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UNITED STATES SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

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

For the quarterly period ended March 31, 2019

or

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

For the transition period from           to

Commission File Number:  001-35358

TC PipeLines, LP

(Exact name of registrant as specified in its charter)

877-290-2772

(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

Yes x                    No 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 x                    No o

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

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

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

Yes o                    No x

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

As of May 7, 2019, there were 71,306,396 of the registrant’s common units outstanding.

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TC PIPELINES, LP

TABLE OF CONTENTS

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

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DEFINITIONS

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

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

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PART I

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

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

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

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

·                  demand for natural gas;

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

·                  natural gas prices and regional differences;

·                  weather conditions;

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

·                  competition from other pipeline systems;

·                  natural gas storage levels; and

·                  rates and terms of service;

·                  the performance 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;

·                  the impact of Public Law No. 115-97, commonly known as the Tax Cuts and Jobs Act (“2017 Tax Act”) enacted on December 22, 2017 on our future operating performance;

·                  other potential changes in the taxation of master limited partnership (MLP) investments by state or federal governments such as 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), U.S. Environmental Protection Agency (EPA) and U.S. Department of Transportation (DOT);

·                  the impact of downward changes in oil and natural gas prices, including the effects on the creditworthiness of our shippers;

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

·                  potential conflicts of interest between TC PipeLines GP, Inc., our general partner (General Partner), TransCanada Corporation, now known as TC Energy Corporation and us;

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

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

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

·                  the impact of any impairment charges;

·                  changes in the political environment;

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

·                  the overall increase in the allocated management and operational expenses to our pipeline systems for services performed by TC Energy Corporation; and

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

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These are not the only factors that could cause actual results to differ materially from those expressed or implied in any forward-looking statement. Other factors described elsewhere in this document, or factors that are unknown or unpredictable, could also have material adverse effects on future results. These and other risks are described in greater detail in Part II, Item 1A. “Risk Factors” of this report and in Part I, Item 1A. “Risk Factors” of our Annual Report on Form 10-K for the year ended December 31, 2018 as filed with the SEC on February 21, 2019. 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.

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PART I — FINANCIAL INFORMATION

Item 1.           Financial Statements

TC PIPELINES, LP

CONSOLIDATED STATEMENTS OF INCOME

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

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TC PIPELINES, LP

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

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

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TC PIPELINES, LP

CONSOLIDATED BALANCE SHEETS

Variable Interest Entities (Note 16)

Subsequent Events (Note 17)

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

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TC PIPELINES, LP

CONSOLIDATED STATEMENT OF CASH FLOWS

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

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TC PIPELINES, LP

CONSOLIDATED STATEMENT OF CHANGES IN PARTNERS’ EQUITY

(a)     Gain (Losses) related to cash flow hedges reported in AOCI and expected to be reclassified to Net income in the next 12 months are estimated to be $1 million. These estimates assume constant interest rates over time; however, the amounts reclassified will vary based on actual value of interest rates at the date of settlement.

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

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TC PIPELINES, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

NOTE 1    ORGANIZATION

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

The Partnership owns its pipeline assets through an intermediate general partnership, TC PipeLines Intermediate GP, LLC and three intermediate limited partnerships (ILPs), TC GL Intermediate Limited Partnership, TC PipeLines Intermediate Limited Partnership and TC Tuscarora Intermediate Limited Partnership.

NOTE 2    SIGNIFICANT ACCOUNTING POLICIES

The accompanying consolidated financial statements and related notes have been prepared in accordance with United States generally accepted accounting principles (GAAP) and amounts are stated in U.S. dollars. The results of operations for the three months ended March 31, 2019 and 2018 are not necessarily indicative of the results that may be expected for the full fiscal year.

The accompanying consolidated financial statements should be read in conjunction with the audited consolidated financial statements and notes thereto for the year ended December 31, 2018 included in our Annual Report on Form 10-K. That report contains a more comprehensive summary of the Partnership’s significant accounting policies. In the opinion of management, the accompanying consolidated financial statements contain all of the appropriate adjustments, which are normally recurring adjustments unless otherwise noted, and considered necessary to present fairly the financial position of the Partnership, the results of operations and cash flows for the respective periods. Our significant accounting policies are consistent with those disclosed in our Annual Report on Form 10-K for the year ended December 31, 2018, except as described in Note 3, Accounting Pronouncements.

Basis of Presentation

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

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

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

U.S. federal and certain state income taxes are the responsibility of the partners and are not reflected in these consolidated financial statements. The tax effect of the Partnership’s activities accrues to its partners. The Partnership’s taxable income or loss, which may vary substantially from the net income or loss reported in the consolidated statement of operations, is includable in the U.S. federal income tax returns of each partner.

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

Use of Estimates

The preparation of financial statements requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities, if any, as of the date of the financial statements, and the

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reported amounts of revenues and expenses during the reporting period. Although management believes these estimates are reasonable, actual results could differ from these estimates.

NOTE 3    ACCOUNTING PRONOUNCEMENTS

Changes in Accounting Policies effective January 1, 2019

Leases

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

Under the new guidance, the Partnership determines if an arrangement is a lease at inception. Operating leases are recognized as ROU assets and included in Property, plant and equipment while corresponding liabilities are included in “Accounts payable and other”, and “Other long-term liabilities” on the consolidated balance sheet.

Operating lease ROU assets and operating lease liabilities are recognized based on the present value of the future minimum lease payments over the lease term at commencement date. As the Partnership’s leases do not provide an implicit rate, the Partnership uses an incremental borrowing rate that approximates its borrowing cost based on the information available at commencement date in determining the present value of future payments. The operating lease ROU asset also includes any lease payments made and initial direct costs incurred and excludes lease incentives. Lease terms may include options to extend or terminate the lease when it is reasonably certain that the Partnership will exercise that option. Operating lease expense is recognized on a straight-line basis over the lease term and included in “Operation and maintenance expenses” in the consolidated statements of income.

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

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

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

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

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

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

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

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

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

·                  the discount rate for the lease.

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

The most significant change as a result of the adoption was the recognition of ROU assets and lease liabilities for operating leases which was approximately $0.6 million at January 1, 2019 and $0.5 million at March 31, 2019. For the three months

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ended March 31, 2019, the Partnership’s operating lease cost was not material to the Partnership’s consolidated results. The weighted average remaining term and discount rate of the Partnership’s operating leases was approximately 2.63 years and 3.57 percent, respectively.

Fair Value Measurement

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

Future accounting changes

Measurement of credit losses on financial instruments

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

Consolidation

In October 2018, the FASB issued new guidance for determining whether fees paid to decision makers and service providers are variable interests for indirect interests held through related parties under common control. This new guidance is effective January 1, 2020, and will be applied on a retrospective basis, however early adoption is permitted. The Partnership is currently evaluating the timing and impact of adoption of this guidance and has not yet determined the effect on its consolidated financial statements.

NOTE 4  REGULATORY

Iroquois, Tuscarora, and Northern Border took the actions listed below to conclude the issues impacting their pipelines as contemplated by the 2017 Tax Act and certain FERC actions that began in March of 2018, namely FERC’s Revised Policy Statement on Treatment of Income Taxes (Revised Policy Statement) and a Final Rule that established a schedule by which interstate pipelines must either (i) file a new uncontested rate settlement or (ii) file a one-time report, called FERC Form No. 501-G, that quantified the rate impact of the 2017 Tax Act on FERC-regulated pipelines and the impact of the Revised Policy Statement on pipelines held by an MLP (collectively “2018 FERC Actions”).

Iroquois

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

Tuscarora

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

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Northern Border

On April 4, 2019, Northern Border filed a petition for approval with FERC to amend the settlement agreement reached with its customers in 2017.  Unless superseded by a subsequent rate case or settlement, effective January 1, 2020, the additional 2 percent rate reduction implemented on February 1, 2019 will be extended to July 1, 2024 as part of the amended settlement agreement. The amendment is pending approval from FERC.

NOTE 5    EQUITY INVESTMENTS

The Partnership has equity interests in Northern Border, Great Lakes and Iroquois. The pipeline systems owned by these entities are regulated by FERC. The pipeline systems of Northern Border and Great Lakes are operated by subsidiaries of TC Energy. The Iroquois pipeline system is operated by Iroquois Pipeline Operating Company, a wholly owned subsidiary of Iroquois. The Partnership uses the equity method of accounting for its interests in its equity investees. The Partnership’s equity investments are held through our ILPs that are considered to be variable interest entities (VIEs) (Refer to Note 16).

Distributions from Equity Investments

Distributions received from equity investments in the three months ended March 31, 2019 were $58 million (March 31, 2018 — $45 million) of which, $2 million (March 31, 2018 - $2 million) was considered a return of capital and is included in “Investing Activities” in the Partnership’s consolidated statement of cash flows. The return of capital was related to our investment in Iroquois (see further discussion below).

Northern Border

The Partnership did not have undistributed earnings from Northern Border for the three months ended March 31, 2019 and 2018.

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

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(a)                   No current maturities as of March 31, 2019 and December 31, 2018. At March 31, 2019, Northern Border is in compliance with all its financial covenants.

Great Lakes

The Partnership made an equity contribution to Great Lakes of $5 million in the first quarter of 2019 (March 31, 2018 - $4 million). This amount represents the Partnership’s 46.45 percent share of an $11 million cash call from Great Lakes to make a scheduled debt repayment.

The Partnership did not have undistributed earnings from Great Lakes for the three months ended March 31, 2019 and 2018.

The summarized financial information provided to us by Great Lakes is as follows:

(a)                   Includes current maturities of $21 million as of March 31, 2019 and as of December 31, 2018. At March 31, 2019, Great Lakes is in compliance with all its financial covenants.

Iroquois

During the three months ended March 31, 2019, the Partnership received distributions from Iroquois amounting to $14 million (March 31, 2018 - $14 million) which includes the Partnership’s 49.34 percent share of the Iroquois unrestricted cash distribution amounting to approximately $2 million (March 31, 2018 - $2 million). The unrestricted cash did not represent a

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distribution of Iroquois’ cash from operations during the period and therefore it was reported as distributions received as return of investment in the Partnership’s consolidated statement of cash flows.

Iroquois declared its first quarter 2019 distribution of $28 million on April 24, 2019, of which the Partnership received its 49.34 percent share or $14 million on May 1, 2019. The distribution includes our 49.34 percent share of the Iroquois unrestricted cash distribution amounting to approximately $2 million. The Partnership did not have undistributed earnings from Iroquois for the three months ended March 31, 2019 and 2018.

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

(a)              Includes current maturities of $146 million as of March 31, 2019 and as of December 31, 2018. At March 31, 2019, Iroquois is in compliance with all its financial covenants.

NOTE 6    REVENUES

Disaggregation of Revenues

For the three months ended March 31, 2019 and March 31, 2018, effectively all of the Partnership’s revenues were from capacity arrangements and transportation contracts with customers as discussed in more detail below.

Capacity Arrangements and Transportation Contracts

The Partnership’s performance obligations in its contracts with customers consist primarily of capacity arrangements and natural gas transportation contracts.

The Partnership’s revenues are generated from contractual arrangements for committed capacity and from transportation of natural gas which are treated as a bundled performance obligation. Revenues earned from firm contracted capacity arrangements are recognized ratably over the term of the contract regardless of the amount of natural gas that is transported. Transportation revenues for interruptible or volumetric-based services are recognized when the service is performed. The Partnership has elected to utilize the practical expedient of recognizing revenue as invoiced.

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The Partnership’s pipeline systems are subject to FERC regulations and, as a result, a portion of revenues collected may be subject to refund if invoiced during an interim period when a rate proceeding is ongoing. Allowances for these potential refunds are recognized using management’s best estimate based on the facts and circumstances of the proceeding. Any allowances that are recognized during the proceeding process are refunded or retained, as applicable, at the time a regulatory decision becomes final. As of March 31, 2019, the Partnership does not have any outstanding refund obligations related to any rate proceedings. Revenues are invoiced and paid on a monthly basis. The Partnership’s pipeline systems do not take ownership of the natural gas that is transported for customers. Revenues from contracts with customers are recognized net of any taxes collected from customers, which are subsequently remitted to governmental authorities.

Contract Balances

All of the Partnership’s contract balances pertain to receivables from contracts with customers amounting to $35 million at March 31, 2019 (December 31, 2018 - $44 million) and are recorded as Trade accounts receivable and reported as “Accounts receivable and other” in the Partnership’s consolidated balance sheet (Refer to Note 14).

Additionally, our accounts receivable represents the Partnership’s unconditional right to consideration for services completed which includes billed and unbilled accounts.

Future revenue from remaining performance obligations

When the right to invoice practical expedient is applied, the guidance does not require disclosure of information related to future revenue from remaining performance obligations; therefore, no additional disclosure is required.

Additionally, in the application of the right to invoice practical expedient, the Partnership’s revenues from regulated capacity arrangements are recognized based on rates specified in the contract. Therefore, the amount invoiced, which includes the capacity contracted and variable volume of natural gas transported, corresponds directly to the value the customer received. These revenues are recognized on a monthly basis once the Partnership’s performance obligation to provide capacity has been satisfied.

NOTE 7    DEBT AND CREDIT FACILITIES

(a)                   Fixed interest rate

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TC PipeLines, LP

The Partnership’s Senior Credit Facility consists of a $500 million senior revolving credit facility with a banking syndicate, maturing November 10, 2021. During the three months ended March 31, 2019, the Partnership repaid all amounts outstanding under its Senior Credit Facility and there was no outstanding balance at March 31, 2019 (December 31, 2018 - $40 million).

The LIBOR-based interest rate on the Senior Credit Facility was 3.77 percent at December 31, 2018.

As of March 31, 2019, the variable interest rate exposure related to the 2013 Term Loan Facility was hedged using interest rate swaps at an average rate of 3.26 percent (December 31, 2018 — 3.26 percent). Prior to hedging activities, the LIBOR-based interest rate on the 2013 Term Loan Facility was 3.74 percent at March 31, 2019 (December 31, 2018 — 3.60 percent).

The Senior Credit Facility and the 2013 Term Loan Facility require the Partnership to maintain a certain leverage ratio (debt to adjusted cash flow [net income plus cash distributions received, extraordinary losses, interest expense, expense for taxes paid or accrued, and depreciation and amortization expense less equity earnings and extraordinary gains]) no greater than 5.00 to 1.00 for each fiscal quarter, except for the fiscal quarter and the two following fiscal quarters in which one or more acquisitions has been executed, in which case the leverage ratio is to be no greater than 5.50 to 1.00. The leverage ratio was 3.03 to 1.00 as of March 31, 2019.

GTN

GTN’s Unsecured Senior Notes, along with GTN’s Unsecured Term Loan Facility contain a covenant that limits total debt to no greater than 70 percent of GTN’s total capitalization.  GTN’s total debt to total capitalization ratio at March 31, 2019 was 42.5 percent.

The LIBOR-based interest rate on GTN’s Unsecured Term Loan Facility was 3.44 percent at March 31, 2019 (December 31, 2018 — 3.30 percent).

PNGTS

PNGTS’ Revolving Credit Facility requires PNGTS to maintain a leverage ratio not greater than 5.00 to 1.00. The leverage ratio was 0.47 to 1.00 as of March 31, 2019.

The LIBOR-based interest rate on PNGTS’ Revolving Credit Facility was 3.74 percent at March 31, 2019 (December 31, 2018 — 3.60 percent).

Tuscarora

Tuscarora’s Unsecured Term Loan contains a covenant that requires Tuscarora to maintain a debt service coverage ratio (cash available from operations divided by a sum of interest expense and principal payments) of greater than or equal to 3.00 to 1.00. As of March 31, 2019, the ratio was 10.14 to 1.00.

The LIBOR-based interest rate on the Tuscarora’s Unsecured Term Loan Facility was 3.61 percent at March 31, 2019 (December 31, 2018 — 3.47 percent).

North Baja

North Baja’s Term Loan Facility contains a covenant that limits total debt to no greater than 70 percent of North Baja’s total capitalization.  North Baja’s total debt to total capitalization ratio at March 31, 2019 was 38.11 percent.

The LIBOR-based interest rate on North Baja’s Term Loan Facility was 3.56 percent at March 31, 2019 (December 31, 2018 - 3.54 percent).

Partnership (TC PipeLines, LP and its subsidiaries)

At March 31, 2019, the Partnership was in compliance with its financial covenants, in addition to the other covenants which include restrictions on entering into mergers, consolidations and sales of assets, granting liens, material amendments to the

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Fourth Amended and Restated Agreement of Limited Partnership (Partnership Agreement), incurring additional debt and distributions to unitholders.

The principal repayments required of the Partnership on its debt are as follows:

NOTE 8           PARTNERS’ EQUITY

ATM equity issuance program (ATM program)

During the three months ended March 31, 2019, no common units were issued under this program.

Class B units issued to TC Energy

The Class B units entitle TC Energy to an annual distribution based on 30 percent of GTN’s annual distributions as follows: (i) 100 percent of distributions above $20 million for the year ending December 31, 2019; (ii) 43.75 percent of distributions above $20 million for the year ending December 31, 2020; and (iii) 25 percent of distributions above $20 million thereafter (Class B Distribution). Additionally, the Class B Distribution will be further reduced by 35 percent, which is equivalent to the percentage by which distributions payable to the common units were reduced in 2018 (Class B Reduction). The Class B Reduction was implemented during the first quarter of 2018 following the Partnership’s common unit distribution reduction of 35 percent. The Class B Reduction will continue to apply for any particular calendar year until distributions payable in respect of common units for such calendar year equal or exceed $3.94 per common unit.

For the year ended December 31, 2019, the Class B units’ equity account will be increased by the Class B Distribution, less the Class B Reduction, until such amount is declared for distribution and paid in the first quarter of 2020. During the three months ended March 31, 2019, the Class B threshold was not exceeded.

For the year ended December 31, 2018, the Class B distribution was $13 million and was declared and paid in the first quarter of 2019.

NOTE 9           NET INCOME PER COMMON UNIT

Net income per common unit is computed by dividing net income attributable to controlling interests, after deduction of amounts attributable to the General Partner and Class B units, by the weighted average number of common units outstanding.

The amount allocable to the General Partner equals an amount based upon the General Partner’s two percent general partner interest, plus an amount equal to incentive distributions. Incentive distributions are paid to the General Partner if quarterly cash distributions on the common units exceed levels specified in the Partnership Agreement.

The amount allocable to the Class B units in 2019 equals 30 percent of GTN’s distributable cash flow during the year ended December 31, 2019 less $20 million and is further reduced by the estimated Class B Reduction for 2019 (December 31, 2018 —$20 million less Class B Reduction). During the three months ended March 31, 2019 and 2018, no amounts were allocated to the Class B units as the annual threshold was not exceeded.

Net income per common unit was determined as follows:

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NOTE 10    CASH DISTRIBUTIONS PAID TO COMMON UNITS

During the three months ended March 31, 2019, the Partnership distributed $0.65 per common unit (March 31, 2018 — $1.00 per common unit) for a total of $47 million (March 31, 2018 - $76 million).

The distribution paid to our General Partner during the three months ended March 31, 2019 for its two percent general partner interest was $1 million (March 31, 2018 - $2 million). The General Partner did not receive any distributions in respect of its IDRs during the three months ended March 31, 2019 (March 31, 2018 - $3 million).

NOTE 11    CHANGE IN OPERATING WORKING CAPITAL