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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, 2018

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

As of May 1, 2018, 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 the 2017 Tax Act and the 2018 FERC Actions on our future operating performance;

·        other potential changes in taxation of master limited partnerships (MLPs) by state or federal governments;

·        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 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, terms and closure of future potential acquisitions;

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

·        the impact of any impairment charges;

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

·        the expected impact of future accounting changes, commitments and contingent liabilities (if any);

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

·        the level of our indebtedness, including the indebtedness of our pipeline systems, and the availability of capital;

·        unfavorable conditions in capital and credit markets, inflation and fluctuations in interest rates; and

·        the overall increase in the allocated management and operational expenses on our pipeline systems for functions performed by TransCanada.

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

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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, 2017 as filed with the SEC on February 26, 2018. 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

(a)         Recast to consolidate PNGTS (Refer to Note 2).

(b)        Net income per common unit prior to recast (Refer to Note 2).

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

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TC PIPELINES, LP CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(a)              Recast to consolidate PNGTS (Refer to Note 2).

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

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TC PIPELINES, LP

CONSOLIDATED BALANCE SHEETS

Contingencies (Note 16)

Variable Interest Entities (Note 17)

Subsequent Events (Note 19)

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

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TC PIPELINES, LP

CONSOLIDATED STATEMENT OF CASH FLOWS

(a)         Recast to consolidate PNGTS (Refer to Note 2).

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)     Losses related to cash flow hedges reported in Accumulated Other Comprehensive Loss and expected to be reclassified to Net income in the next 12 months are estimated to be $4 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 (TransCanada Corporation together with its subsidiaries collectively referred to herein as TransCanada), to acquire, own and participate in the management of energy infrastructure assets in North America.

The Partnership owns its pipeline assets through 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 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, 2018 and 2017 are not necessarily indicative of the results that may be expected for the full fiscal year.

The accompanying financial statements should be read in conjunction with the audited financial statements and notes thereto for the year ended December 31, 2017 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 financial statements contain all of the appropriate adjustments, all of 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, 2017, 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 in non-controlling interests. The Partnership uses the equity method of accounting for its investments in entities over which it is able to exercise significant influence.

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

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

On June 1, 2017, the Partnership acquired from a subsidiary of TransCanada an additional 11.81 percent interest in PNGTS, that resulted in the Partnership owning a 61.71 percent interest in PNGTS.  As a result of the Partnership owning a 61.71 percent interest in PNGTS, the Partnership’s historical financial information has been recast, except net income per common unit, to consolidate PNGTS for all the periods presented in the Partnership’s consolidated financial statements. Additionally, this acquisition was accounted for as transaction between entities under common control, similar to pooling of interests, whereby the assets and liabilities of PNGTS were recorded at TransCanada’s carrying value.

Also, on June 1, 2017, the Partnership acquired from subsidiaries of TransCanada a 49.34 percent interest in Iroquois. Accordingly, this transaction was accounted for as a transaction between entities under common control, similar to pooling of interest, whereby the equity investment in Iroquois was recorded at TransCanada’s carrying value and was accounted for prospectively from the date of acquisition.

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Use of Estimates

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

NOTE 3    ACCOUNTING PRONOUNCEMENTS

Changes in Accounting Policies effective January 1, 2018

Revenue from contracts with customers

In 2014, the Financial Accounting Standards Board (FASB) issued new guidance on revenue from contracts with customers. The new guidance requires that an entity recognize revenue from these contracts in accordance with a prescribed model. This model is used to depict the transfer of promised goods or services to customers in amounts that reflect the total consideration to which it expects to be entitled during the term of the contract in exchange for those promised goods or services. Goods or services that are promised to a customer are referred to as the Partnership’s “performance obligations.” The total consideration to which the Partnership expects to be entitled can include fixed and variable amounts. The Partnership has variable revenue that is subject to factors outside the Partnership’s influence, such as market volatility, actions of third parties and weather conditions. The Partnership considers this variable revenue to be “constrained” as it cannot be reliably estimated, and therefore recognizes variable revenue when the service is provided.

The new guidance also requires additional disclosures about the nature, amount, timing and uncertainty of revenue recognition and the related cash flows. The new guidance was effective January 1, 2018, was applied using the modified retrospective transition method, and did not result in any material differences in the amount and timing of revenue recognition. Refer to Note 6 - Revenues, for further information related to the impact of adopting the new guidance and the Partnership’s updated accounting policies related to revenue recognition from contracts with customers.

Hedge Accounting

In August 2017, the FASB issued new guidance on hedge accounting, making more financial and nonfinancial hedging strategies eligible for hedge accounting. The new guidance amends the presentation requirements relating to the change in fair value of a derivative and additional disclosure requirements include cumulative basis adjustments for fair value hedges and the effect of hedging on individual statement of income line items. This new guidance is effective January 1, 2019 with early adoption permitted. The Partnership has elected to apply this guidance effective January 1, 2018. Application of this guidance did not have a material impact on its consolidated financial statements.

Future accounting changes

Leases

In February 2016, the FASB issued new guidance on the accounting for leases. The new guidance amends the definition of a lease requiring the customer to have both (1) the right to obtain substantially all of the economic benefits from the use of the asset and (2) the right to direct the use of the asset in order for the arrangement to qualify as a lease. The new guidance also establishes a right-of-use (ROU) model that requires a lessee to recognize a ROU asset and corresponding lease liability on the balance sheet for all leases with a term longer than 12 months. Leases will be classified as finance or operating, with classification affecting the pattern and classification of expense recognition in the income statement. The new guidance does not make extensive changes to lessor accounting.

In January 2018, the FASB issued new guidance on accounting for land easements which provides an optional transition practical expedient to not evaluate existing or expired land easements not accounted for as leases prior to entity’s adoption of the new guidance. An entity that elects this practical expedient is required to apply it consistently to all of its existing or expired land easements not previously accounted for as leases.

The new guidance is effective on January 1, 2019, with early adoption permitted. A modified retrospective transition approach is required for leases existing at, or entered into after, the beginning of the earliest comparative period

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presented in the financial statements, with certain practical expedients available. The Partnership is continuing to identify and analyze existing lease agreements to determine the effect of adoption of the new guidance on its consolidated financial statements. The Partnership is also addressing system and process changes necessary to compile the information to meet the recognition and disclosure requirements of the new guidance. The Partnership continues to monitor and analyze additional guidance and clarification provided by FASB.

Goodwill Impairment

In January 2017, the FASB issued new guidance on simplifying the test for goodwill impairment by eliminating the requirement to calculate the implied fair value of goodwill to measure the impairment charge. Instead, entities will record an impairment charge based on the excess of a reporting unit’s carrying amount over its fair value. This new guidance is effective January 1, 2020 and will be applied prospectively, however, early adoption is permitted.

Measurement of credit losses on financial instruments

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

NOTE 4   REGULATORY

In December 2016, FERC issued a Notice of Inquiry (NOI) Regarding the Commission’s Policy for Recovery of Income Tax Costs (Docket No. PL17-1-000) requesting initial comments regarding how to address any “double recovery” resulting from FERC’s current income tax allowance and rate of return policies that had been in effect since 2005.

Docket No. PL17-1-000 is a direct response to United Airlines, Inc., et al. v. FERC (United), a decision issued by the U.S. Court of Appeals for the District of Columbia Circuit in July 2016 in which the D.C. Circuit directed FERC to explain how a pass-through entity such as an MLP receiving a tax allowance and a return on equity derived from the discounted cash flow (DCF) methodology did not result in “double recovery” of taxes.

On December 22, 2017, the President of the United States signed into law H.R.1, originally known as the Tax Cuts and Jobs Act (the “2017 Tax Act”).  This legislation provides for major changes to U.S. corporate federal tax law including a reduction of the federal corporate income tax rate. We are a non-taxable limited partnership for federal income tax purposes, and federal income taxes owed as a result of our earnings are the responsibility of our partners, therefore no amounts have been recorded in the Partnership’s financial statements with respect to federal income taxes as a result of the 2017 Tax Act.

On March 15, 2018, FERC issued (1) a revised Policy Statement to address the treatment of income taxes for ratemaking purposes for MLPs, (2) a Notice of Proposed Rulemaking (NOPR) proposing interstate pipelines file a one-time report to quantify the impact of the federal income tax rate reduction and the revised Policy Statement could have on a pipeline’s Return on Equity (ROE) assuming a single-issue adjustment to a pipeline’s rates, and (3) an NOI seeking comment on how FERC should address changes related to accumulated deferred income taxes and bonus depreciation (collectively, the “2018 FERC Actions”). Each is further described below.

FERC Revised Policy Statement on Income Tax Allowance Cost Recovery in MLP Pipeline Rates

FERC changed its long-standing policy on the treatment of income tax amounts to be included in pipeline rates and other assets subject to cost of service rate regulation held within an MLP.  The revised Policy Statement no longer permits entities organized as MLPs to recover an income tax allowance in their cost of service rates.

TransCanada filed a Request for Clarification and If Necessary Rehearing of FERC’s revised Policy Statement on April 16, 2018, addressing concerns over the lack of clarity around entities with ownership shared between an MLP and a corporation as well as other related concerns. In the request, TransCanada sought clarification or rehearing on several bases: that FERC erred in not assessing the propriety of income tax allowances for pipelines on a case-by-case basis; that FERC overturned applicable legal precedent expressly not affected by United; that FERC failed to consider the effects of its revised policy on industry; and that FERC failed to exhibit reasoned decision making or to support its decision with substantial evidence on the record.

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NOPR on Tax Law Changes for Natural Gas Companies

The NOPR proposes that by a deadline to be set in final rule-making, interstate pipelines must either file a new uncontested settlement or comply with a rule that would require companies to file a one-time report, called FERC Form No. 501-G, that quantifies the rate impact of 2017 Tax Act and, with respect to pipelines held by MLPs, the FERC’s revised Policy Statement. Concurrent with filing the one-time report, each pipeline would have four options:

· make a limited Natural Gas Act Section 4 filing to reduce its rates by the percentage reduction in its cost of service shown in its FERC Form No. 501-G

· commit to file either a pre-packaged uncontested rate settlement or a general Section 4 rate case if it believes that using the limited Section 4 option will not result in just and reasonable rates. If the pipeline commits to file either by December 31, 2018, FERC will not initiate a Natural Gas Act Section 5 investigation of its rates prior to that date

· file a statement explaining its rationale for why it does not believe the pipeline’s rates must change

· take no action other than filing the one-time 501-G report. FERC would then consider whether to initiate a Section 5 investigation of any pipeline that has not submitted a limited Section 4 rate reduction filing or committed to file a general Section 4 rate case.

TransCanada submitted comments on the NOPR on April 25, 2018. Following the requisite public comment period, we expect FERC to issue final order(s) in the late summer or early fall of 2018. We continue to evaluate this NOPR and our next course of action, however, we do not expect an immediate or a retroactive impact from the NOPR or the revised Policy Statement described above.

NOI Regarding the Effect of the 2017 Tax Act on Commission-Jurisdictional Rates

In the NOI, FERC seeks comment to determine what additional action as a result of the 2017 Tax Act, if any, is required by FERC related to accumulated deferred income taxes collected from shippers in anticipation of ultimately being paid to the Internal Revenue Service, but which no longer accurately reflect the future income tax liability. The NOI also seeks comment on the elimination of bonus depreciation for regulated natural gas pipelines and other effects of the 2017 Tax Act.

We plan to submit comments in response to the NOI by the due date of May 21, 2018.

Impairment Considerations

As noted under Note 2, the preparation of financial statements in accordance with GAAP requires us to make estimates and assumptions with respect to values or conditions, which cannot be known with certainty, that affect the reported amount of assets and liabilities at the date of the financial statements. Although we believe these estimates and assumptions are reasonable, actual results could differ.

We review plant, property and equipment and equity investments for impairment whenever events or changes in circumstances indicate the carrying value of the asset may not be recoverable.

Goodwill is tested for impairment on an annual basis or more frequently if events or changes in circumstance indicate that it might be impaired. We can initially make this assessment based on qualitative factors. If we conclude that it is not more likely than not that the fair value of the reporting unit is less than its carrying value, an impairment test is not performed.

Until the proposed 2018 FERC Actions are finalized, implementation requirements are clarified, including the applicability to assets partially-owned by a MLP or held in non-MLP structures, and we have fully evaluated our respective alternatives to minimize the potential negative impact of the 2018 FERC Actions on our future operating performance and cash flows, we believe that it is not more likely than not that the fair values of our reporting units are less than their respective carrying values. Therefore, a goodwill impairment test was not performed. Also, we have determined there is no indication that the carrying values of plant, property and equipment and equity investments potentially impacted by the 2018 FERC Actions are not recoverable.

We will continue to monitor developments and assess our goodwill for impairment. We will also review our property, plant and equipment and equity investments for recoverability as new information becomes available.

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At December 31, 2017, the estimated fair value of our investment in Great Lakes exceeded its carrying value by less than 10 percent. There is a risk that the 2018 FERC Actions, once finalized, could result in an impairment charge to our equity method goodwill on Great Lakes amounting to $260 million at March 31, 2018 (December 31, 2017 — $260 million). Additionally, since the estimated fair value of Tuscarora exceeded its carrying value by less than 10 percent in its most recent valuation, there is also a risk that the $82 million goodwill at March 31, 2018 (December 31, 2017 - $82 million) related to Tuscarora could be negatively impacted by the 2018 FERC Actions.

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 TransCanada. 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 17).

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

(b)             The Partnership acquired a 49.34% interest in Iroquois on June 1, 2017.

Distributions from Equity Investments

Distributions received from equity investments for the quarter ended March 31, 2018 were $45 million (2017 — $28 million;) of which $2 million (2017 - none) 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, 2018 and 2017.

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, 2018 and December 31, 2017.

Great Lakes

The Partnership made an equity contribution to Great Lakes of $4 million in the first quarter of 2018. This amount represents the Partnership’s 46.45 percent share of a $9 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, 2018 and 2017.

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

(a)              Includes current maturities of $21 million as of March 31, 2018 (December 31, 2017 - $19 million).

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Iroquois

On June 1, 2017, the Partnership, through its interest in TC PipeLines Intermediate Limited Partnership acquired a 49.34 percent interest in Iroquois. During the three months ended March 31, 2018, the Partnership received distributions from Iroquois amounting to $14 million which includes the Partnership’s 49.34 percent share of the Iroquois unrestricted cash distribution amounting to approximately $2 million. The unrestricted cash does not represent a 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 2018 distribution of $29 million on March 7, 2018, of which the Partnership received its 49.34 percent share or $14 million on May 1, 2018. The distribution includes our 49.34 percent share of the Iroquois unrestricted cash distribution amounting to approximately $2.6 million. The Partnership did not have undistributed earnings from Iroquois for the three months ended March 31, 2018.

The summarized financial information provided to us by Iroquois for the period from the June 1, 2017 acquisition date through March 31, 2018 is as follows:

(a)              Includes current maturities of $4 million as of March 31, 2018 (December 31, 2017 - $4 million).

NOTE 6    REVENUES

In 2014, the FASB issued new guidance on revenue from contracts with customers. The Partnership adopted the new guidance on January 1, 2018 using the modified retrospective transition method for all contracts that were in effect on the date of adoption. The reported results for all periods in 2018 reflect the application of the new guidance, while the reported results for all periods in 2017 were prepared under previous revenue recognition guidance which is referred to herein as “legacy U.S. GAAP”.

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Disaggregation of Revenues

For the three months ended March 31, 2018, virtually 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.

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.

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. 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.

Financial Statement Impact of Adopting Revenue from Contracts with Customers

The Partnership adopted the new guidance using the modified retrospective transition method. As a practical expedient under this transition method, the Partnership is not required to analyze completed contracts at the date of adoption.  The adoption of the new guidance did not have a material impact on the Partnership’s previously reported consolidated financial statements at December 31, 2017.

Pro-forma Financial Statements under Legacy U.S. GAAP

As required by the new revenue recognition guidance, the following tables illustrate the pro-forma impact on the affected line items of the consolidated balance sheet, as at March 31, 2018, had legacy U.S. GAAP been applied (the income statement line items were not affected):

Contract Balances

Contract assets primarily relate to the Partnership’s right to recognize revenues for services completed but not invoiced at the reporting date. Any change in Contract assets is primarily related to the transfer to Accounts receivable when the right to recognize revenue becomes unconditional and the customer is invoiced as well as when revenue increases but remains to be invoiced.

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Future revenue from remaining performance obligations

As required by the new revenue recognition guidance, the Partnership is required to provide disclosure on future revenue allocated to remaining performance obligations on our contracts with customers that have not yet been recognized. However, all of the Partnership’s contracts qualify for the use of a practical expedient listed below and therefore no disclosure on future revenues from remaining performance obligations is necessary:

1)       The original expected duration of the contract is one year or less.

2)       The Partnership recognizes revenue from the contract that is equal to the amount invoiced. This is referred to as the ‘right to invoice’ practical expedient.

3)       The variable revenue generated from the contract is allocated entirely to a wholly unsatisfied performance obligation or to a wholly unsatisfied promise to transfer a distinct good or service that forms part of a single performance obligation in a series. A single performance obligation in a series occurs when the promises under a contract are a series of distinct services that are substantially the same and have the same pattern of transfer to the customer over time.

In the application of the right to invoice practical expedient, the Partnership’s revenues from regulated capacity arrangements are recognized based on rates specified in the contract. Therefore, the amount invoiced, which includes the variable volume of natural gas transported, corresponds directly to the value the customer received. These revenues are recognized on a monthly basis once the Partnership’s performance obligation to provide capacity has been satisfied. In addition, the Partnership considers interruptible transportation service revenues to be variable revenues as volumes cannot be estimated. These variable revenues are recognized on a monthly basis when the Partnership’s performance obligation of natural gas deliveries is made at the agreed-upon delivery point.

Lastly, future revenues from the Partnership’s firm capacity contracts include fixed revenues for the time periods when current rate settlements are in effect, which is approximately one to four years. Many of these contracts are long-term in nature and revenues from the remaining performance obligations on these contracts will be recognized using the FERC approved rates once the performance obligation to provide capacity has been satisfied.

NOTE 7    DEBT AND CREDIT FACILITIES

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(a)              Fixed interest rate

(b)             Includes the PNGTS portion due at March 31, 2018 amounting to $6.1 million that was paid on April 2, 2018.

(c)              Includes the PNGTS portion due at December 31, 2017 amounting to $5.8 million that was paid on January 2, 2018.

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, under which $165 million was outstanding at March 31, 2018 (December 31, 2017 - $185 million), leaving $335 million available for future borrowing. The LIBOR-based interest rate on the Senior Credit Facility was 2.92 percent at March 31, 2018 (December 31, 2017 — 2.62 percent).

As of March 31, 2018, the variable interest rate exposure related to the 2013 Term Loan Facility was hedged by fixed interest rate swap arrangements and our effective interest rate was 2.31 percent (December 31, 2017 — 2.31 percent). Prior to hedging activities, the LIBOR-based interest rate on the 2013 Term Loan Facility was 2.92 percent at March 31, 2018 (December 31, 2017 — 2.62 percent).

The LIBOR-based interest rate on the 2015 Term Loan Facility was 2.81 percent at March 31, 2018 (December 31, 2017 — 2.51 percent).

The 2013 Term Loan Facility and the 2015 Term Loan Facility (collectively, the Term Loan Facilities) and the Senior Credit Facility require the Partnership to maintain a certain leverage ratio (debt to adjusted cash flow [net income plus cash distributions received, extraordinary losses, interest expense, expense for taxes paid or accrued, and depreciation and amortization expense less equity earnings and extraordinary gains]) no greater than 5.00 to 1.00 for each fiscal quarter, except for the fiscal quarter and the two following fiscal quarters in which one or more acquisitions has been executed, in which case the leverage ratio is to be no greater than 5.50 to 1.00. The leverage ratio was 4.56 to 1.00 as of March 31, 2018.

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, 2018 was 44 percent. The LIBOR-based interest rate on the GTN’s Unsecured Term Loan Facility was 2.61 percent at March 31, 2018 (December 31, 2017 — 2.31 percent).

PNGTS

PNGTS’ Senior Secured Notes are secured by the PNGTS long-term firm shipper contracts and its partners’ pledge of their equity and a guarantee of debt service for six months. PNGTS is restricted under the terms of its note purchase agreement from making cash distributions unless certain conditions are met. Before a distribution can be made, the debt service reserve account must be fully funded and PNGTS’ debt service coverage ratio for the preceding and succeeding twelve months must be 1.30 or greater. At March 31, 2018, the debt service coverage ratio was 1.65 for the twelve preceding months and 2.14 for the twelve succeeding months. Therefore, PNGTS was not restricted to make any cash distributions.

On April 5, 2018, PNGTS entered into a revolving credit agreement under which PNGTS has the ability to borrow up to $125 million with a variable interest rate based on LIBOR. The credit agreement matures on April 5, 2023 and requires PNGTS to maintain a leverage ratio not greater than 5.00 to 1.00. The facility will be utilized to fund the costs of the PXP expansion project, including the repayment of the existing 5.90% Senior Notes.

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, 2018, the ratio was 11.2 to 1.00.

The LIBOR-based interest rate on the Tuscarora’s Unsecured Term Loan Facility was 2.79 percent at March 31, 2018 (December 31, 2017 — 2.49 percent).

At March 31, 2018, 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 Third Amended and Restated Agreement of Limited Partnership (Partnership Agreement), incurring

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additional debt and distributions to unitholders. Refer also to Note 19 for important information relating to distribution reduction to retain cash that will be used to fund ongoing capital expenditures and the repayment of debt to levels that prudently manage our financial metrics in response to the potential negative impact of the 2018 FERC Actions on our future operating performance and cashflows.

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, 2018, we issued 0.7 million common units under our ATM program generating net proceeds of approximately $39 million, plus $1 million contributed by the General Partner to maintain its effective two percent general partner interest. The commissions to our sales agents in the three months ended March 31, 2018 were nil. The net proceeds were used for general partnership purposes.

Class B units issued to TransCanada

The Class B Units we issued on April 1, 2015 to finance a portion of the 2015 GTN Acquisition represent a limited partner interest in us and entitle TransCanada to an annual distribution based on 30 percent of GTN’s annual distributions as follows: (i) 100 percent of distributions above $20 million through March 31, 2020; and (ii) 25 percent of distributions above $20 million thereafter. Additionally, the Class B distribution will be further reduced by the percentage by which distributions payable to common units is reduced for the calendar year (Class B Reduction).

For the year ending December 31, 2018, the Class B units’ equity account will be increased by the excess of 30 percent of GTN’s distributions less the annual threshold of $20 million and the Class B Reduction and until such amount is declared for distribution and paid in the first quarter of 2019. During the three months ended March 31, 2018, the threshold was not exceeded.

For the year ended December 31, 2017, the Class B distribution was $15 million and was declared and paid in the first quarter of 2018.

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 net income attributable to PNGTS’ former parent, 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 effective 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 2018 equals 30 percent of GTN’s distributable cash flow during the year ended December 31, 2018 less $20 million and the Class B Reduction (December 31, 2017 —$20 million). During the three months ended March 31, 2018 and 2017, 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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