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 September 30, 2017

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 xNo 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 (Do not check if a smaller reporting company)	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

As of November 3, 2017, there were 69,881,012 of the registrant’s common units outstanding.

TC PIPELINES, LP

TABLE OF CONTENTS

		Page No.
PART I	FINANCIAL INFORMATION
Item 1.	Financial Statements (Unaudited)	6
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	29
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	41
Item 4.	Controls and Procedures	43
PART II	OTHER INFORMATION
Item 1.	Legal Proceedings	43
Item 1A.	Risk Factors	45
Item 6.	Exhibits	45
	Signatures	47

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
2015 GTN Acquisition	Partnership’s acquisition of the remaining 30 percent interest in GTN on April 1, 2015
2015 Term Loan Facility	TC PipeLines, LP’s term loan credit facility under a term loan agreement as amended, dated September 29, 2017
2016 PNGTS Acquisition	Partnership’s acquisition of a 49.9 percent interest in PNGTS, effective January 1, 2016
2017 Acquisition	Partnership’s acquisition of an additional 11.81 percent interest in PNGTS and 49.34 percent in Iroquois on June 1, 2017
ASC	Accounting Standards Codification
ASU	Accounting Standards Update
ATM program	At-the-market equity issuance program
Bison	Bison Pipeline LLC
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
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	Third Amended and Restated Agreement of Limited Partnership of the Partnership
PHMSA	U.S. Department of Transportation Pipeline and Hazardous Materials Safety Administration
PNGTS	Portland Natural Gas Transmission System
Term Loan Facilities	The 2013 Term Loan Facility and the 2015 Term Loan Facility, collectively
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
TransCanada	TransCanada Corporation and its subsidiaries
Tuscarora	Tuscarora Gas Transmission Company
U.S.	United States of America
VIEs	Variable Interest Entities

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, market or competitive conditions, regulations, organic or strategic growth opportunities, contract renewals and ability to market open capacity, business prospects, outcome of regulatory proceedings and cash distributions to unitholders.

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

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

· demand for natural gas;

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

· natural gas prices and regional differences;

· weather conditions;

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

· competition from other pipeline systems;

· natural gas storage levels; and

· rates and terms of service;

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

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

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

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

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

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

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

·the impact of any impairment charges;

·cybersecurity threats, acts of terrorism and related disruptions;

·the impact of new accounting pronouncements;

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

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

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

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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 I, Item 1A. “Risk Factors”of our Annual Report on Form 10-K for the year ended December 31, 2016 as filed with the SEC on February 28, 2017. 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						Nine months ended
(unaudited)	September 30,						September 30,
(millions of dollars, except per common unit amounts)	2017			2016 (a)			2017			2016 (a)
Transmission revenues	100			103			313			315
Equity earnings (Note 4)	27			22			87			75
Operation and maintenance expenses	(16		)	(15		)	(47		)	(42		)
Property taxes	(7		)	(7		)	(21		)	(20		)
General and administrative	(1		)	(1		)	(6		)	(5		)
Depreciation	(25		)	(24		)	(73		)	(71		)
Financial charges and other (Note 14)	(23		)	(18		)	(59		)	(53		)
Net income before taxes	55			60			194			199
Income taxes (Note 18)	—			—			(1		)	(1		)
Net income	55			60			193			198
Net income attributable to non-controlling interests	1			2			7			10
Net income attributable to controlling interests	54			58			186			188
Net income attributable to controlling interest allocation (Note 8)
Common units	42			43			164			164
General Partner	4			4			12			9
TransCanada and its subsidiaries	8			11			10			15
	54			58			186			188
Net income per common unit (Note 8) — basic and diluted	$	0.61		$	0.65	(b)	$	2.38		$	2.51	(b)
Weighted average common units outstanding — basic and diluted (millions)	69.4			66.1			68.9			65.3
Common units outstanding, end of period (millions)	69.6			66.6			69.6			66.6

(a)Recast to consolidate PNGTS for all periods presented (Refer to Notes 2 and 6).

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

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

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TC PIPELINES, LP CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

	Three months ended		Nine months ended
(unaudited)	September 30,		September 30,
(millions of dollars)	2017	2016(a)	2017	2016(a)
Net income	55	60	193	198
Other comprehensive income
Change in fair value of cash flow hedges (Note 12)	—	2	1	(1	)
Amortization of realized loss on derivative financial instruments (Note 12)	—	—	1	1
Reclassification to net income of gains and losses on cash flow hedges (Note 12)	1	—	—	—
Comprehensive income	56	62	195	198
Comprehensive income attributable to non-controlling interests	1	2	7	10
Comprehensive income attributable to controlling interests	55	60	188	188

(a)Recast to consolidate PNGTS for all periods presented (Refer to Notes 2 and 6).

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)	September 30, 2017	December 31, 2016 (a)
ASSETS
Current Assets
Cash and cash equivalents	73	64
Accounts receivable and other (Note 13)	35	47
Inventories	7	7
Other	6	7
	121	125
Equity investments (Note 4)	1,207	918
Plant, property and equipment
(Net of $1,158 accumulated depreciation; 2016 - $1,088)	2,133	2,180
Goodwill	130	130
Other assets	—	1
	3,591	3,354
LIABILITIES AND PARTNERS’ EQUITY
Current Liabilities
Accounts payable and accrued liabilities	31	29
Accounts payable to affiliates (Note 11)	5	8
Distribution payable	—	3
Accrued interest	21	10
Current portion of long-term debt (Note 5)	51	52
	108	102
Long-term debt, net (Note 5)	2,427	1,859
Deferred state income taxes (Note 18)	10	10
Other liabilities	28	28
	2,573	1,999
Common units subject to rescission (Note 7)	—	83
Partners’ Equity
Common units	790	1,002
Class B units (Note 7)	103	117
General partner	23	27
Accumulated other comprehensive loss	—	(2	)
Controlling interests	916	1,144
Non-controlling interests	102	97
Equity of former parent of PNGTS	—	31
	1,018	1,272
	3,591	3,354

Contingencies (Note 15)

Variable Interest Entities (Note 17)

Subsequent Events (Note 19)

(a)Recast to consolidate PNGTS for all periods presented (Refer to Notes 2 and 6).

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

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TC PIPELINES, LP

CONSOLIDATED STATEMENT OF CASH FLOWS

	Nine months ended
(unaudited)	September 30,
(millions of dollars)	2017		2016 (a)
Cash Generated From Operations
Net income	193		198
Depreciation	73		71
Amortization of debt issue costs reported as interest expense	1		1
Amortization of realized loss on derivative instrument	1		1
Deferred state income tax recovery (Note 18)	—		—
Equity earnings from equity investments (Notes 3 and 4)	(87	)	(75	)
Distributions received from operating activities of equity investments (Note 3)	106		125
Change in operating working capital (Note 10)	24		11
	311		332
Investing Activities
Investment in Northern Border (Note 4)	(83	)	—
Investment in Great Lakes (Note 4)	(4	)	(4	)
Distribution received from Iroquois as return of investment (Note 4)	3		—
Acquisition of a 49.9 percent interest in PNGTS	—		(193	)
Acquisition of a 49.34 percent in Iroquois and an additional 11.81 percent in PNGTS (Note 6)	(646	)	—
Capital expenditures	(26	)	(21	)
Other	—		3
	(756	)	(215	)
Financing Activities
Distributions paid (Note 9)	(210	)	(184	)
Distributions paid to Class B units (Note 7)	(22	)	(12	)
Distributions paid to non-controlling interests	(5	)	(12	)
Distributions paid to former parent of PNGTS	(1	)	(9	)
Common unit issuance, net (Note 7)	126		35
Common unit issuance subject to rescission, net (Note 7)	—		83
Long-term debt issued, net of discount (Note 5)	732		200
Long-term debt repaid (Note 5)	(164	)	(196	)
Debt issuance costs	(2	)	—
	454		(95	)
Decrease in cash and cash equivalents	9		22
Cash and cash equivalents, beginning of period	64		55
Cash and cash equivalents, end of period	73		77

(a)Recast to consolidate PNGTS for all periods presented (Refer to Notes 2 and 6).

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

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TC PIPELINES, LP

CONSOLIDATED STATEMENT OF CHANGES IN PARTNERS’ EQUITY

	Limited Partners
	Common Units			Class B Units			General Partner		Accumulated Other Comprehensive Loss (a) (b)		Non- Controlling Interest(b)		Equity of former parent of PNGTS(b)		Total Equity(b)
(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		millions of dollars
Partners’ Equity at December 31, 2016	67.4	1,002		1.9	117		27		(2	)	97		31		1,272
Net income (b)	—	164		—	8		12		—		7		2		193
Other comprehensive income	—	—		—	—		—		2		—		—		2
ATM equity issuances, net (Note 7)	2.2	124		—	—		2		—		—		—		126
Reclassification of common units no longer subject to rescission (Note 7)	—	81		—	—		2		—		—		—		83
Acquisition of interests in PNGTS and Iroquois (Note 6)	—	(383	)	—	—		(8	)	—		—		(32	)	(423	)
Distributions (b)	—	(198	)	—	(22	)	(12	)	—		(2	)	(1	)	(235	)
Partners’ Equity at September 30, 2017	69.6	790		1.9	103		23		—		102		—		1,018

(a)Losses related to cash flow hedges reported in Accumulated Other Comprehensive Loss and expected to be reclassified to Net Income in the next 12 months are estimated to be $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.

(b)Recast to consolidate PNGTS for all periods presented (Refer to Notes 2 and 6).

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 1ORGANIZATION

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

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

NOTE 2 SIGNIFICANT ACCOUNTING POLICIES

The accompanying financial statements and related notes have been prepared in accordance with United States generally accepted accounting principles (GAAP) and amounts are stated in U.S. dollars. The results of operations for the three and nine months ended September 30, 2017 and 2016 are not necessarily indicative of the results that may be expected for the full fiscal year.

The accompanying financial statements should be read in conjunction with the audited financial statements and notes thereto for the year ended December 31, 2016 included as exhibit 99.2 in our Current Report on Form 8-K dated August 3, 2017. That report contains a more comprehensive summary of the Partnership’s significant accounting policies. In the opinion of management, the accompanying financial statements contain all of the appropriate adjustments, all of which are normally recurring adjustments unless otherwise noted, and considered necessary to present fairly the financial position of the Partnership, the results of operations and cash flows for the respective periods. Our significant accounting policies are consistent with those disclosed in our audited financial statements and notes thereto for the year ended December 31, 2016 included as exhibit 99.2 in our Current Report on Form 8-K dated August 3, 2017, except as described in Note 3, Accounting Pronouncements.

Basis of Presentation

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

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

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

On June 1, 2017, the Partnership acquired from a subsidiary of TransCanada an additional 11.81 percent interest in PNGTS, that resulted in the Partnership owning a 61.71 percent interest in PNGTS (Refer to Note 6).  As a result of the Partnership owning 61.71 percent interest in PNGTS, the Partnership’s historical financial information has been recast, except net income (loss) per common unit, to consolidate PNGTS for all the periods presented in the Partnership’s consolidated financial statements. Additionally, this acquisition was accounted for as transaction between entities under common control, similar to pooling of interests, whereby the assets and liabilities of PNGTS were recorded at TransCanada’s carrying value.

Also, on June 1, 2017, the Partnership acquired from subsidiaries of TransCanada a 49.34 percent interest in Iroquois Gas Transmission, L.P. (“Iroquois”) (Refer to Note 6). Accordingly, this transaction was accounted for as a transaction between entities under common control, similar to pooling of interest, whereby the equity investment in Iroquois was recorded at TransCanada’s carrying value and was accounted for prospectively.

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Use of Estimates

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

NOTE 3ACCOUNTING PRONOUNCEMENTS

Retrospective application of Accounting Standards Update (ASU) No 2016-15 “Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments”

In August 2016, the Financial Accounting Standards Board (FASB) issued an amendment of previously issued guidance, which intends to reduce diversity in practice in how certain transactions are classified in the statement of cash flows. The new guidance is effective January 1, 2018, however, as early adoption is permitted, the Partnership elected to retrospectively apply this guidance effective December 31, 2016. The Partnership has elected to classify distributions received from equity method investees using the nature of distributions approach as it is more representative of the nature of the underlying activities of the investees that generated the distributions. As a result, certain comparative period distributions received from equity method investees, amounting to $50 million for the nine months ended September 30, 2016, have been reclassified from investing activities to cash generated from operations in the consolidated statement of cash flows.

Effective January 1, 2017

Inventory

In July 2015, the FASB issued new guidance on simplifying the measurement of inventory. The new guidance specifies that an entity should measure inventory within the scope of this update at the lower of cost and net realizable value. Net realizable value is the estimated selling price in the ordinary course of business, less reasonably predictable costs of completion, disposal and transportation. This new guidance was effective January 1, 2017, was applied prospectively and did not have a material impact on the Partnership’s consolidated balance sheet.

Equity method and joint ventures

In March 2016, the FASB issued new guidance that simplifies the transition to equity method accounting. The new guidance eliminates the requirement to retroactively apply the equity method of accounting when an increase in ownership interest in an investment qualifies for equity method accounting. The new guidance is effective January 1, 2017 and was applied prospectively. The application of this guidance did not have a material impact on the Partnership’s consolidated financial statements.

Consolidation

In October 2016, the FASB issued new guidance on consolidation relating to interests held through related parties that are under common control.  The new guidance amends the consolidation requirements such that if a decision maker is required to evaluate whether it is the primary beneficiary of a variable interest entry (VIE), it will need to consider only its proportionate indirect interest in the VIE held through a common control party.  The guidance was effective January 1, 2017, was applied retrospectively and did not result in any change to our consolidation conclusions.

Future accounting changes

Revenue from contracts with customers

In 2014, the FASB issued new guidance on revenue from contracts with customers. The new guidance requires that an entity recognize revenue in accordance with a prescribed model. This model is used to depict the transfer of promised goods or services to customers in an amount that reflects the total consideration to which it expects to be entitled during the term of the contract in exchange for those goods or services. The new guidance also requires additional disclosures about the nature, amount, timing and uncertainty of revenue and the related cash flows. The Partnership will adopt the new standard on the effective date of January 1, 2018. There are two methods in which the new standard can be adopted: (1) a full retrospective approach with restatement of all prior periods presented, or (2) a modified retrospective approach with a cumulative-effect adjustment as of the date of adoption. The Partnership will adopt the

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standard using the modified retrospective approach with the cumulative-effect of the adjustment recognized at the date of adoption, subject to allowable and elected practical expedients.

The Partnership has identified all existing customer contracts that are within the scope of the new guidance and is on schedule in the process of analyzing individual contracts or groups of contracts to identify any significant changes in how revenues are recognized as a result of implementing the new guidance. While the Partnership has not identified any material differences in the amount and timing of revenue recognition for the contracts that have been analyzed to date, the evaluation is not complete and the Partnership has not concluded on the overall impact of adopting the new guidance. The Partnership continues its contract analysis to obtain the information necessary to quantify the cumulative-effect adjustment, if any, on prior period revenues and revenue recognized going forward.

Although consolidated revenues may not be materially impacted by the new guidance, the Partnership currently anticipates significant changes to disclosures based on the additional requirements prescribed. These new disclosures include information regarding the significant judgments used in evaluating when and how revenue is recognized and information related to contract assets and liabilities. In addition, the new guidance requires that the Partnership’s revenue recognition policy disclosure includes additional detail regarding the various performance obligations and the nature, amount, timing and estimates of revenue and cash flows generated from contracts with customers. The Partnership continues to develop and evaluate disclosures required with a particular focus on the scope of contracts subject to disclosure of remaining performance obligations. The Partnership also continues to address any system and process changes necessary to compile the information to meet the recognition and disclosure requirements of the new guidance. The Partnership continues to monitor additional authoritative or interpretive guidance related to the new guidance as it becomes available.

Leases

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

The new guidance is effective on January 1, 2019, with early adoption permitted. A modified retrospective transition approach is required for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements, with certain practical expedients available. The Partnership is continuing to identify and analyze existing lease agreements to determine the effect of adoption of the new guidance on its consolidated financial statements. The Partnership is also addressing system and process changes necessary to compile the information to meet the recognition and disclosure requirements of the new guidance.

Goodwill Impairment

In January 2017, the FASB issued new guidance on simplifying the test for goodwill impairment by eliminating the requirement to calculate the implied fair value of goodwill to measure the impairment charge. Instead, entities will record an impairment charge based on the excess of a reporting unit’s carrying amount over its fair value. This new guidance is effective January 1, 2020 and will be applied prospectively. Early adoption is permitted. The Partnership is currently evaluating the impact of the adoption of this guidance and has not yet determined the effect on its consolidated financial statements.

Hedge Accounting

In August 2017, the FASB issued new guidance on hedge accounting, making more financial and nonfinancial hedging strategies eligible for hedge accounting. The new guidance amends the presentation requirements relating to the change in fair value of a derivative and additional disclosure requirements include cumulative basis adjustments for fair value hedges and the effect of hedging on individual statement of income line items. This new guidance is effective January 1, 2019 and will be applied prospectively with a cumulative-effect adjustment to opening equity on adoption. Early adoption is permitted. The Partnership is currently evaluating the impact of the adoption of this guidance and has not yet determined the effect on its consolidated financial statements.

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NOTE 4EQUITY INVESTMENTS

The Partnership has equity interests in Northern Border, Great Lakes and effective June 1, 2017, Iroquois. The pipeline systems owned by these entities are regulated by FERC. The pipeline systems of Northern Border and Great Lakes are operated by subsidiaries of TransCanada. The Iroquois pipeline system is operated by Iroquois Pipeline Operating Company, a wholly owned subsidiary of Iroquois. The Partnership uses the equity method of accounting for its interests in its equity investees. The Partnership’s equity investments are held through our ILPs that are considered to be variable interest entities (VIEs) (Refer to Note 17).

	Ownership		Equity Earnings				Equity Investments
	Interest at		Three months		Nine Months
(unaudited)	September 30,		ended September 30,		ended September 30,		September 30,	December 31,
(millions of dollars)	2017		2017	2016(b)	2017	2016(b)	2017	2016(b)
Northern Border (a)	50	%	16	18	50	52	516	444
Great Lakes	46.45	%	2	4	24	23	469	474
Iroquois	49.34	%	9	—	13	—	222	—
			27	22	87	75	1,207	918

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

(b)Recast to eliminate equity earnings from PNGTS and consolidate PNGTS for all periods presented (Refer to Notes 2 and 6).

Northern Border

On September 1, 2017, the Partnership made an equity contribution to Northern Border amounting to $83 million. This amount represents the Partnership’s 50 percent share of $166 million capital contribution request from Northern Border to reduce the outstanding balance of its revolver debt to increase its available borrowing capacity.

The Partnership did not have undistributed earnings from Northern Border for the three and nine months ended September 30, 2017 and 2016.

The summarized financial information for Northern Border is as follows:

(unaudited)
(millions of dollars)	September 30, 2017		December 31, 2016
ASSETS
Cash and cash equivalents	24		14
Other current assets	36		36
Plant, property and equipment, net	1,069		1,089
Other assets	14		14
	1,143		1,153
LIABILITIES AND PARTNERS’ EQUITY
Current liabilities	48		38
Deferred credits and other	30		28
Long-term debt, including current maturities, net	264		430
Partners’ equity
Partners’ capital	802		659
Accumulated other comprehensive loss	(1	)	(2	)
	1,143		1,153

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	Three months ended				Nine months ended
(unaudited)	September 30,				September 30,
(millions of dollars)	2017		2016		2017		2016
Transmission revenues	73		74		217		218
Operating expenses	(20	)	(18	)	(56	)	(53	)
Depreciation	(15	)	(15	)	(45	)	(44	)
Financial charges and other	(5	)	(5	)	(14	)	(16	)
Net income	33		36		102		105

Great Lakes

The Partnership made an equity contribution to Great Lakes of $4 million in the first quarter of 2017. This amount represents the Partnership’s 46.45 percent share of a $9 million cash call from Great Lakes to make a scheduled debt repayment.

The Partnership did not have undistributed earnings from Great Lakes for the three and nine months ended September 30, 2017 and 2016.

The summarized financial information for Great Lakes is as follows:

(unaudited)
(millions of dollars)	September 30, 2017	December 31, 2016
ASSETS
Current assets	56	66
Plant, property and equipment, net	705	714
	761	780
LIABILITIES AND PARTNERS’ EQUITY
Current liabilities	41	40
Net long-term debt, including current maturities	269	278
Partners’ equity	451	462
	761	780

	Three months ended				Nine months ended
(unaudited)	September 30,				September 30,
(millions of dollars)	2017		2016		2017		2016
Transmission revenues	34		36		138		133
Operating expenses	(19	)	(15	)	(49	)	(45	)
Depreciation	(7	)	(7	)	(21	)	(21	)
Financial charges and other	(5	)	(6	)	(16	)	(17	)
Net income	3		8		52		50

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Iroquois

On June 1, 2017, the Partnership acquired a 49.34 percent interest in Iroquois. Also on July 27, 2017, Iroquois declared its second quarter 2017 distribution of $28 million, of which the Partnership received its 49.34 percent share or $14 million on August 1, 2017. The distribution includes the Partnership’s 49.34 percent share of the Iroquois unrestricted cash distribution amounting to approximately $2.6 million (Refer to Note 6). This amount is reported as distributions received as return of investment in the Partnership’s consolidated statement of cash flows.

The Partnership recorded no undistributed earnings from Iroquois in the three and nine months ended September 30, 2017.

The summarized financial information for Iroquois is as follows:

(unaudited)
(millions of dollars)	September 30, 2017	December 31, 2016
ASSETS
Cash and cash equivalents	93	86
Other current assets	33	34
Plant, property and equipment, net	592	604
Other assets	8	7
	726	731
LIABILITIES AND PARTNERS’ EQUITY
Current liabilities	20	18
Net long-term debt, including current maturities	332	335
Other non-current liabilities	9	6
Partners’ equity	365	372
	726	731

	Three months ended				Nine months ended
(unaudited)	September 30,				September 30,
(millions of dollars)	2017		2016		2017		2016
Transmission revenues	43		45		142		145
Operating expenses	(13	)	(13	)	(41	)	(43	)
Depreciation	(7	)	(9	)	(22	)	(28	)
Financial charges and other	(4	)	(4	)	(13	)	(12	)
Net income	19		19		66		62

NOTE 5 DEBT AND CREDIT FACILITIES

(unaudited) (millions of dollars)	September 30, 2017	Weighted Average Interest Rate for the Nine Months Ended September 30, 2017		December 31, 2016 (a)	Weighted Average Interest Rate for the Year Ended December 31, 2016
TC PipeLines, LP
Senior Credit Facility due 2021	255	2.34	%	160	1.72	%
2013 Term Loan Facility due October 2022	500	2.26	%	500	1.73	%
2015 Term Loan Facility due October 2020	170	2.15	%	170	1.63	%
4.65% Unsecured Senior Notes due 2021	350	4.65	%(b)	350	4.65	%(b)
4.375% Unsecured Senior Notes due 2025	350	4.375	%(b)	350	4.375	%(b)
3.90 % Unsecured Senior Notes due 2027	500	3.90	%(b)	—	—
GTN
5.29% Unsecured Senior Notes due 2020	100	5.29	%(b)	100	5.29	%(b)
5.69% Unsecured Senior Notes due 2035	150	5.69	%(b)	150	5.69	%(b)
Unsecured Term Loan Facility due 2019	55	1.95	%	65	1.43	%
PNGTS
5.90% Senior Secured Notes due December 2018	36	5.90	%(b)	53	5.90	%(b)
Tuscarora
Unsecured Term Loan due 2020	25	2.18	%	10	1.64	%
3.82% Series D Senior Notes due August 2017	—	3.82	%(b)	12	3.82	%(b)
	2,491			1,920
Less: unamortized debt issuance costs and debt discount	13			9
Less: current portion	51			52
	2,427			1,859

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(a)Recast to consolidate PNGTS for all periods presented (Refer to Notes 2 and 6).

(b)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, under which $255 million was outstanding at September 30, 2017 (December 31, 2016 - $160 million), leaving $245 million available for future borrowing. The LIBOR-based interest rate on the Senior Credit Facility was 2.49 percent at September 30, 2017 (December 31, 2016 — 1.92 percent).

On September 29, 2017, the Partnership’s 2013 Term Loan Facility that was due on July 1, 2018 was amended to extend the maturity period through October 2, 2022. As of September 30, 2017, the variable interest rate exposure related to the 2013 Term Loan Facility was hedged by fixed interest rate swap arrangements and our effective interest rate was 2.31 percent (December 31, 2016 — 2.31 percent). Prior to hedging activities, the LIBOR-based interest rate on the 2013 Term Loan Facility was 2.49 percent at September 30, 2017 (December 31, 2016 — 1.87 percent).

On September 29, 2017, the Partnership’s 2015 Term Loan Facility that was due on October 1, 2018 was amended to extend the maturity period through October 1, 2020. The LIBOR-based interest rate on the 2015 Term Loan Facility was 2.39 percent at September 30, 2017 (December 31, 2016 — 1.77 percent).

The 2013 Term Loan Facility and the 2015 Term Loan Facility (collectively, the Term Loan Facilities) and the Senior Credit Facility  require the Partnership to maintain a certain leverage ratio (debt to adjusted cash flow [net income plus cash distributions received, extraordinary losses, interest expense, expense for taxes paid or accrued, and depreciation and amortization expense less equity earnings and extraordinary gains]) no greater than 5.00 to 1.00 for each fiscal quarter, except for the fiscal quarter and the two following fiscal quarters in which one or more acquisitions has been executed, in which case the leverage ratio is to be no greater than 5.50 to 1.00. The leverage ratio was 4.76 to 1.00 as of September 30, 2017.

On May 25, 2017, the Partnership closed a $500 million public offering of senior unsecured notes bearing an interest rate of 3.90 percent maturing May 25, 2027. The net proceeds of $497 million were used to fund a portion of the 2017 Acquisition (Refer to Note 6). The indenture for the notes contains customary investment grade covenants.

PNGTS

PNGTS’ Senior Secured Notes are secured by the PNGTS long-term firm shipper contracts and its partners’ pledge of their equity and a guarantee of debt service for six months. PNGTS is restricted under the terms of its note purchase agreement from making cash distributions unless certain conditions are met. Before a distribution can be made, the debt service reserve account must be fully funded and PNGTS’ debt service coverage ratio for the preceding and succeeding twelve months must be 1.30 or greater. At September 30, 2017, the debt service coverage ratio was 1.71 for the twelve

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preceding months and 5.31 for the twelve succeeding months. Therefore, PNGTS was not restricted to make any cash distributions.

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 September 30, 2017 was 44.2 percent. The LIBOR-based interest rate on the GTN’s Unsecured Term Loan Facility was 2.19 percent at September 30, 2017 (December 31, 2016 — 1.57 percent).

Tuscarora

On August 21, 2017, Tuscarora refinanced all of its outstanding debt by amending its existing Unsecured Term Loan Facility and issuing a new $25 million variable rate term loan that will require yearly principal payments and will mature on August 21, 2020. Tuscarora’s Unsecured Term Loan contains a covenant that requires Tuscarora to maintain a debt service coverage ratio (cash available from operations divided by a sum of interest expense and principal payments) of greater than or equal to 3.00 to 1.00. As of September 30, 2017, the ratio was 3.08 to 1.00.

The LIBOR-based interest rate on the Tuscarora’s Unsecured Term Loan Facility was 2.36 percent at September 30, 2017 (December 31, 2016 — 1.90 percent).

At September 30, 2017, the Partnership was in compliance with its financial covenants, in addition to the other covenants which include restrictions on entering into mergers, consolidations and sales of assets, granting liens, material amendments to the Third 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)
2017	12
2018	45
2019	36
2020	293
2021	605
Thereafter	1,500
	2,491

NOTE 6ACQUISITION

2017 Acquisition

On June 1, 2017, the Partnership acquired from subsidiaries of TransCanada a 49.34 percent interest in Iroquois, including an option to acquire a further 0.66 percent interest in Iroquois, together with an additional 11.81 percent interest in PNGTS resulting in the Partnership owning a 61.71 percent interest in PNGTS (2017 Acquisition). The total purchase price of the 2017 Acquisition was $765 million plus final purchase price adjustments amounting to $50 million. The purchase price consisted of (i) $710 million for the Iroquois interest (less $164 million, which reflected our 49.34 percent share of Iroquois outstanding debt on June 1, 2017), (ii) $55 million for the additional 11.81 percent interest in PNGTS (less $5 million, which reflected our 11.81% proportionate share in PNGTS’ outstanding debt on June 1, 2017) (iii) final working capital adjustments on PNGTS and Iroquois amounting to $3 million and $19 million, respectively and (iv) additional consideration for Iroquois’ surplus cash amounting to $28 million. Additionally, the Partnership paid $1,000 for the option to acquire TransCanada’s remaining 0.66 percent interest in Iroquois. The Partnership funded the cash portion of the 2017 Acquisition through a combination of proceeds from the May 2017 public debt offering (refer to Note 5) and borrowing under our Senior Credit Facility.

At the date of the 2017 Acquisition, there was significant cash on Iroquois’ balance sheet.  Pursuant to the Purchase and Sale Agreement associated with the acquisition of the Iroquois interest, as amended, the Partnership agreed to pay $28 million plus interest to TransCanada on August 1, 2017 for its 49.34 percent share of cash determined to be surplus to Iroquois’ operating needs.

Additionally, Iroquois’ partners adopted a distribution resolution to address the significant cash on Iroquois’ balance sheet post-closing. The Partnership expects to receive the $28 million of unrestricted cash as part of its quarterly

18

distributions from Iroquois over 11 quarters under the terms of the resolution, which began with Iroquois’ second quarter 2017 distribution on August 1, 2017. As of November 6, 2017 the Partnership has received approximately $5.2 million of the expected $28 million, of which $2.6 million was received on November 1, 2017 (Refer to Note 19).

The acquisition of a 49.34 percent interest in Iroquois was accounted for as a transaction between entities under common control, whereby the equity investment in Iroquois was recorded at TransCanada’s carrying value and the total excess purchase price paid was recorded as a reduction in Partners’ Equity.

Iroquois’ net purchase price was allocated as follows:

(millions of dollars)
Net Purchase Price (a)	593
Less: TransCanada’s carrying value of Iroquois at June 1, 2017	223
Excess purchase price (b)	370

(a)Total purchase price of $710 million plus final working capital adjustment of $19 million and the additional consideration on Iroquois surplus cash amounting to approximately $28 million less the assumption of $164 million of proportional Iroquois debt by the Partnership.

(b)The excess purchase price of $370 million was recorded as a reduction in Partners’ Equity.

The acquisition of an additional 11.81 percent interest in PNGTS, which resulted in the Partnership owning 61.71 percent in PNGTS, was accounted for as a transaction between entities under common control, similar to a pooling of interests, whereby assets and liabilities of PNGTS were recorded at TransCanada’s carrying value and the Partnership’s historical financial information, except net income per common unit, was recast to consolidate PNGTS for all periods presented.

The PNGTS purchase price was recorded as follows:

(millions of dollars)
Current assets	25
Property, plant and equipment, net	294
Current liabilities	(4	)
Deferred state income taxes	(10	)
Long-term debt, including current portion	(41	)
	264
Non-controlling interest	(100	)
Carrying value of pre-existing Investment in PNGTS	(132	)
TransCanada’s carrying value of the acquired 11.81 percent interest at June 1, 2017	32
Excess purchase price over net assets acquired (a)	21
Total cash consideration (b)	53

(a)The excess purchase price of $21 million was recorded as a reduction in Partners’ Equity.

(b)Total purchase price of $55 million plus the final working capital adjustment of $3 million less the assumption of $5 million of proportional PNGTS debt by the Partnership.

NOTE 7 PARTNERS’ EQUITY

ATM equity issuance program (ATM program)

During the nine months ended September 30, 2017, we issued 2,165,162 common units under our ATM program generating net proceeds of approximately $124 million, plus $2 million contributed by the General Partner to maintain its effective two percent general partner interest. The commissions to our sales agents in the nine months ended September 30, 2017 were approximately $1 million. The net proceeds were used for general partnership purposes.

Class B units issued to TransCanada

The Class B Units we issued on April 1, 2015 to finance a portion of the 2015 GTN Acquisition represent a limited partner interest in us and entitle TransCanada to an annual distribution based on 30 percent of GTN’s annual

19

distributions as follows: (i) 100 percent of distributions above $20 million through March 31, 2020; and (ii) 25 percent of distributions above $20 million thereafter.

For the year ending December 31, 2017, the Class B units’ equity account will be increased by the excess of 30 percent of GTN’s distributions over the annual threshold of $20 million until such amount is declared for distribution and paid in the first quarter of 2018. During the nine months ended September 30, 2017, 30 percent of GTN’s total distributable cash flow was $28 million. As a result of exceeding the $20 million threshold, the Class B units’ equity account was increased by $8 million (Refer to Note 8).

For the year ended December 31, 2016, the Class B distribution was $22 million and was declared and paid in the first quarter of 2017.

Common unit issuance subject to rescission

In connection with a late filing of an employee-related Form 8-K with the SEC in March 2016, the Partnership became ineligible to use the then effective shelf registration statement upon filing of its Annual Report on Form 10-K for the year ended December 31, 2015. As a result, it was determined that the purchasers of the 1.6 million common units that were issued from March 8, 2016 to May 19, 2016 under the Partnership’s ATM program may have had a rescission right for an amount equal to the purchase price paid for the units, plus statutory interest and less any distributions paid, upon the return of such units to the Partnership. The Securities Act of 1933, as amended (Securities Act) generally requires that any claim brought for a violation of Section 5 of the Securities Act be brought within one year of violation.

At December 31, 2016, $83 million was recorded as common units subject to rescission on the consolidated balance sheet.  The Partnership classified the 1.6 million common units that were sold under its ATM program from March 8, 2016 up to and including May 19, 2016, which may have been subject to rescission rights, outside of equity given the potential redemption feature which was not within the control of the Partnership. These units were treated as outstanding for financial reporting purposes.

No unitholder claimed or attempted to exercise any rescission rights prior to their expiry dates and the final rights related to the sales of such units expired on May 19, 2017. As a result of the expiration of these rights, the $83 million was reclassified back to partners’ equity. At September 30, 2017, there were no outstanding common units subject to rescission on the Partnership’s consolidated balance sheet.

NOTE 8 NET INCOME PER COMMON UNIT

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

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

The amount allocable to the Class B units in 2017 equals 30 percent of GTN’s distributable cash flow during the year ended December 31, 2017 less $20 million (December 31, 2016 —$20 million).

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Net income per common unit was determined as follows:

	Three months ended September 30,						Nine months ended September 30,
(unaudited)
(millions of dollars, except per common unit amounts)	2017			2016 (a)			2017			2016 (a)
Net income attributable to controlling interests (a)	54			58			186			188
Net income attributable to PNGTS’ former parent (a) (b)	—			—			(2		)	(3		)
Net income attributable to General and Limited Partners	54			58			184			185
Incentive distributions allocated to the General Partner (c)	(3		)	(2		)	(9		)	(5		)
Net income attributable to the Class B units (d)	(8		)	(11		)	(8		)	(12		)
Net income attributable to the General Partner and common units	43			45			167			168
Net income attributable to General Partner’s effective two percent interest	(1		)	(2		)	(3		)	(4		)
Net income attributable to common units	42			43			164			164
Weighted average common units outstanding (millions) — basic and diluted	69.4			66.1		(e)	68.9			65.3		(e)
Net income per common unit — basic and diluted	$	0.61		$	0.65	(f)	$	2.38		$	2.51	(f)

(a)Recast to consolidate PNGTS for all periods presented (Refer to Notes 2 and 6).

(b)Net income allocable to General and Limited Partners excludes net income attributed to PNGTS’ former parent as it was allocated    to TransCanada and was not allocable to either the general partner, common units or Class B units.

(c)Under the terms of the Partnership Agreement, for any quarterly period, the participation of the incentive distribution rights (IDRs) is limited to the available cash distributions declared. Accordingly, incentive distributions allocated to the General Partner are based on the Partnership’s available cash during the current reporting period, but declared and paid in the subsequent reporting period.

(d)During the three and nine months ended September 30, 2017, 30 percent of GTN’s total distributable cash flow was $28 million. As a result of exceeding the $20 million threshold, $8 million of net income attributable to controlling interests was allocated to the Class B units during the three and nine months ended September 30, 2017.  During the six months ended June 30, 2016, the threshold was exceeded and during the nine months ended September 30, 2016, 30 percent of GTN’s total distributable cash flow was $32 million. As a result, $12 million of net income attributable to controlling interests was allocated to the Class B units at September 30, 2016, of which $1 million and $11 million were allocated during the three months ended June 30, 2016 and September 30, 2016, respectively (Refer to Note 7).

(e)Includes the common units subject to rescission. These units are treated as outstanding for financial reporting purposes (Refer to Note 7).

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

NOTE 9 CASH DISTRIBUTIONS

During the three and nine months ended September 30, 2017, the Partnership distributed $1.00 and $2.88 per common unit, respectively (September 30, 2016 — $0.94 and $2.72 per common unit) for a total of $74 million and $210 million, respectively (September 30, 2016 - $65 million and $184 million).

The distribution paid to our General Partner during the three months ended September 30, 2017 for its effective two percent general partner interest was $2 million along with an IDR payment of $3 million for a total distribution of $5 million (September 30, 2016 - $1 million for the effective two percent interest and a $2 million IDR payment).

The distribution paid to our General Partner during the nine months ended September 30, 2017 for its effective two percent general partner interest was $4 million along with an IDR payment of $7 million for a total distribution of $11 million (September 30, 2016 - $3 million for the effective two percent interest and a $4 million IDR payment).

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NOTE 10 CHANGE IN OPERATING WORKING CAPITAL

(unaudited)	Nine months ended September 30,
(millions of dollars)	2017		2016 (a)
Change in accounts receivable and other	13		3
Change in other current assets	1		2
Change in accounts payable and accrued liabilities(b)	2		3
Change in accounts payable to affiliates	(3	)	(2	)
Change in accrued interest	11		5
Change in operating working capital	24		11

(a)Recast to consolidate PNGTS for all periods presented (Refer to Notes 2 and 6).

(b)The accrual of $10 million for the construction of GTN’s Carty Lateral in December 31, 2015 was paid during the first quarter 2016. Accordingly, the payment was reported as capital expenditures in our 2016 cash flow statement.

NOTE 11 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 the conduct of 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 and nine months ended September 30, 2017 and 2016, total costs charged to the Partnership by the General Partner were $1 million and $3 million, respectively.

As operator of our pipelines except Iroquois, TransCanada’s subsidiaries provide capital and operating services to our pipeline systems. TransCanada’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. The Iroquois pipeline system is operated by Iroquois Pipeline Operating Company, a wholly owned subsidiary of Iroquois. Therefore, Iroquois does not receive any capital and operating services from TransCanada.

Capital and operating costs charged to our pipeline systems, except for Iroquois, for the three and nine months ended September 30, 2017 and 2016 by TransCanada’s subsidiaries and amounts payable to TransCanada’s subsidiaries at September 30, 2017 and December 31, 2016 are summarized in the following tables:

	Three months ended September 30,		Nine months ended September 30,
(unaudited)
(millions of dollars)	2017	2016	2017	2016
Capital and operating costs charged by TransCanada’s subsidiaries to:
Great Lakes (a)	10	8	27	22
Northern Border (a)	10	9	30	25
GTN	9	8	24	20
Bison	2	1	4	1
North Baja	1	1	3	3
Tuscarora	1	1	3	3
PNGTS	2	2	6	6
Impact on the Partnership’s net income:
Great Lakes (a)	4	3	11	9
Northern Border (a)	4	3	11	9
GTN	7	7	21	18
Bison	2	1	4	2
North Baja	1	1	3	3
Tuscarora	1	1	3	3
PNGTS (b)	1	1	4	3

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(unaudited)	September 30,
(millions of dollars)	2017	December 31, 2016
Net amounts payable to TransCanada’s subsidiaries is as follows:
Great Lakes (a)	3	4
Northern Border (a)	3	4
GTN	3	3
Bison	1	1
North Baja	—	1
Tuscarora	—	1
PNGTS	1	1

(a)Represents 100 percent of the costs.

(b)Recast to consolidate PNGTS for all periods presented (Refer to Note 2).

Great Lakes earns significant transportation revenues from TransCanada and its affiliates, some of which are provided at discounted rates and some at maximum recourse rates. For the three and nine months ended September 30, 2017, Great Lakes earned 44 percent and 53 percent of transportation revenues from TransCanada and its affiliates, respectively (September 30, 2016 — 62 percent and 69 percent).

At September 30, 2017, $8 million was included in Great Lakes’ receivables in regards to the transportation contracts with TransCanada and its affiliates (December 31, 2016 — $19 million).

Great Lakes operates under a FERC approved 2013 rate settlement that includes a revenue sharing mechanism that requires Great Lakes to share with its shippers certain percentages of any qualifying revenues earned above a certain return on equity threshold. For the year ended December 31, 2016, Great Lakes recorded an estimated 2016 revenue sharing provision of $7.2 million. For the three and nine months ended September 30, 2017, Great Lakes recorded an estimated 2017 revenue sharing provision of $12 million and $22 million, respectively. Great Lakes expects that a significant percentage of this refund will be paid to its affiliates.

PNGTS earns transportation revenues from TransCanada and its affiliates. For three and nine months ended September 30, 2017, PNGTS earned approximately nil million and $1 million of its transportation revenues from TransCanada and its affiliates, respectively (2016 — $1 million and $2 million, respectively).

At September 30, 2017, nil million was included in PNGTS’ receivables in regards to the transportation contracts with TransCanada and its affiliates (December 31, 2016 — 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 September 30, 2017, PNGTS does not have an obligation for reimbursement under this arrangement.

NOTE 12 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

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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.

Long-term debt is recorded at amortized cost and classified in Level 2 of the fair value hierarchy for fair value disclosure purposes. Interest rate derivative assets and liabilities are classified in 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 September 30, 2017 and December 31, 2016 was $2,555 million and $1,962 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 interest rate derivatives to manage its exposure to interest rate risk. We regularly assess the impact of interest rate fluctuations on future cash flows and evaluate hedging opportunities to mitigate our interest rate risk.

The Partnership’s interest rate swaps are structured such that the cash flows of the derivative instruments match those of the variable rate of interest on the 2013 Term Loan Facility. The Partnership hedged interest payments on the variable-rate 2013 Term Loan Facility with interest rate swaps maturing July 1, 2018, at a weighted average fixed interest rate of 2.31 percent. At September 30, 2017, the fair value of the interest rate swaps accounted for as cash flow hedges was an asset of $2 million (both on a gross and net basis). At December 31, 2016, the fair value of the interest rate swaps accounted for as cash flow hedges was an asset of $1 million and a liability of $1 million (on a gross basis) and an asset of nil million (on a net basis). The Partnership did not record any amounts in net income related to ineffectiveness for interest rate hedges for the three and nine months ended September 30, 2017 and 2016. The change in fair value of interest rate derivative instruments recognized in other comprehensive income was nil and a gain of $1 million for the three and nine months ended September 30, 2017, respectively (September 30, 2016 — gain of $2 million and a loss of $1 million). For the three and nine months ended September 30, 2017, the net realized loss related to the interest rate swaps was nil, and was included in financial charges and other (September 30, 2016 —$1 million and $2 million) (Refer to Note 14) .

As discussed in Note 5, the Partnership’s $500 million 2013 Term Loan that was due July 1, 2018, was amended to extend the maturity period through October 2, 2022. At September 30, 2017, the entire $500 million 2013 Term Loan was hedged until July 1, 2018. As a result of this extension, the Partnership implemented an interest rate hedging strategy during the fourth quarter and hedged the entire $500 million until its October 2, 2022 maturity using forward starting swaps at an average rate of 3.26 percent.

The Partnership has no master netting agreements; however, 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 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 September 30, 2017 (net asset of nil million as of December 31, 2016).

In anticipation of a debt refinancing in 2003, PNGTS entered into forward interest rate swap agreements to hedge the interest rate on its Senior Secured Notes due in 2018. These interest rate swaps were used to manage the impact of interest rate fluctuations and qualified as derivative financial instruments in accordance with ASC 815, Derivatives and Hedging. PNGTS settled its position with a payment of $20.9 million to counterparties at the time of the refinancing and recorded the realized loss in accumulated other comprehensive income as of the termination date. The previously recorded loss is currently being amortized against earnings over the life of the PNGTS Senior Secured Notes.  At September 30, 2017, our 61.71 percent proportionate share of net unamortized loss on PNGTS included in other comprehensive income was $1 million (December 31, 2016 - $2 million). For the three and nine months ended September 30, 2017, our 61.71 percent proportionate share of the amortization of realized loss on derivative instruments was nil and $1 million, respectively (September 30, 2016 —nil and $1 million).

NOTE 13 ACCOUNTS RECEIVABLE AND OTHER

(unaudited)
(millions of dollars)	September 30, 2017	December 31, 2016 (a)
Trade accounts receivable, net of allowance of nil	34	44
Imbalance receivable from affiliates	—	2
Other	1	1
	35	47

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(a)Recast as discussed in Notes 2 and 6.

NOTE 14 FINANCIAL CHARGES AND OTHER

	Three months ended September 30,		Nine months ended September 30,
(unaudited)
(millions of dollars)	2017	2016(b)	2017		2016(b)
Interest expense (a)	23	17	59		52
PNGTS’ amortization of derivative loss on derivative instruments (Note 12) (b)	—	—	1		1
Net realized loss related to the interest rate swaps	—	1	—		2
Other income	—	—	(1	)	(2	)
	23	18	59		53

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

(b)Recast to consolidate PNGTS for all periods presented (Refer to Note 2).

NOTE 15 CONTINGENCIES

Great Lakes v. Essar Steel Minnesota LLC, et al. —  On October 29, 2009, Great Lakes filed suit in the U.S. District Court, District of Minnesota, against Essar Minnesota LLC (Essar Minnesota) and certain Foreign Essar Affiliates (collectively, Essar) for breach of its monthly payment obligation under its transportation services agreement with Great Lakes. Great Lakes sought to recover approximately $33 million for past and future payments due under the agreement. On September 16, 2015, following a jury trial, the federal district court judge entered a judgment in the amount of $32.9 million in favor of Great Lakes.  On September 20, 2015, Essar appealed the decision to the United States Court of Appeals for the Eighth Circuit (Eighth Circuit) based on an allegation of improper jurisdiction and a number of other rulings by the federal district judge. Essar was required to post a performance bond for the full value of the judgment pending appeal.  The Eighth Circuit heard the appeal on October 20, 2016.  A decision on the appeal was received in December 2016 and the Eighth Circuit vacated Great Lakes’ judgment against Essar finding that there was no federal jurisdiction. Great Lakes filed a Request for Rehearing with the Eighth Circuit and it was denied in January 2017. Before the Circuit Court issued its decision, Essar Minnesota filed for bankruptcy in July 2016. The Foreign Essar Affiliates have not filed for bankruptcy. Following the Circuit Court’s decision, the performance bond was released into the bankruptcy court proceedings. Great Lakes filed a claim against Essar Minnesota in the bankruptcy court and its case against the Foreign Essar Affiliates in Minnesota state court remains pending. In April 2017, after Great Lakes agreement with creditors on an allowed claim, the bankruptcy court approved Great Lakes’ claim in the amount of $31.5 million.  On May 20, 2017, the federal district court awarded Essar Minnesota approximately $1.2 million for costs, including recovery of the performance bond premium, to be paid by Great Lakes. Great Lakes filed a motion with the bankruptcy court to offset the $1.2 million award of costs against its claim against Essar Minnesota in the bankruptcy proceeding.  If Great Lakes’ motion to offset the federal district court’s award of costs is against its claim in the bankruptcy proceeding is not successful, Great Lakes will be responsible to the bankruptcy estate for payment of the award. Great Lakes is unable to estimate the timing or the extent to which its claim will be recoverable in the bankruptcy proceedings.

NOTE 16 REGULATORY

North Baja —On January 6, 2017, North Baja notified FERC that current market conditions do not support the replacement of the compression that was temporarily abandoned in 2013 and requested authorization to permanently abandon two compressor units and a nominal volume of unsubscribed firm capacity. FERC approved the permanent abandonment request on February 16, 2017. The abandonments will not have any impact on existing firm transportation service.

Great Lakes - On April 24, 2017, Great Lakes reached an agreement on the terms of a new long-term transportation capacity contract with its affiliate, TransCanada. The contract, which was subject to Canada’s National Energy Board (NEB) approval, is for a term of 10 years and allows TransCanada the ability to transport up to 0.711 billion cubic feet of natural gas per day on the Great Lakes system from the Manitoba/U.S. border to the U.S. border near Dawn Ontario. On September 21, 2017, TransCanada received approval from the NEB and as a result, this contract commenced on November 1, 2017. This contract contains volume reduction options up to full contract quantity beginning in year three.

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On October 30, 2017, Great Lakes filed a rate settlement with FERC to satisfy its obligations from its 2013 rate settlement for new rates to be in effect by January 1, 2018 (2017 Great Lakes Settlement). The 2017 Great Lakes Settlement, if approved by FERC, will decrease Great Lakes’ maximum transportation rates by 27 percent beginning October 1, 2017.  Great Lakes expects that the impact from other changes, including: the recent long-term transportation contract with TransCanada as described above, other revenue opportunities on the system and the elimination of the revenue sharing mechanism with its customers, will more than offset the full year impact of the reduction in Great Lakes’ rates beginning in 2018. The 2017 Great Lakes Settlement does not contain any moratorium and Great Lakes will be required to file for new rates no later than March 31, 2022, with new rates to be effective October 1, 2022.

Northern Border- Northern Border and its shippers have been engaged in settlement discussions, and have recently agreed to a settlement-in-principle addressing all rate and service related issues raised during the settlement discussions. Northern Border plans to file a settlement agreement with FERC before the end of the year, reflecting the settlement-in-principle, precluding the need to file a general rate case as contemplated by its 2012 Settlement.  Northern Border anticipates that the Commission will accept the settlement agreement and that it will be unopposed. This will provide Northern Border with rate stability over the longer term.  At this time, we do not believe that the final outcome of the settlement will have a material impact to the Partnership’s results. Northern Border remains a key competitive pipeline and continues to operate at full capacity connecting major supply basins with communities in Midwestern U.S.

NOTE 17 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 variable interest entity (VIE) is a legal entity that does not have sufficient equity at risk to finance its activities without additional subordinated financial support or is structured such that equity investors lack the ability to make significant decisions relating to the entity’s operations through voting rights or do not substantively participate in the gains or losses of the entity. A VIE is appropriately consolidated if the Partnership is considered to be the primary beneficiary. The VIE’s primary beneficiary is the entity that has both (1) the power to direct the activities of the VIE that most significantly impact the VIEs economic performance and (2) the obligation to absorb losses or the right to receive benefits from the VIE that could potentially be significant to the VIE.

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

Consolidated VIEs

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

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

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

(unaudited)
(millions of dollars)	September 30, 2017		December 31, 2016(a)
ASSETS (LIABILITIES) *
Cash and cash equivalents	19		14
Accounts receivable and other	23		33
Inventories	6		6
Other current assets	4		6
Equity investments	1,207		918
Plant, property and equipment	1,132		1,146
Other assets	1		2
Accounts payable and accrued liabilities	(21	)	(21	)
Accounts payable to affiliates, net	(25	)	(32	)
Distributions payable	—		(3	)
Other taxes payable	(1	)	—
Accrued interest	(5	)	(2	)
Current portion of long-term debt	(51	)	(52	)
Long-term debt	(314	)	(337	)
Other liabilities	(26	)	(25	)
Deferred state income tax	(10	)	(10	)

*North Baja and Bison, which are also assets held through our consolidated VIEs, are excluded as the assets of these entities can be used for purposes other than the settlement of the VIE’s obligations.

(a) Recast to consolidate PNGTS for all periods presented (Refer to Notes 2 and 6).

NOTE 18 INCOME TAXES

The Partnership’s income taxes relate to business profits tax (BPT) levied at the partnership (PNGTS) level by the state of New Hampshire. As a result of the BPT, PNGTS recognizes deferred taxes related to temporary differences between the financial statement carrying amount of existing assets and liabilities and their respective tax bases. The deferred taxes at September 30, 2017 and December 31, 2016 relate primarily to utility plant. At September 30, 2017 and December 31, 2016 the New Hampshire BPT effective tax rate was 3.8 percent for both periods and was applied to PNGTS’ taxable income.

	Three months ended September 30,			Nine months ended September 30,
(unaudited)
(millions of dollars)	2017	2016(a)		2017	2016(a)
State income taxes
Current	—	(7	)	1	1
Deferred	—	7		—	—
	—	—		1	1

(a)Recast to consolidate PNGTS for all periods presented (Refer to Note 2 and 6).

NOTE 19 SUBSEQUENT EVENTS

Management of the Partnership has reviewed subsequent events through November 6, 2017, the date the financial statements were issued, and concluded there were no events or transactions during this period that would require recognition or disclosure in the consolidated financial statements other than what is disclosed here and/or those already disclosed in the preceding notes.

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On October 24, 2017, the board of directors of the General Partner declared the Partnership’s third quarter 2017 cash distribution in the amount of $1.00 per common unit payable on November 14, 2017 to unitholders of record as of November 3, 2017. The declared distribution totaled $75 million and is payable in the following manner: $70 million to common unitholders (including $6 million to the General Partner as a holder of 5,797,106 common units and $11 million to another subsidiary of TransCanada as holder of 11,287,725 common units) and $5 million to the General Partner, which included $2 million for its effective two percent general partner interest and $3 million in respect of its IDRs.

Northern Border declared its September 2017 distribution of $14 million on October 9, 2017, of which the Partnership will receive its 50 percent share or $7 million on October 31, 2017.

Great Lakes declared its third quarter 2017 distribution of $2 million on October 19, 2017, of which the Partnership will receive its 46.45 percent share or $1 million on November 1, 2017.

Iroquois declared its third quarter 2017 distribution of $28 million on October 23, 2017, of which the Partnership received its 49.34 percent share or $14 million on November 1, 2017. The distribution includes our 49.34 percent share of the Iroquois unrestricted cash distribution amounting to approximately $2.6 million (Refer to Note 6).

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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 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, 2016, in which certain parts of the report were amended through the Partnership’s filing of Current Report on Form 8-K dated August 3, 2017 to give retrospective adjustments to include the results of operations and financial position of PNGTS for all periods presented (Refer to Notes 2 and 6 within Item 1. “Financial Statements” of this Quarterly Report on Form 10-Q).

RECENT BUSINESS DEVELOPMENTS

Cash Distributions —

On April 25, 2017, the board of directors of our General Partner declared the Partnership’s first quarter 2017 cash distribution in the amount of $0.94 per common unit, payable on May 15, 2017 to unitholders of record as of May 5, 2017. The declared distribution totaled $68 million and was paid in the following manner: $65 million to common unitholders (including $5 million to the General Partner as a holder of 5,797,106 common units and $11 million to another subsidiary of TransCanada as holder of 11,287,725 common units) and $3 million to our General Partner, which included $1 million for its effective two percent general partner interest and $2 million in respect of its IDRs.

On July 20, 2017, the board of directors of our General Partner declared the Partnership’s second quarter 2017 cash distribution in the amount of $1.00 per common unit, payable on August 11, 2017 to unitholders of record as of August 1, 2017. The declared distribution totaled $74 million and was paid in the following manner: $69 million to common unitholders (including $6 million to the General Partner as a holder of 5,797,106 common units and $11 million to another subsidiary of TransCanada as holder of 11,287,725 common units) and $5 million to our General Partner, which included $2 million for its effective two percent general partner interest and $3 million in respect of its IDRs.

On October 24, 2017, the board of directors of our General Partner declared the Partnership’s third quarter 2017 cash distribution in the amount of $1.00 per common unit, payable on November 14, 2017 to unitholders of record as of November 3, 2017. The declared distribution totaled $75 million and is payable in the following manner: $70 million to common unitholders (including $6 million to the General Partner as a holder of 5,797,106 common units and $11 million to another subsidiary of TransCanada as holder of 11,287,725 common units) and $5 million to our General Partner, which included $2 million for its effective two percent general partner interest and $3 million in respect of its IDRs.

Pipeline updates

Great Lakes Contracting and Settlement- On April 24, 2017, Great Lakes reached an agreement on the terms of a new long-term transportation capacity contract with its affiliate, TransCanada. The contract, which was subject to Canada’s National Energy Board (NEB) approval, is for a term of 10 years and allows TransCanada the ability to transport up to 0.711 billion cubic feet of natural gas per day on the Great Lakes system from the Manitoba/U.S. border to the U.S. border near Dawn Ontario. On September 21, 2017, TransCanada received approval from the NEB and as a result, this contract commenced on November 1, 2017. This contract contains volume reduction options up to full contract quantity beginning in year three.

On October 30, 2017, Great Lakes filed a rate settlement with FERC to satisfy its obligations from its 2013 rate settlement for new rates to be in effect by January 1, 2018. The 2017 Great Lakes Settlement, if approved by FERC, will decrease Great Lakes’ maximum transportation rates by 27 percent beginning October 1, 2017.  Great Lakes expects that the impact from other changes, including: the recent long-term transportation contract with TransCanada as described above, other revenue opportunities on the system and the elimination of the revenue sharing mechanism with its customers, will more than offset the full year impact of the reduction in Great Lakes’ rates beginning in 2018. The 2017 Great Lakes Settlement does not contain any moratorium and Great Lakes will be required to file for new rates no later than March 31, 2022, with new rates to be effective October 1, 2022.

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Northern Border Rate Case- Northern Border and its shippers have been engaged in settlement discussions, and have recently agreed to a settlement-in-principle addressing all rate and service related issues raised during the settlement discussions. Northern Border plans to file a settlement agreement with FERC before the end of the year, reflecting the settlement-in-principle, precluding the need to file a general rate case as contemplated by its 2012 Settlement.  Northern Border anticipates that the Commission will accept the settlement agreement and that it will be unopposed. This will provide Northern Border with rate stability over the longer term.  At this time, we do not believe that the final outcome of the settlement will have a material impact to the Partnership’s results. Northern Border remains a key competitive pipeline and continues to operate at full capacity connecting major supply basins with communities in Midwestern U.S.

Northern Border Contracting — Northern Border revenues are now substantially supported by firm transportation contracts through March 2020. The continued successful renewals of these contracts provide a strong indication of Northern Border’s attractiveness to its customers.

PNGTS Projects

Continent to Coast (C2C) Project

As previously reported in our 2016 Annual Report on the Form 10-K dated February 28, 2017, PNGTS filed to increase its FERC-certificated capacity as contemplated in its Continent-to-Coast (C2C) contracts, bringing its capacity capability up to 210,000 Dth/day effective November 1, 2017. PNGTS has not received full regulatory approvals to date but will cooperatively work with C2C shippers while awaiting approvals.

Portland XPress Project

PNGTS has executed Precedent Agreements with several Local Distribution Companies in New England and Atlantic Canada to re-contract certain system capacity set to expire in 2019 as well as expand the PNGTS system to bring its certificated capacity up to 0.3 Bcf/d. The approximately $80 million Portland XPress Project (PXP) will proceed concurrently with upstream capacity expansions. The in-service dates of PXP are being phased-in over a three-year period beginning November 1, 2018.

Acquisitions and Financing

Debt Offering — On May 25, 2017, the Partnership closed a $500 million public offering of senior unsecured notes bearing an interest rate of 3.90 percent maturing May 25, 2027. The net proceeds of $497 million were used to fund a portion of the 2017 Acquisition (Refer to Note 6 within Item 1. “Financial Statements” of this Quarterly Report on Form 10Q).

2017 Acquisition — On June 1, 2017, the Partnership completed the acquisitions of a 49.34 percent interest in Iroquois from subsidiaries of TransCanada including an option to acquire a further 0.66 percent interest in Iroquois, together with an additional 11.81 percent interest in PNGTS that resulted in the Partnership owning a 61.71 percent interest in PNGTS. The total purchase price of the 2017 Acquisition was $765 million plus the final purchase price adjustments amounting to approximately $50 million. The purchase price consisted of  (i) $710 million for the Iroquois interest (less $164 million, which reflected the Partnership’s 49.34 percent share of Iroquois outstanding debt at the time of the 2017 Acquisition   (ii) $55 million for the additional 11.81 percent in PNGTS (less $5 million, which reflected our 11.81 percent share in PNGTS’ outstanding debt at the time of the 2017 Acquisition) (iii) final working capital adjustments on PNGTS and Iroquois amounting to $3 million and $19 million, respectively and (iv) additional consideration on Iroquois’ surplus cash amounting to $28 million. The Partnership funded the cash portion of the 2017 Acquisition through a combination of proceeds from the May 25, 2017 public debt offering and borrowing under its Senior Credit Facility

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As at the date of the 2017 Acquisition, there was significant cash on Iroquois’ balance sheet.  Pursuant to the Purchase and Sale Agreement associated with the acquisition of the Iroquois interest, as amended, the Partnership agreed to pay $28 million plus interest to TransCanada on August 1, 2017 for its 49.34 percent share of cash determined to be surplus to Iroquois’ operating needs.

Additionally, Iroquois’ partners adopted a distribution resolution to address the significant cash on Iroquois’ balance sheet post-closing. The Partnership expects to receive the $28 million of unrestricted cash as part of its quarterly distributions from Iroquois over 11 quarters under the terms of the resolution, which began with Iroquois’ second quarter 2017 distribution on August 1, 2017. As of November 6, 2017 the Partnership has received approximately $5.2 million of the expected $28 million, of which $2.6 million was received on November 1, 2017.

The Iroquois pipeline transports natural gas under long-term contracts and extends from the TransCanada Mainline system at the U.S. border near Waddington, New York to markets in the U.S. northeast, including New York City, Long Island and Connecticut.  Iroquois provides service to local gas distribution companies, electric utilities and electric power generators, as well as marketers and other end users, directly or indirectly, through interconnecting pipelines and exchanges throughout the northeastern U.S. Both the Iroquois and PNGTS pipelines are critical natural gas infrastructure systems in the Northeast U.S. market and the addition of Iroquois to the Partnership’s asset portfolio will further diversify our cash flow.

Tuscarora Refinancing — On August 21, 2017, Tuscarora refinanced all of its outstanding debt by amending its existing Unsecured Term Loan Facility and issuing a new $25 million variable rate term loan that will require yearly principal payments and will mature on August 21, 2020. Tuscarora’s Unsecured Term Loan contains a covenant that requires Tuscarora to maintain a debt service coverage ratio (cash available from operations divided by a sum of interest expense and principal payments) of greater than or equal to 3.00 to 1.00. As of September 30, 2017, the ratio was 3.08 to 1.00.

2013 Term Loan Facility - On September 29, 2017, the Partnership’s variable rate 2013 $500 million Term loan facility that was due on July 1, 2018 was amended to extend the maturity period through October 2, 2022. At September 30, 2017, the $500 million 2013 Term loan facility is hedged by fixed interest rate swap arrangements at an effective interest rate of 2.31 percent, expiring July 1, 2018. As a result of this extension, the Partnership implemented an interest rate hedging strategy during the fourth quarter and hedged the entire $500 million until its October 2, 2022 maturity using forward starting swaps at an average rate of 3.26 percent.

2015 Term Loan Facility-On September 29, 2017, the Partnership’s 2015 $170 million Term loan facility that was due on October 1, 2018 was amended to extend the maturity period through October 1, 2020.

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 equity interests in Northern Border, Great Lakes, and effective June 1, 2017, Iroquois and full ownerships of GTN, Bison, North Baja and Tuscarora and beginning also on June 1, 2017, 61.71 percent ownership in PNGTS 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.

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	Three months ended								Nine months ended
(unaudited)	September 30,				$		%		September 30,				$		%
(millions of dollars)	2017		2016(a)		Change*		Change*		2017		2016(a)		Change*		Change*
Transmission revenues	100		103		(3	)	(3	)	313		315		(2	)	(1	)
Equity earnings	27		22		5		23		87		75		12		16
Operating, maintenance and administrative	(24	)	(23	)	(1	)	(4	)	(74	)	(67	)	(7	)	(10	)
Depreciation	(25	)	(24	)	(1	)	(4	)	(73	)	(71	)	(2	)	(3	)
Financial charges and other	(23	)	(18	)	(5	)	(3	)	(59	)	(53	)	(6	)	(11	)
Net income before taxes	55		60		(5	)	(8	)	194		199		(5	)	(3	)
State income taxes	—		—		—		—		(1	)	(1	)	—		—
Net income	55		60		(5	)	(8	)	193		198		(5	)	(3	)
Net income attributable to non-controlling interests	1		2		1		50		7		10		3		30
Net income attributable to controlling interests	54		58		(4	)	7		186		188		(2	)	1

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

(a) Financial information was recast to consolidate PNGTS for all periods presented (Refer to Note 2 and 6 within Item 1. “Financial Statements”).

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Three Months Ended September 30, 2017 compared to Same Period in 2016

Net income attributable to controlling interests - The Partnership’s net income attributable to controlling interests was lower by $4 million compared to prior period due to the net effect of lower revenues and overall higher costs partially offset by higher equity earnings.

Transmission revenues — Revenues were lower due to lower discretionary revenues on short-term services sold by PNGTS.

Equity Earnings - The $5 million increase was primarily due to the addition of equity earnings from Iroquois, resulting from the addition of Iroquois to our portfolio of assets effective June 1, 2017 partially offset by lower equity earnings from Northern Border and Great Lakes due to higher pipeline integrity program spending and other operating costs. The increase in pipeline integrity work at Great Lakes is in relation to the increase in natural gas flows which have been ramping up during the year.

Operating, maintenance and administrative costs - The $1 million increase was mainly attributable to higher pipeline integrity on GTN and overall higher allocated management and operational expenses on our pipeline systems as performed by TransCanada.

Financial charges and other - The $5 million increase was mainly attributable to additional borrowings to finance the 2017 Acquisition.

Net-income attributable to non-controlling interests - The Partnership’s net income attributable to non- controlling interests was lower due to lower earnings from PNGTS during the period.

Nine Months Ended September 30, 2017 compared to Same Period in 2016

Net income attributable to controlling interests - The Partnership’s net income attributable to controlling interests was lower by $2 million compared to prior period due to the net effect of lower revenues and overall higher costs partially offset by higher equity earnings.

Transmission revenues — Comparable to prior year primarily due to higher discretionary revenues on short-term services sold by GTN offset by lower discretionary revenues on short-term services sold by PNGTS and lower transportation rates on Tuscarora as a result of settlement reached with its customers effective August 1, 2016.

Equity Earnings - The $12 million increase was primarily due the addition of equity earnings from Iroquois, effective June 1, 2017.

Operating, maintenance and administrative costs - The $7 million increase was mainly attributable to higher pipeline integrity on GTN and overall higher allocated management and operational expenses on our pipeline systems as performed by TransCanada.

Financial charges and other - The $6 million increase was mainly attributable to additional borrowings to finance the 2017 Acquisition.

Net-income attributable to non-controlling interests - The Partnership’s net income attributable to non- controlling interests was lower due to lower earnings from PNGTS during the period.

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

2017

As discussed in Note 8 within Item 1. “Financial Statements,” we allocated $8 million of the Partnership’s net income attributable to controlling interests to the Class B units in the three and nine months ended September 30, 2017, respectively, representing the excess of 30 percent of GTN’s distribution over the 2017 threshold level of $20 million. This allocation reduced net income attributable to the common units and accordingly, reduced net income per common unit by approximately 12 cents for both the three and nine months ended September 30, 2017, respectively.

2016

We allocated $11 million and $12 million of the Partnership’s net income attributable to controlling interests to the Class B units in the three and nine months ended September 30, 2016, respectively, representing the excess of 30 percent of GTN’s distribution over the 2016 threshold level of $20 million. This allocation reduced net income

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attributable to the common units and accordingly, reduced net income per common unit by approximately 17 cents and 19 cents for the three and nine months ended September 30, 2016, respectively.

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 TransCanada through our General Partner and as holder of all our Class B units) primarily with operating cash flow. Long-term capital needs may be met through the issuance of long-term debt and/or equity. Overall, we believe that our pipeline systems’ ability to obtain financing at reasonable rates, together with a history of consistent cash flow from operating activities, provide a solid foundation to meet future liquidity and capital requirements. We expect to be able to fund our liquidity requirements, including our distributions and required debt repayments, at the Partnership level over the next 12 months utilizing our cash flow and, if required, our existing Senior Credit Facility.

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

(unaudited) (millions of dollars)	September 30, 2017	December 31, 2016
Total capacity under the Senior Credit Facility	500	500
Less: Outstanding borrowings under the Senior Credit Facility	255	160
Available capacity under the Senior Credit Facility	245	340

Our pipeline systems’ principal sources of liquidity 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. Additionally, on September 1, 2017, the Partnership made an equity contribution to Northern Border of $83 million. This amount represents the Partnership’s 50 percent share of a one time $166 million capital contribution request from Northern Border to reduce the outstanding balance of its revolver debt to increase its available borrowing capacity.

Capital expenditures 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 Nine Months Ended September 30, 2017 compared to Same Period in 2016

	Nine months ended
(unaudited)	September 30,
(millions of dollars)	2017		2016 (a)
Net cash provided by (used in):
Operating activities	311		332
Investing activities	(756	)	(215	)
Financing activities	454		(95	)
Net decrease in cash and cash equivalents	9		22
Cash and cash equivalents at beginning of the period	64		55
Cash and cash equivalents at end of the period	73		77

(a) Financial information was recast to consolidate PNGTS for all periods presented (Refer to Notes 2 and 6 within Item 1. “Financial Statements”).

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Operating Cash Flows

Net cash provided by operating activities decreased by $21 million in the nine months ended September 30, 2017 compared to the same period in 2016 primarily due to lower distributions from Great Lakes and Northern Border in 2017 partially offset by distributions received from Iroquois, resulting from the addition of Iroquois to our portfolio of assets effective June 1, 2017. Distributions received in the first quarter of 2016 from Great Lakes were higher than on a run-rate basis due to the resolution of certain regulatory proceedings in the fourth quarter of 2015 which inflated its results during that period and resulted in higher cash flow which was paid to the Partnership in the first quarter of 2016 and not applicable in the first quarter of 2017. Additionally, the Partnership received lower distributions from Northern Border in the current 2017 period compared to the same period in 2016 primarily due to higher maintenance capital expenditures during the current 2017 period together with the change in Northern Border’s distribution policy during 2016 from a lagged quarterly distribution to a more timely monthly distribution that resulted in a larger distribution in the third quarter of 2016.

Investing Cash Flows

Net cash used in investing activities increased by $541 million in the nine months ended September 30, 2017 compared to the same period in 2016.  On January 1, 2016, we invested $193 million to acquire a 49.9 percent interest in PNGTS and on June 1, 2017, we invested $593 million to acquire a 49.34 percent interest in Iroquois and $53 million to acquire an additional 11.81 percent of PNGTS. During the nine months ended September 30, 2017 compared to 2016, we  incurred higher maintenance capital expenditures related to major compression equipment overhauls on GTN’s pipeline system and on September 1, 2017, we contributed $83 million to Northern Border representing our 50 percent share of a requested capital contribution to reduce the outstanding balance of its revolving credit facility.

Financing Cash Flows

The net change in cash from our financing activities was approximately $549 million in the nine months ended September 30, 2017 compared to the same period in 2016 primarily due to the net effect of:

·$564 million increase in net issuances of debt in 2017 primarily to finance the 2017 Acquisition;

·$26 million increase in distributions paid to our common units and to our General Partner in respect of its two percent general partner interest and IDRs;

·$10 million increase in distributions paid to Class B units in 2017 as compared to 2016;

·$8 million increase in our ATM equity issuances in 2017 as compared to 2016;

·$7 million decrease in distributions paid to non-controlling interest due to lower revenues on PNGTS compared to the previous periods; and

·$8 million decrease in distributions paid to TransCanada as the former parent of PNGTS primarily due to the Partnership’s acquisition of a 49.9 percent interest in PNGTS effective January 1, 2016 and additional 11.81 percent effective June 1, 2017.

Cash Flow Outlook

Operating Cash Flow Outlook

Northern Border declared its September 2017 distribution of $14 million on October 7, 2017, of which the Partnership received its 50 percent share or $7 million. The distribution was paid on October 31, 2017.

Great Lakes declared its third quarter 2017 distribution of $2 million on October 19, 2017, of which the Partnership received its 46.45 percent share or $1 million. The distribution was paid on November 1, 2017.

Iroquois declared its third quarter 2017 distribution of $28 million on October 23, 2017, of which the Partnership received its 49.34 percent share or $14 million on November 1, 2017.

Our equity investee Iroquois has $2.8 million of scheduled debt repayments for the remainder of 2017 and Iroquois’ debt repayments are expected to be funded through its cash flow from operations.

Investing Cash Flow Outlook

The Partnership made an equity contribution to Great Lakes of $4 million in the first quarter of 2017. This amount represents the Partnership’s 46.45 percent share of a $9 million cash call from Great Lakes to make a scheduled debt

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repayment. The Partnership expects to make an additional $5 million equity contribution to Great Lakes in the fourth quarter of 2017 to further fund debt repayments.  This is consistent with prior years.

Our consolidated entities have commitments of $7 million as of September 30, 2017 in connection with various maintenance and general plant projects.

Our expected total growth and maintenance capital expenditures on our pipeline systems as outlined in the Management Discussion and Analysis of Financial Condition and Results of Operations for the year ended December 31, 2016 Consolidated Financial Statements and Notes thereto included as Exhibit 99.3 of the Current Report on Form 8-K filed with the SEC on August 3, 2017 remain materially unchanged.

Financing Cash Flow Outlook

On October 24, 2017, the board of directors of our General Partner declared the Partnership’s third quarter 2017 cash distribution in the amount of $1.00 per common unit payable on November 14, 2017 to unitholders of record as of November 3, 2017.  Please see “Recent Business Developments.”

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, 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 amount presented.

Total distributable cash flow includes EBITDA plus:

·Distributions from our equity investments

less:

·Earnings from our equity investments,

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

·Interest expense,

·Distributions to non-controlling interests,

·Distributions to TransCanada as the former parent of PNGTS, and

·Maintenance capital expenditures from consolidated subsidiaries.

Distributable cash flow is computed net of distributions declared to the General Partner and distributions allocable to Class B units. Distributions declared to the General Partner are based on its effective two percent interest plus an amount equal to incentive distributions. Distributions allocable to the Class B units in 2017 equal 30 percent of GTN’s distributable cash flow less $20 million.

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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 performance.

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

Reconciliations of Non-GAAP Financial Measures

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				Nine months ended
(unaudited)	September 30,				September 30,
(millions of dollars)	2017		2016 (a)		2017		2016(a)
Net income	55		60		193		198
Add:
Interest expense(b)	23		18		60		55
Depreciation and amortization	25		24		73		71
Income taxes	—		—		1		1
EBITDA	103		102		327		325
Add:
Distributions from equity investments(c)
Northern Border	21		23		61		67
Great Lakes	1		5		28		28
Iroquois (d)	14		—		28		—
	36		28		117		95
Less:
Equity earnings:
Northern Border	(16	)	(18	)	(50	)	(52	)
Great Lakes	(2	)	(4	)	(24	)	(23	)
Iroquois	(9	)	—		(13	)	—
	(27	)	(22	)	(87	)	(75	)
Less:
Interest expense(b)	(23	)	(18	)	(60	)	(55	)
Income taxes	—		—		(1	)	(1	)
Distributions to non-controlling interests(e)	(2	)	(3	)	(10	)	(11	)
Distributions to TransCanada as PNGTS’ former parent(f)	—		—		(1	)	(3	)
Maintenance capital expenditures (g)	(9	)	(3	)	(26	)	(9	)
	(34	)	(24	)	(98	)	(79	)
Total Distributable Cash Flow	78		84		259		266
General Partner distributions declared (h)	(5	)	(4	)	(13	)	(9	)
Distributions allocable to Class B units (i)	(8	)	(11	)	(8	)	(12	)
Distributable Cash Flow	65		69		238		245

(a)Financial information was recast to consolidate PNGTS for all periods presented. Refer to Notes 2 and 6 within Item 1.” Financial Statements”.

(b)Interest expense as presented includes net realized loss related to the interest rate swaps and amortization of realized loss on PNGTS’ derivative instruments. Refer to Note 14 within Item 1.” Financial Statements”.

(c)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 during the current reporting period.

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(d)This amount represents our proportional 49.34 percent share of the distribution declared by our equity investee Iroquois during the current reporting period and includes our 49.34 percent share of the Iroquois unrestricted cash distribution amounting to approximately $2.6 million and $5.2 million for the three and nine months ending September 30, 2017, respectively. Refer to Note 6 within Item 1. “Financial Statements”.

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

(f)Distributions to TransCanada as PNGTS’ former parent represent TransCanada’s respective share of PNGTS’ distributable cash not owned by us during the periods presented.

(g)The Partnership’s maintenance capital expenditures include cash 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.

(h)Distributions declared to the General Partner for the three and nine months ended September 30, 2017 included an incentive distribution of approximately $3 million and $9 million, respectively (September 30, 2016 — $2 million and $5 million).

(i)During the nine months ended September 30, 2017, 30 percent of GTN’s total distributions amounted to $28 million. As a result of exceeding the $20 million threshold during this quarter, $8 million was allocated to the Class B units for both the three and nine months ended September 30, 2017.

During the nine months ended September 30, 2016, 30 percent of GTN’s total distributions amounted to $32 million. As a result of exceeding the $20 million threshold since the end of the second quarter of 2016, $12 million was allocated to the Class B units at September 30, 2016, of which $1 million and $11 million were allocated during the three months ended June 30, 2016 and September 30, 2016, respectively.

Please read Notes 7 and 8 within Item 1. “Financial Statements” for additional disclosures on the Class B units.

Three months ended September 30, 2017 Compared to Same Period in 2016

Our EBITDA was comparable to the same period in 2016. The slight increase was due to the addition of our equity interest on Iroquois effective June 1, 2017 offset by lower revenues and an increase in operational costs as discussed in more detail under the Results of Operations section.

Our distributable cash flow decreased by $4 million in the third quarter of 2017 compared to the same period in 2016 due to the net effect of:

·addition of 49.34 percent share of Iroquois’ third quarter 2017 distribution;

·lower distributions from Great Lakes and Northern Border due to their higher pipeline integrity and other operating costs;

·higher maintenance capital expenditures related to major compression equipment overhauls on GTN’s pipeline system;

·increased interest expense due to additional borrowings to finance the 2017 Acquisition;

· higher IDRs declared to our General Partner during the current period; and

·lower distributions allocable to the Class B units during the period

Nine Months Ended September 30, 2017 Compared to Same Period in 2016

Our EBITDA was comparable to the same period in prior year primarily due to the addition of equity earnings on Iroquois effective June 1, 2017 offset by lower revenues and an increase in operational costs as discussed in more detail under the Results of Operations section.

Our distributable cash flow decreased by $7 million in the nine months ended September 30, 2017 compared to the same period in 2016 due to the net effect of:

·addition of 49.34 percent share of  Iroquois’ second and third quarter 2017 distribution;

·higher maintenance capital expenditures related to major compression equipment overhauls on GTN’s pipeline system;

·lower distributable cash flow from Northern Border primarily due to its higher operating costs and higher maintenance capital expenditures;

·higher IDRs declared to our General Partner during the current period; and

·lower distributions allocable to the Class B units during the period.

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Contractual Obligations

The Partnership’s Contractual Obligations

The Partnership’s contractual obligations related to debt as of September 30, 2017 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 Nine Months Ended September 30, 2017
TC PipeLines, LP
Senior Credit Facility due 2021	255	—	—	—	255	2.34%
2013 Term Loan Facility due October 2022	500	—	—	—	500	2.26%
2015 Term Loan Facility due October 2020	170	—	—	170	—	2.15%
4.65% Senior Notes due 2021	350	—	—	350	—	4.65%(a)
4.375% Senior Notes due 2025	350	—	—	—	350	4.375%(a)
3.9% Senior Notes due 2027	500	—	—	—	500	3.90%(a)
GTN
5.29% Unsecured Senior Notes due 2020	100	—	100	—	—	5.29%(a)
5.69% Unsecured Senior Notes due 2035	150	—	—	—	150	5.69%(a)
Unsecured Term Loan Facility due 2019	55	20	35	—	—	1.95%
PNGTS
5.90% Senior Secured Notes due December 2018	36	30	6	—	—	5.90%(a)
Tuscarora
Unsecured Term Loan due August 2020	25	1	24	—	—	2.18%
	2,491	51	165	520	1,755

(a)Fixed interest rate

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 the derivatives.

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 September 30, 2017 was $2,555 million.

Please read Note 5 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 related to debt as of September 30, 2017 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 Nine Months Ended September 30, 2017
$200 million Credit Agreement due 2020	16	—	—	16	—	2.11%
7.50% Senior Notes due 2021	250	—	—	250	—	7.50%(b)
	266	—	—	266	—

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

(b) Fixed interest rate

On September 1, 2017, Northern Border’s $100 million 364-day revolving credit facility was terminated.

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As of September 30, 2017, $16 million was outstanding under Northern Border’s $200 million revolving credit agreement, leaving $184 million available for future borrowings. At September 30, 2017, Northern Border was in compliance with all of its financial covenants.

Northern Border has commitments of $12 million as of September 30, 2017 in connection with compressor station overhaul project and other capital projects.

Summary of Great Lakes’ Contractual Obligations

Great Lakes’ contractual obligations related to debt as of September 30, 2017 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 Nine Months Ended September 30, 2017
6.73% series Senior Notes due 2017 to 2018	9	9	—	—	—	6.73%(b)
9.09% series Senior Notes due 2017 and 2021	50	10	20	20	—	9.09%(b)
6.95% series Senior Notes due 2019 and 2028	110	—	22	22	66	6.95%(b)
8.08% series Senior Notes due 2021 and 2030	100	—	—	20	80	8.08%(b)
	269	19	42	62	146

(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 $145 million of Great Lakes’ partners’ capital was restricted as to distributions as of September 30, 2017 (December 31, 2016 — $150 million). Great Lakes was in compliance with all of its financial covenants at September 30, 2017.

Great Lakes has commitments of $2 million as of September 30, 2017 in connection with pipeline integrity program spending, major overhaul projects, and right of way renewals.

Summary of Iroquois’ Contractual Obligations

Iroquois’ contractual obligations related to debt as of September 30, 2017 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 Nine Months Ended September 30, 2017
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	42	5	10	7	20	6.10%(b)
	332	5	300	7	20

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

(b) Fixed interest rate

Iroquois has commitments of $2 million as of September 30, 2017 relative 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%, the debt service coverage ratio must be at least 1.25 times for the four preceding quarters.  At September 30, 2017, the

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debt/capitalization ratio was 47.6% and the debt service coverage ratio was 8.04 times, therefore, Iroquois was not restricted from making any cash distributions.

Critical Accounting Policies and Estimates

The preparation of financial statements in accordance with GAAP requires us to make estimates and assumptions with respect to values or conditions, which cannot be known with certainty, that affect the reported amount of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the financial statements. Such estimates and assumptions also affect the reported amounts of revenue and expenses during the reporting period. Although we believe these estimates and assumptions are reasonable, actual results could differ. There were no significant changes to the Partnership’s critical accounting estimates during the three and nine months ended September 30, 2017. Information about our critical accounting estimates is included in our Annual Report on Form 10-K for the year ended December 31, 2016.

Our significant accounting policies have remained unchanged since December 31, 2016 except as described in Note 3 within Item 1. “Financial Statements,” of this quarterly report on Form 10-Q. A summary of our significant accounting policies can be found in our audited financial statements and notes thereto for the year ended December 31, 2016 included as exhibit 99.2 in our Current Report on Form 8-Kdated August 3, 2017. (Refer also to Note 2 in Item 1. “Financial Statements” of this Quarterly Report on Form 10-Q).

RELATED PARTY TRANSACTIONS

Please read Notes 6 and 11 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 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.

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 September 30, 2017, the Partnership’s interest rate exposure resulted from our floating rate Senior Credit Facility, 2015 Term Loan Facility, GTN’s Unsecured Term Loan Facility and Tuscarora’s Unsecured Term Loan Facility, under which $505 million, or 20 percent, of our outstanding debt was subject to variability in LIBOR interest rates. As of December 31, 2016, the Partnership’s interest rate exposure resulted from our floating rate Senior Credit Facility, 2015 Term Loan Facility, GTN’s Unsecured Term Loan Facility and Tuscarora’s Unsecured Term Loan Facility, under which $405 million or 21 percent of our outstanding debt was subject to variability in LIBOR interest rates.

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As of September 30, 2017, the variable interest rate exposure related to 2013 Term Loan Facility was hedged by fixed interest rate swap arrangements and our effective interest rate was 2.31 percent.  If interest rates hypothetically increased (decreased) by one percent, 100 basis points, compared with rates in effect at September 30, 2017, our annual interest expense would increase (decrease) and net income would decrease (increase) by approximately $5 million.

As of September 30, 2017, $16 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 September 30, 2017, 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 and North Baja, as they currently do 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. 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 are structured such that the cash flows of the derivative instruments match those of the variable rate of interest on the 2013 Term Loan Facility. The Partnership hedged interest payments on the variable-rate 2013 Term Loan Facility with interest rate swaps maturing July 1, 2018, at a weighted average fixed interest rate of 2.31 percent. At September 30, 2017, the fair value of the interest rate swaps accounted for as cash flow hedges was an asset of $2 million (both on a gross and net basis). At December 31, 2016, the fair value of the interest rate swaps accounted for as cash flow hedges was an asset of $1 million and a liability of $1 million (on a gross basis) and an asset of nil million (on a net basis). The Partnership did not record any amounts in net income related to ineffectiveness for interest rate hedges for the three and nine months ended September 30, 2017 and 2016. The change in fair value of interest rate derivative instruments recognized in other comprehensive income was nil and a gain of $1 million for the three and nine months ended September 30, 2017, respectively (September 30, 2016 — gain of $2 million and a loss of $1 million). For the three and nine months ended September 30, 2017, the net realized loss related to the interest rate swaps was nil, and was included in financial charges and other (September 30, 2016 —$1 million and $2 million).  Refer to Note 14 within Item 1. “Financial Statements”.

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 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 September 30, 2017 (net asset of nil million as of December 31, 2016).

As discussed in Note 5 within Item 1. Financial Statements, the Partnership’s 2013 Term Loan that was due July 1, 2018, was amended to extend the maturity period through October 2, 2022. As a result of this extension, the Partnership implemented an interest rate hedging strategy during the fourth quarter and hedged the entire $500 million until its October 2, 2022 maturity using forward starting swaps at an average rate of 3.26 percent.

In anticipation of a debt refinancing in 2003, PNGTS entered into forward interest rate swap agreements to hedge the interest rate on its Senior Secured Notes due in 2018. These interest rate swaps were used to manage the impact of interest rate fluctuations and qualified as derivative financial instruments in accordance with ASC 815, Derivatives and Hedging. PNGTS settled its position with a payment of $20.9 million to counterparties at the time of the refinancing and recorded the realized loss in accumulated other comprehensive income as of the termination date. The previously recorded loss is currently being amortized against earnings over the life of the PNGTS Senior Secured Notes.  At September 30, 2017, our 61.71 percent proportionate share of net unamortized loss on PNGTS included in other comprehensive income was $1 million (December 31, 2016 - $2 million). For the three and nine months ended September 30, 2017, our 61.71 percent proportionate share of the amortization of realized loss on derivative instruments was nil and $1 million, respectively (September 30, 2016 —nil and $1 million).

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OTHER RISKS

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 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 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 September 30, 2017, we had not incurred any significant credit losses and had no significant amounts past due or impaired. At September 30, 2017, we had a credit risk concentration on one of our customers, Anadarko Energy Services Company, which owed us approximately $4 million and this amount represented greater than 10 percent of our trade accounts receivable.

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. Our approach to managing liquidity risk is to ensure that we always have sufficient cash and credit facilities to meet our obligations when due, under both normal and stressed conditions, without incurring unacceptable losses or damage to our reputation. At September 30, 2017, the Partnership had a Senior Credit Facility of $500 million maturing in 2021 and the outstanding balance on this facility was $255 million. In addition, Northern Border had a committed revolving bank line of $200 million maturing in 2020 with $16 million drawn at September 30, 2017. Both the Senior Credit Facility and the Northern Border $200 million credit facility have accordion features for additional capacity of $500 million and $100 million respectively, subject to lender consent.

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 September 30, 2017, 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, 2016.

43

Great Lakes v. Essar Steel Minnesota LLC, et al. —

A description of this legal proceeding can be found in Note 15 within Item 1, “Financial Statements” of this Quarterly Report on Form 10-Q, and is incorporated herein by reference.

In addition to the above written matter, we and our pipeline systems are parties to lawsuits and governmental proceedings that arise in the ordinary course of our business.

44

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, 2016.

Following the closing of the 2017 Acquisition, we will not own a controlling interest in Iroquois, and we will be unable to cause certain actions to take place without the agreement of the other partners.

The major policies of Iroquois are established by its management committee, which consists of individuals who are designated by each of the partners and includes one individual designated by us. The management committee requires at least the affirmative vote of a majority of the partners’ percentage interests to take any action. Because of these provisions, without the concurrence of other partners, we would be unable to cause Iroquois to take or not to take certain actions, even though those actions may be in the best interests of the Partnership or Iroquois. Further, Iroquois may seek additional capital contributions. Our funding of these capital contributions would reduce the amount of cash otherwise available for distribution to our unitholders. In the event we elected not to, or were unable to, make a capital contribution to Iroquois; our ownership interest would be diluted.

Changes in TransCanada’s costs or their cost allocation practices could have an effect on our results of operations, financial position and cash flows.

Under the Partnership Agreement, the Partnership’s pipeline systems operated by TransCanada are allocated certain costs of operations at TransCanada’s sole discretion. Accordingly, revisions in the allocation process or changes to corporate structure may impact the Partnership’s operating results. TransCanada reviews any changes and their prospective impact for reasonableness, however there can be no assurance that allocated operating costs will remain consistent from period to period.

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.

No.	Description
2.1	Agreement for Purchase and Sale of Partnership Interest in Iroquois Gas Transmission System, L.P. by and between TCPL Northeast Ltd. and TransCanada Iroquois Ltd., as Sellers and TC Pipelines Intermediate Limited Partnership as Buyer dated as of May 3, 2017 (Incorporated by reference from Exhibit 2.1 to TC PipeLines, LP’s Form 8-K filed May 3, 2017).
2.1.1	First Amendment to Purchase and Sale Agreement by and between TCPL Northeast Ltd. and TransCanada Iroquois Ltd., as Sellers and TC Pipelines Intermediate Limited Partnership as Buyer dated as of May 31, 2017 (Incorporated by reference from Exhibit 2.1.1 to TC PipeLines, LP’s Form 10-Q filed August 3, 2017).
2.2	Option Agreement Relating to Partnership Interest in Iroquois Gas Transmission System, L.P. by and between TransCanada Iroquois Ltd. and TC Pipelines Intermediate Limited Partnership as dated as of May 3, 2017 (Incorporated by reference from Exhibit 2.2 to TC PipeLines, LP’s Form 8-K filed May 3, 2017).
2.3	Agreement for Purchase and Sale of Partnership Interest in Portland Natural Gas Transmission System, by and between TCPL Portland Inc., as Seller and TC Pipelines Intermediate Limited Partnership as Buyer dated as of May 3, 2017 (Incorporated by reference from Exhibit 2.3 to TC PipeLines, LP’s Form 8-K filed May 3, 2017).
3.1	Third Amended and Restated Agreement of Limited Partnership of TC PipeLines, LP dated April 1, 2015 (Incorporated by reference from Exhibit 3.1 to TC PipeLines, LP’s Form 8-K filed April 1, 2015).
3.2	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).
4.1	Portland Natural Gas Transmission System Senior Secured Note Purchase Agreement dated as of April 10, 2003 (Incorporated by reference from Exhibit 4.1 to TC PipeLines, LP’s Form 10-Q filed August 3, 2017).
4.2	Iroquois Gas Transmission, L.P. Senior Note Purchase Agreement dated as of May 13, 2009 (Incorporated by reference from Exhibit 4.2 to TC PipeLines, LP’s Form 10-Q filed August 3, 2017).
4.3	Iroquois Gas Transmission, L.P. Senior Note Purchase Agreement dated as of April 27,

45

	2010(Incorporated by reference from Exhibit 4.3 to TC PipeLines, LP’s Form 10-Q filed August 3, 2017).
4.4	Indenture dated as of May 30, 2000, between Iroquois Gas Transmission System, L.P. and The Chase Manhattan Bank (Incorporated by reference from Exhibit 4.4 to TC PipeLines, LP’s Form 10-Q filed August 3, 2017).
4.4.1	Second Supplemental Indenture dated as of August 13, 2002, between Iroquois Gas Transmission System, L.P. and JPMorgan Chase Bank (formerly known as The Chase Manhattan Bank) (Incorporated by reference from Exhibit 4.4.1 to TC PipeLines, LP’s Form 10-Q filed August 3, 2017).
4.5	Credit Agreement dated as of June 26, 2008, between Iroquois Gas Transmission System, L.P. and JPMorgan Chase Bank, N.A. as administrative agent (Incorporated by reference from Exhibit 4.5 to TC PipeLines, LP’s Form 10-Q filed August 3, 2017).
4.5.1	Amendment No. 1 to Credit Agreement dated as of June 25, 2009, between Iroquois Gas Transmission System, L.P. and JPMorgan Chase Bank, N.A. as administrative agent for the lenders (Incorporated by reference from Exhibit 4.5.1to TC PipeLines, LP’s Form 10-Q filed August 3, 2017).
4.6	Second Amendment to TC PipeLines LP’s July 1, 2013 Term Loan Agreement, dated September 29, 2017 (Incorporated by reference from Exhibit 99.1 to TC PipeLines, LP’s Form 8-K filed October 3, 2017).
4.7	Amendment No. 1 to TC PipeLines LP’s September 30, 2015 Term Loan Agreement, dated September 29, 2017 (Incorporated by reference from Exhibit 99.2 to TC PipeLines, LP’s Form 8-K filed October 3, 2017).
4.8	First Amendment to TC PipeLines, LP’s Third Amended and Restated Revolving Credit Agreement, dated September 29, 2017(Incorporated by reference from Exhibit 99.3 to TC PipeLines, LP’s Form 8-K filed October 3, 2017).
10.1*	Transportation Service Agreement FT18966 between Great Lakes Gas Transmission Limited Partnership and TransCanada Pipelines Limited, effective August 4, 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*	Transportation Service Agreement FT18759 between Great Lakes Gas Transmission Limited Partnership and ANR Pipeline Company, effective date April 26, 2017.
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.

46

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 6th day of November 2017.

TC PIPELINES, LP
(A Delaware Limited Partnership)
by its General Partner, TC PipeLines GP, Inc.
By:	/s/ Brandon Anderson
	Brandon Anderson
	President
	TC PipeLines GP, Inc. (Principal Executive Officer)
By:	/s/ Nathaniel A. Brown
	Nathaniel A. Brown
	Controller
	TC PipeLines GP, Inc. (Principal Financial Officer)

47

EXHIBIT INDEX

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.

No.	Description
2.1	Agreement for Purchase and Sale of Partnership Interest in Iroquois Gas Transmission System, L.P. by and between TCPL Northeast Ltd. and TransCanada Iroquois Ltd., as Sellers and TC Pipelines Intermediate Limited Partnership as Buyer dated as of May 3, 2017 (Incorporated by reference from Exhibit 2.1 to TC PipeLines, LP’s Form 8-K filed May 3, 2017).
2.1.1	First Amendment to Purchase and Sale Agreement by and between TCPL Northeast Ltd. and TransCanada Iroquois Ltd., as Sellers and TC Pipelines Intermediate Limited Partnership as Buyer dated as of May 31, 2017 (Incorporated by reference from Exhibit 2.1.1 to TC PipeLines, LP’s Form 10-Q filed August 3, 2017).
2.2	Option Agreement Relating to Partnership Interest in Iroquois Gas Transmission System, L.P. by and between TransCanada Iroquois Ltd. and TC Pipelines Intermediate Limited Partnership as dated as of May 3, 2017 (Incorporated by reference from Exhibit 2.2 to TC PipeLines, LP’s Form 8-K filed May 3, 2017).
2.3	Agreement for Purchase and Sale of Partnership Interest in Portland Natural Gas Transmission System, by and between TCPL Portland Inc., as Seller and TC Pipelines Intermediate Limited Partnership as Buyer dated as of May 3, 2017 (Incorporated by reference from Exhibit 2.3 to TC PipeLines, LP’s Form 8-K filed May 3, 2017).
3.1	Third Amended and Restated Agreement of Limited Partnership of TC PipeLines, LP dated April 1, 2015 (Incorporated by reference from Exhibit 3.1 to TC PipeLines, LP’s Form 8-K filed April 1, 2015).
3.2	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).
4.1	Portland Natural Gas Transmission System Senior Secured Note Purchase Agreement dated as of April 10, 2003 (Incorporated by reference from Exhibit 4.1 to TC PipeLines, LP’s Form 10-Q filed August 3, 2017).
4.2	Iroquois Gas Transmission, L.P. Senior Note Purchase Agreement dated as of May 13, 2009 (Incorporated by reference from Exhibit 4.2 to TC PipeLines, LP’s Form 10-Q filed August 3, 2017).
4.3	Iroquois Gas Transmission, L.P. Senior Note Purchase Agreement dated as of April 27, 2010(Incorporated by reference from Exhibit 4.3 to TC PipeLines, LP’s Form 10-Q filed August 3, 2017).
4.4	Indenture dated as of May 30, 2000, between Iroquois Gas Transmission System, L.P. and The Chase Manhattan Bank (Incorporated by reference from Exhibit 4.4 to TC PipeLines, LP’s Form 10-Q filed August 3, 2017).
4.4.1	Second Supplemental Indenture dated as of August 13, 2002, between Iroquois Gas Transmission System, L.P. and JPMorgan Chase Bank (formerly known as The Chase Manhattan Bank) (Incorporated by reference from Exhibit 4.4.1 to TC PipeLines, LP’s Form 10-Q filed August 3, 2017).
4.5	Credit Agreement dated as of June 26, 2008, between Iroquois Gas Transmission System, L.P. and JPMorgan Chase Bank, N.A. as administrative agent (Incorporated by reference from Exhibit 4.5 to TC PipeLines, LP’s Form 10-Q filed August 3, 2017).
4.5.1	Amendment No. 1 to Credit Agreement dated as of June 25, 2009, between Iroquois Gas Transmission System, L.P. and JPMorgan Chase Bank, N.A. as administrative agent for the lenders (Incorporated by reference from Exhibit 4.5.1to TC PipeLines, LP’s Form 10-Q filed August 3, 2017).
4.6	Second Amendment to TC PipeLines LP’s July 1, 2013 Term Loan Agreement, dated September 29, 2017 (Incorporated by reference from Exhibit 99.1 to TC PipeLines, LP’s Form 8-K filed October 3, 2017).
4.7	Amendment No. 1 to TC PipeLines LP’s September 30, 2015 Term Loan Agreement, dated September 29, 2017 (Incorporated by reference from Exhibit 99.2 to TC PipeLines, LP’s Form 8-K filed October 3, 2017).

48

4.8	First Amendment to TC PipeLines, LP’s Third Amended and Restated Revolving Credit Agreement, dated September 29, 2017(Incorporated by reference from Exhibit 99.3 to TC PipeLines, LP’s Form 8-K filed October 3, 2017).
10.1*	Transportation Service Agreement FT18966 between Great Lakes Gas Transmission Limited Partnership and TransCanada Pipelines Limited, effective August 4, 2017.
31.1*	Certification of Principal Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*	Certification of Principal Financial 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*	Transportation Service Agreement FT18759 between Great Lakes Gas Transmission Limited Partnership and ANR Pipeline Company, effective date April 26, 2017.
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.

49

EX-10.1

Exhibit 10.1

TRANSPORTATION SERVICE AGREEMENT

Contract Identification FT18966

This Transportation Service Agreement (Agreement) is entered into by Great Lakes Gas Transmission Limited Partnership (Transporter) and TRANSCANADA PIPELINES LIMITED(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: August 04, 2017

2.CONTRACT IDENTIFICATION: FT18966

3.RATE SCHEDULE: FT

4.SHIPPER TYPE: Other

5.STATE/PROVINCE OF INCORPORATION: Canada

6.TERM: November 01, 2017 to October 31, 2027

The latter of November 1, 2017 or the date upon which Shipper’s Dawn Long Term Fixed Price (“LTFP”) service commences after receipt of National Energy Board (“NEB”) approval of Dawn LTFP service and St. Clair to Dawn sale on terms and conditions acceptable to Shipper in its sole discretion, but no later than April 1, 2018. Shipper will provide written notice to Great Lakes of the commencement date of Dawn LTFP service within 30 days of the later of an acceptable NEB approval of Dawn LTFP service or an acceptable NEB approval of the St. Clair to Dawn sale. Contract Start Date is subject to Great Lakes’ receipt and acceptance, in a form and substance acceptable to Great Lakes in its sole discretion, of all approvals that Great Lakes determines necessary to provide the service contemplated herein. In the event the commencement date is later than November 1, 2017, this Agreement shall terminate ten years thereafter.

Transporter and Shipper agree that Shipper may extend the primary term of this Agreement by exercising a Contractual Right of First Refusal, pursuant to the procedures set forth in 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): N/A

8.MAXIMUM DAILY QUANTITY (Dth/Day): 711,000

Please sec 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 and/or on Appendix B hereto.

Shipper shall pay Transporter the Negotiated Rate components as described on Appendix B.

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:

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:

Shipper shall have the right to reduce its contractual MDQ, or terminate this contract, effective on or after the 3rd anniversary date provided that 1 years’ prior written notice has been given to Great Lakes.

2

On or before April 1, 2018, Shipper shall have a one-time Reduction Option upon written notice, within 30 days of receipt by Shipper of a decision by the NEB on Shipper’s Dawn LTFP service that is not acceptable to Shipper in its sole discretion, or within 30 days of receipt by Shipper of a decision by the NEB on the St. Clair to Dawn-sale that is not acceptable to Shipper in its sole discretion, or Shipper was not able to obtain matching downstream capacity from St. Clair to Dawn despite Shipper’s best efforts. If Shipper invokes this one-time Reduction Option, it may reduce all or a portion of the contractual MDQ associated with this Agreement. If contractual MDQ is changed, Great Lakes may adjust its Reservation Rate, Contract End Date, and/or Reduction Options accordingly.

15.NOTICES AND COMMUNICATIONS:

All notices and communications with respect to this Agreement shall be in writing by mail, e-mail, or fax, 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 fax, or other means similarly agreed to:

ADMINISTRATIVE MATTERS Great Lakes Gas Transmission Limited Partnership Commercial Services 700 Louisiana St., Suite 700 Houston, TX 77002-2700	TRANSCANADA PIPELINES LIMITED 450 - 1st Street S.W. Calgary, AB T2P 5H1 Canada Attn: Don Bell
AGREED TO BY: GREAT LAKES GAS TRANSMISSION LIMITED PARTNERSHIP By: Great Lakes Gas Transmission Company	TRANSCANADA PIPELINES LIMITED

3

APPENDIX A

Contract Identification FT18966

Date: August 04, 2017

Supersedes Appendix Dated: Not Applicable

Shipper: TRANSCANADA PIPELINES LIMITED

Maximum Daily Quantity (Dth/Day) per Location:

					Maximum Allowable Operating Pressure
Begin Date	End Date	Point(s) of Primary Receipt	Point(s) of Primary Delivery	MDQ	(MAOP)
11/01/2017	10/31/2027	EMERSON		711,000	974
11/01/2017	10/31/2027		ST. CLAIR	711,000	974

4

APPENDIX B
RATE SCHEDULE: FT

Date: August 04, 2017

Supersedes Appendix Dated: Not Applicable

SHIPPER:TRANSCANADA PIPELINES LIMITED

Shipper agrees to the Negotiated Rate option in accordance with Section 5.1.4.4 of Rate Schedule FT, Section 5.2.4.4 of Rate Schedule EFT, Section 5.3.4.4 of Rate Schedule LFT, or Section 5.4.4.4 of Rate Schedule IT, as provided above, and notifies Transporter that it desires to be billed, and agrees to pay, the charges specified below during the term of this Appendix B. Shipper acknowledges that this election is an alternative to the billing of charges under the appropriate Rate Schedule as set forth in Sections 4.1, 4.2 and 4.3 of Transporter’s FERC Gas Tariff, Third Revised Volume No. 1.

TERM:November 01, 2017 to October 31, 2027

The latter of November 1, 2017 or the date upon which Shipper’s Dawn Long Term Fixed Price (“LTFP”) service commences after receipt of National Energy Board (“NEB”) approval of Dawn LTFP service and St. Clair to Dawn sale on terms and conditions acceptable to Shipper in its sole discretion, but no later than April 1, 2018. Shipper will provide written notice to Great Lakes of the commencement date of Dawn LTFP service within 30 days of the later of an acceptable NEB approval of Dawn LTFP service or an acceptable NEB approval of the St. Clair to Dawn sale. Contract Start Date is subject to Great Lakes’ receipt and acceptance, in a form and substance acceptable to Great Lakes in its sole discretion, of all approvals that Great Lakes determines necessary to provide the service contemplated herein. In the event the commencement date is later than November 1, 2017, this Agreement shall terminate ten years thereafter.

SPECIFICATION OF NEGOTIATED RATE:

Shipper and Transporter agree that for service under this Agreement from the point(s) of receipt on Appendix A, to the point(s) of delivery listed on Appendix A, the Reservation fee to be charged shall be fixed at $8.890/Dth plus the applicable utilization, fuel and ACA.

Shipper will receive access to multiple Great Lakes delivery points as listed below at the primary path rate:

Belle River Mills, Chippewa, Deward, Farwell and Rattle Run

Where Transporter’s general system recourse reservation rate is higher than the fixed, negotiated rate stated above, then Transporter may require Shipper to convert its negotiated rate to a discounted reservation rate equal to $8.89/Dth per month.

EX-31.1

Exhibit 31.1

CERTIFICATION OF

PRINCIPAL EXECUTIVE OFFICER

I, Brandon Anderson, 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:	November 6, 2017
	/s/ Brandon Anderson
	Brandon Anderson
		Principal Executive Officer and President
		TC PipeLines GP, Inc., as General Partner of
		TC PipeLines, LP

EX-31.2

Exhibit 31.2

CERTIFICATION OF

PRINCIPAL FINANCIAL 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:	November 6, 2017
	/s/ Nathaniel A. Brown
	Nathaniel A. Brown
		Principal Financial Officer and Controller
		TC PipeLines GP, Inc., as General Partner of
		TC PipeLines, LP

EX-32.1

Exhibit 32.1

CERTIFICATION OF

PRINCIPAL EXECUTIVE OFFICER

I, Brandon Anderson, 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 September 30, 2017 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:	November 6, 2017
	/s/ Brandon Anderson
	Brandon Anderson
		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, Nathaniel A. Brown, Principal Financial Officer and Controller 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 September 30, 2017 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:	November 6, 2017
	/s/ Nathaniel A. Brown
	Nathaniel A. Brown
		Principal Financial Officer and Controller
		TC PipeLines GP, Inc., as General Partner of
		TC PipeLines, LP

EX-99.1

Exhibit 99.1

TRANSPORTATION SERVICE AGREEMENT

Contract Identification FT18759

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: April 26, 2017

2.CONTRACT IDENTIFICATION: FT18759

3.RATE SCHEDULE: FT

4.SHIPPER TYPE: Interstate Pl

5.STATE/PROVINCE OF INCORPORATION: Delaware

6.TERM: April 01, 2018 to March 31, 2019

7.EFFECT ON PREVIOUS CONTRACTS:

This Agreement supersedes, cancels and terminates, as of the effective date stated above, the following contract(s): N/A

8.MAXIMUM DAILY QUANTITY (Dth/Day): 10,100

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 and/or on Appendix B hereto.

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:

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.

2

15.NOTICES AND COMMUNICATIONS:

All notices and communications with respect to this Agreement shall be in writing by mail, e-mail, or fax, 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 fax, or other means similarly agreed to:

ADMINISTRATIVE MATTERS
Great Lakes Gas Transmission Limited Partnership	ANR PIPELINE COMPANY
Commercial Services	700 Louisiana St., Suite 700
700 Louisiana St., Suite 700	Houston, TX 77002-2700
Houston, TX 77002-2700	Attn:

3

APPENDIX A
Contract Identification FT18759

Date: April 26, 2017

Supersedes Appendix Dated: Not Applicable

Shipper: ANR PIPELINE COMPANY

Maximum Daily Quantity (Dth/Day) per Location:

					Maximum Allowable Operating Pressure
Begin Date	End Date	Point(s) of Primary Receipt	Point(s) of Primary Delivery	MDQ	(MAOP)
04/01/2018	03/31/2019	FARWELL		10,100	974
04/01/2018	03/31/2019		FORTUNE LAKE	10,100	974

4

XML

Document and Entity Information - shares	9 Months Ended
	Sep. 30, 2017	Nov. 03, 2017
Document and Entity Information
Entity Registrant Name	TC PIPELINES LP
Entity Central Index Key	0001075607
Document Type	10-Q
Document Period End Date	Sep. 30, 2017
Amendment Flag	false
Current Fiscal Year End Date	--12-31
Entity Current Reporting Status	Yes
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		69,881,012
Document Fiscal Year Focus	2017
Document Fiscal Period Focus	Q3

XML

CONSOLIDATED STATEMENTS OF INCOME - USD ($) shares in Millions, $ in Millions	3 Months Ended			9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016		Sep. 30, 2017		Sep. 30, 2016
Transmission revenues	$ 100	$ 103	[1]	$ 313		$ 315	[1]
Equity earnings (Note 4)	27	22	[1]	87		75	[1]
Operation and maintenance expenses	(16)	(15)	[1]	(47)		(42)	[1]
Property taxes	(7)	(7)	[1]	(21)		(20)	[1]
General and administrative	(1)	(1)	[1]	(6)		(5)	[1]
Depreciation	(25)	(24)	[1]	(73)		(71)	[1]
Financial charges and other (Note 14)	(23)	(18)	[1]	(59)		(53)	[1]
Net income before taxes	55	60	[1]	194		199	[1]
Income taxes (Note 18)				(1)		(1)	[1]
Net income	55	60	[1]	193	[2]	198	[1]
Net income attributable to non-controlling interests	1	2	[1]	7		10	[1]
Net income attributable to controlling interests	54	58	[1]	186		188	[1]
Net income attributable to controlling interest allocation (Note 8)
General Partner	4	4	[1]	12		9	[1]
TransCanada and its subsidiaries	8	11	[1]	10		15	[1]
Net income attributable to controlling interests	54	58	[1]	186		188	[1]
Common Units
Net income attributable to controlling interest allocation (Note 8)
Limited partners	$ 42	$ 43	[1]	$ 164		$ 164	[1]
Net income per common unit (Note 8) - basic (in dollars per unit)	$ 0.61	$ 0.65	[1],[3]	$ 2.38		$ 2.51	[1],[3]
Net income per common unit (Note 8) - diluted (in dollars per unit)	$ 0.61	$ 0.65		$ 2.38		$ 2.51
Weighted average common units outstanding - basic (in units)	69.4	66.1	[1]	68.9		65.3	[1]
Weighted average common units outstanding - diluted (in units)	69.4	66.1		68.9		65.3
Common units outstanding, end of period (in units)	69.6	66.6	[1]	69.6		66.6	[1]

[1] Recast to consolidate PNGTS for all periods presented (Refer to Notes 2 and 6).

[2] Recast to consolidate PNGTS for all periods presented (Refer to Notes 2 and 6).

[3] Net income per common unit prior to recast (Refer to Note 2).

XML

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Millions	3 Months Ended			9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	[1]	Sep. 30, 2017		Sep. 30, 2016	[1]
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
Net income	$ 55	$ 60		$ 193	[2]	$ 198
Other comprehensive income
Change in fair value of cash flow hedges (Note 12)		2		1		(1)
Amortization of realized loss on derivative financial instruments (Note 12)				1		1
Reclassification to net income of gains and losses on cash flow hedges (Note 12)	1
Comprehensive income	56	62		195		198
Comprehensive income attributable to non-controlling interests	1	2		7		10
Comprehensive income attributable to controlling interests	$ 55	$ 60		$ 188		$ 188

[1] Recast to consolidate PNGTS for all periods presented (Refer to Notes 2 and 6).

[2] Recast to consolidate PNGTS for all periods presented (Refer to Notes 2 and 6).

XML

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions		Sep. 30, 2017	Dec. 31, 2016
Current Assets
Cash and cash equivalents		$ 73	$ 64	[1]
Accounts receivable and other (Note 13)		35	47	[1]
Inventories		7	7	[1]
Other		6	7	[1]
Total current assets		121	125	[1]
Equity investments (Note 4)		1,207	918	[1]
Plant, property and equipment (Net of $1,158 accumulated depreciation; 2016 - $1,088)		2,133	2,180	[1]
Goodwill		130	130	[1]
Other assets	[1]		1
Total assets		3,591	3,354	[1]
Current Liabilities
Accounts payable and accrued liabilities		31	29	[1]
Accounts payable to affiliates (Note 11)		5	8	[1]
Distribution payable	[1]		3
Accrued interest		21	10	[1]
Current portion of long-term debt (Note 5)		51	52	[1]
Total current liabilities		108	102	[1]
Long-term debt, net (Note 5)		2,427	1,859	[1]
Deferred state income taxes (Note 18)		10	10	[1]
Other liabilities		28	28	[1]
Total liabilities		2,573	1,999	[1]
Common units subject to rescission (Note 7)	[1]		83
Partners' Equity
General partner		23	27	[1]
Accumulated other comprehensive loss	[1]		(2)
Controlling interests		916	1,144	[1]
Non-controlling interests		102	97	[1]
Equity of former parent of PNGTS	[1]		31
Total partners' equity	[2]	1,018	1,272
Total liabilities and partners' equity		3,591	3,354	[1]
Common Units
Partners' Equity
Limited partner		790	1,002	[1]
Class B Units
Partners' Equity
Limited partner		$ 103	$ 117	[1]

[1] Recast to consolidate PNGTS for all periods presented (Refer to Notes 2 and 6).

[2] Recast to consolidate PNGTS for all periods presented (Refer to Notes 2 and 6).

XML

CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Millions	Sep. 30, 2017	Dec. 31, 2016
CONSOLIDATED BALANCE SHEETS
Accumulated depreciation	$ 1,158	$ 1,088

XML

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Millions		9 Months Ended
		Sep. 30, 2017		Sep. 30, 2016
Cash Generated From Operations
Net income		$ 193	[1]	$ 198	[2]
Depreciation		73		71	[2]
Amortization of debt issue costs reported as interest expense		1		1	[2]
Amortization of realized loss on derivative instrument		1		1	[2]
Equity earnings from equity investments (Note 3 and 4)		(87)		(75)	[2]
Distributions received from operating activities of equity investments (Note 3)		106		125	[2]
Change in operating working capital (Note 10)		24		11	[2]
Net Cash Provided by (Used in) Operating Activities		311		332	[2]
Investing Activities
Distribution received from Iroquois as return of investment (Note 4)		3
Capital expenditures		(26)		(21)	[2]
Other	[2]			3
Net Cash Provided by (Used in) Investing Activities		(756)		(215)	[2]
Financing Activities
Distributions paid to non-controlling interests		(5)		(12)	[2]
Common unit issuance, net (Note 7)		126		35	[2]
Common unit issuance subject to rescission, net (Note 7)	[2]			83
Long-term debt issued, net of discount (Note 5)		732		200	[2]
Long-term debt repaid (Note 5)		(164)		(196)	[2]
Debt issuance costs		(2)
Total financing activities		454		(95)	[2]
Decrease in cash and cash equivalents		9		22	[2]
Cash and cash equivalents, beginning of period	[2]	64		55
Cash and cash equivalents, end of period		73		77	[2]
Class B Units
Financing Activities
Distributions paid (Note 7)		(22)		(12)	[2]
Common units and General Partner interest combined
Financing Activities
Distributions paid (Note 9)		(210)		(184)	[2]
Northern Border
Cash Generated From Operations
Equity earnings from equity investments (Note 3 and 4)		(50)		(52)
Investing Activities
Investment/Acquisition of interests		(83)
Great Lakes
Cash Generated From Operations
Equity earnings from equity investments (Note 3 and 4)		(24)		(23)
Investing Activities
Investment/Acquisition of interests		(4)		(4)	[2]
Portland Natural Gas Transmission System
Investing Activities
Investment/Acquisition of interests	[2]			(193)
Financing Activities
Distributions paid to former parent of PNGTS		(1)		$ (9)	[2]
Portland Natural Gas Transmission System And Iroquois Acquisition
Investing Activities
Investment/Acquisition of interests		$ (646)

[1] Recast to consolidate PNGTS for all periods presented (Refer to Notes 2 and 6).

[2] Recast to consolidate PNGTS for all periods presented (Refer to Notes 2 and 6).

XML

CONSOLIDATED STATEMENTS OF CASH FLOWS (Parenthetical)	Sep. 30, 2017	Aug. 01, 2017	Jun. 01, 2017	Sep. 30, 2016
Portland Natural Gas Transmission System
Interest acquired (as a percent)	11.81%		11.81%	49.90%
Iroquois
Interest acquired (as a percent)	49.34%	49.34%	49.34%

XML

CONSOLIDATED STATEMENT OF CHANGES IN PARTNERS' EQUITY - 9 months ended Sep. 30, 2017 - USD ($) shares in Millions, $ in Millions		Limited Partners Common Units	Limited Partners Class B Units	General Partner	Accumulated Other Comprehensive Loss	[1]	Non-Controlling Interest		Equity of former parent of PNGTS		Total
Partners' Equity at beginning of year at Dec. 31, 2016		$ 1,002	$ 117	$ 27	$ (2)	[2]	$ 97	[2]	$ 31	[2]	$ 1,272	[2]
Partners' Equity at beginning of year (in units) at Dec. 31, 2016		67.4	1.9
Increase (Decrease) in Partners' Equity
Net income	[2]	$ 164	$ 8	12			7		2		193
Other comprehensive income	[2]				$ 2						2
ATM equity issuance, net (Note 7)		$ 124		2							126	[2]
ATM equity issuance, net (Note 7) (in units)		2.2
Reclassification of common units no longer subject to rescission (Note 7)		$ 81		2							83	[2]
Acquisition of interests in PNGTS and Iroquois (Note 6)		(383)		(8)					(32)	[2]	(423)	[2]
Distributions	[2]	(198)	(22)	(12)			(2)		$ (1)		(235)
Partners' Equity at end of year at Sep. 30, 2017		$ 790	$ 103	$ 23			$ 102	[2]			$ 1,018	[2]
Partners' Equity at end of year (in units) at Sep. 30, 2017		69.6	1.9

[1] Losses related to cash flow hedges reported in Accumulated Other Comprehensive Loss and expected to be reclassified to Net Income in the next 12 months are estimated to be $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.Recast to consolidate PNGTS for all periods presented (Refer to Notes 2 and 6).

[2] Recast to consolidate PNGTS for all periods presented (Refer to Notes 2 and 6).

XML

CONSOLIDATED STATEMENT OF CHANGES IN PARTNERS' EQUITY (Parenthetical) $ in Millions	9 Months Ended
	Sep. 30, 2017 USD ($)
CONSOLIDATED STATEMENT OF CHANGES IN PARTNERS' EQUITY
Losses expected to be reclassified to Net Income in the next 12 months	$ 1

XML

ORGANIZATION

9 Months Ended

Sep. 30, 2017

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 (TransCanada Corporation together with its subsidiaries collectively referred to herein as TransCanada), to acquire, own and participate in the management of energy infrastructure assets in North America.

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

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SIGNIFICANT ACCOUNTING POLICIES

9 Months Ended

Sep. 30, 2017

SIGNIFICANT ACCOUNTING POLICIES

SIGNIFICANT ACCOUNTING POLICIES

NOTE 2 SIGNIFICANT ACCOUNTING POLICIES

The accompanying financial statements and related notes have been prepared in accordance with United States generally accepted accounting principles (GAAP) and amounts are stated in U.S. dollars. The results of operations for the three and nine months ended September 30, 2017 and 2016 are not necessarily indicative of the results that may be expected for the full fiscal year.

The accompanying financial statements should be read in conjunction with the audited financial statements and notes thereto for the year ended December 31, 2016 included as exhibit 99.2 in our Current Report on Form 8-K dated August 3, 2017. That report contains a more comprehensive summary of the Partnership’s significant accounting policies. In the opinion of management, the accompanying financial statements contain all of the appropriate adjustments, all of which are normally recurring adjustments unless otherwise noted, and considered necessary to present fairly the financial position of the Partnership, the results of operations and cash flows for the respective periods. Our significant accounting policies are consistent with those disclosed in our audited financial statements and notes thereto for the year ended December 31, 2016 included as exhibit 99.2 in our Current Report on Form 8-K dated August 3, 2017, except as described in Note 3, Accounting Pronouncements.

Basis of Presentation

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

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

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

On June 1, 2017, the Partnership acquired from a subsidiary of TransCanada an additional 11.81 percent interest in PNGTS, that resulted in the Partnership owning a 61.71 percent interest in PNGTS (Refer to Note 6).  As a result of the Partnership owning 61.71 percent interest in PNGTS, the Partnership’s historical financial information has been recast, except net income (loss) per common unit, to consolidate PNGTS for all the periods presented in the Partnership’s consolidated financial statements. Additionally, this acquisition was accounted for as transaction between entities under common control, similar to pooling of interests, whereby the assets and liabilities of PNGTS were recorded at TransCanada’s carrying value.

Also, on June 1, 2017, the Partnership acquired from subsidiaries of TransCanada a 49.34 percent interest in Iroquois Gas Transmission, L.P. (“Iroquois”) (Refer to Note 6). Accordingly, this transaction was accounted for as a transaction between entities under common control, similar to pooling of interest, whereby the equity investment in Iroquois was recorded at TransCanada’s carrying value and was accounted for prospectively.

Use of Estimates

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

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ACCOUNTING PRONOUNCEMENTS

9 Months Ended

Sep. 30, 2017

ACCOUNTING PRONOUNCEMENTS

ACCOUNTING PRONOUNCEMENTS

NOTE 3 ACCOUNTING PRONOUNCEMENTS

Retrospective application of Accounting Standards Update (ASU) No 2016-15 “Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments”

In August 2016, the Financial Accounting Standards Board (FASB) issued an amendment of previously issued guidance, which intends to reduce diversity in practice in how certain transactions are classified in the statement of cash flows. The new guidance is effective January 1, 2018, however, as early adoption is permitted, the Partnership elected to retrospectively apply this guidance effective December 31, 2016. The Partnership has elected to classify distributions received from equity method investees using the nature of distributions approach as it is more representative of the nature of the underlying activities of the investees that generated the distributions. As a result, certain comparative period distributions received from equity method investees, amounting to $50 million for the nine months ended September 30, 2016, have been reclassified from investing activities to cash generated from operations in the consolidated statement of cash flows.

Effective January 1, 2017

Inventory

In July 2015, the FASB issued new guidance on simplifying the measurement of inventory. The new guidance specifies that an entity should measure inventory within the scope of this update at the lower of cost and net realizable value. Net realizable value is the estimated selling price in the ordinary course of business, less reasonably predictable costs of completion, disposal and transportation. This new guidance was effective January 1, 2017, was applied prospectively and did not have a material impact on the Partnership’s consolidated balance sheet.

Equity method and joint ventures

In March 2016, the FASB issued new guidance that simplifies the transition to equity method accounting. The new guidance eliminates the requirement to retroactively apply the equity method of accounting when an increase in ownership interest in an investment qualifies for equity method accounting. The new guidance is effective January 1, 2017 and was applied prospectively. The application of this guidance did not have a material impact on the Partnership’s consolidated financial statements.

Consolidation

In October 2016, the FASB issued new guidance on consolidation relating to interests held through related parties that are under common control.  The new guidance amends the consolidation requirements such that if a decision maker is required to evaluate whether it is the primary beneficiary of a variable interest entry (VIE), it will need to consider only its proportionate indirect interest in the VIE held through a common control party.  The guidance was effective January 1, 2017, was applied retrospectively and did not result in any change to our consolidation conclusions.

Future accounting changes

Revenue from contracts with customers

In 2014, the FASB issued new guidance on revenue from contracts with customers. The new guidance requires that an entity recognize revenue in accordance with a prescribed model. This model is used to depict the transfer of promised goods or services to customers in an amount that reflects the total consideration to which it expects to be entitled during the term of the contract in exchange for those goods or services. The new guidance also requires additional disclosures about the nature, amount, timing and uncertainty of revenue and the related cash flows. The Partnership will adopt the new standard on the effective date of January 1, 2018. There are two methods in which the new standard can be adopted: (1) a full retrospective approach with restatement of all prior periods presented, or (2) a modified retrospective approach with a cumulative-effect adjustment as of the date of adoption. The Partnership will adopt the standard using the modified retrospective approach with the cumulative-effect of the adjustment recognized at the date of adoption, subject to allowable and elected practical expedients.

The Partnership has identified all existing customer contracts that are within the scope of the new guidance and is on schedule in the process of analyzing individual contracts or groups of contracts to identify any significant changes in how revenues are recognized as a result of implementing the new guidance. While the Partnership has not identified any material differences in the amount and timing of revenue recognition for the contracts that have been analyzed to date, the evaluation is not complete and the Partnership has not concluded on the overall impact of adopting the new guidance. The Partnership continues its contract analysis to obtain the information necessary to quantify the cumulative-effect adjustment, if any, on prior period revenues and revenue recognized going forward.

Although consolidated revenues may not be materially impacted by the new guidance, the Partnership currently anticipates significant changes to disclosures based on the additional requirements prescribed. These new disclosures include information regarding the significant judgments used in evaluating when and how revenue is recognized and information related to contract assets and liabilities. In addition, the new guidance requires that the Partnership’s revenue recognition policy disclosure includes additional detail regarding the various performance obligations and the nature, amount, timing and estimates of revenue and cash flows generated from contracts with customers. The Partnership continues to develop and evaluate disclosures required with a particular focus on the scope of contracts subject to disclosure of remaining performance obligations. The Partnership also continues to address any system and process changes necessary to compile the information to meet the recognition and disclosure requirements of the new guidance. The Partnership continues to monitor additional authoritative or interpretive guidance related to the new guidance as it becomes available.

Leases

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

The new guidance is effective on January 1, 2019, with early adoption permitted. A modified retrospective transition approach is required for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements, with certain practical expedients available. The Partnership is continuing to identify and analyze existing lease agreements to determine the effect of adoption of the new guidance on its consolidated financial statements. The Partnership is also addressing system and process changes necessary to compile the information to meet the recognition and disclosure requirements of the new guidance.

Goodwill Impairment

In January 2017, the FASB issued new guidance on simplifying the test for goodwill impairment by eliminating the requirement to calculate the implied fair value of goodwill to measure the impairment charge. Instead, entities will record an impairment charge based on the excess of a reporting unit’s carrying amount over its fair value. This new guidance is effective January 1, 2020 and will be applied prospectively. Early adoption is permitted. The Partnership is currently evaluating the impact of the adoption of this guidance and has not yet determined the effect on its consolidated financial statements.

Hedge Accounting

In August 2017, the FASB issued new guidance on hedge accounting, making more financial and nonfinancial hedging strategies eligible for hedge accounting. The new guidance amends the presentation requirements relating to the change in fair value of a derivative and additional disclosure requirements include cumulative basis adjustments for fair value hedges and the effect of hedging on individual statement of income line items. This new guidance is effective January 1, 2019 and will be applied prospectively with a cumulative-effect adjustment to opening equity on adoption. Early adoption is permitted. The Partnership is currently evaluating the impact of the adoption of this guidance and has not yet determined the effect on its consolidated financial statements.

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EQUITY INVESTMENTS

9 Months Ended

Sep. 30, 2017

EQUITY INVESTMENTS

EQUITY INVESTMENTS

NOTE 4 EQUITY INVESTMENTS

The Partnership has equity interests in Northern Border, Great Lakes and effective June 1, 2017, Iroquois. The pipeline systems owned by these entities are regulated by FERC. The pipeline systems of Northern Border and Great Lakes are operated by subsidiaries of TransCanada. The Iroquois pipeline system is operated by Iroquois Pipeline Operating Company, a wholly owned subsidiary of Iroquois. The Partnership uses the equity method of accounting for its interests in its equity investees. The Partnership’s equity investments are held through our ILPs that are considered to be variable interest entities (VIEs) (Refer to Note 17).

	Ownership		Equity Earnings				Equity Investments
	Interest at		Three months		Nine Months
(unaudited)	September 30,		ended September 30,		ended September 30,		September 30,	December 31,
(millions of dollars)	2017		2017	2016(b)	2017	2016(b)	2017	2016(b)
Northern Border (a)	50	%	16	18	50	52	516	444
Great Lakes	46.45	%	2	4	24	23	469	474
Iroquois	49.34	%	9	—	13	—	222	—
			27	22	87	75	1,207	918

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

(b) Recast to eliminate equity earnings from PNGTS and consolidate PNGTS for all periods presented (Refer to Notes 2 and 6).

Northern Border

On September 1, 2017, the Partnership made an equity contribution to Northern Border amounting to $83 million. This amount represents the Partnership’s 50 percent share of $166 million capital contribution request from Northern Border to reduce the outstanding balance of its revolver debt to increase its available borrowing capacity.

The Partnership did not have undistributed earnings from Northern Border for the three and nine months ended September 30, 2017 and 2016.

The summarized financial information for Northern Border is as follows:

(unaudited)
(millions of dollars)	September 30, 2017		December 31, 2016
ASSETS
Cash and cash equivalents	24		14
Other current assets	36		36
Plant, property and equipment, net	1,069		1,089
Other assets	14		14
	1,143		1,153
LIABILITIES AND PARTNERS’ EQUITY
Current liabilities	48		38
Deferred credits and other	30		28
Long-term debt, including current maturities, net	264		430
Partners’ equity
Partners’ capital	802		659
Accumulated other comprehensive loss	(1	)	(2	)
	1,143		1,153

	Three months ended				Nine months ended
(unaudited)	September 30,				September 30,
(millions of dollars)	2017		2016		2017		2016
Transmission revenues	73		74		217		218
Operating expenses	(20	)	(18	)	(56	)	(53	)
Depreciation	(15	)	(15	)	(45	)	(44	)
Financial charges and other	(5	)	(5	)	(14	)	(16	)
Net income	33		36		102		105

Great Lakes

The Partnership made an equity contribution to Great Lakes of $4 million in the first quarter of 2017. This amount represents the Partnership’s 46.45 percent share of a $9 million cash call from Great Lakes to make a scheduled debt repayment.

The Partnership did not have undistributed earnings from Great Lakes for the three and nine months ended September 30, 2017 and 2016.

The summarized financial information for Great Lakes is as follows:

(unaudited)
(millions of dollars)	September 30, 2017	December 31, 2016
ASSETS
Current assets	56	66
Plant, property and equipment, net	705	714
	761	780
LIABILITIES AND PARTNERS’ EQUITY
Current liabilities	41	40
Net long-term debt, including current maturities	269	278
Partners’ equity	451	462
	761	780

	Three months ended				Nine months ended
(unaudited)	September 30,				September 30,
(millions of dollars)	2017		2016		2017		2016
Transmission revenues	34		36		138		133
Operating expenses	(19	)	(15	)	(49	)	(45	)
Depreciation	(7	)	(7	)	(21	)	(21	)
Financial charges and other	(5	)	(6	)	(16	)	(17	)
Net income	3		8		52		50

Iroquois

On June 1, 2017, the Partnership acquired a 49.34 percent interest in Iroquois. Also on July 27, 2017, Iroquois declared its second quarter 2017 distribution of $28 million, of which the Partnership received its 49.34 percent share or $14 million on August 1, 2017. The distribution includes the Partnership’s 49.34 percent share of the Iroquois unrestricted cash distribution amounting to approximately $2.6 million (Refer to Note 6). This amount is reported as distributions received as return of investment in the Partnership’s consolidated statement of cash flows.

The Partnership recorded no undistributed earnings from Iroquois in the three and nine months ended September 30, 2017.

The summarized financial information for Iroquois is as follows:

(unaudited)
(millions of dollars)	September 30, 2017	December 31, 2016
ASSETS
Cash and cash equivalents	93	86
Other current assets	33	34
Plant, property and equipment, net	592	604
Other assets	8	7
	726	731
LIABILITIES AND PARTNERS’ EQUITY
Current liabilities	20	18
Net long-term debt, including current maturities	332	335
Other non-current liabilities	9	6
Partners’ equity	365	372
	726	731

	Three months ended				Nine months ended
(unaudited)	September 30,				September 30,
(millions of dollars)	2017		2016		2017		2016
Transmission revenues	43		45		142		145
Operating expenses	(13	)	(13	)	(41	)	(43	)
Depreciation	(7	)	(9	)	(22	)	(28	)
Financial charges and other	(4	)	(4	)	(13	)	(12	)
Net income	19		19		66		62

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DEBT AND CREDIT FACILITIES

9 Months Ended

Sep. 30, 2017

DEBT AND CREDIT FACILITIES

DEBT AND CREDIT FACILITIES

NOTE 5 DEBT AND CREDIT FACILITIES

(unaudited) (millions of dollars)	September 30, 2017	Weighted Average Interest Rate for the Nine Months Ended September 30, 2017		December 31, 2016 (a)	Weighted Average Interest Rate for the Year Ended December 31, 2016
TC PipeLines, LP
Senior Credit Facility due 2021	255	2.34	%	160	1.72	%
2013 Term Loan Facility due October 2022	500	2.26	%	500	1.73	%
2015 Term Loan Facility due October 2020	170	2.15	%	170	1.63	%
4.65% Unsecured Senior Notes due 2021	350	4.65	%(b)	350	4.65	%(b)
4.375% Unsecured Senior Notes due 2025	350	4.375	%(b)	350	4.375	%(b)
3.90 % Unsecured Senior Notes due 2027	500	3.90	%(b)	—	—
GTN
5.29% Unsecured Senior Notes due 2020	100	5.29	%(b)	100	5.29	%(b)
5.69% Unsecured Senior Notes due 2035	150	5.69	%(b)	150	5.69	%(b)
Unsecured Term Loan Facility due 2019	55	1.95	%	65	1.43	%
PNGTS
5.90% Senior Secured Notes due December 2018	36	5.90	%(b)	53	5.90	%(b)
Tuscarora
Unsecured Term Loan due 2020	25	2.18	%	10	1.64	%
3.82% Series D Senior Notes due August 2017	—	3.82	%(b)	12	3.82	%(b)
	2,491			1,920
Less: unamortized debt issuance costs and debt discount	13			9
Less: current portion	51			52
	2,427			1,859

(a) Recast to consolidate PNGTS for all periods presented (Refer to Notes 2 and 6).

(b) 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, under which $255 million was outstanding at September 30, 2017 (December 31, 2016 - $160 million), leaving $245 million available for future borrowing. The LIBOR-based interest rate on the Senior Credit Facility was 2.49 percent at September 30, 2017 (December 31, 2016 — 1.92 percent).

On September 29, 2017, the Partnership’s 2013 Term Loan Facility that was due on July 1, 2018 was amended to extend the maturity period through October 2, 2022. As of September 30, 2017, the variable interest rate exposure related to the 2013 Term Loan Facility was hedged by fixed interest rate swap arrangements and our effective interest rate was 2.31 percent (December 31, 2016 — 2.31 percent). Prior to hedging activities, the LIBOR-based interest rate on the 2013 Term Loan Facility was 2.49 percent at September 30, 2017 (December 31, 2016 — 1.87 percent).

On September 29, 2017, the Partnership’s 2015 Term Loan Facility that was due on October 1, 2018 was amended to extend the maturity period through October 1, 2020. The LIBOR-based interest rate on the 2015 Term Loan Facility was 2.39 percent at September 30, 2017 (December 31, 2016 — 1.77 percent).

The 2013 Term Loan Facility and the 2015 Term Loan Facility (collectively, the Term Loan Facilities) and the Senior Credit Facility  require the Partnership to maintain a certain leverage ratio (debt to adjusted cash flow [net income plus cash distributions received, extraordinary losses, interest expense, expense for taxes paid or accrued, and depreciation and amortization expense less equity earnings and extraordinary gains]) no greater than 5.00 to 1.00 for each fiscal quarter, except for the fiscal quarter and the two following fiscal quarters in which one or more acquisitions has been executed, in which case the leverage ratio is to be no greater than 5.50 to 1.00. The leverage ratio was 4.76 to 1.00 as of September 30, 2017.

On May 25, 2017, the Partnership closed a $500 million public offering of senior unsecured notes bearing an interest rate of 3.90 percent maturing May 25, 2027. The net proceeds of $497 million were used to fund a portion of the 2017 Acquisition (Refer to Note 6). The indenture for the notes contains customary investment grade covenants.

PNGTS

PNGTS’ Senior Secured Notes are secured by the PNGTS long-term firm shipper contracts and its partners’ pledge of their equity and a guarantee of debt service for six months. PNGTS is restricted under the terms of its note purchase agreement from making cash distributions unless certain conditions are met. Before a distribution can be made, the debt service reserve account must be fully funded and PNGTS’ debt service coverage ratio for the preceding and succeeding twelve months must be 1.30 or greater. At September 30, 2017, the debt service coverage ratio was 1.71 for the twelve preceding months and 5.31 for the twelve succeeding months. Therefore, PNGTS was not restricted to make any cash distributions.

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 September 30, 2017 was 44.2 percent. The LIBOR-based interest rate on the GTN’s Unsecured Term Loan Facility was 2.19 percent at September 30, 2017 (December 31, 2016 — 1.57 percent).

Tuscarora

On August 21, 2017, Tuscarora refinanced all of its outstanding debt by amending its existing Unsecured Term Loan Facility and issuing a new $25 million variable rate term loan that will require yearly principal payments and will mature on August 21, 2020. Tuscarora’s Unsecured Term Loan contains a covenant that requires Tuscarora to maintain a debt service coverage ratio (cash available from operations divided by a sum of interest expense and principal payments) of greater than or equal to 3.00 to 1.00. As of September 30, 2017, the ratio was 3.08 to 1.00.

The LIBOR-based interest rate on the Tuscarora’s Unsecured Term Loan Facility was 2.36 percent at September 30, 2017 (December 31, 2016 — 1.90 percent).

At September 30, 2017, the Partnership was in compliance with its financial covenants, in addition to the other covenants which include restrictions on entering into mergers, consolidations and sales of assets, granting liens, material amendments to the Third 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)
2017	12
2018	45
2019	36
2020	293
2021	605
Thereafter	1,500
	2,491

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ACQUISITION

9 Months Ended

Sep. 30, 2017

ACQUISITION

ACQUISITION

NOTE 6 ACQUISITION

2017 Acquisition

On June 1, 2017, the Partnership acquired from subsidiaries of TransCanada a 49.34 percent interest in Iroquois, including an option to acquire a further 0.66 percent interest in Iroquois, together with an additional 11.81 percent interest in PNGTS resulting in the Partnership owning a 61.71 percent interest in PNGTS (2017 Acquisition). The total purchase price of the 2017 Acquisition was $765 million plus final purchase price adjustments amounting to $50 million. The purchase price consisted of (i) $710 million for the Iroquois interest (less $164 million, which reflected our 49.34 percent share of Iroquois outstanding debt on June 1, 2017), (ii) $55 million for the additional 11.81 percent interest in PNGTS (less $5 million, which reflected our 11.81% proportionate share in PNGTS’ outstanding debt on June 1, 2017) (iii) final working capital adjustments on PNGTS and Iroquois amounting to $3 million and $19 million, respectively and (iv) additional consideration for Iroquois’ surplus cash amounting to $28 million. Additionally, the Partnership paid $1,000 for the option to acquire TransCanada’s remaining 0.66 percent interest in Iroquois. The Partnership funded the cash portion of the 2017 Acquisition through a combination of proceeds from the May 2017 public debt offering (refer to Note 5) and borrowing under our Senior Credit Facility.

At the date of the 2017 Acquisition, there was significant cash on Iroquois’ balance sheet.  Pursuant to the Purchase and Sale Agreement associated with the acquisition of the Iroquois interest, as amended, the Partnership agreed to pay $28 million plus interest to TransCanada on August 1, 2017 for its 49.34 percent share of cash determined to be surplus to Iroquois’ operating needs.

Additionally, Iroquois’ partners adopted a distribution resolution to address the significant cash on Iroquois’ balance sheet post-closing. The Partnership expects to receive the $28 million of unrestricted cash as part of its quarterly distributions from Iroquois over 11 quarters under the terms of the resolution, which began with Iroquois’ second quarter 2017 distribution on August 1, 2017. As of November 6, 2017 the Partnership has received approximately $5.2 million of the expected $28 million, of which $2.6 million was received on November 1, 2017 (Refer to Note 19).

The acquisition of a 49.34 percent interest in Iroquois was accounted for as a transaction between entities under common control, whereby the equity investment in Iroquois was recorded at TransCanada’s carrying value and the total excess purchase price paid was recorded as a reduction in Partners’ Equity.

Iroquois’ net purchase price was allocated as follows:

(millions of dollars)
Net Purchase Price (a)	593
Less: TransCanada’s carrying value of Iroquois at June 1, 2017	223
Excess purchase price (b)	370

(a) Total purchase price of $710 million plus final working capital adjustment of $19 million and the additional consideration on Iroquois surplus cash amounting to approximately $28 million less the assumption of $164 million of proportional Iroquois debt by the Partnership.

(b) The excess purchase price of $370 million was recorded as a reduction in Partners’ Equity.

The acquisition of an additional 11.81 percent interest in PNGTS, which resulted in the Partnership owning 61.71 percent in PNGTS, was accounted for as a transaction between entities under common control, similar to a pooling of interests, whereby assets and liabilities of PNGTS were recorded at TransCanada’s carrying value and the Partnership’s historical financial information, except net income per common unit, was recast to consolidate PNGTS for all periods presented.

The PNGTS purchase price was recorded as follows:

(millions of dollars)
Current assets	25
Property, plant and equipment, net	294
Current liabilities	(4	)
Deferred state income taxes	(10	)
Long-term debt, including current portion	(41	)
	264
Non-controlling interest	(100	)
Carrying value of pre-existing Investment in PNGTS	(132	)
TransCanada’s carrying value of the acquired 11.81 percent interest at June 1, 2017	32
Excess purchase price over net assets acquired (a)	21
Total cash consideration (b)	53

(a) The excess purchase price of $21 million was recorded as a reduction in Partners’ Equity.

(b) Total purchase price of $55 million plus the final working capital adjustment of $3 million less the assumption of $5 million of proportional PNGTS debt by the Partnership.

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PARTNERS' EQUITY

9 Months Ended

Sep. 30, 2017

PARTNERS' EQUITY

PARTNERS' EQUITY

NOTE 7 PARTNERS’ EQUITY

ATM equity issuance program (ATM program)

During the nine months ended September 30, 2017, we issued 2,165,162 common units under our ATM program generating net proceeds of approximately $124 million, plus $2 million contributed by the General Partner to maintain its effective two percent general partner interest. The commissions to our sales agents in the nine months ended September 30, 2017 were approximately $1 million. The net proceeds were used for general partnership purposes.

Class B units issued to TransCanada

The Class B Units we issued on April 1, 2015 to finance a portion of the 2015 GTN Acquisition represent a limited partner interest in us and entitle TransCanada to an annual distribution based on 30 percent of GTN’s annual distributions as follows: (i) 100 percent of distributions above $20 million through March 31, 2020; and (ii) 25 percent of distributions above $20 million thereafter.

For the year ending December 31, 2017, the Class B units’ equity account will be increased by the excess of 30 percent of GTN’s distributions over the annual threshold of $20 million until such amount is declared for distribution and paid in the first quarter of 2018. During the nine months ended September 30, 2017, 30 percent of GTN’s total distributable cash flow was $28 million. As a result of exceeding the $20 million threshold, the Class B units’ equity account was increased by $8 million (Refer to Note 8).

For the year ended December 31, 2016, the Class B distribution was $22 million and was declared and paid in the first quarter of 2017.

Common unit issuance subject to rescission

In connection with a late filing of an employee-related Form 8-K with the SEC in March 2016, the Partnership became ineligible to use the then effective shelf registration statement upon filing of its Annual Report on Form 10-K for the year ended December 31, 2015. As a result, it was determined that the purchasers of the 1.6 million common units that were issued from March 8, 2016 to May 19, 2016 under the Partnership’s ATM program may have had a rescission right for an amount equal to the purchase price paid for the units, plus statutory interest and less any distributions paid, upon the return of such units to the Partnership. The Securities Act of 1933, as amended (Securities Act) generally requires that any claim brought for a violation of Section 5 of the Securities Act be brought within one year of violation.

At December 31, 2016, $83 million was recorded as common units subject to rescission on the consolidated balance sheet.  The Partnership classified the 1.6 million common units that were sold under its ATM program from March 8, 2016 up to and including May 19, 2016, which may have been subject to rescission rights, outside of equity given the potential redemption feature which was not within the control of the Partnership. These units were treated as outstanding for financial reporting purposes.

No unitholder claimed or attempted to exercise any rescission rights prior to their expiry dates and the final rights related to the sales of such units expired on May 19, 2017. As a result of the expiration of these rights, the $83 million was reclassified back to partners’ equity. At September 30, 2017, there were no outstanding common units subject to rescission on the Partnership’s consolidated balance sheet.

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NET INCOME PER COMMON UNIT

9 Months Ended

Sep. 30, 2017

NET INCOME PER COMMON UNIT

NET INCOME PER COMMON UNIT

NOTE 8 NET INCOME PER COMMON UNIT

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

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

The amount allocable to the Class B units in 2017 equals 30 percent of GTN’s distributable cash flow during the year ended December 31, 2017 less $20 million (December 31, 2016 —$20 million).

Net income per common unit was determined as follows:

	Three months ended September 30,						Nine months ended September 30,
(unaudited)
(millions of dollars, except per common unit amounts)	2017			2016 (a)			2017			2016 (a)
Net income attributable to controlling interests (a)	54			58			186			188
Net income attributable to PNGTS’ former parent (a) (b)	—			—			(2		)	(3		)
Net income attributable to General and Limited Partners	54			58			184			185
Incentive distributions allocated to the General Partner (c)	(3		)	(2		)	(9		)	(5		)
Net income attributable to the Class B units (d)	(8		)	(11		)	(8		)	(12		)
Net income attributable to the General Partner and common units	43			45			167			168
Net income attributable to General Partner’s effective two percent interest	(1		)	(2		)	(3		)	(4		)
Net income attributable to common units	42			43			164			164
Weighted average common units outstanding (millions) — basic and diluted	69.4			66.1		(e)	68.9			65.3		(e)
Net income per common unit — basic and diluted	$	0.61		$	0.65	(f)	$	2.38		$	2.51	(f)

(a) Recast to consolidate PNGTS for all periods presented (Refer to Notes 2 and 6).

(b) Net income allocable to General and Limited Partners excludes net income attributed to PNGTS’ former parent as it was allocated    to TransCanada and was not allocable to either the general partner, common units or Class B units.

(c) Under the terms of the Partnership Agreement, for any quarterly period, the participation of the incentive distribution rights (IDRs) is limited to the available cash distributions declared. Accordingly, incentive distributions allocated to the General Partner are based on the Partnership’s available cash during the current reporting period, but declared and paid in the subsequent reporting period.

(d) During the three and nine months ended September 30, 2017, 30 percent of GTN’s total distributable cash flow was $28 million. As a result of exceeding the $20 million threshold, $8 million of net income attributable to controlling interests was allocated to the Class B units during the three and nine months ended September 30, 2017.  During the six months ended June 30, 2016, the threshold was exceeded and during the nine months ended September 30, 2016, 30 percent of GTN’s total distributable cash flow was $32 million. As a result, $12 million of net income attributable to controlling interests was allocated to the Class B units at September 30, 2016, of which $1 million and $11 million were allocated during the three months ended June 30, 2016 and September 30, 2016, respectively (Refer to Note 7).

(e) Includes the common units subject to rescission. These units are treated as outstanding for financial reporting purposes (Refer to Note 7).

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

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CASH DISTRIBUTIONS

9 Months Ended

Sep. 30, 2017

CASH DISTRIBUTIONS

CASH DISTRIBUTIONS

NOTE 9 CASH DISTRIBUTIONS

During the three and nine months ended September 30, 2017, the Partnership distributed $1.00 and $2.88 per common unit, respectively (September 30, 2016 — $0.94 and $2.72 per common unit) for a total of $74 million and $210 million, respectively (September 30, 2016 - $65 million and $184 million).

The distribution paid to our General Partner during the three months ended September 30, 2017 for its effective two percent general partner interest was $2 million along with an IDR payment of $3 million for a total distribution of $5 million (September 30, 2016 - $1 million for the effective two percent interest and a $2 million IDR payment).

The distribution paid to our General Partner during the nine months ended September 30, 2017 for its effective two percent general partner interest was $4 million along with an IDR payment of $7 million for a total distribution of $11 million (September 30, 2016 - $3 million for the effective two percent interest and a $4 million IDR payment).

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CHANGE IN OPERATING WORKING CAPITAL

9 Months Ended

Sep. 30, 2017

CHANGE IN OPERATING WORKING CAPITAL

CHANGE IN OPERATING WORKING CAPITAL

NOTE 10 CHANGE IN OPERATING WORKING CAPITAL

(unaudited)	Nine months ended September 30,
(millions of dollars)	2017		2016 (a)
Change in accounts receivable and other	13		3
Change in other current assets	1		2
Change in accounts payable and accrued liabilities(b)	2		3
Change in accounts payable to affiliates	(3	)	(2	)
Change in accrued interest	11		5
Change in operating working capital	24		11

(a) Recast to consolidate PNGTS for all periods presented (Refer to Notes 2 and 6).

(b) The accrual of $10 million for the construction of GTN’s Carty Lateral in December 31, 2015 was paid during the first quarter 2016. Accordingly, the payment was reported as capital expenditures in our 2016 cash flow statement.

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RELATED PARTY TRANSACTIONS

9 Months Ended

Sep. 30, 2017

RELATED PARTY TRANSACTIONS

RELATED PARTY TRANSACTIONS

NOTE 11 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 the conduct of 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 and nine months ended September 30, 2017 and 2016, total costs charged to the Partnership by the General Partner were $1 million and $3 million, respectively.

As operator of our pipelines except Iroquois, TransCanada’s subsidiaries provide capital and operating services to our pipeline systems. TransCanada’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. The Iroquois pipeline system is operated by Iroquois Pipeline Operating Company, a wholly owned subsidiary of Iroquois. Therefore, Iroquois does not receive any capital and operating services from TransCanada.

Capital and operating costs charged to our pipeline systems, except for Iroquois, for the three and nine months ended September 30, 2017 and 2016 by TransCanada’s subsidiaries and amounts payable to TransCanada’s subsidiaries at September 30, 2017 and December 31, 2016 are summarized in the following tables:

	Three months ended September 30,		Nine months ended September 30,
(unaudited)
(millions of dollars)	2017	2016	2017	2016
Capital and operating costs charged by TransCanada’s subsidiaries to:
Great Lakes (a)	10	8	27	22
Northern Border (a)	10	9	30	25
GTN	9	8	24	20
Bison	2	1	4	1
North Baja	1	1	3	3
Tuscarora	1	1	3	3
PNGTS	2	2	6	6
Impact on the Partnership’s net income:
Great Lakes (a)	4	3	11	9
Northern Border (a)	4	3	11	9
GTN	7	7	21	18
Bison	2	1	4	2
North Baja	1	1	3	3
Tuscarora	1	1	3	3
PNGTS (b)	1	1	4	3

(unaudited)	September 30,
(millions of dollars)	2017	December 31, 2016
Net amounts payable to TransCanada’s subsidiaries is as follows:
Great Lakes (a)	3	4
Northern Border (a)	3	4
GTN	3	3
Bison	1	1
North Baja	—	1
Tuscarora	—	1
PNGTS	1	1

(a) Represents 100 percent of the costs.

(b) Recast to consolidate PNGTS for all periods presented (Refer to Note 2).

Great Lakes earns significant transportation revenues from TransCanada and its affiliates, some of which are provided at discounted rates and some at maximum recourse rates. For the three and nine months ended September 30, 2017, Great Lakes earned 44 percent and 53 percent of transportation revenues from TransCanada and its affiliates, respectively (September 30, 2016 — 62 percent and 69 percent).

At September 30, 2017, $8 million was included in Great Lakes’ receivables in regards to the transportation contracts with TransCanada and its affiliates (December 31, 2016 — $19 million).

Great Lakes operates under a FERC approved 2013 rate settlement that includes a revenue sharing mechanism that requires Great Lakes to share with its shippers certain percentages of any qualifying revenues earned above a certain return on equity threshold. For the year ended December 31, 2016, Great Lakes recorded an estimated 2016 revenue sharing provision of $7.2 million. For the three and nine months ended September 30, 2017, Great Lakes recorded an estimated 2017 revenue sharing provision of $12 million and $22 million, respectively. Great Lakes expects that a significant percentage of this refund will be paid to its affiliates.

PNGTS earns transportation revenues from TransCanada and its affiliates. For three and nine months ended September 30, 2017, PNGTS earned approximately nil million and $1 million of its transportation revenues from TransCanada and its affiliates, respectively (2016 — $1 million and $2 million, respectively).

At September 30, 2017, nil million was included in PNGTS’ receivables in regards to the transportation contracts with TransCanada and its affiliates (December 31, 2016 — 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 September 30, 2017, PNGTS does not have an obligation for reimbursement under this arrangement.

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FAIR VALUE MEASUREMENTS

9 Months Ended

Sep. 30, 2017

FAIR VALUE MEASUREMENTS

FAIR VALUE MEASUREMENTS

NOTE 12 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.

Long-term debt is recorded at amortized cost and classified in Level 2 of the fair value hierarchy for fair value disclosure purposes. Interest rate derivative assets and liabilities are classified in 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 September 30, 2017 and December 31, 2016 was $2,555 million and $1,962 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 interest rate derivatives to manage its exposure to interest rate risk. We regularly assess the impact of interest rate fluctuations on future cash flows and evaluate hedging opportunities to mitigate our interest rate risk.

The Partnership’s interest rate swaps are structured such that the cash flows of the derivative instruments match those of the variable rate of interest on the 2013 Term Loan Facility. The Partnership hedged interest payments on the variable-rate 2013 Term Loan Facility with interest rate swaps maturing July 1, 2018, at a weighted average fixed interest rate of 2.31 percent. At September 30, 2017, the fair value of the interest rate swaps accounted for as cash flow hedges was an asset of $2 million (both on a gross and net basis). At December 31, 2016, the fair value of the interest rate swaps accounted for as cash flow hedges was an asset of $1 million and a liability of $1 million (on a gross basis) and an asset of nil million (on a net basis). The Partnership did not record any amounts in net income related to ineffectiveness for interest rate hedges for the three and nine months ended September 30, 2017 and 2016. The change in fair value of interest rate derivative instruments recognized in other comprehensive income was nil and a gain of $1 million for the three and nine months ended September 30, 2017, respectively (September 30, 2016 — gain of $2 million and a loss of $1 million). For the three and nine months ended September 30, 2017, the net realized loss related to the interest rate swaps was nil, and was included in financial charges and other (September 30, 2016 —$1 million and $2 million) (Refer to Note 14) .

As discussed in Note 5, the Partnership’s $500 million 2013 Term Loan that was due July 1, 2018, was amended to extend the maturity period through October 2, 2022. At September 30, 2017, the entire $500 million 2013 Term Loan was hedged until July 1, 2018. As a result of this extension, the Partnership implemented an interest rate hedging strategy during the fourth quarter and hedged the entire $500 million until its October 2, 2022 maturity using forward starting swaps at an average rate of 3.26 percent.

The Partnership has no master netting agreements; however, 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 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 September 30, 2017 (net asset of nil million as of December 31, 2016).

In anticipation of a debt refinancing in 2003, PNGTS entered into forward interest rate swap agreements to hedge the interest rate on its Senior Secured Notes due in 2018. These interest rate swaps were used to manage the impact of interest rate fluctuations and qualified as derivative financial instruments in accordance with ASC 815, Derivatives and Hedging. PNGTS settled its position with a payment of $20.9 million to counterparties at the time of the refinancing and recorded the realized loss in accumulated other comprehensive income as of the termination date. The previously recorded loss is currently being amortized against earnings over the life of the PNGTS Senior Secured Notes.  At September 30, 2017, our 61.71 percent proportionate share of net unamortized loss on PNGTS included in other comprehensive income was $1 million (December 31, 2016 - $2 million). For the three and nine months ended September 30, 2017, our 61.71 percent proportionate share of the amortization of realized loss on derivative instruments was nil and $1 million, respectively (September 30, 2016 —nil and $1 million).

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ACCOUNTS RECEIVABLE AND OTHER

9 Months Ended

Sep. 30, 2017

ACCOUNTS RECEIVABLE AND OTHER

ACCOUNTS RECEIVABLE AND OTHER

NOTE 13 ACCOUNTS RECEIVABLE AND OTHER

(unaudited)
(millions of dollars)	September 30, 2017	December 31, 2016 (a)
Trade accounts receivable, net of allowance of nil	34	44
Imbalance receivable from affiliates	—	2
Other	1	1
	35	47

(a) Recast as discussed in Notes 2 and 6.

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FINANCIAL CHARGES AND OTHER

9 Months Ended

Sep. 30, 2017

FINANCIAL CHARGES AND OTHER

FINANCIAL CHARGES AND OTHER

NOTE 14 FINANCIAL CHARGES AND OTHER

	Three months ended September 30,		Nine months ended September 30,
(unaudited)
(millions of dollars)	2017	2016(b)	2017		2016(b)
Interest expense (a)	23	17	59		52
PNGTS’ amortization of derivative loss on derivative instruments (Note 12) (b)	—	—	1		1
Net realized loss related to the interest rate swaps	—	1	—		2
Other income	—	—	(1	)	(2	)
	23	18	59		53

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

(b) Recast to consolidate PNGTS for all periods presented (Refer to Note 2).

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CONTINGENCIES

9 Months Ended

Sep. 30, 2017

CONTINGENCIES

CONTINGENCIES

NOTE 15 CONTINGENCIES

Great Lakes v. Essar Steel Minnesota LLC, et al. —  On October 29, 2009, Great Lakes filed suit in the U.S. District Court, District of Minnesota, against Essar Minnesota LLC (Essar Minnesota) and certain Foreign Essar Affiliates (collectively, Essar) for breach of its monthly payment obligation under its transportation services agreement with Great Lakes. Great Lakes sought to recover approximately $33 million for past and future payments due under the agreement. On September 16, 2015, following a jury trial, the federal district court judge entered a judgment in the amount of $32.9 million in favor of Great Lakes.  On September 20, 2015, Essar appealed the decision to the United States Court of Appeals for the Eighth Circuit (Eighth Circuit) based on an allegation of improper jurisdiction and a number of other rulings by the federal district judge. Essar was required to post a performance bond for the full value of the judgment pending appeal.  The Eighth Circuit heard the appeal on October 20, 2016.  A decision on the appeal was received in December 2016 and the Eighth Circuit vacated Great Lakes’ judgment against Essar finding that there was no federal jurisdiction. Great Lakes filed a Request for Rehearing with the Eighth Circuit and it was denied in January 2017. Before the Circuit Court issued its decision, Essar Minnesota filed for bankruptcy in July 2016. The Foreign Essar Affiliates have not filed for bankruptcy. Following the Circuit Court’s decision, the performance bond was released into the bankruptcy court proceedings. Great Lakes filed a claim against Essar Minnesota in the bankruptcy court and its case against the Foreign Essar Affiliates in Minnesota state court remains pending. In April 2017, after Great Lakes agreement with creditors on an allowed claim, the bankruptcy court approved Great Lakes’ claim in the amount of $31.5 million.  On May 20, 2017, the federal district court awarded Essar Minnesota approximately $1.2 million for costs, including recovery of the performance bond premium, to be paid by Great Lakes. Great Lakes filed a motion with the bankruptcy court to offset the $1.2 million award of costs against its claim against Essar Minnesota in the bankruptcy proceeding.  If Great Lakes’ motion to offset the federal district court’s award of costs is against its claim in the bankruptcy proceeding is not successful, Great Lakes will be responsible to the bankruptcy estate for payment of the award. Great Lakes is unable to estimate the timing or the extent to which its claim will be recoverable in the bankruptcy proceedings.

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REGULATORY

9 Months Ended

Sep. 30, 2017

REGULATORY

REGULATORY

NOTE 16 REGULATORY

North Baja —On January 6, 2017, North Baja notified FERC that current market conditions do not support the replacement of the compression that was temporarily abandoned in 2013 and requested authorization to permanently abandon two compressor units and a nominal volume of unsubscribed firm capacity. FERC approved the permanent abandonment request on February 16, 2017. The abandonments will not have any impact on existing firm transportation service.

Great Lakes - On April 24, 2017, Great Lakes reached an agreement on the terms of a new long-term transportation capacity contract with its affiliate, TransCanada. The contract, which was subject to Canada’s National Energy Board (NEB) approval, is for a term of 10 years and allows TransCanada the ability to transport up to 0.711 billion cubic feet of natural gas per day on the Great Lakes system from the Manitoba/U.S. border to the U.S. border near Dawn Ontario. On September 21, 2017, TransCanada received approval from the NEB and as a result, this contract commenced on November 1, 2017. This contract contains volume reduction options up to full contract quantity beginning in year three.

On October 30, 2017, Great Lakes filed a rate settlement with FERC to satisfy its obligations from its 2013 rate settlement for new rates to be in effect by January 1, 2018 (2017 Great Lakes Settlement). The 2017 Great Lakes Settlement, if approved by FERC, will decrease Great Lakes’ maximum transportation rates by 27 percent beginning October 1, 2017.  Great Lakes expects that the impact from other changes, including: the recent long-term transportation contract with TransCanada as described above, other revenue opportunities on the system and the elimination of the revenue sharing mechanism with its customers, will more than offset the full year impact of the reduction in Great Lakes’ rates beginning in 2018. The 2017 Great Lakes Settlement does not contain any moratorium and Great Lakes will be required to file for new rates no later than March 31, 2022, with new rates to be effective October 1, 2022.

Northern Border- Northern Border and its shippers have been engaged in settlement discussions, and have recently agreed to a settlement-in-principle addressing all rate and service related issues raised during the settlement discussions. Northern Border plans to file a settlement agreement with FERC before the end of the year, reflecting the settlement-in-principle, precluding the need to file a general rate case as contemplated by its 2012 Settlement.  Northern Border anticipates that the Commission will accept the settlement agreement and that it will be unopposed. This will provide Northern Border with rate stability over the longer term.  At this time, we do not believe that the final outcome of the settlement will have a material impact to the Partnership’s results. Northern Border remains a key competitive pipeline and continues to operate at full capacity connecting major supply basins with communities in Midwestern U.S.

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VARIABLE INTEREST ENTITIES

9 Months Ended

Sep. 30, 2017

VARIABLE INTEREST ENTITIES

VARIABLE INTEREST ENTITIES

NOTE 17 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 variable interest entity (VIE) is a legal entity that does not have sufficient equity at risk to finance its activities without additional subordinated financial support or is structured such that equity investors lack the ability to make significant decisions relating to the entity’s operations through voting rights or do not substantively participate in the gains or losses of the entity. A VIE is appropriately consolidated if the Partnership is considered to be the primary beneficiary. The VIE’s primary beneficiary is the entity that has both (1) the power to direct the activities of the VIE that most significantly impact the VIEs economic performance and (2) the obligation to absorb losses or the right to receive benefits from the VIE that could potentially be significant to the VIE.

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

Consolidated VIEs

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

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

(unaudited)
(millions of dollars)	September 30, 2017		December 31, 2016(a)
ASSETS (LIABILITIES) *
Cash and cash equivalents	19		14
Accounts receivable and other	23		33
Inventories	6		6
Other current assets	4		6
Equity investments	1,207		918
Plant, property and equipment	1,132		1,146
Other assets	1		2
Accounts payable and accrued liabilities	(21	)	(21	)
Accounts payable to affiliates, net	(25	)	(32	)
Distributions payable	—		(3	)
Other taxes payable	(1	)	—
Accrued interest	(5	)	(2	)
Current portion of long-term debt	(51	)	(52	)
Long-term debt	(314	)	(337	)
Other liabilities	(26	)	(25	)
Deferred state income tax	(10	)	(10	)

* North Baja and Bison, which are also assets held through our consolidated VIEs, are excluded as the assets of these entities can be used for purposes other than the settlement of the VIE’s obligations.

(a) Recast to consolidate PNGTS for all periods presented (Refer to Notes 2 and 6).

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INCOME TAXES

9 Months Ended

Sep. 30, 2017

INCOME TAXES

INCOME TAXES

NOTE 18 INCOME TAXES

The Partnership’s income taxes relate to business profits tax (BPT) levied at the partnership (PNGTS) level by the state of New Hampshire. As a result of the BPT, PNGTS recognizes deferred taxes related to temporary differences between the financial statement carrying amount of existing assets and liabilities and their respective tax bases. The deferred taxes at September 30, 2017 and December 31, 2016 relate primarily to utility plant. At September 30, 2017 and December 31, 2016 the New Hampshire BPT effective tax rate was 3.8 percent for both periods and was applied to PNGTS’ taxable income.

	Three months ended September 30,			Nine months ended September 30,
(unaudited)
(millions of dollars)	2017	2016(a)		2017	2016(a)
State income taxes
Current	—	(7	)	1	1
Deferred	—	7		—	—
	—	—		1	1

(a) Recast to consolidate PNGTS for all periods presented (Refer to Note 2 and 6).

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SUBSEQUENT EVENTS

9 Months Ended

Sep. 30, 2017

SUBSEQUENT EVENTS

SUBSEQUENT EVENTS

NOTE 19 SUBSEQUENT EVENTS

Management of the Partnership has reviewed subsequent events through November 6, 2017, the date the financial statements were issued, and concluded there were no events or transactions during this period that would require recognition or disclosure in the consolidated financial statements other than what is disclosed here and/or those already disclosed in the preceding notes.

On October 24, 2017, the board of directors of the General Partner declared the Partnership’s third quarter 2017 cash distribution in the amount of $1.00 per common unit payable on November 14, 2017 to unitholders of record as of November 3, 2017. The declared distribution totaled $75 million and is payable in the following manner: $70 million to common unitholders (including $6 million to the General Partner as a holder of 5,797,106 common units and $11 million to another subsidiary of TransCanada as holder of 11,287,725 common units) and $5 million to the General Partner, which included $2 million for its effective two percent general partner interest and $3 million in respect of its IDRs.

Northern Border declared its September 2017 distribution of $14 million on October 9, 2017, of which the Partnership will receive its 50 percent share or $7 million on October 31, 2017.

Great Lakes declared its third quarter 2017 distribution of $2 million on October 19, 2017, of which the Partnership will receive its 46.45 percent share or $1 million on November 1, 2017.

Iroquois declared its third quarter 2017 distribution of $28 million on October 23, 2017, of which the Partnership received its 49.34 percent share or $14 million on November 1, 2017. The distribution includes our 49.34 percent share of the Iroquois unrestricted cash distribution amounting to approximately $2.6 million (Refer to Note 6).

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SIGNIFICANT ACCOUNTING POLICIES (Policies)

9 Months Ended

Sep. 30, 2017

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 in non-controlling interests. The Partnership uses the equity method of accounting for its investments in entities over which it is able to exercise significant influence.

Basis of Presentation - Transactions between entities under common control

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

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

On June 1, 2017, the Partnership acquired from a subsidiary of TransCanada an additional 11.81 percent interest in PNGTS, that resulted in the Partnership owning a 61.71 percent interest in PNGTS (Refer to Note 6).  As a result of the Partnership owning 61.71 percent interest in PNGTS, the Partnership’s historical financial information has been recast, except net income (loss) per common unit, to consolidate PNGTS for all the periods presented in the Partnership’s consolidated financial statements. Additionally, this acquisition was accounted for as transaction between entities under common control, similar to pooling of interests, whereby the assets and liabilities of PNGTS were recorded at TransCanada’s carrying value.

Also, on June 1, 2017, the Partnership acquired from subsidiaries of TransCanada a 49.34 percent interest in Iroquois Gas Transmission, L.P. (“Iroquois”) (Refer to Note 6). Accordingly, this transaction was accounted for as a transaction between entities under common control, similar to pooling of interest, whereby the equity investment in Iroquois was recorded at TransCanada’s carrying value and was accounted for prospectively.

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 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)

9 Months Ended

Sep. 30, 2017

EQUITY INVESTMENTS

Schedule of equity investments and summarized financial information for equity investees

	Ownership		Equity Earnings				Equity Investments
	Interest at		Three months		Nine Months
(unaudited)	September 30,		ended September 30,		ended September 30,		September 30,	December 31,
(millions of dollars)	2017		2017	2016(b)	2017	2016(b)	2017	2016(b)
Northern Border (a)	50	%	16	18	50	52	516	444
Great Lakes	46.45	%	2	4	24	23	469	474
Iroquois	49.34	%	9	—	13	—	222	—
			27	22	87	75	1,207	918

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

(b) Recast to eliminate equity earnings from PNGTS and consolidate PNGTS for all periods presented (Refer to Notes 2 and 6).

Northern Border

EQUITY INVESTMENTS

Schedule of equity investments and summarized financial information for equity investees

(unaudited)
(millions of dollars)	September 30, 2017		December 31, 2016
ASSETS
Cash and cash equivalents	24		14
Other current assets	36		36
Plant, property and equipment, net	1,069		1,089
Other assets	14		14
	1,143		1,153
LIABILITIES AND PARTNERS’ EQUITY
Current liabilities	48		38
Deferred credits and other	30		28
Long-term debt, including current maturities, net	264		430
Partners’ equity
Partners’ capital	802		659
Accumulated other comprehensive loss	(1	)	(2	)
	1,143		1,153

	Three months ended				Nine months ended
(unaudited)	September 30,				September 30,
(millions of dollars)	2017		2016		2017		2016
Transmission revenues	73		74		217		218
Operating expenses	(20	)	(18	)	(56	)	(53	)
Depreciation	(15	)	(15	)	(45	)	(44	)
Financial charges and other	(5	)	(5	)	(14	)	(16	)
Net income	33		36		102		105

Great Lakes

EQUITY INVESTMENTS

Schedule of equity investments and summarized financial information for equity investees

(unaudited)
(millions of dollars)	September 30, 2017	December 31, 2016
ASSETS
Current assets	56	66
Plant, property and equipment, net	705	714
	761	780
LIABILITIES AND PARTNERS’ EQUITY
Current liabilities	41	40
Net long-term debt, including current maturities	269	278
Partners’ equity	451	462
	761	780

	Three months ended				Nine months ended
(unaudited)	September 30,				September 30,
(millions of dollars)	2017		2016		2017		2016
Transmission revenues	34		36		138		133
Operating expenses	(19	)	(15	)	(49	)	(45	)
Depreciation	(7	)	(7	)	(21	)	(21	)
Financial charges and other	(5	)	(6	)	(16	)	(17	)
Net income	3		8		52		50

Iroquois

EQUITY INVESTMENTS

Schedule of equity investments and summarized financial information for equity investees

(unaudited)
(millions of dollars)	September 30, 2017	December 31, 2016
ASSETS
Cash and cash equivalents	93	86
Other current assets	33	34
Plant, property and equipment, net	592	604
Other assets	8	7
	726	731
LIABILITIES AND PARTNERS’ EQUITY
Current liabilities	20	18
Net long-term debt, including current maturities	332	335
Other non-current liabilities	9	6
Partners’ equity	365	372
	726	731

	Three months ended				Nine months ended
(unaudited)	September 30,				September 30,
(millions of dollars)	2017		2016		2017		2016
Transmission revenues	43		45		142		145
Operating expenses	(13	)	(13	)	(41	)	(43	)
Depreciation	(7	)	(9	)	(22	)	(28	)
Financial charges and other	(4	)	(4	)	(13	)	(12	)
Net income	19		19		66		62

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DEBT AND CREDIT FACILITIES (Tables)

9 Months Ended

Sep. 30, 2017

DEBT AND CREDIT FACILITIES

Schedule of debt and credit facilities

(unaudited) (millions of dollars)	September 30, 2017	Weighted Average Interest Rate for the Nine Months Ended September 30, 2017		December 31, 2016 (a)	Weighted Average Interest Rate for the Year Ended December 31, 2016
TC PipeLines, LP
Senior Credit Facility due 2021	255	2.34	%	160	1.72	%
2013 Term Loan Facility due October 2022	500	2.26	%	500	1.73	%
2015 Term Loan Facility due October 2020	170	2.15	%	170	1.63	%
4.65% Unsecured Senior Notes due 2021	350	4.65	%(b)	350	4.65	%(b)
4.375% Unsecured Senior Notes due 2025	350	4.375	%(b)	350	4.375	%(b)
3.90 % Unsecured Senior Notes due 2027	500	3.90	%(b)	—	—
GTN
5.29% Unsecured Senior Notes due 2020	100	5.29	%(b)	100	5.29	%(b)
5.69% Unsecured Senior Notes due 2035	150	5.69	%(b)	150	5.69	%(b)
Unsecured Term Loan Facility due 2019	55	1.95	%	65	1.43	%
PNGTS
5.90% Senior Secured Notes due December 2018	36	5.90	%(b)	53	5.90	%(b)
Tuscarora
Unsecured Term Loan due 2020	25	2.18	%	10	1.64	%
3.82% Series D Senior Notes due August 2017	—	3.82	%(b)	12	3.82	%(b)
	2,491			1,920
Less: unamortized debt issuance costs and debt discount	13			9
Less: current portion	51			52
	2,427			1,859

(a) Recast to consolidate PNGTS for all periods presented (Refer to Notes 2 and 6).

(b) Fixed interest rate

Schedule of principal repayments required on debt

(unaudited)
(millions of dollars)
2017	12
2018	45
2019	36
2020	293
2021	605
Thereafter	1,500
	2,491

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ACQUISITION (Tables)

9 Months Ended

Sep. 30, 2017

ACQUISITION

Schedule of net purchase price

(millions of dollars)
Net Purchase Price (a)	593
Less: TransCanada’s carrying value of Iroquois at June 1, 2017	223
Excess purchase price (b)	370

(a) Total purchase price of $710 million plus final working capital adjustment of $19 million and the additional consideration on Iroquois surplus cash amounting to approximately $28 million less the assumption of $164 million of proportional Iroquois debt by the Partnership.

(b) The excess purchase price of $370 million was recorded as a reduction in Partners’ Equity.

Schedule of purchase price allocation

(millions of dollars)
Current assets	25
Property, plant and equipment, net	294
Current liabilities	(4	)
Deferred state income taxes	(10	)
Long-term debt, including current portion	(41	)
	264
Non-controlling interest	(100	)
Carrying value of pre-existing Investment in PNGTS	(132	)
TransCanada’s carrying value of the acquired 11.81 percent interest at June 1, 2017	32
Excess purchase price over net assets acquired (a)	21
Total cash consideration (b)	53

(a) The excess purchase price of $21 million was recorded as a reduction in Partners’ Equity.

(b) Total purchase price of $55 million plus the final working capital adjustment of $3 million less the assumption of $5 million of proportional PNGTS debt by the Partnership.

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NET INCOME PER COMMON UNIT (Tables)

9 Months Ended

Sep. 30, 2017

NET INCOME PER COMMON UNIT

Schedule of net income per common unit

	Three months ended September 30,						Nine months ended September 30,
(unaudited)
(millions of dollars, except per common unit amounts)	2017			2016 (a)			2017			2016 (a)
Net income attributable to controlling interests (a)	54			58			186			188
Net income attributable to PNGTS’ former parent (a) (b)	—			—			(2		)	(3		)
Net income attributable to General and Limited Partners	54			58			184			185
Incentive distributions allocated to the General Partner (c)	(3		)	(2		)	(9		)	(5		)
Net income attributable to the Class B units (d)	(8		)	(11		)	(8		)	(12		)
Net income attributable to the General Partner and common units	43			45			167			168
Net income attributable to General Partner’s effective two percent interest	(1		)	(2		)	(3		)	(4		)
Net income attributable to common units	42			43			164			164
Weighted average common units outstanding (millions) — basic and diluted	69.4			66.1		(e)	68.9			65.3		(e)
Net income per common unit — basic and diluted	$	0.61		$	0.65	(f)	$	2.38		$	2.51	(f)

(a) Recast to consolidate PNGTS for all periods presented (Refer to Notes 2 and 6).

(b) Net income allocable to General and Limited Partners excludes net income attributed to PNGTS’ former parent as it was allocated    to TransCanada and was not allocable to either the general partner, common units or Class B units.

(c) Under the terms of the Partnership Agreement, for any quarterly period, the participation of the incentive distribution rights (IDRs) is limited to the available cash distributions declared. Accordingly, incentive distributions allocated to the General Partner are based on the Partnership’s available cash during the current reporting period, but declared and paid in the subsequent reporting period.

(d) During the three and nine months ended September 30, 2017, 30 percent of GTN’s total distributable cash flow was $28 million. As a result of exceeding the $20 million threshold, $8 million of net income attributable to controlling interests was allocated to the Class B units during the three and nine months ended September 30, 2017.  During the six months ended June 30, 2016, the threshold was exceeded and during the nine months ended September 30, 2016, 30 percent of GTN’s total distributable cash flow was $32 million. As a result, $12 million of net income attributable to controlling interests was allocated to the Class B units at September 30, 2016, of which $1 million and $11 million were allocated during the three months ended June 30, 2016 and September 30, 2016, respectively (Refer to Note 7).

(e) Includes the common units subject to rescission. These units are treated as outstanding for financial reporting purposes (Refer to Note 7).

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

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CHANGE IN OPERATING WORKING CAPITAL (Tables)

9 Months Ended

Sep. 30, 2017

CHANGE IN OPERATING WORKING CAPITAL

Schedule of change in operating working capital

(unaudited)	Nine months ended September 30,
(millions of dollars)	2017		2016 (a)
Change in accounts receivable and other	13		3
Change in other current assets	1		2
Change in accounts payable and accrued liabilities(b)	2		3
Change in accounts payable to affiliates	(3	)	(2	)
Change in accrued interest	11		5
Change in operating working capital	24		11

(a) Recast to consolidate PNGTS for all periods presented (Refer to Notes 2 and 6).

(b) The accrual of $10 million for the construction of GTN’s Carty Lateral in December 31, 2015 was paid during the first quarter 2016. Accordingly, the payment was reported as capital expenditures in our 2016 cash flow statement.

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RELATED PARTY TRANSACTIONS (Tables)

9 Months Ended

Sep. 30, 2017

RELATED PARTY TRANSACTIONS

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

	Three months ended September 30,		Nine months ended September 30,
(unaudited)
(millions of dollars)	2017	2016	2017	2016
Capital and operating costs charged by TransCanada’s subsidiaries to:
Great Lakes (a)	10	8	27	22
Northern Border (a)	10	9	30	25
GTN	9	8	24	20
Bison	2	1	4	1
North Baja	1	1	3	3
Tuscarora	1	1	3	3
PNGTS	2	2	6	6
Impact on the Partnership’s net income:
Great Lakes (a)	4	3	11	9
Northern Border (a)	4	3	11	9
GTN	7	7	21	18
Bison	2	1	4	2
North Baja	1	1	3	3
Tuscarora	1	1	3	3
PNGTS (b)	1	1	4	3

Summary of amount payable to related party for costs charged

(unaudited)	September 30,
(millions of dollars)	2017	December 31, 2016
Net amounts payable to TransCanada’s subsidiaries is as follows:
Great Lakes (a)	3	4
Northern Border (a)	3	4
GTN	3	3
Bison	1	1
North Baja	—	1
Tuscarora	—	1
PNGTS	1	1

(a) Represents 100 percent of the costs.

(b) Recast to consolidate PNGTS for all periods presented (Refer to Note 2).

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ACCOUNTS RECEIVABLE AND OTHER (Tables)

9 Months Ended

Sep. 30, 2017

ACCOUNTS RECEIVABLE AND OTHER

Schedule of accounts receivable and other

(unaudited)
(millions of dollars)	September 30, 2017	December 31, 2016 (a)
Trade accounts receivable, net of allowance of nil	34	44
Imbalance receivable from affiliates	—	2
Other	1	1
	35	47

(a) Recast as discussed in Notes 2 and 6.

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FINANCIAL CHARGES AND OTHER (Tables)

9 Months Ended

Sep. 30, 2017

FINANCIAL CHARGES AND OTHER

Schedule of components of financial charges and other

	Three months ended September 30,		Nine months ended September 30,
(unaudited)
(millions of dollars)	2017	2016(b)	2017		2016(b)
Interest expense (a)	23	17	59		52
PNGTS’ amortization of derivative loss on derivative instruments (Note 12) (b)	—	—	1		1
Net realized loss related to the interest rate swaps	—	1	—		2
Other income	—	—	(1	)	(2	)
	23	18	59		53

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

(b) Recast to consolidate PNGTS for all periods presented (Refer to Note 2).

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VARIABLE INTEREST ENTITIES (Tables)

9 Months Ended

Sep. 30, 2017

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)	September 30, 2017		December 31, 2016(a)
ASSETS (LIABILITIES) *
Cash and cash equivalents	19		14
Accounts receivable and other	23		33
Inventories	6		6
Other current assets	4		6
Equity investments	1,207		918
Plant, property and equipment	1,132		1,146
Other assets	1		2
Accounts payable and accrued liabilities	(21	)	(21	)
Accounts payable to affiliates, net	(25	)	(32	)
Distributions payable	—		(3	)
Other taxes payable	(1	)	—
Accrued interest	(5	)	(2	)
Current portion of long-term debt	(51	)	(52	)
Long-term debt	(314	)	(337	)
Other liabilities	(26	)	(25	)
Deferred state income tax	(10	)	(10	)

* North Baja and Bison, which are also assets held through our consolidated VIEs, are excluded as the assets of these entities can be used for purposes other than the settlement of the VIE’s obligations.

(a) Recast to consolidate PNGTS for all periods presented (Refer to Notes 2 and 6).

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INCOME TAXES (Tables)

9 Months Ended

Sep. 30, 2017

INCOME TAXES

Schedule of state income taxes of PNGTS

	Three months ended September 30,			Nine months ended September 30,
(unaudited)
(millions of dollars)	2017	2016(a)		2017	2016(a)
State income taxes
Current	—	(7	)	1	1
Deferred	—	7		—	—
	—	—		1	1

(a) Recast to consolidate PNGTS for all periods presented (Refer to Note 2 and 6).

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ORGANIZATION - Ownership Interests in Natural Gas Pipeline Systems (Details)	9 Months Ended
	Sep. 30, 2017 LimitedPartnership
ORGANIZATION
Number of intermediate limited partnerships through which pipeline assets are owned	3

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SIGNIFICANT ACCOUNTING POLICIES - Basis of Presentation (Details)	Sep. 30, 2017	Aug. 01, 2017	Jun. 01, 2017	Sep. 30, 2016
Portland Natural Gas Transmission System
ACQUISITION
Ownership interest (as a percent)	11.81%		11.81%	49.90%
Iroquois
ACQUISITION
Ownership interest (as a percent)	49.34%	49.34%	49.34%
Portland Natural Gas Transmission System
ACQUISITION
Ownership interest (as a percent)			11.81%
Interest acquired by Partnership (as a percent)			61.71%

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ACCOUNTING PRONOUNCEMENTS - Statement of Cash Flows (Details) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016
ACCOUNTING PRONOUNCEMENTS
Cumulative distributions in excess of equity earnings	$ 3
Distributions from equity investments	$ 106	$ 125	[1]
Adjustment | ASU 2016-15, Statement of Cash Flows
ACCOUNTING PRONOUNCEMENTS
Cumulative distributions in excess of equity earnings		(50)
Distributions from equity investments		$ 50

[1] Recast to consolidate PNGTS for all periods presented (Refer to Notes 2 and 6).

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EQUITY INVESTMENTS (Details) - USD ($) $ in Millions						1 Months Ended	3 Months Ended				9 Months Ended
		Sep. 01, 2017	Aug. 01, 2017	Jul. 27, 2017	Jun. 01, 2017	Apr. 30, 2006	Sep. 30, 2017	Mar. 31, 2017	Sep. 30, 2016		Sep. 30, 2017	Sep. 30, 2016		Nov. 01, 2017	Oct. 31, 2017	Dec. 31, 2016
EQUITY INVESTMENTS
Equity Earnings							$ 27.0		$ 22.0	[1]	$ 87.0	$ 75.0	[1]
Equity Investments							$ 1,207.0				1,207.0					$ 918.0	[1]
Partnership distribution	[2]										235.0
Partnership's share of distributions											106.0	125.0	[1]
Return on investment distribution classified as investing activities											3.0
Great Lakes
EQUITY INVESTMENTS
Total cash call issued to fund debt repayment											$ 9.0
Northern Border
EQUITY INVESTMENTS
Ownership interest (as a percent)		50.00%					50.00%				50.00%				50.00%
Equity Earnings							$ 16.0		18.0		$ 50.0	52.0
Equity Investments							516.0				516.0					444.0
Amortization period of transaction fee						12 years
Transaction fee						$ 10.0
Additional ownership interest acquired (as a percent)						20.00%
Equity contribution		$ 83.0									83.0
Capital contribution to reduce the outstanding balance of revolver debt		$ 166.0
Assets
Cash and cash equivalents							24.0				24.0					14.0
Other current assets							36.0				36.0					36.0
Plant, property and equipment, net							1,069.0				1,069.0					1,089.0
Other assets							14.0				14.0					14.0
Assets, total							1,143.0				1,143.0					1,153.0
LIABILITIES AND PARTNERS' EQUITY
Current liabilities							48.0				48.0					38.0
Deferred credits and other							30.0				30.0					28.0
Long-term debt, including current maturities, net							264.0				264.0					430.0
Partners' equity
Partners' equity							802.0				802.0					659.0
Accumulated other comprehensive loss							(1.0)				(1.0)					(2.0)
Liabilities and Partners' Equity, total							1,143.0				1,143.0					1,153.0
Revenues (expenses)
Transmission revenues							73.0		74.0		217.0	218.0
Operating expenses							(20.0)		(18.0)		(56.0)	(53.0)
Depreciation							(15.0)		(15.0)		(45.0)	(44.0)
Financial charges and other							(5.0)		(5.0)		(14.0)	(16.0)
Net income							$ 33.0		36.0		$ 102.0	105.0
Great Lakes
EQUITY INVESTMENTS
Ownership interest (as a percent)							46.45%				46.45%			46.45%
Equity Earnings							$ 2.0		4.0		$ 24.0	23.0
Equity Investments							469.0				469.0					474.0
Equity contribution								$ 4.0			4.0	4.0	[1]
Assets
Current assets							56.0				56.0					66.0
Plant, property and equipment, net							705.0				705.0					714.0
Assets, total							761.0				761.0					780.0
LIABILITIES AND PARTNERS' EQUITY
Current liabilities							41.0				41.0					40.0
Long-term debt, including current maturities, net							269.0				269.0					278.0
Partners' equity
Partners' equity							451.0				451.0					462.0
Liabilities and Partners' Equity, total							761.0				761.0					780.0
Revenues (expenses)
Transmission revenues							34.0		36.0		138.0	133.0
Operating expenses							(19.0)		(15.0)		(49.0)	(45.0)
Depreciation							(7.0)		(7.0)		(21.0)	(21.0)
Financial charges and other							(5.0)		(6.0)		(16.0)	(17.0)
Net income							$ 3.0		8.0		$ 52.0	50.0
Iroquois
EQUITY INVESTMENTS
Ownership interest (as a percent)			49.34%		49.34%		49.34%				49.34%
Equity Earnings							$ 9.0				$ 13.0
Equity Investments							222.0				222.0
Equity contribution					$ 710.0
Undistributed earnings							0.0				0.0
Assets
Cash and cash equivalents							93.0				93.0					86.0
Other current assets							33.0				33.0					34.0
Plant, property and equipment, net							592.0				592.0					604.0
Other assets							8.0				8.0					7.0
Assets, total							726.0				726.0					731.0
LIABILITIES AND PARTNERS' EQUITY
Current liabilities							20.0				20.0					18.0
Long-term debt, including current maturities, net							332.0				332.0					335.0
Other non-current liabilities							9.0				9.0					6.0
Partners' equity
Partners' equity							365.0				365.0					372.0
Liabilities and Partners' Equity, total							726.0				726.0					$ 731.0
Revenues (expenses)
Transmission revenues							43.0		45.0		142.0	145.0
Operating expenses							(13.0)		(13.0)		(41.0)	(43.0)
Depreciation							(7.0)		(9.0)		(22.0)	(28.0)
Financial charges and other							(4.0)		(4.0)		(13.0)	(12.0)
Net income							$ 19.0		$ 19.0		$ 66.0	$ 62.0
Iroquois | Distribution declared
EQUITY INVESTMENTS
Partnership distribution				$ 28.0
Iroquois | Cash Distribution Paid
EQUITY INVESTMENTS
Partnership's share of distributions			$ 14.0
Return on investment distribution classified as investing activities			$ 2.6

[1] Recast to consolidate PNGTS for all periods presented (Refer to Notes 2 and 6).

[2] Recast to consolidate PNGTS for all periods presented (Refer to Notes 2 and 6).

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DEBT AND CREDIT FACILITIES - Amounts Outstanding and Description of Terms (Details)			3 Months Ended	9 Months Ended	12 Months Ended
	Aug. 21, 2017 USD ($)	May 25, 2017 USD ($)	Sep. 30, 2017 USD ($)	Sep. 30, 2017 USD ($) entity	Dec. 31, 2016 USD ($)
Credit facilities, short-term loan facility and long-term debt
Debt and credit facilities			$ 2,491,000,000	$ 2,491,000,000	$ 1,920,000,000
Less: unamortized debt issuance costs and debt discount			13,000,000	13,000,000	9,000,000
Less: current portion			51,000,000	51,000,000	52,000,000	[1]
Long-term debt			$ 2,427,000,000	$ 2,427,000,000	1,859,000,000	[1]
Senior Credit Facility due in 2021 and the Term Loan Facilities due in 2020 and 2022
Credit facilities, short-term loan facility and long-term debt
Leverage ratio, actual (as a percent)			476.00%	476.00%
Senior Credit Facility due in 2021 and the Term Loan Facilities due in 2020 and 2022 | Debt agreement covenants, initial period after occurrence of acquisition
Credit facilities, short-term loan facility and long-term debt
Additional period immediately following the fiscal quarter in which a specified material acquisition occurs				6 months
Senior Credit Facility due in 2021 and the Term Loan Facilities due in 2020 and 2022 | Debt agreement covenants, initial period after occurrence of acquisition | Minimum
Credit facilities, short-term loan facility and long-term debt
Number of acquisitions | entity				1
Senior Credit Facility due in 2021 and the Term Loan Facilities due in 2020 and 2022 | Debt agreement covenants, initial period after occurrence of acquisition | Maximum
Credit facilities, short-term loan facility and long-term debt
Leverage ratio, covenant (as a percent)				550.00%
Senior Credit Facility due in 2021 and the Term Loan Facilities due in 2020 and 2022 | Debt agreement covenants, periods subsequent to initial period after occurrence of acquisition | Maximum
Credit facilities, short-term loan facility and long-term debt
Leverage ratio, covenant (as a percent)				500.00%
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			$ 255,000,000	$ 255,000,000	$ 160,000,000
Weighted Average Interest Rate (as a percent)				2.34%	1.72%
Maximum borrowing capacity			500,000,000	$ 500,000,000
Amount outstanding under credit facility			255,000,000	255,000,000	$ 160,000,000
Remaining borrowing capacity			$ 245,000,000	$ 245,000,000
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)			2.49%	2.49%	1.92%
Term loan | TC PipeLines, LP 2013 Term Loan Facility due October 2022
Credit facilities, short-term loan facility and long-term debt
Debt and credit facilities			$ 500,000,000	$ 500,000,000	$ 500,000,000
Weighted Average Interest Rate (as a percent)				2.26%	1.73%
Term loan | TC PipeLines, LP 2013 Term Loan Facility due October 2022 | LIBOR borrowings | LIBOR
Credit facilities, short-term loan facility and long-term debt
Debt interest rate, at period end (as a percent)			2.49%	2.49%	1.87%
Term loan | TC PipeLines, LP 2013 Term Loan Facility due October 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)				2.31%	2.31%
Term loan | TC PipeLines, LP 2015 Term Loan Facility due October 2020
Credit facilities, short-term loan facility and long-term debt
Debt and credit facilities			$ 170,000,000	$ 170,000,000	$ 170,000,000
Weighted Average Interest Rate (as a percent)				2.15%	1.63%
Term loan | TC PipeLines, LP 2015 Term Loan Facility due October 2020 | LIBOR
Credit facilities, short-term loan facility and long-term debt
Debt interest rate, at period end (as a percent)			2.39%	2.39%	1.77%
Unsecured debt | TC PipeLines, LP 4.65% Senior Notes due 2021
Credit facilities, short-term loan facility and long-term debt
Stated interest rate (as a percent)			4.65%	4.65%	4.65%
Debt and credit facilities			$ 350,000,000	$ 350,000,000	$ 350,000,000
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
Stated interest rate (as a percent)			4.375%	4.375%	4.375%
Debt and credit facilities			$ 350,000,000	$ 350,000,000	$ 350,000,000
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
Stated interest rate (as a percent)		3.90%	3.90%	3.90%
Debt and credit facilities			$ 500,000,000	$ 500,000,000
Weighted Average Interest Rate (as a percent)				3.90%
Amount of debt		$ 500,000,000
Net proceeds		$ 497,000,000
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%	5.29%	5.29%
Debt and credit facilities			$ 100,000,000	$ 100,000,000	$ 100,000,000
Weighted Average Interest Rate (as a percent)				5.29%	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%	5.69%	5.69%
Debt and credit facilities			$ 150,000,000	$ 150,000,000	$ 150,000,000
Weighted Average Interest Rate (as a percent)				5.69%	5.69%
Unsecured debt | GTN Term Loan Facility due 2019
Credit facilities, short-term loan facility and long-term debt
Debt and credit facilities			55,000,000	$ 55,000,000	$ 65,000,000
Weighted Average Interest Rate (as a percent)				1.95%	1.43%
Unsecured debt | Tuscarora Term Loan due 2020
Credit facilities, short-term loan facility and long-term debt
Debt and credit facilities			$ 25,000,000	$ 25,000,000	$ 10,000,000
Weighted Average Interest Rate (as a percent)				2.18%	1.64%
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)			2.36%	2.36%	1.90%
Secured debt | PNGTS 5.90% Senior Secured Notes due December 2018
Credit facilities, short-term loan facility and long-term debt
Stated interest rate (as a percent)			5.90%	5.90%	5.90%
Debt and credit facilities			$ 36,000,000	$ 36,000,000	$ 53,000,000
Weighted Average Interest Rate (as a percent)				5.90%	5.90%
Secured debt | Tuscarora 3.82% Series D Senior Notes due August 2017
Credit facilities, short-term loan facility and long-term debt
Stated interest rate (as a percent)			3.82%	3.82%	3.82%
Debt and credit facilities					$ 12,000,000
Weighted Average Interest Rate (as a percent)				3.82%	3.82%
Portland Natural Gas Transmission System | Secured debt | PNGTS 5.90% Senior Secured Notes due December 2018
Credit facilities, short-term loan facility and long-term debt
Debt Service, number of months of guarantee				6 months
Portland Natural Gas Transmission System | Secured debt | PNGTS 5.90% Senior Secured Notes due December 2018 | Debt agreement covenants, preceding twelve months
Credit facilities, short-term loan facility and long-term debt
Debt service coverage, actual (as a percent)				171.00%
Portland Natural Gas Transmission System | Secured debt | PNGTS 5.90% Senior Secured Notes due December 2018 | Debt agreement covenants, preceding twelve months | Minimum
Credit facilities, short-term loan facility and long-term debt
Debt service coverage, covenant (as a percent)				130.00%
Portland Natural Gas Transmission System | Secured debt | PNGTS 5.90% Senior Secured Notes due December 2018 | Debt agreement covenants, succeeding twelve months
Credit facilities, short-term loan facility and long-term debt
Debt service coverage, actual (as a percent)				531.00%
Portland Natural Gas Transmission System | Secured debt | PNGTS 5.90% Senior Secured Notes due December 2018 | Debt agreement covenants, succeeding twelve months | Minimum
Credit facilities, short-term loan facility and long-term debt
Debt service coverage, covenant (as a percent)				130.00%
GTN | Unsecured debt | Senior Notes and Term Loan Facility due 2019
Credit facilities, short-term loan facility and long-term debt
Debt interest rate, at period end (as a percent)			2.19%	2.19%	1.57%
Percentage of debt to total capitalization, actual			44.20%	44.20%
GTN | Unsecured debt | Senior Notes and 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%
Tuscarora Gas Transmission Company | Unsecured Term Loan Facility | Tuscarora Term Loan due 2020
Credit facilities, short-term loan facility and long-term debt
Amount of debt	$ 25,000,000
Debt service coverage, actual (as a percent)			308.00%
Tuscarora Gas Transmission Company | Unsecured Term Loan Facility | Tuscarora Term Loan due 2020 | Minimum
Credit facilities, short-term loan facility and long-term debt
Debt service coverage, covenant (as a percent)	300.00%

[1] Recast to consolidate PNGTS for all periods presented (Refer to Notes 2 and 6).

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DEBT AND CREDIT FACILITIES - Principal Payments Required (Details) $ in Millions	Sep. 30, 2017 USD ($)
Principal repayments required on debt
2017	$ 12
2018	45
2019	36
2020	293
2021	605
Thereafter	1,500
Total debt	$ 2,491

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ACQUISITION - 2017 Acquisition (Details)					9 Months Ended
	Nov. 06, 2017 USD ($)	Nov. 01, 2017 USD ($)	Aug. 01, 2017 USD ($) item	Jun. 01, 2017 USD ($)	Sep. 30, 2017 USD ($)
ACQUISITION
Return on investment distribution classified as investing activities					$ 3,000,000
Iroquois
ACQUISITION
Interest acquired (as a percent)			49.34%	49.34%	49.34%
Option to acquire (as a percent)				0.66
Amount of final purchase price adjustments				$ 19,000,000
Additional consideration on surplus cash				28,000,000
Net purchase price				710,000,000
Outstanding debt				164,000,000
Payment for option to acquire				1,000
Iroquois net purchase price
Net Purchase Price				593,000,000
Less: TransCanada's carrying value of Iroquois at June 1, 2017				223,000,000
Excess purchase price				370,000,000
Purchase price before assumption of debt				710,000,000
Reduction in partner's equity under equity method investments				$ 370,000,000
Iroquois | Cash Distribution Paid
ACQUISITION
Return on investment distribution classified as investing activities			$ 2,600,000
Iroquois | Cash Distribution Paid | Subsequent Events
ACQUISITION
Return on investment distribution classified as investing activities	$ 5,200,000	$ 2,600,000
Iroquois | Investing Activities
ACQUISITION
Return on investment distribution classified as investing activities			$ 28,000,000
Number of quarters for distribution of surplus cash | item			11
Iroquois | TransCanada
ACQUISITION
Additional consideration on surplus cash			$ 28,000,000
Portland Natural Gas Transmission System
ACQUISITION
Interest acquired (as a percent)				11.81%
Interest acquired by Partnership (as a percent)				61.71%
Amount of final purchase price adjustments				$ 3,000,000
Net purchase price				55,000,000
Outstanding debt				5,000,000
PNGTS purchase price
Current assets				25,000,000
Property, plant and equipment, net				294,000,000
Current liabilities				(4,000,000)
Deferred state income taxes				(10,000,000)
Long-term debt, including current portion				(41,000,000)
Net Purchase Price				264,000,000
Non-controlling interest				(100,000,000)
Carrying value of pre-existing Investment in PNGTS				(132,000,000)
TransCanada's carrying value of the acquired 11.81 percent interest at June 1, 2017				32,000,000
Excess purchase price over net assets acquired				21,000,000
Total cash consideration				53,000,000
Purchase price before assumption of debt				55,000,000
Final working capital adjustment				3,000,000
Reduction in partner's equity due to excess purchase price				21,000,000
Portland Natural Gas Transmission System | Iroquois
ACQUISITION
Purchase price				765,000,000
Amount of final purchase price adjustments				$ 50,000,000

XML

PARTNERS' EQUITY - ATM Equity Issuance Program (Details) - USD ($) $ in Millions		3 Months Ended		9 Months Ended
		Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
PARTNERS' EQUITY
Net proceeds from issuance of common units	[1]			$ 126
General Partner
PARTNERS' EQUITY
Net proceeds from issuance of common units				$ 2
TC PipeLines GP, Inc. | General Partner
PARTNERS' EQUITY
Ownership interest in the Partnership (as a percent)		2.00%	2.00%	2.00%	2.00%
ATM Equity Issuance Program | Common Units
PARTNERS' EQUITY
Units sold				2,165,162
Net proceeds from issuance of common units				$ 124
Sales agent commissions				1
ATM Equity Issuance Program | TC PipeLines GP, Inc. | General Partner
PARTNERS' EQUITY
Equity contribution				$ 2

[1] Recast to consolidate PNGTS for all periods presented (Refer to Notes 2 and 6).

XML

PARTNERS' EQUITY - Class B Units (Details) - Class B Units - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Mar. 31, 2017	Sep. 30, 2017	Sep. 30, 2016
PARTNERS' EQUITY
Limited Partners, Distributions paid		$ 22	$ 22	$ 12	[1]
GTN
PARTNERS' EQUITY
Increase in equity account			8
GTN
PARTNERS' EQUITY
30% of GTN's distributable cash flow			$ 28
GTN | TransCanada | Distributions
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%		30.00%	30.00%
Percentage applied to 30 percent of GTN's distributions above threshold through March 31, 2020			100.00%
Threshold of GTN's total distributable cash flows for payment to Class B units			$ 20
Percentage applied to GTN's distributions above threshold after March 31, 2020			25.00%
Percentage applied to GTN's distributable cash flow for the twelve month period ending December 31, 2017			30.00%
30% of GTN's distributable cash flow	$ 28		$ 28	$ 32

[1] Recast to consolidate PNGTS for all periods presented (Refer to Notes 2 and 6).

XML

PARTNERS' EQUITY - Reclassification of units (Details) - USD ($) shares in Millions, $ in Millions		2 Months Ended	4 Months Ended	9 Months Ended
		May 19, 2016	Sep. 30, 2017	Sep. 30, 2017		Dec. 31, 2016
PARTNERS' EQUITY
Common units subject to rescission	[1]					$ 83
Reclassification of common units no longer subject to rescission			$ 83	$ 83	[2]
ATM Equity Issuance Program | Common Units
PARTNERS' EQUITY
Reclassification of common unit issuance subject to rescission, net (in units)		1.6
Common units subject to rescission			$ 0	$ 0		$ 83

[1] Recast to consolidate PNGTS for all periods presented (Refer to Notes 2 and 6).

[2] Recast to consolidate PNGTS for all periods presented (Refer to Notes 2 and 6).

XML

NET INCOME PER COMMON UNIT - General Partner Effective Interest and Allocated Incentive Distributions (Details)	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
TC PipeLines GP, Inc. | General Partner
PARTNERS' EQUITY
General partner interest (as a percent)	2.00%	2.00%	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				9 Months Ended			12 Months Ended
	Sep. 30, 2017	Sep. 30, 2016		Jun. 30, 2016	Sep. 30, 2017	Sep. 30, 2016		Dec. 31, 2016
Net income (loss) per common unit
Net income attributable to controlling interests	$ 54	$ 58	[1]		$ 186	$ 188	[1]
Net income attributable to PNGTS' former parent					(2)	(3)
Net income attributable to General and Limited Partners	54	58			184	185
Incentive distributions allocated to the General Partner	(3)	(2)			(9)	(5)
Net income attributable to the General Partner and common units	43	45			167	168
Net income attributable to General Partner's effective two percent interest	(1)	(2)			(3)	(4)
Class B Units
Net income (loss) per common unit
Net income attributable to limited partners	(8)	(11)			(8)	(12)
Common Units
Net income (loss) per common unit
Net income attributable to limited partners	$ 42	$ 43	[1]		$ 164	$ 164	[1]
Weighted average common units outstanding - basic (in units)	69.4	66.1	[1]		68.9	65.3	[1]
Weighted average common units outstanding - diluted (in units)	69.4	66.1			68.9	65.3
Net income per common unit - basic (in dollars per unit)	$ 0.61	$ 0.65	[1],[2]		$ 2.38	$ 2.51	[1],[2]
Net income per common unit - diluted (in dollars per unit)	$ 0.61	$ 0.65			$ 2.38	$ 2.51
GTN | Class B Units
Distributions
30% of GTN's distributable cash flow					$ 28
GTN | Class B Units | TransCanada | Distributions
Net income (loss) per common unit
Net income attributable to controlling interests	$ 8	$ 11		$ 1	$ 8	$ 12
Distributions
Percentage applied to GTN's distributable cash flow for the twelve month period ending December 31, 2017					30.00%
Threshold of GTN's distributions for payment to Class B units					$ 20			$ 20
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%				30.00%	30.00%
30% of GTN's distributable cash flow	$ 28				$ 28	$ 32

[1] Recast to consolidate PNGTS for all periods presented (Refer to Notes 2 and 6).

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

XML

CASH DISTRIBUTIONS - Distributions Paid (Details) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Common Units
Distributions
Per Unit Distribution, paid (in dollars per unit)	$ 1.00	$ 0.94	$ 2.88	$ 2.72
Total cash distribution	$ 74	$ 65	$ 210	$ 184
Common units and General Partner interest combined
Distributions
Total distribution of general partner interest and IDR payment	5		11
TC PipeLines GP, Inc. | General Partner
Distributions
Total distribution for General Partner interest	$ 2	$ 1	$ 4	$ 3
General partner interest (as a percent)	2.00%	2.00%	2.00%	2.00%
TC PipeLines GP, Inc. | Common units and General Partner interest combined
Distributions
Incentive distribution paid to the General Partner	$ 3	$ 2	$ 7	$ 4

XML

CHANGE IN OPERATING WORKING CAPITAL - Components (Details) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016
CHANGE IN OPERATING WORKING CAPITAL
Change in accounts receivable and other	$ 13	$ 3
Change in other current assets	1	2
Change in accounts payable and accrued liabilities	2	3
Change in accounts payable to affiliates	(3)	(2)
Change in accrued interest	11	5
Change in operating working capital	$ 24	$ 11	[1]

[1] Recast to consolidate PNGTS for all periods presented (Refer to Notes 2 and 6).

XML

CHANGE IN OPERATING WORKING CAPITAL - GTN's Carty Lateral Construction Accrual (Details) - USD ($) $ in Millions	9 Months Ended			12 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	[1]	Dec. 31, 2016	Dec. 31, 2015
Non-cash items
Capital expenditures	$ 26	$ 21
GTN
Non-cash items
Accruals for capital expenditures					$ 10
Capital expenditures				$ 10

[1] Recast to consolidate PNGTS for all periods presented (Refer to Notes 2 and 6).

XML

RELATED PARTY TRANSACTIONS (Details) - USD ($) $ in Millions	3 Months Ended				6 Months Ended		9 Months Ended		12 Months Ended
	Sep. 30, 2017	Jun. 30, 2017	Sep. 30, 2016	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016	Sep. 30, 2017	Sep. 30, 2016	Dec. 31, 2016		Nov. 01, 2017	Oct. 31, 2017	Sep. 01, 2017	Aug. 01, 2017	Jun. 01, 2017
Capital and operating costs charged to the pipeline systems and amount payable
Net amounts payable	$ 5.0						$ 5.0		$ 8.0	[1]
Amount included in receivables from related party									2.0
Great Lakes
Capital and operating costs charged to the pipeline systems and amount payable
Interest acquired (as a percent)	46.45%						46.45%				46.45%
Great Lakes | FERC
Capital and operating costs charged to the pipeline systems and amount payable
Estimated revenue sharing provision	$ 12.0						$ 22.0		7.2
Northern Border
Capital and operating costs charged to the pipeline systems and amount payable
Interest acquired (as a percent)	50.00%						50.00%					50.00%	50.00%
Iroquois
Capital and operating costs charged to the pipeline systems and amount payable
Interest acquired (as a percent)	49.34%						49.34%							49.34%	49.34%
Portland Natural Gas Transmission System
Capital and operating costs charged to the pipeline systems and amount payable
Interest acquired (as a percent)	11.81%		49.90%				11.81%	49.90%							11.81%
General Partner | Reimbursement of costs of services provided
Capital and operating costs charged to the pipeline systems and amount payable
Costs charged	$ 1.0		$ 1.0				$ 3.0	$ 3.0
TransCanada's subsidiaries | Great Lakes
Capital and operating costs charged to the pipeline systems and amount payable
Net amounts payable	3.0						3.0		4.0
Percentage of capital and operating costs charged		100.00%		100.00%	100.00%	100.00%
Amount included in receivables from related party	8.0						8.0		19.0
TransCanada's subsidiaries | Great Lakes | Capital and operating costs
Capital and operating costs charged to the pipeline systems and amount payable
Costs charged	$ 10.0		$ 8.0				$ 27.0	$ 22.0
Percentage of capital and operating costs charged	100.00%		100.00%				100.00%	100.00%
TransCanada's subsidiaries | Northern Border
Capital and operating costs charged to the pipeline systems and amount payable
Net amounts payable	$ 3.0						$ 3.0		4.0
Percentage of capital and operating costs charged		100.00%		100.00%	100.00%	100.00%
TransCanada's subsidiaries | Northern Border | Capital and operating costs
Capital and operating costs charged to the pipeline systems and amount payable
Costs charged	10.0		$ 9.0				30.0	$ 25.0
Percentage of capital and operating costs charged		100.00%		100.00%	100.00%	100.00%
TransCanada's subsidiaries | Iroquois
Capital and operating costs charged to the pipeline systems and amount payable
Percentage of capital and operating costs charged		100.00%			100.00%
TransCanada's subsidiaries | Iroquois | Capital and operating costs
Capital and operating costs charged to the pipeline systems and amount payable
Percentage of capital and operating costs charged		100.00%			100.00%
TransCanada's subsidiaries | GTN
Capital and operating costs charged to the pipeline systems and amount payable
Net amounts payable	3.0						3.0		3.0
TransCanada's subsidiaries | GTN | Capital and operating costs
Capital and operating costs charged to the pipeline systems and amount payable
Costs charged	9.0		8.0				24.0	20.0
Impact on the Partnership's net income attributable to controlling interests	7.0		7.0				21.0	18.0
TransCanada's subsidiaries | Bison
Capital and operating costs charged to the pipeline systems and amount payable
Net amounts payable	1.0						1.0		1.0
TransCanada's subsidiaries | Bison | Capital and operating costs
Capital and operating costs charged to the pipeline systems and amount payable
Costs charged	2.0		1.0				4.0	1.0
Impact on the Partnership's net income attributable to controlling interests	2.0		1.0				4.0	2.0
TransCanada's subsidiaries | North Baja Pipeline, LLC
Capital and operating costs charged to the pipeline systems and amount payable
Net amounts payable									1.0
TransCanada's subsidiaries | North Baja Pipeline, LLC | Capital and operating costs
Capital and operating costs charged to the pipeline systems and amount payable
Costs charged	1.0		1.0				3.0	3.0
Impact on the Partnership's net income attributable to controlling interests	1.0		1.0				3.0	3.0
TransCanada's subsidiaries | Tuscarora Gas Transmission Company
Capital and operating costs charged to the pipeline systems and amount payable
Net amounts payable									1.0
TransCanada's subsidiaries | Tuscarora Gas Transmission Company | Capital and operating costs
Capital and operating costs charged to the pipeline systems and amount payable
Costs charged	1.0		1.0				3.0	3.0
Impact on the Partnership's net income attributable to controlling interests	1.0		1.0				3.0	3.0
TransCanada's subsidiaries | Portland Natural Gas Transmission System
Capital and operating costs charged to the pipeline systems and amount payable
Net amounts payable	1.0						1.0		1.0
Amount included in receivables from related party	0.0						0.0		$ 0.0
TransCanada's subsidiaries | Portland Natural Gas Transmission System | Capital and operating costs
Capital and operating costs charged to the pipeline systems and amount payable
Costs charged	2.0		2.0				6.0	6.0
TransCanada's subsidiaries | Great Lakes | Capital and operating costs
Capital and operating costs charged to the pipeline systems and amount payable
Impact on the Partnership's net income attributable to controlling interests	$ 4.0		$ 3.0				$ 11.0	$ 9.0
TransCanada's subsidiaries | 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	44.00%		62.00%				53.00%	69.00%
TransCanada's subsidiaries | Northern Border | Capital and operating costs
Capital and operating costs charged to the pipeline systems and amount payable
Impact on the Partnership's net income attributable to controlling interests	$ 4.0		$ 3.0				$ 11.0	$ 9.0
TransCanada's subsidiaries | Portland Natural Gas Transmission System | Capital and operating costs
Capital and operating costs charged to the pipeline systems and amount payable
Impact on the Partnership's net income attributable to controlling interests	1.0		1.0				4.0	3.0
TransCanada's subsidiaries | Portland Natural Gas Transmission System | Transportation contracts
Capital and operating costs charged to the pipeline systems and amount payable
Revenues from related party	$ 0.0		$ 1.0				$ 1.0	$ 2.0

[1] Recast to consolidate PNGTS for all periods presented (Refer to Notes 2 and 6).

XML

FAIR VALUE MEASUREMENTS - Estimated Fair Value of Debt (Details) - USD ($) $ in Millions	Sep. 30, 2017	Dec. 31, 2016
Fair Value | Level 2
Financial Instruments
Fair value of debt	$ 2,555	$ 1,962

XML

FAIR VALUE MEASUREMENTS - Interest Rate Swaps (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016		Dec. 31, 2017	Dec. 31, 2016
Interest rate derivatives
Fair value of derivative asset, net							$ 0.0
Amortization of realized gain (loss) on derivative financial instruments			$ 1.0	$ 1.0	[1]
Debt and credit facilities	$ 2,491.0		2,491.0				1,920.0
Amortization of derivatives loss			1.0	1.0
Term loan | TC PipeLines, LP 2013 Term Loan Facility due July 2018
Interest rate derivatives
Debt and credit facilities	500.0		500.0
Term loan | TC PipeLines, LP 2013 Term Loan Facility due October 2022
Interest rate derivatives
Debt and credit facilities	$ 500.0		500.0				500.0
Amount of forward starting swaps hedged						$ 500.0
Average rate of forward starting swaps						3.26%
Portland Natural Gas Transmission System
Interest rate derivatives
Payments for derivative instruments			$ 20.9
Interest acquired by Partnership (as a percent)	61.71%		61.71%
Net unamortized loss included in other comprehensive income	$ 1.0		$ 1.0				2.0
Amortization of derivatives loss	$ 0.0	$ 0.0	$ 1.0	1.0
Interest rate swaps | Term loan | TC PipeLines, LP 2013 Term Loan Facility due July 2018
Interest rate derivatives
Weighted average fixed interest rate (as a percent)	2.31%		2.31%
Hedges of cash flows | Interest rate swaps
Interest rate derivatives
Amortization of realized gain (loss) on derivative financial instruments	$ 0.0	2.0	$ 1.0	(1.0)
Hedges of cash flows | Interest rate swaps | Financial charges and other
Interest rate derivatives
Net realized loss related to the interest rate swaps	0.0	$ 1.0	0.0	$ 2.0
Hedges of cash flows | Interest rate swaps | Recurring fair value measurement | Level 2
Interest rate derivatives
Fair value of derivative asset, net	2.0		2.0
Designated as hedge | Interest rate swaps | Recurring fair value measurement | Level 2
Interest rate derivatives
Fair value of derivative asset, gross	$ 2.0		$ 2.0
Fair value of derivative liability, gross							0.0
Designated as hedge | Hedges of cash flows | Interest rate swaps | Level 2
Interest rate derivatives
Fair value of derivative asset, gross							1.0
Fair value of derivative liability, gross							$ 1.0

[1] Recast to consolidate PNGTS for all periods presented (Refer to Notes 2 and 6).

XML

ACCOUNTS RECEIVABLE AND OTHER (Details) - USD ($) $ in Millions	Sep. 30, 2017	Dec. 31, 2016
ACCOUNTS RECEIVABLE AND OTHER
Trade accounts receivable, net of allowance of nil	$ 34	$ 44
Imbalance receivable from affiliates		2
Other	1	1
Accounts receivable and other	35	47	[1]
Trade accounts receivable, allowance	$ 0	$ 0

[1] Recast to consolidate PNGTS for all periods presented (Refer to Notes 2 and 6).

XML

FINANCIAL CHARGES AND OTHER (Details) - USD ($) $ in Millions	3 Months Ended			9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016		Sep. 30, 2017	Sep. 30, 2016
FINANCIAL CHARGES AND OTHER
Interest Expense	$ 23	$ 17		$ 59	$ 52
PNGTS' amortization of derivative loss on derivative instruments				1	1
Net realized loss related to the interest rate swaps		1			2
Other Income				(1)	(2)
Financial charges and other	$ 23	$ 18	[1]	$ 59	$ 53	[1]

[1] Recast to consolidate PNGTS for all periods presented (Refer to Notes 2 and 6).

XML

CONTINGENCIES (Details) - Great Lakes v. Essar Steel Minnesota LLC, et al. - Great Lakes - USD ($) $ in Millions				1 Months Ended
	May 20, 2017	Sep. 16, 2015	Oct. 29, 2009	Apr. 30, 2017
Contingencies
Judgement awarded				$ 31.5
Essar
Contingencies
Recovery sought			$ 33.0
Judgement awarded	$ 1.2	$ 32.9
Litigation settlement, offset against bankruptcy proceedings	$ 1.2

XML

REGULATORY (Details)	Oct. 24, 2017 Bcf	Apr. 24, 2017	Jan. 06, 2017 item	Oct. 31, 2017
Great Lakes Settlement | FERC
Regulatory Matters
Settlement rate reduced (as a percent)				27.00%
Great Lakes Settlement | NEB | Maximum
Regulatory Matters
Transportation capacity per day | Bcf	0.711
Great Lakes Contracting | NEB
Regulatory Matters
Term of contract		10 years
Termination options beginning		3 years
North Baja Pipeline, LLC | FERC
Regulatory Matters
Number of compression units | item			2

XML

VARIABLE INTEREST ENTITIES - Consolidated VIEs (Details) - USD ($) $ in Millions		9 Months Ended
		Sep. 30, 2017	Dec. 31, 2016		Sep. 30, 2016	[1]	Dec. 31, 2015	[1]
ASSETS (LIABILITIES)
Cash and cash equivalents		$ 73	$ 64	[1]	$ 77		$ 55
Accounts receivable and other		35	47	[1]
Inventories		7	7	[1]
Other current assets		6	7	[1]
Equity investments		1,207	918	[1]
Plant, property and equipment		2,133	2,180	[1]
Other assets	[1]		1
Accounts payable and accrued liabilities		(31)	(29)	[1]
Accounts payable to affiliates, net		(5)	(8)	[1]
Distributions payable	[1]		(3)
Accrued interest		(21)	(10)	[1]
Current portion of long-term debt		(51)	(52)	[1]
Long-term debt		(2,427)	(1,859)	[1]
Other liabilities		(28)	(28)	[1]
Consolidated VIEs | Restricted VIEs
ASSETS (LIABILITIES)
Cash and cash equivalents		19	14
Accounts receivable and other		23	33
Inventories		6	6
Other current assets		4	6
Equity investments		1,207	918
Plant, property and equipment		1,132	1,146
Other assets		1	2
Accounts payable and accrued liabilities		(21)	(21)
Accounts payable to affiliates, net		(25)	(32)
Distributions payable			(3)
Other taxes payable		(1)
Accrued interest		(5)	(2)
Current portion of long-term debt		(51)	(52)
Long-term debt		(314)	(337)
Other liabilities		(26)	(25)
Deferred state income tax		$ (10)	$ (10)

[1] Recast to consolidate PNGTS for all periods presented (Refer to Notes 2 and 6).

XML

INCOME TAXES (Details) - USD ($) $ in Millions	3 Months Ended	9 Months Ended			12 Months Ended
	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016		Dec. 31, 2016
State income taxes
Total state income taxes		$ 1	$ 1	[1]
Portland Natural Gas Transmission System
Income Taxes
Effective income tax rate (as a percent)		3.80%			3.80%
State income taxes
Current	$ (7)	$ 1	1
Deferred	$ 7
Total state income taxes		$ 1	$ 1

[1] Recast to consolidate PNGTS for all periods presented (Refer to Notes 2 and 6).

XML

SUBSEQUENT EVENTS - Distributions (Details) - USD ($) $ / shares in Units, $ in Millions								3 Months Ended			9 Months Ended
		Nov. 30, 2017	Nov. 01, 2017	Oct. 31, 2017	Oct. 24, 2017	Oct. 23, 2017	Oct. 19, 2017	Sep. 30, 2017	Sep. 30, 2016		Sep. 30, 2017	Sep. 30, 2016		Sep. 01, 2017	Jun. 01, 2017
Distributions
Partnership distribution	[1]										$ 235.0
Partnership's share of distributions											106.0	$ 125.0	[2]
Return on investment distribution classified as investing activities											$ 3.0
Northern Border
Distributions
Ownership interest (as a percent)				50.00%				50.00%			50.00%			50.00%
Great Lakes
Distributions
Ownership interest (as a percent)			46.45%					46.45%			46.45%
Portland Natural Gas Transmission System
Distributions
Ownership interest (as a percent)								11.81%	49.90%		11.81%	49.90%			11.81%
Iroquois
Distributions
Ownership interest (as a percent)			49.34%
Portland Natural Gas Transmission System
Distributions
Ownership interest (as a percent)															11.81%
Subsequent Events
Distributions
Total cash distribution		$ 75.0
Subsequent Events | Distribution declared | Northern Border
Distributions
Partnership distribution				$ 14.0
Subsequent Events | Distribution declared | Great Lakes
Distributions
Partnership distribution							$ 2.0
Subsequent Events | Distribution declared | Iroquois
Distributions
Partnership distribution						$ 28.0
Subsequent Events | Cash Distribution Paid | Northern Border
Distributions
Partnership's share of distributions				$ 7.0
Subsequent Events | Cash Distribution Paid | Great Lakes
Distributions
Partnership's share of distributions			$ 1.0
Subsequent Events | Cash Distribution Paid | Iroquois
Distributions
Partnership's share of distributions			14.0
Return on investment distribution classified as investing activities			$ 2.6
General Partner
Distributions
Partnership distribution	[1]										$ 12.0
TC PipeLines GP, Inc. | Subsequent Events
Distributions
General Partner cash distributions					$ 5.0
Ownership interest (as a percent)					2.00%
Total distribution for General Partner interest					$ 2.0
TC PipeLines GP, Inc. | General Partner
Distributions
Total distribution for General Partner interest								$ 2.0	$ 1.0		4.0	$ 3.0
TC PipeLines GP, Inc. | General Partner | Subsequent Events | Distribution declared
Distributions
Distribution declared for IDRs					$ 3.0
Common Units
Distributions
Total cash distribution								$ 74.0	$ 65.0		$ 210.0	$ 184.0
Number of units								69,600,000	66,600,000	[2]	69,600,000	66,600,000	[2]
Common Units | Subsequent Events
Distributions
Per Unit Distribution, declared (in dollars per unit)					$ 1.00
Limited partners, Distribution declared					$ 70.0
Common Units | Limited Partners
Distributions
Partnership distribution	[1]										$ 198.0
Common Units | TC PipeLines GP, Inc. | Subsequent Events
Distributions
Limited Partners, Distributions paid		6.0
Common Units | TC PipeLines GP, Inc. | Limited Partners
Distributions
Number of units					5,797,106
Common Units | TransCanada | Subsequent Events
Distributions
Limited Partners, Distributions paid		$ 11.0
Common Units | TransCanada | TC PipeLines GP, Inc.
Distributions
Number of units					11,287,725

[1] Recast to consolidate PNGTS for all periods presented (Refer to Notes 2 and 6).

[2] Recast to consolidate PNGTS for all periods presented (Refer to Notes 2 and 6).