10-Q

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)

Delaware	52-2135448
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification Number)

700 Louisiana Street, Suite 700 Houston, Texas	77002-2761
(Address of principle executive offices)	(Zip code)

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.

Large accelerated filer x	Accelerated filer o
Non-accelerated filer o	Smaller reporting company o
	Emerging growth company o

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:

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

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

TC PIPELINES, LP

TABLE OF CONTENTS

		Page No.
PART I	FINANCIAL INFORMATION
Item 1.	Consolidated Financial Statements (Unaudited)	7
	Notes to Consolidated Financial Statements	12
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	26
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	35
Item 4.	Controls and Procedures	37
PART II	OTHER INFORMATION
Item 1.	Legal Proceedings	37
Item 1A.	Risk Factors	37
Item 6.	Exhibits	39
	Signatures	40

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:

2013 Term Loan Facility	TC PipeLines, LP’s term loan credit facility under a term loan agreement as amended, dated September 29, 2017
2017 Tax Act	Public Law No. 115-97, commonly known as the Tax Cuts and Jobs Act, enacted on December 22, 2017
2018 FERC Actions	FERC’s 2018 issuance of Revised Policy Statement on Treatment of Income Taxes (Revised Policy Statement) and a Final Rule that established a schedule by which interstate pipelines must either (i) file a new uncontested rate settlement or (ii) file a one-time report, called FERC Form No. 501-G, that quantified the rate impact of the 2017 Tax Act on FERC-regulated pipelines and the impact of the Revised Policy Statement on pipelines held by an MLP
2019 Iroquois Settlement	An uncontested settlement filed by Iroquois with FERC to address the issues contemplated by the 2017 Tax Act and 2018 FERC Actions via an amendment to its prior 2016 settlement approved by FERC on May 2, 2019
2019 Tuscarora Settlement	An uncontested settlement filed by Tuscarora with FERC to address the issues contemplated by the 2017 Tax Act and 2018 FERC Actions via an amendment to its prior 2016 settlement approved by FERC on May 2, 2019
ADIT	Accumulated Deferred Income Tax
ASC	Accounting Standards Codification
ASU	Accounting Standards Update
ATM program	At-the-market equity issuance program
Bison	Bison Pipeline LLC
Class B Distribution	Annual distribution to TC Energy based on 30 percent of GTN’s annual distributions as follows: (i) 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 Reduction	Approximately 35 percent reduction applied to the estimated annual Class B Distribution beginning in 2018, which is equivalent to the percentage by which distributions payable to the common units were reduced in 2018. The Class B Reduction will continue to apply for any particular calendar year until distributions payable in respect of common units for such calendar year equal or exceed $3.94 per common unit
Consolidated Subsidiaries	GTN, Bison, North Baja, Tuscarora and PNGTS
DOT	U.S. Department of Transportation
EBITDA	Earnings Before Interest, Tax, Depreciation and Amortization
EPA	U.S. Environmental Protection Agency
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission
GAAP	U.S. generally accepted accounting principles
General Partner	TC PipeLines GP, Inc.
Great Lakes	Great Lakes Gas Transmission Limited Partnership
GTN	Gas Transmission Northwest LLC
IDRs	Incentive Distribution Rights
ILPs	Intermediate Limited Partnerships
Iroquois	Iroquois Gas Transmission System, L.P.
LIBOR	London Interbank Offered Rate
MLPs	Master limited partnerships
NGA	Natural Gas Act of 1938
North Baja	North Baja Pipeline, LLC
Northern Border	Northern Border Pipeline Company
Our pipeline systems	Our ownership interests in GTN, Northern Border, Bison, Great Lakes, North Baja, Tuscarora, PNGTS and Iroquois
Partnership	TC PipeLines, LP including its subsidiaries, as applicable
Partnership Agreement	Fourth Amended and Restated Agreement of Limited Partnership of the Partnership
PNGTS	Portland Natural Gas Transmission System
PXP	Portland XPress Project
ROU	Right-of-use

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SEC	Securities and Exchange Commission
Senior Credit Facility	TC PipeLines, LP’s senior facility under revolving credit agreement as amended and restated, dated September 29, 2017
TC Energy	TC Energy Corporation formerly known as TransCanada Corporation
Tuscarora	Tuscarora Gas Transmission Company
U.S.	United States of America
VIEs	Variable Interest Entities
Westbrook XPress	Westbrook XPress Project of PNGTS that is part of a coordinated offering to transport incremental Western Canadian Sedimentary Basin natural gas supplies to the Northeast U.S. and Atlantic Canada markets through additional compression capability at an existing PNGTS facility
Wholly-owned subsidiaries	GTN, Bison, North Baja, and Tuscarora

Unless the context clearly indicates otherwise, TC PipeLines, LP and its subsidiaries are collectively referred to in this 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

	Three months ended
(unaudited)	March 31,
(millions of dollars, except per common unit amounts)	2019			2018
Transmission revenues	113			115
Equity earnings (Note 5)	54			59
Operation and maintenance expenses	(16		)	(16		)
Property taxes	(7		)	(7		)
General and administrative	(2		)	(1		)
Depreciation and amortization	(20		)	(24		)
Financial charges and other (Note 15)	(22		)	(23		)
Net income before taxes	100			103
Income taxes	—			(1		)
Net Income	100			102
Net income attributable to non-controlling interest	7			6
Net income attributable to controlling interests	93			96
Net income attributable to controlling interest allocation (Note 9)
Common units	91			94
General Partner	2			2
	93			96
Net income per common unit (Note 9) — basic and diluted	$	1.28		$	1.32
Weighted average common units outstanding — basic and diluted (millions)	71.3			71.2
Common units outstanding, end of period (millions)	71.3			71.3

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

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TC PIPELINES, LP

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

	Three months ended
(unaudited)	March 31,
(millions of dollars)	2019		2018
Net income	100		102
Other comprehensive income
Change in fair value of cash flow hedges (Note 13)	(5	)	7
Comprehensive income	95		109
Comprehensive income attributable to non-controlling interests	7		6
Comprehensive income attributable to controlling interests	88		103

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

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TC PIPELINES, LP

CONSOLIDATED BALANCE SHEETS

(unaudited)
(millions of dollars)	March 31, 2019	December 31, 2018
ASSETS
Current Assets
Cash and cash equivalents	52	33
Accounts receivable and other (Note 14)	41	48
Inventories	9	8
Other	5	8
	107	97
Equity investments (Note 5)	1,196	1,196
Property, plant and equipment      (Net of $1,128 accumulated depreciation; 2018 - $1,110)	1,522	1,529
Goodwill	71	71
Other assets	3	6
TOTAL ASSETS	2,899	2,899
LIABILITIES AND PARTNERS’ EQUITY
Current Liabilities
Accounts payable and accrued liabilities	29	36
Accounts payable to affiliates (Note 12)	7	6
Accrued interest	20	12
Current portion of long-term debt (Note 7)	36	36
	92	90
Long-term debt, net (Note 7)	2,040	2,072
Deferred state income taxes	9	9
Other liabilities	31	29
	2,172	2,200
Partners’ Equity
Common units	507	462
Class B units (Note 8)	95	108
General partner	14	13
Accumulated other comprehensive income (AOCI)	3	8
Controlling interests	619	591
Non-controlling interests	108	108
	727	699
TOTAL LIABILITIES AND PARTNERS’ EQUITY	2,899	2,899

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

	Three months ended
(unaudited)	March 31,
(millions of dollars)	2019		2018
Cash Generated from Operations
Net income	100		102
Depreciation and amortization	20		24
Amortization of debt issue costs reported as interest expense	—		1
Equity earnings from equity investments (Note 5)	(54	)	(59	)
Distributions received from operating activities of equity investments (Note 5)	56		43
Change in operating working capital (Note 11)	13		6
	135		117
Investing Activities
Investment in Great Lakes (Note 5)	(5	)	(4	)
Distribution received from Iroquois as return of investment (Note 5)	2		2
Capital expenditures	(16	)	(2	)
Customer advances for construction	2		—
	(17	)	(4	)
Financing Activities
Distributions paid to common units, including the general partner (Note 10)	(47	)	(76	)
Distributions paid to Class B units (Note 8)	(13	)	(15	)
Distributions paid to non-controlling interests	(7	)	(1	)
Common unit issuance, net	—		40
Long-term debt issued, net of discount (Note 7)	18		75
Long-term debt repaid (Note 7)	(50	)	(101	)
	(99	)	(78	)
Increase in cash and cash equivalents	19		35
Cash and cash equivalents, beginning of period	33		33
Cash and cash equivalents, end of period	52		68

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

10

TC PIPELINES, LP

CONSOLIDATED STATEMENT OF CHANGES IN PARTNERS’ EQUITY

	Limited Partners						General		Accumulated Other Comprehensive		Non- Controlling		Total
	Common units			Class B units			Partner		Income (a)		Interest		Equity
(unaudited)	millions of units	millions of dollars		millions of units	millions of dollars		millions of dollars		millions of dollars		millions of dollars		millions of dollars
Partners’ Equity at December 31, 2018	71.3	462		1.9	108		13		8		108		699
Net income	—	91		—	—		2		—		7		100
Other comprehensive income	—	—		—	—		—		(5	)	—		(5	)
Distributions (Note 10)	—	(46	)	—	(13	)	(1	)	—		(7	)	(67	)
Partners’ Equity at March 31, 2019	71.3	507		1.9	95		14		3		108		727

(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).

	Ownership		Equity Earnings		Equity Investments
	Interest at		Three months
(unaudited)	March 31,		ended March 31,		March 31,	December 31,
(millions of dollars)	2019		2019	2018	2019	2018
Northern Border	50	%	21	17	489	497
Great Lakes	46.45	%	20	24	498	489
Iroquois	49.34	%	13	18	209	210
			54	59	1,196	1,196

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:

(unaudited)
(millions of dollars)	March 31, 2019		December 31, 2018
ASSETS
Cash and cash equivalents	14		10
Other current assets	38		36
Property, plant and equipment, net	1,023		1,037
Other assets	13		13
	1,088		1,096
LIABILITIES AND PARTNERS’ EQUITY
Current liabilities	41		34
Deferred credits and other	35		35
Long-term debt, net (a)	264		264
Partners’ equity
Partners’ capital	749		764
Accumulated other comprehensive loss	(1	)	(1	)
	1,088		1,096

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	Three months ended
(unaudited)	March 31,
(millions of dollars)	2019		2018
Transmission revenues	81		72
Operating expenses	(20	)	(19	)
Depreciation	(15	)	(15	)
Financial charges and other	(4	)	(4	)
Net income	42		34

(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:

(unaudited)
(millions of dollars)	March 31, 2019	December 31, 2018
ASSETS
Current assets	86	75
Property, plant and equipment, net	685	689
	771	764
LIABILITIES AND PARTNERS’ EQUITY
Current liabilities	25	26
Net long-term debt, including current maturities (a)	229	240
Other long-term liabilities	4	4
Partners’ equity	513	494
	771	764

	Three months ended
(unaudited)	March 31,
(millions of dollars)	2019		2018
Transmission revenues	72		81
Operating expenses	(16	)	(17	)
Depreciation	(8	)	(8	)
Financial charges and other	(4	)	(4	)
Net income	44		52

(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:

(unaudited)
(millions of dollars)	March 31, 2019	December 31, 2018
ASSETS
Cash and cash equivalents	84	80
Other current assets	30	32
Property, plant and equipment, net	576	581
Other assets	16	8
	706	701
LIABILITIES AND PARTNERS’ EQUITY
Current liabilities	19	19
Long-term debt, net (a)	325	325
Other non-current liabilities	20	14
Partners’ equity	342	343
	706	701

	Three months ended
(unaudited)	March 31,
(millions of dollars)	2019		2018
Transmission revenues	52		60
Operating expenses	(15	)	(14	)
Depreciation	(7	)	(7	)
Financial charges and other	(3	)	(4	)
Net income	27		35

(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

(unaudited) (millions of dollars)	March 31, 2019	Weighted Average Interest Rate for the Three Months Ended March 31, 2019		December 31, 2018	Weighted Average Interest Rate for the Year Ended December 31, 2018
TC PipeLines, LP
Senior Credit Facility due 2021	—	3.61	%	40	3.14%
2013 Term Loan Facility due 2022	500	3.73	%	500	3.23%
4.65% Unsecured Senior Notes due 2021	350	4.65	%(a)	350	4.65%(a)
4.375% Unsecured Senior Notes due 2025	350	4.375	%(a)	350	4.375%(a)
3.90 % Unsecured Senior Notes due 2027	500	3.90	%(a)	500	3.90%(a)
GTN
5.29% Unsecured Senior Notes due 2020	100	5.29	%(a)	100	5.29%(a)
5.69% Unsecured Senior Notes due 2035	150	5.69	%(a)	150	5.69%(a)
Unsecured Term Loan Facility due 2019	35	3.45	%	35	2.93%
PNGTS
Revolving Credit Facility due 2023	27	3.75	%	19	3.55%
Tuscarora
Unsecured Term Loan due 2020	24	3.63	%	24	3.10%
North Baja
Unsecured Term Loan due 2021	50	3.56	%	50	3.54%
	2,086			2,118
Less: unamortized debt issuance costs and debt discount	10			10
Less: current portion	36			36
	2,040			2,072

(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:

(unaudited)
(millions of dollars)	Principal payments
2019	36
2020	123
2021	400
2022	500
2023	27
Thereafter	1,000
	2,086

NOTE 8PARTNERS’ 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 9NET 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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(unaudited)	Three months ended March 31,
(millions of dollars, except per common unit amounts)	2019			2018
Net income attributable to controlling interests	93			96
Net income attributable to the General Partner	(2		)	(2		)
Net income attributable to common units	91			94
Weighted average common units outstanding (millions) — basic and diluted	71.3			71.2
Net income per common unit — basic and diluted	$	1.28		$	1.32

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

(unaudited)	Three months ended March 31,
(millions of dollars)	2019		2018
Change in accounts receivable and other	7		—
Change in inventories	(1	)	—
Change in other current assets	2		(3	)
Change in accounts payable and accrued liabilities	(4	)	—
Change in accounts payable to affiliates	1		—
Change in accrued interest	8		9
Change in operating working capital	13		6

NOTE 12    RELATED PARTY TRANSACTIONS

The Partnership does not have any employees. The management and operating functions are provided by the General Partner. The General Partner does not receive a management fee in connection with its management of the Partnership. The Partnership reimburses the General Partner for all costs of services provided, including the costs of employee, officer and director compensation and benefits, and all other expenses necessary or appropriate to conduct the business of, and allocable to, the Partnership. Such costs include (i) overhead costs (such as office space and equipment) and (ii) out-of-pocket expenses related to the provision of such services. The Partnership Agreement provides that the General Partner will determine the costs that are allocable to the Partnership in any reasonable manner determined by the General Partner in its sole discretion. For both the three months ended March 31, 2019 and 2018, total costs charged to the Partnership by the General Partner were $1 million.

As operator of our pipelines, except Iroquois, TC Energy’s subsidiaries provide capital and operating services to our pipeline systems. TC Energy’s subsidiaries incur costs on behalf of our pipeline systems, including, but not limited to, employee salary and benefit costs, and property and liability insurance costs. Iroquois does not receive any capital and operating services from TC Energy (Refer to Note 5).

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Capital and operating costs charged to our pipeline systems, except for Iroquois, for the three months ended March 31, 2019 and 2018 by TC Energy’s subsidiaries and amounts payable to TC Energy’s subsidiaries at March 31, 2019 and December 31, 2018 are summarized in the following tables:

	Three months ended
(unaudited)	March 31,
(millions of dollars)	2019	2018
Capital and operating costs charged by TC Energy’s subsidiaries to:
Great Lakes (a)	11	9
Northern Border (a)	9	9
GTN	10	8
Bison	1	2
North Baja	1	1
Tuscarora	1	1
PNGTS (a)	2	2
Impact on the Partnership’s net income:
Great Lakes	5	4
Northern Border	4	4
GTN	8	8
Bison	1	2
North Baja	1	1
Tuscarora	1	1
PNGTS	1	1

(unaudited)
(millions of dollars)	March 31, 2019	December 31, 2018
Net amounts payable to TC Energy’s subsidiaries are as follows:
Great Lakes (a)	5	3
Northern Border (a)	4	3
GTN	4	4
Bison	—	1
North Baja	1	—
Tuscarora	—	1
PNGTS (a)	1	1

(a)Represents 100 percent of the costs.

Great Lakes

Great Lakes earns significant transportation revenues from TC Energy and its affiliates, some of which are provided at discounted rates and some at maximum recourse rates. For the three months ended March 31, 2019, Great Lakes earned 73 percent of transportation revenues from TC Energy and its affiliates (March 31, 2018 — 68 percent).

At March 31, 2019, $18 million was included in Great Lakes’ receivables with regard to the transportation contracts with TC Energy and its affiliates (December 31, 2018 — $18 million).

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

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PNGTS

PNGTS earns transportation revenues from TC Energy and its affiliates. For the three months ended March 31, 2019, PNGTS earned approximately nil of its transportation revenues from TC Energy and its affiliates (March 31, 2018 — $1 million).

At March 31, 2019, PNGTS had nil outstanding receivables with regard to the transportation contracts with TC Energy and its affiliates (December 31, 2018 — nil).

In connection with anticipated future commercial opportunities, PNGTS has entered into an arrangement with its affiliates regarding the construction of certain facilities on their systems that will be required to fulfill future contracts on the PNGTS system. In the event the anticipated developments do not proceed, PNGTS will be required to reimburse its affiliates for any costs incurred related to the development of these facilities. At March 31, 2019, the total costs incurred by these affiliates was approximately $71 million.

NOTE 13    FAIR VALUE MEASUREMENTS

(a) Fair Value Hierarchy

Under Accounting Standards Codification (ASC) 820, Fair Value Measurements and Disclosures, fair value measurements are characterized in one of three levels based upon the inputs used to arrive at the measurement. The three levels of the fair value hierarchy are as follows:

·Level 1 inputs are quoted prices (unadjusted) in active markets for identical assets or liabilities that we have the ability to access at the measurement date.

·Level 2 inputs are inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly.

·Level 3 inputs are unobservable inputs for the asset or liability.

When appropriate, valuations are adjusted for various factors including credit considerations. Such adjustments are generally based on available market evidence. In the absence of such evidence, management’s best estimate is used.

(b) Fair Value of Financial Instruments

The carrying value of “cash and cash equivalents”, “accounts receivable and other”, “accounts payable and accrued liabilities”, “accounts payable to affiliates” and “accrued interest” approximate their fair values because of the short maturity or duration of these instruments, or because the instruments bear a variable rate of interest or a rate that approximates current rates. The fair value of the Partnership’s debt is estimated by discounting the future cash flows of each instrument at estimated current borrowing rates. The fair value of interest rate derivatives is calculated using the income approach, which uses period-end market rates and applies a discounted cash flow valuation model.

The Partnership has classified the fair value of natural gas imbalances as a Level 2 of the fair value hierarchy for fair value disclosure purposes, as the valuation approach includes quoted prices in the market index and observable volumes for the imbalance.

Long-term debt is recorded at amortized cost and classified as Level 2 of the fair value hierarchy for fair value disclosure purposes. Interest rate derivative assets and liabilities are classified as Level 2 for all periods presented where the fair value is determined by using valuation techniques that refer to observable market data or estimated market prices.  The estimated fair value of the Partnership’s debt as at March 31, 2019 and December 31, 2018 was $2,119 million and $2,101 million, respectively.

Market risk is the risk that changes in market interest rates may result in fluctuations in the fair values or cash flows of financial instruments. The Partnership’s floating rate debt is subject to LIBOR benchmark interest rate risk. The Partnership uses derivatives to manage its exposure to interest rate risk. We regularly assess the impact of interest rate fluctuations on future cash flows and evaluate hedging opportunities to mitigate our interest rate risk.

The Partnership’s interest rate swaps mature on October 2, 2022 and are structured such that the cash flows of the derivative instruments match those of the variable rate of interest on the 2013 Term Loan Facility. The fixed weighted average interest rate on these instruments is 3.26 percent.

At March 31, 2019, the fair value of the interest rate swaps accounted for as cash flow hedges was an asset of $3 million (both on a gross and net basis) (December 31, 2018 — asset of $8 million).

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The change in fair value of interest rate derivative instruments recognized in other comprehensive income was a loss of $5 million for the three months ended March 31, 2019 (March 31, 2018 — gain of $7 million). For the three months ended March 31, 2019, the net realized gain related to the interest rate swaps was $1 million, and was included in “financial charges and other” (March 31, 2018 — gain of $1 million) (Refer to Note 15).

The Partnership has no master netting agreements; however, it has derivative contracts containing provisions with rights of offset. The Partnership has elected to present the fair value of derivative instruments with the right to offset on a gross basis in the consolidated balance sheet. Had the Partnership elected to present these instruments on a net basis, there would be no effect on the consolidated balance sheet as of March 31, 2019 and December 31, 2018.

NOTE 14    ACCOUNTS RECEIVABLE AND OTHER

(unaudited)
(millions of dollars)	March 31, 2019	December 31, 2018
Trade accounts receivable, net of allowance of nil	35	44
Imbalance receivable from affiliates	4	2
Other	2	2
	41	48

NOTE 15    FINANCIAL CHARGES AND OTHER

	Three months ended
(unaudited)	March 31,
(millions of dollars)	2019		2018
Interest expense (a)	23		24
Net realized gain related to the interest rate swaps	(1	)	(1	)
	22		23

(a)Includes amortization of debt issuance costs and discount costs.

NOTE 16    VARIABLE INTEREST ENTITIES

In the normal course of business, the Partnership must re-evaluate its legal entities under the current consolidation guidance to determine if those that are considered to be VIEs are appropriately consolidated or if they should be accounted for under other GAAP. A VIE is a legal entity that does not have sufficient equity at risk to finance its activities without additional subordinated financial support or is structured such that equity investors lack the ability to make significant decisions relating to the entity’s operations through voting rights or do not substantively participate in the gains or losses of the entity. A VIE is appropriately consolidated if the Partnership is considered to be the primary beneficiary. The VIE’s primary beneficiary is the entity that has both (1) the power to direct the activities of the VIE that most significantly impact the VIEs economic performance and (2) the obligation to absorb losses or the right to receive benefits from the VIE that could potentially be significant to the VIE.

As a result of its analysis, the Partnership continues to consolidate all legal entities in which it has a variable interest and for which it is considered to be the primary beneficiary. VIEs where the Partnership is not the primary beneficiary, but has a variable interest in the entity, are accounted for as equity investments.

Consolidated VIEs

The Partnership’s consolidated VIEs consist of the intermediate partnerships and mainly the Partnership’s ILPs that hold interests in the Partnership’s pipeline systems. After considering the purpose and design of the ILPs and the risks that they were designed to create and pass through to the Partnership, the Partnership has concluded that it is the primary beneficiary of these ILPs because of the significant amount of variability it absorbs from the ILPs’ economic performance.

The assets and liabilities held through these VIEs that are not available to creditors of the Partnership and whose investors have no recourse to the credit of the Partnership are held through GTN, Tuscarora, Northern Border, Great Lakes, PNGTS, Iroquois

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and North Baja due to their third-party debt. The following table presents the total assets and liabilities of these entities that are included in the Partnership’s consolidated balance sheets:

(unaudited)
(millions of dollars)	March 31, 2019		December 31, 2018
ASSETS (LIABILITIES) (a)
Cash and cash equivalents	25		16
Accounts receivable and other	37		39
Inventories	9		8
Other current assets	5		6
Equity investments	1,196		1,196
Property, plant and equipment, net	1,237		1,240
Other assets	1		1
Accounts payable and accrued liabilities	(26	)	(33	)
Accounts payable to affiliates, net	(38	)	(40	)
Accrued interest	(5	)	(2	)
Current portion of long-term debt	(36	)	(36	)
Long-term debt	(349	)	(341	)
Other liabilities	(28	)	(27	)
Deferred state income tax	(9	)	(9	)

(a)Bison, an asset held through our consolidated VIEs, is excluded at March 31, 2019 and at December 31, 2018 as the assets of this entity can be used for purposes other than the settlement of the VIE’s obligations.

NOTE 17    SUBSEQUENT EVENTS

Management of the Partnership has reviewed subsequent events through May 8, 2019, the date the consolidated financial statements were issued, and concluded there were no events or transactions during this period that would require recognition or disclosure in the consolidated financial statements other than what is disclosed here and/or those already disclosed in the preceding notes.

On April 23, 2019, the board of directors of the General Partner declared the Partnership’s first quarter 2019 cash distribution in the amount of $0.65 per common unit payable on May 13, 2019 to unitholders of record as of May 3, 2019. The declared distribution totaled $47 million and is payable in the following manner: $46 million to common unitholders (including $4 million to the General Partner as a holder of 5,797,106 common units and $7 million to another subsidiary of TC Energy as holder of 11,287,725 common units) and $1 million to the General Partner for its two percent general partner interest. The General Partner did not receive any distributions in respect of its IDRs for the first quarter 2019.

Northern Border declared its March 2019 distribution of $15 million on April 9, 2019, of which the Partnership received its 50 percent share or $7 million on April 30, 2019.

Great Lakes declared its first quarter 2019 distribution of $49 million on April 16, 2019, of which the Partnership received its 46.45 percent share or $23 million on May 1, 2019.

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 $14 million includes our proportionate share of Iroquois’ unrestricted cash amounting to $2 million (refer to Note 5).

PNGTS declared its first quarter 2019 distribution of $19 million on April 9, 2019, of which $7 million was paid to its non-controlling interest owner on April 30, 2019.

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Item 2.   Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis should be read in conjunction with the unaudited consolidated financial statements and notes included in Item 1. “Financial Statements” of this Quarterly Report on Form 10-Q, as well as our Annual Report on Form 10-K for the year ended December 31, 2018.

RECENT BUSINESS DEVELOPMENTS

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

2018 FERC Actions Updates:

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 the 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. 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 by 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. 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 rate changes until January 31, 2023. The 2019 Tuscarora Settlement, which was approved by FERC on May 2, 2019, will also reflect an elimination of the tax allowance previously recovered in rates along with ADIT for rate-making purposes.

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 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.

Growth Projects:

North Baja XPress Project (North Baja XPress) - North Baja XPress is an estimated $90 million project to transport additional volumes of natural gas along North Baja’s mainline system. The project was initiated in response to market demand to provide firm transportation service of up to approximately 495,000 Dth/day between Ehrenberg, Arizona and Ogilby, California. The binding open season for the project was concluded in April of 2019 and the estimated in-service date is February 1, 2023, subject to the satisfaction or waiver of certain conditions precedent.

Westbrook XPress Project (Westbrook XPress) - In addition to Phases 1 and 2 of the Westbrook XPress project as disclosed in our Annual Report of the Form 10-K for the year ended December 31, 2018, we have now signed precedent agreements with certain shippers that will result in a Phase 3 expansion for an additional 18,000 Dth/day. Westbrook XPress is an estimated $100 million multi-phase expansion project that is expected to generate approximately $35 million in revenue for PNGTS on an annualized basis when fully in service. It is part of a coordinated offering to transport incremental Western Canadian Sedimentary Basin natural gas supplies to the Northeast U.S. and Atlantic Canada markets through additional compression capability at an existing PNGTS facility. Westbrook XPress is designed to be phased in over a four-year period with Phases 1, 2 and 3 estimated in-service dates of November 2019, 2021, and 2022, respectively. These three Phases will add incremental

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capacity of approximately 43,000 Dth/day, 63,000 Dth/day, and 18,000 Dth/day respectively. Westbrook XPress, together with Portland XPress, will increase PNGTS’ capacity by approximately 90 percent from 210,000 Dth/day to almost 400,000 Dth/day.

HOW WE EVALUATE OUR OPERATIONS

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

EBITDA

We use EBITDA as a proxy of our operating cash flow and current operating profitability.

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 and Distributable Cash Flow” for more information.

RESULTS OF OPERATIONS

Our ownership interests in eight pipelines were our only material sources of income during the period. Therefore, our results of operations and cash flows were influenced by, and reflect the same factors that influenced, our pipeline systems.

	Three months ended
(unaudited)	March 31,				$		%
(millions of dollars)	2019		2018		Change (a)		Change (a)
Transmission revenues	113		115		(2	)	(2	)
Equity earnings	54		59		(5	)	(8	)
Operating, maintenance and administrative costs	(25	)	(24	)	(1	)	(4	)
Depreciation	(20	)	(24	)	4		17
Financial charges and other	(22	)	(23	)	1		4
Net income before taxes	100		103		(3	)	(3	)
State income taxes	—		(1	)	1		100
Net Income	100		102		(2	)	(2	)
Net income attributable to non-controlling interests	7		6		(1	)	(17	)
Net income attributable to controlling interests	93		96		(3	)	(3	)

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

Three Months Ended March 31, 2019 compared to Same Period in 2018

The Partnership’s net income attributable to controlling interests decreased by $3 million in the three months ended March 31, 2019 compared to 2018, mainly due to the following:

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Transmission revenues — Revenues were lower due largely to the decrease in revenue from Bison. During the fourth quarter of 2018, two of Bison’s customers elected to pay out the remainder of their contracted obligations on Bison and terminate the associated transportation agreements.  The decrease was offset by the following:

·increased contracting from GTN, partially offset by its scheduled 10 percent rate decrease effective January 1, 2019 as part of the settlement reached with its customers in 2018; and

·additional revenue from PNGTS from Phase 1 of its Portland XPress (PXP) project that went into service November 1, 2018.

Equity Earnings - The $5 million decrease was primarily due to the net effect of the following:

·decrease in Iroquois’ and Great Lakes’ equity earnings during the first quarter of 2019 compared to the first quarter of 2018, during which sustained cold temperatures resulted in incremental seasonal winter sales that were not achieved in the same period of 2019; and

·higher earnings from Northern Border resulting from an increase in its short-term firm services, partially offset by its scheduled rate reduction that became effective April 1, 2018.

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

Financial charges and other - The $1 million decrease was primarily attributable to the repayment of our $170 million Term Loan during the fourth quarter of 2018 and repayment of our Senior Credit Facility during the first quarter of 2019.

Net income attributable to non-controlling interests - The Partnership’s net income attributable to non-controlling interests was higher in the first quarter of 2019 than the first quarter of 2018 due to the increase in revenue earned on PNGTS as described above.

Net Income Attributable to Common Units and Net Income per Common Unit

As discussed in Note 9 within Item 1. “Financial Statements,” we will allocate a portion of the Partnership’s income to the Class B units after the annual threshold is exceeded which will effectively reduce the income allocable to the common units and net income per common unit. Currently, we expect to allocate a portion of the Partnership’s income to the Class B units at the end of the fourth quarter of 2019. Please also read Note 8 within Item 1. “Financial Statements,” for additional disclosures on the Class B units.

LIQUIDITY AND CAPITAL RESOURCES

Overview

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

At March 31, 2019, the balance of our cash and cash equivalents was higher than our position at December 31, 2018 by approximately $19 million and our long-term debt balance was lower by $32 million. We continue to use available cash to fund ongoing capital expenditures and the repayment of debt to levels that prudently manage our financial metrics.

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

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

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

The principal sources of liquidity on our pipeline systems are cash generated from operating activities, long-term debt offerings, bank credit facilities and equity contributions from their owners. Our pipeline systems have historically funded operating expenses, debt service and cash distributions to their owners primarily with operating cash flow. However, since the fourth quarter of 2010, Great Lakes has funded its debt repayments with cash calls to its owners.

Capital expenditures of our pipeline systems are funded by a variety of sources, including cash generated from operating activities, borrowings under bank credit facilities, issuance of senior unsecured notes or equity contributions from our pipeline systems’ owners. The ability of our pipeline systems to access the debt capital markets under reasonable terms depends on their financial position and general market conditions.

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

Cash Flow Analysis for the Three Months Ended March 31, 2019 compared to Same Period in 2018

	Three months ended
(unaudited)	March 31,
(millions of dollars)	2019		2018
Net cash provided by (used in):
Operating activities	135		117
Investing activities	(17	)	(4	)
Financing activities	(99	)	(78	)
Net increase in cash and cash equivalents	19		35
Cash and cash equivalents at beginning of the period	33		33
Cash and cash equivalents at end of the period	52		68

Operating Cash Flows

The Partnership’s net cash provided by operating activities increased by $18 million in the three months ended March 31, 2019 compared to the same period in 2018 primarily due to the net effect of:

·lower net cash flow from operations of our subsidiaries primarily due to the decrease in Bison’s revenue partially offset by an increase in GTN’s and PNGTS’ revenue;

·lower interest expense attributable to repayment of the $170 million Term Loan and the Senior Credit Facility;

·higher distributions received from our equity investment in Northern Border as a result of its increased revenue; and

·lower distributions received from our equity investment in Great Lakes due to lower revenue from seasonal winter sales.

Investing Cash Flows

Net cash used in investing activities increased by $13 million in the three months ended March 31, 2019 compared to the same period in 2018 primarily due to our consolidated subsidiaries’ higher capital maintenance expenditures in 2019 and continued capital spending on our PXP project.

Financing Cash Flows

The Partnership’s net cash used for financing activities was approximately $21 million higher in the three months ended March 31, 2019 compared to the same period in 2018 primarily due to the net effect of:

·$6 million increase in net debt repayments;

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·$29 million decrease in distributions paid primarily due to the $0.35 per common unit reduction in distribution payments during the first quarter of 2019 related to performance during the fourth quarter of 2018 as compared to the same period in 2018 in response to the 2018 FERC Actions;

·$2 million decrease in distributions paid to Class B units in 2019 as compared to 2018;

·$40 million decrease in our ATM equity issuances in the first quarter of 2019 as compared to the same period in 2018; and

·$6 million increase in distributions paid to non-controlling interests during the three months ended March 31, 2019 compared to the three months ended March 31, 2018 resulting from PNGTS’ higher revenue in the fourth quarter of 2018 compared to its revenue in the fourth quarter of 2017.

Short-Term Cash Flow Outlook

Operating Cash Flow Outlook

Northern Border declared its March 2019 distribution of $15 million on April 9, 2019, of which the Partnership received its 50 percent share or $7 million. The distribution was paid on April 30, 2019.

Great Lakes declared its first quarter 2019 distribution of $49 million on April 16, 2019, of which the Partnership received its 46.45 percent share or $23 million. The distribution was paid on May 1, 2019.

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.

Investing Cash Flow Outlook

The Partnership made an equity contribution to Great Lakes of $5 million in the first quarter of 2019. 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 expects to make an additional $5 million equity contribution to Great Lakes in the fourth quarter of 2019 to further fund debt repayments. This is consistent with prior years.

Our equity investee Iroquois has $6 million of scheduled debt repayments for the remainder of 2019 and Iroquois’ debt repayments are expected to be funded through a combination of cash flow from operations and debt refinancing.

Our consolidated entities have commitments of $17 million as of March 31, 2019 in connection with various maintenance and general plant projects.

In 2019, our pipeline systems expect to invest approximately $107 million in maintenance of existing facilities and approximately $32 million in growth projects, of which the Partnership’s share would be $82 million and $18 million, respectively.

Financing Cash Flow Outlook

On April 23, 2019, the board of directors of our General Partner declared the Partnership’s first quarter 2019 cash distribution in the amount of $0.65 per common unit payable on May 13, 2019 to unitholders of record as of May 3, 2019.  Please see Note 17 of the “Financial Statements” within Item 1 and “Recent Business Developments” within Item 2 and for additional disclosures.

Non-GAAP Financial Measures: 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. It measures our earnings before deducting interest, depreciation and amortization, taxes, net income attributable to non-controlling interests, and includes earnings from our equity investments.

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 amounts presented.

Total distributable cash flow includes EBITDA plus:

·Distributions from our equity investments

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less:

·Earnings from our equity investments,

·Equity allowance for funds used during construction (if any),

·Interest expense,

·Income taxes,

·Distributions to non-controlling interests, and

·Maintenance capital expenditures from consolidated subsidiaries.

Distributable cash flow is computed net of distributions declared to the General Partner and any distributions allocable to Class B units. Distributions declared to the General Partner are based on its two percent interest plus, if applicable, an amount equal to incentive distributions. Distributions allocable to the Class B units in 2019 equal 30 percent of GTN’s distributable cash flow less $20 million and the Class B Reduction.

Distributable cash flow and 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 generating capacity.

The non-GAAP financial 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 results prepared in accordance with GAAP. Additionally, these measures as presented may not be comparable to similarly titled measures of other companies.

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Reconciliations of Net Income to EBITDA and Distributable Cash Flow

The following table represents a reconciliation of the non-GAAP financial measures of EBITDA, total distributable cash flow and distributable cash flow, to the most directly comparable GAAP financial measure of Net Income:

	Three months ended
(unaudited)	March 31,
(millions of dollars)	2019		2018
Net income	100		102
Add:
Interest expense (a)	22		23
Depreciation and amortization	20		24
Income taxes	—		1
EBITDA	142		150
Add:
Distributions from equity investments (b) (e)
Northern Border	27		19
Great Lakes	23		26
Iroquois (c)	14		14
	64		59
Less:
Equity earnings:
Northern Border	(21	)	(17	)
Great Lakes	(20	)	(24	)
Iroquois	(13	)	(18	)
	(54	)	(59	)
Less:
Interest expense (a)	(22	)	(23	)
Income taxes	—		(1	)
Distributions to non-controlling interest (d)	(7	)	(7	)
Maintenance capital expenditures (e)	(6	)	(6	)
	(35	)	(37	)
Total Distributable Cash Flow	117		113
General Partner distributions declared (f)	(1	)	(1	)
Distributions allocable to Class B units (g)	—		—
Distributable Cash Flow	116		112

(a)Interest expense as presented includes net realized loss or gain related to the interest rate swaps.

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

(c)This amount represents our proportional 49.34 percent share of the distribution declared by our equity investee, Iroquois, for the current reporting period and includes our 49.34 percent share of the Iroquois unrestricted cash distribution amounting to approximately $2 million for the three months ended March 31, 2019 and 2018.

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

(e)The Partnership’s maintenance capital expenditures include expenditures made to maintain, over the long term, the operating capacity, system integrity and reliability of our pipeline assets. 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 for 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.

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(f)No incentive distributions were declared to the General Partner for both the three months ended March 31, 2019 and 2018.

(g)For the three months ended March 31, 2019, 30 percent of GTN’s total distributions amounted to $12 million (March 31, 2018 - $10 million); therefore, no distributions were allocated to the Class B units as the 2019 threshold was not exceeded. We expect the 2019 threshold will be exceeded during the fourth quarter of 2019. Please read Notes 8 and 9 within Item 1. “Financial Statements” for additional disclosures on the Class B units.

Three months ended March 31, 2019 Compared to Same Period in 2018

Our EBITDA was lower for the first quarter of 2019 compared to the same period in 2018. The $8 million decrease was due to lower revenue and equity earnings during the period as discussed in more detail under the “Results of Operations” section.

However, our distributable cash flow increased by $4 million in the first quarter of 2019 compared to the same period in 2018 due to the net effect of:

·higher distributions from our equity investment in Northern Border due to the increase in revenue previously described in “Results of Operations” section and timing of capital spending related to compressor station maintenance costs;

·lower distributions from our equity investment in Great Lakes primarily due to the decrease in its revenue as explained in the “Results of Operations” section; and

·decreased interest expense due to repayment of the $170 million Term Loan during the fourth quarter of 2018 and the repayment of the Senior Credit Facility in the first quarter of 2019.

Contractual Obligations

The Partnership’s Contractual Obligations

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

	Payments Due by Period
(unaudited) (millions of dollars)	Total	Less than 1 Year	1-3 Years	4-5 Years	More than 5 Years	Weighted Average Interest Rate for the Three Months Ended March 31, 2019
TC PipeLines, LP
Senior Credit Facility due 2021	—	—	—	—	—	3.61%
2013 Term Loan Facility due 2022	500	—	—	500	—	3.73%
4.65% Senior Notes due 2021	350	—	350	—	—	4.65%(a)
4.375% Senior Notes due 2025	350	—	—	—	350	4.375%(a)
3.90% Senior Notes due 2027	500	—	—	—	500	3.90%(a)
GTN
5.29% Unsecured Senior Notes due 2020	100	—	100	—	—	5.29%(a)
5.69% Unsecured Senior Notes due 2035	150	—	—	—	150	5.69%(a)
Unsecured Term Loan Facility due 2019	35	35	—	—	—	3.45%
PNGTS
Revolving Credit Facility due 2023	27	—	—	27	—	3.75%
North Baja
Unsecured Term Loan due 2021	50	—	50	—	—	3.56%
Tuscarora
Unsecured Term Loan due 2020	24	1	23	—	—	3.63%
Partnership (TC PipeLines, LP and its subsidiaries)
Interest on Debt Obligations(b)	514	84	151	101	178
Operating Leases	1	—	1	—	—
Right of way Commitments	4	1	—	1	2
	2,605	121	675	629	1,180

(a)Fixed interest rate.

(b)Future interest payments on our fixed rate debt are based on scheduled maturities. Future interest payments on floating rate debt are estimated using debt levels and interest rates at March 31, 2019 and are therefore subject to change beyond 2019.

The Partnership’s long-term debt results in exposures to changing interest rates. The Partnership uses derivatives to assist in managing its exposure to interest rate risk. Refer to Item 3. “Quantitative and Qualitative Disclosures About Market Risk” for additional information regarding our derivatives.

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The fair value of the Partnership’s long-term debt is estimated by discounting the future cash flows of each instrument at estimated current borrowing rates. The estimated fair value of the Partnership’s debt at March 31, 2019 was $2,119 million.

Please read Note 7 within Item 1. “Financial Statements” for additional information regarding the Partnership’s debt.

Summary of Northern Border’s Contractual Obligations

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

	Payments Due by Period (a)
(unaudited) (millions of dollars)	Total	Less than 1 Year	1-3 Years	4-5 Years	More than 5 Years	Weighted Average Interest Rate for the Three Months Ended March 31, 2019
$200 million Credit Agreement due 2020	15	—	15	—	—	3.57%
7.50% Senior Notes due 2021	250	—	250	—	—	7.50%(b)
Interest payments on debt (c)	50	20	30	—	—
Right of way commitments	47	2	5	5	35
	362	22	300	5	35

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

(b)    Fixed interest rate.

(c)    Future interest payments on our fixed rate debt are based on scheduled maturities. Future interest payments on floating rate debt are estimated using debt levels and interest rates at March 31, 2019 and are therefore subject to change beyond 2019.

As of March 31, 2019, $15 million was outstanding under Northern Border’s $200 million revolving credit agreement, leaving $185 million available for future borrowings. At March 31, 2019, Northern Border was in compliance with all of its financial covenants.

Northern Border has commitments of $6 million as of March 31, 2019 in connection with compressor station overhaul project and other capital projects.

Summary of Great Lakes’ Contractual Obligations

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

	Payments Due by Period (a)
(unaudited) (millions of dollars)	Total	Less than 1 Year	1-3 Years	4-5 Years	More than 5 Years	Weighted Average Interest Rate for the Three Months Ended March 31, 2019
9.09% series Senior Notes due 2019 to 2021	30	10	20	—	—	9.09%(b)
6.95% series Senior Notes due 2020 to 2028	99	11	22	22	44	6.95%(b)
8.08% series Senior Notes due 2021 to 2030	100	—	20	20	60	8.08%(b)
Interest payments on debt	93	18	29	21	25
Right of way commitments	1	—	—	—	1
	323	39	91	63	130

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

(b)   Fixed interest rate.

Great Lakes is required to comply with certain financial, operational and legal covenants. Under the most restrictive covenants in the senior note agreements, approximately $123 million of Great Lakes’ partners’ capital was restricted as to distributions as of March 31, 2019 (December 31, 2018 — $129 million). Great Lakes was in compliance with all of its financial covenants at March 31, 2019.

Great Lakes has commitments of $6 million as of March 31, 2019 in connection with pipeline integrity program spending, major overhaul projects, and right of way renewals.

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Summary of Iroquois’ Contractual Obligations

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

	Payments Due by Period (a)
(unaudited) (millions of dollars)	Total	Less than 1 Year	1-3 Years	4-5 Years	More than 5 Years	Weighted Average Interest Rate for the Three Months Ended March 31, 2019
6.63% series Senior Notes due 2019	140	140	—	—	—	6.63%(b)
4.84% series Senior Notes due 2020	150	—	150	—	—	4.84%(b)
6.10% series Senior Notes due 2027	35	6	7	8	14	6.10%(b)
Interest payments on debt	24	13	7	2	2
Transportation by others (b)	11	3	6	2	—
Operating leases	5	1	2	—	2
Pension contributions (c)	1	1	—	—	—
	366	164	172	12	18

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

(b) Fixed interest rate.

(c) Pension contributions cannot be reasonably estimated by Iroquois beyond 2019.

Iroquois has commitments of $3 million as of March 31, 2019 related to procurement of materials on its expansion project.

Iroquois is restricted under the terms of its note purchase agreement from making cash distributions to its partners unless certain conditions are met. Before a distribution can be made, the debt/capitalization ratio must be below 75 percent and, the debt service coverage ratio must be at least 1.25 times for the four preceding quarters. At March 31, 2019, the debt/capitalization ratio was 48.7 percent and the debt service coverage ratio was 5.6 times, therefore, Iroquois was not restricted from making any cash distributions.

RELATED PARTY TRANSACTIONS

Please read Note 12 within Item 1. “Financial Statements” for information regarding related party transactions.

Item 3.Quantitative and Qualitative Disclosures About Market Risk

OVERVIEW

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

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

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

MARKET RISK

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

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

As of March 31, 2019, the Partnership’s interest rate exposure resulted from our floating rate on GTN’s Unsecured Term Loan Facility, North Baja’s Unsecured Term Loan Facility, PNGTS’s Revolving Credit Facility and Tuscarora’s Unsecured Term Loan Facility, under which $136 million, or 7 percent, of our outstanding debt was subject to variability in LIBOR interest rates (December 31, 2018- $168 million or 8 percent).

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

As of March 31, 2019, $15 million, or 6 percent, of Northern Border’s outstanding debt was at floating rates. If interest rates hypothetically increased (decreased) by one percent (100 basis points), compared with rates in effect at March 31, 2019, Northern Border’s annual interest expense would increase (decrease) and its net income would decrease (increase) by approximately nil million.

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

The Partnership and our pipeline systems use derivatives as part of our overall risk management policy to assist in managing exposures to market risk resulting from these activities within established policies and procedures. We do not enter into derivatives for speculative purposes. Derivative contracts used to manage market risk generally consist of the following:

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

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

The Partnership’s interest rate swaps mature on October 2, 2022 and are structured such that the cash flows of the derivative instruments match those of the variable rate of interest on the 2013 Term Loan Facility. The fixed weighted average interest rate on these instruments is 3.26 percent.

At March 31, 2019, the fair value of the interest rate swaps accounted for as cash flow hedges was an asset of $3 million (both on a gross and net basis) (December 31, 2018 — asset of $8 million). The change in fair value of interest rate derivative instruments recognized in other comprehensive income was a loss of $5 million for the three months ended March 31, 2019 (March 31, 2018 — gain of $7 million). For the three months ended March 31, 2019, the net realized gain related to the interest rate swaps was $1 million, and was included in financial charges and other (March 31, 2018 — gain of $1 million).

The Partnership has no master netting agreements; however, it has derivative contracts containing provisions with rights of offset. The Partnership has elected to present the fair value of derivative instruments with the right to offset on a gross basis in the consolidated balance sheet. Had the Partnership elected to present these instruments on a net basis, there would be no effect on the consolidated balance sheet as of March 31, 2019 and December 31, 2018.

COMMODITY PRICE RISK

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

COUNTERPARTY CREDIT RISK AND LIQUIDITY RISK

Counterparty credit risk represents the financial loss that the Partnership and our pipeline systems would experience if a counterparty to a financial instrument failed to meet its obligations in accordance with the terms and conditions of the financial instruments with the Partnership or its pipeline systems. The Partnership and our pipeline systems have significant credit exposure to financial institutions as they provide committed credit lines and critical liquidity in the interest rate derivative market, as well as letters of credit to mitigate exposures to non-creditworthy customers. The Partnership closely monitors the

36

creditworthiness of our counterparties, including financial institutions. However, we cannot predict to what extent our business would be impacted by uncertainty in energy commodity prices, including possible declines in our customers’ creditworthiness.

Our maximum counterparty credit exposure with respect to financial instruments at the consolidated balance sheet date consists primarily of the carrying amount, which approximates fair value, of non-derivative financial assets, such as accounts receivable as well as the fair value of derivative financial assets. We review our accounts receivable regularly and record allowances for doubtful accounts using the specific identification method. At March 31, 2019, we had not incurred any significant credit losses and had no significant amounts past due or impaired. Additionally, during the three months ended March 31, 2019 and at March 31, 2019, no customer accounted for more than 10 percent of our consolidated revenue and accounts receivable, respectively.

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

Item 4.      Controls and Procedures

EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES

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

Changes in Internal Control Over Financial Reporting

During the quarter ended March 31, 2019, there was no change in the Partnership’s internal control over financial reporting that has materially affected or is reasonably likely to materially affect our internal control over financial reporting.

PART II — OTHER INFORMATION

Item 1.      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. For additional information on other legal and environmental proceedings affecting the Partnership, please refer to Part 1 - Item 3 of the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2018.

Item 1A.   Risk Factors

The following updated risk factors should be read in conjunction with the risk factors disclosed in Part I, Item 1A. “Risk Factors,” in our Annual Report on Form 10-K for the year ended December 31, 2018.

We do not own the majority of the land on which our pipeline systems are located, which could result in higher costs and disruptions to our operations, particularly with respect to easements and rights-of-way across Indian tribal lands.

We do not own the majority of the land on which our pipeline systems are located.  We obtain easements, rights-of-way and other rights to construct and operate our pipeline systems from individual landowners, Native American tribes, governmental authorities and other third parties. Some of these rights expire after a specified period of time.  As a result, we are subject to the

37

possibility of more onerous terms and increased costs to renew expiring easements, rights-of-way and other land use rights. While we are generally able to obtain these rights through agreement with land owners or legal process if necessary, rights-of-way across Indian tribal land require approval of the applicable tribal governing authority and the Bureau of Indian Affairs.  If efforts to retain existing land use rights on tribal land at a reasonable cost are unsuccessful, our pipeline systems could also be subject to a disruption of operations and increased costs to re-route the applicable portion of our pipeline system located on tribal land.  Increased costs associated with renewing or obtaining new easements or rights-of-way and any disruption of operations could negatively impact the results of operations and cash available for distribution from our pipeline systems.

Our Great Lakes pipeline system had rights-of-way that expired during the second quarter of 2018 on approximately 7.6 miles of pipeline across tribal land located within the Fond du Lac Reservation and Leech Lake Reservation in Minnesota and the Bad River Reservation in Wisconsin. We are negotiating to renew the rights-of-way with the tribal authorities and expect to continue operating the Great Lakes pipeline while continuing good faith negotiations with the tribal authorities to obtain the necessary rights.  On April 1, 2019, Great Lakes received notice from the Fond du Lac Tribal Chairman to immediately cease operations of the Great Lakes pipeline and begin the process of removing all infrastructure from the tribal land. Great Lakes has responded in an effort to negotiate a mutually acceptable renewal agreement.  If discussions with any of the three tribes ultimately are unsuccessful or the cost of renewal is significantly high, we could be required or choose to remove and relocate a portion or portions of the Great Lakes pipeline system from the tribal lands at a significant cost. While the outcome of these negotiations or the ability to reach agreements is uncertain, the impact of a disruption of operations and cost of relocating a portion of the Great Lakes pipeline or significantly increased costs to renew the rights-of-way could have a material adverse effect on our financial condition, results of operations and cash flows.

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

GTN identified the presence of a chemical substance, dithiazine, at several facilities on the GTN system and those of some upstream and downstream connecting pipeline facilities. Dithiazine is a byproduct of triazine which is liquid chemical scavenger known to be used in natural gas processing to remove hydrogen sulfide from natural gas. It has been determined that dithiazine may drop out of gas streams, under certain conditions, in a powdery form at some points of pressure reduction (for example, at a regulator). In incidents where a sufficient quantity of the material accumulates in certain appurtenances, improper functioning of equipment can occur resulting in increased preventative and corrective action costs.

While we believe that the presence of dithiazine on our pipeline systems is from upstream sourced gas, we have advised stakeholders of potential risks, mitigation efforts and safety measures. We are following appropriate inspection and maintenance protocols to minimize any safety issues to people, equipment or the environment on our pipeline system. At least one over pressure incident potentially related to dithiazine has been reported on the customer’s system and is currently being investigated by GTN and the customer. Until more information is gathered, we cannot speculate on the impact to customers, some of which may not have adequate overpressure protection. Additionally, our pipeline systems are also working with customers, and other stakeholders, gathering information on the substance, seeking potential options to address the issue, and have informed federal and state regulators, trade associations, and other stakeholders of this information.  Additionally, we are currently evaluating interim and long-term solutions to address the presence of dithiazine and, at this time, GTN continues to make capital expenditures to address the matter. In 2018, we incurred capital expenditures of approximately $5 million and, unless the issue is resolved, we expect to spend approximately $10 million in 2019 and 2020 ($5 million per year) to further mitigate the matter. There can be no assurance that significant additional costs will not be incurred in the future or that dithiazine or other substances will not be identified on our other pipeline systems.

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Item 6.      Exhibits

Exhibits designated by an asterisk (*) are filed herewith and those designated with asterisks (**) are furnished herewith; all exhibits not so designated are incorporated herein by reference to a prior filing as indicated.

3.1	Certificate of Limited Partnership of TC PipeLines, LP (Incorporated by reference to Exhibit 3.2 to TC PipeLines, LP’s Form S-1 Registration Statement, filed on December 30, 1998).
3.2	Fourth Amended and Restated Agreement of Limited Partnership of TC PipeLines, LP dated December 31, 2018 (Incorporated by reference from Exhibit 3.1 to TC PipeLines, LP’s Form 8-K filed January 2, 2019).
4.1	Indenture, dated as of June 17, 2011, between the Partnership and The Bank of New York Mellon, as trustee (Incorporated by reference to Exhibit 4.1 to TC PipeLines, LP’s Form 8-K filed on June 17, 2011).
4.2	Supplemental Indenture, dated as of June 17, 2011 relating to the issuance of $350,000,000 aggregate principal amount of 4.65% Senior Notes due 2021 (Incorporated by reference to Exhibit 4.2 to TC PipeLines, LP’s Form 8-K filed on June 17, 2011).
4.3	Specimen of 4.65% Senior Notes due 2021 (Incorporated by reference to Exhibit A to the Supplemental Indenture filed as Exhibit 4.2 to TC PipeLines, LP’s Form 8-K filed on June 17, 2011).
4.4	Form of indenture for senior debt securities (Incorporated by reference to Exhibit 4.1 to TC PipeLines, LP’s Form 8-K filed on June 14, 2011).
4.5	Second Supplemental Indenture, dated March 13, 2015, between TC PipeLines, LP and The Bank of New York Mellon (incorporated by reference from Exhibit 4.1 to TC PipeLines, LP’s Form 8-K filed March 13, 2015).
4.6	Third Supplemental Indenture, dated as of May 25, 2017, relating to the issuance of $500,000,000 aggregate principal amount of 3.900% Senior Notes due 2027 (Incorporated by reference from Exhibit 4.2 to TC PipeLines, LP’s Form 8-K filed May 25, 2017).
31.1*	Certification of Principal Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*	Certification of Principal Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1**	Certification of Principal Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2**	Certification of Principal Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
99.1*	Amended transportation Service Agreement FT19214 between Great Lakes Gas Transmission Limited Partnership and ANR Pipeline Company, effective date November 1, 2021.
99.2*	Amended transportation Service Agreement FT19215 between Great Lakes Gas Transmission Limited Partnership and ANR Pipeline Company, effective date November 1, 2021.
101.INS	XBRL Instance Document.
101.SCH	XBRL Taxonomy Extension Schema Document.
101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document.
101.DEF	XBRL Taxonomy Definition Linkbase Document.
101.LAB	XBRL Taxonomy Extension Label Linkbase Document.
101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document.

39

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized on this 8th day of May 2019.

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

40

EX-31.1

Exhibit 31.1

CERTIFICATION OF

PRINCIPAL EXECUTIVE OFFICER

I, Nathaniel A. Brown, certify that:

1.I have reviewed this quarterly report on Form 10-Q of TC PipeLines, LP;

2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a)designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b)designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c)evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d)disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a)all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b)any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Dated:	May 8, 2019
	/s/ Nathaniel A. Brown
	Nathaniel A. Brown
		Principal Executive Officer and President
		TC PipeLines GP, Inc., as General Partner of
		TC PipeLines, LP

1

EX-31.2

Exhibit 31.2

CERTIFICATION OF

PRINCIPAL FINANCIAL OFFICER

I, William C. Morris, certify that:

1.I have reviewed this quarterly report on Form 10-Q of TC PipeLines, LP;

2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a)designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b)designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c)evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d)disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a)all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b)any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Dated:	May 8, 2019
	/s/ William C. Morris
	William C. Morris
		Principal Financial Officer, Vice President and Treasurer
		TC PipeLines GP, Inc., as General Partner of
		TC PipeLines, LP

EX-32.1

Exhibit 32.1

CERTIFICATION OF

PRINCIPAL EXECUTIVE OFFICER

I, Nathaniel A. Brown , Principal Executive Officer and President of TC PipeLines GP, Inc., the General Partner of TC PipeLines, LP (the Partnership), in compliance with 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 hereby certify, to the best of my knowledge, in connection with the Partnership’s Quarterly Report on Form 10-Q for the period ended March 31, 2019 as filed with the Securities and Exchange Commission (the Report) on the date hereof, that:

·the Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

·the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Partnership.

Dated:	May 8, 2019
	/s/ Nathaniel A. Brown
	Nathaniel A. Brown
		Principal Executive Officer and President
		TC PipeLines GP, Inc., as General Partner of
		TC PipeLines, LP

EX-32.2

Exhibit 32.2

CERTIFICATION OF

PRINCIPAL FINANCIAL OFFICER

I, William C. Morris, Principal Financial Officer, Vice-President and Treasurer of TC PipeLines GP, Inc., the General Partner of TC PipeLines, LP (the Partnership), in compliance with 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 hereby certify, to the best of my knowledge, in connection with the Partnership’s Quarterly Report on Form 10-Q for the period ended March 31, 2019 as filed with the Securities and Exchange Commission (the Report) on the date hereof, that:

·the Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

·the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Partnership.

Dated:	May 8, 2019
	/s/ William C. Morris
	William C Morris
		Principal Financial Officer, Vice President and Treasurer
		TC PipeLines GP, Inc., as General Partner of
		TC PipeLines, LP

EX-99.1

Exhibit 99.1

Contract ID.: FT19214

Amendment No: 1

FORM OF TRANSPORTATION SERVICE AGREEMENT

This Transportation Service Agreement (Agreement) is entered into by Great Lakes Gas Transmission Limited Partnership (Transporter) and ANR Pipeline Company (Shipper).

WHEREAS, Shipper has requested Transporter to transport Gas on its behalf and Transporter represents that it is willing to transport Gas under the terms and conditions of this Agreement.

NOW, THEREFORE, Transporter and Shipper agree that the terms below constitute the transportation service to be provided and the rights and obligations of Shipper and Transporter.

1.EFFECTIVE DATE: November 01, 2021

2.CONTRACT IDENTIFICATION: FT19214

3.RATE SCHEDULE: FT

4.SHIPPER TYPE: Other

5.STATE/PROVINCE OF INCORPORATION: Delaware

6.TERM: November 01, 2021 to October 31, 2036

Right of First Refusal:

Regulatory (in accordance with Section 6.16 of the General Terms and Conditions of Transporter’s FERC Gas Tariff)

7.EFFECT ON PREVIOUS CONTRACTS:

This Agreement supersedes, cancels and terminates, as of the effective date stated above, the following contract(s): Service Agreement dated April 16, 2018 with Contract Identification FT19214.

8.MAXIMUM DAILY QUANTITY (Dth/Day):

Please see Appendix A for further detail.

9.RATES:

Unless Shipper and Transporter have agreed to a rate other than the maximum rate, rates shall be Transporter’s maximum rates and charges plus all applicable surcharges in effect from time to time under the applicable Rate Schedule (as stated above) on file with the Commission unless otherwise agreed to by the parties in writing. Provisions governing a Rate other than the maximum shall be set forth in this Paragraph 9.

10.POINTS OF RECEIPT AND DELIVERY:

The primary receipt and delivery points are set forth on Appendix A.

11.RELEASED CAPACITY: N/A

12.INCORPORATION OF TARIFF INTO AGREEMENT:

This Agreement shall incorporate and in all respects be subject to the “General Terms and Conditions” and the applicable Rate Schedule (as stated above) set forth in Transporter’s FERC Gas Tariff, Third Revised Volume No. 1, as may be revised from time to time. Transporter may file and seek Commission approval under Section 4 of the Natural Gas Act (NGA) at any time and from time to time to change any rates, charges or provisions set forth in the applicable Rate Schedule (as stated above) and the “General Terms and Conditions” in Transporter’s FERC Gas Tariff, Third Revised Volume No. 1, and Transporter shall have the right to place such changes in effect in accordance with the NGA, and this Agreement shall be deemed to include such changes and any such changes which become effective by operation of law and Commission Order, without prejudice to Shipper’s right to protest the same.

13.MISCELLANEOUS:

No waiver by either party to this Agreement of any one or more defaults by the other in the performance of this Agreement shall operate or be construed as a waiver of any continuing or future default(s), whether of a like or a different character.

Any controversy between the parties arising under this Agreement and not resolved by the parties shall be determined in accordance with the laws of the State of Michigan.

14.OTHER PROVISIONS (As necessary):

It is agreed that no personal liability whatsoever shall attach to, be imposed on or otherwise be incurred by any Partner, agent, management official or employee of the Transporter or any director, officer or employee of any of the foregoing, for any obligation of the Transporter arising under this Agreement or for any claim based on such obligation and that the sole recourse of Shipper under this Agreement is limited to assets of the Transporter.

Upon termination of this Agreement, Shipper’s and Transporter’s obligations to each other arising under this Agreement, prior to the date of termination, remain in effect and are not being terminated by any provision of this Agreement.

Transporter and Shipper agree that, pursuant to Section 6.2.1(h) of the General Terms and Conditions, this Agreement is subject to a Reduction Option as herein described:

Upon written notice to Transporter, Shipper shall have a Reduction Option:

1) At any time on or before April 1, 2020 for any reason, and

2) Any time before April 1, 2021, to the extent necessary due to the failure or inability to secure all applicable federal, state, and local governmental and regulatory approval(s) related to an anticipated expansion project.

If Shipper invokes this Reduction Option, it may reduce all or a portion of the contractual MDQ associated with this Agreement, and/or terminate this Agreement earlier than 10/31/2036.

15.NOTICES AND COMMUNICATIONS:

All notices and communications with respect to this Agreement shall be in writing by mail, e-mail, or other means as agreed to by the parties, and sent to the addresses stated below or to any other such address(es) as may be designated in writing by mail, e-mail, or other means similarly agreed to:

ADMINISTRATIVE MATTERS:
Great Lakes Gas Transmission Limited Partnership	ANR Pipeline Company
Commercial Operations	700 Louisiana St., Suite 700
700 Louisiana Street, Suite 700	Houston, TX 77002-2700
Houston, TX 77002-2700	Attn: Pearline McMahon

AGREED TO BY:

GREAT LAKES GAS TRANSMISSION LIMITED PARTNERSHIP		ANR Pipeline Company
By:	Great Lakes Gas Transmission Company
By:		By:	/s/ Jasmin Bertovic
			Jasmin Bertovic
Title:		Title:	Vice President

Legal

RB

2-26-19

Date

APPENDIX A
CONTRACT IDENTIFICATION: FT19214

Date: November 01, 2021

Supersedes Appendix Dated: April 16, 2018

Shipper: ANR Pipeline Company

Maximum Daily Quantity (Dth/Day) per Location:

		Point(s)	Point(s)
Begin	End	of Primary	of Primary
Date	Date	Receipt	Delivery	MDQ
		EMERSON	FORTUNE
11/1/2021	10/31/2036	RECEIPT	LAKE	160,000

EX-99.2

Exhibit 99.2

Contract ID.: FT19215

Amendment No: 1

FORM OF TRANSPORTATION SERVICE AGREEMENT

This Transportation Service Agreement (Agreement) is entered into by Great Lakes Gas Transmission Limited Partnership (Transporter) and ANR Pipeline Company (Shipper).

WHEREAS, Shipper has requested Transporter to transport Gas on its behalf and Transporter represents that it is willing to transport Gas under the terms and conditions of this Agreement.

NOW, THEREFORE, Transporter and Shipper agree that the terms below constitute the transportation service to be provided and the rights and obligations of Shipper and Transporter.

1.EFFECTIVE DATE: November 01, 2021

2.CONTRACT IDENTIFICATION: FT19215

3.RATE SCHEDULE: FT

4.SHIPPER TYPE: Other

5.STATE/PROVINCE OF INCORPORATION: Delaware

6.TERM: November 01, 2021 to October 31, 2036

Right of First Refusal:

Regulatory (in accordance with Section 6.16 of the General Terms and Conditions of Transporter’s FERC Gas Tariff)

7.EFFECT ON PREVIOUS CONTRACTS:

This Agreement supersedes, cancels and terminates, as of the effective date stated above, the following contract(s): Service Agreement dated April 16, 2018 with Contract Identification FT19215.

8.MAXIMUM DAILY QUANTITY (Dth/Day):

Please see Appendix A for further detail.

9.RATES:

Unless Shipper and Transporter have agreed to a rate other than the maximum rate, rates shall be Transporter’s maximum rates and charges plus all applicable surcharges in effect from time to time under the applicable Rate Schedule (as stated above) on file with the Commission unless otherwise agreed to by the parties in writing. Provisions governing a Rate other than the maximum shall be set forth in this Paragraph 9.

10.POINTS OF RECEIPT AND DELIVERY:

The primary receipt and delivery points are set forth on Appendix A.

11.RELEASED CAPACITY: N/A

12.INCORPORATION OF TARIFF INTO AGREEMENT:

This Agreement shall incorporate and in all respects be subject to the “General Terms and Conditions” and the applicable Rate Schedule (as stated above) set forth in Transporter’s FERC Gas Tariff, Third Revised Volume No. 1, as may be revised from time to time. Transporter may file and seek Commission approval under Section 4 of the Natural Gas Act (NGA) at any time and from time to time to change any rates, charges or provisions set forth in the applicable Rate Schedule (as stated above) and the “General Terms and Conditions” in Transporter’s FERC Gas Tariff, Third Revised Volume No. 1, and Transporter shall have the right to place such changes in effect in accordance with the NGA, and this Agreement shall be deemed to include such changes and any such changes which become effective by operation of law and Commission Order, without prejudice to Shipper’s right to protest the same.

13.MISCELLANEOUS:

No waiver by either party to this Agreement of any one or more defaults by the other in the performance of this Agreement shall operate or be construed as a waiver of any continuing or future default(s), whether of a like or a different character.

Any controversy between the parties arising under this Agreement and not resolved by the parties shall be determined in accordance with the laws of the State of Michigan.

14.OTHER PROVISIONS (As necessary):

It is agreed that no personal liability whatsoever shall attach to, be imposed on or otherwise be incurred by any Partner, agent, management official or employee of the Transporter or any director, officer or employee of any of the foregoing, for any obligation of the Transporter arising under this Agreement or for any claim based on such obligation and that the sole recourse of Shipper under this Agreement is limited to assets of the Transporter.

Upon termination of this Agreement, Shipper’s and Transporter’s obligations to each other arising under this Agreement, prior to the date of termination, remain in effect and are not being terminated by any provision of this Agreement.

Transporter and Shipper agree that, pursuant to Section 6.2.1(h) of the General Terms and Conditions, this Agreement is subject to a Reduction Option as herein described:

Upon written notice to Transporter, Shipper shall have a Reduction Option:

1) At any time on or before April 1, 2020 for any reason, and

2) Any time before April 1, 2021, to the extent necessary due to the failure or inability to secure all applicable federal, state, and local governmental and regulatory approval(s) related to an anticipated expansion project.

If Shipper invokes this Reduction Option, it may reduce all or a portion of the contractual MDQ associated with this Agreement, and/or terminate this Agreement earlier than 10/31/2036.

15.NOTICES AND COMMUNICATIONS:

All notices and communications with respect to this Agreement shall be in writing by mail, e-mail, or other means as agreed to by the parties, and sent to the addresses stated below or to any other such address(es) as may be designated in writing by mail, e-mail, or other means similarly agreed to:

ADMINISTRATIVE MATTERS:
Great Lakes Gas Transmission Limited Partnership	ANR Pipeline Company
Commercial Operations	700 Louisiana St., Suite 700
700 Louisiana Street, Suite 700	Houston, TX 77002-2700
Houston, TX 77002-2700	Attn: Pearline McMahon

AGREED TO BY:

GREAT LAKES GAS TRANSMISSION LIMITED PARTNERSHIP		ANR Pipeline Company
By:	Great Lakes Gas Transmission Company
By:		By:	/s/ Jasmin Bertovic
			Jasmin Bertovic
Title:		Title:	Vice President

Legal

RB

2-26-19

Date

APPENDIX A
CONTRACT IDENTIFICATION: FT19215

Date: November 01, 2021

Supersedes Appendix Dated: April 16, 2018

Shipper: ANR Pipeline Company

Maximum Daily Quantity (Dth/Day) per Location:

		Point(s)	Point(s)
Begin	End	of Primary	of Primary
Date	Date	Receipt	Delivery	MDQ
		EMERSON	FARWELL
11/1/2021	10/31/2036	RECEIPT	DELIVERY	800,000

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Document and Entity Information - shares	3 Months Ended
	Mar. 31, 2019	May 07, 2019
Document and Entity Information
Entity Registrant Name	TC PIPELINES LP
Entity Central Index Key	0001075607
Document Type	10-Q
Document Period End Date	Mar. 31, 2019
Amendment Flag	false
Current Fiscal Year End Date	--12-31
Entity Current Reporting Status	Yes
Entity Small Business	false
Entity Emerging Growth Company	false
Trading Symbol	TCP
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		71,306,396
Document Fiscal Year Focus	2019
Document Fiscal Period Focus	Q1

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CONSOLIDATED STATEMENTS OF INCOME - USD ($) shares in Millions, $ in Millions	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Transmission revenues	$ 113	$ 115
Equity earnings (Note 5)	54	59
Operation and maintenance expenses	(16)	(16)
Property taxes	(7)	(7)
General and administrative	(2)	(1)
Depreciation and amortization	(20)	(24)
Financial charges and other (Note 15)	(22)	(23)
Net income before taxes	100	103
Income taxes		(1)
Net Income	100	102
Net income attributable to non-controlling interests	7	6
Net income attributable to controlling interests	93	96
Net income attributable to controlling interest allocation (Note 9)
General Partner	2	2
Net income attributable to controlling interests	93	96
Common units
Net income attributable to controlling interest allocation (Note 9)
Net income attributable to common units	$ 91	$ 94
Net income per common unit (Note 9) - basic and diluted	$ 1.28	$ 1.32
Weighted average common units outstanding - basic and diluted	71.3	71.2
Common units outstanding, end of period	71.3	71.3

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CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
Net income	$ 100	$ 102
Other comprehensive income
Change in fair value of cash flow hedges (Note 13)	(5)	7
Comprehensive income	95	109
Comprehensive income attributable to non-controlling interests	7	6
Comprehensive income attributable to controlling interests	$ 88	$ 103

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CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions	Mar. 31, 2019	Dec. 31, 2018
Current Assets
Cash and cash equivalents	$ 52	$ 33
Accounts receivable and other (Note 14)	41	48
Inventories	9	8
Other	5	8
Total current assets	107	97
Equity investments (Note 5)	1,196	1,196
Property, plant and equipment (Net of $1,128 accumulated depreciation; 2018 - $1,110)	1,522	1,529
Goodwill	71	71
Other assets	3	6
TOTAL ASSETS	2,899	2,899
Current Liabilities
Accounts payable and accrued liabilities	29	36
Accounts payable to affiliates (Note 12)	7	6
Accrued interest	20	12
Current portion of long-term debt (Note 7)	36	36
Total current liabilities	92	90
Long-term debt, net (Note 7)	2,040	2,072
Deferred state income taxes (Note 18)	9	9
Other liabilities	31	29
Total liabilities	2,172	2,200
Partners' Equity
General partner	14	13
Accumulated other comprehensive income (AOCI)	3	8
Controlling interests	619	591
Non-controlling interest	108	108
Total partners' equity	727	699
TOTAL LIABILITIES AND PARTNERS' EQUITY	2,899	2,899
Common units
Partners' Equity
Limited partner	507	462
Class B units
Partners' Equity
Limited partner	$ 95	$ 108

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CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Millions	Mar. 31, 2019	Dec. 31, 2018
CONSOLIDATED BALANCE SHEETS
Accumulated depreciation	$ 1,128	$ 1,110

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CONSOLIDATED STATEMENT OF CASH FLOWS - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Cash Generated from Operations
Net income	$ 100	$ 102
Depreciation and amortization	20	24
Amortization of debt issue costs reported as interest expense		1
Equity earnings from equity investments (Note 5)	(54)	(59)
Distributions received from operating activities of equity investments (Note 5)	56	43
Change in operating working capital (Note 11)	13	6
Cash generated from operations	135	117
Investing Activities
Investment in Great Lakes (Note 5)	(5)	(4)
Distribution received from Iroquois as return of investment (Note 5)	2	2
Capital expenditures	(16)	(2)
Customer advances for construction	2
Investing activities	(17)	(4)
Financing Activities
Distributions paid to common units, including the general partner (Note 10)	(47)	(76)
Distributions paid to Class B units (Note 8)	(13)	(15)
Distributions paid to non-controlling interests	(7)	(1)
Common unit issuance, net		40
Long-term debt issued, net of discount (Note 7)	18	75
Long-term debt repaid (Note 7)	(50)	(101)
Financing activities	(99)	(78)
Increase in cash and cash equivalents	19	35
Cash and cash equivalents, beginning of period	33	33
Cash and cash equivalents, end of period	$ 52	$ 68

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CONSOLIDATED STATEMENT OF CHANGES IN PARTNERS' EQUITY - 3 months ended Mar. 31, 2019 - USD ($) shares in Millions, $ in Millions	Limited Partners Common units	Limited Partners Class B units	General Partner	Accumulated Other Comprehensive Income	[1]	Non-controlling interest	Total
Partners' Equity at beginning of period at Dec. 31, 2018	$ 462	$ 108	$ 13	$ 8		$ 108	$ 699
Partners' Equity at beginning of period (in units) at Dec. 31, 2018	71.3	1.9
Increase (Decrease) in Partners' Equity
Net income	$ 91		2			7	100
Other comprehensive income				(5)			(5)
Distributions (Note 10)	(46)	$ (13)	(1)			(7)	(67)
Partners' Equity at end of period at Mar. 31, 2019	$ 507	$ 95	$ 14	$ 3		$ 108	$ 727
Partners' Equity at end of period (in units) at Mar. 31, 2019	71.3	1.9

[1] 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.

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CONSOLIDATED STATEMENT OF CHANGES IN PARTNERS' EQUITY (Parenthetical) $ in Millions	3 Months Ended
	Mar. 31, 2019 USD ($)
CONSOLIDATED STATEMENT OF CHANGES IN PARTNERS' EQUITY
Gain (Losses) related to cash flow hedges in AOCI expected to be reclassified to Net income in the next 12 months	$ 1

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ORGANIZATION

3 Months Ended

Mar. 31, 2019

ORGANIZATION

ORGANIZATION

NOTE 1     ORGANIZATION

TC PipeLines, LP and its subsidiaries are collectively referred to herein as the Partnership. The Partnership was formed by TransCanada PipeLines Limited, a wholly owned subsidiary of 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.

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SIGNIFICANT ACCOUNTING POLICIES

3 Months Ended

Mar. 31, 2019

SIGNIFICANT ACCOUNTING POLICIES

SIGNIFICANT ACCOUNTING POLICIES

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

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ACCOUNTING PRONOUNCEMENTS

3 Months Ended

Mar. 31, 2019

ACCOUNTING PRONOUNCEMENTS

ACCOUNTING PRONOUNCEMENTS

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 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.

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REGULATORY

3 Months Ended

Mar. 31, 2019

REGULATORY

REGULATORY

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.

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.

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EQUITY INVESTMENTS

3 Months Ended

Mar. 31, 2019

EQUITY INVESTMENTS

EQUITY INVESTMENTS

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).

	Ownership		Equity Earnings		Equity Investments
	Interest at		Three months
(unaudited)	March 31,		Ended March 31,		March 31,	December 31,
(millions of dollars)	2019		2019	2018	2019	2018
Northern Border	50	%	21	17	489	497
Great Lakes	46.45	%	20	24	498	489
Iroquois	49.34	%	13	18	209	210
			54	59	1,196	1,196

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:

(unaudited)
(millions of dollars)	March 31, 2019	December 31, 2018
ASSETS
Cash and cash equivalents	14	10
Other current assets	38	36
Property, plant and equipment, net	1,023	1,037
Other assets	13	13
	1,088	1,096
LIABILITIES AND PARTNERS’ EQUITY
Current liabilities	41	34
Deferred credits and other	35	35
Long-term debt, net (a)	264	264
Partners’ equity
Partners’ capital	749	764
Accumulated other comprehensive loss	(1)	(1)
	1,088	1,096

	Three months ended
(unaudited)	March 31,
(millions of dollars)	2019	2018
Transmission revenues	81	72
Operating expenses	(20)	(19)
Depreciation	(15)	(15)
Financial charges and other	(4)	(4)
Net income	42	34

(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:

(unaudited)
(millions of dollars)	March 31, 2019	December 31, 2018
ASSETS
Current assets	86	75
Property, plant and equipment, net	685	689
	771	764
LIABILITIES AND PARTNERS’ EQUITY
Current liabilities	25	26
Net long-term debt, including current maturities (a)	229	240
Other long-term liabilities	4	4
Partners' equity	513	494
	771	764

	Three months ended
(unaudited)	March 31,
(millions of dollars)	2019	2018
Transmission revenues	72	81
Operating expenses	(16)	(17)
Depreciation	(8)	(8)
Financial charges and other	(4)	(4)
Net income	44	52

(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 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:

(unaudited)
(millions of dollars)	March 31, 2019	December 31, 2018
ASSETS
Cash and cash equivalents	84	80
Other current assets	30	32
Property, plant and equipment, net	576	581
Other assets	16	8
	706	701
LIABILITIES AND PARTNERS’ EQUITY
Current liabilities	19	19
Long-term debt, net (a)	325	325
Other non-current liabilities	20	14
Partners' equity	342	343
	706	701

	Three months ended
(unaudited)	March 31,
(millions of dollars)	2019	2018
Transmission revenues	52	60
Operating expenses	(15)	(14)
Depreciation	(7)	(7)
Financial charges and other	(3)	(4)
Net income	27	35

^(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.

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REVENUES

3 Months Ended

Mar. 31, 2019

REVENUES

REVENUES

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. 

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.

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DEBT AND CREDIT FACILITIES

3 Months Ended

Mar. 31, 2019

DEBT AND CREDIT FACILITIES

DEBT AND CREDIT FACILITIES

NOTE 7     DEBT AND CREDIT FACILITIES

		Weighted Average				Weighted Average
		Interest Rate for the				Interest Rate for the
(unaudited)		Three Months Ended			December 31,	Year Ended
(millions of dollars)	March 31, 2019	March 31, 2019			2018	December 31, 2018
TC PipeLines, LP
Senior Credit Facility due 2021	—	3.61	%		40	3.14	%
2013 Term Loan Facility due 2022	500	3.73	%		500	3.23	%
4.65% Unsecured Senior Notes due 2021	350	4.65	%	(a)	350	4.65	%	(a)
4.375% Unsecured Senior Notes due 2025	350	4.375	%	(a)	350	4.375	%	(a)
3.90 % Unsecured Senior Notes due 2027	500	3.90	%	(a)	500	3.90	%	(a)
GTN
5.29% Unsecured Senior Notes due 2020	100	5.29	%	(a)	100	5.29	%	(a)
5.69% Unsecured Senior Notes due 2035	150	5.69	%	(a)	150	5.69	%	(a)
Unsecured Term Loan Facility due 2019	35	3.45	%		35	2.93	%
PNGTS
Revolving Credit Facility due 2023	27	3.75	%		19	3.55	%
Tuscarora
Unsecured Term Loan due 2020	24	3.63	%		24	3.10	%
North Baja
Unsecured Term Loan due 2021	50	3.56	%		50	3.54	%
	2,086				2,118
Less: unamortized debt issuance costs and debt discount	10				10
Less: current portion	36				36
	2,040				2,072

(a)Fixed interest rate

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 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:

(unaudited)
(millions of dollars)	Principal payments
2019	36
2020	123
2021	400
2022	500
2023	27
Thereafter	1,000
	2,086

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PARTNERS' EQUITY

3 Months Ended

Mar. 31, 2019

PARTNERS' EQUITY

PARTNERS' EQUITY

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.

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NET INCOME PER COMMON UNIT

3 Months Ended

Mar. 31, 2019

NET INCOME PER COMMON UNIT

NET INCOME PER COMMON UNIT

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:

(unaudited)	Three months ended March 31,
(millions of dollars, except per common unit amounts)	2019		2018
Net income attributable to controlling interests		93		96
Net income attributable to the General Partner		(2)		(2)
Net income attributable to common units		91		94
Weighted average common units outstanding (millions) – basic and diluted		71.3		71.2
Net income per common unit – basic and diluted	$	1.28	$	1.32

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CASH DISTRIBUTIONS PAID TO COMMON UNITS

3 Months Ended

Mar. 31, 2019

CASH DISTRIBUTIONS PAID TO COMMON UNITS

CASH DISTRIBUTIONS PAID TO COMMON UNITS

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).

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CHANGE IN OPERATING WORKING CAPITAL

3 Months Ended

Mar. 31, 2019

CHANGE IN OPERATING WORKING CAPITAL

CHANGE IN OPERATING WORKING CAPITAL

NOTE 11     CHANGE IN OPERATING WORKING CAPITAL

(unaudited)	Three months ended March 31,
(millions of dollars)	2019	2018
Change in accounts receivable and other	7	—
Change in inventories	(1)	—
Change in other current assets	2	(3)
Change in accounts payable and accrued liabilities	(4)	—
Change in accounts payable to affiliates	1	—
Change in accrued interest	8	9
Change in operating working capital	13	6

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RELATED PARTY TRANSACTIONS

3 Months Ended

Mar. 31, 2019

RELATED PARTY TRANSACTIONS

RELATED PARTY TRANSACTIONS

NOTE 12     RELATED PARTY TRANSACTIONS

The Partnership does not have any employees. The management and operating functions are provided by the General Partner. The General Partner does not receive a management fee in connection with its management of the Partnership. The Partnership reimburses the General Partner for all costs of services provided, including the costs of employee, officer and director compensation and benefits, and all other expenses necessary or appropriate to conduct the business of, and allocable to, the Partnership. Such costs include (i) overhead costs (such as office space and equipment) and (ii) out-of-pocket expenses related to the provision of such services. The Partnership Agreement provides that the General Partner will determine the costs that are allocable to the Partnership in any reasonable manner determined by the General Partner in its sole discretion. For both the three months ended March 31, 2019 and 2018, total costs charged to the Partnership by the General Partner were $1 million.

As operator of our pipelines, except Iroquois, TC Energy’s subsidiaries provide capital and operating services to our pipeline systems. TC Energy’s subsidiaries incur costs on behalf of our pipeline systems, including, but not limited to, employee salary and benefit costs, and property and liability insurance costs. Iroquois does not receive any capital and operating services from TC Energy (Refer to Note 5).

Capital and operating costs charged to our pipeline systems, except for Iroquois, for the three months ended March 31, 2019 and 2018 by TC Energy’s subsidiaries and amounts payable to TC Energy’s subsidiaries at March 31, 2019 and December 31, 2018 are summarized in the following tables:

	Three months ended
(unaudited)	March 31,
(millions of dollars)	2019	2018
Capital and operating costs charged by TC Energy’s subsidiaries to:
Great Lakes (a)	11	9
Northern Border (a)	9	9
GTN	10	8
Bison	1	2
North Baja	1	1
Tuscarora	1	1
PNGTS (a)	2	2
Impact on the Partnership’s net income:
Great Lakes	5	4
Northern Border	4	4
GTN	8	8
Bison	1	2
North Baja	1	1
Tuscarora	1	1
PNGTS	1	1

(unaudited)
(millions of dollars)	March 31, 2019	December 31, 2018
Net amounts payable to TC Energy’s subsidiaries are as follows:
Great Lakes (a)	5	3
Northern Border (a)	4	3
GTN	4	4
Bison	—	1
North Baja	1	—
Tuscarora	—	1
PNGTS (a)	1	1

^(a) Represents 100 percent of the costs.

Great Lakes

Great Lakes earns significant transportation revenues from TC Energy and its affiliates, some of which are provided at discounted rates and some at maximum recourse rates. For the three months ended March 31, 2019, Great Lakes earned 73 percent of transportation revenues from TC Energy and its affiliates (March 31, 2018 – 68 percent).

At March 31, 2019, $18 million was included in Great Lakes’ receivables with regard to the transportation contracts with TC Energy and its affiliates (December 31, 2018 – $18 million).

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

PNGTS

PNGTS earns transportation revenues from TC Energy and its affiliates. For the three months ended March 31, 2019, PNGTS earned approximately nil of its transportation revenues from TC Energy and its affiliates (March 31, 2018 – $1 million).

At March 31, 2019, PNGTS had nil outstanding receivables with regard to the transportation contracts with TC Energy and its affiliates (December 31, 2018 – nil).

In connection with anticipated future commercial opportunities, PNGTS has entered into an arrangement with its affiliates regarding the construction of certain facilities on their systems that will be required to fulfill future contracts on the PNGTS system. In the event the anticipated developments do not proceed, PNGTS will be required to reimburse its affiliates for any costs incurred related to the development of these facilities. At March 31, 2019, the total costs incurred by these affiliates was approximately $71 million.

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FAIR VALUE MEASUREMENTS

3 Months Ended

Mar. 31, 2019

FAIR VALUE MEASUREMENTS

FAIR VALUE MEASUREMENTS

NOTE 13     FAIR VALUE MEASUREMENTS

(a) Fair Value Hierarchy

Under Accounting Standards Codification (ASC) 820, Fair Value Measurements and Disclosures, fair value measurements are characterized in one of three levels based upon the inputs used to arrive at the measurement. The three levels of the fair value hierarchy are as follows:

· Level 1 inputs are quoted prices (unadjusted) in active markets for identical assets or liabilities that we have the ability to access at the measurement date.

· Level 2 inputs are inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly.

· Level 3 inputs are unobservable inputs for the asset or liability.

When appropriate, valuations are adjusted for various factors including credit considerations. Such adjustments are generally based on available market evidence. In the absence of such evidence, management’s best estimate is used.

(b) Fair Value of Financial Instruments

The carrying value of “cash and cash equivalents”,  “accounts receivable and other”,  “accounts payable and accrued liabilities”,  “accounts payable to affiliates” and “accrued interest” approximate their fair values because of the short maturity or duration of these instruments, or because the instruments bear a variable rate of interest or a rate that approximates current rates. The fair value of the Partnership’s debt is estimated by discounting the future cash flows of each instrument at estimated current borrowing rates. The fair value of interest rate derivatives is calculated using the income approach, which uses period-end market rates and applies a discounted cash flow valuation model.

The Partnership has classified the fair value of natural gas imbalances as a Level 2 of the fair value hierarchy for fair value disclosure purposes, as the valuation approach includes quoted prices in the market index and observable volumes for the imbalance.

Long-term debt is recorded at amortized cost and classified as Level 2 of the fair value hierarchy for fair value disclosure purposes. Interest rate derivative assets and liabilities are classified as Level 2 for all periods presented where the fair value is determined by using valuation techniques that refer to observable market data or estimated market prices.  The estimated fair value of the Partnership’s debt as at March 31, 2019 and December 31, 2018 was $2,119 million and $2,101 million, respectively.

Market risk is the risk that changes in market interest rates may result in fluctuations in the fair values or cash flows of financial instruments. The Partnership’s floating rate debt is subject to LIBOR benchmark interest rate risk. The Partnership uses derivatives to manage its exposure to interest rate risk. We regularly assess the impact of interest rate fluctuations on future cash flows and evaluate hedging opportunities to mitigate our interest rate risk.

The Partnership’s interest rate swaps mature on October 2, 2022 and are structured such that the cash flows of the derivative instruments match those of the variable rate of interest on the 2013 Term Loan Facility. The fixed weighted average interest rate on these instruments is 3.26 percent.

At March 31, 2019, the fair value of the interest rate swaps accounted for as cash flow hedges was an asset of $3 million (both on a gross and net basis) (December 31, 2018  - asset of $8 million).  

The change in fair value of interest rate derivative instruments recognized in other comprehensive income was a loss of $5 million for the three months ended March 31, 2019 (March 31, 2018 – gain of $7 million). For the three months ended March 31, 2019, the net realized gain related to the interest rate swaps was $1 million, and was included in “financial charges and other”  (March 31, 2018 - gain of $1 million) (Refer to Note 15).

The Partnership has no master netting agreements; however, it has derivative contracts containing provisions with rights of offset. The Partnership has elected to present the fair value of derivative instruments with the right to offset on a gross basis in the consolidated balance sheet. Had the Partnership elected to present these instruments on a net basis, there would be no effect on the consolidated balance sheet as of March 31, 2019 and December 31, 2018.

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ACCOUNTS RECEIVABLE AND OTHER

3 Months Ended

Mar. 31, 2019

ACCOUNTS RECEIVABLE AND OTHER

ACCOUNTS RECEIVABLE AND OTHER

NOTE 14     ACCOUNTS RECEIVABLE AN.D OTHER

(unaudited)
(millions of dollars)	March 31, 2019	December 31, 2018
Trade accounts receivable, net of allowance of nil	35	44
Imbalance receivable from affiliates	4	2
Other	2	2
	41	48

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FINANCIAL CHARGES AND OTHER

3 Months Ended

Mar. 31, 2019

FINANCIAL CHARGES AND OTHER

FINANCIAL CHARGES AND OTHER

NOTE 15     FINANCIAL CHARGES AND OTHER

	Three months ended
(unaudited)	March 31,
(millions of dollars)	2019	2018
Interest expense (a)	23	24
Net realized gain related to the interest rate swaps	(1)	(1)
	22	23

^(a) Includes amortization of debt issuance costs and discount costs.

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VARIABLE INTEREST ENTITIES

3 Months Ended

Mar. 31, 2019

VARIABLE INTEREST ENTITIES

VARIABLE INTEREST ENTITIES

NOTE 16     VARIABLE INTEREST ENTITIES

In the normal course of business, the Partnership must re-evaluate its legal entities under the current consolidation guidance to determine if those that are considered to be VIEs are appropriately consolidated or if they should be accounted for under other GAAP. A VIE is a legal entity that does not have sufficient equity at risk to finance its activities without additional subordinated financial support or is structured such that equity investors lack the ability to make significant decisions relating to the entity’s operations through voting rights or do not substantively participate in the gains or losses of the entity. A VIE is appropriately consolidated if the Partnership is considered to be the primary beneficiary. The VIE’s primary beneficiary is the entity that has both (1) the power to direct the activities of the VIE that most significantly impact the VIEs economic performance and (2) the obligation to absorb losses or the right to receive benefits from the VIE that could potentially be significant to the VIE.

As a result of its analysis, the Partnership continues to consolidate all legal entities in which it has a variable interest and for which it is considered to be the primary beneficiary. VIEs where the Partnership is not the primary beneficiary, but has a variable interest in the entity, are accounted for as equity investments.

Consolidated VIEs

The Partnership’s consolidated VIEs consist of the intermediate partnerships and mainly the Partnership’s ILPs that hold interests in the Partnership’s pipeline systems. After considering the purpose and design of the ILPs and the risks that they were designed to create and pass through to the Partnership, the Partnership has concluded that it is the primary beneficiary of these ILPs because of the significant amount of variability it absorbs from the ILPs’ economic performance.

The assets and liabilities held through these VIEs that are not available to creditors of the Partnership and whose investors have no recourse to the credit of the Partnership are held through GTN, Tuscarora, Northern Border, Great Lakes, PNGTS, Iroquois and North Baja due to their third-party debt. The following table presents the total assets and liabilities of these entities that are included in the Partnership’s consolidated balance sheets:

(unaudited)
(millions of dollars)	March 31, 2019	December 31, 2018
ASSETS (LIABILITIES) (a)
Cash and cash equivalents	25	16
Accounts receivable and other	37	39
Inventories	9	8
Other current assets	5	6
Equity investments	1,196	1,196
Property, plant and equipment, net	1,237	1,240
Other assets	1	1
Accounts payable and accrued liabilities	(26)	(33)
Accounts payable to affiliates, net	(38)	(40)
Accrued interest	(5)	(2)
Current portion of long-term debt	(36)	(36)
Long-term debt	(349)	(341)
Other liabilities	(28)	(27)
Deferred state income tax	(9)	(9)

^(a) Bison, an asset held through our consolidated VIEs, is excluded at March 31, 2019 and at December 31, 2018 as the assets of this entity can be used for purposes other than the settlement of the VIE’s obligations.

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SUBSEQUENT EVENTS

3 Months Ended

Mar. 31, 2019

SUBSEQUENT EVENTS

SUBSEQUENT EVENTS

NOTE 17     SUBSEQUENT EVENTS

Management of the Partnership has reviewed subsequent events through May 8, 2019, the date the consolidated financial statements were issued, and concluded there were no events or transactions during this period that would require recognition or disclosure in the consolidated financial statements other than what is disclosed here and/or those already disclosed in the preceding notes.

On April 23, 2019, the board of directors of the General Partner declared the Partnership’s first quarter 2019 cash distribution in the amount of $0.65 per common unit payable on May 13, 2019 to unitholders of record as of May 3, 2019. The declared distribution totaled $47 million and is payable in the following manner: $46 million to common unitholders (including $4 million to the General Partner as a holder of 5,797,106 common units and $7 million to another subsidiary of TC Energy as holder of 11,287,725 common units) and $1 million  to the General Partner for its two percent general partner interest. The General Partner did not receive any distributions in respect of its IDRs for the first quarter 2019.

Northern Border declared its March 2019 distribution of $15 million on April 9, 2019, of which the Partnership received its 50 percent share or $7 million on April 30, 2019.

Great Lakes declared its first quarter 2019 distribution of $49 million on April 16, 2019, of which the Partnership received its 46.45 percent share or $23 million on May 1, 2019.

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 $14 million includes our proportionate share of Iroquois’ unrestricted cash amounting to $2 million (refer to Note 5).

PNGTS declared its first quarter 2019 distribution of $19 million on April 9, 2019, of which $7 million was paid to its non-controlling interest owner on April 30, 2019.

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SIGNIFICANT ACCOUNTING POLICIES (Policies)

3 Months Ended

Mar. 31, 2019

SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation - Consolidation and equity method of accounting

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.

Basis of Presentation - Transactions between entities under common control

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

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

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EQUITY INVESTMENTS (Tables)

3 Months Ended

Mar. 31, 2019

EQUITY INVESTMENTS

Schedule of equity investments and summarized financial information for equity investees

	Ownership		Equity Earnings		Equity Investments
	Interest at		Three months
(unaudited)	March 31,		Ended March 31,		March 31,	December 31,
(millions of dollars)	2019		2019	2018	2019	2018
Northern Border	50	%	21	17	489	497
Great Lakes	46.45	%	20	24	498	489
Iroquois	49.34	%	13	18	209	210
			54	59	1,196	1,196

Northern Border

EQUITY INVESTMENTS

Schedule of equity investments and summarized financial information for equity investees

(unaudited)
(millions of dollars)	March 31, 2019	December 31, 2018
ASSETS
Cash and cash equivalents	14	10
Other current assets	38	36
Property, plant and equipment, net	1,023	1,037
Other assets	13	13
	1,088	1,096
LIABILITIES AND PARTNERS’ EQUITY
Current liabilities	41	34
Deferred credits and other	35	35
Long-term debt, net (a)	264	264
Partners’ equity
Partners’ capital	749	764
Accumulated other comprehensive loss	(1)	(1)
	1,088	1,096

	Three months ended
(unaudited)	March 31,
(millions of dollars)	2019	2018
Transmission revenues	81	72
Operating expenses	(20)	(19)
Depreciation	(15)	(15)
Financial charges and other	(4)	(4)
Net income	42	34

(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

EQUITY INVESTMENTS

Schedule of equity investments and summarized financial information for equity investees

(unaudited)
(millions of dollars)	March 31, 2019	December 31, 2018
ASSETS
Current assets	86	75
Property, plant and equipment, net	685	689
	771	764
LIABILITIES AND PARTNERS’ EQUITY
Current liabilities	25	26
Net long-term debt, including current maturities (a)	229	240
Other long-term liabilities	4	4
Partners' equity	513	494
	771	764

	Three months ended
(unaudited)	March 31,
(millions of dollars)	2019	2018
Transmission revenues	72	81
Operating expenses	(16)	(17)
Depreciation	(8)	(8)
Financial charges and other	(4)	(4)
Net income	44	52

(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

EQUITY INVESTMENTS

Schedule of equity investments and summarized financial information for equity investees

(unaudited)
(millions of dollars)	March 31, 2019	December 31, 2018
ASSETS
Cash and cash equivalents	84	80
Other current assets	30	32
Property, plant and equipment, net	576	581
Other assets	16	8
	706	701
LIABILITIES AND PARTNERS’ EQUITY
Current liabilities	19	19
Long-term debt, net (a)	325	325
Other non-current liabilities	20	14
Partners' equity	342	343
	706	701

	Three months ended
(unaudited)	March 31,
(millions of dollars)	2019	2018
Transmission revenues	52	60
Operating expenses	(15)	(14)
Depreciation	(7)	(7)
Financial charges and other	(3)	(4)
Net income	27	35

^(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.

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DEBT AND CREDIT FACILITIES (Tables)

3 Months Ended

Mar. 31, 2019

DEBT AND CREDIT FACILITIES

Schedule of debt and credit facilities

		Weighted Average				Weighted Average
		Interest Rate for the				Interest Rate for the
(unaudited)		Three Months Ended			December 31,	Year Ended
(millions of dollars)	March 31, 2019	March 31, 2019			2018	December 31, 2018
TC PipeLines, LP
Senior Credit Facility due 2021	—	3.61	%		40	3.14	%
2013 Term Loan Facility due 2022	500	3.73	%		500	3.23	%
4.65% Unsecured Senior Notes due 2021	350	4.65	%	(a)	350	4.65	%	(a)
4.375% Unsecured Senior Notes due 2025	350	4.375	%	(a)	350	4.375	%	(a)
3.90 % Unsecured Senior Notes due 2027	500	3.90	%	(a)	500	3.90	%	(a)
GTN
5.29% Unsecured Senior Notes due 2020	100	5.29	%	(a)	100	5.29	%	(a)
5.69% Unsecured Senior Notes due 2035	150	5.69	%	(a)	150	5.69	%	(a)
Unsecured Term Loan Facility due 2019	35	3.45	%		35	2.93	%
PNGTS
Revolving Credit Facility due 2023	27	3.75	%		19	3.55	%
Tuscarora
Unsecured Term Loan due 2020	24	3.63	%		24	3.10	%
North Baja
Unsecured Term Loan due 2021	50	3.56	%		50	3.54	%
	2,086				2,118
Less: unamortized debt issuance costs and debt discount	10				10
Less: current portion	36				36
	2,040				2,072

(a)Fixed interest rate

Schedule of principal repayments required on debt

(unaudited)
(millions of dollars)	Principal payments
2019	36
2020	123
2021	400
2022	500
2023	27
Thereafter	1,000
	2,086

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NET INCOME PER COMMON UNIT (Tables)

3 Months Ended

Mar. 31, 2019

NET INCOME PER COMMON UNIT

Schedule of net income per common unit

(unaudited)	Three months ended March 31,
(millions of dollars, except per common unit amounts)	2019		2018
Net income attributable to controlling interests		93		96
Net income attributable to the General Partner		(2)		(2)
Net income attributable to common units		91		94
Weighted average common units outstanding (millions) – basic and diluted		71.3		71.2
Net income per common unit – basic and diluted	$	1.28	$	1.32

XML

CHANGE IN OPERATING WORKING CAPITAL (Tables)

3 Months Ended

Mar. 31, 2019

CHANGE IN OPERATING WORKING CAPITAL

Schedule of change in operating working capital

(unaudited)	Three months ended March 31,
(millions of dollars)	2019	2018
Change in accounts receivable and other	7	—
Change in inventories	(1)	—
Change in other current assets	2	(3)
Change in accounts payable and accrued liabilities	(4)	—
Change in accounts payable to affiliates	1	—
Change in accrued interest	8	9
Change in operating working capital	13	6

XML

RELATED PARTY TRANSACTIONS (Tables)

3 Months Ended

Mar. 31, 2019

RELATED PARTY TRANSACTIONS

Summary of capital and operating costs charged to pipeline systems by related party

	Three months ended
(unaudited)	March 31,
(millions of dollars)	2019	2018
Capital and operating costs charged by TC Energy’s subsidiaries to:
Great Lakes (a)	11	9
Northern Border (a)	9	9
GTN	10	8
Bison	1	2
North Baja	1	1
Tuscarora	1	1
PNGTS (a)	2	2
Impact on the Partnership’s net income:
Great Lakes	5	4
Northern Border	4	4
GTN	8	8
Bison	1	2
North Baja	1	1
Tuscarora	1	1
PNGTS	1	1

^(a) Represents 100 percent of the costs.

Summary of amount payable to related party for costs charged

(unaudited)
(millions of dollars)	March 31, 2019	December 31, 2018
Net amounts payable to TC Energy’s subsidiaries are as follows:
Great Lakes (a)	5	3
Northern Border (a)	4	3
GTN	4	4
Bison	—	1
North Baja	1	—
Tuscarora	—	1
PNGTS (a)	1	1

^(a) Represents 100 percent of the costs.

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ACCOUNTS RECEIVABLE AND OTHER (Tables)

3 Months Ended

Mar. 31, 2019

ACCOUNTS RECEIVABLE AND OTHER

Schedule of accounts receivable and other

(unaudited)
(millions of dollars)	March 31, 2019	December 31, 2018
Trade accounts receivable, net of allowance of nil	35	44
Imbalance receivable from affiliates	4	2
Other	2	2
	41	48

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FINANCIAL CHARGES AND OTHER (Tables)

3 Months Ended

Mar. 31, 2019

FINANCIAL CHARGES AND OTHER

Schedule of components of financial charges and other

	Three months ended
(unaudited)	March 31,
(millions of dollars)	2019	2018
Interest expense (a)	23	24
Net realized gain related to the interest rate swaps	(1)	(1)
	22	23

^(a) Includes amortization of debt issuance costs and discount costs.

XML

VARIABLE INTEREST ENTITIES (Tables)

3 Months Ended

Mar. 31, 2019

VARIABLE INTEREST ENTITIES

Schedule of assets and liabilities held through VIEs whose assets cannot be used for purposes other settlement of their obligations

(unaudited)
(millions of dollars)	March 31, 2019	December 31, 2018
ASSETS (LIABILITIES) (a)
Cash and cash equivalents	25	16
Accounts receivable and other	37	39
Inventories	9	8
Other current assets	5	6
Equity investments	1,196	1,196
Property, plant and equipment, net	1,237	1,240
Other assets	1	1
Accounts payable and accrued liabilities	(26)	(33)
Accounts payable to affiliates, net	(38)	(40)
Accrued interest	(5)	(2)
Current portion of long-term debt	(36)	(36)
Long-term debt	(349)	(341)
Other liabilities	(28)	(27)
Deferred state income tax	(9)	(9)

^(a) Bison, an asset held through our consolidated VIEs, is excluded at March 31, 2019 and at December 31, 2018 as the assets of this entity can be used for purposes other than the settlement of the VIE’s obligations.

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ORGANIZATION - Ownership Interests in Natural Gas Pipeline Systems (Details)	3 Months Ended
	Mar. 31, 2019 LimitedPartnership
ORGANIZATION
Number of intermediate limited partnerships through which pipeline assets are owned	3

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ACCOUNTING PRONOUNCEMENTS - Leases (Details) - USD ($) $ in Millions	Mar. 31, 2019	Jan. 01, 2019
ACCOUNTING PRONOUNCEMENTS
Operating ROU assets	$ 0.5	$ 0.6
Operating lease liabilities	$ 0.5	$ 0.6
Weighted average remaining term (in years)	2 years 7 months 17 days
Discount rate (in percent)	3.57%

XML

REGULATORY (Details) - FERC - item	Apr. 04, 2019	Mar. 15, 2019	Feb. 28, 2019
Iroquois
REGULATORY
Reduction of existing maximum system rates (as a percent)			6.50%
Number phases of reduction of rates			2
Reduction of existing maximum system rates effective March 1,2019 (as a percent)			3.25%
Reduction of existing maximum system rates effective April 1,2020 (as a percent)			3.25%
Tuscarora Settlement
REGULATORY
Reduction of existing maximum system rates (as a percent)		1.70%
Additional decrease of unit rate (as a percent)		10.80%
Northern Border
REGULATORY
Decrease in rate (as a percent)	2.00%

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EQUITY INVESTMENTS (Details) - USD ($) $ in Millions			3 Months Ended
	May 01, 2019	Apr. 24, 2019	Mar. 31, 2019	Mar. 31, 2018	Dec. 31, 2018
EQUITY INVESTMENTS
Equity Earnings			$ 54	$ 59
Equity Investments			1,196		$ 1,196
Equity contribution			5	4
LIABILITIES AND PARTNERS' EQUITY
Current portion of long-term debt (Note 7)			36		36
Distributions from Equity Investments
Distributions received from equity investments			58	45
Distributions from equity investments			56	43
Return on investment distribution classified as investing activities			2	2
Great Lakes
EQUITY INVESTMENTS
Total cash call issued to fund debt repayment			$ 11
Iroquois
EQUITY INVESTMENTS
Ownership interest (as a percent)	49.34%		49.34%
Distributions from Equity Investments
Distributions from equity investments	$ 14		$ 14	14
Return on investment distribution classified as investing activities	$ 2		$ 2	2
Limited partners, Distribution declared		$ 28
Northern Border
EQUITY INVESTMENTS
Ownership interest (as a percent)			50.00%
Equity Earnings			$ 21	17
Equity Investments			489		497
ASSETS
Cash and cash equivalents			14		10
Other current assets			38		36
Property, plant and equipment, net			1,023		1,037
Other assets			13		13
Assets, total			1,088		1,096
LIABILITIES AND PARTNERS' EQUITY
Current liabilities			41		34
Deferred credits and other			35		35
Net long-term debt, including current maturities			264		264
Current portion of long-term debt (Note 7)			0		0
Partners' capital			749		764
Accumulated other comprehensive loss			(1)		(1)
Liabilities and Partners' Equity, total			1,088		1,096
Revenues (expenses)
Transmission revenues			81	72
Operating expenses			(20)	(19)
Depreciation			(15)	(15)
Financial charges and other			(4)	(4)
Net income			$ 42	34
Great Lakes
EQUITY INVESTMENTS
Ownership interest (as a percent)			46.45%
Equity Earnings			$ 20	24
Equity Investments			498		489
Equity contribution			5	4
ASSETS
Current assets			86		75
Property, plant and equipment, net			685		689
Assets, total			771		764
LIABILITIES AND PARTNERS' EQUITY
Current liabilities			25		26
Net long-term debt, including current maturities			229		240
Current portion of long-term debt (Note 7)			21		21
Other non-current liabilities			4		4
Partners' capital			513		494
Liabilities and Partners' Equity, total			771		764
Revenues (expenses)
Transmission revenues			72	81
Operating expenses			(16)	(17)
Depreciation			(8)	(8)
Financial charges and other			(4)	(4)
Net income			$ 44	52
Iroquois
EQUITY INVESTMENTS
Ownership interest (as a percent)			49.34%
Equity Earnings			$ 13	18
Equity Investments			209		210
ASSETS
Cash and cash equivalents			84		80
Other current assets			30		32
Property, plant and equipment, net			576		581
Other assets			16		8
Assets, total			706		701
LIABILITIES AND PARTNERS' EQUITY
Current liabilities			19		19
Net long-term debt, including current maturities			325		325
Current portion of long-term debt (Note 7)			146		146
Other non-current liabilities			20		14
Partners' capital			342		343
Liabilities and Partners' Equity, total			706		$ 701
Revenues (expenses)
Transmission revenues			52	60
Operating expenses			(15)	(14)
Depreciation			(7)	(7)
Financial charges and other			(3)	(4)
Net income			$ 27	$ 35

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REVENUES - Contract Balances (Details) - USD ($) $ in Millions	Mar. 31, 2019	Dec. 31, 2018
Contract Balances
Receivables from contracts with customers	$ 35	$ 44

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DEBT AND CREDIT FACILITIES - Amounts Outstanding and Description of Terms (Details) - USD ($) $ in Millions	3 Months Ended	12 Months Ended
	Mar. 31, 2019	Dec. 31, 2018
Credit facilities, short-term loan facility and long-term debt
Total credit facilities, short-term loan facility and long-term debt	$ 2,086	$ 2,118
Less: unamortized debt issuance costs and debt discount	10	10
Less: current portion	36	36
Long-term debt	$ 2,040	2,072
Senior Credit Facility due in 2021 and the Term Loan Facilities due in 2022
Credit facilities, short-term loan facility and long-term debt
Leverage ratio, actual (as a percent)	3.03%
Senior Credit Facility due in 2021 and the Term Loan Facilities due in 2022 | Each fiscal quarter except fiscal quarter and the two following fiscal quarters in which one or more acquisitions has been executed | Maximum
Credit facilities, short-term loan facility and long-term debt
Leverage ratio, covenant (as a percent)	5.00%
Senior Credit Facility due in 2021 and the Term Loan Facilities due in 2022 | Fiscal quarter and the two following fiscal quarters in which one or more acquisitions has been executed | Maximum
Credit facilities, short-term loan facility and long-term debt
Leverage ratio, covenant (as a percent)	5.50%
Revolving credit facility | TC PipeLines, LP Senior Credit Facility due 2021
Credit facilities, short-term loan facility and long-term debt
Debt and credit facilities		$ 40
Weighted average interest rate (as a percent)	3.61%	3.14%
Maximum borrowing capacity	$ 500
Amount outstanding under credit facility	0	$ 40
Revolving credit facility | TC PipeLines, LP Senior Credit Facility due 2021 | LIBOR
Credit facilities, short-term loan facility and long-term debt
Debt interest rate, at period end (as a percent)		3.77%
Term loan | TC PipeLines, LP 2013 Term Loan Facility due 2022
Credit facilities, short-term loan facility and long-term debt
Debt and credit facilities	$ 500	$ 500
Weighted average interest rate (as a percent)	3.73%	3.23%
Term loan | TC PipeLines, LP 2013 Term Loan Facility due 2022 | LIBOR borrowings | LIBOR
Credit facilities, short-term loan facility and long-term debt
Debt interest rate, at period end (as a percent)	3.74%	3.60%
Term loan | TC PipeLines, LP 2013 Term Loan Facility due 2022 | LIBOR borrowings | LIBOR | Hedges of cash flows | Interest rate swaps
Credit facilities, short-term loan facility and long-term debt
Weighted average interest rate (as a percent)	3.26%	3.26%
Unsecured debt | TC PipeLines, LP 4.65% Senior Notes due 2021
Credit facilities, short-term loan facility and long-term debt
Debt and credit facilities	$ 350	$ 350
Stated interest rate (as a percent)	4.65%
Weighted average interest rate (as a percent)	4.65%	4.65%
Unsecured debt | TC PipeLines, LP 4.375% Senior Notes due 2025
Credit facilities, short-term loan facility and long-term debt
Debt and credit facilities	$ 350	$ 350
Stated interest rate (as a percent)	4.375%
Weighted average interest rate (as a percent)	4.375%	4.375%
Unsecured debt | TC PipeLines, LP 3.90% Senior Notes due 2027
Credit facilities, short-term loan facility and long-term debt
Debt and credit facilities	$ 500	$ 500
Stated interest rate (as a percent)	3.90%
Weighted average interest rate (as a percent)	3.90%	3.90%
Unsecured debt | GTN 5.29% Senior Notes due 2020
Credit facilities, short-term loan facility and long-term debt
Stated interest rate (as a percent)	5.29%
Unsecured debt | GTN 5.69% Senior Notes due 2035
Credit facilities, short-term loan facility and long-term debt
Stated interest rate (as a percent)	5.69%
Unsecured debt | Tuscarora Term Loan due 2020
Credit facilities, short-term loan facility and long-term debt
Debt and credit facilities	$ 24	$ 24
Weighted average interest rate (as a percent)	3.63%	3.10%
Unsecured debt | North Baja Term Loan Due 2021
Credit facilities, short-term loan facility and long-term debt
Debt and credit facilities	$ 50	$ 50
Weighted average interest rate (as a percent)	3.56%	3.54%
Unsecured debt | North Baja Term Loan Due 2021 | LIBOR
Credit facilities, short-term loan facility and long-term debt
Debt interest rate, at period end (as a percent)	3.56%	3.54%
GTN | Unsecured debt | GTN 5.29% Senior Notes due 2020
Credit facilities, short-term loan facility and long-term debt
Debt and credit facilities	$ 100	$ 100
Weighted average interest rate (as a percent)	5.29%	5.29%
GTN | Unsecured debt | GTN 5.69% Senior Notes due 2035
Credit facilities, short-term loan facility and long-term debt
Debt and credit facilities	$ 150	$ 150
Weighted average interest rate (as a percent)	5.69%	5.69%
GTN | Unsecured debt | Term Loan Facility due 2019
Credit facilities, short-term loan facility and long-term debt
Debt and credit facilities	$ 35	$ 35
Weighted average interest rate (as a percent)	3.45%	2.93%
Percentage of debt to total capitalization, covenant	42.50%
GTN | Unsecured debt | Term Loan Facility due 2019 | Maximum
Credit facilities, short-term loan facility and long-term debt
Percentage of debt to total capitalization, covenant	70.00%
GTN | Unsecured debt | Term Loan Facility due 2019 | LIBOR
Credit facilities, short-term loan facility and long-term debt
Debt interest rate, at period end (as a percent)	3.44%	3.30%
PNGTS | Secured debt | PNGTS Revolving Credit Facility due 2023
Credit facilities, short-term loan facility and long-term debt
Debt and credit facilities	$ 27	$ 19
Weighted average interest rate (as a percent)	3.75%	3.55%
Leverage ratio, covenant (as a percent)	0.47%
PNGTS | Secured debt | PNGTS Revolving Credit Facility due 2023 | Maximum
Credit facilities, short-term loan facility and long-term debt
Leverage ratio, covenant (as a percent)	5.00%
PNGTS | Secured debt | PNGTS Revolving Credit Facility due 2023 | LIBOR
Credit facilities, short-term loan facility and long-term debt
Debt interest rate, at period end (as a percent)	3.74%	3.60%
Tuscarora | Unsecured debt | Tuscarora Term Loan due 2020
Credit facilities, short-term loan facility and long-term debt
Debt service coverage, covenant (as a percent)	10.14%
Tuscarora | Unsecured debt | Tuscarora Term Loan due 2020 | Minimum
Credit facilities, short-term loan facility and long-term debt
Debt service coverage, covenant (as a percent)	3.00%
Tuscarora | Unsecured debt | Tuscarora Term Loan due 2020 | LIBOR
Credit facilities, short-term loan facility and long-term debt
Debt interest rate, at period end (as a percent)	3.61%	3.47%
North Baja | Unsecured debt | North Baja Term Loan Due 2021
Credit facilities, short-term loan facility and long-term debt
Percentage of debt to total capitalization, actual	38.11%
North Baja | Unsecured debt | North Baja Term Loan Due 2021 | Maximum
Credit facilities, short-term loan facility and long-term debt
Percentage of debt to total capitalization, covenant	70.00%

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DEBT AND CREDIT FACILITIES - Principal Repayments Required (Details) $ in Millions	Mar. 31, 2019 USD ($)
Principal repayments required on debt
2019	$ 36
2020	123
2021	400
2022	500
2023	27
Thereafter	1,000
Total debt	$ 2,086

XML

PARTNERS' EQUITY - ATM Equity Issuance Program (Details)	3 Months Ended
	Mar. 31, 2019 shares
ATM Equity Issuance Program | Common units
PARTNERS' EQUITY
Units sold	0

XML

PARTNERS' EQUITY - Class B Units (Details) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended		12 Months Ended
	Mar. 31, 2019	Mar. 31, 2018	Dec. 31, 2019	Dec. 31, 2018
PARTNERS' EQUITY
Limited Partners, Distributions paid	$ 13	$ 15
Distributions | Class B units
PARTNERS' EQUITY
Limited Partners, Distributions paid	$ 13
TC Energy | Distributions | Class B units
PARTNERS' EQUITY
Percentage of reduction in distributions payable	35.00%
TC Energy | Distributions | Common units
PARTNERS' EQUITY
Percentage of reduction in distributions payable	35.00%
Minimum distribution payable per common unit	$ 3.94
GTN | TC Energy | Distributions | Class B units
PARTNERS' EQUITY
Portion of GTN's annual distributions to which the Class B units are entitled to receive a percentage share of the distributions above threshold (as a percent)	30.00%
Percentage applied to 30 percent of GTN's distributions above threshold for the year ending December 31, 2019	100.00%
Threshold of GTN's total distributable cash flows for payment to Class B units for the year ending December 31, 2019	$ 20
Percentage applied to 30 percent of GTN's distributions above threshold for the year ending December 31, 2020	43.75%
Threshold of GTN's total distributable cash flows for payment to Class B units for the year ending December 31, 2020	$ 20
Percentage applied to 30 percent of GTN's distributions above threshold thereafter	25.00%
Threshold of GTN's distributions for payment to Class B units	$ 20		$ 20	$ 20

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NET INCOME PER COMMON UNIT - General Partner Effective Interest and Allocated Incentive Distributions (Details)	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
General Partner | General Partner
PARTNERS' EQUITY
General partner interest (as a percent)	2.00%	2.00%

XML

NET INCOME PER COMMON UNIT- Terms of Class B Unit Distributions and Determination of Net Income (Loss) per Common Unit (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	3 Months Ended		12 Months Ended
	Mar. 31, 2019	Mar. 31, 2018	Dec. 31, 2019	Dec. 31, 2018
Net income per common unit
Net income attributable to controlling interests	$ 93	$ 96
Net income attributable to the General Partner	(2)	(2)
Class B units
Net income per common unit
Net income attributable to common units	0	0
Common units
Net income per common unit
Net income attributable to common units	$ 91	$ 94
Weighted average common units outstanding - basic (in units)	71.3	71.2
Weighted average common units outstanding - diluted (in units)	71.3	71.2
Net income (loss) per common unit - basic (in dollars per unit)	$ 1.28	$ 1.32
Net income (loss) per common unit - diluted (in dollars per unit)	$ 1.28	$ 1.32
GTN | Class B units | TC Energy | Distributions
Distributions
Percentage applied to GTN's distributable cash flow	30.00%
GTN's distributions for payment to Class B units	$ 20		$ 20	$ 20

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CASH DISTRIBUTIONS PAID TO COMMON UNITS (Details) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Common units
Partners' Equity
Per Unit Distribution, paid (in dollars per unit)	$ 0.65	$ 1.00
Total cash distribution	$ 47	$ 76
General Partner | General Partner
Partners' Equity
Total distribution for General Partner interest	$ 1	$ 2
General partner interest (as a percent)	2.00%	2.00%
General Partner | Common units and General Partner interest combined
Partners' Equity
Incentive distribution paid to the General Partner		$ 3

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CHANGE IN OPERATING WORKING CAPITAL - Components (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
CHANGE IN OPERATING WORKING CAPITAL
Change in accounts receivable and other	$ 7
Change in inventories	(1)
Change in other current assets	2	$ (3)
Change in accounts payable and accrued liabilities	(4)
Change in accounts payable to affiliates	1
Change in accrued interest	8	9
Change in operating working capital	$ 13	$ 6

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RELATED PARTY TRANSACTIONS (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2019	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2018
Capital and operating costs charged to the pipeline systems and amount payable
Net amounts payable	$ 7			$ 6
Amount included in receivables from related party	4			2
General Partner | Reimbursement of costs of services provided
Capital and operating costs charged to the pipeline systems and amount payable
Costs charged	1		$ 1
TC Energy | Great Lakes
Capital and operating costs charged to the pipeline systems and amount payable
Net amounts payable	$ 5			3
Percentage of capital and operating costs charged	100.00%		100.00%
Amount included in receivables from related party	$ 18			18
TC Energy | Great Lakes | Capital and operating costs
Capital and operating costs charged to the pipeline systems and amount payable
Costs charged	11		$ 9
Impact on the Partnership's net income attributable to controlling interests	$ 5		$ 4
Percentage of capital and operating costs charged	100.00%		100.00%
TC Energy | Great Lakes | Transportation contracts | Total net revenues | Customer concentration risk
Capital and operating costs charged to the pipeline systems and amount payable
Percent of total revenues	73.00%		68.00%
TC Energy | Northern Border
Capital and operating costs charged to the pipeline systems and amount payable
Net amounts payable	$ 4			3
Percentage of capital and operating costs charged	100.00%		100.00%
TC Energy | Northern Border | Capital and operating costs
Capital and operating costs charged to the pipeline systems and amount payable
Costs charged	$ 9		$ 9
Impact on the Partnership's net income attributable to controlling interests	$ 4		$ 4
Percentage of capital and operating costs charged	100.00%		100.00%
TC Energy | PNGTS
Capital and operating costs charged to the pipeline systems and amount payable
Net amounts payable	$ 1			1
Percentage of capital and operating costs charged	100.00%		100.00%
TC Energy | PNGTS | Capital and operating costs
Capital and operating costs charged to the pipeline systems and amount payable
Costs charged	$ 2		$ 2
Impact on the Partnership's net income attributable to controlling interests	$ 1		$ 1
Percentage of capital and operating costs charged	100.00%		100.00%
TC Energy | PNGTS | Transportation contracts
Capital and operating costs charged to the pipeline systems and amount payable
Amount included in receivables from related party	$ 0			0
Revenues from related party	0		$ 1
TC Energy | GTN
Capital and operating costs charged to the pipeline systems and amount payable
Net amounts payable	4			4
TC Energy | GTN | Capital and operating costs
Capital and operating costs charged to the pipeline systems and amount payable
Costs charged	10		8
Impact on the Partnership's net income attributable to controlling interests	8		8
TC Energy | Bison
Capital and operating costs charged to the pipeline systems and amount payable
Net amounts payable				1
TC Energy | Bison | Capital and operating costs
Capital and operating costs charged to the pipeline systems and amount payable
Costs charged	1		2
Impact on the Partnership's net income attributable to controlling interests	1		2
TC Energy | North Baja
Capital and operating costs charged to the pipeline systems and amount payable
Net amounts payable	1
TC Energy | North Baja | Capital and operating costs
Capital and operating costs charged to the pipeline systems and amount payable
Costs charged	1		1
Impact on the Partnership's net income attributable to controlling interests	1		1
TC Energy | Tuscarora
Capital and operating costs charged to the pipeline systems and amount payable
Net amounts payable				$ 1
TC Energy | Tuscarora | Capital and operating costs
Capital and operating costs charged to the pipeline systems and amount payable
Costs charged	1		1
Impact on the Partnership's net income attributable to controlling interests	1		$ 1
ANR Pipeline Company | Great Lakes | Transportation contracts
Capital and operating costs charged to the pipeline systems and amount payable
Contract term		15 years
Total contract value		$ 1,300
Affiliates | PNGTS | Construction of facilities
Capital and operating costs charged to the pipeline systems and amount payable
Reimbursement of costs	$ 71

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FAIR VALUE MEASUREMENTS - Estimated Fair Value of Debt (Details) - USD ($) $ in Millions	Mar. 31, 2019	Dec. 31, 2018
Fair Value | Level 2
Financial Instruments
Fair value of debt	$ 2,119	$ 2,101

XML

FAIR VALUE MEASUREMENTS - Interest Rate Swaps (Details) - Interest rate swaps - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018	Dec. 31, 2018
Term loan | TC PipeLines, LP 2013 Term Loan Facility due 2022
Interest rate derivatives
Weighted average fixed interest rate (as a percent)	3.26%
Hedges of cash flows
Interest rate derivatives
Change in fair value of interest rate derivative instruments recognized in other comprehensive income (loss)	$ (5)	$ 7
Hedges of cash flows | Financial charges and other
Interest rate derivatives
Net realized gain related to the interest rate swaps included in financial charges and other	1	$ 1
Hedges of cash flows | Recurring fair value measurement | Level 2
Interest rate derivatives
Fair value of derivative asset, gross	3		$ 8
Fair value of derivative asset, net	$ 3		$ 8

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ACCOUNTS RECEIVABLE AND OTHER (Details) - USD ($) $ in Millions	Mar. 31, 2019	Dec. 31, 2018
ACCOUNTS RECEIVABLE AND OTHER
Trade accounts receivable, net of allowance of nil	$ 35	$ 44
Imbalance receivable from affiliates	4	2
Other	2	2
Accounts receivable and other	41	48
Trade accounts receivable, allowance	$ 0	$ 0

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FINANCIAL CHARGES AND OTHER (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
FINANCIAL CHARGES AND OTHER
Interest expense	$ 23	$ 24
Net realized gain related to the interest rate swaps	(1)	(1)
Financial charges and other	$ 22	$ 23

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VARIABLE INTEREST ENTITIES - Consolidated VIEs (Details) - USD ($) $ in Millions	Mar. 31, 2019	Dec. 31, 2018
ASSETS (LIABILITIES)
Cash and cash equivalents	$ 52	$ 33
Accounts receivable and other	41	48
Inventories	9	8
Other current assets	5	8
Equity investments	1,196	1,196
Property, plant and equipment, net	1,522	1,529
Other assets	3	6
Accounts payable and accrued liabilities	(29)	(36)
Accounts payable to affiliates, net	(7)	(6)
Accrued interest	(20)	(12)
Current portion of long-term debt	(36)	(36)
Long-term debt	(2,040)	(2,072)
Other liabilities	(31)	(29)
Consolidated VIEs | Restricted VIEs
ASSETS (LIABILITIES)
Cash and cash equivalents	25	16
Accounts receivable and other	37	39
Inventories	9	8
Other current assets	5	6
Equity investments	1,196	1,196
Property, plant and equipment, net	1,237	1,240
Other assets	1	1
Accounts payable and accrued liabilities	(26)	(33)
Accounts payable to affiliates, net	(38)	(40)
Accrued interest	(5)	(2)
Current portion of long-term debt	(36)	(36)
Long-term debt	(349)	(341)
Other liabilities	(28)	(27)
Deferred state income tax	$ (9)	$ (9)

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SUBSEQUENT EVENTS - Distributions (Details) - USD ($) $ / shares in Units, $ in Millions								3 Months Ended
	May 13, 2019	May 01, 2019	Apr. 30, 2019	Apr. 24, 2019	Apr. 23, 2019	Apr. 16, 2019	Apr. 09, 2019	Mar. 31, 2019	Mar. 31, 2018
Distributions
Limited Partners, Distributions paid								$ 13	$ 15
Partnership's share of distributions								$ 56	$ 43
Northern Border
Distributions
Ownership interest (as a percent)								50.00%
Great Lakes
Distributions
Ownership interest (as a percent)								46.45%
Subsequent Events | Northern Border
Distributions
Ownership interest (as a percent)			50.00%
Partnership's share of distributions			$ 7
Subsequent Events | Great Lakes
Distributions
Ownership interest (as a percent)		46.45%
Partnership's share of distributions		$ 23
Subsequent Events | Iroquois
Distributions
Ownership interest (as a percent)		49.34%
Partnership's share of distributions		$ 14
Interest in unrestricted cash		$ 2
Subsequent Events | Northern Border
Distributions
Limited partners, Distribution declared							$ 15
Subsequent Events | Great Lakes
Distributions
Limited partners, Distribution declared						$ 49
Subsequent Events | Iroquois
Distributions
Limited partners, Distribution declared				$ 28
Subsequent Events | PNGTS
Distributions
Limited partners, Distribution declared							$ 19
Share of distributions to its non-controlling interest owner			$ 7
General Partner | General Partner
Distributions
Ownership interest in the Partnership (as a percent)								2.00%	2.00%
Forecast | Subsequent Events
Distributions
Limited Partners, Distributions paid	$ 47
Distribution to General Partner	1
Common units | Subsequent Events
Distributions
Per Unit Distribution, declared (in dollars per unit)					$ 0.65
Common units | Subsequent Events | General Partner
Distributions
Ownership interest in the Partnership (as a percent)					2.00%
Common units | General Partner | Subsequent Events
Distributions
Number of units held by investor			5,797,106
Common units | TC Energy | Subsequent Events
Distributions
Number of units held by investor			11,287,725
Common units | Forecast | Subsequent Events
Distributions
Limited Partners, Distributions paid	46
Common units | Forecast | General Partner | Subsequent Events
Distributions
Limited Partners, Distributions paid	4
Common units | Forecast | TC Energy | Subsequent Events
Distributions
Limited Partners, Distributions paid	$ 7