10-Q

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

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

For the quarterly period ended March 31, 2017

or

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

For the transition period from           to          

Commission File Number:  001-35358

TC PipeLines, LP

(Exact name of registrant as specified in its charter)

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

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

877-290-2772

(Registrant’s telephone number, including area code)

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

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

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

Large accelerated filer x	Accelerated filer o
Non-accelerated filer o	Smaller reporting company o
(Do not check if a smaller reporting company)
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 May 2, 2017, there were 68,938,577 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	23
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	30
Item 4.	Controls and Procedures	32
PART II	OTHER INFORMATION
Item 1.	Legal Proceedings	33
Item 1A.	Risks	33
Item 6.	Exhibits	34
	Signatures	35

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 dated July 1, 2013
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 dated September 30, 2015
ASC	Accounting Standards Codification
ASU	Accounting Standards Update
ATM program	At-the-market equity issuance program
Bison	Bison Pipeline LLC
Carty Lateral	GTN lateral pipeline in north-central Oregon that delivers natural gas to a power plant owned by Portland General Electric Company
Consolidated Subsidiaries	GTN, Bison, North Baja and Tuscarora
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
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, and PNGTS
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
PNGTS Acquisition	Partnership’s acquisition of a 49.9 percent interest in PNGTS, effective January 1, 2016
SEC	Securities and Exchange Commission
Senior Credit Facility	TC PipeLines, LP’s senior facility under revolving credit agreement as amended and restated, dated November 10, 2016
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) and Portland Natural Gas Transmission System (PNGTS).

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PART I

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

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

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

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

·demand for natural gas;

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

·natural gas prices and regional differences;

·weather conditions;

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

·competition from other pipeline systems;

·natural gas storage levels; and

·rates and terms of service;

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

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

·changes in the taxation of master limited 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, structure and closure of further potential acquisitions;

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

·the ability to maintain secure operation of our information technology;

·the impact of any impairment charges;

·changes in the political environment;

·cybersecurity threats, acts of terrorism and related disruptions;

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

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

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

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

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greater detail in Part I, Item 1A. “Risk Factors” in our Form 10-K for the year ended December 31, 2016. All forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by these factors. All forward-looking statements are made only as of the date made and except as required by applicable law, we undertake no obligation to update any forward-looking statements to reflect new information, subsequent events or other changes.

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PART I — FINANCIAL INFORMATION

Item 1.   Financial Statements

TC PIPELINES, LP

CONSOLIDATED STATEMENTS OF INCOME

	Three months ended
(unaudited)	March 31,
(millions of dollars, except per common unit amounts)	2017			2016
Transmission revenues	89			86
Equity earnings (Note 4)	43			42
Operation and maintenance expenses	(12		)	(10		)
Property taxes	(5		)	(5		)
General and administrative	(2		)	(2		)
Depreciation	(22		)	(21		)
Financial charges and other (Note 13)	(16		)	(17		)
Net income	75			73
Net income attributable to controlling interests	75			73
Net income attributable to controlling interest allocation
Common units	72			71
General Partner	3			2
	75			73
Net income per common unit (Note 7) — basic and diluted	$	1.05		$	1.10
Weighted average common units outstanding — basic and diluted (millions)	68.3			64.4
Common units outstanding, end of period (millions)	68.6			64.7

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

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TC PIPELINES, LP

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

	Three months ended
(unaudited)	March 31,
(millions of dollars)	2017	2016
Net income	75	73
Other comprehensive income
Change in fair value of cash flow hedges (Note 11)	1	(2	)
Reclassification to net income of gains and losses on cash flow hedges (Note 11)	—	—
Comprehensive income	76	71

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

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TC PIPELINES, LP

CONSOLIDATED BALANCE SHEETS

(unaudited)
(millions of dollars)	March 31, 2017	December 31, 2016
ASSETS
Current Assets
Cash and cash equivalents	60	50
Accounts receivable and other (Note 12)	34	37
Distribution receivable from affiliate (Note 10)	2	3
Inventories	7	7
Other	4	5
	107	102
Equity investments (Note 4)	1,062	1,044
Plant, property and equipment (Net of $914 accumulated depreciation; 2016 - $892)	1,866	1,881
Goodwill	130	130
Other assets	1	1
	3,166	3,158
LIABILITIES AND PARTNERS’ EQUITY
Current Liabilities
Accounts payable and accrued liabilities	24	27
Accounts payable to affiliates (Note 10)	6	7
Accrued interest	13	9
Current portion of long-term debt (Note 5)	23	23
	66	66
Long-term debt, net (Note 5)	1,786	1,835
Other liabilities	28	28
	1,880	1,929
Common units subject to rescission (Note 6)	64	83
Partners’ Equity
Common units	1,098	1,002
Class B units (Note 6)	95	117
General partner	28	27
Accumulated other comprehensive loss	1	—
Controlling interests	1,222	1,146
	3,166	3,158

Variable Interest Entities (Note 16)

Subsequent Events (Note 17)

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

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TC PIPELINES, LP

CONSOLIDATED STATEMENT OF CASH FLOWS

	Three months ended
(unaudited)	March 31,
(millions of dollars)	2017		2016
Cash Generated From Operations
Net income	75		73
Depreciation	22		21
Amortization of debt issue costs reported as interest expense	—		1
Equity earnings from equity investments (Notes 3 and 4)	(43	)	(42	)
Distributions received from operating activities of equity investments (Note 3)	31		41
Change in operating working capital (Note 9)	5		6
	90		100
Investing Activities
Investment in Great Lakes (Note 4)	(4	)	(4	)
Acquisition of PNGTS	—		(193	)
Capital expenditures	(7	)	(11	)
	(11	)	(208	)
Financing Activities
Distributions paid (Note 8)	(68	)	(60	)
Distributions paid to Class B units (Note 6)	(22	)	(12	)
Common unit issuance, net (Note 6)	71		—
Common unit issuance subject to rescission, net (Note 6)	—		19
Long-term debt issued, net of discount (Note 5)	—		195
Long-term debt repaid (Note 5)	(50	)	(25	)
	(69	)	117
Increase/(decrease) in cash and cash equivalents	10		9
Cash and cash equivalents, beginning of period	50		39
Cash and cash equivalents, end of period	60		48

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						General		Accumulated Other Comprehensive	Total
	Common Units			Class B Units			Partner		Income (a)	Equity
(unaudited)	(millions of units)	(millions of dollars)		(millions of units)	(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		—	1,146
Net income	—	72		—	—		3		—	75
Other Comprehensive Loss	—	—		—	—		—		1	1
ATM Equity Issuance, net (Note 6)	1.2	69		—	—		2		—	71
Reclassification of common units no longer subject to rescission (Note 6)	—	19		—	—		—		—	19
Distributions	—	(64	)	—	(22	)	(4	)	—	(90	)
Partners’ Equity at March 31, 2017	68.6	1,098		1.9	95		28		1	1,222

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

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

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TC PIPELINES, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1        ORGANIZATION

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

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

NOTE 2        SIGNIFICANT ACCOUNTING POLICIES

The accompanying financial statements and related notes have been prepared in accordance with United States generally accepted accounting principles (GAAP) and amounts are stated in U.S. dollars. The results of operations for the three months ended March 31, 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 financial statements and notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2016. That report contains a more comprehensive summary of the Partnership’s significant accounting policies. In the opinion of management, the accompanying financial statements contain all of the appropriate adjustments, all of which are normally recurring adjustments unless otherwise noted, and considered necessary to present fairly the financial position of the Partnership, the results of operations and cash flows for the respective periods. Our significant accounting policies are consistent with those disclosed in our Annual Report on Form 10-K for the year ended December 31, 2016, except as described in Note 3, Accounting Pronouncements.

Use of Estimates

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

NOTE 3        ACCOUNTING PRONOUNCEMENTS

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

In August 2016, the 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 $8 million for the three months ended March 31, 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, and was applied prospectively and did not have a material impact on the Partnership’s consolidated balance sheet.

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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 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 five-step 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 is evaluating both methods of adoption as it works through its analysis.

The Partnership has identified all existing customer contracts that are within the scope of the new guidance and is in the process of analyzing individual contracts or groups of contracts on a segmented basis to identify any significant changes in how revenues are recognized as a result of implementing the new standard. As the Partnership continues its contract analysis, it will also quantify the impact, if any, on prior period revenues. The Partnership will address any system and process changes necessary to compile the information to meet the recognition and disclosure requirements of the new standard. As the Partnership is currently evaluating the impact of this standard, it has not yet determined the effect on its consolidated financial statements.

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 requires lessees to recognize most leases, including operating leases, on the balance sheet as lease assets and lease liabilities. The new standard does not make extensive changes to lessor accounting. Lessees may also be required to reassess assumptions associated with existing leases as well as to provide expanded qualitative and quantitative disclosures. The new guidance is effective January 1, 2019. The Partnership is currently identifying existing lease agreements that may have an impact on the Company’s consolidated financial statements as a result of adopting this 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.

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NOTE 4        EQUITY INVESTMENTS

Northern Border, Great Lakes and PNGTS are regulated by FERC and are operated by TransCanada. The Partnership uses the equity method of accounting for its interests in its equity investees. The Partnership’s equity investments are held through our ILPs that are considered to be variable interest entities (VIEs) (refer to Note 16).

	Ownership		Equity Earnings		Equity Investments
	Interest at		Three months
(unaudited)	March 31,		ended March 31,		March 31,	December 31,
(millions of dollars)	2017		2017	2016	2017	2016
Northern Border(a)	50	%	19	18	441	444
Great Lakes	46.45	%	17	15	489	474
PNGTS (b)	49.9	%	7	9	132	126
			43	42	1,062	1,044

(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 additional 20 percent interest acquisition in April 2006.

(b)For the three months ending March 31, 2017 and 2016, the Partnership recorded no undistributed earnings from PNGTS.

Northern Border

The Partnership did not have undistributed earnings from Northern Border for the three months ended March 31, 2017 and 2016.

The summarized financial information for Northern Border is as follows:

(unaudited)
(millions of dollars)	March 31, 2017		December 31, 2016
ASSETS
Cash and cash equivalents	18		14
Other current assets	36		36
Plant, property and equipment, net	1,085		1,089
Other assets	15		14
	1,154		1,153
LIABILITIES AND PARTNERS’ EQUITY
Current liabilities	44		38
Deferred credits and other	29		28
Long-term debt, including current maturities, net	430		430
Partners’ equity
Partners’ capital	653		659
Accumulated other comprehensive loss	(2	)	(2	)
	1,154		1,153

	Three months ended
(unaudited)	March 31,
(millions of dollars)	2017		2016
Transmission revenues	74		74
Operating expenses	(17	)	(16	)
Depreciation	(15	)	(15	)
Financial charges and other	(4	)	(6	)
Net income	38		37

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 months ended March 31, 2017 and 2016.

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The summarized financial information for Great Lakes is as follows:

(unaudited)
(millions of dollars)	March 31, 2017	December 31, 2016
ASSETS
Current assets	86	66
Plant, property and equipment, net	708	714
	794	780
LIABILITIES AND PARTNERS’ EQUITY
Current liabilities	31	40
Long-term debt, including current maturities, net	269	278
Partners’ equity	494	462
	794	780

	Three months ended
(unaudited)	March 31,
(millions of dollars)	2017		2016
Transmission revenues	63		61
Operating expenses	(14	)	(15	)
Depreciation	(7	)	(7	)
Financial charges and other	(5	)	(6	)
Net income	37		33

NOTE 5        DEBT AND CREDIT FACILITIES

(unaudited) (millions of dollars)	March 31, 2017	Weighted Average Interest Rate for the Quarter Ended March 31, 2017		December 31, 2016	Weighted Average Interest Rate for the Year Ended December 31, 2016
TC PipeLines, LP
Senior Credit Facility due 2021	110	2.03	%	160	1.72	%
2013 Term Loan Facility due July 2018	500	2.03	%	500	1.73	%
2015 Term Loan Facility due September 2018	170	1.93	%	170	1.63	%
4.65% Unsecured Senior Notes due 2021	350	4.65	%(a)	350	4.65	%(a)
4.375% Unsecured Senior Notes due 2025	350	4.375	%(a)	350	4.375	%(a)
GTN
5.29% Unsecured Senior Notes due 2020	100	5.29	%(a)	100	5.29	%(a)
5.69% Unsecured Senior Notes due 2035	150	5.69	%(a)	150	5.69	%(a)
Unsecured Term Loan Facility due 2019	65	1.73	%	65	1.43	%
Tuscarora
Unsecured Term Loan due 2019	10	1.91	%	10	1.64	%
3.82% Series D Senior Notes due 2017	12	3.82	%(a)	12	3.82	%(a)
	1,817			1,867
Less: unamortized debt issuance costs and debt discount	8			9
Less: current portion	23			23
	1,786			1,835

(a)Fixed interest rate

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 $110 million was outstanding at March 31, 2017 (December 31, 2016 - $160 million), leaving $390 million available for future borrowing. The LIBOR-based interest rate on the Senior Credit Facility was 2.04 percent at March 31, 2017 (December 31, 2016 — 1.92 percent).

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As of March 31, 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 (December 31, 2016 — 2.31 percent). Prior to hedging activities, the LIBOR-based interest rate on 2013 Term Loan Facility was 2.04 percent at March 31, 2017 (December 31, 2016 — 1.87 percent).

The LIBOR-based interest rate on the 2015 Term Loan Facility was 1.93 percent at March 31, 2017 (December 31, 2016 — 1.77 percent).

The 2013 Term Loan Facility and the 2015 Term Loan Facility (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 4.04 to 1.00 as of March 31, 2017.

GTN’s Unsecured Senior Notes, along with GTN’s Unsecured Term Loan Facility contain a covenant that limits total debt to no greater than 70 percent of GTN’s total capitalization.  GTN’s total debt to total capitalization ratio at March 31, 2017 was 44.7 percent. The LIBOR-based interest rate on the GTN’s Unsecured Term Loan Facility was 1.73 percent at March 31, 2017 (December 31, 2016 — 1.57 percent).

Tuscarora’s Series D Senior Notes, which require yearly principal payments until maturity, are secured by Tuscarora’s transportation contracts, supporting agreements and substantially all of Tuscarora’s property. The note purchase agreements contain certain provisions that include, among other items, limitations on additional indebtedness and distributions to partners. The Series D Senior Notes contain a covenant that limits total debt to no greater than 45 percent of Tuscarora’s total capitalization.  Tuscarora’s total debt to total capitalization ratio at March 31, 2017 was 21.05 percent. Additionally, the Series D Senior Notes require 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 3.00 to 1.00. The ratio was 3.92 to 1.00 as of March 31, 2017.

The LIBOR-based interest rate on the Tuscarora’s Unsecured Term Loan Facility was 2.12 percent at March 31, 2017 (December 31, 2016 —1.90 percent).

At March 31, 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	23
2018	691
2019	43
2020	100
2021	460
Thereafter	500
	1,817

NOTE 6        PARTNERS’ EQUITY

ATM equity issuance program (ATM program)

During the three months ended March 31, 2017, we issued 1,197,749 common units under our ATM program generating net proceeds of approximately $69 million, plus $2 million from the General Partner to maintain its effective two percent general partner interest. The commissions to our sales agents in the three months ended March 31, 2017 were approximately $704,000. The net proceeds were used for general partnership purposes.

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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 three months ended March 31, 2017, the threshold has not been exceeded.

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 2015 Annual Report. 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 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. No unitholder has claimed or attempted to exercise any rescission rights to date and these rights expire one year from the date of purchase of the unit.

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

At March 31, 2017, $19 million of the Common units subject to rescission on the consolidated balance sheet were reclassified back to equity. The amount reclassified represents the net proceeds received from the 0.4 million units sold from March 8, 2016 up to and including March 31, 2016 as the rescission rights attached to these units expired.

NOTE 7        NET INCOME PER COMMON UNIT

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

The 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). During the three months ended March 31, 2017 and 2016, no amounts were allocated to the Class B units as the annual threshold of $20 million has  not been exceeded.

Net income per common unit was determined as follows:

(unaudited)	Three months ended March 31,
(millions of dollars, except per common unit amounts)	2017			2016
Net income attributable to controlling interests	75			73
Net income attributable to the General Partner	(1		)	(1		)
Incentive distributions attributable to the General Partner (a)	(2		)	(1		)
Net income attributable to common units	72			71
Weighted average common units outstanding (millions) — basic and diluted (b)	68.3			64.4
Net income per common unit — basic and diluted	$	1.05		$	1.10

(a)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

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Partner are based on the Partnership’s available cash during the current reporting period, but declared and paid in the subsequent reporting period.

(b)Includes the common units subject to rescission. These units are treated as outstanding for financial reporting purposes. Refer to Note 6.

NOTE 8        CASH DISTRIBUTIONS TO COMMON UNITS

During the three months ended March 31, 2017, the Partnership distributed $0.94 per common unit (March 31, 2016 — $0.89 per common unit) for a total of $68 million (March 31, 2016 - $60 million).

The distribution paid to our General Partner during the three months ended March 31, 2017 for its effective two percent general partner interest was $2 million along with an IDR payment of $2 million for a total distribution of $4 million (March 31, 2016 - $1 million for the effective two percent interest and a $1 million IDR payment).

NOTE 9        CHANGE IN OPERATING WORKING CAPITAL

(unaudited)	Three months ended March 31,
(millions of dollars)	2017		2016
Change in accounts receivable and other	3		(1	)
Change in other current assets	2		—
Change in accounts payable and accrued liabilities	(3	)	3	(a)
Change in accounts payable to affiliates	(1	)	(1	)
Change in accrued interest	4		5
Change in operating working capital	5		6

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

NOTE 10      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. Total costs charged to the Partnership by the General Partner were $1 million for each of the three months ended March 31, 2017 and 2016.

As operator, 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.

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

	Three months ended
(unaudited)	March 31,
(millions of dollars)	2017	2016
Capital and operating costs charged by TransCanada’s subsidiaries to:
Great Lakes (a)	8	7
Northern Border (a)	10	6
PNGTS (a)	2	2
GTN (a)	7	6
Bison (b)	1	(1	)
North Baja	1	1
Tuscarora	1	1
Impact on the Partnership’s net income:
Great Lakes	3	3
Northern Border	3	3
PNGTS	1	1
GTN	7	5
Bison	1	1
North Baja	1	1
Tuscarora	1	1

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

(a) Represents 100 percent of the costs.

(b) In March 2016, Bison sold excess pipe (at cost) to an affiliate.

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 months ended March 31, 2017, Great Lakes earned 67 percent of transportation revenues from TransCanada and its affiliates (March 31, 2016 — 76 percent).

At March 31, 2017, $16 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 months ended March 31, 2017, Great Lakes recorded an estimated 2017 revenue sharing provision of $3.4 million. Great Lakes expects that a significant percentage of this refund will be paid to its affiliates.

On March 31, 2017, PNGTS declared its first quarter 2017 distribution of $5 million, of which the Partnership received its 49.9 percent share or $2 million on April 18, 2017.

NOTE 11      FAIR VALUE MEASUREMENTS

(a) Fair Value Hierarchy

Under 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:

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·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 at March 31, 2017 and December 31, 2016 was $1,863 million and $1,908 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 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 March 31, 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 months ended March 31, 2017 and 2016. The change in fair value of interest rate derivative instruments recognized in other comprehensive income was a gain of $1 million for the three months ended March 31, 2017 (March 31, 2016 — loss of $2 million). For the three months ended March 31, 2017, the net realized loss related to the interest rate swaps was nil million and was included in financial charges and other (March 31, 2016 — nil million) (refer to Note 13).

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

NOTE 12      ACCOUNTS RECEIVABLE AND OTHER

(unaudited)
(millions of dollars)	March 31, 2017	December 31, 2016
Trade accounts receivable, net of allowance of nil	31	34
Imbalance receivable from affiliates	1	2
Other	2	1
	34	37

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NOTE 13      FINANCIAL CHARGES AND OTHER

	Three months ended
(unaudited)	March 31,
(millions of dollars)	2017	2016
Interest Expense (a)	16	17
Net realized loss related to the interest rate swaps (b)	—	—
Other Income (b)	—	—
	16	17

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

(b)Nil million for both periods.

NOTE 14      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.  In July 2016, Essar Minnesota filed for Bankruptcy. The performance bond was released into the bankruptcy court proceedings.The Foreign Essar Affiliates have not filed for bankruptcy. The Eighth Circuit heard the appeal on October 20, 2016.  A decision on the appeal was received in December 2016 and the Eighth Circuit vacated Great Lakes’ judgment against Essar finding that there was no federal jurisdiction. Great Lakes filed a Request for Rehearing with the Eighth Circuit and it was denied in January 2017. Great Lakes currently is proceeding against Essar Minnesota in the bankruptcy court and its case against the Foreign Essar Affiliates in Minnesota state court remains pending. In April, after reaching agreement with creditors on an allowed claim, the Bankruptcy court approved Great Lakes’ claim in the amount of $31.5 million.

NOTE 15              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- Great Lakes is required to file a new section 4 rate case with rates effective no later than January 1, 2018 as part of the settlement agreement with customers approved in November 2013. On March 31, 2017, Great Lakes submitted a General Section 4 Rate Filing and Tariff Changes with FERC. The rates proposed in the filing will become effective on October 1, 2017, subject to refund, if alternate resolution to the proceeding is not reached prior to that date. Great Lakes has initiated customer discussions regarding the details of the filing and will seek to achieve a mutually beneficial resolution through settlement with its customers.

NOTE 16              VARIABLE INTEREST ENTITIES

In the normal course of business, the Partnership must re-evaluate its legal entities under the newly effective consolidation guidance to determine if those that are considered to be VIEs are appropriately consolidated or if they should be accounted for under other US 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.

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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 and PNGTS 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 Sheet:

(unaudited)
(millions of dollars)	March 31, 2017		December 31, 2016
ASSETS (LIABILITIES) *
Accounts receivable and other	21		24
Inventories	6		6
Other current assets	3		4
Equity investments	1,062		1,044
Plant, property and equipment	844		847
Other assets	2		2
Accounts payable and accrued liabilities	(18	)	(20	)
Accounts payable to affiliates, net	(21	)	(28	)
Accrued interest	(5	)	(1	)
Current portion of long-term debt	(23	)	(23	)
Long-term debt	(313	)	(313	)
Other liabilities	(26	)	(25	)

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

NOTE 17      SUBSEQUENT EVENTS

Management of the Partnership has reviewed subsequent events through May 4, 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 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 and payable on May 15, 2017 to unitholders of record as of May 5, 2017. The declared distribution totaled $68 million and payable 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 of IDRs.

Northern Border declared its March 2017 distribution of $13 million on April 7, 2017, of which the Partnership received its 50 percent share or $7 million on April 28, 2017.

Great Lakes declared its first quarter 2017 distribution of $43 million on April 19, 2017, of which the Partnership received its 46.45 percent share or $20 million. The distribution was paid on May 1, 2017.

On April 24, 2017, Great Lakes reached an agreement on the terms of a potential new long-term transportation capacity contract with its affiliate, TransCanada.  The contract is for a term of 10 years with a total contract value of up to $758 million. The contract may commence as soon as November 1, 2017 and contains termination options beginning in year three. The contract is subject to the satisfaction of certain conditions, including but not limited to approval by the Canadian National Energy Board of an associated contract between TransCanada and third party customers. Great Lakes current rate structure includes a revenue sharing mechanism that requires Great Lakes to share with its customers certain percentages of any qualifying revenues earned above a calculated return on equity threshold. Additionally, Great Lakes is currently pursuing resolution of its March 31, 2017 General Section 4 Rate

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Filing (refer to Note 15). We cannot predict the cumulative impact of these circumstances to the Partnership’s earnings at this time.

On May 3, 2017, the Partnership entered into agreements to purchase from subsidiaries of TransCanada a 49.34 percent interest in Iroquois Gas Transmission System, L.P. (Iroquois), including a future option to acquire a further 0.66 percent in Iroquois, together with an additional 11.81 percent interest in PNGTS resulting in the Partnership owning a 61.71 percent in PNGTS (2017 Acquisition). The total purchase price of the 2017 Acquisition is $765 million comprised of $597 million in cash and the assumption of a total $168 million of proportional Iroquois and PNGTS debt.  The Partnership expects to fund the cash portion of the transaction through a combination of debt and equity issuances including proceeds from our ATM Program and borrowing under our Senior Credit Facility. The transaction is expected to close mid-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 is currently jointly owned by affiliates of TransCanada Corporation and Dominion Resources, Inc. via a joint venture.

The transaction was approved by the Board of Directors of the General Partner based on approval and recommendation from the Board’s Conflicts Committee, which is comprised entirely of independent directors. In connection with the transaction, Evercore served as independent financial advisor to the Conflicts Committee. Latham & Watkins served as legal counsel to the Conflicts Committee and Vinson & Elkins served as legal counsel to the Partnership. Wood Mackenzie served as commercial and market advisor to the Conflicts Committee.

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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.

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 payable 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 of IDRs.

Great Lakes - Great Lakes is required to file a new section 4 rate case with rates effective no later than January 1, 2018 as part of the settlement agreement with customers approved in November 2013. On March 31, 2017, Great Lakes submitted a General Section 4 Rate Filing and Tariff Changes with FERC (2017 Rate Case). The rates proposed in the filing will become effective on October 1, 2017, subject to refund, if alternate resolution to the proceeding is not reached prior to that date. Great Lakes has initiated customer discussions regarding the details of the filing and will seek to achieve a mutually beneficial resolution through settlement with its customers.

On April 24, 2017, Great Lakes reached an agreement on the terms of a potential new long-term transportation capacity contract with its affiliate, TransCanada.  The contract is for a term of 10 years with a total contract value of up to $758 million. The contract may commence as soon as November 1, 2017 and contains termination options beginning in year three. The contract is subject to the satisfaction of certain conditions, including but not limited to approval by the Canadian National Energy Board of an associated contract between TransCanada and third party customers. Great Lakes current rate structure includes a revenue sharing mechanism that requires Great Lakes to share with its customers certain percentages of any qualifying revenues earned above a calculated return on equity threshold. Additionally, Great Lakes is currently pursuing resolution of its 2017 Rate Case. We cannot predict the cumulative impact of these circumstances to the Partnership’s earnings at this time.

2017 Acquisition —On May 3, 2017, the Partnership entered into agreements to purchase from subsidiaries of TransCanada a 49.34 percent interest in Iroquois, including a future option to acquire a further 0.66 percent in Iroquois, together with an additional 11.81 percent interest in PNGTS resulting in the Partnership owning a 61.71 percent in PNGTS. The total purchase price of the 2017 Acquisition is $765 million comprised of $597 million in cash and the assumption of a total $168 million of proportional Iroquois and PNGTS debt.  The Partnership expects to fund the cash portion of the transaction through a combination of debt and equity issuances including proceeds from our ATM Program and borrowing under our Senior Credit Facility. The transaction is expected to close mid-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 is currently jointly owned by affiliates of TransCanada Corporation and Dominion Resources, Inc. via a joint venture. 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 its cash flow.

The transaction was approved by the Board of Directors of the General Partner based on approval and recommendation from the Board’s Conflicts Committee, which is comprised entirely of independent directors. In connection with the transaction, Evercore served as independent financial advisor to the Conflicts Committee. Latham & Watkins served as legal counsel to the Conflicts Committee and Vinson & Elkins served as legal counsel to the Partnership. Wood Mackenzie served as commercial and market advisor to the Conflicts Committee.

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.

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RESULTS OF OPERATIONS

Net Income Attributable to Controlling Interests

Our equity interests in Northern Border, Great Lakes, and PNGTS, and ownership of GTN, Bison, North Baja and Tuscarora were our only material sources of income during the period. Therefore, our results of operations and cash flows were influenced by, and reflect the same factors that influenced, our pipeline systems.

	Three months ended
(unaudited)	March 31,				$		%
(millions of dollars)	2017		2016		Change*		Change*
Transmission revenues	89		86		3		3
Equity earnings from unconsolidated affiliates	43		42		1		2
Operating, maintenance and administrative costs	(19	)	(17	)	(2	)	(12	)
Depreciation	(22	)	(21	)	(1	)	(5	)
Financial charges and other	(16	)	(17	)	1		6
Net income	75		73		2		3
Net income attributable to controlling interests	75		73		2		3

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

Three Months Ended March 31, 2017 compared to Same Period in 2016

Net  income attributable to controlling interests - The Partnership’s net income attributable to controlling interests increased by $2 million or 3 percent due to higher revenues partially offset by higher costs.

Transmission revenues - The $3 million increase was primarily due to higher transportation revenues on GTN.

Operating, maintenance and administrative costs - The $2 million increase was mainly attributable to higher operational costs on GTN.

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

As discussed in Note 7 within Item 1. “Financial Statements,” we will allocate a portion of the Partnership’s income to the Class B Units after the annual threshold is exceeded which will effectively reduce the income allocable to the common units and net income per common unit. Currently, we expect to allocate a portion of the Partnership’s income to the Class B units beginning in the third quarter of 2017.

Please read also Note 6 within Item 1. “Financial Statements” for additional disclosures on the Class B units.

LIQUIDITY AND CAPITAL RESOURCES

Overview

Our principal sources of liquidity and cash flows include distributions received from our equity investments, operating cash flows from our subsidiaries, public offerings of debt and equity, term loans and our bank 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

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(millions of dollars)	March 31, 2017	December 31, 2016
Total capacity under the Senior Credit Facility	500	500
Less: Outstanding borrowings under the Senior Credit Facility	110	160
Available capacity under the Senior Credit Facility	390	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.

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 Three Months Ended March 31, 2017 compared to Same Period in 2016

	Three months ended
(unaudited)	March 31,
(millions of dollars)	2017		2016
Net cash provided by (used in):
Operating activities	90		100
Investing activities	(11	)	(208	)
Financing activities	(69	)	117
Net increase in cash and cash equivalents	10		9
Cash and cash equivalents at beginning of the period	50		39
Cash and cash equivalents at end of the period	60		48

Operating Cash Flows

Net cash provided by operating activities decreased by $10 million in the three months ended March 31, 2017 compared to the same period in 2016 primarily due to lower distributions from Great Lakes in 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.

Investing Cash Flows

Net cash used in investing activities decreased by $197 million in the three months ended March 31, 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 there were no large capital expenditures in the three months ended March 31, 2017.

Financing Cash Flows

Net cash provided by financing activities decreased by $186 million in the three months ended March 31, 2017 compared to the same period in 2016 primarily due to the net effect of:

·$195 million decrease in issuances of debt;

·$25 million increase in debt repayments;

·$52 million increase in ATM equity issuances;

·$8 million increase in distributions paid to our common units including our General Partner’s effective two percent share and its related IDRs; and

·$10 million increase in distributions paid to Class B units.

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Cash Flow Outlook

Operating Cash Flow Outlook

Northern Border declared its March 2017 distribution of $13 million on April 7, 2017, of which the Partnership received its 50 percent share or $7 million. The distribution was paid on April 28, 2017.

Great Lakes declared its first quarter 2017 distribution of $43 million on April 19, 2017, of which the Partnership received its 46.45 percent share or $20 million. The distribution was paid on May 1, 2017.

PNGTS declared its first quarter 2017 distribution of $5 million on March 31, 2017, of which the Partnership received its 49.9 percent share or $2 million.  The distribution was paid on April 18, 2017.

Our equity investee PNGTS has $17 million of scheduled debt repayments for the remainder of 2017, of which the Partnership’s share is approximately $9 million. PNGTS’ debt repayments are not funded with cash calls to its owners as PNGTS has historically funded its scheduled debt repayments by adjusting its available cash for distribution, which effectively reduces the net cash that is received by the Partnership as distributions from PNGTS.

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 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 $1 million as of March 31, 2017 in connection with various maintenance and general plant projects.

Our expected total growth and maintenance capital expenditures as outlined in our 2016 Annual Report for the Form 10-K remain unchanged.

Financing Cash Flow Outlook

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.  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, 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
(unaudited)	March 31,
(millions of dollars)	2017		2016
Net income	75		73
Add:
Interest expense	16		17
Depreciation and amortization	22		21
EBITDA	113		111
Add:
Distributions from equity investments (a)
Northern Border	20		23
Great Lakes	20		17
PNGTS (b)	5		6
	45		46
Less:
Equity earnings:
Northern Border	(19	)	(18	)
Great Lakes	(17	)	(15	)
PNGTS (b)	(7	)	(9	)
	(43	)	(42	)
Less:
Interest expense	(16	)	(17	)
Maintenance capital expenditures (c)	(4	)	(1	)
Total Distributable Cash Flow	95		97
General Partner distributions declared (d)	(3	)	(2	)
Distributions allocable to Class B units (e)	—		—
Distributable Cash Flow	92		95

(a)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.

(b)Our equity investee PNGTS has $23 million of senior secured notes payments due in 2017, of which the Partnership’s share is approximately $11 million. PNGTS’ debt repayments are not funded with cash calls to its owners as PNGTS has historically funded its scheduled debt repayments and other cash needs such as tax payments, by adjusting its available cash for distribution, which effectively reduces the net cash that we receive as distributions from PNGTS.  The distribution reported from PNGTS represents our 49.9 percent share of distributions from PNGTS’ available cash before our proportionate share of the total debt repayment of PNGTS.

(c)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.

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(d)Distributions declared to the General Partner for the three months ended March 31, 2017 included an incentive distribution of approximately $2 million (March 31, 2016 — $1 million).

(e)During the three months ended March 31, 2017, 30 percent of GTN’s total eligible distributions was $10 million (March 31, 2016 - $11 million), therefore, no distributions were allocated to the Class B units as the threshold level of $20 million has not been exceeded. Consistent with 2016, we expect the 2017 threshold will be exceeded in the third quarter of 2017.

Please read Notes 6 and 7 within Item 1. “Financial Statements” for additional disclosures on the Class B units.

First Quarter 2017 Compared with First Quarter 2016

Our EBITDA increased by $2 million as a result of higher revenues on GTN  partially offset by an increase in GTN’s operational costs. However, our distributable cash flow decreased by $3 million in the first quarter of 2017 compared to the same period in 2016 due to higher maintenance capital expenditures related to major compression equipment overhauls on GTN’s pipeline system.

Contractual Obligations

The Partnership’s Contractual Obligations

The Partnership’s contractual obligations related to debt as of March 31, 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 Three Months Ended March 31, 2017
TC PipeLines, LP
Senior Credit Facility due 2021	110	—	—	110	—	2.03	%
2013 Term Loan Facility due July 2018	500	—	500	—	—	2.03	%
2015 Term Loan Facility due September 2018	170	—	170	—	—	1.93	%
4.65% Senior Notes due 2021	350	—	—	350	—	4.65	%(a)
4.375% Senior Notes due 2025	350	—	—	—	350	4.375	%(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	65	10	55	—	—	1.73	%
Tuscarora
Unsecured Term Loan due 2019	10	1	9	—	—	1.91	%
3.82% Series D Senior Notes due 2017	12	12	—	—	—	3.82	%(a)
	1,817	23	734	560	500

(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 March 31, 2017 was $1,863 million.

Please read Note 5 within Item 1. “Financial Information” for additional information regarding the Partnership’s debt.

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Summary of Northern Border’s Contractual Obligations

Northern Border’s contractual obligations related to debt as of March 31, 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 Three Months Ended March 31, 2017
$200 million Credit Agreement due 2020	181	—	—	181	—	1.91	%
7.50% Senior Notes due 2021	250	—	—	250	—	7.50	%(b)
	431	—	—	431	—

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

(b) Fixed interest rate

As of March 31, 2017, $181 million was outstanding under Northern Border’s $200 million revolving credit agreement, leaving $19 million available for future borrowings. At March 31, 2017, Northern Border was in compliance with all of its financial covenants.

As of March 31, 2017, Northern Border had not utilized the $100 million 364-day revolving credit facility.

Northern Border has commitments of $3 million as of March 31, 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 March 31, 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 Three Months Ended March 31, 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 March 31, 2017 (December 31, 2016 — $150 million). Great Lakes was in compliance with all of its financial covenants at March 31, 2017.

Great Lakes has commitments of $1 million as of March 31, 2017 in connection with pipeline integrity, major overhaul projects, and right of way renewals.

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Summary of PNGTS’ Contractual Obligations

PNGTS’ contractual obligations related to debt as of March 31, 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 Three Months Ended March 31, 2017
5.90% Senior Secured Notes due 2018	42	23	19	—	—	5.90	%(b)
	42	23	19	—	—

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

(b) Fixed interest rate

PNGTS has no material commitments as of March 31, 2017.

The Partnership’s equity investee PNGTS has $17 million of senior secured notes due over the remainder of 2017, of which the Partnership’s share is approximately $9 million.

Additionally, PNGTS 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 service reserve account must be fully funded and the PNGTS debt service coverage ratio for the preceding and succeeding twelve months must be 1.30 or greater. At March 31, 2017, the debt service coverage ratio was 1.86 for the twelve preceding months and 1.52 for the twelve succeeding months. Therefore, PNGTS 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 months ended March 31, 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 Annual Report on Form 10-K for the year ended December 31, 2016.

RELATED PARTY TRANSACTIONS

Please read Note 10 and 17 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.

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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 March 31, 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 $355 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 22 percent of our outstanding debt was subject to variability in LIBOR interest rates.

As of March 31, 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 March 31, 2017, our annual interest expense would increase (decrease) and net income would decrease (increase) by approximately $4 million.

As of March 31, 2017 and December 31, 2016, $181 million, or 42 percent, of Northern Border’s outstanding debt was at floating rates. If interest rates hypothetically increased (decreased) by one percent, 100 basis points, compared with rates in effect at March 31, 2017, Northern Border’s annual interest expense would increase (decrease) and its net income would decrease (increase) by approximately $2 million.

GTN’s Unsecured Senior Notes, Northern Border’s Senior Notes, Tuscarora’s Series D 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 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 March 31, 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 months ended March 31, 2017 and 2016. The change in fair value of interest rate derivative instruments recognized in other comprehensive income was a gain of $1 million for

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the three months ended March 31, 2017 (2016 — loss of $2 million). For the three months ended March 31, 2017, the net realized loss related to the interest rate swaps was nil million and was included in financial charges and other (2016 — nil million).

The Partnership has no master netting agreements; however, it has derivative contracts containing provisions with rights of offset. The Partnership has elected to present the fair value of derivative instruments with the right to offset on a gross basis in the balance sheet. Had the Partnership elected to present these instruments on a net basis, there would be no effect on the consolidated balance sheet as of March 31, 2017 (net asset of nil million as of December 31, 2016).

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 March 31, 2017, we had not incurred any significant credit losses and had no significant amounts past due or impaired. At March 31, 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 March 31, 2017, the Partnership had a Senior Credit Facility of $500 million maturing in 2021 and the outstanding balance on this facility was $110 million. In addition, at March 31, 2017, Northern Border had a committed revolving bank line of $200 million maturing in 2020 with $181 million drawn and an additional $100 million 364-day revolving credit facility with no current borrowings. 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 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.

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Changes in Internal Control Over Financial Reporting

During the quarter ended March 31, 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 “Legal Proceedings” of the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2016.

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

A description of this legal proceeding can be found in Notes to Consolidated Financial Statements —Note 14 Contingencies in Part I, Item 1, 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.

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.

The 2017 Acquisition is subject to customary closing conditions.

On May 3, 2017, we entered into definitive agreements to acquire a 49.34 percent equity interest in Iroquois Gas Transmission System and its remaining 11.81 percent interest in PNGTS from TransCanada expected to close mid-2017. The completion of the acquisition is subject to customary closing conditions, including the ability of the seller to make certain representations and warranties and the absence of a material adverse effect at closing. We cannot assure you that these conditions will be met and as a result there can be no assurance that the acquisition will be completed.  The 2017 Acquisition is not subject to a financing condition. We expect to finance the cash portion of the purchase price of the acquisition with equity and debt. There can be no assurance that the 2017 Acquisition, if completed, will result in an increase in cash per common unit generated from operations.

Following the 2017 Acquisition, if completed, 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 would include 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.

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Item 6.                   Exhibits

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

No.	Description
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).
3.3	First Amended and Restated General Partnership Agreement of Northern Border Pipeline Company by and between Northern Border Intermediate Limited Partnership and TC Pipelines Intermediate Limited Partnership dated April 6, 2006 (Incorporated by reference to Exhibit 3.1 to Northern Border Pipeline Company’s Form 8-K filed on April 12, 2006).
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 FT18577 between Great Lakes Gas Transmission Limited Partnership and ANR Pipeline Company, effective date January 09, 2017.
99.2*	Transportation Service Agreement FT18659 between Great Lakes Gas Transmission Limited Partnership and ANR Pipeline Company, effective date April 01, 2017.
99.3*	Transportation Term Sheet between Great Lakes Gas Transmission Limited Partnership and TransCanada PipeLines Limited.
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.

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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 4th day of May 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)

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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
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).
3.3	First Amended and Restated General Partnership Agreement of Northern Border Pipeline Company by and between Northern Border Intermediate Limited Partnership and TC Pipelines Intermediate Limited Partnership dated April 6, 2006 (Incorporated by reference to Exhibit 3.1 to Northern Border Pipeline Company’s Form 8-K filed on April 12, 2006).
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 FT18577 between Great Lakes Gas Transmission Limited Partnership and ANR Pipeline Company, effective date January 09, 2017.
99.2*	Transportation Service Agreement FT18659 between Great Lakes Gas Transmission Limited Partnership and ANR Pipeline Company, effective date April 01, 2017.
99.3*	Transportation Term Sheet between Great Lakes Gas Transmission Limited Partnership and TransCanada PipeLines Limited.
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.

36

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: May 4, 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: May 4, 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 March 31, 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: May 4, 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 March 31, 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: May 4, 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 FT18577

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: January 09, 2017

2.CONTRACT IDENTIFICATION: FT18577

3.RATE SCHEDULE: FT

4.SHIPPER TYPE: Interstate Pl

5.STATE/PROVINCE OF INCORPORATION: Delaware

6.TERM: February 01, 2017 to October 31, 2018

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): 294,211

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.

Contract ID:  FT18577

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

Contract ID:  FT18577

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:
AGREED TO BY:
GREAT LAKES GAS TRANSMISSION LIMITED PARTNERSHIP	ANR PIPELINE COMPANY
By: Great Lakes Gas Transmission Company
/s/ Kay Dennison	/s/ Joseph E. Pollard
Director, Transportation Accounting and Contracts	Director, Long Term Marketing
Dated: January 11, 2017	Dated: January 11, 2017

3

APPENDIX A

Contract Identification FT18577

Date:  January 09, 2017

Supersedes Appendix Dated: Not Applicable

Shipper:  ANR PIPELINE COMPANY

Maximum Daily Quantity (Dth/Day) per Location:

Begin Date	End Date	Point(s) of Primary Receipt	Point(s) of Primary Delivery	MDQ	Maximum Allowable Operating Pressure (MAOP)
02/01/2017	03/31/2017	SOUTH CHESTER		115,771	974
02/01/2017	03/31/2017	DEWARD		294,211	974
04/01/2017	10/31/2017	DEWARD		0	974
11/01/2017	03/31/2018	SOUTH CHESTER		115,771	974
11/01/2017	03/31/2018	DEWARD		202,464	974
04/01/2018	10/31/2018	DEWARD		0	974
02/01/2017	03/31/2017		FARWELL	294,211	974
04/01/2017	10/31/2017		FARWELL	0	974
11/01/2017	03/31/2018		FARWELL	202,464	974
04/01/2018	10/31/2018		FARWELL	0	974

4

EX-99.2

Exhibit 99.2

TRANSPORTATION SERVICE AGREEMENT

Contract Identification FT18659

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: March 07, 2017

2.CONTRACT IDENTIFICATION: FT18659

3.RATE SCHEDULE: FT

4.SHIPPER TYPE: Interstate Pl

5.STATE/PROVINCE OF INCORPORATION: Delaware

6.TERM: April 01, 2017 to October 31, 2018

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): 202,464

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.

Contract ID:  FT18659

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

Contract ID:  FT18659

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:
AGREED TO BY:
GREAT LAKES GAS TRANSMISSION LIMITED PARTNERSHIP	ANR PIPELINE COMPANY
By: Great Lakes Gas Transmission Company
/s/ Kay Dennison	/s/ Joseph E. Pollard
Director, Transportation Accounting and Contracts	Director, Long Term Marketing
Dated: March 09, 2017	Dated: March 09, 2017

3

APPENDIX A

Contract Identification FT18659

Date:  March 07, 2017

Supersedes Appendix Dated: Not Applicable

Shipper:  ANR PIPELINE COMPANY

Maximum Daily Quantity (Dth/Day) per Location:

Begin Date	End Date	Point(s) of Primary Receipt	Point(s) of Primary Delivery	MDQ	Maximum Allowable Operating Pressure (MAOP)
04/01/2017	10/31/2017	DEWARD		0	974
11/01/2017	03/31/2018	SOUTH CHESTER		115,771	974
11/01/2017	03/31/2018	DEWARD		202,464	974
04/01/2018	10/31/2018	DEWARD		0	974
04/01/2017	10/31/2017		FARWELL	0	974
11/01/2017	03/31/2018		FARWELL	202,464	974
04/01/2018	10/31/2018		FARWELL	0	974

4

EX-99.3

Exhibit 99.3

Great Lakes Gas Transmission Limited Partnership (“Great Lakes”) and TransCanada PipeLines Limited (“Shipper”) Term Sheet for Proposed Service (the “Term Sheet”)

Transporter:	Great Lakes
Shipper:	TransCanada PipeLines Limited
Contract Start Date:	The latter of November 1, 2017, or NEB Approval of LTFP and St. Clair to Dawn sale, but no later than April 1, 20181
Contract End Date:	Ten years from the Contract Start Date
Primary Receipt:	Emerson
Primary Delivery:	St. Clair
MDQ:	711,000 Dth/d
Reservation Rate:	$8.89/Dth monthly, fixed negotiated reservation rate2
Utilization Rate:	Maximum tariff utilization rate
Other Rates:	Fuel, ACA, and all other rates and surcharges in accordance with Great Lakes’ FERC gas tariff, which may be amended from time to time.
Other Costs:	Regulatory approved costs necessary to comply with domestic or foreign laws, regulations, or rules that were not in effect or applicable to Great Lakes on October 13, 2016.
Secondary Optionality:	Shipper will receive access to multiple Great Lakes delivery points as listed below at the primary path rate:
	Belle River Mills — DTE Gas
	Chippewa — Consumers Energy
	Deward — ANR Storage Company
	Farwell — ANR Pipeline Company
	Rattle Run — Bluewater Storage

1Subject 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.

2Where Transporter’s general system recourse reservation rate is greater 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 per Dth/month.

Right of First Refusal:	A contractual ROFR is provided for the initial term of the agreement.
Reduction Option:	Shipper shall have the right to reduce its contractual MDQ, or terminate this contract, on each anniversary date effective after the 3rd anniversary provided that 1 years’ prior written notice has been given to Great Lakes.
Regulatory Out:	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 National Energy Board that TransCanada’s Long-term Fixed Price proposal was not approved, the St. Clair to Dawn sale was not approved, or Shipper was not able to obtain matching downstream capacity from St. Clair to Dawn despite Shippers 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.
Credit:	Shipper shall demonstrate creditworthiness in accordance with Section 6.26 of Great Lakes’ FERC Gas Tariff.
Non Recourse:	No personal liability whatsoever shall attach to, be imposed on or otherwise be incurred by a Partner, agent, management official or employee of the Partnership or any director, officer or employee of any of the foregoing for any obligation of the Partnership under such agreement or for any claim based on such obligation and that the sole recourse of other parties to such agreements shall be limited to the assets of the Partnership.

/s/ John Soini	April 21, 2017
Commercial Vice President, TransCanada Mainline
/s/ Jay White	April 24, 2017
Vice-President, Commercial West

1Subject to Great Lakes’ receipt and acceptance, in a form and substance acceptable to Great Lakes to sole discretion, of all approvals that Great Lakes determines necessary to provide the service contemplated herein.

2Where Transporter’s general system recourse reservation rate is greater 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 per Dth/month.

2

XML

Document and Entity Information - shares	3 Months Ended
	Mar. 31, 2017	May 02, 2017
Document and Entity Information
Entity Registrant Name	TC PIPELINES LP
Entity Central Index Key	0001075607
Document Type	10-Q
Document Period End Date	Mar. 31, 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		68,938,577
Document Fiscal Year Focus	2017
Document Fiscal Period Focus	Q1

XML

CONSOLIDATED STATEMENTS OF INCOME - USD ($) shares in Millions, $ in Millions	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Transmission revenues	$ 89	$ 86
Equity earnings (Note 4)	43	42
Operation and maintenance expenses	(12)	(10)
Property taxes	(5)	(5)
General and administrative	(2)	(2)
Depreciation	(22)	(21)
Financial charges and other (Note 13)	(16)	(17)
Net income	75	73
Net income (loss) attributable to controlling interest allocation
General Partner	3	2
Net income	75	73
Common units
Net income (loss) attributable to controlling interest allocation
Limited partners	$ 72	$ 71
Net income (loss) per common unit (Note 7) - basic (in dollars per unit)	$ 1.05	$ 1.10
Net income (loss) per common unit (Note 7) - diluted (in dollars per unit)	$ 1.05	$ 1.10
Weighted average common units outstanding - basic (in units)	68.3	64.4
Weighted average common units outstanding - diluted (in units)	68.3	64.4
Common units outstanding, end of year (in units)	68.6	64.7

XML

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
Net income	$ 75	$ 73
Other comprehensive income
Change in fair value of cash flow hedges (Note 11)	1	(2)
Comprehensive income	$ 76	$ 71

XML

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions	Mar. 31, 2017	Dec. 31, 2016
Current Assets
Cash and cash equivalents	$ 60	$ 50
Accounts receivable and other (Note 12)	34	37
Distribution receivable from affiliate (Note 10)	2	3
Inventories	7	7
Other	4	5
Total current assets	107	102
Equity investments (Note 4)	1,062	1,044
Plant, property and equipment (Net of $914 accumulated depreciation; 2016- $892)	1,866	1,881
Goodwill	130	130
Other assets	1	1
Total assets	3,166	3,158
Current Liabilities
Accounts payable and accrued liabilities	24	27
Accounts payable to affiliates (Note 10)	6	7
Accrued interest	13	9
Current portion of long-term debt (Note 5)	23	23
Total current liabilities	66	66
Long-term debt, net (Note 5)	1,786	1,835
Other liabilities	28	28
Total liabilities	1,880	1,929
Common units subject to rescission (Note 6)	64	83
Partners' Equity
General partner	28	27
Accumulated other comprehensive loss	1
Controlling interests	1,222	1,146
Total liabilities and partners' equity	3,166	3,158
Common units
Partners' Equity
Limited partner	1,098	1,002
Class B units
Partners' Equity
Limited partner	$ 95	$ 117

XML

CONSOLIDATED BALANCE SHEET (Parenthetical) - USD ($) $ in Millions	Mar. 31, 2017	Dec. 31, 2016
CONSOLIDATED BALANCE SHEETS
Accumulated depreciation	$ 914	$ 892

XML

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Cash Generated From Operations
Net income	$ 75	$ 73
Depreciation	22	21
Amortization of debt issue costs reported as interest expense		1
Equity earnings from equity investments (Note 3 and 4)	(43)	(42)
Distributions received from operating activities of equity investments (Note 3)	31	41
Change in operating working capital (Note 9)	5	6
Total cash generated from operations	90	100
Investing Activities
Capital expenditures	(7)	(11)
Total investing activities	(11)	(208)
Financing Activities
Common unit issuance, net (Note 6)	71
Common unit issuance subject to rescission, net (Note 6)		19
Long-term debt issued, net of discount (Note 5)		195
Long-term debt repaid (Note 5)	(50)	(25)
Total financing activities	(69)	117
Increase/(decrease) in cash and cash equivalents	10	9
Cash and cash equivalents, beginning of year	50	39
Cash and cash equivalents, end of year	60	48
Class B units
Financing Activities
Distributions paid (Note 6)	(22)	(12)
Common units and General Partner interest combined
Financing Activities
Distributions paid (Note 8)	(68)	(60)
Great Lakes
Cash Generated From Operations
Equity earnings from equity investments (Note 3 and 4)	(17)	(15)
Investing Activities
Investment/Acquisition of interests	(4)	(4)
Portland Natural Gas Transmission System
Cash Generated From Operations
Equity earnings from equity investments (Note 3 and 4)	$ (7)	(9)
Investing Activities
Investment/Acquisition of interests		$ (193)

XML

CONSOLIDATED STATEMENT OF CHANGES IN PARTNERS' EQUITY - 3 months ended Mar. 31, 2017 - USD ($) shares in Millions, $ in Millions	Limited Partners Common units	Limited Partners Class B units	General Partner	Accumulated Other Comprehensive Income	[1]	Common units ATM Equity Issuance Program	Total
Partners' Equity at beginning of year at Dec. 31, 2016	$ 1,002	$ 117	$ 27				$ 1,146
Partners' Equity at beginning of year (in units) at Dec. 31, 2016	67.4	1.9
Increase (Decrease) in Partners' Equity
Net income	$ 72		3				75
Other Comprehensive Loss				$ 1			1
ATM Equity Issuance, net (Note 6)	$ 69		2			$ 69	71
ATM Equity Issuance, net (Note 6) (in units)	1.2
Reclassification of common units no longer subject to rescission (Note 6 )	$ 19						19
Distributions	(64)	$ (22)	(4)				(90)
Partners' Equity at end of year at Mar. 31, 2017	$ 1,098	$ 95	$ 28	$ 1			$ 1,222
Partners' Equity at end of year (in units) at Mar. 31, 2017	68.6	1.9

[1] Income related to cash flow hedges reported in Accumulated Other Comprehensive Income and expected to be reclassified to Net Income in the next 12 months is estimated to be $1 million. These estimates assume constant interest rates over time; however, the amounts reclassified will vary based on actual value of interest rates at the date of settlement.

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CONSOLIDATED STATEMENT OF CHANGES IN PARTNERS' EQUITY (Parenthetical) $ in Millions	3 Months Ended
	Mar. 31, 2017 USD ($)
CONSOLIDATED STATEMENT OF CHANGES IN PARTNERS' EQUITY
Income expected to be reclassified to Net Income in the next 12 months	$ 1

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ORGANIZATION

3 Months Ended

Mar. 31, 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

3 Months Ended

Mar. 31, 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 months ended March 31, 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 financial statements and notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2016. That report contains a more comprehensive summary of the Partnership’s significant accounting policies. In the opinion of management, the accompanying financial statements contain all of the appropriate adjustments, all of which are normally recurring adjustments unless otherwise noted, and considered necessary to present fairly the financial position of the Partnership, the results of operations and cash flows for the respective periods. Our significant accounting policies are consistent with those disclosed in our Annual Report on Form 10-K for the year ended December 31, 2016, except as described in Note 3, Accounting Pronouncements.

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

3 Months Ended

Mar. 31, 2017

ACCOUNTING PRONOUNCEMENTS

ACCOUNTING PRONOUNCEMENTS

NOTE 3         ACCOUNTING PRONOUNCEMENTS

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

In August 2016, the 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 $8 million for the three months ended March 31, 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, and 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 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 five-step 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 is evaluating both methods of adoption as it works through its analysis.

The Partnership has identified all existing customer contracts that are within the scope of the new guidance and is in the process of analyzing individual contracts or groups of contracts on a segmented basis to identify any significant changes in how revenues are recognized as a result of implementing the new standard. As the Partnership continues its contract analysis, it will also quantify the impact, if any, on prior period revenues. The Partnership will address any system and process changes necessary to compile the information to meet the recognition and disclosure requirements of the new standard. As the Partnership is currently evaluating the impact of this standard, it has not yet determined the effect on its consolidated financial statements.

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 requires lessees to recognize most leases, including operating leases, on the balance sheet as lease assets and lease liabilities. The new standard does not make extensive changes to lessor accounting. Lessees may also be required to reassess assumptions associated with existing leases as well as to provide expanded qualitative and quantitative disclosures. The new guidance is effective January 1, 2019. The Partnership is currently identifying existing lease agreements that may have an impact on the Company’s consolidated financial statements as a result of adopting this 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.

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EQUITY INVESTMENTS

3 Months Ended

Mar. 31, 2017

EQUITY INVESTMENTS

EQUITY INVESTMENTS

NOTE 4         EQUITY INVESTMENTS

Northern Border, Great Lakes and PNGTS are regulated by FERC and are operated by TransCanada. The Partnership uses the equity method of accounting for its interests in its equity investees. The Partnership’s equity investments are held through our ILPs that are considered to be variable interest entities (VIEs) (refer to Note 16).

	Ownership		Equity Earnings		Equity Investments
	Interest at		Three months
(unaudited)	March 31,		ended March 31,		March 31,	December 31,
(millions of dollars)	2017		2017	2016	2017	2016
Northern Border(a)	50	%	19	18	441	444
Great Lakes	46.45	%	17	15	489	474
PNGTS (b)	49.9	%	7	9	132	126
			43	42	1,062	1,044

(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 additional 20 percent interest acquisition in April 2006.

(b) For the three months ending March 31, 2017 and 2016, the Partnership recorded no undistributed earnings from PNGTS.

Northern Border

The Partnership did not have undistributed earnings from Northern Border for the three months ended March 31, 2017 and 2016.

The summarized financial information for Northern Border is as follows:

(unaudited)
(millions of dollars)	March 31, 2017		December 31, 2016
ASSETS
Cash and cash equivalents	18		14
Other current assets	36		36
Plant, property and equipment, net	1,085		1,089
Other assets	15		14
	1,154		1,153
LIABILITIES AND PARTNERS’ EQUITY
Current liabilities	44		38
Deferred credits and other	29		28
Long-term debt, including current maturities, net	430		430
Partners’ equity
Partners’ capital	653		659
Accumulated other comprehensive loss	(2	)	(2	)
	1,154		1,153

	Three months ended
(unaudited)	March 31,
(millions of dollars)	2017		2016
Transmission revenues	74		74
Operating expenses	(17	)	(16	)
Depreciation	(15	)	(15	)
Financial charges and other	(4	)	(6	)
Net income	38		37

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 months ended March 31, 2017 and 2016.

The summarized financial information for Great Lakes is as follows:

(unaudited)
(millions of dollars)	March 31, 2017	December 31, 2016
ASSETS
Current assets	86	66
Plant, property and equipment, net	708	714
	794	780
LIABILITIES AND PARTNERS’ EQUITY
Current liabilities	31	40
Long-term debt, including current maturities, net	269	278
Partners’ equity	494	462
	794	780

	Three months ended
(unaudited)	March 31,
(millions of dollars)	2017		2016
Transmission revenues	63		61
Operating expenses	(14	)	(15	)
Depreciation	(7	)	(7	)
Financial charges and other	(5	)	(6	)
Net income	37		33

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DEBT AND CREDIT FACILITIES

3 Months Ended

Mar. 31, 2017

DEBT AND CREDIT FACILITIES

DEBT AND CREDIT FACILITIES

NOTE 5         DEBT AND CREDIT FACILITIES

(unaudited) (millions of dollars)	March 31, 2017	Weighted Average Interest Rate for the Quarter Ended March 31, 2017		December 31, 2016	Weighted Average Interest Rate for the Year Ended December 31, 2016
TC PipeLines, LP
Senior Credit Facility due 2021	110	2.03	%	160	1.72	%
2013 Term Loan Facility due July 2018	500	2.03	%	500	1.73	%
2015 Term Loan Facility due September 2018	170	1.93	%	170	1.63	%
4.65% Unsecured Senior Notes due 2021	350	4.65	%(a)	350	4.65	%(a)
4.375% Unsecured Senior Notes due 2025	350	4.375	%(a)	350	4.375	%(a)
GTN
5.29% Unsecured Senior Notes due 2020	100	5.29	%(a)	100	5.29	%(a)
5.69% Unsecured Senior Notes due 2035	150	5.69	%(a)	150	5.69	%(a)
Unsecured Term Loan Facility due 2019	65	1.73	%	65	1.43	%
Tuscarora
Unsecured Term Loan due 2019	10	1.91	%	10	1.64	%
3.82% Series D Senior Notes due 2017	12	3.82	%(a)	12	3.82	%(a)
	1,817			1,867
Less: unamortized debt issuance costs and debt discount	8			9
Less: current portion	23			23
	1,786			1,835

(a) Fixed interest rate

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 $110 million was outstanding at March 31, 2017 (December 31, 2016 - $160 million), leaving $390 million available for future borrowing. The LIBOR-based interest rate on the Senior Credit Facility was 2.04 percent at March 31, 2017 (December 31, 2016 — 1.92 percent).

As of March 31, 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 (December 31, 2016 — 2.31 percent). Prior to hedging activities, the LIBOR-based interest rate on 2013 Term Loan Facility was 2.04 percent at March 31, 2017 (December 31, 2016 — 1.87 percent).

The LIBOR-based interest rate on the 2015 Term Loan Facility was 1.93 percent at March 31, 2017 (December 31, 2016 — 1.77 percent).

The 2013 Term Loan Facility and the 2015 Term Loan Facility (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 4.04 to 1.00 as of March 31, 2017.

GTN’s Unsecured Senior Notes, along with GTN’s Unsecured Term Loan Facility contain a covenant that limits total debt to no greater than 70 percent of GTN’s total capitalization.  GTN’s total debt to total capitalization ratio at March 31, 2017 was 44.7 percent. The LIBOR-based interest rate on the GTN’s Unsecured Term Loan Facility was 1.73 percent at March 31, 2017 (December 31, 2016 — 1.57 percent).

Tuscarora’s Series D Senior Notes, which require yearly principal payments until maturity, are secured by Tuscarora’s transportation contracts, supporting agreements and substantially all of Tuscarora’s property. The note purchase agreements contain certain provisions that include, among other items, limitations on additional indebtedness and distributions to partners. The Series D Senior Notes contain a covenant that limits total debt to no greater than 45 percent of Tuscarora’s total capitalization.  Tuscarora’s total debt to total capitalization ratio at March 31, 2017 was 21.05 percent. Additionally, the Series D Senior Notes require 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 3.00 to 1.00. The ratio was 3.92 to 1.00 as of March 31, 2017.

The LIBOR-based interest rate on the Tuscarora’s Unsecured Term Loan Facility was 2.12 percent at March 31, 2017 (December 31, 2016 —1.90 percent).

At March 31, 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	23
2018	691
2019	43
2020	100
2021	460
Thereafter	500
	1,817

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PARTNERS' EQUITY

3 Months Ended

Mar. 31, 2017

PARTNERS' EQUITY

PARTNERS' EQUITY

NOTE 6         PARTNERS’ EQUITY

ATM equity issuance program (ATM program)

During the three months ended March 31, 2017, we issued 1,197,749 common units under our ATM program generating net proceeds of approximately $69 million, plus $2 million from the General Partner to maintain its effective two percent general partner interest. The commissions to our sales agents in the three months ended March 31, 2017 were approximately $704,000. 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 three months ended March 31, 2017, the threshold has not been exceeded.

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 2015 Annual Report. 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 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. No unitholder has claimed or attempted to exercise any rescission rights to date and these rights expire one year from the date of purchase of the unit.

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

At March 31, 2017, $19 million of the Common units subject to rescission on the consolidated balance sheet were reclassified back to equity. The amount reclassified represents the net proceeds received from the 0.4 million units sold from March 8, 2016 up to and including March 31, 2016 as the rescission rights attached to these units expired.

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NET INCOME PER COMMON UNIT

3 Months Ended

Mar. 31, 2017

NET INCOME PER COMMON UNIT

NET INCOME PER COMMON UNIT

NOTE 7         NET INCOME PER COMMON UNIT

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

The 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). During the three months ended March 31, 2017 and 2016, no amounts were allocated to the Class B units as the annual threshold of $20 million has  not been exceeded.

Net income per common unit was determined as follows:

(unaudited)	Three months ended March 31,
(millions of dollars, except per common unit amounts)	2017			2016
Net income attributable to controlling interests	75			73
Net income attributable to the General Partner	(1		)	(1		)
Incentive distributions attributable to the General Partner (a)	(2		)	(1		)
Net income attributable to common units	72			71
Weighted average common units outstanding (millions) — basic and diluted (b)	68.3			64.4
Net income per common unit — basic and diluted	$	1.05		$	1.10

(a) 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.

(b) Includes the common units subject to rescission. These units are treated as outstanding for financial reporting purposes. Refer to Note 6.

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CASH DISTRIBUTIONS TO COMMON UNITS

3 Months Ended

Mar. 31, 2017

CASH DISTRIBUTIONS TO COMMON UNITS

CASH DISTRIBUTIONS TO COMMON UNITS

NOTE 8         CASH DISTRIBUTIONS TO COMMON UNITS

During the three months ended March 31, 2017, the Partnership distributed $0.94 per common unit (March 31, 2016 — $0.89 per common unit) for a total of $68 million (March 31, 2016 - $60 million).

The distribution paid to our General Partner during the three months ended March 31, 2017 for its effective two percent general partner interest was $2 million along with an IDR payment of $2 million for a total distribution of $4 million (March 31, 2016 - $1 million for the effective two percent interest and a $1 million IDR payment).

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CHANGE IN OPERATING WORKING CAPITAL

3 Months Ended

Mar. 31, 2017

CHANGE IN OPERATING WORKING CAPITAL

CHANGE IN OPERATING WORKING CAPITAL

NOTE 9         CHANGE IN OPERATING WORKING CAPITAL

(unaudited)	Three months ended March 31,
(millions of dollars)	2017		2016
Change in accounts receivable and other	3		(1	)
Change in other current assets	2		—
Change in accounts payable and accrued liabilities	(3	)	3	(a)
Change in accounts payable to affiliates	(1	)	(1	)
Change in accrued interest	4		5
Change in operating working capital	5		6

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

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RELATED PARTY TRANSACTIONS

3 Months Ended

Mar. 31, 2017

RELATED PARTY TRANSACTIONS

RELATED PARTY TRANSACTIONS

NOTE 10       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. Total costs charged to the Partnership by the General Partner were $1 million for each of the three months ended March 31, 2017 and 2016.

As operator, 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.

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

	Three months ended
(unaudited)	March 31,
(millions of dollars)	2017	2016
Capital and operating costs charged by TransCanada’s subsidiaries to:
Great Lakes (a)	8	7
Northern Border (a)	10	6
PNGTS (a)	2	2
GTN (a)	7	6
Bison (b)	1	(1	)
North Baja	1	1
Tuscarora	1	1
Impact on the Partnership’s net income:
Great Lakes	3	3
Northern Border	3	3
PNGTS	1	1
GTN	7	5
Bison	1	1
North Baja	1	1
Tuscarora	1	1

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

(a) Represents 100 percent of the costs.

(b) In March 2016, Bison sold excess pipe (at cost) to an affiliate.

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 months ended March 31, 2017, Great Lakes earned 67 percent of transportation revenues from TransCanada and its affiliates (March 31, 2016 — 76 percent).

At March 31, 2017, $16 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 months ended March 31, 2017, Great Lakes recorded an estimated 2017 revenue sharing provision of $3.4 million. Great Lakes expects that a significant percentage of this refund will be paid to its affiliates.

On March 31, 2017, PNGTS declared its first quarter 2017 distribution of $5 million, of which the Partnership received its 49.9 percent share or $2 million on April 18, 2017.

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FAIR VALUE MEASUREMENTS

3 Months Ended

Mar. 31, 2017

FAIR VALUE MEASUREMENTS

FAIR VALUE MEASUREMENTS

NOTE 11       FAIR VALUE MEASUREMENTS

(a) Fair Value Hierarchy

Under 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 at March 31, 2017 and December 31, 2016 was $1,863 million and $1,908 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 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 March 31, 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 months ended March 31, 2017 and 2016. The change in fair value of interest rate derivative instruments recognized in other comprehensive income was a gain of $1 million for the three months ended March 31, 2017 (March 31, 2016 — loss of $2 million). For the three months ended March 31, 2017, the net realized loss related to the interest rate swaps was nil million and was included in financial charges and other (March 31, 2016 — nil million) (refer to Note 13).

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

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ACCOUNTS RECEIVABLE AND OTHER

3 Months Ended

Mar. 31, 2017

ACCOUNTS RECEIVABLE AND OTHER

ACCOUNTS RECEIVABLE AND OTHER

NOTE 12       ACCOUNTS RECEIVABLE AND OTHER

(unaudited)
(millions of dollars)	March 31, 2017	December 31, 2016
Trade accounts receivable, net of allowance of nil	31	34
Imbalance receivable from affiliates	1	2
Other	2	1
	34	37

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FINANCIAL CHARGES AND OTHER

3 Months Ended

Mar. 31, 2017

FINANCIAL CHARGES AND OTHER

FINANCIAL CHARGES AND OTHER

NOTE 13       FINANCIAL CHARGES AND OTHER

	Three months ended
(unaudited)	March 31,
(millions of dollars)	2017	2016
Interest Expense (a)	16	17
Net realized loss related to the interest rate swaps (b)	—	—
Other Income (b)	—	—
	16	17

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

(b) Nil million for both periods.

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CONTINGENCIES

3 Months Ended

Mar. 31, 2017

CONTINGENCIES

CONTINGENCIES

NOTE 14       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.  In July 2016, Essar Minnesota filed for Bankruptcy. The performance bond was released into the bankruptcy court proceedings.The Foreign Essar Affiliates have not filed for bankruptcy. The Eighth Circuit heard the appeal on October 20, 2016.  A decision on the appeal was received in December 2016 and the Eighth Circuit vacated Great Lakes’ judgment against Essar finding that there was no federal jurisdiction. Great Lakes filed a Request for Rehearing with the Eighth Circuit and it was denied in January 2017. Great Lakes currently is proceeding against Essar Minnesota in the bankruptcy court and its case against the Foreign Essar Affiliates in Minnesota state court remains pending. In April, after reaching agreement with creditors on an allowed claim, the Bankruptcy court approved Great Lakes’ claim in the amount of $31.5 million.

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REGULATORY

3 Months Ended

Mar. 31, 2017

REGULATORY

REGULATORY

NOTE 15       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- Great Lakes is required to file a new section 4 rate case with rates effective no later than January 1, 2018 as part of the settlement agreement with customers approved in November 2013. On March 31, 2017, Great Lakes submitted a General Section 4 Rate Filing and Tariff Changes with FERC. The rates proposed in the filing will become effective on October 1, 2017, subject to refund, if alternate resolution to the proceeding is not reached prior to that date. Great Lakes has initiated customer discussions regarding the details of the filing and will seek to achieve a mutually beneficial resolution through settlement with its customers.

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VARIABLE INTEREST ENTITIES

3 Months Ended

Mar. 31, 2017

VARIABLE INTEREST ENTITIES

VARIABLE INTEREST ENTITIES

NOTE 16       VARIABLE INTEREST ENTITIES

In the normal course of business, the Partnership must re-evaluate its legal entities under the newly effective consolidation guidance to determine if those that are considered to be VIEs are appropriately consolidated or if they should be accounted for under other US 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 and PNGTS 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 Sheet:

(unaudited)
(millions of dollars)	March 31, 2017		December 31, 2016
ASSETS (LIABILITIES) *
Accounts receivable and other	21		24
Inventories	6		6
Other current assets	3		4
Equity investments	1,062		1,044
Plant, property and equipment	844		847
Other assets	2		2
Accounts payable and accrued liabilities	(18	)	(20	)
Accounts payable to affiliates, net	(21	)	(28	)
Accrued interest	(5	)	(1	)
Current portion of long-term debt	(23	)	(23	)
Long-term debt	(313	)	(313	)
Other liabilities	(26	)	(25	)

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

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SUBSEQUENT EVENTS

3 Months Ended

Mar. 31, 2017

SUBSEQUENT EVENTS.

SUBSEQUENT EVENTS

NOTE 17       SUBSEQUENT EVENTS

Management of the Partnership has reviewed subsequent events through May 4, 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 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 and payable on May 15, 2017 to unitholders of record as of May 5, 2017. The declared distribution totaled $68 million and payable 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 of IDRs.

Northern Border declared its March 2017 distribution of $13 million on April 7, 2017, of which the Partnership received its 50 percent share or $7 million on April 28, 2017.

Great Lakes declared its first quarter 2017 distribution of $43 million on April 19, 2017, of which the Partnership received its 46.45 percent share or $20 million. The distribution was paid on May 1, 2017.

On April 24, 2017, Great Lakes reached an agreement on the terms of a potential new long-term transportation capacity contract with its affiliate, TransCanada.  The contract is for a term of 10 years with a total contract value of up to $758 million. The contract may commence as soon as November 1, 2017 and contains termination options beginning in year three. The contract is subject to the satisfaction of certain conditions, including but not limited to approval by the Canadian National Energy Board of an associated contract between TransCanada and third party customers. Great Lakes current rate structure includes a revenue sharing mechanism that requires Great Lakes to share with its customers certain percentages of any qualifying revenues earned above a calculated return on equity threshold. Additionally, Great Lakes is currently pursuing resolution of its March 31, 2017 General Section 4 Rate Filing (refer to Note 15). We cannot predict the cumulative impact of these circumstances to the Partnership’s earnings at this time.

On May 3, 2017, the Partnership entered into agreements to purchase from subsidiaries of TransCanada a 49.34 percent interest in Iroquois Gas Transmission System, L.P. (Iroquois), including a future option to acquire a further 0.66 percent in Iroquois, together with an additional 11.81 percent interest in PNGTS resulting in the Partnership owning a 61.71 percent in PNGTS (2017 Acquisition). The total purchase price of the 2017 Acquisition is $765 million comprised of $597 million in cash and the assumption of a total $168 million of proportional Iroquois and PNGTS debt.  The Partnership expects to fund the cash portion of the transaction through a combination of debt and equity issuances including proceeds from our ATM Program and borrowing under our Senior Credit Facility. The transaction is expected to close mid-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 is currently jointly owned by affiliates of TransCanada Corporation and Dominion Resources, Inc. via a joint venture.

The transaction was approved by the Board of Directors of the General Partner based on approval and recommendation from the Board’s Conflicts Committee, which is comprised entirely of independent directors. In connection with the transaction, Evercore served as independent financial advisor to the Conflicts Committee. Latham & Watkins served as legal counsel to the Conflicts Committee and Vinson & Elkins served as legal counsel to the Partnership. Wood Mackenzie served as commercial and market advisor to the Conflicts Committee.

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SIGNIFICANT ACCOUNTING POLICIES (Policies)

3 Months Ended

Mar. 31, 2017

SIGNIFICANT ACCOUNTING POLICIES

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)

3 Months Ended

Mar. 31, 2017

EQUITY INVESTMENTS

Schedule of equity investments and summarized financial information for equity investees

	Ownership		Equity Earnings		Equity Investments
	Interest at		Three months
(unaudited)	March 31,		ended March 31,		March 31,	December 31,
(millions of dollars)	2017		2017	2016	2017	2016
Northern Border(a)	50	%	19	18	441	444
Great Lakes	46.45	%	17	15	489	474
PNGTS (b)	49.9	%	7	9	132	126
			43	42	1,062	1,044

(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 additional 20 percent interest acquisition in April 2006.

(b) For the three months ending March 31, 2017 and 2016, the Partnership recorded no undistributed earnings from PNGTS.

Northern Border

EQUITY INVESTMENTS

Schedule of equity investments and summarized financial information for equity investees

(unaudited)
(millions of dollars)	March 31, 2017		December 31, 2016
ASSETS
Cash and cash equivalents	18		14
Other current assets	36		36
Plant, property and equipment, net	1,085		1,089
Other assets	15		14
	1,154		1,153
LIABILITIES AND PARTNERS’ EQUITY
Current liabilities	44		38
Deferred credits and other	29		28
Long-term debt, including current maturities, net	430		430
Partners’ equity
Partners’ capital	653		659
Accumulated other comprehensive loss	(2	)	(2	)
	1,154		1,153

	Three months ended
(unaudited)	March 31,
(millions of dollars)	2017		2016
Transmission revenues	74		74
Operating expenses	(17	)	(16	)
Depreciation	(15	)	(15	)
Financial charges and other	(4	)	(6	)
Net income	38		37

Great Lakes

EQUITY INVESTMENTS

Schedule of equity investments and summarized financial information for equity investees

(unaudited)
(millions of dollars)	March 31, 2017	December 31, 2016
ASSETS
Current assets	86	66
Plant, property and equipment, net	708	714
	794	780
LIABILITIES AND PARTNERS’ EQUITY
Current liabilities	31	40
Long-term debt, including current maturities, net	269	278
Partners’ equity	494	462
	794	780

	Three months ended
(unaudited)	March 31,
(millions of dollars)	2017		2016
Transmission revenues	63		61
Operating expenses	(14	)	(15	)
Depreciation	(7	)	(7	)
Financial charges and other	(5	)	(6	)
Net income	37		33

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DEBT AND CREDIT FACILITIES (Tables)

3 Months Ended

Mar. 31, 2017

DEBT AND CREDIT FACILITIES

Schedule of debt and credit facilities

(unaudited) (millions of dollars)	March 31, 2017	Weighted Average Interest Rate for the Quarter Ended March 31, 2017		December 31, 2016	Weighted Average Interest Rate for the Year Ended December 31, 2016
TC PipeLines, LP
Senior Credit Facility due 2021	110	2.03	%	160	1.72	%
2013 Term Loan Facility due July 2018	500	2.03	%	500	1.73	%
2015 Term Loan Facility due September 2018	170	1.93	%	170	1.63	%
4.65% Unsecured Senior Notes due 2021	350	4.65	%(a)	350	4.65	%(a)
4.375% Unsecured Senior Notes due 2025	350	4.375	%(a)	350	4.375	%(a)
GTN
5.29% Unsecured Senior Notes due 2020	100	5.29	%(a)	100	5.29	%(a)
5.69% Unsecured Senior Notes due 2035	150	5.69	%(a)	150	5.69	%(a)
Unsecured Term Loan Facility due 2019	65	1.73	%	65	1.43	%
Tuscarora
Unsecured Term Loan due 2019	10	1.91	%	10	1.64	%
3.82% Series D Senior Notes due 2017	12	3.82	%(a)	12	3.82	%(a)
	1,817			1,867
Less: unamortized debt issuance costs and debt discount	8			9
Less: current portion	23			23
	1,786			1,835

(a) Fixed interest rate

Schedule of principal repayments required on debt

(unaudited)
(millions of dollars)
2017	23
2018	691
2019	43
2020	100
2021	460
Thereafter	500
	1,817

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NET INCOME PER COMMON UNIT (Tables)

3 Months Ended

Mar. 31, 2017

NET INCOME PER COMMON UNIT

Schedule of net income per common unit

(unaudited)	Three months ended March 31,
(millions of dollars, except per common unit amounts)	2017			2016
Net income attributable to controlling interests	75			73
Net income attributable to the General Partner	(1		)	(1		)
Incentive distributions attributable to the General Partner (a)	(2		)	(1		)
Net income attributable to common units	72			71
Weighted average common units outstanding (millions) — basic and diluted (b)	68.3			64.4
Net income per common unit — basic and diluted	$	1.05		$	1.10

(a) 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.

(b) Includes the common units subject to rescission. These units are treated as outstanding for financial reporting purposes. Refer to Note 6.

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CHANGE IN OPERATING WORKING CAPITAL (Tables)

3 Months Ended

Mar. 31, 2017

CHANGE IN OPERATING WORKING CAPITAL

Schedule of change in operating working capital

(unaudited)	Three months ended March 31,
(millions of dollars)	2017		2016
Change in accounts receivable and other	3		(1	)
Change in other current assets	2		—
Change in accounts payable and accrued liabilities	(3	)	3	(a)
Change in accounts payable to affiliates	(1	)	(1	)
Change in accrued interest	4		5
Change in operating working capital	5		6

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

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RELATED PARTY TRANSACTIONS (Tables)

3 Months Ended

Mar. 31, 2017

RELATED PARTY TRANSACTIONS

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

	Three months ended
(unaudited)	March 31,
(millions of dollars)	2017	2016
Capital and operating costs charged by TransCanada’s subsidiaries to:
Great Lakes (a)	8	7
Northern Border (a)	10	6
PNGTS (a)	2	2
GTN (a)	7	6
Bison (b)	1	(1	)
North Baja	1	1
Tuscarora	1	1
Impact on the Partnership’s net income:
Great Lakes	3	3
Northern Border	3	3
PNGTS	1	1
GTN	7	5
Bison	1	1
North Baja	1	1
Tuscarora	1	1

(a) Represents 100 percent of the costs.

(b) In March 2016, Bison sold excess pipe (at cost) to an affiliate.

Summary of amount payable to related party for costs charged

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

(a) Represents 100 percent of the costs.

(b) In March 2016, Bison sold excess pipe (at cost) to an affiliate.

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ACCOUNTS RECEIVABLE AND OTHER (Tables)

3 Months Ended

Mar. 31, 2017

ACCOUNTS RECEIVABLE AND OTHER

Schedule of accounts receivable and other

(unaudited)
(millions of dollars)	March 31, 2017	December 31, 2016
Trade accounts receivable, net of allowance of nil	31	34
Imbalance receivable from affiliates	1	2
Other	2	1
	34	37

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FINANCIAL CHARGES AND OTHER (Tables)

3 Months Ended

Mar. 31, 2017

FINANCIAL CHARGES AND OTHER

Schedule of components of financial charges and other

	Three months ended
(unaudited)	March 31,
(millions of dollars)	2017	2016
Interest Expense (a)	16	17
Net realized loss related to the interest rate swaps (b)	—	—
Other Income (b)	—	—
	16	17

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

(b) Nil million for both periods.

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VARIABLE INTEREST ENTITIES (Tables)

3 Months Ended

Mar. 31, 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)	March 31, 2017		December 31, 2016
ASSETS (LIABILITIES) *
Accounts receivable and other	21		24
Inventories	6		6
Other current assets	3		4
Equity investments	1,062		1,044
Plant, property and equipment	844		847
Other assets	2		2
Accounts payable and accrued liabilities	(18	)	(20	)
Accounts payable to affiliates, net	(21	)	(28	)
Accrued interest	(5	)	(1	)
Current portion of long-term debt	(23	)	(23	)
Long-term debt	(313	)	(313	)
Other liabilities	(26	)	(25	)

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

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ORGANIZATION - Ownership Interests in Natural Gas Pipeline Systems (Details)	3 Months Ended
	Mar. 31, 2017 LimitedPartnership
ORGANIZATION
Number of intermediate limited partnerships through which pipeline assets are owned	3

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ACCOUNTING PRONOUNCEMENTS - Statement of Cash Flows (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
ACCOUNTING PRONOUNCEMENTS
Distributions received from operating activities of equity investments (Note 3)	$ 31	$ 41
Adjustment | ASU 2016-15, Statement of Cash Flows
ACCOUNTING PRONOUNCEMENTS
Cumulative distributions in excess of equity earnings		(8)
Distributions received from operating activities of equity investments (Note 3)		$ 8

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EQUITY INVESTMENTS (Details) - USD ($) $ in Millions	1 Months Ended	3 Months Ended
	Apr. 30, 2006	Mar. 31, 2017	Mar. 31, 2016	May 01, 2017	Apr. 28, 2017	Apr. 18, 2017	Dec. 31, 2016
EQUITY INVESTMENTS
Equity Earnings		$ 43	$ 42
Equity Investments		1,062					$ 1,044
LIABILITIES AND PARTNERS' EQUITY
Current portion of long-term debt		23					23
Amount borrowed			195
Great Lakes
EQUITY INVESTMENTS
Total cash call issued to fund debt repayment		$ 9
Northern Border
EQUITY INVESTMENTS
Ownership interest (as a percent)		50.00%			50.00%
Equity Earnings		$ 19	18
Equity Investments		441					444
Amortization period of transaction fee	12 years
Transaction fee	$ 10
Additional ownership interest acquired (as a percent)	20.00%
Assets
Cash and cash equivalents		18					14
Other current assets		36					36
Plant, property and equipment, net		1,085					1,089
Other assets		15					14
Assets, total		1,154					1,153
LIABILITIES AND PARTNERS' EQUITY
Current liabilities		44					38
Deferred credits and other		29					28
Long-term debt, including current maturities, net		430					430
Partners' equity
Partners' equity		653					659
Accumulated other comprehensive loss		(2)					(2)
Liabilities and Partners' Equity, total		1,154					1,153
Revenues (expenses)
Transmission revenues		74	74
Operating expenses		(17)	(16)
Depreciation		(15)	(15)
Financial charges and other		(4)	(6)
Net income		$ 38	37
Great Lakes
EQUITY INVESTMENTS
Ownership interest (as a percent)		46.45%		46.45%
Equity Earnings		$ 17	15
Equity Investments		489					474
Equity contribution		4	4
Assets
Current assets		86					66
Plant, property and equipment, net		708					714
Assets, total		794					780
LIABILITIES AND PARTNERS' EQUITY
Current liabilities		31					40
Long-term debt, including current maturities, net		269					278
Partners' equity
Partners' equity		494					462
Liabilities and Partners' Equity, total		794					780
Revenues (expenses)
Transmission revenues		63	61
Operating expenses		(14)	(15)
Depreciation		(7)	(7)
Financial charges and other		(5)	(6)
Net income		$ 37	33
Portland Natural Gas Transmission System
EQUITY INVESTMENTS
Ownership interest (as a percent)		49.90%				49.90%
Equity Earnings		$ 7	9
Equity Investments		132					$ 126
Undistributed earnings		$ 0
Equity contribution			$ 193

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DEBT AND CREDIT FACILITIES - Amounts Outstanding and Description of Terms (Details)	3 Months Ended		12 Months Ended
	Mar. 31, 2017 USD ($) entity	Mar. 31, 2016 USD ($)	Dec. 31, 2016 USD ($)
Credit facilities, short-term loan facility and long-term debt
Long-term debt	$ 1,817,000,000
Debt and credit facilities	1,817,000,000		$ 1,867,000,000
Less: unamortized debt issuance costs and debt discount	8,000,000		9,000,000
Less: current portion	23,000,000		23,000,000
Long-term debt	$ 1,786,000,000		1,835,000,000
Amount borrowed		$ 195,000,000
Senior Credit Facility and the Term Loan Facilities due in 2018
Credit facilities, short-term loan facility and long-term debt
Leverage ratio, actual (as a percent)	4.04%
Senior Credit Facility and the Term Loan Facilities due in 2018 | 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 and the Term Loan Facilities due in 2018 | 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 and the Term Loan Facilities due in 2018 | 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 and the Term Loan Facilities due in 2018 | 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	$ 110,000,000		$ 160,000,000
Weighted Average Interest Rate (as a percent)	2.03%		1.72%
Maximum borrowing capacity	$ 500,000,000
Amount outstanding under credit facility	110,000,000		$ 160,000,000
Remaining borrowing capacity	$ 390,000,000
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)	2.04%		1.92%
Term loan | TC PipeLines, LP 2013 Term Loan Facility due July 2018
Credit facilities, short-term loan facility and long-term debt
Debt and credit facilities	$ 500,000,000		$ 500,000,000
Weighted Average Interest Rate (as a percent)	2.03%		1.73%
Term loan | TC PipeLines, LP 2013 Term Loan Facility due July 2018 | LIBOR borrowings | LIBOR
Credit facilities, short-term loan facility and long-term debt
Debt interest rate, at period end (as a percent)	2.04%		1.87%
Term loan | TC PipeLines, LP 2013 Term Loan Facility due July 2018 | 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 September 2018
Credit facilities, short-term loan facility and long-term debt
Debt and credit facilities	$ 170,000,000		$ 170,000,000
Weighted Average Interest Rate (as a percent)	1.93%		1.63%
Term loan | TC PipeLines, LP 2015 Term Loan Facility due September 2018 | LIBOR
Credit facilities, short-term loan facility and long-term debt
Debt interest rate, at period end (as a percent)	1.93%		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%
Debt and credit facilities	$ 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%
Debt and credit facilities	$ 350,000,000		$ 350,000,000
Weighted Average Interest Rate (as a percent)	4.375%		4.375%
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%
Debt and credit facilities	$ 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%
Debt and credit facilities	$ 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	$ 65,000,000		$ 65,000,000
Weighted Average Interest Rate (as a percent)	1.73%		1.43%
Unsecured debt | Tuscarora Term Loan due 2019
Credit facilities, short-term loan facility and long-term debt
Debt and credit facilities	$ 10,000,000		$ 10,000,000
Weighted Average Interest Rate (as a percent)	1.91%		1.64%
Secured debt | Tuscarora 3.82% Series D Senior Notes due 2017
Credit facilities, short-term loan facility and long-term debt
Stated interest rate (as a percent)	3.82%		3.82%
Debt and credit facilities	$ 12,000,000		$ 12,000,000
Weighted Average Interest Rate (as a percent)	3.82%		3.82%
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)	1.73%		1.57%
Percentage of debt to total capitalization, actual	44.70%
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 debt | Tuscarora Term Loan due 2019 | LIBOR
Credit facilities, short-term loan facility and long-term debt
Debt interest rate, at period end (as a percent)	2.12%		1.90%
Tuscarora Gas Transmission Company | Unsecured debt | Tuscarora 3.82% Series D Senior Notes due 2017
Credit facilities, short-term loan facility and long-term debt
Percentage of debt to total capitalization, actual	21.05%
Debt Service Coverage, Actual (as a percent)	3.92%
Tuscarora Gas Transmission Company | Unsecured debt | Tuscarora 3.82% Series D Senior Notes due 2017 | Minimum
Credit facilities, short-term loan facility and long-term debt
Debt Service Coverage, covenant (as a percent)	300.00%
Tuscarora Gas Transmission Company | Unsecured debt | Tuscarora 3.82% Series D Senior Notes due 2017 | Maximum
Credit facilities, short-term loan facility and long-term debt
Percentage of debt to total capitalization, covenant	45.00%

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DEBT AND CREDIT FACILITIES - Principal Payments Required (Details) $ in Millions	Mar. 31, 2017 USD ($)
Principal repayments required on debt
2017	$ 23
2018	691
2019	43
2020	100
2021	460
Thereafter	500
Total debt	$ 1,817

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PARTNERS' EQUITY - ATM Equity Issuance Program (Details) - USD ($)	1 Months Ended	2 Months Ended	3 Months Ended	4 Months Ended	9 Months Ended
	Mar. 31, 2016	May 09, 2016	Mar. 31, 2017	Jun. 30, 2016	Sep. 30, 2016	Sep. 30, 2015	Dec. 31, 2016
Partners' Equity
Net proceeds from issuance of common units			$ 71,000,000
Common units subject to rescission			64,000,000				$ 83,000,000
General Partner
Partners' Equity
Net proceeds from issuance of common units			$ 2,000,000
TC PipeLines GP, Inc. | General Partner
Partners' Equity
Ownership interest in the Partnership (as a percent)			2.00%		2.00%	2.00%
ATM Equity Issuance Program | Common units
Partners' Equity
Units sold			1,197,749
Net proceeds from issuance of common units			$ 69,000,000
Sales agent commissions			704,000
Period of time for Section 5 Securities violations to be filed within				1 year
Reclassification of common unit issuance subject to rescission, net (in units)	400,000	1,600,000
Common units subject to rescission							$ 83,000,000
ATM Equity Issuance Program | TC PipeLines GP, Inc. | General Partner
Partners' Equity
Equity contribution			$ 2,000,000

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PARTNERS' EQUITY - Class B Units (Details) - USD ($)	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Class B units
Partners' Equity
Limited Partners, Distributions paid	$ 22,000,000	$ 12,000,000
Common units
Partners' Equity
Net income attributable to limited partners	$ 72,000,000	71,000,000
GTN | TransCanada | Distributions | Class B units
Partners' Equity
Portion of GTN's annual distributions to which the Class B units are entitled to receive a percentage share of the distributions above threshold (as a percent)	30.00%
Percentage applied to 30 percent of GTN's distributions above threshold through March 31, 2020	100.00%
Threshold of GTN's total distributable cash flows for payment to Class B units	$ 20,000,000
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%
Net income attributable to limited partners	$ 0	$ 0

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PARTNERS' EQUITY - Reclassification of units (Details) - USD ($) $ in Millions	1 Months Ended	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2017	Mar. 31, 2016
Partners' Equity
Common units issuance subject to rescission net			$ 19
Net proceeds from issuance of common units		$ 71
Reclassification of common units no longer subject to rescission (Note 6 )		$ 19
Common units
Partners' Equity
Reclassification of common units no longer subject to rescission (Note 6 )	$ 19

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NET INCOME PER COMMON UNIT - General Partner Effective Interest and Allocated Incentive Distributions (Details)	3 Months Ended	9 Months Ended
	Mar. 31, 2017	Sep. 30, 2016	Sep. 30, 2015
TC PipeLines GP, Inc. | General Partner
Partners' Equity
General partner interest (as a percent)	2.00%	2.00%	2.00%

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NET INCOME PER COMMON UNIT - Terms of Class B Unit Distributions and Determination of Net Income (Loss) per Common Unit (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	3 Months Ended		12 Months Ended
	Mar. 31, 2017	Mar. 31, 2016	Dec. 31, 2016
Net income (loss) per common unit
Net income attributable to controlling interests	$ 75	$ 73
Net income attributable to General Partner	(1)	(1)
Incentive distributions attributable to the General Partner	(2)	(1)
Common units
Net income (loss) per common unit
Net income attributable to limited partners	$ 72	$ 71
Weighted average common units outstanding - basic (in units)	68.3	64.4
Weighted average common units outstanding - diluted (in units)	68.3	64.4
Net income per common unit - basic (in dollars per unit)	$ 1.05	$ 1.10
Net income per common unit - diluted (in dollars per unit)	$ 1.05	$ 1.10
GTN | Class B units | TransCanada | Distributions
Net income (loss) per common unit
Net income attributable to limited partners	$ 0	$ 0
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%

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CASH DISTRIBUTIONS TO COMMON UNITS - Distributions Paid (Details) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended		9 Months Ended
	Mar. 31, 2017	Mar. 31, 2016	Sep. 30, 2016	Sep. 30, 2015
Common units
Distributions
Per Unit Distribution, paid (in dollars per unit)	$ 0.94	$ 0.89
Total cash distribution	$ 68	$ 60
Common units and General Partner interest combined
Distributions
Total distribution of general partner interest and IDR payment	4
TC PipeLines GP, Inc. | General Partner
Distributions
Total distribution for General Partner interest	$ 2	1
General partner interest (as a percent)	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	$ 2	$ 1

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CHANGE IN OPERATING WORKING CAPITAL - Components (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
CHANGE IN OPERATING WORKING CAPITAL
Change in accounts receivable and other	$ 3	$ (1)
Change in other current assets	2
Change in accounts payable and accrued liabilities	(3)	3
Change in accounts payable to affiliates	(1)	(1)
Change in accrued interest	4	5
Change in operating working capital	$ 5	$ 6

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CHANGE IN OPERATING WORKING CAPITAL - GTN's Carty Lateral Construction Accrual (Details) - USD ($) $ in Millions	3 Months Ended		12 Months Ended
	Mar. 31, 2017	Mar. 31, 2016	Dec. 31, 2015
Non-cash items
Capital expenditures	$ 7	$ 11
GTN
Non-cash items
Accruals for capital expenditures			$ 10
Capital expenditures		$ 10

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RELATED PARTY TRANSACTIONS (Details) - USD ($) $ in Millions			3 Months Ended		12 Months Ended
	Apr. 18, 2017	Mar. 31, 2017	Mar. 31, 2017	Mar. 31, 2016	Dec. 31, 2016	May 01, 2017	Apr. 28, 2017
Capital and operating costs charged to the pipeline systems and amount payable
Net amounts payable		$ 6.0	$ 6.0		$ 7.0
Amount included in receivables from related party		$ 1.0	1.0		2.0
Partnership distribution			90.0
Partnership's share of distributions			$ 31.0	$ 41.0
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			$ 3.4		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%
Portland Natural Gas Transmission System
Capital and operating costs charged to the pipeline systems and amount payable
Interest acquired (as a percent)	49.90%	49.90%	49.90%
Portland Natural Gas Transmission System | Distribution declared
Capital and operating costs charged to the pipeline systems and amount payable
Partnership distribution		$ 5.0
Portland Natural Gas Transmission System | Cash Distribution Paid
Capital and operating costs charged to the pipeline systems and amount payable
Partnership's share of distributions	$ 2.0
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
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			7.0	6.0
Impact on the Partnership's net income attributable to controlling interests			$ 7.0	$ 5.0
Percentage of capital and operating costs charged			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%
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	$ 6.0
Percentage of capital and operating costs charged			100.00%	100.00%
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
Percentage of capital and operating costs charged			100.00%	100.00%
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
Percentage of capital and operating costs charged			100.00%	100.00%
TransCanada's subsidiaries | Bison
Capital and operating costs charged to the pipeline systems and amount payable
Net amounts payable					1.0
TransCanada's subsidiaries | Bison | Capital and operating costs
Capital and operating costs charged to the pipeline systems and amount payable
Costs charged			$ 1.0
Revenue, net of costs charged				$ (1.0)
Impact on the Partnership's net income attributable to controlling interests			1.0	$ 1.0
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%
Amount included in receivables from related party		16.0	$ 16.0		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			$ 8.0	$ 7.0
Percentage of capital and operating costs charged			100.00%	100.00%
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
Impact on the Partnership's net income attributable to controlling interests			1.0	1.0
TransCanada's subsidiaries | Tuscarora Gas Transmission Company
Capital and operating costs charged to the pipeline systems and amount payable
Net amounts payable		$ 1.0	1.0		$ 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
Impact on the Partnership's net income attributable to controlling interests			1.0	1.0
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			$ 3.0	$ 3.0
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			67.00%	76.00%
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			$ 3.0	$ 3.0
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

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FAIR VALUE MEASUREMENTS - Estimated Fair Value of Debt (Details) - USD ($) $ in Millions	Mar. 31, 2017	Dec. 31, 2016
Fair Value | Level 2
Financial Instruments
Fair value of debt	$ 1,863	$ 1,908

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FAIR VALUE MEASUREMENTS - Interest Rate Swaps (Details) - Interest rate swaps - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016	Dec. 31, 2016
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%
Hedges of cash flows
Interest rate derivatives
Change in fair value of interest rate derivative instruments recognized in other comprehensive income (loss)	$ 1	$ (2)
Hedges of cash flows | Financial charges and other.
Interest rate derivatives
Net realized loss related to the interest rate swaps	0	$ 0
Hedges of cash flows | Recurring fair value measurement | Level 2
Interest rate derivatives
Fair value of derivatives, net	2
Designated as hedge | Recurring fair value measurement | Level 2
Interest rate derivatives
Fair value of derivative asset, gross	$ 2
Fair value of derivative liability, gross			$ 0
Designated as hedge | Hedges of cash flows | Level 2
Interest rate derivatives
Fair value of derivative asset, gross			1
Fair value of derivative liability, gross			$ 1

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ACCOUNTS RECEIVABLE AND OTHER (Details) - USD ($) $ in Millions	Mar. 31, 2017	Dec. 31, 2016
ACCOUNTS RECEIVABLE AND OTHER
Trade accounts receivable, net of allowance of nil	$ 31	$ 34
Imbalance receivable from affiliates	1	2
Other	2	1
Accounts receivable and other	34	37
Trade accounts receivable, allowance	$ 0	$ 0

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FINANCIAL CHARGES AND OTHER (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
FINANCIAL CHARGES AND OTHER
Interest Expense	$ 16	$ 17
Financial charges and other	$ 16	$ 17

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

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REGULATORY (Details)	Jan. 06, 2017 item
North Baja Pipeline, LLC | FERC
Goodwill and Regulatory Matters
Number of compression units	2

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VARIABLE INTEREST ENTITIES - Consolidated VIEs (Details) - USD ($) $ in Millions	Mar. 31, 2017	Dec. 31, 2016
ASSETS (LIABILITIES)
Accounts receivable and other	$ 34	$ 37
Inventories	7	7
Other current assets	4	5
Equity investments	1,062	1,044
Plant, property and equipment	1,866	1,881
Other assets	1	1
Accounts payable and accrued liabilities	(24)	(27)
Accounts payable to affiliates	(6)	(7)
Accrued interest	(13)	(9)
Current portion of long-term debt	(23)	(23)
Long-term debt	(1,786)	(1,835)
Other liabilities	(28)	(28)
Consolidated VIEs | Restricted VIEs
ASSETS (LIABILITIES)
Accounts receivable and other	21	24
Inventories	6	6
Other current assets	3	4
Equity investments	1,062	1,044
Plant, property and equipment	844	847
Other assets	2	2
Accounts payable and accrued liabilities	(18)	(20)
Accounts payable to affiliates	(21)	(28)
Accrued interest	(5)	(1)
Current portion of long-term debt	(23)	(23)
Long-term debt	(313)	(313)
Other liabilities	$ (26)	$ (25)

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SUBSEQUENT EVENTS - Distributions (Details) - USD ($) $ / shares in Units, $ in Millions											3 Months Ended		9 Months Ended
	May 15, 2017	May 03, 2017	May 01, 2017	Apr. 28, 2017	Apr. 25, 2017	Apr. 24, 2017	Apr. 19, 2017	Apr. 18, 2017	Apr. 07, 2017	Mar. 31, 2017	Mar. 31, 2017	Mar. 31, 2016	Sep. 30, 2016	Sep. 30, 2015
Distributions
Partnership distribution											$ 90.0
Partnership's share of distributions											$ 31.0	$ 41.0
Northern Border
Distributions
Ownership interest (as a percent)				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)								49.90%		49.90%	49.90%
Distribution declared | Portland Natural Gas Transmission System
Distributions
Partnership distribution										$ 5.0
Cash Distribution Paid | Portland Natural Gas Transmission System
Distributions
Partnership's share of distributions								$ 2.0
Subsequent Events
Distributions
Total cash distribution	$ 68.0
Subsequent Events | Distribution declared | Northern Border
Distributions
Partnership distribution									$ 13.0
Subsequent Events | Distribution declared | Great Lakes
Distributions
Partnership distribution							$ 43.0
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			$ 20.0
Common units and General Partner interest combined
Distributions
Total distribution of general partner interest and IDR payment											$ 4.0
General Partner
Distributions
Partnership distribution											4.0
TC PipeLines GP, Inc. | Subsequent Events
Distributions
General partner cash distributions					$ 3.0
Ownership interest (as a percent)					2.00%
Total Distribution For General Partner Interest					$ 1.0
TC PipeLines GP, Inc. | Common units and General Partner interest combined
Distributions
General Partner IDRs paid											$ 2.0	1.0
TC PipeLines GP, Inc. | General Partner
Distributions
Ownership interest in the Partnership (as a percent)											2.00%		2.00%	2.00%
Total Distribution For General Partner Interest											$ 2.0	1.0
TC PipeLines GP, Inc. | General Partner | Subsequent Events | Distribution declared
Distributions
Distribution declared for IDRs					$ 2.0
TransCanada | Subsequent Events | Great Lakes
Distributions
Contract term						10 years
Total contract value						$ 758.0
Forecast | Subsequent Events | Iroquois
Distributions
Ownership interest (as a percent)		49.34%
Future option to acquire (as a percent)		0.66%
Forecast | Subsequent Events | Portland Natural Gas Transmission System
Distributions
Interest acquired by Partnership (as a percent)		11.81%
Forecast | Subsequent Events | Portland Natural Gas Transmission System
Distributions
Ownership interest, including acquired interest (as a percent)		61.71%
Forecast | Subsequent Events | Portland Natural Gas Transmission System | Portland Natural Gas Transmission System And Iroquois Acquisition
Distributions
Purchase price		$ 765.0
Cash consideration		597.0
Assumption of proportional debt		$ 168.0
Common units
Distributions
Total cash distribution											$ 68.0	$ 60.0
Number of units										68,600,000	68,600,000	64,700,000
Common units | Subsequent Events
Distributions
Per Unit Distribution, declared (in dollars per unit)					$ 0.94
Distribution declared					$ 65.0
Common units | Limited Partners
Distributions
Partnership distribution											$ 64.0
Common units | TC PipeLines GP, Inc. | Subsequent Events
Distributions
Limited Partners, Distributions paid	5.0
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
Class B units
Distributions
Distribution declared											22.0
Limited Partners, Distributions paid											22.0	$ 12.0
Class B units | Limited Partners
Distributions
Partnership distribution											$ 22.0