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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549

FORM 10-K

Commission File Number: 001-35358

TC PipeLines, LP
(Exact name of registrant as specified in its charter)

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.    Yes ý    No o

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.    Yes o    No ý

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

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes ý    No o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.    ý

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

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

The aggregate market value of the common units of the registrant held by non-affiliates as of June 30, 20152016 was approximately $2.7$2.8 billion.

As of February 22, 2016,24, 2017, there were 64,317,44968,424,792 common units of the registrant outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

None

TC PIPELINES, LP

TABLE OF CONTENTS

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

2015 ANNUAL REPORT    TC PipeLines, LPAnnual Report2016    3

DefinitionsDEFINITIONS

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

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4    TC PipeLines, LPAnnual Report2016

Unless the context clearly indicates otherwise, TC PipeLines, LP and its subsidiaries are collectively referred to in this annual report as "we," "us," "our" and "the Partnership." We use "our pipeline systems" and "our pipelines" when referring to the Partnership's ownership interests in Gas Transmission Northwest LLC (GTN), Northern Border Pipeline Company (Northern Border), Bison Pipeline LLC (Bison), Great Lakes Gas Transmission Limited Partnership (Great Lakes), North Baja Pipeline, LLC (North Baja), Tuscarora Gas Transmission Company (Tuscarora), and effective January 1, 2016, Portland Natural Gas Transmission System (PNGTS).

2015 ANNUAL REPORT    TC PipeLines, LPAnnual Report2016    5

PART I

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

This report includes certain forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. Forward-looking statements are identified by words and phrases such as: "anticipate," "estimate," "expect," "project," "intend," "plan," "believe," "forecast," "should," "predict," "could," "will," "may," and other terms and expressions of similar meaning. The absence of these words, however, does not mean that the statements are not forward-looking. These statements are based on management's beliefs and assumptions and on currently available information and include, but are not limited to, statements regarding anticipated financial performance, future capital expenditures, liquidity, market or competitive conditions, regulations, organic or strategic growth opportunities, contract renewals and ability to market open capacity, business prospects, outcome of regulatory proceedings and cash distributions to unitholders.

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

•

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

•

demand for natural gas;

•

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

•

natural gas prices and regional differences;

•

weather conditions;

•

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

•

competition from other pipeline systems;

•

natural gas storage levels; and

•

rates and terms of service;

•

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

•

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

•

changes in the taxation of master limited partnership (MLP) investments by state or federal governments such as final adoption of proposed regulations narrowing the sources of income qualifying for partnership tax treatment or the elimination of pass-through taxation or tax deferred distributions;

•

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

•

the impact of recent significant declinesdownward changes in oil and natural gas prices, including the effects on the creditworthiness of our shippers;

•

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

•

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

•

the ability to maintain secure operation of our information technology;

•

the impact of any impairment charges;

6TC PIPELINES,PipeLines, LPAnnual Report2016

•

changes in the political environment;

•

cybersecurity threats, acts of terrorism and related distractions;

•

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

•

potential of claims for rescission or loss in connection with certain sales under our at-the-market equity issuance program (ATM program); and

•

the level of our indebtedness, including the indebtedness of our pipeline systems, increase of interest rates, and the availability of capital.

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

Item 1.    Business

NARRATIVE DESCRIPTION OF BUSINESS

General

We are a Delaware master limited partnership, and ourpartnership. Our common units are tradedtrade on the New York Stock Exchange (NYSE) under the symbol TCP. We were formed by TransCanada Corporation 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.

We are managed by our General Partner, which is an indirect, wholly-owned subsidiary of TransCanada. Through itsAt December 31, 2016, subsidiaries of TransCanada ownsown approximately 26.625.3 percent of our common units, 100 percent of our Class B units, 100 percent of our incentive distribution rights (IDRs) and an effective two percent general partner interest in us. See Part II, Item 5. "Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities" for more information regarding TransCanada's ownership in us.

Recent Business Developments

On April 23, 2015,21, 2016, the board of directors of our General Partner declared the Partnership's first quarter 20152016 cash distribution in the amount of $0.84$0.89 per common unit payablewhich was paid on May 15, 201513, 2016 to unitholders of record as of May 5, 2015.2, 2016. The declared distribution to our General Partner included a $1.2 million distribution for its effective two percent general partner interest and an IDR payment amounting to $0.9 million for a total distribution of $2.1 million.

On July 23, 2015,21, 2016, the board of directors of our General Partner declared the Partnership's second quarter 20152016 cash distribution in the amount of $0.89$0.94 per common unit payablewhich was paid on August 14, 201512, 2016 to unitholders of record as of August 4, 2015.1, 2016. The declared distribution reflected a $0.05 per common unit increase to the first quarter 2015 cash2016 quarterly distribution. The declared distribution to our General Partner included a $1.3 million distribution for its effective two percent general partner interest and an IDR payment amounting to $1.9 million for a total distribution of $3.2 million.

On October 22, 2015,20, 2016, the board of directors of our General Partner declared the Partnership's third quarter 20152016 cash distribution in the amount of $0.89$0.94 per common unit payablewhich was paid on November 13, 201514, 2016 to unitholders of record as of November 3, 2015.1, 2016. The declared distribution to our General Partner included a $1.3 million distribution for its effective two percent general partner interest and an IDR payment amounting to $2.0 million for a total distribution of $3.3 million.

TC PipeLines, LPAnnual Report2016    7

On January 21, 2016,23, 2017, the board of directors of our General Partner declared the Partnership's fourth quarter 20152016 cash distribution in the amount of $0.89$0.94 per common unit payable on February 12, 201614, 2017 to unitholders of record as of February 2, 2016. The declared distribution to our General Partner included a $1.3 million distribution for its effective two percent general partner interest and an IDR payment of $2.0 million for a total distribution of $3.3 million.

The first quarter 2015 distribution exceededIncentive distributions are paid to our General Partner if quarterly cash distributions on the first targetcommon units exceed levels specified in the Third Amended and Restated Agreement of Limited Partnership of the General Partner's IDRs by $0.03 per common unit, resulting in an increase in the distribution on the General Partner interest from 2 percent to 15 percent on the incremental distribution in excessPartnership (Partnership Agreement). See Part II, Item 7 "Management's Discussion and Analysis of Financial Condition and Results of Operations – Cash Distribution Policy of the first target.

2015 ANNUAL REPORT    7

The second, third and fourth quarter 2015 distributions exceeded the first and second targets of the General Partner's IDRs by $0.07 and $0.01 per common unit, respectively, resulting in an increase in the distribution on the General Partner interest from 2 percent to 15 percent on the incremental distribution in excess of the first target and from 15 percent to 25 percent on the incremental distribution in excess of the second target.

Debt Offering – 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 and reduce the amount outstanding under our Senior Credit Facility.

GTN Acquisition – On April 1, 2015, the Partnership acquired the remaining 30 percent interest in GTN from a subsidiary of TransCanada (2015 GTN Acquisition). The total purchase price of the 2015 GTN Acquisition was $446 million plus purchase price adjustments. 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 $95 million of new Class B units to TransCanada.

GTN Settlement – On June 30, 2015, FERC approved GTN's rate settlement as filed on April 23, 2015. The 2015 rate settlement satisfies GTN's obligations from its 2011 rate settlement for new rates to be in effect on January 1, 2016 and reduced rates on the mainline by three percent on July 1, 2015 (GTN Settlement). Beginning January 1, 2016, the rates decreased a further 10 percent. We expect any near term impact of the rate reduction to GTN's revenue will in part be offset by increased contracting and other revenue opportunities on the system as well as revenue from the Carty Lateral which was placed in-service in October 2015. See Regulatory and Rate Proceedings within Item 1. "Business – Government Regulation"Partnership" for further information.

Great Lakes – On October 15, 2015, FERC accepted and approved a settlementinformation regarding transportation service rates payable to Great Lakes from its TransCanada affiliate, ANR Pipeline Company (ANR). As a result of this settlement, Great Lakes recognized the deferred transportation revenue of approximately $23 million in the fourth quarter of 2015, inclusive of an approximate $9 million of revenue related to services performed in 2014. See Regulatory and Rate Proceedings within Item 1. "Business" of this document for detailed disclosure regarding Great Lakes suspended contracts with ANR.

GTN's Carty Lateral – In October 2015, GTN placed the Carty Lateral in-service. The lateral was constructed in north-central Oregon to deliver natural gas to an electric generation facility owned by Portland General Electric Company. Portland General Electric Company has a 30-year contract for 100 percent of Carty Lateral's capacity that began in 2015 and a 20-year GTN mainline contract for 75,000 dekatherms/day that is expected to begin in 2016.IDRs.

PNGTS Acquisition–  – On January 1, 2016, the Partnership acquired a 49.9 percent interest in PNGTS from a subsidiary of TransCanada (PNGTS Acquisition).TransCanada. The total purchase price of the PNGTS Acquisition was $223$228 million plus preliminary purchase price adjustments of $3 million. The purchase priceand consisted of $191$193 million in cash (including the preliminaryfinal purchase price adjustment of $3$5 million) and the assumption of $35 million in proportional PNGTS debt. This transaction adds a new market geography for us, further diversifying our cash flow stream and extending our breadth of operations.

Great Lakes ImpairmentATM program –  – ForOn August 5, 2016, the year ended December 31, 2015,Partnership entered into a $400 million Equity Distribution Agreement (EDA) with five financial institutions (the Managers). Pursuant to the terms of the $400 Million EDA, the Partnership may sell from time to time through the Managers, as the Partnership's sales agents, the Partnership's common units at an aggregate offering price up to $400,000,000. Sales of the common units will be made by means of ordinary brokers' transactions through the NYSE at market prices, in connection with reverse inquiry transactions or as otherwise agreed by the Partnership and one or more of the Managers. The common units will be issued pursuant to 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.

During 2016, we determined thatsold 3,137,382 common units at an average price of $53.49 for total net proceeds of approximately $167 million, including our General Partner's proportionate equity contribution of approximately $3.4 million to maintain its two percent effective interest, net of approximately $1.7 million of commissions to our sales agents.

Of these common units, an aggregate 1,619,631 common units may be deemed to have been unregistered sales of securities.

See Note 9 of the carrying value of our investmentPartnership's consolidated financial statements included in Great Lakes was in excess of its fair valuePart IV, Item 15 "Exhibits and that the decline is not temporary. Accordingly, we concluded that the carrying value of our investment in Great Lakes was impaired resulting in a fourth quarter impairment charge of $199 million, reflected as Impairment of equity-method investment on ourFinancial Statement of Income. 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 – Equity Investments"Schedules" for further information regarding the impairmentrescission of our equity investmentcommon units.

Tuscarora Rate Case – On January 21, 2016, FERC issued an Order initiating an investigation pursuant to Section 5 of the NGA to determine whether Tuscarora's existing rates for jurisdictional services were just and reasonable. On September 22, 2016, FERC approved the settlement (Tuscarora Settlement) Tuscarora made with its customers that resolved the Section 5 rate review initiated by FERC in Great Lakes.January 2016. Under the terms of the Tuscarora 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. While this new rate structure reduced Tuscarora's cash flows beginning August 1, 2016, the achievement of rate certainty helps ensure predictable cash flows from this pipeline system.

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Business Strategies

•

Our strategy is to invest in long-life critical energy infrastructure that provides reliable deliverytransportation of energy to customers.

•

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

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•

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

Understanding the Natural Gas Pipeline Business

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

Regulation, rates and cost recovery

Interstate natural gas pipelines are regulated by FERC. FERC approves the construction of new 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. Although FERC regulates maximum rates for services, interstate natural gas pipelines frequently face competition and therefore may choose to discount their services in order to compete.

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

Contracting

New pipeline projects are typically supported by long-term contracts. The term of the contracts is dependent on the individual developer's appetite for risk and is a function of expected rates of return, and 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 thenatural gas transportation and consumption.

Business environment

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

The map below shows the location of the North American basins in relation to our pipeline systems together with those of our General Partner, TransCanada Corporation.

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Supply

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

There has been an increase in production from the development of shale gas reserves that are located close to traditional markets, particularly in the Northeastern U.S. This has increased the number of supply choices for natural gas consumers resulting in changes to historical natural gas pipeline flow patterns.

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

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

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

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

•

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

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•

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

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

Demand

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

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

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natural gas-fired power generation;

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petrochemical and industrial facilities;

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the production of Alberta's oil sands, although new greenfield projects that have not begun construction may be delayed in the current low oil price environment; and

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exports to Mexico to fuel electric power generation facilities; and

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

Commodity Prices

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

Competition

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

Our Pipeline Systems

We have four wholly-owned pipelines and equity ownership interests in three natural gas interstate pipeline systems that are collectively designed to transport approximately 9.1 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 are operated by subsidiaries of TransCanada.

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Our pipeline systems include:

(a)

Effective January 1, 2016. See Note 22 within Part IV, Item 15. "Exhibits and Financial Statements Schedules" for further information.

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The map below shows the location of our pipeline systems.

Customers, Contracting and Demand

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

Our pipeline systems actively market their available capacity and work closely with customers, including natural gas producers, LDC's,LDCs, marketers and end users, to ensure our pipelines are offering attractive services and competitive rates. Approximately 74 percent of our long-term contract revenues are with customers who have an investment grade rating or who have provided guarantees from investment grade parties. We have obtained financial assurances as permitted by FERC and our tariffs for the remaining long-term contracts. See Part I, Item 1A. "Risk Factors."

Two of our customers, Anadarko Energy Services Company and Pacific Gas and Electric Company, account for a significant portion of our revenue and comprised 1413 percent and 1210 percent, respectively, of the Partnership's revenues in 2015.2016.

GTN – GTN's revenues are substantially supported by long-term contracts, the majority of which are expiring prior to 2023. These contracts are primarily held by LDCs that historically use a diversified portfolio of transportation options to

2015 ANNUAL REPORT    13

serve their long-term markets and marketers contracting under a variety of contract terms. 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. GTN's rates were established based on its current contracted long-term capacity.capacity at the time of its last rate case in 2015 and thus ensures full coverage of its cost of service. In 2016, GTN benefited from an increase in the volumes of natural gas it transports as debottlenecking activities occurred on upstream pipeline systems which deliver natural gas to GTN. These upstream activities are expected to continue resulting in additional volumes that could potentially flow onto GTN by November 2018. GTN continues to market its remaining long-term capacity.

Northern Border – Northern Border'sBorder is a highly competitive pipeline system and is fully contracted with its revenues are substantially supported by firm transportation contracts through March 2017. As2018. Northern Border's contracts include

TC PipeLines, LPAnnual Report2016    13

renewal rights and expiring contracts have expired, market conditions have enabled Northern Border to negotiate contract extensions that are typically been renewed for terms of two years or longer. Its uncontracted capacity is subject toIn addition, Northern Border sells seasonal demand for transportation services which hashave traditionally been strongest during peak winter months to serve heating demand and peak spring/summer months to serve electric cooling demand and storage injection.

Great Lakes – Great Lakes' revenue is derived from shorter-term contracts for short-haul and long-haul transportation. A majority of these contracts are with TransCanada 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 beyond.the upper Midwest of the U.S.

PNGTS – PNGTS' revenue is primarily from gas utilities, paper mills and electric generation plants throughout New England. Approximately 50 percent of PNGTS' current revenue stream is driven by long-term contracts that expire in 2019 with the remaining 50 percent driven by short-term contracts. PNGTS recently completed ancontracts that are typically renewed on a continuing short-term basis. Long-term contract commitments from the Continent to Coast (C2C) open season for additional contract volumes. Additional contract commitments are expectedscheduled to begin inNovember 2017 with expiration in 2032. Its uncontracted capacity2032 and will replace some expiring short-term contracts. The C2C expansion is subjectexpected to seasonal demand for transportation services,bring additional, diverse natural gas supply options to markets in New England and Atlantic Canada. The shippers on the C2C project signed binding Precedent Agreements (PAs) which has traditionally been strongest during peak winter months to serve heating demandscontain conditions precedent in favor of both PNGTS and the shippers. The majority of the area.shippers' conditions have been met. Under the PAs, PNGTS is required to obtain an increase in its FERC-certificated capacity and Presidential gas import permit. PNGTS has applied for these permits and they are expected to be approved in 2017. PNGTS is continuing to market its remaining long-term capacity.capacity and to pursue expansion opportunities.

Bison – Natural gas is currently not flowing in response to the recent relative cost advantage of WCSB-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.

Other Pipelines – Bison, North Baja and Tuscarora revenues are substantially supported by long-term contracts through 2020.

Competition

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

Three of our pipeline systems, GTN, Northern Border, and Great Lakes, compete with each other for WCSB natural gas supply as well as with other pipelines, including TransCanada's Mainline system, 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 Rocky Mountain area, Mid-Continent, Gulf Coast, Utica and Marcellus basins. GTN primarily competes with pipelines supplying natural gas into California and Pacific Northwest markets.

Bison competes for deliveries with other pipelines that transport natural gas supplies within and away from the Rocky Mountain area.

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

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

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

Relationship with TransCanada

TransCanada is the indirect parent of our General Partner and at December 31, 2016 owns, through its subsidiaries, approximately 26.625.3 percent of our common units, 100 percent of our Class B units, 100 percent of our IDRs and an effective two percent general partner interest in us. TransCanada 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. TransCanadaTransCanada's business is primarily focused on natural gas and oil transmission and power generation services. TransCanada owns approximately $64 billion Canadianconsists of investments in total assets, including a 41,900 mile network of56,900 miles natural gas pipelines, 2,6402,700 miles of wholly-owned oil pipelines and over 350653 billion cubic feet of natural gas storage capacity. TransCanada also owns controls or is developinghas interests in over 13,10010,700 megawatts of power generation.

TransCanada operates 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 views the dropdownPartnership as a core element of its remaining U.S. natural gas pipelinestrategy and considers the dropdown of assets into the Partnership as an importanteffective financing option as it executes its capital growth program, subject to actual 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. See Part III, Item 13. "Certain Relationships and Related Transactions, and Director Independence" for more information on our relationship with TransCanada.

Government Regulation

Federal Energy Regulatory Commission

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

•

transportation of natural gas in interstate commerce;

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rates and charges;

•

terms of service and service contracts with customers, including counterparty credit support requirements;

•

certification and construction of new facilities;

•

extension or abandonment of service and facilities;

•

accounts and records;

•

depreciation and amortization policies;

•

acquisition and disposition of facilities;

•

initiation and discontinuation of services; and

•

standards of conduct for business relations with certain affiliates.

Our pipeline systems' operating revenues are determined based on rate options stated in our tariffs which are approved by FERC. Tariffs specify the general terms and conditions for pipeline transportation service including the rates that may be charged. FERC, either through hearing a rate case or as a result of approving a negotiated settlement, approves the maximum rates permissible for transportation service on a pipeline system which are designed to recover the pipeline's

2015 ANNUAL REPORT    15

cost-based investment, operating expenses and a reasonable return for its investors. Once maximum rates are set, a

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pipeline system is not permitted to adjust the maximum rates to reflect changes in costs or contract demand until new rates are approved by FERC. Pipelines are permitted to charge rates lower than the maximum tariff rates in order to compete. As a result, earnings and cash flows of each pipeline system depend on a number of factors including costs incurred, contracted capacity and transportation path, the volume of natural gas transported and rates charged.

Regulatory and Rate Proceedings

GTN – OnGTN operates under rates established pursuant to a settlement approved by FERC in June 30, 2015, FERC approved GTN's rate settlement as filed on April 23, 2015. The rate settlement satisfies GTN's obligations from its 2011 rate settlement for new rates to beBeginning in effect on January 1, 2016 and the 2015 settlement reduced rates on the mainline by three percent on July 1, 2015. In January 2016, GTN's rates decreased a furtherby 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.

Northern Border – Northern Border has a FERC-approved settlement agreement which established maximum long-term transportation rates and charges on the Northern Border system effective January 1, 2013 and requires Northern Border to file for new rates no later than January 1, 2018.

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.

Great Lakes – Great Lakes operates under rates established pursuant to a settlement approved by FERC in November 2013. Under the settlement, Great Lakes is required to file for new rates to be effective no later than January 1, 2018.

Effective November 1, 2014, Great Lakes executed contracts with an affiliate, 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, the 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 $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.

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, 2014,2017, North Baja notified FERC approved North Baja's applicationthat current market conditions do not support the replacement of the compression that was temporarily abandoned in 2013 and requested authorization to temporarilypermanently abandon compression associated with the original designtwo compressor units and a nominal volume of its pipeline system up to three years. This temporary abandonmentunsubscribed firm capacity. The requested abandonments will preserve replacement options while reducing maintenance requirements and related expenses withoutnot have any reduction in capacity or impact toon existing firm transportation service.

Tuscarora – On January 21, 2016, the FERC issued an Order (the January 21 Order) initiating an investigation pursuant to Section 5 of the NGA to determine whether Tuscarora's existing rates for jurisdictional services are just and reasonable. On September 22, 2016, FERC approved the settlement (Tuscarora Settlement) Tuscarora is currently preparingmade with its response as requiredcustomers that resolved the Section 5 rate review initiated by FERC in January 2016. Under the January 21 Order. We cannot predictterms of the outcomeTuscarora Settlement, Tuscarora's system-wide unit rate initially decreased by 17 percent, effective August 1, 2016. Unless superseded by a subsequent rate case or potential impact ofsettlement, this proceedingrate 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 Tuscarora at this time.file to establish new rates no later than August 1, 2022.

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

Environmental

Our pipelines are subject to stringent and complex federal, state and local laws and regulations governing environmental protection, including air emissions, water quality, wastewater discharges and waste management. Such laws and regulations generally require natural gas pipelines to obtain and comply with a wide variety of environmental registrations, licenses, permits and other approvals required for construction and operations. Certain violations of environmental laws can result in the imposition of strict, joint and several liability. Failure to comply with these laws and regulations 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 enjoining future operations in affected areas.

The following is a discussion of some of the applicable environmental laws and regulations that relate to our business.

•

Solid Wastes and Hazardous Substance and Wastes Statutes – The operations of our pipeline systems are subject to federal and analogous state statutes that regulate the handling, management, storage and disposal of solid wastes,

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including hazardous wastes and hazardous substances. These include the Resource Conservation and Recovery Act the Solid Waste Disposal Act and the Comprehensive Environmental Response, Compensation and Liability Act, on the federal level and comparable state statutes. These statutes subject our operations to rigorous waste management and disposal practices to ensure compliance. In addition, the improper disposal or a release of wastes or hazardous substance could result in the imposition of investigatory or remedial obligations.

•

The Clean Air Act (CAA) – The CAA and comparable state laws regulate emissions of air pollutants from various industrial sources, including compressor stations, and impose various monitoring, reporting, and in some cases, control requirements. Such laws and regulations may require pre-approval for the construction or modification of certain facilities expected 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. For example, in October 2015, the U.S. Environmental Protection Agency (EPA) issued a final rule under the CAA, lowering the National Ambit Air Quality Standards for ground-level ozone to 70 parts per billion. With EPA lowering the ground-level ozone standard, states may be required to implement more stringent regulations resulting in permitting delays or increased pollution control expenditures, which could apply to our operations in nonattainment areas.

•

Toxic Substances Control Act (TSCA) – The TSCA addresses the production, importation, use and disposal of specific chemicals and provides the EPA with authority to require reporting, record-keeping and testing requirements, and restrictions relating to chemical substances and mixtures. These include polychlorinated biphenyls (PCBs), asbestos, radon and lead-based paint.

•

The Clean Water Act (CWA) and the Oil Pollution Act of 1990 (OPA) – The CWA, OPA and comparable state laws impose strict controls with respect to the discharge of pollutants, including spills and leaks of oil and other substances, into 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 issued by the EPA or a delegated state or federal agency. The CWA and federal regulations also prohibit the discharge of dredge and fill material into regulated waters, including wetlands, unless authorized by an appropriately issued permit. The EPA released a final rule in May 2015 that attempted to clarify federal jurisdiction under the CWA over waters of the United States, but a numberU.S. This interpretation by the EPA may constitute an expansion of legal challenges to this rule are pending, and implementationfederal jurisdiction over waters of the U.S. Implementation of the rule has been stayed nationwide.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. Litigation surrounding the rule is ongoing. To the extent the 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.

2015 ANNUAL REPORT    17

•

National Environmental Policy Act (NEPA) – Natural gas transportation activities over federally-managed land or involving federal approval can be subject to review under NEPA, or analogous state requirements. NEPA requires federal agencies, including the Department of the Interior or FERC, to evaluate governmental agency actions having the potential to significantly impact the environment. In the course of such evaluations, an agency will prepare an Environmental Assessment that addresses the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed Environmental Impact Statement that is made available for public review and comment. The current activities of our pipeline systems, as well as any proposed plans for future activities, on federal lands are subject to the requirements 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, whichwho have frequently used the NEPA process to challenge pipeline construction projects over the past several years, and therefore, have the potential to delay current and future natural gas transportation activities.

•

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.

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We have not incurred and do not anticipate incurring material costs to comply with existing environmental laws and regulations. We have not accrued for any environmental liabilities.

Greenhouse Gas

Scientific studiesClimate change continues to attract considerable public and scientific attention. As a result, numerous proposals have suggested thatbeen made and are likely to continue to be made at the international, national, and state levels of government to monitor and limit emissions of carbon dioxide, methane, and other greenhouse gases (GHGs) may be contributing. At the federal level, no comprehensive climate change legislation has been implemented to warming ofdate, but the Earth's atmosphere. The 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 GHG emissions from, among other sources, certain onshore natural gas transmission and storage facilities, including gathering and boosting facilities, completions and workovers of oil wells with hydraulic fracturing and blowdowns of natural gas transmission pipelines between compressor stations in the U.S., on an annual basis. Pursuant to President Obama's Strategy to Reduce Methane Emissions fromRecent federal rulemakings have focused on the oil and gas sector by up to 45 percent from 2012 levels by 2025, in August 2015, the EPA proposed a suiteemission of requirements and draft guidance related to the reduction in methane emissions from certain equipment and processes in the oil and natural gas source category, including production, processing, transmission and storage activities, including proposed requirements for fugitive emissions of methane and new leak detection and repair requirements. The Pipeline and Hazardous Materials Safety Administration (PHMSA) is also expected to propose additional requirements to control methane emissions in the near future; however, we cannot predict what these requirements will be or their potential impact on our operations at this time.methane.

Additionally, while the U.S. Congress has from time to time considered legislation to reduce emissions of GHGs, in the absence of any significant activity by Congress in recent years to adopt such legislation, a number of state and regional efforts have emerged that are aimed at tracking and/or reducing GHG emissions by means of cap and trade programs. These types of efforts may become more prevalent as a result of implementationFor example, Washington, one of the EPA's Clean Power Plan (CPP),states in which is designedwe operate, has implemented a carbon tax that has the potential to limit GHG emissions from power plants;impact our operations; however, on February 9, 2015, the U.S. Supreme Court stayed implementation of the CPP pending outcome of all judicial challenges to the CPP. Atat this time we cannot predictdo not expect the outcomeimpact of this litigation. Washington's carbon tax on our operations to be material.

On an international level in December 2015, the U.S. joined the international community at the 21^st Conference of the Parties of the United States is one of almost 200 nations that agreedNations Framework Convention on December 12, 2015 to an international climate change agreementClimate Change in Paris, France that calls forprepared an agreement requiring member countries to setreview and "represent a progression" in their ownintended nationally determined contributions, which set GHG emission targetsreduction goals every five years beginning in 2020. The agreement was signed by the U.S. in April 2016 and be transparent aboutentered into force in November 2016. The U.S. is one of more than 120 countries having ratified or otherwise consented to the measures each country will use to achieve its GHGagreement; however the agreement does not set binding emission reduction targets. Although 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, any such future laws and regulations that limit emissions of GHGs could adversely affect demand for the oil and natural gas that exploration and production operators produce, some of whom are our customers, which could thereby reduce demand for our natural gas transportation services.

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services. Finally, it should be noted that some scientists have concluded that increasing concentrations of GHGs in the Earth's atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts and floods and other climatic events; ifevents. If any such effectschanges were to occur, it is uncertain ifwhat effect they wouldmight have an adverse effect on our financial condition and operations.

Safety

Our pipeline systems are subject to federal pipeline safety statutes, such as the Natural Gas Pipeline Safety Act of 1968 (NGPSA), the Pipeline Safety Improvement Act of 2002 (the PSI Act), the Pipeline Inspection, Protection, and Enforcement Act of 2006 (the PIPES Act), and the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 (the 2011 Pipeline Safety Act) and the Protecting Our Infrastructure of Pipelines and Enhancing Safety Act of 2016 (the 2016 Pipeline Safety Act), as well as regulations promulgated and administered by the 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 intended 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,

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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, among other things, pipeline control room management. Pursuant to the authority granted under the NGPSA, as amended, PHMSA has established a series of rules requiring pipeline operators, such as us, to develop and implement integrity management programs for natural gas transmission pipelines in HCAs that require the performance of frequent inspections and other precautionary measures. PHMSA may assess penalties for violations of these and other requirements imposed by its regulations. The 2011 Pipeline Safety Act also increases the maximum penalty for violation of pipeline safety regulations from $100,000 to $200,000 per violation per day of violation and also from $1 million to $2 million for a related series of violations.

The ongoing implementation of the pipeline integrity management programslaws 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. New laws and regulations related to

Additional rulemakings regarding pipeline safety could also adversely impactis likely. In June 2016, the operations of our pipeline systems. For example, in March 2015, PHMSA finalized new rules applicable to gas2016 Pipeline Safety Act was passed, extending PHMSA's statutory mandate through 2019 and, hazardous liquid pipelines that, among other changes, impose new post-construction inspections, welding, gas component pressure testing requirements, as well as requirements related to maximum allowable operating pressure calculations. More recently, in December 2015, the Senate Commerce Committee approved the SAFE PIPES legislation, which will now be considered by the U.S. Senate. Among other things, the SAFE PIPES legislation would requirerequiring PHMSA to conduct an assessmentcomplete certain of its inspection processoutstanding mandates under the 2011 Act and integrity management programsdeveloping new safety standards for natural gas storage facilities by June 22, 2018. The safety enhancement requirements and hazardous liquid pipelines. While we cannot predict the outcomeother provisions of these initiatives or future legislative or regulatory efforts, new laws and regulations related to pipeline inspection and integrity management requirements have the potential to adversely impact out business. Also, in July 2015, PHMSA published a Notice of Proposed Rulemaking (NPRM) that among other things, proposes to expand the Operator Qualification requirements from operations to construction, allows PHMSA to recover its costs to review the design and construction of significant projects, and requires a shorter notification period for incident and accident events. Industry groups and individual operators submitted extensive comments to the NPRM. PHMSA's response to the public comments will not be known until 2016 when the rule is finalized. It is not possible to determine the content of the rule, its effective date or the materiality of any cost impact to the pipelines until then.

It is anticipated that PHMSA will publish an NPRM to amend the pipeline safety regulations pertaining to integrity management of gas transmission pipelines in 2016. With one exception, most of the rulemaking is expected to have low-to-moderate cost impacts on the pipelines. However, in the event that the regulations are amended to require operators to verify pipe characteristics through activities such as pressure testing and materials testing, the costs could be significant. It is not possible to determine the content, the effective date, or the materiality of any cost impacts for the Final Rule associated with the NPRM until it is published. One additional NPRM is expected to be issued in 2016

2015 ANNUAL REPORT    19

addressing the remaining mandates in the 2011 Pipeline Safety Act. Once published, we will reviewAct as further amended by the proposed2016 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 us to determine the ultimate impactinstall new or modified safety controls, pursue additional capital projects, conduct maintenance programs on our pipeline systems. These proposed rulemakings couldan accelerated basis, or result in significant increased costs to any new or existing pipelines and the potential fora temporary or permanent reductionsreduction in maximum allowable operating pressure, which would reduce available capacity on our pipelines.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.

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.

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, 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.

Other

On November 19, 2015, the Bureau of Indian Affairs published a final rule, Rights-of-Way on Indian Land; Final Rule (25 CFR 169) with the intended goal to update and streamline the process for obtaining BIA grants of rights-of-way (ROW) over and across tribal and individual Indian allotted land. The effective date of the rule is December 21, 2015. While many of the provisions simplify and expedite the process of negotiating and obtaining a ROW, certain provisions provide increased tribal authority over ROWs. As a result, tribes will have greater authority to enforce tribal laws as it relates to tax obligations for improvements, increased notification and consent for financing and bonding requirements for restoration. The rule also sets forth additional requirements concerning real property that may affect new and existing agreements.

On December 15, 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. Initial Comments are due to FERC by March 8, 2017 and Reply Comments by April 7, 2017.

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EMPLOYEES

We do not have any employees. We are managed and operated by our General Partner. Subsidiaries of TransCanada operate our pipelines systems pursuant to operating agreements.

AVAILABLE INFORMATION

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

Item 1A.    Risk Factors

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

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RISKS RELATED TO THE PARTNERSHIP

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

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

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

The amount of cash we can distribute on our units principally depends upon the amount of cash we generate from our operations, which will fluctuate based on, among other things:

•

the rates we charge for our transmission;

•

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

•

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

•

the creditworthiness of our customers;

•

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

•

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

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•

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

•

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

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

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

If we do not successfully identify and complete expansion projects or make and integrate acquisitions that are accretive, we may not be able to continue to 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, and 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. 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.

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TransCanada may offer its remainingto sell U.S. natural gas pipeline assets to the Partnership, subject to TransCanada's actual 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. Our ability to grow distributions depends upon the rate of acquisitions.

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.

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

•

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

•

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

•

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

•

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

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

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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, 2015, $7952016, $404 million of our total $1,910$1,858 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, 2015,2016, the variable interest rate exposure related to $150 million of theentire $500 million 2013 Term Loan Facility was hedged by fixed interest rate swap arrangements.

On January 25, 2016, we entered into a fixed interest rate swap related to the remaining $350 million of the $500 million 2013 Term Loan Facility, significantly reducing our debt subject to variable interest rates.

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

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

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

•

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

•

credit rating agencies may view our debt level negatively;

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•

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

•

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

•

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

In addition, our ability to access capital markets to raise capital on favorable terms will be affected by our debt level, our operating and financial performance, the amount of our current maturities and debt maturing in the next several years and by prevailing market conditions. Moreover, if the rating agencies were to downgrade our credit ratings, then we could experience an increase in our borrowing costs, face difficulty accessing capital markets or incurring additional indebtedness, be unable 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 might be forced to refinance some of our debt obligations through bank credit, as opposed to long-term public debt securities or equity securities, or sell assets. The price and terms upon which we might receive such extensions or additional bank credit, if at all, could be more onerous than those contained in existing debt agreements. Any such arrangements could, in turn, increase the risk that our leverage may adversely affect our future financial and operating flexibility and thereby impact our ability to pay cash distributions at expected rates.

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

Global financial markets and economic conditions have been, and continue to be, volatile, particularly for companies in the energy industry. The current weak economic conditions in the energy industry have made, and will likely continue to make, it difficult for some entities to obtain funding. In order to fund our expansion capital expenditures, we will 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

22    TC PipeLines, LPAnnual Report2016

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 expenditures through equity or debt financings, the terms thereof 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 unitholdersunitholders.

An impairment of our equity investment, our long-lived assets or goodwill could reduce our earnings or negatively impact the value of our common units.

Consistent with GAAP, we evaluate our goodwill for impairment at least annually and our equity investments and long-lived assets, including intangible assets with finite useful lives, 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 the underlying net assets, has declined and whether that decline is other than temporary. If we determine that impairment

2015 ANNUAL REPORT    23

is indicated, we would be required to take an immediate noncash charge to earnings with a correlative effect on equity and balance sheet leverage as measured by debt to total capitalization. This could have a negative impact on the common unit price.

As an example, during the fourth quarter ofin 2015, we recognized an impairment charge on our equity investment in Great Lakes amounting to $199 million. 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 (Northern Border, Great Lakes and PNGTS), 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.

As of December 31, 2015, no impairment has been identified related to our equity investment in Northern Border, long-lived assets or goodwill.

For more information, 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 – Equity Investments."

We do not own a controlling interest in Northern Border, Great Lakes and PNGTS,our Equity Investments, which limits our ability to control these assets.

We do not own a controlling interest in Northern Border, Great Lakes and PNGTSour Equity Investments 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 by us. The management committee requires at least the affirmative vote of a majority of the partners' percentage interests to take any action. Because of these provisions, without the concurrence of other partners, we would be unable to cause these assets to take or not to take certain actions, even though those actions may be in the best interests of the Partnership or these assets. Further, these assets may seek additional capital contributions. Our funding of these capital contributions would reduce the amount of cash otherwise available for distribution to our unitholders. In the event we elected not to, or were unable to, make a capital contribution to these assets; our ownership interest would be diluted.

TC PipeLines, LPAnnual Report2016    23

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

RISKS RELATED TO OUR PIPELINE SYSTEMS

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

Our primary exposure to market risk and competitive pressure occurs at the time existing shipper contracts expire and are subject to renegotiation and renewal. The value of our transportation services depends on a shipper's demand for pipeline capacity and the price paid for that capacity. The inability of our pipelines 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 prior contracts, depends on many factors including:

•

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

•

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

•

competition from alternative sources of supply;

•

competition from other existing or proposed pipelines;

•

contract expirations and capacity on competing pipelines;

24        TC PIPELINES, LP

•

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

•

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

•

the liquidity and willingness of shippers to contract for transportation services; and

•

regulatory developments.

As an example natural gas on Bison is currently not flowing in response to the recent relative cost advantage of WCSB-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. Such condition also increases the risk of future impairment of Bison's long lived assets.

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

Our pipeline systems are subject to extensive regulation over virtually all aspects of their business, including the types and terms of services they may offer to their customers, construction of new facilities, creation, modification or abandonment of services or facilities, and the rates that they can charge to shippers. Under the NGA, their rates must be just, reasonable and not unduly discriminatory. Actions by FERC (see Item 1. "Business – Government Regulation") could adversely affect our pipeline 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.

In July 2016, the United States Court of Appeals for the District of Columbia Circuit issued its opinion inUnited Airlines, Inc., et al. v. FERC, finding that FERC had acted arbitrarily and capriciously when it failed to demonstrate that permitting an interstate petroleum products pipeline organized as a limited partnership to include an income tax allowance in the cost of service underlying its rates in addition to the discounted cash flow return on equity would not

24    TC PipeLines, LPAnnual Report2016

result in the pipeline partnership owners double-recovering their income taxes. The court vacated FERC's order and remanded to FERC to consider mechanisms for demonstrating that there is no double recovery as a result of the income tax allowance. There is not likely to be a definitive resolution of these issues for some time, and the ultimate outcome of this proceeding 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.

On December 15, 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 Initial Comments are to FERC by March 8, 2017 and Reply Comments by April 7, 2017.

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

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

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

In 2012, the U.S. Department of Homeland Security issued public warnings that indicate that pipelines and other assets might be specific targets of terrorist organizations or "cyber security" events. More recently in December 2016 the Pipeline & Hazardous Materials Safety Administration 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 targetssecurity events might include our pipeline systems or operating systems and may result in damage to our pipeline facilities, 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 we use to safely operate our pipeline systems. Security breaches could expose our business to a risk of loss, misuse or interruption of critical physical assets or information and functions that affect the pipeline operations. Such losses could result in operational impacts, damage to our assets, public or personnel safety incidents, damage to the environment, reputational harm, competitive disadvantage, regulatory enforcement actions, litigation and a potential material adverse effect on our operations, financial position and results of operations. There is no certainty that costs incurred related to securing against threats will be recovered through rates.

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

Our pipeline systems are allowed to collect from their customers a return on their assets or "rate base" as reflected in their financial records, as well as recover a portion of that rate base over time through depreciation. In the absence of

TC PipeLines, LPAnnual Report2016    25

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.

2015 ANNUAL REPORT    25

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

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

•

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

•

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

•

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

•

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

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

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

Our pipeline systems are subject to inherent risks including, among other events, earthquakes, adverse weather conditions and other natural disasters; terrorist activity, civil disobedience or acts of aggression; damage to a pipeline by a third party; and, pipeline or equipment failures. Each of these risks could result in damage to one of our pipeline systems, business interruptions, release of pollution or contaminants into the environment and other environmental hazards, or injuries to persons and property. These risks 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' shipper contracts, as applicable. In addition, if one of our pipeline systems was to experience a serious pipeline failure, a regulator could require our pipelines to conduct testing of the pipeline system or upgrade segments of a pipeline unrelated to the failure which costs may not be covered by insurance or recoverable through rate increases or face a potential reduction in operational parameters which could reduce the capacity available for sale.

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

Our pipelines are subjected to substantial penalties and fines if the FERC finds 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 the FERC. Under the Energy Policy Act of 2005, the FERC has civil penalty authority under the NGA and NGPA to impose penalties for violations of up to $1,000,000approximately $1.2 million per day for each violation, to revoke existing certificate authority and to order disgorgement of profits associated with any violation.

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

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

The ongoing implementation of the pipeline integrity management programs could cause our pipeline systems to incur significant and unanticipated capital and operating expenditures for repairs or upgrades deemed necessary to ensure their continued safe and reliable operation and to comply with the federal pipeline safety statutes and regulations.

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Additionally, any failure to comply with PHMSA's regulations could subject our pipeline systems to penalties, fines or restrictions on our pipeline systems' operations.

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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 are not recoverable through rates.

Our pipeline systems are regulated by federal, state and local laws and regulations that could impose costs for compliance with environmental protection.protection requirements.

Each of our pipeline systems is subject to federal, state and local environmental laws, regulations and enforcement policies and potentialpolicies. Potential liabilities may arise related to protection of the environment and natural resources. Existing or new environmental laws, regulations or enforcement policies could be implemented that significantly increase our pipeline systems' compliance costs. As an example, revisions to the National Ambient Air Quality StandardsNAAQS for ozone may result in the addition of non-attainment designations in additional counties in which our pipeline systems operate, which could result in additional permitting delays and expenditures for pollution control equipment. Also, changes to legislation, such as the Toxic Substances Control Act,TSCA, may result in increased monitoring of chemicals present in the pipeline environment. It is uncertain which proposed laws, regulations or reforms, if any, will be adopted and what impact they might ultimately have on our operations or financial results.

In addition, under certain environmental laws and regulations, we may be exposed to substantial liabilities for pre-existing contamination that arise in connection with our past or current operations. For instance, although we do not have reportable information that requires corrective action at this time, during the installation, maintenance and operation of our pipeline systems, we may discover pre-existing conditions that may require us to notify, obtain and maintain permits and approvals issued by various federal, state and local governmental authorities, and to limit or prevent releases of materials from our operations in accordance with these permits and approvals, or install pollution control equipment. For instance, during routine maintenance activities, we may discover historical contamination, such as hydrocarbon, mercury, polychlorinated biphenyls, or heavy metals. This discovery may require notification to the appropriate governmental authorities and corrective action to address these conditions. Moreover, new environmental laws, regulations or enforcement policies could be implemented that significantly increase our pipeline systems' compliance costs or the cost of any remediation of environmental contamination which may not be recoverable under their rates.

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, substantial 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. Pursuant to President Obama's Strategy to Reduce Methane Emissions fromRecent federal rulemakings have focused on the oil and gas sectoremission of methane, which is considered by up to 45 percent from 2012 levels by 2025, in August 2015, the EPA proposedas a suite of requirements and draft guidance related toGHG. For example, in June 2016, the reduction in methane emissions fromEPA published New Source Performance Standards, known as Subpart OOOOa, that require certain equipment and processesnew, modified or reconstructed facilities in the oil and natural gas source category, including production, processing, transmissionsector to reduce these methane gas and storage activities, including proposed requirementsvolatile 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 fugitive emissions of methanepneumatic controllers and newpumps as well as compressors and imposing leak detection and repair requirements. The PHMSA is also expected to propose additional requirements to control for natural gas compressor and booster stations. Moreover, in November 2016, the EPA issued a final Information Collection Request seeking information about

TC PipeLines, LPAnnual Report2016    27

methane emissions from facilities and operators in the near future; however,oil and natural gas industry that the agency. The EPA has indicated that it intended to use the information from this request to develop regulations to reduce methane emissions from existing sources in the oil and natural gas industry.. Currently, our operator is assembling operator information and facility data for six facilities in response to this information request, which is due in third quarter 2017. While we cannot predict what these requirementsdo not believe that compliance with the new Subpart OOOOa regulations will be or their potential impacthave a material adverse effect on our operations, at this time. Wewe cannot estimate the effect of proposed and final regulations, and industry litigation related to the control of GHG emissions on our future financial position, results of operations or cash flow. However, such legislation, regulation and litigation could materially increase their operating costs, including their cost of environmental compliance. Given the uncertainty of policy and regulatory schemes,rulemaking, the future effects on our pipelines cannot be predicted.

2015 ANNUAL REPORT    27Recent 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.

In 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. 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 our business and results of operations.

Our pipelines do not own all of the land on which our pipelines are located, which could disrupt their operations.

Our pipelines do not own all of the land on which their pipelines have been constructed, and theyconstructed. They are therefore subject to the possibility of more onerous terms and/or increased costs to retain necessary land use if they do not have valid rights-of-way or if such rights-of-way lapse or terminate. They may obtain the rights to construct and operate our pipelines on land owned by third parties, indigenous and governmental agencies for a specific period of time. A loss of these rights, through their inability to renew right-of-way contracts or otherwise, could cause them to cease operations temporarily or permanently on the affected land, increase costs related to the construction and continuing operations elsewhere and adversely affect their results of operations and their ability to make cash distributions to us.

RISKS RELATED TO OUR PARTNERSHIP STRUCTURE

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

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

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Common unitholders have limited voting rights and are not entitled to elect our General Partner or its board of directors.

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

Common unitholders cannot remove our General Partner without its consent.

Our General Partner may not be removed except by the vote of the holders of at least 66²/3 percent of the outstanding common units. These required votes would include the votes of common units owned by our General Partner and its affiliates. TransCanada's ownership of 26.625.3 percent of our outstanding common units at December 31, 2016, has the practical effect of making removal of our General Partner difficult.

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

•

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



28        TC PIPELINES, LP

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•

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

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

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

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

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

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

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

A general partner generally has unlimited liability for the obligations of a limited partnership, except for those contractual obligations of the partnership that are expressly made without recourse to the general partner. We are

TC PipeLines, LPAnnual Report2016    29

organized under Delaware law and conduct business in a number of other states. The limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly established in some states. Our unitholders could be liable for any and all of our obligations as if our unitholders were a general partner if a court or government agency determined that:

•

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



•

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

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

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

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

2015 ANNUAL REPORT    29

incur a tax liability upon a sale of their units. As of December 31, 2015,2016, the General Partner and its affiliates own approximately 26.625.3 percent of our outstanding common units.

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

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

•

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



•

whether to exercise its limited call right;



•

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



•

whether to elect to reset target distribution levels;



•

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



•

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

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

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

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

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

The credit and business risk profiles of our General Partner and TransCanada 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, including the degree of their financial leverage and their dependence on cash flows from us to service their indebtedness.

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

Prior to making any distribution on the common units, we reimburse our General Partner and its affiliates, including officers and directors of the General Partner, for all expenses incurred by our General Partner and its affiliates on our behalf. During each of the years ended December 31, 2016, 2015 and 2014, we paid fees and reimbursements to our General Partner in the amount of $3 million. Our General Partner, in its sole discretion, determines the amount of these

30        TC PIPELINES, LP

expenses. In addition, our General Partner and its affiliates may provide us with services for which we will be charged reasonable fees as determined by the General Partner. The reimbursement of expenses and the payment of fees could adversely affect our ability to make distributions.

To the extent there may have been a violation of federal securities laws, we may be subject to claims for rescission or damages in connection with certain sales of our Common Units to certain investors who participated in our ATM offering program after the filing of our Annual Report on Form 10-K for the year-ended December 31, 2015.

On July 17, 2014, the SEC declared effective the Registration Statement that we had filed to cover sales of Common Units under the ATM program. On February 26, 2016, at the time of the filing of the 2015 Form 10-K, we believed that the Partnership continued to be eligible to use the effective Registration Statement to sell Common Units under our ATM program. However, we were advised by the staff of the SEC on June 23, 2016 that as a result of the filing of an employee-related Form 8-K on October 28, 2015, which was not filed via EDGAR until 6:02 p.m. Eastern Time (32 minutes after the 5:30 p.m. Eastern Time cutoff), the Partnership was ineligible to use the Registration Statement after the filing of the 2015 Form 10-K.

Because the Partnership was ineligible to continue using the Registration Statement following the filing of the 2015 Form 10-K, it is possible that the sales of an aggregate 1,619,631 Common Units under the Registration Statement (the ATM Common Units), which were sold between March 8, 2016 and May 19, 2016 at per Common Unit prices ranging from $47.00 to $54.95, may be deemed to have been unregistered sales of securities. If it is determined that persons who purchased the ATM Common Units from the Partnership after February 26, 2016, purchased such Common Units in an offering deemed to be unregistered, then to the extent there may have been a violation of federal securities laws such persons may be entitled to rescission rights, pursuant to which they could be entitled to recover the amount paid for such ATM Common Units, plus interest (based on the statutory rate under applicable state law), less the amount of any distributions. If such investor has sold any of the ATM Common Units purchased by the investor, then the investor would be entitled to recover the difference between the amount paid for such ATM Common Units and the amount at which such ATM Common Units were sold, assuming the investor's ATM Common Units were sold at a loss, plus interest and less the amount of any distributions. If all of the investors who purchased the ATM Common

TC PipeLines, LPAnnual Report2016    31

Units from the Partnership after February 26, 2016 continue to own all of the ATM Common Units and were to demand rescission of their purchases, and such investors were in fact found to be entitled to such rescission, then we would be obligated to repay approximately $82,334,015, plus interest, less the amount of any distributions. The Securities Act generally requires that any claim brought for a violation of Section 5 of the Securities Act be brought within one year of the violation.

We are unable to predict the likelihood of any claims or actions being brought against us related to these events.

TAX RISKS

Our tax treatment depends on our status as a partnership for U.S. federal income tax purposes, as well as us not being subject to a material amount of entity-level taxation by individual states. If the Internal Revenue Service (IRS) were to treat us as a corporation for U.S federal income tax purposes, or if we were to become subject to a material amount of entity level taxation for state tax purposes, then our cash available for distribution would be substantially reduced.

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

Despite the fact that we are organized as a limited partnership under Delaware law, we would be treated as a corporation for U.S. federal income tax purposes unless we satisfy a "qualifying income" requirement. Based upon our current operations, we believe we satisfy the qualifying income requirement. We have not requested, and do not plan to request, a ruling from the IRS on this or any other tax matter affecting us. Failing to meet the qualifying income requirement or a 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.

If we were treated as a corporation for U.S. federal income tax purposes, we would pay federal income taxes on our taxable income at the applicable corporate tax rate, which is currently a maximum of 35 percent, and we would likely have to pay state income taxes at varying rates. Distributions to our unitholders (to the extent of our earnings and profits) would generally be taxed again to unitholders as corporate dividends, and no income, gains, losses, deductions or credits would flow through to our unitholders. Because of a tax imposed upon us as a corporation, the cash available for distribution to our unitholders would be substantially reduced. Any tax treatment of us as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to unitholders and thus would likely result in a substantial reduction in the value of the common units.

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

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

The present U.S. federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units, may be modified by administrative, legislative or judicial changes or differing interpretations at any time. For example, fromFrom time to time, members of the U.S. Congress propose and consider substantive changes to the existing U.S. federal tax laws that affect publicly traded partnerships. In addition, President Obama has proposedAlthough there is no current legislative proposal, a budgetprior legislative proposal would have eliminated the qualifying income exception for fiscal year 2017 that calls for corporate taxation ofall publicly traded partnerships upon which we rely for our treatment as a partnership beginning in 2022. We are unable to predict whether or not changes in the law regarding the treatment of publicly traded partnership, if any, will ultimately occur or become enacted.for U.S. federal income tax purposes.

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At the state level, several states have either adopted or may be evaluating a variety of ways to subject partnerships and limited liability companies to entity level taxation. OurA majority of our pipeline systems are held in operating partnerships or limited liability companies, which are generally treated as flow-through entities for income tax purposes, and as such the income from our pipeline systems generally has not been subject to income tax at the entity level. Currently, only a portion of our taxable income related to PNGTS is subject to income tax. Imposition of such

2015 ANNUAL REPORT    31

taxes on our pipeline systems would reduce the cash available for distribution to us and for other business needs by our pipeline systems, and could adversely affect the amount of funds available for distribution to our unitholders.

In addition, the IRS, on May 5, 2015, issued proposed regulations concerning which activities give rise to qualifying income within the meaning of Section 7704 of the Internal Revenue Code. We do not believe the proposed regulations affect our ability to qualify as a publicly traded partnership. However, finalized regulations could modify the amount of our gross income that we are able to treat as qualifying income for the purposes of the qualifying income requirement.

Any modification to the U.S. federal income tax laws may be applied retroactively and could make it more difficult or impossible for us to meet the exception for certain publicly traded partnerships to be treated as partnerships for U.S. federal income tax purposes. We are unable to predict whether any of these changes or other proposals will ultimately be enacted. Any such changes could negatively impact the value of an investment in our common units.

In addition, on January 24, 2017, final regulations (the Final Regulations) regarding which activities give rise to qualifying income within the meaning of Section 7704 of the Internal Revenue Code of 1986, as amended (the Code) were published in the Federal Register. We do not believe the Final Regulations affect our ability to be treated as a partnership for U.S. federal income tax purposes.

If the IRS were to contest the federal income tax positions we take, it may adversely impact the market for our common units, and the costs of any such contest would reduce cash available for distribution to our unitholders. Recently enacted legislation alters the procedures for assessing and collecting taxes due for taxable years beginning after December 31, 2017 in a manner that could substantially reduce cash available for distribution to you.

We have not requested a ruling from the IRS with respect to any tax matter affecting us. 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 contest with the IRS, and the outcome of any contest with the IRS, may materially and adversely impact the market for our common units and the price at which the common units trade. In addition, the costs of any contest with the IRS will be borne directly or indirectly by the unitholders and the General Partner.

Recently enacted legislation applicableIf the IRS makes audit adjustments to usour income tax returns for taxabletax years beginning after December 31, 2017, alters the procedures for auditing large partnershipsit (and some states) may assess and also alters the procedures for assessing and collectingcollect any taxes due (including any applicable penalties and interest) as a result of an audit. Unless we are eligible to (and choose to) elect to issue revised Schedules K-1resulting from such audit adjustment directly from us, in which case our cash available for distribution to our partners with respectunitholders might be substantially reduced.

Pursuant to an audited and adjusted return,the Bipartisan Budget Act of 2015, for tax years beginning after December 31, 2017, if the IRS makes audit adjustments to our income tax returns, it (and some states) may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit adjustment directly from us. Under our limited Partnership Agreement, our general partner is permitted to make elections under the new rules to either pay the taxes (including any applicable penalties and interest) directly to the IRS or, if we are eligible, issue a revised Schedule K-1 to each unitholder with respect to an audited and adjusted return. Although our general partner may elect to have our unitholders take such audit adjustment into account in accordance with their interests in us during the tax year under audit, there can be no assurance that such election will be practical, permissible or effective in all circumstances. As a result, our current unitholders may bear some or all of the tax liability resulting from such audit adjustment, even if such unitholders did not own units in us induring the tax year in which theunder audit. If, as a result of any such audit is completed under the new rules. Ifadjustment, we are required to paymake payments of taxes, penalties and interest, as the result of audit adjustments,our cash available for distribution to our unitholders maymight be substantially reduced. In addition, because payment would be dueThese rules are not applicable for the taxable year in which the audit is completed, unitholders during that taxable year would bear the expense of the adjustment even if they were not unitholders during the audited taxable year.tax years beginning on or prior to December 31, 2017.

Unitholders may be required to pay taxes on income from us, including their share of income from the cancellation of debt, even if they receive no cash distributions.

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

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Unitholders may not receive cash distributions equal to their allocable share of our taxable income or even the tax liability that results from that income.

In response to current market conditions, weWe may engage in transactions to decrease the Partnership's financial leverage and manage our liquidity that may result in income and gain to our unitholders without a corresponding cash distribution. For example, if we sell assets and use the proceeds to repay existing debt or fund capital expenditures, you may be allocated taxable income and gain resulting from the sale without receiving a cash distribution. Further, taking advantage of opportunities to reduce our existing debt, such as debt exchanges, debt repurchases, or modifications of our existing debt could result in "cancellation of indebtedness income" (COD income) being allocated to our unitholders as taxable income. Unitholders may be allocated COD income, and income tax liabilities arising therefrom may exceed cash distributions. The ultimate effect of any such allocations will depend on the unitholder's individual tax position with

32        TC PIPELINES, LP

respect to its units. Unitholders are encouraged to consult their tax advisors with respect to the consequences to them of COD income.

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

If unitholders sell their common units, they will recognize a taxable gain or loss equal to the difference between the amount realized and their adjusted tax basis in those common units. Prior distributions in excess of the total net taxable income that a unitholder was allocated for a common unit, which distributions decreased the unitholder's tax basis in that common unit, will, in effect, become taxable income if the common unit is sold at a price greater than their 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. 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.

Tax-exempt and non-U.S. investors may have adverse tax consequences from owning common units.

An investment in common units by tax-exempt entities, such as employee benefit plans and individual retirement accounts (IRAs), and non-U.S. persons raises issues unique to these persons. For example, virtually all of our income allocated to organizations which are exempt from federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to them. Allocations and/or distributions to non-U.S. persons are subject to withholding taxes imposed at the highest effective tax rate applicable to such non-U.S. persons, and each non-U.S. person will be required to file federal income tax returns and pay tax on its share of our taxable income. Any tax-exempt entity or non-U.S. person should consult its tax advisor before investing in our common units.

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

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

We prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among our unitholders.

We prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month (the Allocation Date), instead of on the basis of the date a particular unit is transferred. Similarly, we generally allocate certain deductions for depreciation of capital

34    TC PipeLines, LPAnnual Report2016

additions, gain or loss realized on a sale or other disposition of our assets and, in the discretion of the general partner, any other extraordinary item of income, gain, loss or deduction based upon ownership on the Allocation Date. The U.S. Department of the Treasury recently adopted final Treasury Regulations allowing a similar monthly simplifying convention, for taxable years beginning on or after August 3, 2015. However,but such regulations do not specifically authorize the use of the proration method we have adopted for our 2015 taxable year and may not specifically authorize all aspects of our proration method thereafter.adopted. If the IRS were to challenge our proration method, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders.

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

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

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

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

Although we may, from time to time, consult with professional appraisers regarding valuation matters, we make many fair market value estimates using a methodology based on the market value of our common units as a means to measure the fair market value of our assets. The IRS may challenge these valuation methods and the resulting allocations of income, gain, loss and deduction.

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

The sale or exchange of 50 percent or more of our capital and profits interest during any twelve-month period will result in the termination of our Partnership for federal income tax purposes.

We will be considered to have terminated for federal income tax purposes if there is a sale or exchange of 50 percent or more of the total interests in our capital and profits within a 12-month period. For purposes of determining whether the 50 percent threshold has been met, multiple sales of the same interest will be counted only once.

Our termination would, among other things, result in the closing of our taxable year for all unitholders, which would result in us filing two tax returns for one calendar year and could result in a deferral of depreciation deductions allowable in computing our taxable income. In the case of a unitholder reporting on a taxable year other than a calendar year, the closing of our taxable year may also result in more than twelve months of our taxable income or loss being includable in taxable income for the unitholder's taxable year that includes our termination. Our termination would not affect our classification as a partnership for federal income tax purposes, but it would result in our being treated as a new partnership for U.S. federal income tax purposes following the termination. If we were treated as a

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new partnership, we would be required to make new tax elections and could be subject to penalties if we were unable to determine that a termination occurred. The IRS has announced a relief procedure whereby if a publicly traded partnership that has technically terminated requests and the IRS grants special relief, among other things, the partnership may be permitted to provide only a single Schedule K-1 to unitholders for the two short tax periods included in the year in which the termination occurs.

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

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

We currently own assets in multiple states. Many of these states 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.

Item 1B.    Unresolved Staff Comments

None.

Item 2.    Properties

A description of the location and general character of our principal physical properties is included in Item 1.1 "Business" and is incorporated herein by reference.

We believe that our pipeline systems hold all rights, titles and interests in their respective 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 land owned by third parties, governmental authorities and others pursuant to leases, easements, rights-of-way, permits and licenses. We believe that our pipeline systems' properties are adequate and suitable for the conduct of their business in the future.

Northern Border – Approximately 90 miles of Northern Border's 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 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.

Great Lakes – Approximately 74 miles of Great Lakes' pipeline system is located within the boundaries of three Indian reservations: the Leech Lake Chippewa Indian Reservation and the Fond du Lac Chippewa Indian Reservation in Minnesota, and the Bad River Chippewa Indian Reservation in Wisconsin. Great Lakes has right-of-way access, granted by the BIA, across allotted lands located within each reservation's boundaries that expire in 2018. Also, the Great Lakes pipeline crosses approximately 1,000 feet in two tracts under perpetual easement, located within the Chippewa Indian Reservation in Lower Michigan.

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Please read Part I, Item 1. "Business – Narrative Description of Business – Government Regulation – Other" for more information regarding legislation affecting easements on tribal land.

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Item 3.    Legal Proceedings

We are involved in various legal proceedings that arise in the ordinary course of business, as well as proceedings that we consider material under federal securities regulations. Information regarding our pipeline systems' rate proceedings described in Item 1. "Business – Government Regulation – Regulatory and Rate Proceedings" is incorporated herein by reference. We are also a party to the following legal proceedings:

Employees Retirement System of the City of St. Louis v. TC PipeLines GP, Inc., et al. On October 13, 2015, an alleged unitholder of the Partnership filed a class action and derivative complaint in the Delaware Court of Chancery against the General Partner, TransCanada American Investments, Ltd. (TAIL) and TransCanada, and the Partnership as a nominal defendant. The complaint alleges direct and derivative claims for breach of contract, breach of the duty of good faith and fair dealing, aiding and abetting breach of contract, and tortious interference in connection with the 2015 GTN Acquisition, including the issuance by the Partnership of $95 million in Class B Units and amendments to the Partnership Agreement to provide for the issuance of the Class B Units. Plaintiff seeks, among other things, to enjoin future issuances of Class B Units to TransCanada or any of its subsidiaries, disgorgement of certain distributions to the General Partner, TransCanada and any related entities, return of some or all of the Class B Units to the Partnership, rescission of the amendments to the Partnership Agreement, monetary damages and attorney fees. The Partnership has moved to dismiss the complaint and intends to defend vigorously against the claims asserted. In April 2016, the Chancery Court granted the Partnership and other defendants' motion to dismiss the plaintiffs' complaint. The plaintiff has appealed the decision to dismiss its claims. The appeal of this matter was heard by the Delaware Supreme Court in December, 2016. The court found in the Defendant's favor and dismissed the Plaintiff's motion. There are no further rights of appeal.

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 affiliatesAffiliates (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 8^thEighth Circuit (8^th(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. In July 2016, Essar Minnesota filed for Bankruptcy. The matter is expectedForeign Essar Affiliates have not filed for bankruptcy. 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. Great Lakes has ninety days to be heard byappeal to the 8^th circuit in 2016.

Northern Border Pipeline Company v. State of South Dakota Department of Revenue – On February 28, 2011,U.S. Supreme Court on Certiorari. In the South Dakota Department of Revenue (Department of Revenue) assessed a use taxalternative, it may proceed with its lawsuit against the Foreign Essar Affiliates in the amountstate of approximately $6 million on Northern Border for shipper supplied natural gas used to fuel compressors on Northern Border's pipeline system from July 1, 2007 to December 31, 2010. Following an unsuccessful rehearing, Northern Border received a favorable ruling on appeal by the South Dakota Circuit Court, Sixth Judicial Circuit, which decision was appealed by the Department of Revenue to the South Dakota Supreme Court. On August 5, 2015, the South Dakota Supreme Court issued its decision in favor of Northern Border, ruling that the Department of Revenue could not assess use tax on gas burned in compressors on Northern Border's pipeline located in South Dakota because Northern Border did not own the gas. The decision resulted in Northern Border's reversal of $15 million recorded liability, including interest and the related deferred asset on its books with no impact to the Partnership's earnings.Minnesota.

Item 4.    Mine Safety Disclosures

None.

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PART II

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

As of February 26, 2016,24, 2017, there were 4239 registered holders of common units and approximately 12,20028,342 beneficial owners of common units, including common units held in street name. Our common units trade on the NYSE under the symbol "TCP.""TCP".

As of February 26, 2016,24, 2017, the Partnership had 64,317,44968,424,792 common units outstanding, of which 47,232,61851,339,961 were held by non-affiliates and 17,084,831 common units were held by subsidiaries of TransCanada, including 5,797,106 common units held by our General Partner. Additionally, TransCanada, thoroughthrough our General Partner, owns 100 percent of our IDRs and an effective two percent general partner interest in the Partnership. TransCanada 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.

As of February 24, 2017, the Partnership had 1,619,631 redeemable common units outstanding. Please read Note 9 within Part IV, Item 15. "Exhibits and Financial Statement Schedules" for more detailed disclosure on the common units issuance subject to rescission.

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 cash distributions declared 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.

On February 12, 2016,14, 2017, we paid a cash distribution of $59$68 million to common unitholders and the General Partner, representing a cash distribution of $0.89$0.94 per common unit for the quarter ended December 31, 2015.2016. The distribution was allocated in the following manner: $57$64 million to the common unitholders as of the close of business on February 2, 20162017 (including approximately $15$16 million to TransCanada as holder of 17,084,831 common units), and $2$4 million to the General Partner, in respect ofwhich included $2 million for its effective two percent general partner interest which includes $1and $2 million of incentive distributions.IDRs payment. In 2015,2016, the Partnership made cash distributions to common unitholders and the General Partner that amounted to $228$250 million compared to $212$228 million in 2014.2015.

Cash Distribution Policy

Pursuant to the Partnership Agreement, the General Partner receives two percent of all cash distributions in regard to its general partner interest and is also entitled to incentive distributions as described below. The unitholders receive the remaining portion of the cash distribution. 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

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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);

2015 ANNUAL REPORT    37

•

comply with applicable laws or any debt instrument or other agreement to which we are subject; and

•

provide funds for cash distributions to unitholders and the General Partner in respect of any one or more of the next four quarters.

Incentive Distributions

The 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.

The first quarter 2015 distributionIncentive 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 $0.84 per common unit exceeded the first targetFinancial Condition and Results of Operations – Cash Distribution Policy of the General Partner's IDRs by $0.03 per common unit, resulting in an increase in the distribution on the General Partner interest from 2 percent to 15 percent on the incremental distribution in excess of the first target.

The second, third and fourth quarter 2015 distributions of $0.89 per common unit exceeded the first and second targets of the General Partner's IDRs by $0.07 and $0.01 per common unit, respectively, resulting in an increase in the distribution on the General Partner interest from 2 percent to 15 percent on the incremental distribution in excess of the first target and from 15 percent to 25 percent on the incremental distribution in excess of the second target.Partnership" for further information regarding IDRs.

In 2015,2016, we paid incentive distributions to our General Partner of approximately $2$6 million (2014(2015 – $1$2 million).

Distributions to Class B units

On January 21, 2016,23, 2017, the board of directors of our General Partner declared distributions to Class B unitholders in the amount of $12$22 million which amount was paid on February 12, 2016.14, 2017. In 2016, the Class B distribution was $12 million. The Class B distribution represents an amount based upon 30 percent of GTN's distributable cash flow duringexceeding certain annual thresholds.

Please read Notes 6, 9, 12 and 13 within Part IV, Item 15. "Exhibits and Financial Statement Schedules" for more detailed disclosures on the nine months ended December 31, 2015 less $15 million.Class B units.

See Part II, Item 7. "Management's Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources" and Item 13. "Certain Relationships and Related Transactions, and Director Independence" for additional information about cash distributions.

Item 6.    Selected Financial Data

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

38TC PipeLines, LP        TC PIPELINES, LPAnnual Report2016    39

(a)

Recast information to consolidate GTN and Bison for all periods as discusseda result of an 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, Significant Accounting Policies under Acquisitions and Note 6 of the Partnership's consolidated financial statementsGoodwill included in Part IV, Item 15. "Exhibits and Financial Statement Schedules" of this report.

(b)

Equity earnings represent our share in investee's earnings and doesdo not include any impairment charge on our equity method goodwill included as part of the carrying value of our investments in unconsolidated affiliates.investments.

(c)

During the fourth quarter of 2015, we recognized an impairment charge on our investment in Great Lakes amounting to $199 million. No other impairment has been identified on our investment in Northern Border. Refer towas recognized during the periods presented. Please read Note 4, of the Partnership's consolidated financial statements included in Part IV, Item 15. "Exhibits and Financial Statement Schedules" of this report.

(d)

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

(e)

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

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

Management's Discussion and Analysis is intended to give our unitholders an opportunity to view the Partnership through the eyes of our management. We have done so by providing management's current assessment of, and outlook of the business of the Partnership. Our discussion and analysis includes the following:

•

EXECUTIVE OVERVIEW;

•

HOW WE EVALUATE OUR OPERATIONS;

•

RESULTS OF OPERATIONS;

•

LIQUIDITY AND CAPITAL RESOURCES;

•

CRITICAL ACCOUNTING ESTIMATES;

•

CONTINGENCIES; and

•

RELATED PARTY TRANSACTIONS.

40    TC PipeLines, LPAnnual Report2016

The following discussion and analysis should be read in conjunction with Part IV, Item 15. "Exhibits and Financial Statements Schedules."

EXECUTIVE OVERVIEW

Net income (loss) attributable to controlling interests was $244 million or $3.21 per common unit in 2016 compared to $13 million, or $(0.03) per common unit in 2015. Adjusted earnings, which excluded the impact of the $199 million non-cash impairment charge on our investment in Great Lakes in the fourth quarter 2015, increased by $32 million in 2016 compared to $172 million, or $2.67 per common unit in 2014. Adjusted earnings were $212 million or $3.03 per common unit in 2015, an increase of $40 million, or $0.36 per common unit over 2014 adjusted earnings.

2015 ANNUAL REPORT    39

2015. Cash distributions declared per common unit increased fiveby six percent from $3.33 per common unit in 2014 to $3.51 per common unit in 2015.2015 to $3.71 per common unit in 2016. Please see "Non-GAAP Financial Measures: Adjusted earnings and Adjusted earnings per common unit" for more information.

Our 2016 EBITDA increased by seven$232 million to $398 million compared to $166 million in 2015 primarily due to the recognition of $199 million non-cash impairment charge to our investment in Great Lakes in 2015. Our Adjusted EBITDA, which excluded the impact of the $199 million non-cash impairment charge on our investment in Great Lakes, increased by nine percent to $365$398 million and Distributable cash flow increased by 14eight percent to $291$313 million. Please see "Non-GAAP Financial Measures: Adjusted earnings and Adjusted earnings per common unit" for more information.

PNGTS Acquisition – On January 1, 2016, we acquiredthe Partnership completed the $228 million acquisition of a 49.9 percent interest in PNGTS from TransCanada for $223 million plus a preliminary purchase price adjustmentsubsidiary of $3 million.TransCanada. The purchase price consistedwas comprised of $191$193 million in cash (including the preliminary purchase price of $3 million) and the assumption of approximately $35 million in proportionateproportional PNGTS debt. The Partnership funded the cash portion of the transaction using proceeds received 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.

PNGTS is a high-capacity, high-pressure interstate natural gas pipeline which began serving New England's energy needs in March 1999. The pipeline system is strategically located in the northeastern United States. The pipeline connects with the TQM Pipeline at the Canadian border and shares facilities with the Maritimes and Northeast Pipeline from Westbrook, Maine to a connection with the Tennessee Gas Pipeline System near Boston, Massachusetts.

This transaction addsadded a new market geography for us, extending our breadth of operations and further diversifying our cash flow stream and extending our breadth of operations. Continuing changes in the New England and Canadian Maritime gas markets in which PNGTS operates are expected which should lead to future growth opportunities for this pipeline system.

Investment in Great Lakes Impairment Charge – Despite the recent improvement in income from our investment in Great Lakes since 2013, including favorable current year results, its long-term value has been adversely impacted by the changing natural gas flows in its market region as well as our conclusion in the fourth quarter that other strategic alternatives to increase its utilization or revenue were no longer feasible. As a result, we determined that the carrying value of our investment in Great Lakes was in excess of its fair value and the decline is not temporary. Accordingly, we concluded that the carrying value of our investment in Great Lakes was impaired.

Our analysis determined that the fair value of our investment in Great Lakes is $465 million, resulting in an impairment charge of $199 million in the fourth quarter of 2015, reflected as Impairment of equity-method investment on our Statements of Income forstream. During the year ended December 31, 2015.2016, our equity interest in PNGTS contributed $19 million in earnings and $24 million in distributable cash flow.

Tuscarora Rate Case – On January 21, 2016, FERC issued an Order initiating an investigation pursuant to Section 5 of the NGA to determine whether Tuscarora's existing rates for jurisdictional services were just and reasonable. On September 22, 2016, FERC approved the settlement (Tuscarora Settlement) Tuscarora made with its customers that resolved the Section 5 review initiated by FERC. Under the terms of the Tuscarora 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. While this new rate structure reduced Tuscarora's cash flows beginning August 1, 2016, the achievement of rate certainty helps ensure predictable cash flows from this pipeline system.

Outlook of Our Business

TransCanada, the ultimate parent company of our General Partner, closed the acquisition of all of the outstanding publicly-held common units of Columbia Pipeline Partners LP on February 17, 2017. This acquisition leaves TransCanada with a single MLP in TC PipeLines, which it describes as a core element of TransCanada's strategy.

TransCanada is currently executing a largeadvancing CAD $23 billion of near-term capital projects, approximately CAD $5.8 billion of which has been invested to date with the remainder to be spent largely over the next three years. TransCanada says it intends to prudently fund its capital program in a manner that includes $13 billion Canadian of near-term growth opportunities that are expected to be complete by 2018. Over the medium to longer-term, TransCanada is also advancing $45 billion Canadian of commercially secured large-scale projects, and various other initiatives backed by long-term contracts or cost-of-service business models. Depending on market conditions and actual funding needs, TransCanada views the dropdown ofconsistent with maintaining its remaining U.S. natural gas pipeline assets into the Partnership as an important financing option as it executes its capital growth program. There can be no assurance when and on what terms these assets will be offeredfinancial strength, including potential drop downs to the Partnership.

The Partnership's financial performance is expectedcontinues to benefit from its recent acquisitions,transactions with TransCanada, including the acquisition of an interest in PNGTS from TransCanada.TransCanada effective January 1, 2016. Despite uncertaintythe volatility in energy commodity prices, our portfolio of seven FERC-regulated interstate natural gas pipelines is expected to deliver generally stable results in 20162017 due to ship-or-pay contracts with creditworthy customers.

40TC PipeLines, LP        TC PIPELINES, LPAnnual Report2016    41

HOW WE EVALUATE OUR OPERATIONS

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

EBITDA

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

Adjusted EBITDA, Adjusted earnings and Adjusted earnings per common unit

We have evaluated our financial performance and position inclusive of the impairment charge to our investment in Great Lakes recognized during the fourth quarter of 2015, however, we believe it is not reflective of our underlying operations during the periods presented. Therefore, thesewe have presented adjusted EBITDA, adjusted earnings and adjusted earnings per common unit as non-GAAP measures that exclude the impact of the $199 million non-cash impairment charge.

EBITDA

We use EBITDA as a proxy of our operating cash flow and current operating profitability. It measures our earnings from our pipeline systems before certain expenses are deducted.

Distributable Cash Flows

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

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

RESULTS OF OPERATIONS

We believe that the following presentation of the earnings contribution from each of our pipeline systems will enhance investors' understanding of the way we analyze our financial performance. However, this presentation is not meant to be considered in isolation or as a substitute for results prepared in accordance with GAAP.

Our equity interests in Northern Border, and Great Lakes, and effective January 1, 2016, PNGTS, and our full ownership of GTN, Bison, North Baja and Tuscarora were our only material sources of income in 2015.during the period. Therefore, our results of operations and cash flows were influenced by, and reflect the same factors that influenced, our pipeline systems. See Part 1, Item 1. "Business."

2015 ANNUAL REPORT42    41TC PipeLines, LPAnnual Report2016

Year Ended December 31, 2016 Compared with the Year Ended December 31, 2015

(a)

Recast as discussed in Note 2Adjusted earnings and Note 6 of the Partnership's consolidated financial statements included in Part IV, Item 15. "Exhibits and Financial Statement Schedules" of this report.

(b)

ReconciledAdjusted earnings per common unit are non-GAAP measures for which reconciliations to the appropriate GAAP measures are provided for below.

(b)

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

*

Change is greater than 100 percent.

Net income attributable to controlling interests increased by $231 million to $244 million in 2016 compared to $13 million in 2015, resulting in net income per common unit during the year of $3.21 after allocations to the General Partner and to the Class B units. This increase was primarily the result of the recognition of a $199 million non-cash impairment charge to our investment in Great Lakes in fourth quarter 2015 which lowered our net income attributable to controlling interests in 2015. (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 – Equity Investments.")

The Partnership's Adjusted earnings were higher by $32 million in 2016 compared to 2015, an increase of $0.09 per common unit mainly due to the following:

Transmission revenues – increase of $13 million primarily due to the net effect of:

•

higher discretionary revenues on GTN 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 GTN as a result of the settlement reached with its customers effective July 1, 2015.

Earnings from equity investments – $19 million increase mainly due to our share of earnings from the acquisition of a 49.9 percent interest in PNGTS effective January 1, 2016.

TC PipeLines, LPAnnual Report2016    43

Operating, maintenance and administrative – generally lower expenses in 2016 as a result of lower operational costs on our consolidated entities. Additionally, dropdown costs were incurred in 2015 related to the PNGTS Acquisition.

Financial charges and other – $11 million increase mainly attributable to additional borrowings to fund a portion of our recent acquisitions.

Net income attributable to non-controlling interests – $7 million decrease due to the 2015 GTN acquisition effective April 1, 2015, whereby the Partnership now owns 100 percent of GTN.

Year Ended December 31, 2015 Compared with the Year Ended December 31, 2014

(a)

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

(b)

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

*

Change is greater than 100 percent.

Net income attributable to controlling interests decreased by $159 million to $13 million in 2015 compared to $172 million in 2014, resulting in a net loss per common unit during the year of $0.03 after allocations to the General Partner and to the Class B units. This decrease was primarily the result of the recognition of a $199 million non-cash impairment charge to our investment in Great Lakes in fourth quarter 2015. (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 – Equity Investments.")

The Partnership's Adjusted earnings increasedwere higher by $40 million in 2015 compared to 2014, an increase of $0.36 per common unit. This unit due to the following:

Transmission revenues – increase wasof $8 million primarily due to higher discretionary revenues on GTN from short-term services sold to its customers.

Earnings from equity investments – $9 million increase mainly due the net effect of:

•

higher net income from GTN mainly due to higher revenues from the sale of short-term services;

•

higher net income from Bison mainly due to lower expenses related to pipeline integrity program spending and lower property taxes as compared to 2014;

•

lower equity earnings from Northern Border primarily due to lower revenues from the sale of short-term services as a result of the milder winter in 2015 compared to 2014;

 and

44    TC PipeLines, LPAnnual Report2016

•

higher equity earnings from Great Lakes in 2015 primarily due to additional revenues from new contracts with ANR, a related party;party.

Operating, maintenance and administrative – $3 million decrease mainly due to:

•

lower expenses on Bison related to pipeline integrity program spending; and

•

the acquisitionslower property taxes on Bison as compared to 2014.

Financial charges and other – $6 million increase mainly attributable to additional borrowings to fund a portion of the remainingour recent acquisitions.

Net income attributable to non-controlling interests in GTN and Bison whereby the Partnership now owns– $25 million decrease due to our 100 percent ofownership in GTN and Bison effective April 1, 2015 and October 1, 2014, respectively; and

42        TC PIPELINES, LP

On January 23, 2017, the board of directors of our General Partner declared distributions to Class B Units to TransCanada

unitholders in the amount of $22 million which was paid on February 14, 2017. The Class B units issued on April 1, 2015 represent limited partner interests in us and entitle TransCanada to an annual distribution which isrepresents an amount based onequal to 30 percent of GTN's annual distributions after achieving certain annual thresholds.

Duringdistributable cash flow during the current year we allocated a certain portion of our income toended December 31, 2016 less the Class B units representing the excess of 30 percent of GTN's distribution over the 2015 threshold level of $15$20 million. The allocated amount of $12 million was paid by the Partnership on February 12, 2016. See also Note 9 within Part IV, Item 15. "Exhibits and Financial Statements Schedules."

For 2016,2017, the threshold level is $20 millionthe same and we expectanticipate such threshold will be exceeded in the third quarter of 2016. Our cash flows will continue to be impacted by distributions payable to the Class B units.2017.

Please read Notes 6, 9 12 and 713 within Part IV, Item 15. "Exhibits and Financial Statements Schedules" for more detailed disclosures on the 2015 GTN Acquisition and Issuance of Class B units.

48    TC PipeLines, LPAnnual Report2016

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

EBITDA is an approximate measure of our operating cash flow during the current earnings period and reconciles directly to the most comparable measure of net income amount presented.income. It measures our earnings before deducting interest, depreciation and amortization, and net income attributable to non-controlling interests, and it includes earnings from our equity investments. Our Adjusted EBITDA excludes the impact of the $199 million non-cash impairment charge we recognized in fourth quarter 2015 on our investment in Great Lakes. We believe the charge is significant but not reflective of our underlying operations.

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

Total distributable cash flow includes our Adjusted EBITDAplus:

•

Distributions from our equity investments

44        TC PIPELINES, LP

 less:

•

Earnings from our equity investments,

•

Equity allowance for funds used during construction (Equity AFUDC),

•

Interest expense,

•

Distributions to non-controlling interests, and

•

Maintenance capital expendituresexpenditures.

Distributable cash flow is computed net of distributions declared to the General Partner and distributions allocable to Class B units. Distributions declared to the General Partner are based on its effective two percent interest plus an amount equal to incentive distributions. Distributions allocable to the Class B units equal 30 percent of GTN's distributable cash flow for the nine monthsyear ended December 31, 20152016 less $20 million (2015- less $15 million.million).

Distributable cash flow, informationEBITDA and Adjusted EBITDA are performance measures presented to assist investors in evaluating our business performance. We believe these measures provide additional meaningful information in evaluating our financial performance and cash distribution capability. As well, management uses these measures as a basis for recommendations to our General Partner's board of directors regarding the distribution amount to be declared each quarter.generating performance.

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

2015 ANNUAL REPORT    TC PipeLines, LP45Annual Report2016    49

The following table represents a reconciliation of our EBITDA, Adjusted EBITDA, Total distributable cash flow and distributableDistributable cash flow to the most directly comparable GAAP financial measure, Net income, for the periods presented:

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

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

(a)

Recast as discussed in Note 2 and Note 6 within Part IV, Item 15. "Exhibits and Financial Statement Schedules."

(b)

Interest expense as presented here includes net realized loss related to the interest rates swaps. Please read Notes 11 and 18 within Part IV, Item 15. "Exhibits and Financial Statements Schedules" for information.

(c)(b)

Amounts presented here represent depreciation of Plant, property and equipment and Amortization of debt issuance costs. Please read Note 11 within Part IV, Item 15. "Exhibits and Financial Statements Schedules" for information.

(d)

Amounts hereThese amounts are calculated in accordance with the cash distribution policies of these entities. Distributions from each of our equity investments represent our respective share of these entities' quarterly distributable cash during the current reporting period.

(e)(c)

Amounts here are calculatedOur equity investee PNGTS had $22 million of senior secured notes payment due in accordance with2016, of which the Partnership's share was approximately $11 million. PNGTS has historically funded its scheduled debt repayments and other cash needs by adjusting its available cash for distribution, policieswhich effectively reduces the net cash that we actually receive as distributions from PNGTS. Accordingly, these

50    TC PipeLines, LPAnnual Report2016

amounts represent our 49.9 percent share of distributions from PNGTS' available cash before our consolidated subsidiaries. proportionate share of the total debt repayment of PNGTS.

(d)

Distributions to non-controlling interests represent the respective share of our consolidated entities' quarterly distributable cash not owned by us during the current reporting period not owned by us.period.

(e)

The Partnership's maintenance capital expenditures include cash expenditures made to maintain, over the long term, our assets' operating capacity, system integrity and reliability. Accordingly, this amount represents the Partnership's and its consolidated subsidiaries' maintenance capital expenditures and does not include the Partnership's share of maintenance capital expenditures on our equity investments. Such amounts are reflected in "Distributions from equity investments" as those amounts are withheld by those entities from their quarterly distributable cash.

Please read the Capital spending section within Part II, Item 7. "Management Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources" for more information regarding the Partnership's total proportionate share of maintenance capital expenditures from our consolidated entities and equity investments.

(f)

Distributions declared to the General Partner for the year ended December 31, 2016 included an incentive distribution of approximately $6 million (2015 – $2 million).

(g)

During the twelve months ended December 31, 2016, 30 percent of GTN's total distributions was $42 million; therefore the distributions allocable to the Class B units was $22 million, representing the amount that exceeded the threshold level of $20 million. During the nine 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 determined and payable annually.

On January 23, 2017, the board of directors of our General Partner declared distributions to Class B unitholders in the amount of $22 million which was paid on February 14, 2017. The 2015 Class B distribution amounting to $12 million was paid by the Partnership on February 12, 2016. Please read Notes 6, 9, 12 and 13 within Part IV, Item 15. "Exhibits and Financial Statements Schedules" for more detailed disclosures on the Class B units.

(h)

"Total Distributable Cash Flow" and "Distributable Cash Flow" represent the amount of distributable cash generated by the Partnership subsidiaries and equity investments during the current earnings period and thus reconcile directly to the net income amount presented.

46        TC PIPELINES, LP

The calculation differs from the previous 2014 non-GAAP measures "Partnership Cash Flows before General Partner distributions" and "Partnership Cash Flows" as the previously used measures primarily reflected cash received during the period through distributions from our subsidiaries and equity investments that were generated from the prior quarter's financial results. The 2014 amounts reflected here have been adjusted to reflect the calculation as described above and to present the comparable "Total Distributable Cash flow" and "Distributable Cash Flow" from the previous periods.

(g)

Distributions declared to the General Partner for the year ended

Year Ended December 31, 2015 included an incentive distribution of approximately $3 million (2014 – $1 million).