8-K

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C.  20549

FORM 8-K

CURRENT REPORT

Pursuant To Section 13 or 15(d) of the Securities Exchange Act of 1934

Date of Report (Date of earliest event reported) August 3, 2017

TC PipeLines, LP

(Exact name of registrant as specified in its charter)

Delaware	001-35358	52-2135448
(State or other jurisdiction of incorporation)	(Commission File Number)	(IRS Employer Identification No.)

700 Louisiana Street, Suite 700 Houston, TX	77002-2761
(Address of principal executive offices)	(Zip Code)

Registrant’s telephone number, including area code (877) 290-2772

(Former name or former address if changed since last report)

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions

oWritten communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

oSoliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

oPre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

oPre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

Indicate by check mark whether the registrant is an emerging growth company as defined in Rule 405 of the Securities Act of 1933 (§230.405 of this chapter) or Rule 12b-2 of the Securities Exchange Act of 1934 (§240.12b-2 of this chapter).

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

Item 8.01.  Other Events

On June 1, 2017, TC PipeLines, LP (the “Partnership”) filed a Current Report on Form 8-K to report under Item 2.01 thereof that the Partnership, through its subsidiary TC PipeLines Intermediate Limited Partnership, completed the previously announced acquisitions of a 49.34 percent interest in Iroquois Gas Transmission System, L.P. (“Iroquois”) from subsidiaries of TransCanada Corporation (“TransCanada”)  together with TransCanada’s remaining 11.81% percent interest in the Portland Natural Gas Transmission System (“PNGTS”) for a total purchase price of approximately $765 million, plus working capital adjustments.

On January 4, 2016, the Partnership filed a Current Report on Form 8-K to report under Item 2.01 thereof that the Partnership, through its subsidiary TC PipeLines Intermediate Limited Partnership, completed on January 1, 2016, the previously announced $ 228 million acquisition of a 49.9 percent interest in PNGTS.

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

The initial acquisition of a 49.9 percent interest in PNGTS on January 1, 2016 and additional 11.81 percent on June 1, 2017 (collectively, the PNGTS Acquisitions), which resulted in the Partnership owning 61.71 percent of PNGTS were accounted for as transaction between entities under common control, which are required to be accounted for as if the PNGTS Acquisitions had occurred at the beginning of the year, with financial statements for prior periods retrospectively recast to furnish comparative information. Exhibits 99.1 to 99.6, included in this Current Report on Form 8-K, give retroactive effect of the PNGTS Acquisitions through the consolidation of PNGTS for all the periods presented.

The Partnership’s Annual Report on Form 10-K for the year ended December 31, 2016 filed with the SEC on February 28, 2017 (the “2016 Form 10-K”) and its Quarterly Report on Form 10-Q for the quarter ended March 31, 2017 (the “March 31, 2017 Form 10-Q”), filed with the SEC on May 4, 2017 are hereby recast by this Current Report on Form 8-K as follows:

2016 Form 10-K:

·The Selected Financial Data included herein as Exhibit 99.1 supersedes Part II, Item 6 of the 2016 Form 10-K

·The Partnership’s Audited Consolidated Financial Statements and Notes thereto for the year ended December 31, 2016 included herein as Exhibit 99.2 supersede the Partnership’s 2016 Audited Consolidated Financial Statements and Notes thereto  for the year ended December 31, 2016 included in Part II, Item 8 of the 2016 Form 10-K

·The Management’s Discussion and Analysis of Financial Condition and Results of Operations and the Quantitative and Qualitative Disclosures About Market Risk included herein as Exhibit 99.3 supersede Part II, Item 7 and Item 7A, respectively of the 2016 Form 10-K

·The Computation of Ratio of Earnings to Fixed Charges included herein as Exhibit 99.4 supersedes the Computation of Ratio of Earnings to Fixed Charges filed as Exhibit 12.1 of the 2016 Form 10-K

March 31, 2017 Form 10-Q:

·The Partnership’s Unaudited Consolidated Financial Statements and Notes thereto for the quarter ended March 31, 2017 included herein as Exhibit 99.5 supersede Part I, Item 1 of the March 31, 2017 Form 10-Q

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·The Management’s Discussion and Analysis of Financial Condition and Results of Operations and the Quantitative and Qualitative Disclosures About Market Risk included herein as Exhibit 99.6 supersede Part I, Item 2 and 3, respectively of the March 31, 2017 Form 10-Q

When the Partnership acquires an asset or an investment from TransCanada, which will be accounted for by the equity method, the financial information is not required to be recast and the transaction is accounted for prospectively from the date of the acquisition. Accordingly, the Partnership’s acquisition of a 49.34 percent interest in Iroquois was accounted prospectively and did not form part of the consolidated financial statements included as Exhibits 99.2 and 99.5.

Item 9.01.  Financial Statements and Exhibits

(d)Exhibits

Exhibit No.	Description
23.1	TC Pipelines, LP Consent of Independent Registered Public Accounting Firm
99.1	Recast 2016 Form 10-K Item 6. Selected Financial Data
99.2	Recast Audited Consolidated Financial Statements and Notes thereto for the year ended December 31, 2016
99.3	Recast 2016 Form 10-K Item 7-Management’s Discussion and Analysis of Financial Condition and Results of Operations and Item 7A- Quantitative and Qualitative disclosures About Market Risk
99.4	Recast Computation of Ratio of Earnings to Fixed Charges
99.5	Recast Unaudited Consolidated Financial Statements and Notes thereto for the quarter ended March 31, 2017
99.6	Recast March 31, 2017 Form 10-Q Part 1, Item 2- Management’s Discussion and Analysis of Financial Condition and Results of Operations and Item 3- Quantitative and Qualitative Disclosures About Market Risk
101	The consolidated financial statements and notes thereto included in this Current Report on Form 8-K of TC PipeLines, LP formatted in eXtensible Business Reporting Language (XBRL)

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SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.

TC PipeLines, LP
by: TC PipeLines GP, Inc.,
its general partner
By:	/s/ Nathaniel A. Brown
	Controller
	TC PipeLines GP, Inc. (Principal Financial Officer)

Dated:  August 3, 2017

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EXHIBIT INDEX

Exhibit No.	Description
23.1	TC Pipelines, LP Consent of Independent Registered Public Accounting Firm
99.1	Recast 2016 Form 10-K Item 6. Selected Financial Data
99.2	Recast Audited Consolidated Financial Statements and Notes thereto for the year ended December 31, 2016
99.3	Recast 2016 Form 10-K Item 7-Management’s Discussion and Analysis of Financial Condition and Results of Operations and Item 7A- Quantitative and Qualitative disclosures About Market Risk
99.4	Recast Computation of Ratio of Earnings to Fixed Charges
99.5	Recast Unaudited Consolidated Financial Statements and Notes thereto for the quarter ended March 31, 2017
99.6	Recast March 31, 2017 Form 10-Q Part 1, Item 2- Management’s Discussion and Analysis of Financial Condition and Results of Operations and Item 3- Quantitative and Qualitative disclosures About Market Risk
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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EX-23.1

Exhibit 23.1

Consent of Independent Registered Public Accounting Firm

The Board of Directors of TC PipeLines GP, Inc.

General Partner of TC PipeLines, LP:

We consent to the incorporation by reference in the registration statements (Nos. 333-211907 and 333-213024) on Form S-3 of TC PipeLines, LP of our report dated August 3, 2017, with respect to the consolidated balance sheets of TC PipeLines, LP and subsidiaries as of December 31, 2016 and 2015, and the related consolidated statements of income, comprehensive income, cash flows and  changes in partners’ equity for each of the years in the three-year period ended December 31, 2016, which report appears in the Form 8-K of TC PipeLines, LP dated August 3, 2017.

Our report dated August 3, 2017 refers to a change in accounting for the classification of distributions received from equity method investments.

/s/ KPMG LLP

Houston, Texas

August 3, 2017

EX-99.1

Exhibit 99.1

Item 6.Selected Financial Data

The selected financial data should be read in conjunction with the Audited Consolidated Financial Statements, including the Notes thereto, for the year ended December 31, 2016  included as Exhibit 99.2 of  this Current Report on Form 8-K and Item 7.  “Management’s Discussion and Analysis of Financial Condition and Results of Operations” included as Exhibit 99.3 of this Current Report on Form 8K.

(millions of dollars, except per common unit amounts)	2016(a)		2015(a)			2014(a)		2013(a)(b)		2012(a) (b)
Income Data (for the year ended December 31)
Transmission revenues	426		417			410		410		393
Equity earnings (c)	97		97			88		67		99
Impairment of equity-method investment (d)	—		(199		)	—		—		—
Net income	263		58			241		221		244
Net income attributable to controlling interests	248		37			195		174		201
Basic and diluted net (loss) income per common unit (e)	3.21		$	(0.03	)	$	2.67	$	2.13	$	2.51
Cash Flow Data (for the year ended December 31)
Cash distribution declared per common unit	$	3.71	$	3.51		$	3.33	$	3.21	$	3.11
Balance Sheet Data (at December 31)
Total assets (f)	3,354		3,459			3,802		3,867		3,912
Long-term debt (including current maturities) (f)	1,911		1,971			1,778		1,679		1,134
Partners’ equity	1,272		1,391			1,818		2,013		2,641

(a)Recast information to consolidate PNGTS for all periods presented as a result of an additional 11.81 percent in PNGTS that was acquired from a subsidiary of TransCanada on June 1, 2017. Prior to this transaction, the Partnership owned a 49.9 percent interest in PNGTS that was acquired from TransCanada on January 1, 2016.  Please read Note 2- Significant Accounting policies-Basis of Presentation section of  the Notes to the Consolidated Financial Statements included in Exhibit 99.2 of this Current Report on Form 8K.

(b)Recast information to consolidate GTN and Bison for all periods presented as a result of additional 45 percent membership interests in each of GTN and Bison that were acquired from subsidiaries of TransCanada in 2013 resulting in a 70 percent ownership in each. Please read Note 2, Significant Accounting Policies-Basis of Presentation section of the Notes to the Consolidated Financial Statements included in Exhibit 99.2 of this Current Report on Form 8K.

(c)Equity earnings represent our share in investee’s earnings and do not include any impairment charge on our equity investments.

(d)During the fourth quarter of 2015, we recognized an impairment charge on our investment in Great Lakes amounting to $199 million. No other impairment was recognized during the periods presented. Please read Note 4-Equity Investments, Notes to the Consolidated Financial Statements included in Exhibit 99.2 of this Current Report on Form 8K.

(e)Represents basic and diluted net income per common unit prior to recast.

(f)As a result of the application of ASU No. 2015-03 “Interest-Imputation of Interest” and similar to the presentation of debt discounts, debt issuance costs previously reported as other assets in the balance sheet were reclassified as an offset against their respective debt liabilities.

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EX-99.2

Exhibit 99.2

Report of Independent Registered Public Accounting Firm

The Board of Directors and Unitholders

TC PipeLines GP, Inc. General Partner of TC PipeLines, LP:

We have audited the accompanying consolidated balance sheets of TC PipeLines, LP (a Delaware limited partnership) and subsidiaries as of December 31, 2016 and 2015, and the related consolidated statements of income, comprehensive income, changes in partners’ equity, and cash flows for each of the years in the three-year period ended December 31, 2016. These consolidated financial statements are the responsibility of management of the General Partner of TC PipeLines, LP. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of TC PipeLines, LP and subsidiaries as of December 31, 2016 and 2015, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2016, in conformity with U.S. generally accepted accounting principles.

As discussed in Note 3 to the financial statements, TC PipeLines, LP changed its method of accounting for the classification of distributions received from equity method investments effective January 1, 2014 due to the adoption of FASB ASU 2016-15, Statement of Cash Flows: Classification of Certain Cash Receipts and Cash Payments.

/s/ KPMG LLP

Houston, Texas
August 3, 2017

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TC PIPELINES, LP

CONSOLIDATED BALANCE SHEETS

December 31 (millions of dollars)	2016(a)		2015(a)
ASSETS
Current Assets
Cash and cash equivalents	64		55
Accounts receivable and other (Note 19)	47		41
Inventories	7		7
Other	7		3
	125		106
Equity investments (Note 4)	918		965
Plant, property and equipment, net (Note 5)	2,180		2,257
Goodwill	130		130
Other assets (Note 3)	1		1
	3,354		3,459
LIABILITIES AND PARTNERS’ EQUITY
Current Liabilities
Accounts payable and accrued liabilities	29		34
Accounts payable to affiliates (Note 16)	8		8
Accrued interest	10		8
Distributions payable	3		10
Current portion of long-term debt (Note 7)	52		36
	102		96
Long-term debt (Note 7)	1,859		1,935
Deferred state income taxes (Note 23)	10		10
Other liabilities (Note 8)	28		27
	1,999		2,068
Common units subject to rescission (Note 9)	83		—
Partners’ Equity (Note 9)
Common units	1,002		1,021
Class B units	117		107
General partner	27		25
Accumulated other comprehensive loss (AOCL)(Note 10)	(2	)	(4	)
Controlling interests	1,144		1,149
Non—controlling interest	97		91
Equity of former parent of PNGTS	31		151
	1,272		1,391
	3,354		3,459
Contingencies (Note 21)
Variable Interest Entities (Note 22)
Subsequent Events (Note 24)

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

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

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TC PIPELINES, LP

CONSOLIDATED STATEMENTS OF INCOME

Year ended December 31 (millions of dollars except per common unit amounts)	2016(a)			2015(a)			2014(a)
Transmission revenues	426			417			410
Equity earnings (Note 4)	97			97			88
Impairment of equity-method investment (Note 4)	—			(199		)	—
Operation and maintenance expenses	(58		)	(61		)	(61		)
Property taxes	(27		)	(27		)	(28		)
General and administrative	(7		)	(9		)	(9		)
Depreciation	(96		)	(95		)	(96		)
Financial charges and other (Note 11)	(71		)	(63		)	(61		)
Net income before taxes	264			60			243
Income taxes (Note 23)	(1		)	(2		)	(2		)
Net Income	263			58			241
Net income attributable to non-controlling interests	15			21			46
Net income attributable to controlling interests	248			37			195
Net income (loss) attributable to controlling interest allocation (Note 12)
Common units	211			(2		)	168
General Partner	11			3			4
TransCanada and its subsidiaries	26			36			23
	248			37			195
Net income (loss) per common unit (Note 12) — basic and diluted (b)	$	3.21		$	(0.03	)	$	2.67
Weighted average common units outstanding (millions) — basic and diluted	65.7			63.9			62.7
Common units outstanding, end of year (millions)	67.4			64.3			63.6

TC PIPELINES, LP

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

Year ended December 31 (millions of dollars)	2016(a)		2015(a)	2014(a)
Net income	263		58	241
Other comprehensive income
Change in fair value of cash flow hedges (Notes 10 and 18)	3		—	(1	)
Reclassification to net income of gains and losses on cash flow hedges (Note 10)	(2	)	—	—
Amortization of realized loss on derivative instrument (Notes 10 and 18)	1		1	1
Comprehensive income	265		59	241
Comprehensive income attributable to non-controlling interests	16		21	46
Comprehensive income attributable to controlling interests	249		38	195

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

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

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

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TC PIPELINES, LP

CONSOLIDATED STATEMENTS OF CASH FLOWS

Year ended December 31 (millions of dollars)	2016 (a)		2015 (a)		2014 (a)
Cash Generated From Operations
Net income	263		58		241
Depreciation	96		95		96
Impairment of equity-method investment (Note 4)			199		—
Amortization of debt issue costs reported as interest expense (Note 11)	2		1		1
Amortization of realized loss on derivative instrument (Note 18)	1		1		1
Accrual of costs related to acquisition of 49.9% interest in PNGTS (Note 6)	—		2		—
Equity earnings from equity investments (Note 4)	(97	)	(97	)	(88	)
Distributions received from operating activities of equity investments (Note 3)	153		119		115
Provision for deferred state income taxes (Note 23)	—		4		(1	)
Provision for rate refund (Note 2)	—		(101	)	23
Equity allowance for funds used during construction	—		(1	)	—
Change in operating working capital (Note 14)	(1	)	(20	)	29
	417		260		417
Investing Activities
Investment in Great Lakes (Note 4)	(9	)	(9	)	(9	)
Acquisition of 49.9 percent interest in PNGTS (Note 6)	(193	)	—		—
Acquisition of the remaining 30 percent interest in GTN (Note 6)	—		(264	)	—
Acquisition of the remaining 30 percent interest in Bison (Note 6)	—		—		(217	)
Adjustment to the 2013 Acquisition	—		—		(25	)
Capital expenditures	(29	)	(54	)	(10	)
Other	1		1		—
	(230	)	(326	)	(261	)
Financing Activities
Distributions paid (Note 13)	(250	)	(228	)	(212	)
Distributions paid to Class B units (Note 9 and 13)	(12	)	—		—
Distributions paid to non-controlling interests	(12	)	(21	)	(60	)
Distributions paid to former parent of PNGTS	(9	)	(19	)	(16	)
Common unit issuance, net (Note 9)	84		44		73
Common unit issuance subject to rescission, net (Note 9)	83		—		—
Equity contribution by the General Partner (Note 6)	—		2		—
Long-term debt issued, net of discount (Note 7)	209		618		35
Short-term loan issued (Note 7)	—		—		170
Long-term debt repaid (Note 7)	(270	)	(425	)	(109	)
Debt issuance costs	(1	)	(3	)	—
	(178	)	(32	)	(119	)
Increase/(decrease) in cash and cash equivalents	9		(98	)	37
Cash and cash equivalents, beginning of year	55		153		116
Cash and cash equivalents, end of year	64		55		153
Interest payments paid	66		59		53
State income taxes paid	2		2		—
Supplemental information about non-cash investing and financing activities
Accrual for costs related to construction of GTN’s Carty Lateral (Note 14)	—		10		—
Issuance of Class B units to TransCanada (Note 9)	—		95		—

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

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

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TC PIPELINES, LP

CONSOLIDATED STATEMENT OF CHANGES IN PARTNERS’ EQUITY

	Limited Partners						General				Non- Controlling		PNGTS		Total Equity
	Common Units			Class B Units			Partner		AOCL (a) (c)		Interest (d)		(c) (d)		(d)
	(millions of units)	(millions of dollars)		(millions of units)	(millions of dollars)		(millions of dollars)		(millions of dollars)		(millions of dollars)		(millions of dollars)		(millions of dollars)
Partners’ Equity at December 31, 2013 (d)	62.3	1,322		—	—		28		(5	)	526		142		2,013
Net income (d)	—	168		—	—		4		—		46		23		241
Other Comprehensive Loss, net(d)	—	—		—	—		—		—		—				—
ATM Equity Issuance, net (Note 9)	1.3	71		—	—		2		—		—				73
Acquisition of the remaining interest in Bison (Note 6)	—	(29	)	—	—		—		—		(188	)			(217	)
Distributions (d)	—	(207	)	—	—		(5	)	—		(61	)	(19	)	(292	)
Partners’ Equity at December 31, 2014 (d)	63.6	1,325		—	—		29		(5	)	323		146		1,818
Issuance of Class B Units (Note 6 and 9)	—	—		1.9	95		—		—		—				95
Net income (loss) (d)	—	(2	)	—	12		3		—		21		24		58
Other Comprehensive Loss, net(d)	—	—		—	—		—		1		—				1
ATM Equity Issuance, net (Note 9)	0.7	43		—	—		1		—		—				44
Acquisition of the remaining interest in GTN (Note 6)	—	(124	)	—	—		(3	)	—		(232	)			(359	)
Equity Contribution (Note 6)	—	—		—	—		2		—		—				2
Distributions (d)	—	(221	)	—	—		(7	)	—		(21	)	(19	)	(268	)
Partners’ Equity at December 31, 2015(d)	64.3	1,021		1.9	107		25		(4	)	91		151		1,391
Net income (d)	—	211		—	22		11		—		15		4		263
Other Comprehensive Income, net(d)	—	—		—	—		—		2		1				3
Common unit issuance subject to rescission, net (b)  (Note 9)	1.6	81		—	—		2		—		—				83
Reclassification of common unit issuance subject to rescission, net (b) (Note 9)		(81	)	—	—		(2	)	—		—				(83	)
ATM Equity Issuance, net (Note 9)	1.5	82		—	—		2		—		—				84
Acquisition of 49.9 percent interest in PNGTS (Note 6)	—	(72	)	—	—		(1	)	—		—				(73	)
Distributions (d)	—	(240	)	—	(12	)	(10	)	—		(10	)	(4	)	(276	)
Former parent carrying amount of PNGTS(d)													(120	)	(120	)
Partners’ Equity at December 31, 2016(d)	67.4	1,002		1.9	117		27		(2	)	97		31		1,272

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(a)Losses related to cash flow hedges reported in Accumulated Other Comprehensive Loss and expected to be reclassified to net income in the next 12 months are estimated to be nil. These estimates assume constant interest rates over time; however, the amounts reclassified will vary based on actual value of interest rates at the date of settlement.

(b)These units are treated as outstanding for financial reporting purposes.

(c)Equity of Former Parent of PNGTS.

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

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 interests in the following natural gas pipeline systems through three intermediate limited partnerships (ILPs), TC GL Intermediate Limited Partnership, TC PipeLines Intermediate Limited Partnership and TC Tuscarora Intermediate Limited Partnership:

Pipeline	Length	Description	Ownership
Gas Transmission Northwest LLC (GTN)	1,377 miles	Extends between an interconnection near Kingsgate, British Columbia, Canada at the Canadian border to a point near Malin, Oregon at the California border and delivers natural gas to the Pacific Northwest and to California.	100 percent
Bison Pipeline LLC (Bison)	303 miles	Extends from a location near Gillette, Wyoming to Northern Border’s pipeline system in North Dakota. Bison can transport natural gas from the Powder River Basin to Midwest markets.	100 percent
North Baja Pipeline, LLC (North Baja)	86 miles	Extends between an interconnection with the El Paso Natural Gas Company pipeline near Ehrenberg, Arizona and an interconnection with a natural gas pipeline near Ogilby, California on the Mexican border transporting natural gas in the southwest. North Baja is a bi-directional pipeline.	100 percent
Tuscarora Gas Transmission Company (Tuscarora)	305 miles	Extends between the GTN pipeline near Malin, Oregon to its terminus near Reno, Nevada and delivers natural gas in northeastern California and northwestern Nevada.	100 percent
Northern Border Pipeline Company (Northern Border)	1,412 miles	Extends between the Canadian border near Port of Morgan, Montana to a terminus near North Hayden, Indiana, south of Chicago. Northern Border is capable of receiving natural gas from Canada, the Williston Basin and Rocky Mountain area for deliveries to the Midwest. ONEOK Partners, L.P. owns the remaining 50 percent of Northern Border.	50 percent
Portland Natural Gas Transmission System (PNGTS)	295 miles	Connects with the TransQuebec and Maritimes Pipeline (TQM) at the Canadian border to deliver natural gas to customers in the U.S. northeast. Northern New England Investment Company, Inc. owns the remaining 38.29 percent of PNGTS.	61.71 percent (a)
Great Lakes Gas Transmission Limited Partnership (Great Lakes)	2,115 miles	Connects with the TransCanada Mainline at the Canadian border near Emerson, Manitoba, Canada and St. Clair, Michigan, near Detroit. Great Lakes is a bi-directional pipeline that can receive and deliver natural gas at multiple points along its system. TransCanada owns the remaining 53.55 percent of Great Lakes.	46.45 percent
Iroquois Gas Transmission System, L.P (Iroquois)	416 miles	Extends from the TransCanada Mainline system near Waddington, New York to deliver natural gas to customers in the U.S. northeast. The remaining 50.66 percent is owned by TransCanada (0.66 percent), Dominion Midstream (25.93 percent) and Dominion Resources (24.07 percent).	49.34 percent (b)

(a)On June 1, 2017, the Partnership acquired an additional 11.81 percent from TransCanada resulting in 61.71 percent ownership in PNGTS. (Refer to Note 24-Subsequent Events).

(b)Effective June 1, 2017 (Refer to Note 24-Subsequent Events).

The Partnership is managed by its General Partner, TC PipeLines GP, Inc. (General Partner), an indirect wholly-owned subsidiary of TransCanada. The General Partner provides management and operating services to the Partnership and is reimbursed for its costs and expenses. The General Partner owns 5,797,106 of our common units,

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100 percent of our IDRs and an effective two percent general partner interest in the Partnership at December 31, 2016. TransCanada also indirectly holds an additional 11,287,725 common units, for total ownership of 25.3 percent of our outstanding common units and 100 percent of our Class B units at December 31, 2016 (Refer to Note 6).

NOTE 2 SIGNIFICANT ACCOUNTING POLICIES

The accompanying consolidated financial statements and related notes have been prepared in accordance with United States generally accepted accounting principles (GAAP) and amounts are stated in U.S. dollars. The financial statements and notes present the financial position of the Partnership as of December 31, 2016 and 2015 and the results of its operations, cash flows and changes in partners’ equity for the years ended December 31, 2016, 2015 and 2014. Certain prior year amounts have been reclassified to conform to the current year presentation.

(a) Basis of Presentation

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

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

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

On June 1, 2017, the Partnership acquired from a subsidiary of TransCanada an additional 11.81 percent interest in PNGTS, resulting in the Partnership owning 61.71 percent in PNGTS (Refer to Note 24-Subsequent Events).  As a result of the Partnership owning 61.71 percent of PNGTS, the Partnership’s historical financial information was recast, except net income (loss) per common unit, to consolidate PNGTS for all the periods presented in these consolidated financial statements. Additionally, this acquisition was accounted for as transaction between entities under common control, similar to pooling of interests, whereby the assets and liabilities of PNGTS were recorded at TransCanada’s carrying value.

Also, on June 1, 2017, the Partnership acquired from subsidiaries of TransCanada a 49.34 percent interest in Iroquois (Refer to Note 24-Subsequent Events). Accordingly, the equity method investment in Iroquois  was accounted prospectively and did not form part of these consolidated financial statements.

On January 1, 2016, the Partnership acquired a 49.9 percent interest in PNGTS (2016 PNGTS Acquisition) from a subsidiary of TransCanada. The 2016 PNGTS Acquisition was accounted for as a transaction between entities under common control, similar to a pooling of interests, whereby the equity investment in PNGTS was recorded at TransCanada’s carrying value and the total excess purchase price paid was recorded as a reduction in Partners’ Equity. Accordingly, the equity investment in PNGTS is being eliminated as a result of consolidating PNGTS for all the periods presented. Refer to Note 6 for additional disclosure regarding the PNGTS Acquisition.

On April 1, 2015 and October 1, 2014, the Partnership acquired the remaining 30 percent interest in GTN and Bison, respectively, from subsidiaries of TransCanada. These acquisitions resulted in GTN and Bison being wholly-owned by the Partnership. Prior to these transactions, the remaining 30 percent interests held by subsidiaries of TransCanada were reflected as non-controlling interests in the Partnership’s consolidated financial statements. The acquisitions of these already-consolidated entities were accounted as a transaction between entities under common control, similar to a pooling of interests, whereby the acquired interests were recorded at TransCanada’s carrying value and the total excess purchase price paid was recorded as a reduction in Partners’ Equity. Refer to Note 6 for additional disclosures regarding these acquisitions.

(b) 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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(c) Cash and Cash Equivalents

The Partnership’s cash and cash equivalents consist of cash and highly liquid short-term investments with original maturities of three months or less and are recorded at cost, which approximates fair value.

(d) Trade Accounts Receivable

Trade accounts receivable are recorded at the invoiced amount and do not bear interest. We review our accounts receivable regularly and record allowances for doubtful accounts using the specific identification method.

(e) Natural gas imbalances

Natural gas imbalances occur when the actual amount of natural gas delivered to or received from a pipeline system differs from the amount of natural gas scheduled to be delivered or received. The Partnership values these imbalances due to or from shippers and interconnecting parties at current index prices. Imbalances are settled in kind, subject to the terms of the pipelines’ tariff.

Imbalances due from others are reported as  trade accounts receivable or accounts receivable from affiliates under the caption accounts receivable and other on the balance sheets. Imbalances owed to others are reported on the balance sheets as accounts payable and accrued liabilities and accounts payable to affiliates. In addition, the Partnership classifies all imbalances as current as the Partnership expects to settle them within a year.

(f) Inventories

Inventories primarily consist of materials and supplies and are carried at the lower of weighted average cost or market.

(g) Plant, Property and Equipment

Plant, property and equipment are stated at original cost. Costs of restoring the land above and around the pipeline are capitalized to pipeline facilities and depreciated over the remaining life of the related pipeline facilities. Pipeline facilities and compression equipment have an estimated useful life of 20 to 77 years and metering and other equipment ranges from 5 to 77 years. Depreciation is calculated on a straight-line composite basis over the assets’ estimated useful lives. Repair and maintenance costs are expensed as incurred. Costs that are considered a betterment are capitalized.

The Partnership’s subsidiaries capitalize a carrying cost on funds invested in the construction of long lived assets. This carrying cost includes a return on the investment financed by debt and equity allowance for funds used during construction (AFUDC), calculated based the average cost of debt and equity. Capitalized carrying costs for AFUDC debt and equity are reflected as an increase in the cost of plant, property and equipment on the balance sheets. Amounts included in construction work in progress are not amortized until transferred into service.

(h) Impairment of Equity Method Investments

We review our equity method investments when a significant event or change in circumstances has occurred that may have an adverse effect on the fair value of each investment. When such events or changes occur, we compare the estimated fair value to the carrying value of the related investment. We calculate the estimated fair value of an investment in an equity method investee using an income approach and market approach. The development of fair value estimates requires significant judgment including estimates of future cash flows, which is dependent on internal forecasts, estimates of the long-term rate of growth for the investee, estimates of the useful life over which cash flows will occur, and determination of weighted average cost of capital. The estimates used to calculate the fair value of an investee can change from year to year based on operating results and market conditions. Changes in these estimates and assumptions could materially affect the determination of fair value and our assessment as to whether an investment in an equity method investee has suffered an impairment.

If the estimated fair value of an investment is less than its carrying value, we are required to determine if the decline in fair value is other than temporary. This determination considers the aforementioned valuation methodologies, the length of time and the extent to which fair value has been less than carrying value, the financial condition and near-term prospects of the investee, including any specific events which may influence the operations of the investee, the

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intent and ability of the holder to retain its investment in the investee for a period of time sufficient to allow for any anticipated recovery in market value, and other facts and circumstances. If the fair value of an investment is less than its carrying value and the decline in value is determined to be other than temporary, we record an impairment charge.

(i) Impairment of Long-lived Assets

The Partnership reviews long-lived assets, such as plant, property and equipment for impairment whenever events or changes in circumstances indicate the carrying value may not be recoverable. If the total of the estimated undiscounted future cash flows is less than the carrying value of the assets, an impairment loss is recognized for the excess of the carrying value over the fair value of the assets.

(j) Partners’ Equity

Costs incurred in connection with the issuance of units are deducted from the proceeds received.

(k) Revenue Recognition

Transmission revenues are recognized in the period in which the service is provided. When a rate case is pending final FERC approval, a portion of the revenue collected is subject to possible refund. As of December 31, 2016, the Partnership has not recognized any transmission revenue that is subject to possible refund.

For the year ended December 31, 2014 and in January 2015, as required by FERC, PNGTS was charging customers rates applied for in its 2008 and 2010 rate cases. Due to the uncertainty in the outcome of its two outstanding rate cases, PNGTS was only recognizing revenue up to the amount of the interim FERC approved rates . The difference between these amounts was recognized as a provision (liability) for rate refund in the consolidated balance sheet. On February 19, 2015, FERC approved PNGTS’ final rates and PNGTS was required to refund the customers within sixty days of the issuance of the final rates, including interest at the quarterly average prime interest rate as prescribed by FERC. Total refunds accumulated to $114.3 million, including $8.0 million of interest, and were paid to customers on April 15, 2015.

(l) Income Taxes

Federal and certain state income taxes are the responsibility of the partners and are not reflected in these consolidated financial statements. The tax effect of the Partnership’s activities accrues to its partners. The Partnership’s taxable income or loss, which may vary substantially from the net income or loss reported in the consolidated statement of income, is includable in the federal income tax returns of each partner. The aggregate difference in the basis of the Partnership’s net assets for financial and income tax purposes cannot be readily determined because all information regarding each partner’s tax attributes related to the partnership is not available.

In instances where the Partnership is subject to state income taxes, the asset-liability method is used to account for taxes. This method requires the recognition of deferred tax assets and liabilities for future tax consequences attributable to the differences between the financial statement carrying amount of existing assets and liabilities and their respective tax bases.

Balance Sheet Classification of Deferred Taxes

In November 2015, the FASB issued new guidance which requires that deferred tax assets and liabilities be classified as non-current on the balance sheet. The new guidance is effective January 1, 2017, however, since early application is permitted, the Partnership elected to retrospectively apply this guidance effective January 1, 2015. Application of this new guidance will simplify the Partnership’s process in determining deferred tax amounts and simplify their presentation. The application of this guidance did not have a material impact on the Partnership’s consolidated financial statements.

(m) Acquisitions and Goodwill

The Partnership accounts for business acquisitions from third parties using the acquisition method of accounting and, accordingly, the assets and liabilities of the acquired entities are recorded at their estimated fair values at the date of acquisition. The excess of the purchase price over the fair value of net assets acquired is attributed to goodwill. Goodwill is not amortized and is tested on an annual basis for impairment or more frequently if any indicators of impairment are evident. The Partnership initially assesses qualitative factors to determine whether events or changes in circumstances indicate that the goodwill might be impaired. If the Partnership does not conclude that it is more likely than not that fair value of the reporting unit is greater than its carrying value, the first step of the two-step impairment test is performed by comparing the fair value of the reporting unit to its book value, which includes goodwill. If the fair value is less than book value, an impairment is indicated and a second step is performed to measure the amount of the impairment. In the second step, the implied fair value of goodwill is calculated by deducting the recognized amounts of all tangible and intangible net assets of the reporting unit from the fair value determined in the initial assessment. If the carrying value of goodwill exceeds the calculated implied fair value of goodwill, an impairment charge is recorded.

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At December 31, 2016 and 2015, we had $130 million of goodwill recorded on our consolidated balance sheet related to the North Baja ($48 million) and Tuscarora ($82 million) acquisitions. No impairment of goodwill existed at December 31, 2016 (Refer also to Note 20).

The Partnership accounts for business acquisitions between itself and TransCanada, also known as “dropdowns”, as transactions between entities under common control.  Using this approach, the assets and liabilities of the acquired entities are recorded at TransCanada’s carrying value. In the event recasting is required, the Partnership’s historical financial information will be recast, except net income (loss) per common unit, to include the acquired entities for all periods presented. If the fair market value paid for the acquired entities is greater than the recorded net assets of the acquired entities, the excess purchase price paid is recorded as a reduction in Partners’ Equity. Similarly, if the fair market value paid for the acquired entities is less than the recorded net assets of the acquired entities, the excess of assets acquired is recorded as an increase in Partners’ Equity.

(n) Fair Value Measurements

For cash and cash equivalents, receivables, accounts payable, certain accrued expenses and short-term debt, the carrying amount approximates fair value due to the short maturities of these instruments. For long-term debt instruments and the interest rate swap agreements, fair value is estimated based upon market values (if applicable) or on the current interest rates available to us for debt with similar terms and remaining maturities. Considerable judgment is required in developing these estimates.

(o) Derivative Financial Instruments and Hedging Activities

The Partnership recognizes all derivative instruments as either assets or liabilities in the balance sheet at their respective fair values. For derivatives designated in hedging relationships, changes in the fair value are either offset through earnings against the change in fair value of the hedged item attributable to the risk being hedged or recognized in accumulated other comprehensive income, to the extent the derivative is effective at offsetting the changes in cash flows being hedged until the hedged item affects earnings.

The Partnership only enters into derivative contracts that it intends to designate as a hedge of a forecasted transaction or the variability of cash flows to be received or paid related to a recognized asset or liability (cash flow hedge). For all hedging relationships, the Partnership formally documents the hedging relationship and its risk management objective and strategy for undertaking the hedge, the hedging instrument, the hedged transaction, the nature of the risk being hedged, how the hedging instrument’s effectiveness in offsetting the hedged risk will be assessed prospectively and retrospectively, and a description of the method used to measure ineffectiveness. The Partnership also formally assesses, both at the inception of the hedging relationship and on an ongoing basis, whether the derivatives that are used in hedging relationships are highly effective in offsetting changes in cash flows of hedged transactions. For derivative instruments that are designated and qualify as part of a cash flow hedging relationship, the effective portion of the gain or loss on the derivative is reported as a component of other comprehensive income and reclassified into earnings in the same period or periods during which the hedged transaction affects earnings. Gains and losses on the derivative representing either hedge ineffectiveness or hedge components excluded from the assessment of effectiveness are recognized in current earnings.

The Partnership discontinues hedge accounting prospectively when it determines that the derivative is no longer effective in offsetting cash flows attributable to the hedged risk, the derivative expires or is sold, terminated, or exercised, the cash flow hedge is de-designated because a forecasted transaction is not probable of occurring, or management determines to remove the designation of the cash flow hedge.

In all situations in which hedge accounting is discontinued and the derivative remains outstanding, the Partnership continues to carry the derivative at its fair value on the balance sheet and recognizes any subsequent changes in its fair value in earnings. When it is probable that a forecasted transaction will not occur, the Partnership discontinues hedge accounting and recognizes immediately in earnings gains and losses that were accumulated in other comprehensive income related to the hedging relationship.

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(p) Asset Retirement Obligation

The Partnership recognizes the fair value of a liability for asset retirement obligations in the period in which it is incurred, when a legal obligation exists and a reasonable estimate of fair value can be made. The fair value is added to the carrying amount of the associated asset and the liability is accreted through charges to operating expenses.

The Partnership has determined it has legal obligations associated with its natural gas pipelines and related transmission facilities. The obligations relate primarily to purging and sealing the pipelines if they are abandoned. The Partnership is also required to operate and maintain its natural gas pipeline system, and intends to do so as long as supply and demand for natural gas exists, which the Partnership expects for the foreseeable future. Therefore, the Partnership believes its natural gas pipeline system assets have indeterminate lives and, accordingly, has recorded no asset retirement obligation as of December 31, 2016 and 2015.

(q) Government Regulation

The Partnership’s subsidiaries are subject to regulation by FERC. Under regulatory accounting principles, certain assets or liabilities that result from the regulated ratemaking process may be recorded that would not be recorded under GAAP for non-regulated entities. The timing of recognition of certain revenues and expenses in our regulated business may differ from that otherwise expected under GAAP to appropriately reflect the economic impact of the regulators’ decisions regarding revenues and rates. The Partnership regularly evaluates the continued applicability of regulatory accounting, considering such factors as regulatory changes, the impact of competition, and the ability to recover regulatory assets. At December 31, 2016, the Partnership had regulatory assets amounting to $1 million reported as part of other current assets  in the balance sheet representing volumetric fuel tracker assets that are settled with in-kind exchanges with customers continually (2015 — $2 million). Regulatory liabilities are included in other long-term liabilities (refer to Note 8). AFUDC is capitalized and included in plant, property and equipment.

(r) Debt Issuance Costs

Costs related to the issuance of debt are deferred and amortized using the effective interest rate method over the term of the related debt. Refer also to Note 3 — Imputation of Interest for the change in accounting policy related to debt issuance costs.

NOTE 3 ACCOUNTING PRONOUNCEMENTS

Changes in Accounting Policies effective January 1, 2016

Consolidation

In February 2015, the Financial Accounting Standards Board (FASB) issued new guidance on consolidation, which requires that an entity evaluate whether it should consolidate certain legal entities. All legal entities are subject to reevaluation under the revised consolidation model. This guidance became effective beginning January 1, 2016 and was applied retrospectively to all financial statements presented. The application of this guidance did not result in any change to the Partnership’s consolidation conclusions. Refer to Note 22, Variable Interest Entities.

In October 2016, the FASB issued an updated guidance on consolidation, under which a single decision maker is not required to consider indirect interests held through related parties that are under common control with the single decision maker to be the equivalent of direct interests in their entirety. Instead, a single decision maker is required to include those interests on a proportionate basis consistent with indirect interests held through other related parties. Entities that already have adopted the amendments in February 2015 update are required to apply the amendments in this update retrospectively to all relevant prior periods beginning with the fiscal year in which the amendments were applied. The application of this guidance did not result in any change to the Partnership’s consolidation conclusions. Refer to Note 22, Variable Interest Entities.

Imputation of interest

In April 2015, the FASB issued an amendment of previously issued guidance on imputation of interest, which requires debt issuance costs be presented in the balance sheet as a direct deduction from the carrying amount of debt liabilities, consistent with debt discount or premiums. In addition, amortization of debt issuance costs should be reported as interest expense. The recognition and measurement for debt issuance costs would not be affected. This guidance is effective from January 1, 2016 and was applied retrospectively resulting in a reclassification of debt

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issuance costs previously recorded in other assets to an offset of their respective debt liabilities on the Partnership’s consolidated balance sheet. Amortization of debt issuance costs was reported as interest expense in all periods presented in the Partnership’s consolidated statement of income.

As a result of the application of this guidance and similar to the presentation of debt discounts, debt issuance costs of $8 million at December 31, 2015 previously reported as other assets in the balance sheet were reclassified as an offset against their respective debt liabilities.

Earnings per share

In April 2015, the FASB issued an amendment of previously issued guidance on earnings per share (EPS) as it is being calculated by master limited partnerships. This updated guidance specifies that for purposes of calculating historical EPS under the two-class method, the earnings (losses) of a transferred business before the date of a dropdown transaction should be allocated entirely to the general partner interest, and previously reported EPS of the limited partners would not change as a result of a dropdown transaction. Qualitative disclosures about how the rights to the earnings (losses) differ before and after the dropdown transaction occurs are also required. This guidance became effective on January 1, 2016 and applies to all dropdown transactions requiring recast. The retrospective application of this guidance did not have a material impact on the Partnership’s consolidated financial statements as our current accounting policy is consistent with the new guidance.

Business combinations

In September 2015, the FASB issued new guidance which replaces the requirement that an acquirer in a business combination account for measurement period adjustments retrospectively with a requirement that an acquirer recognize adjustments to the provisional amounts that are identified during the measurement period in the reporting period in which the adjustment amounts are determined. The amended guidance requires that the acquirer record, in the same period’s financial statements, the effect on earnings of changes in depreciation, amortization, or other income effects, if any, as a result of the change to the provisional amounts, calculated as if the accounting had been completed at the acquisition date. The new guidance is effective January 1, 2016 and was applied prospectively. The application of this guidance did not have a material impact on the Partnership’s consolidated financial statements.

Statement of Cash Flows

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 since early adoption is permitted, the Partnership elected to retrospectively apply this guidance effective December 31, 2016. The application of this guidance will not have a material impact on the classification of debt pre-payments or extinguishment costs, contingent consideration payments made after a business combination, proceeds from the settlement of insurance claims and proceeds from the settlement of corporate owned life insurance. 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 $25 million and $27 million in 2015 and 2014, respectively, have been reclassified from investing activities to cash generated from operations in the consolidated statement of cash flows.

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 currently anticipates adopting the standard using the modified retrospective approach with the cumulative-effect of initially applying the guidance recognized at the date of adoption, subject to allowable and elected practical expedients.

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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 to identify any significant changes in how revenues are recognized as a result of implementing the new standard. While the Partnership has not identified any material differences in the amount and timing of revenue recognition for the contracts that have been analyzed to date, the evaluation is not complete and the Partnership has not concluded on the overall impact of adopting the new guidance. The Partnership continues its contract analysis to obtain the information necessary to quantify, the cumulative-effect adjustment, if any, on prior period revenues. The Partnership also continues to address any system and process changes necessary to compile the information to meet the recognition and disclosure requirements of the new guidance.

Leases

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

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

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. This new guidance is effective January 1, 2017 and will be applied prospectively. The Partnership does not expect the adoption of this new standard to have a material impact on its consolidated financial statements.

NOTE 4 EQUITY INVESTMENTS

Northern Border and Great Lakes are regulated by FERC and are operated by subsidiaries of 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 3, Accounting Pronouncements and Note 22, Variable Interest Entities.

	Ownership Interest at		Equity Earnings (b)			Equity Investments
	December 31,		Year ended December 31			December 31
(millions of dollars)	2016		2016(d)	2015	2014	2016 (d)	2015
Northern Border (a)	50.00	%	69	66	69	444	480
Great Lakes	46.45	%	28	31	19	474	485	(c)
			97	97	88	918	965

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

(b)Equity Earnings represents our share in investee’s earnings and does not include any impairment charge on the equity method investment recorded as a reduction of carrying value of these investments. Accordingly, no impairment charge was recorded by the Partnership on its equity investees for all the periods presented here except the impairment recognized in 2015 on our investment in Great Lakes as discussed below.

(c)During the fourth quarter of 2015, we recognized an impairment charge on our investment in Great Lakes amounting to $199 million. See discussion below.

(d)Recast to eliminate equity earnings from PNGTS and consolidate PNGTS for all periods presented  (Refer to Note 2).

Northern Border

The Partnership, through its interest in TC PipeLines Intermediate Limited Partnership owns a 50 percent general partner interest in Northern Border. The other 50 percent partnership interest in Northern Border is held by ONEOK Partners, L.P., a publicly traded limited partnership.TC PipeLines Intermediate Limited Partnership, as one of the general partners, may be exposed to the commitments and contingencies of Northern Border. The Partnership holds a 98.9899 percent limited partnership interest in TC PipeLines Intermediate Limited Partnership.

Northern Border has a FERC-approved settlement agreement which established maximum long-term transportation rates and charges on the Northern Border system effective January 1, 2013. Northern Border is required to file for new rates no later than January 1, 2018.

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The Partnership recorded no undistributed earnings from Northern Border for the years ended December 31, 2016, 2015 and 2014. At December 31, 2016 and 2015, the Partnership had a $116 million difference between the carrying value of Northern Border and the underlying equity in the net assets primarily resulting from the recognition and inclusion of goodwill in the Partnership’s investment in Northern Border relating to the Partnership’s April 2006 acquisition of an additional 20 percent general partnership interest in Northern Border. As of December 31, 2016, no impairment has been identified in our investment in Northern Border.

The summarized financial information for Northern Border is as follows:

December 31 (millions of dollars)	2016		2015
Assets
Cash and cash equivalents	14		27
Other current assets	36		33
Plant, property and equipment, net	1,089		1,124
Other assets (a)	14		16
	1,153		1,200
Liabilities and Partners’ Equity
Current liabilities	38		39
Deferred credits and other	28		26
Long-term debt, net (a), (b)	430		409
Partners’ equity
Partners’ capital	659		728
Accumulated other comprehensive loss	(2	)	(2	)
	1,153		1,200

(a)As a result of the application of ASU No. 2015-03 and similar to the presentation of debt discounts, debt issuance costs of $2 million at December 31, 2015 previously reported as other assets in the balance sheet were reclassified as an offset against their respective debt liabilities.

(b)Includes current maturities of $100 million senior notes at December 31, 2015. During August 2016, the $100 million senior notes were refinanced with a draw on Northern Border’s $200 million revolving credit agreement that expires in 2020.

Year ended December 31 (millions of dollars)	2016		2015		2014
Transmission revenues	292		286		293
Operating expenses	(72	)	(70	)	(72	)
Depreciation	(59	)	(60	)	(59	)
Financial charges and other	(21	)	(22	)	(22	)
Net income	140		134		140

Great Lakes

The Partnership, through its interest in TC GL Intermediate Limited Partnership owns a 46.45 percent general partner interest in Great Lakes. TransCanada owns the other 53.55 percent partnership interest. TC GL Intermediate Limited Partnership, as one of the general partners, may be exposed to the commitments and contingencies of Great Lakes. The Partnership holds a 98.9899 percent limited partnership interest in TC GL Intermediate Limited Partnership.

Great Lakes operates under rates established pursuant to a settlement approved by FERC in November 2013. Under the settlement, Great Lakes is required to file for new rates to be effective no later than January 1, 2018.

The Partnership recorded no undistributed earnings from Great Lakes for the years ended December 31, 2016, 2015, and 2014.

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The Partnership made equity contributions to Great Lakes of $4 million and $5 million in the first and fourth quarter of 2016, respectively. These amounts represent the Partnership’s 46.45 percent share of a $9 million and $10 million cash call from Great Lakes to make scheduled debt repayments.

During the fourth quarter of 2015, we determined that our investment in Great Lakes’ long-term value had been adversely impacted by the changing natural gas flows in its market region. Additionally, we have concluded that other strategic alternatives to increase its utilization or revenue were no longer feasible. As a result, we determined that the carrying value of our investment in Great Lakes was in excess of its fair value and the decline was not temporary. Accordingly, we concluded that the carrying value of our investment in Great Lakes was impaired.

Our analysis resulted in an impairment charge of $199 million reflected as Impairment of equity-method investment on our Statement of Income for the year ended December 31, 2015.  The impairment charge reduced the difference between the carrying value of our investment in Great Lakes and the underlying equity in the net assets, to $260 million and  the difference represented the equity method goodwill remaining in our investment in Great Lakes relating to the Partnership’s February 2007 acquisition of a 46.45 percent general partner interest in Great Lakes.

The assumptions we used in 2015 related to the estimated fair value of our remaining equity investment in Great Lakes could be negatively impacted by near and long-term conditions including:

· future regulatory rate action or settlement,

· valuation of Great lakes in future transactions,

· changes in customer demand at Great Lakes for pipeline capacity and services,

· changes in North American natural gas production in the major producing basins,

· changes in natural gas prices and natural gas storage market conditions, and

· changes in other long-term strategic objectives.

Great Lakes’ evolving market conditions and other factors relevant to Great Lakes’ long term financial performance have remained relatively stable during the year ended 2016 and into 2017.  Accordingly, our estimation of the fair value of our investment in Great Lakes has not materially changed from 2015.  There is a risk that reductions in future cash flow forecasts and other adverse changes in these key assumptions could result in additional future impairment of the carrying value of our investment in Great Lakes.

The summarized financial information for Great Lakes is as follows:

December 31 (millions of dollars)	2016	2015
Assets
Current assets	66	86
Plant, property and equipment, net	714	727
	780	813
Liabilities and Partners’ Equity
Current liabilities	40	31
Long-term debt, net (a),(b)	278	297
Partners’ equity	462	485
	780	813

(a)The application of ASU No. 2015-03 did not have a material effect on Great Lakes’ financial statements.

(b)Includes current maturities of $19 million as of December 31, 2016 (December 31, 2015 - $19 million).

Year ended December 31 (millions of dollars)	2016		2015		2014
Transmission revenues	179		177		146
Operating expenses	(69	)	(59	)	(53	)
Depreciation	(28	)	(28	)	(28	)
Financial charges and other	(21	)	(23	)	(25	)
Net income	61		67		40

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NOTE 5 PLANT, PROPERTY AND EQUIPMENT

The following table includes plant, property and equipment of our consolidated entities:

	2016 (a)				2015 (a)
December 31 (millions of dollars)	Cost	Accumulated Depreciation		Net Book Value	Cost	Accumulated Depreciation		Net Book Value
Pipeline	2,540	(879	)	1,661	2,535	(806	)	1,729
Compression	519	(148	)	371	516	(134	)	382
Metering and other	205	(61	)	144	201	(57	)	144
Construction in progress	4	—		4	2	—		2
	3,268	(1,088	)	2,180	3,254	(997	)	2,257

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

NOTE 6 ACQUISITIONS

2016 PNGTS Acquisition

On January 1, 2016, the Partnership acquired a 49.9 percent interest in PNGTS from a subsidiary of TransCanada. The total purchase price of the PNGTS Acquisition was $228 million and consisted of $193 million in cash (including the final purchase price adjustment of $5 million) and the assumption of $35 million in proportional PNGTS debt.

The Partnership funded the cash portion of the transaction using proceeds received in 2015 from our ATM Program and additional borrowings under our Senior Credit Facility. The purchase agreement provides for additional payments to TransCanada ranging from $5 million up to a total of $50 million if pipeline capacity is expanded to various thresholds during the fifteen year period following the date of closing.

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

The net purchase price was allocated as follows:

(millions of dollars)
Net Purchase Price (a)	193
Less: TransCanada’s carrying value of PNGTS’ net assets at January 1, 2016	120
Excess purchase price (b)	73

(a)Total purchase price of $228 million less the assumption of $35 million of proportional PNGTS debt by the Partnership.

(b)The excess purchase price of $73 million was recorded as a reduction in Partners’ Equity.

2015 GTN Acquisition

On April 1, 2015, the Partnership acquired the remaining 30 percent interest in GTN from a subsidiary of TransCanada (2015 GTN Acquisition), which resulted in GTN being wholly-owned by the Partnership. The total purchase price of the 2015 GTN Acquisition was $446 million plus the final purchase price adjustment of $11 million, for a total of $457 million. The purchase price consisted of $264 million in cash (including the final purchase price adjustment of $11 million), the assumption of $98 million in proportional GTN debt and the issuance of 1,900,000 new Class B units to TransCanada valued at $50 each, representing a limited partner interest in the Partnership with a total value of $95 million.

The Partnership funded the cash portion of the transaction using a portion of the proceeds received on our March 13, 2015 debt offering (refer to Note 7). The Class B units entitle TransCanada to a 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. Under the terms of the Third Amended and Restated Agreement of Limited Partnership of the Partnership (Partnership Agreement), the Class B distribution was initially

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calculated to equal 30 percent of GTN’s distributable cash flow for the nine months ended December 31, 2015, less $15 million.

Prior to this transaction, the remaining 30 percent interest held by a subsidiary of TransCanada was reflected as a non-controlling interest in the Partnership’s consolidated financial statements. The 2015 GTN Acquisition of this already-consolidated entity was accounted as a transaction between entities under common control, similar to a pooling of interests, whereby the acquired interest was recorded at TransCanada’s carrying value and the total excess purchase price paid was recorded as a reduction in Partners’ Equity.

The net purchase price was allocated as follows:

(millions of dollars)
Net Purchase Price (a)	359
Less: TransCanada’s carrying value of non-controlling interest at April 1, 2015	232
Excess purchase price (b)	127

(a)Total purchase price of $457 million less the assumption of $98 million of proportional GTN debt by the Partnership.

(b)The excess purchase price of $127 million was recorded as a reduction in Partners’ Equity.

Our General Partner also contributed approximately $2 million to maintain its effective two percent interest in the Partnership.

2014 Bison Acquisition

On October 1, 2014, the Partnership acquired the remaining 30 percent interest in Bison from a subsidiary of TransCanada. The total purchase price of the 2014 Bison Acquisition was $215 million plus purchase price adjustments of $2 million. The acquisition of Bison was financed through combinations of (i) net proceeds from the ATM Program (refer to Note 9), and (ii) short-term financing.

Prior to this transaction, the remaining 30 percent interest held by a subsidiary of TransCanada was reflected as non-controlling interest in the Partnership’s consolidated financial statements. The 2014 Bison Acquisition of this already-consolidated entity was accounted as a transaction between entities under common control, similar to a pooling of interests, whereby the acquired interest was recorded at TransCanada’s carrying value and the total excess purchase price paid was recorded as a reduction in Partners’ Equity.

The purchase price was allocated as follows:

(millions of dollars)
Total cash consideration	217
TransCanada’s carrying value of non-controlling interest at October 1, 2014	188
Excess purchase price	29

The excess purchase price of $29 million was recorded as a reduction in Partners’ Equity.

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NOTE 7 DEBT AND CREDIT FACILITIES

(millions of dollars)	December 31, 2016 (c)		Weighted Average Interest Rate for the Year Ended December 31, 2016 (c)		December 31, 2015 (c)	Weighted Average Interest Rate for the Year Ended December 31, 2015 (c)
TC PipeLines, LP
Senior Credit Facility due 2021	160		1.72	%	200	1.44	%
2013 Term Loan Facility due 2018	500		1.73	%	500	1.44	%
2015 Term Loan Facility due 2018	170		1.63	%	170	1.47	%
4.65% Unsecured Senior Notes due 2021	350		4.65	%(b)	350	4.65	%(b)
4.375% Unsecured Senior Notes due 2025	350		4.375	%(b)	350	4.375	%(b)
GTN
5.29% Unsecured Senior Notes due 2020	100		5.29	%(b)	100	5.29	%(b)
5.69% Unsecured Senior Notes due 2035	150		5.69	%(b)	150	5.69	%(b)
Unsecured Term Loan Facility due 2019	65		1.43	%	75	1.15	%
PNGTS
5.90% Senior Secured Notes due December 2018	53		5.90	%(b)	69	5.90	%(b)
Tuscarora
Unsecured Term Loan due 2019	10		1.64	%	—	—
3.82% Series D Senior Notes due 2017	12		3.82	%(b)	16	3.82	%(b)
	1,920				1,980
Less: unamortized debt issuance costs and debt discount (a)	9				9
Less: current portion	52	(d)			36
	1,859				1,935

(a)As a result of the application of ASU No. 2015-03 and similar to the presentation of debt discounts, debt issuance costs of $8 million at December 31, 2015 previously reported as other assets in the balance sheet were reclassified as an offset against debt. Refer to Note 3, Accounting Pronouncements.

(b)Fixed interest rate.

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

(d)Includes the PNGTS portion due at December 31, 2016 amounting to $5.5 million that was paid on January 3, 2017 (Refer to Note 24-Subsequent Events).

TC PipeLines, LP

On November 10, 2016, the Partnership’s Senior Credit Facility was amended to extend the maturity period through November 10, 2021. The Facility consists of a $500 million senior revolving credit facility with a banking syndicate, under which $160 million was outstanding at December 31, 2016 (December 31, 2015 - $200 million), leaving $340 million available for future borrowing.

At the Partnership’s option, the interest rate on the outstanding borrowings under the Senior Credit Facility may be lenders’ base rate or the London Interbank Offered Rate (LIBOR) plus, in either case, an applicable margin that is based on the Partnership’s long-term unsecured credit ratings. The Senior Credit Facility permits the Partnership to specify the portion of the borrowings to be covered by specific interest rate options and, for LIBOR-based borrowings, to specify the interest rate period. The Partnership is required to pay a commitment fee based on its credit rating and on the unused principal amount of the commitments under the Senior Credit Facility. The Senior Credit Facility has a feature whereby at any time, so long as no event of default has occurred and is continuing, the Partnership may request an increase in the Senior Credit Facility of up to $500 million, but no lender has an obligation to increase their respective share of the facility.

The LIBOR-based interest rate on the Senior Credit Facility was 1.92 percent at December 31, 2016 (December 31, 2015 - 1.50 percent).

On July 1, 2013, the Partnership entered into a term loan agreement with a syndicate of lenders for a $500 million term loan credit facility (2013 Term Loan Facility). On July 2, 2013, the Partnership borrowed $500 million under the 2013 Term Loan Facility, to pay a portion of the purchase price of the 2013 Acquisition, maturing on July 1, 2018. The 2013 Term Loan Facility bears interest based, at the Partnership’s election, on the LIBOR or the base rate plus, in either case, an applicable margin. The base rate equals the highest of (i) SunTrust Bank’s prime rate, (ii) 0.50 percent above the federal funds rate and (iii) 1.00 percent above one-month LIBOR. The applicable margin for the term loan is based on the Partnership’s senior debt rating and ranges between 1.125 percent and 2.000 percent for LIBOR borrowings and 0.125 percent and 1.000 percent for base rate borrowings.

As of December 31, 2016, 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 (2015-2.79 percent) . Prior to

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hedging activities, the LIBOR-based interest rate was 1.87 percent at December 31, 2016 (December 31, 2015 — 1.50 percent).

On September 30, 2015, the Partnership entered into an agreement for a $170 million term loan credit facility (2015 Term Loan Facility). The Partnership borrowed $170 million under the 2015 Term Loan Facility to refinance its Short-Term Loan Facility which matured on September 30, 2015.  The 2015 Term Loan Facility matures on October 1, 2018. The LIBOR-based interest rate on the 2015 Term Loan Facility was 1.77 percent at December 31, 2016 (December 31, 2015 — 1.39 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 4.01 to 1.00 as of December 31, 2016.

The Senior Credit Facility and the Term Loan Facilities contain additional covenants that include restrictions on entering into mergers, consolidations and sales of assets, granting liens, material amendments to the Partnership Agreement, incurrence of additional debt by the Partnership’s subsidiaries and distributions to unitholders. Upon any breach of these covenants, amounts outstanding under the Senior Credit Facility and the Term Loan Facilities may become immediately due and payable.

On March 13, 2015, the Partnership closed a $350 million public offering of senior unsecured notes bearing an interest rate of 4.375 percent maturing March 13, 2025. The net proceeds of $346 million were used to fund a portion of the 2015 GTN Acquisition (refer to Note 6) and to reduce the amount outstanding under our Senior Credit Facility. The indenture for the notes contains customary investment grade covenants.

PNGTS

PNGTS’ Senior Secured Notes are secured by the PNGTS long-term firm shipper contracts and its partners’ pledge of their equity and a guarantee of debt service for six months. PNGTS is restricted under the terms of its note purchase agreement from making cash distributions unless certain conditions are met. Before a distribution can be made, the debt service reserve account must be fully funded and PNGTS’ debt service coverage ratio for the preceding and succeeding twelve months must be 1.30 or greater. At December 31, 2016, the debt service coverage ratio was 2.41 for the twelve preceding months and 1.43 for the twelve succeeding months. Therefore, PNGTS was not restricted to make any cash distributions.

GTN

On June 1, 2015, GTN’s 5.09 percent unsecured Senior Notes matured. Also, on June 1, 2015, GTN entered into a $75 million unsecured variable rate term loan facility (Unsecured Term Loan Facility), which requires yearly principal payments until its maturity on June 1, 2019. The variable interest is based on LIBOR plus an applicable margin. The LIBOR-based interest rate on the Unsecured Term Loan Facility was 1.57 percent at December 31, 2016 (December 31, 2015 — 1.19 percent). GTN’s Unsecured Senior Notes, along with this new 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 December 31, 2016 is 44.5 percent.

Tuscarora

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 December 31, 2016 was 21.22 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 4.15 to 1.00 as of December 31, 2016.

On  April  29,  2016,  Tuscarora  entered  into  a $9.5  million  unsecured  variable  rate  term  loan  facility which requires  yearly principal  payments  until  its  maturity  on  April  29,  2019.  The variable interest is based on LIBOR plus an applicable margin and was 1.90 percent at December 31, 2016.

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At December 31, 2016, 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 Partnership Agreement, incurring additional debt and distributions to unitholders.

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

(millions of dollars)
2017	52	(a)
2018	715	(a)
2019	43
2020	100
2021	510
Thereafter	500
	1,920	(a)

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

NOTE 8 OTHER LIABILITIES

December 31 (millions of dollars)	2016	2015
Regulatory liabilities	25	24
Other liabilities	3	3
	28	27

The Partnership collects estimated future removal costs related to its transmission and gathering facilities in its current rates and recognizes regulatory liabilities in this respect in the balance sheet. Estimated costs associated with the future removal of transmission and gathering facilities are collected through depreciation as allowed by FERC. These amounts do not represent asset retirement obligations as defined by FASB ASC 410, Accounting for Asset Retirement Obligations.

NOTE 9 PARTNERS’ EQUITY

At December 31, 2016, the Partnership had 67,454,831common units outstanding, of which 50,370,000 were held by non-affiliates and 17,084,831 common units were held by subsidiaries of TransCanada, including 5,797,106 common units held by our General Partner. Additionally, TransCanada, through our General Partner, owns 100 percent of our IDRs and an effective two percent general partner interest in the Partnership. TransCanada also holds 100 percent of our 1,900,000 outstanding Class B units.

ATM Equity Issuance Program (ATM Program)

In August 2014, the Partnership launched its $200 million ATM program pursuant to which, the Partnership may from time to time, offer and sell, through sales agents, common units, representing limited partner interests.

On August 5, 2016, the Partnership entered into a new $400 million Equity Distribution Agreement (EDA) with five financial institutions (the Managers). Sales of the common units will be issued pursuant to the Partnership’s shelf registration statement on Form S-3 (Registration No. 333-211907), which was declared effective by the SEC on August 4, 2016.

In 2016, the Partnership issued 3.1 million common units under the ATM Program generating net proceeds of approximately $164 million, plus an additional $3 million from  the General Partner’s to maintain its effective two percent interest. The commissions to our sales agents were approximately $2 million.  The net proceeds were used to repay a portion of the borrowings under the Senior Credit Facility for the 2016 PNGTS Acquisition and for general partnership purposes. The 3.1 million common units issued include the 1.6 million common units subject to rescission as discussed below.

In 2015, the Partnership issued 0.7 million common units under the ATM Program generating net proceeds of approximately $43 million, plus an additional $1 million from  the General Partner’s to maintain its effective two

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percent interest. The commissions to our sales agents were approximately $0.4 million.  The net proceeds were used for general partnership purposes.

In 2014, the Partnership issued 1.3 million common units under the ATM Program generating net proceeds of approximately $71 million, plus an additional $2 million from  the General Partner’s to maintain its effective two percent interest. The commissions to our sales agents were approximately $1 million.  The net proceeds were used to finance the 2014 Bison Acquisition (refer to Note 6).

Common unit issuance subject to rescission

On July 17, 2014, the SEC declared effective a registration statement (the Registration Statement) that we had filed to cover sales of Common Units under our ATM program. On February 26, 2016, at the time of the filing of the 2015 Form 10-K, we believed that the Partnership continued to be eligible to use the effective Registration Statement to sell Common Units under our ATM program.  However, we were advised by the SEC on June 23, 2016 that as a result of the untimely filing of an employee-related Form 8-K on October 28, 2015, which was not filed via EDGAR until 6:02 p.m. Eastern Time (32 minutes after the 5:30 p.m. Eastern Time cutoff), the Partnership was ineligible to use the Registration Statement after the filing of the 2015 Form 10-K.

Because the Partnership was ineligible to continue using the Registration Statement following the filing of the 2015 Form 10-K, it is possible that the sales of an aggregate 1,619,631 Common Units under the Registration Statement (the ATM Common Units), which were sold between March 8, 2016 and May 19, 2016 at per Common Unit prices ranging from $47.00 to $54.95, may be deemed to have been unregistered sales of securities.  If it is determined that persons who purchased the ATM Common Units from the Partnership after February 26, 2016, purchased such Common Units in an offering deemed to be unregistered, then to the extent there may have been a violation of federal securities laws such persons may be entitled to rescission rights, pursuant to which they could be entitled to recover the amount paid for such ATM Common Units, plus interest (based on the statutory rate under applicable state law), less the amount of any distributions.  If such investor has sold any of the ATM Common Units purchased by the investor, then the investor would be entitled to recover the difference between the amount paid for such ATM Common Units and the amount at which such ATM Common Units were sold, assuming the investor’s ATM Common Units were sold at a loss, plus interest and less the amount of any distributions. If all of the investors who purchased the ATM Common Units from the Partnership after February 26, 2016 continue to own all of the ATM Common Units and were to demand rescission of their purchases, and such investors were in fact found to be entitled to such rescission, then we would be obligated to repay approximately $82,334,015, plus interest, less the amount of any distributions.  The Securities Act generally requires that any claim brought for a violation of Section 5 of the Securities Act be brought within one year of the violation.

At December 31, 2016, the Partnership classified all the 1.6 million common units issued under its ATM program after February 26, 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 were treated as outstanding for financial reporting purposes.

The total amount transferred  outside of equity was approximately $83 million which includes interest, less distributions paid, and includes our General Partner’s share to maintain its effective two percent interest.

No unitholder claimed or attempted to exercise any rescission rights prior to the expiry dates of such rights and the final rights related to the sales of such units expired on May 19, 2017. Therefore, all the common units subject to rescission on the consolidated balance sheet were reclassified back to equity on our consolidated balance sheet at June 30, 2017 as filed on our Second Quarterly report on Form 10Q dated August 3, 2017.

Issuance of Class B units

On April 1, 2015, we issued Class B units to TransCanada to finance a portion of the 2015 GTN Acquisition. The Class B units entitle TransCanada to an annual distribution which is an amount based on 30 percent of cash distributions from GTN exceeding certain annual thresholds (refer to Note 6). The Class B units contain no mandatory or optional redemption features and are also non-convertible, non-exchangeable, non-voting and rank equally with common units upon liquidation.

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The Class B units’ equity account is increased by the excess of 30 percent of GTN’s distributions over the annual threshold until such amount is declared for distribution and paid every first quarter of the subsequent year.

For the year ended December 31, 2016 and 2015, the Class B units’ equity account was increased by $22 million and $12 million, respectively. These amounts equal 30 percent of GTN’s total distributable cash flow above the $20 million threshold in 2016 and $15 million in 2015 (refer to Notes 12 and 13).

NOTE 10 ACCUMULATED OTHER COMPREHENSIVE LOSS

The changes in accumulated other comprehensive loss (AOCL) by component are as follows:

	Cash flow hedges (a)
	(millions of dollars)
Balance at December 31, 2013	(5	)
Change in fair value of cash flow hedges	(1	)
Amounts reclassified from AOCL	—
PNGTS’ amortization of realized loss on derivative instrument (Note 18)	1
Net other comprehensive income (loss)	—
Balance at December 31, 2014	(5	)
Change in fair value of cash flow hedges	—
Amounts reclassified from AOCL	—
PNGTS’ amortization of realized loss on derivative instrument (Note 18)	1
Net other comprehensive income	1
Balance at December 31, 2015	(4	)
Change in fair value of cash flow hedges	3
Amounts reclassified from AOCL	(2	)
PNGTS’ amortization of realized loss on derivative instrument (Note 18)	1
Net other comprehensive income	2
Balance as of December 31, 2016	(2	)

(a)Recast  to consolidate PNGTS for all periods presented (Refer to in Note 2). Additionally, AOCL as presented here is net of non-controlling interest on PNGTS.

NOTE 11 FINANCIAL CHARGES AND OTHER

Year ended December 31 (millions of dollars)	2016(a)		2015(a)		2014(a)
Interest expense (b)	69		65		59
Net realized loss related to the interest rate swaps	3		2		2
PNGTS’ amortization of realized loss on derivative instrument (Note 18)	1		1		1
Other	(2	)	(5	)	(1	)
	71		63		61

(a)Recast to consolidate PNGTS for all periods presented.

(b)Effective January 1, 2016, interest expense includes amortization of debt issuance costs and discount costs. Refer to Note 3.

NOTE 12 NET INCOME (LOSS) PER COMMON UNIT

Net income (loss) per common unit is computed by dividing net income attributable to controlling interests, after deduction of  net income attributed to PNGTS’ former parent, amounts attributable to the General Partner andClass 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 (refer to Note 13).

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The amount allocable to the Class B units in 2016 equals an amount based upon 30 percent of GTN’s distributable cash flow during the year ended December 31, 2016 less $20 million (2015 - $15 million).

Net income (loss) per common unit was determined as follows:

(millions of dollars, except per common unit amounts)	2016			2015			2014
Net income attributable to controlling interests (a)	248			37			195
Net income attributable to PNGTS’ former parent (a) (b)	(4		)	(24		)	(23		)
Net income allocable to General Partner and Limited Partners	244			13			172
Incentive distributions attributable to the General Partner (c)	(7		)	(3		)	(1		)
Net income attributable to the Class B units (d)	(22		)	(12		)	—
Net income (loss) allocable to the General Partner and common units	215			(2		)	171
Net income (loss) allocable to the General Partner’s two percent interest	(4		)	—			(3		)
Net income (loss) attributable to common units	211			(2		)	168
Weighted average common units outstanding (millions) — basic and diluted	65.7		(e)	63.9			62.7
Net income (loss) per common unit — basic and diluted (f)	$	3.21		$	(0.03	)	$	2.67

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

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

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

(d)As discussed in Note 9, the Class B units entitle TransCanada to a distribution which is an amount based on 30 percent of GTN’s distributions after exceeding certain annual thresholds. The distribution will be payable in the first quarter with respect to the prior year’s distributions. Consistent with the application of Accounting Standards Codification (ASC) Topic 260 — “Earnings per share”, the Partnership allocated a portion of net income attributable to controlling interests to the Class B units in an amount equal to 30 percent of GTN’s total distributable cash flows during the year ended December 31, 2016 less the threshold level of $20 million (2015 - less $15 million). During the year ended December 31, 2016, 30 percent of GTN’s total distributable cash flow was $42 million. As a result of exceeding the threshold level of $20 million, $22 million of net income attributable to controlling interests was allocated to the Class B units at December 31, 2016 (2015 - $12 million). Refer to Note 9.

(e)Includes the common units subject to rescission. These units are treated as outstanding for financial reporting purposes. Refer to Note 9.

(f)Net income (loss) per common unit prior to recast.

NOTE 13 CASH DISTRIBUTIONS

The Partnership makes cash distributions to its partners with respect to each calendar quarter within 45 days after the end of each quarter. Distributions are based on Available Cash, as defined in the Partnership Agreement, which includes all cash and cash equivalents of the Partnership and working capital borrowings less reserves established by the General Partner.

Pursuant to the Partnership Agreement, the General Partner receives two percent of all cash distributions in regard to its general partner interest and is also entitled to incentive distributions as described below. The unitholders receive the remaining portion of the cash distribution.

The following table illustrates the percentage allocations of available cash from operating surplus between the common unitholders and our General Partner based on the specified target distribution levels. The percentage interests set forth below for our General Partner include its two percent general partner interest and IDRs, and assume our General Partner has contributed any additional capital necessary to maintain its two percent general partner interest. The distribution to the General Partner illustrated below, other than in its capacity as a holder of 5,797,106 common units that are in excess of its effective two percent general partner interest, represents the IDRs.

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		Marginal Percentage Interest in Distribution
	Total Quarterly Distribution Per Unit Target Amount	Common Unitholders		General Partner
Minimum Quarterly Distribution	$0.45	98	%	2	%
First Target Distribution	above $0.45 up to $0.81	98	%	2	%
Second Target Distribution	above $0.81 up to $0.88	85	%	15	%
Thereafter	above $0.88	75	%	25	%

The following table provides information about our distributions (in millions, except per unit distributions amounts).

				Limited Partners					General Partner
Declaration Date	Payment Date	Per Unit Distribution		Common Units		Class B Units(c)			2%		IDRs(a)		Total Cash Distribution
1/16/2014	2/14/2014	$	0.81	$	50	$	—		$	1	$	—	$	51
4/25/2014	5/15/2014	$	0.81	$	51	$	—		$	1	$	—	$	52
7/23/2014	8/14/2014	$	0.84	$	53	$	—		$	1	$	—	$	54
10/23/2014	11/14/2014	$	0.84	$	53	$	—		$	1	$	1	$	55
1/22/2015	2/13/2015	$	0.84	$	54	$	—		$	1	$	—	$	55
4/23/2015	5/15/2015	$	0.84	$	54	$	—		$	1	$	—	$	55
7/23/2015	8/14/2015	$	0.89	$	56	$	—		$	2	$	1	$	59
10/22/2015	11/13/2015	$	0.89	$	57	$	—		$	1	$	1	$	59
1/21/2016	2/12/2016	$	0.89	$	57	$	12	(d)	$	1	$	1	$	71
4/21/2016	5/13/2016	$	0.89	$	58	$	—		$	1	$	1	$	60
7/21/2016	8/12/2016	$	0.94	$	62	$	—		$	1	$	2	$	65
10/20/2016	11/14/2016	$	0.94	$	63	$	—		$	1	$	2	$	66
1/23/2017 (b)	2/14/2017 (b)	$	0.94	$	64	$	22	(e)	$	2	$	2	$	90

(a)The distributions paid for the year ended December 31, 2016 included incentive distributions to the General Partner of $6 million (2015 - $2 million, 2014 - $1 million).

(b)On February 14, 2017, we paid a cash distribution of $0.94 per unit on our outstanding common units to unitholders of record at the close of business on February 2, 2017 (refer to Note 24).

(c)The Class B units issued by us on April 1, 2015 represent limited partner interests in us and entitle TransCanada to an annual distribution which is an amount based on 30 percent of GTN’s annual distributions after exceeding certain annual thresholds (refer to Note 6 and 9).

(d)On February 12, 2016, we paid TransCanada $12 million representing 30 percent of GTN’s total distributable cash flows for the nine months ended December 31, 2015 less $15 million.

(e)On February 14, 2017, we paid TransCanada $22 million representing 30 percent of GTN’s total distributable cash flows for the year ended December 31, 2016 less $20 million (refer to Note 9 and 24).

NOTE 14 CHANGE IN OPERATING WORKING CAPITAL

Year Ended December 31 (millions of dollars)	2016 (c)		2015(c)		2014(c)
Change in accounts receivable and other	(4	)	6		2
Change in other current assets	(4	)	(1	)	(1	)
Change in accounts payable and accrued liabilities (a)	5		(2	)	29
Change in accounts payable to affiliates	—		(15	) (b)	(6	)
Change in state income taxes payable	—		(5	)	2
Change in accrued interest	2		(3	)	3
Change in operating working capital	(1	)	(20	)	29

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

(b)Excludes certain non-cash items primarily related to accruals of $10 million for construction of GTN’s Carty Lateral and $2 million of costs related to acquisition of 49.9 percent interest in PNGTS (Refer to Note 6).

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

NOTE 15 TRANSACTIONS WITH MAJOR CUSTOMERS

The following table shows revenues from the Partnership’s major customers comprising more than 10 percent of the Partnership’s total consolidated recasted revenues (refer to Note 2) for the years ended December 31, 2016, 2015 and 2014:

Year Ended December 31 (millions of dollars)	2016		2015	2014
Anadarko Energy Services Company (Anadarko)	48		48	48
Pacific Gas and Electric Company (Pacific Gas)	36	(a)	42	45

At December 31, 2016 and 2015, Anadarko owed the Partnership approximately $4 million, which is approximately 10 percent of our consolidated recasted trade accounts receivable (Refer to Note 2).

(a)Less than 10 percent

NOTE 16 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 $3 million for each of the years ended December 31, 2016, 2015 and 2014.

As operator, TransCanada’s subsidiaries provide capital and operating services to GTN, Northern Border, PNGTS, Bison, Great Lakes, North Baja and Tuscarora (together, “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 years ended December 31, 2016, 2015 and 2014 by TransCanada’s subsidiaries and amounts payable to TransCanada’s subsidiaries at December 31, 2016 and 2015 are summarized in the following tables:

Year ended December 31 (millions of dollars)	2016	2015	2014
Capital and operating costs charged by TransCanada’s subsidiaries to:
Great Lakes (a)	30	30	30
Northern Border (a)	32	36	35
PNGTS (a) (b)	8	8	8
GTN (a) (c)	27	30	30
Bison (a) (d)	2	4	6
North Baja	4	5	5
Tuscarora	5	4	4
Impact on the Partnership’s net income attributable to controlling interests:
Great Lakes	13	13	13
Northern Border	12	14	16
PNGTS (b)	5	5	5
GTN (c)	24	25	19
Bison (d)	3	4	4
North Baja	4	5	4
Tuscarora	4	4	4

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December 31 (millions of dollars)	2016	2015
Amount payable to TransCanada’s subsidiaries for costs charged in the year by:
Great Lakes (a)	4	3
Northern Border (a)	4	5
PNGTS (a) (b)	1	3
GTN	3	3
Bison	1	—
North Baja	1	—
Tuscarora	1	1

(a)Represents 100 percent of the costs.

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

(c)In 2015, the Partnership acquired the remaining 30 percent interest in GTN (Refer to Note 6).

(d)In 2014, the Partnership acquired the remaining 30 percent interest in Bison (Refer to Note 6).

Great Lakes

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 year ended December 31, 2016, Great Lakes earned 68 percent of its transportation revenues from TransCanada and its affiliates  (2015 — 71 percent; 2014 — 49 percent). Additionally, Great Lakes earned approximately one percent of its total revenues as affiliated rental revenue in 2016 (2015 — 1 percent and 2014 — 1 percent).

At December 31, 2016, $19 million was included in Great Lakes’ receivables in regards to the transportation contracts with TransCanada and its affiliates (December 31, 2015 — $17 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 ROEs. A refund of $2.5 million was paid to shippers in 2016 relating to the year ended December 31, 2015, of which approximately 85 percent was made to affiliates of Great Lakes. For the year ended December 31, 2016, Great Lakes has recorded an estimated revenue sharing provision amounting to $7.2 million and Great Lakes expects that a significant percentage of the refund will be to its affiliates as well.

Great Lakes has a cash management agreement with TransCanada whereby Great Lakes’ funds are pooled with other TransCanada affiliates. The agreement also gives Great Lakes the ability to obtain short-term borrowings to provide liquidity for Great Lakes’ operating needs. At December 31, 2016 and 2015, Great Lakes has an outstanding receivable from this arrangement amounting to $27 million and $51 million, respectively.

Effective November 1, 2014, Great Lakes executed contracts with an affiliate, ANR Pipeline Company (ANR), to provide firm service in Michigan and Wisconsin.  These contracts were at the maximum FERC authorized rate and were intended to replace historical contracts.  On December 3, 2014, FERC accepted and suspended Great Lakes’ tariff records to become effective May 3, 2015, subject to refund.  On February 2, 2015, FERC issued an Order granting a rehearing and clarification request submitted by Great Lakes, which allowed additional time for FERC to consider Great Lakes’ request.  Following extensive discussions with numerous shippers and other stakeholders, on April 20, 2015, ANR filed a settlement with FERC that included an agreement by ANR to pay Great Lakes the difference between the historical and maximum rates (ANR Settlement). Great Lakes provided service to ANR under multiple service agreements and rates through May 3, 2015 when Great Lakes’ tariff records became effective and subject to refund.  Great Lakes deferred an approximate $9 million of revenue related to services performed in 2014 and approximately $14 million of additional revenue related to services performed through May 3, 2015 under such agreements. On October 15, 2015, FERC accepted and approved the ANR Settlement.  As a result, Great Lakes recognized the deferred transportation revenue of approximately $23 million in the fourth quarter of 2015.

PNGTS

For the years ended December 31, 2016 and 2015, PNGTS provided transportation services to a related party. Revenues from TransCanada Energy Ltd., a subsidiary of TransCanada, for 2016 and 2015 were approximately $2 million and $3 million, respectively. At December 31, 2016, PNGTS had nil million outstanding receivables from TransCanada Energy Ltd. in the consolidated balance sheets.

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NOTE 17 QUARTERLY FINANCIAL DATA (unaudited)

The following sets forth selected unaudited financial data for the four quarters in 2016 and 2015:

Quarter ended (millions of dollars except per common unit amounts)	Mar 31		Jun 30		Sept 30		Dec 31
2016
Transmission revenues (a)	111		101		103		111
Equity earnings (a) (b ) (c)	33		20		22		22
Net income (a)	81		57		60		65
Net income attributable to controlling interests (a)	74		55		58		61
Net income per common unit (d)	$	1.10	$	0.76	$	0.65	$	0.70
Cash distribution paid (f)	71		60		65		66
2015
Transmission revenues (a)	114		97		96		110
Equity earnings (e)	31		15		17		34
Impairment of equity-method investment (b)	—		—		—		(199		)
Net income (loss) (a)	81		47		54		(124		)
Net income (loss) attributable to controlling interests (a)	67		46		52		(128		)
Net income (loss) per common unit (d)	$	0.88	$	0.66	$	0.70	$	(2.27	)
Cash distribution paid (f)	55		55		59		59

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

(b)Equity Earnings represents our share in investee’s earnings and does not include any impairment charge on equity method goodwill included as part of the carrying value of our equity investments.

(c)During the year ended December 31, 2016, no impairment has been identified related to our equity investments in Northern Border and Great Lakes.

(d)Historical net income (loss) per common unit was not recasted.

(e)During the three months ended December 31, 2015, we recognized an impairment charge on our investment in Great Lakes amounting to $199 million. During the year ended December 31, 2015, no impairment has been identified on our investment in Northern Border (Refer to Note 4).

(f)Distributions paid to common units and Class B units.

NOTE 18 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 input 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, accrued interest and short-term debt 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 long-term debt is estimated by discounting the future cash flows of each instrument at estimated current borrowing rates. The fair value of interest rate derivatives is calculated using the income approach which uses period-end market rates and applies a discounted cash flow valuation model.

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

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Long-term debt is recorded at amortized cost and classified in Level 2 of the fair value hierarchy for fair value disclosure purposes. Interest rate derivative assets and liabilities are classified in Level 2 for all periods presented where the fair value is determined by using valuation techniques that refer to observable market data or estimated market prices. The estimated fair value of the Partnership’s debt as at December 31, 2016 and December 31, 2015 was $1,963 million and $1,945 million, respectively.

The ATM common units which may be subject to rescission rights, as discussed more fully in Note 9, were measured using the original issuance price, plus statutory interest and less any distributions paid. This fair value measurement is classified as Level 2.

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 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). At December 31, 2015, the fair value of the interest rate swaps accounted for as cash flow hedges was a liability of $1 million both on a gross and net basis. The Partnership did not record any amounts in net income related to ineffectiveness for interest rate hedges for the years ended December 31, 2016, 2015 and 2014. The net change in fair value of interest rate derivative instruments recognized in other comprehensive income was a gain of $2 million for the year ended December 31, 2016 (2015 — nil million, 2014 — loss of $1 million). In 2016, the net realized loss related to the interest rate swaps was $3 million, and was included in financial charges and other (2015 — $2 million, 2014 — $2 million).  Refer to Note 11 — Financial Charges and Other.

The Partnership has no master netting agreements, however, contracts contain 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 net asset of nil million as of December 31, 2016 and there would be no effect on the consolidated balance sheet as of December 31, 2015.

In anticipation of a debt refinancing in 2003, PNGTS entered into forward interest rate swap agreements to hedge the interest rate on its Senior Secured Notes due in 2018. These interest rate swaps were used to manage the impact of interest rate fluctuations and qualified as derivative financial instruments in accordance with ASC 815, Derivatives and Hedging. PNGTS settled its position with a payment of $20.9 million to counterparties at the time of the refinancing and recorded the realized loss in AOCL as of the termination date. The previously recorded AOCL is currently being amortized against earnings over the life of the PNGTS Senior Secured Notes.  At December 31, 2016, our 61.71 percent proportionate share of net unamortized loss on PNGTS included in AOCL was $2 million (2015 - $2 million). For the year ended December 31, 2016, 2015 and 2014, our 61.71 percent proportionate share of the amortization of realized loss on derivative instruments was $0.8 million for each year.

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 cash and cash equivalents and receivables, 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 December 31, 2016, we had not incurred any significant credit losses and had no significant amounts past due or impaired. At December 31, 2016, we had a credit risk concentration on one of our customers and the amount owed is greater than 10 percent of our recasted trade accounts receivable (refer to Note 15).

(c) Other

The estimated fair value measurements on Tuscarora (refer to Note 20) and our equity investment in Great Lakes (refer to Note 4) are both classified as Level 3. In the determination of the fair value, we used internal forecasts on expected future cash flows and applied appropriate discount rates. The determination of expected future cash flows involved significant assumptions and estimates as discussed more fully on Notes 4 and 20.

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NOTE 19 ACCOUNTS RECEIVABLE AND OTHER

December 31 (millions of dollars)	2016 (a)	2015(a)
Trade accounts receivable, net of allowance of nil	44	40
Imbalance receivable from affiliates	2	1
Other	1	—
	47	41

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

NOTE 20 GOODWILL AND REGULATORY

Tuscarora - On January 21, 2016, FERC issued an Order initiating an investigation pursuant to Section 5 of the Natural Gas Act of 1938 (NGA) to determine whether Tuscarora’s existing rates for jurisdictional services are just and reasonable. On July 22, 2016, Tuscarora filed a petition with FERC requesting appeal of the Stipulation and Agreement of Settlement (Tuscarora Settlement) Tuscarora made with its customers. On September 22, 2016, FERC approved the Tuscarora Settlement that resolved the Section 5 rate review initiated by FERC in January 2016. Under the terms of the Tuscarora Settlement, Tuscarora’s system-wide unit rate initially decreased by 17 percent, effective August 1, 2016. Unless superseded by a subsequent rate case or settlement, this rate will remain in effect until July 31, 2019, after which time the unit rate will decrease an additional seven percent from August 1, 2019 through July 31, 2022. The settlement does not contain a rate moratorium and requires Tuscarora to file to establish new rates no later than August 1, 2022.

The reduction in Tuscarora’s future cash flows as a result of the Tuscarora Settlement constituted a triggering event in the second quarter of 2016 that led us to evaluate, for possible impairment, the $82 million of goodwill related to our acquisition of Tuscarora.

Our second quarter analysis which was also reviewed for any material updates as part of our annual impairment test on goodwill, resulted in the estimated fair value of Tuscarora exceeding its carrying value but the excess was less than 10 percent. The fair value was measured using a discounted cash flow analysis and included revenues expected from Tuscarora’s current and expected future contracting level. There is a risk that reductions in future cash flow forecasts as a result of Tuscarora not being able to maintain its current contracting level and/or not being able to realize other opportunities on the system, together with adverse changes in other key assumptions such as expected outcome of future rate proceedings, projected operating costs and estimated rate of return on invested capital, could result in a future impairment of the goodwill balance relating to Tuscarora.

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. The requested abandonments will not have any impact on existing firm transportation service.

GTN —   GTN operates under rates established pursuant to a settlement approved by FERC in June 2015. Beginning in January 2016, GTN’s rates decreased by 10 percent and will continue in effect through December 31, 2019. Unless superseded by a subsequent rate case or settlement, GTN’s rates will decrease an additional eight percent for the period January 1, 2020 through December 31, 2021 when GTN will be required to establish new rates.

PNGTS - PNGTS continues to operate under the rates approved by FERC in February 2015 (Refer to Note 2-Significant Accounting Policies-Revenue Recognition). PNGTS has no requirement to file a new rate proceeding.

NOTE 21 CONTINGENCIES

The Partnership and its pipeline systems are subject to various legal proceedings in the ordinary course of business. Our accounting for contingencies covers a variety of business activities, including contingencies for legal and environmental liabilities. The Partnership accrues for these contingencies when the assessments indicate that it is probable that a liability has been incurred or an asset will not be recovered and an amount can be reasonably estimated in accordance with ASC 450 — Contingencies. We base these estimates on currently available facts and the estimates of the ultimate outcome or resolution. Actual results may differ from estimates resulting in an impact, positive or negative, on earnings and cash flow. Contingencies that might result in a gain are not accrued in our consolidated financial statements.

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Below are the material legal proceedings that might have a significant impact on the Partnership:

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 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.

Employees Retirement System of the City of St. Louis v. TC PipeLines GP, Inc., et al. — On October 13, 2015, an alleged unitholder of the Partnership filed a class action and derivative complaint in the Delaware Court of Chancery against the General Partner, TransCanada American Investments, Ltd. (TAIL) and TransCanada, and the Partnership as a nominal defendant.   The complaint alleges direct and derivative claims for breach of contract, breach of the duty of good faith and fair dealing, aiding and abetting breach of contract, and tortious interference in connection with the 2015 GTN Acquisition, including the issuance by the Partnership of $95 million in Class B Units and amendments to the Partnership Agreement to provide for the issuance of the Class B Units.   Plaintiff seeks, among other things, to enjoin future issuances of Class B Units to TransCanada or any of its subsidiaries, disgorgement of certain distributions to the General Partner, TransCanada and any related entities, return of some or all of the Class B Units to the Partnership, rescission of the amendments to the Partnership Agreement, monetary damages and attorney fees.   The Partnership has moved to dismiss the complaint and intends to defend vigorously against the claims asserted. In April 2016, the Chancery Court granted the Partnership and other defendants’ motion to dismiss the plaintiffs’ complaint.  The plaintiff has appealed the decision to dismiss its claims.  The appeal of this matter was heard by the Delaware Supreme Court in December, 2016.  The court found in TransCanada’s favor and dismissed the Plaintiff’s motion.  There are no further rights of appeal.

NOTE 22 VARIABLE INTEREST ENTITIES

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

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

Consolidated VIEs

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

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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 Sheets:

(millions of dollars)	December 31, 2016(b)		December 31, 2015(b)
ASSETS (LIABILITIES) (a)
Cash and cash equivalents	14		16
Accounts receivable and other	33		29
Inventories	6		6
Other current assets	6		6
Equity investments	918		965
Plant, property and equipment	1,146		1,180
Other assets	2		2
Accounts payable and accrued liabilities	(21	)	(27	)
Accounts payable to affiliates, net	(32	)	(9	)
Distributions payable	(3	)	(10	)
Accrued interest	(2	)	(1	)
Current portion of long-term debt	(52	)	(36	)
Long-term debt	(337	)	(373	)
Other liabilities	(25	)	(24	)
Deferred state income tax	(10	)	(11	)

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

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

NOTE 23 INCOME TAXES

The state of New Hampshire (NH) imposes a business profits tax (BPT) levied at the PNGTS level. As a result of the BPT, PNGTS recognizes deferred taxes related to temporary differences between the financial statement carrying amount of existing assets and liabilities and their respective tax bases. The deferred taxes at December 31, 2016, 2015 and 2014 relate primarily to utility plant. For the years ended December 31, 2016, 2015 and 2014, the NH BPT effective tax rate was 3.8 percent for all periods and was applied to PNGTS’ taxable income.

The state income taxes of PNGTS are broken out as follows:

Year ended December 31 (millions of dollars)	2016 (a)	2015 (a)		2014(a)
State income taxes
Current	1	(2	)	3
Deferred	—	4		(1	)
	1	2		2

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

NOTE 24 SUBSEQUENT EVENTS

Management of the Partnership has reviewed subsequent events through August 3, 2017, the date the financial statements were issued, and concluded there were no events or transactions during this period that would require recognition or disclosure in the consolidated financial statements other than what is disclosed here and/or those already disclosed in the preceding notes.

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Partnership

On January 23, 2017, the board of directors of our General Partner declared the Partnership’s fourth quarter 2016 cash distribution in the amount of $0.94 per common unit and was paid on February 14, 2017 to unitholders of record as of February 2, 2017. The declared distribution totaled $68 million and was paid in the following manner: $64 million to common unitholders (including $5 million to the General Partner as holder of 5,797,106 common units and $11 million to another subsidiary of TransCanada as holder of 11,287,725 common units) and $4 million to our General Partner, which included $2 million for its effective two percent general partner interest and $2 million of IDRs payment.

On January 23, 2017, the board of directors of our General Partner declared distributions to Class B unitholders in the amount of $22 million and was paid on February 14, 2017. The Class B distribution represents an amount equal to 30 percent of GTN’s distributable cash flow during the year ended December 31, 2016 less $20 million.

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 was paid on May 15, 2017 to unitholders of record as of May 5, 2017. The declared distribution totaled $68 million and was paid in the following manner: $65 million to common unitholders (including $5 million to the General Partner as a holder of 5,797,106 common units and $11 million to another subsidiary of TransCanada as holder of 11,287,725 common units) and $3 million to our General Partner, which included $1 million for its effective two percent general partner interest and $2 million of IDRs.

On May 25, 2017, the Partnership closed a $500 million public offering of senior unsecured notes bearing an interest rate of 3.90 percent maturing May 25, 2027. The net proceeds of $497 million were used to fund a portion of the Partnership’s June 1, 2017  acquisition.The indenture for the notes contains customary investment grade covenants.

On June 1, 2017, the Partnership acquired from subsidiaries of TransCanada a 49.34 percent interest in Iroquois Gas Transmission System, L.P. (Iroquois), including an option to acquire a further 0.66 percent interest in Iroquois, together with an additional 11.81 percent interest in PNGTS resulting in the Partnership owning a 61.71 percent interest in PNGTS (2017 Acquisition). The total purchase price of the 2017 Acquisition was $765 million plus preliminary purchase price adjustments amounting to $9 million. The purchase price consisted of  (i) $710 million for the Iroquois interest (less $164 million, which reflected our 49.34 percent share of Iroquois outstanding debt on June 1)  (ii) $55 million for the additional 11.81 percent interest in PNGTS (less $5 million, which reflected our 11.81% proportionate share in PNGTS’ debt on June 1) and (iii) preliminary working capital adjustments on PNGTS and Iroquois amounting to $3 million and $6 million, respectively. Additionally, the Partnership paid $1,000 for the option to acquire TransCanada’s remaining 0.66 percent interest in Iroquois. The Partnership funded the cash portion of the 2017 Acquisition through a combination of proceeds from the May 2017 public debt offering (refer to Note 5) and borrowing under our Senior Credit Facility.

As at the date of the 2017 Acquisition, there was significant cash on Iroquois’ balance sheet. Pursuant to the Purchase and Sale Agreement associated with the acquisition of the Iroquois interest, as amended, the Partnership agreed to pay $28 million plus interest to TransCanada on August 1, 2017 for its 49.34 percent share of cash determined to be surplus to Iroquois’ operating needs. In addition, the Partnership expects to make a final working capital adjustment payment by the end of August. The $28 million and the related interest were included in accounts payable to affiliates at June 30, 2017.

The Iroquois’ partners adopted a distribution resolution to address the significant cash on Iroquois’ balance sheet post-closing. The Partnership expects to receive the $28 million of unrestricted cash as part of its quarterly distributions from Iroquois over 11 quarters under the terms of the resolution, beginning with the second quarter 2017 distribution on August 1, 2017.

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

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

On July 20, 2017, the board of directors of our General Partner declared the Partnership’s second quarter 2017 cash distribution in the amount of $1.00 per common unit payable on August 11, 2017 to unitholders of record as of August 1, 2017. The declared distribution reflects a $0.06 per common unit increase to the Partnership’s first quarter 2017 quarterly distribution. The declared distribution totaled $74 million and is payable in the following manner: $69 million to common unitholders (including $6 million to the General Partner as a holder of 5,797,106 common units and $11 million to another subsidiary of TransCanada as holder of 11,287,725 common units) and $5 million to our

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General Partner, which included $2 million for its effective two percent general partner interest and $3 million of IDRs.

Northern Border

Northern Border declared its December 2016 distribution of $16 million on January 9, 2017, of which the Partnership received its 50 percent share or $8 million. The distribution was paid on January 31, 2017.

Northern Border declared its January 2017 distribution of $18 million on February 15, 2017, of which the Partnership received its 50 percent share or $9 million on February 28, 2017.

Northern Border declared its February 2017 distribution of $9 million on March 10, 2017, of which the Partnership received its 50 percent share or $5 million on March 31, 2017.

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.

Northern Border declared its April 2017 distribution of $14 million on May 12, 2017, of which the Partnership received its 50 percent share or $7 million on May 31, 2017.

Northern Border declared its May 2017 distribution of $12 million on June 7, 2017, of which the Partnership received its 50 percent share or $6 million on June 30, 2017.

Northern Border declared its June 2017 distribution of $14 million on July 7, 2017, of which the Partnership received its 50 percent share or $7 million on July 31, 2017.

Great Lakes

Great Lakes declared its fourth quarter 2016 distribution of $14 million on January 9, 2017, of which the Partnership received its 46.45 percent share or $7 million. The distribution was paid on February 1, 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.

Great Lakes declared its second quarter 2017 distribution of $15 million on July 18, 2017, of which the Partnership will receive its 46.45 percent share or $7 million on August 1, 2017.

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 filed its rate case pursuant to Section 4 of the Natural Gas Act. 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 is currently seeking 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 March 31, 2017 General Section 4 Rate Filing. We cannot predict the cumulative impact of these circumstances to the Partnership’s earnings and cash flows at this time.

PNGTS

On January 3, 2017, PNGTS  paid the amount due on December 31, 2016 on its 2003 Senior Secured Notes amounting to $6.3 million representing $5.5 million in principal and $0.8 million in interest pursuant to the terms of the Note Purchase agreement. Under the agreement, any principal and interest that is due on a date other than a normal business day shall be made on the next succeeding business day without additional interest or penalty.

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Iroquois

Iroquois declared its second quarter 2017 distribution of $28 million on July 27, 2017, of which the Partnership received its 49.34 percent share or $14 million on August 1, 2017.

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EX-99.3

Exhibit 99.3

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis should be read in conjunction with the Audited Consolidated Financial Statements and Notes thereto for the year ended December 31, 2016 included as Exhibit 99.2 of this Current Report on Form 8-K. This report includes certain forward-looking statements. 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. 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.

Management’s Discussion and Analysis is intended to give our unitholders an opportunity to view the Partnership through the eyes of our management. We have done so by providing management’s current assessment of, and outlook of the business of the Partnership. Our discussion and analysis includes the following:

·BASIS OF PRESENTATION;

·EXECUTIVE OVERVIEW;

·HOW WE EVALUATE OUR OPERATIONS;

·RESULTS OF OPERATIONS;

·LIQUIDITY AND CAPITAL RESOURCES;

·CRITICAL ACCOUNTING ESTIMATES;

·CONTINGENCIES; and

·RELATED PARTY TRANSACTIONS.

BASIS OF PRESENTATION

See the Basis of Presentation section of Note 2- Significant Accounting Policies, Notes to Consolidated Financial Statements for the year ended December 31, 2016 included in Exhibit 99.2 of this Current Report on Form 8-K, for important information on the content and comparability of our historical financial statements.

The initial acquisition of a 49.9 percent interest in PNGTS on January 1, 2016 and additional 11.81 percent on June 1, 2017 (collectively, the PNGTS Acquisitions) were accounted for as transaction between entities under common control, which are required to be accounted for as if the PNGTS Acquisitions had occurred at the beginning of the year, with financial statements for prior periods recast to furnish comparative information. Accordingly, the accompanying financial information has been recast, except net income (loss) per common unit, to consolidate PNGTS for all periods presented.

Also, on June 1, 2017, the Partnership acquired from subsidiaries of TransCanada a 49.34 percent in Iroquois (Refer to Note 24-Subsequent Events Notes to Consolidated Financial Statements  for the year ended December 31, 2016 included in Exhibit 99.2 of this Current Report on Form 8-K). This transaction was accounted prospectively and did not form part of the accompanying financial information.

EXECUTIVE OVERVIEW

Net income (loss) attributable to controlling interests was $248 million or $3.21 per common unit in 2016 compared to $37 million, or $(0.03) per common unit in 2015. Adjusted earnings, which excluded the impact of the $199 million non-cash impairment charge on our investment in Great Lakes in the fourth quarter 2015, increased by $12 million in 2016 compared to 2015. Cash distributions declared per common unit increased by six percent from $3.51 per common unit in 2015 to $3.71 per common unit in 2016. Please see “Non-GAAP Financial Measures: Adjusted earnings and Adjusted earnings per common unit” for more information.

Our 2016 EBITDA increased by $210 million to $433 million compared to $223 million in 2015 primarily due to the recognition of $199 million non-cash impairment charge to our investment in Great Lakes in 2015. Our Adjusted

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EBITDA, which excluded the impact of the $199 million non-cash impairment charge on our investment in Great Lakes, increased by three percent to $433 million and Distributable cash flow increased by eight percent to $313 million. Please see “Non-GAAP Financial Measures: Adjusted earnings and Adjusted earnings per common unit” for more information.

2017 Developments

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 filed its rate case pursuant to Section 4 of the Natural Gas Act. 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 is currently seeking 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 March 31, 2017 General Section 4 Rate Filing. We cannot predict the cumulative impact of these circumstances to the Partnership’s earnings and cash flows at this time.

Debt Offering-On May 25, 2017, the Partnership closed a $500 million public offering of senior unsecured notes bearing an interest rate of 3.90 percent maturing May 25, 2027. The net proceeds of $497 million were used to fund a portion of the Partnership’s June 1, 2017 acquisitions. The indenture for the notes contains customary investment grade covenants.

2017 Acquisition — On June 1, 2017, the Partnership acquired from subsidiaries of TransCanada a 49.34 percent interest in Iroquois Gas Transmission System, L.P. (Iroquois), including an option to acquire a further 0.66 percent interest in Iroquois, together with an additional 11.81 percent interest in PNGTS resulting in the Partnership owning a 61.71 percent interest in PNGTS (2017 Acquisition). The total purchase price of the 2017 Acquisition was $765 million plus preliminary purchase price adjustments amounting to $9 million. The purchase price consisted of  (i) $710 million for the Iroquois interest (less $164 million, which reflected our 49.34 percent share of Iroquois outstanding debt on June 1)  (ii) $55 million for the additional 11.81 percent interest in PNGTS (less $5 million, which reflected our 11.81% proportionate share in PNGTS’ debt on June 1) and (iii) preliminary working capital adjustments on PNGTS and Iroquois amounting to $3 million and $6 million, respectively. Additionally, the Partnership paid $1,000 for the option to acquire TransCanada’s remaining 0.66 percent interest in Iroquois. The Partnership funded the cash portion of the 2017 Acquisition through a combination of proceeds from the May 2017 public debt offering and borrowing under our Senior Credit Facility.

As at the date of the 2017 Acquisition, there was significant cash on Iroquois’ balance sheet. Pursuant to the Purchase and Sale Agreement associated with the acquisition of the Iroquois interest, as amended, the Partnership agreed to pay $28 million plus interest to TransCanada on August 1, 2017 for its 49.34 percent share of cash determined to be surplus to Iroquois’ operating needs. In addition, the Partnership expects to make a final working capital adjustment payment by the end of August. The $28 million and the related interest were included in accounts payable to affiliates at June 30, 2017.

The Iroquois’ partners adopted a distribution resolution to address the significant cash on Iroquois’ balance sheet post-closing. The Partnership expects to receive the $28 million of unrestricted cash as part of its quarterly distributions from Iroquois over 11 quarters under the terms of the resolution, beginning with the second quarter 2017 distribution on August 1, 2017.

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

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

2016 Developments

2016 PNGTS Acquisition- On January 1, 2016, the Partnership completed the $228 million acquisition of a 49.9 percent interest in PNGTS from a subsidiary of TransCanada. The purchase price was comprised of $193 million in cash and the assumption of $35 million in proportional PNGTS debt. This transaction added a new market geography for us, extending our breadth of operations and further diversifying our cash flow stream.

Tuscarora Rate Case - On January 21, 2016, FERC issued an Order initiating an investigation pursuant to Section 5 of the NGA to determine whether Tuscarora’s existing rates for jurisdictional services were just and reasonable. On September 22, 2016, FERC approved the settlement (Tuscarora Settlement) Tuscarora made with its customers that resolved the Section 5 review initiated by FERC. Under the terms of the Tuscarora Settlement, Tuscarora’s system-wide unit rate initially decreased by 17 percent, effective August 1, 2016. Unless superseded by a subsequent rate

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case or settlement, this rate will remain in effect until July 31, 2019, after which time the unit rate will decrease by an additional seven percent from August 1, 2019 through July 31, 2022. The settlement does not contain a rate moratorium and requires Tuscarora to file to establish new rates no later than August 1, 2022. While this new rate structure reduced Tuscarora’s cash flows beginning August 1, 2016, the achievement of rate certainty helps ensure predictable cash flows from this pipeline system.

Outlook of Our Business

TransCanada, the ultimate parent company of our General Partner, closed the acquisition of all of the outstanding publicly-held common units of Columbia Pipeline Partners LP on February 17, 2017. This acquisition leaves TransCanada with a single MLP in TC PipeLines, which it describes as a core element of TransCanada’s strategy.

TransCanada is advancing CAD $24 billion of near-term capital projects, approximately CAD $9 billion of which has been invested to date with the remainder to be spent largely over the next three years. TransCanada says it intends to prudently fund its capital program in a manner that is consistent with maintaining its financial strength, including potential drop downs to the Partnership.

The Partnership’s financial performance continues to benefit from its transactions with TransCanada, Despite the volatility in energy commodity prices, our portfolio of eight FERC-regulated interstate natural gas pipelines is expected to deliver generally stable results in 2017 due to ship-or-pay contracts with creditworthy customers.

HOW WE EVALUATE OUR OPERATIONS

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

EBITDA

We use EBITDA as an approximate measure of our operating cash flow and current operating profitability. It measures our earnings from our pipeline systems before certain expenses are deducted.

Adjusted EBITDA, Adjusted earnings and Adjusted earnings per common unit

We have evaluated our financial performance and position inclusive of the impairment charge to our investment in Great Lakes recognized during the fourth quarter of 2015, however, we believe it is not reflective of our underlying operations during the periods presented. Therefore, we have presented adjusted EBITDA, adjusted earnings and adjusted earnings per common unit as non-GAAP measures that exclude the impact of the $199 million non-cash impairment charge.

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, Adjusted EBITDA and Distributable Cash Flow” for more information.

RESULTS OF OPERATIONS

Our equity interests in Northern Border, Great Lakes, 61.71 percent ownership in PNGTS, and our full ownership of GTN, Bison, North Baja and Tuscarora were our only material sources of income during the periods presented. Therefore, our results of operations and cash flows were influenced by, and reflect the same factors that influenced, our pipeline systems.

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Year Ended December 31, 2016 Compared with the Year Ended December 31, 2015

(unaudited) (millions of dollars, except per common unit amounts)	2016 (a)		2015 (a)		$ Change (d)		% Change (d)
Transmission revenues	426		417		9		2
Equity earnings	97		97		—		—
Impairment of equity-method investment	—		(199	)	199		100
Operating, maintenance and administrative	(92	)	(97	)	5		5
Depreciation	(96	)	(95	)	(1	)	(1	)
Financial charges and other	(71	)	(63	)	(8	)	(13	)
Net income before taxes	264		60		204		*
Income taxes	(1	)	(2	)	1		50
Net Income	263		58		205		*
Net income attributable to non-controlling interests	15		21		6		29
Net income attributable to controlling interests	248		37		211		*
Adjusted earnings (b)	248		236		12		5
Net income (loss) per common unit (c)	3.21		(0.03	)	3.24		*
Adjusted earnings per common unit (b)	3.21		3.03		0.18		6

(a)Financial information was recast to consolidate PNGTS for all periods presented. Please see “Basis of Presentation” section for more information.

(b)Adjusted earnings and Adjusted earnings per common unit are non-GAAP measures for which reconciliations to the appropriate GAAP measures are provided for below.

(c)Net income (loss) per common unit prior to recast.

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

*Change is greater than 100 percent.

Net income attributable to controlling interests increased by $211 million to $248 million in 2016 compared to $37 million in 2015, resulting in net income per common unit during the year of $3.21 after allocations to the General Partner and to the Class B units. This increase was primarily the result of the recognition of a $199 million non-cash impairment charge to our investment in Great Lakes in fourth quarter 2015 which lowered our net income attributable to controlling interests in 2015. (See Critical Accounting Estimates - Impairment of Equity Investments, Goodwill and Long-Lived Assets — Equity Investments section for more information.)

The Partnership’s Adjusted earnings were higher by $12 million in 2016 compared to 2015, an increase of $0.18 per common unit mainly due to the following:

Transmission revenues - increase of $9 million primarily due to the net effect of:

·higher discretionary revenues on GTN from short-term services sold to its customers;

·lower discretionary revenues on PNGTS from short-term services sold to its customers;

·full year of  revenues from GTN’s Carty lateral system which was placed into service in October 2015; and

·lower transportation rates on GTN as a result of the settlement reached with its customers effective July 1, 2015.

Operating, maintenance and administrative - generally lower expenses in 2016 as a result of lower operational costs on our consolidated entities. Additionally, dropdown costs were incurred in 2015 related to the acquisition of the initial 49.9 percent interest on PNGTS.

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Financial charges and other - $8 million increase primarily due to the net effect of:

·additional borrowings to fund a portion of our recent acquisitions

·lower interest incurred by PNGTS as a result of its 2016 principal payments on its long term debt

·no interest was incurred in 2016 on PNGTS’ rate refund liability due to the payment of  all of PNGTS’ outstanding rate refund liability on April 15, 2015.  (See Note 2-Significant Accounting Policies-Revenue Recognition section, Notes to Consolidated Financial Statements for the year ended December 31, 2016 included in Exhibit 99.2 of this Current Report on Form 8-K for more details)

Net income attributable to non-controlling interests - $6 million decrease primarily due to the Partnership’s 100 percent ownership in GTN effective April 1, 2015.

Year Ended December 31, 2015 Compared with the Year Ended December 31, 2014

(unaudited) (millions of dollars, except per common unit amounts)	2015 (a)		2014 (a)		$ Change (d)		% Change (d)
Transmission revenues	417		410		7		2
Equity earnings	97		88		9		10
Impairment of equity-method investment	(199	)	—		(199	)	(100	)
Operating, maintenance and administrative	(97	)	(98	)	1		1
Depreciation	(95	)	(96	)	1		1
Financial charges and other	(63	)	(61	)	(2	)	(3	)
Net income before taxes	60		243		183		(75	)
Income taxes	(2	)	(2	)	—		—
Net Income	58		241		183		(76	)
Net income attributable to non-controlling interests	21		46		25		54
Net income attributable to controlling interests	37		195		158		(81	)
Adjusted earnings (b)	236		195		41		21
Net income (loss) per common unit (c)	(0.03	)	2.67		2.70		*
Adjusted earnings per common unit (b)	3.03		2.67		0.36		13

(a)Financial information was recast to consolidate PNGTS for all periods presented. Please see “Basis of Presentation” section for more information.

(b)Adjusted earnings and Adjusted earnings per common unit are non-GAAP measures for which reconciliations to the appropriate GAAP measures are provided for below.

(c)Net income (loss) per common unit prior to recast.

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

*Change is greater than 100 percent.

Net income attributable to controlling interests decreased by $158 million to $37 million in 2015 compared to $195 million in 2014, resulting in a net loss per common unit during the year of $0.03 after allocations to the General Partner and to the Class B units. This decrease was primarily the result of the recognition of a $199 million non-cash impairment charge to our investment in Great Lakes in fourth quarter 2015. (See Critical Accounting Estimates - Impairment of Equity Investments, Goodwill and Long-Lived Assets — Equity Investments section for more information.)

The Partnership’s Adjusted earnings were higher by $41 million in 2015 compared to 2014, an increase of $0.36 per common unit due to the following:

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Transmission revenues - increase of $7 million primarily due to higher discretionary revenues on GTN from short-term services sold to its customers.

Earnings from equity investments - $9 million increase mainly due the net effect of:

·lower equity earnings from Northern Border primarily due to lower revenues from the sale of short-term services as a result of the milder winter in 2015 compared to 2014; and

·higher equity earnings from Great Lakes in 2015 primarily due to additional revenues from new contracts with ANR, a related party.

Operating, maintenance and administrative - $1 million decrease was mainly due to the net effect of: lower expenses on Bison related to pipeline integrity program spending;

·lower property taxes on Bison as compared to 2014;and

·higher operating costs on PNGTS

Financial charges and other - $2 million increase mainly due to the net effect of:

·additional borrowings to fund a portion of our recent acquisitions;

·lower interest incurred by PNGTS as a result of its 2015 principal payments on its long term debt; and

·lower interest on PNGTS’ rate refund liability due to the payment of  all of PNGTS’  outstanding rate refund liability on April 15, 2015. (See Note 2-Significant Accounting Policies-Revenue Recognition, Notes to Consolidated Financial Statements for the year ended December 31, 2016 included in Exhibit 99.2 of this Current Report on Form 8-K for more details)

Net income attributable to non-controlling interests - $25 million decrease due to our 100 percent ownership in GTN and Bison effective April 1, 2015 and October 1, 2014, respectively.

Non-GAAP Financial Measures: Adjusted earnings and Adjusted earnings per common unit

Reconciliation of Net income attributable to controlling interests to Adjusted earnings

(millions of dollars)
Year ended December 31	2016	2015	2014
Net income attributable to controlling interests	248	37	195
Add: Impairment of equity-method investment	—	199	—
Adjusted earnings	248	236	195

Reconciliation of Net income (loss) per common unit to Adjusted earnings per common unit

Year ended December 31	2016	2015		2014
Net income (loss) per common unit-basic and diluted (a)	3.21	(.03	)	2.67
Add: per unit impact of impairment of equity-method investment (b)	—	3.06		—
Adjusted earnings per common unit	3.21	3.03		2.67

(a)Net income (loss) per common unit prior to recast.See also Note 12, Notes to Consolidated Financial statements for the year ended December 31, 2016 included in exhibit 99.2 of this Current Report on Form 8-K for details of the calculation of net income (loss) per common unit- basic and diluted.

(b)Computed by dividing the $199 million impairment charge, after deduction of amounts attributable to the General Partner with respect to its effective two percent interest, by the weighted average number of common units outstanding during the period.

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

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requirements. We expect to be able to fund our liquidity and capital resource requirements, including our distributions and required debt repayments, at the Partnership level over the next 12 months utilizing our cash flow and, if required, our existing Senior Credit Facility. The following table sets forth the available borrowing capacity under the Partnership’s Senior Credit Facility.

(unaudited) (millions of dollars)	June 30, 2017	December 31, 2016	December 31, 2015
Total capacity under the Senior Credit Facility	500	500	500
Less: Outstanding borrowings under the Senior Credit Facility	170	160	200
Available capacity under the Senior Credit Facility	330	340	300

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.

Summarized Cash Flow

Year Ended December 31,
(millions of dollars)	2016 (a)		2015(a)		2014(a)
Net cash provided by (used in):
Operating activities	417		260		417
Investing activities	(230	)	(326	)	(261	)
Financing activities	(178	)	(32	)	(119	)
Net increase in cash and cash equivalents	9		(98	)	37
Cash and cash equivalents at beginning of the period	55		153		116
Cash and cash equivalents at end of the period	64		55		153

(a)Financial information was recast to consolidate PNGTS for all periods presented. Please see “Basis of Presentation” section for more information.

Cash Flow Analysis for the Year Ended December 31, 2016 compared to Same Period in 2015

Operating Cash Flows

Net cash provided by operating activities increased by $157 million in the twelve months ended December 31, 2016 compared to the same period in 2015 primarily due to the net effect of:

·higher earnings as discussed in more detail in the “Results of Operations” section.

·higher distributed earnings received  from equity investments in 2016 as a result of additional revenues from new contracts with ANR, a related party

·payment of all of PNGTS’ outstanding rate refund liability in 2015, including interest as a result of its rate case settlement approved by FERC on February 2015. Total refunds accumulated to $114 million, including $8 million of interest, and were paid to customers on April 15, 2015. (See Note 2-Significant Accounting Policies-Revenue Recognition, Notes to Consolidated Financial Statements  for the year ended December 31, 2016 included in Exhibit 99.2 of this Current Report on Form 8-K for more details); and

·timing of working capital changes. The majority of the timing impact relates to the settlement of our accounts payable and accrued liabilities.

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Investing Cash Flows

Net cash used in investing activities decreased by $96 million in the twelve months ended December 31, 2016 compared to the same period in 2015 as we invested a lesser amount on our initial 49.9 percent acquisition of interest on PNGTS compared to our investment during the same period in 2015. In 2015, we paid $264 million to acquire the remaining 30 percent interest in GTN compared to $193 million paid for the acquisition of a 49.9 percent interest in PNGTS in 2016. Additionally, we had higher capital expenditures in 2015 due to expenditures related to the construction of the Carty Lateral.

Financing Cash Flows

Net cash used in financing activities increased by $146 million in the twelve months ended December 31, 2016 compared to the same period in 2015 primarily due to the net effect of:

·$254 million decrease in net issuances of debt in 2016 as compared with 2015;

·$123 million increase in our ATM equity issuances in 2016 as compared with 2015;

·$22 million increase in distributions paid to our common units including our General Partner’s effective two percent share and its related IDRs;

·$12 million of distributions paid to Class B units in 2016;

·$9 million decrease in distributions paid to non-controlling interest due to the Partnership’s 100 percent ownership in GTN effective April 1, 2015; and

·$10 million decrease in distributions paid to TransCanada as the former parent of PNGTS due to the Partnership’s acquisition of a 49.9 percent interest in PNGTS effective January 1, 2016.

Cash Flow Analysis for the Year Ended December 31, 2015 compared to Same Period in 2014

Operating Cash Flows

Net cash provided by operating activities decreased by $157 million in the twelve months ended December 31, 2015 compared to the same period in 2014 primarily due to the net effect of:

·payment of all of PNGTS’ outstanding rate refund liability in 2015, including interest as a result of its rate case settlement approved by FERC on February 2015. Total refunds accumulated to $114 million, including $8 million of interest, and were paid to customers on April 15, 2015. (See Note 2-Significant Accounting Policies-Revenue Recognition, Notes to Consolidated Financial Statements for the year ended December 31, 2016  included in Exhibit 99.2 of this Current Report on Form 8-K for more details;

·higher adjusted earnings as discussed in more detail in the “Results of Operations” section; and

·timing of working capital changes. The majority of the timing impact relates to the settlement of our accounts payable and accrued liabilities.

Investing Cash Flows

Net cash used in investing activities increased by $65 million in the twelve months ended December 31, 2015 compared to the same period in 2014 as we invested a higher amount on the acquisition of the remaining 30 percent interest in GTN effective April 1, 2015 compared to our investment in the acquisition of the remaining 30 percent interest in Bison. In 2015, we paid $264 million to acquire the remaining 30 percent interest in GTN compared to $217 million the remaining 30 percent interest in Bison. Additionally, we had higher capital expenditures in 2015  due to expenditures related to the construction of the Carty Lateral. We also paid an additional $25 million to TransCanada in 2014 related to our 2013 Acquisition as a result of the attainment of certain events with respect to the Carty Lateral project.

Financing Cash Flows

Net cash used in financing activities decreased by $87 million in the twelve months ended December 31, 2015 compared to the same period in 2014 primarily due to the net effect of:

·$97 million increase in net issuances of debt in 2015 as compared with 2014;

·$29 million decrease in our ATM equity issuances in 2015 as compared with 2014;

·$16 million increase in distributions paid to our common units including our General Partner’s effective two percent share and its related IDRs; and

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·$39 million decrease in distributions paid to non-controlling interest due to the Partnership’s 100 percent ownership in GTN and Bison effective April 1, 2015 and October 1, 2014, respectively.

Capital spending

The Partnership’s share in capital spending for maintenance of existing facilities and growth projects was as follows:

Year Ended December 31 (millions of dollars) (unaudited)	2016 (a)	2015 (a)	2014 (a)
Maintenance	31	21	18
Growth	5	54	4
Total (b)	36	75	22

(a)Financial information was recast to reflect our 61.71 percent share of PNGTS’ capital spending for all periods presented however, PNGTS did not incur significant capital expenditures for all the periods presented. Please see “Basis of Presentation” section for more information.

(b)Total maintenance and growth capital expenditures as reflected in this table include amounts attributable to the Partnership’s proportionate share of maintenance and growth capital expenditures of the Partnership’s equity investments, which are not reflected in our total capital expenditures as presented in our consolidated statement of cash flows.

Year Ended December 31, 2016 Compared with the Year Ended December 31, 2015

Maintenance capital spending increased by $10 million in 2016 compared to 2015 mainly due to major overhauls conducted in 2016 on Northern Border and Great Lakes and costs related to pipe integrity on Great Lakes and North Baja.

In 2015, The Partnership incurred significant spending related to the construction of Carty Lateral. No such significant project occurred in 2016.

Year Ended December 31, 2015 Compared with the Year Ended December 31, 2014

Overall capital spending increased by $53 million in 2015 compared to 2014 mainly due to the cost incurred on the construction of Carty Lateral, which was placed in service in October 2015.

Cash Flow Outlook

Operating Cash Flow Outlook

Northern Border declared its December 2016 distribution of $16 million on January 9, 2017, of which the Partnership received its 50 percent share or $8 million. The distribution was paid on January 31, 2017.

Northern Border declared its January 2017 distribution of $18 million on February 15, 2017, of which the Partnership received its 50 percent share or $9 million on February 28, 2017.

Northern Border declared its February 2017 distribution of $9 million on March 10, 2017, of which the Partnership received its 50 percent share or $5 million on March 31, 2017.

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.

Northern Border declared its April 2017 distribution of $14 million on May 12, 2017, of which the Partnership received its 50 percent share or $7 million on May 31, 2017.

Northern Border declared its May 2017 distribution of $12 million on June 7, 2017, of which the Partnership received its 50 percent share or $6 million on June 30, 2017.

Northern Border declared its June 2017 distribution of $14 million on July 7, 2017, of which the Partnership received its 50 percent share or $7 million on July 31, 2017.

Great Lakes declared its fourth quarter 2016 distribution of $14 million on January 9, 2017, of which the Partnership received its 46.45 percent share or $7 million. The distribution was paid on February 1, 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.

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Great Lakes declared its second quarter 2017 distribution of $15 million on July 18, 2017, of which the Partnership will receive its 46.45 percent share or $7 million on August 1, 2017.

Iroquois declared its second quarter 2017 distribution of $28 million on July 27, 2017, of which the Partnership received its 49.34 percent share or $14 million on August 1, 2017.

Investing Cash Flow Outlook

The Partnership expects to fund $9 million contribution in 2017 to fund debt repayments of Great Lakes which is consistent with prior years.

In 2017, our pipeline systems, which includes Iroquois, expect to invest approximately $95 million in maintenance of existing facilities and approximately $7 million in growth projects, of which the Partnership’s share would be $64 million and $3 million, respectively. Our consolidated entities have commitments of $1 million as of December 31, 2016 in connection with various maintenance and general plant projects.

Financing Cash Flow Outlook

On January 23, 2017, the board of directors of our General Partner declared the Partnership’s fourth quarter 2016 cash distribution in the amount of $0.94 per common unit which was paid on February 14, 2017 to unitholders of record as of February 2, 2017.

On January 23, 2017, the board of directors of our General Partner declared distributions to Class B unitholders in the amount of $22 million which was paid on February 14, 2017. The Class B distribution represents an amount equal to 30 percent of GTN’s distributable cash flow during the year ended December 31, 2016 less the threshold level of $20 million. For 2017, the threshold level is the same and we anticipate such threshold will be exceeded in the third quarter of 2017.

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 was paid on May 15, 2017 to unitholders of record as of May 5, 2017. The declared distribution totaled $68 million and was paid in the following manner: $65 million to common unitholders (including $5 million to the General Partner as a holder of 5,797,106 common units and $11 million to another subsidiary of TransCanada as holder of 11,287,725 common units) and $3 million to our General Partner, which included $1 million for its effective two percent general partner interest and $2 million of IDRs.

On July 20, 2017, the board of directors of our General Partner declared the Partnership’s second quarter 2017 cash distribution in the amount of $1.00 per common unit payable on August 11, 2017 to unitholders of record as of August 1, 2017. The declared distribution reflects a $0.06 per common unit increase to the Partnership’s first quarter 2017 quarterly distribution. The declared distribution totaled $74 million and is payable in the following manner: $69 million to common unitholders (including $6 million to the General Partner as a holder of 5,797,106 common units and $11 million to another subsidiary of TransCanada as holder of 11,287,725 common units) and $5 million to our General Partner, which included $2 million for its effective two percent general partner interest and $3 million of IDRs.

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

Please read Notes 6, 9, 12 and 13, Notes to Consolidated Financial Statements for the year ended December 31, 2016 included in exhibit 99.2 of this Current Report on Form 8-K for more detailed disclosures on the Class B units.

Non-GAAP Financial Measures: EBITDA, Adjusted 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 it includes earnings from our equity investments. Our Adjusted EBITDA excludes the impact of the $199 million non-cash impairment charge we recognized in fourth quarter 2015 on our investment in Great Lakes. We believe the charge is significant but not reflective of our underlying operations.

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.

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Total distributable cash flow includes our Adjusted EBITDA plus:

·Distributions from our equity investments

less:

·Earnings from our equity investments,

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

·Interest expense,

·Distributions to non-controlling interests,

·Distributions to TransCanada as former parent of PNGTS, and

·Maintenance capital expenditures.

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 equal 30 percent of GTN’s distributable cash flow for the year ended December 31, 2016 less $20 million (2015- less $15 million).

Distributable cash flow, EBITDA and Adjusted 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 information prepared in accordance with GAAP. Additionally, these measures as presented may not be comparable to similarly titled measures of other companies.

The following table represents a reconciliation of our EBITDA, Adjusted EBITDA, Total distributable cash flow and Distributable cash flow to the most directly comparable GAAP financial measure, Net income, for the periods presented:

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Reconciliations of Net Income to EBITDA, Adjusted EBITDA and Distributable Cash Flow

The following table presents a reconciliation of the non-GAAP financial measures of EBITDA, Adjusted EBITDA and Distributable Cash Flow, to the GAAP financial measure of net income.

Year Ended December 31 (unaudited)
(millions of dollars)	2016 (a)		2015 (a)		2014 (a)
Net income	263		58		241
Add:
Interest expense (b)	73		68		62
Depreciation and amortization	96		95		96
Income taxes	1		2		2
EBITDA	433		223		401
Impairment of equity investment	—		199		—
Adjusted EBITDA	433		422		401
Add:
Distributions from equity investments (c)
Northern Border	91		91		88
Great Lakes	34		40		29
	125		131		117
Less:
Equity earnings:
Northern Border	(69	)	(66	)	(69	)
Great Lakes	(28	)	(31	)	(19	)
	(97	)	(97	)	(88	)
Less:
Equity AFUDC	—		(1	)	—
Interest expense (b)	(73	)	(68	)	(62	)
Income taxes	(1	)	(2	)	(2	)
Distributions to non-controlling interests (d)	(18	)	(29	)	(69	)
Distributions to TransCanada as PNGTS’ former parent(e)	(6	)	(30	)	(29	)
Maintenance capital expenditures (f)	(16	)	(16	)	(8	)
	(114	)	(146	)	(170	)
Total Distributable Cash Flow (j)	347		310		260
General Partner distributions declared (h)	(12	)	(8	)	(5	)
Distributions allocable to Class B units (i)	(22	)	(12	)	—
Distributable Cash Flow (j)	313		290		255

(a)Financial information was recast to consolidate PNGTS for all periods presented. Please see “Basis of Presentation” section for more information.

(b)Interest expense as presented includes net realized loss related to the interest rates swaps and amortization of realized loss on PNGTS’ derivative instruments. See Notes 11 and 18, Notes to Consolidated Financial Statements for the year ended December 31, 2016 included in Exhibit 99.2 of this Current Report on Form 8-K for more information.

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

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

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

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(f) The Partnership’s maintenance capital expenditures include cash expenditures made to maintain, over the long term, our assets’ operating capacity, system integrity and reliability.  Accordingly, 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 on 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.

Please read the Capital spending section for more information regarding the Partnership’s total proportionate share of maintenance capital expenditures from our consolidated entities and equity investments.

(g)Distributions declared to the General Partner for the year ended December 31, 2016 included an incentive distribution of approximately $6 million (2015 - $2 million; 2014 - $1 million).

(h)During the twelve months ended December 31, 2016, 30 percent of GTN’s total distributions was $42 million; therefore the distributions allocable to the Class B units was $22 million, representing the amount that exceeded the threshold level of $20 million. During the nine months ended December 31, 2015, 30 percent of GTN’s total distributions was $27 million; therefore the distributions allocable to the Class B units was $12 million, representing the amount that exceeded the threshold level of $15 million. The Class B distribution is determined and payable annually.

(i)On January 23, 2017, the board of directors of our General Partner declared distributions to Class B unitholders in the amount of $22 million which was paid on February 14, 2017. The 2015 Class B distribution amounting to $12 million was paid by the Partnership on February 12, 2016.  Please read Notes 6,9,12 and 13, Notes to Consolidated Financial Statements for the year ended December 31, 2016 included in Exhibit 99.2 of this Current Report on Form 8-K for more  detailed disclosures on the Class B units.

(j)“Total Distributable Cash Flow” and “Distributable Cash Flow” represent the amount of distributable cash generated by the Partnership’s subsidiaries and equity investments during the current earnings period and thus reconcile directly to the net income amount presented. The calculation differs from the previous 2014 non-GAAP measures “Partnership Cash Flows before General Partner distributions” and “Partnership Cash Flows” as the previously used measures primarily reflected cash received during the period through distributions from our subsidiaries and equity investments that were generated from the prior quarter’s financial results. The 2014 amounts reflected here have been adjusted to reflect the calculation as described above and to present the comparable “Total Distributable Cash flow” and “Distributable Cash Flow” from the previous periods.

Year Ended December 31, 2016 Compared with the Year Ended December 31, 2015

EBITDA increased by $210 million to $433 million in 2016 compared to $223 million in 2015. The increase was primarily the result of the recognition of a $199 million non-cash impairment charge in 2015 to our investment in Great Lakes which lowered EBITDA in 2015 accordingly (See Critical Accounting Estimates - Impairment of Equity Investments, Goodwill and Long-Lived Assets — Equity Investments section for more information.)

Adjusted EBITDA increased by $11 million compared to the same period in 2015 mainly due to higher transmission revenues as discussed in more detail in the Results of Operations section.

Distributable cash flow increased by $23 million in the twelve months ended December 31, 2016 compared to the same period in 2015 primarily due to the net effect of:

·the cash impact of higher Adjusted EBITDA;

·lower distributable cash flow from our equity investments as a result of higher maintenance capital in 2016 as discussed in more detail on the “Capital Spending” section;

·lower distributions paid to non-controlling interests due to the Partnership owning 100 percent of GTN effective April 1, 2015 and

·lower distributable cash flow allocable to TransCanada as the former parent of PNGTS due to the Partnership’s acquisition of 49.9 percent interest in PNGTS from TransCanada effective January 1, 2016;

·higher interest expense related to higher borrowings as a result of the recent acquisitions offset by ;

·higher General Partner distributions due to higher IDRs in the current period; and

·higher distributions allocable to the Class B units during the current period.

Year Ended December 31, 2015 Compared with the Year Ended December 31, 2014

EBITDA decreased by $178 million to $223 million in 2015 compared to $401 million in 2014. The decrease was primarily the result of the recognition of a $199 million non-cash impairment charge to our investment in Great Lakes in fourth quarter 2015 (See Critical Accounting Estimates - Impairment of Equity Investments, Goodwill and Long-Lived Assets — Equity Investments section for more information.)

Adjusted EBITDA increased by $21 million compared to the same period in 2014 due higher transmission revenues and higher earnings from our equity investments as discussed in more detail in the Results of Operations section.

Distributable cash flow increased by $35 million in the twelve months ended December 31, 2015 compared to the same period in 2014 primarily due to the net effect of:

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·the cash impact of higher Adjusted EBITDA from our subsidiaries and equity investments;

·lower distributions to non-controlling interests as a result of the Partnership owning 100 percent of GTN beginning April 1, 2015 and 100 percent of Bison beginning October 1, 2014;

·higher maintenance capital expenditures primarily due to  major compression equipment overhauls on GTN’s pipeline system in 2015;

·higher interest expense related to additional borrowings to fund recent acquisitions;

·higher General Partner distributions due to higher IDRs in the current period; and

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

Contractual Obligations

The Partnership’s Contractual Obligations

The Partnership’s contractual obligations as of December 31, 2016 included the following:

	Payments Due by Period
(millions of dollars)	Total	Less than 1 Year	1-3 Years	4-5 Years	More than 5 Years
Senior Credit Facility due 2021	160	—	—	160	—
2013 Term Loan Facility due 2018	500	—	500	—	—
2015 Term Loan Facility due 2018	170	—	170	—	—
5.90% Senior Notes due in 2018	53	29	24	—	—
4.65% Senior Notes due 2021	350	—	—	350	—
4.375% Senior Notes due 2025	350	—	—	—	350
5.29% Senior Notes due 2020	100	—	—	100	—
5.69% Senior Notes due 2035	150	—	—	—	150
Unsecured Term Loan Facility due 2019	65	10	55	—	—
Unsecured Term Loan due 2019	10	1	9	—	—
3.82% Series D Senior Notes due 2017	12	12	—	—	—
Interest on Debt Obligations (b)	439	69	120	82	168
Operating Leases	9	1	2	1	5
	2,368	122	880	693	673

(a)Financial information was recast to consolidate PNGTS for all periods presented. Please see “Basis of Presentation” section for more information.

(b)Interest payments on floating-rate debt are estimated using interest rates effective as of December 31, 2016.

On November 10, 2016, the Partnership’s Senior Credit Facility was amended to extend the maturity period through November 10, 2021. The Facility consists of a $500 million senior revolving credit facility with a banking syndicate, under which $160 million was outstanding at December 31, 2016 (December 31, 2015 - $200 million), leaving $340 million available for future borrowing.

At the Partnership’s option, the interest rate on the outstanding borrowings under the Senior Credit Facility may be lenders’ base rate or the London Interbank Offered Rate (LIBOR) plus, in either case, an applicable margin that is based on the Partnership’s long-term unsecured credit ratings. The Senior Credit Facility permits the Partnership to specify the portion of the borrowings to be covered by specific interest rate options and, for LIBOR-based borrowings, to specify the interest rate period. The Partnership is required to pay a commitment fee based on its credit rating and on the unused principal amount of the commitments under the Senior Credit Facility. The Senior Credit Facility has a feature whereby at any time, so long as no event of default has occurred and is continuing, the Partnership may request an increase in the Senior Credit Facility of up to $500 million, but no lender has an obligation to increase their respective share of the facility.

The LIBOR-based interest rate on the Senior Credit Facility was 1.92 percent at December 31, 2016 (December 31, 2015 - 1.50 percent).

On July 1, 2013, the Partnership entered into a term loan agreement with a syndicate of lenders for a $500 million term loan credit facility (2013 Term Loan Facility). On July 2, 2013, the Partnership borrowed $500 million under the 2013 Term Loan Facility, to pay a portion of the purchase price of the 2013 Acquisition, maturing on July 1, 2018. The 2013 Term Loan Facility bears interest based, at the Partnership’s election, on the LIBOR or the base rate plus, in either case, an applicable margin. The base rate equals the highest of (i) SunTrust Bank’s prime rate, (ii) 0.50 percent above the federal funds rate and (iii) 1.00 percent above one-month LIBOR. The applicable margin for the term loan is based on the Partnership’s senior debt rating and ranges between 1.125 percent and 2.000 percent for LIBOR borrowings and 0.125 percent and 1.000 percent for base rate borrowings.

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As of December 31, 2016, 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 ( 2015 - 2.79 percent) . Prior to hedging activities, the LIBOR-based interest rate was 1.87 percent at December 31, 2016 (December 31, 2015 — 1.50 percent).

On September 30, 2015, the Partnership entered into an agreement for a $170 million term loan credit facility (2015 Term Loan Facility). The Partnership borrowed $170 million under the 2015 Term Loan Facility to refinance its Short-Term Loan Facility which matured on September 30, 2015.  The 2015 Term Loan Facility matures on October 1, 2018. The LIBOR-based interest rate on the 2015 Term Loan Facility was 1.77 percent at December 31, 2016 (December 31, 2015 — 1.39 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 4.01 to 1.00 as of December 31, 2016.

The Senior Credit Facility and the Term Loan Facilities contain additional covenants that include restrictions on entering into mergers, consolidations and sales of assets, granting liens, material amendments to the Partnership Agreement, incurrence of additional debt by the Partnership’s subsidiaries and distributions to unitholders. Upon any breach of these covenants, amounts outstanding under the Senior Credit Facility and the Term Loan Facilities may become immediately due and payable.

On March 13, 2015, the Partnership closed a $350 million public offering of senior unsecured notes bearing an interest rate of 4.375 percent maturing March 13, 2025. The net proceeds of $346 million were used to fund a portion of the 2015 GTN Acquisition and to reduce the amount outstanding under our Senior Credit Facility. The indenture for the notes contains customary investment grade covenants.

PNGTS’ Senior Secured Notes are secured by the PNGTS long-term firm shipper contracts and its partners’ pledge of their equity and a guarantee of debt service for six months. PNGTS is restricted under the terms of its note purchase agreement from making cash distributions unless certain conditions are met. Before a distribution can be made, the debt service reserve account must be fully funded and PNGTS’ debt service coverage ratio for the preceding and succeeding twelve months must be 1.30 or greater. At December 31, 2016, the debt service coverage ratio was 2.41 for the twelve preceding months and 1.43 for the twelve succeeding months. Therefore, PNGTS was not restricted to make any cash distributions.

On June 1, 2015, GTN’s 5.09 percent unsecured Senior Notes matured. Also, on June 1, 2015, GTN entered into a $75 million unsecured variable rate term loan facility (Unsecured Term Loan Facility), which requires yearly principal payments until its maturity on June 1, 2019. The variable interest is based on LIBOR plus an applicable margin. The LIBOR-based interest rate on the Unsecured Term Loan Facility was 1.57 percent at December 31, 2016 (December 31, 2015 — 1.19 percent). GTN’s Unsecured Senior Notes, along with this new 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 December 31, 2016 is 44.5 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 December 31, 2016 was 21.22 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 4.15 to 1.00 as of December 31, 2016.

On  April  29,  2016,  Tuscarora  entered  into  a $9.5  million  unsecured  variable  rate  term  loan  facility which requires  yearly principal  payments  until  its  maturity  on  April  29,  2019.  The variable interest is based on LIBOR plus an applicable margin and was 1.90 percent at December 31, 2016.

At December 31, 2016, 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 Partnership Agreement, incurring additional debt and distributions to unitholders.

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The fair value of the Partnership’s long-term debt is estimated by discounting the future cash flows of each instrument at estimated current borrowing rates. The estimated fair value of the Partnership’s long-term debt at December 31, 2016 was $1,963 million. As of February 28, 2017, the Partnership had $120 million outstanding under the Senior Credit Facility.

Summary of Northern Border’s Contractual Obligations

Northern Border’s contractual obligations as of December 31, 2016 included the following:

	Payments Due by Period (a)
(millions of dollars)	Total	Less than 1 Year	1-3 Years	4-5 Years	More than 5 Years
7.50% Senior Notes due 2021	250	—	—	250	—
$200 million Credit Agreement due 2020	181	—	—	181	—
Interest payments on debt	103	22	44	37	—
Operating leases (b)	55	3	5	5	42
	589	25	49	473	42

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

(b) Future minimum payments for office space and rights-of-way under non-cancelable operating leases

Northern Border has commitments of $8 million as of December 31, 2016 in connection with various pipeline, metering and overhaul projects.

Senior Notes

All of Northern Border’s outstanding debt securities are senior unsecured notes with similar terms except for interest rates, maturity dates and prepayment premiums. The indentures for the notes do not limit the amount of unsecured debt Northern Border may incur, but do restrict secured indebtedness. At December 31, 2016, Northern Border was in compliance with all of its financial covenants.

At December 31, 2016, the aggregate estimated fair value of Northern Border’s long-term debt was approximately $464 million (2015 — $426 million). In 2016, interest expense related to the senior notes was $23 million (2015 — $25 million; 2014 — $25 million).

Credit Agreement

Northern Border’s credit agreement consists of a $200 million revolving credit facility. At December 31, 2016, $181 million was outstanding leaving $19 million available for future borrowings. At Northern Border’s option, the interest rate on the outstanding borrowings may be the lenders’ base rate or LIBOR plus, in either case, an applicable margin that is based on Northern Border’s long-term unsecured credit ratings. The interest rate on Northern Border’s credit agreement at December 31, 2016 was 1.90 percent (2015 — 1.74 percent). At December 31, 2016, Northern Border was in compliance with all of its financial covenants.

2016 Credit Facility

On November 15, 2016, Northern Border entered into a $100 million 364-day revolving credit facility expiring on November 14, 2017, which utilizes the same covenants as the $200 million revolving credit facility.  As a result of the shared covenants, the $200 million revolving credit facility was amended for the second time to include the cross default with the new $100 million 364-day revolving credit facility.  At December 31, 2016, the $100 million 364-day revolving credit facility has not been utilized.

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Summary of Great Lakes’ Contractual Obligations

Great Lakes’ contractual obligations as of December 31, 2016 included the following:

	Payments Due by Period (a)
(millions of dollars)	Total	Less than 1 Year	1-3 Years	4-5 Years	More than 5 Years
6.73% series Senior Notes due 2016 to 2018	18	9	9	—	—
9.09% series Senior Notes due 2016 to 2021	50	10	20	20	—
6.95% series Senior Notes due 2019 to 2028	110	—	11	22	77
8.08% series Senior Notes due 2021 to 2030	100	—	—	10	90
Interest payments on debt	141	21	38	31	51
	419	40	78	83	218

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

Great Lakes has commitments of $1 million as of December 31, 2016 in connection with pipeline integrity and overhaul projects.

Long-Term Financing

All of Great Lakes’ outstanding debt securities are senior unsecured notes with similar terms except for interest rates, maturity dates and prepayment premiums.

Great Lakes is required to comply with certain financial, operational and legal covenants. Under the most restrictive covenants in the senior note agreements, approximately $150 million of Great Lakes’ partners’ capital was restricted as to distributions as of December 31, 2016 (2015 — $160 million). Great Lakes was in compliance with all of its financial covenants at December 31, 2016.

The aggregate estimated fair value of Great Lakes’ long-term debt was $354 million at December 31, 2016 (2015 — $362 million).  The aggregate annual required repayment of senior notes is $19 million for each year 2017 and 2018 and $21 million for each year 2019 and 2020 and $31 million for 2021. Aggregate required repayments of senior notes thereafter total $167 million.  In 2016, interest expense related to Great Lakes’ senior notes was $22 million (2015 - $24 million; 2014 - $25 million).

Other

Great Lakes has a cash management agreement with TransCanada whereby Great Lakes’ funds are pooled with other TransCanada affiliates. The agreement also gives Great Lakes the ability to obtain short-term borrowings to provide liquidity for Great Lakes’ operating needs. At December 31, 2016 and 2015, Great Lakes has an outstanding receivable from this arrangement amounting to $27 million and $51 million, respectively.

Cash Distribution Policy of the Partnership

The following table illustrates the percentage allocations of available cash from operating surplus between the common unitholders and our General Partner based on the specified target distribution levels. The percentage interests set forth below for our General Partner include its two percent general partner interest and IDRs, and assume our General Partner has contributed any additional capital necessary to maintain its two percent general partner interest. The distribution to the General Partner illustrated below, other than in its capacity as a holder of 5,797,106 common units that are in excess of its effective two percent general partner interest, represents the IDRs.

			Marginal Percentage Interest in Distribution
	Total Quarterly Distribution Per Unit Target Amount		Common Unitholders		General Partner
Minimum Quarterly Distribution	$0.45		98	%	2	%
First Target Distribution	above $0.45	up to $0.81	98	%	2	%
Second Target Distribution	above $0.81	up to $0.88	85	%	15	%
Thereafter	above $0.88		75	%	25	%

The following table provides information about our distributions (in millions, except per unit distributions amounts).

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				Limited Partners					General Partner
Declaration Date	Payment Date	Per Unit Distribution		Common Units		Class B Units(c)			2%		IDRs (a)		Total Cash Distribution
1/16/2014	2/14/2014	$	0.81	$	50	$	—		$	1	$	—	$	51
4/25/2014	5/15/2014	$	0.81	$	51	$	—		$	1	$	—	$	52
7/23/2014	8/14/2014	$	0.84	$	53	$	—		$	1	$	—	$	54
10/23/2014	11/14/2014	$	0.84	$	53	$	—		$	1	$	1	$	55
1/22/2015	2/13/2015	$	0.84	$	54	$	—		$	1	$	—	$	55
4/23/2015	5/15/2015	$	0.84	$	54	$	—		$	1	$	—	$	55
7/23/2015	8/14/2015	$	0.89	$	56	$	—		$	2	$	1	$	59
10/22/2015	11/13/2015	$	0.89	$	57	$	—		$	1	$	1	$	59
1/21/2016	2/12/2016	$	0.89	$	57	$	12	(d)	$	1	$	1	$	71
4/21/2016	5/13/2016	$	0.89	$	58	$	—		$	1	$	1	$	60
7/21/2016	8/12/2016	$	0.94	$	62	$	—		$	1	$	2	$	65
10/20/2016	11/14/2016	$	0.94	$	63	$	—		$	1	$	2	$	66
1/23/2017 (b)	2/14/2017 (b)	$	0.94	$	64	$	22	(e)	$	2	$	2	$	90

(a)The distributions paid for the year ended December 31, 2016 included incentive distributions to the General Partner of $6 million (2015 - $2 million, 2014 - $1 million).

(b)On February 14, 2017, we paid a cash distribution of $0.94 per unit on our outstanding common units to unitholders of record at the close of business on February 2, 2017. Please read Note 23, Notes to Consolidated Financial Statements for the year ended December 31, 2016 included in Exhibit 99.2 of this Current Report on Form 8-K for more detailed disclosures

(c)The Class B units issued by us on April 1, 2015 represent limited partner interests in us and entitle TransCanada to an annual distribution which is an amount based on 30 percent of GTN’s annual distributions after exceeding certain annual thresholds. Please read Notes 6, 9 and 12,Notes to Consolidated Financial Statements for the year ended December 31, 2016 included in Exhibit 99.2 of this Current Report on Form 8-K for more detailed disclosures on the Class B units.

(d)On February 12, 2016, we paid TransCanada $12 million representing 30 percent of GTN’s total distributable cash flows for the nine months ended December 31, 2015 less $15 million. Please read Notes 6, 9 and 12 within Part IV, Item 15. “Exhibits and Financial Statement Schedules” for more detailed disclosures on the Class B units.

(e)On February 14, 2017, we paid TransCanada $22 million representing 30 percent of GTN’s total distributable cash flows for the year ended December 31, 2016 less $20 million Please read Notes 6, 9 and 12, Notes to Consolidated Financial Statements for the year ended December 31, 2016included in Exhibit 99.2 of this Current Report on Form 8-K for more detailed disclosures on the Class B units.

Distribution Policies of Our Pipeline Systems

Distributions of available cash are made to partners on a pro rata basis according to each partner’s ownership percentage, approximately one month following the end of a quarter. Our pipeline systems’ respective management committees determine the amounts and timing of cash distributions, where the amounts of such distributions are based on distributable cash flow as determined by a prescribed formula. Any changes to, or suspension of our pipeline systems’ cash distribution policies requires the unanimous approval of their respective management committees.

GTN, Bison, and North Baja’s distribution policies require the pipelines to distribute 100 percent of distributable cash flow based on earnings before depreciation and amortization less allowance for funds used during construction (AFUDC) and maintenance capital expenditures. This defined formula is subject to management committee approval and can be modified to ensure minimum cash balances, equity balances and ratios are maintained.

Tuscarora’s distribution policy requires the distribution of 100 percent of distributable cash flow based on earnings before depreciation and amortization less debt repayment, AFUDC and maintenance capital expenditures. This defined formula is subject to management committee approval and can be modified to ensure minimum cash balances, equity balances and ratios are maintained.

PNGTS distributes its available cash less any required reserves that are necessary to comply with its debt covenants and/or appropriately conduct its business, as determined and approved by its management committee. While PNGTS debt repayments are not funded with cash calls to its owners, PNGTS has historically funded its scheduled debt repayments by adjusting its available cash for distribution, which effectively reduces the cash available for distributions.

Northern Border’s distribution policy requires Northern Border to distribute on a monthly basis, 100 percent of the distributable cash flow based on earnings before interest, taxes, depreciation and amortization less interest expense and maintenance capital expenditures. Northern Border adopted certain changes related to equity contributions that defined minimum equity to total capitalization ratios to be used by the Northern Border management committee to

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determine the amount of required equity contributions, timing of the required contributions and for any shortfall due to the inability to refinance maturing debt to be funded by equity contributions.

Great Lakes’ distribution policy requires the distribution of 100 percent of distributable cash flow based on earnings before income taxes, depreciation, AFUDC less capital expenditures and debt repayments not funded with cash calls to its partners. This defined formula is subject to management committee approval and can be modified to ensure minimum cash balances, equity balances and ratios are maintained.

CRITICAL ACCOUNTING 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.

We believe our critical accounting estimates discussed in the following paragraphs require us to make the most significant assumptions when preparing our financial statements and changes in these assumptions could have a material impact on the financial statements. These critical accounting estimates should be read in conjunction with our accounting policies summarized on Notes 2 and 3, Notes to Consolidated Financial Statements for the year ended December 31, 2016 included in Exhibit 99.2 of this Current Report on Form 8-K.

Regulation

Our pipeline systems’ accounting policies conform to Accounting Standards Codification (ASC) 980 — Regulated Operations. As a result, our pipeline systems record assets and liabilities that result from the regulated ratemaking process that may not be recorded under GAAP for non-regulated entities. Regulatory assets generally represent incurred costs that have been deferred because such costs are probable of future recovery in customer rates. Regulatory liabilities generally represent obligations to make refunds to customers or for instances where the regulator provides current rates that are intended to recover costs that are expected to be incurred in the future.  Our pipeline systems consider several factors to evaluate their continued application of the provisions of ASC 980 such as potential deregulation of their pipelines; anticipated changes from cost-based ratemaking to another form of regulation; increasing competition that limits their ability to recover costs; and regulatory actions that limit rate relief to a level insufficient to recover costs.

Certain assets that result from the ratemaking process are reflected on the balance sheets of our pipeline systems. If it is determined that future recovery of these assets is no longer probable as a result of discontinuing application of ASC 980 or other regulatory actions, our pipeline systems would be required to write off the regulatory assets at that time.

As of December 31, 2016, our equity investees have regulatory assets amounting to $15 million (2015 - $16 million).

As of December 31, 2016, our equity investees have regulatory liabilities amounting to $27 million (2015 - $22 million).

At December 31, 2016, the Partnership had $1 million regulatory assets reported as part of other current assets on the balance sheet representing volumetric fuel tracker assets that are settled with in-kind exchanges with customers continually (2015 — $2 million). As of December 31, 2016, the Partnership had regulatory liabilities of $25 million mostly relating to estimated costs associated with future removal of transmission and gathering facilities or allowed to be collected by FERC in depreciation rates (2015 - $24 million).

Impairment of Equity Investments, Goodwill and Long-Lived Assets

Equity Investments

We review our equity method investments when a significant event or change in circumstances has occurred that may have an adverse effect on the fair value of each investment. When such events or changes occur, we compare the estimated fair value to the carrying value of the related investment. We calculate the estimated fair value of an investment in an equity method investee using an income approach and market approach. The development of fair value estimates requires significant judgment including estimates of future cash flows, which is dependent on internal forecasts, estimates of the long-term rate of growth for the investee, estimates of the useful life over which cash flows will occur, and determination of weighted average cost of capital. The estimates used to calculate the fair value of an investee can change from year to year based on operating results and market conditions. Changes in these estimates and assumptions could materially affect the determination of fair value and our assessment as to whether an investment in an equity method investee has suffered impairment.

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If the estimated fair value of an investment is less than its carrying value, we are required to determine if the decline in fair value is other than temporary. This determination considers the aforementioned valuation methodologies, the length of time and the extent to which fair value has been less than carrying value, the financial condition and near-term prospects of the investee, including any specific events which may influence the operations of the investee, the intent and ability of the holder to retain its investment in the investee for a period of time sufficient to allow for any anticipated recovery in market value, and other facts and circumstances. If the fair value of an investment is less than its carrying value and the decline in value is determined to be other than temporary, we record an impairment charge.

During the fourth quarter of 2015, we determined that our investment in Great Lakes’ long-term value had been adversely impacted by the changing natural gas flows in its market region. Additionally, we concluded that other strategic alternatives to increase its utilization or revenue were no longer feasible. As a result, we determined that the carrying value of our investment in Great Lakes was in excess of its fair value and the decline was not temporary. Accordingly, we concluded that the carrying value of our investment in Great Lakes was impaired.

Our analysis resulted in an impairment charge of $199 million reflected as Impairment of equity-method investment on our Statement of Income for the year ended December 31, 2015.  The impairment charge reduced the difference between the carrying value of our investment in Great Lakes and the underlying equity in the net assets, to $260 million. The difference represented the equity method goodwill remaining in our investment in Great Lakes.

The assumptions we used in 2015 related to the estimated fair value of our remaining equity investment in Great Lakes could be negatively impacted by near and long-term conditions including:

· future regulatory rate action or settlement,

· valuation of Great Lakes in future transactions,

· changes in customer demand at Great Lakes for pipeline capacity and services,

· changes in North American natural gas production in the major producing basins,

· changes in natural gas prices and natural gas storage market conditions, and

· changes in other long-term strategic objectives.

Great Lakes’ evolving market conditions and other factors relevant to Great Lakes’ long term financial performance have remained relatively stable during the year ended 2016 and into 2017.  Accordingly, our estimation of the fair value of our investment in Great Lakes has not materially changed from 2015.  There is a risk that reductions in future cash flow forecasts and other adverse changes in these key assumptions could result in additional future impairment of the carrying value of our investment in Great Lakes.

As of December 31, 2016, no impairment charge has been recorded related to any of our other equity investments.

Goodwill

We test goodwill for impairment annually based on ASC 350 — Intangibles — Goodwill and Other, or more frequently if events or changes in circumstances lead us to believe it might be impaired. We assess qualitative factors to determine whether events or changes in circumstances indicate that goodwill might be impaired, and if we do not conclude that it is more likely than not that the fair value of the reporting unit is greater than the carrying value, we use a two-step process to test for impairment:

1.First, we compare the fair value of the reporting unit, including its goodwill, to its book value. If the fair value is less than book value, we consider our goodwill to be impaired.

2.Next, we measure the amount of the impairment by calculating the implied fair value of the reporting unit’s goodwill. We do this by deducting the fair value of the tangible and intangible net assets of the reporting unit from the fair value calculated in the first step. If the goodwill’s carrying value exceeds its implied fair value we record an impairment charge.

We base these valuations on our projection of future cash flows which involves making estimates and assumptions about:

·discount rates;

·commodity and capacity prices;

·market supply and demand assumptions;

·growth opportunities;

·output levels;

·competition from other companies;

·regulatory changes; and

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·regulatory rate action or settlement.

If our assumptions are not appropriate, or future events indicate that our goodwill is impaired, our net income would be impacted by the amount by which the carrying value exceeds the fair value of reporting unit, to the extent of the balance of goodwill.

At December 31, 2016 and 2015, we had $130 million of goodwill recorded on our consolidated balance sheet related to the North Baja and Tuscarora acquisitions. No impairment of goodwill existed at December 31, 2016.

As discussed more fully in Note 20, Notes to Consolidated Financial Statements for the year ended December 31, 2016 included in Exhibit 99.2 of this Current Report on Form 8-K, the reduction in Tuscarora’s future cash flows as a result of the Tuscarora Settlement constituted a triggering event in the second quarter of 2016 that led us to evaluate, for possible impairment, the $82 million of goodwill related to our acquisition of Tuscarora.

Our second quarter analysis, which was also reviewed for any material updates as part of our annual impairment test on goodwill, resulted in the estimated fair value of Tuscarora exceeding its carrying value but the excess was less than 10 percent. The fair value was measured using a discounted cash flow analysis and included revenues expected from Tuscarora’s current and expected future contracting level. There is a risk that reductions in future cash flow forecasts as a result of Tuscarora not being able to maintain its current contracting level and/or not being able to realize other opportunities on the system, together with adverse changes in other key assumptions such as expected outcome of future rate proceedings, projected operating costs and estimated rate of return on invested capital, could result in a future impairment of the goodwill balance relating to Tuscarora.

Long-Lived Assets

We assess our long-lived assets for impairment based on ASC 360-10-35 Property, Plant, and Equipment — Overall — Subsequent Measurement when events or changes in circumstances indicate that the carrying value may not be recoverable. If the total of the estimated undiscounted future cash flows expected to be generated by that asset or asset group is less than the carrying value of the assets, an impairment charge is recognized for the excess of the carrying value over the fair value of the assets. Fair value is determined through various valuation techniques including discounted cash flow models, quoted market values and third-party independent appraisals as considered necessary.

Our management evaluates changes in our business and economic conditions and their implications for recoverability of our long-lived assets’ carrying values when assessing these assets for impairments. The development of fair value estimates requires significant judgement in estimating future cash flows. In order to determine the estimated future cash flows, management must make certain estimates and assumptions, which include, but are not limited to, demand, competition, contract renewals and other factors.

Any changes we make to these estimates and assumptions could materially affect future cash flows, which could result to the recognition of an impairment loss in our statement of income.

As of December 31, 2016, there were no indicators of impairment for our long-lived assets.

Contingencies

Our pipeline systems’ accounting for contingencies covers a variety of business activities, including contingencies for legal and environmental liabilities. Our pipeline systems accrue for these contingencies when their assessments indicate that it is probable that a liability has been incurred or an asset will not be recovered and an amount can be reasonably estimated in accordance with ASC 450 — Contingencies. Our pipeline systems base their estimates on currently available facts and their estimates of the ultimate outcome or resolution. Actual results may differ from our pipeline systems’ estimates resulting in an impact, positive or negative, on earnings and cash flow.

CONTINGENCIES

Legal

Various legal actions or governmental proceedings involving our pipeline systems that have arisen in the ordinary course of business are pending. Our pipeline systems believe that the resolution of these issues will not have a material adverse impact on their results of operations or financial position. Please read Part I, Item 3. “Legal Proceedings” of our 2016 Annual Report on Form 10-K dated February 28, 2017 for additional information.

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Environmental

We do not believe that compliance with existing environmental laws and regulations will have a material adverse effect on our pipeline systems. Because of the inherent uncertainties as to the final outcome of proposed environmental regulations and legislation, we cannot estimate the range of possible costs, if any, from the proposals. Please read Part I, Item 1. “Business — Government Regulation” of our 2016 Annual Report on Form 10-K dated February 28, 2017 for additional information.

Greenhouse Gas Regulation

Through the EPA, the U.S. Government has imposed various measures related to GHG emissions, including emission monitoring and reporting requirements, preconstruction and operating permits for certain large stationary sources.  The EPA has also proposed rules requiring the control of methane emissions from and leak detection and repair requirements for certain oil and natural gas production, processing, transmission and storage activities, as well as leak detection and repair requirements.  These final and proposed rules, as well as additional legislation or regulations for the control of GHG emissions could materially increase our operating costs, including our cost of environmental compliance by requiring us to install additional equipment and potentially purchase emission allowances or offset credits. The regulation or restriction of GHG emissions could also result in changes to the consumption and demand for natural gas. This could have either positive or adverse effects on our pipeline systems, our financial position, results of operations and future prospects. Please read Part I, Item 1. “Business — Government Regulation” of our 2016 Annual Report on Form 10-K dated February 28, 2017 for additional information.

RELATED PARTY TRANSACTIONS

Please read Part III, Item 13. “Certain Relationships and Related Transactions, and Director Independence” of our 2016 Annual Report on Form 10-K dated February 28, 2017 and Note 16, Notes to Consolidated Financial Statements for the year ended December 31, 2016 included as exhibit 99.2 of this Current Report on Form 8-K  for more information regarding related party transactions.

Item 7A.        Quantitative and Qualitative Disclosures About Market Risk

OVERVIEW

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

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

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

MARKET RISK

From time to time, and in order to finance our business and that of our pipeline systems, the Partnership and our pipeline systems issue debt to invest in growth opportunities and provide for ongoing operations. The issuance of 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 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 Facility and Tuscarora’s Unsecured Term Facility, under

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which $405 million, or 21 percent, of our outstanding debt was subject to variability in LIBOR interest rates. As of December 31, 2015, the Partnership’s interest rate exposure results from our floating rate Senior Credit Facility, the unhedged portion ($350 million) of our 2013 Term Loan Facility, our 2015 Term Loan Facility and GTN’s Unsecured Term Facility, under which $795 million, or 40 percent, of our outstanding debt was subject to variability in LIBOR interest rates.

As of December 31, 2016, 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 December 31, 2016, The Partnership’s annual interest expense on its remaining debt with variable interest exposure would increase (decrease) and net income would decrease (increase) by approximately $4 million.

As of December 31, 2016, $181 million, or 42 percent of Northern Border’s outstanding debt was at floating rates (2015 — $61 million or 15 percent). If interest rates hypothetically increased (decreased) by one percent, 100 basis points, compared with rates in effect at December 31, 2016, 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 Partnership and our pipeline systems enter into interest rate swaps and option agreements to mitigate the impact of changes in interest rates.

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 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). At December 31, 2015, the fair value of the interest rate swaps accounted for as cash flow hedges was a liability of $1 million both on a gross and net basis. The Partnership did not record any amounts in net income related to ineffectiveness for interest rate hedges for the years ended December 31, 2016, 2015 and 2014. The net change in fair value of interest rate derivative instruments recognized in other comprehensive income was a gain of $2 million for the year ended December 31, 2016 (2015 —nil million, 2014 — loss of $1 million). In 2016, the net realized loss related to the interest rate swaps was $3 million, and was included in financial charges and other (2015 — $2 million, 2014 - $2 million).

The Partnership has no master netting agreements, however, contracts contain 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 net asset of nil million as of December 31, 2016 and there would be no effect on the consolidated balance sheet as of December 31, 2015.

In anticipation of a debt refinancing in 2003, PNGTS entered into forward interest rate swap agreements to hedge the interest rate on its Senior Secured Notes due in 2018. These interest rate swaps were used to manage the impact of interest rate fluctuations and qualified as derivative financial instruments in accordance with ASC 815, Derivatives and Hedging. PNGTS settled its position with a payment of $20.9 million to counterparties at the time of the refinancing and recorded the realized loss in AOCL as of the termination date. The previously recorded AOCL is currently being amortized against earnings over the life of the PNGTS’ 5.90% Senior Secured Notes.  At December 31, 2016, our 61.71 percent proportionate share of net unamortized loss on PNGTS included in AOCL was $2 million (2015 - $2 million). For the year ended December 31, 2016, 2015 and 2014, our 61.71 percent proportionate share of the amortization of realized loss on derivative instruments was $0.8 million for each year.

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

COUNTERPARTY CREDIT RISK AND LIQUIDITY RISK

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

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 cash and cash equivalents and receivables, 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 December 31, 2016, we had not incurred any significant credit losses and had no significant amounts past due or impaired. At December 31, 2016, we had a credit risk concentration on one of our customers, Anadarko Energy Services Company, which owed us $4 million and this amount represented approximately 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 December 31, 2016, the Partnership had a Senior Credit Facility of $500 million maturing in 2021 and the outstanding balance on this facility was $160 million. In addition, at December 31, 2016, Northern Border had a committed revolving bank line of $200 million maturing in 2020 and $181 million was 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.

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EX-99.4

Exhibit 99.4

COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES

December 31 (millions of dollars)	2016 (a)	2015(a)		2014(a)		2013(a)(b)		2012 (a) (b)
Earnings
Net income before adjustment for income from equity investees	166	160		153		154		145
Fixed charges	73	68		62		57		50
Distributed income (loss) of equity investees (c)	97	(102	)	88		67		99
Non-controlling interests of subsidiaries that have not incurred fixed charges	—	—		(10	)	(14	)	(13	)
Total Earnings	336	126		293		264		281
Fixed Charges
Interest expensed and capitalized	69	64		56		50		49
Amortization of other assets	4	4		6		7		1
Total Fixed Charges	73	68		62		57		50
Ratio of Earnings/Fixed Charges	4.60X	1.85x		4.73x		4.63x		5.62x

(a)Recast information to consolidate PNGTS for all periods presented as a result of an additional 11.81 percent in PNGTS that was acquired from a subsidiary of TransCanada on June 1, 2017. Prior to this transaction, the Partnership owned a 49.9 percent interest in PNGTS that was acquired from TransCanada on January 1, 2016.  Please read Note 2- Significant Accounting policies-Basis of Presentation section of  the Notes to the Consolidated Financial Statements included in Exhibit 99.2 of this Current Report on Form 8K.

(b)Recast information to consolidate GTN and Bison for all periods presented as a result of additional 45 percent membership interests in each of GTN and Bison that were acquired from subsidiaries of TransCanada in 2013 resulting in a 70 percent ownership in each. Please read Note 2, Significant Accounting Policies-Basis of Presentation section of the Notes to the Consolidated Financial Statements included in Exhibit 99.2 of this Current Report on Form 8K.

(c)Distributed income of equity investees for 2015 includes $199 million impairment charge on our Investment in Great Lakes. Please read Note 4-Equity Investments, Notes to the Consolidated Financial Statements included in Exhibit 99.2 of this Current Report on Form 8K.

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EX-99.5

Exhibit 99.5

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 (a)			2016 (a)
Transmission revenues	112			111
Equity earnings (Note 4)	36			33
Operation and maintenance expenses	(14		)	(12		)
Property taxes	(7		)	(7		)
General and administrative	(2		)	(2		)
Depreciation	(24		)	(23		)
Financial charges and other (Note 13)	(17		)	(18		)
Net income before taxes	84			82
Income taxes (Note 17)	(1		)	(1		)
Net Income	83			81
Net income attributable to non-controlling interest	6			7
Net income attributable to controlling interests	77			74
Net income attributable to controlling interest allocation (Note 7)
Common units	72			71
General Partner	3			2
TransCanada, as former parent of PNGTS	2			1
	77			74
Net income per common unit (Note 7) — basic and diluted (b)	$	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

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

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

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

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TC PIPELINES, LP

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

	Three months ended
(unaudited)	March 31,
(millions of dollars)	2017 (a)	2016 (a)
Net income	83	81
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)	—	—
Amortization of realized loss on derivative instrument (Note 11)	—	—
Comprehensive income	84	79
Comprehensive income attributable to non-controlling interests	6	7
Comprehensive income attributable to controlling interests	78	72

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

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

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TC PIPELINES, LP

CONSOLIDATED BALANCE SHEETS

(unaudited)
(millions of dollars)	March 31, 2017 (a)		December 31, 2016 (a)
ASSETS
Current Assets
Cash and cash equivalents	77		64
Accounts receivable and other (Note 12)	41		47
Inventories	7		7
Other	6		7
	131		125
Equity investments (Note 4)	930		918
Plant, property and equipment (Net of $1,112 accumulated depreciation; 2016 - $1,088)	2,162		2,180
Goodwill	130		130
Other assets	1		1
	3,354		3,354
LIABILITIES AND PARTNERS’ EQUITY
Current Liabilities
Accounts payable and accrued liabilities	26		29
Accounts payable to affiliates (Note 10)	7		8
Accrued interest	13		10
Distributions payable	3		3
Current portion of long-term debt (Note 5)	46		52
	95		102
Long-term debt, net (Note 5)	1,804		1,859
Deferred state income taxes (Note 17)	10		10
Other liabilities	28		28
	1,937		1,999
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 (AOCL)	(1	)	(2	)
Controlling interests	1,220		1,144
Non-controlling interest	101		97
Equity of former parent of PNGTS	32		31
	1,353		1,272
	3,354		3,354
Variable Interest Entities (Note 16)
Subsequent Events (Note 18)

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

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

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TC PIPELINES, LP

CONSOLIDATED STATEMENT OF CASH FLOWS

	Three months ended
(unaudited)	March 31,
(millions of dollars)	2017 (a)		2016 (a)
Cash Generated From Operations
Net income	83		81
Depreciation	24		23
Amortization of debt issue costs reported as interest expense	1		1
Deferred state income taxes recovery	—		(7	)
Equity earnings from equity investments (Note 3 and 4)	(36	)	(33	)
Distributions received from operating activities of equity investments (Note 3)	28		41
Change in operating working capital (Note 9)	7		14
	107		120
Investing Activities
Investment in Great Lakes (Note 4)	(4	)	(4	)
Acquisition of a 49.9 percent interest in 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	)
Distributions paid to non-controlling interests	(2	)	(4	)
Distributions paid to former parent of PNGTS	(1	)	(6	)
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)	(61	)	(30	)
	(83	)	102
Increase in cash and cash equivalents	13		14
Cash and cash equivalents, beginning of period	64		55
Cash and cash equivalents, end of period	77		69

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

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

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TC PIPELINES, LP

CONSOLIDATED STATEMENT OF CHANGES IN PARTNERS’ EQUITY

	Limited Partners							General				Non- Controlling		PNGTS		Total Equity
	Common Units				Class B Units			Partner		AOCL (a)		Interest (d)		(c) (d)		(d)
	(millions of units)		(millions of dollars)		(millions of units)	(millions of dollars)		(millions of dollars)		(millions of dollars)		(millions of dollars)		(millions ofdollars)		(millions of dollars)
Partners’ Equity at  December 31, 2016(d)	67.4		1,002		1.9	117		27		(2	)	97		31		1,272
Net income (d)	—		72		—	—		3		—		6		2		83
Other Comprehensive income, net(d)	—		—		—	—		—		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 (d)	—		(64	)	—	(22	)	(4	)	—		(2	)	(1	)	(93	)
Partners’ Equity at March 31, 2017(d)	68.6	(b)	1,098		1.9	95		28		(1	)	101		32		1,353

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

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

(c)Equity of Former Parent of PNGTS.

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

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 1ORGANIZATION

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

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

NOTE 2SIGNIFICANT 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 Audited Consolidated Financial Statements and Notes thereto included as Exhibit 99.2 of  this Current Report on Form 8-K. That report contains a more comprehensive summary of the Partnership’s significant accounting policies. In the opinion of management, the accompanying financial statements contain all of the appropriate adjustments, all of which are normally recurring adjustments unless otherwise noted, and considered necessary to present fairly the financial position of the Partnership, the results of operations and cash flows for the respective periods. Our significant accounting policies are consistent with those disclosed in the Audited Consolidated Financial Statements and Notes thereto included in Exhibit 99.2 of  this Current Report on Form 8-K, except as described in Note 3, Accounting Pronouncements.

Basis of Presentation

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

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

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

On June 1, 2017, the Partnership acquired from a subsidiary of TransCanada an additional 11.81 percent interest in PNGTS, resulting in the Partnership owning 61.71 percent in PNGTS (Refer to Note 18-Subsequent Events).  As a result of the Partnership owning 61.71 percent of PNGTS, the Partnership’s historical financial information was recast, except net income (loss) per common unit, to consolidate PNGTS for all the periods presented in these consolidated financial statements. Additionally, this acquisition was accounted for as transaction between entities under common control, similar to pooling of interests, whereby the assets and liabilities of PNGTS were recorded at TransCanada’s carrying value.

Also, on June 1, 2017, the Partnership acquired from subsidiaries of TransCanada a 49.34 percent interest in Iroquois Gas Transmission,L.P (“Iroquois”) (Refer to Note 18-Subsequent Events). Accordingly, the equity method investment in Iroquois was accounted for prospectively and did not form part of these consolidated financial statements.

On January 1, 2016, the Partnership acquired a 49.9 percent interest in PNGTS (2016 PNGTS Acquisition) from a subsidiary of TransCanada. The PNGTS Acquisition was accounted for as a transaction between entities under common control, similar to a pooling of interests, whereby the equity investment in PNGTS was recorded at

6

TransCanada’s carrying value and the total excess purchase price paid was recorded as a reduction in Partners’ Equity. Accordingly, the equity investment in PNGTS is being eliminated as a result of consolidating PNGTS for all the periods presented. Refer to Note 6 for additional disclosure regarding the PNGTS Acquisition.

Use of Estimates

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

NOTE 3ACCOUNTING PRONOUNCEMENTS

Retrospective application of 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 entity (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.

7

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 currently anticipates adopting the standard using the modified retrospective approach with the cumulative-effect of initially applying the guidance recognized at the date of adoption, subject to allowable and elected practical expedients.

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

Leases

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

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

Goodwill Impairment

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

NOTE 4EQUITY INVESTMENTS

Northern Border and Great Lakes 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 (b)		Equity Investments (b)
	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
			36	33	930	918

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

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

8

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

9

	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 5DEBT AND CREDIT FACILITIES

(unaudited) (millions of dollars)	March 31, 2017(b)	Weighted Average Interest Rate for the Quarter Ended March 31, 2017 (b)		December 31, 2016(b)		Weighted Average Interest Rate for the Year Ended December 31, 2016(b)
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	%
PNGTS
5.90% Senior Secured Notes due December 2018	41	5.90	%(a)	53		5.90	%(a)
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)
	1,858			1,920
Less: unamortized debt issuance costs and debt discount	8			9
Less: current portion	46			52	(c)
	1,804			1,859

(a)Fixed interest rate

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

(c)Includes the PNGTS portion due at December 31, 2016 amounting to $5.5 million that was paid on January 3, 2017

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).

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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

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).

PNGTS

PNGTS’ Senior Secured Notes are secured by the PNGTS long-term firm shipper contracts and its partners’ pledge of their equity and a guarantee of debt service for six months. PNGTS is restricted under the terms of its note purchase agreement from making cash distributions unless certain conditions are met. Before a distribution can be made, the debt service reserve account must be fully funded and PNGTS’ debt service coverage ratio for the preceding and succeeding twelve months must be 1.30 or greater. At March 31, 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 to make any cash distributions.

Tuscarora

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	40	(a)
2018	715	(a)
2019	43
2020	100
2021	460
Thereafter	500
	1,858	(a)

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

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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. The Securities Act generally requires that any claim brought for a violation of Section 5 of the Securities Act be brought within one year of violation.

At December 31, 2016, $83 million was recorded as Common units subject to rescission on the consolidated balance sheet.  The Partnership classified 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.

No unitholder claimed or attempted to exercise any rescission rights prior to their expiry dates and the final rights related to the sales of such units expired on May 19, 2017. Therefore all the common units subject to rescission on the consolidated balance sheet were reclassified back to equity on our consolidated balance sheet at June 30, 2017 as filed on our Second Quarterly report on Form 10Q dated August 3, 2017.

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 net income attributed to PNGTS’ former parent, amounts attributable to the General Partner and Class B units by the weighted average number of common units outstanding.

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

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

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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 (a)	77			74
Net income attributable to PNGTS’ former parent (a) (b)	(2		)	(1		)
Net income allocable to General Partner and Limited Partners	75			73
Net income attributable to the General Partner	(1		)	(1		)
Incentive distributions attributable to the General Partner (c)	(2		)	(1		)
Net income attributable to common units	72			71
Weighted average common units outstanding (millions) — basic and diluted (d)	68.3			64.4
Net income per common unit — basic and diluted (e)	$	1.05		$	1.10

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

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

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

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

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

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 (b)		2016 (b)
Change in accounts receivable and other	7		(2	)
Change in other current assets	1		3
Change in accounts payable and accrued liabilities	(3	)	3	(a)
Change in accounts payable to affiliates	(1	)	(4	)
Change in state income taxes payable	—		9
Change in accrued interest	3		5
Change in operating working capital	7		14

(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.

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

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

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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) (c)	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 (c)	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) (c)	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.

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

Great Lakes

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, $15 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

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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.

PNGTS

For the three months ended March 31, 2017 and 2016, PNGTS provided transportation services to a related party. Revenues from TransCanada Energy Ltd., a subsidiary of TransCanada, for the three months ended March 31, 2017 and 2016 were approximately nil million and  $1 million, respectively. At March 31, 2017, PNGTS had nil million outstanding receivables from TransCanada Energy Ltd. in the consolidated balance sheets (December 31, 2016- nil million).

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 $1,905 million and $1,963 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

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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).

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

NOTE 12      ACCOUNTS RECEIVABLE AND OTHER

(unaudited)
(millions of dollars)	March 31, 2017 (a)	December 31, 2016 (a)
Trade accounts receivable, net of allowance of nil	38	44
Imbalance receivable from affiliates	1	2
Other	2	1
	41	47

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

NOTE 13      FINANCIAL CHARGES AND OTHER

	Three months ended
(unaudited)	March 31,
(millions of dollars)	2017 (c )	2016 (c )
Interest Expense (a)	17	18
PNGTS’ amortization of derivative loss on derivative instruments (Note 11) (b)	—	—
Net realized loss related to the interest rate swaps (b)	—	—
Other Income (b)	—	—
	17	18

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

(b)      Nil million for both periods.

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

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

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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 filed its rate case pursuant  to Section 4 of the Natural Gas Act (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 is currently seeking 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 current consolidation guidance to determine if those that are considered to be VIEs are appropriately consolidated or if they should be accounted for under other 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:

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(unaudited)
(millions of dollars)	March 31, 2017 (b)		December 31, 2016 (b)
ASSETS (LIABILITIES) *
Cash and cash equivalents	18		14
Accounts receivable and other	28		33
Inventories	6		6
Other current assets	4		6
Equity investments	930		918
Plant, property and equipment	1,140		1,146
Other assets	2		2
Accounts payable and accrued liabilities	(20	)	(21	)
Accounts payable to affiliates, net	(24	)	(32	)
Distributions payable	(3	)	(3	)
Accrued interest	(5	)	(2	)
State income tax payable	(1	)	—
Current portion of long-term debt	(46	)	(52	)
Long-term debt	(330	)	(337	)
Other liabilities	(26	)	(25	)
Deferred state income tax	(10	)	(10	)

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

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

NOTE 17      INCOME TAXES

The state of New Hampshire (NH) imposes a business profits tax (BPT) levied at the PNGTS level. As a result of the BPT, PNGTS recognizes deferred taxes related to temporary differences between the financial statement carrying amount of existing assets and liabilities and their respective tax bases. The deferred taxes at March 31, 2017 and December 31, 2016 relate primarily to utility plant. For the three months ended March 31, 2017 and 2016, the NH BPT effective tax rate was 3.8 percent for all periods and was applied to PNGTS’ taxable income.

The state income taxes of PNGTS are broken out as follows:

	Three months ended
(unaudited)	March 31,
(millions of dollars)	2017 (a)	2016 (a)
State income taxes
Current	1	8
Deferred	—	(7	)
	1	1

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

NOTE 18      SUBSEQUENT EVENTS

Management of the Partnership has reviewed subsequent events through August 3, 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.

Partnership

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 was paid 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.

On May 25, 2017, the Partnership closed a $500 million public offering of senior unsecured notes bearing an interest rate of 3.90 percent maturing May 25, 2027. The net proceeds of $497 million were used to fund a portion of the Partnership’s June 1, 2017 acquisition. The indenture for the notes contains customary investment grade covenants.

On June 1, 2017, the Partnership acquired from subsidiaries of TransCanada a 49.34 percent interest in Iroquois Gas Transmission System, L.P. (Iroquois), including an option to acquire a further 0.66 percent interest in Iroquois, together with an additional 11.81 percent interest in PNGTS resulting in the Partnership owning a 61.71 percent interest in PNGTS (2017 Acquisition). The total purchase price of the 2017 Acquisition was $765 million plus preliminary purchase price adjustments amounting to $9 million. The purchase price consisted of  (i) $710 million for the Iroquois interest (less $164 million, which reflected our 49.34 percent share of Iroquois outstanding debt on June 1)  (ii) $55 million for the additional 11.81 percent interest in PNGTS (less $5 million, which reflected our 11.81% proportionate share in PNGTS’ debt on June 1) and (iii) preliminary working capital adjustments on PNGTS and Iroquois amounting to $3 million and $6 million, respectively. Additionally, the Partnership paid $1,000 for the option to acquire TransCanada’s remaining 0.66 percent interest in Iroquois. The Partnership funded the cash portion of the 2017 Acquisition through a combination of proceeds from the May 2017 public debt offering (refer to Note 5) and borrowing under our Senior Credit Facility.

As at the date of the 2017 Acquisition, there was significant cash on Iroquois’ balance sheet.  Pursuant to the Purchase and Sale Agreement associated with the acquisition of the Iroquois interest, as amended, the Partnership agreed to pay $28 million plus interest to TransCanada on August 1, 2017 for its 49.34 percent share of cash determined to be surplus to Iroquois’ operating needs. In addition, the Partnership expects to make a final working capital adjustment payment by the end of August. The $28 million and the related interest were included in accounts payable to affiliates at June 30, 2017.

The Iroquois’ partners adopted a distribution resolution to address the significant cash on Iroquois’ balance sheet post-closing. The Partnership expects to receive the $28 million of unrestricted cash as part of its quarterly distributions from Iroquois over 11 quarters under the terms of the resolution, beginning with the second quarter 2017 distribution on August 1, 2017.

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

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

On July 20, 2017, the board of directors of our General Partner declared the Partnership’s second quarter 2017 cash distribution in the amount of $1.00 per common unit payable on August 11, 2017 to unitholders of record as of August 1, 2017. The declared distribution reflects a $0.06 per common unit increase to the Partnership’s first quarter 2017 quarterly distribution. The declared distribution totaled $74 million and is payable in the following manner: $69 million to common unitholders (including $6 million to the General Partner as a holder of 5,797,106 common units and $11 million to another subsidiary of TransCanada as holder of 11,287,725 common units) and $5 million to our General Partner, which included $2 million for its effective two percent general partner interest and $3 million of IDRs.

Northern Border

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.

Northern Border declared its April 2017 distribution of $14 million on May 12, 2017, of which the Partnership received its 50 percent share or $7 million on May 31, 2017.

Northern Border declared its May 2017 distribution of $12 million on June 7, 2017, of which the Partnership received its 50 percent share or $6 million on June 30, 2017.

Northern Border declared its June 2017 distribution of $14 million on July 7, 2017, of which the Partnership received its 50 percent share or $7 million on July 31, 2017.

Great Lakes

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.

Great Lakes declared its second quarter 2017 distribution of $15 million on July 18, 2017, of which the Partnership will receive its 46.45 percent share or $7 million on August 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

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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 20). We cannot predict the cumulative impact of these circumstances to the Partnership’s earnings and cash flows at this time.

Iroquois

Iroquois declared its second quarter 2017 distribution of $28 million on July 27, 2017, of which the Partnership received its 49.34 percent share or $14 million on August 1, 2017.

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EX-99.6

Exhibit 99.6

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

The following discussion and analysis should be read in conjunction with the Unaudited Consolidated Financial Statements and Notes thereto for quarter ended March 31, 2017 included as Exhibit 99.5 of  this Current Report on Form 8-K, as well as our Audited Consolidated Financial Statements and Notes thereto for the year ended December 31, 2016 included as Exhibit 99.2 of this Current Report on Form 8-K. This report includes certain forward-looking statements. 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. 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.

BASIS OF PRESENTATION

See the Basis of Presentation section of Note 2- Significant Accounting Policies, Notes to Consolidated Financial Statements for the quarter ended March 31, 2017 included in Exhibit 99.5 of this Current Report on Form 8-K, for important information on the content and comparability of our historical financial statements.

The initial acquisition of a 49.9 percent interest in PNGTS on January 1, 2016 and additional 11.81 percent on June 1, 2017 (collectively, the PNGTS Acquisitions) were accounted for as was accounted for as transaction between entities under common control, which are required to be accounted for as if the PNGTS Acquisitions had occurred at the beginning of the year, with financial statements for prior periods recast to furnish comparative information. Accordingly, the accompanying financial information has been recast, except net income (loss) per common unit, to consolidate PNGTS for all periods presented.

Also, on June 1, 2017, the Partnership acquired from subsidiaries of TransCanada a 49.34 percent in Iroquois (Refer to Note 18-Subsequent Events, Notes to Consolidated Financial Statements for the quarter ended March 31, 2017 included in Exhibit 99.5 of this Current Report on Form 8-K). This transaction was accounted prospectively and did not form part of the accompanying financial information.

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 and was paid on May 15, 2017 to unitholders of record as of May 5, 2017. The declared distribution totaled $68 million and was paid in the following manner: $65 million to common unitholders (including $5 million to the General Partner as a holder of 5,797,106 common units and $11 million to another subsidiary of TransCanada as holder of 11,287,725 common units) and $3 million to our General Partner, which included $1 million for its effective two percent general partner interest and $2 million of IDRs.

On July 20, 2017, the board of directors of our General Partner declared the Partnership’s second quarter 2017 cash distribution in the amount of $1.00 per common unit payable on August 11, 2017 to unitholders of record as of August 1, 2017. The declared distribution reflects a $0.06 per common unit increase to the Partnership’s first quarter 2017 quarterly distribution. The declared distribution totaled $74 million and is payable in the following manner: $69 million to common unitholders (including $6 million to the General Partner as a holder of 5,797,106 common units and $11 million to another subsidiary of TransCanada as holder of 11,287,725 common units) and $5 million to our General Partner, which included $2 million for its effective two percent general partner interest and $3 million 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 filed its rate case pursuant to Section 4 of the Natural Gas Act (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 is currently seeking 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

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threshold. Additionally, Great Lakes is currently pursuing resolution of its March 31, 2017 General Section 4 Rate Filing. We cannot predict the cumulative impact of these circumstances to the Partnership’s earnings and cash flows at this time.

Debt Offering- On May 25, 2017, the Partnership closed a $500 million public offering of senior unsecured notes bearing an interest rate of 3.90 percent maturing May 25, 2027. The net proceeds of $497 million were used to fund a portion of the Partnership’s June 1, 2017 acquisitions. The indenture for the notes contains customary investment grade covenants.

2017 Acquisition — On June 1, 2017, the Partnership acquired from subsidiaries of TransCanada a 49.34 percent interest in Iroquois Gas Transmission System, L.P. (Iroquois), including an option to acquire a further 0.66 percent interest in Iroquois, together with an additional 11.81 percent interest in PNGTS resulting in the Partnership owning a 61.71 percent interest in PNGTS (2017 Acquisition). The total purchase price of the 2017 Acquisition was $765 million plus preliminary purchase price adjustments amounting to $9 million. The purchase price consisted of  (i) $710 million for the Iroquois interest (less $164 million, which reflected our 49.34 percent share of Iroquois outstanding debt on June 1)  (ii) $55 million for the additional 11.81 percent interest in PNGTS (less $5 million, which reflected our 11.81% proportionate share in PNGTS’ debt on June 1) and (iii) preliminary working capital adjustments on PNGTS and Iroquois amounting to $3 million and $6 million, respectively. Additionally, the Partnership paid $1,000 for the option to acquire TransCanada’s remaining 0.66 percent interest in Iroquois. The Partnership funded the cash portion of the 2017 Acquisition through a combination of proceeds from the May 2017 public debt offering and borrowing under our Senior Credit Facility.

As at the date of the 2017 Acquisition, there was significant cash on Iroquois’ balance sheet. Pursuant to the Purchase and Sale Agreement associated with the acquisition of the Iroquois interest, as amended, the Partnership agreed to pay $28 million plus interest to TransCanada on August 1, 2017 for its 49.34 percent share of cash determined to be surplus to Iroquois’ operating needs. In addition, the Partnership expects to make a final working capital adjustment payment by the end of August. The $28 million and the related interest were included in accounts payable to affiliates at June 30, 2017.

The Iroquois’ partners adopted a distribution resolution to address the significant cash on Iroquois’ balance sheet post-closing. The Partnership expects to receive the $28 million of unrestricted cash as part of its quarterly distributions from Iroquois over 11 quarters under the terms of the resolution, beginning with the second quarter 2017 distribution on August 1, 2017.

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

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

HOW WE EVALUATE OUR OPERATIONS

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

EBITDA

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

Distributable Cash Flows

Total distributable cash flow and distributable cash flow provide measures of distributable cash generated during the current earnings period.

Please see “Non-GAAP Financial Measures: EBITDA and Distributable Cash Flow” for more information.

RESULTS OF OPERATIONS

Our equity interests in Northern Border, Great Lakes, and 61.71 percent ownership in PNGTS, and full 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.

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	Three months ended
(unaudited)	March 31,				$		%
(millions of dollars)	2017 (a)		2016 (a)		Change*		Change*
Transmission revenues	112		111		1		**
Equity earnings	36		33		3		9
Operating, maintenance and administrative costs	(23	)	(21	)	(2	)	(10	)
Depreciation	(24	)	(23	)	(1	)	(4	)
Financial charges and other	(17	)	(18	)	1		6
Net income before taxes	84		82		2		2
Income taxes	(1	)	(1	)	—		—
Net income	83		81		2		2
Net income attributable to non-controlling interest	6		7		1		14
Net income attributable to controlling interests	77		74		3		4

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

** less than 1 percent change

(a)Financial information was recast to consolidate PNGTS for all periods presented. Please see “Basis of Presentation” section for more information.

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 $3 million or 4 percent mainly due to higher revenues and equity earnings partially offset by higher costs.

Transmission revenues - The $1 million increase was primarily due to higher transportation revenues on GTN offset by lower discretionary revenues on PNGTS.

Equity Earnings - The $3 million increase was primarily due to higher equity earnings on our investment in Great Lakes primarily due to its higher transportation revenues.

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-Partner’s Equity, Notes to Consolidated Financial Statements for the quarter ended March 31, 2017 included in Exhibit 99.5 of this Current Report on Form 8-K, 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

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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

(millions of dollars)	June 30, 2017	March 31, 2017	December 31, 2016
Total capacity under the Senior Credit Facility	500	500	500
Less: Outstanding borrowings under the Senior Credit Facility	170	110	160
Available capacity under the Senior Credit Facility	330	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 (a)		2016 (a)
Net cash provided by (used in):
Operating activities	107		120
Investing activities	(11	)	(208	)
Financing activities	(83	)	102
Net increase in cash and cash equivalents	13		14
Cash and cash equivalents at beginning of the period	64		55
Cash and cash equivalents at end of the period	77		69

(a)Financial information was recast to consolidate PNGTS for all periods presented. Please see “Basis of Presentation” section for more information.

Operating Cash Flows

Net cash provided by operating activities decreased by $13 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.

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Financing Cash Flows

Net cash provided by financing activities decreased by $185 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;

·$31 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;

·$5 million decrease in distributions paid to TransCanada as the former parent of PNGTS due to the Partnership’s acquisition of a 49.9 percent interest in PNGTS effective January 1, 2016; and

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

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.

Northern Border declared its April 2017 distribution of $14 million on May 12, 2017, of which the Partnership received its 50 percent share or $7 million on May 31, 2017.

Northern Border declared its May 2017 distribution of $12 million on June 7, 2017, of which the Partnership received its 50 percent share or $6 million on June 30, 2017.

Northern Border declared its June 2017 distribution of $14 million on July 7, 2017, of which the Partnership received its 50 percent share or $7 million on July 31, 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.

Great Lakes declared its second quarter 2017 distribution of $15 million on July 18, 2017, of which the Partnership will receive its 46.45 percent share or $7 million on August 1, 2017.

Iroquois declared its second quarter 2017 distribution of $28 million on July 27, 2017, of which the Partnership received its 49.34 percent share or $14 million on August 1, 2017.

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 Management Discussion and Analysis of Financial Condition and Results of Operations for the year ended December 31, 2016 Consolidated Financial Statements and Notes thereto included as Exhibit 99.3 of this Current Report on Form 8-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 and was paid on May 15, 2017 to unitholders of record as of May 5, 2017.  Please see “Recent Business Developments section.”

On May 25, 2017, the Partnership closed a $500 million public offering of senior unsecured notes bearing an interest rate of 3.90 percent maturing May 25, 2027. The net proceeds of $497 million were used to fund a portion of the 2017 Acquisition. The indenture for the notes contains customary investment grade covenants. Please see “Recent Business Developments section.”

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On July 20, 2017, the board of directors of our General Partner declared the Partnership’s second quarter 2017 cash distribution in the amount of $1.00 per common unit payable on August 11, 2017 to unitholders of record as of August 1, 2017. Please see “Recent Business Developments section.”

Non-GAAP Financial Measures: EBITDA and Distributable Cash Flow

EBITDA is an approximate measure of our operating cash flow during the current earnings period and reconciles directly to the most comparable measure of net income. It measures our earnings before deducting interest, depreciation and amortization, net income attributable to non-controlling interests, and includes earnings from our equity investments.

Total distributable cash flow and distributable cash flow provide measures of distributable cash generated during the current earnings period and reconcile directly to the net income amount presented.

Total distributable cash flow includes EBITDA plus:

·Distributions from our equity investments

less:

·Earnings from our equity investments,

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

·Interest expense,

·Distributions to non-controlling interests;

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

·Maintenance capital expenditures from consolidated subsidiaries.

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

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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 (a)		2016(a)
Net income	83		81
Add:
Interest expense	17		18
Depreciation and amortization	24		23
Income taxes	1		1
EBITDA	125		123
Add:
Distributions from equity investments (b)
Northern Border	20		23
Great Lakes	20		17
	40		40
Less:
Equity earnings:
Northern Border	(19	)	(18	)
Great Lakes	(17	)	(15	)
	(36	)	(33	)
Less:
Interest expense	(17	)	(18	)
Income taxes	(1	)	(1	)
Distributions to non-controlling interest (c)	(5	)	(9	)
Distributions to TransCanada as PNGTS’ former parent(d)	(1	)	(2	)
Maintenance capital expenditures (e)	(10	)	(1	)
	(34	)	(31	)
Total Distributable Cash Flow	95		99
General Partner distributions declared (f)	(3	)	(2	)
Distributions allocable to Class B units (g)	—		—
Distributable Cash Flow	92		97

(a)Financial information was recast to consolidate PNGTS for all periods presented. Please see “Basis of Presentation” section for more information.

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

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

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

(e)The Partnership’s maintenance capital expenditures include cash expenditures incurred or cash reserved 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.

(f)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).

(g)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.

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Please read Notes 6 and 7, Notes to Consolidated Financial Statements for the quarter ended March 31, 2017 included in Exhibit 99.5 of this Current Report on Form 8-K 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 and equity earnings partially offset by an increase in GTN’s operational costs as discussed in the “Results of Operations” section. However, our distributable cash flow decreased by $5 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 and cash reserved on PNGTS’ pipeline integrity program that is currently being implemented on its 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	%
PNGTS
5.90% Senior Secured Notes due 2018	41	23	18	—	—	5.90	(a)
Tuscarora
Unsecured Term Loan due 2019	10	1	9	—	—	1.91	%
3.82% Series D Senior Notes due 2017	12	12	—	—	—	3.82	%(a)
	1,858	46	752	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 $1,905 million.

Please read Note 5, Notes to Consolidated Financial Statements for the quarter ended March 31, 2017 included in Exhibit 99.5 of this Current Report on Form 8-K 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 projects 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.

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

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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 the Audited Consolidated Financial Statements and Notes thereto for the year ended December 31, 2016 included in Exhibit 99.2 of  this Current Report on Form 8-K

Our significant accounting policies have remained unchanged since December 31, 2016 except as described in Note 3, Notes to Consolidated Financial Statements and Notes thereto for the quarter ended March 31, 2017 included in Exhibit 99.5 of  this Current Report on Form 8-K. A summary of our significant accounting policies can be found in the Audited Consolidated Financial Statements and Notes thereto for the year ended December 31, 2016 included in Exhibit 99.2 of  this Current Report on Form 8-K.

RELATED PARTY TRANSACTIONS

Please read Note 10 and 18, Notes to Consolidated Financial Statements for quarter ended March 31, 2017 included in Exhibit 99.5 of this Current Report on Form 8-K for additional information regarding related party transactions.

Item 3.Quantitative and Qualitative Disclosures About Market Risk

OVERVIEW

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

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

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

MARKET RISK

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

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

As of 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 19 percent, of our outstanding debt was subject to variability in LIBOR interest rates. As of December 31, 2016, the Partnership’s interest rate exposure resulted from our floating rate Senior Credit Facility, 2015 Term Loan Facility, GTN’s Unsecured Term Loan Facility and Tuscarora’s Unsecured Term Loan Facility, under which $405 million or 21 percent of our outstanding debt was subject to variability in LIBOR interest rates.

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.

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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 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).

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

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.

11

XML

Document and Entity Information	3 Months Ended
	Mar. 31, 2017
Document and Entity Information
Entity Registrant Name	TC PIPELINES LP
Entity Central Index Key	0001075607
Document Type	8-K
Document Period End Date	Mar. 31, 2017
Amendment Flag	true
AmendmentDescription	Recast to consolidate PNGTS for all periods presented.
Current Fiscal Year End Date	--12-31

XML

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions		Mar. 31, 2017		Dec. 31, 2016		Mar. 31, 2016	Dec. 31, 2015		Dec. 31, 2014		Dec. 31, 2013
Current Assets
Cash and cash equivalents	[1]	$ 77		$ 64		$ 69	$ 55		$ 153		$ 116
Accounts receivable and other (Note 12)	[1]	41		47			41
Inventories	[1]	7		7			7
Other	[1]	6		7			3
Total current assets	[1]	131		125			106
Equity investments (Note 4)	[1]	930		918			965
Plant, property and equipment (Net of $1,112 accumulated depreciation; 2016- $1,088)	[1]	2,162		2,180			2,257
Goodwill	[1]	130		130			130
Other assets (Note 3)	[1]	1		1			1
Total assets	[1]	3,354		3,354			3,459
Current Liabilities
Accounts payable and accrued liabilities	[1]	26		29			34
Accounts payable to affiliates (Note 10)	[1]	7		8			8
Accrued interest	[1]	13		10			8
Distribution payable	[1]	3		3			10
Current portion of long-term debt (Note 5)	[1]	46		52			36
Total current liabilities	[1]	95		102			96
Long-term debt, net (Note 5)	[1]	1,804		1,859			1,935
Deferred state income taxes (Note 23)	[1]	10		10			10
Other liabilities (Note 8)	[1]	28		28			27
Total liabilities	[1]	1,937		1,999			2,068
Common units subject to rescission (Note 6)	[1]	64		83
Partners' Equity (Note 9)
General partner	[1]	28		27			25
Accumulated other comprehensive loss (AOCL)(Note 10)	[1]	(1)		(2)			(4)
Controlling interests	[1]	1,220		1,144			1,149
Non-controlling interest	[1]	101		97			91
Equity of former parent of PNGTS	[1]	32		31			151
Total partners' equity		1,353	[1]	1,272	[1]		1,391	[1]	$ 1,818	[2]	$ 2,013	[2]
Total liabilities and partners' equity	[1]	3,354		3,354			3,459
Common units
Partners' Equity (Note 9)
Limited partner	[1]	1,098		1,002			1,021
Class B units
Partners' Equity (Note 9)
Limited partner	[1]	$ 95		$ 117			$ 107

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

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

XML

CONSOLIDATED STATEMENTS OF INCOME - USD ($) shares in Millions, $ in Millions		3 Months Ended											12 Months Ended
		Mar. 31, 2017		Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016		Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2016		Dec. 31, 2015		Dec. 31, 2014
Transmission revenues		$ 112	[1]	$ 111	$ 103	$ 101	$ 111		$ 110	$ 96	$ 97	$ 114	$ 426	[1]	$ 417	[1]	$ 410	[1]
Equity earnings (Note 4)		36	[1]	22	22	20	33		34	17	15	31	97	[1]	97	[1]	88	[1]
Impairment of equity-method investment (Note 4)									199						199	[1]
Operation and maintenance expenses	[1]	(14)					(12)						(58)		(61)		(61)
Property taxes	[1]	(7)					(7)						(27)		(27)		(28)
General and administrative	[1]	(2)					(2)						(7)		(9)		(9)
Depreciation	[1]	(24)					(23)						(96)		(95)		(96)
Financial charges and other (Note 11)	[1]	(17)					(18)						(71)		(63)		(61)
Net income before taxes	[1]	84					82						264		60		243
Income taxes (Note 17)	[1]	(1)					(1)						(1)		(2)		(2)
Net Income		83	[1]	65	60	57	81		(124)	54	47	81	263	[1]	58	[1]	241	[1]
Net income attributable to non-controlling interests	[1]	6					7						15		21		46
Net income attributable to controlling interests		77	[1]	61	58	55	74		(128)	52	46	67	248	[1]	37	[1]	195	[1]
Net income (loss) attributable to controlling interest allocation (Note 12)
General Partner	[1]	3					2						11		3		4
TransCanada and its subsidiaries	[1]	2					1						26		36		23
Net income attributable to controlling interests		77	[1]	$ 61	$ 58	$ 55	74		$ (128)	$ 52	$ 46	$ 67	248	[1]	37	[1]	195	[1]
Common units
Net income (loss) attributable to controlling interest allocation (Note 12)
Limited partners	[1]	$ 72					$ 71						$ 211		$ (2)		$ 168
Net income (loss) per common unit (Note 7) - basic (in dollars per unit)		$ 1.05	[1],[2]	$ 0.70	$ 0.65	$ 0.76	$ 1.10	[2]	$ (2.27)	$ 0.70	$ 0.66	$ 0.88	$ 3.21	[1]	$ (0.03)	[1]	$ 2.67	[1]
Net income (loss) per common unit (Note 7) - diluted (in dollars per unit)		$ 1.05	[1],[2]				$ 1.10	[1],[2]					$ 3.21		$ (0.03)		$ 2.67
Weighted average common units outstanding - basic (in units)	[1]	68.3					64.4						65.7		63.9		62.7
Weighted average common units outstanding - diluted (in units)		68.3	[1]				64.4	[1]					65.7		63.9		62.7
Common units outstanding, end of year (in units)	[1]	68.6		67.4			64.7		64.3				67.4		64.3		63.6

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

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

XML

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME $ in Millions	12 Months Ended
	Dec. 31, 2016 USD ($)	[1]
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
Net income	$ 263
Other comprehensive income
Change in fair value of cash flow hedges (Note 10 and 18)	3
Reclassification to net income of gains and losses on cash flow hedges (Note 10)	(2)
Amortization of realized loss on derivative instrument (Note 11)	1
Comprehensive income	265
Comprehensive income attributable to non-controlling interests	16
Comprehensive income attributable to controlling interests	$ 249

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

XML

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Cash Generated From Operations
Net income	[1]	$ 263	$ 58	$ 241
Depreciation	[1]	96	95	96
Impairment of equity-method investment (Note 4)	[1]		199
Amortization of debt issue costs reported as interest expense (Note 11)	[1]	2	1	1
Change in fair value of interest rate derivative instruments recognized in other comprehensive income (loss)	[1]	1	1	1
Accrual of costs related to acquisition of 49.9% interest in PNGTS (Note 6)	[1]		2
Equity earnings from equity investments (Note 4)	[1]	(97)	(97)	(88)
Distributions received from operating activities of equity investments (Note 3)	[1]	153	119	115
Provision for deferred state income taxes (Note 23)	[1]		4	(1)
Provision for rate refund (Note 2)	[1]		(101)	23
Equity allowance for funds used during construction	[1]		(1)
Change in operating working capital (Note 14)	[1]	(1)	(20)	29
Total cash generated from operations	[1]	417	260	417
Investing Activities
Capital expenditures	[1]	(29)	(54)	(10)
Other	[1]	1	1
Total investing activities	[1]	(230)	(326)	(261)
Financing Activities
Distributions paid (Note 13)	[1]	(250)	(228)	(212)
Distributions paid to non-controlling interests	[1]	(12)	(21)	(60)
Distributions paid to former parent of PNGTS	[1]	(9)	(19)	(16)
Common unit issuance, net (Note 9)	[1]	84	44	73
Common unit issuance subject to rescission, net (Note 9)	[1]	83
Equity contribution by the General Partner (Note 6)	[1]		2
Long-term debt issued, net of discount (Note 5)	[1]	209	618	35
Short-term loan issued (Note 7)	[1]			170
Long-term debt repaid (Note 7)	[1]	(270)	(425)	(109)
Debt issuance costs	[1]	(1)	(3)
Total financing activities	[1]	(178)	(32)	(119)
Increase in cash and cash equivalents	[1]	9	(98)	37
Cash and cash equivalents, beginning of year	[1]	55	153	116
Cash and cash equivalents, end of year	[1]	64	55	153
Interest payments paid	[1]	66	59	53
State income taxes paid	[1]	2	2
Supplemental information about non-cash investing and financing activities
Accrual for costs related to construction of GTN's Carty Lateral (Note 14)	[1]		10
Issuance of Class B units to TransCanada (Note 9)	[1]		95
Class B units
Financing Activities
Distributions paid (Note 9 and 13)	[1]	(12)
Bison
Investing Activities
Acquisition of interest	[1]			(217)
GTN
Investing Activities
Acquisition of interest	[1]		(264)	(25)
Northern Border
Cash Generated From Operations
Equity earnings from equity investments (Note 4)		(69)	(66)	(69)
Great Lakes
Cash Generated From Operations
Equity earnings from equity investments (Note 4)		(28)	(31)	(19)
Investing Activities
Investment/Acquisition of interests (Note 4)	[1]	(9)	$ (9)	$ (9)
Portland Natural Gas Transmission System | GTN
Investing Activities
Acquisition of interest	[1]	$ (193)

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

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CONSOLIDATED STATEMENTS OF CASH FLOWS (Parenthetical)	Jun. 01, 2017	Dec. 31, 2016	Jan. 01, 2016	Dec. 31, 2015	Apr. 01, 2015	Oct. 01, 2014
Portland Natural Gas Transmission System
Acquisitions
Interest acquired (as a percent)	61.71%
Portland Natural Gas Transmission System | Transaction between entities under common control | Former parent, TransCanada subsidiaries
Acquisitions
Interest acquired (as a percent)		30.00%	49.90%	49.90%
GTN | Transaction between entities under common control | Former parent, TransCanada subsidiaries
Acquisitions
Interest acquired (as a percent)					30.00%
Bison | Transaction between entities under common control | Former parent, TransCanada subsidiaries
Acquisitions
Interest acquired (as a percent)		30.00%			30.00%	30.00%

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CONSOLIDATED STATEMENT OF CHANGES IN PARTNERS' EQUITY - USD ($) shares in Millions, $ in Millions		Limited Partners Common units GTN	Limited Partners Common units Bison	Limited Partners Common units Portland Natural Gas Transmission System	Limited Partners Common units ATM Equity Issuance Program	Limited Partners Common units		Limited Partners Class B units		General Partner GTN	General Partner Portland Natural Gas Transmission System	General Partner ATM Equity Issuance Program	General Partner		AOCL		Common units ATM Equity Issuance Program	Class B units	[1]	Non-controlling interests GTN	[1]	Non-controlling interests Bison	[1]	Non-controlling interests		Equity of former parent of PNGTS	[3]	GTN	[1]	Bison	[1]	Portland Natural Gas Transmission System	[1]	ATM Equity Issuance Program	[1]	Total
Partners' Equity at beginning of year at Dec. 31, 2013	[1]					$ 1,322							$ 28		$ (5)	[2]								$ 526		$ 142										$ 2,013
Partners' Equity at beginning of year (in units) at Dec. 31, 2013	[1]					62.3
Increase (Decrease) in Partners' Equity
Net income (loss)						$ 168	[1]						4	[1]										46	[1]	23	[1]									241	[4]
ATM Equity Issuance, net (Note 6)					$ 71							$ 2																						$ 73
ATM Equity Issuance, net (Note 6) (in units)					1.3
Acquisition of interest (Note 6)			$ (29)																			$ (188)								$ (217)
Distributions	[1]					(207)							(5)											(61)		(19)										(292)
Partners' Equity at end of year at Dec. 31, 2014	[1]					$ 1,325							29		(5)	[2]								323		146										1,818
Partners' Equity at end of year (in units) at Dec. 31, 2014	[1]					63.6
Increase (Decrease) in Partners' Equity
Net income (loss)						$ (2)	[1]	$ 12	[1]				3	[1]										21	[1]	24	[1]									58	[4]
Other Comprehensive Income (Loss), net	[1]														1	[2]																				1
ATM Equity Issuance, net (Note 6)					$ 43			$ 95				1						$ 95																44
ATM Equity Issuance, net (Note 6) (in units)					0.7			1.9
Acquisition of interest (Note 6)		$ (124)								$ (3)										$ (232)								$ (359)
Equity Contribution (Note 6)													2																							2	[1]
Distributions	[1]					(221)							(7)											(21)		(19)										(268)
Partners' Equity at end of year at Dec. 31, 2015						$ 1,021	[1]	$ 107	[1]				25	[1]	(4)	[1],[2]								91	[1]	151	[1]									1,391	[4]
Partners' Equity at end of year (in units) at Dec. 31, 2015	[1]					64.3		1.9
Increase (Decrease) in Partners' Equity
Net income (loss)						$ 211	[1]	$ 22	[1]				11	[1]										15	[1]	4	[1]									263	[4]
Other Comprehensive Income (Loss), net	[1]														2	[2]								1												3
ATM Equity Issuance, net (Note 6)					$ 82							$ 2																						$ 84
ATM Equity Issuance, net (Note 6) (in units)					1.5
Common unit issuance subject to rescission, net (Note 9)	[5]					$ 81							2																							83	[1]
Common unit issuance subject to rescission, net (Note 9) (in units)	[5]					1.6
Reclassification of common unit issuance subject to rescission, net (Note 9)	[5]					$ (81)							(2)																							(83)	[1]
Acquisition of interest (Note 6)				$ (72)							$ (1)																					$ (73)
Distributions	[1]					(240)		(12)					(10)											(10)		(4)										(276)
Former parent carrying amount of PNGTS(d)	[1]																									(120)										(120)
Partners' Equity at end of year at Dec. 31, 2016						$ 1,002	[1]	$ 117	[1]				27	[1]	(2)	[1],[2],[6]								97	[1]	31	[1]									1,272	[4]
Partners' Equity at end of year (in units) at Dec. 31, 2016	[1]					67.4		1.9
Increase (Decrease) in Partners' Equity
Net income (loss)	[4]					$ 72							3											6		2	[1]									83
Other Comprehensive Income (Loss), net	[4]														1	[6]																				1
ATM Equity Issuance, net (Note 6)						$ 69							2				$ 69																			71	[4]
ATM Equity Issuance, net (Note 6) (in units)						1.2
Distributions	[4]					$ (64)		$ (22)					(4)											(2)		(1)	[1]									(93)
Partners' Equity at end of year at Mar. 31, 2017	[4]					$ 1,098		$ 95					$ 28		$ (1)	[6]								$ 101		$ 32	[1]									$ 1,353
Partners' Equity at end of year (in units) at Mar. 31, 2017	[4]					68.6	[7]	1.9

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

[2] Losses related to cash flow hedges reported in Accumulated Other Comprehensive Loss and expected to be reclassified to net income in the next 12?months are estimated to be nil. 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.

[3] Equity of Former Parent of PNGTS.

[4] Recast to consolidate PNGTS for all periods presented (Refer to Note 2).

[5] These units are treated as outstanding for financial reporting purposes.

[6] Income related to cash flow hedges reported in Accumulated Other Comprehensive Loss and expected to be reclassified to net income in the next 12 months are estimated to be $1 million. These estimates assume constant interest rates over time; however, the amounts reclassified will vary based on actual value of interest rates at the date of settlement.Includes common units subject to rescission. These units are treated as outstanding for financial reporting purposes. Equity of Former Parent of PNGTS.Recast to consolidate PNGTS for all periods presented (Refer to Note 2).

[7] Includes common units subject to rescission. These units are treated as outstanding for financial reporting purposes.

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CONSOLIDATED STATEMENT OF CHANGES IN PARTNERS' EQUITY (Parenthetical) - Portland Natural Gas Transmission System	Jun. 01, 2017	Dec. 31, 2016	Jan. 01, 2016	Dec. 31, 2015
Interest acquired (as a percent)	61.71%
Transaction between entities under common control | Former parent, TransCanada subsidiaries
Interest acquired (as a percent)		30.00%	49.90%	49.90%

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ORGANIZATION

3 Months Ended

12 Months Ended

Mar. 31, 2017

Dec. 31, 2016

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.

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 interests in the following natural gas pipeline systems through three intermediate limited partnerships (ILPs), TC GL Intermediate Limited Partnership, TC PipeLines Intermediate Limited Partnership and TC Tuscarora Intermediate Limited Partnership:

Pipeline	Length	Description	Ownership
Gas Transmission Northwest LLC (GTN)	1,377 miles	Extends between an interconnection near Kingsgate, British Columbia, Canada at the Canadian border to a point near Malin, Oregon at the California border and delivers natural gas to the Pacific Northwest and to California.	100 percent
Bison Pipeline LLC (Bison)	303 miles	Extends from a location near Gillette, Wyoming to Northern Border’s pipeline system in North Dakota. Bison can transport natural gas from the Powder River Basin to Midwest markets.	100 percent
North Baja Pipeline, LLC (North Baja)	86 miles	Extends between an interconnection with the El Paso Natural Gas Company pipeline near Ehrenberg, Arizona and an interconnection with a natural gas pipeline near Ogilby, California on the Mexican border transporting natural gas in the southwest. North Baja is a bi-directional pipeline.	100 percent
Tuscarora Gas Transmission Company (Tuscarora)	305 miles	Extends between the GTN pipeline near Malin, Oregon to its terminus near Reno, Nevada and delivers natural gas in northeastern California and northwestern Nevada.	100 percent
Northern Border Pipeline Company (Northern Border)	1,412 miles	Extends between the Canadian border near Port of Morgan, Montana to a terminus near North Hayden, Indiana, south of Chicago. Northern Border is capable of receiving natural gas from Canada, the Williston Basin and Rocky Mountain area for deliveries to the Midwest. ONEOK Partners, L.P. owns the remaining 50 percent of Northern Border.	50 percent
Portland Natural Gas Transmission System (PNGTS)	295 miles	Connects with the TransQuebec and Maritimes Pipeline (TQM) at the Canadian border to deliver natural gas to customers in the U.S. northeast. Northern New England Investment Company, Inc. owns the remaining 38.29 percent of PNGTS.	61.71 percent (a)
Great Lakes Gas Transmission Limited Partnership (Great Lakes)	2,115 miles	Connects with the TransCanada Mainline at the Canadian border near Emerson, Manitoba, Canada and St. Clair, Michigan, near Detroit. Great Lakes is a bi-directional pipeline that can receive and deliver natural gas at multiple points along its system. TransCanada owns the remaining 53.55 percent of Great Lakes.	46.45 percent
Iroquois Gas Transmission System, L.P (Iroquois)	416 miles	Extends from the TransCanada Mainline system near Waddington, New York to deliver natural gas to customers in the U.S. northeast. The remaining 50.66 percent is owned by TransCanada (0.66 percent), Dominion Midstream (25.93 percent) and Dominion Resources (24.07 percent).	49.34 percent (b)

^(a) On June 1, 2017, the Partnership acquired an additional 11.81 percent from TransCanada resulting in 61.71 percent ownership in PNGTS. (Refer to Note 24-Subsequent Events).

^(b) Effective June 1, 2017 (Refer to Note 24-Subsequent Events).

The Partnership is managed by its General Partner, TC PipeLines GP, Inc. (General Partner), an indirect wholly-owned subsidiary of TransCanada. The General Partner provides management and operating services to the Partnership and is reimbursed for its costs and expenses. The General Partner owns 5,797,106 of our common units, 100 percent of our IDRs and an effective two percent general partner interest in the Partnership at December 31, 2016. TransCanada also indirectly holds an additional 11,287,725 common units, for total ownership of 25.3 percent of our outstanding common units and 100 percent of our Class B units at December 31, 2016 (Refer to Note 6).

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SIGNIFICANT ACCOUNTING POLICIES

3 Months Ended

12 Months Ended

Mar. 31, 2017

Dec. 31, 2016

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 Audited Consolidated Financial Statements and Notes thereto included as Exhibit 99.2 of  this Current Report on Form 8-K. That report contains a more comprehensive summary of the Partnership’s significant accounting policies. In the opinion of management, the accompanying financial statements contain all of the appropriate adjustments, all of which are normally recurring adjustments unless otherwise noted, and considered necessary to present fairly the financial position of the Partnership, the results of operations and cash flows for the respective periods. Our significant accounting policies are consistent with those disclosed in the Audited Consolidated Financial Statements and Notes thereto included in Exhibit 99.2 of  this Current Report on Form 8-K, except as described in Note 3, Accounting Pronouncements.

Basis of Presentation

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

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

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

On June 1, 2017, the Partnership acquired from a subsidiary of TransCanada an additional 11.81 percent interest in PNGTS, resulting in the Partnership owning 61.71 percent in PNGTS (Refer to Note 18-Subsequent Events).  As a result of the Partnership owning 61.71 percent of PNGTS, the Partnership’s historical financial information was recast, except net income (loss) per common unit, to consolidate PNGTS for all the periods presented in these consolidated financial statements. Additionally, this acquisition was accounted for as transaction between entities under common control, similar to pooling of interests, whereby the assets and liabilities of PNGTS were recorded at TransCanada’s carrying value.

Also, on June 1, 2017, the Partnership acquired from subsidiaries of TransCanada a 49.34 percent interest in Iroquois Gas Transmission,L.P (“Iroquois”) (Refer to Note 18-Subsequent Events). Accordingly, the equity method investment in Iroquois was accounted for prospectively and did not form part of these consolidated financial statements.

On January 1, 2016, the Partnership acquired a 49.9 percent interest in PNGTS (2016 PNGTS Acquisition) from a subsidiary of TransCanada. The PNGTS Acquisition was accounted for as a transaction between entities under common control, similar to a pooling of interests, whereby the equity investment in PNGTS was recorded at TransCanada’s carrying value and the total excess purchase price paid was recorded as a reduction in Partners’ Equity. Accordingly, the equity investment in PNGTS is being eliminated as a result of consolidating PNGTS for all the periods presented. Refer to Note 6 for additional disclosure regarding the PNGTS Acquisition.

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 2 SIGNIFICANT ACCOUNTING POLICIES

The accompanying consolidated financial statements and related notes have been prepared in accordance with United States generally accepted accounting principles (GAAP) and amounts are stated in U.S. dollars. The financial statements and notes present the financial position of the Partnership as of December 31, 2016 and 2015 and the results of its operations, cash flows and changes in partners’ equity for the years ended December 31, 2016, 2015 and 2014. Certain prior year amounts have been reclassified to conform to the current year presentation.

(a) Basis of Presentation

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

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

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

On June 1, 2017, the Partnership acquired from a subsidiary of TransCanada an additional 11.81 percent interest in PNGTS, resulting in the Partnership owning 61.71 percent in PNGTS (Refer to Note 24-Subsequent Events).  As a result of the Partnership owning 61.71 percent of PNGTS, the Partnership’s historical financial information was recast, except net income (loss) per common unit, to consolidate PNGTS for all the periods presented in these consolidated financial statements. Additionally, this acquisition was accounted for as transaction between entities under common control, similar to pooling of interests, whereby the assets and liabilities of PNGTS were recorded at TransCanada’s carrying value.

Also, on June 1, 2017, the Partnership acquired from subsidiaries of TransCanada a 49.34 percent interest in Iroquois (Refer to Note 24-Subsequent Events). Accordingly, the equity method investment in Iroquois  was accounted prospectively and did not form part of these consolidated financial statements.

On January 1, 2016, the Partnership acquired a 49.9 percent interest in PNGTS (2016 PNGTS Acquisition) from a subsidiary of TransCanada. The 2016 PNGTS Acquisition was accounted for as a transaction between entities under common control, similar to a pooling of interests, whereby the equity investment in PNGTS was recorded at TransCanada’s carrying value and the total excess purchase price paid was recorded as a reduction in Partners’ Equity. Accordingly, the equity investment in PNGTS is being eliminated as a result of consolidating PNGTS for all the periods presented. Refer to Note 6 for additional disclosure regarding the PNGTS Acquisition.

On April 1, 2015 and October 1, 2014, the Partnership acquired the remaining 30 percent interest in GTN and Bison, respectively, from subsidiaries of TransCanada. These acquisitions resulted in GTN and Bison being wholly-owned by the Partnership. Prior to these transactions, the remaining 30 percent interests held by subsidiaries of TransCanada were reflected as non-controlling interests in the Partnership’s consolidated financial statements. The acquisitions of these already-consolidated entities were accounted as a transaction between entities under common control, similar to a pooling of interests, whereby the acquired interests were recorded at TransCanada’s carrying value and the total excess purchase price paid was recorded as a reduction in Partners’ Equity. Refer to Note 6 for additional disclosures regarding these acquisitions.

(b) 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.

(c) Cash and Cash Equivalents

The Partnership’s cash and cash equivalents consist of cash and highly liquid short-term investments with original maturities of three months or less and are recorded at cost, which approximates fair value.

(d) Trade Accounts Receivable

Trade accounts receivable are recorded at the invoiced amount and do not bear interest. We review our accounts receivable regularly and record allowances for doubtful accounts using the specific identification method.

(e) Natural gas imbalances

Natural gas imbalances occur when the actual amount of natural gas delivered to or received from a pipeline system differs from the amount of natural gas scheduled to be delivered or received. The Partnership values these imbalances due to or from shippers and interconnecting parties at current index prices. Imbalances are settled in kind, subject to the terms of the pipelines’ tariff.

Imbalances due from others are reported as  trade accounts receivable or accounts receivable from affiliates under the caption accounts receivable and other on the balance sheets. Imbalances owed to others are reported on the balance sheets as accounts payable and accrued liabilities and accounts payable to affiliates. In addition, the Partnership classifies all imbalances as current as the Partnership expects to settle them within a year.

(f) Inventories

Inventories primarily consist of materials and supplies and are carried at the lower of weighted average cost or market.

(g) Plant, Property and Equipment

Plant, property and equipment are stated at original cost. Costs of restoring the land above and around the pipeline are capitalized to pipeline facilities and depreciated over the remaining life of the related pipeline facilities. Pipeline facilities and compression equipment have an estimated useful life of 20 to 77 years and metering and other equipment ranges from 5 to 77 years. Depreciation is calculated on a straight-line composite basis over the assets’ estimated useful lives. Repair and maintenance costs are expensed as incurred. Costs that are considered a betterment are capitalized.

The Partnership’s subsidiaries capitalize a carrying cost on funds invested in the construction of long lived assets. This carrying cost includes a return on the investment financed by debt and equity allowance for funds used during construction (AFUDC), calculated based the average cost of debt and equity. Capitalized carrying costs for AFUDC debt and equity are reflected as an increase in the cost of plant, property and equipment on the balance sheets. Amounts included in construction work in progress are not amortized until transferred into service.

(h) Impairment of Equity Method Investments

We review our equity method investments when a significant event or change in circumstances has occurred that may have an adverse effect on the fair value of each investment. When such events or changes occur, we compare the estimated fair value to the carrying value of the related investment. We calculate the estimated fair value of an investment in an equity method investee using an income approach and market approach. The development of fair value estimates requires significant judgment including estimates of future cash flows, which is dependent on internal forecasts, estimates of the long-term rate of growth for the investee, estimates of the useful life over which cash flows will occur, and determination of weighted average cost of capital. The estimates used to calculate the fair value of an investee can change from year to year based on operating results and market conditions. Changes in these estimates and assumptions could materially affect the determination of fair value and our assessment as to whether an investment in an equity method investee has suffered an impairment.

If the estimated fair value of an investment is less than its carrying value, we are required to determine if the decline in fair value is other than temporary. This determination considers the aforementioned valuation methodologies, the length of time and the extent to which fair value has been less than carrying value, the financial condition and near-term prospects of the investee, including any specific events which may influence the operations of the investee, the intent and ability of the holder to retain its investment in the investee for a period of time sufficient to allow for any anticipated recovery in market value, and other facts and circumstances. If the fair value of an investment is less than its carrying value and the decline in value is determined to be other than temporary, we record an impairment charge.

(i) Impairment of Long-lived Assets

The Partnership reviews long-lived assets, such as plant, property and equipment for impairment whenever events or changes in circumstances indicate the carrying value may not be recoverable. If the total of the estimated undiscounted future cash flows is less than the carrying value of the assets, an impairment loss is recognized for the excess of the carrying value over the fair value of the assets.

(j) Partners’ Equity

Costs incurred in connection with the issuance of units are deducted from the proceeds received.

(k) Revenue Recognition

Transmission revenues are recognized in the period in which the service is provided. When a rate case is pending final FERC approval, a portion of the revenue collected is subject to possible refund. As of December 31, 2016, the Partnership has not recognized any transmission revenue that is subject to possible refund.

For the year ended December 31, 2014 and in January 2015, as required by FERC, PNGTS was charging customers rates applied for in its 2008 and 2010 rate cases. Due to the uncertainty in the outcome of its two outstanding rate cases, PNGTS was only recognizing revenue up to the amount of the interim FERC approved rates . The difference between these amounts was recognized as a provision (liability) for rate refund in the consolidated balance sheet. On February 19, 2015, FERC approved PNGTS’ final rates and PNGTS was required to refund the customers within sixty days of the issuance of the final rates, including interest at the quarterly average prime interest rate as prescribed by FERC. Total refunds accumulated to $114.3 million, including $8.0 million of interest, and were paid to customers on April 15, 2015.

(l) Income Taxes

Federal and certain state income taxes are the responsibility of the partners and are not reflected in these consolidated financial statements. The tax effect of the Partnership’s activities accrues to its partners. The Partnership’s taxable income or loss, which may vary substantially from the net income or loss reported in the consolidated statement of income, is includable in the federal income tax returns of each partner. The aggregate difference in the basis of the Partnership’s net assets for financial and income tax purposes cannot be readily determined because all information regarding each partner’s tax attributes related to the partnership is not available.

In instances where the Partnership is subject to state income taxes, the asset-liability method is used to account for taxes. This method requires the recognition of deferred tax assets and liabilities for future tax consequences attributable to the differences between the financial statement carrying amount of existing assets and liabilities and their respective tax bases.

Balance Sheet Classification of Deferred Taxes

In November 2015, the FASB issued new guidance which requires that deferred tax assets and liabilities be classified as non-current on the balance sheet. The new guidance is effective January 1, 2017, however, since early application is permitted, the Partnership elected to retrospectively apply this guidance effective January 1, 2015. Application of this new guidance will simplify the Partnership’s process in determining deferred tax amounts and simplify their presentation. The application of this guidance did not have a material impact on the Partnership’s consolidated financial statements.

(m) Acquisitions and Goodwill

The Partnership accounts for business acquisitions from third parties using the acquisition method of accounting and, accordingly, the assets and liabilities of the acquired entities are recorded at their estimated fair values at the date of acquisition. The excess of the purchase price over the fair value of net assets acquired is attributed to goodwill. Goodwill is not amortized and is tested on an annual basis for impairment or more frequently if any indicators of impairment are evident. The Partnership initially assesses qualitative factors to determine whether events or changes in circumstances indicate that the goodwill might be impaired. If the Partnership does not conclude that it is more likely than not that fair value of the reporting unit is greater than its carrying value, the first step of the two-step impairment test is performed by comparing the fair value of the reporting unit to its book value, which includes goodwill. If the fair value is less than book value, an impairment is indicated and a second step is performed to measure the amount of the impairment. In the second step, the implied fair value of goodwill is calculated by deducting the recognized amounts of all tangible and intangible net assets of the reporting unit from the fair value determined in the initial assessment. If the carrying value of goodwill exceeds the calculated implied fair value of goodwill, an impairment charge is recorded.

At December 31, 2016 and 2015, we had $130 million of goodwill recorded on our consolidated balance sheet related to the North Baja ($48 million) and Tuscarora ($82 million) acquisitions. No impairment of goodwill existed at December 31, 2016 (Refer also to Note 20).

The Partnership accounts for business acquisitions between itself and TransCanada, also known as “dropdowns”, as transactions between entities under common control.  Using this approach, the assets and liabilities of the acquired entities are recorded at TransCanada’s carrying value. In the event recasting is required, the Partnership’s historical financial information will be recast, except net income (loss) per common unit, to include the acquired entities for all periods presented. If the fair market value paid for the acquired entities is greater than the recorded net assets of the acquired entities, the excess purchase price paid is recorded as a reduction in Partners’ Equity. Similarly, if the fair market value paid for the acquired entities is less than the recorded net assets of the acquired entities, the excess of assets acquired is recorded as an increase in Partners’ Equity.

(n) Fair Value Measurements

For cash and cash equivalents, receivables, accounts payable, certain accrued expenses and short-term debt, the carrying amount approximates fair value due to the short maturities of these instruments. For long-term debt instruments and the interest rate swap agreements, fair value is estimated based upon market values (if applicable) or on the current interest rates available to us for debt with similar terms and remaining maturities. Considerable judgment is required in developing these estimates.

(o) Derivative Financial Instruments and Hedging Activities

The Partnership recognizes all derivative instruments as either assets or liabilities in the balance sheet at their respective fair values. For derivatives designated in hedging relationships, changes in the fair value are either offset through earnings against the change in fair value of the hedged item attributable to the risk being hedged or recognized in accumulated other comprehensive income, to the extent the derivative is effective at offsetting the changes in cash flows being hedged until the hedged item affects earnings.

The Partnership only enters into derivative contracts that it intends to designate as a hedge of a forecasted transaction or the variability of cash flows to be received or paid related to a recognized asset or liability (cash flow hedge). For all hedging relationships, the Partnership formally documents the hedging relationship and its risk management objective and strategy for undertaking the hedge, the hedging instrument, the hedged transaction, the nature of the risk being hedged, how the hedging instrument’s effectiveness in offsetting the hedged risk will be assessed prospectively and retrospectively, and a description of the method used to measure ineffectiveness. The Partnership also formally assesses, both at the inception of the hedging relationship and on an ongoing basis, whether the derivatives that are used in hedging relationships are highly effective in offsetting changes in cash flows of hedged transactions. For derivative instruments that are designated and qualify as part of a cash flow hedging relationship, the effective portion of the gain or loss on the derivative is reported as a component of other comprehensive income and reclassified into earnings in the same period or periods during which the hedged transaction affects earnings. Gains and losses on the derivative representing either hedge ineffectiveness or hedge components excluded from the assessment of effectiveness are recognized in current earnings.

The Partnership discontinues hedge accounting prospectively when it determines that the derivative is no longer effective in offsetting cash flows attributable to the hedged risk, the derivative expires or is sold, terminated, or exercised, the cash flow hedge is de-designated because a forecasted transaction is not probable of occurring, or management determines to remove the designation of the cash flow hedge.

In all situations in which hedge accounting is discontinued and the derivative remains outstanding, the Partnership continues to carry the derivative at its fair value on the balance sheet and recognizes any subsequent changes in its fair value in earnings. When it is probable that a forecasted transaction will not occur, the Partnership discontinues hedge accounting and recognizes immediately in earnings gains and losses that were accumulated in other comprehensive income related to the hedging relationship.

(p) Asset Retirement Obligation

The Partnership recognizes the fair value of a liability for asset retirement obligations in the period in which it is incurred, when a legal obligation exists and a reasonable estimate of fair value can be made. The fair value is added to the carrying amount of the associated asset and the liability is accreted through charges to operating expenses.

The Partnership has determined it has legal obligations associated with its natural gas pipelines and related transmission facilities. The obligations relate primarily to purging and sealing the pipelines if they are abandoned. The Partnership is also required to operate and maintain its natural gas pipeline system, and intends to do so as long as supply and demand for natural gas exists, which the Partnership expects for the foreseeable future. Therefore, the Partnership believes its natural gas pipeline system assets have indeterminate lives and, accordingly, has recorded no asset retirement obligation as of December 31, 2016 and 2015.

(q) Government Regulation

The Partnership’s subsidiaries are subject to regulation by FERC. Under regulatory accounting principles, certain assets or liabilities that result from the regulated ratemaking process may be recorded that would not be recorded under GAAP for non-regulated entities. The timing of recognition of certain revenues and expenses in our regulated business may differ from that otherwise expected under GAAP to appropriately reflect the economic impact of the regulators’ decisions regarding revenues and rates. The Partnership regularly evaluates the continued applicability of regulatory accounting, considering such factors as regulatory changes, the impact of competition, and the ability to recover regulatory assets. At December 31, 2016, the Partnership had regulatory assets amounting to $1 million reported as part of other current assets  in the balance sheet representing volumetric fuel tracker assets that are settled with in-kind exchanges with customers continually (2015 — $2 million). Regulatory liabilities are included in other long-term liabilities (refer to Note 8). AFUDC is capitalized and included in plant, property and equipment.

(r) Debt Issuance Costs

Costs related to the issuance of debt are deferred and amortized using the effective interest rate method over the term of the related debt. Refer also to Note 3 — Imputation of Interest for the change in accounting policy related to debt issuance costs.

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ACCOUNTING PRONOUNCEMENTS

3 Months Ended

12 Months Ended

Mar. 31, 2017

Dec. 31, 2016

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 entity (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 currently anticipates adopting the standard using the modified retrospective approach with the cumulative-effect of initially applying the guidance recognized at the date of adoption, subject to allowable and elected practical expedients.

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

Leases

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

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

Goodwill Impairment

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

NOTE 3 ACCOUNTING PRONOUNCEMENTS

Changes in Accounting Policies effective January 1, 2016

Consolidation

In February 2015, the Financial Accounting Standards Board (FASB) issued new guidance on consolidation, which requires that an entity evaluate whether it should consolidate certain legal entities. All legal entities are subject to reevaluation under the revised consolidation model. This guidance became effective beginning January 1, 2016 and was applied retrospectively to all financial statements presented. The application of this guidance did not result in any change to the Partnership’s consolidation conclusions. Refer to Note 22, Variable Interest Entities.

In October 2016, the FASB issued an updated guidance on consolidation, under which a single decision maker is not required to consider indirect interests held through related parties that are under common control with the single decision maker to be the equivalent of direct interests in their entirety. Instead, a single decision maker is required to include those interests on a proportionate basis consistent with indirect interests held through other related parties. Entities that already have adopted the amendments in February 2015 update are required to apply the amendments in this update retrospectively to all relevant prior periods beginning with the fiscal year in which the amendments were applied. The application of this guidance did not result in any change to the Partnership’s consolidation conclusions. Refer to Note 22, Variable Interest Entities.

Imputation of interest

In April 2015, the FASB issued an amendment of previously issued guidance on imputation of interest, which requires debt issuance costs be presented in the balance sheet as a direct deduction from the carrying amount of debt liabilities, consistent with debt discount or premiums. In addition, amortization of debt issuance costs should be reported as interest expense. The recognition and measurement for debt issuance costs would not be affected. This guidance is effective from January 1, 2016 and was applied retrospectively resulting in a reclassification of debt issuance costs previously recorded in other assets to an offset of their respective debt liabilities on the Partnership’s consolidated balance sheet. Amortization of debt issuance costs was reported as interest expense in all periods presented in the Partnership’s consolidated statement of income.

As a result of the application of this guidance and similar to the presentation of debt discounts, debt issuance costs of $8 million at December 31, 2015 previously reported as other assets in the balance sheet were reclassified as an offset against their respective debt liabilities.

Earnings per share

In April 2015, the FASB issued an amendment of previously issued guidance on earnings per share (EPS) as it is being calculated by master limited partnerships. This updated guidance specifies that for purposes of calculating historical EPS under the two-class method, the earnings (losses) of a transferred business before the date of a dropdown transaction should be allocated entirely to the general partner interest, and previously reported EPS of the limited partners would not change as a result of a dropdown transaction. Qualitative disclosures about how the rights to the earnings (losses) differ before and after the dropdown transaction occurs are also required. This guidance became effective on January 1, 2016 and applies to all dropdown transactions requiring recast. The retrospective application of this guidance did not have a material impact on the Partnership’s consolidated financial statements as our current accounting policy is consistent with the new guidance.

Business combinations

In September 2015, the FASB issued new guidance which replaces the requirement that an acquirer in a business combination account for measurement period adjustments retrospectively with a requirement that an acquirer recognize adjustments to the provisional amounts that are identified during the measurement period in the reporting period in which the adjustment amounts are determined. The amended guidance requires that the acquirer record, in the same period’s financial statements, the effect on earnings of changes in depreciation, amortization, or other income effects, if any, as a result of the change to the provisional amounts, calculated as if the accounting had been completed at the acquisition date. The new guidance is effective January 1, 2016 and was applied prospectively. The application of this guidance did not have a material impact on the Partnership’s consolidated financial statements.

Statement of Cash Flows

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 since early adoption is permitted, the Partnership elected to retrospectively apply this guidance effective December 31, 2016. The application of this guidance will not have a material impact on the classification of debt pre-payments or extinguishment costs, contingent consideration payments made after a business combination, proceeds from the settlement of insurance claims and proceeds from the settlement of corporate owned life insurance. 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 $25 million and $27 million in 2015 and 2014, respectively, have been reclassified from investing activities to cash generated from operations in the consolidated statement of cash flows.

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 currently anticipates adopting the standard using the modified retrospective approach with the cumulative-effect of initially applying the guidance recognized at the date of adoption, subject to allowable and elected practical expedients.

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

Leases

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

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

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. This new guidance is effective January 1, 2017 and will be applied prospectively. The Partnership does not expect the adoption of this new standard to have a material impact on its consolidated financial statements.

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EQUITY INVESTMENTS

3 Months Ended

12 Months Ended

Mar. 31, 2017

Dec. 31, 2016

EQUITY INVESTMENTS

EQUITY INVESTMENTS

NOTE 4       EQUITY INVESTMENTS

Northern Border and Great Lakes 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 (b)		Equity Investments (b)
	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
			36	33	930	918

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

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

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

NOTE 4 EQUITY INVESTMENTS

Northern Border and Great Lakes are regulated by FERC and are operated by subsidiaries of 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 3, Accounting Pronouncements and Note 22, Variable Interest Entities.

	Ownership Interest at		Equity Earnings (b)			Equity Investments
	December 31,		Year ended December 31			December 31
(millions of dollars)	2016		2016(d)	2015	2014	2016 (d)	2015
Northern Border (a)	50.00	%	69	66	69	444	480
Great Lakes	46.45	%	28	31	19	474	485	(c)
			97	97	88	918	965

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

^(b) Equity Earnings represents our share in investee’s earnings and does not include any impairment charge on the equity method investment recorded as a reduction of carrying value of these investments. Accordingly, no impairment charge was recorded by the Partnership on its equity investees for all the periods presented here except the impairment recognized in 2015 on our investment in Great Lakes as discussed below.

^(c) During the fourth quarter of 2015, we recognized an impairment charge on our investment in Great Lakes amounting to $199 million. See discussion below.

^(d) Recast to eliminate equity earnings from PNGTS and consolidate PNGTS for all periods presented  (Refer to Note 2).

Northern Border

The Partnership, through its interest in TC PipeLines Intermediate Limited Partnership owns a 50 percent general partner interest in Northern Border. The other 50 percent partnership interest in Northern Border is held by ONEOK Partners, L.P., a publicly traded limited partnership.TC PipeLines Intermediate Limited Partnership, as one of the general partners, may be exposed to the commitments and contingencies of Northern Border. The Partnership holds a 98.9899 percent limited partnership interest in TC PipeLines Intermediate Limited Partnership.

Northern Border has a FERC-approved settlement agreement which established maximum long-term transportation rates and charges on the Northern Border system effective January 1, 2013. Northern Border is required to file for new rates no later than January 1, 2018.

The Partnership recorded no undistributed earnings from Northern Border for the years ended December 31, 2016, 2015 and 2014. At December 31, 2016 and 2015, the Partnership had a $116 million difference between the carrying value of Northern Border and the underlying equity in the net assets primarily resulting from the recognition and inclusion of goodwill in the Partnership’s investment in Northern Border relating to the Partnership’s April 2006 acquisition of an additional 20 percent general partnership interest in Northern Border. As of December 31, 2016, no impairment has been identified in our investment in Northern Border.

The summarized financial information for Northern Border is as follows:

December 31 (millions of dollars)	2016		2015
Assets
Cash and cash equivalents	14		27
Other current assets	36		33
Plant, property and equipment, net	1,089		1,124
Other assets (a)	14		16
	1,153		1,200
Liabilities and Partners’ Equity
Current liabilities	38		39
Deferred credits and other	28		26
Long-term debt, net (a), (b)	430		409
Partners’ equity
Partners’ capital	659		728
Accumulated other comprehensive loss	(2	)	(2	)
	1,153		1,200

^(a) As a result of the application of ASU No. 2015-03 and similar to the presentation of debt discounts, debt issuance costs of $2 million at December 31, 2015 previously reported as other assets in the balance sheet were reclassified as an offset against their respective debt liabilities.

^(b) Includes current maturities of $100 million senior notes at December 31, 2015. During August 2016, the $100 million senior notes were refinanced with a draw on Northern Border’s $200 million revolving credit agreement that expires in 2020.

Year ended December 31 (millions of dollars)	2016		2015		2014
Transmission revenues	292		286		293
Operating expenses	(72	)	(70	)	(72	)
Depreciation	(59	)	(60	)	(59	)
Financial charges and other	(21	)	(22	)	(22	)
Net income	140		134		140

Great Lakes

The Partnership, through its interest in TC GL Intermediate Limited Partnership owns a 46.45 percent general partner interest in Great Lakes. TransCanada owns the other 53.55 percent partnership interest. TC GL Intermediate Limited Partnership, as one of the general partners, may be exposed to the commitments and contingencies of Great Lakes. The Partnership holds a 98.9899 percent limited partnership interest in TC GL Intermediate Limited Partnership.

Great Lakes operates under rates established pursuant to a settlement approved by FERC in November 2013. Under the settlement, Great Lakes is required to file for new rates to be effective no later than January 1, 2018.

The Partnership recorded no undistributed earnings from Great Lakes for the years ended December 31, 2016, 2015, and 2014.

The Partnership made equity contributions to Great Lakes of $4 million and $5 million in the first and fourth quarter of 2016, respectively. These amounts represent the Partnership’s 46.45 percent share of a $9 million and $10 million cash call from Great Lakes to make scheduled debt repayments.

During the fourth quarter of 2015, we determined that our investment in Great Lakes’ long-term value had been adversely impacted by the changing natural gas flows in its market region. Additionally, we have concluded that other strategic alternatives to increase its utilization or revenue were no longer feasible. As a result, we determined that the carrying value of our investment in Great Lakes was in excess of its fair value and the decline was not temporary. Accordingly, we concluded that the carrying value of our investment in Great Lakes was impaired.

Our analysis resulted in an impairment charge of $199 million reflected as Impairment of equity-method investment on our Statement of Income for the year ended December 31, 2015.  The impairment charge reduced the difference between the carrying value of our investment in Great Lakes and the underlying equity in the net assets, to $260 million and  the difference represented the equity method goodwill remaining in our investment in Great Lakes relating to the Partnership’s February 2007 acquisition of a 46.45 percent general partner interest in Great Lakes.

The assumptions we used in 2015 related to the estimated fair value of our remaining equity investment in Great Lakes could be negatively impacted by near and long-term conditions including:

· future regulatory rate action or settlement,

· valuation of Great lakes in future transactions,

· changes in customer demand at Great Lakes for pipeline capacity and services,

· changes in North American natural gas production in the major producing basins,

· changes in natural gas prices and natural gas storage market conditions, and

· changes in other long-term strategic objectives.

Great Lakes’ evolving market conditions and other factors relevant to Great Lakes’ long term financial performance have remained relatively stable during the year ended 2016 and into 2017.  Accordingly, our estimation of the fair value of our investment in Great Lakes has not materially changed from 2015.  There is a risk that reductions in future cash flow forecasts and other adverse changes in these key assumptions could result in additional future impairment of the carrying value of our investment in Great Lakes.

The summarized financial information for Great Lakes is as follows:

December 31 (millions of dollars)	2016	2015
Assets
Current assets	66	86
Plant, property and equipment, net	714	727
	780	813
Liabilities and Partners’ Equity
Current liabilities	40	31
Long-term debt, net (a),(b)	278	297
Partners’ equity	462	485
	780	813

^(a) The application of ASU No. 2015-03 did not have a material effect on Great Lakes’ financial statements.

^(b) Includes current maturities of $19 million as of December 31, 2016 (December 31, 2015 - $19 million).

Year ended December 31 (millions of dollars)	2016		2015		2014
Transmission revenues	179		177		146
Operating expenses	(69	)	(59	)	(53	)
Depreciation	(28	)	(28	)	(28	)
Financial charges and other	(21	)	(23	)	(25	)
Net income	61		67		40

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PLANT, PROPERTY AND EQUIPMENT

12 Months Ended

Dec. 31, 2016

PLANT, PROPERTY AND EQUIPMENT

PLANT, PROPERTY AND EQUIPMENT

NOTE 5 PLANT, PROPERTY AND EQUIPMENT

The following table includes plant, property and equipment of our consolidated entities:

	2016 (a)				2015 (a)
December 31 (millions of dollars)	Cost	Accumulated Depreciation		Net Book Value	Cost	Accumulated Depreciation		Net Book Value
Pipeline	2,540	(879	)	1,661	2,535	(806	)	1,729
Compression	519	(148	)	371	516	(134	)	382
Metering and other	205	(61	)	144	201	(57	)	144
Construction in progress	4	—		4	2	—		2
	3,268	(1,088	)	2,180	3,254	(997	)	2,257

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

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ACQUISITIONS

12 Months Ended

Dec. 31, 2016

ACQUISITIONS

ACQUISITIONS

NOTE 6 ACQUISITIONS

2016 PNGTS Acquisition

On January 1, 2016, the Partnership acquired a 49.9 percent interest in PNGTS from a subsidiary of TransCanada. The total purchase price of the PNGTS Acquisition was $228 million and consisted of $193 million in cash (including the final purchase price adjustment of $5 million) and the assumption of $35 million in proportional PNGTS debt.

The Partnership funded the cash portion of the transaction using proceeds received in 2015 from our ATM Program and additional borrowings under our Senior Credit Facility. The purchase agreement provides for additional payments to TransCanada ranging from $5 million up to a total of $50 million if pipeline capacity is expanded to various thresholds during the fifteen year period following the date of closing.

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

The net purchase price was allocated as follows:

(millions of dollars)
Net Purchase Price (a)	193
Less: TransCanada’s carrying value of PNGTS’ net assets at January 1, 2016	120
Excess purchase price (b)	73

^(a) Total purchase price of $228 million less the assumption of $35 million of proportional PNGTS debt by the Partnership.

^(b) The excess purchase price of $73 million was recorded as a reduction in Partners’ Equity.

2015 GTN Acquisition

On April 1, 2015, the Partnership acquired the remaining 30 percent interest in GTN from a subsidiary of TransCanada (2015 GTN Acquisition), which resulted in GTN being wholly-owned by the Partnership. The total purchase price of the 2015 GTN Acquisition was $446 million plus the final purchase price adjustment of $11 million, for a total of $457 million. The purchase price consisted of $264 million in cash (including the final purchase price adjustment of $11 million), the assumption of $98 million in proportional GTN debt and the issuance of 1,900,000 new Class B units to TransCanada valued at $50 each, representing a limited partner interest in the Partnership with a total value of $95 million.

The Partnership funded the cash portion of the transaction using a portion of the proceeds received on our March 13, 2015 debt offering (refer to Note 7). The Class B units entitle TransCanada to a 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. Under the terms of the Third Amended and Restated Agreement of Limited Partnership of the Partnership (Partnership Agreement), the Class B distribution was initially calculated to equal 30 percent of GTN’s distributable cash flow for the nine months ended December 31, 2015, less $15 million.

Prior to this transaction, the remaining 30 percent interest held by a subsidiary of TransCanada was reflected as a non-controlling interest in the Partnership’s consolidated financial statements. The 2015 GTN Acquisition of this already-consolidated entity was accounted as a transaction between entities under common control, similar to a pooling of interests, whereby the acquired interest was recorded at TransCanada’s carrying value and the total excess purchase price paid was recorded as a reduction in Partners’ Equity.

The net purchase price was allocated as follows:

(millions of dollars)
Net Purchase Price (a)	359
Less: TransCanada’s carrying value of non-controlling interest at April 1, 2015	232
Excess purchase price (b)	127

^(a) Total purchase price of $457 million less the assumption of $98 million of proportional GTN debt by the Partnership.

^(b) The excess purchase price of $127 million was recorded as a reduction in Partners’ Equity.

Our General Partner also contributed approximately $2 million to maintain its effective two percent interest in the Partnership.

2014 Bison Acquisition

On October 1, 2014, the Partnership acquired the remaining 30 percent interest in Bison from a subsidiary of TransCanada. The total purchase price of the 2014 Bison Acquisition was $215 million plus purchase price adjustments of $2 million. The acquisition of Bison was financed through combinations of (i) net proceeds from the ATM Program (refer to Note 9), and (ii) short-term financing.

Prior to this transaction, the remaining 30 percent interest held by a subsidiary of TransCanada was reflected as non-controlling interest in the Partnership’s consolidated financial statements. The 2014 Bison Acquisition of this already-consolidated entity was accounted as a transaction between entities under common control, similar to a pooling of interests, whereby the acquired interest was recorded at TransCanada’s carrying value and the total excess purchase price paid was recorded as a reduction in Partners’ Equity.

The purchase price was allocated as follows:

(millions of dollars)
Total cash consideration	217
TransCanada’s carrying value of non-controlling interest at October 1, 2014	188
Excess purchase price	29

The excess purchase price of $29 million was recorded as a reduction in Partners’ Equity.

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DEBT AND CREDIT FACILITIES

3 Months Ended

12 Months Ended

Mar. 31, 2017

Dec. 31, 2016

DEBT AND CREDIT FACILITIES

DEBT AND CREDIT FACILITIES

NOTE 5       DEBT AND CREDIT FACILITIES

(unaudited) (millions of dollars)	March 31, 2017(b)	Weighted Average Interest Rate for the Quarter Ended March 31, 2017 (b)		December 31, 2016(b)		Weighted Average Interest Rate for the Year Ended December 31, 2016(b)
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	%
PNGTS
5.90% Senior Secured Notes due December 2018	41	5.90	%(a)	53		5.90	%(a)
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)
	1,858			1,920
Less: unamortized debt issuance costs and debt discount	8			9
Less: current portion	46			52	(c)
	1,804			1,859

^(a) Fixed interest rate

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

^(c) Includes the PNGTS portion due at December 31, 2016 amounting to $5.5 million that was paid on January 3, 2017

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

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).

PNGTS

PNGTS’ Senior Secured Notes are secured by the PNGTS long-term firm shipper contracts and its partners’ pledge of their equity and a guarantee of debt service for six months. PNGTS is restricted under the terms of its note purchase agreement from making cash distributions unless certain conditions are met. Before a distribution can be made, the debt service reserve account must be fully funded and PNGTS’ debt service coverage ratio for the preceding and succeeding twelve months must be 1.30 or greater. At March 31, 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 to make any cash distributions.

Tuscarora

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	40	(a)
2018	715	(a)
2019	43
2020	100
2021	460
Thereafter	500
	1,858	(a)

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

NOTE 7 DEBT AND CREDIT FACILITIES

(millions of dollars)	December 31, 2016 (c)		Weighted Average Interest Rate for the Year Ended December 31, 2016 (c)		December 31, 2015 (c)	Weighted Average Interest Rate for the Year Ended December 31, 2015 (c)
TC PipeLines, LP
Senior Credit Facility due 2021	160		1.72	%	200	1.44	%
2013 Term Loan Facility due 2018	500		1.73	%	500	1.44	%
2015 Term Loan Facility due 2018	170		1.63	%	170	1.47	%
4.65% Unsecured Senior Notes due 2021	350		4.65	%(b)	350	4.65	%(b)
4.375% Unsecured Senior Notes due 2025	350		4.375	%(b)	350	4.375	%(b)
GTN
5.29% Unsecured Senior Notes due 2020	100		5.29	%(b)	100	5.29	%(b)
5.69% Unsecured Senior Notes due 2035	150		5.69	%(b)	150	5.69	%(b)
Unsecured Term Loan Facility due 2019	65		1.43	%	75	1.15	%
PNGTS
5.90% Senior Secured Notes due December 2018	53		5.90	%(b)	69	5.90	%(b)
Tuscarora
Unsecured Term Loan due 2019	10		1.64	%	—	—
3.82% Series D Senior Notes due 2017	12		3.82	%(b)	16	3.82	%(b)
	1,920				1,980
Less: unamortized debt issuance costs and debt discount (a)	9				9
Less: current portion	52	(d)			36
	1,859				1,935

^(a) As a result of the application of ASU No. 2015-03 and similar to the presentation of debt discounts, debt issuance costs of $8 million at December 31, 2015 previously reported as other assets in the balance sheet were reclassified as an offset against debt. Refer to Note 3, Accounting Pronouncements.

^(b) Fixed interest rate.

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

^(d) Includes the PNGTS portion due at December 31, 2016 amounting to $5.5 million that was paid on January 3, 2017 (Refer to Note 24-Subsequent Events).

TC PipeLines, LP

On November 10, 2016, the Partnership’s Senior Credit Facility was amended to extend the maturity period through November 10, 2021. The Facility consists of a $500 million senior revolving credit facility with a banking syndicate, under which $160 million was outstanding at December 31, 2016 (December 31, 2015 - $200 million), leaving $340 million available for future borrowing.

At the Partnership’s option, the interest rate on the outstanding borrowings under the Senior Credit Facility may be lenders’ base rate or the London Interbank Offered Rate (LIBOR) plus, in either case, an applicable margin that is based on the Partnership’s long-term unsecured credit ratings. The Senior Credit Facility permits the Partnership to specify the portion of the borrowings to be covered by specific interest rate options and, for LIBOR-based borrowings, to specify the interest rate period. The Partnership is required to pay a commitment fee based on its credit rating and on the unused principal amount of the commitments under the Senior Credit Facility. The Senior Credit Facility has a feature whereby at any time, so long as no event of default has occurred and is continuing, the Partnership may request an increase in the Senior Credit Facility of up to $500 million, but no lender has an obligation to increase their respective share of the facility.

The LIBOR-based interest rate on the Senior Credit Facility was 1.92 percent at December 31, 2016 (December 31, 2015 - 1.50 percent).

On July 1, 2013, the Partnership entered into a term loan agreement with a syndicate of lenders for a $500 million term loan credit facility (2013 Term Loan Facility). On July 2, 2013, the Partnership borrowed $500 million under the 2013 Term Loan Facility, to pay a portion of the purchase price of the 2013 Acquisition, maturing on July 1, 2018. The 2013 Term Loan Facility bears interest based, at the Partnership’s election, on the LIBOR or the base rate plus, in either case, an applicable margin. The base rate equals the highest of (i) SunTrust Bank’s prime rate, (ii) 0.50 percent above the federal funds rate and (iii) 1.00 percent above one-month LIBOR. The applicable margin for the term loan is based on the Partnership’s senior debt rating and ranges between 1.125 percent and 2.000 percent for LIBOR borrowings and 0.125 percent and 1.000 percent for base rate borrowings.

As of December 31, 2016, 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 (2015-2.79 percent) . Prior to hedging activities, the LIBOR-based interest rate was 1.87 percent at December 31, 2016 (December 31, 2015 — 1.50 percent).

On September 30, 2015, the Partnership entered into an agreement for a $170 million term loan credit facility (2015 Term Loan Facility). The Partnership borrowed $170 million under the 2015 Term Loan Facility to refinance its Short-Term Loan Facility which matured on September 30, 2015.  The 2015 Term Loan Facility matures on October 1, 2018. The LIBOR-based interest rate on the 2015 Term Loan Facility was 1.77 percent at December 31, 2016 (December 31, 2015 — 1.39 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 4.01 to 1.00 as of December 31, 2016.

The Senior Credit Facility and the Term Loan Facilities contain additional covenants that include restrictions on entering into mergers, consolidations and sales of assets, granting liens, material amendments to the Partnership Agreement, incurrence of additional debt by the Partnership’s subsidiaries and distributions to unitholders. Upon any breach of these covenants, amounts outstanding under the Senior Credit Facility and the Term Loan Facilities may become immediately due and payable.

On March 13, 2015, the Partnership closed a $350 million public offering of senior unsecured notes bearing an interest rate of 4.375 percent maturing March 13, 2025. The net proceeds of $346 million were used to fund a portion of the 2015 GTN Acquisition (refer to Note 6) and to reduce the amount outstanding under our Senior Credit Facility. The indenture for the notes contains customary investment grade covenants.

PNGTS

PNGTS’ Senior Secured Notes are secured by the PNGTS long-term firm shipper contracts and its partners’ pledge of their equity and a guarantee of debt service for six months. PNGTS is restricted under the terms of its note purchase agreement from making cash distributions unless certain conditions are met. Before a distribution can be made, the debt service reserve account must be fully funded and PNGTS’ debt service coverage ratio for the preceding and succeeding twelve months must be 1.30 or greater. At December 31, 2016, the debt service coverage ratio was 2.41 for the twelve preceding months and 1.43 for the twelve succeeding months. Therefore, PNGTS was not restricted to make any cash distributions.

GTN

On June 1, 2015, GTN’s 5.09 percent unsecured Senior Notes matured. Also, on June 1, 2015, GTN entered into a $75 million unsecured variable rate term loan facility (Unsecured Term Loan Facility), which requires yearly principal payments until its maturity on June 1, 2019. The variable interest is based on LIBOR plus an applicable margin. The LIBOR-based interest rate on the Unsecured Term Loan Facility was 1.57 percent at December 31, 2016 (December 31, 2015 — 1.19 percent). GTN’s Unsecured Senior Notes, along with this new 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 December 31, 2016 is 44.5 percent.

Tuscarora

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 December 31, 2016 was 21.22 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 4.15 to 1.00 as of December 31, 2016.

On  April  29,  2016,  Tuscarora  entered  into  a $9.5  million  unsecured  variable  rate  term  loan  facility which requires  yearly principal  payments  until  its  maturity  on  April  29,  2019.  The variable interest is based on LIBOR plus an applicable margin and was 1.90 percent at December 31, 2016.

At December 31, 2016, 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 Partnership Agreement, incurring additional debt and distributions to unitholders.

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

(millions of dollars)
2017	52	(a)
2018	715	(a)
2019	43
2020	100
2021	510
Thereafter	500
	1,920	(a)

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

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OTHER LIABILITIES

12 Months Ended

Dec. 31, 2016

OTHER LIABILITIES

OTHER LIABILITIES

NOTE 8 OTHER LIABILITIES

December 31 (millions of dollars)	2016	2015
Regulatory liabilities	25	24
Other liabilities	3	3
	28	27

The Partnership collects estimated future removal costs related to its transmission and gathering facilities in its current rates and recognizes regulatory liabilities in this respect in the balance sheet. Estimated costs associated with the future removal of transmission and gathering facilities are collected through depreciation as allowed by FERC. These amounts do not represent asset retirement obligations as defined by FASB ASC 410, Accounting for Asset Retirement Obligations.

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PARTNERS' EQUITY

3 Months Ended

12 Months Ended

Mar. 31, 2017

Dec. 31, 2016

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. The Securities Act generally requires that any claim brought for a violation of Section 5 of the Securities Act be brought within one year of violation.

At December 31, 2016, $83 million was recorded as Common units subject to rescission on the consolidated balance sheet.  The Partnership classified 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.

No unitholder claimed or attempted to exercise any rescission rights prior to their expiry dates and the final rights related to the sales of such units expired on May 19, 2017. Therefore all the common units subject to rescission on the consolidated balance sheet were reclassified back to equity on our consolidated balance sheet at June 30, 2017 as filed on our Second Quarterly report on Form 10Q dated August 3, 2017.

NOTE 9 PARTNERS’ EQUITY

At December 31, 2016, the Partnership had 67,454,831common units outstanding, of which 50,370,000 were held by non-affiliates and 17,084,831 common units were held by subsidiaries of TransCanada, including 5,797,106 common units held by our General Partner. Additionally, TransCanada, through our General Partner, owns 100 percent of our IDRs and an effective two percent general partner interest in the Partnership. TransCanada also holds 100 percent of our 1,900,000 outstanding Class B units.

ATM Equity Issuance Program (ATM Program)

In August 2014, the Partnership launched its $200 million ATM program pursuant to which, the Partnership may from time to time, offer and sell, through sales agents, common units, representing limited partner interests.

On August 5, 2016, the Partnership entered into a new $400 million Equity Distribution Agreement (EDA) with five financial institutions (the Managers). Sales of the common units will be issued pursuant to the Partnership’s shelf registration statement on Form S-3 (Registration No. 333-211907), which was declared effective by the SEC on August 4, 2016.

In 2016, the Partnership issued 3.1 million common units under the ATM Program generating net proceeds of approximately $164 million, plus an additional $3 million from  the General Partner’s to maintain its effective two percent interest. The commissions to our sales agents were approximately $2 million.  The net proceeds were used to repay a portion of the borrowings under the Senior Credit Facility for the 2016 PNGTS Acquisition and for general partnership purposes. The 3.1 million common units issued include the 1.6 million common units subject to rescission as discussed below.

In 2015, the Partnership issued 0.7 million common units under the ATM Program generating net proceeds of approximately $43 million, plus an additional $1 million from  the General Partner’s to maintain its effective two percent interest. The commissions to our sales agents were approximately $0.4 million.  The net proceeds were used for general partnership purposes.

In 2014, the Partnership issued 1.3 million common units under the ATM Program generating net proceeds of approximately $71 million, plus an additional $2 million from  the General Partner’s to maintain its effective two percent interest. The commissions to our sales agents were approximately $1 million.  The net proceeds were used to finance the 2014 Bison Acquisition (refer to Note 6).

Common unit issuance subject to rescission

On July 17, 2014, the SEC declared effective a registration statement (the Registration Statement) that we had filed to cover sales of Common Units under our ATM program. On February 26, 2016, at the time of the filing of the 2015 Form 10-K, we believed that the Partnership continued to be eligible to use the effective Registration Statement to sell Common Units under our ATM program.  However, we were advised by the SEC on June 23, 2016 that as a result of the untimely filing of an employee-related Form 8-K on October 28, 2015, which was not filed via EDGAR until 6:02 p.m. Eastern Time (32 minutes after the 5:30 p.m. Eastern Time cutoff), the Partnership was ineligible to use the Registration Statement after the filing of the 2015 Form 10-K.

Because the Partnership was ineligible to continue using the Registration Statement following the filing of the 2015 Form 10-K, it is possible that the sales of an aggregate 1,619,631 Common Units under the Registration Statement (the ATM Common Units), which were sold between March 8, 2016 and May 19, 2016 at per Common Unit prices ranging from $47.00 to $54.95, may be deemed to have been unregistered sales of securities.  If it is determined that persons who purchased the ATM Common Units from the Partnership after February 26, 2016, purchased such Common Units in an offering deemed to be unregistered, then to the extent there may have been a violation of federal securities laws such persons may be entitled to rescission rights, pursuant to which they could be entitled to recover the amount paid for such ATM Common Units, plus interest (based on the statutory rate under applicable state law), less the amount of any distributions.  If such investor has sold any of the ATM Common Units purchased by the investor, then the investor would be entitled to recover the difference between the amount paid for such ATM Common Units and the amount at which such ATM Common Units were sold, assuming the investor’s ATM Common Units were sold at a loss, plus interest and less the amount of any distributions. If all of the investors who purchased the ATM Common Units from the Partnership after February 26, 2016 continue to own all of the ATM Common Units and were to demand rescission of their purchases, and such investors were in fact found to be entitled to such rescission, then we would be obligated to repay approximately $82,334,015, plus interest, less the amount of any distributions.  The Securities Act generally requires that any claim brought for a violation of Section 5 of the Securities Act be brought within one year of the violation.

At December 31, 2016, the Partnership classified all the 1.6 million common units issued under its ATM program after February 26, 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 were treated as outstanding for financial reporting purposes.

The total amount transferred  outside of equity was approximately $83 million which includes interest, less distributions paid, and includes our General Partner’s share to maintain its effective two percent interest.

No unitholder claimed or attempted to exercise any rescission rights prior to the expiry dates of such rights and the final rights related to the sales of such units expired on May 19, 2017. Therefore, all the common units subject to rescission on the consolidated balance sheet were reclassified back to equity on our consolidated balance sheet at June 30, 2017 as filed on our Second Quarterly report on Form 10Q dated August 3, 2017.

Issuance of Class B units

On April 1, 2015, we issued Class B units to TransCanada to finance a portion of the 2015 GTN Acquisition. The Class B units entitle TransCanada to an annual distribution which is an amount based on 30 percent of cash distributions from GTN exceeding certain annual thresholds (refer to Note 6). The Class B units contain no mandatory or optional redemption features and are also non-convertible, non-exchangeable, non-voting and rank equally with common units upon liquidation.

The Class B units’ equity account is increased by the excess of 30 percent of GTN’s distributions over the annual threshold until such amount is declared for distribution and paid every first quarter of the subsequent year.

For the year ended December 31, 2016 and 2015, the Class B units’ equity account was increased by $22 million and $12 million, respectively. These amounts equal 30 percent of GTN’s total distributable cash flow above the $20 million threshold in 2016 and $15 million in 2015 (refer to Notes 12 and 13).

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ACCUMULATED OTHER COMPREHENSIVE LOSS

12 Months Ended

Dec. 31, 2016

ACCUMULATED OTHER COMPREHENSIVE LOSS

ACCUMULATED OTHER COMPREHENSIVE LOSS

NOTE 10 ACCUMULATED OTHER COMPREHENSIVE LOSS

The changes in accumulated other comprehensive loss (AOCL) by component are as follows:

	Cash flow hedges (a)
	(millions of dollars)
Balance at December 31, 2013	(5	)
Change in fair value of cash flow hedges	(1	)
Amounts reclassified from AOCL	—
PNGTS’ amortization of realized loss on derivative instrument (Note 18)	1
Net other comprehensive income (loss)	—
Balance at December 31, 2014	(5	)
Change in fair value of cash flow hedges	—
Amounts reclassified from AOCL	—
PNGTS’ amortization of realized loss on derivative instrument (Note 18)	1
Net other comprehensive income	1
Balance at December 31, 2015	(4	)
Change in fair value of cash flow hedges	3
Amounts reclassified from AOCL	(2	)
PNGTS’ amortization of realized loss on derivative instrument (Note 18)	1
Net other comprehensive income	2
Balance as of December 31, 2016	(2	)

^(a) Recast  to consolidate PNGTS for all periods presented (Refer to in Note 2). Additionally, AOCL as presented here is net of non-controlling interest on PNGTS.

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FINANCIAL CHARGES AND OTHER

3 Months Ended

12 Months Ended

Mar. 31, 2017

Dec. 31, 2016

FINANCIAL CHARGES AND OTHER

FINANCIAL CHARGES AND OTHER

NOTE 13       FINANCIAL CHARGES AND OTHER

	Three months ended
(unaudited)	March 31,
(millions of dollars)	2017 (c )	2016 (c )
Interest Expense (a)	17	18
PNGTS’ amortization of derivative loss on derivative instruments (Note 11) (b)	—	—
Net realized loss related to the interest rate swaps (b)	—	—
Other Income (b)	—	—
	17	18

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

(b)      Nil million for both periods.

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

NOTE 11 FINANCIAL CHARGES AND OTHER

Year ended December 31 (millions of dollars)	2016(a)		2015(a)		2014(a)
Interest expense (b)	69		65		59
Net realized loss related to the interest rate swaps	3		2		2
PNGTS’ amortization of realized loss on derivative instrument (Note 18)	1		1		1
Other	(2	)	(5	)	(1	)
	71		63		61

(a) Recast to consolidate PNGTS for all periods presented.

(b) Effective January 1, 2016, interest expense includes amortization of debt issuance costs and discount costs. Refer to Note 3.

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NET INCOME (LOSS) PER COMMON UNIT

3 Months Ended

12 Months Ended

Mar. 31, 2017

Dec. 31, 2016

NET INCOME PER COMMON UNIT

NET INCOME (LOSS) 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 net income attributed to PNGTS’ former parent, amounts attributable to the General Partner and Class B units by the weighted average number of common units outstanding.

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

The amount allocable to the Class B units in 2017 equals 30 percent of GTN’s distributable cash flow during the year ended December 31, 2017 less $20 million (December 31, 2016 —$20 million). 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 (a)	77			74
Net income attributable to PNGTS’ former parent (a) (b)	(2		)	(1		)
Net income allocable to General Partner and Limited Partners	75			73
Net income attributable to the General Partner	(1		)	(1		)
Incentive distributions attributable to the General Partner (c)	(2		)	(1		)
Net income attributable to common units	72			71
Weighted average common units outstanding (millions) — basic and diluted (d)	68.3			64.4
Net income per common unit — basic and diluted (e)	$	1.05		$	1.10

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

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

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

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

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

NOTE 12 NET INCOME (LOSS) PER COMMON UNIT

Net income (loss) per common unit is computed by dividing net income attributable to controlling interests, after deduction of  net income attributed to PNGTS’ former parent, amounts attributable to the General Partner andClass 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 (refer to Note 13).

The amount allocable to the Class B units in 2016 equals an amount based upon 30 percent of GTN’s distributable cash flow during the year ended December 31, 2016 less $20 million (2015 - $15 million).

Net income (loss) per common unit was determined as follows:

(millions of dollars, except per common unit amounts)	2016			2015			2014
Net income attributable to controlling interests (a)	248			37			195
Net income attributable to PNGTS’ former parent (a) (b)	(4		)	(24		)	(23		)
Net income allocable to General Partner and Limited Partners	244			13			172
Incentive distributions attributable to the General Partner (c)	(7		)	(3		)	(1		)
Net income attributable to the Class B units (d)	(22		)	(12		)	—
Net income (loss) allocable to the General Partner and common units	215			(2		)	171
Net income (loss) allocable to the General Partner’s two percent interest	(4		)	—			(3		)
Net income (loss) attributable to common units	211			(2		)	168
Weighted average common units outstanding (millions) — basic and diluted	65.7		(e)	63.9			62.7
Net income (loss) per common unit — basic and diluted (f)	$	3.21		$	(0.03	)	$	2.67

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

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

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

^(d) As discussed in Note 9, the Class B units entitle TransCanada to a distribution which is an amount based on 30 percent of GTN’s distributions after exceeding certain annual thresholds. The distribution will be payable in the first quarter with respect to the prior year’s distributions. Consistent with the application of Accounting Standards Codification (ASC) Topic 260 — “Earnings per share”, the Partnership allocated a portion of net income attributable to controlling interests to the Class B units in an amount equal to 30 percent of GTN’s total distributable cash flows during the year ended December 31, 2016 less the threshold level of $20 million (2015 - less $15 million). During the year ended December 31, 2016, 30 percent of GTN’s total distributable cash flow was $42 million. As a result of exceeding the threshold level of $20 million, $22 million of net income attributable to controlling interests was allocated to the Class B units at December 31, 2016 (2015 - $12 million). Refer to Note 9.

^(e) Includes the common units subject to rescission. These units are treated as outstanding for financial reporting purposes. Refer to Note 9.

^(f) Net income (loss) per common unit prior to recast.

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CASH DISTRIBUTIONS

3 Months Ended

12 Months Ended

Mar. 31, 2017

Dec. 31, 2016

CASH DISTRIBUTIONS TO COMMON UNITS

CASH DISTRIBUTIONS

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 13 CASH DISTRIBUTIONS

The Partnership makes cash distributions to its partners with respect to each calendar quarter within 45 days after the end of each quarter. Distributions are based on Available Cash, as defined in the Partnership Agreement, which includes all cash and cash equivalents of the Partnership and working capital borrowings less reserves established by the General Partner.

Pursuant to the Partnership Agreement, the General Partner receives two percent of all cash distributions in regard to its general partner interest and is also entitled to incentive distributions as described below. The unitholders receive the remaining portion of the cash distribution.

The following table illustrates the percentage allocations of available cash from operating surplus between the common unitholders and our General Partner based on the specified target distribution levels. The percentage interests set forth below for our General Partner include its two percent general partner interest and IDRs, and assume our General Partner has contributed any additional capital necessary to maintain its two percent general partner interest. The distribution to the General Partner illustrated below, other than in its capacity as a holder of 5,797,106 common units that are in excess of its effective two percent general partner interest, represents the IDRs.

		Marginal Percentage Interest in Distribution
	Total Quarterly Distribution Per Unit Target Amount	Common Unitholders		General Partner
Minimum Quarterly Distribution	$0.45	98	%	2	%
First Target Distribution	above $0.45 up to $0.81	98	%	2	%
Second Target Distribution	above $0.81 up to $0.88	85	%	15	%
Thereafter	above $0.88	75	%	25	%

The following table provides information about our distributions (in millions, except per unit distributions amounts).

				Limited Partners					General Partner
Declaration Date	Payment Date	Per Unit Distribution		Common Units		Class B Units(c)			2%		IDRs(a)		Total Cash Distribution
1/16/2014	2/14/2014	$	0.81	$	50	$	—		$	1	$	—	$	51
4/25/2014	5/15/2014	$	0.81	$	51	$	—		$	1	$	—	$	52
7/23/2014	8/14/2014	$	0.84	$	53	$	—		$	1	$	—	$	54
10/23/2014	11/14/2014	$	0.84	$	53	$	—		$	1	$	1	$	55
1/22/2015	2/13/2015	$	0.84	$	54	$	—		$	1	$	—	$	55
4/23/2015	5/15/2015	$	0.84	$	54	$	—		$	1	$	—	$	55
7/23/2015	8/14/2015	$	0.89	$	56	$	—		$	2	$	1	$	59
10/22/2015	11/13/2015	$	0.89	$	57	$	—		$	1	$	1	$	59
1/21/2016	2/12/2016	$	0.89	$	57	$	12	(d)	$	1	$	1	$	71
4/21/2016	5/13/2016	$	0.89	$	58	$	—		$	1	$	1	$	60
7/21/2016	8/12/2016	$	0.94	$	62	$	—		$	1	$	2	$	65
10/20/2016	11/14/2016	$	0.94	$	63	$	—		$	1	$	2	$	66
1/23/2017 (b)	2/14/2017 (b)	$	0.94	$	64	$	22	(e)	$	2	$	2	$	90

^(a) The distributions paid for the year ended December 31, 2016 included incentive distributions to the General Partner of $6 million (2015 - $2 million, 2014 - $1 million).

^(b) On February 14, 2017, we paid a cash distribution of $0.94 per unit on our outstanding common units to unitholders of record at the close of business on February 2, 2017 (refer to Note 24).

^(c) The Class B units issued by us on April 1, 2015 represent limited partner interests in us and entitle TransCanada to an annual distribution which is an amount based on 30 percent of GTN’s annual distributions after exceeding certain annual thresholds (refer to Note 6 and 9).

^(d) On February 12, 2016, we paid TransCanada $12 million representing 30 percent of GTN’s total distributable cash flows for the nine months ended December 31, 2015 less $15 million.

^(e) On February 14, 2017, we paid TransCanada $22 million representing 30 percent of GTN’s total distributable cash flows for the year ended December 31, 2016 less $20 million (refer to Note 9 and 24).

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CHANGE IN OPERATING WORKING CAPITAL

3 Months Ended

12 Months Ended

Mar. 31, 2017

Dec. 31, 2016

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 (b)		2016 (b)
Change in accounts receivable and other	7		(2	)
Change in other current assets	1		3
Change in accounts payable and accrued liabilities	(3	)	3	(a)
Change in accounts payable to affiliates	(1	)	(4	)
Change in state income taxes payable	—		9
Change in accrued interest	3		5
Change in operating working capital	7		14

^(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.

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

NOTE 14 CHANGE IN OPERATING WORKING CAPITAL

Year Ended December 31 (millions of dollars)	2016 (c)		2015(c)		2014(c)
Change in accounts receivable and other	(4	)	6		2
Change in other current assets	(4	)	(1	)	(1	)
Change in accounts payable and accrued liabilities (a)	5		(2	)	29
Change in accounts payable to affiliates	—		(15	) (b)	(6	)
Change in state income taxes payable	—		(5	)	2
Change in accrued interest	2		(3	)	3
Change in operating working capital	(1	)	(20	)	29

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

^(b) Excludes certain non-cash items primarily related to accruals of $10 million for construction of GTN’s Carty Lateral and $2 million of costs related to acquisition of 49.9 percent interest in PNGTS (Refer to Note 6).

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

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TRANSACTIONS WITH MAJOR CUSTOMERS

12 Months Ended

Dec. 31, 2016

TRANSACTIONS WITH MAJOR CUSTOMERS

TRANSACTIONS WITH MAJOR CUSTOMERS

NOTE 15 TRANSACTIONS WITH MAJOR CUSTOMERS

The following table shows revenues from the Partnership’s major customers comprising more than 10 percent of the Partnership’s total consolidated recasted revenues (refer to Note 2) for the years ended December 31, 2016, 2015 and 2014:

Year Ended December 31 (millions of dollars)	2016		2015	2014
Anadarko Energy Services Company (Anadarko)	48		48	48
Pacific Gas and Electric Company (Pacific Gas)	36	(a)	42	45

At December 31, 2016 and 2015, Anadarko owed the Partnership approximately $4 million, which is approximately 10 percent of our consolidated recasted trade accounts receivable (Refer to Note 2).

^(a) Less than 10 percent

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RELATED PARTY TRANSACTIONS

3 Months Ended

12 Months Ended

Mar. 31, 2017

Dec. 31, 2016

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) (c)	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 (c)	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) (c)	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.

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

Great Lakes

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, $15 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.

PNGTS

For the three months ended March 31, 2017 and 2016, PNGTS provided transportation services to a related party. Revenues from TransCanada Energy Ltd., a subsidiary of TransCanada, for the three months ended March 31, 2017 and 2016 were approximately nil million and  $1 million, respectively. At March 31, 2017, PNGTS had nil million outstanding receivables from TransCanada Energy Ltd. in the consolidated balance sheets (December 31, 2016- nil million).

NOTE 16 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 $3 million for each of the years ended December 31, 2016, 2015 and 2014.

As operator, TransCanada’s subsidiaries provide capital and operating services to GTN, Northern Border, PNGTS, Bison, Great Lakes, North Baja and Tuscarora (together, “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 years ended December 31, 2016, 2015 and 2014 by TransCanada’s subsidiaries and amounts payable to TransCanada’s subsidiaries at December 31, 2016 and 2015 are summarized in the following tables:

Year ended December 31 (millions of dollars)	2016	2015	2014
Capital and operating costs charged by TransCanada’s subsidiaries to:
Great Lakes (a)	30	30	30
Northern Border (a)	32	36	35
PNGTS (a) (b)	8	8	8
GTN (a) (c)	27	30	30
Bison (a) (d)	2	4	6
North Baja	4	5	5
Tuscarora	5	4	4
Impact on the Partnership’s net income attributable to controlling interests:
Great Lakes	13	13	13
Northern Border	12	14	16
PNGTS (b)	5	5	5
GTN (c)	24	25	19
Bison (d)	3	4	4
North Baja	4	5	4
Tuscarora	4	4	4

December 31 (millions of dollars)	2016	2015
Amount payable to TransCanada’s subsidiaries for costs charged in the year by:
Great Lakes (a)	4	3
Northern Border (a)	4	5
PNGTS (a) (b)	1	3
GTN	3	3
Bison	1	—
North Baja	1	—
Tuscarora	1	1

^(a) Represents 100 percent of the costs.

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

^(c) In 2015, the Partnership acquired the remaining 30 percent interest in GTN (Refer to Note 6).

^(d) In 2014, the Partnership acquired the remaining 30 percent interest in Bison (Refer to Note 6).

Great Lakes

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 year ended December 31, 2016, Great Lakes earned 68 percent of its transportation revenues from TransCanada and its affiliates  (2015 — 71 percent; 2014 — 49 percent). Additionally, Great Lakes earned approximately one percent of its total revenues as affiliated rental revenue in 2016 (2015 — 1 percent and 2014 — 1 percent).

At December 31, 2016, $19 million was included in Great Lakes’ receivables in regards to the transportation contracts with TransCanada and its affiliates (December 31, 2015 — $17 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 ROEs. A refund of $2.5 million was paid to shippers in 2016 relating to the year ended December 31, 2015, of which approximately 85 percent was made to affiliates of Great Lakes. For the year ended December 31, 2016, Great Lakes has recorded an estimated revenue sharing provision amounting to $7.2 million and Great Lakes expects that a significant percentage of the refund will be to its affiliates as well.

Great Lakes has a cash management agreement with TransCanada whereby Great Lakes’ funds are pooled with other TransCanada affiliates. The agreement also gives Great Lakes the ability to obtain short-term borrowings to provide liquidity for Great Lakes’ operating needs. At December 31, 2016 and 2015, Great Lakes has an outstanding receivable from this arrangement amounting to $27 million and $51 million, respectively.

Effective November 1, 2014, Great Lakes executed contracts with an affiliate, ANR Pipeline Company (ANR), to provide firm service in Michigan and Wisconsin.  These contracts were at the maximum FERC authorized rate and were intended to replace historical contracts.  On December 3, 2014, FERC accepted and suspended Great Lakes’ tariff records to become effective May 3, 2015, subject to refund.  On February 2, 2015, FERC issued an Order granting a rehearing and clarification request submitted by Great Lakes, which allowed additional time for FERC to consider Great Lakes’ request.  Following extensive discussions with numerous shippers and other stakeholders, on April 20, 2015, ANR filed a settlement with FERC that included an agreement by ANR to pay Great Lakes the difference between the historical and maximum rates (ANR Settlement). Great Lakes provided service to ANR under multiple service agreements and rates through May 3, 2015 when Great Lakes’ tariff records became effective and subject to refund.  Great Lakes deferred an approximate $9 million of revenue related to services performed in 2014 and approximately $14 million of additional revenue related to services performed through May 3, 2015 under such agreements. On October 15, 2015, FERC accepted and approved the ANR Settlement.  As a result, Great Lakes recognized the deferred transportation revenue of approximately $23 million in the fourth quarter of 2015.

PNGTS

For the years ended December 31, 2016 and 2015, PNGTS provided transportation services to a related party. Revenues from TransCanada Energy Ltd., a subsidiary of TransCanada, for 2016 and 2015 were approximately $2 million and $3 million, respectively. At December 31, 2016, PNGTS had nil million outstanding receivables from TransCanada Energy Ltd. in the consolidated balance sheets.

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QUARTERLY FINANCIAL DATA (unaudited)

12 Months Ended

Dec. 31, 2016

QUARTERLY FINANCIAL DATA (unaudited)

QUARTERLY FINANCIAL DATA (unaudited)

NOTE 17 QUARTERLY FINANCIAL DATA (unaudited)

The following sets forth selected unaudited financial data for the four quarters in 2016 and 2015:

Quarter ended (millions of dollars except per common unit amounts)	Mar 31		Jun 30		Sept 30		Dec 31
2016
Transmission revenues (a)	111		101		103		111
Equity earnings (a) (b ) (c)	33		20		22		22
Net income (a)	81		57		60		65
Net income attributable to controlling interests (a)	74		55		58		61
Net income per common unit (d)	$	1.10	$	0.76	$	0.65	$	0.70
Cash distribution paid (f)	71		60		65		66
2015
Transmission revenues (a)	114		97		96		110
Equity earnings (e)	31		15		17		34
Impairment of equity-method investment (b)	—		—		—		(199		)
Net income (loss) (a)	81		47		54		(124		)
Net income (loss) attributable to controlling interests (a)	67		46		52		(128		)
Net income (loss) per common unit (d)	$	0.88	$	0.66	$	0.70	$	(2.27	)
Cash distribution paid (f)	55		55		59		59

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

^(b) Equity Earnings represents our share in investee’s earnings and does not include any impairment charge on equity method goodwill included as part of the carrying value of our equity investments.

^(c) During the year ended December 31, 2016, no impairment has been identified related to our equity investments in Northern Border and Great Lakes.

^(d) Historical net income (loss) per common unit was not recasted.

^(e) During the three months ended December 31, 2015, we recognized an impairment charge on our investment in Great Lakes amounting to $199 million. During the year ended December 31, 2015, no impairment has been identified on our investment in Northern Border (Refer to Note 4).

^(f) Distributions paid to common units and Class B units.

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FAIR VALUE MEASUREMENTS

3 Months Ended

12 Months Ended

Mar. 31, 2017

Dec. 31, 2016

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 $1,905 million and $1,963 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).

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

NOTE 18 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 input 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, accrued interest and short-term debt 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 long-term debt is estimated by discounting the future cash flows of each instrument at estimated current borrowing rates. The fair value of interest rate derivatives is calculated using the income approach which uses period-end market rates and applies a discounted cash flow valuation model.

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

Long-term debt is recorded at amortized cost and classified in Level 2 of the fair value hierarchy for fair value disclosure purposes. Interest rate derivative assets and liabilities are classified in Level 2 for all periods presented where the fair value is determined by using valuation techniques that refer to observable market data or estimated market prices. The estimated fair value of the Partnership’s debt as at December 31, 2016 and December 31, 2015 was $1,963 million and $1,945 million, respectively.

The ATM common units which may be subject to rescission rights, as discussed more fully in Note 9, were measured using the original issuance price, plus statutory interest and less any distributions paid. This fair value measurement is classified as Level 2.

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 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). At December 31, 2015, the fair value of the interest rate swaps accounted for as cash flow hedges was a liability of $1 million both on a gross and net basis. The Partnership did not record any amounts in net income related to ineffectiveness for interest rate hedges for the years ended December 31, 2016, 2015 and 2014. The net change in fair value of interest rate derivative instruments recognized in other comprehensive income was a gain of $2 million for the year ended December 31, 2016 (2015 — nil million, 2014 — loss of $1 million). In 2016, the net realized loss related to the interest rate swaps was $3 million, and was included in financial charges and other (2015 — $2 million, 2014 — $2 million).  Refer to Note 11 — Financial Charges and Other.

The Partnership has no master netting agreements, however, contracts contain 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 net asset of nil million as of December 31, 2016 and there would be no effect on the consolidated balance sheet as of December 31, 2015.

In anticipation of a debt refinancing in 2003, PNGTS entered into forward interest rate swap agreements to hedge the interest rate on its Senior Secured Notes due in 2018. These interest rate swaps were used to manage the impact of interest rate fluctuations and qualified as derivative financial instruments in accordance with ASC 815, Derivatives and Hedging. PNGTS settled its position with a payment of $20.9 million to counterparties at the time of the refinancing and recorded the realized loss in AOCL as of the termination date. The previously recorded AOCL is currently being amortized against earnings over the life of the PNGTS Senior Secured Notes.  At December 31, 2016, our 61.71 percent proportionate share of net unamortized loss on PNGTS included in AOCL was $2 million (2015 - $2 million). For the year ended December 31, 2016, 2015 and 2014, our 61.71 percent proportionate share of the amortization of realized loss on derivative instruments was $0.8 million for each year.

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 cash and cash equivalents and receivables, 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 December 31, 2016, we had not incurred any significant credit losses and had no significant amounts past due or impaired. At December 31, 2016, we had a credit risk concentration on one of our customers and the amount owed is greater than 10 percent of our recasted trade accounts receivable (refer to Note 15).

(c) Other

The estimated fair value measurements on Tuscarora (refer to Note 20) and our equity investment in Great Lakes (refer to Note 4) are both classified as Level 3. In the determination of the fair value, we used internal forecasts on expected future cash flows and applied appropriate discount rates. The determination of expected future cash flows involved significant assumptions and estimates as discussed more fully on Notes 4 and 20.

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ACCOUNTS RECEIVABLE AND OTHER

3 Months Ended

12 Months Ended

Mar. 31, 2017

Dec. 31, 2016

ACCOUNTS RECEIVABLE AND OTHER

ACCOUNTS RECEIVABLE AND OTHER

NOTE 12       ACCOUNTS RECEIVABLE AND OTHER

(unaudited)
(millions of dollars)	March 31, 2017 (a)	December 31, 2016 (a)
Trade accounts receivable, net of allowance of nil	38	44
Imbalance receivable from affiliates	1	2
Other	2	1
	41	47

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

NOTE 19 ACCOUNTS RECEIVABLE AND OTHER

December 31 (millions of dollars)	2016 (a)	2015(a)
Trade accounts receivable, net of allowance of nil	44	40
Imbalance receivable from affiliates	2	1
Other	1	—
	47	41

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

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GOODWILL AND REGULATORY

3 Months Ended

12 Months Ended

Mar. 31, 2017

Dec. 31, 2016

REGULATORY

GOODWILL AND 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 filed its rate case pursuant  to Section 4 of the Natural Gas Act (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 is currently seeking to achieve a mutually beneficial resolution through settlement with its customers.

NOTE 20 GOODWILL AND REGULATORY

Tuscarora - On January 21, 2016, FERC issued an Order initiating an investigation pursuant to Section 5 of the Natural Gas Act of 1938 (NGA) to determine whether Tuscarora’s existing rates for jurisdictional services are just and reasonable. On July 22, 2016, Tuscarora filed a petition with FERC requesting appeal of the Stipulation and Agreement of Settlement (Tuscarora Settlement) Tuscarora made with its customers. On September 22, 2016, FERC approved the Tuscarora Settlement that resolved the Section 5 rate review initiated by FERC in January 2016. Under the terms of the Tuscarora Settlement, Tuscarora’s system-wide unit rate initially decreased by 17 percent, effective August 1, 2016. Unless superseded by a subsequent rate case or settlement, this rate will remain in effect until July 31, 2019, after which time the unit rate will decrease an additional seven percent from August 1, 2019 through July 31, 2022. The settlement does not contain a rate moratorium and requires Tuscarora to file to establish new rates no later than August 1, 2022.

The reduction in Tuscarora’s future cash flows as a result of the Tuscarora Settlement constituted a triggering event in the second quarter of 2016 that led us to evaluate, for possible impairment, the $82 million of goodwill related to our acquisition of Tuscarora.

Our second quarter analysis which was also reviewed for any material updates as part of our annual impairment test on goodwill, resulted in the estimated fair value of Tuscarora exceeding its carrying value but the excess was less than 10 percent. The fair value was measured using a discounted cash flow analysis and included revenues expected from Tuscarora’s current and expected future contracting level. There is a risk that reductions in future cash flow forecasts as a result of Tuscarora not being able to maintain its current contracting level and/or not being able to realize other opportunities on the system, together with adverse changes in other key assumptions such as expected outcome of future rate proceedings, projected operating costs and estimated rate of return on invested capital, could result in a future impairment of the goodwill balance relating to Tuscarora.

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. The requested abandonments will not have any impact on existing firm transportation service.

GTN —   GTN operates under rates established pursuant to a settlement approved by FERC in June 2015. Beginning in January 2016, GTN’s rates decreased by 10 percent and will continue in effect through December 31, 2019. Unless superseded by a subsequent rate case or settlement, GTN’s rates will decrease an additional eight percent for the period January 1, 2020 through December 31, 2021 when GTN will be required to establish new rates.

PNGTS - PNGTS continues to operate under the rates approved by FERC in February 2015 (Refer to Note 2-Significant Accounting Policies-Revenue Recognition). PNGTS has no requirement to file a new rate proceeding.

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CONTINGENCIES

3 Months Ended

12 Months Ended

Mar. 31, 2017

Dec. 31, 2016

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.

NOTE 21 CONTINGENCIES

The Partnership and its pipeline systems are subject to various legal proceedings in the ordinary course of business. Our accounting for contingencies covers a variety of business activities, including contingencies for legal and environmental liabilities. The Partnership accrues for these contingencies when the assessments indicate that it is probable that a liability has been incurred or an asset will not be recovered and an amount can be reasonably estimated in accordance with ASC 450 — Contingencies. We base these estimates on currently available facts and the estimates of the ultimate outcome or resolution. Actual results may differ from estimates resulting in an impact, positive or negative, on earnings and cash flow. Contingencies that might result in a gain are not accrued in our consolidated financial statements.

Below are the material legal proceedings that might have a significant impact on the Partnership:

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 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.

Employees Retirement System of the City of St. Louis v. TC PipeLines GP, Inc., et al. — On October 13, 2015, an alleged unitholder of the Partnership filed a class action and derivative complaint in the Delaware Court of Chancery against the General Partner, TransCanada American Investments, Ltd. (TAIL) and TransCanada, and the Partnership as a nominal defendant.   The complaint alleges direct and derivative claims for breach of contract, breach of the duty of good faith and fair dealing, aiding and abetting breach of contract, and tortious interference in connection with the 2015 GTN Acquisition, including the issuance by the Partnership of $95 million in Class B Units and amendments to the Partnership Agreement to provide for the issuance of the Class B Units.   Plaintiff seeks, among other things, to enjoin future issuances of Class B Units to TransCanada or any of its subsidiaries, disgorgement of certain distributions to the General Partner, TransCanada and any related entities, return of some or all of the Class B Units to the Partnership, rescission of the amendments to the Partnership Agreement, monetary damages and attorney fees.   The Partnership has moved to dismiss the complaint and intends to defend vigorously against the claims asserted. In April 2016, the Chancery Court granted the Partnership and other defendants’ motion to dismiss the plaintiffs’ complaint.  The plaintiff has appealed the decision to dismiss its claims.  The appeal of this matter was heard by the Delaware Supreme Court in December, 2016.  The court found in TransCanada’s favor and dismissed the Plaintiff’s motion.  There are no further rights of appeal.

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VARIABLE INTEREST ENTITIES

3 Months Ended

12 Months Ended

Mar. 31, 2017

Dec. 31, 2016

VARIABLE INTEREST ENTITIES

VARIABLE INTEREST ENTITIES

NOTE 16       VARIABLE INTEREST ENTITIES

In the normal course of business, the Partnership must re-evaluate its legal entities under the current consolidation guidance to determine if those that are considered to be VIEs are appropriately consolidated or if they should be accounted for under other 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 (b)		December 31, 2016 (b)
ASSETS (LIABILITIES) *
Cash and cash equivalents	18		14
Accounts receivable and other	28		33
Inventories	6		6
Other current assets	4		6
Equity investments	930		918
Plant, property and equipment	1,140		1,146
Other assets	2		2
Accounts payable and accrued liabilities	(20	)	(21	)
Accounts payable to affiliates, net	(24	)	(32	)
Distributions payable	(3	)	(3	)
Accrued interest	(5	)	(2	)
State income tax payable	(1	)	—
Current portion of long-term debt	(46	)	(52	)
Long-term debt	(330	)	(337	)
Other liabilities	(26	)	(25	)
Deferred state income tax	(10	)	(10	)

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

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

NOTE 22 VARIABLE INTEREST ENTITIES

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

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

Consolidated VIEs

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

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

(millions of dollars)	December 31, 2016(b)		December 31, 2015(b)
ASSETS (LIABILITIES) (a)
Cash and cash equivalents	14		16
Accounts receivable and other	33		29
Inventories	6		6
Other current assets	6		6
Equity investments	918		965
Plant, property and equipment	1,146		1,180
Other assets	2		2
Accounts payable and accrued liabilities	(21	)	(27	)
Accounts payable to affiliates, net	(32	)	(9	)
Distributions payable	(3	)	(10	)
Accrued interest	(2	)	(1	)
Current portion of long-term debt	(52	)	(36	)
Long-term debt	(337	)	(373	)
Other liabilities	(25	)	(24	)
Deferred state income tax	(10	)	(11	)

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

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

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INCOME TAXES

3 Months Ended

12 Months Ended

Mar. 31, 2017

Dec. 31, 2016

INCOME TAXES

INCOME TAXES

NOTE 17       INCOME TAXES

The state of New Hampshire (NH) imposes a business profits tax (BPT) levied at the PNGTS level. As a result of the BPT, PNGTS recognizes deferred taxes related to temporary differences between the financial statement carrying amount of existing assets and liabilities and their respective tax bases. The deferred taxes at March 31, 2017 and December 31, 2016 relate primarily to utility plant. For the three months ended March 31, 2017 and 2016, the NH BPT effective tax rate was 3.8 percent for all periods and was applied to PNGTS’ taxable income.

The state income taxes of PNGTS are broken out as follows:

	Three months ended
(unaudited)	March 31,
(millions of dollars)	2017 (a)	2016 (a)
State income taxes
Current	1	8
Deferred	—	(7	)
	1	1

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

NOTE 23 INCOME TAXES

The state of New Hampshire (NH) imposes a business profits tax (BPT) levied at the PNGTS level. As a result of the BPT, PNGTS recognizes deferred taxes related to temporary differences between the financial statement carrying amount of existing assets and liabilities and their respective tax bases. The deferred taxes at December 31, 2016, 2015 and 2014 relate primarily to utility plant. For the years ended December 31, 2016, 2015 and 2014, the NH BPT effective tax rate was 3.8 percent for all periods and was applied to PNGTS’ taxable income.

The state income taxes of PNGTS are broken out as follows:

Year ended December 31 (millions of dollars)	2016 (a)	2015 (a)		2014(a)
State income taxes
Current	1	(2	)	3
Deferred	—	4		(1	)
	1	2		2

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

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SUBSEQUENT EVENTS

3 Months Ended

12 Months Ended

Mar. 31, 2017

Dec. 31, 2016

SUBSEQUENT EVENTS

SUBSEQUENT EVENTS

NOTE 18    SUBSEQUENT EVENTS

Management of the Partnership has reviewed subsequent events through August 3, 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.

Partnership

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 was paid 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.

On May 25, 2017, the Partnership closed a $500 million public offering of senior unsecured notes bearing an interest rate of 3.90 percent maturing May 25, 2027. The net proceeds of $497 million were used to fund a portion of the Partnership’s June 1, 2017 acquisition. The indenture for the notes contains customary investment grade covenants.

On June 1, 2017, the Partnership acquired from subsidiaries of TransCanada a 49.34 percent interest in Iroquois Gas Transmission System, L.P. (Iroquois), including an option to acquire a further 0.66 percent interest in Iroquois, together with an additional 11.81 percent interest in PNGTS resulting in the Partnership owning a 61.71 percent interest in PNGTS (2017 Acquisition). The total purchase price of the 2017 Acquisition was $765 million plus preliminary purchase price adjustments amounting to $9 million. The purchase price consisted of  (i) $710 million for the Iroquois interest (less $164 million, which reflected our 49.34 percent share of Iroquois outstanding debt on June 1)  (ii) $55 million for the additional 11.81 percent interest in PNGTS (less $5 million, which reflected our 11.81% proportionate share in PNGTS’ debt on June 1) and (iii) preliminary working capital adjustments on PNGTS and Iroquois amounting to $3 million and $6 million, respectively. Additionally, the Partnership paid $1,000 for the option to acquire TransCanada’s remaining 0.66 percent interest in Iroquois. The Partnership funded the cash portion of the 2017 Acquisition through a combination of proceeds from the May 2017 public debt offering (refer to Note 5) and borrowing under our Senior Credit Facility.

As at the date of the 2017 Acquisition, there was significant cash on Iroquois’ balance sheet.  Pursuant to the Purchase and Sale Agreement associated with the acquisition of the Iroquois interest, as amended, the Partnership agreed to pay $28 million plus interest to TransCanada on August 1, 2017 for its 49.34 percent share of cash determined to be surplus to Iroquois’ operating needs. In addition, the Partnership expects to make a final working capital adjustment payment by the end of August. The $28 million and the related interest were included in accounts payable to affiliates at June 30, 2017.

The Iroquois’ partners adopted a distribution resolution to address the significant cash on Iroquois’ balance sheet post-closing. The Partnership expects to receive the $28 million of unrestricted cash as part of its quarterly distributions from Iroquois over 11 quarters under the terms of the resolution, beginning with the second quarter 2017 distribution on August 1, 2017.

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

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

On July 20, 2017, the board of directors of our General Partner declared the Partnership’s second quarter 2017 cash distribution in the amount of $1.00 per common unit payable on August 11, 2017 to unitholders of record as of August 1, 2017. The declared distribution reflects a $0.06 per common unit increase to the Partnership’s first quarter 2017 quarterly distribution. The declared distribution totaled $74 million and is payable in the following manner: $69 million to common unitholders (including $6 million to the General Partner as a holder of 5,797,106 common units and $11 million to another subsidiary of TransCanada as holder of 11,287,725 common units) and $5 million to our General Partner, which included $2 million for its effective two percent general partner interest and $3 million of IDRs.

Northern Border

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.

Northern Border declared its April 2017 distribution of $14 million on May 12, 2017, of which the Partnership received its 50 percent share or $7 million on May 31, 2017.

Northern Border declared its May 2017 distribution of $12 million on June 7, 2017, of which the Partnership received its 50 percent share or $6 million on June 30, 2017.

Northern Border declared its June 2017 distribution of $14 million on July 7, 2017, of which the Partnership received its 50 percent share or $7 million on July 31, 2017.

Great Lakes

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.

Great Lakes declared its second quarter 2017 distribution of $15 million on July 18, 2017, of which the Partnership will receive its 46.45 percent share or $7 million on August 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 20). We cannot predict the cumulative impact of these circumstances to the Partnership’s earnings and cash flows at this time.

Iroquois

Iroquois declared its second quarter 2017 distribution of $28 million on July 27, 2017, of which the Partnership received its 49.34 percent share or $14 million on August 1, 2017.

NOTE 24 SUBSEQUENT EVENTS

Management of the Partnership has reviewed subsequent events through August 3, 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.

Partnership

On January 23, 2017, the board of directors of our General Partner declared the Partnership’s fourth quarter 2016 cash distribution in the amount of $0.94 per common unit and was paid on February 14, 2017 to unitholders of record as of February 2, 2017. The declared distribution totaled $68 million and was paid in the following manner: $64 million to common unitholders (including $5 million to the General Partner as holder of 5,797,106 common units and $11 million to another subsidiary of TransCanada as holder of 11,287,725 common units) and $4 million to our General Partner, which included $2 million for its effective two percent general partner interest and $2 million of IDRs payment.

On January 23, 2017, the board of directors of our General Partner declared distributions to Class B unitholders in the amount of $22 million and was paid on February 14, 2017. The Class B distribution represents an amount equal to 30 percent of GTN’s distributable cash flow during the year ended December 31, 2016 less $20 million.

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 was paid on May 15, 2017 to unitholders of record as of May 5, 2017. The declared distribution totaled $68 million and was paid in the following manner: $65 million to common unitholders (including $5 million to the General Partner as a holder of 5,797,106 common units and $11 million to another subsidiary of TransCanada as holder of 11,287,725 common units) and $3 million to our General Partner, which included $1 million for its effective two percent general partner interest and $2 million of IDRs.

On May 25, 2017, the Partnership closed a $500 million public offering of senior unsecured notes bearing an interest rate of 3.90 percent maturing May 25, 2027. The net proceeds of $497 million were used to fund a portion of the Partnership’s June 1, 2017  acquisition.The indenture for the notes contains customary investment grade covenants.

On June 1, 2017, the Partnership acquired from subsidiaries of TransCanada a 49.34 percent interest in Iroquois Gas Transmission System, L.P. (Iroquois), including an option to acquire a further 0.66 percent interest in Iroquois, together with an additional 11.81 percent interest in PNGTS resulting in the Partnership owning a 61.71 percent interest in PNGTS (2017 Acquisition). The total purchase price of the 2017 Acquisition was $765 million plus preliminary purchase price adjustments amounting to $9 million. The purchase price consisted of  (i) $710 million for the Iroquois interest (less $164 million, which reflected our 49.34 percent share of Iroquois outstanding debt on June 1)  (ii) $55 million for the additional 11.81 percent interest in PNGTS (less $5 million, which reflected our 11.81% proportionate share in PNGTS’ debt on June 1) and (iii) preliminary working capital adjustments on PNGTS and Iroquois amounting to $3 million and $6 million, respectively. Additionally, the Partnership paid $1,000 for the option to acquire TransCanada’s remaining 0.66 percent interest in Iroquois. The Partnership funded the cash portion of the 2017 Acquisition through a combination of proceeds from the May 2017 public debt offering (refer to Note 5) and borrowing under our Senior Credit Facility.

As at the date of the 2017 Acquisition, there was significant cash on Iroquois’ balance sheet. Pursuant to the Purchase and Sale Agreement associated with the acquisition of the Iroquois interest, as amended, the Partnership agreed to pay $28 million plus interest to TransCanada on August 1, 2017 for its 49.34 percent share of cash determined to be surplus to Iroquois’ operating needs. In addition, the Partnership expects to make a final working capital adjustment payment by the end of August. The $28 million and the related interest were included in accounts payable to affiliates at June 30, 2017.

The Iroquois’ partners adopted a distribution resolution to address the significant cash on Iroquois’ balance sheet post-closing. The Partnership expects to receive the $28 million of unrestricted cash as part of its quarterly distributions from Iroquois over 11 quarters under the terms of the resolution, beginning with the second quarter 2017 distribution on August 1, 2017.

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

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

On July 20, 2017, the board of directors of our General Partner declared the Partnership’s second quarter 2017 cash distribution in the amount of $1.00 per common unit payable on August 11, 2017 to unitholders of record as of August 1, 2017. The declared distribution reflects a $0.06 per common unit increase to the Partnership’s first quarter 2017 quarterly distribution. The declared distribution totaled $74 million and is payable in the following manner: $69 million to common unitholders (including $6 million to the General Partner as a holder of 5,797,106 common units and $11 million to another subsidiary of TransCanada as holder of 11,287,725 common units) and $5 million to our General Partner, which included $2 million for its effective two percent general partner interest and $3 million of IDRs.

Northern Border

Northern Border declared its December 2016 distribution of $16 million on January 9, 2017, of which the Partnership received its 50 percent share or $8 million. The distribution was paid on January 31, 2017.

Northern Border declared its January 2017 distribution of $18 million on February 15, 2017, of which the Partnership received its 50 percent share or $9 million on February 28, 2017.

Northern Border declared its February 2017 distribution of $9 million on March 10, 2017, of which the Partnership received its 50 percent share or $5 million on March 31, 2017.

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.

Northern Border declared its April 2017 distribution of $14 million on May 12, 2017, of which the Partnership received its 50 percent share or $7 million on May 31, 2017.

Northern Border declared its May 2017 distribution of $12 million on June 7, 2017, of which the Partnership received its 50 percent share or $6 million on June 30, 2017.

Northern Border declared its June 2017 distribution of $14 million on July 7, 2017, of which the Partnership received its 50 percent share or $7 million on July 31, 2017.

Great Lakes

Great Lakes declared its fourth quarter 2016 distribution of $14 million on January 9, 2017, of which the Partnership received its 46.45 percent share or $7 million. The distribution was paid on February 1, 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.

Great Lakes declared its second quarter 2017 distribution of $15 million on July 18, 2017, of which the Partnership will receive its 46.45 percent share or $7 million on August 1, 2017.

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 filed its rate case pursuant to Section 4 of the Natural Gas Act. 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 is currently seeking 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 March 31, 2017 General Section 4 Rate Filing. We cannot predict the cumulative impact of these circumstances to the Partnership’s earnings and cash flows at this time.

PNGTS

On January 3, 2017, PNGTS  paid the amount due on December 31, 2016 on its 2003 Senior Secured Notes amounting to $6.3 million representing $5.5 million in principal and $0.8 million in interest pursuant to the terms of the Note Purchase agreement. Under the agreement, any principal and interest that is due on a date other than a normal business day shall be made on the next succeeding business day without additional interest or penalty.

Iroquois

Iroquois declared its second quarter 2017 distribution of $28 million on July 27, 2017, of which the Partnership received its 49.34 percent share or $14 million on August 1, 2017.

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SIGNIFICANT ACCOUNTING POLICIES (Policies)

3 Months Ended

12 Months Ended

Mar. 31, 2017

Dec. 31, 2016

SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation - Consolidation and equity method of accounting

Basis of Presentation

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

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

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

On June 1, 2017, the Partnership acquired from a subsidiary of TransCanada an additional 11.81 percent interest in PNGTS, resulting in the Partnership owning 61.71 percent in PNGTS (Refer to Note 18-Subsequent Events).  As a result of the Partnership owning 61.71 percent of PNGTS, the Partnership’s historical financial information was recast, except net income (loss) per common unit, to consolidate PNGTS for all the periods presented in these consolidated financial statements. Additionally, this acquisition was accounted for as transaction between entities under common control, similar to pooling of interests, whereby the assets and liabilities of PNGTS were recorded at TransCanada’s carrying value.

Also, on June 1, 2017, the Partnership acquired from subsidiaries of TransCanada a 49.34 percent interest in Iroquois Gas Transmission,L.P (“Iroquois”) (Refer to Note 18-Subsequent Events). Accordingly, the equity method investment in Iroquois was accounted for prospectively and did not form part of these consolidated financial statements.

On January 1, 2016, the Partnership acquired a 49.9 percent interest in PNGTS (2016 PNGTS Acquisition) from a subsidiary of TransCanada. The PNGTS Acquisition was accounted for as a transaction between entities under common control, similar to a pooling of interests, whereby the equity investment in PNGTS was recorded at TransCanada’s carrying value and the total excess purchase price paid was recorded as a reduction in Partners’ Equity. Accordingly, the equity investment in PNGTS is being eliminated as a result of consolidating PNGTS for all the periods presented. Refer to Note 6 for additional disclosure regarding the PNGTS Acquisition.

(a) Basis of Presentation

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

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

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

On June 1, 2017, the Partnership acquired from a subsidiary of TransCanada an additional 11.81 percent interest in PNGTS, resulting in the Partnership owning 61.71 percent in PNGTS (Refer to Note 24-Subsequent Events).  As a result of the Partnership owning 61.71 percent of PNGTS, the Partnership’s historical financial information was recast, except net income (loss) per common unit, to consolidate PNGTS for all the periods presented in these consolidated financial statements. Additionally, this acquisition was accounted for as transaction between entities under common control, similar to pooling of interests, whereby the assets and liabilities of PNGTS were recorded at TransCanada’s carrying value.

Also, on June 1, 2017, the Partnership acquired from subsidiaries of TransCanada a 49.34 percent interest in Iroquois (Refer to Note 24-Subsequent Events). Accordingly, the equity method investment in Iroquois  was accounted prospectively and did not form part of these consolidated financial statements.

Basis of Presentation - Transactions between entities under common control

On January 1, 2016, the Partnership acquired a 49.9 percent interest in PNGTS (2016 PNGTS Acquisition) from a subsidiary of TransCanada. The 2016 PNGTS Acquisition was accounted for as a transaction between entities under common control, similar to a pooling of interests, whereby the equity investment in PNGTS was recorded at TransCanada’s carrying value and the total excess purchase price paid was recorded as a reduction in Partners’ Equity. Accordingly, the equity investment in PNGTS is being eliminated as a result of consolidating PNGTS for all the periods presented. Refer to Note 6 for additional disclosure regarding the PNGTS Acquisition.

On April 1, 2015 and October 1, 2014, the Partnership acquired the remaining 30 percent interest in GTN and Bison, respectively, from subsidiaries of TransCanada. These acquisitions resulted in GTN and Bison being wholly-owned by the Partnership. Prior to these transactions, the remaining 30 percent interests held by subsidiaries of TransCanada were reflected as non-controlling interests in the Partnership’s consolidated financial statements. The acquisitions of these already-consolidated entities were accounted as a transaction between entities under common control, similar to a pooling of interests, whereby the acquired interests were recorded at TransCanada’s carrying value and the total excess purchase price paid was recorded as a reduction in Partners’ Equity. Refer to Note 6 for additional disclosures regarding these acquisitions.

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.

(b) 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.

Cash and Cash Equivalents

(c) Cash and Cash Equivalents

The Partnership’s cash and cash equivalents consist of cash and highly liquid short-term investments with original maturities of three months or less and are recorded at cost, which approximates fair value.

Trade Accounts Receivable

(d) Trade Accounts Receivable

Trade accounts receivable are recorded at the invoiced amount and do not bear interest. We review our accounts receivable regularly and record allowances for doubtful accounts using the specific identification method.

Natural Gas Imbalances

(e) Natural gas imbalances

Natural gas imbalances occur when the actual amount of natural gas delivered to or received from a pipeline system differs from the amount of natural gas scheduled to be delivered or received. The Partnership values these imbalances due to or from shippers and interconnecting parties at current index prices. Imbalances are settled in kind, subject to the terms of the pipelines’ tariff.

Imbalances due from others are reported as  trade accounts receivable or accounts receivable from affiliates under the caption accounts receivable and other on the balance sheets. Imbalances owed to others are reported on the balance sheets as accounts payable and accrued liabilities and accounts payable to affiliates. In addition, the Partnership classifies all imbalances as current as the Partnership expects to settle them within a year.

Inventories

(f) Inventories

Inventories primarily consist of materials and supplies and are carried at the lower of weighted average cost or market.

Plant, Property and Equipment

(g) Plant, Property and Equipment

Plant, property and equipment are stated at original cost. Costs of restoring the land above and around the pipeline are capitalized to pipeline facilities and depreciated over the remaining life of the related pipeline facilities. Pipeline facilities and compression equipment have an estimated useful life of 20 to 77 years and metering and other equipment ranges from 5 to 77 years. Depreciation is calculated on a straight-line composite basis over the assets’ estimated useful lives. Repair and maintenance costs are expensed as incurred. Costs that are considered a betterment are capitalized.

The Partnership’s subsidiaries capitalize a carrying cost on funds invested in the construction of long lived assets. This carrying cost includes a return on the investment financed by debt and equity allowance for funds used during construction (AFUDC), calculated based the average cost of debt and equity. Capitalized carrying costs for AFUDC debt and equity are reflected as an increase in the cost of plant, property and equipment on the balance sheets. Amounts included in construction work in progress are not amortized until transferred into service.

Impairment of Equity Method Investments

(h) Impairment of Equity Method Investments

We review our equity method investments when a significant event or change in circumstances has occurred that may have an adverse effect on the fair value of each investment. When such events or changes occur, we compare the estimated fair value to the carrying value of the related investment. We calculate the estimated fair value of an investment in an equity method investee using an income approach and market approach. The development of fair value estimates requires significant judgment including estimates of future cash flows, which is dependent on internal forecasts, estimates of the long-term rate of growth for the investee, estimates of the useful life over which cash flows will occur, and determination of weighted average cost of capital. The estimates used to calculate the fair value of an investee can change from year to year based on operating results and market conditions. Changes in these estimates and assumptions could materially affect the determination of fair value and our assessment as to whether an investment in an equity method investee has suffered an impairment.

If the estimated fair value of an investment is less than its carrying value, we are required to determine if the decline in fair value is other than temporary. This determination considers the aforementioned valuation methodologies, the length of time and the extent to which fair value has been less than carrying value, the financial condition and near-term prospects of the investee, including any specific events which may influence the operations of the investee, the intent and ability of the holder to retain its investment in the investee for a period of time sufficient to allow for any anticipated recovery in market value, and other facts and circumstances. If the fair value of an investment is less than its carrying value and the decline in value is determined to be other than temporary, we record an impairment charge.

Impairment of Long-lived Assets

(i) Impairment of Long-lived Assets

The Partnership reviews long-lived assets, such as plant, property and equipment for impairment whenever events or changes in circumstances indicate the carrying value may not be recoverable. If the total of the estimated undiscounted future cash flows is less than the carrying value of the assets, an impairment loss is recognized for the excess of the carrying value over the fair value of the assets.

Partners' Equity

(j) Partners’ Equity

Costs incurred in connection with the issuance of units are deducted from the proceeds received.

Revenue Recognition

(k) Revenue Recognition

Transmission revenues are recognized in the period in which the service is provided. When a rate case is pending final FERC approval, a portion of the revenue collected is subject to possible refund. As of December 31, 2016, the Partnership has not recognized any transmission revenue that is subject to possible refund.

For the year ended December 31, 2014 and in January 2015, as required by FERC, PNGTS was charging customers rates applied for in its 2008 and 2010 rate cases. Due to the uncertainty in the outcome of its two outstanding rate cases, PNGTS was only recognizing revenue up to the amount of the interim FERC approved rates . The difference between these amounts was recognized as a provision (liability) for rate refund in the consolidated balance sheet. On February 19, 2015, FERC approved PNGTS’ final rates and PNGTS was required to refund the customers within sixty days of the issuance of the final rates, including interest at the quarterly average prime interest rate as prescribed by FERC. Total refunds accumulated to $114.3 million, including $8.0 million of interest, and were paid to customers on April 15, 2015.

Income Taxes

(l) Income Taxes

Federal and certain state income taxes are the responsibility of the partners and are not reflected in these consolidated financial statements. The tax effect of the Partnership’s activities accrues to its partners. The Partnership’s taxable income or loss, which may vary substantially from the net income or loss reported in the consolidated statement of income, is includable in the federal income tax returns of each partner. The aggregate difference in the basis of the Partnership’s net assets for financial and income tax purposes cannot be readily determined because all information regarding each partner’s tax attributes related to the partnership is not available.

In instances where the Partnership is subject to state income taxes, the asset-liability method is used to account for taxes. This method requires the recognition of deferred tax assets and liabilities for future tax consequences attributable to the differences between the financial statement carrying amount of existing assets and liabilities and their respective tax bases.

Balance Sheet Classification of Deferred Taxes

In November 2015, the FASB issued new guidance which requires that deferred tax assets and liabilities be classified as non-current on the balance sheet. The new guidance is effective January 1, 2017, however, since early application is permitted, the Partnership elected to retrospectively apply this guidance effective January 1, 2015. Application of this new guidance will simplify the Partnership’s process in determining deferred tax amounts and simplify their presentation. The application of this guidance did not have a material impact on the Partnership’s consolidated financial statements.

Acquisitions and Goodwill

(m) Acquisitions and Goodwill

The Partnership accounts for business acquisitions from third parties using the acquisition method of accounting and, accordingly, the assets and liabilities of the acquired entities are recorded at their estimated fair values at the date of acquisition. The excess of the purchase price over the fair value of net assets acquired is attributed to goodwill. Goodwill is not amortized and is tested on an annual basis for impairment or more frequently if any indicators of impairment are evident. The Partnership initially assesses qualitative factors to determine whether events or changes in circumstances indicate that the goodwill might be impaired. If the Partnership does not conclude that it is more likely than not that fair value of the reporting unit is greater than its carrying value, the first step of the two-step impairment test is performed by comparing the fair value of the reporting unit to its book value, which includes goodwill. If the fair value is less than book value, an impairment is indicated and a second step is performed to measure the amount of the impairment. In the second step, the implied fair value of goodwill is calculated by deducting the recognized amounts of all tangible and intangible net assets of the reporting unit from the fair value determined in the initial assessment. If the carrying value of goodwill exceeds the calculated implied fair value of goodwill, an impairment charge is recorded.

At December 31, 2016 and 2015, we had $130 million of goodwill recorded on our consolidated balance sheet related to the North Baja ($48 million) and Tuscarora ($82 million) acquisitions. No impairment of goodwill existed at December 31, 2016 (Refer also to Note 20).

The Partnership accounts for business acquisitions between itself and TransCanada, also known as “dropdowns”, as transactions between entities under common control.  Using this approach, the assets and liabilities of the acquired entities are recorded at TransCanada’s carrying value. In the event recasting is required, the Partnership’s historical financial information will be recast, except net income (loss) per common unit, to include the acquired entities for all periods presented. If the fair market value paid for the acquired entities is greater than the recorded net assets of the acquired entities, the excess purchase price paid is recorded as a reduction in Partners’ Equity. Similarly, if the fair market value paid for the acquired entities is less than the recorded net assets of the acquired entities, the excess of assets acquired is recorded as an increase in Partners’ Equity.

Fair Value Measurements

(n) Fair Value Measurements

For cash and cash equivalents, receivables, accounts payable, certain accrued expenses and short-term debt, the carrying amount approximates fair value due to the short maturities of these instruments. For long-term debt instruments and the interest rate swap agreements, fair value is estimated based upon market values (if applicable) or on the current interest rates available to us for debt with similar terms and remaining maturities. Considerable judgment is required in developing these estimates.

Derivative Financial Instruments and Hedging Activities

(o) Derivative Financial Instruments and Hedging Activities

The Partnership recognizes all derivative instruments as either assets or liabilities in the balance sheet at their respective fair values. For derivatives designated in hedging relationships, changes in the fair value are either offset through earnings against the change in fair value of the hedged item attributable to the risk being hedged or recognized in accumulated other comprehensive income, to the extent the derivative is effective at offsetting the changes in cash flows being hedged until the hedged item affects earnings.

The Partnership only enters into derivative contracts that it intends to designate as a hedge of a forecasted transaction or the variability of cash flows to be received or paid related to a recognized asset or liability (cash flow hedge). For all hedging relationships, the Partnership formally documents the hedging relationship and its risk management objective and strategy for undertaking the hedge, the hedging instrument, the hedged transaction, the nature of the risk being hedged, how the hedging instrument’s effectiveness in offsetting the hedged risk will be assessed prospectively and retrospectively, and a description of the method used to measure ineffectiveness. The Partnership also formally assesses, both at the inception of the hedging relationship and on an ongoing basis, whether the derivatives that are used in hedging relationships are highly effective in offsetting changes in cash flows of hedged transactions. For derivative instruments that are designated and qualify as part of a cash flow hedging relationship, the effective portion of the gain or loss on the derivative is reported as a component of other comprehensive income and reclassified into earnings in the same period or periods during which the hedged transaction affects earnings. Gains and losses on the derivative representing either hedge ineffectiveness or hedge components excluded from the assessment of effectiveness are recognized in current earnings.

The Partnership discontinues hedge accounting prospectively when it determines that the derivative is no longer effective in offsetting cash flows attributable to the hedged risk, the derivative expires or is sold, terminated, or exercised, the cash flow hedge is de-designated because a forecasted transaction is not probable of occurring, or management determines to remove the designation of the cash flow hedge.

In all situations in which hedge accounting is discontinued and the derivative remains outstanding, the Partnership continues to carry the derivative at its fair value on the balance sheet and recognizes any subsequent changes in its fair value in earnings. When it is probable that a forecasted transaction will not occur, the Partnership discontinues hedge accounting and recognizes immediately in earnings gains and losses that were accumulated in other comprehensive income related to the hedging relationship.

Asset Retirement Obligation

(p) Asset Retirement Obligation

The Partnership recognizes the fair value of a liability for asset retirement obligations in the period in which it is incurred, when a legal obligation exists and a reasonable estimate of fair value can be made. The fair value is added to the carrying amount of the associated asset and the liability is accreted through charges to operating expenses.

The Partnership has determined it has legal obligations associated with its natural gas pipelines and related transmission facilities. The obligations relate primarily to purging and sealing the pipelines if they are abandoned. The Partnership is also required to operate and maintain its natural gas pipeline system, and intends to do so as long as supply and demand for natural gas exists, which the Partnership expects for the foreseeable future. Therefore, the Partnership believes its natural gas pipeline system assets have indeterminate lives and, accordingly, has recorded no asset retirement obligation as of December 31, 2016 and 2015.

Government Regulation

(q) Government Regulation

The Partnership’s subsidiaries are subject to regulation by FERC. Under regulatory accounting principles, certain assets or liabilities that result from the regulated ratemaking process may be recorded that would not be recorded under GAAP for non-regulated entities. The timing of recognition of certain revenues and expenses in our regulated business may differ from that otherwise expected under GAAP to appropriately reflect the economic impact of the regulators’ decisions regarding revenues and rates. The Partnership regularly evaluates the continued applicability of regulatory accounting, considering such factors as regulatory changes, the impact of competition, and the ability to recover regulatory assets. At December 31, 2016, the Partnership had regulatory assets amounting to $1 million reported as part of other current assets  in the balance sheet representing volumetric fuel tracker assets that are settled with in-kind exchanges with customers continually (2015 — $2 million). Regulatory liabilities are included in other long-term liabilities (refer to Note 8). AFUDC is capitalized and included in plant, property and equipment.

Debt Issuance Costs

(r) Debt Issuance Costs

Costs related to the issuance of debt are deferred and amortized using the effective interest rate method over the term of the related debt. Refer also to Note 3 — Imputation of Interest for the change in accounting policy related to debt issuance costs.

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ORGANIZATION (Tables)

12 Months Ended

Dec. 31, 2016

ORGANIZATION

Schedule of ownership interests in natural gas pipeline systems

Pipeline	Length	Description	Ownership
Gas Transmission Northwest LLC (GTN)	1,377 miles	Extends between an interconnection near Kingsgate, British Columbia, Canada at the Canadian border to a point near Malin, Oregon at the California border and delivers natural gas to the Pacific Northwest and to California.	100 percent
Bison Pipeline LLC (Bison)	303 miles	Extends from a location near Gillette, Wyoming to Northern Border’s pipeline system in North Dakota. Bison can transport natural gas from the Powder River Basin to Midwest markets.	100 percent
North Baja Pipeline, LLC (North Baja)	86 miles	Extends between an interconnection with the El Paso Natural Gas Company pipeline near Ehrenberg, Arizona and an interconnection with a natural gas pipeline near Ogilby, California on the Mexican border transporting natural gas in the southwest. North Baja is a bi-directional pipeline.	100 percent
Tuscarora Gas Transmission Company (Tuscarora)	305 miles	Extends between the GTN pipeline near Malin, Oregon to its terminus near Reno, Nevada and delivers natural gas in northeastern California and northwestern Nevada.	100 percent
Northern Border Pipeline Company (Northern Border)	1,412 miles	Extends between the Canadian border near Port of Morgan, Montana to a terminus near North Hayden, Indiana, south of Chicago. Northern Border is capable of receiving natural gas from Canada, the Williston Basin and Rocky Mountain area for deliveries to the Midwest. ONEOK Partners, L.P. owns the remaining 50 percent of Northern Border.	50 percent
Portland Natural Gas Transmission System (PNGTS)	295 miles	Connects with the TransQuebec and Maritimes Pipeline (TQM) at the Canadian border to deliver natural gas to customers in the U.S. northeast. Northern New England Investment Company, Inc. owns the remaining 38.29 percent of PNGTS.	61.71 percent (a)
Great Lakes Gas Transmission Limited Partnership (Great Lakes)	2,115 miles	Connects with the TransCanada Mainline at the Canadian border near Emerson, Manitoba, Canada and St. Clair, Michigan, near Detroit. Great Lakes is a bi-directional pipeline that can receive and deliver natural gas at multiple points along its system. TransCanada owns the remaining 53.55 percent of Great Lakes.	46.45 percent
Iroquois Gas Transmission System, L.P (Iroquois)	416 miles	Extends from the TransCanada Mainline system near Waddington, New York to deliver natural gas to customers in the U.S. northeast. The remaining 50.66 percent is owned by TransCanada (0.66 percent), Dominion Midstream (25.93 percent) and Dominion Resources (24.07 percent).	49.34 percent (b)

^(a) On June 1, 2017, the Partnership acquired an additional 11.81 percent from TransCanada resulting in 61.71 percent ownership in PNGTS. (Refer to Note 24-Subsequent Events).

^(b) Effective June 1, 2017 (Refer to Note 24-Subsequent Events).

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EQUITY INVESTMENTS (Tables)

3 Months Ended

12 Months Ended

Mar. 31, 2017

Dec. 31, 2016

EQUITY INVESTMENTS

Schedule of equity investments and summarized financial information for equity investees

	Ownership		Equity Earnings (b)		Equity Investments (b)
	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
			36	33	930	918

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

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

	Ownership Interest at		Equity Earnings (b)			Equity Investments
	December 31,		Year ended December 31			December 31
(millions of dollars)	2016		2016(d)	2015	2014	2016 (d)	2015
Northern Border (a)	50.00	%	69	66	69	444	480
Great Lakes	46.45	%	28	31	19	474	485	(c)
			97	97	88	918	965

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

^(b) Equity Earnings represents our share in investee’s earnings and does not include any impairment charge on the equity method investment recorded as a reduction of carrying value of these investments. Accordingly, no impairment charge was recorded by the Partnership on its equity investees for all the periods presented here except the impairment recognized in 2015 on our investment in Great Lakes as discussed below.

^(c) During the fourth quarter of 2015, we recognized an impairment charge on our investment in Great Lakes amounting to $199 million. See discussion below.

^(d) Recast to eliminate equity earnings from PNGTS and consolidate PNGTS for all periods presented  (Refer to Note 2).

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

December 31 (millions of dollars)	2016		2015
Assets
Cash and cash equivalents	14		27
Other current assets	36		33
Plant, property and equipment, net	1,089		1,124
Other assets (a)	14		16
	1,153		1,200
Liabilities and Partners’ Equity
Current liabilities	38		39
Deferred credits and other	28		26
Long-term debt, net (a), (b)	430		409
Partners’ equity
Partners’ capital	659		728
Accumulated other comprehensive loss	(2	)	(2	)
	1,153		1,200

^(a) As a result of the application of ASU No. 2015-03 and similar to the presentation of debt discounts, debt issuance costs of $2 million at December 31, 2015 previously reported as other assets in the balance sheet were reclassified as an offset against their respective debt liabilities.

^(b) Includes current maturities of $100 million senior notes at December 31, 2015. During August 2016, the $100 million senior notes were refinanced with a draw on Northern Border’s $200 million revolving credit agreement that expires in 2020.

Year ended December 31 (millions of dollars)	2016		2015		2014
Transmission revenues	292		286		293
Operating expenses	(72	)	(70	)	(72	)
Depreciation	(59	)	(60	)	(59	)
Financial charges and other	(21	)	(22	)	(22	)
Net income	140		134		140

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

December 31 (millions of dollars)	2016	2015
Assets
Current assets	66	86
Plant, property and equipment, net	714	727
	780	813
Liabilities and Partners’ Equity
Current liabilities	40	31
Long-term debt, net (a),(b)	278	297
Partners’ equity	462	485
	780	813

^(a) The application of ASU No. 2015-03 did not have a material effect on Great Lakes’ financial statements.

^(b) Includes current maturities of $19 million as of December 31, 2016 (December 31, 2015 - $19 million).

Year ended December 31 (millions of dollars)	2016		2015		2014
Transmission revenues	179		177		146
Operating expenses	(69	)	(59	)	(53	)
Depreciation	(28	)	(28	)	(28	)
Financial charges and other	(21	)	(23	)	(25	)
Net income	61		67		40

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PLANT, PROPERTY AND EQUIPMENT (Tables)

12 Months Ended

Dec. 31, 2016

PLANT, PROPERTY AND EQUIPMENT

Schedule of plant, property and equipment

	2016 (a)				2015 (a)
December 31 (millions of dollars)	Cost	Accumulated Depreciation		Net Book Value	Cost	Accumulated Depreciation		Net Book Value
Pipeline	2,540	(879	)	1,661	2,535	(806	)	1,729
Compression	519	(148	)	371	516	(134	)	382
Metering and other	205	(61	)	144	201	(57	)	144
Construction in progress	4	—		4	2	—		2
	3,268	(1,088	)	2,180	3,254	(997	)	2,257

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

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ACQUISITIONS (Tables)

12 Months Ended

Dec. 31, 2016

Portland Natural Gas Transmission System

ACQUISITIONS

Schedule of purchase price

(millions of dollars)
Net Purchase Price (a)	193
Less: TransCanada’s carrying value of PNGTS’ net assets at January 1, 2016	120
Excess purchase price (b)	73

^(a) Total purchase price of $228 million less the assumption of $35 million of proportional PNGTS debt by the Partnership.

^(b) The excess purchase price of $73 million was recorded as a reduction in Partners’ Equity.

GTN

ACQUISITIONS

Schedule of purchase price

(millions of dollars)
Net Purchase Price (a)	359
Less: TransCanada’s carrying value of non-controlling interest at April 1, 2015	232
Excess purchase price (b)	127

^(a) Total purchase price of $457 million less the assumption of $98 million of proportional GTN debt by the Partnership.

^(b) The excess purchase price of $127 million was recorded as a reduction in Partners’ Equity.

Bison

ACQUISITIONS

Schedule of purchase price

(millions of dollars)
Total cash consideration	217
TransCanada’s carrying value of non-controlling interest at October 1, 2014	188
Excess purchase price	29

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DEBT AND CREDIT FACILITIES (Tables)

3 Months Ended

12 Months Ended

Mar. 31, 2017

Dec. 31, 2016

DEBT AND CREDIT FACILITIES

Schedule of debt and credit facilities

(unaudited) (millions of dollars)	March 31, 2017(b)	Weighted Average Interest Rate for the Quarter Ended March 31, 2017 (b)		December 31, 2016(b)		Weighted Average Interest Rate for the Year Ended December 31, 2016(b)
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	%
PNGTS
5.90% Senior Secured Notes due December 2018	41	5.90	%(a)	53		5.90	%(a)
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)
	1,858			1,920
Less: unamortized debt issuance costs and debt discount	8			9
Less: current portion	46			52	(c)
	1,804			1,859

^(a) Fixed interest rate

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

^(c) Includes the PNGTS portion due at December 31, 2016 amounting to $5.5 million that was paid on January 3, 2017

(millions of dollars)	December 31, 2016 (c)		Weighted Average Interest Rate for the Year Ended December 31, 2016 (c)		December 31, 2015 (c)	Weighted Average Interest Rate for the Year Ended December 31, 2015 (c)
TC PipeLines, LP
Senior Credit Facility due 2021	160		1.72	%	200	1.44	%
2013 Term Loan Facility due 2018	500		1.73	%	500	1.44	%
2015 Term Loan Facility due 2018	170		1.63	%	170	1.47	%
4.65% Unsecured Senior Notes due 2021	350		4.65	%(b)	350	4.65	%(b)
4.375% Unsecured Senior Notes due 2025	350		4.375	%(b)	350	4.375	%(b)
GTN
5.29% Unsecured Senior Notes due 2020	100		5.29	%(b)	100	5.29	%(b)
5.69% Unsecured Senior Notes due 2035	150		5.69	%(b)	150	5.69	%(b)
Unsecured Term Loan Facility due 2019	65		1.43	%	75	1.15	%
PNGTS
5.90% Senior Secured Notes due December 2018	53		5.90	%(b)	69	5.90	%(b)
Tuscarora
Unsecured Term Loan due 2019	10		1.64	%	—	—
3.82% Series D Senior Notes due 2017	12		3.82	%(b)	16	3.82	%(b)
	1,920				1,980
Less: unamortized debt issuance costs and debt discount (a)	9				9
Less: current portion	52	(d)			36
	1,859				1,935

^(a) As a result of the application of ASU No. 2015-03 and similar to the presentation of debt discounts, debt issuance costs of $8 million at December 31, 2015 previously reported as other assets in the balance sheet were reclassified as an offset against debt. Refer to Note 3, Accounting Pronouncements.

^(b) Fixed interest rate.

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

^(d) Includes the PNGTS portion due at December 31, 2016 amounting to $5.5 million that was paid on January 3, 2017 (Refer to Note 24-Subsequent Events).

Schedule of principal repayments required on consolidated debt

(unaudited)
(millions of dollars)
2017	40	(a)
2018	715	(a)
2019	43
2020	100
2021	460
Thereafter	500
	1,858	(a)

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

(millions of dollars)
2017	52	(a)
2018	715	(a)
2019	43
2020	100
2021	510
Thereafter	500
	1,920	(a)

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

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OTHER LIABILITIES (Tables)

12 Months Ended

Dec. 31, 2016

OTHER LIABILITIES

Schedule of other liabilities

December 31 (millions of dollars)	2016	2015
Regulatory liabilities	25	24
Other liabilities	3	3
	28	27

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ACCUMULATED OTHER COMPREHENSIVE LOSS (Tables)

12 Months Ended

Dec. 31, 2016

ACCUMULATED OTHER COMPREHENSIVE LOSS

Schedule of changes in accumulated other comprehensive loss (AOCL) by components

	Cash flow hedges (a)
	(millions of dollars)
Balance at December 31, 2013	(5	)
Change in fair value of cash flow hedges	(1	)
Amounts reclassified from AOCL	—
PNGTS’ amortization of realized loss on derivative instrument (Note 18)	1
Net other comprehensive income (loss)	—
Balance at December 31, 2014	(5	)
Change in fair value of cash flow hedges	—
Amounts reclassified from AOCL	—
PNGTS’ amortization of realized loss on derivative instrument (Note 18)	1
Net other comprehensive income	1
Balance at December 31, 2015	(4	)
Change in fair value of cash flow hedges	3
Amounts reclassified from AOCL	(2	)
PNGTS’ amortization of realized loss on derivative instrument (Note 18)	1
Net other comprehensive income	2
Balance as of December 31, 2016	(2	)

^(a) Recast  to consolidate PNGTS for all periods presented (Refer to in Note 2). Additionally, AOCL as presented here is net of non-controlling interest on PNGTS.

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FINANCIAL CHARGES AND OTHER (Tables)

3 Months Ended

12 Months Ended

Mar. 31, 2017

Dec. 31, 2016

FINANCIAL CHARGES AND OTHER

Schedule of components of financial charges and other

	Three months ended
(unaudited)	March 31,
(millions of dollars)	2017 (c )	2016 (c )
Interest Expense (a)	17	18
PNGTS’ amortization of derivative loss on derivative instruments (Note 11) (b)	—	—
Net realized loss related to the interest rate swaps (b)	—	—
Other Income (b)	—	—
	17	18

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

(b)      Nil million for both periods.

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

Year ended December 31 (millions of dollars)	2016(a)		2015(a)		2014(a)
Interest expense (b)	69		65		59
Net realized loss related to the interest rate swaps	3		2		2
PNGTS’ amortization of realized loss on derivative instrument (Note 18)	1		1		1
Other	(2	)	(5	)	(1	)
	71		63		61

(a) Recast to consolidate PNGTS for all periods presented.

(b) Effective January 1, 2016, interest expense includes amortization of debt issuance costs and discount costs. Refer to Note 3.

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NET INCOME (LOSS) PER COMMON UNIT (Tables)

3 Months Ended

12 Months Ended

Mar. 31, 2017

Dec. 31, 2016

NET INCOME PER COMMON UNIT

Schedule of net income (loss) 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 (a)	77			74
Net income attributable to PNGTS’ former parent (a) (b)	(2		)	(1		)
Net income allocable to General Partner and Limited Partners	75			73
Net income attributable to the General Partner	(1		)	(1		)
Incentive distributions attributable to the General Partner (c)	(2		)	(1		)
Net income attributable to common units	72			71
Weighted average common units outstanding (millions) — basic and diluted (d)	68.3			64.4
Net income per common unit — basic and diluted (e)	$	1.05		$	1.10

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

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

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

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

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

(millions of dollars, except per common unit amounts)	2016			2015			2014
Net income attributable to controlling interests (a)	248			37			195
Net income attributable to PNGTS’ former parent (a) (b)	(4		)	(24		)	(23		)
Net income allocable to General Partner and Limited Partners	244			13			172
Incentive distributions attributable to the General Partner (c)	(7		)	(3		)	(1		)
Net income attributable to the Class B units (d)	(22		)	(12		)	—
Net income (loss) allocable to the General Partner and common units	215			(2		)	171
Net income (loss) allocable to the General Partner’s two percent interest	(4		)	—			(3		)
Net income (loss) attributable to common units	211			(2		)	168
Weighted average common units outstanding (millions) — basic and diluted	65.7		(e)	63.9			62.7
Net income (loss) per common unit — basic and diluted (f)	$	3.21		$	(0.03	)	$	2.67

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

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

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

^(d) As discussed in Note 9, the Class B units entitle TransCanada to a distribution which is an amount based on 30 percent of GTN’s distributions after exceeding certain annual thresholds. The distribution will be payable in the first quarter with respect to the prior year’s distributions. Consistent with the application of Accounting Standards Codification (ASC) Topic 260 — “Earnings per share”, the Partnership allocated a portion of net income attributable to controlling interests to the Class B units in an amount equal to 30 percent of GTN’s total distributable cash flows during the year ended December 31, 2016 less the threshold level of $20 million (2015 - less $15 million). During the year ended December 31, 2016, 30 percent of GTN’s total distributable cash flow was $42 million. As a result of exceeding the threshold level of $20 million, $22 million of net income attributable to controlling interests was allocated to the Class B units at December 31, 2016 (2015 - $12 million). Refer to Note 9.

^(e) Includes the common units subject to rescission. These units are treated as outstanding for financial reporting purposes. Refer to Note 9.

^(f) Net income (loss) per common unit prior to recast.

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CASH DISTRIBUTIONS (Tables)

12 Months Ended

Dec. 31, 2016

CASH DISTRIBUTIONS TO COMMON UNITS

Schedule of allocations of available cash from operating surplus between common unitholders and General Partner

		Marginal Percentage Interest in Distribution
	Total Quarterly Distribution Per Unit Target Amount	Common Unitholders		General Partner
Minimum Quarterly Distribution	$0.45	98	%	2	%
First Target Distribution	above $0.45 up to $0.81	98	%	2	%
Second Target Distribution	above $0.81 up to $0.88	85	%	15	%
Thereafter	above $0.88	75	%	25	%

Schedule of distributions

The following table provides information about our distributions (in millions, except per unit distributions amounts).

				Limited Partners					General Partner
Declaration Date	Payment Date	Per Unit Distribution		Common Units		Class B Units(c)			2%		IDRs(a)		Total Cash Distribution
1/16/2014	2/14/2014	$	0.81	$	50	$	—		$	1	$	—	$	51
4/25/2014	5/15/2014	$	0.81	$	51	$	—		$	1	$	—	$	52
7/23/2014	8/14/2014	$	0.84	$	53	$	—		$	1	$	—	$	54
10/23/2014	11/14/2014	$	0.84	$	53	$	—		$	1	$	1	$	55
1/22/2015	2/13/2015	$	0.84	$	54	$	—		$	1	$	—	$	55
4/23/2015	5/15/2015	$	0.84	$	54	$	—		$	1	$	—	$	55
7/23/2015	8/14/2015	$	0.89	$	56	$	—		$	2	$	1	$	59
10/22/2015	11/13/2015	$	0.89	$	57	$	—		$	1	$	1	$	59
1/21/2016	2/12/2016	$	0.89	$	57	$	12	(d)	$	1	$	1	$	71
4/21/2016	5/13/2016	$	0.89	$	58	$	—		$	1	$	1	$	60
7/21/2016	8/12/2016	$	0.94	$	62	$	—		$	1	$	2	$	65
10/20/2016	11/14/2016	$	0.94	$	63	$	—		$	1	$	2	$	66
1/23/2017 (b)	2/14/2017 (b)	$	0.94	$	64	$	22	(e)	$	2	$	2	$	90

^(a) The distributions paid for the year ended December 31, 2016 included incentive distributions to the General Partner of $6 million (2015 - $2 million, 2014 - $1 million).

^(b) On February 14, 2017, we paid a cash distribution of $0.94 per unit on our outstanding common units to unitholders of record at the close of business on February 2, 2017 (refer to Note 24).

^(c) The Class B units issued by us on April 1, 2015 represent limited partner interests in us and entitle TransCanada to an annual distribution which is an amount based on 30 percent of GTN’s annual distributions after exceeding certain annual thresholds (refer to Note 6 and 9).

^(d) On February 12, 2016, we paid TransCanada $12 million representing 30 percent of GTN’s total distributable cash flows for the nine months ended December 31, 2015 less $15 million.

^(e) On February 14, 2017, we paid TransCanada $22 million representing 30 percent of GTN’s total distributable cash flows for the year ended December 31, 2016 less $20 million (refer to Note 9 and 24).

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CHANGE IN OPERATING WORKING CAPITAL (Tables)

3 Months Ended

12 Months Ended

Mar. 31, 2017

Dec. 31, 2016

CHANGE IN OPERATING WORKING CAPITAL

Schedule of change in operating working capital

(unaudited)	Three months ended March 31,
(millions of dollars)	2017 (b)		2016 (b)
Change in accounts receivable and other	7		(2	)
Change in other current assets	1		3
Change in accounts payable and accrued liabilities	(3	)	3	(a)
Change in accounts payable to affiliates	(1	)	(4	)
Change in state income taxes payable	—		9
Change in accrued interest	3		5
Change in operating working capital	7		14

^(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.

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

Year Ended December 31 (millions of dollars)	2016 (c)		2015(c)		2014(c)
Change in accounts receivable and other	(4	)	6		2
Change in other current assets	(4	)	(1	)	(1	)
Change in accounts payable and accrued liabilities (a)	5		(2	)	29
Change in accounts payable to affiliates	—		(15	) (b)	(6	)
Change in state income taxes payable	—		(5	)	2
Change in accrued interest	2		(3	)	3
Change in operating working capital	(1	)	(20	)	29

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

^(b) Excludes certain non-cash items primarily related to accruals of $10 million for construction of GTN’s Carty Lateral and $2 million of costs related to acquisition of 49.9 percent interest in PNGTS (Refer to Note 6).

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

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TRANSACTIONS WITH MAJOR CUSTOMERS (Tables)

12 Months Ended

Dec. 31, 2016

TRANSACTIONS WITH MAJOR CUSTOMERS

Schedule of revenues from major customers

Year Ended December 31 (millions of dollars)	2016		2015	2014
Anadarko Energy Services Company (Anadarko)	48		48	48
Pacific Gas and Electric Company (Pacific Gas)	36	(a)	42	45

^(a) Less than 10 percent

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RELATED PARTY TRANSACTIONS (Tables)

3 Months Ended

12 Months Ended

Mar. 31, 2017

Dec. 31, 2016

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) (c)	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 (c)	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.

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

Year ended December 31 (millions of dollars)	2016	2015	2014
Capital and operating costs charged by TransCanada’s subsidiaries to:
Great Lakes (a)	30	30	30
Northern Border (a)	32	36	35
PNGTS (a) (b)	8	8	8
GTN (a) (c)	27	30	30
Bison (a) (d)	2	4	6
North Baja	4	5	5
Tuscarora	5	4	4
Impact on the Partnership’s net income attributable to controlling interests:
Great Lakes	13	13	13
Northern Border	12	14	16
PNGTS (b)	5	5	5
GTN (c)	24	25	19
Bison (d)	3	4	4
North Baja	4	5	4
Tuscarora	4	4	4

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) (c)	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.

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

December 31 (millions of dollars)	2016	2015
Amount payable to TransCanada’s subsidiaries for costs charged in the year by:
Great Lakes (a)	4	3
Northern Border (a)	4	5
PNGTS (a) (b)	1	3
GTN	3	3
Bison	1	—
North Baja	1	—
Tuscarora	1	1

^(a) Represents 100 percent of the costs.

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

^(c) In 2015, the Partnership acquired the remaining 30 percent interest in GTN (Refer to Note 6).

^(d) In 2014, the Partnership acquired the remaining 30 percent interest in Bison (Refer to Note 6).

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QUARTERLY FINANCIAL DATA (unaudited) (Tables)

12 Months Ended

Dec. 31, 2016

QUARTERLY FINANCIAL DATA (unaudited)

Schedule of selected unaudited financial data

Quarter ended (millions of dollars except per common unit amounts)	Mar 31		Jun 30		Sept 30		Dec 31
2016
Transmission revenues (a)	111		101		103		111
Equity earnings (a) (b ) (c)	33		20		22		22
Net income (a)	81		57		60		65
Net income attributable to controlling interests (a)	74		55		58		61
Net income per common unit (d)	$	1.10	$	0.76	$	0.65	$	0.70
Cash distribution paid (f)	71		60		65		66
2015
Transmission revenues (a)	114		97		96		110
Equity earnings (e)	31		15		17		34
Impairment of equity-method investment (b)	—		—		—		(199		)
Net income (loss) (a)	81		47		54		(124		)
Net income (loss) attributable to controlling interests (a)	67		46		52		(128		)
Net income (loss) per common unit (d)	$	0.88	$	0.66	$	0.70	$	(2.27	)
Cash distribution paid (f)	55		55		59		59

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

^(b) Equity Earnings represents our share in investee’s earnings and does not include any impairment charge on equity method goodwill included as part of the carrying value of our equity investments.

^(c) During the year ended December 31, 2016, no impairment has been identified related to our equity investments in Northern Border and Great Lakes.

^(d) Historical net income (loss) per common unit was not recasted.

^(e) During the three months ended December 31, 2015, we recognized an impairment charge on our investment in Great Lakes amounting to $199 million. During the year ended December 31, 2015, no impairment has been identified on our investment in Northern Border (Refer to Note 4).

^(f) Distributions paid to common units and Class B units.

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ACCOUNTS RECEIVABLE AND OTHER (Tables)

3 Months Ended

12 Months Ended

Mar. 31, 2017

Dec. 31, 2016

ACCOUNTS RECEIVABLE AND OTHER

Schedule of accounts receivable and other

(unaudited)
(millions of dollars)	March 31, 2017 (a)	December 31, 2016 (a)
Trade accounts receivable, net of allowance of nil	38	44
Imbalance receivable from affiliates	1	2
Other	2	1
	41	47

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

December 31 (millions of dollars)	2016 (a)	2015(a)
Trade accounts receivable, net of allowance of nil	44	40
Imbalance receivable from affiliates	2	1
Other	1	—
	47	41

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

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VARIABLE INTEREST ENTITIES (Tables)

3 Months Ended

12 Months Ended

Mar. 31, 2017

Dec. 31, 2016

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 (b)		December 31, 2016 (b)
ASSETS (LIABILITIES) *
Cash and cash equivalents	18		14
Accounts receivable and other	28		33
Inventories	6		6
Other current assets	4		6
Equity investments	930		918
Plant, property and equipment	1,140		1,146
Other assets	2		2
Accounts payable and accrued liabilities	(20	)	(21	)
Accounts payable to affiliates, net	(24	)	(32	)
Distributions payable	(3	)	(3	)
Accrued interest	(5	)	(2	)
State income tax payable	(1	)	—
Current portion of long-term debt	(46	)	(52	)
Long-term debt	(330	)	(337	)
Other liabilities	(26	)	(25	)
Deferred state income tax	(10	)	(10	)

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

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

(millions of dollars)	December 31, 2016(b)		December 31, 2015(b)
ASSETS (LIABILITIES) (a)
Cash and cash equivalents	14		16
Accounts receivable and other	33		29
Inventories	6		6
Other current assets	6		6
Equity investments	918		965
Plant, property and equipment	1,146		1,180
Other assets	2		2
Accounts payable and accrued liabilities	(21	)	(27	)
Accounts payable to affiliates, net	(32	)	(9	)
Distributions payable	(3	)	(10	)
Accrued interest	(2	)	(1	)
Current portion of long-term debt	(52	)	(36	)
Long-term debt	(337	)	(373	)
Other liabilities	(25	)	(24	)
Deferred state income tax	(10	)	(11	)

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

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

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INCOME TAXES (Tables)

3 Months Ended

12 Months Ended

Mar. 31, 2017

Dec. 31, 2016

INCOME TAXES

Schedule of state income taxes of PNGTS

	Three months ended
(unaudited)	March 31,
(millions of dollars)	2017 (a)	2016 (a)
State income taxes
Current	1	8
Deferred	—	(7	)
	1	1

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

Year ended December 31 (millions of dollars)	2016 (a)	2015 (a)		2014(a)
State income taxes
Current	1	(2	)	3
Deferred	—	4		(1	)
	1	2		2

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

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ORGANIZATION - Ownership Interests in Natural Gas Pipeline Systems (Details)		3 Months Ended	12 Months Ended
	Jun. 01, 2017	Mar. 31, 2017 LimitedPartnership	Dec. 31, 2016 LimitedPartnership mi	Jul. 31, 2017	Jun. 30, 2017	May 31, 2017	Apr. 28, 2017	Jan. 31, 2016	Jan. 01, 2016
Organization
Number of intermediate limited partnerships through which pipeline assets are owned | LimitedPartnership		3	3
Northern Border
Organization
Remaining ownership interest (as a percent)			50.00%
Interest acquired (as a percent)		50.00%	50.00%	50.00%	50.00%	50.00%	50.00%
Portland Natural Gas Transmission System
Organization
Interest acquired (as a percent)								49.90%
TransCanada | Portland Natural Gas Transmission System
Organization
Remaining noncontrolling ownership interest (as a percent)			38.29%
Portland Natural Gas Transmission System
Organization
Interest acquired (as a percent)	11.81%								49.90%
GTN
Organization
Length of pipeline owned (in miles)			1,377
Remaining ownership interest (as a percent)			100.00%
Bison
Organization
Length of pipeline owned (in miles)			303
Remaining ownership interest (as a percent)			100.00%
North Baja Pipeline, LLC
Organization
Length of pipeline owned (in miles)			86
Ownership interest (as a percent)			100.00%
Tuscarora Gas Transmission Company
Organization
Length of pipeline owned (in miles)			305
Ownership interest (as a percent)			100.00%
Northern Border
Organization
Length of pipeline owned (in miles)			1,412
Ownership interest (as a percent)			50.00%
Portland Natural Gas Transmission System
Organization
Length of pipeline owned (in miles)			295
Ownership interest (as a percent)			61.71%
Great Lakes
Organization
Length of pipeline owned (in miles)			2,115
Ownership interest (as a percent)			46.45%
Great Lakes | TransCanada
Organization
Remaining noncontrolling ownership interest (as a percent)			53.55%
Iroquois
Organization
Length of pipeline owned (in miles)			416
Ownership interest (as a percent)			49.34%
Remaining ownership interest (as a percent)			50.66%
Iroquois | TransCanada
Organization
Remaining ownership interest (as a percent)			0.66%
Iroquois | Dominion Midstream
Organization
Remaining ownership interest (as a percent)			25.93%
Iroquois | Dominion Energy
Organization
Remaining ownership interest (as a percent)			24.07%
ONEOK Partners, L.P. | Northern Border
Organization
Remaining ownership interest (as a percent)			50.00%
Subsequent event | Portland Natural Gas Transmission System
Organization
Ownership interest (as a percent)	11.81%
Subsequent event | Portland Natural Gas Transmission System
Organization
Ownership interest, including acquired interest (as a percent)	61.71%

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ORGANIZATION - Capitalization (Details) - shares			3 Months Ended	9 Months Ended		12 Months Ended
		Apr. 01, 2015	Mar. 31, 2017	Sep. 30, 2016	Sep. 30, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Apr. 25, 2017	Mar. 31, 2016
Common units
Partners' Equity
Number of units	[1]		68,600,000			67,400,000	64,300,000	63,600,000		64,700,000
General Partner | TC PipeLines GP, Inc.
Partners' Equity
IDRs ownership (as a percent)						100.00%
Ownership interest in the Partnership (as a percent)		2.00%	2.00%	2.00%	2.00%	2.00%	2.00%	2.00%
Limited Partners | Common units
Partners' Equity
Number of units						67,454,831
Limited Partners | Common units | TC PipeLines GP, Inc.
Partners' Equity
Number of units						5,797,106			5,797,106
Limited Partners | Common units | TransCanada
Partners' Equity
Number of units						11,287,725
Limited partner interest (as a percent)						25.30%
Limited Partners | Class B units | TransCanada
Partners' Equity
Number of units						1,900,000
Limited partner interest (as a percent)						100.00%

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

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SIGNIFICANT ACCOUNTING POLICIES - Ownership Interests Acquired (Details)	Aug. 01, 2017	Jun. 01, 2017	Dec. 31, 2016	Jan. 31, 2016	Jan. 01, 2016	Dec. 31, 2015	Apr. 01, 2015	Mar. 31, 2015	Oct. 01, 2014	Sep. 30, 2014
Portland Natural Gas Transmission System
Acquisitions
Ownership interest (as a percent)				49.90%
Iroquois
Acquisitions
Ownership interest (as a percent)	49.34%	49.34%
Former parent, TransCanada subsidiaries | Portland Natural Gas Transmission System | Transaction between entities under common control
Acquisitions
Interest acquired (as a percent)					49.90%
TransCanada | Portland Natural Gas Transmission System
Acquisitions
Remaining noncontrolling ownership interest (as a percent)			38.29%
TransCanada | GTN
Acquisitions
Remaining noncontrolling ownership interest (as a percent)								30.00%
TransCanada | Bison
Acquisitions
Remaining noncontrolling ownership interest (as a percent)										30.00%
Portland Natural Gas Transmission System
Acquisitions
Ownership interest (as a percent)		11.81%			49.90%
Interest acquired (as a percent)		61.71%
Portland Natural Gas Transmission System | Former parent, TransCanada subsidiaries | Transaction between entities under common control
Acquisitions
Interest acquired (as a percent)			30.00%		49.90%	49.90%
GTN | Former parent, TransCanada subsidiaries | Transaction between entities under common control
Acquisitions
Interest acquired (as a percent)							30.00%
Bison | Former parent, TransCanada subsidiaries | Transaction between entities under common control
Acquisitions
Interest acquired (as a percent)			30.00%				30.00%		30.00%
Subsequent event | Portland Natural Gas Transmission System
Acquisitions
Interest acquired (as a percent)		11.81%
Subsequent event | Iroquois
Acquisitions
Ownership interest (as a percent)	49.34%
Subsequent event | Portland Natural Gas Transmission System
Acquisitions
Ownership interest, including acquired interest (as a percent)		61.71%
Subsequent event | Portland Natural Gas Transmission System | Transaction between entities under common control
Acquisitions
Ownership interest, including acquired interest (as a percent)		61.71%

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SIGNIFICANT ACCOUNTING POLICIES - Useful Lives of Plant, Property and Equipment (Details)	12 Months Ended
	Dec. 31, 2016
Pipeline facilities and compression equipment | Minimum
PLANT, PROPERTY AND EQUIPMENT
Estimated useful lives	20 years
Pipeline facilities and compression equipment | Maximum
PLANT, PROPERTY AND EQUIPMENT
Estimated useful lives	77 years
Metering and other equipment | Minimum
PLANT, PROPERTY AND EQUIPMENT
Estimated useful lives	5 years
Metering and other equipment | Maximum
PLANT, PROPERTY AND EQUIPMENT
Estimated useful lives	77 years

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SIGNIFICANT ACCOUNTING POLICIES - Revenue Recognition (Details) - Portland Natural Gas Transmission System $ in Millions		13 Months Ended
	Feb. 19, 2015 USD ($)	Jan. 31, 2015 item
Revenue Recognition
Outstanding rate cases | item		2
Maximum number of days to refund to customers	60 days
Accumulated refunds	$ 114.3
Interest on refund	$ 8.0

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SIGNIFICANT ACCOUNTING POLICIES - Impairment of Equity Method Investments (Details) - USD ($) $ in Millions	3 Months Ended	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2015
EQUITY INVESTMENTS
Impairment of equity-method investment	$ 199	$ 199	[1]
Great Lakes | Nonrecurring fair value measurement
EQUITY INVESTMENTS
Impairment of equity-method investment	$ 199	$ 199

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

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SIGNIFICANT ACCOUNTING POLICIES - Acquisitions and Goodwill (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2016	Mar. 31, 2017	Dec. 31, 2015
Acquisitions and Goodwill
Goodwill	[1]	$ 130	$ 130	$ 130
Impairment of goodwill		0
North Baja Pipeline, LLC
Acquisitions and Goodwill
Goodwill		48		48
Tuscarora Gas Transmission Company
Acquisitions and Goodwill
Goodwill		$ 82		$ 82

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

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SIGNIFICANT ACCOUNTING POLICIES - Asset Retirement Obligation and Regulatory Assets (Details) - USD ($)	Dec. 31, 2016	Dec. 31, 2015
Accounts receivable and other
Regulatory assets and liabilities
Regulatory assets	$ 1,000,000	$ 2,000,000
Pipeline
Asset Retirement Obligation
Asset retirement liabilities	$ 0	$ 0

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ACCOUNTING PRONOUNCEMENTS - Imputation of Interest (Details) - USD ($) $ in Millions		Mar. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
ACCOUNTING PRONOUNCEMENTS
Other assets (Note 3)	[1]	$ 1	$ 1	$ 1
Debt issuance costs		$ 8	$ 9	9
ASU 2015-03, Interest - Imputation of Interest | Adjustment
ACCOUNTING PRONOUNCEMENTS
Other assets (Note 3)				(8)
Debt issuance costs				$ (8)

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

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ACCOUNTING PRONOUNCEMENTS - Statement of Cash Flows (Details) - USD ($) $ in Millions		3 Months Ended	12 Months Ended
		Mar. 31, 2016	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
ACCOUNTING PRONOUNCEMENTS.
Distributed earnings received from equity investments	[1]		$ (153)	$ (119)	$ (115)
Adjustment | ASU 2016-15, Statement of Cash Flows
ACCOUNTING PRONOUNCEMENTS.
Cumulative distributions in excess of equity earnings		$ (8)
Adjustment | Early Adoption | ASU 2016-15, Statement of Cash Flows
ACCOUNTING PRONOUNCEMENTS.
Cumulative distributions in excess of equity earnings				(25)	(27)
Distributed earnings received from equity investments				$ (25)	$ (27)

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

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EQUITY INVESTMENTS (Details) - USD ($) $ in Millions			1 Months Ended		3 Months Ended										12 Months Ended
		Dec. 31, 2015	Aug. 31, 2016	Apr. 30, 2006	Mar. 31, 2017		Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2016		Dec. 31, 2015		Dec. 31, 2014		Aug. 01, 2017	Jul. 31, 2017	Jun. 30, 2017	May 31, 2017	May 01, 2017	Apr. 28, 2017
EQUITY INVESTMENTS
Equity Earnings					$ 36	[1]	$ 22	$ 22	$ 20	$ 33	$ 34	$ 17	$ 15	$ 31	$ 97	[1]	$ 97	[1]	$ 88	[1]
Equity Investments	[1]	$ 965			930		918				965				918		965
Impairment of equity-method investment											199						199	[1]
LIABILITIES AND PARTNERS' EQUITY
Current portion of long-term debt	[1]	36			46		52				36				52		36
Amount borrowed	[1]									195					$ 209		618		35
Northern Border
EQUITY INVESTMENTS
Partnership interest held (as a percent)															50.00%
LIABILITIES AND PARTNERS' EQUITY
Current portion of long-term debt		100	$ 100								100						100
Northern Border | Revolving credit facility | Revolving Credit Agreement Expiring 2020
LIABILITIES AND PARTNERS' EQUITY
Amount borrowed			$ 200
Great Lakes
EQUITY INVESTMENTS
Partnership interest held (as a percent)															46.45%
Total cash call issued to fund debt repayment					$ 9		10			9	10			$ 9
LIABILITIES AND PARTNERS' EQUITY
Current portion of long-term debt		19					$ 19				19				$ 19		19
Northern Border
EQUITY INVESTMENTS
Ownership interest (as a percent)					50.00%		50.00%								50.00%							50.00%	50.00%	50.00%		50.00%
Equity Earnings					$ 19					18					$ 69		66		69
Equity Investments		480			441		$ 444				480				$ 444		480
Amortization period of transaction fee				12 years
Transaction fee				$ 10
Additional ownership interest acquired (as a percent)				20.00%
Ownership interest (as a percent)							50.00%								50.00%
Undistributed earnings															$ 0		0		0
Amount of difference between the carrying value and the underlying equity in net assets resulting from the recognition and inclusion of goodwill		116					$ 116				116				116		116
Assets
Cash and cash equivalents		27			18		14				27				14		27
Other current assets		33			36		36				33				36		33
Plant, property and equipment, net		1,124			1,085		1,089				1,124				1,089		1,124
Other assets		16			15		14				16				14		16
Assets, total		1,200			1,154		1,153				1,200				1,153		1,200
LIABILITIES AND PARTNERS' EQUITY
Current liabilities		39			44		38				39				38		39
Deferred credits and other		26			29		28				26				28		26
Long-term debt, net		409			430		430				409				430		409
Partners' equity
Partners' equity		728			653		659				728				659		728
Accumulated other comprehensive loss		(2)			(2)		(2)				(2)				(2)		(2)
Liabilities and Partners' Equity, total		1,200			1,154		$ 1,153				$ 1,200				1,153		1,200
Revenues (expenses)
Transmission revenues					74					74					292		286		293
Operating expenses					(17)					(16)					(72)		(70)		(72)
Depreciation					(15)					(15)					(59)		(60)		(59)
Financial charges and other					(4)					(6)					(21)		(22)		(22)
Net income					$ 38					37					140		$ 134		140
Northern Border | Nonrecurring fair value measurement
EQUITY INVESTMENTS
Impairment of equity-method investment		$ 0													$ 0
Northern Border | ONEOK Partners, L.P.
EQUITY INVESTMENTS
Ownership interest (as a percent)							50.00%								50.00%
Great Lakes
EQUITY INVESTMENTS
Ownership interest (as a percent)		46.45%			46.45%		46.45%				46.45%			46.45%	46.45%		46.45%				46.45%				46.45%
Equity Earnings					$ 17					15					$ 28		$ 31		19
Equity Investments		$ 485			489		$ 474				$ 485				474		485
Undistributed earnings															0		0		0
Equity contribution					4	[1]	5			4	5			$ 4	9	[1]	9	[1]	9	[1]
Assets
Current assets		86			86		66				86				66		86
Plant, property and equipment, net		727			708		714				727				714		727
Assets, total		813			794		780				813				780		813
LIABILITIES AND PARTNERS' EQUITY
Current liabilities		31			31		40				31				40		31
Long-term debt, net		297			269		278				297				278		297
Partners' equity
Partners' equity		485			494		462				485				462		485
Liabilities and Partners' Equity, total		813			794		$ 780				813				780		813
Revenues (expenses)
Transmission revenues					63					61					179		177		146
Operating expenses					(14)					(15)					(69)		(59)		(53)
Depreciation					(7)					(7)					(28)		(28)		(28)
Financial charges and other					(5)					(6)					(21)		(23)		(25)
Net income					$ 37					$ 33					$ 61		67		$ 40
Great Lakes | Nonrecurring fair value measurement
EQUITY INVESTMENTS
Impairment of equity-method investment											199						199
Amount of difference between the carrying value and the underlying equity in net assets resulting from the recognition and inclusion of goodwill		260									260						260
Great Lakes | TransCanada
EQUITY INVESTMENTS
Ownership interest (as a percent)							53.55%								53.55%
TC PipeLines Intermediate Limited Partnership
EQUITY INVESTMENTS
Partnership interest held (as a percent)															98.9899%
TC GL Intermediate Limited Partnership
EQUITY INVESTMENTS
Partnership interest held (as a percent)															98.9899%
ASU 2015-03, Interest - Imputation of Interest | Adjustment | Northern Border
Assets
Other assets		(2)									(2)						(2)
LIABILITIES AND PARTNERS' EQUITY
Long-term debt, net		$ (2)									$ (2)						$ (2)

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

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PLANT, PROPERTY AND EQUIPMENT (Details) - USD ($) $ in Millions		Mar. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
PLANT, PROPERTY AND EQUIPMENT
Cost			$ 3,268	$ 3,254
Accumulated Depreciation		$ (1,112)	(1,088)	(997)
Net Book Value	[1]	$ 2,162	2,180	2,257
Pipeline
PLANT, PROPERTY AND EQUIPMENT
Cost			2,540	2,535
Accumulated Depreciation			(879)	(806)
Net Book Value			1,661	1,729
Compression
PLANT, PROPERTY AND EQUIPMENT
Cost			519	516
Accumulated Depreciation			(148)	(134)
Net Book Value			371	382
Metering and other equipment
PLANT, PROPERTY AND EQUIPMENT
Cost			205	201
Accumulated Depreciation			(61)	(57)
Net Book Value			144	144
Construction in progress
PLANT, PROPERTY AND EQUIPMENT
Cost			4	2
Net Book Value			$ 4	$ 2

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

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ACQUISITIONS - Acquisition of Ownership Interest in PNGTS (Details) - Portland Natural Gas Transmission System - USD ($) $ in Millions			3 Months Ended
		Jan. 01, 2016	Mar. 31, 2016	Jan. 31, 2016
Acquisition
Interest acquired (as a percent)				49.90%
Net purchase price	[1]		$ 193
TransCanada | Transaction between entities under common control
Acquisition
Total purchase price		$ 228
Net purchase price		193
Less: TransCanada's carrying value of non-controlling interest		120
Excess purchase price		73
Purchase price adjustments		5
Assumption of proportional debt		35
Additional contingent payment, minimum		5
Additional contingent payment, maximum		$ 50
Period following closing date during which additional payments may be required		15 years

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

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ACQUISITIONS - 2015 GTN Acquisition Summary and Terms of New Class B Units (Details) - USD ($)				3 Months Ended	9 Months Ended	12 Months Ended
		Feb. 14, 2017	Apr. 01, 2015	Mar. 31, 2017	Dec. 31, 2015	Dec. 31, 2016	Dec. 31, 2015	Mar. 31, 2015
Acquisition
Equity contribution	[1]						$ 2,000,000
TransCanada | GTN
Noncontrolling interest
Remaining noncontrolling ownership interest (as a percent)								30.00%
General Partner
Acquisition
Equity contribution			$ 2,000,000				2,000,000
GTN
Acquisition
Reduction in Partners' Equity	[1]						359,000,000
GTN | General Partner
Acquisition
Reduction in Partners' Equity							3,000,000
GTN | Former parent, TransCanada subsidiaries | Transaction between entities under common control
Acquisition
Interest acquired (as a percent)			30.00%
Purchase price adjustments			$ 11,000,000
Purchase price			457,000,000
Total cash consideration			264,000,000
Assumption of proportional debt			98,000,000
Net purchase price			359,000,000
Less: TransCanada's carrying value of non-controlling interest			232,000,000
Excess purchase price			127,000,000
GTN | Former parent, TransCanada subsidiaries | Transaction between entities under common control | As previously recast
Acquisition
Purchase price			446,000,000
GTN | Former parent, TransCanada subsidiaries | Transaction between entities under common control | General Partner
Acquisition
Reduction in Partners' Equity			$ 127,000,000
Partnership interest | Class B units | GTN | Former parent, TransCanada subsidiaries | Transaction between entities under common control
Acquisition
Units issued (in units)			1,900,000
Value per unit (in dollars per unit)			$ 50
Equity issuance			$ 95,000,000
GTN | Class B units | TransCanada | Distributions
Distributions
Portion of GTN's annual distributions to which the Class B units are entitled to receive a percentage share of the distributions above threshold (as a percent)			30.00%	30.00%		30.00%
Percentage applied to 30 percent of GTN's distributions above threshold through March 31, 2020			100.00%	100.00%
Threshold of 30 percent of GTN's annual distributions for payment to Class B units at specified percentage			$ 20,000,000	$ 20,000,000		$ 20,000,000	15,000,000
Percentage applied to 30 percent of GTN's distributions above threshold after March 31, 2020			25.00%	25.00%
Percentage applied to GTN's distributable cash flow				30.00%	30.00%	30.00%
Threshold of GTN's distributions for payment to Class B units		$ 20,000,000		$ 20,000,000	$ 15,000,000	$ 20,000,000	$ 15,000,000

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

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ACQUISITIONS - 2014 Bison Acquisition (Details) - USD ($) $ in Millions			12 Months Ended
		Oct. 01, 2014	Dec. 31, 2014	Dec. 31, 2016	Apr. 01, 2015	Sep. 30, 2014
Bison
Acquisitions
Reduction in Partners' Equity	[1]		$ 217
Bison | Limited Partners | Common units
Acquisitions
Reduction in Partners' Equity			$ 29
Bison | Former parent, TransCanada subsidiaries | Transaction between entities under common control
Acquisitions
Interest acquired (as a percent)		30.00%		30.00%	30.00%
Purchase price adjustments		$ 2
Total cash consideration		217
TransCanada's carrying value of non-controlling interest		188
Excess purchase price		29
Bison | Former parent, TransCanada subsidiaries | Transaction between entities under common control | As previously recast
Acquisitions
Purchase price		215
Bison | Former parent, TransCanada subsidiaries | Limited Partners | Transaction between entities under common control | Common units
Acquisitions
Reduction in Partners' Equity		$ 29
Bison | TransCanada
Acquisitions
Remaining noncontrolling ownership interest (as a percent)						30.00%

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

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DEBT AND CREDIT FACILITIES - Amounts Outstanding and Description of Terms (Details) - USD ($)								3 Months Ended		12 Months Ended
		Jan. 03, 2017	Dec. 31, 2016	Sep. 30, 2015	Mar. 13, 2015	Jul. 02, 2013	Jul. 01, 2013	Mar. 31, 2017	Mar. 31, 2016	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Apr. 29, 2016	Jun. 01, 2015
Credit facilities, short-term loan facility and long-term debt
Other assets (Note 3)	[1]		$ 1,000,000					$ 1,000,000		$ 1,000,000	$ 1,000,000
Long-term debt			1,920,000,000					1,858,000,000		1,920,000,000
Debt and credit facilities			1,920,000,000					1,858,000,000		1,920,000,000
Less: unamortized debt issuance costs and debt discount			9,000,000					8,000,000		9,000,000	9,000,000
Less: current portion	[1]		52,000,000					46,000,000		52,000,000	36,000,000
Total credit facilities, short-term loan facility and long-term debt 10K			1,920,000,000							1,920,000,000	1,980,000,000
Long-term debt	[1]		$ 1,859,000,000					$ 1,804,000,000		1,859,000,000	1,935,000,000
Amount borrowed	[1]								$ 195,000,000	$ 209,000,000	618,000,000	$ 35,000,000
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)			401.00%					4.04%		401.00%
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		6 months
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%		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%		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			$ 160,000,000					$ 110,000,000		$ 160,000,000	$ 200,000,000
Weighted Average Interest Rate (as a percent)								2.03%		1.72%	1.44%
Maximum borrowing capacity			500,000,000					$ 500,000,000		$ 500,000,000
Amount outstanding under credit facility			160,000,000					110,000,000		160,000,000	$ 200,000,000
Remaining borrowing capacity			340,000,000					$ 390,000,000		340,000,000
Revolving credit facility | TC Pipelines, LP Senior Credit Facility due 2021 | Maximum
Credit facilities, short-term loan facility and long-term debt
Increase in credit facility			$ 500,000,000							$ 500,000,000
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)			1.92%					2.04%		1.92%	1.50%
Term loan | 2013 Term Loan Facility due 2018
Credit facilities, short-term loan facility and long-term debt
Debt and credit facilities			$ 500,000,000					$ 500,000,000		$ 500,000,000	$ 500,000,000
Weighted Average Interest Rate (as a percent)								2.03%		1.73%	1.44%
Amount of debt							$ 500,000,000
Borrowings under the facility						$ 500,000,000
Term loan | 2013 Term Loan Facility due 2018 | Base rate borrowings | Federal funds rate
Credit facilities, short-term loan facility and long-term debt
Basis spread on variable rate (as a percent)							0.50%
Term loan | 2013 Term Loan Facility due 2018 | Base rate borrowings | LIBOR
Credit facilities, short-term loan facility and long-term debt
Basis spread on variable rate (as a percent)							1.00%
Term loan | 2013 Term Loan Facility due 2018 | Base rate borrowings | Base rate | Minimum
Credit facilities, short-term loan facility and long-term debt
Basis spread on variable rate (as a percent)							0.125%
Term loan | 2013 Term Loan Facility due 2018 | Base rate borrowings | Base rate | Maximum
Credit facilities, short-term loan facility and long-term debt
Basis spread on variable rate (as a percent)							1.00%
Term loan | 2013 Term Loan Facility due 2018 | LIBOR borrowings | LIBOR
Credit facilities, short-term loan facility and long-term debt
Weighted Average Interest Rate (as a percent)										2.31%	2.79%
Debt interest rate, at period end (as a percent)			1.87%					2.04%		1.87%	1.50%
Term loan | 2013 Term Loan Facility due 2018 | LIBOR borrowings | LIBOR | Minimum
Credit facilities, short-term loan facility and long-term debt
Basis spread on variable rate (as a percent)							1.125%
Term loan | 2013 Term Loan Facility due 2018 | LIBOR borrowings | LIBOR | Maximum
Credit facilities, short-term loan facility and long-term debt
Basis spread on variable rate (as a percent)							2.00%
Term loan | TC PipeLines, LP 2015 Term Loan Facility due 2018
Credit facilities, short-term loan facility and long-term debt
Debt and credit facilities			$ 170,000,000					$ 170,000,000		$ 170,000,000	$ 170,000,000
Weighted Average Interest Rate (as a percent)								1.93%		1.63%	1.47%
Amount of debt				$ 170,000,000
Amount borrowed				$ 170,000,000
Term loan | TC PipeLines, LP 2015 Term Loan Facility due 2018 | LIBOR
Credit facilities, short-term loan facility and long-term debt
Debt interest rate, at period end (as a percent)			1.77%					1.93%		1.77%	1.39%
Unsecured debt | 4.65% Senior Notes due 2021
Credit facilities, short-term loan facility and long-term debt
Stated interest rate (as a percent)			4.65%					4.65%		4.65%	4.65%
Debt and credit facilities			$ 350,000,000					$ 350,000,000		$ 350,000,000	$ 350,000,000
Weighted Average Interest Rate (as a percent)								4.65%		4.65%	4.65%
Unsecured debt | TC PipeLines, LP 4.375% Senior Notes due 2025
Credit facilities, short-term loan facility and long-term debt
Stated interest rate (as a percent)			4.375%		4.375%			4.375%		4.375%	4.375%
Debt and credit facilities			$ 350,000,000					$ 350,000,000		$ 350,000,000	$ 350,000,000
Weighted Average Interest Rate (as a percent)								4.375%		4.375%	4.375%
Amount of debt					$ 350,000,000
Net proceeds					$ 346,000,000
Unsecured debt | GTN 5.29% Senior Notes due 2020
Credit facilities, short-term loan facility and long-term debt
Stated interest rate (as a percent)			5.29%					5.29%		5.29%	5.29%
Debt and credit facilities			$ 100,000,000					$ 100,000,000		$ 100,000,000
Weighted Average Interest Rate (as a percent)								5.29%		5.29%
Unsecured debt | GTN 5.69% Senior Notes due 2035
Credit facilities, short-term loan facility and long-term debt
Stated interest rate (as a percent)			5.69%					5.69%		5.69%	5.69%
Debt and credit facilities			$ 150,000,000					$ 150,000,000		$ 150,000,000
Weighted Average Interest Rate (as a percent)								5.69%		5.69%
Unsecured debt | 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		$ 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		$ 10,000,000
Weighted Average Interest Rate (as a percent)								1.91%		1.64%
Secured debt | PNGTS 5.90% Senior Secured Notes due December 2018
Credit facilities, short-term loan facility and long-term debt
Stated interest rate (as a percent)			5.90%							5.90%	5.90%
Secured debt | 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%		3.82%	3.82%
Debt and credit facilities			$ 12,000,000					$ 12,000,000		$ 12,000,000
Weighted Average Interest Rate (as a percent)								3.82%		3.82%
GTN
Credit facilities, short-term loan facility and long-term debt
Percentage of debt to total capitalization, actual			44.50%							44.50%
GTN | 5.09% Senior Notes due 2015
Credit facilities, short-term loan facility and long-term debt
Stated interest rate (as a percent)														5.09%
GTN | Unsecured debt | GTN 5.29% Senior Notes due 2020
Credit facilities, short-term loan facility and long-term debt
Debt and credit facilities			$ 100,000,000							$ 100,000,000	$ 100,000,000
Weighted Average Interest Rate (as a percent)										5.29%	5.29%
GTN | Unsecured debt | GTN 5.69% Senior Notes due 2035
Credit facilities, short-term loan facility and long-term debt
Debt and credit facilities			150,000,000							$ 150,000,000	$ 150,000,000
Weighted Average Interest Rate (as a percent)										5.69%	5.69%
GTN | Unsecured debt | Term Loan Facility due 2019
Credit facilities, short-term loan facility and long-term debt
Debt and credit facilities			$ 65,000,000							$ 65,000,000	$ 75,000,000
Weighted Average Interest Rate (as a percent)										1.43%	1.15%
GTN | Unsecured debt | Term Loan Facility due 2019 | LIBOR
Credit facilities, short-term loan facility and long-term debt
Debt interest rate, at period end (as a percent)			1.57%							1.57%	1.19%
Amount of debt														$ 75,000,000
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)			1.57%					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%		70.00%
Tuscarora Gas Transmission Company
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)										1.64%
Tuscarora Gas Transmission Company | Unsecured debt | Tuscarora Term Loan due 2019
Credit facilities, short-term loan facility and long-term debt
Amount of debt													$ 9,500,000
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)			1.90%					2.12%		1.90%
Tuscarora Gas Transmission Company | Unsecured debt | 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			21.22%					21.05%		21.22%
Debt Service Coverage, Actual (as a percent)			415.00%					3.92%
Tuscarora Gas Transmission Company | Unsecured debt | 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%					300.00%
Tuscarora Gas Transmission Company | Unsecured debt | 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%					45.00%
Tuscarora Gas Transmission Company | Secured debt | 3.82% Series D Senior Notes due 2017
Credit facilities, short-term loan facility and long-term debt
Debt and credit facilities			$ 12,000,000							$ 12,000,000	$ 16,000,000
Weighted Average Interest Rate (as a percent)										3.82%	3.82%
Portland Natural Gas Transmission System | PNGTS 5.90% Senior Secured Notes due December 2018
Credit facilities, short-term loan facility and long-term debt
Debt and credit facilities			53,000,000					$ 41,000,000		$ 53,000,000
Payment of principal amount on secured notes		$ 5,500,000
Weighted Average Interest Rate (as a percent)								5.90%		5.90%
Portland Natural Gas Transmission System | PNGTS 5.90% Senior Secured Notes due December 2018 | Subsequent event
Credit facilities, short-term loan facility and long-term debt
Payment of principal amount on secured notes		$ 5,500,000
Portland Natural Gas Transmission System | Secured debt | PNGTS 5.90% Senior Secured Notes due December 2018
Credit facilities, short-term loan facility and long-term debt
Debt and credit facilities			$ 53,000,000							$ 53,000,000	$ 69,000,000
Weighted Average Interest Rate (as a percent)										5.90%	5.90%
Debt Service, number of months of guarantee										6 months
Portland Natural Gas Transmission System | Secured debt | PNGTS 5.90% Senior Secured Notes due December 2018 | Debt agreement covenants, preceding twelve months
Credit facilities, short-term loan facility and long-term debt
Debt Service Coverage, Actual (as a percent)								1.86%		2.41%
Portland Natural Gas Transmission System | Secured debt | PNGTS 5.90% Senior Secured Notes due December 2018 | Debt agreement covenants, preceding twelve months | Minimum
Credit facilities, short-term loan facility and long-term debt
Debt Service Coverage, covenant (as a percent)								1.30%		1.30%
Portland Natural Gas Transmission System | Secured debt | PNGTS 5.90% Senior Secured Notes due December 2018 | Debt agreement covenants, succeeding twelve months
Credit facilities, short-term loan facility and long-term debt
Debt Service Coverage, Actual (as a percent)								1.52%		1.43%
Portland Natural Gas Transmission System | Secured debt | PNGTS 5.90% Senior Secured Notes due December 2018 | Debt agreement covenants, succeeding twelve months | Minimum
Credit facilities, short-term loan facility and long-term debt
Debt Service Coverage, covenant (as a percent)								1.30%
ASU 2015-03, Interest - Imputation of Interest | Adjustment
Credit facilities, short-term loan facility and long-term debt
Other assets (Note 3)											$ (8,000,000)
Long-term debt											(8,000,000)
Less: unamortized debt issuance costs and debt discount											$ (8,000,000)

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

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DEBT AND CREDIT FACILITIES - Principal Payments Required (Details) - USD ($) $ in Millions	Mar. 31, 2017	Dec. 31, 2016
Principal repayments required on debt
2017		$ 52
2018	$ 715	715
2019	43	43
2020	100	100
2021	460	510
Thereafter	500	500
Total debt	$ 1,858	$ 1,920

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OTHER LIABILITIES (Details) - USD ($) $ in Millions		Mar. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
OTHER LIABILITIES
Regulatory liabilities			$ 25	$ 24
Other liabilities			3	3
Other liabilities, total	[1]	$ 28	$ 28	$ 27

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

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PARTNERS' EQUITY - Ownership (Details) - shares			3 Months Ended	9 Months Ended		12 Months Ended
		Apr. 01, 2015	Mar. 31, 2017	Sep. 30, 2016	Sep. 30, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Apr. 25, 2017	Mar. 31, 2016
Common units
Partners' Equity
Common units outstanding, end of year (in units)	[1]		68,600,000			67,400,000	64,300,000	63,600,000		64,700,000
Common units | Limited Partners
Partners' Equity
Common units outstanding, end of year (in units)						67,454,831
Non-affiliates | Common units | Limited Partners
Partners' Equity
Common units outstanding, end of year (in units)						50,370,000
TC PipeLines GP, Inc. | General Partner
Partners' Equity
IDRs ownership (as a percent)						100.00%
Ownership interest in the Partnership (as a percent)		2.00%	2.00%	2.00%	2.00%	2.00%	2.00%	2.00%
TC PipeLines GP, Inc. | Common units | Limited Partners
Partners' Equity
Common units outstanding, end of year (in units)						5,797,106			5,797,106
TransCanada Corporation and subsidiaries | Common units | Limited Partners
Partners' Equity
Common units outstanding, end of year (in units)						17,084,831
TransCanada | Common units | Limited Partners
Partners' Equity
Common units outstanding, end of year (in units)						11,287,725
Ownership interest in the Partnership (as a percent)						25.30%
TransCanada | Class B units | Limited Partners
Partners' Equity
Common units outstanding, end of year (in units)						1,900,000
Ownership interest in the Partnership (as a percent)						100.00%

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

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PARTNERS' EQUITY - ATM Equity Issuance Program (Details)					2 Months Ended	3 Months Ended			9 Months Ended		12 Months Ended
		Jun. 30, 2017 item	Aug. 05, 2016 USD ($) item	Apr. 01, 2015 USD ($)	May 19, 2016 USD ($) $ / shares	Mar. 31, 2017 USD ($) shares	May 19, 2016 shares	Mar. 31, 2016 USD ($)	Sep. 30, 2016	Sep. 30, 2015	Dec. 31, 2016 USD ($) shares	Dec. 31, 2015 USD ($) shares	Dec. 31, 2014 USD ($) shares	Aug. 31, 2014 USD ($)
Partners' Equity
Net proceeds from public offering of common units	[1],[2]										$ 83,000,000
Equity contribution	[1]											$ 2,000,000
Common units issuance subject to rescission net	[3]							$ 19,000,000			83,000,000
Common units subject to rescission	[3]					$ 64,000,000					83,000,000
General Partner
Partners' Equity
Net proceeds from public offering of common units	[2]										$ 2,000,000
Equity contribution				$ 2,000,000								$ 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%	2.00%	2.00%	2.00%	2.00%
ATM Equity Issuance Program | Common units
Partners' Equity
Aggregate offering price of units														$ 200,000,000
Units sold | shares						1,197,749	1,619,631				3,100,000	700,000	1,300,000
Net proceeds from issuance of common units											$ 164,000,000	$ 43,000,000	$ 71,000,000
Sales agent commissions						$ 704,000					2,000,000	400,000	1,000,000
Common units issuance subject to rescission net					$ 82,334,015
Number of unitholders that have claimed or exercised any rescission rights | item		0
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					$ 3,000,000	$ 1,000,000	$ 2,000,000
ATM Equity Issuance Program | Minimum | Common units
Partners' Equity
Common units (price per unit) | $ / shares					$ 47.00
ATM Equity Issuance Program | Maximum | Common units
Partners' Equity
Common units (price per unit) | $ / shares					$ 54.95
Period of time for Section 5 Securities violations to be filed within					1 year
Equity Distribution Agreement (EDA) | Common units
Partners' Equity
Number of financial institutions | item			5
Amended shelf registration with SEC			$ 400,000,000

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

[2] These units are treated as outstanding for financial reporting purposes.

[3] Recast to consolidate PNGTS for all periods presented (Refer to Note 2).

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PARTNERS' EQUITY - Class B Units (Details) - Class B units - USD ($)				3 Months Ended				9 Months Ended	12 Months Ended
	Feb. 14, 2017	Feb. 12, 2016	Apr. 01, 2015	Mar. 31, 2017		Mar. 31, 2016		Dec. 31, 2015	Dec. 31, 2016		Dec. 31, 2015
Partners' Equity
Net income attributable to limited partners									$ 22,000,000		$ 12,000,000
Limited partners, distributions paid	$ 22,000,000	$ 12,000,000		$ 22,000,000	[1]	$ 12,000,000	[1]		$ 12,000,000	[1]
GTN | TransCanada | Distributions
Partners' Equity
Portion of GTN's annual distributions to which the Class B units are entitled to receive a percentage share of the distributions above threshold (as a percent)			30.00%	30.00%					30.00%
Percentage applied to 30 percent of GTN's distributions above threshold through March 31, 2020			100.00%	100.00%
Threshold of GTN's total distributable cash flows for payment to Class B units			$ 20,000,000	$ 20,000,000					$ 20,000,000		$ 15,000,000
Percentage applied to GTN's distributions above threshold after March 31, 2020			25.00%	25.00%
Percentage applied to GTN's distributable cash flow for the twelve month period ending December 31, 2016				30.00%				30.00%	30.00%
30% of GTN's distributable cash flow									$ 42,000,000
Net income attributable to limited partners				$ 0		$ 0

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

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ACCUMULATED OTHER COMPREHENSIVE LOSS (Details) - USD ($) $ in Millions		3 Months Ended			12 Months Ended
		Mar. 31, 2017		Mar. 31, 2016	Dec. 31, 2016		Dec. 31, 2015		Dec. 31, 2014
Changes in accumulated other comprehensive loss (AOCL) by components
Partners' Equity at beginning of year	[1]	$ 1,144		$ 1,149	$ 1,149
Change in fair value of cash flow hedges (Note 10 and 18)	[1]	1		(2)	3				$ (1)
Change in fair value of interest rate derivative instruments recognized in other comprehensive income (loss)	[1]				1		$ 1		1
Net other comprehensive income (loss)		1	[1]		3	[2]	1	[2]
Partners' Equity at end of year	[1]	1,220			1,144		1,149
Cash flow hedges
Changes in accumulated other comprehensive loss (AOCL) by components
Partners' Equity at beginning of year		$ (2)		$ (4)	(4)		(5)		(5)
Change in fair value of cash flow hedges (Note 10 and 18)					3				(1)
Amounts reclassified from AOCL					(2)
Net other comprehensive income (loss)					2		1
Partners' Equity at end of year					(2)		(4)		(5)
Portland Natural Gas Transmission System
Changes in accumulated other comprehensive loss (AOCL) by components
Change in fair value of interest rate derivative instruments recognized in other comprehensive income (loss)					1		1		1
Portland Natural Gas Transmission System | Cash flow hedges
Changes in accumulated other comprehensive loss (AOCL) by components
Change in fair value of interest rate derivative instruments recognized in other comprehensive income (loss)					$ 1		$ 1		$ 1

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

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

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FINANCIAL CHARGES AND OTHER (Details) - USD ($) $ in Millions		3 Months Ended		12 Months Ended
		Mar. 31, 2017	Mar. 31, 2016	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Interest expense				$ 69	$ 65	$ 59
Net realized loss related to the interest rate swaps				3	2	2
Change in fair value of interest rate derivative instruments recognized in other comprehensive income (loss)	[1]			1	1	1
Other				(2)	(5)	(1)
Financial charges and other	[1]	$ 17	$ 18	71	63	61
Portland Natural Gas Transmission System
Change in fair value of interest rate derivative instruments recognized in other comprehensive income (loss)				$ 1	$ 1	$ 1

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

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NET INCOME (LOSS) PER COMMON UNIT - General Partner Effective Interest and Allocated Incentive Distributions (Details)		3 Months Ended	9 Months Ended		12 Months Ended
	Apr. 01, 2015	Mar. 31, 2017	Sep. 30, 2016	Sep. 30, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
TC PipeLines GP, Inc. | General Partner
Partners' Equity
General partner interest (as a percent)	2.00%	2.00%	2.00%	2.00%	2.00%	2.00%	2.00%

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NET INCOME (LOSS) 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				3 Months Ended											9 Months Ended	12 Months Ended
		Feb. 14, 2017	Apr. 01, 2015	Mar. 31, 2017		Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016		Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2015	Dec. 31, 2016		Dec. 31, 2015		Dec. 31, 2014
Net income (loss) per common unit
Net income attributable to controlling interests				$ 77,000,000	[1]	$ 61,000,000	$ 58,000,000	$ 55,000,000	$ 74,000,000		$ (128,000,000)	$ 52,000,000	$ 46,000,000	$ 67,000,000		$ 248,000,000	[1]	$ 37,000,000	[1]	$ 195,000,000	[1]
Net income attributed to PNGTS' former parent				(2,000,000)					(1,000,000)							(4,000,000)		(24,000,000)		(23,000,000)
Net income allocable to General Partner and Limited Partners				75,000,000					73,000,000							244,000,000		13,000,000		172,000,000
Incentive distributions attributable to the General Partner				(2,000,000)					(1,000,000)							(7,000,000)		(3,000,000)		(1,000,000)
Net income (loss) allocable to the General Partner and common units																215,000,000		(2,000,000)		171,000,000
Net income attributable to General Partner's two percent interest				(1,000,000)					(1,000,000)							(4,000,000)				(3,000,000)
Class B units
Net income (loss) per common unit
Net income attributable to limited partners																22,000,000		12,000,000
Common units
Net income (loss) per common unit
Net income attributable to limited partners	[1]			$ 72,000,000					$ 71,000,000							$ 211,000,000		$ (2,000,000)		$ 168,000,000
Weighted average common units outstanding - basic (in units)	[1]			68.3					64.4							65.7		63.9		62.7
Weighted average common units outstanding - diluted (in units)				68.3	[1]				64.4	[1]						65.7		63.9		62.7
Net income per common unit - basic (in dollars per unit)				$ 1.05	[1],[2]	$ 0.70	$ 0.65	$ 0.76	$ 1.10	[2]	$ (2.27)	$ 0.70	$ 0.66	$ 0.88		$ 3.21	[1]	$ (0.03)	[1]	$ 2.67	[1]
Net income per common unit - diluted (in dollars per unit)				$ 1.05	[1],[2]				$ 1.10	[1],[2]						$ 3.21		$ (0.03)		$ 2.67
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, 2016				30.00%											30.00%	30.00%
Threshold of GTN's distributions for payment to Class B units		$ 20,000,000		$ 20,000,000											$ 15,000,000	$ 20,000,000		$ 15,000,000
Portion of GTN's annual distributions to which the Class B units are entitled to receive a percentage share of the distributions above threshold (as a percent)			30.00%	30.00%												30.00%
30% of GTN's distributable cash flow																$ 42,000,000

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

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

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CASH DISTRIBUTIONS - Quarterly Distributions (Details)		3 Months Ended	9 Months Ended		12 Months Ended
	Apr. 01, 2015	Mar. 31, 2017	Sep. 30, 2016	Sep. 30, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Cash distributions
Period after the end of each quarter within which quarterly cash distributions to partners are to be paid					45 days
General Partner | TC PipeLines GP, Inc.
Cash distributions
General partner interest (as a percent)	2.00%	2.00%	2.00%	2.00%	2.00%	2.00%	2.00%

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CASH DISTRIBUTIONS - General Partner Distribution Incentives (Details) - $ / shares			3 Months Ended	9 Months Ended		12 Months Ended
		Apr. 01, 2015	Mar. 31, 2017	Sep. 30, 2016	Sep. 30, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Apr. 25, 2017	Mar. 31, 2016
Common units
Schedule of Capitalization, Equity [Line Items]
Number of units	[1]		68,600,000			67,400,000	64,300,000	63,600,000		64,700,000
Limited Partners | Common units
Schedule of Capitalization, Equity [Line Items]
Number of units						67,454,831
Limited Partners | Common units | TC PipeLines GP, Inc.
Schedule of Capitalization, Equity [Line Items]
Number of units						5,797,106			5,797,106
General Partner | TC PipeLines GP, Inc.
Schedule of Capitalization, Equity [Line Items]
General partner interest (as a percent)		2.00%	2.00%	2.00%	2.00%	2.00%	2.00%	2.00%
Minimum Quarterly Distribution
Schedule of Capitalization, Equity [Line Items]
Total Quarterly Distribution Per Unit Target Amount (in dollars per unit)						$ 0.45
Minimum Quarterly Distribution | Limited Partners | Common units
Schedule of Capitalization, Equity [Line Items]
Marginal Percentage Interest in Distribution, Common Unitholders (as a percent)						98.00%
Minimum Quarterly Distribution | General Partner
Schedule of Capitalization, Equity [Line Items]
Marginal Percentage Interest in Distribution, General Partner (includes IDRs)						2.00%
First Target Distribution | Minimum
Schedule of Capitalization, Equity [Line Items]
Total Quarterly Distribution Per Unit Target Amount (in dollars per unit)						$ 0.45
First Target Distribution | Maximum
Schedule of Capitalization, Equity [Line Items]
Total Quarterly Distribution Per Unit Target Amount (in dollars per unit)						$ 0.81
First Target Distribution | Limited Partners | Common units
Schedule of Capitalization, Equity [Line Items]
Marginal Percentage Interest in Distribution, Common Unitholders (as a percent)						98.00%
First Target Distribution | General Partner
Schedule of Capitalization, Equity [Line Items]
Marginal Percentage Interest in Distribution, General Partner (includes IDRs)						2.00%
Second Target Distribution | Minimum
Schedule of Capitalization, Equity [Line Items]
Total Quarterly Distribution Per Unit Target Amount (in dollars per unit)						$ 0.81
Second Target Distribution | Maximum
Schedule of Capitalization, Equity [Line Items]
Total Quarterly Distribution Per Unit Target Amount (in dollars per unit)						$ 0.88
Second Target Distribution | Limited Partners | Common units
Schedule of Capitalization, Equity [Line Items]
Marginal Percentage Interest in Distribution, Common Unitholders (as a percent)						85.00%
Second Target Distribution | General Partner
Schedule of Capitalization, Equity [Line Items]
Marginal Percentage Interest in Distribution, General Partner (includes IDRs)						15.00%
Thereafter | Minimum
Schedule of Capitalization, Equity [Line Items]
Total Quarterly Distribution Per Unit Target Amount (in dollars per unit)						$ 0.88
Thereafter | Limited Partners | Common units
Schedule of Capitalization, Equity [Line Items]
Marginal Percentage Interest in Distribution, Common Unitholders (as a percent)						75.00%
Thereafter | General Partner
Schedule of Capitalization, Equity [Line Items]
Marginal Percentage Interest in Distribution, General Partner (includes IDRs)						25.00%

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

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CASH DISTRIBUTIONS - Distributions by Payment Date (Details) - USD ($)																																3 Months Ended											9 Months Ended	12 Months Ended
	Aug. 11, 2017	Jul. 20, 2017	May 15, 2017	Apr. 25, 2017	Feb. 14, 2017	Jan. 23, 2017	Nov. 14, 2016	Oct. 20, 2016	Aug. 12, 2016	Jul. 21, 2016	May 13, 2016	Apr. 21, 2016	Feb. 12, 2016	Jan. 21, 2016	Nov. 13, 2015	Oct. 22, 2015	Aug. 14, 2015	Jul. 23, 2015	May 15, 2015	Apr. 23, 2015	Apr. 01, 2015	Feb. 13, 2015	Jan. 22, 2015	Nov. 14, 2014	Oct. 23, 2014	Aug. 14, 2014	Jul. 23, 2014	May 15, 2014	Apr. 25, 2014	Feb. 14, 2014	Jan. 16, 2014	Mar. 31, 2017		Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016		Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2015	Dec. 31, 2016		Dec. 31, 2015		Dec. 31, 2014
Distributions
General Partner 2% paid					$ 2,000,000		$ 1,000,000		$ 1,000,000		$ 1,000,000		$ 1,000,000		$ 1,000,000		$ 2,000,000		$ 1,000,000			$ 1,000,000		$ 1,000,000		$ 1,000,000		$ 1,000,000		$ 1,000,000
General Partner IDRs paid					2,000,000		2,000,000		2,000,000		1,000,000		1,000,000		1,000,000		1,000,000							1,000,000																				$ 6,000,000		$ 2,000,000		$ 1,000,000
Total cash distributions 10K					$ 90,000,000		$ 66,000,000		$ 65,000,000		$ 60,000,000		$ 71,000,000		$ 59,000,000		$ 59,000,000		$ 55,000,000			$ 55,000,000		$ 55,000,000		$ 54,000,000		$ 52,000,000		$ 51,000,000				$ 66,000,000	$ 65,000,000	$ 60,000,000	$ 71,000,000		$ 59,000,000	$ 59,000,000	$ 55,000,000	$ 55,000,000		250,000,000	[1]	228,000,000	[1]	$ 212,000,000	[1]
Common units
Distributions
Per Unit Distribution, declared (in dollars per unit)						$ 0.94		$ 0.94		$ 0.94		$ 0.89		$ 0.89		$ 0.89		$ 0.89		$ 0.84			$ 0.84		$ 0.84		$ 0.84		$ 0.81		$ 0.81
Per Unit Distribution, paid (in dollars per unit)					$ 0.94		$ 0.94		$ 0.94		$ 0.89		$ 0.89		$ 0.89		$ 0.89		$ 0.84			$ 0.84		$ 0.84		$ 0.84		$ 0.81		$ 0.81		$ 0.94					$ 0.89
Limited Partners, Distribution declared						$ 64,000,000		$ 63,000,000		$ 62,000,000		$ 58,000,000		$ 57,000,000		$ 57,000,000		$ 56,000,000		$ 54,000,000			$ 54,000,000		$ 53,000,000		$ 53,000,000		$ 51,000,000		$ 50,000,000
Limited partners, distributions paid					$ 64,000,000		$ 63,000,000		$ 62,000,000		$ 58,000,000		$ 57,000,000		$ 57,000,000		$ 56,000,000		$ 54,000,000			$ 54,000,000		$ 53,000,000		$ 53,000,000		$ 51,000,000		$ 50,000,000
Total Cash Distribution																																$ 68,000,000					$ 60,000,000
Class B units
Distributions
Limited Partners, Distribution declared						$ 22,000,000								$ 12,000,000																		22,000,000
Limited partners, distributions paid					22,000,000								$ 12,000,000																			$ 22,000,000	[1]				$ 12,000,000	[1]						$ 12,000,000	[1]
GTN | Class B units | TransCanada | Distributions
Distributions
Portion of GTN's annual distributions to which the Class B units are entitled to receive a percentage share of the distributions above threshold (as a percent)																					30.00%											30.00%												30.00%
Percentage applied to GTN's distributable cash flow																																30.00%											30.00%	30.00%
Threshold of GTN's distributions for payment to Class B units					20,000,000																											$ 20,000,000											$ 15,000,000	$ 20,000,000		$ 15,000,000
Subsequent event
Distributions
Total Cash Distribution	$ 74,000,000		$ 68,000,000		68,000,000
Subsequent event | Common units
Distributions
Per Unit Distribution, declared (in dollars per unit)	$ 0.06	$ 1.00		$ 0.94		$ 0.94
Limited Partners, Distribution declared	$ 69,000,000		$ 65,000,000	$ 65,000,000	64,000,000
Subsequent event | Class B units
Distributions
Limited Partners, Distribution declared						$ 22,000,000
Limited partners, distributions paid					$ 22,000,000

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

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CHANGE IN OPERATING WORKING CAPITAL - Components (Details) - USD ($) $ in Millions		3 Months Ended		12 Months Ended
		Mar. 31, 2017	Mar. 31, 2016	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
CHANGE IN OPERATING WORKING CAPITAL
Change in accounts receivable and other		$ 7	$ (2)	$ (4)	$ 6	$ 2
Change in other current assets		1	3	(4)	(1)	(1)
Change in accounts payable and accrued liabilities		(3)	3	5	(2)	29
Change in accounts payable to affiliates		(1)	(4)		(15)	(6)
Change in state income taxes payable			9		(5)	2
Change in accrued interest		3	5	2	(3)	3
Change in operating working capital	[1]	$ 7	$ 14	$ (1)	$ (20)	$ 29

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

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CHANGE IN OPERATING WORKING CAPITAL - Certain Non-Cash Items Excluded from Change in Operating Working Capital (Details) - USD ($) $ in Millions		3 Months Ended		12 Months Ended
		Mar. 31, 2017	Mar. 31, 2016	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Jun. 01, 2017	Jan. 01, 2016
Non-cash items
Payments of capital expenditures	[1]	$ 7	$ 11	$ 29	$ 54	$ 10
Accruals for capital expenditures	[1]				10
Accrual of costs related to acquisition of 49.9% interest in PNGTS (Note 6)	[1]				2
GTN
Non-cash items
Payments of capital expenditures			$ 10
Accruals for capital expenditures					10
Portland Natural Gas Transmission System
Non-cash items
Interest acquired (as a percent)							61.71%
Portland Natural Gas Transmission System | Former parent, TransCanada subsidiaries | Transaction between entities under common control
Non-cash items
Accrual of costs related to acquisition of 49.9% interest in PNGTS (Note 6)					$ 2
Interest acquired (as a percent)				30.00%	49.90%			49.90%

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

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TRANSACTIONS WITH MAJOR CUSTOMERS (Details) - USD ($) $ in Millions	3 Months Ended										12 Months Ended
	Mar. 31, 2017		Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2016		Dec. 31, 2015		Dec. 31, 2014
Transactions with major customers
Revenues	$ 112	[1]	$ 111	$ 103	$ 101	$ 111	$ 110	$ 96	$ 97	$ 114	$ 426	[1]	$ 417	[1]	$ 410	[1]
Trade accounts receivable	$ 38		44				40				44		40
Total revenues | Customer concentration risk | Anadarko Energy Services Company
Transactions with major customers
Revenues											48		48		48
Total revenues | Customer concentration risk | Pacific Gas and Electric Company
Transactions with major customers
Revenues											36		42		$ 45
Accounts receivable and other | Amounts owed by major customers | Anadarko Energy Services Company
Transactions with major customers
Trade accounts receivable			$ 4				$ 4				$ 4		$ 4

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

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RELATED PARTY TRANSACTIONS (Details) - USD ($) $ in Millions		3 Months Ended			4 Months Ended	12 Months Ended
		Mar. 31, 2017	Mar. 31, 2016	Dec. 31, 2015	May 03, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Jan. 01, 2016	Apr. 01, 2015	Oct. 01, 2014
Capital and operating costs charged to the pipeline systems and amount payable
Net amounts payable	[1]	$ 7.0		$ 8.0		$ 8.0	$ 8.0
Amount included in receivables from related party		$ 1.0		1.0		$ 2.0	1.0
Portland Natural Gas Transmission System
Capital and operating costs charged to the pipeline systems and amount payable
Interest acquired (as a percent)		61.71%				61.71%
Great Lakes
Capital and operating costs charged to the pipeline systems and amount payable
Refund paid to shippers						$ 2.5
Percentage of refund paid to shippers						85.00%
Estimated revenue sharing provision						$ 7.2
Great Lakes | Federal Energy Regulatory Commission [Member]
Capital and operating costs charged to the pipeline systems and amount payable
Estimated revenue sharing provision		$ 3.4				7.2
General Partner | Reimbursement of costs of services provided
Capital and operating costs charged to the pipeline systems and amount payable
Costs charged		1.0	$ 1.0			3.0	3.0	$ 3.0
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	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			27.0	30.0	30.0
Impact on the Partnership's net income attributable to controlling interests		$ 7.0	$ 5.0			$ 24.0	$ 25.0	$ 19.0
Percentage of capital and operating costs charged		100.00%	100.00%			100.00%	100.00%	100.00%
TransCanada's subsidiaries | Northern Border
Capital and operating costs charged to the pipeline systems and amount payable
Net amounts payable		$ 3.0		5.0		$ 4.0	$ 5.0
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			$ 32.0	$ 36.0	$ 35.0
Percentage of capital and operating costs charged		100.00%	100.00%			100.00%	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		3.0		$ 1.0	$ 3.0
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			$ 8.0	8.0	$ 8.0
Percentage of capital and operating costs charged		100.00%	100.00%			100.00%
TransCanada's subsidiaries | Portland Natural Gas Transmission System | Transportation contracts
Capital and operating costs charged to the pipeline systems and amount payable
Amount included in receivables from related party		$ 0.0				$ 0.0
Revenue from related parties		0.0	$ 1.0			2.0	3.0
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				2.0	4.0	6.0
Impact on the Partnership's net income attributable to controlling interests		1.0	$ 1.0
Impact on the Partnership's net income attributable to controlling interests						$ 3.0	$ 4.0	$ 4.0
Percentage of capital and operating costs charged						100.00%	100.00%	100.00%
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	$ 3.0
Percentage of capital and operating costs charged		100.00%	100.00%
Amount included in receivables from related party		$ 15.0		17.0		19.0	17.0
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			30.0	30.0	$ 30.0
Impact on the Partnership's net income attributable to controlling interests						$ 13.0	$ 13.0	$ 13.0
Percentage of capital and operating costs charged		100.00%	100.00%			100.00%	100.00%	100.00%
Amount included in receivables from related party				51.0		$ 27.0	$ 51.0
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						68.00%	71.00%	49.00%
TransCanada's subsidiaries | Great Lakes | Affiliated rental revenue
Capital and operating costs charged to the pipeline systems and amount payable
Percent of total revenues						1.00%	1.00%	1.00%
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			4.0	$ 5.0	$ 5.0
Impact on the Partnership's net income attributable to controlling interests		1.0	1.0			4.0	5.0	4.0
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	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			5.0	4.0	4.0
Impact on the Partnership's net income attributable to controlling interests		1.0	1.0			4.0	4.0	4.0
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			12.0	14.0	16.0
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			$ 5.0	$ 5.0	5.0
Former parent, TransCanada subsidiaries | Transaction between entities under common control | GTN
Capital and operating costs charged to the pipeline systems and amount payable
Interest acquired (as a percent)										30.00%
Former parent, TransCanada subsidiaries | Transaction between entities under common control | Bison
Capital and operating costs charged to the pipeline systems and amount payable
Interest acquired (as a percent)						30.00%				30.00%	30.00%
Former parent, TransCanada subsidiaries | Portland Natural Gas Transmission System | Transaction between entities under common control
Capital and operating costs charged to the pipeline systems and amount payable
Interest acquired (as a percent)									49.90%
ANR Pipeline Company | Great Lakes | Firm service between Michigan and Wisconsin
Capital and operating costs charged to the pipeline systems and amount payable
Deferred revenue related to services performed					$ 14.0			$ 9.0
Deferred revenue recognized				$ 23.0

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

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QUARTERLY FINANCIAL DATA (unaudited) (Details) - USD ($) $ / shares in Units, $ in Millions															3 Months Ended											12 Months Ended
	Feb. 14, 2017	Nov. 14, 2016	Aug. 12, 2016	May 13, 2016	Feb. 12, 2016	Dec. 31, 2015	Nov. 13, 2015	Aug. 14, 2015	May 15, 2015	Feb. 13, 2015	Nov. 14, 2014	Aug. 14, 2014	May 15, 2014	Feb. 14, 2014	Mar. 31, 2017		Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016		Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2016		Dec. 31, 2015		Dec. 31, 2014
Quarterly financial data (unaudited)
Transmission revenues															$ 112	[1]	$ 111	$ 103	$ 101	$ 111		$ 110	$ 96	$ 97	$ 114	$ 426	[1]	$ 417	[1]	$ 410	[1]
Equity earnings															36	[1]	22	22	20	33		34	17	15	31	97	[1]	97	[1]	88	[1]
Impairment of equity-method investment																						(199)						(199)	[1]
Net income (loss)															83	[1]	65	60	57	81		(124)	54	47	81	263	[1]	58	[1]	241	[1]
Net income attributable to controlling interests															77	[1]	61	58	55	74		(128)	52	46	67	248	[1]	37	[1]	195	[1]
Cash distribution paid	$ 90	$ 66	$ 65	$ 60	$ 71		$ 59	$ 59	$ 55	$ 55	$ 55	$ 54	$ 52	$ 51			$ 66	$ 65	$ 60	71		59	$ 59	$ 55	$ 55	250	[1]	228	[1]	212	[1]
Northern Border and Great Lakes | Nonrecurring fair value measurement
Quarterly financial data (unaudited)
Impairment of equity-method investment																										0
Great Lakes
Quarterly financial data (unaudited)
Equity earnings															17					15						28		31		19
Great Lakes | Nonrecurring fair value measurement
Quarterly financial data (unaudited)
Impairment of equity-method investment																						$ (199)						(199)
Northern Border
Quarterly financial data (unaudited)
Equity earnings															$ 19					$ 18						69		$ 66		$ 69
Northern Border | Nonrecurring fair value measurement
Quarterly financial data (unaudited)
Impairment of equity-method investment						$ 0																				$ 0
Common units
Quarterly financial data (unaudited)
Net income per common unit (in dollars per unit)															$ 1.05	[1],[2]	$ 0.70	$ 0.65	$ 0.76	$ 1.10	[2]	$ (2.27)	$ 0.70	$ 0.66	$ 0.88	$ 3.21	[1]	$ (0.03)	[1]	$ 2.67	[1]

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

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

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FAIR VALUE MEASUREMENTS - Estimated Fair Value of Debt (Details) - USD ($) $ in Millions	Mar. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Fair Value | Level 2
Financial Instruments
Fair value of debt	$ 1,905.0	$ 1,963.0	$ 1,945.0

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FAIR VALUE MEASUREMENTS - Interest Rate Swaps (Details)		3 Months Ended		12 Months Ended
		Mar. 31, 2017 USD ($)	Mar. 31, 2016 USD ($)	Dec. 31, 2016 USD ($) item	Dec. 31, 2015 USD ($)	Dec. 31, 2014 USD ($)	Jul. 01, 2013 USD ($)
Interest rate derivatives
Amortization of realized loss on derivative instrument (Note 11)	[1]			$ 1,000,000	$ 1,000,000	$ 1,000,000
Accounts receivable
Interest rate derivatives
Maximum counterparty credit exposure				$ 0
Number of credit risk customers | item				1
Term loan | 2013 Term Loan Facility due 2018
Interest rate derivatives
Amount of facility							$ 500,000,000
Portland Natural Gas Transmission System
Interest rate derivatives
Amortization of realized loss on derivative instrument (Note 11)				$ 1,000,000	1,000,000	1,000,000
Payments for derivative instruments		$ 20,900,000		$ 20,900,000
Interest acquired (as a percent)		61.71%		61.71%
Net unamortized loss included in AOCL		$ 2,000,000		$ 2,000,000	2,000,000
Amortization of derivatives loss		$ 0	$ 0	$ 800,000	800,000	800,000
Interest rate swaps | Term loan | 2013 Term Loan Facility due 2018
Interest rate derivatives
Weighted average fixed interest rate (as a percent)		2.31%		2.31%
Hedges of cash flows | Interest rate swaps
Interest rate derivatives
Amortization of realized loss on derivative instrument (Note 11)		$ 1,000,000	(2,000,000)	$ 2,000,000	0	(1,000,000)
Hedges of cash flows | Interest rate swaps | Financial charges and other
Interest rate derivatives
Net realized loss related to the interest rate swaps		0	$ 0	3,000,000	2,000,000	$ 2,000,000
Hedges of cash flows | Interest rate swaps | Recurring fair value measurement | Level 2
Interest rate derivatives
Fair value of derivative asset, gross				1,000,000
Fair value of derivative liability, gross				1,000,000
Fair value of derivatives, net		2,000,000		0	1,000,000
Designated as hedge | Interest rate swaps | Recurring fair value measurement | Level 2
Interest rate derivatives
Fair value of derivative asset, gross		$ 2,000,000
Fair value of derivative liability, gross				0	$ 1,000,000
Designated as hedge | Hedges of cash flows | Interest rate swaps | Level 2
Interest rate derivatives
Fair value of derivative asset, gross				1,000,000
Fair value of derivative liability, gross				$ 1,000,000

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

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ACCOUNTS RECEIVABLE AND OTHER (Details) - USD ($) $ in Millions		Mar. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
ACCOUNTS RECEIVABLE AND OTHER
Trade accounts receivable, net of allowance of nil		$ 38	$ 44	$ 40
Imbalance receivable from affiliates		1	2	1
Other		2	1
Accounts receivable and other	[1]	41	47	41
Trade accounts receivable, allowance		$ 0	$ 0	$ 0

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

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GOODWILL AND REGULATORY (Details) $ in Millions				3 Months Ended	12 Months Ended
		Jan. 06, 2017 item	Aug. 01, 2016	Jun. 30, 2016 USD ($)	Dec. 31, 2016 USD ($)	Mar. 31, 2017 USD ($)	Dec. 31, 2015 USD ($)
Goodwill and Regulatory Matters
Goodwill	[1]				$ 130	$ 130	$ 130
GTN | FERC
Goodwill and Regulatory Matters
Decrease of system-wide unit rate (as a percent)					10.00%
Additional decrease of unit rate (as a percent)					8.00%
North Baja Pipeline, LLC | FERC
Goodwill and Regulatory Matters
Number of compression units | item		2
Tuscarora Gas Transmission Company
Goodwill and Regulatory Matters
Goodwill					$ 82		$ 82
Tuscarora Gas Transmission Company | Tuscarora Settlement | FERC
Goodwill and Regulatory Matters
Decrease of system-wide unit rate (as a percent)			17.00%
Additional decrease of unit rate (as a percent)			7.00%
Goodwill				$ 82
Tuscarora Gas Transmission Company | Tuscarora Settlement | FERC | Maximum
Goodwill and Regulatory Matters
Estimated Fair value over carrying value (as a percent)				10.00%

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

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CONTINGENCIES (Details) - USD ($) $ in Millions				1 Months Ended	12 Months Ended
	Sep. 16, 2015	Apr. 01, 2015	Oct. 29, 2009	Apr. 30, 2017	Dec. 31, 2017
Former parent, TransCanada subsidiaries | Transaction between entities under common control | GTN | Partnership interest | Class B units
Contingencies
Equity issuance		$ 95.0
Great Lakes v. Essar Steel Minnesota LLC, et al. | Great Lakes
Contingencies
Judgement awarded				$ 31.5	$ 31.5
Great Lakes v. Essar Steel Minnesota LLC, et al. | Great Lakes | Essar
Contingencies
Recovery sought			$ 33.0
Judgement awarded	$ 32.9

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VARIABLE INTEREST ENTITIES - Consolidated VIEs (Details) - USD ($) $ in Millions		Mar. 31, 2017	Dec. 31, 2016	Mar. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
ASSETS (LIABILITIES)
Cash and cash equivalents	[1]	$ 77	$ 64	$ 69	$ 55	$ 153	$ 116
Accounts receivable and other	[1]	41	47		41
Inventories	[1]	7	7		7
Other current assets	[1]	6	7		3
Equity investments	[1]	930	918		965
Plant, property and equipment	[1]	2,162	2,180		2,257
Other assets (Note 3)	[1]	1	1		1
Accounts payable and accrued liabilities	[1]	(26)	(29)		(34)
Accounts payable to affiliates	[1]	(7)	(8)		(8)
Distribution payable	[1]	(3)	(3)		(10)
Accrued interest	[1]	(13)	(10)		(8)
Current portion of long-term debt	[1]	(46)	(52)		(36)
Long-term debt	[1]	(1,804)	(1,859)		(1,935)
Other liabilities	[1]	(28)	(28)		(27)
Consolidated VIEs | Restricted VIEs
ASSETS (LIABILITIES)
Cash and cash equivalents		18	14		16
Accounts receivable and other		28	33		29
Inventories		6	6		6
Other current assets		4	6		6
Equity investments		930	918		965
Plant, property and equipment		1,140	1,146		1,180
Other assets (Note 3)		2	2		2
Accounts payable and accrued liabilities		(20)	(21)		(27)
Accounts payable to affiliates		(24)	(32)		(9)
Distribution payable		(3)	(3)		(10)
Accrued interest		(5)	(2)		(1)
Current portion of long-term debt		(46)	(52)		(36)
Long-term debt		(330)	(337)		(373)
Other liabilities		(26)	(25)		(24)
Deferred state income tax		$ (10)	$ (10)		$ (11)

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

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INCOME TAXES (Details) - USD ($) $ in Millions		3 Months Ended		12 Months Ended
		Mar. 31, 2017	Mar. 31, 2016	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Components of Income Tax Expense (Benefit), Continuing Operations [Abstract]
Deferred	[1]				$ 4	$ (1)
Total state income taxes	[1]	$ 1	$ 1	$ 1	$ 2	$ 2
Portland Natural Gas Transmission System
INCOME TAXES
Effective income tax rate (as a percent)		3.80%	3.80%	3.80%	3.80%	3.80%
Components of Income Tax Expense (Benefit), Continuing Operations [Abstract]
Current		$ 1	$ 8	$ 1	$ (2)	$ 3
Deferred			(7)		4	(1)
Total state income taxes		$ 1	$ 1	$ 1	$ 2	$ 2

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

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SUBSEQUENT EVENTS - Distributions (Details)																																																									3 Months Ended							9 Months Ended			12 Months Ended
		Aug. 11, 2017 USD ($) $ / shares	Aug. 01, 2017 USD ($) item	Jul. 31, 2017 USD ($)	Jul. 27, 2017 USD ($)	Jul. 20, 2017 USD ($) $ / shares shares	Jul. 18, 2017 USD ($)	Jul. 07, 2017 USD ($)	Jun. 30, 2017 USD ($)	Jun. 07, 2017 USD ($)	Jun. 01, 2017 USD ($)	May 31, 2017 USD ($)	May 25, 2017 USD ($)	May 15, 2017 USD ($)	May 12, 2017 USD ($)	May 01, 2017 USD ($)	Apr. 28, 2017 USD ($)	Apr. 25, 2017 USD ($) $ / shares shares	Apr. 24, 2017 USD ($)	Apr. 19, 2017 USD ($)	Apr. 07, 2017 USD ($)	Mar. 31, 2017 USD ($) shares	Mar. 10, 2017 USD ($)	Feb. 28, 2017 USD ($)	Feb. 15, 2017 USD ($)	Feb. 14, 2017 USD ($)	Feb. 01, 2017 USD ($)	Jan. 31, 2017 USD ($)	Jan. 23, 2017 USD ($) $ / shares shares	Jan. 09, 2017 USD ($)	Jan. 03, 2017 USD ($)	Nov. 14, 2016 USD ($)	Oct. 20, 2016 USD ($) $ / shares	Aug. 12, 2016 USD ($)	Jul. 21, 2016 USD ($) $ / shares	May 13, 2016 USD ($)	Apr. 21, 2016 USD ($) $ / shares	Feb. 12, 2016 USD ($)	Jan. 21, 2016 USD ($) $ / shares	Nov. 13, 2015 USD ($)	Oct. 22, 2015 USD ($) $ / shares	Aug. 14, 2015 USD ($)	Jul. 23, 2015 USD ($) $ / shares	May 15, 2015 USD ($)	Apr. 23, 2015 USD ($) $ / shares	Apr. 01, 2015	Feb. 13, 2015 USD ($)	Jan. 22, 2015 USD ($) $ / shares	Nov. 14, 2014 USD ($)	Oct. 23, 2014 USD ($) $ / shares	Aug. 14, 2014 USD ($)	Jul. 23, 2014 USD ($) $ / shares	May 15, 2014 USD ($)	Apr. 25, 2014 USD ($) $ / shares	Feb. 14, 2014 USD ($)	Jan. 16, 2014 USD ($) $ / shares	Mar. 31, 2017 USD ($) shares		Dec. 31, 2016 USD ($) shares	Mar. 31, 2016 USD ($) shares		Dec. 31, 2015 USD ($) shares	Mar. 31, 2015 USD ($)	Sep. 30, 2016	Dec. 31, 2015 USD ($) shares	Sep. 30, 2015	Dec. 31, 2016 USD ($) shares		Dec. 31, 2015 USD ($) shares		Dec. 31, 2014 USD ($) shares		Jan. 31, 2016	Jan. 01, 2016
Distributions
Partnership's share of distributions	[1]																																																								$ 28,000,000			$ 41,000,000
Accounts payable to affiliates	[1]																					$ 7,000,000																																			$ 7,000,000		$ 8,000,000			$ 8,000,000			$ 8,000,000		$ 8,000,000		$ 8,000,000
Northern Border
Distributions
Ownership interest (as a percent)				50.00%					50.00%			50.00%					50.00%					50.00%																																			50.00%		50.00%								50.00%
Great Lakes
Distributions
Ownership interest (as a percent)			46.45%													46.45%						46.45%																																			46.45%		46.45%			46.45%	46.45%		46.45%		46.45%		46.45%
Net purchase price																																																									$ 4,000,000	[1]	$ 5,000,000	4,000,000		$ 5,000,000	$ 4,000,000				$ 9,000,000	[1]	$ 9,000,000	[1]	$ 9,000,000	[1]
Iroquois
Distributions
Ownership interest (as a percent)			49.34%								49.34%
Portland Natural Gas Transmission System
Distributions
Ownership interest (as a percent)																																																																									49.90%
Net purchase price	[1]																																																											193,000,000
Portland Natural Gas Transmission System
Distributions
Interest acquired (as a percent)																						61.71%																																			61.71%		61.71%								61.71%
Subsequent event
Distributions
Total cash distribution		$ 74,000,000												$ 68,000,000												$ 68,000,000
Subsequent event | Iroquois
Distributions
Ownership interest (as a percent)			49.34%
Preliminary purchase price adjustments											$ 6,000,000
Net purchase price											710,000,000
Outstanding debt											164,000,000
Payment for future option to acquire											$ 1,000
Subsequent event | Portland Natural Gas Transmission System
Distributions
Interest acquired (as a percent)											11.81%
Subsequent event | Distribution declared | Northern Border
Distributions
Distribution declared								$ 14,000,000		$ 12,000,000					$ 14,000,000						$ 13,000,000		$ 9,000,000		$ 18,000,000					$ 16,000,000
Subsequent event | Distribution declared | Great Lakes
Distributions
Distribution declared							$ 15,000,000													$ 43,000,000										$ 14,000,000
Subsequent event | Distribution declared | Iroquois
Distributions
Distribution declared					$ 28,000,000
Subsequent event | Cash Distribution Paid | Northern Border
Distributions
Partnership's share of distributions				$ 7,000,000					$ 6,000,000			$ 7,000,000					$ 7,000,000					$ 5,000,000		$ 9,000,000				$ 8,000,000
Subsequent event | Cash Distribution Paid | Great Lakes
Distributions
Partnership's share of distributions			$ 7,000,000													$ 20,000,000											$ 7,000,000
Subsequent event | Cash Distribution Paid | Iroquois
Distributions
Partnership's share of distributions			14,000,000
Portland Natural Gas Transmission System
Distributions
Ownership interest (as a percent)											11.81%																																																															49.90%
Interest acquired (as a percent)											61.71%
Portland Natural Gas Transmission System | Subsequent event
Distributions
Ownership interest, including acquired interest (as a percent)											61.71%
Preliminary purchase price adjustments											$ 3,000,000
Net purchase price											55,000,000
Outstanding debt											5,000,000
Portland Natural Gas Transmission System | Subsequent event | Iroquois
Distributions
Purchase price											765,000,000
Preliminary purchase price adjustments											$ 9,000,000
TC PipeLines GP, Inc. | Subsequent event
Distributions
Ownership interest (as a percent)						2.00%												2.00%
General partner cash distributions						$ 5,000,000												$ 3,000,000								4,000,000
Total distribution for General Partner interest						$ 2,000,000												$ 1,000,000								2,000,000
Ownership interest in the Partnership (as a percent)						2.00%												2.00%
TC PipeLines GP, Inc. | General Partner
Distributions
Total distribution for General Partner interest																																																									$ 2,000,000			1,000,000
Ownership interest in the Partnership (as a percent)																																														2.00%											2.00%							2.00%		2.00%	2.00%		2.00%		2.00%
TC PipeLines GP, Inc. | General Partner | Subsequent event | Distribution declared
Distributions
Distribution declared for IDRs						$ 3,000,000												$ 2,000,000								2,000,000
Capital and operating costs | Subsequent event
Distributions
Accounts payable to affiliates									$ 28,000,000
Investing Activities | Subsequent event | Iroquois
Distributions
Return on investment distribution classified as investing activities			$ 28,000,000
Number of quarters for distribution of surplus cash | item			11
Investing Activities | Iroquois | Subsequent event
Distributions
Return on investment distribution classified as investing activities			$ 28,000,000
Number of quarters for distribution of surplus cash | item			11
PNGTS 5.90% Senior Secured Notes due December 2018 | Portland Natural Gas Transmission System
Distributions
Payment of principal amount on secured notes																															$ 5,500,000
PNGTS 5.90% Senior Secured Notes due December 2018 | Subsequent event | Portland Natural Gas Transmission System
Distributions
Payment of amount due on secured notes																															6,300,000
Payment of principal amount on secured notes																															5,500,000
Payment of interest amount on secured notes																															$ 800,000
Unsecured debt | 3.90% Senior Notes due May 2027 | Subsequent event
Distributions
Amount of debt													$ 500,000,000
Stated interest rate (as a percent)													3.90%
Net proceeds													$ 497,000,000
TransCanada | Subsequent event | Great Lakes
Distributions
Contract term																			10 years
Total contract value																			$ 758,000,000
Forecast | Subsequent event | Iroquois
Distributions
Ownership interest (as a percent)											49.34%
Future option to acquire (as a percent)											0.66
Forecast | Subsequent event | Portland Natural Gas Transmission System
Distributions
Interest acquired (as a percent)											11.81%
Forecast | Subsequent event | Cash Distribution Paid | Iroquois
Distributions
Partnership's share of distributions			$ 14,000,000
Forecast | Portland Natural Gas Transmission System | Subsequent event
Distributions
Ownership interest, including acquired interest (as a percent)											61.71%
Purchase price											$ 55,000,000
Forecast | Iroquois | Subsequent event
Distributions
Purchase price											$ 710,000,000
Common units
Distributions
Per Unit Distribution, declared (in dollars per unit) | $ / shares																													$ 0.94				$ 0.94		$ 0.94		$ 0.89		$ 0.89		$ 0.89		$ 0.89		$ 0.84			$ 0.84		$ 0.84		$ 0.84		$ 0.81		$ 0.81
Distribution declared																													$ 64,000,000				$ 63,000,000		$ 62,000,000		$ 58,000,000		$ 57,000,000		$ 57,000,000		$ 56,000,000		$ 54,000,000			$ 54,000,000		$ 53,000,000		$ 53,000,000		$ 51,000,000		$ 50,000,000
Total cash distribution																																																									$ 68,000,000			$ 60,000,000
Limited partners, distributions paid																										64,000,000						$ 63,000,000		$ 62,000,000		$ 58,000,000		$ 57,000,000		$ 57,000,000		$ 56,000,000		$ 54,000,000			$ 54,000,000		$ 53,000,000		$ 53,000,000		$ 51,000,000		$ 50,000,000
Number of units | shares	[1]																					68,600,000																																			68,600,000		67,400,000	64,700,000		64,300,000			64,300,000		67,400,000		64,300,000		63,600,000
Common units | Subsequent event
Distributions
Per Unit Distribution, declared (in dollars per unit) | $ / shares		$ 0.06				$ 1.00												$ 0.94											$ 0.94
Distribution declared		$ 69,000,000												65,000,000				$ 65,000,000								64,000,000
Common units | Limited Partners
Distributions
Number of units | shares																																																											67,454,831								67,454,831
Common units | TC PipeLines GP, Inc. | Subsequent event
Distributions
Per Unit Distribution, declared (in dollars per unit) | $ / shares						$ 1.00
Distribution declared						$ 69,000,000
Total cash distribution						74,000,000
Limited partners, distributions paid		6,000,000				6,000,000								5,000,000
General partner cash distributions						$ 11,000,000																				5,000,000
Common units | TC PipeLines GP, Inc. | Limited Partners
Distributions
Number of units | shares																		5,797,106																																									5,797,106								5,797,106
Common units | TC PipeLines GP, Inc. | Limited Partners | Subsequent event
Distributions
Number of units | shares						5,797,106												5,797,106											5,797,106
Common units | TransCanada | Subsequent event
Distributions
Limited partners, distributions paid		$ 11,000,000												$ 11,000,000												11,000,000
Common units | TransCanada | Limited Partners
Distributions
Number of units | shares																																																											11,287,725								11,287,725
Common units | TransCanada | TC PipeLines GP, Inc.
Distributions
Number of units | shares																		11,287,725
Common units | TransCanada | TC PipeLines GP, Inc. | Subsequent event
Distributions
Number of units | shares						11,287,725												11,287,725											11,287,725
Class B units
Distributions
Distribution declared																													$ 22,000,000										$ 12,000,000																		$ 22,000,000
Limited partners, distributions paid																										22,000,000												$ 12,000,000																			$ 22,000,000	[1]		$ 12,000,000	[1]						$ 12,000,000	[1]
Class B units | Subsequent event
Distributions
Distribution declared																													$ 22,000,000
Limited partners, distributions paid																										22,000,000
Class B units | TransCanada | Limited Partners
Distributions
Number of units | shares																																																											1,900,000								1,900,000
Class B units | TransCanada | Distributions | GTN
Distributions
Percentage applied to GTN's distributable cash flow for the twelve month period ending December 31, 2016																																																									30.00%								30.00%		30.00%
Threshold of GTN's distributions for payment to Class B units																										$ 20,000,000																															$ 20,000,000								$ 15,000,000		$ 20,000,000		$ 15,000,000

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

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CONSOLIDATED STATEMENTS OF INCOME - USD ($) shares in Millions, $ in Millions		3 Months Ended											12 Months Ended
		Mar. 31, 2017		Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016		Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2016		Dec. 31, 2015		Dec. 31, 2014
Transmission revenues		$ 112	[1]	$ 111	$ 103	$ 101	$ 111		$ 110	$ 96	$ 97	$ 114	$ 426	[1]	$ 417	[1]	$ 410	[1]
Equity earnings (Note 4)		36	[1]	22	22	20	33		34	17	15	31	97	[1]	97	[1]	88	[1]
Operation and maintenance expenses	[1]	(14)					(12)						(58)		(61)		(61)
Property taxes	[1]	(7)					(7)						(27)		(27)		(28)
General and administrative	[1]	(2)					(2)						(7)		(9)		(9)
Depreciation	[1]	(24)					(23)						(96)		(95)		(96)
Financial charges and other (Note 13)	[1]	(17)					(18)						(71)		(63)		(61)
Net income before taxes	[1]	84					82						264		60		243
Income taxes (Note 17)	[1]	(1)					(1)						(1)		(2)		(2)
Net Income		83	[1]	65	60	57	81		(124)	54	47	81	263	[1]	58	[1]	241	[1]
Net income attributable to non-controlling interests	[1]	6					7						15		21		46
Net income attributable to controlling interests		77	[1]	61	58	55	74		(128)	52	46	67	248	[1]	37	[1]	195	[1]
Net income attributable to controlling interest allocation (Note 7)
General Partner	[1]	3					2						11		3		4
TransCanada, as former parent of PNGTS	[1]	2					1						26		36		23
Net income		77	[1]	$ 61	$ 58	$ 55	74		$ (128)	$ 52	$ 46	$ 67	248	[1]	37	[1]	195	[1]
Common units
Net income attributable to controlling interest allocation (Note 7)
Limited partners	[1]	$ 72					$ 71						$ 211		$ (2)		$ 168
Net income (loss) per common unit (Note 7) - basic (in dollars per unit)		$ 1.05	[1],[2]	$ 0.70	$ 0.65	$ 0.76	$ 1.10	[2]	$ (2.27)	$ 0.70	$ 0.66	$ 0.88	$ 3.21	[1]	$ (0.03)	[1]	$ 2.67	[1]
Net income (loss) per common unit (Note 7) - diluted (in dollars per unit)		$ 1.05	[1],[2]				$ 1.10	[1],[2]					$ 3.21		$ (0.03)		$ 2.67
Weighted average common units outstanding - basic (in units)	[1]	68.3					64.4						65.7		63.9		62.7
Weighted average common units outstanding - diluted (in units)		68.3	[1]				64.4	[1]					65.7		63.9		62.7
Common units outstanding, end of year (in units)	[1]	68.6		67.4			64.7		64.3				67.4		64.3		63.6

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

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

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CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Millions		3 Months Ended										12 Months Ended
		Mar. 31, 2017		Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2016		Dec. 31, 2015		Dec. 31, 2014
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
Net income		$ 83	[1]	$ 65	$ 60	$ 57	$ 81	$ (124)	$ 54	$ 47	$ 81	$ 263	[1]	$ 58	[1]	$ 241	[1]
Other comprehensive income
Change in fair value of cash flow hedges (Note 11)	[1]	1					(2)					3				(1)
Amortization of realized loss on derivative instrument (Note 11)	[1]											1		1		1
Comprehensive income	[1]	84					79					265		59		241
Comprehensive income attributable to non-controlling interests	[1]	6					7					16		21		46
Comprehensive income attributable to controlling interests	[1]	$ 78					$ 72					$ 249		$ 38		$ 195

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

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CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions		Mar. 31, 2017		Dec. 31, 2016		Mar. 31, 2016	Dec. 31, 2015		Dec. 31, 2014		Dec. 31, 2013
Current Assets
Cash and cash equivalents	[1]	$ 77		$ 64		$ 69	$ 55		$ 153		$ 116
Accounts receivable and other (Note 12)	[1]	41		47			41
Inventories	[1]	7		7			7
Other	[1]	6		7			3
Total current assets	[1]	131		125			106
Equity investments (Note 4)	[1]	930		918			965
Plant, property and equipment (Net of $1,112 accumulated depreciation; 2016- $1,088)	[1]	2,162		2,180			2,257
Goodwill	[1]	130		130			130
Other assets	[1]	1		1			1
Total assets	[1]	3,354		3,354			3,459
Current Liabilities
Accounts payable and accrued liabilities	[1]	26		29			34
Accounts payable to affiliates (Note 10)	[1]	7		8			8
Accrued interest	[1]	13		10			8
Distributions payable	[1]	3		3			10
Current portion of long-term debt (Note 5)	[1]	46		52			36
Total current liabilities	[1]	95		102			96
Long-term debt, net (Note 5)	[1]	1,804		1,859			1,935
Deferred state income taxes (Note 17)	[1]	10		10			10
Other liabilities	[1]	28		28			27
Total liabilities	[1]	1,937		1,999			2,068
Common units subject to rescission (Note 6)	[1]	64		83
Partners' Equity
General partner	[1]	28		27			25
Accumulated other comprehensive loss (AOCL)	[1]	(1)		(2)			(4)
Controlling interests	[1]	1,220		1,144			1,149
Non-controlling interests	[1]	101		97			91
Equity of former parent of PNGTS	[1]	32		31			151
Total partners' equity		1,353	[1]	1,272	[1]		1,391	[1]	$ 1,818	[2]	$ 2,013	[2]
Total liabilities and partners' equity	[1]	3,354		3,354			3,459
Common units
Partners' Equity
Limited partner	[1]	1,098		1,002			1,021
Class B units
Partners' Equity
Limited partner	[1]	$ 95		$ 117			$ 107

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

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

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CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Millions	Mar. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
CONSOLIDATED BALANCE SHEETS
Accumulated depreciation	$ 1,112	$ 1,088	$ 997

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CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Millions		3 Months Ended
		Mar. 31, 2017		Mar. 31, 2016
Cash Generated From Operations
Net income		$ 83	[1]	$ 81
Depreciation	[1]	24		23
Amortization of debt issue costs reported as interest expense	[1]	1		1
Deferred state income taxes recovery	[1]			(7)
Equity earnings from equity investments (Note 3 and 4)		(36)	[1]	(33)
Distributions received from operating activities of equity investments (Note 3)	[1]	28		41
Change in operating working capital (Note 9)	[1]	7		14
Total cash generated from operations	[1]	107		120
Investing Activities
Capital expenditures	[1]	(7)		(11)
Total investing activities	[1]	(11)		(208)
Financing Activities
Distributions paid (Note 8)				(71)
Distributions paid to non-controlling interests	[1]	(2)		(4)
Distributions paid to former parent of PNGTS	[1]	(1)		(6)
Common unit issuance, net (Note 6)	[1]	71
Common unit issuance subject to rescission, net (Note 6)	[1]			19
Long-term debt issued, net of discount (Note 5)	[1]			195
Long-term debt repaid (Note 5)	[1]	(61)		(30)
Total financing activities	[1]	(83)		102
Increase in cash and cash equivalents	[1]	13		14
Cash and cash equivalents, beginning of year	[1]	64		55
Cash and cash equivalents, end of year	[1]	77		69
Class B units
Financing Activities
Distributions paid (Note 6)	[1]	(22)		(12)
Common units and General Partner interest combined
Financing Activities
Distributions paid (Note 8)	[1]	(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)	[1]	(4)
Portland Natural Gas Transmission System
Investing Activities
Investment/Acquisition of interests	[1]			$ (193)

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

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CONSOLIDATED STATEMENTS OF CASH FLOWS (Parenthetical)	Jun. 01, 2017	Jan. 01, 2016
Portland Natural Gas Transmission System
Acquisitions
Ownership interest (as a percent)	11.81%	49.90%

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CONSOLIDATED STATEMENT OF CHANGES IN PARTNERS' EQUITY - USD ($) shares in Millions, $ in Millions		Limited Partners Common units ATM Equity Issuance Program	Limited Partners Common units		Limited Partners Class B units		General Partner ATM Equity Issuance Program	General Partner		AOCL		Common units ATM Equity Issuance Program	Class B units	[1]	Non-Controlling Interests		PNGTS	[3]	ATM Equity Issuance Program	[1]	Total
Partners' Equity at beginning of year at Dec. 31, 2013	[1]		$ 1,322					$ 28		$ (5)	[2]				$ 526		$ 142				$ 2,013
Partners' Equity at beginning of year (in units) at Dec. 31, 2013	[1]		62.3
Increase (Decrease) in Partners' Equity
Net income			$ 168	[1]				4	[1]						46	[1]	23	[1]			241	[4]
ATM Equity Issuance, net (Note 6)		$ 71					$ 2												$ 73
ATM Equity Issuance, net (Note 6) (in units)		1.3
Distributions	[1]		(207)					(5)							(61)		(19)				(292)
Partners' Equity at end of year at Dec. 31, 2014	[1]		$ 1,325					29		(5)	[2]				323		146				1,818
Partners' Equity at end of year (in units) at Dec. 31, 2014	[1]		63.6
Increase (Decrease) in Partners' Equity
Net income			$ (2)	[1]	$ 12	[1]		3	[1]						21	[1]	24	[1]			58	[4]
Other Comprehensive income, net	[1]									1	[2]										1
ATM Equity Issuance, net (Note 6)		$ 43			$ 95		1						$ 95						44
ATM Equity Issuance, net (Note 6) (in units)		0.7			1.9
Distributions	[1]		(221)					(7)							(21)		(19)				(268)
Partners' Equity at end of year at Dec. 31, 2015			$ 1,021	[1]	$ 107	[1]		25	[1]	(4)	[1],[2]				91	[1]	151	[1]			1,391	[4]
Partners' Equity at end of year (in units) at Dec. 31, 2015	[1]		64.3		1.9
Increase (Decrease) in Partners' Equity
Net income			$ 211	[1]	$ 22	[1]		11	[1]						15	[1]	4	[1]			263	[4]
Other Comprehensive income, net	[1]									2	[2]				1						3
ATM Equity Issuance, net (Note 6)		$ 82					$ 2												$ 84
ATM Equity Issuance, net (Note 6) (in units)		1.5
Distributions	[1]		(240)		(12)			(10)							(10)		(4)				(276)
Partners' Equity at end of year at Dec. 31, 2016			$ 1,002	[1]	$ 117	[1]		27	[1]	(2)	[1],[2],[5]				97	[1]	31	[1]			1,272	[4]
Partners' Equity at end of year (in units) at Dec. 31, 2016	[1]		67.4		1.9
Increase (Decrease) in Partners' Equity
Net income	[4]		$ 72					3							6		2	[1]			83
Other Comprehensive income, net	[4]									1	[5]										1
ATM Equity Issuance, net (Note 6)			$ 69					2				$ 69									71	[4]
ATM Equity Issuance, net (Note 6) (in units)			1.2
Reclassification of common units no longer subject to rescission (Note 6 )			$ 19																		19	[4]
Distributions	[4]		(64)		$ (22)			(4)							(2)		(1)	[1]			(93)
Partners' Equity at end of year at Mar. 31, 2017	[4]		$ 1,098		$ 95			$ 28		$ (1)	[5]				$ 101		$ 32	[1]			$ 1,353
Partners' Equity at end of year (in units) at Mar. 31, 2017	[4]		68.6	[6]	1.9

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

[2] Losses related to cash flow hedges reported in Accumulated Other Comprehensive Loss and expected to be reclassified to net income in the next 12?months are estimated to be nil. 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.

[3] Equity of Former Parent of PNGTS.

[4] Recast to consolidate PNGTS for all periods presented (Refer to Note 2).

[5] Income related to cash flow hedges reported in Accumulated Other Comprehensive Loss and expected to be reclassified to net income in the next 12 months are estimated to be $1 million. These estimates assume constant interest rates over time; however, the amounts reclassified will vary based on actual value of interest rates at the date of settlement.Includes common units subject to rescission. These units are treated as outstanding for financial reporting purposes. Equity of Former Parent of PNGTS.Recast to consolidate PNGTS for all periods presented (Refer to Note 2).

[6] Includes common units subject to rescission. These units are treated as outstanding for financial reporting purposes.

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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

12 Months Ended

Mar. 31, 2017

Dec. 31, 2016

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.

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 interests in the following natural gas pipeline systems through three intermediate limited partnerships (ILPs), TC GL Intermediate Limited Partnership, TC PipeLines Intermediate Limited Partnership and TC Tuscarora Intermediate Limited Partnership:

Pipeline	Length	Description	Ownership
Gas Transmission Northwest LLC (GTN)	1,377 miles	Extends between an interconnection near Kingsgate, British Columbia, Canada at the Canadian border to a point near Malin, Oregon at the California border and delivers natural gas to the Pacific Northwest and to California.	100 percent
Bison Pipeline LLC (Bison)	303 miles	Extends from a location near Gillette, Wyoming to Northern Border’s pipeline system in North Dakota. Bison can transport natural gas from the Powder River Basin to Midwest markets.	100 percent
North Baja Pipeline, LLC (North Baja)	86 miles	Extends between an interconnection with the El Paso Natural Gas Company pipeline near Ehrenberg, Arizona and an interconnection with a natural gas pipeline near Ogilby, California on the Mexican border transporting natural gas in the southwest. North Baja is a bi-directional pipeline.	100 percent
Tuscarora Gas Transmission Company (Tuscarora)	305 miles	Extends between the GTN pipeline near Malin, Oregon to its terminus near Reno, Nevada and delivers natural gas in northeastern California and northwestern Nevada.	100 percent
Northern Border Pipeline Company (Northern Border)	1,412 miles	Extends between the Canadian border near Port of Morgan, Montana to a terminus near North Hayden, Indiana, south of Chicago. Northern Border is capable of receiving natural gas from Canada, the Williston Basin and Rocky Mountain area for deliveries to the Midwest. ONEOK Partners, L.P. owns the remaining 50 percent of Northern Border.	50 percent
Portland Natural Gas Transmission System (PNGTS)	295 miles	Connects with the TransQuebec and Maritimes Pipeline (TQM) at the Canadian border to deliver natural gas to customers in the U.S. northeast. Northern New England Investment Company, Inc. owns the remaining 38.29 percent of PNGTS.	61.71 percent (a)
Great Lakes Gas Transmission Limited Partnership (Great Lakes)	2,115 miles	Connects with the TransCanada Mainline at the Canadian border near Emerson, Manitoba, Canada and St. Clair, Michigan, near Detroit. Great Lakes is a bi-directional pipeline that can receive and deliver natural gas at multiple points along its system. TransCanada owns the remaining 53.55 percent of Great Lakes.	46.45 percent
Iroquois Gas Transmission System, L.P (Iroquois)	416 miles	Extends from the TransCanada Mainline system near Waddington, New York to deliver natural gas to customers in the U.S. northeast. The remaining 50.66 percent is owned by TransCanada (0.66 percent), Dominion Midstream (25.93 percent) and Dominion Resources (24.07 percent).	49.34 percent (b)

^(a) On June 1, 2017, the Partnership acquired an additional 11.81 percent from TransCanada resulting in 61.71 percent ownership in PNGTS. (Refer to Note 24-Subsequent Events).

^(b) Effective June 1, 2017 (Refer to Note 24-Subsequent Events).

The Partnership is managed by its General Partner, TC PipeLines GP, Inc. (General Partner), an indirect wholly-owned subsidiary of TransCanada. The General Partner provides management and operating services to the Partnership and is reimbursed for its costs and expenses. The General Partner owns 5,797,106 of our common units, 100 percent of our IDRs and an effective two percent general partner interest in the Partnership at December 31, 2016. TransCanada also indirectly holds an additional 11,287,725 common units, for total ownership of 25.3 percent of our outstanding common units and 100 percent of our Class B units at December 31, 2016 (Refer to Note 6).

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SIGNIFICANT ACCOUNTING POLICIES

3 Months Ended

12 Months Ended

Mar. 31, 2017

Dec. 31, 2016

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 Audited Consolidated Financial Statements and Notes thereto included as Exhibit 99.2 of  this Current Report on Form 8-K. That report contains a more comprehensive summary of the Partnership’s significant accounting policies. In the opinion of management, the accompanying financial statements contain all of the appropriate adjustments, all of which are normally recurring adjustments unless otherwise noted, and considered necessary to present fairly the financial position of the Partnership, the results of operations and cash flows for the respective periods. Our significant accounting policies are consistent with those disclosed in the Audited Consolidated Financial Statements and Notes thereto included in Exhibit 99.2 of  this Current Report on Form 8-K, except as described in Note 3, Accounting Pronouncements.

Basis of Presentation

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

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

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

On June 1, 2017, the Partnership acquired from a subsidiary of TransCanada an additional 11.81 percent interest in PNGTS, resulting in the Partnership owning 61.71 percent in PNGTS (Refer to Note 18-Subsequent Events).  As a result of the Partnership owning 61.71 percent of PNGTS, the Partnership’s historical financial information was recast, except net income (loss) per common unit, to consolidate PNGTS for all the periods presented in these consolidated financial statements. Additionally, this acquisition was accounted for as transaction between entities under common control, similar to pooling of interests, whereby the assets and liabilities of PNGTS were recorded at TransCanada’s carrying value.

Also, on June 1, 2017, the Partnership acquired from subsidiaries of TransCanada a 49.34 percent interest in Iroquois Gas Transmission,L.P (“Iroquois”) (Refer to Note 18-Subsequent Events). Accordingly, the equity method investment in Iroquois was accounted for prospectively and did not form part of these consolidated financial statements.

On January 1, 2016, the Partnership acquired a 49.9 percent interest in PNGTS (2016 PNGTS Acquisition) from a subsidiary of TransCanada. The PNGTS Acquisition was accounted for as a transaction between entities under common control, similar to a pooling of interests, whereby the equity investment in PNGTS was recorded at TransCanada’s carrying value and the total excess purchase price paid was recorded as a reduction in Partners’ Equity. Accordingly, the equity investment in PNGTS is being eliminated as a result of consolidating PNGTS for all the periods presented. Refer to Note 6 for additional disclosure regarding the PNGTS Acquisition.

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 2 SIGNIFICANT ACCOUNTING POLICIES

The accompanying consolidated financial statements and related notes have been prepared in accordance with United States generally accepted accounting principles (GAAP) and amounts are stated in U.S. dollars. The financial statements and notes present the financial position of the Partnership as of December 31, 2016 and 2015 and the results of its operations, cash flows and changes in partners’ equity for the years ended December 31, 2016, 2015 and 2014. Certain prior year amounts have been reclassified to conform to the current year presentation.

(a) Basis of Presentation

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

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

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

On June 1, 2017, the Partnership acquired from a subsidiary of TransCanada an additional 11.81 percent interest in PNGTS, resulting in the Partnership owning 61.71 percent in PNGTS (Refer to Note 24-Subsequent Events).  As a result of the Partnership owning 61.71 percent of PNGTS, the Partnership’s historical financial information was recast, except net income (loss) per common unit, to consolidate PNGTS for all the periods presented in these consolidated financial statements. Additionally, this acquisition was accounted for as transaction between entities under common control, similar to pooling of interests, whereby the assets and liabilities of PNGTS were recorded at TransCanada’s carrying value.

Also, on June 1, 2017, the Partnership acquired from subsidiaries of TransCanada a 49.34 percent interest in Iroquois (Refer to Note 24-Subsequent Events). Accordingly, the equity method investment in Iroquois  was accounted prospectively and did not form part of these consolidated financial statements.

On January 1, 2016, the Partnership acquired a 49.9 percent interest in PNGTS (2016 PNGTS Acquisition) from a subsidiary of TransCanada. The 2016 PNGTS Acquisition was accounted for as a transaction between entities under common control, similar to a pooling of interests, whereby the equity investment in PNGTS was recorded at TransCanada’s carrying value and the total excess purchase price paid was recorded as a reduction in Partners’ Equity. Accordingly, the equity investment in PNGTS is being eliminated as a result of consolidating PNGTS for all the periods presented. Refer to Note 6 for additional disclosure regarding the PNGTS Acquisition.

On April 1, 2015 and October 1, 2014, the Partnership acquired the remaining 30 percent interest in GTN and Bison, respectively, from subsidiaries of TransCanada. These acquisitions resulted in GTN and Bison being wholly-owned by the Partnership. Prior to these transactions, the remaining 30 percent interests held by subsidiaries of TransCanada were reflected as non-controlling interests in the Partnership’s consolidated financial statements. The acquisitions of these already-consolidated entities were accounted as a transaction between entities under common control, similar to a pooling of interests, whereby the acquired interests were recorded at TransCanada’s carrying value and the total excess purchase price paid was recorded as a reduction in Partners’ Equity. Refer to Note 6 for additional disclosures regarding these acquisitions.

(b) 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.

(c) Cash and Cash Equivalents

The Partnership’s cash and cash equivalents consist of cash and highly liquid short-term investments with original maturities of three months or less and are recorded at cost, which approximates fair value.

(d) Trade Accounts Receivable

Trade accounts receivable are recorded at the invoiced amount and do not bear interest. We review our accounts receivable regularly and record allowances for doubtful accounts using the specific identification method.

(e) Natural gas imbalances

Natural gas imbalances occur when the actual amount of natural gas delivered to or received from a pipeline system differs from the amount of natural gas scheduled to be delivered or received. The Partnership values these imbalances due to or from shippers and interconnecting parties at current index prices. Imbalances are settled in kind, subject to the terms of the pipelines’ tariff.

Imbalances due from others are reported as  trade accounts receivable or accounts receivable from affiliates under the caption accounts receivable and other on the balance sheets. Imbalances owed to others are reported on the balance sheets as accounts payable and accrued liabilities and accounts payable to affiliates. In addition, the Partnership classifies all imbalances as current as the Partnership expects to settle them within a year.

(f) Inventories

Inventories primarily consist of materials and supplies and are carried at the lower of weighted average cost or market.

(g) Plant, Property and Equipment

Plant, property and equipment are stated at original cost. Costs of restoring the land above and around the pipeline are capitalized to pipeline facilities and depreciated over the remaining life of the related pipeline facilities. Pipeline facilities and compression equipment have an estimated useful life of 20 to 77 years and metering and other equipment ranges from 5 to 77 years. Depreciation is calculated on a straight-line composite basis over the assets’ estimated useful lives. Repair and maintenance costs are expensed as incurred. Costs that are considered a betterment are capitalized.

The Partnership’s subsidiaries capitalize a carrying cost on funds invested in the construction of long lived assets. This carrying cost includes a return on the investment financed by debt and equity allowance for funds used during construction (AFUDC), calculated based the average cost of debt and equity. Capitalized carrying costs for AFUDC debt and equity are reflected as an increase in the cost of plant, property and equipment on the balance sheets. Amounts included in construction work in progress are not amortized until transferred into service.

(h) Impairment of Equity Method Investments

We review our equity method investments when a significant event or change in circumstances has occurred that may have an adverse effect on the fair value of each investment. When such events or changes occur, we compare the estimated fair value to the carrying value of the related investment. We calculate the estimated fair value of an investment in an equity method investee using an income approach and market approach. The development of fair value estimates requires significant judgment including estimates of future cash flows, which is dependent on internal forecasts, estimates of the long-term rate of growth for the investee, estimates of the useful life over which cash flows will occur, and determination of weighted average cost of capital. The estimates used to calculate the fair value of an investee can change from year to year based on operating results and market conditions. Changes in these estimates and assumptions could materially affect the determination of fair value and our assessment as to whether an investment in an equity method investee has suffered an impairment.

If the estimated fair value of an investment is less than its carrying value, we are required to determine if the decline in fair value is other than temporary. This determination considers the aforementioned valuation methodologies, the length of time and the extent to which fair value has been less than carrying value, the financial condition and near-term prospects of the investee, including any specific events which may influence the operations of the investee, the intent and ability of the holder to retain its investment in the investee for a period of time sufficient to allow for any anticipated recovery in market value, and other facts and circumstances. If the fair value of an investment is less than its carrying value and the decline in value is determined to be other than temporary, we record an impairment charge.

(i) Impairment of Long-lived Assets

The Partnership reviews long-lived assets, such as plant, property and equipment for impairment whenever events or changes in circumstances indicate the carrying value may not be recoverable. If the total of the estimated undiscounted future cash flows is less than the carrying value of the assets, an impairment loss is recognized for the excess of the carrying value over the fair value of the assets.

(j) Partners’ Equity

Costs incurred in connection with the issuance of units are deducted from the proceeds received.

(k) Revenue Recognition

Transmission revenues are recognized in the period in which the service is provided. When a rate case is pending final FERC approval, a portion of the revenue collected is subject to possible refund. As of December 31, 2016, the Partnership has not recognized any transmission revenue that is subject to possible refund.

For the year ended December 31, 2014 and in January 2015, as required by FERC, PNGTS was charging customers rates applied for in its 2008 and 2010 rate cases. Due to the uncertainty in the outcome of its two outstanding rate cases, PNGTS was only recognizing revenue up to the amount of the interim FERC approved rates . The difference between these amounts was recognized as a provision (liability) for rate refund in the consolidated balance sheet. On February 19, 2015, FERC approved PNGTS’ final rates and PNGTS was required to refund the customers within sixty days of the issuance of the final rates, including interest at the quarterly average prime interest rate as prescribed by FERC. Total refunds accumulated to $114.3 million, including $8.0 million of interest, and were paid to customers on April 15, 2015.

(l) Income Taxes

Federal and certain state income taxes are the responsibility of the partners and are not reflected in these consolidated financial statements. The tax effect of the Partnership’s activities accrues to its partners. The Partnership’s taxable income or loss, which may vary substantially from the net income or loss reported in the consolidated statement of income, is includable in the federal income tax returns of each partner. The aggregate difference in the basis of the Partnership’s net assets for financial and income tax purposes cannot be readily determined because all information regarding each partner’s tax attributes related to the partnership is not available.

In instances where the Partnership is subject to state income taxes, the asset-liability method is used to account for taxes. This method requires the recognition of deferred tax assets and liabilities for future tax consequences attributable to the differences between the financial statement carrying amount of existing assets and liabilities and their respective tax bases.

Balance Sheet Classification of Deferred Taxes

In November 2015, the FASB issued new guidance which requires that deferred tax assets and liabilities be classified as non-current on the balance sheet. The new guidance is effective January 1, 2017, however, since early application is permitted, the Partnership elected to retrospectively apply this guidance effective January 1, 2015. Application of this new guidance will simplify the Partnership’s process in determining deferred tax amounts and simplify their presentation. The application of this guidance did not have a material impact on the Partnership’s consolidated financial statements.

(m) Acquisitions and Goodwill

The Partnership accounts for business acquisitions from third parties using the acquisition method of accounting and, accordingly, the assets and liabilities of the acquired entities are recorded at their estimated fair values at the date of acquisition. The excess of the purchase price over the fair value of net assets acquired is attributed to goodwill. Goodwill is not amortized and is tested on an annual basis for impairment or more frequently if any indicators of impairment are evident. The Partnership initially assesses qualitative factors to determine whether events or changes in circumstances indicate that the goodwill might be impaired. If the Partnership does not conclude that it is more likely than not that fair value of the reporting unit is greater than its carrying value, the first step of the two-step impairment test is performed by comparing the fair value of the reporting unit to its book value, which includes goodwill. If the fair value is less than book value, an impairment is indicated and a second step is performed to measure the amount of the impairment. In the second step, the implied fair value of goodwill is calculated by deducting the recognized amounts of all tangible and intangible net assets of the reporting unit from the fair value determined in the initial assessment. If the carrying value of goodwill exceeds the calculated implied fair value of goodwill, an impairment charge is recorded.

At December 31, 2016 and 2015, we had $130 million of goodwill recorded on our consolidated balance sheet related to the North Baja ($48 million) and Tuscarora ($82 million) acquisitions. No impairment of goodwill existed at December 31, 2016 (Refer also to Note 20).

The Partnership accounts for business acquisitions between itself and TransCanada, also known as “dropdowns”, as transactions between entities under common control.  Using this approach, the assets and liabilities of the acquired entities are recorded at TransCanada’s carrying value. In the event recasting is required, the Partnership’s historical financial information will be recast, except net income (loss) per common unit, to include the acquired entities for all periods presented. If the fair market value paid for the acquired entities is greater than the recorded net assets of the acquired entities, the excess purchase price paid is recorded as a reduction in Partners’ Equity. Similarly, if the fair market value paid for the acquired entities is less than the recorded net assets of the acquired entities, the excess of assets acquired is recorded as an increase in Partners’ Equity.

(n) Fair Value Measurements

For cash and cash equivalents, receivables, accounts payable, certain accrued expenses and short-term debt, the carrying amount approximates fair value due to the short maturities of these instruments. For long-term debt instruments and the interest rate swap agreements, fair value is estimated based upon market values (if applicable) or on the current interest rates available to us for debt with similar terms and remaining maturities. Considerable judgment is required in developing these estimates.

(o) Derivative Financial Instruments and Hedging Activities

The Partnership recognizes all derivative instruments as either assets or liabilities in the balance sheet at their respective fair values. For derivatives designated in hedging relationships, changes in the fair value are either offset through earnings against the change in fair value of the hedged item attributable to the risk being hedged or recognized in accumulated other comprehensive income, to the extent the derivative is effective at offsetting the changes in cash flows being hedged until the hedged item affects earnings.

The Partnership only enters into derivative contracts that it intends to designate as a hedge of a forecasted transaction or the variability of cash flows to be received or paid related to a recognized asset or liability (cash flow hedge). For all hedging relationships, the Partnership formally documents the hedging relationship and its risk management objective and strategy for undertaking the hedge, the hedging instrument, the hedged transaction, the nature of the risk being hedged, how the hedging instrument’s effectiveness in offsetting the hedged risk will be assessed prospectively and retrospectively, and a description of the method used to measure ineffectiveness. The Partnership also formally assesses, both at the inception of the hedging relationship and on an ongoing basis, whether the derivatives that are used in hedging relationships are highly effective in offsetting changes in cash flows of hedged transactions. For derivative instruments that are designated and qualify as part of a cash flow hedging relationship, the effective portion of the gain or loss on the derivative is reported as a component of other comprehensive income and reclassified into earnings in the same period or periods during which the hedged transaction affects earnings. Gains and losses on the derivative representing either hedge ineffectiveness or hedge components excluded from the assessment of effectiveness are recognized in current earnings.

The Partnership discontinues hedge accounting prospectively when it determines that the derivative is no longer effective in offsetting cash flows attributable to the hedged risk, the derivative expires or is sold, terminated, or exercised, the cash flow hedge is de-designated because a forecasted transaction is not probable of occurring, or management determines to remove the designation of the cash flow hedge.

In all situations in which hedge accounting is discontinued and the derivative remains outstanding, the Partnership continues to carry the derivative at its fair value on the balance sheet and recognizes any subsequent changes in its fair value in earnings. When it is probable that a forecasted transaction will not occur, the Partnership discontinues hedge accounting and recognizes immediately in earnings gains and losses that were accumulated in other comprehensive income related to the hedging relationship.

(p) Asset Retirement Obligation

The Partnership recognizes the fair value of a liability for asset retirement obligations in the period in which it is incurred, when a legal obligation exists and a reasonable estimate of fair value can be made. The fair value is added to the carrying amount of the associated asset and the liability is accreted through charges to operating expenses.

The Partnership has determined it has legal obligations associated with its natural gas pipelines and related transmission facilities. The obligations relate primarily to purging and sealing the pipelines if they are abandoned. The Partnership is also required to operate and maintain its natural gas pipeline system, and intends to do so as long as supply and demand for natural gas exists, which the Partnership expects for the foreseeable future. Therefore, the Partnership believes its natural gas pipeline system assets have indeterminate lives and, accordingly, has recorded no asset retirement obligation as of December 31, 2016 and 2015.

(q) Government Regulation

The Partnership’s subsidiaries are subject to regulation by FERC. Under regulatory accounting principles, certain assets or liabilities that result from the regulated ratemaking process may be recorded that would not be recorded under GAAP for non-regulated entities. The timing of recognition of certain revenues and expenses in our regulated business may differ from that otherwise expected under GAAP to appropriately reflect the economic impact of the regulators’ decisions regarding revenues and rates. The Partnership regularly evaluates the continued applicability of regulatory accounting, considering such factors as regulatory changes, the impact of competition, and the ability to recover regulatory assets. At December 31, 2016, the Partnership had regulatory assets amounting to $1 million reported as part of other current assets  in the balance sheet representing volumetric fuel tracker assets that are settled with in-kind exchanges with customers continually (2015 — $2 million). Regulatory liabilities are included in other long-term liabilities (refer to Note 8). AFUDC is capitalized and included in plant, property and equipment.

(r) Debt Issuance Costs

Costs related to the issuance of debt are deferred and amortized using the effective interest rate method over the term of the related debt. Refer also to Note 3 — Imputation of Interest for the change in accounting policy related to debt issuance costs.

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ACCOUNTING PRONOUNCEMENTS

3 Months Ended

12 Months Ended

Mar. 31, 2017

Dec. 31, 2016

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 entity (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 currently anticipates adopting the standard using the modified retrospective approach with the cumulative-effect of initially applying the guidance recognized at the date of adoption, subject to allowable and elected practical expedients.

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

Leases

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

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

Goodwill Impairment

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

NOTE 3 ACCOUNTING PRONOUNCEMENTS

Changes in Accounting Policies effective January 1, 2016

Consolidation

In February 2015, the Financial Accounting Standards Board (FASB) issued new guidance on consolidation, which requires that an entity evaluate whether it should consolidate certain legal entities. All legal entities are subject to reevaluation under the revised consolidation model. This guidance became effective beginning January 1, 2016 and was applied retrospectively to all financial statements presented. The application of this guidance did not result in any change to the Partnership’s consolidation conclusions. Refer to Note 22, Variable Interest Entities.

In October 2016, the FASB issued an updated guidance on consolidation, under which a single decision maker is not required to consider indirect interests held through related parties that are under common control with the single decision maker to be the equivalent of direct interests in their entirety. Instead, a single decision maker is required to include those interests on a proportionate basis consistent with indirect interests held through other related parties. Entities that already have adopted the amendments in February 2015 update are required to apply the amendments in this update retrospectively to all relevant prior periods beginning with the fiscal year in which the amendments were applied. The application of this guidance did not result in any change to the Partnership’s consolidation conclusions. Refer to Note 22, Variable Interest Entities.

Imputation of interest

In April 2015, the FASB issued an amendment of previously issued guidance on imputation of interest, which requires debt issuance costs be presented in the balance sheet as a direct deduction from the carrying amount of debt liabilities, consistent with debt discount or premiums. In addition, amortization of debt issuance costs should be reported as interest expense. The recognition and measurement for debt issuance costs would not be affected. This guidance is effective from January 1, 2016 and was applied retrospectively resulting in a reclassification of debt issuance costs previously recorded in other assets to an offset of their respective debt liabilities on the Partnership’s consolidated balance sheet. Amortization of debt issuance costs was reported as interest expense in all periods presented in the Partnership’s consolidated statement of income.

As a result of the application of this guidance and similar to the presentation of debt discounts, debt issuance costs of $8 million at December 31, 2015 previously reported as other assets in the balance sheet were reclassified as an offset against their respective debt liabilities.

Earnings per share

In April 2015, the FASB issued an amendment of previously issued guidance on earnings per share (EPS) as it is being calculated by master limited partnerships. This updated guidance specifies that for purposes of calculating historical EPS under the two-class method, the earnings (losses) of a transferred business before the date of a dropdown transaction should be allocated entirely to the general partner interest, and previously reported EPS of the limited partners would not change as a result of a dropdown transaction. Qualitative disclosures about how the rights to the earnings (losses) differ before and after the dropdown transaction occurs are also required. This guidance became effective on January 1, 2016 and applies to all dropdown transactions requiring recast. The retrospective application of this guidance did not have a material impact on the Partnership’s consolidated financial statements as our current accounting policy is consistent with the new guidance.

Business combinations

In September 2015, the FASB issued new guidance which replaces the requirement that an acquirer in a business combination account for measurement period adjustments retrospectively with a requirement that an acquirer recognize adjustments to the provisional amounts that are identified during the measurement period in the reporting period in which the adjustment amounts are determined. The amended guidance requires that the acquirer record, in the same period’s financial statements, the effect on earnings of changes in depreciation, amortization, or other income effects, if any, as a result of the change to the provisional amounts, calculated as if the accounting had been completed at the acquisition date. The new guidance is effective January 1, 2016 and was applied prospectively. The application of this guidance did not have a material impact on the Partnership’s consolidated financial statements.

Statement of Cash Flows

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 since early adoption is permitted, the Partnership elected to retrospectively apply this guidance effective December 31, 2016. The application of this guidance will not have a material impact on the classification of debt pre-payments or extinguishment costs, contingent consideration payments made after a business combination, proceeds from the settlement of insurance claims and proceeds from the settlement of corporate owned life insurance. 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 $25 million and $27 million in 2015 and 2014, respectively, have been reclassified from investing activities to cash generated from operations in the consolidated statement of cash flows.

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 currently anticipates adopting the standard using the modified retrospective approach with the cumulative-effect of initially applying the guidance recognized at the date of adoption, subject to allowable and elected practical expedients.

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

Leases

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

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

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. This new guidance is effective January 1, 2017 and will be applied prospectively. The Partnership does not expect the adoption of this new standard to have a material impact on its consolidated financial statements.

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EQUITY INVESTMENTS

3 Months Ended

12 Months Ended

Mar. 31, 2017

Dec. 31, 2016

EQUITY INVESTMENTS

EQUITY INVESTMENTS

NOTE 4       EQUITY INVESTMENTS

Northern Border and Great Lakes 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 (b)		Equity Investments (b)
	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
			36	33	930	918

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

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

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

NOTE 4 EQUITY INVESTMENTS

Northern Border and Great Lakes are regulated by FERC and are operated by subsidiaries of 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 3, Accounting Pronouncements and Note 22, Variable Interest Entities.

	Ownership Interest at		Equity Earnings (b)			Equity Investments
	December 31,		Year ended December 31			December 31
(millions of dollars)	2016		2016(d)	2015	2014	2016 (d)	2015
Northern Border (a)	50.00	%	69	66	69	444	480
Great Lakes	46.45	%	28	31	19	474	485	(c)
			97	97	88	918	965

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

^(b) Equity Earnings represents our share in investee’s earnings and does not include any impairment charge on the equity method investment recorded as a reduction of carrying value of these investments. Accordingly, no impairment charge was recorded by the Partnership on its equity investees for all the periods presented here except the impairment recognized in 2015 on our investment in Great Lakes as discussed below.

^(c) During the fourth quarter of 2015, we recognized an impairment charge on our investment in Great Lakes amounting to $199 million. See discussion below.

^(d) Recast to eliminate equity earnings from PNGTS and consolidate PNGTS for all periods presented  (Refer to Note 2).

Northern Border

The Partnership, through its interest in TC PipeLines Intermediate Limited Partnership owns a 50 percent general partner interest in Northern Border. The other 50 percent partnership interest in Northern Border is held by ONEOK Partners, L.P., a publicly traded limited partnership.TC PipeLines Intermediate Limited Partnership, as one of the general partners, may be exposed to the commitments and contingencies of Northern Border. The Partnership holds a 98.9899 percent limited partnership interest in TC PipeLines Intermediate Limited Partnership.

Northern Border has a FERC-approved settlement agreement which established maximum long-term transportation rates and charges on the Northern Border system effective January 1, 2013. Northern Border is required to file for new rates no later than January 1, 2018.

The Partnership recorded no undistributed earnings from Northern Border for the years ended December 31, 2016, 2015 and 2014. At December 31, 2016 and 2015, the Partnership had a $116 million difference between the carrying value of Northern Border and the underlying equity in the net assets primarily resulting from the recognition and inclusion of goodwill in the Partnership’s investment in Northern Border relating to the Partnership’s April 2006 acquisition of an additional 20 percent general partnership interest in Northern Border. As of December 31, 2016, no impairment has been identified in our investment in Northern Border.

The summarized financial information for Northern Border is as follows:

December 31 (millions of dollars)	2016		2015
Assets
Cash and cash equivalents	14		27
Other current assets	36		33
Plant, property and equipment, net	1,089		1,124
Other assets (a)	14		16
	1,153		1,200
Liabilities and Partners’ Equity
Current liabilities	38		39
Deferred credits and other	28		26
Long-term debt, net (a), (b)	430		409
Partners’ equity
Partners’ capital	659		728
Accumulated other comprehensive loss	(2	)	(2	)
	1,153		1,200

^(a) As a result of the application of ASU No. 2015-03 and similar to the presentation of debt discounts, debt issuance costs of $2 million at December 31, 2015 previously reported as other assets in the balance sheet were reclassified as an offset against their respective debt liabilities.

^(b) Includes current maturities of $100 million senior notes at December 31, 2015. During August 2016, the $100 million senior notes were refinanced with a draw on Northern Border’s $200 million revolving credit agreement that expires in 2020.

Year ended December 31 (millions of dollars)	2016		2015		2014
Transmission revenues	292		286		293
Operating expenses	(72	)	(70	)	(72	)
Depreciation	(59	)	(60	)	(59	)
Financial charges and other	(21	)	(22	)	(22	)
Net income	140		134		140

Great Lakes

The Partnership, through its interest in TC GL Intermediate Limited Partnership owns a 46.45 percent general partner interest in Great Lakes. TransCanada owns the other 53.55 percent partnership interest. TC GL Intermediate Limited Partnership, as one of the general partners, may be exposed to the commitments and contingencies of Great Lakes. The Partnership holds a 98.9899 percent limited partnership interest in TC GL Intermediate Limited Partnership.

Great Lakes operates under rates established pursuant to a settlement approved by FERC in November 2013. Under the settlement, Great Lakes is required to file for new rates to be effective no later than January 1, 2018.

The Partnership recorded no undistributed earnings from Great Lakes for the years ended December 31, 2016, 2015, and 2014.

The Partnership made equity contributions to Great Lakes of $4 million and $5 million in the first and fourth quarter of 2016, respectively. These amounts represent the Partnership’s 46.45 percent share of a $9 million and $10 million cash call from Great Lakes to make scheduled debt repayments.

During the fourth quarter of 2015, we determined that our investment in Great Lakes’ long-term value had been adversely impacted by the changing natural gas flows in its market region. Additionally, we have concluded that other strategic alternatives to increase its utilization or revenue were no longer feasible. As a result, we determined that the carrying value of our investment in Great Lakes was in excess of its fair value and the decline was not temporary. Accordingly, we concluded that the carrying value of our investment in Great Lakes was impaired.

Our analysis resulted in an impairment charge of $199 million reflected as Impairment of equity-method investment on our Statement of Income for the year ended December 31, 2015.  The impairment charge reduced the difference between the carrying value of our investment in Great Lakes and the underlying equity in the net assets, to $260 million and  the difference represented the equity method goodwill remaining in our investment in Great Lakes relating to the Partnership’s February 2007 acquisition of a 46.45 percent general partner interest in Great Lakes.

The assumptions we used in 2015 related to the estimated fair value of our remaining equity investment in Great Lakes could be negatively impacted by near and long-term conditions including:

· future regulatory rate action or settlement,

· valuation of Great lakes in future transactions,

· changes in customer demand at Great Lakes for pipeline capacity and services,

· changes in North American natural gas production in the major producing basins,

· changes in natural gas prices and natural gas storage market conditions, and

· changes in other long-term strategic objectives.

Great Lakes’ evolving market conditions and other factors relevant to Great Lakes’ long term financial performance have remained relatively stable during the year ended 2016 and into 2017.  Accordingly, our estimation of the fair value of our investment in Great Lakes has not materially changed from 2015.  There is a risk that reductions in future cash flow forecasts and other adverse changes in these key assumptions could result in additional future impairment of the carrying value of our investment in Great Lakes.

The summarized financial information for Great Lakes is as follows:

December 31 (millions of dollars)	2016	2015
Assets
Current assets	66	86
Plant, property and equipment, net	714	727
	780	813
Liabilities and Partners’ Equity
Current liabilities	40	31
Long-term debt, net (a),(b)	278	297
Partners’ equity	462	485
	780	813

^(a) The application of ASU No. 2015-03 did not have a material effect on Great Lakes’ financial statements.

^(b) Includes current maturities of $19 million as of December 31, 2016 (December 31, 2015 - $19 million).

Year ended December 31 (millions of dollars)	2016		2015		2014
Transmission revenues	179		177		146
Operating expenses	(69	)	(59	)	(53	)
Depreciation	(28	)	(28	)	(28	)
Financial charges and other	(21	)	(23	)	(25	)
Net income	61		67		40

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DEBT AND CREDIT FACILITIES

3 Months Ended

12 Months Ended

Mar. 31, 2017

Dec. 31, 2016

DEBT AND CREDIT FACILITIES

DEBT AND CREDIT FACILITIES

NOTE 5       DEBT AND CREDIT FACILITIES

(unaudited) (millions of dollars)	March 31, 2017(b)	Weighted Average Interest Rate for the Quarter Ended March 31, 2017 (b)		December 31, 2016(b)		Weighted Average Interest Rate for the Year Ended December 31, 2016(b)
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	%
PNGTS
5.90% Senior Secured Notes due December 2018	41	5.90	%(a)	53		5.90	%(a)
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)
	1,858			1,920
Less: unamortized debt issuance costs and debt discount	8			9
Less: current portion	46			52	(c)
	1,804			1,859

^(a) Fixed interest rate

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

^(c) Includes the PNGTS portion due at December 31, 2016 amounting to $5.5 million that was paid on January 3, 2017

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

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).

PNGTS

PNGTS’ Senior Secured Notes are secured by the PNGTS long-term firm shipper contracts and its partners’ pledge of their equity and a guarantee of debt service for six months. PNGTS is restricted under the terms of its note purchase agreement from making cash distributions unless certain conditions are met. Before a distribution can be made, the debt service reserve account must be fully funded and PNGTS’ debt service coverage ratio for the preceding and succeeding twelve months must be 1.30 or greater. At March 31, 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 to make any cash distributions.

Tuscarora

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	40	(a)
2018	715	(a)
2019	43
2020	100
2021	460
Thereafter	500
	1,858	(a)

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

NOTE 7 DEBT AND CREDIT FACILITIES

(millions of dollars)	December 31, 2016 (c)		Weighted Average Interest Rate for the Year Ended December 31, 2016 (c)		December 31, 2015 (c)	Weighted Average Interest Rate for the Year Ended December 31, 2015 (c)
TC PipeLines, LP
Senior Credit Facility due 2021	160		1.72	%	200	1.44	%
2013 Term Loan Facility due 2018	500		1.73	%	500	1.44	%
2015 Term Loan Facility due 2018	170		1.63	%	170	1.47	%
4.65% Unsecured Senior Notes due 2021	350		4.65	%(b)	350	4.65	%(b)
4.375% Unsecured Senior Notes due 2025	350		4.375	%(b)	350	4.375	%(b)
GTN
5.29% Unsecured Senior Notes due 2020	100		5.29	%(b)	100	5.29	%(b)
5.69% Unsecured Senior Notes due 2035	150		5.69	%(b)	150	5.69	%(b)
Unsecured Term Loan Facility due 2019	65		1.43	%	75	1.15	%
PNGTS
5.90% Senior Secured Notes due December 2018	53		5.90	%(b)	69	5.90	%(b)
Tuscarora
Unsecured Term Loan due 2019	10		1.64	%	—	—
3.82% Series D Senior Notes due 2017	12		3.82	%(b)	16	3.82	%(b)
	1,920				1,980
Less: unamortized debt issuance costs and debt discount (a)	9				9
Less: current portion	52	(d)			36
	1,859				1,935

^(a) As a result of the application of ASU No. 2015-03 and similar to the presentation of debt discounts, debt issuance costs of $8 million at December 31, 2015 previously reported as other assets in the balance sheet were reclassified as an offset against debt. Refer to Note 3, Accounting Pronouncements.

^(b) Fixed interest rate.

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

^(d) Includes the PNGTS portion due at December 31, 2016 amounting to $5.5 million that was paid on January 3, 2017 (Refer to Note 24-Subsequent Events).

TC PipeLines, LP

On November 10, 2016, the Partnership’s Senior Credit Facility was amended to extend the maturity period through November 10, 2021. The Facility consists of a $500 million senior revolving credit facility with a banking syndicate, under which $160 million was outstanding at December 31, 2016 (December 31, 2015 - $200 million), leaving $340 million available for future borrowing.

At the Partnership’s option, the interest rate on the outstanding borrowings under the Senior Credit Facility may be lenders’ base rate or the London Interbank Offered Rate (LIBOR) plus, in either case, an applicable margin that is based on the Partnership’s long-term unsecured credit ratings. The Senior Credit Facility permits the Partnership to specify the portion of the borrowings to be covered by specific interest rate options and, for LIBOR-based borrowings, to specify the interest rate period. The Partnership is required to pay a commitment fee based on its credit rating and on the unused principal amount of the commitments under the Senior Credit Facility. The Senior Credit Facility has a feature whereby at any time, so long as no event of default has occurred and is continuing, the Partnership may request an increase in the Senior Credit Facility of up to $500 million, but no lender has an obligation to increase their respective share of the facility.

The LIBOR-based interest rate on the Senior Credit Facility was 1.92 percent at December 31, 2016 (December 31, 2015 - 1.50 percent).

On July 1, 2013, the Partnership entered into a term loan agreement with a syndicate of lenders for a $500 million term loan credit facility (2013 Term Loan Facility). On July 2, 2013, the Partnership borrowed $500 million under the 2013 Term Loan Facility, to pay a portion of the purchase price of the 2013 Acquisition, maturing on July 1, 2018. The 2013 Term Loan Facility bears interest based, at the Partnership’s election, on the LIBOR or the base rate plus, in either case, an applicable margin. The base rate equals the highest of (i) SunTrust Bank’s prime rate, (ii) 0.50 percent above the federal funds rate and (iii) 1.00 percent above one-month LIBOR. The applicable margin for the term loan is based on the Partnership’s senior debt rating and ranges between 1.125 percent and 2.000 percent for LIBOR borrowings and 0.125 percent and 1.000 percent for base rate borrowings.

As of December 31, 2016, 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 (2015-2.79 percent) . Prior to hedging activities, the LIBOR-based interest rate was 1.87 percent at December 31, 2016 (December 31, 2015 — 1.50 percent).

On September 30, 2015, the Partnership entered into an agreement for a $170 million term loan credit facility (2015 Term Loan Facility). The Partnership borrowed $170 million under the 2015 Term Loan Facility to refinance its Short-Term Loan Facility which matured on September 30, 2015.  The 2015 Term Loan Facility matures on October 1, 2018. The LIBOR-based interest rate on the 2015 Term Loan Facility was 1.77 percent at December 31, 2016 (December 31, 2015 — 1.39 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 4.01 to 1.00 as of December 31, 2016.

The Senior Credit Facility and the Term Loan Facilities contain additional covenants that include restrictions on entering into mergers, consolidations and sales of assets, granting liens, material amendments to the Partnership Agreement, incurrence of additional debt by the Partnership’s subsidiaries and distributions to unitholders. Upon any breach of these covenants, amounts outstanding under the Senior Credit Facility and the Term Loan Facilities may become immediately due and payable.

On March 13, 2015, the Partnership closed a $350 million public offering of senior unsecured notes bearing an interest rate of 4.375 percent maturing March 13, 2025. The net proceeds of $346 million were used to fund a portion of the 2015 GTN Acquisition (refer to Note 6) and to reduce the amount outstanding under our Senior Credit Facility. The indenture for the notes contains customary investment grade covenants.

PNGTS

PNGTS’ Senior Secured Notes are secured by the PNGTS long-term firm shipper contracts and its partners’ pledge of their equity and a guarantee of debt service for six months. PNGTS is restricted under the terms of its note purchase agreement from making cash distributions unless certain conditions are met. Before a distribution can be made, the debt service reserve account must be fully funded and PNGTS’ debt service coverage ratio for the preceding and succeeding twelve months must be 1.30 or greater. At December 31, 2016, the debt service coverage ratio was 2.41 for the twelve preceding months and 1.43 for the twelve succeeding months. Therefore, PNGTS was not restricted to make any cash distributions.

GTN

On June 1, 2015, GTN’s 5.09 percent unsecured Senior Notes matured. Also, on June 1, 2015, GTN entered into a $75 million unsecured variable rate term loan facility (Unsecured Term Loan Facility), which requires yearly principal payments until its maturity on June 1, 2019. The variable interest is based on LIBOR plus an applicable margin. The LIBOR-based interest rate on the Unsecured Term Loan Facility was 1.57 percent at December 31, 2016 (December 31, 2015 — 1.19 percent). GTN’s Unsecured Senior Notes, along with this new 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 December 31, 2016 is 44.5 percent.

Tuscarora

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 December 31, 2016 was 21.22 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 4.15 to 1.00 as of December 31, 2016.

On  April  29,  2016,  Tuscarora  entered  into  a $9.5  million  unsecured  variable  rate  term  loan  facility which requires  yearly principal  payments  until  its  maturity  on  April  29,  2019.  The variable interest is based on LIBOR plus an applicable margin and was 1.90 percent at December 31, 2016.

At December 31, 2016, 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 Partnership Agreement, incurring additional debt and distributions to unitholders.

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

(millions of dollars)
2017	52	(a)
2018	715	(a)
2019	43
2020	100
2021	510
Thereafter	500
	1,920	(a)

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

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PARTNERS' EQUITY

3 Months Ended

12 Months Ended

Mar. 31, 2017

Dec. 31, 2016

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. The Securities Act generally requires that any claim brought for a violation of Section 5 of the Securities Act be brought within one year of violation.

At December 31, 2016, $83 million was recorded as Common units subject to rescission on the consolidated balance sheet.  The Partnership classified 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.

No unitholder claimed or attempted to exercise any rescission rights prior to their expiry dates and the final rights related to the sales of such units expired on May 19, 2017. Therefore all the common units subject to rescission on the consolidated balance sheet were reclassified back to equity on our consolidated balance sheet at June 30, 2017 as filed on our Second Quarterly report on Form 10Q dated August 3, 2017.

NOTE 9 PARTNERS’ EQUITY

At December 31, 2016, the Partnership had 67,454,831common units outstanding, of which 50,370,000 were held by non-affiliates and 17,084,831 common units were held by subsidiaries of TransCanada, including 5,797,106 common units held by our General Partner. Additionally, TransCanada, through our General Partner, owns 100 percent of our IDRs and an effective two percent general partner interest in the Partnership. TransCanada also holds 100 percent of our 1,900,000 outstanding Class B units.

ATM Equity Issuance Program (ATM Program)

In August 2014, the Partnership launched its $200 million ATM program pursuant to which, the Partnership may from time to time, offer and sell, through sales agents, common units, representing limited partner interests.

On August 5, 2016, the Partnership entered into a new $400 million Equity Distribution Agreement (EDA) with five financial institutions (the Managers). Sales of the common units will be issued pursuant to the Partnership’s shelf registration statement on Form S-3 (Registration No. 333-211907), which was declared effective by the SEC on August 4, 2016.

In 2016, the Partnership issued 3.1 million common units under the ATM Program generating net proceeds of approximately $164 million, plus an additional $3 million from  the General Partner’s to maintain its effective two percent interest. The commissions to our sales agents were approximately $2 million.  The net proceeds were used to repay a portion of the borrowings under the Senior Credit Facility for the 2016 PNGTS Acquisition and for general partnership purposes. The 3.1 million common units issued include the 1.6 million common units subject to rescission as discussed below.

In 2015, the Partnership issued 0.7 million common units under the ATM Program generating net proceeds of approximately $43 million, plus an additional $1 million from  the General Partner’s to maintain its effective two percent interest. The commissions to our sales agents were approximately $0.4 million.  The net proceeds were used for general partnership purposes.

In 2014, the Partnership issued 1.3 million common units under the ATM Program generating net proceeds of approximately $71 million, plus an additional $2 million from  the General Partner’s to maintain its effective two percent interest. The commissions to our sales agents were approximately $1 million.  The net proceeds were used to finance the 2014 Bison Acquisition (refer to Note 6).

Common unit issuance subject to rescission

On July 17, 2014, the SEC declared effective a registration statement (the Registration Statement) that we had filed to cover sales of Common Units under our ATM program. On February 26, 2016, at the time of the filing of the 2015 Form 10-K, we believed that the Partnership continued to be eligible to use the effective Registration Statement to sell Common Units under our ATM program.  However, we were advised by the SEC on June 23, 2016 that as a result of the untimely filing of an employee-related Form 8-K on October 28, 2015, which was not filed via EDGAR until 6:02 p.m. Eastern Time (32 minutes after the 5:30 p.m. Eastern Time cutoff), the Partnership was ineligible to use the Registration Statement after the filing of the 2015 Form 10-K.

Because the Partnership was ineligible to continue using the Registration Statement following the filing of the 2015 Form 10-K, it is possible that the sales of an aggregate 1,619,631 Common Units under the Registration Statement (the ATM Common Units), which were sold between March 8, 2016 and May 19, 2016 at per Common Unit prices ranging from $47.00 to $54.95, may be deemed to have been unregistered sales of securities.  If it is determined that persons who purchased the ATM Common Units from the Partnership after February 26, 2016, purchased such Common Units in an offering deemed to be unregistered, then to the extent there may have been a violation of federal securities laws such persons may be entitled to rescission rights, pursuant to which they could be entitled to recover the amount paid for such ATM Common Units, plus interest (based on the statutory rate under applicable state law), less the amount of any distributions.  If such investor has sold any of the ATM Common Units purchased by the investor, then the investor would be entitled to recover the difference between the amount paid for such ATM Common Units and the amount at which such ATM Common Units were sold, assuming the investor’s ATM Common Units were sold at a loss, plus interest and less the amount of any distributions. If all of the investors who purchased the ATM Common Units from the Partnership after February 26, 2016 continue to own all of the ATM Common Units and were to demand rescission of their purchases, and such investors were in fact found to be entitled to such rescission, then we would be obligated to repay approximately $82,334,015, plus interest, less the amount of any distributions.  The Securities Act generally requires that any claim brought for a violation of Section 5 of the Securities Act be brought within one year of the violation.

At December 31, 2016, the Partnership classified all the 1.6 million common units issued under its ATM program after February 26, 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 were treated as outstanding for financial reporting purposes.

The total amount transferred  outside of equity was approximately $83 million which includes interest, less distributions paid, and includes our General Partner’s share to maintain its effective two percent interest.

No unitholder claimed or attempted to exercise any rescission rights prior to the expiry dates of such rights and the final rights related to the sales of such units expired on May 19, 2017. Therefore, all the common units subject to rescission on the consolidated balance sheet were reclassified back to equity on our consolidated balance sheet at June 30, 2017 as filed on our Second Quarterly report on Form 10Q dated August 3, 2017.

Issuance of Class B units

On April 1, 2015, we issued Class B units to TransCanada to finance a portion of the 2015 GTN Acquisition. The Class B units entitle TransCanada to an annual distribution which is an amount based on 30 percent of cash distributions from GTN exceeding certain annual thresholds (refer to Note 6). The Class B units contain no mandatory or optional redemption features and are also non-convertible, non-exchangeable, non-voting and rank equally with common units upon liquidation.

The Class B units’ equity account is increased by the excess of 30 percent of GTN’s distributions over the annual threshold until such amount is declared for distribution and paid every first quarter of the subsequent year.

For the year ended December 31, 2016 and 2015, the Class B units’ equity account was increased by $22 million and $12 million, respectively. These amounts equal 30 percent of GTN’s total distributable cash flow above the $20 million threshold in 2016 and $15 million in 2015 (refer to Notes 12 and 13).

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NET INCOME PER COMMON UNIT

3 Months Ended

12 Months Ended

Mar. 31, 2017

Dec. 31, 2016

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 net income attributed to PNGTS’ former parent, amounts attributable to the General Partner and Class B units by the weighted average number of common units outstanding.

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

The amount allocable to the Class B units in 2017 equals 30 percent of GTN’s distributable cash flow during the year ended December 31, 2017 less $20 million (December 31, 2016 —$20 million). 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 (a)	77			74
Net income attributable to PNGTS’ former parent (a) (b)	(2		)	(1		)
Net income allocable to General Partner and Limited Partners	75			73
Net income attributable to the General Partner	(1		)	(1		)
Incentive distributions attributable to the General Partner (c)	(2		)	(1		)
Net income attributable to common units	72			71
Weighted average common units outstanding (millions) — basic and diluted (d)	68.3			64.4
Net income per common unit — basic and diluted (e)	$	1.05		$	1.10

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

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

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

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

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

NOTE 12 NET INCOME (LOSS) PER COMMON UNIT

Net income (loss) per common unit is computed by dividing net income attributable to controlling interests, after deduction of  net income attributed to PNGTS’ former parent, amounts attributable to the General Partner andClass 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 (refer to Note 13).

The amount allocable to the Class B units in 2016 equals an amount based upon 30 percent of GTN’s distributable cash flow during the year ended December 31, 2016 less $20 million (2015 - $15 million).

Net income (loss) per common unit was determined as follows:

(millions of dollars, except per common unit amounts)	2016			2015			2014
Net income attributable to controlling interests (a)	248			37			195
Net income attributable to PNGTS’ former parent (a) (b)	(4		)	(24		)	(23		)
Net income allocable to General Partner and Limited Partners	244			13			172
Incentive distributions attributable to the General Partner (c)	(7		)	(3		)	(1		)
Net income attributable to the Class B units (d)	(22		)	(12		)	—
Net income (loss) allocable to the General Partner and common units	215			(2		)	171
Net income (loss) allocable to the General Partner’s two percent interest	(4		)	—			(3		)
Net income (loss) attributable to common units	211			(2		)	168
Weighted average common units outstanding (millions) — basic and diluted	65.7		(e)	63.9			62.7
Net income (loss) per common unit — basic and diluted (f)	$	3.21		$	(0.03	)	$	2.67

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

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

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

^(d) As discussed in Note 9, the Class B units entitle TransCanada to a distribution which is an amount based on 30 percent of GTN’s distributions after exceeding certain annual thresholds. The distribution will be payable in the first quarter with respect to the prior year’s distributions. Consistent with the application of Accounting Standards Codification (ASC) Topic 260 — “Earnings per share”, the Partnership allocated a portion of net income attributable to controlling interests to the Class B units in an amount equal to 30 percent of GTN’s total distributable cash flows during the year ended December 31, 2016 less the threshold level of $20 million (2015 - less $15 million). During the year ended December 31, 2016, 30 percent of GTN’s total distributable cash flow was $42 million. As a result of exceeding the threshold level of $20 million, $22 million of net income attributable to controlling interests was allocated to the Class B units at December 31, 2016 (2015 - $12 million). Refer to Note 9.

^(e) Includes the common units subject to rescission. These units are treated as outstanding for financial reporting purposes. Refer to Note 9.

^(f) Net income (loss) per common unit prior to recast.

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CASH DISTRIBUTIONS TO COMMON UNITS

3 Months Ended

12 Months Ended

Mar. 31, 2017

Dec. 31, 2016

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).

NOTE 13 CASH DISTRIBUTIONS

The Partnership makes cash distributions to its partners with respect to each calendar quarter within 45 days after the end of each quarter. Distributions are based on Available Cash, as defined in the Partnership Agreement, which includes all cash and cash equivalents of the Partnership and working capital borrowings less reserves established by the General Partner.

Pursuant to the Partnership Agreement, the General Partner receives two percent of all cash distributions in regard to its general partner interest and is also entitled to incentive distributions as described below. The unitholders receive the remaining portion of the cash distribution.

The following table illustrates the percentage allocations of available cash from operating surplus between the common unitholders and our General Partner based on the specified target distribution levels. The percentage interests set forth below for our General Partner include its two percent general partner interest and IDRs, and assume our General Partner has contributed any additional capital necessary to maintain its two percent general partner interest. The distribution to the General Partner illustrated below, other than in its capacity as a holder of 5,797,106 common units that are in excess of its effective two percent general partner interest, represents the IDRs.

		Marginal Percentage Interest in Distribution
	Total Quarterly Distribution Per Unit Target Amount	Common Unitholders		General Partner
Minimum Quarterly Distribution	$0.45	98	%	2	%
First Target Distribution	above $0.45 up to $0.81	98	%	2	%
Second Target Distribution	above $0.81 up to $0.88	85	%	15	%
Thereafter	above $0.88	75	%	25	%

The following table provides information about our distributions (in millions, except per unit distributions amounts).

				Limited Partners					General Partner
Declaration Date	Payment Date	Per Unit Distribution		Common Units		Class B Units(c)			2%		IDRs(a)		Total Cash Distribution
1/16/2014	2/14/2014	$	0.81	$	50	$	—		$	1	$	—	$	51
4/25/2014	5/15/2014	$	0.81	$	51	$	—		$	1	$	—	$	52
7/23/2014	8/14/2014	$	0.84	$	53	$	—		$	1	$	—	$	54
10/23/2014	11/14/2014	$	0.84	$	53	$	—		$	1	$	1	$	55
1/22/2015	2/13/2015	$	0.84	$	54	$	—		$	1	$	—	$	55
4/23/2015	5/15/2015	$	0.84	$	54	$	—		$	1	$	—	$	55
7/23/2015	8/14/2015	$	0.89	$	56	$	—		$	2	$	1	$	59
10/22/2015	11/13/2015	$	0.89	$	57	$	—		$	1	$	1	$	59
1/21/2016	2/12/2016	$	0.89	$	57	$	12	(d)	$	1	$	1	$	71
4/21/2016	5/13/2016	$	0.89	$	58	$	—		$	1	$	1	$	60
7/21/2016	8/12/2016	$	0.94	$	62	$	—		$	1	$	2	$	65
10/20/2016	11/14/2016	$	0.94	$	63	$	—		$	1	$	2	$	66
1/23/2017 (b)	2/14/2017 (b)	$	0.94	$	64	$	22	(e)	$	2	$	2	$	90

^(a) The distributions paid for the year ended December 31, 2016 included incentive distributions to the General Partner of $6 million (2015 - $2 million, 2014 - $1 million).

^(b) On February 14, 2017, we paid a cash distribution of $0.94 per unit on our outstanding common units to unitholders of record at the close of business on February 2, 2017 (refer to Note 24).

^(c) The Class B units issued by us on April 1, 2015 represent limited partner interests in us and entitle TransCanada to an annual distribution which is an amount based on 30 percent of GTN’s annual distributions after exceeding certain annual thresholds (refer to Note 6 and 9).

^(d) On February 12, 2016, we paid TransCanada $12 million representing 30 percent of GTN’s total distributable cash flows for the nine months ended December 31, 2015 less $15 million.

^(e) On February 14, 2017, we paid TransCanada $22 million representing 30 percent of GTN’s total distributable cash flows for the year ended December 31, 2016 less $20 million (refer to Note 9 and 24).

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CHANGE IN OPERATING WORKING CAPITAL

3 Months Ended

12 Months Ended

Mar. 31, 2017

Dec. 31, 2016

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 (b)		2016 (b)
Change in accounts receivable and other	7		(2	)
Change in other current assets	1		3
Change in accounts payable and accrued liabilities	(3	)	3	(a)
Change in accounts payable to affiliates	(1	)	(4	)
Change in state income taxes payable	—		9
Change in accrued interest	3		5
Change in operating working capital	7		14

^(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.

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

NOTE 14 CHANGE IN OPERATING WORKING CAPITAL

Year Ended December 31 (millions of dollars)	2016 (c)		2015(c)		2014(c)
Change in accounts receivable and other	(4	)	6		2
Change in other current assets	(4	)	(1	)	(1	)
Change in accounts payable and accrued liabilities (a)	5		(2	)	29
Change in accounts payable to affiliates	—		(15	) (b)	(6	)
Change in state income taxes payable	—		(5	)	2
Change in accrued interest	2		(3	)	3
Change in operating working capital	(1	)	(20	)	29

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

^(b) Excludes certain non-cash items primarily related to accruals of $10 million for construction of GTN’s Carty Lateral and $2 million of costs related to acquisition of 49.9 percent interest in PNGTS (Refer to Note 6).

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

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RELATED PARTY TRANSACTIONS

3 Months Ended

12 Months Ended

Mar. 31, 2017

Dec. 31, 2016

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) (c)	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 (c)	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) (c)	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.

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

Great Lakes

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, $15 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.

PNGTS

For the three months ended March 31, 2017 and 2016, PNGTS provided transportation services to a related party. Revenues from TransCanada Energy Ltd., a subsidiary of TransCanada, for the three months ended March 31, 2017 and 2016 were approximately nil million and  $1 million, respectively. At March 31, 2017, PNGTS had nil million outstanding receivables from TransCanada Energy Ltd. in the consolidated balance sheets (December 31, 2016- nil million).

NOTE 16 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 $3 million for each of the years ended December 31, 2016, 2015 and 2014.

As operator, TransCanada’s subsidiaries provide capital and operating services to GTN, Northern Border, PNGTS, Bison, Great Lakes, North Baja and Tuscarora (together, “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 years ended December 31, 2016, 2015 and 2014 by TransCanada’s subsidiaries and amounts payable to TransCanada’s subsidiaries at December 31, 2016 and 2015 are summarized in the following tables:

Year ended December 31 (millions of dollars)	2016	2015	2014
Capital and operating costs charged by TransCanada’s subsidiaries to:
Great Lakes (a)	30	30	30
Northern Border (a)	32	36	35
PNGTS (a) (b)	8	8	8
GTN (a) (c)	27	30	30
Bison (a) (d)	2	4	6
North Baja	4	5	5
Tuscarora	5	4	4
Impact on the Partnership’s net income attributable to controlling interests:
Great Lakes	13	13	13
Northern Border	12	14	16
PNGTS (b)	5	5	5
GTN (c)	24	25	19
Bison (d)	3	4	4
North Baja	4	5	4
Tuscarora	4	4	4

December 31 (millions of dollars)	2016	2015
Amount payable to TransCanada’s subsidiaries for costs charged in the year by:
Great Lakes (a)	4	3
Northern Border (a)	4	5
PNGTS (a) (b)	1	3
GTN	3	3
Bison	1	—
North Baja	1	—
Tuscarora	1	1

^(a) Represents 100 percent of the costs.

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

^(c) In 2015, the Partnership acquired the remaining 30 percent interest in GTN (Refer to Note 6).

^(d) In 2014, the Partnership acquired the remaining 30 percent interest in Bison (Refer to Note 6).

Great Lakes

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 year ended December 31, 2016, Great Lakes earned 68 percent of its transportation revenues from TransCanada and its affiliates  (2015 — 71 percent; 2014 — 49 percent). Additionally, Great Lakes earned approximately one percent of its total revenues as affiliated rental revenue in 2016 (2015 — 1 percent and 2014 — 1 percent).

At December 31, 2016, $19 million was included in Great Lakes’ receivables in regards to the transportation contracts with TransCanada and its affiliates (December 31, 2015 — $17 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 ROEs. A refund of $2.5 million was paid to shippers in 2016 relating to the year ended December 31, 2015, of which approximately 85 percent was made to affiliates of Great Lakes. For the year ended December 31, 2016, Great Lakes has recorded an estimated revenue sharing provision amounting to $7.2 million and Great Lakes expects that a significant percentage of the refund will be to its affiliates as well.

Great Lakes has a cash management agreement with TransCanada whereby Great Lakes’ funds are pooled with other TransCanada affiliates. The agreement also gives Great Lakes the ability to obtain short-term borrowings to provide liquidity for Great Lakes’ operating needs. At December 31, 2016 and 2015, Great Lakes has an outstanding receivable from this arrangement amounting to $27 million and $51 million, respectively.

Effective November 1, 2014, Great Lakes executed contracts with an affiliate, ANR Pipeline Company (ANR), to provide firm service in Michigan and Wisconsin.  These contracts were at the maximum FERC authorized rate and were intended to replace historical contracts.  On December 3, 2014, FERC accepted and suspended Great Lakes’ tariff records to become effective May 3, 2015, subject to refund.  On February 2, 2015, FERC issued an Order granting a rehearing and clarification request submitted by Great Lakes, which allowed additional time for FERC to consider Great Lakes’ request.  Following extensive discussions with numerous shippers and other stakeholders, on April 20, 2015, ANR filed a settlement with FERC that included an agreement by ANR to pay Great Lakes the difference between the historical and maximum rates (ANR Settlement). Great Lakes provided service to ANR under multiple service agreements and rates through May 3, 2015 when Great Lakes’ tariff records became effective and subject to refund.  Great Lakes deferred an approximate $9 million of revenue related to services performed in 2014 and approximately $14 million of additional revenue related to services performed through May 3, 2015 under such agreements. On October 15, 2015, FERC accepted and approved the ANR Settlement.  As a result, Great Lakes recognized the deferred transportation revenue of approximately $23 million in the fourth quarter of 2015.

PNGTS

For the years ended December 31, 2016 and 2015, PNGTS provided transportation services to a related party. Revenues from TransCanada Energy Ltd., a subsidiary of TransCanada, for 2016 and 2015 were approximately $2 million and $3 million, respectively. At December 31, 2016, PNGTS had nil million outstanding receivables from TransCanada Energy Ltd. in the consolidated balance sheets.

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FAIR VALUE MEASUREMENTS

3 Months Ended

12 Months Ended

Mar. 31, 2017

Dec. 31, 2016

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 $1,905 million and $1,963 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).

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

NOTE 18 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 input 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, accrued interest and short-term debt 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 long-term debt is estimated by discounting the future cash flows of each instrument at estimated current borrowing rates. The fair value of interest rate derivatives is calculated using the income approach which uses period-end market rates and applies a discounted cash flow valuation model.

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

Long-term debt is recorded at amortized cost and classified in Level 2 of the fair value hierarchy for fair value disclosure purposes. Interest rate derivative assets and liabilities are classified in Level 2 for all periods presented where the fair value is determined by using valuation techniques that refer to observable market data or estimated market prices. The estimated fair value of the Partnership’s debt as at December 31, 2016 and December 31, 2015 was $1,963 million and $1,945 million, respectively.

The ATM common units which may be subject to rescission rights, as discussed more fully in Note 9, were measured using the original issuance price, plus statutory interest and less any distributions paid. This fair value measurement is classified as Level 2.

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 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). At December 31, 2015, the fair value of the interest rate swaps accounted for as cash flow hedges was a liability of $1 million both on a gross and net basis. The Partnership did not record any amounts in net income related to ineffectiveness for interest rate hedges for the years ended December 31, 2016, 2015 and 2014. The net change in fair value of interest rate derivative instruments recognized in other comprehensive income was a gain of $2 million for the year ended December 31, 2016 (2015 — nil million, 2014 — loss of $1 million). In 2016, the net realized loss related to the interest rate swaps was $3 million, and was included in financial charges and other (2015 — $2 million, 2014 — $2 million).  Refer to Note 11 — Financial Charges and Other.

The Partnership has no master netting agreements, however, contracts contain 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 net asset of nil million as of December 31, 2016 and there would be no effect on the consolidated balance sheet as of December 31, 2015.

In anticipation of a debt refinancing in 2003, PNGTS entered into forward interest rate swap agreements to hedge the interest rate on its Senior Secured Notes due in 2018. These interest rate swaps were used to manage the impact of interest rate fluctuations and qualified as derivative financial instruments in accordance with ASC 815, Derivatives and Hedging. PNGTS settled its position with a payment of $20.9 million to counterparties at the time of the refinancing and recorded the realized loss in AOCL as of the termination date. The previously recorded AOCL is currently being amortized against earnings over the life of the PNGTS Senior Secured Notes.  At December 31, 2016, our 61.71 percent proportionate share of net unamortized loss on PNGTS included in AOCL was $2 million (2015 - $2 million). For the year ended December 31, 2016, 2015 and 2014, our 61.71 percent proportionate share of the amortization of realized loss on derivative instruments was $0.8 million for each year.

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 cash and cash equivalents and receivables, 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 December 31, 2016, we had not incurred any significant credit losses and had no significant amounts past due or impaired. At December 31, 2016, we had a credit risk concentration on one of our customers and the amount owed is greater than 10 percent of our recasted trade accounts receivable (refer to Note 15).

(c) Other

The estimated fair value measurements on Tuscarora (refer to Note 20) and our equity investment in Great Lakes (refer to Note 4) are both classified as Level 3. In the determination of the fair value, we used internal forecasts on expected future cash flows and applied appropriate discount rates. The determination of expected future cash flows involved significant assumptions and estimates as discussed more fully on Notes 4 and 20.

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ACCOUNTS RECEIVABLE AND OTHER

3 Months Ended

12 Months Ended

Mar. 31, 2017

Dec. 31, 2016

ACCOUNTS RECEIVABLE AND OTHER

ACCOUNTS RECEIVABLE AND OTHER

NOTE 12       ACCOUNTS RECEIVABLE AND OTHER

(unaudited)
(millions of dollars)	March 31, 2017 (a)	December 31, 2016 (a)
Trade accounts receivable, net of allowance of nil	38	44
Imbalance receivable from affiliates	1	2
Other	2	1
	41	47

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

NOTE 19 ACCOUNTS RECEIVABLE AND OTHER

December 31 (millions of dollars)	2016 (a)	2015(a)
Trade accounts receivable, net of allowance of nil	44	40
Imbalance receivable from affiliates	2	1
Other	1	—
	47	41

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

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FINANCIAL CHARGES AND OTHER

3 Months Ended

12 Months Ended

Mar. 31, 2017

Dec. 31, 2016

FINANCIAL CHARGES AND OTHER

FINANCIAL CHARGES AND OTHER

NOTE 13       FINANCIAL CHARGES AND OTHER

	Three months ended
(unaudited)	March 31,
(millions of dollars)	2017 (c )	2016 (c )
Interest Expense (a)	17	18
PNGTS’ amortization of derivative loss on derivative instruments (Note 11) (b)	—	—
Net realized loss related to the interest rate swaps (b)	—	—
Other Income (b)	—	—
	17	18

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

(b)      Nil million for both periods.

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

NOTE 11 FINANCIAL CHARGES AND OTHER

Year ended December 31 (millions of dollars)	2016(a)		2015(a)		2014(a)
Interest expense (b)	69		65		59
Net realized loss related to the interest rate swaps	3		2		2
PNGTS’ amortization of realized loss on derivative instrument (Note 18)	1		1		1
Other	(2	)	(5	)	(1	)
	71		63		61

(a) Recast to consolidate PNGTS for all periods presented.

(b) Effective January 1, 2016, interest expense includes amortization of debt issuance costs and discount costs. Refer to Note 3.

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CONTINGENCIES

3 Months Ended

12 Months Ended

Mar. 31, 2017

Dec. 31, 2016

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.

NOTE 21 CONTINGENCIES

The Partnership and its pipeline systems are subject to various legal proceedings in the ordinary course of business. Our accounting for contingencies covers a variety of business activities, including contingencies for legal and environmental liabilities. The Partnership accrues for these contingencies when the assessments indicate that it is probable that a liability has been incurred or an asset will not be recovered and an amount can be reasonably estimated in accordance with ASC 450 — Contingencies. We base these estimates on currently available facts and the estimates of the ultimate outcome or resolution. Actual results may differ from estimates resulting in an impact, positive or negative, on earnings and cash flow. Contingencies that might result in a gain are not accrued in our consolidated financial statements.

Below are the material legal proceedings that might have a significant impact on the Partnership:

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 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.

Employees Retirement System of the City of St. Louis v. TC PipeLines GP, Inc., et al. — On October 13, 2015, an alleged unitholder of the Partnership filed a class action and derivative complaint in the Delaware Court of Chancery against the General Partner, TransCanada American Investments, Ltd. (TAIL) and TransCanada, and the Partnership as a nominal defendant.   The complaint alleges direct and derivative claims for breach of contract, breach of the duty of good faith and fair dealing, aiding and abetting breach of contract, and tortious interference in connection with the 2015 GTN Acquisition, including the issuance by the Partnership of $95 million in Class B Units and amendments to the Partnership Agreement to provide for the issuance of the Class B Units.   Plaintiff seeks, among other things, to enjoin future issuances of Class B Units to TransCanada or any of its subsidiaries, disgorgement of certain distributions to the General Partner, TransCanada and any related entities, return of some or all of the Class B Units to the Partnership, rescission of the amendments to the Partnership Agreement, monetary damages and attorney fees.   The Partnership has moved to dismiss the complaint and intends to defend vigorously against the claims asserted. In April 2016, the Chancery Court granted the Partnership and other defendants’ motion to dismiss the plaintiffs’ complaint.  The plaintiff has appealed the decision to dismiss its claims.  The appeal of this matter was heard by the Delaware Supreme Court in December, 2016.  The court found in TransCanada’s favor and dismissed the Plaintiff’s motion.  There are no further rights of appeal.

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REGULATORY

3 Months Ended

12 Months Ended

Mar. 31, 2017

Dec. 31, 2016

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 filed its rate case pursuant  to Section 4 of the Natural Gas Act (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 is currently seeking to achieve a mutually beneficial resolution through settlement with its customers.

NOTE 20 GOODWILL AND REGULATORY

Tuscarora - On January 21, 2016, FERC issued an Order initiating an investigation pursuant to Section 5 of the Natural Gas Act of 1938 (NGA) to determine whether Tuscarora’s existing rates for jurisdictional services are just and reasonable. On July 22, 2016, Tuscarora filed a petition with FERC requesting appeal of the Stipulation and Agreement of Settlement (Tuscarora Settlement) Tuscarora made with its customers. On September 22, 2016, FERC approved the Tuscarora Settlement that resolved the Section 5 rate review initiated by FERC in January 2016. Under the terms of the Tuscarora Settlement, Tuscarora’s system-wide unit rate initially decreased by 17 percent, effective August 1, 2016. Unless superseded by a subsequent rate case or settlement, this rate will remain in effect until July 31, 2019, after which time the unit rate will decrease an additional seven percent from August 1, 2019 through July 31, 2022. The settlement does not contain a rate moratorium and requires Tuscarora to file to establish new rates no later than August 1, 2022.

The reduction in Tuscarora’s future cash flows as a result of the Tuscarora Settlement constituted a triggering event in the second quarter of 2016 that led us to evaluate, for possible impairment, the $82 million of goodwill related to our acquisition of Tuscarora.

Our second quarter analysis which was also reviewed for any material updates as part of our annual impairment test on goodwill, resulted in the estimated fair value of Tuscarora exceeding its carrying value but the excess was less than 10 percent. The fair value was measured using a discounted cash flow analysis and included revenues expected from Tuscarora’s current and expected future contracting level. There is a risk that reductions in future cash flow forecasts as a result of Tuscarora not being able to maintain its current contracting level and/or not being able to realize other opportunities on the system, together with adverse changes in other key assumptions such as expected outcome of future rate proceedings, projected operating costs and estimated rate of return on invested capital, could result in a future impairment of the goodwill balance relating to Tuscarora.

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. The requested abandonments will not have any impact on existing firm transportation service.

GTN —   GTN operates under rates established pursuant to a settlement approved by FERC in June 2015. Beginning in January 2016, GTN’s rates decreased by 10 percent and will continue in effect through December 31, 2019. Unless superseded by a subsequent rate case or settlement, GTN’s rates will decrease an additional eight percent for the period January 1, 2020 through December 31, 2021 when GTN will be required to establish new rates.

PNGTS - PNGTS continues to operate under the rates approved by FERC in February 2015 (Refer to Note 2-Significant Accounting Policies-Revenue Recognition). PNGTS has no requirement to file a new rate proceeding.

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VARIABLE INTEREST ENTITIES

3 Months Ended

12 Months Ended

Mar. 31, 2017

Dec. 31, 2016

VARIABLE INTEREST ENTITIES

VARIABLE INTEREST ENTITIES

NOTE 16       VARIABLE INTEREST ENTITIES

In the normal course of business, the Partnership must re-evaluate its legal entities under the current consolidation guidance to determine if those that are considered to be VIEs are appropriately consolidated or if they should be accounted for under other 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 (b)		December 31, 2016 (b)
ASSETS (LIABILITIES) *
Cash and cash equivalents	18		14
Accounts receivable and other	28		33
Inventories	6		6
Other current assets	4		6
Equity investments	930		918
Plant, property and equipment	1,140		1,146
Other assets	2		2
Accounts payable and accrued liabilities	(20	)	(21	)
Accounts payable to affiliates, net	(24	)	(32	)
Distributions payable	(3	)	(3	)
Accrued interest	(5	)	(2	)
State income tax payable	(1	)	—
Current portion of long-term debt	(46	)	(52	)
Long-term debt	(330	)	(337	)
Other liabilities	(26	)	(25	)
Deferred state income tax	(10	)	(10	)

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

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

NOTE 22 VARIABLE INTEREST ENTITIES

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

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

Consolidated VIEs

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

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

(millions of dollars)	December 31, 2016(b)		December 31, 2015(b)
ASSETS (LIABILITIES) (a)
Cash and cash equivalents	14		16
Accounts receivable and other	33		29
Inventories	6		6
Other current assets	6		6
Equity investments	918		965
Plant, property and equipment	1,146		1,180
Other assets	2		2
Accounts payable and accrued liabilities	(21	)	(27	)
Accounts payable to affiliates, net	(32	)	(9	)
Distributions payable	(3	)	(10	)
Accrued interest	(2	)	(1	)
Current portion of long-term debt	(52	)	(36	)
Long-term debt	(337	)	(373	)
Other liabilities	(25	)	(24	)
Deferred state income tax	(10	)	(11	)

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

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

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INCOME TAXES

3 Months Ended

12 Months Ended

Mar. 31, 2017

Dec. 31, 2016

INCOME TAXES

INCOME TAXES

NOTE 17       INCOME TAXES

The state of New Hampshire (NH) imposes a business profits tax (BPT) levied at the PNGTS level. As a result of the BPT, PNGTS recognizes deferred taxes related to temporary differences between the financial statement carrying amount of existing assets and liabilities and their respective tax bases. The deferred taxes at March 31, 2017 and December 31, 2016 relate primarily to utility plant. For the three months ended March 31, 2017 and 2016, the NH BPT effective tax rate was 3.8 percent for all periods and was applied to PNGTS’ taxable income.

The state income taxes of PNGTS are broken out as follows:

	Three months ended
(unaudited)	March 31,
(millions of dollars)	2017 (a)	2016 (a)
State income taxes
Current	1	8
Deferred	—	(7	)
	1	1

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

NOTE 23 INCOME TAXES

The state of New Hampshire (NH) imposes a business profits tax (BPT) levied at the PNGTS level. As a result of the BPT, PNGTS recognizes deferred taxes related to temporary differences between the financial statement carrying amount of existing assets and liabilities and their respective tax bases. The deferred taxes at December 31, 2016, 2015 and 2014 relate primarily to utility plant. For the years ended December 31, 2016, 2015 and 2014, the NH BPT effective tax rate was 3.8 percent for all periods and was applied to PNGTS’ taxable income.

The state income taxes of PNGTS are broken out as follows:

Year ended December 31 (millions of dollars)	2016 (a)	2015 (a)		2014(a)
State income taxes
Current	1	(2	)	3
Deferred	—	4		(1	)
	1	2		2

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

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SUBSEQUENT EVENTS

3 Months Ended

12 Months Ended

Mar. 31, 2017

Dec. 31, 2016

SUBSEQUENT EVENTS

SUBSEQUENT EVENTS

NOTE 18    SUBSEQUENT EVENTS

Management of the Partnership has reviewed subsequent events through August 3, 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.

Partnership

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 was paid 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.

On May 25, 2017, the Partnership closed a $500 million public offering of senior unsecured notes bearing an interest rate of 3.90 percent maturing May 25, 2027. The net proceeds of $497 million were used to fund a portion of the Partnership’s June 1, 2017 acquisition. The indenture for the notes contains customary investment grade covenants.

On June 1, 2017, the Partnership acquired from subsidiaries of TransCanada a 49.34 percent interest in Iroquois Gas Transmission System, L.P. (Iroquois), including an option to acquire a further 0.66 percent interest in Iroquois, together with an additional 11.81 percent interest in PNGTS resulting in the Partnership owning a 61.71 percent interest in PNGTS (2017 Acquisition). The total purchase price of the 2017 Acquisition was $765 million plus preliminary purchase price adjustments amounting to $9 million. The purchase price consisted of  (i) $710 million for the Iroquois interest (less $164 million, which reflected our 49.34 percent share of Iroquois outstanding debt on June 1)  (ii) $55 million for the additional 11.81 percent interest in PNGTS (less $5 million, which reflected our 11.81% proportionate share in PNGTS’ debt on June 1) and (iii) preliminary working capital adjustments on PNGTS and Iroquois amounting to $3 million and $6 million, respectively. Additionally, the Partnership paid $1,000 for the option to acquire TransCanada’s remaining 0.66 percent interest in Iroquois. The Partnership funded the cash portion of the 2017 Acquisition through a combination of proceeds from the May 2017 public debt offering (refer to Note 5) and borrowing under our Senior Credit Facility.

As at the date of the 2017 Acquisition, there was significant cash on Iroquois’ balance sheet.  Pursuant to the Purchase and Sale Agreement associated with the acquisition of the Iroquois interest, as amended, the Partnership agreed to pay $28 million plus interest to TransCanada on August 1, 2017 for its 49.34 percent share of cash determined to be surplus to Iroquois’ operating needs. In addition, the Partnership expects to make a final working capital adjustment payment by the end of August. The $28 million and the related interest were included in accounts payable to affiliates at June 30, 2017.

The Iroquois’ partners adopted a distribution resolution to address the significant cash on Iroquois’ balance sheet post-closing. The Partnership expects to receive the $28 million of unrestricted cash as part of its quarterly distributions from Iroquois over 11 quarters under the terms of the resolution, beginning with the second quarter 2017 distribution on August 1, 2017.

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

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

On July 20, 2017, the board of directors of our General Partner declared the Partnership’s second quarter 2017 cash distribution in the amount of $1.00 per common unit payable on August 11, 2017 to unitholders of record as of August 1, 2017. The declared distribution reflects a $0.06 per common unit increase to the Partnership’s first quarter 2017 quarterly distribution. The declared distribution totaled $74 million and is payable in the following manner: $69 million to common unitholders (including $6 million to the General Partner as a holder of 5,797,106 common units and $11 million to another subsidiary of TransCanada as holder of 11,287,725 common units) and $5 million to our General Partner, which included $2 million for its effective two percent general partner interest and $3 million of IDRs.

Northern Border

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.

Northern Border declared its April 2017 distribution of $14 million on May 12, 2017, of which the Partnership received its 50 percent share or $7 million on May 31, 2017.

Northern Border declared its May 2017 distribution of $12 million on June 7, 2017, of which the Partnership received its 50 percent share or $6 million on June 30, 2017.

Northern Border declared its June 2017 distribution of $14 million on July 7, 2017, of which the Partnership received its 50 percent share or $7 million on July 31, 2017.

Great Lakes

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.

Great Lakes declared its second quarter 2017 distribution of $15 million on July 18, 2017, of which the Partnership will receive its 46.45 percent share or $7 million on August 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 20). We cannot predict the cumulative impact of these circumstances to the Partnership’s earnings and cash flows at this time.

Iroquois

Iroquois declared its second quarter 2017 distribution of $28 million on July 27, 2017, of which the Partnership received its 49.34 percent share or $14 million on August 1, 2017.

NOTE 24 SUBSEQUENT EVENTS

Management of the Partnership has reviewed subsequent events through August 3, 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.

Partnership

On January 23, 2017, the board of directors of our General Partner declared the Partnership’s fourth quarter 2016 cash distribution in the amount of $0.94 per common unit and was paid on February 14, 2017 to unitholders of record as of February 2, 2017. The declared distribution totaled $68 million and was paid in the following manner: $64 million to common unitholders (including $5 million to the General Partner as holder of 5,797,106 common units and $11 million to another subsidiary of TransCanada as holder of 11,287,725 common units) and $4 million to our General Partner, which included $2 million for its effective two percent general partner interest and $2 million of IDRs payment.

On January 23, 2017, the board of directors of our General Partner declared distributions to Class B unitholders in the amount of $22 million and was paid on February 14, 2017. The Class B distribution represents an amount equal to 30 percent of GTN’s distributable cash flow during the year ended December 31, 2016 less $20 million.

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 was paid on May 15, 2017 to unitholders of record as of May 5, 2017. The declared distribution totaled $68 million and was paid in the following manner: $65 million to common unitholders (including $5 million to the General Partner as a holder of 5,797,106 common units and $11 million to another subsidiary of TransCanada as holder of 11,287,725 common units) and $3 million to our General Partner, which included $1 million for its effective two percent general partner interest and $2 million of IDRs.

On May 25, 2017, the Partnership closed a $500 million public offering of senior unsecured notes bearing an interest rate of 3.90 percent maturing May 25, 2027. The net proceeds of $497 million were used to fund a portion of the Partnership’s June 1, 2017  acquisition.The indenture for the notes contains customary investment grade covenants.

On June 1, 2017, the Partnership acquired from subsidiaries of TransCanada a 49.34 percent interest in Iroquois Gas Transmission System, L.P. (Iroquois), including an option to acquire a further 0.66 percent interest in Iroquois, together with an additional 11.81 percent interest in PNGTS resulting in the Partnership owning a 61.71 percent interest in PNGTS (2017 Acquisition). The total purchase price of the 2017 Acquisition was $765 million plus preliminary purchase price adjustments amounting to $9 million. The purchase price consisted of  (i) $710 million for the Iroquois interest (less $164 million, which reflected our 49.34 percent share of Iroquois outstanding debt on June 1)  (ii) $55 million for the additional 11.81 percent interest in PNGTS (less $5 million, which reflected our 11.81% proportionate share in PNGTS’ debt on June 1) and (iii) preliminary working capital adjustments on PNGTS and Iroquois amounting to $3 million and $6 million, respectively. Additionally, the Partnership paid $1,000 for the option to acquire TransCanada’s remaining 0.66 percent interest in Iroquois. The Partnership funded the cash portion of the 2017 Acquisition through a combination of proceeds from the May 2017 public debt offering (refer to Note 5) and borrowing under our Senior Credit Facility.

As at the date of the 2017 Acquisition, there was significant cash on Iroquois’ balance sheet. Pursuant to the Purchase and Sale Agreement associated with the acquisition of the Iroquois interest, as amended, the Partnership agreed to pay $28 million plus interest to TransCanada on August 1, 2017 for its 49.34 percent share of cash determined to be surplus to Iroquois’ operating needs. In addition, the Partnership expects to make a final working capital adjustment payment by the end of August. The $28 million and the related interest were included in accounts payable to affiliates at June 30, 2017.

The Iroquois’ partners adopted a distribution resolution to address the significant cash on Iroquois’ balance sheet post-closing. The Partnership expects to receive the $28 million of unrestricted cash as part of its quarterly distributions from Iroquois over 11 quarters under the terms of the resolution, beginning with the second quarter 2017 distribution on August 1, 2017.

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

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

On July 20, 2017, the board of directors of our General Partner declared the Partnership’s second quarter 2017 cash distribution in the amount of $1.00 per common unit payable on August 11, 2017 to unitholders of record as of August 1, 2017. The declared distribution reflects a $0.06 per common unit increase to the Partnership’s first quarter 2017 quarterly distribution. The declared distribution totaled $74 million and is payable in the following manner: $69 million to common unitholders (including $6 million to the General Partner as a holder of 5,797,106 common units and $11 million to another subsidiary of TransCanada as holder of 11,287,725 common units) and $5 million to our General Partner, which included $2 million for its effective two percent general partner interest and $3 million of IDRs.

Northern Border

Northern Border declared its December 2016 distribution of $16 million on January 9, 2017, of which the Partnership received its 50 percent share or $8 million. The distribution was paid on January 31, 2017.

Northern Border declared its January 2017 distribution of $18 million on February 15, 2017, of which the Partnership received its 50 percent share or $9 million on February 28, 2017.

Northern Border declared its February 2017 distribution of $9 million on March 10, 2017, of which the Partnership received its 50 percent share or $5 million on March 31, 2017.

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.

Northern Border declared its April 2017 distribution of $14 million on May 12, 2017, of which the Partnership received its 50 percent share or $7 million on May 31, 2017.

Northern Border declared its May 2017 distribution of $12 million on June 7, 2017, of which the Partnership received its 50 percent share or $6 million on June 30, 2017.

Northern Border declared its June 2017 distribution of $14 million on July 7, 2017, of which the Partnership received its 50 percent share or $7 million on July 31, 2017.

Great Lakes

Great Lakes declared its fourth quarter 2016 distribution of $14 million on January 9, 2017, of which the Partnership received its 46.45 percent share or $7 million. The distribution was paid on February 1, 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.

Great Lakes declared its second quarter 2017 distribution of $15 million on July 18, 2017, of which the Partnership will receive its 46.45 percent share or $7 million on August 1, 2017.

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 filed its rate case pursuant to Section 4 of the Natural Gas Act. 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 is currently seeking 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 March 31, 2017 General Section 4 Rate Filing. We cannot predict the cumulative impact of these circumstances to the Partnership’s earnings and cash flows at this time.

PNGTS

On January 3, 2017, PNGTS  paid the amount due on December 31, 2016 on its 2003 Senior Secured Notes amounting to $6.3 million representing $5.5 million in principal and $0.8 million in interest pursuant to the terms of the Note Purchase agreement. Under the agreement, any principal and interest that is due on a date other than a normal business day shall be made on the next succeeding business day without additional interest or penalty.

Iroquois

Iroquois declared its second quarter 2017 distribution of $28 million on July 27, 2017, of which the Partnership received its 49.34 percent share or $14 million on August 1, 2017.

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SIGNIFICANT ACCOUNTING POLICIES (Policies)

3 Months Ended

12 Months Ended

Mar. 31, 2017

Dec. 31, 2016

SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation

Basis of Presentation

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

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

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

On June 1, 2017, the Partnership acquired from a subsidiary of TransCanada an additional 11.81 percent interest in PNGTS, resulting in the Partnership owning 61.71 percent in PNGTS (Refer to Note 18-Subsequent Events).  As a result of the Partnership owning 61.71 percent of PNGTS, the Partnership’s historical financial information was recast, except net income (loss) per common unit, to consolidate PNGTS for all the periods presented in these consolidated financial statements. Additionally, this acquisition was accounted for as transaction between entities under common control, similar to pooling of interests, whereby the assets and liabilities of PNGTS were recorded at TransCanada’s carrying value.

Also, on June 1, 2017, the Partnership acquired from subsidiaries of TransCanada a 49.34 percent interest in Iroquois Gas Transmission,L.P (“Iroquois”) (Refer to Note 18-Subsequent Events). Accordingly, the equity method investment in Iroquois was accounted for prospectively and did not form part of these consolidated financial statements.

On January 1, 2016, the Partnership acquired a 49.9 percent interest in PNGTS (2016 PNGTS Acquisition) from a subsidiary of TransCanada. The PNGTS Acquisition was accounted for as a transaction between entities under common control, similar to a pooling of interests, whereby the equity investment in PNGTS was recorded at TransCanada’s carrying value and the total excess purchase price paid was recorded as a reduction in Partners’ Equity. Accordingly, the equity investment in PNGTS is being eliminated as a result of consolidating PNGTS for all the periods presented. Refer to Note 6 for additional disclosure regarding the PNGTS Acquisition.

(a) Basis of Presentation

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

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

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

On June 1, 2017, the Partnership acquired from a subsidiary of TransCanada an additional 11.81 percent interest in PNGTS, resulting in the Partnership owning 61.71 percent in PNGTS (Refer to Note 24-Subsequent Events).  As a result of the Partnership owning 61.71 percent of PNGTS, the Partnership’s historical financial information was recast, except net income (loss) per common unit, to consolidate PNGTS for all the periods presented in these consolidated financial statements. Additionally, this acquisition was accounted for as transaction between entities under common control, similar to pooling of interests, whereby the assets and liabilities of PNGTS were recorded at TransCanada’s carrying value.

Also, on June 1, 2017, the Partnership acquired from subsidiaries of TransCanada a 49.34 percent interest in Iroquois (Refer to Note 24-Subsequent Events). Accordingly, the equity method investment in Iroquois  was accounted prospectively and did not form part of these consolidated financial statements.

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.

(b) 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

12 Months Ended

Mar. 31, 2017

Dec. 31, 2016

EQUITY INVESTMENTS

Schedule of equity investments and summarized financial information for equity investees

	Ownership		Equity Earnings (b)		Equity Investments (b)
	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
			36	33	930	918

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

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

	Ownership Interest at		Equity Earnings (b)			Equity Investments
	December 31,		Year ended December 31			December 31
(millions of dollars)	2016		2016(d)	2015	2014	2016 (d)	2015
Northern Border (a)	50.00	%	69	66	69	444	480
Great Lakes	46.45	%	28	31	19	474	485	(c)
			97	97	88	918	965

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

^(b) Equity Earnings represents our share in investee’s earnings and does not include any impairment charge on the equity method investment recorded as a reduction of carrying value of these investments. Accordingly, no impairment charge was recorded by the Partnership on its equity investees for all the periods presented here except the impairment recognized in 2015 on our investment in Great Lakes as discussed below.

^(c) During the fourth quarter of 2015, we recognized an impairment charge on our investment in Great Lakes amounting to $199 million. See discussion below.

^(d) Recast to eliminate equity earnings from PNGTS and consolidate PNGTS for all periods presented  (Refer to Note 2).

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

December 31 (millions of dollars)	2016		2015
Assets
Cash and cash equivalents	14		27
Other current assets	36		33
Plant, property and equipment, net	1,089		1,124
Other assets (a)	14		16
	1,153		1,200
Liabilities and Partners’ Equity
Current liabilities	38		39
Deferred credits and other	28		26
Long-term debt, net (a), (b)	430		409
Partners’ equity
Partners’ capital	659		728
Accumulated other comprehensive loss	(2	)	(2	)
	1,153		1,200

^(a) As a result of the application of ASU No. 2015-03 and similar to the presentation of debt discounts, debt issuance costs of $2 million at December 31, 2015 previously reported as other assets in the balance sheet were reclassified as an offset against their respective debt liabilities.

^(b) Includes current maturities of $100 million senior notes at December 31, 2015. During August 2016, the $100 million senior notes were refinanced with a draw on Northern Border’s $200 million revolving credit agreement that expires in 2020.

Year ended December 31 (millions of dollars)	2016		2015		2014
Transmission revenues	292		286		293
Operating expenses	(72	)	(70	)	(72	)
Depreciation	(59	)	(60	)	(59	)
Financial charges and other	(21	)	(22	)	(22	)
Net income	140		134		140

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

December 31 (millions of dollars)	2016	2015
Assets
Current assets	66	86
Plant, property and equipment, net	714	727
	780	813
Liabilities and Partners’ Equity
Current liabilities	40	31
Long-term debt, net (a),(b)	278	297
Partners’ equity	462	485
	780	813

^(a) The application of ASU No. 2015-03 did not have a material effect on Great Lakes’ financial statements.

^(b) Includes current maturities of $19 million as of December 31, 2016 (December 31, 2015 - $19 million).

Year ended December 31 (millions of dollars)	2016		2015		2014
Transmission revenues	179		177		146
Operating expenses	(69	)	(59	)	(53	)
Depreciation	(28	)	(28	)	(28	)
Financial charges and other	(21	)	(23	)	(25	)
Net income	61		67		40

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DEBT AND CREDIT FACILITIES (Tables)

3 Months Ended

12 Months Ended

Mar. 31, 2017

Dec. 31, 2016

DEBT AND CREDIT FACILITIES

Schedule of debt and credit facilities

(unaudited) (millions of dollars)	March 31, 2017(b)	Weighted Average Interest Rate for the Quarter Ended March 31, 2017 (b)		December 31, 2016(b)		Weighted Average Interest Rate for the Year Ended December 31, 2016(b)
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	%
PNGTS
5.90% Senior Secured Notes due December 2018	41	5.90	%(a)	53		5.90	%(a)
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)
	1,858			1,920
Less: unamortized debt issuance costs and debt discount	8			9
Less: current portion	46			52	(c)
	1,804			1,859

^(a) Fixed interest rate

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

^(c) Includes the PNGTS portion due at December 31, 2016 amounting to $5.5 million that was paid on January 3, 2017

(millions of dollars)	December 31, 2016 (c)		Weighted Average Interest Rate for the Year Ended December 31, 2016 (c)		December 31, 2015 (c)	Weighted Average Interest Rate for the Year Ended December 31, 2015 (c)
TC PipeLines, LP
Senior Credit Facility due 2021	160		1.72	%	200	1.44	%
2013 Term Loan Facility due 2018	500		1.73	%	500	1.44	%
2015 Term Loan Facility due 2018	170		1.63	%	170	1.47	%
4.65% Unsecured Senior Notes due 2021	350		4.65	%(b)	350	4.65	%(b)
4.375% Unsecured Senior Notes due 2025	350		4.375	%(b)	350	4.375	%(b)
GTN
5.29% Unsecured Senior Notes due 2020	100		5.29	%(b)	100	5.29	%(b)
5.69% Unsecured Senior Notes due 2035	150		5.69	%(b)	150	5.69	%(b)
Unsecured Term Loan Facility due 2019	65		1.43	%	75	1.15	%
PNGTS
5.90% Senior Secured Notes due December 2018	53		5.90	%(b)	69	5.90	%(b)
Tuscarora
Unsecured Term Loan due 2019	10		1.64	%	—	—
3.82% Series D Senior Notes due 2017	12		3.82	%(b)	16	3.82	%(b)
	1,920				1,980
Less: unamortized debt issuance costs and debt discount (a)	9				9
Less: current portion	52	(d)			36
	1,859				1,935

^(a) As a result of the application of ASU No. 2015-03 and similar to the presentation of debt discounts, debt issuance costs of $8 million at December 31, 2015 previously reported as other assets in the balance sheet were reclassified as an offset against debt. Refer to Note 3, Accounting Pronouncements.

^(b) Fixed interest rate.

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

^(d) Includes the PNGTS portion due at December 31, 2016 amounting to $5.5 million that was paid on January 3, 2017 (Refer to Note 24-Subsequent Events).

Schedule of principal repayments required on debt

(unaudited)
(millions of dollars)
2017	40	(a)
2018	715	(a)
2019	43
2020	100
2021	460
Thereafter	500
	1,858	(a)

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

(millions of dollars)
2017	52	(a)
2018	715	(a)
2019	43
2020	100
2021	510
Thereafter	500
	1,920	(a)

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

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NET INCOME PER COMMON UNIT (Tables)

3 Months Ended

12 Months Ended

Mar. 31, 2017

Dec. 31, 2016

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 (a)	77			74
Net income attributable to PNGTS’ former parent (a) (b)	(2		)	(1		)
Net income allocable to General Partner and Limited Partners	75			73
Net income attributable to the General Partner	(1		)	(1		)
Incentive distributions attributable to the General Partner (c)	(2		)	(1		)
Net income attributable to common units	72			71
Weighted average common units outstanding (millions) — basic and diluted (d)	68.3			64.4
Net income per common unit — basic and diluted (e)	$	1.05		$	1.10

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

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

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

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

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

(millions of dollars, except per common unit amounts)	2016			2015			2014
Net income attributable to controlling interests (a)	248			37			195
Net income attributable to PNGTS’ former parent (a) (b)	(4		)	(24		)	(23		)
Net income allocable to General Partner and Limited Partners	244			13			172
Incentive distributions attributable to the General Partner (c)	(7		)	(3		)	(1		)
Net income attributable to the Class B units (d)	(22		)	(12		)	—
Net income (loss) allocable to the General Partner and common units	215			(2		)	171
Net income (loss) allocable to the General Partner’s two percent interest	(4		)	—			(3		)
Net income (loss) attributable to common units	211			(2		)	168
Weighted average common units outstanding (millions) — basic and diluted	65.7		(e)	63.9			62.7
Net income (loss) per common unit — basic and diluted (f)	$	3.21		$	(0.03	)	$	2.67

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

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

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

^(d) As discussed in Note 9, the Class B units entitle TransCanada to a distribution which is an amount based on 30 percent of GTN’s distributions after exceeding certain annual thresholds. The distribution will be payable in the first quarter with respect to the prior year’s distributions. Consistent with the application of Accounting Standards Codification (ASC) Topic 260 — “Earnings per share”, the Partnership allocated a portion of net income attributable to controlling interests to the Class B units in an amount equal to 30 percent of GTN’s total distributable cash flows during the year ended December 31, 2016 less the threshold level of $20 million (2015 - less $15 million). During the year ended December 31, 2016, 30 percent of GTN’s total distributable cash flow was $42 million. As a result of exceeding the threshold level of $20 million, $22 million of net income attributable to controlling interests was allocated to the Class B units at December 31, 2016 (2015 - $12 million). Refer to Note 9.

^(e) Includes the common units subject to rescission. These units are treated as outstanding for financial reporting purposes. Refer to Note 9.

^(f) Net income (loss) per common unit prior to recast.

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CHANGE IN OPERATING WORKING CAPITAL (Tables)

3 Months Ended

12 Months Ended

Mar. 31, 2017

Dec. 31, 2016

CHANGE IN OPERATING WORKING CAPITAL

Schedule of change in operating working capital

(unaudited)	Three months ended March 31,
(millions of dollars)	2017 (b)		2016 (b)
Change in accounts receivable and other	7		(2	)
Change in other current assets	1		3
Change in accounts payable and accrued liabilities	(3	)	3	(a)
Change in accounts payable to affiliates	(1	)	(4	)
Change in state income taxes payable	—		9
Change in accrued interest	3		5
Change in operating working capital	7		14

^(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.

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

Year Ended December 31 (millions of dollars)	2016 (c)		2015(c)		2014(c)
Change in accounts receivable and other	(4	)	6		2
Change in other current assets	(4	)	(1	)	(1	)
Change in accounts payable and accrued liabilities (a)	5		(2	)	29
Change in accounts payable to affiliates	—		(15	) (b)	(6	)
Change in state income taxes payable	—		(5	)	2
Change in accrued interest	2		(3	)	3
Change in operating working capital	(1	)	(20	)	29

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

^(b) Excludes certain non-cash items primarily related to accruals of $10 million for construction of GTN’s Carty Lateral and $2 million of costs related to acquisition of 49.9 percent interest in PNGTS (Refer to Note 6).

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

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RELATED PARTY TRANSACTIONS (Tables)

3 Months Ended

12 Months Ended

Mar. 31, 2017

Dec. 31, 2016

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) (c)	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 (c)	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.

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

Year ended December 31 (millions of dollars)	2016	2015	2014
Capital and operating costs charged by TransCanada’s subsidiaries to:
Great Lakes (a)	30	30	30
Northern Border (a)	32	36	35
PNGTS (a) (b)	8	8	8
GTN (a) (c)	27	30	30
Bison (a) (d)	2	4	6
North Baja	4	5	5
Tuscarora	5	4	4
Impact on the Partnership’s net income attributable to controlling interests:
Great Lakes	13	13	13
Northern Border	12	14	16
PNGTS (b)	5	5	5
GTN (c)	24	25	19
Bison (d)	3	4	4
North Baja	4	5	4
Tuscarora	4	4	4

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) (c)	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.

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

December 31 (millions of dollars)	2016	2015
Amount payable to TransCanada’s subsidiaries for costs charged in the year by:
Great Lakes (a)	4	3
Northern Border (a)	4	5
PNGTS (a) (b)	1	3
GTN	3	3
Bison	1	—
North Baja	1	—
Tuscarora	1	1

^(a) Represents 100 percent of the costs.

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

^(c) In 2015, the Partnership acquired the remaining 30 percent interest in GTN (Refer to Note 6).

^(d) In 2014, the Partnership acquired the remaining 30 percent interest in Bison (Refer to Note 6).

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ACCOUNTS RECEIVABLE AND OTHER (Tables)

3 Months Ended

12 Months Ended

Mar. 31, 2017

Dec. 31, 2016

ACCOUNTS RECEIVABLE AND OTHER

Schedule of accounts receivable and other

(unaudited)
(millions of dollars)	March 31, 2017 (a)	December 31, 2016 (a)
Trade accounts receivable, net of allowance of nil	38	44
Imbalance receivable from affiliates	1	2
Other	2	1
	41	47

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

December 31 (millions of dollars)	2016 (a)	2015(a)
Trade accounts receivable, net of allowance of nil	44	40
Imbalance receivable from affiliates	2	1
Other	1	—
	47	41

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

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FINANCIAL CHARGES AND OTHER (Tables)

3 Months Ended

12 Months Ended

Mar. 31, 2017

Dec. 31, 2016

FINANCIAL CHARGES AND OTHER

Schedule of components of financial charges and other

	Three months ended
(unaudited)	March 31,
(millions of dollars)	2017 (c )	2016 (c )
Interest Expense (a)	17	18
PNGTS’ amortization of derivative loss on derivative instruments (Note 11) (b)	—	—
Net realized loss related to the interest rate swaps (b)	—	—
Other Income (b)	—	—
	17	18

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

(b)      Nil million for both periods.

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

Year ended December 31 (millions of dollars)	2016(a)		2015(a)		2014(a)
Interest expense (b)	69		65		59
Net realized loss related to the interest rate swaps	3		2		2
PNGTS’ amortization of realized loss on derivative instrument (Note 18)	1		1		1
Other	(2	)	(5	)	(1	)
	71		63		61

(a) Recast to consolidate PNGTS for all periods presented.

(b) Effective January 1, 2016, interest expense includes amortization of debt issuance costs and discount costs. Refer to Note 3.

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VARIABLE INTEREST ENTITIES (Tables)

3 Months Ended

12 Months Ended

Mar. 31, 2017

Dec. 31, 2016

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 (b)		December 31, 2016 (b)
ASSETS (LIABILITIES) *
Cash and cash equivalents	18		14
Accounts receivable and other	28		33
Inventories	6		6
Other current assets	4		6
Equity investments	930		918
Plant, property and equipment	1,140		1,146
Other assets	2		2
Accounts payable and accrued liabilities	(20	)	(21	)
Accounts payable to affiliates, net	(24	)	(32	)
Distributions payable	(3	)	(3	)
Accrued interest	(5	)	(2	)
State income tax payable	(1	)	—
Current portion of long-term debt	(46	)	(52	)
Long-term debt	(330	)	(337	)
Other liabilities	(26	)	(25	)
Deferred state income tax	(10	)	(10	)

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

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

(millions of dollars)	December 31, 2016(b)		December 31, 2015(b)
ASSETS (LIABILITIES) (a)
Cash and cash equivalents	14		16
Accounts receivable and other	33		29
Inventories	6		6
Other current assets	6		6
Equity investments	918		965
Plant, property and equipment	1,146		1,180
Other assets	2		2
Accounts payable and accrued liabilities	(21	)	(27	)
Accounts payable to affiliates, net	(32	)	(9	)
Distributions payable	(3	)	(10	)
Accrued interest	(2	)	(1	)
Current portion of long-term debt	(52	)	(36	)
Long-term debt	(337	)	(373	)
Other liabilities	(25	)	(24	)
Deferred state income tax	(10	)	(11	)

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

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

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INCOME TAXES (Tables)

3 Months Ended

12 Months Ended

Mar. 31, 2017

Dec. 31, 2016

INCOME TAXES

Schedule of state income taxes of PNGTS

	Three months ended
(unaudited)	March 31,
(millions of dollars)	2017 (a)	2016 (a)
State income taxes
Current	1	8
Deferred	—	(7	)
	1	1

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

Year ended December 31 (millions of dollars)	2016 (a)	2015 (a)		2014(a)
State income taxes
Current	1	(2	)	3
Deferred	—	4		(1	)
	1	2		2

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

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ORGANIZATION - Ownership Interests in Natural Gas Pipeline Systems (Details) - LimitedPartnership	3 Months Ended	12 Months Ended
	Mar. 31, 2017	Dec. 31, 2016
ORGANIZATION
Number of intermediate limited partnerships through which pipeline assets are owned	3	3

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SIGNIFICANT ACCOUNTING POLICIES - Basis of Presentation (Details)	Aug. 01, 2017	Jun. 01, 2017	Jan. 31, 2016	Jan. 01, 2016
Portland Natural Gas Transmission System
Acquisitions
Ownership interest (as a percent)			49.90%
Iroquois
Acquisitions
Ownership interest (as a percent)	49.34%	49.34%
Portland Natural Gas Transmission System
Acquisitions
Ownership interest (as a percent)		11.81%		49.90%
Interest acquired by Partnership (as a percent)		61.71%

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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)	[1]	$ 28	$ 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

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

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EQUITY INVESTMENTS (Details) - USD ($) $ in Millions		1 Months Ended	3 Months Ended										12 Months Ended
		Apr. 30, 2006	Mar. 31, 2017		Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2016		Dec. 31, 2015		Dec. 31, 2014		Aug. 01, 2017	Jul. 31, 2017	Jun. 30, 2017	May 31, 2017	May 01, 2017	Apr. 28, 2017	Jan. 31, 2016
EQUITY INVESTMENTS
Equity Earnings			$ 36	[1]	$ 22	$ 22	$ 20	$ 33	$ 34	$ 17	$ 15	$ 31	$ 97	[1]	$ 97	[1]	$ 88	[1]
Equity Investments	[1]		930		918				965				918		965
LIABILITIES AND PARTNERS' EQUITY
Current portion of long-term debt	[1]		46		52				36				52		36
Amount borrowed	[1]							195					209		618		35
Great Lakes
EQUITY INVESTMENTS
Total cash call issued to fund debt repayment			$ 9		10			9	10			$ 9
LIABILITIES AND PARTNERS' EQUITY
Current portion of long-term debt					$ 19				19				$ 19		19
Northern Border
EQUITY INVESTMENTS
Ownership interest (as a percent)			50.00%		50.00%								50.00%							50.00%	50.00%	50.00%		50.00%
Equity Earnings			$ 19					18					$ 69		66		69
Equity Investments			441		$ 444				480				444		480
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				27				14		27
Other current assets			36		36				33				36		33
Plant, property and equipment, net			1,085		1,089				1,124				1,089		1,124
Other assets			15		14				16				14		16
Assets, total			1,154		1,153				1,200				1,153		1,200
LIABILITIES AND PARTNERS' EQUITY
Current liabilities			44		38				39				38		39
Deferred credits and other			29		28				26				28		26
Long-term debt, including current maturities, net			430		430				409				430		409
Partners' equity
Partners' equity			653		659				728				659		728
Accumulated other comprehensive loss			(2)		(2)				(2)				(2)		(2)
Liabilities and Partners' Equity, total			1,154		$ 1,153				$ 1,200				1,153		1,200
Revenues (expenses)
Transmission revenues			74					74					292		286		293
Operating expenses			(17)					(16)					(72)		(70)		(72)
Depreciation			(15)					(15)					(59)		(60)		(59)
Financial charges and other			(4)					(6)					(21)		(22)		(22)
Net income			$ 38					37					$ 140		$ 134		140
Great Lakes
EQUITY INVESTMENTS
Ownership interest (as a percent)			46.45%		46.45%				46.45%			46.45%	46.45%		46.45%				46.45%				46.45%
Equity Earnings			$ 17					15					$ 28		$ 31		19
Equity Investments			489		$ 474				$ 485				474		485
Equity contribution			4	[1]	5			4	5			$ 4	9	[1]	9	[1]	9	[1]
Assets
Current assets			86		66				86				66		86
Plant, property and equipment, net			708		714				727				714		727
Assets, total			794		780				813				780		813
LIABILITIES AND PARTNERS' EQUITY
Current liabilities			31		40				31				40		31
Long-term debt, including current maturities, net			269		278				297				278		297
Partners' equity
Partners' equity			494		462				485				462		485
Liabilities and Partners' Equity, total			794		$ 780				$ 813				780		813
Revenues (expenses)
Transmission revenues			63					61					179		177		146
Operating expenses			(14)					(15)					(69)		(59)		(53)
Depreciation			(7)					(7)					(28)		(28)		(28)
Financial charges and other			(5)					(6)					(21)		(23)		(25)
Net income			$ 37					33					$ 61		$ 67		$ 40
Portland Natural Gas Transmission System
EQUITY INVESTMENTS
Ownership interest (as a percent)																									49.90%
Equity contribution	[1]							$ 193

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

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DEBT AND CREDIT FACILITIES - Amounts Outstanding and Description of Terms (Details)					3 Months Ended		12 Months Ended
		Jan. 03, 2017 USD ($)	Dec. 31, 2016 USD ($)	Sep. 30, 2015 USD ($)	Mar. 31, 2017 USD ($) entity	Mar. 31, 2016 USD ($)	Dec. 31, 2016 USD ($)	Dec. 31, 2015 USD ($)	Dec. 31, 2014 USD ($)	Mar. 13, 2015
Credit facilities, short-term loan facility and long-term debt
Long-term debt			$ 1,920,000,000		$ 1,858,000,000		$ 1,920,000,000
Debt and credit facilities			1,920,000,000		1,858,000,000		1,920,000,000
Less: unamortized debt issuance costs and debt discount			9,000,000		8,000,000		9,000,000	$ 9,000,000
Less: current portion	[1]		52,000,000		46,000,000		52,000,000	36,000,000
Long-term debt	[1]		$ 1,859,000,000		$ 1,804,000,000		1,859,000,000	1,935,000,000
Amount borrowed	[1]					$ 195,000,000	$ 209,000,000	618,000,000	$ 35,000,000
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)			401.00%		4.04%		401.00%
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		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%		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%		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			$ 160,000,000		$ 110,000,000		$ 160,000,000	$ 200,000,000
Weighted Average Interest Rate (as a percent)					2.03%		1.72%	1.44%
Maximum borrowing capacity			500,000,000		$ 500,000,000		$ 500,000,000
Amount outstanding under credit facility			160,000,000		110,000,000		160,000,000	$ 200,000,000
Remaining borrowing capacity			$ 340,000,000		$ 390,000,000		$ 340,000,000
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)			1.92%		2.04%		1.92%	1.50%
Term loan | 2013 Term Loan Facility due 2018
Credit facilities, short-term loan facility and long-term debt
Debt and credit facilities			$ 500,000,000		$ 500,000,000		$ 500,000,000	$ 500,000,000
Weighted Average Interest Rate (as a percent)					2.03%		1.73%	1.44%
Term loan | 2013 Term Loan Facility due 2018 | LIBOR borrowings | LIBOR
Credit facilities, short-term loan facility and long-term debt
Weighted Average Interest Rate (as a percent)							2.31%	2.79%
Debt interest rate, at period end (as a percent)			1.87%		2.04%		1.87%	1.50%
Term loan | 2013 Term Loan Facility due 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		$ 170,000,000	$ 170,000,000
Weighted Average Interest Rate (as a percent)					1.93%		1.63%	1.47%
Amount borrowed				$ 170,000,000
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)			1.77%		1.93%		1.77%	1.39%
Unsecured debt | 4.65% Senior Notes due 2021
Credit facilities, short-term loan facility and long-term debt
Stated interest rate (as a percent)			4.65%		4.65%		4.65%	4.65%
Debt and credit facilities			$ 350,000,000		$ 350,000,000		$ 350,000,000	$ 350,000,000
Weighted Average Interest Rate (as a percent)					4.65%		4.65%	4.65%
Unsecured debt | TC PipeLines, LP 4.375% Senior Notes due 2025
Credit facilities, short-term loan facility and long-term debt
Stated interest rate (as a percent)			4.375%		4.375%		4.375%	4.375%		4.375%
Debt and credit facilities			$ 350,000,000		$ 350,000,000		$ 350,000,000	$ 350,000,000
Weighted Average Interest Rate (as a percent)					4.375%		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%		5.29%	5.29%
Debt and credit facilities			$ 100,000,000		$ 100,000,000		$ 100,000,000
Weighted Average Interest Rate (as a percent)					5.29%		5.29%
Unsecured debt | GTN 5.69% Senior Notes due 2035
Credit facilities, short-term loan facility and long-term debt
Stated interest rate (as a percent)			5.69%		5.69%		5.69%	5.69%
Debt and credit facilities			$ 150,000,000		$ 150,000,000		$ 150,000,000
Weighted Average Interest Rate (as a percent)					5.69%		5.69%
Unsecured debt | 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		$ 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		$ 10,000,000
Weighted Average Interest Rate (as a percent)					1.91%		1.64%
Secured debt | 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%		3.82%	3.82%
Debt and credit facilities			$ 12,000,000		$ 12,000,000		$ 12,000,000
Weighted Average Interest Rate (as a percent)					3.82%		3.82%
Secured debt | 5.90% Senior Secured Notes due December 2018
Credit facilities, short-term loan facility and long-term debt
Stated interest rate (as a percent)			5.90%				5.90%	5.90%
GTN
Credit facilities, short-term loan facility and long-term debt
Percentage of debt to total capitalization, actual			44.50%				44.50%
GTN | Unsecured debt | GTN 5.29% Senior Notes due 2020
Credit facilities, short-term loan facility and long-term debt
Debt and credit facilities			$ 100,000,000				$ 100,000,000	$ 100,000,000
Weighted Average Interest Rate (as a percent)							5.29%	5.29%
GTN | Unsecured debt | GTN 5.69% Senior Notes due 2035
Credit facilities, short-term loan facility and long-term debt
Debt and credit facilities			150,000,000				$ 150,000,000	$ 150,000,000
Weighted Average Interest Rate (as a percent)							5.69%	5.69%
GTN | Unsecured debt | Term Loan Facility due 2019
Credit facilities, short-term loan facility and long-term debt
Debt and credit facilities			$ 65,000,000				$ 65,000,000	$ 75,000,000
Weighted Average Interest Rate (as a percent)							1.43%	1.15%
GTN | Unsecured debt | Term Loan Facility due 2019 | LIBOR
Credit facilities, short-term loan facility and long-term debt
Debt interest rate, at period end (as a percent)			1.57%				1.57%	1.19%
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)			1.57%		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%		70.00%
Portland Natural Gas Transmission System | 5.90% Senior Secured Notes due December 2018
Credit facilities, short-term loan facility and long-term debt
Debt and credit facilities			$ 53,000,000		$ 41,000,000		$ 53,000,000
Weighted Average Interest Rate (as a percent)					5.90%		5.90%
Payment of principal amount on secured notes		$ 5,500,000
Portland Natural Gas Transmission System | Secured debt | 5.90% Senior Secured Notes due December 2018
Credit facilities, short-term loan facility and long-term debt
Debt and credit facilities			53,000,000				$ 53,000,000	$ 69,000,000
Weighted Average Interest Rate (as a percent)							5.90%	5.90%
Portland Natural Gas Transmission System | Secured debt | 5.90% Senior Secured Notes due December 2018 | Debt agreement covenants, preceding twelve months
Credit facilities, short-term loan facility and long-term debt
Debt Service Coverage, Actual (as a percent)					1.86%		2.41%
Portland Natural Gas Transmission System | Secured debt | 5.90% Senior Secured Notes due December 2018 | Debt agreement covenants, preceding twelve months | Minimum
Credit facilities, short-term loan facility and long-term debt
Debt Service Coverage, covenant (as a percent)					1.30%		1.30%
Portland Natural Gas Transmission System | Secured debt | 5.90% Senior Secured Notes due December 2018 | Debt agreement covenants, succeeding twelve months
Credit facilities, short-term loan facility and long-term debt
Debt Service Coverage, Actual (as a percent)					1.52%		1.43%
Portland Natural Gas Transmission System | Secured debt | 5.90% Senior Secured Notes due December 2018 | Debt agreement covenants, succeeding twelve months | Minimum
Credit facilities, short-term loan facility and long-term debt
Debt Service Coverage, covenant (as a percent)					1.30%
Tuscarora Gas Transmission Company
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)							1.64%
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)			1.90%		2.12%		1.90%
Tuscarora Gas Transmission Company | Unsecured debt | 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			21.22%		21.05%		21.22%
Debt Service Coverage, Actual (as a percent)			415.00%		3.92%
Tuscarora Gas Transmission Company | Unsecured debt | 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%		300.00%
Tuscarora Gas Transmission Company | Unsecured debt | 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%		45.00%
Tuscarora Gas Transmission Company | Secured debt | 3.82% Series D Senior Notes due 2017
Credit facilities, short-term loan facility and long-term debt
Debt and credit facilities			$ 12,000,000				$ 12,000,000	$ 16,000,000
Weighted Average Interest Rate (as a percent)							3.82%	3.82%

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

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DEBT AND CREDIT FACILITIES - Principal Payments Required (Details) - USD ($) $ in Millions	Mar. 31, 2017	Dec. 31, 2016
Principal repayments required on debt
2017	$ 40
2018	715	$ 715
2019	43	43
2020	100	100
2021	460	510
Thereafter	500	500
Total debt	$ 1,858	$ 1,920

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PARTNERS' EQUITY - ATM Equity Issuance Program (Details) - USD ($)			1 Months Ended	2 Months Ended	3 Months Ended		9 Months Ended		12 Months Ended
		Apr. 01, 2015	Mar. 31, 2016	May 09, 2016	Mar. 31, 2017	May 19, 2016	Sep. 30, 2016	Sep. 30, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Partners' Equity
Net proceeds from issuance of common units	[1]				$ 71,000,000
Equity contribution	[2]									$ 2,000,000
Common units subject to rescission	[1]				64,000,000				$ 83,000,000
General Partner
Partners' Equity
Net proceeds from issuance of common units					$ 2,000,000
Equity contribution		$ 2,000,000								$ 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%	2.00%	2.00%	2.00%	2.00%
ATM Equity Issuance Program
Partners' Equity
Net proceeds from issuance of common units	[2]								$ 84,000,000	$ 44,000,000	$ 73,000,000
ATM Equity Issuance Program | General Partner
Partners' Equity
Net proceeds from issuance of common units									$ 2,000,000	$ 1,000,000	$ 2,000,000
ATM Equity Issuance Program | Common units
Partners' Equity
Units sold					1,197,749	1,619,631			3,100,000	700,000	1,300,000
Net proceeds from issuance of common units					$ 69,000,000
Sales agent commissions					704,000				$ 2,000,000	$ 400,000	$ 1,000,000
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				$ 3,000,000	$ 1,000,000	$ 2,000,000

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

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

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PARTNERS' EQUITY - Class B Units (Details) - USD ($)																3 Months Ended				9 Months Ended	12 Months Ended
		Feb. 14, 2017	Nov. 14, 2016	Aug. 12, 2016	May 13, 2016	Feb. 12, 2016	Nov. 13, 2015	Aug. 14, 2015	May 15, 2015	Apr. 01, 2015	Feb. 13, 2015	Nov. 14, 2014	Aug. 14, 2014	May 15, 2014	Feb. 14, 2014	Mar. 31, 2017		Mar. 31, 2016		Dec. 31, 2015	Dec. 31, 2016		Dec. 31, 2015	Dec. 31, 2014
Class B units
Partners' Equity
Net income attributable to limited partners																					$ 22,000,000		$ 12,000,000
Limited Partners, Distributions paid		$ 22,000,000				$ 12,000,000										$ 22,000,000	[1]	$ 12,000,000	[1]		12,000,000	[1]
Common units
Partners' Equity
Net income attributable to limited partners	[1]															$ 72,000,000		71,000,000			$ 211,000,000		(2,000,000)	$ 168,000,000
Limited Partners, Distributions paid		$ 64,000,000	$ 63,000,000	$ 62,000,000	$ 58,000,000	$ 57,000,000	$ 57,000,000	$ 56,000,000	$ 54,000,000		$ 54,000,000	$ 53,000,000	$ 53,000,000	$ 51,000,000	$ 50,000,000
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%						30.00%					30.00%
Percentage applied to 30 percent of GTN's distributions above threshold through March 31, 2020										100.00%						100.00%
Threshold of GTN's total distributable cash flows for payment to Class B units										$ 20,000,000						$ 20,000,000					$ 20,000,000		$ 15,000,000
Percentage applied to GTN's distributions above threshold after March 31, 2020										25.00%						25.00%
Percentage applied to GTN's distributable cash flow for the twelve month period ending December 31, 2017																30.00%				30.00%	30.00%
Net income attributable to limited partners																$ 0		$ 0

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

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PARTNERS' EQUITY - Reclassification of units (Details) - USD ($) $ in Millions		1 Months Ended	3 Months Ended		12 Months Ended
		Mar. 31, 2017	Mar. 31, 2017	Mar. 31, 2016	Dec. 31, 2016
Partners' Equity
Common units issuance subject to rescission net	[1]			$ 19	$ 83
Net proceeds from issuance of common units	[1]		$ 71
Reclassification of common units no longer subject to rescission (Note 6 )	[1]		$ 19
Common units
Partners' Equity
Reclassification of common units no longer subject to rescission (Note 6 )		$ 19

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

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NET INCOME PER COMMON UNIT - General Partner Effective Interest and Allocated Incentive Distributions (Details)		3 Months Ended	9 Months Ended		12 Months Ended
	Apr. 01, 2015	Mar. 31, 2017	Sep. 30, 2016	Sep. 30, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
TC PipeLines GP, Inc. | General Partner
Partners' Equity
General partner interest (as a percent)	2.00%	2.00%	2.00%	2.00%	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				3 Months Ended											9 Months Ended	12 Months Ended
		Feb. 14, 2017	Apr. 01, 2015	Mar. 31, 2017		Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016		Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2015	Dec. 31, 2016		Dec. 31, 2015		Dec. 31, 2014
Net income (loss) per common unit
Net income attributable to controlling interests				$ 77,000,000	[1]	$ 61,000,000	$ 58,000,000	$ 55,000,000	$ 74,000,000		$ (128,000,000)	$ 52,000,000	$ 46,000,000	$ 67,000,000		$ 248,000,000	[1]	$ 37,000,000	[1]	$ 195,000,000	[1]
Net income attributable to PNGTS' former parent				(2,000,000)					(1,000,000)							(4,000,000)		(24,000,000)		(23,000,000)
Net income allocable to General Partner and Limited Partners				75,000,000					73,000,000							244,000,000		13,000,000		172,000,000
Net income attributable to General Partner				(1,000,000)					(1,000,000)							(4,000,000)				(3,000,000)
Incentive distributions attributable to the General Partner				(2,000,000)					(1,000,000)							(7,000,000)		(3,000,000)		(1,000,000)
Class B units
Net income (loss) per common unit
Net income attributable to limited partners																22,000,000		12,000,000
Common units
Net income (loss) per common unit
Net income attributable to limited partners	[1]			$ 72,000,000					$ 71,000,000							$ 211,000,000		$ (2,000,000)		$ 168,000,000
Weighted average common units outstanding - basic (in units)	[1]			68.3					64.4							65.7		63.9		62.7
Weighted average common units outstanding - diluted (in units)				68.3	[1]				64.4	[1]						65.7		63.9		62.7
Net income per common unit - basic (in dollars per unit)				$ 1.05	[1],[2]	$ 0.70	$ 0.65	$ 0.76	$ 1.10	[2]	$ (2.27)	$ 0.70	$ 0.66	$ 0.88		$ 3.21	[1]	$ (0.03)	[1]	$ 2.67	[1]
Net income per common unit - diluted (in dollars per unit)				$ 1.05	[1],[2]				$ 1.10	[1],[2]						$ 3.21		$ (0.03)		$ 2.67
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%											30.00%	30.00%
Threshold of GTN's distributions for payment to Class B units		$ 20,000,000		$ 20,000,000											$ 15,000,000	$ 20,000,000		$ 15,000,000
Portion of GTN's annual distributions to which the Class B units are entitled to receive a percentage share of the distributions above threshold (as a percent)			30.00%	30.00%												30.00%

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

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

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CASH DISTRIBUTIONS TO COMMON UNITS - Distributions Paid (Details) - USD ($) $ / shares in Units, $ in Millions															3 Months Ended		9 Months Ended		12 Months Ended
	Feb. 14, 2017	Nov. 14, 2016	Aug. 12, 2016	May 13, 2016	Feb. 12, 2016	Nov. 13, 2015	Aug. 14, 2015	May 15, 2015	Apr. 01, 2015	Feb. 13, 2015	Nov. 14, 2014	Aug. 14, 2014	May 15, 2014	Feb. 14, 2014	Mar. 31, 2017	Mar. 31, 2016	Sep. 30, 2016	Sep. 30, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Distributions
Incentive distribution paid to the General Partner	$ 2	$ 2	$ 2	$ 1	$ 1	$ 1	$ 1				$ 1								$ 6	$ 2	$ 1
Common units
Distributions
Per Unit Distribution, paid (in dollars per unit)	$ 0.94	$ 0.94	$ 0.94	$ 0.89	$ 0.89	$ 0.89	$ 0.89	$ 0.84		$ 0.84	$ 0.84	$ 0.84	$ 0.81	$ 0.81	$ 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%	2.00%	2.00%	2.00%	2.00%
TC PipeLines GP, Inc. | Common units and General Partner interest combined
Distributions
Incentive distribution paid to the General Partner															$ 2	$ 1

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CHANGE IN OPERATING WORKING CAPITAL - Components (Details) - USD ($) $ in Millions		3 Months Ended		12 Months Ended
		Mar. 31, 2017	Mar. 31, 2016	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
CHANGE IN OPERATING WORKING CAPITAL
Change in accounts receivable and other		$ 7	$ (2)	$ (4)	$ 6	$ 2
Change in other current assets		1	3	(4)	(1)	(1)
Change in accounts payable and accrued liabilities		(3)	3	5	(2)	29
Change in state income taxes payable			9		(5)	2
Change in accounts payable to affiliates		(1)	(4)		(15)	(6)
Change in accrued interest		3	5	2	(3)	3
Change in operating working capital	[1]	$ 7	$ 14	$ (1)	$ (20)	$ 29

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

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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, 2016	Dec. 31, 2015	Dec. 31, 2014
Non-cash items
Accruals for capital expenditures	[1]				$ 10
Capital expenditures	[1]	$ 7	$ 11	$ 29	54	$ 10
GTN
Non-cash items
Accruals for capital expenditures					$ 10
Capital expenditures			$ 10

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

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RELATED PARTY TRANSACTIONS (Details) - USD ($) $ in Millions		3 Months Ended		12 Months Ended
		Mar. 31, 2017	Mar. 31, 2016	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Aug. 01, 2017	Jul. 31, 2017	Jun. 30, 2017	May 31, 2017	May 01, 2017	Apr. 28, 2017	Jan. 31, 2016	Mar. 31, 2015
Capital and operating costs charged to the pipeline systems and amount payable
Net amounts payable	[1]	$ 7.0		$ 8.0	$ 8.0
Amount included in receivables from related party		$ 1.0		$ 2.0	$ 1.0
Portland Natural Gas Transmission System
Capital and operating costs charged to the pipeline systems and amount payable
Interest acquired by Partnership (as a percent)		61.71%		61.71%
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%		46.45%				46.45%			46.45%
Estimated revenue sharing provision				$ 7.2
Northern Border
Capital and operating costs charged to the pipeline systems and amount payable
Interest acquired (as a percent)		50.00%		50.00%				50.00%	50.00%	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%
General Partner | Reimbursement of costs of services provided
Capital and operating costs charged to the pipeline systems and amount payable
Costs charged		$ 1.0	$ 1.0	$ 3.0	$ 3.0	$ 3.0
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	27.0	30.0	30.0
Impact on the Partnership's net income attributable to controlling interests		$ 7.0	$ 5.0	$ 24.0	$ 25.0	$ 19.0
Percentage of capital and operating costs charged		100.00%	100.00%	100.00%	100.00%	100.00%
TransCanada's subsidiaries | Northern Border
Capital and operating costs charged to the pipeline systems and amount payable
Net amounts payable		$ 3.0		$ 4.0	$ 5.0
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	$ 32.0	$ 36.0	$ 35.0
Percentage of capital and operating costs charged		100.00%	100.00%	100.00%	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	$ 3.0
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	$ 8.0	8.0	$ 8.0
Percentage of capital and operating costs charged		100.00%	100.00%	100.00%
TransCanada's subsidiaries | Portland Natural Gas Transmission System | Transportation contracts
Capital and operating costs charged to the pipeline systems and amount payable
Amount included in receivables from related party		$ 0.0		$ 0.0
Revenues from related party		0.0	$ 1.0	2.0	3.0
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		2.0	4.0	6.0
Revenue, net of costs charged			(1.0)
Impact on the Partnership's net income attributable to controlling interests		1.0	$ 1.0
Impact on the Partnership's net income attributable to controlling interests				$ 3.0	$ 4.0	$ 4.0
Percentage of capital and operating costs charged				100.00%	100.00%	100.00%
TransCanada's subsidiaries | Great Lakes
Capital and operating costs charged to the pipeline systems and amount payable
Net amounts payable		$ 3.0		$ 4.0	$ 3.0
Percentage of capital and operating costs charged		100.00%	100.00%
Amount included in receivables from related party		$ 15.0		19.0	17.0
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	30.0	30.0	$ 30.0
Impact on the Partnership's net income attributable to controlling interests				$ 13.0	$ 13.0	$ 13.0
Percentage of capital and operating costs charged		100.00%	100.00%	100.00%	100.00%	100.00%
Amount included in receivables from related party				$ 27.0	$ 51.0
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				68.00%	71.00%	49.00%
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	4.0	$ 5.0	$ 5.0
Impact on the Partnership's net income attributable to controlling interests		1.0	1.0	4.0	5.0	4.0
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	5.0	4.0	4.0
Impact on the Partnership's net income attributable to controlling interests		1.0	1.0	4.0	4.0	4.0
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	12.0	14.0	16.0
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	$ 5.0	$ 5.0	$ 5.0

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

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FAIR VALUE MEASUREMENTS - Estimated Fair Value of Debt (Details) - USD ($) $ in Millions	Mar. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Fair Value | Level 2
Financial Instruments
Fair value of debt	$ 1,905.0	$ 1,963.0	$ 1,945.0

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FAIR VALUE MEASUREMENTS - Interest Rate Swaps (Details) - USD ($)		3 Months Ended		12 Months Ended
		Mar. 31, 2017	Mar. 31, 2016	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Jul. 01, 2013
Interest rate derivatives
Change in fair value of interest rate derivative instruments recognized in other comprehensive income (loss)	[1]			$ 1,000,000	$ 1,000,000	$ 1,000,000
Term loan | 2013 Term Loan Facility due 2018
Interest rate derivatives
Amount of facility							$ 500,000,000
Portland Natural Gas Transmission System
Interest rate derivatives
Change in fair value of interest rate derivative instruments recognized in other comprehensive income (loss)				1,000,000	1,000,000	1,000,000
Payments for derivative instruments		$ 20,900,000		$ 20,900,000
Interest acquired by Partnership (as a percent)		61.71%		61.71%
Net unamortized loss included in AOCL		$ 2,000,000		$ 2,000,000	2,000,000
Amortization of derivatives loss		$ 0	$ 0	$ 800,000	800,000	800,000
Interest rate swaps | Term loan | 2013 Term Loan Facility due 2018
Interest rate derivatives
Weighted average fixed interest rate (as a percent)		2.31%		2.31%
Hedges of cash flows | Interest rate swaps
Interest rate derivatives
Change in fair value of interest rate derivative instruments recognized in other comprehensive income (loss)		$ 1,000,000	(2,000,000)	$ 2,000,000	0	(1,000,000)
Hedges of cash flows | Interest rate swaps | Financial charges and other
Interest rate derivatives
Net realized loss related to the interest rate swaps		0	$ 0	3,000,000	2,000,000	$ 2,000,000
Hedges of cash flows | Interest rate swaps | Recurring fair value measurement | Level 2
Interest rate derivatives
Fair value of derivative asset, gross				1,000,000
Fair value of derivative liability, gross				1,000,000
Fair value of derivatives, net		2,000,000		0	1,000,000
Designated as hedge | Interest rate swaps | Recurring fair value measurement | Level 2
Interest rate derivatives
Fair value of derivative asset, gross		$ 2,000,000
Fair value of derivative liability, gross				0	$ 1,000,000
Designated as hedge | Hedges of cash flows | Interest rate swaps | Level 2
Interest rate derivatives
Fair value of derivative asset, gross				1,000,000
Fair value of derivative liability, gross				$ 1,000,000

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

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ACCOUNTS RECEIVABLE AND OTHER (Details) - USD ($) $ in Millions		Mar. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
ACCOUNTS RECEIVABLE AND OTHER
Trade accounts receivable, net of allowance of nil		$ 38	$ 44	$ 40
Imbalance receivable from affiliates		1	2	1
Other		2	1
Accounts receivable and other	[1]	41	47	41
Trade accounts receivable, allowance		$ 0	$ 0	$ 0

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

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FINANCIAL CHARGES AND OTHER (Details) - USD ($) $ in Millions		3 Months Ended		12 Months Ended
		Mar. 31, 2017	Mar. 31, 2016	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
FINANCIAL CHARGES AND OTHER
Interest Expense		$ 17	$ 18
Amortization of realized loss on derivative instrument (Note 11)	[1]			$ 1	$ 1	$ 1
Financial charges and other	[1]	$ 17	$ 18	$ 71	$ 63	$ 61

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

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CONTINGENCIES (Details) - Great Lakes v. Essar Steel Minnesota LLC, et al. - Great Lakes - USD ($) $ in Millions			1 Months Ended	12 Months Ended
	Sep. 16, 2015	Oct. 29, 2009	Apr. 30, 2017	Dec. 31, 2017
Contingencies
Judgement awarded			$ 31.5	$ 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		3 Months Ended		12 Months Ended
		Mar. 31, 2017	Mar. 31, 2016	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
ASSETS (LIABILITIES)
Cash and cash equivalents	[1]	$ 77	$ 69	$ 64	$ 55	$ 153	$ 116
Accounts receivable and other	[1]	41		47	41
Inventories	[1]	7		7	7
Other current assets	[1]	6		7	3
Equity investments	[1]	930		918	965
Plant, property and equipment	[1]	2,162		2,180	2,257
Other assets	[1]	1		1	1
Accounts payable and accrued liabilities	[1]	(26)		(29)	(34)
Accounts payable to affiliates	[1]	(7)		(8)	(8)
Distributions payable	[1]	(3)		(3)	(10)
Accrued interest	[1]	(13)		(10)	(8)
State income tax payable	[1]	(1)	$ (1)	(1)	(2)	$ (2)
Current portion of long-term debt	[1]	(46)		(52)	(36)
Long-term debt	[1]	(1,804)		(1,859)	(1,935)
Other liabilities	[1]	(28)		(28)	(27)
Consolidated VIEs | Restricted VIEs
ASSETS (LIABILITIES)
Cash and cash equivalents		18		14	16
Accounts receivable and other		28		33	29
Inventories		6		6	6
Other current assets		4		6	6
Equity investments		930		918	965
Plant, property and equipment		1,140		1,146	1,180
Other assets		2		2	2
Accounts payable and accrued liabilities		(20)		(21)	(27)
Accounts payable to affiliates		(24)		(32)	(9)
Distributions payable		(3)		(3)	(10)
Accrued interest		(5)		(2)	(1)
State income tax payable		(1)
Current portion of long-term debt		(46)		(52)	(36)
Long-term debt		(330)		(337)	(373)
Other liabilities		(26)		(25)	(24)
Deferred state income tax		$ (10)		$ (10)	$ (11)

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

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INCOME TAXES (Details) - USD ($) $ in Millions		3 Months Ended		12 Months Ended
		Mar. 31, 2017	Mar. 31, 2016	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
State income taxes
Deferred	[1]				$ 4	$ (1)
Total state income taxes	[1]	$ 1	$ 1	$ 1	$ 2	$ 2
Portland Natural Gas Transmission System
INCOME TAXES
Effective income tax rate (as a percent)		3.80%	3.80%	3.80%	3.80%	3.80%
State income taxes
Current		$ 1	$ 8	$ 1	$ (2)	$ 3
Deferred			(7)		4	(1)
Total state income taxes		$ 1	$ 1	$ 1	$ 2	$ 2

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

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SUBSEQUENT EVENTS - Distributions (Details) - USD ($)																																																								3 Months Ended				9 Months Ended		12 Months Ended
		Aug. 11, 2017	Aug. 01, 2017	Jul. 31, 2017	Jul. 27, 2017	Jul. 20, 2017	Jul. 18, 2017	Jul. 07, 2017	Jun. 30, 2017	Jun. 07, 2017	Jun. 01, 2017	May 31, 2017	May 25, 2017	May 15, 2017	May 12, 2017	May 01, 2017	Apr. 28, 2017	Apr. 25, 2017	Apr. 24, 2017	Apr. 19, 2017	Apr. 07, 2017	Mar. 31, 2017	Mar. 10, 2017	Feb. 28, 2017	Feb. 15, 2017	Feb. 14, 2017	Feb. 01, 2017	Jan. 31, 2017	Jan. 23, 2017	Jan. 09, 2017	Nov. 14, 2016	Oct. 20, 2016	Aug. 12, 2016	Jul. 21, 2016	May 13, 2016	Apr. 21, 2016	Feb. 12, 2016	Jan. 21, 2016	Nov. 13, 2015	Oct. 22, 2015	Aug. 14, 2015	Jul. 23, 2015	May 15, 2015	Apr. 23, 2015	Apr. 01, 2015	Feb. 13, 2015	Jan. 22, 2015	Nov. 14, 2014	Oct. 23, 2014	Aug. 14, 2014	Jul. 23, 2014	May 15, 2014	Apr. 25, 2014	Feb. 14, 2014	Jan. 16, 2014	Mar. 31, 2017		Mar. 31, 2016		Sep. 30, 2016	Sep. 30, 2015	Dec. 31, 2016		Dec. 31, 2015		Dec. 31, 2014		Jan. 31, 2016	Jan. 01, 2016	Mar. 31, 2015
Distributions
Accounts payable to affiliates	[1]																					$ 7,000,000																																		$ 7,000,000						$ 8,000,000		$ 8,000,000
General Partner IDRs paid																										$ 2,000,000					$ 2,000,000		$ 2,000,000		$ 1,000,000		$ 1,000,000		$ 1,000,000		$ 1,000,000							$ 1,000,000														6,000,000		2,000,000		$ 1,000,000
Partnership distribution																																																								93,000,000	[1]					$ 276,000,000	[2]	268,000,000	[2]	292,000,000	[2]
Equity contribution	[2]																																																															$ 2,000,000
Partnership's share of distributions	[1]																																																							$ 28,000,000		$ 41,000,000
Northern Border
Distributions
Ownership interest (as a percent)				50.00%					50.00%			50.00%					50.00%					50.00%																																		50.00%						50.00%
Great Lakes
Distributions
Ownership interest (as a percent)			46.45%													46.45%						46.45%																																		46.45%						46.45%		46.45%						46.45%
Iroquois
Distributions
Ownership interest (as a percent)			49.34%								49.34%
Portland Natural Gas Transmission System
Distributions
Ownership interest (as a percent)																																																																				49.90%
Portland Natural Gas Transmission System
Distributions
Interest acquired by Partnership (as a percent)																						61.71%																																		61.71%						61.71%
Portland Natural Gas Transmission System
Distributions
Ownership interest (as a percent)											11.81%																																																										49.90%
Interest acquired by Partnership (as a percent)											61.71%
Subsequent event
Distributions
Total cash distribution		$ 74,000,000												$ 68,000,000												68,000,000
Subsequent event | Iroquois
Distributions
Ownership interest (as a percent)			49.34%
Subsequent event | Portland Natural Gas Transmission System
Distributions
Interest acquired by Partnership (as a percent)											11.81%
Subsequent event | Portland Natural Gas Transmission System
Distributions
Ownership interest, including acquired interest (as a percent)											61.71%
Subsequent event | Portland Natural Gas Transmission System | Iroquois
Distributions
Purchase price											$ 765,000,000
Subsequent event | Distribution declared | Northern Border
Distributions
Distribution declared								$ 14,000,000		$ 12,000,000					$ 14,000,000						$ 13,000,000		$ 9,000,000		$ 18,000,000					$ 16,000,000
Subsequent event | Distribution declared | Great Lakes
Distributions
Distribution declared							$ 15,000,000													$ 43,000,000										$ 14,000,000
Subsequent event | Distribution declared | Iroquois
Distributions
Distribution declared					$ 28,000,000
Subsequent event | Distribution declared | Northern Border
Distributions
Partnership distribution								$ 14,000,000		$ 12,000,000					$ 14,000,000						$ 13,000,000
Subsequent event | Distribution declared | Great Lakes
Distributions
Partnership distribution							$ 15,000,000													$ 43,000,000
Subsequent event | Distribution declared | Iroquois
Distributions
Partnership distribution					$ 28,000,000
Subsequent event | Cash Distribution Paid | Northern Border
Distributions
Partnership's share of distributions				$ 7,000,000					$ 6,000,000			$ 7,000,000					$ 7,000,000					$ 5,000,000		$ 9,000,000				$ 8,000,000
Subsequent event | Cash Distribution Paid | Great Lakes
Distributions
Partnership's share of distributions			$ 7,000,000													$ 20,000,000											$ 7,000,000
Subsequent event | Cash Distribution Paid | Iroquois
Distributions
Partnership's share of distributions			14,000,000
Common units and General Partner interest combined
Distributions
Total distribution of general partner interest and IDR payment																																																								$ 4,000,000
General Partner
Distributions
Partnership distribution																																																								4,000,000	[1]					$ 10,000,000	[2]	$ 7,000,000	[2]	$ 5,000,000	[2]
Equity contribution																																													$ 2,000,000																			$ 2,000,000
TC PipeLines GP, Inc. | Subsequent event
Distributions
Ownership interest (as a percent)						2.00%												2.00%
General partner cash distributions						$ 5,000,000												$ 3,000,000								4,000,000
Ownership interest in the Partnership (as a percent)						2.00%												2.00%
Total Distribution For General Partner Interest						$ 2,000,000												$ 1,000,000								2,000,000
TC PipeLines GP, Inc. | Common units and General Partner interest combined
Distributions
General Partner IDRs paid																																																								$ 2,000,000		1,000,000
TC PipeLines GP, Inc. | General Partner
Distributions
Ownership interest in the Partnership (as a percent)																																													2.00%											2.00%				2.00%	2.00%	2.00%		2.00%		2.00%
Total Distribution For General Partner Interest																																																								$ 2,000,000		1,000,000
TC PipeLines GP, Inc. | General Partner | Subsequent event | Distribution declared
Distributions
Distribution declared for IDRs						$ 3,000,000												$ 2,000,000								2,000,000
TC PipeLines GP, Inc. | 3.90% Senior Notes due 2027 | Unsecured debt | Subsequent event
Distributions
Amount of debt													$ 500,000,000
Stated interest rate (as a percent)													3.90%
Net proceeds													$ 497,000,000
Transaction between entities under common control | Subsequent event | Portland Natural Gas Transmission System
Distributions
Ownership interest, including acquired interest (as a percent)											61.71%
Capital and operating costs | Subsequent event
Distributions
Accounts payable to affiliates									$ 28,000,000
TransCanada | Subsequent event | Great Lakes
Distributions
Contract term																			10 years
Total contract value																			$ 758,000,000
Forecast | Subsequent event | Iroquois
Distributions
Ownership interest (as a percent)											49.34%
Future option to acquire (as a percent)											0.66%
Forecast | Subsequent event | Portland Natural Gas Transmission System
Distributions
Interest acquired by Partnership (as a percent)											11.81%
Forecast | Subsequent event | Portland Natural Gas Transmission System
Distributions
Ownership interest, including acquired interest (as a percent)											61.71%
Purchase price											$ 55,000,000
Purchase price adjustments											3,000,000
Assumption of proportional debt											5,000,000
Forecast | Subsequent event | Portland Natural Gas Transmission System | Portland Natural Gas Transmission System And Iroquois Acquisition
Distributions
Purchase price											765,000,000
Purchase price adjustments											9,000,000
Forecast | Subsequent event | Iroquois
Distributions
Purchase price											710,000,000
Purchase price adjustments											6,000,000
Assumption of proportional debt											164,000,000
Amount of future option to acquire											$ 1,000
Forecast | Subsequent event | Cash Distribution Paid | Iroquois
Distributions
Partnership's share of distributions			$ 14,000,000
Forecast | Transaction between entities under common control | Subsequent event | Portland Natural Gas Transmission System
Distributions
Interest acquired by Partnership (as a percent)											11.81%
Forecast | Transaction between entities under common control | Subsequent event | Iroquois
Distributions
Interest acquired by Partnership (as a percent)											49.34%
Common units
Distributions
Per Unit Distribution, declared (in dollars per unit)																													$ 0.94			$ 0.94		$ 0.94		$ 0.89		$ 0.89		$ 0.89		$ 0.89		$ 0.84			$ 0.84		$ 0.84		$ 0.84		$ 0.81		$ 0.81
Total cash distribution																																																								$ 68,000,000		$ 60,000,000
Distribution declared																													$ 64,000,000			$ 63,000,000		$ 62,000,000		$ 58,000,000		$ 57,000,000		$ 57,000,000		$ 56,000,000		$ 54,000,000			$ 54,000,000		$ 53,000,000		$ 53,000,000		$ 51,000,000		$ 50,000,000
Limited Partners, Distributions paid																										64,000,000					$ 63,000,000		$ 62,000,000		$ 58,000,000		57,000,000		$ 57,000,000		$ 56,000,000		$ 54,000,000			$ 54,000,000		$ 53,000,000		$ 53,000,000		$ 51,000,000		$ 50,000,000
Number of units	[1]																					68,600,000																																		68,600,000		64,700,000				67,400,000		64,300,000		63,600,000
Common units | Subsequent event
Distributions
Per Unit Distribution, declared (in dollars per unit)		$ 0.06				$ 1.00												$ 0.94											$ 0.94
Distribution declared		$ 69,000,000												65,000,000				$ 65,000,000								64,000,000
Common units | Limited Partners
Distributions
Partnership distribution																																																								$ 64,000,000	[1]					$ 240,000,000	[2]	$ 221,000,000	[2]	$ 207,000,000	[2]
Number of units																																																														67,454,831
Common units | TC PipeLines GP, Inc. | Subsequent event
Distributions
Per Unit Distribution, declared (in dollars per unit)						$ 1.00
Total cash distribution						$ 74,000,000
Distribution declared						69,000,000
Limited Partners, Distributions paid		6,000,000				6,000,000								5,000,000
General partner cash distributions						$ 11,000,000																				5,000,000
Common units | TC PipeLines GP, Inc. | Subsequent event | Distribution declared
Distributions
Increase to Partnership's quarterly distribution (per unit)						$ 0.06
Common units | TC PipeLines GP, Inc. | Limited Partners
Distributions
Number of units																		5,797,106																																												5,797,106
Common units | TC PipeLines GP, Inc. | Limited Partners | Subsequent event
Distributions
Number of units						5,797,106												5,797,106											5,797,106
Common units | TransCanada | Subsequent event
Distributions
Limited Partners, Distributions paid		$ 11,000,000												$ 11,000,000												11,000,000
Common units | TransCanada | Limited Partners
Distributions
Number of units																																																														11,287,725
Common units | TransCanada | TC PipeLines GP, Inc.
Distributions
Number of units																		11,287,725
Common units | TransCanada | TC PipeLines GP, Inc. | Subsequent event
Distributions
Number of units						11,287,725												11,287,725											11,287,725
Class B units
Distributions
Distribution declared																													$ 22,000,000									$ 12,000,000																		22,000,000
Limited Partners, Distributions paid																										22,000,000											$ 12,000,000																			22,000,000	[1]	$ 12,000,000	[1]			$ 12,000,000	[1]
Class B units | Subsequent event
Distributions
Distribution declared																													$ 22,000,000
Limited Partners, Distributions paid																										$ 22,000,000
Class B units | Limited Partners
Distributions
Partnership distribution																																																								$ 22,000,000	[1]					$ 12,000,000	[2]
Class B units | TransCanada | Limited Partners
Distributions
Number of units																																																														1,900,000

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

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