7,644 ) Other 406 45 1,843 Total adjustments 57,848 58,778 53,527 Net cash provided by operating activities 194,154 198,757 187,410 Cash flows used in investing activities: Capital expenditures (27,054 ) (21,592 ) (15,348 ) Other (722 ) (982 ) (3,417 ) Net cash used in investing activities (27,776 ) (22,574 ) (18,765 ) Cash flows used in financing activities: Equity contributions from partners 166,000 – – Distributions to partners (165,903 ) (209,792 ) (182,173 ) Proceeds from issuance of debt – 128,000 10,000 Repayment of debt (166,000 ) (108,000 ) (10,000 ) Debt issuance costs – (150 ) (564 ) Net cash used in financing activities (165,903 ) (189,942 ) (182,737 ) Net change in cash and cash equivalents 475 (13,759 ) (14,092 ) Cash and cash equivalents at beginning of year 13,535 27,294 41,386 Cash and cash equivalents at end of year $ 14,010 13,535 27,294 Supplemental disclosure for cash flow information: Cash paid for interest, net of amount capitalized $ 21,301 26,746 25,802 Accruals for property, plant and equipment 2,592 63 1,841 Changes in components of working capital: Accounts receivable $ (1,254 ) (973 ) 1,220 Related party receivables 454 (1,163 ) (742 ) Materials and supplies 511 (78 ) (109 ) Prepaid expenses and other 319 374 (118 ) Accounts payable (1,702 ) 3,369 (1,183 ) Related party payables 709 318 (6,507 ) Accrued taxes other than income (676 ) 520 (188 ) Accrued interest (15 ) (2,150 ) (17 ) Other current liabilities 243 – – Total $ (1,411 ) 217 (7,644 ) December 31, 2020, 2019, and 2018 (in thousands) 2020 2019 2018 Net income to partners $ 150,818 137,742 135,707 Other comprehensive income: Changes associated with hedging transactions 354 329 306 Total comprehensive income $ 151,172 138,071 136,013 F-382017 2020CHANGES IN PARTNERS' EQUITY(In thousands)
TC PipeLines
Intermediate
Limited
Partnership
ONEOK
Partners
Intermediate
Limited
Partnership
Accumulated
Other
Comprehensive
Income (Loss)
Total
Partners'
Equity Partners' equity at December 31, 2014 $ 388,284 388,285 (2,063 ) 774,506 Net income to partners 66,941 66,942 – 133,883 Changes associated with hedging transactions – – 245 245 Distributions to partners (91,086 ) (91,087 ) – (182,173 ) Partners' equity at December 31, 2015 $ 364,139 364,140 (1,818 ) 726,461 Net income to partners 69,990 69,989 – 139,979 Changes associated with hedging transactions – – 264 264 Distributions to partners (104,896 ) (104,896 ) – (209,792 ) 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 Years ended December 31, 2020, 2019, and 2018 (In thousands) 2020 2019 2018 Cash flows from operating activities: Net income to partners $ 150,818 137,742 135,707 Adjustments to reconcile net income to partners to net cash provided by operating activities: Depreciation and amortization 62,109 61,588 60,492 Allowance for equity funds used during construction (1,169) (318) (623) Changes in components of working capital 4,800 578 (5,909) Amortization of debt expense 871 226 704 Other (208) 1,708 2,208 Total adjustments 66,403 63,782 56,872 Net cash provided by operating activities 217,221 201,524 192,579 Cash flows used in investing activities: Capital expenditures (42,886) (11,344) (31,269) Other 2,887 7,787 646 Net cash used in investing activities (39,999) (3,557) (30,623) Cash flows used in financing activities: Distributions to partners (181,615) (286,899) (166,367) Proceeds from issuance of debt 14,900 100,000 — Net cash used in financing activities (166,715) (186,899) (166,367) Net change in cash and cash equivalents 10,507 11,068 (4,411) Cash and cash equivalents at beginning of year 20,667 9,599 14,010 Cash and cash equivalents at end of year $ 31,174 20,667 9,599 Supplemental disclosure for cash flow information: Cash paid for interest, net of amount capitalized $ 20,827 20,687 19,098 Accruals for property, plant and equipment, net 2,462 (625) (1,113) Changes in components of working capital: Accounts receivable $ 1,238 1,223 (903) Related party receivables (486) (1,120) (222) Materials and supplies (766) (94) (396) Prepaid expenses and other (24) (699) (167) Accounts payable 4,774 1,209 (5,834) Related party payables (223) 741 2,119 Accrued taxes other than income 442 (937) (303) Accrued interest (155) 255 40 Other current liabilities — — (243) Total $ 4,800 578 (5,909) 2017 F-392020F-35(In thousands) TC PipeLines,
LPONEOK
Northern
Border
Pipeline
Company
Holdings,
L.L.C.Accumulated
Other
Comprehensive
Income (Loss)Total
Partners'
EquityPartners' 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 Net income to partners 75,409 75,409 — 150,818 Changes associated with hedging transactions — — 354 354 Distributions to partners (90,808) (90,807) — (181,615) Partners' equity at December 31, 2020 $ 292,127 292,128 (280) 583,975 YEARS ENDED DECEMBER2017 AND 2016at December 31, 2017 and 2016 were as follows:PartnerOwnershipONEOK Partners Intermediate Limited Partnership (ONEOK)50%Ownership ONEOK Northern Border Pipeline Company Holdings, L.L.C. 50 % TC PipeLines, Intermediate Limited Partnership (TC PipeLines)LP50 50%% TC PipeLinesTCP designates one of its members as chairman.U.S. generally accepted accounting principles (GAAP)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.(b) Judgment is required in developing these estimates.Partnership'sPartnership’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.(c) 20172020 and 20162019 were not material to the Partnership'sPartnership’s financial statements.(d) Partnership'sPartnership’s tariff.accounts payable to affiliates.related party payables. In addition, the Partnership classifies all imbalances as current as the Partnership expects to settle them within a year.(e) Partnership'sPartnership’s inventories primarily consist of materials and supplies and are carried at lower of weighted average cost or market.F-40 and net realizable value.20172020F-37Partnership'sPartnership’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.20172020 and 2016: December 31,
Remaining
recovery/
settlement
period
2017
2016 (In thousands) (Years) Regulatory Assets Fort Peck lease option $ 12,149 12,466 38 Pipeline extension project 1,845 2,307 4 Volumetric fuel tracker 1,161 1,387 (a ) Compressor usage surcharge 823 – (b ) 15,978 16,160 Less: Current portion included in Prepaid expenses and other 1,984 1,387 $ 13,994 14,773 Regulatory Liabilities Negative salvage $ 27,031 24,473 (c ) Compressor usage surcharge – 196 (b ) 27,031 24,669 Less: Current portion included in Other – 196 $ 27,031 24,473 December 31, Remaining
recovery/
settlement2020 2019 period (In thousands) (Years) Regulatory Assets Fort Peck right-of-way option $ 11,196 11,513 35 Pipeline extension project 461 923 1 Volumetric fuel tracker 816 139 (a) 12,473 12,575 Less: Current portion included in Prepaid expenses and other 816 139 $ 11,657 12,436 Regulatory Liabilities Negative salvage $ 34,575 31,966 (c) Compressor usage surcharge 1,540 1,253 (b) $ 36,115 33,219 continuallyPartnership'sPartnership’s electric compressors and compressor fuel use taxes imposed on the consumption of natural gas powered stations along the Partnership'sPartnership’s pipeline system (refer to Note 5(b)4(b))2(g)2(h))(g) Partnership'sPartnership’s last rate proceeding. Currently, the Partnership'sPartnership’s depreciation rates vary from 2% to 20% per year. Using these rates, the remaining depreciable life of these assets ranges from 1 to 3738 years.TC PipeLines, LPAnnual Report2017 F-41 calculatedPartnership'sPartnership’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.(h) (i) Partnership'sPartnership’s revenues are primarily generated from contractual arrangements for committed capacity and from transportation services.of natural gas which are treated as a bundled performance obligation. Revenues for all services are based on the quantity of gas delivered or subscribed at a price specified in the contract. For the Partnership's transportation services, reservation revenues are recognized onearned from firm contracted capacity arrangements are recognized ratably over the term of the contract period regardless of the amount of natural gas that is transported. For the Partnership'sTransportation revenues for interruptible or volumetric-based services are recognized when the Partnership records revenues when physical deliveries of natural gas are made at the agreed-upon delivery point.service is performed. The Partnership doesutilizes 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 it transports. 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.Partnership isPartnership's pipeline systems are subject to FERC regulations and, as a result, a portion of revenues the Partnership collectscollected may be subject to refund inif invoiced during an interim period when a rate proceeding. The Partnership establishes provisionproceeding is ongoing. Allowances for these potential refunds.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, 20172020, and 2016,2019, there are no refund provisions reflected in these financial statements.(j) systemsystem’s life is not determinable with the degree of accuracy necessary to currently establish a liability for the obligations.20172020 and 2016.2019. The Partnership continues to evaluate its asset retirement obligations and future developments that could impact amounts it records.(k) For all hedging relationships, the Partnership formally documents the hedging relationship and its risk-management objective and strategy for undertaking the hedge, the hedging instrument, the hedged transaction, the nature of the risk being hedged, how the hedging instrument's effectiveness in offsetting the hedged risk will be assessed prospectively and retrospectively, and a description of the method used to measure ineffectiveness. The Partnership also formally assesses, both at the inception of the hedging relationship and on an ongoing basis, whether the derivatives that are used in theF-42 TC PipeLines, LPAnnual Report2017hedging relationships are highly effective in offsetting changes in cash flows of hedged transactions. For derivative instruments that are designated and qualify as part ofIn a cash flow hedging relationship, the effective portionchange in the fair value of the gain or loss on the derivativeshedging 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 transactionearnings. Gains and losses onearnings or is reclassified immediately to net income when the derivative representing either hedge ineffectivenesshedged item is sold or hedge components excluded from the assessment of effectiveness are recognized in current earnings.The Partnership discontinues hedge accounting prospectivelyterminated early, or when it determinesbecomes probable that the derivative is no longer effective in offsetting cash flows attributable to the hedged risk, the derivative expires or is sold, terminated, or exercised, the cash flow hedge is de-designated because a forecasted transaction is not probable of occurring, or management determines to remove the designation of the cash flow hedge.In all situations in which hedge accounting is discontinued and the derivative remains outstanding, the Partnership continues to carry the derivative at its fair value on the balance sheet and recognizes any subsequent changes in its fair value in earnings. When it is probable that a forecastedanticipated transaction will not occur,occur.discontinues hedge accounting and recognizes immediatelyterminated a series of interest rate derivatives in earnings gains and losses that wereexchange for cash. These derivatives had previously been accounted for as hedges with $4.1 million recorded in accumulated in other comprehensive incomeloss (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, 2020, the remaining balance in AOCL that is left to be reclassified to earnings is $0.3 million, of which all is expected to be reclassified in 2021.hedging relationship.(l) year ended December 31, 2020.discount or premiums.discounts. In addition, amortization of debt issuance costs, premiums, and discounts are reported as part of interest expense.(m) ContingenciesThe Partnership recognizes liabilities for contingencies when it has an exposure that, when fully analyzed, indicates it is both probable that a liability has been incurred and the amount of loss can be reasonably estimated. Where the most likely outcome of a contingency can be reasonably estimated, the Partnership accrues a liability for that amount. Where the most likely outcome cannot be estimated, a range of potential losses is established and if no one amount in that range is more likely than any other, the lower end of the range is accrued. CommitmentsThe Partnership has non-cancelable leases for office space and rights-of-way commitments. The Partnership records expenses straight-line over the life of the of these arrangements.(o) (p) Considerable judgmentJudgment is required in developing these estimates.(a) for 2017InventoryJuly 2015,June 2016, the FASB issued new guidance on simplifying the measurement of inventory.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 specifies thatamends the impairment model of financial instruments basing it on expected losses rather than incurred losses. These expected credit losses will be recognized as an entity should measure inventory withinallowance rather than as a direct write down of the scope of this update at the lower ofamortized cost and net realizable value. Net realizable value is the estimated selling price in the ordinary course of business, less reasonably predictable costs of completion, disposal and transportation. Thisbasis. The new guidance wasis effective January 1, 2017,2020 and was applied prospectively andusing a modified retrospective approach. The adoption of this new guidance did not have a material impact on the Partnership's balance sheets.TC PipeLines, LPAnnual Report2017 F-43(b) Future Accounting ChangesRevenuePartnership’s financial statements.contracts with customersIn 2014,late 2021 to mid-2023, the FASB issued new optional guidance on revenue from contracts with customers.that eases the potential burden of accounting for reference rate reform. The new guidance requiresprovides optional expedients for contracts and hedging relationships that an entity recognizes revenue with a prescribed model. This model is used to depict the transfer of promised goods or services to customers in an amount that reflects the total consideration to which the company expects to be entitled during the termare affected by reference rate reform, if certain criteria are met. Each of the contract in exchange for those goods or services. The new guidance also requires additional disclosures about the nature, amount, timing and uncertainty of revenue and the related cash flows. The Partnership will adopt the new standard on the effective dateexpedients can be applied as of January 1, 2018. There are two methods in which the new standard can be adopted: (1) a full retrospective approach with restatement of all prior periods presented, or (2) a modified retrospective approach with a cumulative-effect adjustment as of the date of adoption. The Partnership will adopt the guidance using the modified retrospective approach with the cumulative-effect of the adjustment recognized at the date of adoption, subject to allowable and elected practical expedients.The Partnership has identified all existing customer contracts that are within the scope of the new guidance. The Partnership has completed its analysis and has not identified any material differences in the amount and timing of revenue recognition through. The Partnership will not require a cumulative-effect adjustment to opening partners' equity on January 1, 2018.Although revenues will not be materially impacted by the guidance, the Partnership will be required to add significant disclosures based on the prescribed requirements. These new disclosures will include information regarding the significant judgments used in evaluating when and how revenue is recognized and information related to contract assets and deferred revenues. In addition, the new guidance requires that the Partnership's revenue recognition policy disclosure includes additional detail regarding the various performance obligations and the nature, amount, timing and estimates of revenue and cash flows generated from contracts with customers. The Partnership has addressed system and process changes necessary to compile the information to meet the recognition and disclosure requirements of the new guidance.LeasesIn February 2016, the FASB issued new guidance on the accounting for leases. The new guidance amends the definition of a lease requiring the customer 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 in order for the arrangement to qualify as a lease. 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 12 months. Leases will be classified as finance or operating, with classification affecting the pattern and classification of expense recognition in the income statement. The new guidance does not make extensive changes to lessor accounting.The new guidance is effective on January 1, 2019, with early adoption permitted. A modified retrospective transition approach is required for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements, with certain practical expedients available.2020 through December 31, 2022. The Partnership is continuing to identify and analyze existing lease agreements to determine the effect of adoption of the new guidancereference rate reform on its consolidated financial statements. The Partnership is also addressing systemwill continue to evaluate the timing and process changes necessary to compile the information to meet the recognition and disclosure requirements of the new guidance. The Partnership continues to monitor and analyze additional guidance and clarification provided by FASB.4. U.S. TAX REFORM IMPACTOn December 22, 2017, the President of the United States signed into law H.R. 1 (the Tax Cuts and Jobs Act). This legislation provides for major changes to U.S. corporate federal tax law; including a reduction in the U.S. corporate tax rate to 21 percent from 35 percent. As a Texas general partnership, the Partnership is a non-taxable pass through entity and income taxes owed as a result of the Partnership's earnings are the responsibility of each partner, therefore no amounts have been recorded in the Partnership's financial statements as a result of the Tax Cuts and Jobs Act.The Partnership is regulated by the FERC, which approves its rates, the most recent of which were established through a negotiated settlement that did not ascribe any specific cost of service elements to income taxes. While the FERC also evaluates the Partnership's rate of return on an overall cost-of-service basis, they provide for a recovery of the Partnership's ultimate taxable owners' income tax expense and related balance sheet accounts as components of the maximum recourse rates that may be charged to customers. As a non-taxable pass through entity, the Partnership does not recognize income tax expense nor has it established deferred income tax assets or liabilities. Income tax related expenses, benefits, assets, and liabilities attributable to regulated operations are the responsibility of the ultimate taxable owners of the Partnership and any adjustment to income tax accounts following the Tax Cuts and Jobs Act must be evaluated by those owners.The Partnership cannot predict the ultimate impact; if any, of lower U.S. corporate tax rates on its future revenues. If in the future the FERC were to require a change in the Partnership's maximum recourse rates related to the change in the U.S. corporate tax rate, the Partnership expects rates would be revised through future rate proceedings or other regulatory action.At December 31, 2017, the Partnership considers its assessment of thepotential impact of the Tax Cuts and Jobs Act to be its best interpretationadoption of available guidance. Should additional guidance on the impact of the Tax Cuts and Jobs Act on non-taxable partnerships be provided by regulatory, tax and accounting authorities or other sources in the future, the Partnership will review the approach used and adjust as appropriate.F-44 TC PipeLines, LPAnnual Report20175.optional expedients when deemed necessary.Partnership'sPartnership’s financial condition, results of operations, or cash flows.pipeline'spipeline’s actual prudent historical cost investment. The rates and terms and conditions for service are found in each pipeline'spipeline’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.Effective January 1, 2013, theimplemented new rates asoperates under a result of itssettlement approved by FERC approved settlement agreement (2012 Settlement) with its customers and requires the Partnership to file for new rates no later than January 1, 2018. On December 4, 2017, Northern Border filed a rate settlement with FERC precluding the need to file a general rate case byeffective January 1, 2018 (2017 Settlement). The 2017if approved by FERC, providesprovided for tiered rate reductions beginningfrom January 1, 2018 with no changeto December 31, 2019 that equates to an overall rateunderlying rate design.2017 rates (10.5% by December 31, 2019 and additionaldoesdid not contain anya 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 to July 1, 2024 unless superseded by a subsequent rate case or settlement, recourse rates in effect at December 31, 2017, will decrease by 5.0% on January 1, 2018; by an additional 5.5% on April 1, 2018; and by a further 2.0% beginning January 1, 2020 through December 31, 2023, when the Partnership will be required to establish new rates. This equates to an overall rate reduction of 12.5% by January 1, 2020 from the recourse rates in effect at December 31, 2017.Partnership'sPartnership’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 recoveryover-recovery of actual costs or as a decrease to expense for an under recoveryunder-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 recognized 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, 20172020, and 2016,2019, the Partnership had recorded $0.8$1.5 million and $1.3 million as prepaid expenses other and $0.2 million as other current liabilities,regulatory liability, respectively, on the accompanying balance sheets for the net over and under recoveries of compressor usage related costs.non-cancelable leases on office space and rights-of-wayits right-of-way commitments. The Partnership'sPartnership’s expense incurred for these commitments was $2.9 million for the year ended December 31, 2020, $2.9 million and $3.0 million for each of the years ended December 31, 2017, 2016,2019, and 2015,2018, respectively. The Partnership'sPartnership’s future minimum payments on these arrangementsits rights-of-way commitments are as follows:
Year Ending (In thousands)
Rights-of-Way
Office Space
Total 2018 2,214 393 2,607 2019 2,215 393 2,608 2020 2,232 211 2,443 2021 2,567 28 2,595 2022 2,568 28 2,596 Thereafter 39,927 85 40,012 $51,723 $1,138 $52,861 Year Ending Rights-of-Way (In thousands) 2021 2,565 2022 2,566 2023 2,566 2024 2,565 2025 2,582 Thereafter 32,249 $ 45,093 right-of-way leaserights-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 PeckTC PipeLines, LPAnnual Report2017 F-456.FACILITIESFACILITY AND LONG-TERM DEBTPartnership'sPartnership’s long-term debt outstanding consisted of the following at December 31:
(In thousands)
2017
2016 2011 Credit Agreement – average interest rate of 2.695% at December 31, 2017 due 2020 $15,500 181,500 2001 Senior Notes – 7.50%, due 2021 250,000 250,000 Unamortized debt discount (188 ) (230 ) Unamortized debt expense (1,256 ) (1,725 ) $264,056 429,545 2020 2019 (In thousands) $ 130,400 115,500 250,000 250,000 Total 380,400 365,500 Less: Unamortized debt issuance costs 42 94 Less: Unamortized debt expense 589 1,054 Less Current maturities of long-term debt 250,000 — Total long-term debt, net $ 129,769 364,352 8, 20151, 2019, the Partnership closed on the renewal and first extension of the 2011 Credit Agreement that was to expire on November 16, 2016 for an additional five years, maturing on October 9, 2020.On August 26, 2016, the $100 million 2009 Senior Notes matured and the repayment was financed through a $100 million draw on the Partnership's 2011 Credit Agreement, which brought the Partnership's outstanding borrowings underextended the 2011 Credit Agreement to $181.5 million.On November 15, 2016,extend the Partnership entered into a $100 million 364-day Revolving Credit Agreement (364-day Credit Agreement) that expired on November 14, 2017, which utilized the same covenants as the 2011 Credit Agreement. As a result of the shared covenants, the 2011 Credit Agreement was amended for the second time to include the cross default with the 364-day Credit Agreement.On Septembermaturity until October 1, 2017, the Partnership paid down the outstanding borrowings under the 2011 Credit Agreement from $181.5 million to $15.5 million. The $166 million payment was financed through contributions from partners of $83 million each. At the time of the payment on the 2011 Credit Agreement, the Partnership also terminated the 364-day Credit Agreement.2017,2020, the Partnership'sPartnership’s outstanding borrowings under the 2011 Credit Agreement were $15.5$130.4 million, leaving $184.5$69.6 million available for future borrowings. The Partnership may, at its option, so long as no default or event of default has occurred and is continuing, elect to increase the capacity under its 2011 Credit Agreement byhave accordion features for an aggregate amount notadditional capacity of $200 million, subject to exceed $300 million, provided that lenders are willing to commit additional amounts.lender consent. At the Partnership'sPartnership’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. The 2011 Credit Agreement permits the Partnership to specify the portion of the borrowings to be covered by specific interest rate options and 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 commitment of $200 million under the 2011 Credit Agreement.Partnership'sPartnership’s long-term debt arrangements contain covenants that restrict the incurrence ofPartnership's ability to incur 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 (total consolidated debt to consolidated EBITDA (net income plus interest expense, income taxes, depreciation and amortization and all other non-cash charges)) of no more than 5.00 to 1.1.00. 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 11.00 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.2017,2020, the Partnership was in compliance with all of its financial covenants.Aggregate required repayment offorrepayments consisted of the next five years is $265.5 million, with $15.5 million due in 2020 and $250 million due in 2021. There are no required repayment obligations for 2018, 2019, or 2022.F-46 TC PipeLines, LPAnnual Report20177. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIESPrior tofollowing at December 31, 2001, the Partnership terminated a series2020 (in thousands 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 amortized under the effective interest method over the remaining term of the related hedged instrument, the Partnership's 2001 Senior Notes due 2021.During the three-year period ended December 31, 2017, the Partnership reclassified the below amounts from AOCL into earnings for these terminated derivatives.Net Loss Reclassified from AOCL into Income (Effective Portion) Years Ended December 31, (In thousands)
Statements of Income Caption
2017
2016
2015 Cash flow hedges Interest expense $(285 ) (264 ) (245 ) At December 31, 2017 and 2016, AOCL was $1.3 million and $1.5 million, respectively, and is being amortized through 2021 as noted above. The Partnership expects to reclassify $0.3 million from AOCL as an increase to interest expense in 2018. The Partnership had no other derivative instruments during the period ended December 31, 2017.8.dollars):Year Ending 2021 250,000 2022 — 2023 — 2024 130,400 $ 380,400 management'smanagement’s best estimate is used.The following table presents the carrying amounts and estimated fair values of the Partnership's financial instruments at December 31, 2017 and 2016. The fair value of a financial instrument is the amount that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. 2017 2016
Carrying
Amount
Fair
Value
Carrying
Amount
Fair
ValueFinancial asset: Cash and cash equivalents $14,010 14,010 13,535 13,535 Financial liability: Long-term debt 265,500 294,154 431,500 464,357 The following methods and assumptions were used to estimate the fair value of each class of financial instruments:Cash and cash equivalents – amountvalue of cash and cash equivalents, approximatesaccrued interest, all current receivable and payable accounts, except for natural gas imbalances are classified as Level 1 in fair value due tohierarchy. Accordingly, the carrying values approximate their fair values because of the short maturity or duration of these investments.Long-term debt – instruments.fair valuePartnership’s natural gas imbalances, which are reported as part of senior notes was estimated based on quoted market prices for the same or similar debt instruments with similar termsaccounts receivable, accounts payable and remaining maturities, which isrelated party accounts, are classified as a Level 2 in the "Fair“Fair Value Hierarchy", whereHierarchy,” as the fair value is determined by usingTC PipeLines, LPAnnual Report2017 F-47techniques that refer toapproach includes quoted prices in the market index and observable market data. The Partnership presently intends to maintain the current schedule of maturitiesvolumes for the 2001 Senior Notes, which will result in no gains or losses on its repayment. The fair value of the 2011 Credit Agreement approximates the carrying value since the interest rates are periodically adjusted to reflect current market conditions.(c) Other Recurring Fair Value of Financial InstrumentsThe following table presents the carrying amounts and estimated fair values of other items measured and recorded at fair value on a recurring basis as of December 31, 2017 and 2016: 2017 2016
Carrying
Amount
Fair
Value
Carrying
Amount
Fair
ValueNatural gas imbalance asset $815 815 44 44 Related party natural gas imbalance asset — — 951 951 Natural gas imbalance liability 1,232 1,232 2,484 2,484 Related party natural gas imbalance liability $308 308 — — Natural Gas Imbalances –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 valuesrecords 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. The Partnership has classified the fair value of natural gas imbalances 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.9. TRANSACTIONS WITH MAJOR CUSTOMERS2017,2020, the total estimated fair value of our natural gas imbalance was a net payable of approximately $1.5 million. (2019- net payable of $1.5 million). For the year ended December 31, 2020, the total estimated fair value of our related party natural gas imbalance was a net payable of approximately $0.1 million. (2019- net receivable of $0.6 million).were Sequent Energy Management, for the year ended December 31 (in thousands):2020 2019 2018 $ 59,844 39,549 29,425 Tenaska Marketing Ventures 39,104 42,032 38,744 BP Canada Energy Marketing Group 22,096 23,112 27,538 Sequent Energy 18,552 20,297 27,806 BP Canada, and Tenaska Marketing VenturesInc.revenues of $34.6 million, $31.5 million, $30.2 million, and $28.7 million, respectively. At December 31, 2017, Tenaska Marketing Ventures, EDF Trading North America, ONEOK Rockies and Sequent Energy Management, owed the Partnership approximately $3.1 million, $3.1 million, $2.8 million and $2.7 million, respectively, which isaccounts receivable balances greater than 10 percent of the Partnership's tradePartnership’s accounts receivable.For the year ended December 31, 2016, shippers providing significant operating revenues to the Partnership were BP Canada, Tenaska Marketing Ventures, receivable (in thousands).2020 2019 Tenaska Marketing Ventures $ 3,637 3,337 ONEOK Rockies (a) 3,221 3,735 and EDF Trading North America with revenuesMidstream, L.L.C. (ONEOK Rockies), is a subsidiary of $29.5 million, $28.5 million, $28.4 million and $27.9 million, respectively. At December 31, 2016, Sequent Energy Management, Tenaska Marketing Ventures, and ONEOK Rockies owed the Partnership approximately $3.2 million, $2.9 million, and $2.6 million, respectively, which is greater than 10 percentInc.Partnership'sPartnership’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, 2007.2007 (as amended). TransCanada Northern Border utilizes the services of TransCanada Corporation (TransCanada)TC Energy and its affiliates for management services related to the Partnership. The Partnership is charged for the capital, salaries, benefits and expenses of TransCanadaTC Energy and its affiliates attributable to the Partnership'sPartnership’s operations. For the years ended December 31, 2017, 2016,2020, 2019, and 2015,2018, the Partnership'sPartnership’s charges from TransCanadaTC Energy and its affiliates totaled approximately $43.3$38.9 million, $32.0$39.2 million, and $36.4$35.6 million, respectively. The impact of these charges on the Partnership'sPartnership’s income was $31.3$32.1 million, $24.4$36.3 million, and $28.0$32.2 million, respectively. At December 31, 20172020 and 2016,2019, the Partnership owed $3.6$2.4 million and $3.5$3.6 million, respectively, to these affiliates classified to related party accounts on the balance sheets.2017, 2016,2020, 2019, and 2015,2018, the Partnership had contracted firm capacity held by one customertwo customers affiliated with onethe Partnership’s general partners, namely ONEOK Rockies, a subsidiary of the Partnership's general partners. RevenuesONEOK Inc. and beginning in November 2020, TC Energy Marketing, Inc (TC Energy Marketing), a wholly owned subsidiary of TC Energy. Revenue and outstanding receivable from TC Energy Marketing are $0.8 million and $0.4 million, respectively. See Note 9 – Transactions with Major Customers for details regarding revenues and outstanding accounts receivable balances with ONEOK Rockies for 2017, 2016, and 2015 were $31.5 million, $28.4 million, and $22.6 million, respectively. At December 31, 2017 and 2016, the Partnership had outstanding receivables from ONEOK Rockies of $2.8 million and $2.6 million, respectively.F-48 TC PipeLines, LPAnnual Report201711.past three years.Partnership'sPartnership’s General Partnership Agreement provides that distributions to its partners are to be made on a pro rata basis according to each partner'spartner’s capital account balance. The Partnership'sPartnership’s Management Committee determineshas 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'sPartnership’s cash distribution policy requires the unanimous approval of the Management Committee. The Partnership'sPartnership’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. Effective April 1, 2016, theThe Partnership transitioned from quarterly distributions paid approximately one month following the end of the quarter to monthly distributions paid approximately one month following the end of each reported month.2017, 2016,2020, 2019, and 2015,2018, the Partnership paid distributions to its general partners of $165.9$181.6 million, $209.8$286.9 million and $182.2(including the distribution of $100 million respectively. In 2017,from the Partnership received contributions from its partnersproceeds of $166 million, $83 million each, which was used as a payment onadditional borrowings under the 2011 Credit Agreement.12.Agreement, see Note 5), and $166.4 million, respectively.8, 2018, the Management Committee of15, 2021, the Partnership declared a cash distribution in the amount of $14.8$16.4 million. The distribution was paid on January 31, 2018.14, 2018, the Management Committee of16, 2021, the Partnership declared a cash distribution in the amount of $17.1$18.1 million. The distribution will be paid on February 28, 2018.16, 2018,19, 2021, 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.2017 F-49 2020GREAT LAKES GAS TRANSMISSION LIMITED PARTNERSHIPFinancial StatementsDecember 31, 2017 and 2016(With Auditors'Auditors’ Report Thereon)GREAT LAKES GAS TRANSMISSION LIMITED PARTNERSHIPINDEPENDENT AUDITORS' REPORTReport on the Financial Statements(the Partnership), which comprise the balance sheets as of December 31, 20172020 and 2016,2019, and the related statements of income and partners'partners’ capital, and cash flows for each of the years in the three-year period ended December 31, 2017,2020, and the related notes to the financial statements.Management'sAuditors'auditors'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'sentity’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'sentity’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.20172020 and 2016,2019, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2017,2020 in accordance with U.S. generally accepted accounting principles.LLP16, 20182017 F-512020F-45
December 31, 2017 and 2016 (In Thousands)
2017
2016 Assets Current assets: Cash and cash equivalents $ 44 39 Demand loan receivable from affiliate 64,040 27,144 Accounts receivable: Trade 7,409 7,351 Affiliates 20,236 19,185 Materials and supplies 9,689 10,150 Other 5,356 2,287 Total current assets 106,774 66,156 Property, plant, and equipment: Property, plant, and equipment 2,105,808 2,087,281 Construction work in progress 1,330 5,853 2,107,138 2,093,134 Less accumulated depreciation and amortization (1,406,348 ) (1,379,043 ) Total property, plant, and equipment, net 700,790 714,091 Total assets $ 807,564 780,247 Liabilities and Partners' Capital Current liabilities: Accounts payable: Trade $ 8,095 11,772 Affiliates 4,919 3,744 Provision for revenue sharing refund(Note 2(j)) 39,601 7,200 Provision for rate refund (Note 5) 7,972 – Current maturities of long-term debt 19,000 19,000 Taxes payable (other than income) 7,916 7,990 Accrued interest 6,240 6,543 Other current liabilities – 2,767 Total current liabilities 93,743 59,016 Long-term debt, net of current maturities 239,753 258,712 Regulatory liabilities 744 – Other noncurrent liabilities 212 226 Partners' capital 473,112 462,293 Total liabilities and partners' capital $ 807,564 780,247 2020 2019 Assets Current assets: Cash and cash equivalents 46 39 Demand loan receivable from related party 26,886 34,262 Accounts receivable: Trade 8,491 7,016 Related parties 17,184 19,262 Materials and supplies 10,200 9,850 Regulatory Assets 1,314 — Other 1,409 1,858 Total current assets 65,530 72,287 Property, plant, and equipment: Property, plant, and equipment 2,178,171 2,130,615 Construction work in progress 13,482 3,129 2,191,653 2,133,744 Less accumulated depreciation and amortization (1,475,580) (1,448,825) Total property, plant, and equipment, net 716,073 684,919 Total assets $ 781,603 757,206 Liabilities and Partners' Capital Current liabilities: Accounts payable: Trade $ 8,982 6,395 Related parties 3,224 5,108 Current maturities of long-term debt 31,000 21,000 Taxes payable (other than income) 8,513 7,989 Accrued interest 5,197 5,554 Other current liabilities 11,972 8,434 Total current liabilities 68,888 54,480 Long-term debt, net of current maturities 166,848 197,817 Regulatory liabilities and other 8,708 5,953 Partners' capital 537,159 498,956 Total liabilities and partners' capital $ 781,603 757,206 F-522017 2020
Years ended December 31, 2017, 2016, and 2015 (In Thousands)
2017
2016
2015 Operating revenues,net (Note 2(j)) $181,487 179,133 176,901 Operating expenses: Operation and maintenance 54,885 58,048 49,222 Depreciation and amortization 29,474 27,911 27,756 Taxes, other than income 10,830 10,872 10,637 Total operating expenses 95,189 96,831 87,615 Operating income 86,298 82,302 89,286 Other income, net 480 521 1,511 Interest and debt expense (20,831 ) (22,295 ) (23,946 ) Affiliated interest income 372 114 54 Net income $ 66,319 60,642 66,905 Partners' capital: Balance at beginning of year $462,293 484,951 460,446 Net income 66,319 60,642 66,905 Distributions to partners (74,500 ) (102,300 ) (61,400 ) Contributions from partners 19,000 19,000 19,000 Balance at end of year $473,112 462,293 484,951 2020 2019 2018 $ 238,839 237,894 245,646 Operating expenses: Operation and maintenance 57,469 67,996 56,613 Depreciation and amortization 32,958 31,954 31,813 Taxes, other than income 12,035 10,848 11,651 Total operating expenses 102,462 110,798 100,077 Operating income 136,377 127,096 145,569 Interest and debt expense: Interest expense 16,069 17,747 19,378 Interest expense capitalized (185) (119) (184) Interest expense, net 15,884 17,628 19,194 Other income: Allowance for equity funds used during construction 800 411 308 Other income 210 1,203 979 Total other income 1,010 1,614 1,287 Net income $ 121,503 111,082 127,662 Partners' capital: Balance at beginning of year $ 498,956 494,174 473,112 Net income 121,503 111,082 127,662 Distributions to partners (104,300) (127,300) (125,600) Contributions from partners 21,000 21,000 19,000 Balance at end of year $ 537,159 498,956 494,174 2017 F-532020F-47STATEMENTS OF CASH FLOWSYears ended December 31, 2017, 2016, and 2015
(In Thousands) 2017 2016 2015 Cash flows from operating activities: Net income $ 66,319 60,642 66,905 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation and amortization 29,474 27,911 27,756 Allowance for funds used during construction, equity (116 ) (263 ) (78 ) Amortization of debt issuance cost, reported as part of interest expense 41 82 46 Asset and liability changes: Accounts receivable (1,109 ) (4,437 ) 2,191 Other current assets (2,608 ) 321 (1,107 ) Accounts payable (1,792 ) 1,043 (941 ) Provision for revenue sharing refund 32,401 5,300 1,900 Provision for rate refund 7,972 – – Other current liabilities (3,144 ) 2,712 (9,579 ) Noncurrent liabilities (14 ) (9 ) (10 ) Net cash provided by operating activities 127,424 93,302 87,083 Cash flows from (used in) investing activities: Additions to property, plant, and equipment (13,814 ) (14,885 ) (7,265 ) Net change in demand loan receivable from affiliate (36,896 ) 23,928 (20,670 ) Other (2,209 ) (54 ) 2,263 Net cash provided by (used in) investing activities (52,919 ) 8,989 (25,672 ) Cash flows used in financing activities: Payments for retirement of long-term debt (19,000 ) (19,000 ) (19,000 ) Distributions to partners (74,500 ) (102,300 ) (61,400 ) Contributions from partners 19,000 19,000 19,000 Net cash used in financing activities (74,500 ) (102,300 ) (61,400 ) Net change in cash and cash equivalents 5 (9 ) 11 Cash and cash equivalents at beginning of year 39 48 37 Cash and cash equivalents at end of year $ 44 39 48 Supplemental cash flow information: Interest paid, net of capitalized interest $ 20,791 22,529 24,153 Accruals for property, plant and equipment $ 1,497 – 340 2020 2019 2018 Cash flows from operating activities: Net income $ 121,503 111,082 127,662 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation and amortization 32,958 31,954 31,813 Allowance for funds used during construction, equity (800) (411) (308) Gain on sale of property, plant and equipment — (780) — Amortization of debt issuance cost, reported as part of interest expense 31 35 29 Asset and liability changes: Accounts receivable 603 1,058 309 Other current assets (1,215) (253) 3,590 Accounts payable (1,853) 2,705 (3,207) Provision for revenue sharing refund — — (44,722) Provision for rate refund — — (2,851) Other current and noncurrent liabilities 3,711 3,747 2,337 Net cash provided by operating activities 154,938 149,137 114,652 Cash flows from (used in) investing activities: Additions to property, plant, and equipment (58,007) (30,234) (17,178) Net change in demand loan receivable from related party 7,376 1,672 28,106 Proceeds from sale of property, plant and equipment — 6,735 — Other — (20) 25 Net cash provided by (used in) investing activities (50,631) (21,847) 10,953 Cash flows used in financing activities: Contributions from partners 21,000 21,000 19,000 Payments for retirement of long-term debt (21,000) (21,000) (19,000) Distributions to partners (104,300) (127,300) (125,600) Net cash used in financing activities (104,300) (127,300) (125,600) Net change in cash and cash equivalents 7 (10) 5 Cash and cash equivalents at beginning of year 39 49 44 Cash and cash equivalents at end of year $ 46 39 49 Supplemental cash flow information: Interest paid, net of capitalized interest $ 16,211 17,950 19,599 Accruals for property, plant and equipment, net $ 2,556 905 389 F-542017 2020GREAT LAKES GAS TRANSMISSION LIMITED PARTNERSHIPDECEMBER2017 AND 2016partners and partnershippartners’ ownership percentages in the Partnership at December 31, 20172020 and 20162019 were as follows:OwnershippercentageGeneral Partners:Ownership
percentageGeneral Partners: TransCanada GL, Inc. 46.45 46.45TC Pipelines, LP (TCP) TC GL Intermediate Limited Partnership46.45 46.45Limited Partner: Great Lakes Gas Transmission Company 7.10 7.10 and, TransCanada GL Inc., and TCP are wholly owned indirect subsidiaries of TC Energy Corporation (TC Energy), formerly known as TransCanada Corporation (TransCanada). TC GL Intermediate Limited Partnership's parent, TC PipeLines, LP is also an indirect subsidiary of TransCanada.Partnership'sPartnership’s financial statements have been prepared by management in accordance with U.S. generally accepted accounting principles (GAAP).Partnership'sPartnership’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.Partnership'sPartnership’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 ratemakingrate-making process are reflected on theTC PipeLines, LPAnnual Report2017 F-55assetsasset and liabilities at December 31, 20172020 and 2016:
December 31,
Remaining
recovery/
settlement
period
2017
2016 (In thousands) (Years) Regulatory Assets Volumetric fuel tracker 2,787 – (a ) Less: Current portion included in Other 2,787 – $ – – Regulatory Liabilities Negative salvage $ 744 – (b ) Volumetric fuel tracker – 2,767 (a ) – 2,767 Less: Current portion included in Other – 2,767 $ 744 – December 31, 2020 2019 Remaining
recovery/
settlement
period(In thousands) (Years) Regulatory Assets Volumetric fuel tracker $ 1,314 — (a) Regulatory Liabilities Negative salvage $ 8,697 5,948 (b) Volumetric fuel tracker — 686 (a) 8,697 6,634 Less: Current portion included in Other — 686 $ 8,697 5,948 4(b)2(h)).20172020 and 2016.Partnership'sPartnership’s tariff.affiliates.related parties. Imbalances owed to others are reported on the balance sheets as trade accounts payable or accounts payable to affiliates.related parties. In addition, the Partnership classifies all imbalances as current as the Partnership expects to settle them within a year.Partnership'sPartnership’s inventories primarily consist of materials and supplies and are carried at lower of weighted average cost or market.depreciation rates.in the Partnership’s last rate proceeding. A substantial portion of the Partnership'sF-56 TC PipeLines, LPAnnual Report201720.00%10.00%. Using these rates, the remaining depreciable life of these assets ranges from 4 to 4454 years.athe 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 calculatedrecorded based on the Partnership'sPartnership’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.Partnership'sPartnership’s revenues are primarily generated from contractual arrangements for committed capacity and from transportation services.of natural gas. These are treated as a bundled performance obligation. Revenues for all services are based on the quantity of gas delivered or subscribed at a price specified in the contract. For the Partnership's transportation services, reservation revenues are recognized onearned from firm contracted capacity arrangements are recognized ratably over the term of the contract period regardless of the amount of natural gas that is transported. ForTransportation revenues for interruptible or volumetric-based services are recognized when the Partnership records revenues when physical deliveries of natural gas are made at the agreed-upon delivery point.service is performed. The Partnership doesutilizes 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 it transports. 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.Partnership isPartnership's pipeline systems are subject to FERC regulations and, as a result, a portion of revenues the Partnership collectscollected may be subject to refund inif invoiced during an interim period when a rate proceeding. The Partnership establishes provisionproceeding is ongoing. Allowances for these potential refunds.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, 20172020, 2019, and 2016, the Partnership has not collected and recognized any revenue that is subject to potential refund.The Partnership operates under a FERC approved 2013 rate settlement that includes a revenue sharing mechanism that requires the Partnership share with its shippers 50% of any qualifying revenues earned during the year that result2018, there are no refund provisions reflected 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, 2016 and 2015 were net of $39.6 million, $7.8 million and $1.9 million estimated revenue sharing provision, respectively. During 2016, the calculation of the 2015 refund was finalized and a total of $2.5 million was refunded to qualifying shippers in November 2016. During 2017, the calculation of the 2016 refund was finalized and a total of $6.9 million was refunded to qualifying shippers in June 2017. The Partnership expects that a significant portion of the 2017 estimated revenue sharing provision will be refunded to its affiliates which is consistent with prior years. Commitments and ContingenciesAccounting for Asset Retirement Obligationsas 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, 20172020 and 2016.2019. The Partnership continues to evaluate its asset retirement obligations and future developments that could impact amounts it records.TC PipeLines, LPAnnual Report2017 F-57Other ContingenciesThe Partnership recognizes liabilities for contingencies when it has an exposure that, when fully analyzed, indicates it is both probable that a liability has been incurred and the amount of loss can be reasonably estimated. Where the most likely outcome of a contingency can be reasonably estimated, the Partnership accrues a liability for that amount. Where the most likely outcome cannot be estimated, a range of potential losses is established and if no one amount in that range is more likely than any other, the lower end of the range is accrued.costsdiscount or premiums.discount. In addition, amortization of debt issuance costs, premiums, and discounts are reported as part of interest expense.PRONOUNCEMENTS2017InventoryJuly 2015,June 2016, the FASB issued new guidance on simplifying the measurement of inventory.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 specifies thatamends the impairment model of financial instruments basing it on expected losses rather than incurred losses. These expected credit losses will be recognized as an entity should measure inventory withinallowance rather than as a direct write down of the scope of this update at the lower ofamortized cost and net realizable value. Net realizable value is the estimated selling price in the ordinary course of business, less reasonably predictable costs of completion, disposal and transportation. Thisbasis. The new guidance was effective January 1, 2017,2020 and was applied prospectively andusing a modified retrospective approach. The adoption of this new guidance did not have a material impact on the Partnership's consolidated balance sheet.Future Accounting ChangesRevenue from Contracts with CustomersIn 2014, the FASB issued new guidance on revenue from contracts with customers. Current guidance allows for revenue recognition when certain criteria are met. The new guidance requires that an entity recognizes revenue with a five step model. This model is used to depict the transfer of promised goods or services to customers in an amount that reflects the total consideration to which the company expects to be entitled, during the term of the contract, in exchange for those goods or services. Partnership’s financial statements.will adoptis subject to various legal proceedings in the new standard on the effective dateordinary course of January 1, 2018. There are two methods in which the new standard can be adopted: (1)business. The accounting for contingencies covers a full retrospective approach with restatementvariety of all prior periods presented, or (2) a modified retrospective approach with a cumulative-effect adjustment as of the date of adoption.business activities, including contingencies for legal and environmental liabilities. The Partnership will adoptaccrues for these contingencies when the guidance using the modified retrospective approach with the cumulative-effect of the adjustment recognized at the date of adoption, subject to allowable and elected practical expedients.The Partnershipassessments indicate that it is probable that a liability has identified all existing customer contracts that are within the scope of the new guidance. The Partnership has completed its analysis and has not identified any material differences in the amount and timing of revenue recognition. The Partnership will not require a cumulative-effect adjustment to opening partners' equity on January 1, 2018.Although revenuesbeen incurred or an asset will not be materially impacted by the new guidance, therecovered, and an amount can be reasonably estimated in accordance with ASC 450, will be required to add significant disclosures basedbases these estimates on the prescribed requirements. These new disclosures will include information regarding the significant judgments used in evaluating when and how revenue is recognized and information related to contract assets and deferred revenues. In addition, the new guidance requires that the Partnership's revenue recognition policy disclosure includes additional detail regarding the various performance obligationscurrently available facts and the nature, amount, timing and estimates of revenuethe ultimate outcomes or resolution. Actual results may vary from estimates resulting in an impact, positive or negative, on results of operations and cash flows generated from contracts with customers. The Partnership has addressed system and process changes necessary to compile the information to meet the recognition and disclosure requirements of the new guidance.LeasesIn February 2016, the FASB issued new guidance on the accounting for leases. The new guidance amends the definition of a lease requiring the customer 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 in order for the arrangement to qualify as a lease. 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 12 months. Leases will be classified as finance or operating, with classification affecting the pattern and classification of expense recognition in the income statement. The new guidance does not make extensive changes to lessor accounting.F-58 TC PipeLines, LPAnnual Report2017The new guidance is effective on January 1, 2019, with early adoption permitted. A modified retrospective transition approach is required for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements, with certain practical expedients available.flows. The Partnership is continuing to identify and analyze existing lease agreements to determinenot aware of any contingent liabilities that would have a material adverse effect on the effectPartnership’s financial condition, results of adoption of the new guidance on its consolidated financial statements. operations, or cash flows.also addressing system and process changes necessary to compile the information to meet the recognition and disclosure requirementsnot a party in any material legal proceedings as of the new guidance. The Partnership continues to monitor and analyze additional guidance and clarification provided by FASB.(4) TAX REFORM IMPACTOn December 22, 2017, the President of the United States signed into law H.R. 1 (the Tax Cuts and Jobs Act). This legislation provides for major changes to U.S. corporate federal tax law, including a reduction in the U.S. corporate tax rate to 21 percent from 35 percent. As a limited partnership, the Partnership is a non-taxable pass through entity and income taxes owed as a result of the Partnership's earnings are the responsibility of each partner, therefore no amounts have been recorded in the Partnership's financial statements as a result of the Tax Cuts and Jobs Act.regulatednot aware of any material contingent liabilities with respect to compliance with applicable environmental laws and regulations.FERC, which approves its rates,Bureau of Indian Affairs (BIA), approval by the most recentapplicable tribal governing authorities and the BIA.which were established through2018, 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 negotiated settlement that did not ascribe any specific costresult, beginning the second quarter of service elements2018, the Partnership started accruing the estimated costs and associated liability related to income taxes. these pending agreements.FERC also evaluatesPartnership has progressed on the Partnership's rate of return on an overall cost-of-service basis, they provide for a recovery ofrenewal process, the Partnership's ultimate taxable owners' income tax expense and related balance sheet accounts as components of the maximum recourse rates that may be charged to customers. As a non-taxable pass through entity, the Partnership does not recognize income tax expense nor has it established deferred income tax assets or liabilities. Income tax related expenses, benefits, assets, and liabilities attributable to regulated operations are the responsibility of the ultimate taxable owners of the Partnership and any adjustment to income tax accounts following the Tax Cuts and Jobs Act must be evaluated by those owners.The Partnership cannot predict the impact; if any,full outcome of lower U.S. corporate tax rates on its future revenues.these negotiations. If in the future the FERC were to require a change in the Partnership's maximum recourse rates related to the change in U.S. corporate tax rate, the Partnership expects rates would be revised through future rate proceedings or other regulatory action.At December 31, 2017, the Partnership considers its assessment of the impact of the Tax Cuts and Jobs Act to be its best interpretation of available guidance. Should additional guidance on the impact of the Tax Cuts and Jobs Act on non-taxable partnerships be provided by regulatory, tax and accounting authorities or other sources in the future, the Partnership will review the approach used and adjust as appropriate.(5) COMMITMENTS AND CONTINGENCIES(a) Legal ProceedingsOn October 29, 2009, the Partnership filed suit in the U.S. District Court, District of Minnesota, against Essar Minnesota LLC (Essar Minnesota) and certain Foreign Essar Affiliates (collectively, Essar) for breach of its monthly payment obligation under its transportation services agreement with the Partnership. The Partnership sought to recover approximately $33 million for past and future payments due under the agreement. On September 16, 2015, following a jury trial, the federal district court judge entered a judgment in the amount of $32.9 million in favor of the Partnership. On September 20, 2015, Essar appealed the decision to the United States Court of Appeals for the Eighth Circuit (Eighth Circuit) based on an allegation of improper jurisdiction and a number of other rulings by the federal district judge. Essar was required to post a performance bond for the full value of the judgment pending appeal. The Eighth Circuit heard the appeal on October 20, 2016. A decision on the appeal was received in December 2016 and the Eighth Circuit vacated the Partnership' judgment against Essar finding that there was no federal jurisdiction. The Partnership filed a Request for Rehearing with the Eighth Circuit and it was denied in January 2017. Before the Circuit Court issued its decision, Essar Minnesota filed for bankruptcy in July 2016. The Foreign Essar Affiliates have not filed for bankruptcy. Following the Circuit Court's decision, the performance bond was released into the bankruptcy court proceedings. The Partnership filed a claim against Essar Minnesota in the bankruptcy court and its case against the Foreign Essar Affiliates in Minnesota state court remains pending. In April 2017, after The Partnership agreement with creditors on an allowed claim, the bankruptcy court approved the Partnership's claim in the amount of $31.5 million. On May 20, 2017, the federal district court awarded Essar Minnesota approximately $1.2 million for costs, including recovery of the performance bond premium, to be paid by the Partnership. The Partnership filed a motion with the bankruptcy court to offset the $1.2 million award of costs against its claim against Essar Minnesota in the bankruptcy proceeding but was unsuccessful. As a result, in November 2017, the Partnership accrued the $1.2 million costs in relationship to the claim.The Partnership is unable to estimateobtain new easements or rights-of-way across all or a portion of the timingtribal lands at reasonable rates, or at all, the extentPartnership may be required to whichacquire 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 claim willfinancial condition, results of operations and cash flows.recoverableunjust 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. Thethe bankruptcy proceedings; therefore, did not recognize any accrualeach pipeline's FERC-approved tariff. Under its tariff, an interstate pipeline is allowed to charge for its outstanding legal matters at December 31, 2017.TC PipeLines, LPAnnual Report2017 F-59(b) Regulatory MattersANR contractsEffective November 1, 2014,services on the Partnership executed contracts with an affiliate, ANR Pipeline Company (ANR),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 firm service in Michiganservices under negotiated and Wisconsin. These contracts were at the maximum FERC authorized rate and were intended to replace historical contracts. On December 3, 2014, the FERC accepted and suspended the Partnership's tariff records to become effective May 3, 2015, subject to refund. On February 2, 2015, FERC issued an Order granting a rehearing and clarification request submitted by thediscounted rates.which allowed additional time for FERC to consider the Partnership's request. Following extensive discussions with numerous shippers and other stakeholders, on April 20, 2015, ANR filedoperates under a settlement withapproved by FERC that included an agreement by ANR to pay the Partnership the difference between the historical and maximum rates (ANR Settlement). The Partnership provided service to ANR under multiple service agreements and rates through May 3, 2015 when the Partnership's tariff records became effective and subject to refund. The Partnership deferred approximately $9.4 million of revenue related to services performed in 2014 and approximately $13.9 million of additional revenue related to services performed through May 3, 2015 under such agreements. On October 15, 2015, FERC accepted and approved the ANR Settlement. As a result, the Partnership recognized the deferred transportation revenue of approximately $23.3 million in the fourth quarter of 2015.2017 Rate caseOn October 30, 2017, the Partnership filed a rate settlement with FERC to satisfy its obligations from its 2013 rate settlement for new rates to be in effect by January 1, 2018 (2017 Settlement). The 2017 Settlement if approved by FERC, will decrease the Partnership's maximum transportation rates by 27 percent beginning October 1, 2017. The 2017 Settlement doesdid not contain anya moratorium and theeliminated its revenue sharing mechanism with customers. The Partnership will befor new rates no later than March 31, 2022, with new rates to be effective October 1, 2022.Under Additionally, the terms of the 2017 Settlement, the revenue sharing mechanism was eliminated (refer to Note 2(j)). The Partnership'sPartnership’s annual depreciation rates remainshallis required to reflect a negative salvage at an annual Additionally, beginning October2017, the Partnership was still charging customers rates in effect prior2019, FERC approved an additional 2 percent rate reduction to the 2017 Settlement but was only recognizing revenue upapproved rates,amountPartnership’s filing of a one-time reporting requirement, designated as FERC Form 501-G related to the rate effect of the new ratesTax Cuts and Jobs Act (2017 Tax Act). On May 11, 2020, FERC terminated the Partnership's 501-G proceeding and ruled that the Partnership had complied with the FERC Form No. 501-G reporting requirement. Additionally, FERC also stated that rate reductions provided for in its 2017 settlement and the 2017 Settlement. The difference between these two amounts was recognized2.0% rate reduction as described above have provided substantial rate relief for the Partnership's customers and as a provisionresult, FERC will not exercise its right for rate refundan investigation to determine if the Partnership is over-recovering on the balance sheet.(c) its current tariff rates.Partnership'sPartnership’s pipeline system. Currently, the Partnership's obligations under these easementsThe Partnership’s future minimum payments on its rights-of-way commitments are not material to its results of operations. Certain arrangements with the Native American groups expire in 2018 and the Partnership is currently negotiating to renew these agreements.(6)as follows:Year Ending Rights-of-Way (In thousands) 2021 64 2022 66 2023 67 2024 70 2025 72 Thereafter 1,070 $ 1,409 Partnership'sPartnership’s outstanding long-term debt consisted of the following at December 31:
(In thousands)
2017
2016 6.73% series Senior Notes due 2016 to 2018 $9,000 18,000 9.09% series Senior Notes due 2016 to 2021 40,000 50,000 6.95% series Senior Notes due 2019 to 2028 110,000 110,000 8.08% series Senior Notes due 2021 to 2030 100,000 100,000 259,000 278,000 Less current maturities 19,000 19,000 Total long-term debt less current maturities $240,000 259,000 Year Ending 2020 2019 (In thousands) 9.09% series Senior Notes due 2016 to 2021 $ 10,000 20,000 6.95% series Senior Notes due 2019 to 2028 88,000 99,000 8.08% series Senior Notes due 2021 to 2030 100,000 100,000 Total 198,000 219,000 Less: Unamortized debt issuance costs 152 183 Less: Current maturities of long-term debt 31,000 21,000 Total long-term debt, net $ 166,848 197,817 aggregate annual required repayment ofPartnership’s long-term debt is $19.0 million for 2018, $21.0 million for each year 2019 throughrepayments consisted of the following at December 31, 2020 and $31.0 million for 2021. Aggregate required repayments(in thousands of long-term debt thereafter total $167.0 million.Year Ending 2021 31,000 2022 21,000 2023 21,000 2024 21,000 2025 21,000 Thereafter 83,000 $ 198,000 NoteNotes Agreements, approximately $139.5$106.6 million of partners'partners’ capital was restricted as to distributions as of December 31, 2017.2020. As of December 31, 20172020, Partnership was in compliance with all of its financial covenants.F-60 TC PipeLines, LPAnnual Report2017(7)management'smanagement’s best estimate is used.The following table presents the carrying amounts and estimated fair values of the Partnership's financial instruments at December 31, 2017 and 2016. The fair value of a financial instrument is the amount that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date.The following methods and assumptions were used to estimate the fair value of each class of financial instruments measured on a recurring basis:Cash and cash equivalents – amountvalue of cash and cash equivalents, approximatesaccrued interest, all current receivable and payable accounts, except for natural gas imbalances are classified as Level 1 in fair value due tohierarchy. Accordingly, the carrying values approximate their fair values because of the short maturity or duration of these investments.Demand loaninstruments. The Partnership’s natural gas imbalances, which are reported as part of accounts receivable, – The carrying amount of the demand loan receivable approximates fair value due to the short maturity of these investments.Long-term debt – The fair value of senior notes was estimated based on quoted market prices for the same or similar debt instruments with similar termsaccounts payable and remaining maturities, which isrelated party accounts, are classified as a Level 2 in the "Fair“Fair Value Hierarchy", whereHierarchy,” as the fair value is determined by using valuation techniques that refer toapproach includes quoted prices in the market index and observable market data. The Partnership presently intends to maintain the current schedule of maturitiesvolumes for the notes, which will result in no gains or losses on its repayment. At December 31, 2017 the carrying value of the long term debt is $259 million and the fair value amount is $335 million. At December 31, 2016 the carrying value of the long term debt was $278 million and the fair value amount was $354 million.(c) Other Recurring Fair Value of Financial InstrumentsThe following table presents the carrying amounts which equal fair values of other items measured and recorded at fair value on a recurring basis as of December 31, 2017 and 2016:
2017
2016
(In thousands)
Carrying
amount
Fair
value
Carrying
amount
Fair
value Affiliate natural gas imbalance asset $325 325 4,366 4,366 Natural gas imbalance asset $343 343 322 322 Affiliate natural gas imbalance liability $1,796 1,796 12 12 Natural gas imbalance liability $3,089 3,089 3,049 3,049 Natural Gas Imbalances –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. We valueThe 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. We have classifiedFor the year ended December 31, 2020, the total estimated fair value of our third party natural gas imbalance was a net payable of approximately $1.1 million. (2019- net payable of $1.2 million). For the year ended December 31, 2020, the total estimated fair value of our related party natural gas imbalance was a net payable of approximately $0.4 million. (2019- net receivable of $1.3 million).natural gas imbalancesthe Partnership’s long term debt was $277 million (2019-$287 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 a Level 2 in the "Fair“Fair Value Hierarchy"Hierarchy”, aswhere the fair value is determined by using valuation approach includes quoted prices in thetechniques that refer to observable market index and observable volumes for the imbalance.TC PipeLines, LPAnnual Report2017 F-61(8)data.AFFILIATED COMPANIESTransCanada'sTC Energy’s cash management program, which matches short-term cash surpluses and needs of participating affiliates,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 TransCanadaTC Energy at the rate of interest earned by TransCanadaTC Energy on its short-term cash investments. The Partnership pays interest on monies advanced from TransCanadaTC Energy based on TransCanada'sTC Energy’s short-term borrowing costs. For the years ended December 31, 2020, 2019 and 2018, the net interest income on this arrangement is immaterial. At December 31, 20172020 and 2016,2019, the Partnership had a demand loan receivable from TransCanadaTC Energy of $64.0$26.9 million and $27.1$34.3 million, respectively. AffiliateRelated Party Revenues and ExpensesTransCanadaTC Energy and its affiliatesrelated 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 substantial majority of the Partnerships' affiliatedPartnership’s related party revenue is derived from both short-haul and long-haul transportation servicesPartnership'sPartnership’s Operating Agreement, day-to-day operation of partnership activities is the responsibility of the Company. The Partnership is charged by the Company and affiliatesrelated 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. In addition, the Partnership charges rent to affiliates for use of office space in Troy, Michigan.Partnerships' affiliatesPartnership’s related parties for the years ended December 31:
(In thousands)
2017
2016
2015 Transportation revenues from affiliates $130,165 127,932 125,296 Rental revenue from affiliates 1,556 1,680 1,803 Costs charged from affiliates 35,381 30,100 30,022 *Transportation revenues2020 2019 2018 (In thousands) Transportation revenues from related parties: $ 122,637 123,862 124,359 ANR Pipeline Company (ANR) 51,887 51,419 54,007 — 740 1,332 Capital and operating costs charged by TC Energy's subsidiaries 66,136 47,421 43,737 Impact on the Partnership's net income 35,504 42,241 40,434 affiliates representrelated parties represents the amount recognized by the Partnership before any allowance on revenue sharing and provision for rate refund, which represent 57%, 68% and 70%,Partnership’s recovery of a portion of the Partnership's total revenuescosts of the facility it owns by charging its related parties for the year ended December 31, 2017, 2016 and 2015, respectively.On April 24, 2017, Great Lakes reached an agreement on the termsuse of office space in Troy, Michigan. The building in Troy, Michigan was sold in August 2019 for a newgain of approximately $780 thousand.capacity contractagreement with its affiliate, TransCanada. The contract, which was subject to Canada's National Energy Board (NEB) approval, isCanadian Mainline, a related party, that commenced on November 1, 2017 for a term of 10 years andten-year period that allows TransCanada the abilityTC Energy to transport up to 0.711 billion of cubic feet of natural gas per day on the Great Lakes system from the Manitoba/U.S. border to the U.S. border near Dawn Ontario. On September 21, 2017, TransCanada received approval from the NEB and as a result, thisday. This contract, commenced on November 1, 2017. The Partnership recognized $13.0 million in transportation revenue related to this contract in 2017. This contractwhich contains volume reduction options up to full contract quantity beginning in year three.Partnership'sPartnership’s distribution policy generally results in a quarterly cash distribution equal to 100%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.10, 2018,13, 2021, the Management Committee of the Partnership declared a cash distribution in the amount of $19.5$23.3 million to the partners. The distribution was paid on February 1, 2018.16, 2018,22, 2021, which is the date the financial statements were issued, and wethe 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-622017
2020