TC Pipelines (TCP) 8-K 3 Aug 17 Other Events Financial data

Document and Entity Information

Document and Entity Information	3 Months Ended
	Mar. 31, 2017
Document and Entity Information
Entity Registrant Name	TC PIPELINES LP
Entity Central Index Key	1,075,607
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

CONSOLIDATED BALANCE SHEETS

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).

CONSOLIDATED STATEMENTS OF INCO

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).

CONSOLIDATED STATEMENTS OF COMP

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME $ in Millions	12 Months Ended
	Dec. 31, 2016USD ($)	[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).

CONSOLIDATED STATEMENTS OF CASH

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).

CONSOLIDATED STATEMENTS OF CAS6

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%

CONSOLIDATED STATEMENT OF CHANG

CONSOLIDATED STATEMENT OF CHANGES IN PARTNERS' EQUITY - USD ($) shares in Millions, $ in Millions		Limited PartnersCommon unitsGTN	Limited PartnersCommon unitsBison	Limited PartnersCommon unitsPortland Natural Gas Transmission System	Limited PartnersCommon unitsATM Equity Issuance Program	Limited PartnersCommon units		Limited PartnersClass B units		General PartnerGTN	General PartnerPortland Natural Gas Transmission System	General PartnerATM Equity Issuance Program	General Partner		AOCL		Common unitsATM Equity Issuance Program	Class B units	[1]	Non-controlling interestsGTN	[1]	Non-controlling interestsBison	[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.

CONSOLIDATED STATEMENT OF CHAN8

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%

ORGANIZATION

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).

SIGNIFICANT ACCOUNTING POLICIES

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 (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 (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.

ACCOUNTING PRONOUNCEMENTS

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.

EQUITY INVESTMENTS

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) % Great Lakes % (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 Other current assets Plant, property and equipment, net Other assets LIABILITIES AND PARTNERS’ EQUITY Current liabilities Deferred credits and other Long-term debt, including current maturities, net Partners’ equity Partners’ capital Accumulated other comprehensive loss ) ) Three months ended (unaudited) March 31, (millions of dollars) 2017 2016 Transmission revenues Operating expenses ) ) Depreciation ) ) Financial charges and other ) ) Net income 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 Plant, property and equipment, net LIABILITIES AND PARTNERS’ EQUITY Current liabilities Long-term debt, including current maturities, net Partners’ equity Three months ended (unaudited) March 31, (millions of dollars) 2017 2016 Transmission revenues Operating expenses ) ) Depreciation ) ) Financial charges and other ) ) Net income	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 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) % Great Lakes % (c) (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 Other current assets Plant, property and equipment, net Other assets (a) Liabilities and Partners’ Equity Current liabilities Deferred credits and other Long-term debt, net (a), (b) Partners’ equity Partners’ capital Accumulated other comprehensive loss ) ) (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 Operating expenses ) ) ) Depreciation ) ) ) Financial charges and other ) ) ) Net income 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 Plant, property and equipment, net Liabilities and Partners’ Equity Current liabilities Long-term debt, net (a),(b) Partners’ equity (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 Operating expenses ) ) ) Depreciation ) ) ) Financial charges and other ) ) ) Net income

PLANT, PROPERTY AND EQUIPMENT

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 Cost Accumulated Net Cost Accumulated Net Pipeline ) ) Compression ) ) Metering and other ) ) Construction in progress — — ) ) (a) Recast to consolidate PNGTS for all periods presented (Refer to Note 2).

ACQUISITIONS

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) Less: TransCanada’s carrying value of PNGTS’ net assets at January 1, 2016 Excess purchase price (b) (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) Less: TransCanada’s carrying value of non-controlling interest at April 1, 2015 Excess purchase price (b) (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 TransCanada’s carrying value of non-controlling interest at October 1, 2014 Excess purchase price The excess purchase price of $29 million was recorded as a reduction in Partners’ Equity.

DEBT AND CREDIT FACILITIES

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) March 31, (b) Weighted Average (b) December 31, (b) Weighted Average (b) TC PipeLines, LP Senior Credit Facility due 2021 % % 2013 Term Loan Facility due July 2018 % % 2015 Term Loan Facility due September 2018 % % 4.65% Unsecured Senior Notes due 2021 % (a) % (a) 4.375% Unsecured Senior Notes due 2025 % (a) % (a) GTN 5.29% Unsecured Senior Notes due 2020 % (a) % (a) 5.69% Unsecured Senior Notes due 2035 % (a) % (a) Unsecured Term Loan Facility due 2019 % % PNGTS 5.90% Senior Secured Notes due December 2018 % (a) % (a) Tuscarora Unsecured Term Loan due 2019 % % 3.82% Series D Senior Notes due 2017 % (a) % (a) Less: unamortized debt issuance costs and debt discount Less: current portion (c) (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 (a) 2018 (a) 2019 2020 2021 Thereafter (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, (c) Weighted Average (c) December 31, (c) Weighted Average (c) TC PipeLines, LP Senior Credit Facility due 2021 % % 2013 Term Loan Facility due 2018 % % 2015 Term Loan Facility due 2018 % % 4.65% Unsecured Senior Notes due 2021 % (b) % (b) 4.375% Unsecured Senior Notes due 2025 % (b) % (b) GTN 5.29% Unsecured Senior Notes due 2020 % (b) % (b) 5.69% Unsecured Senior Notes due 2035 % (b) % (b) Unsecured Term Loan Facility due 2019 % % PNGTS 5.90% Senior Secured Notes due December 2018 % (b) % (b) Tuscarora Unsecured Term Loan due 2019 % — — 3.82% Series D Senior Notes due 2017 % (b) % (b) Less: unamortized debt issuance costs and debt discount (a) Less: current portion (d) (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 (a) 2018 (a) 2019 2020 2021 Thereafter (a) (a) Recast to consolidate PNGTS for all periods presented. (Refer to Note 2).

OTHER LIABILITIES

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 Other liabilities 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 .

PARTNERS' EQUITY

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).

ACCUMULATED OTHER COMPREHENSIVE

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 ) Change in fair value of cash flow hedges ) Amounts reclassified from AOCL — PNGTS’ amortization of realized loss on derivative instrument (Note 18) Net other comprehensive income (loss) — Balance at December 31, 2014 ) Change in fair value of cash flow hedges — Amounts reclassified from AOCL — PNGTS’ amortization of realized loss on derivative instrument (Note 18) Net other comprehensive income Balance at December 31, 2015 ) Change in fair value of cash flow hedges Amounts reclassified from AOCL ) PNGTS’ amortization of realized loss on derivative instrument (Note 18) Net other comprehensive income Balance as of December 31, 2016 ) (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.

FINANCIAL CHARGES AND OTHER

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) PNGTS’ amortization of derivative loss on derivative instruments (Note 11) (b) — — Net realized loss related to the interest rate swaps (b) — — Other Income (b) — — (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) (b)

NET INCOME (LOSS) PER COMMON UN

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) Net income attributable to PNGTS’ former parent (a) (b) ) ) Net income allocable to General Partner and Limited Partners Net income attributable to the General Partner ) ) Incentive distributions attributable to the General Partner (c) ) ) Net income attributable to common units Weighted average common units outstanding (millions) — basic and diluted (d) Net income per common unit — basic and diluted (e) $ $ (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) Net income attributable to PNGTS’ former parent (a) (b) ) ) ) Net income allocable to General Partner and Limited Partners Incentive distributions attributable to the General Partner (c) ) ) ) Net income attributable to the Class B units (d) ) ) — Net income (loss) allocable to the General Partner and common units ) Net income (loss) allocable to the General Partner’s two percent interest ) — ) Net income (loss) attributable to common units ) Weighted average common units outstanding (millions) — basic and diluted (e) Net income (loss) per common unit — basic and diluted (f) $ $ ) $ (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.

CASH DISTRIBUTIONS

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 Total Quarterly Distribution Common General Minimum Quarterly Distribution $0.45 % % First Target Distribution above $0.45 up to $0.81 % % Second Target Distribution above $0.81 up to $0.88 % % Thereafter above $0.88 % % 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 Common Class B (c) 2% IDRs (a) Total Cash 1/16/2014 2/14/2014 $ $ $ — $ $ — $ 4/25/2014 5/15/2014 $ $ $ — $ $ — $ 7/23/2014 8/14/2014 $ $ $ — $ $ — $ 10/23/2014 11/14/2014 $ $ $ — $ $ $ 1/22/2015 2/13/2015 $ $ $ — $ $ — $ 4/23/2015 5/15/2015 $ $ $ — $ $ — $ 7/23/2015 8/14/2015 $ $ $ — $ $ $ 10/22/2015 11/13/2015 $ $ $ — $ $ $ 1/21/2016 2/12/2016 $ $ $ (d) $ $ $ 4/21/2016 5/13/2016 $ $ $ — $ $ $ 7/21/2016 8/12/2016 $ $ $ — $ $ $ 10/20/2016 11/14/2016 $ $ $ — $ $ $ 1/23/2017 (b) 2/14/2017 (b) $ $ $ (e) $ $ $ (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).

CHANGE IN OPERATING WORKING CAP

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 ) Change in other current assets Change in accounts payable and accrued liabilities ) (a) Change in accounts payable to affiliates ) ) Change in state income taxes payable — Change in accrued interest Change in operating working capital (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 ) Change in other current assets ) ) ) Change in accounts payable and accrued liabilities (a) ) Change in accounts payable to affiliates — ) (b) ) Change in state income taxes payable — ) Change in accrued interest ) Change in operating working capital ) ) (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).

TRANSACTIONS WITH MAJOR CUSTOME

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) Pacific Gas and Electric Company (Pacific Gas) (a) 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

RELATED PARTY TRANSACTIONS

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) Northern Border (a) PNGTS (a) (c) GTN (a) Bison (b) ) North Baja Tuscarora Impact on the Partnership’s net income: Great Lakes Northern Border PNGTS (c) GTN Bison North Baja Tuscarora (unaudited) (millions of dollars) March 31, 2017 December 31, 2016 Net amounts payable to TransCanada’s subsidiaries is as follows: Great Lakes (a) Northern Border (a) PNGTS (a) (c) GTN Bison –– North Baja –– Tuscarora (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) Northern Border (a) PNGTS (a) (b) GTN (a) (c) Bison (a) (d) North Baja Tuscarora Impact on the Partnership’s net income attributable to controlling interests: Great Lakes Northern Border PNGTS (b) GTN (c) Bison (d) North Baja Tuscarora December 31 (millions of dollars) 2016 2015 Amount payable to TransCanada’s subsidiaries for costs charged in the year by: Great Lakes (a) Northern Border (a) PNGTS (a) (b) GTN Bison — North Baja — Tuscarora (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.

QUARTERLY FINANCIAL DATA (unaud

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 Mar 31 Jun 30 Sept 30 Dec 31 2016 Transmission revenues (a) Equity earnings (a) (b ) (c) Net income (a) Net income attributable to controlling interests (a) Net income per common unit (d) $ $ $ $ Cash distribution paid (f) 2015 Transmission revenues (a) Equity earnings (e) Impairment of equity-method investment (b) — — — ) Net income (loss) (a) ) Net income (loss) attributable to controlling interests (a) ) Net income (loss) per common unit (d) $ $ $ $ ) Cash distribution paid (f) (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.

FAIR VALUE MEASUREMENTS

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.

ACCOUNTS RECEIVABLE AND OTHER

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 Imbalance receivable from affiliates Other (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 Imbalance receivable from affiliates Other — (a) Recast to consolidate PNGTS for all periods presented (Refer to Note 2).

GOODWILL AND REGULATORY

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.

CONTINGENCIES

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.

VARIABLE INTEREST ENTITIES

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 Accounts receivable and other Inventories Other current assets Equity investments Plant, property and equipment Other assets Accounts payable and accrued liabilities ) ) Accounts payable to affiliates, net ) ) Distributions payable ) ) Accrued interest ) ) State income tax payable ) — Current portion of long-term debt ) ) Long-term debt ) ) Other liabilities ) ) Deferred state income tax ) ) (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 Accounts receivable and other Inventories Other current assets Equity investments Plant, property and equipment Other assets Accounts payable and accrued liabilities ) ) Accounts payable to affiliates, net ) ) Distributions payable ) ) Accrued interest ) ) Current portion of long-term debt ) ) Long-term debt ) ) Other liabilities ) ) Deferred state income tax ) ) (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).

INCOME TAXES

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 Deferred — ) (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 2016 (a) 2015 (a) 2014 (a) State income taxes Current ) Deferred — ) (a) Recast to consolidate PNGTS for all periods presented (Refer to Note 2).

SUBSEQUENT EVENTS

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 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 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.

SIGNIFICANT ACCOUNTING POLICI33

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.

ORGANIZATION (Tables)

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).

EQUITY INVESTMENTS (Tables)

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) % Great Lakes % (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 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) % Great Lakes % (c) (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 Other current assets Plant, property and equipment, net Other assets LIABILITIES AND PARTNERS’ EQUITY Current liabilities Deferred credits and other Long-term debt, including current maturities, net Partners’ equity Partners’ capital Accumulated other comprehensive loss ) ) Three months ended (unaudited) March 31, (millions of dollars) 2017 2016 Transmission revenues Operating expenses ) ) Depreciation ) ) Financial charges and other ) ) Net income	December 31 (millions of dollars) 2016 2015 Assets Cash and cash equivalents Other current assets Plant, property and equipment, net Other assets (a) Liabilities and Partners’ Equity Current liabilities Deferred credits and other Long-term debt, net (a), (b) Partners’ equity Partners’ capital Accumulated other comprehensive loss ) ) (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 Operating expenses ) ) ) Depreciation ) ) ) Financial charges and other ) ) ) Net income
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 Plant, property and equipment, net LIABILITIES AND PARTNERS’ EQUITY Current liabilities Long-term debt, including current maturities, net Partners’ equity Three months ended (unaudited) March 31, (millions of dollars) 2017 2016 Transmission revenues Operating expenses ) ) Depreciation ) ) Financial charges and other ) ) Net income	December 31 (millions of dollars) 2016 2015 Assets Current assets Plant, property and equipment, net Liabilities and Partners’ Equity Current liabilities Long-term debt, net (a),(b) Partners’ equity (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 Operating expenses ) ) ) Depreciation ) ) ) Financial charges and other ) ) ) Net income

PLANT, PROPERTY AND EQUIPMENT (

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 Cost Accumulated Net Cost Accumulated Net Pipeline ) ) Compression ) ) Metering and other ) ) Construction in progress — — ) ) (a) Recast to consolidate PNGTS for all periods presented (Refer to Note 2).

ACQUISITIONS (Tables)

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) Less: TransCanada’s carrying value of PNGTS’ net assets at January 1, 2016 Excess purchase price (b) (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) Less: TransCanada’s carrying value of non-controlling interest at April 1, 2015 Excess purchase price (b) (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 TransCanada’s carrying value of non-controlling interest at October 1, 2014 Excess purchase price

DEBT AND CREDIT FACILITIES (Tab

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) March 31, (b) Weighted Average (b) December 31, (b) Weighted Average (b) TC PipeLines, LP Senior Credit Facility due 2021 % % 2013 Term Loan Facility due July 2018 % % 2015 Term Loan Facility due September 2018 % % 4.65% Unsecured Senior Notes due 2021 % (a) % (a) 4.375% Unsecured Senior Notes due 2025 % (a) % (a) GTN 5.29% Unsecured Senior Notes due 2020 % (a) % (a) 5.69% Unsecured Senior Notes due 2035 % (a) % (a) Unsecured Term Loan Facility due 2019 % % PNGTS 5.90% Senior Secured Notes due December 2018 % (a) % (a) Tuscarora Unsecured Term Loan due 2019 % % 3.82% Series D Senior Notes due 2017 % (a) % (a) Less: unamortized debt issuance costs and debt discount Less: current portion (c) (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, (c) Weighted Average (c) December 31, (c) Weighted Average (c) TC PipeLines, LP Senior Credit Facility due 2021 % % 2013 Term Loan Facility due 2018 % % 2015 Term Loan Facility due 2018 % % 4.65% Unsecured Senior Notes due 2021 % (b) % (b) 4.375% Unsecured Senior Notes due 2025 % (b) % (b) GTN 5.29% Unsecured Senior Notes due 2020 % (b) % (b) 5.69% Unsecured Senior Notes due 2035 % (b) % (b) Unsecured Term Loan Facility due 2019 % % PNGTS 5.90% Senior Secured Notes due December 2018 % (b) % (b) Tuscarora Unsecured Term Loan due 2019 % — — 3.82% Series D Senior Notes due 2017 % (b) % (b) Less: unamortized debt issuance costs and debt discount (a) Less: current portion (d) (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 (a) 2018 (a) 2019 2020 2021 Thereafter (a) (a) Recast to consolidate PNGTS for all periods presented. (Refer to Note 2).	(millions of dollars) 2017 (a) 2018 (a) 2019 2020 2021 Thereafter (a) (a) Recast to consolidate PNGTS for all periods presented. (Refer to Note 2).

OTHER LIABILITIES (Tables)

OTHER LIABILITIES (Tables)	12 Months Ended
	Dec. 31, 2016
OTHER LIABILITIES
Schedule of other liabilities	December 31 (millions of dollars) 2016 2015 Regulatory liabilities Other liabilities

ACCUMULATED OTHER COMPREHENSI40

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 ) Change in fair value of cash flow hedges ) Amounts reclassified from AOCL — PNGTS’ amortization of realized loss on derivative instrument (Note 18) Net other comprehensive income (loss) — Balance at December 31, 2014 ) Change in fair value of cash flow hedges — Amounts reclassified from AOCL — PNGTS’ amortization of realized loss on derivative instrument (Note 18) Net other comprehensive income Balance at December 31, 2015 ) Change in fair value of cash flow hedges Amounts reclassified from AOCL ) PNGTS’ amortization of realized loss on derivative instrument (Note 18) Net other comprehensive income Balance as of December 31, 2016 ) (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.

FINANCIAL CHARGES AND OTHER (Ta

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) PNGTS’ amortization of derivative loss on derivative instruments (Note 11) (b) — — Net realized loss related to the interest rate swaps (b) — — Other Income (b) — — (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) (b)

NET INCOME (LOSS) PER COMMON 42

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) Net income attributable to PNGTS’ former parent (a) (b) ) ) Net income allocable to General Partner and Limited Partners Net income attributable to the General Partner ) ) Incentive distributions attributable to the General Partner (c) ) ) Net income attributable to common units Weighted average common units outstanding (millions) — basic and diluted (d) Net income per common unit — basic and diluted (e) $ $ (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) Net income attributable to PNGTS’ former parent (a) (b) ) ) ) Net income allocable to General Partner and Limited Partners Incentive distributions attributable to the General Partner (c) ) ) ) Net income attributable to the Class B units (d) ) ) — Net income (loss) allocable to the General Partner and common units ) Net income (loss) allocable to the General Partner’s two percent interest ) — ) Net income (loss) attributable to common units ) Weighted average common units outstanding (millions) — basic and diluted (e) Net income (loss) per common unit — basic and diluted (f) $ $ ) $ (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.

CASH DISTRIBUTIONS (Tables)

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 Total Quarterly Distribution Common General Minimum Quarterly Distribution $0.45 % % First Target Distribution above $0.45 up to $0.81 % % Second Target Distribution above $0.81 up to $0.88 % % Thereafter above $0.88 % %
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 Common Class B (c) 2% IDRs (a) Total Cash 1/16/2014 2/14/2014 $ $ $ — $ $ — $ 4/25/2014 5/15/2014 $ $ $ — $ $ — $ 7/23/2014 8/14/2014 $ $ $ — $ $ — $ 10/23/2014 11/14/2014 $ $ $ — $ $ $ 1/22/2015 2/13/2015 $ $ $ — $ $ — $ 4/23/2015 5/15/2015 $ $ $ — $ $ — $ 7/23/2015 8/14/2015 $ $ $ — $ $ $ 10/22/2015 11/13/2015 $ $ $ — $ $ $ 1/21/2016 2/12/2016 $ $ $ (d) $ $ $ 4/21/2016 5/13/2016 $ $ $ — $ $ $ 7/21/2016 8/12/2016 $ $ $ — $ $ $ 10/20/2016 11/14/2016 $ $ $ — $ $ $ 1/23/2017 (b) 2/14/2017 (b) $ $ $ (e) $ $ $ (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).

CHANGE IN OPERATING WORKING C44

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 ) Change in other current assets Change in accounts payable and accrued liabilities ) (a) Change in accounts payable to affiliates ) ) Change in state income taxes payable — Change in accrued interest Change in operating working capital (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 ) Change in other current assets ) ) ) Change in accounts payable and accrued liabilities (a) ) Change in accounts payable to affiliates — ) (b) ) Change in state income taxes payable — ) Change in accrued interest ) Change in operating working capital ) ) (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).

TRANSACTIONS WITH MAJOR CUSTO45

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) Pacific Gas and Electric Company (Pacific Gas) (a) (a) Less than 10 percent

RELATED PARTY TRANSACTIONS (Tab

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) Northern Border (a) PNGTS (a) (c) GTN (a) Bison (b) ) North Baja Tuscarora Impact on the Partnership’s net income: Great Lakes Northern Border PNGTS (c) GTN Bison North Baja Tuscarora (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) Northern Border (a) PNGTS (a) (b) GTN (a) (c) Bison (a) (d) North Baja Tuscarora Impact on the Partnership’s net income attributable to controlling interests: Great Lakes Northern Border PNGTS (b) GTN (c) Bison (d) North Baja Tuscarora
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) Northern Border (a) PNGTS (a) (c) GTN Bison –– North Baja –– Tuscarora (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) Northern Border (a) PNGTS (a) (b) GTN Bison — North Baja — Tuscarora (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).

QUARTERLY FINANCIAL DATA (una47

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 Mar 31 Jun 30 Sept 30 Dec 31 2016 Transmission revenues (a) Equity earnings (a) (b ) (c) Net income (a) Net income attributable to controlling interests (a) Net income per common unit (d) $ $ $ $ Cash distribution paid (f) 2015 Transmission revenues (a) Equity earnings (e) Impairment of equity-method investment (b) — — — ) Net income (loss) (a) ) Net income (loss) attributable to controlling interests (a) ) Net income (loss) per common unit (d) $ $ $ $ ) Cash distribution paid (f) (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.

ACCOUNTS RECEIVABLE AND OTHER (

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 Imbalance receivable from affiliates Other (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 Imbalance receivable from affiliates Other — (a) Recast to consolidate PNGTS for all periods presented (Refer to Note 2).

VARIABLE INTEREST ENTITIES (Tab

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 Accounts receivable and other Inventories Other current assets Equity investments Plant, property and equipment Other assets Accounts payable and accrued liabilities ) ) Accounts payable to affiliates, net ) ) Distributions payable ) ) Accrued interest ) ) State income tax payable ) — Current portion of long-term debt ) ) Long-term debt ) ) Other liabilities ) ) Deferred state income tax ) ) (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 Accounts receivable and other Inventories Other current assets Equity investments Plant, property and equipment Other assets Accounts payable and accrued liabilities ) ) Accounts payable to affiliates, net ) ) Distributions payable ) ) Accrued interest ) ) Current portion of long-term debt ) ) Long-term debt ) ) Other liabilities ) ) Deferred state income tax ) ) (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).

INCOME TAXES (Tables)

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 Deferred — ) (a) Recast to consolidate PNGTS for all periods presented (Refer to Note 2).	Year ended December 31 2016 (a) 2015 (a) 2014 (a) State income taxes Current ) Deferred — ) (a) Recast to consolidate PNGTS for all periods presented (Refer to Note 2).

ORGANIZATION - Ownership Intere

ORGANIZATION - Ownership Interests in Natural Gas Pipeline Systems (Details)	Jun. 01, 2017	Mar. 31, 2017LimitedPartnership	Dec. 31, 2016LimitedPartnershipmi	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%

ORGANIZATION - Capitalization (

ORGANIZATION - Capitalization (Details) - shares		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).

SIGNIFICANT ACCOUNTING POLICI53

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%

SIGNIFICANT ACCOUNTING POLICI54

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

SIGNIFICANT ACCOUNTING POLICI55

SIGNIFICANT ACCOUNTING POLICIES - Revenue Recognition (Details) - Portland Natural Gas Transmission System $ in Millions	Feb. 19, 2015USD ($)	Jan. 31, 2015item
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

SIGNIFICANT ACCOUNTING POLICI56

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).

SIGNIFICANT ACCOUNTING POLICI57

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).

SIGNIFICANT ACCOUNTING POLICI58

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

ACCOUNTING PRONOUNCEMENTS - Imp

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).

ACCOUNTING PRONOUNCEMENTS - Sta

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).

EQUITY INVESTMENTS (Details)

EQUITY INVESTMENTS (Details) - USD ($) $ in Millions		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).

PLANT, PROPERTY AND EQUIPMENT62

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).

ACQUISITIONS - Acquisition of O

ACQUISITIONS - Acquisition of Ownership Interest in PNGTS (Details) - Portland Natural Gas Transmission System - USD ($) $ in Millions		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).

ACQUISITIONS - 2015 GTN Acquisi

ACQUISITIONS - 2015 GTN Acquisition Summary and Terms of New Class B Units (Details) - USD ($)		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).

ACQUISITIONS - 2014 Bison Acqui

ACQUISITIONS - 2014 Bison Acquisition (Details) - USD ($) $ in Millions		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).

DEBT AND CREDIT FACILITIES - Am

DEBT AND CREDIT FACILITIES - Amounts Outstanding and Description of Terms (Details) - USD ($)		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).

DEBT AND CREDIT FACILITIES - Pr

DEBT AND CREDIT FACILITIES - Principal Payments Required (Details) - USD ($) $ in Millions	Mar. 31, 2017	Dec. 31, 2016
Principal repayments required on debt
2,017		$ 52
2,018	$ 715	715
2,019	43	43
2,020	100	100
2,021	460	510
Thereafter	500	500
Total debt	$ 1,858	$ 1,920

OTHER LIABILITIES (Details)

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).

PARTNERS' EQUITY - Ownership (D

PARTNERS' EQUITY - Ownership (Details) - shares		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).

PARTNERS' EQUITY - ATM Equity I

PARTNERS' EQUITY - ATM Equity Issuance Program (Details)

Jun. 30, 2017item

Aug. 05, 2016USD ($)item

Apr. 01, 2015USD ($)

May 19, 2016USD ($)$ / shares

Mar. 31, 2017USD ($)shares

May 19, 2016shares

Mar. 31, 2016USD ($)

Sep. 30, 2016

Sep. 30, 2015

Dec. 31, 2016USD ($)shares

Dec. 31, 2015USD ($)shares

Dec. 31, 2014USD ($)shares

Aug. 31, 2014USD ($)

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

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).

PARTNERS' EQUITY - Class B Unit

PARTNERS' EQUITY - Class B Units (Details) - Class B units - USD ($)	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).

ACCUMULATED OTHER COMPREHENSI72

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).

FINANCIAL CHARGES AND OTHER (De

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).

NET INCOME (LOSS) PER COMMON 74

NET INCOME (LOSS) PER COMMON UNIT - General Partner Effective Interest and Allocated Incentive Distributions (Details)	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%

NET INCOME (LOSS) PER COMMON 75

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		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).

CASH DISTRIBUTIONS - Quarterly

CASH DISTRIBUTIONS - Quarterly Distributions (Details)	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%

CASH DISTRIBUTIONS - General Pa

CASH DISTRIBUTIONS - General Partner Distribution Incentives (Details) - $ / shares		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).

CASH DISTRIBUTIONS - Distributi

CASH DISTRIBUTIONS - Distributions by Payment Date (Details) - USD ($)	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		$ 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).

CHANGE IN OPERATING WORKING C79

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).

CHANGE IN OPERATING WORKING C80

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).

TRANSACTIONS WITH MAJOR CUSTO81

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).

RELATED PARTY TRANSACTIONS (Det

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		$ 8		$ 8	$ 8
Amount included in receivables from related party		$ 1		1		$ 2	1
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	$ 1			3	3	$ 3
TransCanada's subsidiaries | GTN
Capital and operating costs charged to the pipeline systems and amount payable
Net amounts payable		3		3		3	3
TransCanada's subsidiaries | GTN | Capital and operating costs
Capital and operating costs charged to the pipeline systems and amount payable
Costs charged		7	6			27	30	30
Impact on the Partnership's net income attributable to controlling interests		$ 7	$ 5			$ 24	$ 25	$ 19
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		5		$ 4	$ 5
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	$ 6			$ 32	$ 36	$ 35
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		3		$ 1	$ 3
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	$ 2			$ 8	8	$ 8
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
Revenue from related parties		0	$ 1			2	3
TransCanada's subsidiaries | Bison
Capital and operating costs charged to the pipeline systems and amount payable
Net amounts payable						1
TransCanada's subsidiaries | Bison | Capital and operating costs
Capital and operating costs charged to the pipeline systems and amount payable
Costs charged		1				2	4	6
Impact on the Partnership's net income attributable to controlling interests		1	$ 1
Impact on the Partnership's net income attributable to controlling interests						$ 3	$ 4	$ 4
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		3		$ 4	$ 3
Percentage of capital and operating costs charged		100.00%	100.00%
Amount included in receivables from related party		$ 15		17		19	17
TransCanada's subsidiaries | Great Lakes | Capital and operating costs
Capital and operating costs charged to the pipeline systems and amount payable
Costs charged		$ 8	$ 7			30	30	$ 30
Impact on the Partnership's net income attributable to controlling interests						$ 13	$ 13	$ 13
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		$ 27	$ 51
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
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	$ 1			4	$ 5	$ 5
Impact on the Partnership's net income attributable to controlling interests		1	1			4	5	4
TransCanada's subsidiaries | Tuscarora Gas Transmission Company
Capital and operating costs charged to the pipeline systems and amount payable
Net amounts payable		1		1		1	1
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	1			5	4	4
Impact on the Partnership's net income attributable to controlling interests		1	1			4	4	4
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	$ 3
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	$ 3			12	14	16
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	$ 1			$ 5	$ 5	5
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			$ 9
Deferred revenue recognized				$ 23
[1]	Recast to consolidate PNGTS for all periods presented (Refer to Note 2).

QUARTERLY FINANCIAL DATA (una83

QUARTERLY FINANCIAL DATA (unaudited) (Details) - USD ($) $ / shares in Units, $ in Millions	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).

FAIR VALUE MEASUREMENTS - Estim

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	$ 1,963	$ 1,945

FAIR VALUE MEASUREMENTS - Inter

FAIR VALUE MEASUREMENTS - Interest Rate Swaps (Details)		3 Months Ended		12 Months Ended
		Mar. 31, 2017USD ($)	Mar. 31, 2016USD ($)	Dec. 31, 2016USD ($)item	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)	Jul. 01, 2013USD ($)
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).

ACCOUNTS RECEIVABLE AND OTHER86

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).

GOODWILL AND REGULATORY (Detail

GOODWILL AND REGULATORY (Details) $ in Millions		Jan. 06, 2017item	Aug. 01, 2016	Jun. 30, 2016USD ($)	Dec. 31, 2016USD ($)	Mar. 31, 2017USD ($)	Dec. 31, 2015USD ($)
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).

CONTINGENCIES (Details)

CONTINGENCIES (Details) - USD ($) $ in Millions	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
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
Judgement awarded	$ 32.9

VARIABLE INTEREST ENTITIES - Co

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).

INCOME TAXES (Details)

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).

SUBSEQUENT EVENTS - Distributio

SUBSEQUENT EVENTS - Distributions (Details)		Aug. 11, 2017USD ($)$ / shares	Aug. 01, 2017USD ($)item	Jul. 31, 2017USD ($)	Jul. 27, 2017USD ($)	Jul. 20, 2017USD ($)$ / sharesshares	Jul. 18, 2017USD ($)	Jul. 07, 2017USD ($)	Jun. 30, 2017USD ($)	Jun. 07, 2017USD ($)	Jun. 01, 2017USD ($)	May 31, 2017USD ($)	May 25, 2017USD ($)	May 15, 2017USD ($)	May 12, 2017USD ($)	May 01, 2017USD ($)	Apr. 28, 2017USD ($)	Apr. 25, 2017USD ($)$ / sharesshares	Apr. 24, 2017USD ($)	Apr. 19, 2017USD ($)	Apr. 07, 2017USD ($)	Mar. 31, 2017USD ($)shares	Mar. 10, 2017USD ($)	Feb. 28, 2017USD ($)	Feb. 15, 2017USD ($)	Feb. 14, 2017USD ($)	Feb. 01, 2017USD ($)	Jan. 31, 2017USD ($)	Jan. 23, 2017USD ($)$ / sharesshares	Jan. 09, 2017USD ($)	Jan. 03, 2017USD ($)	Nov. 14, 2016USD ($)	Oct. 20, 2016USD ($)$ / shares	Aug. 12, 2016USD ($)	Jul. 21, 2016USD ($)$ / shares	May 13, 2016USD ($)	Apr. 21, 2016USD ($)$ / shares	Feb. 12, 2016USD ($)	Jan. 21, 2016USD ($)$ / shares	Nov. 13, 2015USD ($)	Oct. 22, 2015USD ($)$ / shares	Aug. 14, 2015USD ($)	Jul. 23, 2015USD ($)$ / shares	May 15, 2015USD ($)	Apr. 23, 2015USD ($)$ / shares	Apr. 01, 2015	Feb. 13, 2015USD ($)	Jan. 22, 2015USD ($)$ / shares	Nov. 14, 2014USD ($)	Oct. 23, 2014USD ($)$ / shares	Aug. 14, 2014USD ($)	Jul. 23, 2014USD ($)$ / shares	May 15, 2014USD ($)	Apr. 25, 2014USD ($)$ / shares	Feb. 14, 2014USD ($)	Jan. 16, 2014USD ($)$ / shares	Mar. 31, 2017USD ($)shares		Dec. 31, 2016USD ($)shares	Mar. 31, 2016USD ($)shares		Dec. 31, 2015USD ($)shares	Mar. 31, 2015USD ($)	Sep. 30, 2016	Dec. 31, 2015USD ($)shares	Sep. 30, 2015	Dec. 31, 2016USD ($)shares		Dec. 31, 2015USD ($)shares		Dec. 31, 2014USD ($)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												$ 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
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).

CONSOLIDATED STATEMENTS OF IN92

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).

CONSOLIDATED STATEMENTS OF CO93

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).

CONSOLIDATED BALANCE SHEETS94

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).

CONSOLIDATED BALANCE SHEETS (Pa

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

CONSOLIDATED STATEMENTS OF CA96

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).

CONSOLIDATED STATEMENTS OF CA97

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%

CONSOLIDATED STATEMENT OF CHA98

CONSOLIDATED STATEMENT OF CHANGES IN PARTNERS' EQUITY - USD ($) shares in Millions, $ in Millions		Limited PartnersCommon unitsATM Equity Issuance Program	Limited PartnersCommon units		Limited PartnersClass B units		General PartnerATM Equity Issuance Program	General Partner		AOCL		Common unitsATM 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.

CONSOLIDATED STATEMENT OF CHA99

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

ORGANIZATION100

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).

SIGNIFICANT ACCOUNTING POLIC101

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 (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 (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.

ACCOUNTING PRONOUNCEMENTS102

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.

EQUITY INVESTMENTS103

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) % Great Lakes % (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 Other current assets Plant, property and equipment, net Other assets LIABILITIES AND PARTNERS’ EQUITY Current liabilities Deferred credits and other Long-term debt, including current maturities, net Partners’ equity Partners’ capital Accumulated other comprehensive loss ) ) Three months ended (unaudited) March 31, (millions of dollars) 2017 2016 Transmission revenues Operating expenses ) ) Depreciation ) ) Financial charges and other ) ) Net income 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 Plant, property and equipment, net LIABILITIES AND PARTNERS’ EQUITY Current liabilities Long-term debt, including current maturities, net Partners’ equity Three months ended (unaudited) March 31, (millions of dollars) 2017 2016 Transmission revenues Operating expenses ) ) Depreciation ) ) Financial charges and other ) ) Net income	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 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) % Great Lakes % (c) (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 Other current assets Plant, property and equipment, net Other assets (a) Liabilities and Partners’ Equity Current liabilities Deferred credits and other Long-term debt, net (a), (b) Partners’ equity Partners’ capital Accumulated other comprehensive loss ) ) (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 Operating expenses ) ) ) Depreciation ) ) ) Financial charges and other ) ) ) Net income 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 Plant, property and equipment, net Liabilities and Partners’ Equity Current liabilities Long-term debt, net (a),(b) Partners’ equity (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 Operating expenses ) ) ) Depreciation ) ) ) Financial charges and other ) ) ) Net income

DEBT AND CREDIT FACILITIES104

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) March 31, (b) Weighted Average (b) December 31, (b) Weighted Average (b) TC PipeLines, LP Senior Credit Facility due 2021 % % 2013 Term Loan Facility due July 2018 % % 2015 Term Loan Facility due September 2018 % % 4.65% Unsecured Senior Notes due 2021 % (a) % (a) 4.375% Unsecured Senior Notes due 2025 % (a) % (a) GTN 5.29% Unsecured Senior Notes due 2020 % (a) % (a) 5.69% Unsecured Senior Notes due 2035 % (a) % (a) Unsecured Term Loan Facility due 2019 % % PNGTS 5.90% Senior Secured Notes due December 2018 % (a) % (a) Tuscarora Unsecured Term Loan due 2019 % % 3.82% Series D Senior Notes due 2017 % (a) % (a) Less: unamortized debt issuance costs and debt discount Less: current portion (c) (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 (a) 2018 (a) 2019 2020 2021 Thereafter (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, (c) Weighted Average (c) December 31, (c) Weighted Average (c) TC PipeLines, LP Senior Credit Facility due 2021 % % 2013 Term Loan Facility due 2018 % % 2015 Term Loan Facility due 2018 % % 4.65% Unsecured Senior Notes due 2021 % (b) % (b) 4.375% Unsecured Senior Notes due 2025 % (b) % (b) GTN 5.29% Unsecured Senior Notes due 2020 % (b) % (b) 5.69% Unsecured Senior Notes due 2035 % (b) % (b) Unsecured Term Loan Facility due 2019 % % PNGTS 5.90% Senior Secured Notes due December 2018 % (b) % (b) Tuscarora Unsecured Term Loan due 2019 % — — 3.82% Series D Senior Notes due 2017 % (b) % (b) Less: unamortized debt issuance costs and debt discount (a) Less: current portion (d) (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 (a) 2018 (a) 2019 2020 2021 Thereafter (a) (a) Recast to consolidate PNGTS for all periods presented. (Refer to Note 2).

PARTNERS' EQUITY105

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).

NET INCOME PER COMMON UNIT

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) Net income attributable to PNGTS’ former parent (a) (b) ) ) Net income allocable to General Partner and Limited Partners Net income attributable to the General Partner ) ) Incentive distributions attributable to the General Partner (c) ) ) Net income attributable to common units Weighted average common units outstanding (millions) — basic and diluted (d) Net income per common unit — basic and diluted (e) $ $ (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) Net income attributable to PNGTS’ former parent (a) (b) ) ) ) Net income allocable to General Partner and Limited Partners Incentive distributions attributable to the General Partner (c) ) ) ) Net income attributable to the Class B units (d) ) ) — Net income (loss) allocable to the General Partner and common units ) Net income (loss) allocable to the General Partner’s two percent interest ) — ) Net income (loss) attributable to common units ) Weighted average common units outstanding (millions) — basic and diluted (e) Net income (loss) per common unit — basic and diluted (f) $ $ ) $ (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.

CASH DISTRIBUTIONS TO COMMON UN

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 Total Quarterly Distribution Common General Minimum Quarterly Distribution $0.45 % % First Target Distribution above $0.45 up to $0.81 % % Second Target Distribution above $0.81 up to $0.88 % % Thereafter above $0.88 % % 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 Common Class B (c) 2% IDRs (a) Total Cash 1/16/2014 2/14/2014 $ $ $ — $ $ — $ 4/25/2014 5/15/2014 $ $ $ — $ $ — $ 7/23/2014 8/14/2014 $ $ $ — $ $ — $ 10/23/2014 11/14/2014 $ $ $ — $ $ $ 1/22/2015 2/13/2015 $ $ $ — $ $ — $ 4/23/2015 5/15/2015 $ $ $ — $ $ — $ 7/23/2015 8/14/2015 $ $ $ — $ $ $ 10/22/2015 11/13/2015 $ $ $ — $ $ $ 1/21/2016 2/12/2016 $ $ $ (d) $ $ $ 4/21/2016 5/13/2016 $ $ $ — $ $ $ 7/21/2016 8/12/2016 $ $ $ — $ $ $ 10/20/2016 11/14/2016 $ $ $ — $ $ $ 1/23/2017 (b) 2/14/2017 (b) $ $ $ (e) $ $ $ (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).

CHANGE IN OPERATING WORKING 108

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 ) Change in other current assets Change in accounts payable and accrued liabilities ) (a) Change in accounts payable to affiliates ) ) Change in state income taxes payable — Change in accrued interest Change in operating working capital (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 ) Change in other current assets ) ) ) Change in accounts payable and accrued liabilities (a) ) Change in accounts payable to affiliates — ) (b) ) Change in state income taxes payable — ) Change in accrued interest ) Change in operating working capital ) ) (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).

RELATED PARTY TRANSACTIONS109

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) Northern Border (a) PNGTS (a) (c) GTN (a) Bison (b) ) North Baja Tuscarora Impact on the Partnership’s net income: Great Lakes Northern Border PNGTS (c) GTN Bison North Baja Tuscarora (unaudited) (millions of dollars) March 31, 2017 December 31, 2016 Net amounts payable to TransCanada’s subsidiaries is as follows: Great Lakes (a) Northern Border (a) PNGTS (a) (c) GTN Bison –– North Baja –– Tuscarora (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) Northern Border (a) PNGTS (a) (b) GTN (a) (c) Bison (a) (d) North Baja Tuscarora Impact on the Partnership’s net income attributable to controlling interests: Great Lakes Northern Border PNGTS (b) GTN (c) Bison (d) North Baja Tuscarora December 31 (millions of dollars) 2016 2015 Amount payable to TransCanada’s subsidiaries for costs charged in the year by: Great Lakes (a) Northern Border (a) PNGTS (a) (b) GTN Bison — North Baja — Tuscarora (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.

FAIR VALUE MEASUREMENTS110

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.

ACCOUNTS RECEIVABLE AND OTHE111

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 Imbalance receivable from affiliates Other (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 Imbalance receivable from affiliates Other — (a) Recast to consolidate PNGTS for all periods presented (Refer to Note 2).

FINANCIAL CHARGES AND OTHER112

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) PNGTS’ amortization of derivative loss on derivative instruments (Note 11) (b) — — Net realized loss related to the interest rate swaps (b) — — Other Income (b) — — (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) (b)

CONTINGENCIES113

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.

REGULATORY

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.

VARIABLE INTEREST ENTITIES115

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 Accounts receivable and other Inventories Other current assets Equity investments Plant, property and equipment Other assets Accounts payable and accrued liabilities ) ) Accounts payable to affiliates, net ) ) Distributions payable ) ) Accrued interest ) ) State income tax payable ) — Current portion of long-term debt ) ) Long-term debt ) ) Other liabilities ) ) Deferred state income tax ) ) (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 Accounts receivable and other Inventories Other current assets Equity investments Plant, property and equipment Other assets Accounts payable and accrued liabilities ) ) Accounts payable to affiliates, net ) ) Distributions payable ) ) Accrued interest ) ) Current portion of long-term debt ) ) Long-term debt ) ) Other liabilities ) ) Deferred state income tax ) ) (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).

INCOME TAXES116

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 Deferred — ) (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 2016 (a) 2015 (a) 2014 (a) State income taxes Current ) Deferred — ) (a) Recast to consolidate PNGTS for all periods presented (Refer to Note 2).

SUBSEQUENT EVENTS117

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 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 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.

SIGNIFICANT ACCOUNTING POLIC118

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.

EQUITY INVESTMENTS (Tables)119

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) % Great Lakes % (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 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) % Great Lakes % (c) (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 Other current assets Plant, property and equipment, net Other assets LIABILITIES AND PARTNERS’ EQUITY Current liabilities Deferred credits and other Long-term debt, including current maturities, net Partners’ equity Partners’ capital Accumulated other comprehensive loss ) ) Three months ended (unaudited) March 31, (millions of dollars) 2017 2016 Transmission revenues Operating expenses ) ) Depreciation ) ) Financial charges and other ) ) Net income	December 31 (millions of dollars) 2016 2015 Assets Cash and cash equivalents Other current assets Plant, property and equipment, net Other assets (a) Liabilities and Partners’ Equity Current liabilities Deferred credits and other Long-term debt, net (a), (b) Partners’ equity Partners’ capital Accumulated other comprehensive loss ) ) (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 Operating expenses ) ) ) Depreciation ) ) ) Financial charges and other ) ) ) Net income
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 Plant, property and equipment, net LIABILITIES AND PARTNERS’ EQUITY Current liabilities Long-term debt, including current maturities, net Partners’ equity Three months ended (unaudited) March 31, (millions of dollars) 2017 2016 Transmission revenues Operating expenses ) ) Depreciation ) ) Financial charges and other ) ) Net income	December 31 (millions of dollars) 2016 2015 Assets Current assets Plant, property and equipment, net Liabilities and Partners’ Equity Current liabilities Long-term debt, net (a),(b) Partners’ equity (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 Operating expenses ) ) ) Depreciation ) ) ) Financial charges and other ) ) ) Net income

DEBT AND CREDIT FACILITIES (120

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) March 31, (b) Weighted Average (b) December 31, (b) Weighted Average (b) TC PipeLines, LP Senior Credit Facility due 2021 % % 2013 Term Loan Facility due July 2018 % % 2015 Term Loan Facility due September 2018 % % 4.65% Unsecured Senior Notes due 2021 % (a) % (a) 4.375% Unsecured Senior Notes due 2025 % (a) % (a) GTN 5.29% Unsecured Senior Notes due 2020 % (a) % (a) 5.69% Unsecured Senior Notes due 2035 % (a) % (a) Unsecured Term Loan Facility due 2019 % % PNGTS 5.90% Senior Secured Notes due December 2018 % (a) % (a) Tuscarora Unsecured Term Loan due 2019 % % 3.82% Series D Senior Notes due 2017 % (a) % (a) Less: unamortized debt issuance costs and debt discount Less: current portion (c) (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, (c) Weighted Average (c) December 31, (c) Weighted Average (c) TC PipeLines, LP Senior Credit Facility due 2021 % % 2013 Term Loan Facility due 2018 % % 2015 Term Loan Facility due 2018 % % 4.65% Unsecured Senior Notes due 2021 % (b) % (b) 4.375% Unsecured Senior Notes due 2025 % (b) % (b) GTN 5.29% Unsecured Senior Notes due 2020 % (b) % (b) 5.69% Unsecured Senior Notes due 2035 % (b) % (b) Unsecured Term Loan Facility due 2019 % % PNGTS 5.90% Senior Secured Notes due December 2018 % (b) % (b) Tuscarora Unsecured Term Loan due 2019 % — — 3.82% Series D Senior Notes due 2017 % (b) % (b) Less: unamortized debt issuance costs and debt discount (a) Less: current portion (d) (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 (a) 2018 (a) 2019 2020 2021 Thereafter (a) (a) Recast to consolidate PNGTS for all periods presented. (Refer to Note 2).	(millions of dollars) 2017 (a) 2018 (a) 2019 2020 2021 Thereafter (a) (a) Recast to consolidate PNGTS for all periods presented. (Refer to Note 2).

NET INCOME PER COMMON UNIT (Tab

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) Net income attributable to PNGTS’ former parent (a) (b) ) ) Net income allocable to General Partner and Limited Partners Net income attributable to the General Partner ) ) Incentive distributions attributable to the General Partner (c) ) ) Net income attributable to common units Weighted average common units outstanding (millions) — basic and diluted (d) Net income per common unit — basic and diluted (e) $ $ (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) Net income attributable to PNGTS’ former parent (a) (b) ) ) ) Net income allocable to General Partner and Limited Partners Incentive distributions attributable to the General Partner (c) ) ) ) Net income attributable to the Class B units (d) ) ) — Net income (loss) allocable to the General Partner and common units ) Net income (loss) allocable to the General Partner’s two percent interest ) — ) Net income (loss) attributable to common units ) Weighted average common units outstanding (millions) — basic and diluted (e) Net income (loss) per common unit — basic and diluted (f) $ $ ) $ (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.

CHANGE IN OPERATING WORKING 122

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 ) Change in other current assets Change in accounts payable and accrued liabilities ) (a) Change in accounts payable to affiliates ) ) Change in state income taxes payable — Change in accrued interest Change in operating working capital (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 ) Change in other current assets ) ) ) Change in accounts payable and accrued liabilities (a) ) Change in accounts payable to affiliates — ) (b) ) Change in state income taxes payable — ) Change in accrued interest ) Change in operating working capital ) ) (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).

RELATED PARTY TRANSACTIONS (123

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) Northern Border (a) PNGTS (a) (c) GTN (a) Bison (b) ) North Baja Tuscarora Impact on the Partnership’s net income: Great Lakes Northern Border PNGTS (c) GTN Bison North Baja Tuscarora (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) Northern Border (a) PNGTS (a) (b) GTN (a) (c) Bison (a) (d) North Baja Tuscarora Impact on the Partnership’s net income attributable to controlling interests: Great Lakes Northern Border PNGTS (b) GTN (c) Bison (d) North Baja Tuscarora
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) Northern Border (a) PNGTS (a) (c) GTN Bison –– North Baja –– Tuscarora (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) Northern Border (a) PNGTS (a) (b) GTN Bison — North Baja — Tuscarora (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).

ACCOUNTS RECEIVABLE AND OTHE124

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 Imbalance receivable from affiliates Other (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 Imbalance receivable from affiliates Other — (a) Recast to consolidate PNGTS for all periods presented (Refer to Note 2).

FINANCIAL CHARGES AND OTHER 125

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) PNGTS’ amortization of derivative loss on derivative instruments (Note 11) (b) — — Net realized loss related to the interest rate swaps (b) — — Other Income (b) — — (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) (b)

VARIABLE INTEREST ENTITIES (126

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 Accounts receivable and other Inventories Other current assets Equity investments Plant, property and equipment Other assets Accounts payable and accrued liabilities ) ) Accounts payable to affiliates, net ) ) Distributions payable ) ) Accrued interest ) ) State income tax payable ) — Current portion of long-term debt ) ) Long-term debt ) ) Other liabilities ) ) Deferred state income tax ) ) (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 Accounts receivable and other Inventories Other current assets Equity investments Plant, property and equipment Other assets Accounts payable and accrued liabilities ) ) Accounts payable to affiliates, net ) ) Distributions payable ) ) Accrued interest ) ) Current portion of long-term debt ) ) Long-term debt ) ) Other liabilities ) ) Deferred state income tax ) ) (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).

INCOME TAXES (Tables)127

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 Deferred — ) (a) Recast to consolidate PNGTS for all periods presented (Refer to Note 2).	Year ended December 31 2016 (a) 2015 (a) 2014 (a) State income taxes Current ) Deferred — ) (a) Recast to consolidate PNGTS for all periods presented (Refer to Note 2).

ORGANIZATION - Ownership Int128

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

SIGNIFICANT ACCOUNTING POLIC129

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%

ACCOUNTING PRONOUNCEMENTS - 130

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).

EQUITY INVESTMENTS (Details)131

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).

DEBT AND CREDIT FACILITIES -132

DEBT AND CREDIT FACILITIES - Amounts Outstanding and Description of Terms (Details)		Jan. 03, 2017USD ($)	Dec. 31, 2016USD ($)	Sep. 30, 2015USD ($)	Mar. 31, 2017USD ($)entity	Mar. 31, 2016USD ($)	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)	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).

DEBT AND CREDIT FACILITIES -133

DEBT AND CREDIT FACILITIES - Principal Payments Required (Details) - USD ($) $ in Millions	Mar. 31, 2017	Dec. 31, 2016
Principal repayments required on debt
2,017	$ 40
2,018	715	$ 715
2,019	43	43
2,020	100	100
2,021	460	510
Thereafter	500	500
Total debt	$ 1,858	$ 1,920

PARTNERS' EQUITY - ATM Equit134

PARTNERS' EQUITY - ATM Equity Issuance Program (Details) - USD ($)		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).

PARTNERS' EQUITY - Class B U135

PARTNERS' EQUITY - Class B Units (Details) - USD ($)		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).

PARTNERS' EQUITY - Reclassifica

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).

NET INCOME PER COMMON UNIT - Ge

NET INCOME PER COMMON UNIT - General Partner Effective Interest and Allocated Incentive Distributions (Details)	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%

NET INCOME PER COMMON UNIT - Te

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		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).

CASH DISTRIBUTIONS TO COMMON139

CASH DISTRIBUTIONS TO COMMON UNITS - Distributions Paid (Details) - USD ($) $ / shares in Units, $ in Millions	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

CHANGE IN OPERATING WORKING 140

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).

CHANGE IN OPERATING WORKING 141

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).

RELATED PARTY TRANSACTIONS (142

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		$ 8	$ 8
Amount included in receivables from related party		$ 1		$ 2	$ 1
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	$ 1	$ 3	$ 3	$ 3
TransCanada's subsidiaries | GTN
Capital and operating costs charged to the pipeline systems and amount payable
Net amounts payable		3		3	3
TransCanada's subsidiaries | GTN | Capital and operating costs
Capital and operating costs charged to the pipeline systems and amount payable
Costs charged		7	6	27	30	30
Impact on the Partnership's net income attributable to controlling interests		$ 7	$ 5	$ 24	$ 25	$ 19
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		$ 4	$ 5
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	$ 6	$ 32	$ 36	$ 35
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		$ 1	$ 3
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	$ 2	$ 8	8	$ 8
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
Revenues from related party		0	$ 1	2	3
TransCanada's subsidiaries | Bison
Capital and operating costs charged to the pipeline systems and amount payable
Net amounts payable				1
TransCanada's subsidiaries | Bison | Capital and operating costs
Capital and operating costs charged to the pipeline systems and amount payable
Costs charged		1		2	4	6
Revenue, net of costs charged			(1)
Impact on the Partnership's net income attributable to controlling interests		1	$ 1
Impact on the Partnership's net income attributable to controlling interests				$ 3	$ 4	$ 4
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		$ 4	$ 3
Percentage of capital and operating costs charged		100.00%	100.00%
Amount included in receivables from related party		$ 15		19	17
TransCanada's subsidiaries | Great Lakes | Capital and operating costs
Capital and operating costs charged to the pipeline systems and amount payable
Costs charged		$ 8	$ 7	30	30	$ 30
Impact on the Partnership's net income attributable to controlling interests				$ 13	$ 13	$ 13
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	$ 51
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
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	$ 1	4	$ 5	$ 5
Impact on the Partnership's net income attributable to controlling interests		1	1	4	5	4
TransCanada's subsidiaries | Tuscarora Gas Transmission Company
Capital and operating costs charged to the pipeline systems and amount payable
Net amounts payable		1		1	1
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	1	5	4	4
Impact on the Partnership's net income attributable to controlling interests		1	1	4	4	4
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	$ 3
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	$ 3	12	14	16
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	$ 1	$ 5	$ 5	$ 5
[1]	Recast to consolidate PNGTS for all periods presented (Refer to Note 2).

FAIR VALUE MEASUREMENTS - Es143

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	$ 1,963	$ 1,945

FAIR VALUE MEASUREMENTS - In144

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).

ACCOUNTS RECEIVABLE AND OTHE145

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).

FINANCIAL CHARGES AND OTHER 146

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).

CONTINGENCIES (Details)147

CONTINGENCIES (Details) - Great Lakes v. Essar Steel Minnesota LLC, et al. - Great Lakes - USD ($) $ in Millions	Sep. 16, 2015	Oct. 29, 2009	Apr. 30, 2017	Dec. 31, 2017
Contingencies
Judgement awarded			$ 31.5	$ 31.5
Essar
Contingencies
Recovery sought		$ 33
Judgement awarded	$ 32.9

REGULATORY (Details)

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

VARIABLE INTEREST ENTITIES -149

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).

INCOME TAXES (Details)150

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).

SUBSEQUENT EVENTS - Distribu151

SUBSEQUENT EVENTS - Distributions (Details) - USD ($)		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												$ 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
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).