View Filing Data

Operation and maintenance expenses

$ 100

$ 103

^[1]

$ 313

$ 315

^[1]

Equity earnings (Note 4)

^[1]

(16)

(15)

^[1]

(47)

(42)

^[1]

Property taxes

(7)

^[1]

(21)

(20)

^[1]

General and administrative

(1)

^[1]

(6)

(5)

^[1]

Financial charges and other (Note 14)

(25)

(24)

^[1]

(73)

(71)

^[1]

(23)

(18)

^[1]

(59)

(53)

^[1]

Net income before taxes

^[1]

194

199

^[1]

Income taxes (Note 18)

(1)

^[1]

Net income attributable to non-controlling interests

^[1]

193

^[2]

198

^[1]

^[1]

Net income attributable to controlling interest allocation (Note 8)

^[1]

186

188

^[1]

General Partner

^[1]

TransCanada and its subsidiaries

^[1]

^[1]

186

188

^[1]

Net income attributable to controlling interest allocation (Note 8)

Limited partners

$ 42

$ 43

^[1]

$ 164

^[1]

Net income per common unit (Note 8) - basic (in dollars per unit)

$ 0.61

$ 0.65

^[1],[3]

$ 2.38

$ 2.51

^[1],[3]

Net income per common unit (Note 8) - diluted (in dollars per unit)

$ 0.61

$ 0.65

$ 2.38

$ 2.51

Weighted average common units outstanding - basic (in units)

69.4

66.1

^[1]

68.9

65.3

^[1]

Weighted average common units outstanding - diluted (in units)

69.4

66.1

68.9

65.3

Common units outstanding, end of period (in units)

69.6

66.6

^[1]

69.6

66.6

^[1]

[1]	Recast to consolidate PNGTS for all periods presented (Refer to Notes 2 and 6).
[2]	Recast to consolidate PNGTS for all periods presented (Refer to Notes 2 and 6).
[3]	Net income per common unit prior to recast (Refer to Note 2).

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($)
$ in Millions

3 Months Ended

9 Months Ended

Sep. 30, 2017

Sep. 30, 2016

^[1]

Sep. 30, 2017

Sep. 30, 2016

^[1]

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

Change in fair value of cash flow hedges (Note 12)

$ 55

$ 60

$ 193

^[2]

$ 198

Other comprehensive income

(1)

Amortization of realized loss on derivative financial instruments (Note 12)

Reclassification to net income of gains and losses on cash flow hedges (Note 12)

Comprehensive income

195

198

Comprehensive income attributable to non-controlling interests

Comprehensive income attributable to controlling interests

$ 55

$ 60

$ 188

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

CONSOLIDATED BALANCE SHEETS - USD ($)
$ in Millions

Sep. 30, 2017

Dec. 31, 2016

Current Assets

Accounts receivable and other (Note 13)

$ 73

$ 64

^[1]

^[1]

Inventories

^[1]

Other

^[1]

Total current assets

121

125

^[1]

Equity investments (Note 4)

1,207

918

^[1]

Plant, property and equipment (Net of $1,158 accumulated depreciation; 2016 - $1,088)

2,133

2,180

^[1]

Goodwill

130

^[1]

Accounts payable and accrued liabilities

^[1]

Total assets

3,591

3,354

^[1]

Current Liabilities

^[1]

Accounts payable to affiliates (Note 11)

^[1]

Distribution payable

^[1]

Accrued interest

^[1]

Current portion of long-term debt (Note 5)

^[1]

Total current liabilities

108

102

^[1]

Long-term debt, net (Note 5)

2,427

1,859

^[1]

Deferred state income taxes (Note 18)

^[1]

Other liabilities

^[1]

Total liabilities

2,573

1,999

^[1]

Common units subject to rescission (Note 7)

^[1]

Partners' Equity

General partner

^[1]

Accumulated other comprehensive loss

^[1]

(2)

Controlling interests

916

1,144

^[1]

Non-controlling interests

102

^[1]

Equity of former parent of PNGTS

^[1]

Total partners' equity

^[2]

1,018

1,272

Total liabilities and partners' equity

3,591

3,354

^[1]

Partners' Equity

Limited partner

790

1,002

^[1]

Class B Units

Partners' Equity

Limited partner

$ 103

$ 117

^[1]

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

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

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($)
$ in Millions

9 Months Ended

Sep. 30, 2017

Sep. 30, 2016

Cash Generated From Operations

$ 193

^[1]

$ 198

^[2]

Amortization of debt issue costs reported as interest expense

^[2]

^[2]

Amortization of realized loss on derivative instrument

^[2]

Equity earnings from equity investments (Note 3 and 4)

(87)

(75)

^[2]

Distributions received from operating activities of equity investments (Note 3)

106

125

^[2]

Change in operating working capital (Note 10)

^[2]

Net Cash Provided by (Used in) Operating Activities

311

332

^[2]

Distribution received from Iroquois as return of investment (Note 4)

Capital expenditures

(26)

(21)

^[2]

Other

^[2]

Net Cash Provided by (Used in) Investing Activities

(756)

(215)

^[2]

Distributions paid to non-controlling interests

(5)

(12)

^[2]

Common unit issuance, net (Note 7)

126

^[2]

Common unit issuance subject to rescission, net (Note 7)

^[2]

Long-term debt issued, net of discount (Note 5)

732

200

^[2]

Long-term debt repaid (Note 5)

(164)

(196)

^[2]

Debt issuance costs

(2)

Total financing activities

454

(95)

^[2]

Decrease in cash and cash equivalents

^[2]

Cash and cash equivalents, beginning of period

^[2]

Cash and cash equivalents, end of period

^[2]

Class B Units

Distributions paid (Note 7)

(22)

(12)

^[2]

Common units and General Partner interest combined

Distributions paid (Note 9)

(210)

(184)

^[2]

Equity earnings from equity investments (Note 3 and 4)

Cash Generated From Operations

(50)

(52)

(83)

Equity earnings from equity investments (Note 3 and 4)

Cash Generated From Operations

(24)

(23)

(4)

^[2]

^[2]

(193)

Distributions paid to former parent of PNGTS

(1)

$ (9)

^[2]

Portland Natural Gas Transmission System And Iroquois Acquisition

Partners' Equity at beginning of year at Dec. 31, 2016

$ (646)

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

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

CONSOLIDATED STATEMENT OF CHANGES IN PARTNERS' EQUITY - 9 months ended Sep. 30, 2017 - USD ($)
shares in Millions, $ in Millions

Limited Partners

Common Units

Limited Partners

Class B Units

General Partner

Accumulated Other Comprehensive Loss

^[1]

Non-Controlling Interest

Equity of former parent of PNGTS

Total

$ 1,002

$ 117

$ 27

$ (2)

^[2]

$ 97

^[2]

$ 31

^[2]

$ 1,272

^[2]

Partners' Equity at beginning of year (in units) at Dec. 31, 2016

67.4

1.9

Increase (Decrease) in Partners' Equity

Other comprehensive income

^[2]

$ 164

$ 8

193

^[2]

$ 2

ATM equity issuance, net (Note 7)

$ 124

126

^[2]

ATM equity issuance, net (Note 7) (in units)

2.2

Reclassification of common units no longer subject to rescission (Note 7)

$ 81

^[2]

Acquisition of interests in PNGTS and Iroquois (Note 6)

(383)

(8)

(32)

^[2]

(423)

^[2]

Distributions

^[2]

(198)

(22)

(12)

(2)

$ (1)

(235)

Partners' Equity at end of year at Sep. 30, 2017

$ 790

$ 103

$ 23

$ 102

^[2]

$ 1,018

^[2]

Partners' Equity at end of year (in units) at Sep. 30, 2017

69.6

1.9

[1]

Losses related to cash flow hedges reported in Accumulated Other Comprehensive Loss and expected to be reclassified to Net Income in the next 12 months are estimated to be $1 million. These estimates assume constant interest rates over time; however, the amounts reclassified will vary based on actual value of interest rates at the date of settlement.Recast to consolidate PNGTS for all periods presented (Refer to Notes 2 and 6).

[2]

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

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

ORGANIZATION	9 Months Ended
ORGANIZATION	Sep. 30, 2017
ORGANIZATION
ORGANIZATION	NOTE 1 ORGANIZATION TC PipeLines, LP and its subsidiaries are collectively referred to herein as the Partnership. The Partnership was formed by TransCanada PipeLines Limited, a wholly owned subsidiary of TransCanada Corporation (TransCanada Corporation together with its subsidiaries collectively referred to herein as TransCanada), to acquire, own and participate in the management of energy infrastructure assets in North America. The Partnership owns its pipeline assets through three intermediate limited partnerships (ILPs), TC GL Intermediate Limited Partnership, TC PipeLines Intermediate Limited Partnership and TC Tuscarora Intermediate Limited Partnership.

SIGNIFICANT ACCOUNTING POLICIES	9 Months Ended
SIGNIFICANT ACCOUNTING POLICIES	Sep. 30, 2017
SIGNIFICANT ACCOUNTING POLICIES
SIGNIFICANT ACCOUNTING POLICIES	NOTE 2 SIGNIFICANT ACCOUNTING POLICIES The accompanying financial statements and related notes have been prepared in accordance with United States generally accepted accounting principles (GAAP) and amounts are stated in U.S. dollars. The results of operations for the three and nine months ended September 30, 2017 and 2016 are not necessarily indicative of the results that may be expected for the full fiscal year. The accompanying financial statements should be read in conjunction with the audited financial statements and notes thereto for the year ended December 31, 2016 included as exhibit 99.2 in our Current Report on Form 8-K dated August 3, 2017. That report contains a more comprehensive summary of the Partnership’s significant accounting policies. In the opinion of management, the accompanying financial statements contain all of the appropriate adjustments, all of which are normally recurring adjustments unless otherwise noted, and considered necessary to present fairly the financial position of the Partnership, the results of operations and cash flows for the respective periods. Our significant accounting policies are consistent with those disclosed in our audited financial statements and notes thereto for the year ended December 31, 2016 included as exhibit 99.2 in our Current Report on Form 8-K dated August 3, 2017, except as described in Note 3, Accounting Pronouncements. Basis of Presentation The Partnership consolidates its interests in entities over which it is able to exercise control. To the extent there are interests owned by other parties, these interests are included in non-controlling interests. The Partnership uses the equity method of accounting for its investments in entities over which it is able to exercise significant influence. Acquisitions by the Partnership from TransCanada are considered common control transactions. When businesses are acquired from TransCanada that will be consolidated by the Partnership, the historical financial statements are required to be recast, except net income per common unit, to include the acquired entities for all periods presented. When the Partnership acquires an asset or an investment from TransCanada, which will be accounted for by the equity method, the financial information is not required to be recast and the transaction is accounted for prospectively from the date of the acquisition. On June 1, 2017, the Partnership acquired from a subsidiary of TransCanada an additional 11.81 percent interest in PNGTS, that resulted in the Partnership owning a 61.71 percent interest in PNGTS (Refer to Note 6). As a result of the Partnership owning 61.71 percent interest in PNGTS, the Partnership’s historical financial information has been recast, except net income (loss) per common unit, to consolidate PNGTS for all the periods presented in the Partnership’s consolidated financial statements. Additionally, this acquisition was accounted for as transaction between entities under common control, similar to pooling of interests, whereby the assets and liabilities of PNGTS were recorded at TransCanada’s carrying value. Also, on June 1, 2017, the Partnership acquired from subsidiaries of TransCanada a 49.34 percent interest in Iroquois Gas Transmission, L.P. (“Iroquois”) (Refer to Note 6). Accordingly, this transaction was accounted for as a transaction between entities under common control, similar to pooling of interest, whereby the equity investment in Iroquois was recorded at TransCanada’s carrying value and was accounted for prospectively. Use of Estimates The preparation of financial statements requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities as of the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Although management believes these estimates are reasonable, actual results could differ from these estimates.

ACCOUNTING PRONOUNCEMENTS	9 Months Ended
ACCOUNTING PRONOUNCEMENTS	Sep. 30, 2017
ACCOUNTING PRONOUNCEMENTS
ACCOUNTING PRONOUNCEMENTS	NOTE 3 ACCOUNTING PRONOUNCEMENTS Retrospective application of Accounting Standards Update (ASU) No 2016-15 “Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments” In August 2016, the Financial Accounting Standards Board (FASB) issued an amendment of previously issued guidance, which intends to reduce diversity in practice in how certain transactions are classified in the statement of cash flows. The new guidance is effective January 1, 2018, however, as early adoption is permitted, the Partnership elected to retrospectively apply this guidance effective December 31, 2016. The Partnership has elected to classify distributions received from equity method investees using the nature of distributions approach as it is more representative of the nature of the underlying activities of the investees that generated the distributions. As a result, certain comparative period distributions received from equity method investees, amounting to $50 million for the nine months ended September 30, 2016, have been reclassified from investing activities to cash generated from operations in the consolidated statement of cash flows. Effective January 1, 2017 Inventory In July 2015, the FASB issued new guidance on simplifying the measurement of inventory. The new guidance specifies that an entity should measure inventory within the scope of this update at the lower of cost and net realizable value. Net realizable value is the estimated selling price in the ordinary course of business, less reasonably predictable costs of completion, disposal and transportation. This new guidance was effective January 1, 2017, was applied prospectively and did not have a material impact on the Partnership’s consolidated balance sheet. Equity method and joint ventures In March 2016, the FASB issued new guidance that simplifies the transition to equity method accounting. The new guidance eliminates the requirement to retroactively apply the equity method of accounting when an increase in ownership interest in an investment qualifies for equity method accounting. The new guidance is effective January 1, 2017 and was applied prospectively. The application of this guidance did not have a material impact on the Partnership’s consolidated financial statements. Consolidation In October 2016, the FASB issued new guidance on consolidation relating to interests held through related parties that are under common control. The new guidance amends the consolidation requirements such that if a decision maker is required to evaluate whether it is the primary beneficiary of a variable interest entry (VIE), it will need to consider only its proportionate indirect interest in the VIE held through a common control party. The guidance was effective January 1, 2017, was applied retrospectively and did not result in any change to our consolidation conclusions. Future accounting changes Revenue from contracts with customers In 2014, the FASB issued new guidance on revenue from contracts with customers. The new guidance requires that an entity recognize revenue in accordance with a prescribed model. This model is used to depict the transfer of promised goods or services to customers in an amount that reflects the total consideration to which it expects to be entitled during the term of the contract in exchange for those goods or services. The new guidance also requires additional disclosures about the nature, amount, timing and uncertainty of revenue and the related cash flows. The Partnership will adopt the new standard on the effective date of January 1, 2018. There are two methods in which the new standard can be adopted: (1) a full retrospective approach with restatement of all prior periods presented, or (2) a modified retrospective approach with a cumulative-effect adjustment as of the date of adoption. The Partnership will adopt the standard using the modified retrospective approach with the cumulative-effect of the adjustment recognized at the date of adoption, subject to allowable and elected practical expedients. The Partnership has identified all existing customer contracts that are within the scope of the new guidance and is on schedule in the process of analyzing individual contracts or groups of contracts to identify any significant changes in how revenues are recognized as a result of implementing the new guidance. While the Partnership has not identified any material differences in the amount and timing of revenue recognition for the contracts that have been analyzed to date, the evaluation is not complete and the Partnership has not concluded on the overall impact of adopting the new guidance. The Partnership continues its contract analysis to obtain the information necessary to quantify the cumulative-effect adjustment, if any, on prior period revenues and revenue recognized going forward. Although consolidated revenues may not be materially impacted by the new guidance, the Partnership currently anticipates significant changes to disclosures based on the additional requirements prescribed. These new disclosures include information regarding the significant judgments used in evaluating when and how revenue is recognized and information related to contract assets and liabilities. In addition, the new guidance requires that the Partnership’s revenue recognition policy disclosure includes additional detail regarding the various performance obligations and the nature, amount, timing and estimates of revenue and cash flows generated from contracts with customers. The Partnership continues to develop and evaluate disclosures required with a particular focus on the scope of contracts subject to disclosure of remaining performance obligations. The Partnership also continues to address any system and process changes necessary to compile the information to meet the recognition and disclosure requirements of the new guidance. The Partnership continues to monitor additional authoritative or interpretive guidance related to the new guidance as it becomes available. Leases In February 2016, the FASB issued new guidance on the accounting for leases. The new guidance amends the definition of a lease requiring the customer to have both (1) the right to obtain substantially all of the economic benefits from the use of the asset and (2) the right to direct the use of the asset in order for the arrangement to qualify as a lease. The new guidance also establishes a right-of-use (ROU) model that requires a lessee to recognize a ROU asset and corresponding lease liability on the balance sheet for all leases with a term longer than 12 months. Leases will be classified as finance or operating, with classification affecting the pattern and classification of expense recognition in the income statement. The new guidance does not make extensive changes to lessor accounting. The new guidance is effective on January 1, 2019, with early adoption permitted. A modified retrospective transition approach is required for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements, with certain practical expedients available. The Partnership is continuing to identify and analyze existing lease agreements to determine the effect of adoption of the new guidance on its consolidated financial statements. The Partnership is also addressing system and process changes necessary to compile the information to meet the recognition and disclosure requirements of the new guidance. Goodwill Impairment In January 2017, the FASB issued new guidance on simplifying the test for goodwill impairment by eliminating the requirement to calculate the implied fair value of goodwill to measure the impairment charge. Instead, entities will record an impairment charge based on the excess of a reporting unit’s carrying amount over its fair value. This new guidance is effective January 1, 2020 and will be applied prospectively. Early adoption is permitted. The Partnership is currently evaluating the impact of the adoption of this guidance and has not yet determined the effect on its consolidated financial statements. Hedge Accounting In August 2017, the FASB issued new guidance on hedge accounting, making more financial and nonfinancial hedging strategies eligible for hedge accounting. The new guidance amends the presentation requirements relating to the change in fair value of a derivative and additional disclosure requirements include cumulative basis adjustments for fair value hedges and the effect of hedging on individual statement of income line items. This new guidance is effective January 1, 2019 and will be applied prospectively with a cumulative-effect adjustment to opening equity on adoption. Early adoption is permitted. The Partnership is currently evaluating the impact of the adoption of this guidance and has not yet determined the effect on its consolidated financial statements.

EQUITY INVESTMENTS

9 Months Ended

Sep. 30, 2017

DEBT AND CREDIT FACILITIES

EQUITY INVESTMENTS

NOTE 4 EQUITY INVESTMENTS

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

	Ownership		Equity Earnings				Equity Investments
	Interest at		Three months		Nine Months
(unaudited)	September 30,		ended September 30,		ended September 30,		September 30,	December 31,
(millions of dollars)	2017		2017	2016(b)	2017	2016(b)	2017	2016(b)

Northern Border (a)	50	%	16	18	50	52	516	444
Great Lakes	46.45	%	2	4	24	23	469	474
Iroquois	49.34	%	9	—	13	—	222	—

			27	22	87	75	1,207	918

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

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

Northern Border

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

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

The summarized financial information for Northern Border is as follows:

(unaudited)
(millions of dollars)	September 30, 2017		December 31, 2016

ASSETS
Cash and cash equivalents	24		14
Other current assets	36		36
Plant, property and equipment, net	1,069		1,089
Other assets	14		14

	1,143		1,153


LIABILITIES AND PARTNERS’ EQUITY
Current liabilities	48		38
Deferred credits and other	30		28
Long-term debt, including current maturities, net	264		430
Partners’ equity
Partners’ capital	802		659
Accumulated other comprehensive loss	(1	)	(2	)

	1,143		1,153

	Three months ended				Nine months ended
(unaudited)	September 30,				September 30,
(millions of dollars)	2017		2016		2017		2016

Transmission revenues	73		74		217		218
Operating expenses	(20	)	(18	)	(56	)	(53	)
Depreciation	(15	)	(15	)	(45	)	(44	)
Financial charges and other	(5	)	(5	)	(14	)	(16	)

Net income	33		36		102		105

Great Lakes

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

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

The summarized financial information for Great Lakes is as follows:

(unaudited)
(millions of dollars)	September 30, 2017	December 31, 2016

ASSETS
Current assets	56	66
Plant, property and equipment, net	705	714

	761	780


LIABILITIES AND PARTNERS’ EQUITY
Current liabilities	41	40
Net long-term debt, including current maturities	269	278
Partners’ equity	451	462

	761	780

	Three months ended				Nine months ended
(unaudited)	September 30,				September 30,
(millions of dollars)	2017		2016		2017		2016

Transmission revenues	34		36		138		133
Operating expenses	(19	)	(15	)	(49	)	(45	)
Depreciation	(7	)	(7	)	(21	)	(21	)
Financial charges and other	(5	)	(6	)	(16	)	(17	)

Net income	3		8		52		50

Iroquois

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

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

The summarized financial information for Iroquois is as follows:

(unaudited)
(millions of dollars)	September 30, 2017	December 31, 2016

ASSETS
Cash and cash equivalents	93	86
Other current assets	33	34
Plant, property and equipment, net	592	604
Other assets	8	7

	726	731


LIABILITIES AND PARTNERS’ EQUITY
Current liabilities	20	18
Net long-term debt, including current maturities	332	335
Other non-current liabilities	9	6
Partners’ equity	365	372

	726	731

	Three months ended				Nine months ended
(unaudited)	September 30,				September 30,
(millions of dollars)	2017		2016		2017		2016

Transmission revenues	43		45		142		145
Operating expenses	(13	)	(13	)	(41	)	(43	)
Depreciation	(7	)	(9	)	(22	)	(28	)
Financial charges and other	(4	)	(4	)	(13	)	(12	)

Net income	19		19		66		62

DEBT AND CREDIT FACILITIES

9 Months Ended

Sep. 30, 2017

DEBT AND CREDIT FACILITIES

NOTE 5 DEBT AND CREDIT FACILITIES

(unaudited) (millions of dollars)	September 30, 2017	Weighted Average Interest Rate for the Nine Months Ended September 30, 2017		December 31, 2016 (a)	Weighted Average Interest Rate for the Year Ended December 31, 2016

TC PipeLines, LP
Senior Credit Facility due 2021	255	2.34	%	160	1.72	%
2013 Term Loan Facility due October 2022	500	2.26	%	500	1.73	%
2015 Term Loan Facility due October 2020	170	2.15	%	170	1.63	%
4.65% Unsecured Senior Notes due 2021	350	4.65	%(b)	350	4.65	%(b)
4.375% Unsecured Senior Notes due 2025	350	4.375	%(b)	350	4.375	%(b)
3.90 % Unsecured Senior Notes due 2027	500	3.90	%(b)	—	—
GTN
5.29% Unsecured Senior Notes due 2020	100	5.29	%(b)	100	5.29	%(b)
5.69% Unsecured Senior Notes due 2035	150	5.69	%(b)	150	5.69	%(b)
Unsecured Term Loan Facility due 2019	55	1.95	%	65	1.43	%
PNGTS
5.90% Senior Secured Notes due December 2018	36	5.90	%(b)	53	5.90	%(b)
Tuscarora
Unsecured Term Loan due 2020	25	2.18	%	10	1.64	%
3.82% Series D Senior Notes due August 2017	—	3.82	%(b)	12	3.82	%(b)

	2,491			1,920
Less: unamortized debt issuance costs and debt discount	13			9
Less: current portion	51			52

	2,427			1,859

(a)

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

(b)

Fixed interest rate

TC Pipelines, LP

The Partnership’s Senior Credit Facility consists of a $500 million senior revolving credit facility with a banking syndicate, maturing November 10, 2021, under which $255 million was outstanding at September 30, 2017 (December 31, 2016 - $160 million), leaving $245 million available for future borrowing. The LIBOR-based interest rate on the Senior Credit Facility was 2.49 percent at September 30, 2017 (December 31, 2016 — 1.92 percent).

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

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

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

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

PNGTS

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

GTN

GTN’s Unsecured Senior Notes, along with GTN’s Unsecured Term Loan Facility contain a covenant that limits total debt to no greater than 70 percent of GTN’s total capitalization. GTN’s total debt to total capitalization ratio at September 30, 2017 was 44.2 percent. The LIBOR-based interest rate on the GTN’s Unsecured Term Loan Facility was 2.19 percent at September 30, 2017 (December 31, 2016 — 1.57 percent).

Tuscarora

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

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

At September 30, 2017, the Partnership was in compliance with its financial covenants, in addition to the other covenants which include restrictions on entering into mergers, consolidations and sales of assets, granting liens, material amendments to the Third Amended and Restated Agreement of Limited Partnership (Partnership Agreement), incurring additional debt and distributions to unitholders.

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

(unaudited)
(millions of dollars)

2017		12
2018		45
2019		36
2020		293
2021		605
Thereafter		1,500

		2,491

ACQUISITION

9 Months Ended

Sep. 30, 2017

ACQUISITION

ACQUISITION

NOTE 6 ACQUISITION

2017 Acquisition

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

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

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

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

Iroquois’ net purchase price was allocated as follows:

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

Excess purchase price (b)		370

(a)

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

(b)

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

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

The PNGTS purchase price was recorded as follows:

(millions of dollars)
Current assets	25
Property, plant and equipment, net	294
Current liabilities	(4	)
Deferred state income taxes	(10	)
Long-term debt, including current portion	(41	)

	264

Non-controlling interest	(100	)
Carrying value of pre-existing Investment in PNGTS	(132	)

TransCanada’s carrying value of the acquired 11.81 percent interest at June 1, 2017	32
Excess purchase price over net assets acquired (a)	21

Total cash consideration (b)	53

(a)

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

(b)

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

PARTNERS' EQUITY	9 Months Ended
PARTNERS' EQUITY	Sep. 30, 2017
PARTNERS' EQUITY
PARTNERS' EQUITY	NOTE 7 PARTNERS’ EQUITY ATM equity issuance program (ATM program) During the nine months ended September 30, 2017, we issued 2,165,162 common units under our ATM program generating net proceeds of approximately $124 million, plus $2 million contributed by the General Partner to maintain its effective two percent general partner interest. The commissions to our sales agents in the nine months ended September 30, 2017 were approximately $1 million. The net proceeds were used for general partnership purposes. Class B units issued to TransCanada The Class B Units we issued on April 1, 2015 to finance a portion of the 2015 GTN Acquisition represent a limited partner interest in us and entitle TransCanada to an annual distribution based on 30 percent of GTN’s annual distributions as follows: (i) 100 percent of distributions above $20 million through March 31, 2020; and (ii) 25 percent of distributions above $20 million thereafter. For the year ending December 31, 2017, the Class B units’ equity account will be increased by the excess of 30 percent of GTN’s distributions over the annual threshold of $20 million until such amount is declared for distribution and paid in the first quarter of 2018. During the nine months ended September 30, 2017, 30 percent of GTN’s total distributable cash flow was $28 million. As a result of exceeding the $20 million threshold, the Class B units’ equity account was increased by $8 million (Refer to Note 8). For the year ended December 31, 2016, the Class B distribution was $22 million and was declared and paid in the first quarter of 2017. Common unit issuance subject to rescission In connection with a late filing of an employee-related Form 8-K with the SEC in March 2016, the Partnership became ineligible to use the then effective shelf registration statement upon filing of its Annual Report on Form 10-K for the year ended December 31, 2015. As a result, it was determined that the purchasers of the 1.6 million common units that were issued from March 8, 2016 to May 19, 2016 under the Partnership’s ATM program may have had a rescission right for an amount equal to the purchase price paid for the units, plus statutory interest and less any distributions paid, upon the return of such units to the Partnership. The Securities Act of 1933, as amended (Securities Act) generally requires that any claim brought for a violation of Section 5 of the Securities Act be brought within one year of violation. At December 31, 2016, $83 million was recorded as common units subject to rescission on the consolidated balance sheet. The Partnership classified the 1.6 million common units that were sold under its ATM program from March 8, 2016 up to and including May 19, 2016, which may have been subject to rescission rights, outside of equity given the potential redemption feature which was not within the control of the Partnership. These units were treated as outstanding for financial reporting purposes. No unitholder claimed or attempted to exercise any rescission rights prior to their expiry dates and the final rights related to the sales of such units expired on May 19, 2017. As a result of the expiration of these rights, the $83 million was reclassified back to partners’ equity. At September 30, 2017, there were no outstanding common units subject to rescission on the Partnership’s consolidated balance sheet.

NET INCOME PER COMMON UNIT

9 Months Ended

Sep. 30, 2017

NET INCOME PER COMMON UNIT

NET INCOME PER COMMON UNIT

NOTE 8 NET INCOME PER COMMON UNIT

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

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

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

Net income per common unit was determined as follows:

	Three months ended September 30,						Nine months ended September 30,
(unaudited)
(millions of dollars, except per common unit amounts)	2017			2016 (a)			2017			2016 (a)

Net income attributable to controlling interests (a)	54			58			186			188
Net income attributable to PNGTS’ former parent (a) (b)	—			—			(2		)	(3		)

Net income attributable to General and Limited Partners	54			58			184			185
Incentive distributions allocated to the General Partner (c)	(3		)	(2		)	(9		)	(5		)
Net income attributable to the Class B units (d)	(8		)	(11		)	(8		)	(12		)

Net income attributable to the General Partner and common units	43			45			167			168
Net income attributable to General Partner’s effective two percent interest	(1		)	(2		)	(3		)	(4		)

Net income attributable to common units	42			43			164			164
Weighted average common units outstanding (millions) — basic and diluted	69.4			66.1		(e)	68.9			65.3		(e)
Net income per common unit — basic and diluted	$	0.61		$	0.65	(f)	$	2.38		$	2.51	(f)

(a)

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

(b)

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

(c)

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

(d)

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

(e)

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

(f)

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

CASH DISTRIBUTIONS	9 Months Ended
CASH DISTRIBUTIONS	Sep. 30, 2017
CASH DISTRIBUTIONS
CASH DISTRIBUTIONS	NOTE 9 CASH DISTRIBUTIONS During the three and nine months ended September 30, 2017, the Partnership distributed $1.00 and $2.88 per common unit, respectively (September 30, 2016 — $0.94 and $2.72 per common unit) for a total of $74 million and $210 million, respectively (September 30, 2016 - $65 million and $184 million). The distribution paid to our General Partner during the three months ended September 30, 2017 for its effective two percent general partner interest was $2 million along with an IDR payment of $3 million for a total distribution of $5 million (September 30, 2016 - $1 million for the effective two percent interest and a $2 million IDR payment). The distribution paid to our General Partner during the nine months ended September 30, 2017 for its effective two percent general partner interest was $4 million along with an IDR payment of $7 million for a total distribution of $11 million (September 30, 2016 - $3 million for the effective two percent interest and a $4 million IDR payment).

CHANGE IN OPERATING WORKING CAPITAL

9 Months Ended

Sep. 30, 2017

CHANGE IN OPERATING WORKING CAPITAL

CHANGE IN OPERATING WORKING CAPITAL

NOTE 10 CHANGE IN OPERATING WORKING CAPITAL

(unaudited)	Nine months ended September 30,
(millions of dollars)	2017		2016 (a)

Change in accounts receivable and other	13		3
Change in other current assets	1		2
Change in accounts payable and accrued liabilities(b)	2		3
Change in accounts payable to affiliates	(3	)	(2	)
Change in accrued interest	11		5

Change in operating working capital	24		11

(a)

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

(b)

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

RELATED PARTY TRANSACTIONS

9 Months Ended

Sep. 30, 2017

RELATED PARTY TRANSACTIONS

RELATED PARTY TRANSACTIONS

NOTE 11 RELATED PARTY TRANSACTIONS

The Partnership does not have any employees. The management and operating functions are provided by the General Partner. The General Partner does not receive a management fee in connection with its management of the Partnership. The Partnership reimburses the General Partner for all costs of services provided, including the costs of employee, officer and director compensation and benefits, and all other expenses necessary or appropriate to the conduct of the business of, and allocable to, the Partnership. Such costs include (i) overhead costs (such as office space and equipment) and (ii) out-of-pocket expenses related to the provision of such services. The Partnership Agreement provides that the General Partner will determine the costs that are allocable to the Partnership in any reasonable manner determined by the General Partner in its sole discretion. For both the three and nine months ended September 30, 2017 and 2016, total costs charged to the Partnership by the General Partner were $1 million and $3 million, respectively.

As operator of our pipelines except Iroquois, TransCanada’s subsidiaries provide capital and operating services to our pipeline systems. TransCanada’s subsidiaries incur costs on behalf of our pipeline systems, including, but not limited to, employee salary and benefit costs, and property and liability insurance costs. The Iroquois pipeline system is operated by Iroquois Pipeline Operating Company, a wholly owned subsidiary of Iroquois. Therefore, Iroquois does not receive any capital and operating services from TransCanada.

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

	Three months ended September 30,		Nine months ended September 30,
(unaudited)	Three months ended September 30,		Nine months ended September 30,
(millions of dollars)	2017	2016	2017	2016

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

(unaudited)	September 30,
(millions of dollars)	2017	December 31, 2016

Net amounts payable to TransCanada’s subsidiaries is as follows:
Great Lakes (a)	3	4
Northern Border (a)	3	4
GTN	3	3
Bison	1	1
North Baja	—	1
Tuscarora	—	1
PNGTS	1	1

(a)

Represents 100 percent of the costs.

(b)

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

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

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

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

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

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

In connection with anticipated future commercial opportunities, PNGTS has entered into an arrangement with its affiliates regarding the construction of certain facilities on their systems that will be required to fulfill future contracts on the PNGTS’ system. In the event the anticipated developments do not proceed, PNGTS will be required to reimburse its affiliates for any costs incurred related to the development of these facilities. At September 30, 2017, PNGTS does not have an obligation for reimbursement under this arrangement.

FAIR VALUE MEASUREMENTS

9 Months Ended

Sep. 30, 2017

FAIR VALUE MEASUREMENTS

FAIR VALUE MEASUREMENTS

NOTE 12 FAIR VALUE MEASUREMENTS

(a) Fair Value Hierarchy

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

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

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

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

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

(b) Fair Value of Financial Instruments

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

Long-term debt is recorded at amortized cost and classified in Level 2 of the fair value hierarchy for fair value disclosure purposes. Interest rate derivative assets and liabilities are classified in Level 2 for all periods presented where the fair value is determined by using valuation techniques that refer to observable market data or estimated market prices. The estimated fair value of the Partnership’s debt as at September 30, 2017 and December 31, 2016 was $2,555 million and $1,962 million, respectively.

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

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

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

The Partnership has no master netting agreements; however, it has derivative contracts containing provisions with rights of offset. The Partnership has elected to present the fair value of derivative instruments with the right to offset on a gross basis in the balance sheet. Had the Partnership elected to present these instruments on a net basis, there would be no effect on the consolidated balance sheet as of September 30, 2017 (net asset of nil million as of December 31, 2016).

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

ACCOUNTS RECEIVABLE AND OTHER

9 Months Ended

Sep. 30, 2017

ACCOUNTS RECEIVABLE AND OTHER

ACCOUNTS RECEIVABLE AND OTHER

NOTE 13 ACCOUNTS RECEIVABLE AND OTHER

(unaudited)
(millions of dollars)	September 30, 2017	December 31, 2016 (a)

Trade accounts receivable, net of allowance of nil	34	44
Imbalance receivable from affiliates	—	2
Other	1	1

	35	47

(a)

Recast as discussed in Notes 2 and 6.

FINANCIAL CHARGES AND OTHER

9 Months Ended

Sep. 30, 2017

FINANCIAL CHARGES AND OTHER

FINANCIAL CHARGES AND OTHER

NOTE 14 FINANCIAL CHARGES AND OTHER

	Three months ended September 30,		Nine months ended September 30,
(unaudited)	Three months ended September 30,		Nine months ended September 30,
(millions of dollars)	2017	2016(b)	2017		2016(b)

Interest expense (a)	23	17	59		52
PNGTS’ amortization of derivative loss on derivative instruments (Note 12) (b)	—	—	1		1
Net realized loss related to the interest rate swaps	—	1	—		2
Other income	—	—	(1	)	(2	)

	23	18	59		53

(a)

Includes amortization of debt issuance costs and discount costs.

(b)

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

CONTINGENCIES	9 Months Ended
CONTINGENCIES	Sep. 30, 2017
CONTINGENCIES
CONTINGENCIES	NOTE 15 CONTINGENCIES Great Lakes v. Essar Steel Minnesota LLC, et al. — On October 29, 2009, Great Lakes filed suit in the U.S. District Court, District of Minnesota, against Essar Minnesota LLC (Essar Minnesota) and certain Foreign Essar Affiliates (collectively, Essar) for breach of its monthly payment obligation under its transportation services agreement with Great Lakes. Great Lakes sought to recover approximately $33 million for past and future payments due under the agreement. On September 16, 2015, following a jury trial, the federal district court judge entered a judgment in the amount of $32.9 million in favor of Great Lakes. On September 20, 2015, Essar appealed the decision to the United States Court of Appeals for the Eighth Circuit (Eighth Circuit) based on an allegation of improper jurisdiction and a number of other rulings by the federal district judge. Essar was required to post a performance bond for the full value of the judgment pending appeal. The Eighth Circuit heard the appeal on October 20, 2016. A decision on the appeal was received in December 2016 and the Eighth Circuit vacated Great Lakes’ judgment against Essar finding that there was no federal jurisdiction. Great Lakes filed a Request for Rehearing with the Eighth Circuit and it was denied in January 2017. Before the Circuit Court issued its decision, Essar Minnesota filed for bankruptcy in July 2016. The Foreign Essar Affiliates have not filed for bankruptcy. Following the Circuit Court’s decision, the performance bond was released into the bankruptcy court proceedings. Great Lakes filed a claim against Essar Minnesota in the bankruptcy court and its case against the Foreign Essar Affiliates in Minnesota state court remains pending. In April 2017, after Great Lakes agreement with creditors on an allowed claim, the bankruptcy court approved Great Lakes’ claim in the amount of $31.5 million. On May 20, 2017, the federal district court awarded Essar Minnesota approximately $1.2 million for costs, including recovery of the performance bond premium, to be paid by Great Lakes. Great Lakes filed a motion with the bankruptcy court to offset the $1.2 million award of costs against its claim against Essar Minnesota in the bankruptcy proceeding. If Great Lakes’ motion to offset the federal district court’s award of costs is against its claim in the bankruptcy proceeding is not successful, Great Lakes will be responsible to the bankruptcy estate for payment of the award. Great Lakes is unable to estimate the timing or the extent to which its claim will be recoverable in the bankruptcy proceedings.

REGULATORY	9 Months Ended
REGULATORY	Sep. 30, 2017
REGULATORY
REGULATORY	NOTE 16 REGULATORY North Baja —On January 6, 2017, North Baja notified FERC that current market conditions do not support the replacement of the compression that was temporarily abandoned in 2013 and requested authorization to permanently abandon two compressor units and a nominal volume of unsubscribed firm capacity. FERC approved the permanent abandonment request on February 16, 2017. The abandonments will not have any impact on existing firm transportation service. Great Lakes - On April 24, 2017, Great Lakes reached an agreement on the terms of a new long-term transportation capacity contract with its affiliate, TransCanada. The contract, which was subject to Canada’s National Energy Board (NEB) approval, is for a term of 10 years and allows TransCanada the ability to transport up to 0.711 billion cubic feet of natural gas per day on the Great Lakes system from the Manitoba/U.S. border to the U.S. border near Dawn Ontario. On September 21, 2017, TransCanada received approval from the NEB and as a result, this contract commenced on November 1, 2017. This contract contains volume reduction options up to full contract quantity beginning in year three. On October 30, 2017, Great Lakes filed a rate settlement with FERC to satisfy its obligations from its 2013 rate settlement for new rates to be in effect by January 1, 2018 (2017 Great Lakes Settlement). The 2017 Great Lakes Settlement, if approved by FERC, will decrease Great Lakes’ maximum transportation rates by 27 percent beginning October 1, 2017. Great Lakes expects that the impact from other changes, including: the recent long-term transportation contract with TransCanada as described above, other revenue opportunities on the system and the elimination of the revenue sharing mechanism with its customers, will more than offset the full year impact of the reduction in Great Lakes’ rates beginning in 2018. The 2017 Great Lakes Settlement does not contain any moratorium and Great Lakes will be required to file for new rates no later than March 31, 2022, with new rates to be effective October 1, 2022. Northern Border- Northern Border and its shippers have been engaged in settlement discussions, and have recently agreed to a settlement-in-principle addressing all rate and service related issues raised during the settlement discussions. Northern Border plans to file a settlement agreement with FERC before the end of the year, reflecting the settlement-in-principle, precluding the need to file a general rate case as contemplated by its 2012 Settlement. Northern Border anticipates that the Commission will accept the settlement agreement and that it will be unopposed. This will provide Northern Border with rate stability over the longer term. At this time, we do not believe that the final outcome of the settlement will have a material impact to the Partnership’s results. Northern Border remains a key competitive pipeline and continues to operate at full capacity connecting major supply basins with communities in Midwestern U.S.

VARIABLE INTEREST ENTITIES

9 Months Ended

Sep. 30, 2017

VARIABLE INTEREST ENTITIES

VARIABLE INTEREST ENTITIES

NOTE 17 VARIABLE INTEREST ENTITIES

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

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

Consolidated VIEs

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

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

(unaudited)
(millions of dollars)	September 30, 2017		December 31, 2016(a)

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

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

(a)

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

INCOME TAXES

9 Months Ended

Sep. 30, 2017

INCOME TAXES

INCOME TAXES

NOTE 18 INCOME TAXES

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

	Three months ended September 30,			Nine months ended September 30,
(unaudited)	Three months ended September 30,			Nine months ended September 30,
(millions of dollars)	2017	2016(a)		2017	2016(a)

State income taxes
Current	—	(7	)	1	1
Deferred	—	7		—	—

	—	—		1	1

(a)

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

SUBSEQUENT EVENTS	9 Months Ended
SUBSEQUENT EVENTS	Sep. 30, 2017
SUBSEQUENT EVENTS
SUBSEQUENT EVENTS	NOTE 19 SUBSEQUENT EVENTS Management of the Partnership has reviewed subsequent events through November 6, 2017, the date the financial statements were issued, and concluded there were no events or transactions during this period that would require recognition or disclosure in the consolidated financial statements other than what is disclosed here and/or those already disclosed in the preceding notes. On October 24, 2017, the board of directors of the General Partner declared the Partnership’s third quarter 2017 cash distribution in the amount of $1.00 per common unit payable on November 14, 2017 to unitholders of record as of November 3, 2017. The declared distribution totaled $75 million and is payable in the following manner: $70 million to common unitholders (including $6 million to the General Partner as a holder of 5,797,106 common units and $11 million to another subsidiary of TransCanada as holder of 11,287,725 common units) and $5 million to the General Partner, which included $2 million for its effective two percent general partner interest and $3 million in respect of its IDRs. Northern Border declared its September 2017 distribution of $14 million on October 9, 2017, of which the Partnership will receive its 50 percent share or $7 million on October 31, 2017. Great Lakes declared its third quarter 2017 distribution of $2 million on October 19, 2017, of which the Partnership will receive its 46.45 percent share or $1 million on November 1, 2017. Iroquois declared its third quarter 2017 distribution of $28 million on October 23, 2017, of which the Partnership received its 49.34 percent share or $14 million on November 1, 2017. The distribution includes our 49.34 percent share of the Iroquois unrestricted cash distribution amounting to approximately $2.6 million (Refer to Note 6).

SIGNIFICANT ACCOUNTING POLICIES (Policies)	9 Months Ended
SIGNIFICANT ACCOUNTING POLICIES (Policies)	Sep. 30, 2017
SIGNIFICANT ACCOUNTING POLICIES
Basis of Presentation - Consolidation and equity method of accounting	Basis of Presentation The Partnership consolidates its interests in entities over which it is able to exercise control. To the extent there are interests owned by other parties, these interests are included in non-controlling interests. The Partnership uses the equity method of accounting for its investments in entities over which it is able to exercise significant influence.
Basis of Presentation - Transactions between entities under common control	Acquisitions by the Partnership from TransCanada are considered common control transactions. When businesses are acquired from TransCanada that will be consolidated by the Partnership, the historical financial statements are required to be recast, except net income per common unit, to include the acquired entities for all periods presented. When the Partnership acquires an asset or an investment from TransCanada, which will be accounted for by the equity method, the financial information is not required to be recast and the transaction is accounted for prospectively from the date of the acquisition. On June 1, 2017, the Partnership acquired from a subsidiary of TransCanada an additional 11.81 percent interest in PNGTS, that resulted in the Partnership owning a 61.71 percent interest in PNGTS (Refer to Note 6). As a result of the Partnership owning 61.71 percent interest in PNGTS, the Partnership’s historical financial information has been recast, except net income (loss) per common unit, to consolidate PNGTS for all the periods presented in the Partnership’s consolidated financial statements. Additionally, this acquisition was accounted for as transaction between entities under common control, similar to pooling of interests, whereby the assets and liabilities of PNGTS were recorded at TransCanada’s carrying value. Also, on June 1, 2017, the Partnership acquired from subsidiaries of TransCanada a 49.34 percent interest in Iroquois Gas Transmission, L.P. (“Iroquois”) (Refer to Note 6). Accordingly, this transaction was accounted for as a transaction between entities under common control, similar to pooling of interest, whereby the equity investment in Iroquois was recorded at TransCanada’s carrying value and was accounted for prospectively.
Use of Estimates	Use of Estimates The preparation of financial statements requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities as of the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Although management believes these estimates are reasonable, actual results could differ from these estimates.

EQUITY INVESTMENTS (Tables)

9 Months Ended

Sep. 30, 2017

Schedule of equity investments and summarized financial information for equity investees

	Ownership		Equity Earnings				Equity Investments
	Interest at		Three months		Nine Months
(unaudited)	September 30,		ended September 30,		ended September 30,		September 30,	December 31,
(millions of dollars)	2017		2017	2016(b)	2017	2016(b)	2017	2016(b)

Northern Border (a)	50	%	16	18	50	52	516	444
Great Lakes	46.45	%	2	4	24	23	469	474
Iroquois	49.34	%	9	—	13	—	222	—

			27	22	87	75	1,207	918

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

Schedule of equity investments and summarized financial information for equity investees

(unaudited)
(millions of dollars)	September 30, 2017		December 31, 2016

ASSETS
Cash and cash equivalents	24		14
Other current assets	36		36
Plant, property and equipment, net	1,069		1,089
Other assets	14		14

	1,143		1,153


LIABILITIES AND PARTNERS’ EQUITY
Current liabilities	48		38
Deferred credits and other	30		28
Long-term debt, including current maturities, net	264		430
Partners’ equity
Partners’ capital	802		659
Accumulated other comprehensive loss	(1	)	(2	)

	1,143		1,153

	Three months ended				Nine months ended
(unaudited)	September 30,				September 30,
(millions of dollars)	2017		2016		2017		2016

Transmission revenues	73		74		217		218
Operating expenses	(20	)	(18	)	(56	)	(53	)
Depreciation	(15	)	(15	)	(45	)	(44	)
Financial charges and other	(5	)	(5	)	(14	)	(16	)

Net income	33		36		102		105

Schedule of equity investments and summarized financial information for equity investees

(unaudited)
(millions of dollars)	September 30, 2017	December 31, 2016

ASSETS
Current assets	56	66
Plant, property and equipment, net	705	714

	761	780


LIABILITIES AND PARTNERS’ EQUITY
Current liabilities	41	40
Net long-term debt, including current maturities	269	278
Partners’ equity	451	462

	761	780

	Three months ended				Nine months ended
(unaudited)	September 30,				September 30,
(millions of dollars)	2017		2016		2017		2016

Transmission revenues	34		36		138		133
Operating expenses	(19	)	(15	)	(49	)	(45	)
Depreciation	(7	)	(7	)	(21	)	(21	)
Financial charges and other	(5	)	(6	)	(16	)	(17	)

Net income	3		8		52		50

Schedule of equity investments and summarized financial information for equity investees

(unaudited)
(millions of dollars)	September 30, 2017	December 31, 2016

ASSETS
Cash and cash equivalents	93	86
Other current assets	33	34
Plant, property and equipment, net	592	604
Other assets	8	7

	726	731


LIABILITIES AND PARTNERS’ EQUITY
Current liabilities	20	18
Net long-term debt, including current maturities	332	335
Other non-current liabilities	9	6
Partners’ equity	365	372

	726	731

	Three months ended				Nine months ended
(unaudited)	September 30,				September 30,
(millions of dollars)	2017		2016		2017		2016

Transmission revenues	43		45		142		145
Operating expenses	(13	)	(13	)	(41	)	(43	)
Depreciation	(7	)	(9	)	(22	)	(28	)
Financial charges and other	(4	)	(4	)	(13	)	(12	)

Net income	19		19		66		62

DEBT AND CREDIT FACILITIES (Tables)

9 Months Ended

Sep. 30, 2017

DEBT AND CREDIT FACILITIES

Schedule of debt and credit facilities

(unaudited) (millions of dollars)	September 30, 2017	Weighted Average Interest Rate for the Nine Months Ended September 30, 2017		December 31, 2016 (a)	Weighted Average Interest Rate for the Year Ended December 31, 2016

TC PipeLines, LP
Senior Credit Facility due 2021	255	2.34	%	160	1.72	%
2013 Term Loan Facility due October 2022	500	2.26	%	500	1.73	%
2015 Term Loan Facility due October 2020	170	2.15	%	170	1.63	%
4.65% Unsecured Senior Notes due 2021	350	4.65	%(b)	350	4.65	%(b)
4.375% Unsecured Senior Notes due 2025	350	4.375	%(b)	350	4.375	%(b)
3.90 % Unsecured Senior Notes due 2027	500	3.90	%(b)	—	—
GTN
5.29% Unsecured Senior Notes due 2020	100	5.29	%(b)	100	5.29	%(b)
5.69% Unsecured Senior Notes due 2035	150	5.69	%(b)	150	5.69	%(b)
Unsecured Term Loan Facility due 2019	55	1.95	%	65	1.43	%
PNGTS
5.90% Senior Secured Notes due December 2018	36	5.90	%(b)	53	5.90	%(b)
Tuscarora
Unsecured Term Loan due 2020	25	2.18	%	10	1.64	%
3.82% Series D Senior Notes due August 2017	—	3.82	%(b)	12	3.82	%(b)

	2,491			1,920
Less: unamortized debt issuance costs and debt discount	13			9
Less: current portion	51			52

	2,427			1,859

(a)

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

(b)

Fixed interest rate

Schedule of principal repayments required on debt

(unaudited)
(millions of dollars)

2017		12
2018		45
2019		36
2020		293
2021		605
Thereafter		1,500

		2,491

ACQUISITION (Tables)

9 Months Ended

Sep. 30, 2017

ACQUISITION

Schedule of net purchase price

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

Excess purchase price (b)		370

(a)

(b)

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

Schedule of purchase price allocation

(millions of dollars)
Current assets	25
Property, plant and equipment, net	294
Current liabilities	(4	)
Deferred state income taxes	(10	)
Long-term debt, including current portion	(41	)

	264

Non-controlling interest	(100	)
Carrying value of pre-existing Investment in PNGTS	(132	)

TransCanada’s carrying value of the acquired 11.81 percent interest at June 1, 2017	32
Excess purchase price over net assets acquired (a)	21

Total cash consideration (b)	53

(a)

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

(b)

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

NET INCOME PER COMMON UNIT (Tables)

9 Months Ended

Sep. 30, 2017

NET INCOME PER COMMON UNIT

Schedule of net income per common unit

	Three months ended September 30,						Nine months ended September 30,
(unaudited)
(millions of dollars, except per common unit amounts)	2017			2016 (a)			2017			2016 (a)

Net income attributable to controlling interests (a)	54			58			186			188
Net income attributable to PNGTS’ former parent (a) (b)	—			—			(2		)	(3		)

Net income attributable to General and Limited Partners	54			58			184			185
Incentive distributions allocated to the General Partner (c)	(3		)	(2		)	(9		)	(5		)
Net income attributable to the Class B units (d)	(8		)	(11		)	(8		)	(12		)

Net income attributable to the General Partner and common units	43			45			167			168
Net income attributable to General Partner’s effective two percent interest	(1		)	(2		)	(3		)	(4		)

Net income attributable to common units	42			43			164			164
Weighted average common units outstanding (millions) — basic and diluted	69.4			66.1		(e)	68.9			65.3		(e)
Net income per common unit — basic and diluted	$	0.61		$	0.65	(f)	$	2.38		$	2.51	(f)

(a)

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

(b)

(c)

(d)

(e)

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

(f)

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

CHANGE IN OPERATING WORKING CAPITAL (Tables)

9 Months Ended

Sep. 30, 2017

CHANGE IN OPERATING WORKING CAPITAL

Schedule of change in operating working capital

(unaudited)	Nine months ended September 30,
(millions of dollars)	2017		2016 (a)

Change in accounts receivable and other	13		3
Change in other current assets	1		2
Change in accounts payable and accrued liabilities(b)	2		3
Change in accounts payable to affiliates	(3	)	(2	)
Change in accrued interest	11		5

Change in operating working capital	24		11

(a)

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

(b)

RELATED PARTY TRANSACTIONS (Tables)

9 Months Ended

Sep. 30, 2017

RELATED PARTY TRANSACTIONS

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

	Three months ended September 30,		Nine months ended September 30,
(unaudited)	Three months ended September 30,		Nine months ended September 30,
(millions of dollars)	2017	2016	2017	2016

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

Summary of amount payable to related party for costs charged

(unaudited)	September 30,
(millions of dollars)	2017	December 31, 2016

Net amounts payable to TransCanada’s subsidiaries is as follows:
Great Lakes (a)	3	4
Northern Border (a)	3	4
GTN	3	3
Bison	1	1
North Baja	—	1
Tuscarora	—	1
PNGTS	1	1

(a)

Represents 100 percent of the costs.

(b)

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

ACCOUNTS RECEIVABLE AND OTHER (Tables)

9 Months Ended

Sep. 30, 2017

ACCOUNTS RECEIVABLE AND OTHER

Schedule of accounts receivable and other

(unaudited)
(millions of dollars)	September 30, 2017	December 31, 2016 (a)

Trade accounts receivable, net of allowance of nil	34	44
Imbalance receivable from affiliates	—	2
Other	1	1

	35	47

(a)

Recast as discussed in Notes 2 and 6.

FINANCIAL CHARGES AND OTHER (Tables)

9 Months Ended

Sep. 30, 2017

FINANCIAL CHARGES AND OTHER

Schedule of components of financial charges and other

	Three months ended September 30,		Nine months ended September 30,
(unaudited)	Three months ended September 30,		Nine months ended September 30,
(millions of dollars)	2017	2016(b)	2017		2016(b)

Interest expense (a)	23	17	59		52
PNGTS’ amortization of derivative loss on derivative instruments (Note 12) (b)	—	—	1		1
Net realized loss related to the interest rate swaps	—	1	—		2
Other income	—	—	(1	)	(2	)

	23	18	59		53

(a)

Includes amortization of debt issuance costs and discount costs.

(b)

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

VARIABLE INTEREST ENTITIES (Tables)

9 Months Ended

Sep. 30, 2017

VARIABLE INTEREST ENTITIES

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

(unaudited)
(millions of dollars)	September 30, 2017		December 31, 2016(a)

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

(a)

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

- Definition

Tabular disclosure of the significant judgments and assumptions made in determining whether a variable interest (as defined) held by the entity requires the variable interest entity (VIE) (as defined) to be consolidated and (or) disclose information about its involvement with the VIE, individually or in aggregate (as applicable); the nature of restrictions, if any, on the consolidated VIE's assets and on the settlement of its liabilities reported by an entity in its statement of financial position, including the carrying amounts of such assets and liabilities; the nature of, and changes in, the risks associated with involvement in the VIE; how involvement with the VIE affects the entity's financial position, financial performance, and cash flows; the lack of recourse if creditors (or beneficial interest holders) of the consolidated VIE have no recourse to the general credit of the primary beneficiary (if applicable); the terms of arrangements, giving consideration to both explicit arrangements and implicit variable interests, if any, that could require the entity to provide financial support to the VIE, including events or circumstances that could expose the entity to a loss; the methodology used by the entity for determining whether or not it is the primary beneficiary of the variable interest entity; the significant factors considered and judgments made in determining that the power to direct the activities of a VIE that most significantly impact the VIE's economic performance are shared (as defined); the carrying amounts and classification of assets and liabilities of the VIE included in the statement of financial position; the entity's maximum exposure to loss, if any, as a result of its involvement with the VIE, including how the maximum exposure is determined and significant sources of the entity's exposure to the VIE; a comparison of the carrying amounts of the assets and liabilities and the entity's maximum exposure to loss; information about any liquidity arrangements, guarantees, and (or) other commitments by third parties that may affect the fair value or risk of the entity's variable interest in the VIE; whether or not the entity has provided financial support or other support (explicitly or implicitly) to the VIE that it was not previously contractually required to provide or whether the entity intends to provide that support, including the type and amount of the support and the primary reasons for providing the support; and supplemental information the entity determines necessary to provide.

+ References + Details

INCOME TAXES (Tables)

9 Months Ended

Sep. 30, 2017

INCOME TAXES

Schedule of state income taxes of PNGTS

	Three months ended September 30,			Nine months ended September 30,
(unaudited)	Three months ended September 30,			Nine months ended September 30,
(millions of dollars)	2017	2016(a)		2017	2016(a)

State income taxes
Current	—	(7	)	1	1
Deferred	—	7		—	—

	—	—		1	1

(a)

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

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

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

ACCOUNTING PRONOUNCEMENTS - Statement of Cash Flows (Details) - USD ($)
$ in Millions

9 Months Ended

Sep. 30, 2017

Sep. 30, 2016

ACCOUNTING PRONOUNCEMENTS

Cumulative distributions in excess of equity earnings

$ 3

Distributions from equity investments

$ 106

$ 125

^[1]

Adjustment | ASU 2016-15, Statement of Cash Flows

ACCOUNTING PRONOUNCEMENTS

Cumulative distributions in excess of equity earnings

(50)

Distributions from equity investments

$ 50

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

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

1 Months Ended

3 Months Ended

9 Months Ended

Sep. 01, 2017

Aug. 01, 2017

Jul. 27, 2017

Jun. 01, 2017

Apr. 30, 2006

Sep. 30, 2017

Mar. 31, 2017

Sep. 30, 2016

Sep. 30, 2017

Sep. 30, 2016

Nov. 01, 2017

Oct. 31, 2017

Dec. 31, 2016

$ 27.0

$ 22.0

^[1]

$ 87.0

$ 75.0

^[1]

$ 1,207.0

1,207.0

$ 918.0

^[1]

^[2]

235.0

Return on investment distribution classified as investing activities

106.0

125.0

^[1]

3.0

Total cash call issued to fund debt repayment

$ 9.0

50.00%

$ 16.0

18.0

$ 50.0

52.0

Amortization period of transaction fee

516.0

444.0

12 years

Transaction fee

$ 10.0

Additional ownership interest acquired (as a percent)

20.00%

Capital contribution to reduce the outstanding balance of revolver debt

$ 83.0

83.0

$ 166.0

Assets

24.0

14.0

Plant, property and equipment, net

36.0

1,069.0

1,089.0

Deferred credits and other

14.0

Assets, total

1,143.0

1,153.0

LIABILITIES AND PARTNERS' EQUITY

Current liabilities

48.0

38.0

30.0

28.0

Long-term debt, including current maturities, net

264.0

430.0

Partners' equity

Partners' equity

802.0

659.0

Accumulated other comprehensive loss

(1.0)

(2.0)

Liabilities and Partners' Equity, total

1,143.0

1,153.0

Revenues (expenses)

73.0

74.0

217.0

218.0

Operating expenses

(20.0)

(18.0)

(56.0)

(53.0)

(15.0)

(45.0)

(44.0)

(5.0)

(14.0)

(16.0)

$ 33.0

36.0

$ 102.0

105.0

46.45%

$ 2.0

4.0

$ 24.0

23.0

469.0

474.0

Plant, property and equipment, net

$ 4.0

4.0

^[1]

Assets

Current assets

56.0

66.0

705.0

714.0

Assets, total

761.0

780.0

LIABILITIES AND PARTNERS' EQUITY

Current liabilities

41.0

40.0

Long-term debt, including current maturities, net

269.0

278.0

Partners' equity

Partners' equity

451.0

462.0

Liabilities and Partners' Equity, total

761.0

780.0

Revenues (expenses)

34.0

36.0

138.0

133.0

Operating expenses

(19.0)

(15.0)

(49.0)

(45.0)

(7.0)

(21.0)

(5.0)

(6.0)

(16.0)

(17.0)

$ 3.0

8.0

$ 52.0

50.0

49.34%

$ 9.0

$ 13.0

222.0

$ 710.0

Undistributed earnings

0.0

Assets

93.0

86.0

Plant, property and equipment, net

33.0

34.0

592.0

604.0

Long-term debt, including current maturities, net

8.0

7.0

Assets, total

726.0

731.0

LIABILITIES AND PARTNERS' EQUITY

Current liabilities

20.0

18.0

332.0

335.0

Other non-current liabilities

9.0

6.0

Partners' equity

Partners' equity

365.0

372.0

Liabilities and Partners' Equity, total

726.0

$ 731.0

Revenues (expenses)

43.0

45.0

142.0

145.0

Operating expenses

(13.0)

(41.0)

(43.0)

(7.0)

(9.0)

(22.0)

(28.0)

(4.0)

(13.0)

(12.0)

Iroquois | Distribution declared

$ 19.0

$ 66.0

$ 62.0

Iroquois | Cash Distribution Paid

$ 28.0

Return on investment distribution classified as investing activities

$ 14.0

$ 2.6

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

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

3 Months Ended

9 Months Ended

12 Months Ended

Aug. 21, 2017

USD ($)

May 25, 2017

USD ($)

Sep. 30, 2017

USD ($)

Sep. 30, 2017

USD ($)

entity

Dec. 31, 2016

USD ($)

Credit facilities, short-term loan facility and long-term debt

Less: unamortized debt issuance costs and debt discount

$ 2,491,000,000

$ 1,920,000,000

13,000,000

9,000,000

Less: current portion

51,000,000

52,000,000

^[1]

Long-term debt

$ 2,427,000,000

1,859,000,000

^[1]

Senior Credit Facility due in 2021 and the Term Loan Facilities due in 2020 and 2022

Credit facilities, short-term loan facility and long-term debt

Leverage ratio, actual (as a percent)

476.00%

Senior Credit Facility due in 2021 and the Term Loan Facilities due in 2020 and 2022 | Debt agreement covenants, initial period after occurrence of acquisition

Credit facilities, short-term loan facility and long-term debt

Additional period immediately following the fiscal quarter in which a specified material acquisition occurs

6 months

Senior Credit Facility due in 2021 and the Term Loan Facilities due in 2020 and 2022 | Debt agreement covenants, initial period after occurrence of acquisition | Minimum

Credit facilities, short-term loan facility and long-term debt

Number of acquisitions | entity

Senior Credit Facility due in 2021 and the Term Loan Facilities due in 2020 and 2022 | Debt agreement covenants, initial period after occurrence of acquisition | Maximum

Credit facilities, short-term loan facility and long-term debt

Leverage ratio, covenant (as a percent)

550.00%

Senior Credit Facility due in 2021 and the Term Loan Facilities due in 2020 and 2022 | Debt agreement covenants, periods subsequent to initial period after occurrence of acquisition | Maximum

Credit facilities, short-term loan facility and long-term debt

Leverage ratio, covenant (as a percent)

500.00%

Revolving credit facility | TC Pipelines, LP Senior Credit Facility due 2021

Credit facilities, short-term loan facility and long-term debt

$ 255,000,000

$ 160,000,000

Maximum borrowing capacity

2.34%

1.72%

500,000,000

$ 500,000,000

Amount outstanding under credit facility

255,000,000

$ 160,000,000

Remaining borrowing capacity

$ 245,000,000

Revolving credit facility | TC Pipelines, LP Senior Credit Facility due 2021 | LIBOR

Credit facilities, short-term loan facility and long-term debt

Term loan | TC PipeLines, LP 2013 Term Loan Facility due October 2022

2.49%

1.92%

Credit facilities, short-term loan facility and long-term debt

$ 500,000,000

Term loan | TC PipeLines, LP 2013 Term Loan Facility due October 2022 | LIBOR borrowings | LIBOR

2.26%

1.73%

Credit facilities, short-term loan facility and long-term debt

Credit facilities, short-term loan facility and long-term debt

2.49%

1.87%

Term loan | TC PipeLines, LP 2015 Term Loan Facility due October 2020

2.31%

Credit facilities, short-term loan facility and long-term debt

$ 170,000,000

Term loan | TC PipeLines, LP 2015 Term Loan Facility due October 2020 | LIBOR

2.15%

1.63%

Credit facilities, short-term loan facility and long-term debt

Unsecured debt | TC PipeLines, LP 4.65% Senior Notes due 2021

2.39%

1.77%

Credit facilities, short-term loan facility and long-term debt

4.65%

$ 350,000,000

Unsecured debt | TC PipeLines, LP 4.375% Senior Notes due 2025

4.65%

Credit facilities, short-term loan facility and long-term debt

4.375%

$ 350,000,000

Unsecured debt | TC Pipelines, LP 3.90% Senior Notes due 2027

4.375%

Credit facilities, short-term loan facility and long-term debt

3.90%

$ 500,000,000

Unsecured debt | GTN 5.29% Senior Notes due 2020

3.90%

Amount of debt

$ 500,000,000

Net proceeds

$ 497,000,000

Credit facilities, short-term loan facility and long-term debt

5.29%

$ 100,000,000

Unsecured debt | GTN 5.69% Senior Notes due 2035

5.29%

Credit facilities, short-term loan facility and long-term debt

5.69%

$ 150,000,000

Unsecured debt | GTN Term Loan Facility due 2019

5.69%

Credit facilities, short-term loan facility and long-term debt

55,000,000

$ 55,000,000

$ 65,000,000

Unsecured debt | Tuscarora Term Loan due 2020

1.95%

1.43%

Credit facilities, short-term loan facility and long-term debt

$ 25,000,000

$ 10,000,000

Unsecured debt | Tuscarora Term Loan due 2020 | LIBOR

2.18%

1.64%

Credit facilities, short-term loan facility and long-term debt

Secured debt | PNGTS 5.90% Senior Secured Notes due December 2018

2.36%

1.90%

Credit facilities, short-term loan facility and long-term debt

5.90%

$ 36,000,000

$ 53,000,000

Secured debt | Tuscarora 3.82% Series D Senior Notes due August 2017

5.90%

Credit facilities, short-term loan facility and long-term debt

3.82%

$ 12,000,000

Portland Natural Gas Transmission System | Secured debt | PNGTS 5.90% Senior Secured Notes due December 2018

3.82%

Credit facilities, short-term loan facility and long-term debt

Debt Service, number of months of guarantee

6 months

Portland Natural Gas Transmission System | Secured debt | PNGTS 5.90% Senior Secured Notes due December 2018 | Debt agreement covenants, preceding twelve months

Credit facilities, short-term loan facility and long-term debt

Debt service coverage, actual (as a percent)

171.00%

Portland Natural Gas Transmission System | Secured debt | PNGTS 5.90% Senior Secured Notes due December 2018 | Debt agreement covenants, preceding twelve months | Minimum

Credit facilities, short-term loan facility and long-term debt

Debt service coverage, covenant (as a percent)

130.00%

Portland Natural Gas Transmission System | Secured debt | PNGTS 5.90% Senior Secured Notes due December 2018 | Debt agreement covenants, succeeding twelve months

Credit facilities, short-term loan facility and long-term debt

Debt service coverage, actual (as a percent)

531.00%

Portland Natural Gas Transmission System | Secured debt | PNGTS 5.90% Senior Secured Notes due December 2018 | Debt agreement covenants, succeeding twelve months | Minimum

Credit facilities, short-term loan facility and long-term debt

Debt service coverage, covenant (as a percent)

130.00%

GTN | Unsecured debt | Senior Notes and Term Loan Facility due 2019

Credit facilities, short-term loan facility and long-term debt

Percentage of debt to total capitalization, actual

2.19%

1.57%

44.20%

GTN | Unsecured debt | Senior Notes and Term Loan Facility due 2019 | Maximum

Credit facilities, short-term loan facility and long-term debt

Percentage of debt to total capitalization, covenant

70.00%

Tuscarora Gas Transmission Company | Unsecured Term Loan Facility | Tuscarora Term Loan due 2020

Credit facilities, short-term loan facility and long-term debt

Amount of debt

$ 25,000,000

Debt service coverage, actual (as a percent)

308.00%

Tuscarora Gas Transmission Company | Unsecured Term Loan Facility | Tuscarora Term Loan due 2020 | Minimum

Credit facilities, short-term loan facility and long-term debt

Debt service coverage, covenant (as a percent)

300.00%

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

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

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

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

3 Months Ended

9 Months Ended

Sep. 30, 2017

Sep. 30, 2016

Sep. 30, 2017

Sep. 30, 2016

Net proceeds from issuance of common units

^[1]

$ 126

General Partner

Net proceeds from issuance of common units

$ 2

TC PipeLines GP, Inc. | General Partner

Ownership interest in the Partnership (as a percent)

2.00%

ATM Equity Issuance Program | Common Units

Net proceeds from issuance of common units

Units sold

2,165,162

$ 124

Sales agent commissions

ATM Equity Issuance Program | TC PipeLines GP, Inc. | General Partner

$ 2

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

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

3 Months Ended

9 Months Ended

Sep. 30, 2017

Mar. 31, 2017

Sep. 30, 2017

Sep. 30, 2016

Limited Partners, Distributions paid

$ 22

$ 12

^[1]

GTN

Increase in equity account

GTN

GTN | TransCanada | Distributions

$ 28

Portion of GTN's annual distributions to which the Class B units are entitled to receive a percentage share of the distributions above threshold (as a percent)

30.00%

Percentage applied to 30 percent of GTN's distributions above threshold through March 31, 2020

100.00%

Threshold of GTN's total distributable cash flows for payment to Class B units

$ 20

Percentage applied to GTN's distributions above threshold after March 31, 2020

25.00%

Percentage applied to GTN's distributable cash flow for the twelve month period ending December 31, 2017

30.00%

$ 28

$ 32

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

PARTNERS' EQUITY - Reclassification of units (Details) - USD ($)
shares in Millions, $ in Millions

2 Months Ended

4 Months Ended

9 Months Ended

May 19, 2016

Sep. 30, 2017

Dec. 31, 2016

Common units subject to rescission

^[1]

$ 83

Reclassification of common units no longer subject to rescission

$ 83

^[2]

ATM Equity Issuance Program | Common Units

Reclassification of common unit issuance subject to rescission, net (in units)

1.6

Common units subject to rescission

$ 0

$ 83

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

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

NET INCOME PER COMMON UNIT - Terms of Class B Unit Distributions and Determination of Net Income (Loss) per Common Unit (Details) - USD ($)
$ / shares in Units, shares in Millions, $ in Millions

3 Months Ended

9 Months Ended

12 Months Ended

Sep. 30, 2017

Sep. 30, 2016

Jun. 30, 2016

Sep. 30, 2017

Sep. 30, 2016

Dec. 31, 2016

Net income attributable to PNGTS' former parent

$ 54

$ 58

^[1]

$ 186

$ 188

^[1]

(2)

(3)

Net income attributable to General and Limited Partners

184

185

Incentive distributions allocated to the General Partner

(3)

(2)

(9)

(5)

Net income attributable to the General Partner and common units

167

168

Net income attributable to General Partner's effective two percent interest

(1)

(2)

(3)

(4)

Class B Units

Net income attributable to limited partners

(8)

(11)

(8)

(12)

Net income attributable to limited partners

$ 42

$ 43

^[1]

$ 164

^[1]

Weighted average common units outstanding - basic (in units)

69.4

66.1

^[1]

68.9

65.3

^[1]

Weighted average common units outstanding - diluted (in units)

69.4

66.1

68.9

65.3

Net income per common unit - basic (in dollars per unit)

$ 0.61

$ 0.65

^[1],[2]

$ 2.38

$ 2.51

^[1],[2]

Net income per common unit - diluted (in dollars per unit)

$ 0.61

$ 0.65

$ 2.38

$ 2.51

GTN | Class B Units

GTN | Class B Units | TransCanada | Distributions

$ 28

$ 8

$ 11

$ 1

$ 8

$ 12

Percentage applied to GTN's distributable cash flow for the twelve month period ending December 31, 2017

30.00%

Threshold of GTN's distributions for payment to Class B units

$ 20

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%

Change in accounts receivable and other

$ 28

$ 32

[1]	Recast to consolidate PNGTS for all periods presented (Refer to Notes 2 and 6).
[2]	Net income per common unit prior to recast (Refer to Note 2).

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

CHANGE IN OPERATING WORKING CAPITAL - Components (Details) - USD ($)
$ in Millions

9 Months Ended

Sep. 30, 2017

Sep. 30, 2016

CHANGE IN OPERATING WORKING CAPITAL

$ 13

$ 3

Change in other current assets

Change in accounts payable and accrued liabilities

Change in accounts payable to affiliates

(3)

(2)

Change in accrued interest

Change in operating working capital

$ 24

$ 11

^[1]

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

CHANGE IN OPERATING WORKING CAPITAL - GTN's Carty Lateral Construction Accrual (Details) - USD ($)
$ in Millions

9 Months Ended

12 Months Ended

Sep. 30, 2017

Sep. 30, 2016

^[1]

Dec. 31, 2016

Dec. 31, 2015

Non-cash items

Capital expenditures

$ 26

$ 21

GTN

Non-cash items

Accruals for capital expenditures

$ 10

Capital expenditures

$ 10

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

RELATED PARTY TRANSACTIONS (Details) - USD ($)
$ in Millions

3 Months Ended

6 Months Ended

9 Months Ended

12 Months Ended

Sep. 30, 2017

Jun. 30, 2017

Sep. 30, 2016

Jun. 30, 2016

Jun. 30, 2017

Jun. 30, 2016

Sep. 30, 2017

Sep. 30, 2016

Dec. 31, 2016

Nov. 01, 2017

Oct. 31, 2017

Sep. 01, 2017

Aug. 01, 2017

Jun. 01, 2017

Capital and operating costs charged to the pipeline systems and amount payable

Amount included in receivables from related party

$ 5.0

$ 8.0

^[1]

2.0

Capital and operating costs charged to the pipeline systems and amount payable

Capital and operating costs charged to the pipeline systems and amount payable

46.45%

Great Lakes | FERC

Estimated revenue sharing provision

$ 12.0

$ 22.0

7.2

Capital and operating costs charged to the pipeline systems and amount payable

50.00%

Capital and operating costs charged to the pipeline systems and amount payable

49.34%

Capital and operating costs charged to the pipeline systems and amount payable

General Partner | Reimbursement of costs of services provided

11.81%

49.90%

11.81%

49.90%

11.81%

Capital and operating costs charged to the pipeline systems and amount payable

TransCanada's subsidiaries | Great Lakes

$ 1.0

$ 3.0

Capital and operating costs charged to the pipeline systems and amount payable

3.0

4.0

Amount included in receivables from related party

100.00%

8.0

19.0

TransCanada's subsidiaries | Great Lakes | Capital and operating costs

Capital and operating costs charged to the pipeline systems and amount payable

$ 10.0

$ 8.0

$ 27.0

$ 22.0

TransCanada's subsidiaries | Northern Border

100.00%

Capital and operating costs charged to the pipeline systems and amount payable

$ 3.0

4.0

TransCanada's subsidiaries | Northern Border | Capital and operating costs

100.00%

Capital and operating costs charged to the pipeline systems and amount payable

10.0

$ 9.0

30.0

$ 25.0

TransCanada's subsidiaries | Iroquois

100.00%

Capital and operating costs charged to the pipeline systems and amount payable

TransCanada's subsidiaries | Iroquois | Capital and operating costs

100.00%

Capital and operating costs charged to the pipeline systems and amount payable

TransCanada's subsidiaries | GTN

100.00%

Capital and operating costs charged to the pipeline systems and amount payable

TransCanada's subsidiaries | GTN | Capital and operating costs

3.0

Capital and operating costs charged to the pipeline systems and amount payable

Impact on the Partnership's net income attributable to controlling interests

9.0

8.0

24.0

20.0

7.0

21.0

18.0

TransCanada's subsidiaries | Bison

Capital and operating costs charged to the pipeline systems and amount payable

TransCanada's subsidiaries | Bison | Capital and operating costs

1.0

Capital and operating costs charged to the pipeline systems and amount payable

Impact on the Partnership's net income attributable to controlling interests

2.0

1.0

4.0

1.0

2.0

1.0

4.0

2.0

TransCanada's subsidiaries | North Baja Pipeline, LLC

Capital and operating costs charged to the pipeline systems and amount payable

TransCanada's subsidiaries | North Baja Pipeline, LLC | Capital and operating costs

1.0

Capital and operating costs charged to the pipeline systems and amount payable

Impact on the Partnership's net income attributable to controlling interests

1.0

3.0

1.0

3.0

TransCanada's subsidiaries | Tuscarora Gas Transmission Company

Capital and operating costs charged to the pipeline systems and amount payable

TransCanada's subsidiaries | Tuscarora Gas Transmission Company | Capital and operating costs

1.0

Capital and operating costs charged to the pipeline systems and amount payable

Impact on the Partnership's net income attributable to controlling interests

1.0

3.0

1.0

3.0

TransCanada's subsidiaries | Portland Natural Gas Transmission System

Capital and operating costs charged to the pipeline systems and amount payable

Amount included in receivables from related party

1.0

0.0

$ 0.0

TransCanada's subsidiaries | Portland Natural Gas Transmission System | Capital and operating costs

Capital and operating costs charged to the pipeline systems and amount payable

TransCanada's subsidiaries | Great Lakes | Capital and operating costs

2.0

6.0

Capital and operating costs charged to the pipeline systems and amount payable

Impact on the Partnership's net income attributable to controlling interests

$ 4.0

$ 3.0

$ 11.0

$ 9.0

TransCanada's subsidiaries | Great Lakes | Transportation contracts | Total net revenues | Customer concentration risk

Capital and operating costs charged to the pipeline systems and amount payable

Percent of total revenues

44.00%

62.00%

53.00%

69.00%

TransCanada's subsidiaries | Northern Border | Capital and operating costs

Capital and operating costs charged to the pipeline systems and amount payable

Impact on the Partnership's net income attributable to controlling interests

$ 4.0

$ 3.0

$ 11.0

$ 9.0

TransCanada's subsidiaries | Portland Natural Gas Transmission System | Capital and operating costs

Capital and operating costs charged to the pipeline systems and amount payable

Impact on the Partnership's net income attributable to controlling interests

1.0

4.0

3.0

TransCanada's subsidiaries | Portland Natural Gas Transmission System | Transportation contracts

Capital and operating costs charged to the pipeline systems and amount payable

Revenues from related party

$ 0.0

$ 1.0

$ 2.0

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

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

FAIR VALUE MEASUREMENTS - Interest Rate Swaps (Details) - USD ($)
$ in Millions

3 Months Ended

9 Months Ended

Sep. 30, 2017

Sep. 30, 2016

Sep. 30, 2017

Sep. 30, 2016

Dec. 31, 2017

Dec. 31, 2016

Fair value of derivative asset, net

$ 0.0

Amortization of realized gain (loss) on derivative financial instruments

$ 1.0

^[1]

Amortization of derivatives loss

$ 2,491.0

2,491.0

1,920.0

1.0

Term loan | TC PipeLines, LP 2013 Term Loan Facility due July 2018

Term loan | TC PipeLines, LP 2013 Term Loan Facility due October 2022

500.0

Amount of forward starting swaps hedged

$ 500.0

500.0

$ 500.0

Average rate of forward starting swaps

3.26%

Payments for derivative instruments

$ 20.9

Interest acquired by Partnership (as a percent)

61.71%

Net unamortized loss included in other comprehensive income

$ 1.0

2.0

Amortization of derivatives loss

$ 0.0

$ 1.0

1.0

Interest rate swaps | Term loan | TC PipeLines, LP 2013 Term Loan Facility due July 2018

Weighted average fixed interest rate (as a percent)

2.31%

Hedges of cash flows | Interest rate swaps

Amortization of realized gain (loss) on derivative financial instruments

$ 0.0

2.0

$ 1.0

(1.0)

Hedges of cash flows | Interest rate swaps | Financial charges and other

Net realized loss related to the interest rate swaps

0.0

$ 1.0

0.0

$ 2.0

Hedges of cash flows | Interest rate swaps | Recurring fair value measurement | Level 2

Fair value of derivative asset, net

2.0

Designated as hedge | Interest rate swaps | Recurring fair value measurement | Level 2

Fair value of derivative asset, gross

$ 2.0

Fair value of derivative liability, gross

0.0

Designated as hedge | Hedges of cash flows | Interest rate swaps | Level 2

Fair value of derivative asset, gross

1.0

Fair value of derivative liability, gross

$ 1.0

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

ACCOUNTS RECEIVABLE AND OTHER (Details) - USD ($)
$ in Millions

Sep. 30, 2017

Dec. 31, 2016

ACCOUNTS RECEIVABLE AND OTHER

Trade accounts receivable, net of allowance of nil

$ 34

$ 44

Imbalance receivable from affiliates

Other

Accounts receivable and other

^[1]

Trade accounts receivable, allowance

$ 0

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

FINANCIAL CHARGES AND OTHER (Details) - USD ($)
$ in Millions

3 Months Ended

9 Months Ended

Sep. 30, 2017

Sep. 30, 2016

Sep. 30, 2017

Sep. 30, 2016

FINANCIAL CHARGES AND OTHER

Interest Expense

$ 23

$ 17

$ 59

$ 52

PNGTS' amortization of derivative loss on derivative instruments

Net realized loss related to the interest rate swaps

Other Income

(1)

(2)

$ 23

$ 18

^[1]

$ 59

$ 53

^[1]

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

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

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

VARIABLE INTEREST ENTITIES - Consolidated VIEs (Details) - USD ($)
$ in Millions

9 Months Ended

Sep. 30, 2017

Dec. 31, 2016

Sep. 30, 2016

^[1]

Dec. 31, 2015

^[1]

ASSETS (LIABILITIES)

Accounts receivable and other

$ 73

$ 64

^[1]

$ 77

$ 55

^[1]

Inventories

^[1]

Plant, property and equipment

^[1]

Equity investments

1,207

918

^[1]

2,133

2,180

^[1]

Accounts payable and accrued liabilities

^[1]

(31)

(29)

^[1]

Accounts payable to affiliates, net

(5)

(8)

^[1]

Distributions payable

^[1]

(3)

Accrued interest

(21)

(10)

^[1]

Current portion of long-term debt

(51)

(52)

^[1]

Long-term debt

(2,427)

(1,859)

^[1]

Other liabilities

(28)

^[1]

Consolidated VIEs | Restricted VIEs

ASSETS (LIABILITIES)

Accounts receivable and other

Inventories

Plant, property and equipment

Equity investments

1,207

918

1,132

1,146

Accounts payable and accrued liabilities

(21)

Accounts payable to affiliates, net

(25)

(32)

Distributions payable

(3)

Other taxes payable

(1)

Accrued interest

(5)

(2)

Current portion of long-term debt

(51)

(52)

Long-term debt

(314)

(337)

Other liabilities

(26)

(25)

Deferred state income tax

$ (10)

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

INCOME TAXES (Details) - USD ($)
$ in Millions

3 Months Ended

9 Months Ended

12 Months Ended

Sep. 30, 2016

Sep. 30, 2017

Sep. 30, 2016

Dec. 31, 2016

State income taxes

Total state income taxes

$ 1

^[1]

Effective income tax rate (as a percent)

Income Taxes

3.80%

State income taxes

Current

$ (7)

$ 1

Deferred

$ 7

Total state income taxes

$ 1

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

SUBSEQUENT EVENTS - Distributions (Details) - USD ($)
$ / shares in Units, $ in Millions

3 Months Ended

9 Months Ended

Nov. 30, 2017

Nov. 01, 2017

Oct. 31, 2017

Oct. 24, 2017

Oct. 23, 2017

Oct. 19, 2017

Sep. 30, 2017

Sep. 30, 2016

Sep. 30, 2017

Sep. 30, 2016

Sep. 01, 2017

Jun. 01, 2017

^[1]

$ 235.0

Return on investment distribution classified as investing activities

106.0

$ 125.0

^[2]

$ 3.0

50.00%

46.45%

11.81%

49.90%

11.81%

49.90%

11.81%

49.34%

11.81%

Subsequent Events

Subsequent Events | Distribution declared | Northern Border

Total cash distribution

$ 75.0

Subsequent Events | Distribution declared | Great Lakes

$ 14.0

Subsequent Events | Distribution declared | Iroquois

$ 2.0

Subsequent Events | Cash Distribution Paid | Northern Border

$ 28.0

Subsequent Events | Cash Distribution Paid | Great Lakes

$ 7.0

Subsequent Events | Cash Distribution Paid | Iroquois

$ 1.0

Return on investment distribution classified as investing activities

14.0

$ 2.6

General Partner

TC PipeLines GP, Inc. | Subsequent Events

^[1]

$ 12.0

General Partner cash distributions

$ 5.0

Total distribution for General Partner interest

2.00%

$ 2.0

TC PipeLines GP, Inc. | General Partner

Total distribution for General Partner interest

$ 2.0

$ 1.0

4.0

$ 3.0

TC PipeLines GP, Inc. | General Partner | Subsequent Events | Distribution declared

Distribution declared for IDRs

$ 3.0

Common Units | Subsequent Events

Total cash distribution

$ 74.0

$ 65.0

$ 210.0

$ 184.0

Number of units

69,600,000

66,600,000

^[2]

69,600,000

66,600,000

^[2]

Per Unit Distribution, declared (in dollars per unit)

$ 1.00

Limited partners, Distribution declared

$ 70.0

Common Units | Limited Partners

Common Units | TC PipeLines GP, Inc. | Subsequent Events

^[1]

$ 198.0

Limited Partners, Distributions paid

6.0

Common Units | TC PipeLines GP, Inc. | Limited Partners

Common Units | TransCanada | Subsequent Events

Number of units

5,797,106

Limited Partners, Distributions paid

$ 11.0

Common Units | TransCanada | TC PipeLines GP, Inc.