View Filing Data

Accounts receivable and other (Note 20)

$ 33

$ 64

^[1]

^[1]

Inventories

^[1],[2]

Equity investments (Note 5)

^[1],[2]

Total current assets

125

^[1],[2]

1,213

918

^[1]

Plant, property and equipment ,net ( Note 6)

2,123

2,180

^[1]

130

^[1]

Accounts payable and accrued liabilities

^[1],[2]

Total assets

3,559

3,354

^[1],[2]

Current Liabilities

^[1],[2]

Accounts payable to affiliates (Note 17)

^[1],[2]

Accrued interest

^[1],[2]

Distributions payable

^[1],[2]

Total current liabilities

^[1]

100

102

^[1],[2]

Long-term debt (Note 8)

2,352

1,859

^[1]

Deferred state income taxes (Note 24)

^[1],[2]

Other liabilities (Note 9)

^[1]

Total liabilities

2,491

1,999

^[1],[2]

Common units subject to rescission (Note 10)

^[1],[2]

Partners' Equity (Note 10)

General partner

^[1],[2]

Accumulated other comprehensive income (loss) (AOCI) (Note 11)

(2)

^[1],[2]

Controlling interests

963

1,144

^[1],[2]

Non-controlling interest

105

^[1],[2]

Equity of former parent of PNGTS

^[1],[2]

Total partners' equity

^[3]

1,068

1,272

Total liabilities and partners' equity

3,559

3,354

^[1],[2]

Partners' Equity (Note 10)

Limited partner

824

1,002

^[1],[2]

Partners' Equity (Note 10)

Limited partner

$ 110

$ 117

^[1],[2]

[1]	Recast to consolidate PNGTS (Refer to Notes 2 and 7).
[2]	Recast to consolidate PNGTS (Refer to Notes 2 and 7).
[3]	Recast to consolidate PNGTS (Refer to Notes 2 and 7).

CONSOLIDATED STATEMENTS OF INCOME
shares in Millions, $ in Millions

12 Months Ended

Dec. 31, 2017

USD ($)

$ / shares

Dec. 31, 2016

USD ($)

$ / shares

Dec. 31, 2015

USD ($)

$ / shares

Impairment of equity-method investment (Note 5)

$ 422

$ 426

^[1],[2]

$ 417

^[1]

Equity earnings (Note 5)

124

^[1]

(199)

^[1]

Operation and maintenance expenses

(67)

(58)

^[1],[2]

(61)

^[1]

Property taxes

(28)

(27)

^[1],[2]

(27)

^[1]

General and administrative

(8)

(7)

^[1],[2]

(9)

^[1]

Financial charges and other (Note 12)

(97)

(96)

^[1]

(95)

^[1]

(82)

(71)

^[1]

(63)

^[1]

Net income before taxes

264

^[1],[2]

^[1]

Income taxes (Note 24)

(1)

^[1],[2]

(2)

^[1]

Net Income

263

^[3]

263

^[2]

Net income attributable to non-controlling interests

^[1],[2]

^[1]

Net income attributable to controlling interest allocation (Note 13)

252

248

^[1]

TransCanada and its subsidiaries

^[1],[2]

^[1]

^[1],[2]

^[1]

252

248

^[1]

Net income attributable to controlling interest allocation (Note 13)

Net income (loss) attributable to common units

$ 219

$ 211

^[1]

$ (2)

^[1]

Net income per common unit (Note 13) - basic (in dollars per unit) | $ / shares

$ 3.16

^[4]

$ 3.21

^[1],[4]

$ (0.03)

^[1],[4]

Net income per common unit (Note 13) - diluted (in dollars per unit) | $ / shares

$ 3.16

$ 3.21

$ (0.03)

Weighted average common units outstanding - basic (in units) | shares

69.2

65.7

^[1]

63.9

^[1]

Weighted average common units outstanding - diluted (in units) | shares

69.2

65.7

63.9

Common units outstanding, end of year (in units) | shares

70.6

67.4

^[1],[2]

64.3

^[1]

[1]	Recast to consolidate PNGTS (Refer to Notes 2 and 7).
[2]	Recast to consolidate PNGTS (Refer to Notes 2 and 7).
[3]	Recast to consolidate PNGTS (Refer to Notes 2 and 7).
[4]	Net income per common unit prior to recast (Refer to Note 2).

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

12 Months Ended

Dec. 31, 2017

Dec. 31, 2016

Dec. 31, 2015

^[2]

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

Change in fair value of cash flow hedges (Notes 11 and 19)

$ 263

^[1]

$ 263

^[2]

$ 58

Other comprehensive income

^[2]

Reclassification to net income of gains and losses on cash flow hedges (Note 11)

^[2]

(2)

Amortization of realized loss on derivative instrument (Notes 11 and 19)

^[2]

Other comprehensive income on equity investments (Note 11)

Comprehensive income

270

265

^[2]

Comprehensive income attributable to non-controlling interests

^[2]

Comprehensive income attributable to controlling interests

$ 259

$ 249

^[2]

$ 38

[1]	Recast to consolidate PNGTS (Refer to Notes 2 and 7).
[2]	Recast to consolidate PNGTS (Refer to Notes 2 and 7).

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

12 Months Ended

Dec. 31, 2017

Dec. 31, 2016

Dec. 31, 2015

$ 263

^[1]

$ 263

^[2]

$ 58

^[2]

Impairment of equity-method investment (Note 5)

^[3]

^[3]

199

Amortization of debt issue costs reported as interest expense (Note 12)

^[3]

Amortization of realized loss on derivative instrument (Note 19)

^[3]

Accrual of costs related to acquisition of 49.9% interest in PNGTS (Note 7)

^[3]

Distributions received from operating activities of equity investments (Note 5)

(124)

(97)

^[3]

(97)

^[3]

140

153

^[3]

119

^[3]

Provision for deferred state income taxes (Note 24)

^[3]

Provision for rate refund-PNGTS (Note 2)

^[3]

(101)

Equity allowance for funds used during construction

(1)

^[3]

Change in operating working capital (Note 15)

(2)

(1)

^[3]

(20)

^[3]

Net Cash Provided by (Used in) Operating Activities

376

417

^[3]

260

^[3]

Distribution received as return of investment (Note 5)

Capital expenditures

(29)

^[3]

(54)

^[3]

Net Cash Provided by (Used in) Investing Activities

^[3]

(761)

(230)

^[3]

(326)

^[3]

Financing Activities

Distributions paid (Note 14)

(284)

(250)

^[3]

(228)

^[3]

Distributions paid to non-controlling interests

(5)

(12)

^[3]

(21)

^[3]

Common unit issuance, net (Note 10)

176

^[3]

Common unit issuance subject to rescission, net (Note 10)

^[3]

Equity contribution by the General Partner (Note 7)

^[3]

Long-term debt issued, net of discount (Note 8)

802

209

^[3]

618

^[3]

Long-term debt repaid (Note 8)

(310)

(270)

^[3]

(425)

^[3]

Debt issuance costs

(2)

(1)

^[3]

(3)

^[3]

Total financing activities

354

(178)

^[3]

(32)

^[3]

Increase/(decrease) in cash and cash equivalents

(31)

^[3]

(98)

^[3]

Cash and cash equivalents, beginning of year

^[3]

153

Cash and cash equivalents, end of year

^[3]

Interest payments paid

^[3]

State income taxes paid

^[3]

Supplemental information about non-cash investing and financing activities

Accrued capital expenditures

^[3]

Issuance of Class B units to TransCanada (Note 10)

^[3]

Distributions paid (Note 10 and 14)

Financing Activities

(22)

(12)

^[3]

(67)

(69)

(66)

(83)

Provision for rate refund-PNGTS (Note 2)

(31)

(28)

(31)

(9)

^[3]

(9)

^[3]

Distributions paid to former parent of PNGTS

^[3]

(193)

Financing Activities

(1)

$ (9)

^[3]

(19)

^[3]

GTN

^[3]

$ (264)

(26)

Distribution received as return of investment (Note 5)

Portland Natural Gas Transmission System And Iroquois Acquisition

Partners' Equity at beginning of year at Dec. 31, 2014

$ (646)

[1]	Recast to consolidate PNGTS (Refer to Notes 2 and 7).
[2]	Recast to consolidate PNGTS (Refer to Notes 2 and 7).
[3]	Recast to consolidate PNGTS (Refer to Notes 2 and 7).

CONSOLIDATED STATEMENTS OF CASH FLOWS (Parenthetical)	Dec. 31, 2017	Aug. 01, 2017	Jun. 01, 2017	Jan. 01, 2016
Interest acquired (as a percent)		49.34%
Portland Natural Gas Transmission System
Interest acquired (as a percent)			11.81%	49.90%
Iroquois
Interest acquired (as a percent)	49.34%		49.34%

CONSOLIDATED STATEMENT OF CHANGES IN PARTNERS' EQUITY - USD ($)
shares in Millions, $ in Millions

ATM Equity Issuance Program

Limited Partners

Common Units

ATM Equity Issuance Program

General Partner

ATM Equity Issuance Program

^[1]

Limited Partners

GTN

Common Units

Limited Partners

Portland Natural Gas Transmission System

Common Units

Limited Partners

Portland Natural Gas Transmission System And Iroquois Acquisition

Common Units

Limited Partners

Common Units

Limited Partners

Class B Units

General Partner

GTN

General Partner

Portland Natural Gas Transmission System

General Partner

Portland Natural Gas Transmission System And Iroquois Acquisition

General Partner

Accumulated Other Comprehensive Income (Loss)

^[2],[3]

GTN

Non-Controlling Interest

^[1]

GTN

^[1]

Portland Natural Gas Transmission System

Portland Natural Gas Transmission System And Iroquois Acquisition

Equity of former parent of PNGTS

^[1],[2]

Portland Natural Gas Transmission System And Iroquois Acquisition

^[1]

Class B Units

^[1]

Non-Controlling Interest

Equity of former parent of PNGTS

^[2]

Total

^[1]

$ 1,325

$ 29

$ (5)

$ 323

$ 146

$ 1,818

Partners' Equity at beginning of year (in units) at Dec. 31, 2014

^[1]

63.6

Increase (Decrease) in Partners' Equity

Net income (loss)

$ (2)

^[1]

$ 12

^[1]

^[4]

Equity Issuance, net (in units)

^[1]

Equity issuance, net

$ 43

$ 1

$ 44

$ 95

0.7

1.9

Acquisition of interests (note 7)

$ (124)

$ (3)

$ (232)

$ (359)

Equity Contribution (Note 7)

^[1]

Distributions

^[1]

(221)

(7)

(21)

(19)

(268)

Partners' Equity at end of year at Dec. 31, 2015

^[1]

$ 1,021

$ 107

(4)

151

1,391

Partners' Equity at end of year (in units) at Dec. 31, 2015

^[1]

64.3

1.9

Increase (Decrease) in Partners' Equity

Net income (loss)

$ 211

^[1]

$ 22

^[1]

263

^[4]

Equity Issuance, net (in units)

^[1]

Equity issuance, net

$ 82

1.5

Common unit issuance subject to rescission, net (Note 10)

^[5]

$ 81

^[1]

Common unit issuance subject to rescission, net (Note 10) (in units)

^[5]

1.6

Reclassification of common units no longer subject to rescission (Note 10)

^[5]

$ (81)

(2)

(83)

^[1]

Acquisition of interests (note 7)

^[1]

$ (72)

$ (1)

$ (73)

Distributions

^[1]

(240)

(12)

(10)

(4)

(276)

Former parent carrying amount of PNGTS

^[1]

(120)

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

^[1]

$ 1,002

$ 117

(2)

1,272

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

^[1]

67.4

1.9

Increase (Decrease) in Partners' Equity

Net income (loss)

$ 219

$ 15

^[1]

263

^[1]

Equity Issuance, net (in units)

^[1]

Equity issuance, net

$ 173

$ 3

$ 176

3.2

Reclassification of common units no longer subject to rescission (Note 10)

^[1]

Acquisition of interests (note 7)

$ (383)

$ (8)

$ (32)

$ (423)

Distributions

(268)

(22)

(16)

(3)

^[1]

$ (1)

^[1]

(310)

^[1]

Partners' Equity at end of year at Dec. 31, 2017

^[1]

$ 824

$ 110

$ 24

$ 5

$ 105

$ 1,068

Partners' Equity at end of year (in units) at Dec. 31, 2017

^[1]

70.6

1.9

[1]	Recast to consolidate PNGTS (Refer to Notes 2 and 7).
[2]	Equity of Former Parent of PNGTS.
[3]	Losses related to cash flow hedges reported in AOCI and expected to be reclassified to net income in the next 12 months are estimated to be $2 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
[4]	Recast to consolidate PNGTS (Refer to Notes 2 and 7).
[5]	These units are treated as outstanding for financial reporting purposes.

CONSOLIDATED STATEMENT OF CHANGES IN PARTNERS' EQUITY (Parenthetical) $ in Millions	12 Months Ended
	Dec. 31, 2017 USD ($)
Losses expected to be reclassified to Net Income in the next 12 months	$ (2)

ORGANIZATION

12 Months Ended

Dec. 31, 2017

ORGANIZATION

ORGANIZATION

NOTE 1 ORGANIZATION

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

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


Pipeline	Length	Description	Ownership

Gas Transmission Northwest LLC (GTN)	1,377 miles	Extends between an interconnection near Kingsgate, British Columbia, Canada at the Canadian border to a point near Malin, Oregon at the California border and delivers natural gas to the Pacific Northwest and to California.	100 percent
Bison Pipeline LLC (Bison)	303 miles	Extends from a location near Gillette, Wyoming to Northern Border's pipeline system in North Dakota. Bison can transport natural gas from the Powder River Basin to Midwest markets.	100 percent
North Baja Pipeline, LLC (North Baja)	86 miles	Extends between an interconnection with the El Paso Natural Gas Company pipeline near Ehrenberg, Arizona and an interconnection with a natural gas pipeline near Ogilby, California on the Mexican border transporting natural gas in the southwest. North Baja is a bi-directional pipeline.	100 percent
Tuscarora Gas Transmission Company (Tuscarora)	305 miles	Extends between the GTN pipeline near Malin, Oregon to its terminus near Reno, Nevada and delivers natural gas in northeastern California and northwestern Nevada.	100 percent
Northern Border Pipeline Company (Northern Border)	1,412 miles	Extends between the Canadian border near Port of Morgan, Montana to a terminus near North Hayden, Indiana, south of Chicago. Northern Border is capable of receiving natural gas from Canada, the Bakken, the Williston Basin and Rocky Mountain area for deliveries to the Midwest. ONEOK Partners, L.P. owns the remaining 50 percent of Northern Border.	50 percent
Portland Natural Gas Transmission System (PNGTS)	295 miles	Connects with the TQM at the Canadian border to deliver natural gas to customers in the U.S. northeast. Northern New England Investment Company, Inc. owns the remaining 38.29 percent of PNGTS. The 295-mile pipeline includes a 107 miles of jointly owned pipeline facilities (the Joint Facilities) with MNE. The Joint Facilities extend from Westbrook, Maine to Dracut, Massachusetts and PNGTS owns approximately 32% of the undivided ownership interest based on contractually agreed upon percentages. The Joint Facilities are maintained and operated by a wholly owned subsidiary of MNE. MNE is a subsidiary of Enbridge Inc.	61.71 percent(a)
Great Lakes Gas Transmission Limited Partnership (Great Lakes)	2,115 miles	Connects with the TransCanada Mainline at the Canadian border near Emerson, Manitoba, Canada and St. Clair, Michigan, near Detroit. Great Lakes is a bi-directional pipeline that can receive and deliver natural gas at multiple points along its system. TransCanada owns the remaining 53.55 percent of Great Lakes.	46.45 percent
Iroquois Gas Transmission System, L.P (Iroquois)	416 miles	Extends from the TransCanada Mainline system near Waddington, New York to deliver natural gas to customers in the U.S. northeast. The remaining 50.66 percent is owned by TransCanada (0.66 percent), Dominion Midstream (25.93 percent) and Dominion Resources (24.07 percent). Iroquois is maintained and operated by a subsidiary of Iroquois.	49.34 percent(b)


(a)	On June 1, 2017, the Partnership acquired an additional 11.81 percent from TransCanada resulting in 61.71 percent ownership in PNGTS. (Refer to Note 7).
(b)	Effective June 1, 2017 (Refer to Note 7).

The Partnership is managed by its General Partner, TC PipeLines GP, Inc. (General Partner), an indirect wholly-owned subsidiary of TransCanada. The General Partner provides management and operating services to the Partnership and is reimbursed for its costs and expenses. The General Partner owns 5,797,106 of our common units, 100 percent of our IDRs and an effective two percent general partner interest in the Partnership at December 31, 2017. TransCanada also indirectly holds an additional 11,287,725 common units, for total ownership of 24.2 percent of our outstanding common units and 100 percent of our Class B units at December 31, 2017 (Refer to Note 10).

SIGNIFICANT ACCOUNTING POLICIES	12 Months Ended
SIGNIFICANT ACCOUNTING POLICIES	Dec. 31, 2017
SIGNIFICANT ACCOUNTING POLICIES
SIGNIFICANT ACCOUNTING POLICIES	NOTE 2 SIGNIFICANT ACCOUNTING POLICIES The accompanying consolidated financial statements and related notes have been prepared in accordance with United States generally accepted accounting principles (GAAP) and amounts are stated in U.S. dollars. The financial statements and notes present the financial position of the Partnership as of December 31, 2017 and 2016 and the results of its operations, cash flows and changes in partners' equity for the years ended December 31, 2017, 2016 and 2015. (a) Basis of Presentation The Partnership consolidates variable interest entities (VIEs) for which it is considered to be the primary beneficiary as well as voting interest entities in which it has a controlling financial interest. To the extent there are interests owned by other parties, these interests are included in non-controlling interests. The Partnership uses the equity method of accounting for its investments in entities over which it is able to exercise significant influence. Acquisitions by the Partnership from TransCanada are considered common control transactions. When businesses that will be consolidated are acquired from TransCanada by the Partnership, the historical financial statements are required to be recast, except net income (loss) per common unit, to include the acquired entities for all periods presented. When the Partnership acquires an asset or an investment from TransCanada, which will be accounted for by the equity method, the financial information is not required to be recast and the transaction is accounted for prospectively from the date of the acquisition. On June 1, 2017, the Partnership acquired from a subsidiary of TransCanada an additional 11.81 percent interest in PNGTS, resulting in the Partnership owning 61.71 percent in PNGTS (Refer to Note 7). As a result of the Partnership owning 61.71 percent of PNGTS, the Partnership's historical financial information was recast, except net income (loss) per common unit, to consolidate PNGTS for all the periods presented in these consolidated financial statements. Additionally, this acquisition was accounted for as transaction between entities under common control, similar to pooling of interests, whereby the assets and liabilities of PNGTS were recorded at TransCanada's carrying value. Also, on June 1, 2017, the Partnership acquired from subsidiaries of TransCanada a 49.34 percent interest in Iroquois (Refer to Note 7). 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. On January 1, 2016, the Partnership acquired a 49.9 percent interest in PNGTS (2016 PNGTS Acquisition) from a subsidiary of TransCanada. The 2016 PNGTS Acquisition was accounted for as a transaction between entities under common control, similar to a pooling of interests, whereby the equity investment in PNGTS was recorded at TransCanada's carrying value and the total excess purchase price paid was recorded as a reduction in Partners' Equity. Accordingly, the equity investment on PNGTS is being eliminated as a result of consolidating PNGTS for all periods presented. Refer to Note 7 for additional disclosure regarding the PNGTS Acquisition. On April 1, 2015, the Partnership acquired the remaining 30 percent interest in GTN from a subsidiary of TransCanada. This acquisition resulted in being wholly-owned by the Partnership. Prior to this transaction, the remaining 30 percent interest held by a subsidiary of TransCanada was reflected as non-controlling interest in the Partnership's consolidated financial statements. The acquisitions of this already-consolidated entity was accounted as a transaction between entities under common control, similar to a pooling of interests, whereby the acquired interests were recorded at TransCanada's carrying value and the total excess purchase price paid was recorded as a reduction in Partners' Equity. Refer to Note 7 for additional disclosures regarding these acquisitions. (b) Use of Estimates The preparation of financial statements requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities as of the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Although management believes these estimates are reasonable, actual results could differ from these estimates. (c) Cash and Cash Equivalents The Partnership's cash and cash equivalents consist of cash and highly liquid short-term investments with original maturities of three months or less and are recorded at cost, which approximates fair value. (d) Trade Accounts Receivable Trade accounts receivable are recorded at the invoiced amount and do not bear interest. We review our accounts receivable regularly and record allowances for doubtful accounts using the specific identification method. (e) Natural gas imbalances Natural gas imbalances occur when the actual amount of natural gas delivered to or received from a pipeline system differs from the amount of natural gas scheduled to be delivered or received. The Partnership values these imbalances due to or from shippers and interconnecting parties at current index prices. Imbalances are settled in kind, subject to the terms of the pipelines' tariff. Imbalances due from others are reported as trade accounts receivable or accounts receivable from affiliates under the caption accounts receivable and other on the balance sheets. Imbalances owed to others are reported on the balance sheets as accounts payable and accrued liabilities and accounts payable to affiliates. In addition, the Partnership classifies all imbalances as current as the Partnership expects to settle them within a year. (f) Inventories Inventories primarily consist of materials and supplies and are carried at the lower of weighted average cost or market. (g) Plant, Property and Equipment Plant, property and equipment are stated at original cost. Costs of restoring the land above and around the pipeline are capitalized to pipeline facilities and depreciated over the remaining life of the related pipeline facilities. Pipeline facilities and compression equipment have an estimated useful life of 20 to 77 years and metering and other equipment ranges from 5 to 77 years. Depreciation is calculated on a straight-line composite basis over the assets' estimated useful lives. Repair and maintenance costs are expensed as incurred. Costs that are considered a betterment are capitalized. The Partnership's subsidiaries capitalize a carrying cost on funds invested in the construction of long lived assets. This carrying cost includes a return on the investment financed by debt and equity allowance for funds used during construction (AFUDC), calculated based the average cost of debt and equity. Capitalized carrying costs for AFUDC debt and equity are reflected as an increase in the cost of plant, property and equipment on the balance sheets. Amounts included in construction work in progress are not amortized until transferred into service. (h) Impairment of Equity Method Investments We review our equity method investments when a significant event or change in circumstances has occurred that may have an adverse effect on the fair value of each investment. When such events or changes occur, we compare the estimated fair value to the carrying value of the related investment. We calculate the estimated fair value of an investment in an equity method investee using an income approach and market approach. The development of fair value estimates requires significant judgment including estimates of future cash flows, which is dependent on internal forecasts, estimates of the long-term rate of growth for the investee, estimates of the useful life over which cash flows will occur, and determination of weighted average cost of capital. The estimates used to calculate the fair value of an investee can change from year to year based on operating results and market conditions. Changes in these estimates and assumptions could materially affect the determination of fair value and our assessment as to whether an investment in an equity method investee has suffered an impairment. If the estimated fair value of an investment is less than its carrying value, we are required to determine if the decline in fair value is other than temporary. This determination considers the aforementioned valuation methodologies, the length of time and the extent to which fair value has been less than carrying value, the financial condition and near-term prospects of the investee, including any specific events which may influence the operations of the investee, the intent and ability of the holder to retain its investment in the investee for a period of time sufficient to allow for any anticipated recovery in market value, and other facts and circumstances. If the fair value of an investment is less than its carrying value and the decline in value is determined to be other than temporary, we record an impairment charge. (i) Impairment of Long-lived Assets The Partnership reviews long-lived assets, such as plant, property and equipment for impairment whenever events or changes in circumstances indicate the carrying value may not be recoverable. If the total of the estimated undiscounted future cash flows is less than the carrying value of the assets, an impairment loss is recognized for the excess of the carrying value over the fair value of the assets. (j) Partners' Equity Costs incurred in connection with the issuance of units are deducted from the proceeds received. (k) Revenue Recognition Transmission revenues are recognized in the period in which the service is provided. When a rate case is pending final FERC approval, a portion of the revenue collected is subject to possible refund. As of December 31, 2017, the Partnership has not recognized any transmission revenue that is subject to possible refund. For the years ended December 31, 2014 and in January 2015, as required by FERC, PNGTS was charging customers rates applied for in its 2008 and 2010 rate cases. Due to the uncertainty in the outcome of its two outstanding rate cases, PNGTS was only recognizing revenue up to the amount of the interim FERC approved rates. The difference between these amounts was recognized as a provision (liability) for rate refund in the consolidated balance sheet. On February 19, 2015, FERC approved PNGTS' final rates and PNGTS was required to refund the customers within sixty days of the issuance of the final rates, including interest at the quarterly average prime interest rate as prescribed by FERC. Total refunds accumulated to $114.3 million, including $8.0 million of interest, and were paid to customers on April 15, 2015. (l) Debt Issuance Costs Costs related to the issuance of debt are deferred and amortized using the effective interest rate method over the term of the related debt. Debt issuances costs are presented in the balance sheet as a direct deduction from the carrying amount of debt liabilities, consistent with debt discount and premiums. The amortization of debt issuance costs is reported as interest expense. (m) Income Taxes Federal and certain state income taxes are the responsibility of the partners and are not reflected in these consolidated financial statements. The tax effect of the Partnership's activities accrues to its partners. The Partnership's taxable income or loss, which may vary substantially from the net income or loss reported in the consolidated statement of income, is includable in the federal income tax returns of each partner. The aggregate difference in the basis of the Partnership's net assets for financial and income tax purposes cannot be readily determined because all information regarding each partner's tax attributes related to the partnership is not available. In instances where the Partnership is subject to state income taxes, the asset – liability method is used to account for taxes. This method requires the recognition of deferred tax assets and liabilities for future tax consequences attributable to the differences between the financial statement carrying amount of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are classified as non-current on our balance sheet. (n) Acquisitions and Goodwill The Partnership accounts for business acquisitions from third parties using the acquisition method of accounting and, accordingly, the assets and liabilities of the acquired entities are recorded at their estimated fair values at the date of acquisition. The excess of the purchase price over the fair value of net assets acquired is attributed to goodwill. Goodwill is not amortized and is tested on an annual basis for impairment or more frequently if any indicators of impairment are evident. The Partnership initially assesses qualitative factors to determine whether events or changes in circumstances indicate that the goodwill might be impaired. If the Partnership does not conclude that it is more likely than not that fair value of the reporting unit is greater than its carrying value, the first step of the two-step impairment test is performed by comparing the fair value of the reporting unit to its book value, which includes goodwill. If the fair value is less than book value, an impairment is indicated and a second step is performed to measure the amount of the impairment. In the second step, the implied fair value of goodwill is calculated by deducting the recognized amounts of all tangible and intangible net assets of the reporting unit from the fair value determined in the initial assessment. If the carrying value of goodwill exceeds the calculated implied fair value of goodwill, an impairment charge is recorded. At December 31, 2017 and 2016, we had $130 million of goodwill recorded on our consolidated balance sheet related to the North Baja ($48 million) and Tuscarora ($82 million) acquisitions. No impairment of goodwill existed at December 31, 2017. The Partnership accounts for business acquisitions between itself and TransCanada, also known as "dropdowns", as transactions between entities under common control. Using this approach, the assets and liabilities of the acquired entities are recorded at TransCanada's carrying value. In the event recasting is required, the Partnership's historical financial information will be recast, except net income (loss) per common unit, to include the acquired entities for all periods presented. If the fair market value paid for the acquired entities is greater than the recorded net assets of the acquired entities, the excess purchase price paid is recorded as a reduction in Partners' Equity. Similarly, if the fair market value paid for the acquired entities is less than the recorded net assets of the acquired entities, the excess of assets acquired is recorded as an increase in Partners' Equity. (o) Fair Value Measurements For cash and cash equivalents, receivables, accounts payable, certain accrued expenses and short-term debt, the carrying amount approximates fair value due to the short maturities of these instruments. For long-term debt instruments and the interest rate swap agreements, fair value is estimated based upon market values (if applicable) or on the current interest rates available to us for debt with similar terms and remaining maturities. Considerable judgment is required in developing these estimates. (p) Derivative Financial Instruments and Hedging Activities The Partnership recognizes all derivative instruments as either assets or liabilities in the balance sheet at their respective fair values. For derivatives designated in hedging relationships, changes in the fair value are either offset through earnings against the change in fair value of the hedged item attributable to the risk being hedged or recognized in accumulated other comprehensive income, to the extent the derivative is effective at offsetting the changes in cash flows being hedged until the hedged item affects earnings. The Partnership only enters into derivative contracts that it intends to designate as a hedge of a forecasted transaction or the variability of cash flows to be received or paid related to a recognized asset or liability (cash flow hedge). For all hedging relationships, the Partnership formally documents the hedging relationship and its risk management objective and strategy for undertaking the hedge, the hedging instrument, the hedged transaction, the nature of the risk being hedged, how the hedging instrument's effectiveness in offsetting the hedged risk will be assessed prospectively and retrospectively, and a description of the method used to measure ineffectiveness. The Partnership also formally assesses, both at the inception of the hedging relationship and on an ongoing basis, whether the derivatives that are used in hedging relationships are highly effective in offsetting changes in cash flows of hedged transactions. For derivative instruments that are designated and qualify as part of a cash flow hedging relationship, the effective portion of the gain or loss on the derivative is reported as a component of other comprehensive income and reclassified into earnings in the same period or periods during which the hedged transaction affects earnings. Gains and losses on the derivative representing either hedge ineffectiveness or hedge components excluded from the assessment of effectiveness are recognized in current earnings. The Partnership discontinues hedge accounting prospectively when it determines that the derivative is no longer effective in offsetting cash flows attributable to the hedged risk, the derivative expires or is sold, terminated, or exercised, the cash flow hedge is de-designated because a forecasted transaction is not probable of occurring, or management determines to remove the designation of the cash flow hedge. In all situations in which hedge accounting is discontinued and the derivative remains outstanding, the Partnership continues to carry the derivative at its fair value on the balance sheet and recognizes any subsequent changes in its fair value in earnings. When it is probable that a forecasted transaction will not occur, the Partnership discontinues hedge accounting and recognizes immediately in earnings gains and losses that were accumulated in other comprehensive income related to the hedging relationship. (q) Asset Retirement Obligation The Partnership recognizes the fair value of a liability for asset retirement obligations in the period in which it is incurred, when a legal obligation exists and a reasonable estimate of fair value can be made. The fair value is added to the carrying amount of the associated asset and the liability is accreted through charges to operating expenses. The Partnership has determined it has legal obligations associated with its natural gas pipelines and related transmission facilities. The obligations relate primarily to purging and sealing the pipelines if they are abandoned. The Partnership is also required to operate and maintain its natural gas pipeline system, and intends to do so as long as supply and demand for natural gas exists, which the Partnership expects for the foreseeable future. Therefore, the Partnership believes its natural gas pipeline system assets have indeterminate lives and, accordingly, has recorded no asset retirement obligation as of December 31, 2017 and 2016. (r) Government Regulation The Partnership's subsidiaries are subject to regulation by FERC. Under regulatory accounting principles, certain assets or liabilities that result from the regulated ratemaking process may be recorded that would not be recorded under GAAP for non-regulated entities. The timing of recognition of certain revenues and expenses in our regulated business may differ from that otherwise expected under GAAP to appropriately reflect the economic impact of the regulators' decisions regarding revenues and rates. The Partnership regularly evaluates the continued applicability of regulatory accounting, considering such factors as regulatory changes, the impact of competition, and the ability to recover regulatory assets. At December 31, 2017, the Partnership had regulatory assets amounting to nil reported as part of other current assets in the balance sheet representing volumetric fuel tracker assets that are settled with in-kind exchanges with customers continually (2016 – $1 million). Regulatory liabilities are included in other long-term liabilities (refer to Note 9). AFUDC is capitalized and included in plant, property and equipment.

ACCOUNTING PRONOUNCEMENTS	12 Months Ended
ACCOUNTING PRONOUNCEMENTS	Dec. 31, 2017
ACCOUNTING PRONOUNCEMENTS
ACCOUNTING PRONOUNCEMENTS	NOTE 3 ACCOUNTING PRONOUNCEMENTS Changes in Accounting Policies 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 entity (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 guidance 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. The Partnership has completed its analysis and has not identified any material differences in the amount and timing of revenue recognition as a result of implementing the new guidance. The Partnership will not require a cumulative-effect adjustment to opening partners' equity on January 1, 2018. Although consolidated revenues will not be materially impacted by the new guidance, the Partnership will be required to add significant disclosures based on the prescribed requirements. These new disclosures will include information regarding the significant judgments used in evaluating when and how revenue is recognized and information related to contract assets and deferred revenues. 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 has developed draft disclosures required in the first quarter 2018 with a particular focus on the scope of contracts subject to disclosure of future revenues from remaining performance obligations. The Partnership has addressed system and process changes necessary to compile the information to meet the recognition and disclosure requirements of the new guidance. Leases In February 2016, the FASB issued new guidance on the accounting for leases. The new guidance amends the definition of a lease requiring the customer to have both (1) the right to obtain substantially all of the economic benefits from the use of the asset and (2) the right to direct the use of the asset in order for the arrangement to qualify as a lease. The new guidance also establishes a right-of-use (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. The Partnership continues to monitor and analyze additional guidance and clarification provided by FASB. 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, however, early adoption is permitted. 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 with early adoption permitted. The Partnership has elected to apply this guidance effective January 1, 2018. The Partnership has completed its analysis and does not expect the application of this guidance to have a material impact on its consolidated financial statements.

THE 2017 TAX ACT	12 Months Ended
THE 2017 TAX ACT	Dec. 31, 2017
THE 2017 TAX ACT
THE 2017 TAX ACT	NOTE 4 THE 2017 TAX ACT On December 22, 2017, the President of the United States signed into law the 2017 Tax Act. This legislation provides for major changes to U.S. corporate federal tax law. As mentioned in Note 2, we are a non-taxable limited partnership, and income taxes owed as a result of our earnings are the responsibility of our partners, therefore no amounts have been recorded in the Partnership's financial statements as a result of the 2017 Tax Act. Our pipeline systems are regulated by the FERC, which approves the systems' rates on a cost-of-service basis and provides for a recovery of our ultimate taxable owners' income tax expense and related balance sheet accounts as components of the maximum recourse rates that may be charged to customers. As a non-taxable entity, the Partnership does not recognize federal income tax expense nor has it established the related federal deferred income tax assets or liabilities. Income tax related expenses, benefits, assets, and liabilities attributable to regulated operations are the responsibility of the ultimate taxable owners of the Partnership and any adjustment to income tax accounts following the 2017 Tax Act must be evaluated by those owners. Any changes to the maximum recourse rates charged by our pipeline systems following the 2017 Tax Act will be reflected as those rates are revised through future rate proceedings individually unless superseded through other possible future action by the FERC. The Partnership cannot predict the ultimate impact of the 2017 Tax Act on future revenues of our pipeline systems. At December 31, 2017, the Partnership considers its assessment of the impact of the 2017 Tax Act to be its best interpretation of available guidance. Should additional guidance on the impact of the 2017 Tax Act on non-taxable partnerships be provided by regulatory, tax and accounting authorities or other sources in the future, the Partnership will review the approach used and adjust as appropriate.

EQUITY INVESTMENTS

12 Months Ended

Dec. 31, 2017

EQUITY INVESTMENTS

NOTE 5 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 23, Variable Interest Entities.

		Equity Earnings(b)			Equity Investments
		Year ended December 31			December 31
	Ownership Interest at December 31, 2017	Year ended December 31			December 31
(millions of dollars)	Ownership Interest at December 31, 2017	2017	2016(c)	2015	2017	2016(c)

Northern Border(a)	50.00%	67	69	66	512	444
Great Lakes	46.45%	31	28	31	479	474
Iroquois	49.34%	26	–	–	222	–

		124	97	97	1,213	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 in April 2006.
(b)	Equity Earnings represents our share in investee's earnings and does not include any impairment charge on the equity method investment recorded as a reduction of carrying value of these investments. Accordingly, no impairment charge was recorded by the Partnership on its equity investees for all the periods presented here except the $199 million impairment recognized in 2015 on our investment in Great Lakes as discussed below.
(c)	Recast to eliminate equity earnings from PNGTS and consolidate PNGTS (Refer to Notes 2 and 7).

Distributions from Equity Investments

As a result of adoption of FASB ASU 2016-15, Statement of Cash Flows: Classification of Certain Cash Receipts and Cash Payments, the Partnership changed its method of accounting for the classification of distributions received from equity investments from cumulative earnings approach to nature of distributions approach effective January 1, 2014, as it is more representative of the nature of the underlying activities of the investees that generated the distributions. As a result, distributions received from equity method investees in 2015, amounting to $25 million, have been reclassified from investing activities to cash generated from operations in the consolidated statement of cash flows.

Distributions received from equity investments for the year ended December 31, 2017 were $145 million (2016 – $153 million; 2015 – $119 million) of which $5 million (2016 and 2015 – none) was considered a return of capital and is included in Investing activities in the Partnership's consolidated statement of cash flows. The return of capital was related to our investment in Iroquois (see further discussion below).

Northern Border

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

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 a $166 million capital contribution request from Northern Border to reduce the outstanding balance of its revolving credit facility to increase its available borrowing capacity.

The Partnership recorded no undistributed earnings from Northern Border for the years ended December 31, 2017, 2016 and 2015. At December 31, 2017 the Partnership had a $115 million (December 31, 2016 – $116 million) difference between the carrying value of Northern Border and the underlying equity in the net assets primarily resulting from the recognition and inclusion of goodwill in the Partnership's investment in Northern Border relating to the Partnership's April 2006 acquisition of an additional 20 percent general partnership interest in Northern Border.

Northern Border's 2013 settlement agreement required Northern Border to file for new rates no later than January 1, 2018. On December 4, 2017, Northern Border filed a rate settlement with FERC which precluded the need to file a general rate case by January 1, 2018. The 2017 Northern Border Settlement which was approved by FERC on February 23, 2018, provides for tiered rate reductions beginning January 1, 2018, with no change to the underlying rate design. The 2017 Northern Border Settlement does not contain a moratorium provision and, unless superseded by a subsequent rate case or settlement, recourse rates in effect at December 31, 2017, will decrease by 5.0% on January 1, 2018; by an additional 5.50% on April 1, 2018; and by an additional 2.0% beginning January 1, 2020 through December 31, 2023, when Northern Border will be required to establish new rates. This equates to an overall rate reduction of 12.5% by January 1, 2020 from the recourse rates in effect at December 31, 2017.

The 2017 Northern Border Settlement will provide Northern Border with rate stability over the longer term. We do not believe that the rate reduction as described above will have a material impact on the Partnership's results and, therefore, we do not believe the settlement outcome has negatively impacted the underlying value of our investment in Northern Border. The overall long-term market fundamentals of Northern Border continue to be positive due to its strategic footprint. Northern Border remains a key competitive pipeline and continues to operate at full capacity connecting major supply basins with communities in the Midwestern U.S. Accordingly, no impairment has been identified in our investment in Northern Border.

The summarized financial information provided to us by Northern Border is as follows:

December 31 (millions of dollars)		2017		2016

Assets
Cash and cash equivalents		14		14
Other current assets		36		36
Plant, property and equipment, net		1,063		1,089
Other assets		14		14

		1,127		1,153

Liabilities and Partners' Equity
Current liabilities		38		38
Deferred credits and other		31		28
Long-term debt, net(a)		264		430
Partners' equity
	Partners' capital	795		659
	Accumulated other comprehensive loss	(1	)	(2	)

		1,127		1,153

Year ended December 31 (millions of dollars)	2017		2016		2015

Transmission revenues	291		292		286
Operating expenses	(78	)	(72	)	(70	)
Depreciation	(59	)	(59	)	(60	)
Financial charges and other	(18	)	(21	)	(22	)

Net income	136		140		134


(a)	No current maturities as of December 31, 2017 or 2016.

Great Lakes

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

The Partnership recorded no undistributed earnings from Great Lakes for the years ended December 31, 2017, 2016, and 2015.

The Partnership made equity contributions to Great Lakes of $4 million and $5 million in the first and fourth quarter of 2017, respectively. These amounts represent the Partnership's 46.45 percent share of a $9 million and $10 million cash call from Great Lakes to make scheduled debt repayments.

During the fourth quarter of 2015, we recorded an impairment charge of $199 million on our investment in Great Lakes. The impairment charge was the result of our determination that our investment in Great Lakes' long-term value had been adversely impacted by the changing natural gas flows in its market region and that other strategic alternatives to increase its utilization or revenue were no longer feasible. The impairment charge reduced the difference between the carrying value of our investment in Great Lakes and the underlying equity in the net assets, to $260 million and the difference represented the equity method goodwill remaining in our investment in Great Lakes relating to the Partnership's February 2007 acquisition of a 46.45 percent general partner interest in Great Lakes.

On October 30, 2017, Great Lakes filed a rate settlement with FERC to satisfy its obligations from its 2013 rate settlement for new rates to be in effect by January 1, 2018. The 2017 Great Lakes Settlement does not contain a moratorium provision 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. The 2017 Great Lakes Settlement, which was approved by FERC on February 22, 2018, decreased Great Lakes' maximum transportation rates by 27 percent effective October 1, 2017. At December 31, 2017, the estimation of fair value on the remaining equity investment in Great Lakes was completed and we concluded the fair value of our investment in Great Lakes has not materially changed from 2015.

The assumptions we used in the analysis related to the estimated fair value of our remaining equity investment in Great Lakes included the reduction in Great Lakes' rates effective October 1, 2017. The reduction in rates was offset by expected cash flows from the long-term transportation contract with the TransCanada other revenue opportunities on the system and the settlement's elimination of the revenue sharing mechanism with its customers. Although evolving market conditions and other factors relevant to Great Lakes' long term financial performance have remained positive, there is a risk that reductions in future cash flow forecasts or adverse changes in other key assumptions could result in an additional future impairment of the carrying value of our investment in Great Lakes.

Our key assumptions could be negatively impacted by near and long-term conditions including:


•	future regulatory rate action or settlement,
•	valuation of Great lakes in future transactions,
•	changes in customer demand at Great Lakes for pipeline capacity and services,
•	changes in North American natural gas production in the major producing basins,
•	changes in natural gas prices and natural gas storage market conditions,
•	discount rates and multiples used, and
•	changes in other long-term strategic objectives.

The summarized financial information provided to us by Great Lakes is as follows:

December 31 (millions of dollars)	2017	2016

Assets
Current assets	107	66
Plant, property and equipment, net	701	714

	808	780

Liabilities and Partners' Equity
Current liabilities	75	40
Long-term debt, net(a)	259	278
Other long term liabilities	1	–
Partners' equity	473	462

	808	780

Year ended December 31 (millions of dollars)	2017		2016		2015

Transmission revenues	181		179		177
Operating expenses	(66	)	(69	)	(59	)
Depreciation	(29	)	(28	)	(28	)
Financial charges and other	(20	)	(21	)	(23	)

Net income	66		61		67


(a)	Includes current maturities of $19 million as of December 31, 2017 (December 31, 2016 – $19 million).

Iroquois

On June 1, 2017, the Partnership, through its interest in TC PipeLines Intermediate Limited Partnership acquired a 49.34 percent interest in Iroquois. For the year ended December 31, 2017, The Partnership received distributions from Iroquois amounting to $27 million which includes the Partnership's 49.34 percent share of the Iroquois unrestricted cash distribution amounting to approximately $5 million (Refer to Note 7). 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 for the period from June 1, 2017, acquisition date through December 31, 2017. At December 31, 2017, the Partnership had a $41 million difference between the carrying value of Iroquois and the underlying equity in the net assets primarily from TransCanada's carrying value and is due to their fair value assessment of Iroquois' assets at the time of its acquisition of interests from third parties (refer to Note 2-Acquisitions and Goodwill for our accounting policy on acquisitions from TransCanada)

The summarized financial information provided to us by Iroquois for the period from the June 1, 2017 acquisition date through December 31, 2017 is as follows:

(millions of dollars)		At December 31, 2017

ASSETS
Cash and cash equivalents		86
Other current assets		36
Plant, property and equipment, net		591
Other assets		8

		721

LIABILITIES AND PARTNERS' EQUITY
Current liabilities		17
Net long-term debt, including current maturities(a)		329
Other non-current liabilities		9
Partners' equity		366

		721

Period of 7 months ended December 31 (millions of dollars)		2017

Transmission revenues		110
Operating expenses		(32)
Depreciation		(17)
Financial charges and other		(9)

Net income		52


(a)	Includes current maturities of $4 million as of December 31, 2017.

PLANT, PROPERTY AND EQUIPMENT

12 Months Ended

Dec. 31, 2017

PLANT, PROPERTY AND EQUIPMENT

NOTE 6 PLANT, PROPERTY AND EQUIPMENT

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

	2017				2016(a)
		Accumulated		Net Book		Accumulated		Net Book
December 31 (millions of dollars)	Cost	Depreciation		Value	Cost	Depreciation		Value

Pipeline	2,577	(962	)	1,615	2,540	(879	)	1,661
Compression	533	(165	)	368	519	(148	)	371
Metering and other	182	(54	)	128	205	(61	)	144
Construction in progress	12	–		12	4	–		4

	3,304	(1,181	)	2,123	3,268	(1,088	)	2,180


(a)	Recast to consolidate PNGTS (Refer to Notes 2 and 7).

ACQUISITIONS

12 Months Ended

Dec. 31, 2017

DEBT AND CREDIT FACILITIES

ACQUISITIONS

NOTE 7 ACQUISITIONS

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 (the 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 for Iroquois and PNGTS amounting to $19 million and $3 million, respectively and (iv) additional consideration of $28 million for the surplus cash on Iroquois' balance sheet. 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 8) 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 the cash determined to be surplus to Iroquois' operating needs.

Iroquois' partners adopted a distribution resolution to address the surplus cash on its 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 February 26, 2018 the Partnership has received approximately $7.8 million of the expected $28 million, of which $5.2 million was received in 2017 and $2.6 million was received on February 1, 2018 (Refer to Note 25).

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.

2016 PNGTS Acquisition

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

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

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

The net purchase price was allocated as follows:

(millions of dollars)

Net Purchase Price(a)		193
Less: TransCanada's carrying value of PNGTS' net assets at January 1, 2016		120

Excess purchase price(b)		73


(a)	Total purchase price of $228 million less the assumption of $35 million of proportional PNGTS debt by the Partnership.
(b)	The excess purchase price of $73 million was recorded as a reduction in Partners' Equity.

2015 GTN Acquisition

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

The Partnership funded the cash portion of the transaction using a portion of the proceeds received on our March 13, 2015 debt offering (refer to Note 8). The Class B units entitle TransCanada to a distribution based on 30 percent of GTN's annual distributions as follows: (i) 100 percent of distributions above $20 million through March 31, 2020; and (ii) 25 percent of distributions above $20 million thereafter. Under the terms of the Third Amended and Restated Agreement of Limited Partnership of the Partnership (Partnership Agreement), the Class B distribution was initially calculated to equal 30 percent of GTN's distributable cash flow for the nine months ended December 31, 2015, less $15 million.

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

The net purchase price was allocated as follows:

(millions of dollars)

Net Purchase Price(a)		359
Less: TransCanada's carrying value of non-controlling interest at April 1, 2015		232

Excess purchase price(b)		127


(a)	Total purchase price of $457 million less the assumption of $98 million of proportional GTN debt by the Partnership.
(b)	The excess purchase price of $127 million was recorded as a reduction in Partners' Equity.

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

DEBT AND CREDIT FACILITIES

12 Months Ended

Dec. 31, 2017

DEBT AND CREDIT FACILITIES

NOTE 8 DEBT AND CREDIT FACILITIES

(millions of dollars)		2017		Weighted Average Interest Rate for the Year Ended December 31, 2017		2016(b)		Weighted Average Interest Rate for the Year Ended December 31, 2016(b)

TC PipeLines, LP
	Senior Credit Facility due 2021	185		2.41%		160		1.72%
	2013 Term Loan Facility due 2022	500		2.33%		500		1.73%
	2015 Term Loan Facility due 2020	170		2.22%		170		1.63%
	4.65% Unsecured Senior Notes due 2021	350		4.65%	(a)	350		4.65%	(a)
	4.375% Unsecured Senior Notes due 2025	350		4.375%	(a)	350		4.375%	(a)
	3.90% Unsecured Senior Notes due 2027	500		3.90%	(a)	–		–
GTN
	5.29% Unsecured Senior Notes due 2020	100		5.29%	(a)	100		5.29%	(a)
	5.69% Unsecured Senior Notes due 2035	150		5.69%	(a)	150		5.69%	(a)
	Unsecured Term Loan Facility due 2019	55		2.02%		65		1.43%
PNGTS
	5.90% Senior Secured Notes due 2018	30		5.90%	(a)	53		5.90%	(a)
Tuscarora
	Unsecured Term Loan due 2020	25		2.27%		10		1.64%
	3.82% Series D Senior Notes due 2017	–		–		12		3.82%	(a)

		2,415				1,920
Less: unamortized debt issuance costs and debt discount		12				9
Less: current portion		51	(d)			52	(c)

		2,352				1,859


(a)	Fixed interest rate.
(b)	Recast to consolidate PNGTS (Refer to Notes 2 and 7).
(c)	Includes the PNGTS portion due at December 31, 2016 amounting to $5.5 million that was paid on January 3, 2017.
(d)	Includes the PNGTS portion due at December 31, 2017 amounting to $5.8 million that was paid on January 2, 2018.

TC PipeLines, LP

On November 10, 2016, the Partnership's Senior Credit Facility was amended to extend the maturity period through November 10, 2021. The Facility consists of a $500 million senior revolving credit facility with a banking syndicate, under which $185 million was outstanding at December 31, 2017 (December 31, 2016 – $160 million), leaving $315 million available for future borrowing.

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

The LIBOR-based interest rate on the Senior Credit Facility was 2.62 percent at December 31, 2017 (December 31, 2016 – 1.92 percent).

On July 1, 2013, the Partnership entered into a term loan agreement with a syndicate of lenders for a $500 million term loan credit facility (2013 Term Loan Facility). On July 2, 2013, the Partnership borrowed $500 million under the 2013 Term Loan Facility, to pay a portion of the purchase price of the 2013 Acquisition, maturing originally on July 1, 2018. On September 29, 2017, the Partnership's 2013 Term Loan Facility was amended to extend the maturity period through October 2, 2022. The 2013 Term Loan Facility bears interest based, at the Partnership's election, on the LIBOR or the base rate plus, in either case, an applicable margin. The base rate equals the highest of (i) SunTrust Bank's prime rate, (ii) 0.50 percent above the federal funds rate and (iii) 1.00 percent above one-month LIBOR. The applicable margin for the term loan is based on the Partnership's senior debt rating and ranges between 1.125 percent and 2.00 percent for LIBOR borrowings and 0.125 percent and 1.00 percent for base rate borrowings.

As of December 31, 2017, the variable interest rate exposure related to 2013 Term Loan Facility was hedged by fixed interest rate swap arrangements and our effective interest rate was 2.31 percent (2016 – 2.31 percent). Prior to hedging activities, the LIBOR-based interest rate was 2.62 percent at December 31, 2017 (December 31, 2016 – 1.87 percent).

On September 30, 2015, the Partnership entered into an agreement for a $170 million term loan credit facility (2015 Term Loan Facility). The Partnership borrowed $170 million under the 2015 Term Loan Facility to refinance its Short-Term Loan Facility which matured on September 30, 2015. 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 2.51 percent at December 31, 2017 (December 31, 2016 – 1.77 percent).

The 2013 Term Loan Facility and the 2015 Term Loan Facility (Term Loan Facilities) and the Senior Credit Facility require the Partnership to maintain a certain leverage ratio (debt to adjusted cash flow [net income plus cash distributions received, extraordinary losses, interest expense, expense for taxes paid or accrued, and depreciation and amortization expense less equity earnings and extraordinary gains]) no greater than 5.00 to 1.00 for each fiscal quarter, except for the fiscal quarter and the two following fiscal quarters in which one or more acquisitions has been executed, in which case the leverage ratio is to be no greater than 5.50 to 1.00. The leverage ratio was 4.70 to 1.00 as of December 31, 2017.

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

On March 13, 2015, the Partnership closed a $350 million public offering of senior unsecured notes bearing an interest rate of 4.375 percent maturing March 13, 2025. The net proceeds of $346 million were used to fund a portion of the 2015 GTN Acquisition (Refer to Note 7) and to reduce the amount outstanding under our Senior Credit Facility. The indenture for the notes contains customary investment grade covenants.

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 7). The indenture for the notes contains customary investment grade covenants.

PNGTS

PNGTS' Senior Secured Notes are secured by the PNGTS long-term firm shipper contracts and its partners' pledge of their equity and a guarantee of debt service for six months. PNGTS is restricted under the terms of its note purchase agreement from making cash distributions unless certain conditions are met. Before a distribution can be made, the debt service reserve account must be fully funded and PNGTS' debt service coverage ratio for the preceding and succeeding twelve months must be 1.30 or greater. At December 31, 2017, the debt service coverage ratio was 1.72 for the twelve preceding months and 1.53 for the twelve succeeding months. Therefore, PNGTS was not restricted to make any cash distributions.

GTN

On June 1, 2015, GTN entered into a $75 million unsecured variable rate term loan facility (Unsecured Term Loan Facility), which requires yearly principal payments until its maturity on June 1, 2019. The variable interest is based on LIBOR plus an applicable margin. The LIBOR-based interest rate on the Unsecured Term Loan Facility was 2.31 percent at December 31, 2017 (December 31, 2016 – 1.57 percent). GTN's Unsecured Senior Notes, along with this new Unsecured Term Loan Facility contain a covenant that limits total debt to no greater than 70 percent of GTN's total capitalization. GTN's total debt to total capitalization ratio at December 31, 2017 is 44.6 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 December 31, 2017, the ratio was 11.09 to 1.00.

The LIBOR-based interest rate on the Tuscarora's Unsecured Term Loan Facility was 2.49 percent at December 31, 2017 (December 31, 2016 – 1.90 percent).

Partnership (TC PipeLines, LP and its subsidiaries)

At December 31, 2017, the Partnership was in compliance with its financial covenants, in addition to the other covenants which include restrictions on entering into mergers, consolidations and sales of assets, granting liens, material amendments to the Partnership Agreement, incurring additional debt and distributions to unitholders.

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

(millions of dollars)

2018		51
2019		36
2020		293
2021		535
2022		500
Thereafter		1,000

		2,415

OTHER LIABILITIES

12 Months Ended

Dec. 31, 2017

OTHER LIABILITIES

OTHER LIABILITIES

NOTE 9 OTHER LIABILITIES

December 31 (millions of dollars)	2017	2016

Regulatory liabilities	26	25
Other liabilities	3	3

	29	28

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

PARTNERS' EQUITY	12 Months Ended
PARTNERS' EQUITY	Dec. 31, 2017
PARTNERS' EQUITY
PARTNERS' EQUITY	NOTE 10 PARTNERS' EQUITY At December 31, 2017, the Partnership had 70,573,423 common units outstanding, of which 53,488,592 were held by non-affiliates and 17,084,831 common units were held by subsidiaries of TransCanada, including 5,797,106 common units held by our General Partner. Additionally, TransCanada, through our General Partner, owns 100 percent of our IDRs and an effective two percent general partner interest in the Partnership. TransCanada also holds 100 percent of our 1,900,000 outstanding Class B units. ATM Equity Issuance Program (ATM Program) In August 2014, the Partnership launched its $200 million ATM program pursuant to which, the Partnership may from time to time, offer and sell, through sales agents, common units, representing limited partner interests. On August 5, 2016, the Partnership entered into a new $400 million Equity Distribution Agreement (EDA) with five financial institutions (the Managers). Sales of the common units will be issued pursuant to the Partnership's shelf registration statement on Form S-3 (Registration No. 333-211907), which was declared effective by the SEC on August 4, 2016. In 2017, the Partnership issued 3.2 million common units under the ATM Program generating net proceeds of approximately $173 million, plus an additional $3 million from the General Partner to maintain its effective two percent interest. The commissions to our sales agents were approximately $2 million. The net proceeds were used to repay a portion of the borrowings under the Senior Credit Facility and for general partnership purposes. In 2016, the Partnership issued 3.1 million common units under the ATM Program generating net proceeds of approximately $164 million, plus an additional $3 million from the General Partner to maintain its effective two percent interest. The commissions to our sales agents were approximately $2 million. The net proceeds were used to repay a portion of the borrowings under the Senior Credit Facility for the 2016 PNGTS Acquisition and for general partnership purposes. The 3.1 million common units issued include the 1.6 million common units subject to rescission as discussed below. In 2015, the Partnership issued 0.7 million common units under the ATM Program generating net proceeds of approximately $43 million, plus an additional $1 million from the General Partner to maintain its effective two percent interest. The commissions to our sales agents were approximately $0.4 million. The net proceeds were used for general partnership purposes. 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 December 31, 2017, there were no outstanding common units subject to rescission on the Partnership's consolidated balance sheet. Issuance of Class B units On April 1, 2015, we issued Class B units to TransCanada to finance a portion of the 2015 GTN Acquisition. The Class B units entitle TransCanada to an annual distribution which is an amount based on 30 percent of cash distributions from GTN exceeding certain annual thresholds (refer to Note 7). The Class B units contain no mandatory or optional redemption features and are also non-convertible, non-exchangeable, non-voting and rank equally with common units upon liquidation. The Class B units' equity account is increased by the excess of 30 percent of GTN's distributions over the annual threshold until such amount is declared for distribution and paid every first quarter of the subsequent year. For the years ended December 31, 2017, 2016 and 2015, the Class B units' equity account was increased by $15 million, $22 million and $12 million, respectively. These amounts equal 30 percent of GTN's total distributable cash flow above the $20 million threshold in 2017 and 2016 and the $15 million threshold in 2015 (refer to Notes 13 and 14).

ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)

12 Months Ended

Dec. 31, 2017

ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)

ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)

NOTE 11 ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)

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

(millions of dollars)	Cash flow hedges(a)		Equity Investments	Total

Balance at December 31, 2014	(5	)	–	(5	)
Change in fair value of cash flow hedges	–		–	–
Amounts reclassified from AOCI	–		–	–
PNGTS' amortization of realized loss on derivative instrument (Note 19)	1		–	1

Net other comprehensive income	1		–	1

Balance at December 31, 2015	(4	)	–	(4	)
Change in fair value of cash flow hedges	3		–	3
Amounts reclassified from AOCI	(2	)	–	(2	)
PNGTS' amortization of realized loss on derivative instrument (Note 19)	1		–	1

Net other comprehensive income	2		–	2

Balance at December 31, 2016	(2	)	–	(2	)
Change in fair value of cash flow hedges	5		–	5
Amounts reclassified from AOCI	–		–	–
PNGTS' amortization of realized loss on derivative instrument (Note 19)	1		–	1
Other comprehensive income – effects of Iroquois' retirement benefit plans	–		1	1

Net other comprehensive income	6		1	7

Balance as of December 31, 2017	4		1	5


(a)	Recast to consolidate PNGTS (Refer to in Notes 2 and 7). Additionally, AOCI as presented here is net of non-controlling interest on PNGTS.

FINANCIAL CHARGES AND OTHER

12 Months Ended

Dec. 31, 2017

FINANCIAL CHARGES AND OTHER

FINANCIAL CHARGES AND OTHER

NOTE 12 FINANCIAL CHARGES AND OTHER

Year ended December 31 (millions of dollars)	2017		2016(a)		2015(a)

Interest expense(b)	83		69		65
Net realized loss related to the interest rate swaps	–		3		2
PNGTS' amortization of realized loss on derivative instrument (Note 19)	1		1		1
Other	(2	)	(2	)	(5	)

	82		71		63


(a)	Recast to consolidate PNGTS (Refer to Notes 2 and 7).
(b)	Interest expense includes amortization of debt issuance costs and discount costs.

NET INCOME PER COMMON UNIT

12 Months Ended

Dec. 31, 2017

NET INCOME PER COMMON UNIT

NET INCOME PER COMMON UNIT

NOTE 13 NET INCOME PER COMMON UNIT

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

The amounts allocable to the General Partner equals an amount based upon the General Partner's effective two percent general partner interest, plus an amount equal to incentive distributions. Incentive distributions are paid to the General Partner if quarterly cash distributions on the common units exceed levels specified in the Partnership Agreement (refer to Note 14).

The amount allocable to the Class B units in 2017 equals an amount based upon 30 percent of GTN's distributable cash flow during the year ended December 31, 2017 less $20 million (2016 – $20 million; 2015 – $15 million).

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

(millions of dollars, except per common unit amounts)	2017		2016		2015

Net income attributable to controlling interests(a)	252		248		37
Net income attributable to PNGTS' former parent(a)(b)	(2	)	(4	)	(24	)

Net income allocable to General Partner and Limited Partners	250		244		13
Incentive distributions attributable to the General Partner(c)	(12	)	(7	)	(3	)
Net income attributable to the Class B units(d)	(15	)	(22	)	(12	)

Net income (loss) allocable to the General Partner and common units	223		215		(2	)
Net income allocable to the General Partner's two percent interest	(4	)	(4	)	–

Net income (loss) attributable to common units	219		211		(2	)

Weighted average common units outstanding (millions) – basic and diluted	69.2		65.7	(e)	63.9
Net income (loss) per common unit – basic and diluted(f)	$ 3.16		$ 3.21		$ (0.03	)


(a)	Recast to consolidate PNGTS for years ended December 2016 and 2015 (Refer to Note 2).
(b)	Net income allocable to General and Limited Partners excludes net income attributed to PNGTS' former parent as it was allocated to TransCanada and was not allocable to either the general partner, common units or Class B units.
(c)	Under the terms of the Partnership Agreement, for any quarterly period, the participation of the incentive distribution rights (IDRs) is limited to the available cash distributions declared. Accordingly, incentive distributions allocated to the General Partner are based on the Partnership's available cash during the current reporting period, but declared and paid in the subsequent reporting period.
(d)	As discussed in Note 10, the Class B units entitle TransCanada to a distribution which is an amount based on 30 percent of GTN's distributions after exceeding certain annual thresholds. The distribution will be payable in the first quarter with respect to the prior year's distributions. Consistent with the application of Accounting Standards Codification (ASC) Topic 260 – "Earnings per share", the Partnership allocated the Class B units a distribution in an amount equal to 30 percent of GTN's total distributable cash flows during the year ended December 31, 2017 less the threshold level of $20 million (2016 – less $20 million; 2015 – less $15 million). During the year ended December 31, 2017, 30 percent of GTN's total distributable cash flow was $35 million. As a result of exceeding the threshold level of $20 million, $15 million of net income attributable to controlling interests was allocated to the Class B units at December 31, 2017 (2016 – $22 million; 2015 – $12 million) (Refer to Note 10).
(e)	Includes the common units subject to rescission. These units are treated as outstanding for financial reporting purposes (Refer to Note 10).
(f)	Net income (loss) per common unit prior to recast.

CASH DISTRIBUTIONS

12 Months Ended

Dec. 31, 2017

CASH DISTRIBUTIONS

CASH DISTRIBUTIONS

NOTE 14 CASH DISTRIBUTIONS

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

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

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

		Marginal Percentage Interest in Distribution
	Total Quarterly Distribution Per Unit Target Amount	Common Unitholders	General Partner

Minimum Quarterly Distribution	$0.45	98%	2%
First Target Distribution	above $0.45 up to $0.81	98%	2%
Second Target Distribution	above $0.81 up to $0.88	85%	15%
Thereafter	above $0.88	75%	25%

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

					Limited Partners			General Partner
Declaration Date		Payment Date		Per Unit Distribution	Common Units	Class B Units(c)		2%	IDRs(a)	Total Cash Distribution

1/22/2015		2/13/2015		$ 0.84	$ 54	$ –		$ 1	$–	$ 55
4/23/2015		5/15/2015		$ 0.84	$ 54	$ –		$ 1	$–	$ 55
7/23/2015		8/14/2015		$ 0.89	$ 56	$ –		$ 2	$ 1	$ 59
10/22/2015		11/13/2015		$ 0.89	$ 57	$ –		$ 1	$ 1	$ 59
1/21/2016		2/12/2016		$ 0.89	$ 57	$ 12	(d)	$ 1	$ 1	$ 71
4/21/2016		5/13/2016		$ 0.89	$ 58	$ –		$ 1	$ 1	$ 60
7/21/2016		8/12/2016		$ 0.94	$ 62	$ –		$ 1	$ 2	$ 65
10/20/2016		11/14/2016		$ 0.94	$ 63	$ –		$ 1	$ 2	$ 66
1/23/2017		2/14/2017		$ 0.94	$ 64	$ 22	(e)	$ 2	$ 2	$ 90
4/25/2017		5/15/2017		$ 0.94	$ 65	$ –		$ 1	$ 2	$ 68
7/20/2017		8/11/2017		$ 1.00	$ 69	$ –		$ 2	$ 3	$ 74
10/24/2017		11/14/2017		$ 1.00	$ 70	$ –		$ 1	$ 3	$ 74
1/23/2018	(b)	2/13/2018	(b)	$ 1.00	$ 71	$ 15	(f)	$ 2	$ 3	$ 91


(a)	The distributions paid during the year ended December 31, 2017 included incentive distributions to the General Partner of $10 million (2016 – $6 million, 2015 – $2 million).
(b)	On February 13, 2018, we paid a cash distribution of $1.00 per unit on our outstanding common units to unitholders of record at the close of business on February 2, 2018 (refer to Note 25).
(c)	The Class B units issued by us on April 1, 2015 represent limited partner interests in us and entitle TransCanada to an annual distribution which is an amount based on 30 percent of GTN's annual distributions after exceeding certain annual thresholds (refer to Note 7 and 10).
(d)	On February 12, 2016, we paid TransCanada $12 million representing 30 percent of GTN's total distributable cash flows for the nine months ended December 31, 2015 less $15 million.
(e)	On February 14, 2017, we paid TransCanada $22 million representing 30 percent of GTN's total distributable cash flows for the year ended December 31, 2016 less $20 million (refer to Note 10 and 25).
(f)	On February 13, 2018, we paid TransCanada $15 million representing 30 percent of GTN's total distributable cash flows for the year ended December 31, 2017 less $20 million (refer to Note 10 and 25).

CHANGE IN OPERATING WORKING CAPITAL

12 Months Ended

Dec. 31, 2017

CHANGE IN OPERATING WORKING CAPITAL

CHANGE IN OPERATING WORKING CAPITAL

NOTE 15 CHANGE IN OPERATING WORKING CAPITAL

Year Ended December 31 (millions of dollars)	2017		2016(b)		2015(b)

Change in accounts receivable and other	4		(4	)	6
Change in other current assets	2		(4	)	(1	)
Change in accounts payable and accrued liabilities	(7	)(a)	5	(a)	(2	)
Change in accounts payable to affiliates	(3	)	–		(15	)(a)
Change in state income taxes payable	–		–		(5	)
Change in accrued interest	2		2		(3	)

Change in operating working capital	(2	)	(1	)	(20	)


(a)	Excludes certain non-cash items primarily related to capital accruals and dropdown costs.
(b)	Recast to consolidate PNGTS (Refer to Notes 2 and 7).

TRANSACTIONS WITH MAJOR CUSTOMERS

12 Months Ended

Dec. 31, 2017

TRANSACTIONS WITH MAJOR CUSTOMERS

TRANSACTIONS WITH MAJOR CUSTOMERS

NOTE 16 TRANSACTIONS WITH MAJOR CUSTOMERS

The following table shows revenues from the Partnership's major customers comprising more than 10 percent of the Partnership's total consolidated recasted revenues (refer to Note 2) for the years ended December 31, 2017, 2016 and 2015:

Year Ended December 31 (millions of dollars)	2017		2016		2015

Anadarko Energy Services Company (Anadarko)	48		48		48
Pacific Gas and Electric Company (Pacific Gas)	33	(a)(b)	36	(a)	42

At December 31, 2017 and 2016, Anadarko owed the Partnership approximately $4 million, which is approximately 10 percent of our consolidated recasted trade accounts receivable (Refer to Note 2).


(a)	Less than 10 percent of trade accounts receivable
(b)	Less than 10 percent of consolidated revenue

RELATED PARTY TRANSACTIONS

12 Months Ended

Dec. 31, 2017

RELATED PARTY TRANSACTIONS

RELATED PARTY TRANSACTIONS

NOTE 17 RELATED PARTY TRANSACTIONS

The Partnership does not have any employees. The management and operating functions are provided by the General Partner. The General Partner does not receive a management fee in connection with its management of the Partnership. The Partnership reimburses the General Partner for all costs of services provided, including the costs of employee, officer and director compensation and benefits, and all other expenses necessary or appropriate to the conduct of the business of, and allocable to, the Partnership. Such costs include (i) overhead costs (such as office space and equipment) and (ii) out-of-pocket expenses related to the provision of such services. The Partnership Agreement provides that the General Partner will determine the costs that are allocable to the Partnership in any reasonable manner determined by the General Partner in its sole discretion. Total costs charged to the Partnership by the General Partner were $4 million for the year ended December 31, 2017 (2016 – $3 million, 2015 – $3 million).

As operator of most of our pipelines (except Iroquois and the PNGTS joint facilities) 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. The PNGTS joint facilities are operated by MNOC. Therefore, Iroquois and the PNGTS joint facilities do not receive capital and operating services from TransCanada.

Capital and operating costs charged to our pipeline systems, except for Iroquois, for the years ended December 31, 2017, 2016 and 2015 by TransCanada's subsidiaries and amounts payable to TransCanada's subsidiaries at December 31, 2017 and 2016 are summarized in the following tables:

Year ended December 31 (millions of dollars)		2017	2016	2015

Capital and operating costs charged by TransCanada's subsidiaries to:
	Great Lakes(a)	36	30	30
	Northern Border(a)	43	32	36
	PNGTS(a)(b)	9	8	8
	GTN(a)(c)	34	27	30
	Bison	6	2	4
	North Baja	4	4	5
	Tuscarora	4	5	4
Impact on the Partnership's net income attributable to controlling interests:
	Great Lakes	15	13	13
	Northern Border	16	12	14
	PNGTS(b)	5	5	5
	GTN(c)	29	24	25
	Bison	6	3	4
	North Baja	4	4	5
	Tuscarora	4	4	4

December 31 (millions of dollars)		2017	2016

Amount payable to TransCanada's subsidiaries for costs charged in the year by:
	Great Lakes(a)	3	4
	Northern Border(a)	4	4
	PNGTS(a)(b)	1	1
	GTN	3	3
	Bison	1	1
	North Baja	–	1
	Tuscarora	–	1


(a)	Represents 100 percent of the costs.
(b)	Recast to consolidate PNGTS for years ended December 31, 2016 and 2015 (Refer to Note 2).
(c)	In 2015, the Partnership acquired the remaining 30 percent interest in GTN (Refer to Note 7).

Great Lakes

Great Lakes earns significant transportation revenues from TransCanada and its affiliates, some of which are provided at discounted rates, negotiated rates and some at maximum recourse rates. For the year ended December 31, 2017, Great Lakes earned 57 percent of its transportation revenues from TransCanada and its affiliates (2016 – 68 percent; 2015 – 71 percent). Additionally, Great Lakes earned approximately one percent of its total revenues as affiliated rental revenue in 2017 (2016 – 1 percent; 2015 – 1 percent).

At December 31, 2017, $20 million was included in Great Lakes' receivables in regards to the transportation contracts with TransCanada and its affiliates (December 31, 2016 – $19 million).

In 2017, Great Lakes operates under a FERC approved 2013 rate settlement that includes a revenue sharing mechanism that requires Great Lakes to share with its customers certain percentages of any qualifying revenues earned above certain ROEs. A refund of $7 million was paid to shippers in 2017 relating to the year ended December 31, 2016, of which approximately 86 percent was made to affiliates of Great Lakes. For the year ended December 31, 2017, Great Lakes has recorded an estimated revenue sharing provision amounting to $40 million and Great Lakes expects that a significant percentage of the 2017 revenue sharing refund will be to its affiliates.

Under the terms of the 2017 Great Lakes Settlement, beginning 2018, the revenue sharing was eliminated (refer to Note 5. Additionally, effective October 1, 2017, Great Lakes still charged customers rates in effect prior to the 2017 Great Lakes Settlement but only recognized revenue up to the amount of the new rates in the 2017 Great Lakes Settlement. The difference between these two amounts was recognized as a provision for rate refund (liability) on Great Lakes' balance sheet amounting to $8 million. Great Lakes expects that a significant percentage of the provision for rate refund will be to its affiliates as well.

Great Lakes has a cash management agreement with TransCanada whereby Great Lakes' funds are pooled with other TransCanada affiliates. The agreement also gives Great Lakes the ability to obtain short-term borrowings to provide liquidity for Great Lakes' operating needs. At December 31, 2017 and 2016, Great Lakes has an outstanding receivable from this arrangement amounting to $64 million and $27 million, respectively.

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

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. For the year ended December 31, 2017, the total revenue earned by Great Lakes on this contract was $13 million.

PNGTS

For the years ended December 31, 2017, 2016 and 2015, PNGTS provided transportation services to a related party. Revenues from TransCanada Energy Ltd., a subsidiary of TransCanada, for 2017, 2016 and 2015 were approximately $1 million, $2 million and $3 million, respectively. At December 31, 2017, PNGTS had nil million outstanding receivables from TransCanada Energy Ltd. in the consolidated balance sheets.

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. As of December 31, 2017, the total costs incurred by these affiliates was approximately $3 million.

QUARTERLY FINANCIAL DATA (unaudited)

12 Months Ended

Dec. 31, 2017

QUARTERLY FINANCIAL DATA (unaudited)

QUARTERLY FINANCIAL DATA (unaudited)

NOTE 18 QUARTERLY FINANCIAL DATA (unaudited)

The following sets forth selected unaudited financial data for the four quarters in 2017 and 2016:

Quarter ended (millions of dollars except per common unit amounts)	Mar 31	Jun 30	Sept 30	Dec 31

2017
Transmission revenues	112	101	100	109
Equity earnings	36	24	27	37
Net income	83	55	55	70
Net income attributable to controlling interests	77	55	54	66
Net income per common unit	$ 1.05	$ 0.73	$ 0.61	$ 0.77
Cash distribution paid to common units(a)	68	68	74	74
Cash distribution paid to Class B units	22	–	–	–

2016
Transmission revenues(b)	111	101	103	111
Equity earnings(b)	33	20	22	22
Net income(b)	81	57	60	65
Net income attributable to controlling interests(b)	74	55	58	61
Net income per common unit(c)	$ 1.10	$ 0.76	$ 0.65	$ 0.70
Cash distribution paid to common unit(c)	59	60	65	66
Cash distribution paid to Class B units	12	–	–	–


(a)	Distributions paid to common units includes our general partner's effective two percent share and IDRs.
(b)	Recast to consolidate PNGTS for the year ended December 31, 2016 (Refer to Note 2).
(c)	Historical net income per common unit was not recasted.

FAIR VALUE MEASUREMENTS

12 Months Ended

Dec. 31, 2017

FAIR VALUE MEASUREMENTS

FAIR VALUE MEASUREMENTS

NOTE 19 FAIR VALUE MEASUREMENTS

(a) Fair Value Hierarchy

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


•	Level 1 inputs are quoted prices (unadjusted) in active markets for identical assets or liabilities that we have the ability to access at the measurement date.
•	Level 2 inputs are inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly.
•	Level 3 inputs are unobservable inputs for the asset or liability.

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

(b) Fair Value of Financial Instruments

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

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

Long-term debt is recorded at amortized cost and classified in Level 2 of the fair value hierarchy for fair value disclosure purposes. Interest rate derivative assets and liabilities are classified in Level 2 for all periods presented where the fair value is determined by using valuation techniques that refer to observable market data or estimated market prices. The estimated fair value of the Partnership's debt as at December 31, 2017 and December 31, 2016 was $2,475 million and $1,963 million, respectively.

The common units subject to rescission as presented in the December 31, 2016 balance sheet, as discussed more fully in Note 10, were measured using the original issuance price, plus statutory interest and less any distributions paid. This fair value measurement is classified as Level 2.

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

The interest rate swaps are structured such that the cash flows of the derivative instruments match those of the variable rate of interest on the 2013 Term Loan Facility. The Partnership hedged interest payments on the variable-rate 2013 Term Loan Facility with interest rate swaps maturing July 1, 2018, at a weighted average fixed interest rate of 2.31 percent. At December 31, 2017, the fair value of the interest rate swaps accounted for as cash flow hedges was an asset of $5 million (on both 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 years ended December 31, 2017, 2016 and 2015. The net change in fair value of interest rate derivative instruments recognized in other comprehensive income was a gain of $5 million for the year ended December 31, 2017 (2016 – gain of $2 million, 2015 – nil). In 2017, the net realized loss related to the interest rate swaps was nil, and was included in financial charges and other (2016 – $3 million, 2015 – $2 million). Refer to Note 12 – Financial Charges and Other.

As discussed in Note 8, 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. As a result of this extension, the Partnership implemented an interest rate hedging strategy during the fourth quarter of 2017 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, its contracts contain provisions with rights of offset. The Partnership has elected to present the fair value of derivative instruments with the right to offset on a gross basis in the balance sheet. Had the Partnership elected to present these instruments on a net basis, there would be net asset of $5 million as of December 31, 2017 and there would be no effect on the consolidated balance sheet 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 AOCI as of the termination date. The previously recorded AOCI is currently being amortized against earnings over the life of the PNGTS Senior Secured Notes. At December 31, 2017, our 61.71 percent proportionate share of net unamortized loss on PNGTS included in AOCI was $1 million (2016 – $2 million). For the year ended December 31, 2017, 2016 and 2015, our 61.71 percent proportionate share of the amortization of realized loss on derivative instruments was $0.8 million for each year.

Our maximum counterparty credit exposure with respect to financial instruments at the balance sheet date consists primarily of the carrying amount, which approximates fair value, of non-derivative financial assets, such as cash and cash equivalents and receivables, as well as the fair value of derivative financial assets. We review our accounts receivable regularly and record allowances for doubtful accounts using the specific identification method. At December 31, 2017, we had not incurred any significant credit losses and had no significant amounts past due or impaired. At December 31, 2017, we had a credit risk concentration on one of our customers and the amount owed is greater than 10 percent of our trade accounts receivable (refer to Note 16).

The estimated fair value measurement on our equity investment in Great Lakes is classified as Level 3. In the determination of fair value, we used internal forecasts on expected future cash flows and applied appropriate discount rates. The determination of expected future cash flows involved significant assumptions and estimates as discussed more fully in Note 5.

ACCOUNTS RECEIVABLE AND OTHER

12 Months Ended

Dec. 31, 2017

ACCOUNTS RECEIVABLE AND OTHER

ACCOUNTS RECEIVABLE AND OTHER

NOTE 20 ACCOUNTS RECEIVABLE AND OTHER

December 31 (millions of dollars)	2017	2016(a)

Trade accounts receivable, net of allowance of nil	40	44
Imbalance receivable from affiliates	1	2
Other	1	1

	42	47


(a)	Recast to consolidate PNGTS (Refer to Notes 2 and 7).

REGULATORY	12 Months Ended
REGULATORY	Dec. 31, 2017
REGULATORY
REGULATORY	NOTE 21 REGULATORY GTN – GTN operates under rates established pursuant to a settlement approved by FERC in June 2015. Beginning in January 2016, GTN's rates decreased by 10 percent and will continue in effect through December 31, 2019. Unless superseded by a subsequent rate case or settlement, GTN's rates will decrease an additional eight percent for the period January 1, 2020 through December 31, 2021 when GTN will be required to establish new rates. Tuscarora – Tuscarora operates under rates established pursuant to a settlement approved by FERC in September 2016. Under the settlement, Tuscarora's system-wide unit rate initially decreased by 17 percent, effective August 1, 2016. Unless superseded by a subsequent rate case or settlement, this rate will remain in effect until July 31, 2019, after which time the unit rate will decrease by an additional seven percent from August 1, 2019 through July 31, 2022. The settlement does not contain a rate moratorium and requires Tuscarora to file to establish new rates no later than August 1, 2022. Bison – Bison continues to operate under the rates approved by FERC in connection with Bison's initial construction and has no requirement to file a new rate proceeding. North Baja – North Baja continues to operate under the rates approved by FERC and has no requirement to file a new rate proceeding. 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 requested abandonments will not have any impact on existing firm transportation service. PNGTS – PNGTS continues to operate under the rates approved by FERC in February 2015 (Refer to Note 2 – Significant Accounting Policies – Revenue Recognition). PNGTS has no requirement to file a new rate proceeding.

CONTINGENCIES	12 Months Ended
CONTINGENCIES	Dec. 31, 2017
CONTINGENCIES
CONTINGENCIES	NOTE 22 CONTINGENCIES The Partnership and its pipeline systems are subject to various legal proceedings in the ordinary course of business. Our accounting for contingencies covers a variety of business activities, including contingencies for legal and environmental liabilities. The Partnership accrues for these contingencies when the assessments indicate that it is probable that a liability has been incurred or an asset will not be recovered and an amount can be reasonably estimated in accordance with ASC 450 – Contingencies. We base these estimates on currently available facts and the estimates of the ultimate outcome or resolution. Actual results may differ from estimates resulting in an impact, positive or negative, on earnings and cash flow. Contingencies that might result in a gain are not accrued in our consolidated financial statements. Below is a material legal proceeding that might have a significant impact on the Partnership: Great Lakes v. Essar Steel Minnesota LLC, et al. – On October 29, 2009, Great Lakes filed suit in the U.S. District Court, District of Minnesota, against Essar Minnesota LLC (Essar Minnesota) and certain Foreign Essar Affiliates (collectively, Essar) for breach of its monthly payment obligation under its transportation services agreement with Great Lakes. Great Lakes sought to recover approximately $33 million for past and future payments due under the agreement. On September 16, 2015, following a jury trial, the federal district court judge entered a judgment in the amount of $32.9 million in favor of Great Lakes. On September 20, 2015, Essar appealed the decision to the United States Court of Appeals for the Eighth Circuit (Eighth Circuit) based on an allegation of improper jurisdiction and a number of other rulings by the federal district judge. Essar was required to post a performance bond for the full value of the judgment pending appeal. 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 but was unsuccessful. As a result, Great Lakes accrued the $1.2 million in its books. Great Lakes is unable to estimate the timing or the extent to which its claim will be recoverable in the bankruptcy proceedings.

VARIABLE INTEREST ENTITIES

12 Months Ended

Dec. 31, 2017

VARIABLE INTEREST ENTITIES

VARIABLE INTEREST ENTITIES

NOTE 23 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:

(millions of dollars)		December 31, 2017		December 31, 2016(b)

ASSETS (LIABILITIES)(a)
	Cash and cash equivalents	19		14
	Accounts receivable and other	30		33
	Inventories	6		6
	Other current assets	5		6
	Equity investments	1,213		918
	Plant, property and equipment	1,133		1,146
	Other assets	1		2
	Accounts payable and accrued liabilities	(24	)	(21	)
	Accounts payable to affiliates, net	(42	)	(32	)
	Distributions payable	(1	)	(3	)
	Accrued interest	(2	)	(2	)
	Current portion of long-term debt	(51	)	(52	)
	Long-term debt	(308	)	(337	)
	Other liabilities	(26	)	(25	)
	Deferred state income tax	(10	)	(10	)


(a)	North Baja and Bison, which are also assets held through our consolidated VIEs, are excluded as the assets of these entities can be used for purposes other than the settlement of the VIE's obligations.
(b)	Recast to consolidate PNGTS for the year ended December 31, 2016 (Refer to Note 2).

INCOME TAXES

12 Months Ended

Dec. 31, 2017

INCOME TAXES

INCOME TAXES

NOTE 24 INCOME TAXES

The state of New Hampshire (NH) imposes a business profits tax (BPT) levied at the PNGTS level. As a result of the BPT, PNGTS recognizes deferred taxes related to temporary differences between the financial statement carrying amount of existing assets and liabilities and their respective tax bases. The deferred taxes at December 31, 2017, 2016 and 2015 relate primarily to utility plant. For the years ended December 31, 2017, 2016 and 2015, the NH BPT effective tax rate was 3.8 percent for all periods and was applied to PNGTS' taxable income.

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

Year ended December 31 (millions of dollars)		2017	2016(a)	2015(a)

State income taxes
	Current	1	1	(2	)
	Deferred	–	–	4

		1	1	2


(a)	Recast to consolidate PNGTS (Refer to Notes 2 and 7).

SUBSEQUENT EVENTS	12 Months Ended
SUBSEQUENT EVENTS	Dec. 31, 2017
SUBSEQUENT EVENTS
SUBSEQUENT EVENTS	NOTE 25 SUBSEQUENT EVENTS Management of the Partnership has reviewed subsequent events through February 26, 2018, the date the financial statements were issued, and concluded there were no events or transactions during this period that would require recognition or disclosure in the consolidated financial statements other than what is disclosed here and/or those already disclosed in the preceding notes. Partnership On January 23, 2018, the board of directors of our General Partner declared the Partnership's fourth quarter 2017 cash distribution in the amount of $1.00 per common unit and was paid on February 13, 2018 to unitholders of record as of February 2, 2018. The declared distribution totaled $76 million and was paid in the following manner: $71 million to common unitholders (including $6 million to the General Partner as holder of 5,797,106 common units and $11 million to another subsidiary of TransCanada as holder of 11,287,725 common units) and $5 million to our General Partner, which included $2 million for its effective two percent general partner interest and $3 million of IDRs payment. On January 23, 2018, the board of directors of our General Partner declared distributions to Class B unitholders in the amount of $15 million which was paid on February 13, 2018. The Class B distribution represents an amount equal to 30 percent of GTN's distributable cash flow during the year ended December 31, 2017 less $20 million. Northern Border Northern Border declared its December 2017 distribution of $15 million on January 8, 2018, of which the Partnership received its 50 percent share or $7 million on January 31, 2018. Northern Border declared its January 2018 distribution of $17 million on February 14, 2018, of which the Partnership will receive its 50 percent share or $9 million on February 28, 2018. Great Lakes Great Lakes declared its fourth quarter 2017 distribution of $20 million on January 10, 2018, of which the Partnership received its 46.45 percent share or $9 million on February 1, 2018. Iroquois Iroquois declared its fourth quarter 2017 distribution of $29 million on January 22, 2018, of which the Partnership received its 49.34 percent share or $14 million on February 1, 2018. The $14 million includes our proportionate share of Iroquois' unrestricted cash amounting to $2.6 million (refer to Note 7). PNGTS On January 2, 2018, PNGTS paid the amount due on December 31, 2017 on its 2003 Senior Secured Notes amounting to $6 million representing $6 million in principal and nil in interest pursuant to the terms of the Note Purchase agreement. Under the agreement, any principal and interest that is due on a date other than a normal business day shall be made on the next succeeding business day without additional interest or penalty.

SIGNIFICANT ACCOUNTING POLICIES (Policies)	12 Months Ended
SIGNIFICANT ACCOUNTING POLICIES (Policies)	Dec. 31, 2017
SIGNIFICANT ACCOUNTING POLICIES
Basis of Presentation - Consolidation and equity method of accounting	(a) Basis of Presentation The Partnership consolidates variable interest entities (VIEs) for which it is considered to be the primary beneficiary as well as voting interest entities in which it has a controlling financial interest. 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 that will be consolidated are acquired from TransCanada by the Partnership, the historical financial statements are required to be recast, except net income (loss) per common unit, to include the acquired entities for all periods presented. When the Partnership acquires an asset or an investment from TransCanada, which will be accounted for by the equity method, the financial information is not required to be recast and the transaction is accounted for prospectively from the date of the acquisition. On June 1, 2017, the Partnership acquired from a subsidiary of TransCanada an additional 11.81 percent interest in PNGTS, resulting in the Partnership owning 61.71 percent in PNGTS (Refer to Note 7). As a result of the Partnership owning 61.71 percent of PNGTS, the Partnership's historical financial information was recast, except net income (loss) per common unit, to consolidate PNGTS for all the periods presented in these consolidated financial statements. Additionally, this acquisition was accounted for as transaction between entities under common control, similar to pooling of interests, whereby the assets and liabilities of PNGTS were recorded at TransCanada's carrying value. Also, on June 1, 2017, the Partnership acquired from subsidiaries of TransCanada a 49.34 percent interest in Iroquois (Refer to Note 7). 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. On January 1, 2016, the Partnership acquired a 49.9 percent interest in PNGTS (2016 PNGTS Acquisition) from a subsidiary of TransCanada. The 2016 PNGTS Acquisition was accounted for as a transaction between entities under common control, similar to a pooling of interests, whereby the equity investment in PNGTS was recorded at TransCanada's carrying value and the total excess purchase price paid was recorded as a reduction in Partners' Equity. Accordingly, the equity investment on PNGTS is being eliminated as a result of consolidating PNGTS for all periods presented. Refer to Note 7 for additional disclosure regarding the PNGTS Acquisition. On April 1, 2015, the Partnership acquired the remaining 30 percent interest in GTN from a subsidiary of TransCanada. This acquisition resulted in being wholly-owned by the Partnership. Prior to this transaction, the remaining 30 percent interest held by a subsidiary of TransCanada was reflected as non-controlling interest in the Partnership's consolidated financial statements. The acquisitions of this already-consolidated entity was accounted as a transaction between entities under common control, similar to a pooling of interests, whereby the acquired interests were recorded at TransCanada's carrying value and the total excess purchase price paid was recorded as a reduction in Partners' Equity. Refer to Note 7 for additional disclosures regarding these acquisitions.
Use of Estimates	(b) Use of Estimates The preparation of financial statements requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities as of the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Although management believes these estimates are reasonable, actual results could differ from these estimates.
Cash and Cash Equivalents	(c) Cash and Cash Equivalents The Partnership's cash and cash equivalents consist of cash and highly liquid short-term investments with original maturities of three months or less and are recorded at cost, which approximates fair value.
Trade Accounts Receivable	(d) Trade Accounts Receivable Trade accounts receivable are recorded at the invoiced amount and do not bear interest. We review our accounts receivable regularly and record allowances for doubtful accounts using the specific identification method.
Natural gas imbalances	(e) Natural gas imbalances Natural gas imbalances occur when the actual amount of natural gas delivered to or received from a pipeline system differs from the amount of natural gas scheduled to be delivered or received. The Partnership values these imbalances due to or from shippers and interconnecting parties at current index prices. Imbalances are settled in kind, subject to the terms of the pipelines' tariff. Imbalances due from others are reported as trade accounts receivable or accounts receivable from affiliates under the caption accounts receivable and other on the balance sheets. Imbalances owed to others are reported on the balance sheets as accounts payable and accrued liabilities and accounts payable to affiliates. In addition, the Partnership classifies all imbalances as current as the Partnership expects to settle them within a year.
Inventories	(f) Inventories Inventories primarily consist of materials and supplies and are carried at the lower of weighted average cost or market.
Plant, Property and Equipment	(g) Plant, Property and Equipment Plant, property and equipment are stated at original cost. Costs of restoring the land above and around the pipeline are capitalized to pipeline facilities and depreciated over the remaining life of the related pipeline facilities. Pipeline facilities and compression equipment have an estimated useful life of 20 to 77 years and metering and other equipment ranges from 5 to 77 years. Depreciation is calculated on a straight-line composite basis over the assets' estimated useful lives. Repair and maintenance costs are expensed as incurred. Costs that are considered a betterment are capitalized. The Partnership's subsidiaries capitalize a carrying cost on funds invested in the construction of long lived assets. This carrying cost includes a return on the investment financed by debt and equity allowance for funds used during construction (AFUDC), calculated based the average cost of debt and equity. Capitalized carrying costs for AFUDC debt and equity are reflected as an increase in the cost of plant, property and equipment on the balance sheets. Amounts included in construction work in progress are not amortized until transferred into service.
Impairment of Equity Method Investments	(h) Impairment of Equity Method Investments We review our equity method investments when a significant event or change in circumstances has occurred that may have an adverse effect on the fair value of each investment. When such events or changes occur, we compare the estimated fair value to the carrying value of the related investment. We calculate the estimated fair value of an investment in an equity method investee using an income approach and market approach. The development of fair value estimates requires significant judgment including estimates of future cash flows, which is dependent on internal forecasts, estimates of the long-term rate of growth for the investee, estimates of the useful life over which cash flows will occur, and determination of weighted average cost of capital. The estimates used to calculate the fair value of an investee can change from year to year based on operating results and market conditions. Changes in these estimates and assumptions could materially affect the determination of fair value and our assessment as to whether an investment in an equity method investee has suffered an impairment. If the estimated fair value of an investment is less than its carrying value, we are required to determine if the decline in fair value is other than temporary. This determination considers the aforementioned valuation methodologies, the length of time and the extent to which fair value has been less than carrying value, the financial condition and near-term prospects of the investee, including any specific events which may influence the operations of the investee, the intent and ability of the holder to retain its investment in the investee for a period of time sufficient to allow for any anticipated recovery in market value, and other facts and circumstances. If the fair value of an investment is less than its carrying value and the decline in value is determined to be other than temporary, we record an impairment charge.
Impairment of Long-lived Assets	(i) Impairment of Long-lived Assets The Partnership reviews long-lived assets, such as plant, property and equipment for impairment whenever events or changes in circumstances indicate the carrying value may not be recoverable. If the total of the estimated undiscounted future cash flows is less than the carrying value of the assets, an impairment loss is recognized for the excess of the carrying value over the fair value of the assets.
Partners' Equity	(j) Partners' Equity Costs incurred in connection with the issuance of units are deducted from the proceeds received.
Revenue Recognition	(k) Revenue Recognition Transmission revenues are recognized in the period in which the service is provided. When a rate case is pending final FERC approval, a portion of the revenue collected is subject to possible refund. As of December 31, 2017, the Partnership has not recognized any transmission revenue that is subject to possible refund. For the years ended December 31, 2014 and in January 2015, as required by FERC, PNGTS was charging customers rates applied for in its 2008 and 2010 rate cases. Due to the uncertainty in the outcome of its two outstanding rate cases, PNGTS was only recognizing revenue up to the amount of the interim FERC approved rates. The difference between these amounts was recognized as a provision (liability) for rate refund in the consolidated balance sheet. On February 19, 2015, FERC approved PNGTS' final rates and PNGTS was required to refund the customers within sixty days of the issuance of the final rates, including interest at the quarterly average prime interest rate as prescribed by FERC. Total refunds accumulated to $114.3 million, including $8.0 million of interest, and were paid to customers on April 15, 2015.
Debt Issuance Costs	(l) Debt Issuance Costs Costs related to the issuance of debt are deferred and amortized using the effective interest rate method over the term of the related debt. Debt issuances costs are presented in the balance sheet as a direct deduction from the carrying amount of debt liabilities, consistent with debt discount and premiums. The amortization of debt issuance costs is reported as interest expense.
Income Taxes	(m) Income Taxes Federal and certain state income taxes are the responsibility of the partners and are not reflected in these consolidated financial statements. The tax effect of the Partnership's activities accrues to its partners. The Partnership's taxable income or loss, which may vary substantially from the net income or loss reported in the consolidated statement of income, is includable in the federal income tax returns of each partner. The aggregate difference in the basis of the Partnership's net assets for financial and income tax purposes cannot be readily determined because all information regarding each partner's tax attributes related to the partnership is not available. In instances where the Partnership is subject to state income taxes, the asset – liability method is used to account for taxes. This method requires the recognition of deferred tax assets and liabilities for future tax consequences attributable to the differences between the financial statement carrying amount of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are classified as non-current on our balance sheet.
Acquisitions and Goodwill	(n) Acquisitions and Goodwill The Partnership accounts for business acquisitions from third parties using the acquisition method of accounting and, accordingly, the assets and liabilities of the acquired entities are recorded at their estimated fair values at the date of acquisition. The excess of the purchase price over the fair value of net assets acquired is attributed to goodwill. Goodwill is not amortized and is tested on an annual basis for impairment or more frequently if any indicators of impairment are evident. The Partnership initially assesses qualitative factors to determine whether events or changes in circumstances indicate that the goodwill might be impaired. If the Partnership does not conclude that it is more likely than not that fair value of the reporting unit is greater than its carrying value, the first step of the two-step impairment test is performed by comparing the fair value of the reporting unit to its book value, which includes goodwill. If the fair value is less than book value, an impairment is indicated and a second step is performed to measure the amount of the impairment. In the second step, the implied fair value of goodwill is calculated by deducting the recognized amounts of all tangible and intangible net assets of the reporting unit from the fair value determined in the initial assessment. If the carrying value of goodwill exceeds the calculated implied fair value of goodwill, an impairment charge is recorded. At December 31, 2017 and 2016, we had $130 million of goodwill recorded on our consolidated balance sheet related to the North Baja ($48 million) and Tuscarora ($82 million) acquisitions. No impairment of goodwill existed at December 31, 2017. The Partnership accounts for business acquisitions between itself and TransCanada, also known as "dropdowns", as transactions between entities under common control. Using this approach, the assets and liabilities of the acquired entities are recorded at TransCanada's carrying value. In the event recasting is required, the Partnership's historical financial information will be recast, except net income (loss) per common unit, to include the acquired entities for all periods presented. If the fair market value paid for the acquired entities is greater than the recorded net assets of the acquired entities, the excess purchase price paid is recorded as a reduction in Partners' Equity. Similarly, if the fair market value paid for the acquired entities is less than the recorded net assets of the acquired entities, the excess of assets acquired is recorded as an increase in Partners' Equity.
Fair Value Measurements	(o) Fair Value Measurements For cash and cash equivalents, receivables, accounts payable, certain accrued expenses and short-term debt, the carrying amount approximates fair value due to the short maturities of these instruments. For long-term debt instruments and the interest rate swap agreements, fair value is estimated based upon market values (if applicable) or on the current interest rates available to us for debt with similar terms and remaining maturities. Considerable judgment is required in developing these estimates.
Derivative Financial Instruments and Hedging Activities	(p) Derivative Financial Instruments and Hedging Activities The Partnership recognizes all derivative instruments as either assets or liabilities in the balance sheet at their respective fair values. For derivatives designated in hedging relationships, changes in the fair value are either offset through earnings against the change in fair value of the hedged item attributable to the risk being hedged or recognized in accumulated other comprehensive income, to the extent the derivative is effective at offsetting the changes in cash flows being hedged until the hedged item affects earnings. The Partnership only enters into derivative contracts that it intends to designate as a hedge of a forecasted transaction or the variability of cash flows to be received or paid related to a recognized asset or liability (cash flow hedge). For all hedging relationships, the Partnership formally documents the hedging relationship and its risk management objective and strategy for undertaking the hedge, the hedging instrument, the hedged transaction, the nature of the risk being hedged, how the hedging instrument's effectiveness in offsetting the hedged risk will be assessed prospectively and retrospectively, and a description of the method used to measure ineffectiveness. The Partnership also formally assesses, both at the inception of the hedging relationship and on an ongoing basis, whether the derivatives that are used in hedging relationships are highly effective in offsetting changes in cash flows of hedged transactions. For derivative instruments that are designated and qualify as part of a cash flow hedging relationship, the effective portion of the gain or loss on the derivative is reported as a component of other comprehensive income and reclassified into earnings in the same period or periods during which the hedged transaction affects earnings. Gains and losses on the derivative representing either hedge ineffectiveness or hedge components excluded from the assessment of effectiveness are recognized in current earnings. The Partnership discontinues hedge accounting prospectively when it determines that the derivative is no longer effective in offsetting cash flows attributable to the hedged risk, the derivative expires or is sold, terminated, or exercised, the cash flow hedge is de-designated because a forecasted transaction is not probable of occurring, or management determines to remove the designation of the cash flow hedge. In all situations in which hedge accounting is discontinued and the derivative remains outstanding, the Partnership continues to carry the derivative at its fair value on the balance sheet and recognizes any subsequent changes in its fair value in earnings. When it is probable that a forecasted transaction will not occur, the Partnership discontinues hedge accounting and recognizes immediately in earnings gains and losses that were accumulated in other comprehensive income related to the hedging relationship.
Asset Retirement Obligation	(q) Asset Retirement Obligation The Partnership recognizes the fair value of a liability for asset retirement obligations in the period in which it is incurred, when a legal obligation exists and a reasonable estimate of fair value can be made. The fair value is added to the carrying amount of the associated asset and the liability is accreted through charges to operating expenses. The Partnership has determined it has legal obligations associated with its natural gas pipelines and related transmission facilities. The obligations relate primarily to purging and sealing the pipelines if they are abandoned. The Partnership is also required to operate and maintain its natural gas pipeline system, and intends to do so as long as supply and demand for natural gas exists, which the Partnership expects for the foreseeable future. Therefore, the Partnership believes its natural gas pipeline system assets have indeterminate lives and, accordingly, has recorded no asset retirement obligation as of December 31, 2017 and 2016.
Government Regulation	(r) Government Regulation The Partnership's subsidiaries are subject to regulation by FERC. Under regulatory accounting principles, certain assets or liabilities that result from the regulated ratemaking process may be recorded that would not be recorded under GAAP for non-regulated entities. The timing of recognition of certain revenues and expenses in our regulated business may differ from that otherwise expected under GAAP to appropriately reflect the economic impact of the regulators' decisions regarding revenues and rates. The Partnership regularly evaluates the continued applicability of regulatory accounting, considering such factors as regulatory changes, the impact of competition, and the ability to recover regulatory assets. At December 31, 2017, the Partnership had regulatory assets amounting to nil reported as part of other current assets in the balance sheet representing volumetric fuel tracker assets that are settled with in-kind exchanges with customers continually (2016 – $1 million). Regulatory liabilities are included in other long-term liabilities (refer to Note 9). AFUDC is capitalized and included in plant, property and equipment.

ORGANIZATION (Tables)

12 Months Ended

Dec. 31, 2017

ORGANIZATION

Schedule of ownership interests in natural gas pipeline systems


Pipeline	Length	Description	Ownership

Gas Transmission Northwest LLC (GTN)	1,377 miles	Extends between an interconnection near Kingsgate, British Columbia, Canada at the Canadian border to a point near Malin, Oregon at the California border and delivers natural gas to the Pacific Northwest and to California.	100 percent
Bison Pipeline LLC (Bison)	303 miles	Extends from a location near Gillette, Wyoming to Northern Border's pipeline system in North Dakota. Bison can transport natural gas from the Powder River Basin to Midwest markets.	100 percent
North Baja Pipeline, LLC (North Baja)	86 miles	Extends between an interconnection with the El Paso Natural Gas Company pipeline near Ehrenberg, Arizona and an interconnection with a natural gas pipeline near Ogilby, California on the Mexican border transporting natural gas in the southwest. North Baja is a bi-directional pipeline.	100 percent
Tuscarora Gas Transmission Company (Tuscarora)	305 miles	Extends between the GTN pipeline near Malin, Oregon to its terminus near Reno, Nevada and delivers natural gas in northeastern California and northwestern Nevada.	100 percent
Northern Border Pipeline Company (Northern Border)	1,412 miles	Extends between the Canadian border near Port of Morgan, Montana to a terminus near North Hayden, Indiana, south of Chicago. Northern Border is capable of receiving natural gas from Canada, the Bakken, the Williston Basin and Rocky Mountain area for deliveries to the Midwest. ONEOK Partners, L.P. owns the remaining 50 percent of Northern Border.	50 percent
Portland Natural Gas Transmission System (PNGTS)	295 miles	Connects with the TQM at the Canadian border to deliver natural gas to customers in the U.S. northeast. Northern New England Investment Company, Inc. owns the remaining 38.29 percent of PNGTS. The 295-mile pipeline includes a 107 miles of jointly owned pipeline facilities (the Joint Facilities) with MNE. The Joint Facilities extend from Westbrook, Maine to Dracut, Massachusetts and PNGTS owns approximately 32% of the undivided ownership interest based on contractually agreed upon percentages. The Joint Facilities are maintained and operated by a wholly owned subsidiary of MNE. MNE is a subsidiary of Enbridge Inc.	61.71 percent(a)
Great Lakes Gas Transmission Limited Partnership (Great Lakes)	2,115 miles	Connects with the TransCanada Mainline at the Canadian border near Emerson, Manitoba, Canada and St. Clair, Michigan, near Detroit. Great Lakes is a bi-directional pipeline that can receive and deliver natural gas at multiple points along its system. TransCanada owns the remaining 53.55 percent of Great Lakes.	46.45 percent
Iroquois Gas Transmission System, L.P (Iroquois)	416 miles	Extends from the TransCanada Mainline system near Waddington, New York to deliver natural gas to customers in the U.S. northeast. The remaining 50.66 percent is owned by TransCanada (0.66 percent), Dominion Midstream (25.93 percent) and Dominion Resources (24.07 percent). Iroquois is maintained and operated by a subsidiary of Iroquois.	49.34 percent(b)


(a)	On June 1, 2017, the Partnership acquired an additional 11.81 percent from TransCanada resulting in 61.71 percent ownership in PNGTS. (Refer to Note 7).
(b)	Effective June 1, 2017 (Refer to Note 7).

EQUITY INVESTMENTS (Tables)

12 Months Ended

Dec. 31, 2017

Schedule of equity investments and summarized financial information for equity investees

		Equity Earnings(b)			Equity Investments
		Year ended December 31			December 31
	Ownership Interest at December 31, 2017	Year ended December 31			December 31
(millions of dollars)	Ownership Interest at December 31, 2017	2017	2016(c)	2015	2017	2016(c)

Northern Border(a)	50.00%	67	69	66	512	444
Great Lakes	46.45%	31	28	31	479	474
Iroquois	49.34%	26	–	–	222	–

		124	97	97	1,213	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 in April 2006.
(b)	Equity Earnings represents our share in investee's earnings and does not include any impairment charge on the equity method investment recorded as a reduction of carrying value of these investments. Accordingly, no impairment charge was recorded by the Partnership on its equity investees for all the periods presented here except the $199 million impairment recognized in 2015 on our investment in Great Lakes as discussed below.
(c)	Recast to eliminate equity earnings from PNGTS and consolidate PNGTS (Refer to Notes 2 and 7).

Schedule of equity investments and summarized financial information for equity investees

December 31 (millions of dollars)		2017		2016

Assets
Cash and cash equivalents		14		14
Other current assets		36		36
Plant, property and equipment, net		1,063		1,089
Other assets		14		14

		1,127		1,153

Liabilities and Partners' Equity
Current liabilities		38		38
Deferred credits and other		31		28
Long-term debt, net(a)		264		430
Partners' equity
	Partners' capital	795		659
	Accumulated other comprehensive loss	(1	)	(2	)

		1,127		1,153

Year ended December 31 (millions of dollars)	2017		2016		2015

Transmission revenues	291		292		286
Operating expenses	(78	)	(72	)	(70	)
Depreciation	(59	)	(59	)	(60	)
Financial charges and other	(18	)	(21	)	(22	)

Net income	136		140		134


(a)	No current maturities as of December 31, 2017 or 2016.

Schedule of equity investments and summarized financial information for equity investees

December 31 (millions of dollars)	2017	2016

Assets
Current assets	107	66
Plant, property and equipment, net	701	714

	808	780

Liabilities and Partners' Equity
Current liabilities	75	40
Long-term debt, net(a)	259	278
Other long term liabilities	1	–
Partners' equity	473	462

	808	780

Year ended December 31 (millions of dollars)	2017		2016		2015

Transmission revenues	181		179		177
Operating expenses	(66	)	(69	)	(59	)
Depreciation	(29	)	(28	)	(28	)
Financial charges and other	(20	)	(21	)	(23	)

Net income	66		61		67


(a)	Includes current maturities of $19 million as of December 31, 2017 (December 31, 2016 – $19 million).

Schedule of equity investments and summarized financial information for equity investees

(millions of dollars)		At December 31, 2017

ASSETS
Cash and cash equivalents		86
Other current assets		36
Plant, property and equipment, net		591
Other assets		8

		721

LIABILITIES AND PARTNERS' EQUITY
Current liabilities		17
Net long-term debt, including current maturities(a)		329
Other non-current liabilities		9
Partners' equity		366

		721

Period of 7 months ended December 31 (millions of dollars)		2017

Transmission revenues		110
Operating expenses		(32)
Depreciation		(17)
Financial charges and other		(9)

Net income		52


(a)	Includes current maturities of $4 million as of December 31, 2017.

PLANT, PROPERTY AND EQUIPMENT (Tables)

12 Months Ended

Dec. 31, 2017

Schedule of plant, property and equipment

	2017				2016(a)
		Accumulated		Net Book		Accumulated		Net Book
December 31 (millions of dollars)	Cost	Depreciation		Value	Cost	Depreciation		Value

Pipeline	2,577	(962	)	1,615	2,540	(879	)	1,661
Compression	533	(165	)	368	519	(148	)	371
Metering and other	182	(54	)	128	205	(61	)	144
Construction in progress	12	–		12	4	–		4

	3,304	(1,181	)	2,123	3,268	(1,088	)	2,180


(a)	Recast to consolidate PNGTS (Refer to Notes 2 and 7).

ACQUISITION (Tables)

12 Months Ended

Dec. 31, 2017

Schedule of net purchase price

(millions of dollars)

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

Excess purchase price(b)		370


(a)	Total purchase price of $710 million plus final working capital adjustment of $19 million and the additional consideration on Iroquois surplus cash amounting to approximately $28 million less the assumption of $164 million of proportional Iroquois debt by the Partnership.
(b)	The excess purchase price of $370 million was recorded as a reduction in Partners' Equity.

Schedule of purchase price allocation

(millions of dollars)

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

	264
Non-controlling interest	(100	)
Carrying value of pre-existing Investment in PNGTS	(132	)

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

Total cash consideration(b)	53


(a)	The excess purchase price of $21 million was recorded as a reduction in Partners' Equity.
(b)	Total purchase price of $55 million plus the final working capital adjustment of $3 million less the assumption of $5 million of proportional PNGTS debt by the Partnership.

Schedule of purchase price

(millions of dollars)

Net Purchase Price(a)		193
Less: TransCanada's carrying value of PNGTS' net assets at January 1, 2016		120

Excess purchase price(b)		73


(a)	Total purchase price of $228 million less the assumption of $35 million of proportional PNGTS debt by the Partnership.
(b)	The excess purchase price of $73 million was recorded as a reduction in Partners' Equity.

GTN

Schedule of purchase price

(millions of dollars)

Net Purchase Price(a)		359
Less: TransCanada's carrying value of non-controlling interest at April 1, 2015		232

Excess purchase price(b)		127


(a)	Total purchase price of $457 million less the assumption of $98 million of proportional GTN debt by the Partnership.
(b)	The excess purchase price of $127 million was recorded as a reduction in Partners' Equity.

DEBT AND CREDIT FACILITIES (Tables)

12 Months Ended

Dec. 31, 2017

DEBT AND CREDIT FACILITIES

Schedule of debt and credit facilities

(millions of dollars)		2017		Weighted Average Interest Rate for the Year Ended December 31, 2017		2016(b)		Weighted Average Interest Rate for the Year Ended December 31, 2016(b)

TC PipeLines, LP
	Senior Credit Facility due 2021	185		2.41%		160		1.72%
	2013 Term Loan Facility due 2022	500		2.33%		500		1.73%
	2015 Term Loan Facility due 2020	170		2.22%		170		1.63%
	4.65% Unsecured Senior Notes due 2021	350		4.65%	(a)	350		4.65%	(a)
	4.375% Unsecured Senior Notes due 2025	350		4.375%	(a)	350		4.375%	(a)
	3.90% Unsecured Senior Notes due 2027	500		3.90%	(a)	–		–
GTN
	5.29% Unsecured Senior Notes due 2020	100		5.29%	(a)	100		5.29%	(a)
	5.69% Unsecured Senior Notes due 2035	150		5.69%	(a)	150		5.69%	(a)
	Unsecured Term Loan Facility due 2019	55		2.02%		65		1.43%
PNGTS
	5.90% Senior Secured Notes due 2018	30		5.90%	(a)	53		5.90%	(a)
Tuscarora
	Unsecured Term Loan due 2020	25		2.27%		10		1.64%
	3.82% Series D Senior Notes due 2017	–		–		12		3.82%	(a)

		2,415				1,920
Less: unamortized debt issuance costs and debt discount		12				9
Less: current portion		51	(d)			52	(c)

		2,352				1,859


(a)	Fixed interest rate.
(b)	Recast to consolidate PNGTS (Refer to Notes 2 and 7).
(c)	Includes the PNGTS portion due at December 31, 2016 amounting to $5.5 million that was paid on January 3, 2017.
(d)	Includes the PNGTS portion due at December 31, 2017 amounting to $5.8 million that was paid on January 2, 2018.

Schedule of principal repayments required on debt

(millions of dollars)

2018		51
2019		36
2020		293
2021		535
2022		500
Thereafter		1,000

		2,415

OTHER LIABILITIES (Tables)

12 Months Ended

Dec. 31, 2017

OTHER LIABILITIES

Schedule of other liabilities

December 31 (millions of dollars)	2017	2016

Regulatory liabilities	26	25
Other liabilities	3	3

	29	28

ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) (Tables)

12 Months Ended

Dec. 31, 2017

ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)

Schedule of changes in accumulated other comprehensive income (loss) (AOCI) by component

(millions of dollars)	Cash flow hedges(a)		Equity Investments	Total

Balance at December 31, 2014	(5	)	–	(5	)
Change in fair value of cash flow hedges	–		–	–
Amounts reclassified from AOCI	–		–	–
PNGTS' amortization of realized loss on derivative instrument (Note 19)	1		–	1

Net other comprehensive income	1		–	1

Balance at December 31, 2015	(4	)	–	(4	)
Change in fair value of cash flow hedges	3		–	3
Amounts reclassified from AOCI	(2	)	–	(2	)
PNGTS' amortization of realized loss on derivative instrument (Note 19)	1		–	1

Net other comprehensive income	2		–	2

Balance at December 31, 2016	(2	)	–	(2	)
Change in fair value of cash flow hedges	5		–	5
Amounts reclassified from AOCI	–		–	–
PNGTS' amortization of realized loss on derivative instrument (Note 19)	1		–	1
Other comprehensive income – effects of Iroquois' retirement benefit plans	–		1	1

Net other comprehensive income	6		1	7

Balance as of December 31, 2017	4		1	5


(a)	Recast to consolidate PNGTS (Refer to in Notes 2 and 7). Additionally, AOCI as presented here is net of non-controlling interest on PNGTS.

FINANCIAL CHARGES AND OTHER (Tables)

12 Months Ended

Dec. 31, 2017

FINANCIAL CHARGES AND OTHER

Schedule of components of financial charges and other

Year ended December 31 (millions of dollars)	2017		2016(a)		2015(a)

Interest expense(b)	83		69		65
Net realized loss related to the interest rate swaps	–		3		2
PNGTS' amortization of realized loss on derivative instrument (Note 19)	1		1		1
Other	(2	)	(2	)	(5	)

	82		71		63


(a)	Recast to consolidate PNGTS (Refer to Notes 2 and 7).
(b)	Interest expense includes amortization of debt issuance costs and discount costs.

NET INCOME PER COMMON UNIT (Tables)

12 Months Ended

Dec. 31, 2017

NET INCOME PER COMMON UNIT

Schedule of net income (loss) per common unit

(millions of dollars, except per common unit amounts)	2017		2016		2015

Net income attributable to controlling interests(a)	252		248		37
Net income attributable to PNGTS' former parent(a)(b)	(2	)	(4	)	(24	)

Net income allocable to General Partner and Limited Partners	250		244		13
Incentive distributions attributable to the General Partner(c)	(12	)	(7	)	(3	)
Net income attributable to the Class B units(d)	(15	)	(22	)	(12	)

Net income (loss) allocable to the General Partner and common units	223		215		(2	)
Net income allocable to the General Partner's two percent interest	(4	)	(4	)	–

Net income (loss) attributable to common units	219		211		(2	)

Weighted average common units outstanding (millions) – basic and diluted	69.2		65.7	(e)	63.9
Net income (loss) per common unit – basic and diluted(f)	$ 3.16		$ 3.21		$ (0.03	)


(a)	Recast to consolidate PNGTS for years ended December 2016 and 2015 (Refer to Note 2).
(b)	Net income allocable to General and Limited Partners excludes net income attributed to PNGTS' former parent as it was allocated to TransCanada and was not allocable to either the general partner, common units or Class B units.
(c)	Under the terms of the Partnership Agreement, for any quarterly period, the participation of the incentive distribution rights (IDRs) is limited to the available cash distributions declared. Accordingly, incentive distributions allocated to the General Partner are based on the Partnership's available cash during the current reporting period, but declared and paid in the subsequent reporting period.
(d)	As discussed in Note 10, the Class B units entitle TransCanada to a distribution which is an amount based on 30 percent of GTN's distributions after exceeding certain annual thresholds. The distribution will be payable in the first quarter with respect to the prior year's distributions. Consistent with the application of Accounting Standards Codification (ASC) Topic 260 – "Earnings per share", the Partnership allocated the Class B units a distribution in an amount equal to 30 percent of GTN's total distributable cash flows during the year ended December 31, 2017 less the threshold level of $20 million (2016 – less $20 million; 2015 – less $15 million). During the year ended December 31, 2017, 30 percent of GTN's total distributable cash flow was $35 million. As a result of exceeding the threshold level of $20 million, $15 million of net income attributable to controlling interests was allocated to the Class B units at December 31, 2017 (2016 – $22 million; 2015 – $12 million) (Refer to Note 10).
(e)	Includes the common units subject to rescission. These units are treated as outstanding for financial reporting purposes (Refer to Note 10).
(f)	Net income (loss) per common unit prior to recast.

CASH DISTRIBUTIONS (Tables)

12 Months Ended

Dec. 31, 2017

CASH DISTRIBUTIONS

Schedule of allocations of available cash from operating surplus between common unitholders and General Partner

		Marginal Percentage Interest in Distribution
	Total Quarterly Distribution Per Unit Target Amount	Common Unitholders	General Partner

Minimum Quarterly Distribution	$0.45	98%	2%
First Target Distribution	above $0.45 up to $0.81	98%	2%
Second Target Distribution	above $0.81 up to $0.88	85%	15%
Thereafter	above $0.88	75%	25%

Schedule of distributions

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

					Limited Partners			General Partner
Declaration Date		Payment Date		Per Unit Distribution	Common Units	Class B Units(c)		2%	IDRs(a)	Total Cash Distribution

1/22/2015		2/13/2015		$ 0.84	$ 54	$ –		$ 1	$–	$ 55
4/23/2015		5/15/2015		$ 0.84	$ 54	$ –		$ 1	$–	$ 55
7/23/2015		8/14/2015		$ 0.89	$ 56	$ –		$ 2	$ 1	$ 59
10/22/2015		11/13/2015		$ 0.89	$ 57	$ –		$ 1	$ 1	$ 59
1/21/2016		2/12/2016		$ 0.89	$ 57	$ 12	(d)	$ 1	$ 1	$ 71
4/21/2016		5/13/2016		$ 0.89	$ 58	$ –		$ 1	$ 1	$ 60
7/21/2016		8/12/2016		$ 0.94	$ 62	$ –		$ 1	$ 2	$ 65
10/20/2016		11/14/2016		$ 0.94	$ 63	$ –		$ 1	$ 2	$ 66
1/23/2017		2/14/2017		$ 0.94	$ 64	$ 22	(e)	$ 2	$ 2	$ 90
4/25/2017		5/15/2017		$ 0.94	$ 65	$ –		$ 1	$ 2	$ 68
7/20/2017		8/11/2017		$ 1.00	$ 69	$ –		$ 2	$ 3	$ 74
10/24/2017		11/14/2017		$ 1.00	$ 70	$ –		$ 1	$ 3	$ 74
1/23/2018	(b)	2/13/2018	(b)	$ 1.00	$ 71	$ 15	(f)	$ 2	$ 3	$ 91


(a)	The distributions paid during the year ended December 31, 2017 included incentive distributions to the General Partner of $10 million (2016 – $6 million, 2015 – $2 million).
(b)	On February 13, 2018, we paid a cash distribution of $1.00 per unit on our outstanding common units to unitholders of record at the close of business on February 2, 2018 (refer to Note 25).
(c)	The Class B units issued by us on April 1, 2015 represent limited partner interests in us and entitle TransCanada to an annual distribution which is an amount based on 30 percent of GTN's annual distributions after exceeding certain annual thresholds (refer to Note 7 and 10).
(d)	On February 12, 2016, we paid TransCanada $12 million representing 30 percent of GTN's total distributable cash flows for the nine months ended December 31, 2015 less $15 million.
(e)	On February 14, 2017, we paid TransCanada $22 million representing 30 percent of GTN's total distributable cash flows for the year ended December 31, 2016 less $20 million (refer to Note 10 and 25).
(f)	On February 13, 2018, we paid TransCanada $15 million representing 30 percent of GTN's total distributable cash flows for the year ended December 31, 2017 less $20 million (refer to Note 10 and 25).

CHANGE IN OPERATING WORKING CAPITAL (Tables)

12 Months Ended

Dec. 31, 2017

CHANGE IN OPERATING WORKING CAPITAL

Schedule of change in operating working capital

Year Ended December 31 (millions of dollars)	2017		2016(b)		2015(b)

Change in accounts receivable and other	4		(4	)	6
Change in other current assets	2		(4	)	(1	)
Change in accounts payable and accrued liabilities	(7	)(a)	5	(a)	(2	)
Change in accounts payable to affiliates	(3	)	–		(15	)(a)
Change in state income taxes payable	–		–		(5	)
Change in accrued interest	2		2		(3	)

Change in operating working capital	(2	)	(1	)	(20	)


(a)	Excludes certain non-cash items primarily related to capital accruals and dropdown costs.
(b)	Recast to consolidate PNGTS (Refer to Notes 2 and 7).

TRANSACTIONS WITH MAJOR CUSTOMERS (Tables)

12 Months Ended

Dec. 31, 2017

TRANSACTIONS WITH MAJOR CUSTOMERS

Schedule of revenues from major customers

Year Ended December 31 (millions of dollars)	2017		2016		2015

Anadarko Energy Services Company (Anadarko)	48		48		48
Pacific Gas and Electric Company (Pacific Gas)	33	(a)(b)	36	(a)	42


(a)	Less than 10 percent of trade accounts receivable
(b)	Less than 10 percent of consolidated revenue

RELATED PARTY TRANSACTIONS (Tables)

12 Months Ended

Dec. 31, 2017

RELATED PARTY TRANSACTIONS

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

Year ended December 31 (millions of dollars)		2017	2016	2015

Capital and operating costs charged by TransCanada's subsidiaries to:
	Great Lakes(a)	36	30	30
	Northern Border(a)	43	32	36
	PNGTS(a)(b)	9	8	8
	GTN(a)(c)	34	27	30
	Bison	6	2	4
	North Baja	4	4	5
	Tuscarora	4	5	4
Impact on the Partnership's net income attributable to controlling interests:
	Great Lakes	15	13	13
	Northern Border	16	12	14
	PNGTS(b)	5	5	5
	GTN(c)	29	24	25
	Bison	6	3	4
	North Baja	4	4	5
	Tuscarora	4	4	4

Summary of amount payable to related party for costs charged

December 31 (millions of dollars)		2017	2016

Amount payable to TransCanada's subsidiaries for costs charged in the year by:
	Great Lakes(a)	3	4
	Northern Border(a)	4	4
	PNGTS(a)(b)	1	1
	GTN	3	3
	Bison	1	1
	North Baja	–	1
	Tuscarora	–	1


(a)	Represents 100 percent of the costs.
(b)	Recast to consolidate PNGTS for years ended December 31, 2016 and 2015 (Refer to Note 2).
(c)	In 2015, the Partnership acquired the remaining 30 percent interest in GTN (Refer to Note 7).

QUARTERLY FINANCIAL DATA (unaudited) (Tables)

12 Months Ended

Dec. 31, 2017

QUARTERLY FINANCIAL DATA (unaudited)

Schedule of selected unaudited financial data

Quarter ended (millions of dollars except per common unit amounts)	Mar 31	Jun 30	Sept 30	Dec 31

2017
Transmission revenues	112	101	100	109
Equity earnings	36	24	27	37
Net income	83	55	55	70
Net income attributable to controlling interests	77	55	54	66
Net income per common unit	$ 1.05	$ 0.73	$ 0.61	$ 0.77
Cash distribution paid to common units(a)	68	68	74	74
Cash distribution paid to Class B units	22	–	–	–

2016
Transmission revenues(b)	111	101	103	111
Equity earnings(b)	33	20	22	22
Net income(b)	81	57	60	65
Net income attributable to controlling interests(b)	74	55	58	61
Net income per common unit(c)	$ 1.10	$ 0.76	$ 0.65	$ 0.70
Cash distribution paid to common unit(c)	59	60	65	66
Cash distribution paid to Class B units	12	–	–	–


(a)	Distributions paid to common units includes our general partner's effective two percent share and IDRs.
(b)	Recast to consolidate PNGTS for the year ended December 31, 2016 (Refer to Note 2).
(c)	Historical net income per common unit was not recasted.

ACCOUNTS RECEIVABLE AND OTHER (Tables)

12 Months Ended

Dec. 31, 2017

ACCOUNTS RECEIVABLE AND OTHER

Schedule of accounts receivable and other

December 31 (millions of dollars)	2017	2016(a)

Trade accounts receivable, net of allowance of nil	40	44
Imbalance receivable from affiliates	1	2
Other	1	1

	42	47


(a)	Recast to consolidate PNGTS (Refer to Notes 2 and 7).

VARIABLE INTEREST ENTITIES (Tables)

12 Months Ended

Dec. 31, 2017

VARIABLE INTEREST ENTITIES

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

(millions of dollars)		December 31, 2017		December 31, 2016(b)

ASSETS (LIABILITIES)(a)
	Cash and cash equivalents	19		14
	Accounts receivable and other	30		33
	Inventories	6		6
	Other current assets	5		6
	Equity investments	1,213		918
	Plant, property and equipment	1,133		1,146
	Other assets	1		2
	Accounts payable and accrued liabilities	(24	)	(21	)
	Accounts payable to affiliates, net	(42	)	(32	)
	Distributions payable	(1	)	(3	)
	Accrued interest	(2	)	(2	)
	Current portion of long-term debt	(51	)	(52	)
	Long-term debt	(308	)	(337	)
	Other liabilities	(26	)	(25	)
	Deferred state income tax	(10	)	(10	)


(a)	North Baja and Bison, which are also assets held through our consolidated VIEs, are excluded as the assets of these entities can be used for purposes other than the settlement of the VIE's obligations.
(b)	Recast to consolidate PNGTS for the year ended December 31, 2016 (Refer to Note 2).

- 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)

12 Months Ended

Dec. 31, 2017

INCOME TAXES

Schedule of state income taxes of PNGTS

Year ended December 31 (millions of dollars)		2017	2016(a)	2015(a)

State income taxes
	Current	1	1	(2	)
	Deferred	–	–	4

		1	1	2


(a)	Recast to consolidate PNGTS (Refer to Notes 2 and 7).

ORGANIZATION - Ownership Interests in Natural Gas Pipeline Systems (Details)	12 Months Ended
	Dec. 31, 2017 LimitedPartnership mi	Feb. 28, 2018	Jan. 31, 2018	Sep. 01, 2017	Aug. 01, 2017	Jun. 01, 2017	Dec. 31, 2016	Jan. 01, 2016	Dec. 31, 2015
Organization
Number of intermediate limited partnerships through which pipeline assets are owned \| LimitedPartnership	3
Interest acquired (as a percent)					49.34%
Northern Border
Organization
Interest acquired (as a percent)	50.00%	50.00%	50.00%
Portland Natural Gas Transmission System
Organization
Interest acquired (as a percent)						11.81%		49.90%
Interest acquired by Partnership (as a percent)						61.71%
Ownership interest, including acquired interest (as a percent)						61.71%
Northern New England Investment \| Portland Natural Gas Transmission System
Organization
Remaining noncontrolling ownership interest (as a percent)	38.29%
GTN
Organization
Length of pipeline owned (in miles)	1,377
Ownership interest (as a percent)	100.00%
Bison
Organization
Length of pipeline owned (in miles)	303
Ownership interest (as a percent)	100.00%
North Baja Pipeline, LLC
Organization
Length of pipeline owned (in miles)	86
Ownership interest (as a percent)	100.00%
Tuscarora Gas Transmission Company
Organization
Length of pipeline owned (in miles)	305
Ownership interest (as a percent)	100.00%
Northern Border
Organization
Length of pipeline owned (in miles)	1,412
Ownership interest (as a percent)	50.00%
Interest acquired (as a percent)				50.00%
Portland Natural Gas Transmission System
Organization
Length of pipeline owned (in miles)	295
Interest acquired (as a percent)	61.71%
Interest acquired by Partnership (as a percent)	61.71%						61.71%		61.71%
Portland Natural Gas Transmission System \| Maritimes and Northeast Pipeline LLC
Organization
Length of pipeline owned (in miles)	107
Great Lakes
Organization
Length of pipeline owned (in miles)	2,115
Ownership interest (as a percent)	46.45%
Great Lakes \| TransCanada
Organization
Remaining noncontrolling ownership interest (as a percent)	53.55%
Iroquois Gas
Organization
Length of pipeline owned (in miles)	416
Ownership interest (as a percent)	49.34%
Remaining ownership interest (as a percent)	50.66%
Iroquois Gas \| TransCanada
Organization
Remaining ownership interest (as a percent)	0.66%
Iroquois Gas \| Dominion Midstream
Organization
Remaining ownership interest (as a percent)	25.93%
Iroquois Gas \| Dominion Resources
Organization
Remaining ownership interest (as a percent)	24.07%
ONEOK Partners, L.P. \| Northern Border
Organization
Remaining ownership interest (as a percent)	50.00%
Interest acquired (as a percent)	50.00%
Portland Natural Gas Transmission System
Organization
Ownership interest, including acquired interest (as a percent)						61.71%
Portland Natural Gas Transmission System \| Maritimes and Northeast Pipeline LLC
Organization
Interest acquired (as a percent)	32.00%

ORGANIZATION - Capitalization (Details) - shares

12 Months Ended

Apr. 01, 2015

Dec. 31, 2017

Dec. 31, 2016

Dec. 31, 2015

General Partner | TC PipeLines GP, Inc.

70,600,000

67,400,000

^[1],[2]

64,300,000

^[1]

IDRs ownership (as a percent)

100.00%

Ownership interest in the Partnership (as a percent)

2.00%

Limited Partners | Common Units

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

70,573,423

Limited Partners | Common Units | TransCanada

5,797,106

Limited partner interest (as a percent)

11,287,725

24.20%

Limited Partners | Class B Units | TransCanada

Limited partner interest (as a percent)

1,900,000

100.00%

[1]	Recast to consolidate PNGTS (Refer to Notes 2 and 7).
[2]	Recast to consolidate PNGTS (Refer to Notes 2 and 7).

SIGNIFICANT ACCOUNTING POLICIES - Ownership Interests Acquired (Details)	Aug. 01, 2017	Jun. 01, 2017	Jan. 01, 2016	Apr. 01, 2015	Mar. 31, 2015
Acquisitions
Ownership interest (as a percent)	49.34%
Portland Natural Gas Transmission System
Acquisitions
Ownership interest, including acquired interest (as a percent)		61.71%
Ownership interest (as a percent)		11.81%	49.90%
Interest acquired (as a percent)		61.71%
GTN
Acquisitions
Ownership interest (as a percent)				30.00%
Iroquois
Acquisitions
Interest acquired (as a percent)		49.34%
Former parent, TransCanada subsidiaries \| Portland Natural Gas Transmission System \| Transaction between entities under common control
Acquisitions
Interest acquired (as a percent)			49.90%
TransCanada \| GTN
Acquisitions
Remaining noncontrolling ownership interest (as a percent)					30.00%
GTN \| Former parent, TransCanada subsidiaries \| Transaction between entities under common control
Acquisitions
Interest acquired (as a percent)				30.00%
Portland Natural Gas Transmission System
Acquisitions
Ownership interest, including acquired interest (as a percent)		61.71%
Portland Natural Gas Transmission System \| Former parent, TransCanada subsidiaries \| Transaction between entities under common control
Acquisitions
Ownership interest (as a percent)			49.90%

SIGNIFICANT ACCOUNTING POLICIES - Useful Lives of Plant, Property and Equipment (Details)	12 Months Ended
	Dec. 31, 2017
Pipeline facilities and compression equipment \| Minimum
Plant, Property and Equipment
Estimated useful lives	20 years
Pipeline facilities and compression equipment \| Maximum
Plant, Property and Equipment
Estimated useful lives	77 years
Metering and other equipment \| Minimum
Plant, Property and Equipment
Estimated useful lives	5 years
Metering and other equipment \| Maximum
Plant, Property and Equipment
Estimated useful lives	77 years

SIGNIFICANT ACCOUNTING POLICIES - Revenue Recognition (Details) - Portland Natural Gas Transmission System $ in Millions		1 Months Ended	12 Months Ended
	Feb. 19, 2015 USD ($)	Jan. 31, 2015 item	Dec. 31, 2014 item
Revenue Recognition
Outstanding rate cases \| item		2	2
Maximum number of days to refund to customers	60 days
Accumulated refunds	$ 114.3
Interest on refund	$ 8.0

SIGNIFICANT ACCOUNTING POLICIES - Acquisitions and Goodwill (Details) - USD ($)
$ in Millions

12 Months Ended

Dec. 31, 2017

Dec. 31, 2016

Acquisitions and Goodwill

$ 130

^[1]

Impairment of goodwill

North Baja Pipeline, LLC

Acquisitions and Goodwill

Tuscarora Gas Transmission Company

Acquisitions and Goodwill

$ 82

[1]	Recast to consolidate PNGTS (Refer to Notes 2 and 7).

SIGNIFICANT ACCOUNTING POLICIES - Asset Retirement Obligation and Regulatory Assets (Details) - USD ($)	Dec. 31, 2017	Dec. 31, 2016
Accounts receivable and other
Regulatory assets and liabilities
Regulatory assets	$ 0	$ 1,000,000
Pipeline
Asset Retirement Obligation
Asset retirement liabilities	$ 0	$ 0

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

1 Months Ended

3 Months Ended

7 Months Ended

12 Months Ended

Dec. 31, 2017

Sep. 01, 2017

Jun. 01, 2017

Apr. 30, 2006

Dec. 31, 2017

Sep. 30, 2017

Jun. 30, 2017

Mar. 31, 2017

Dec. 31, 2016

Sep. 30, 2016

Jun. 30, 2016

Mar. 31, 2016

Dec. 31, 2015

Dec. 31, 2017

Dec. 31, 2016

Dec. 31, 2015

Feb. 28, 2018

Feb. 01, 2018

Jan. 31, 2018

Oct. 01, 2017

Aug. 01, 2017

Jan. 31, 2017

49.34%

$ 37

$ 27

$ 24

$ 36

$ 22

$ 20

$ 33

$ 124

$ 97

^[1]

$ 97

^[1]

$ 1,213

1,213

918

^[1]

$ 1,213

1,213

918

^[1]

Capital contribution to reduce the outstanding balance of revolver debt

^[1]

199

^[1]

Return on investment distribution classified as investing activities

Distributions from Equity Investments

$ 51

^[1]

Distributions received from equity investments

145

Distributions from equity investments

140

153

^[1]

119

^[1]

Return on investment distribution classified as investing activities

$ 5

Great Lakes Settlement | FERC

Settlement rate reduced (as a percent)

27.00%

Northern Border Settlement | FERC

Decrease in recourse rate on January 1, 2018 (as percent)

5.00%

Decrease in recourse rate on April 1, 2018 (as percent)

5.50%

Decrease in recourse rate beginning January 1, 2020 through December 31, 2023 (as percent)

2.00%

Decrease in overall recourse rate by January 1, 2020 (as percent)

12.50%

Nonrecurring fair value measurement

$ 0

50.00%

50.00%

Capital contribution to reduce the outstanding balance of revolver debt

$ 83

$ 166

Total cash call issued to fund debt repayment

46.45%

$ 19

$ 4

Revenues (expenses)

110

Operating expenses

(32)

(17)

(9)

$ 52

50.00%

$ 67

Amortization period of transaction fee

$ 512

444

$ 512

512

444

12 years

Transaction fee

$ 10

Additional ownership interest acquired (as a percent)

20.00%

Amount of difference between the carrying value and the underlying equity in net assets resulting from the recognition and inclusion of goodwill

Undistributed earnings

115

116

115

116

Assets

Plant, property and equipment, net

1,063

1,089

1,063

1,089

Assets, total

1,127

1,153

1,127

1,153

Deferred credits and other

Net long-term debt, including current maturities

264

430

264

430

Accumulated other comprehensive loss

Partners' equity

Partners' capital

795

659

795

659

(1)

(2)

(1)

(2)

Liabilities and Partners' Equity, total

$ 1,127

1,153

$ 1,127

1,127

1,153

Revenues (expenses)

291

292

286

Operating expenses

(78)

(72)

(70)

(59)

(60)

(18)

(21)

(22)

Northern Border | Nonrecurring fair value measurement

136

140

134

Northern Border | ONEOK Partners, L.P.

$ 0

50.00%

50.00%

46.45%

$ 31

$ 479

474

$ 479

479

474

Plant, property and equipment, net

$ 4

^[1]

Undistributed earnings

Assets

Current assets

107

701

714

701

714

Assets, total

808

780

808

780

Net long-term debt, including current maturities

259

278

259

278

Other non-current liabilities

Partners' equity

Partners' capital

473

462

473

462

Liabilities and Partners' Equity, total

$ 808

$ 780

$ 808

808

780

Revenues (expenses)

181

179

177

Operating expenses

(66)

(69)

(59)

(29)

(28)

(20)

(21)

(23)

Great Lakes | Nonrecurring fair value measurement

$ 66

$ 61

Amount of difference between the carrying value and the underlying equity in net assets resulting from the recognition and inclusion of goodwill

$ 199

199

$ 260

260

Great Lakes | TransCanada

53.55%

49.34%

$ 26

$ 222

222

Amount of difference between the carrying value and the underlying equity in net assets resulting from the recognition and inclusion of goodwill

$ 710

Undistributed earnings

Return on investment distribution classified as investing activities

Additional consideration on surplus cash

$ 28

Assets

Plant, property and equipment, net

591

Assets, total

721

Net long-term debt, including current maturities

329

Other non-current liabilities

Partners' equity

Partners' capital

366

Liabilities and Partners' Equity, total

$ 721

721

Distributions from Equity Investments

Return on investment distribution classified as investing activities

$ 5

TC PipeLines Intermediate Limited Partnership

TC GL Intermediate Limited Partnership

98.9899%

98.9899%

ASU 2016-15

Return on investment distribution classified as investing activities

(25)

Distributions from Equity Investments

Distributions from equity investments

Return on investment distribution classified as investing activities

$ (25)

[1]	Recast to consolidate PNGTS (Refer to Notes 2 and 7).

PLANT, PROPERTY AND EQUIPMENT (Details) - USD ($)
$ in Millions

Dec. 31, 2017

Dec. 31, 2016

$ 3,304

$ 3,268

(1,181)

(1,088)

2,123

2,180

^[1]

Pipeline

2,577

2,540

(962)

(879)

1,615

1,661

Compression

533

519

(165)

(148)

Metering and other equipment

368

371

182

205

(54)

(61)

128

144

Construction in progress

$ 12

$ 4

[1]	Recast to consolidate PNGTS (Refer to Notes 2 and 7).

ACQUISITIONS - 2017 Acquisition and 2016 PNGTS Acquisition (Details)

9 Months Ended

12 Months Ended

Feb. 01, 2018

USD ($)

Aug. 01, 2017

USD ($)

item

Jun. 01, 2017

USD ($)

Jan. 01, 2016

USD ($)

Feb. 28, 2018

USD ($)

Dec. 31, 2017

USD ($)

Dec. 31, 2016

USD ($)

Dec. 31, 2015

USD ($)

Return on investment distribution classified as investing activities

49.34%

$ 5,000,000

$ 0

Option to acquire (as a percent)

49.34%

0.66

Amount of final purchase price adjustments

$ 19,000,000

Additional consideration on surplus cash

28,000,000

Payment for option to acquire

710,000,000

Outstanding debt

164,000,000

1,000

Return on investment distribution classified as investing activities

$ 5,000,000

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 | Portland Natural Gas Transmission System

Amount of final purchase price adjustments

Purchase price

765,000,000

$ 50,000,000

Iroquois | Investing Activities

Return on investment distribution classified as investing activities

$ 28,000,000

Number of quarters for distribution of surplus cash | item

Iroquois | TransCanada

Additional consideration on surplus cash

$ 28,000,000

Iroquois | Cash Distribution Paid

Return on investment distribution classified as investing activities

$ 5,200,000

Iroquois | Cash Distribution Paid | Subsequent Events

Return on investment distribution classified as investing activities

$ 2,600,000

$ 7,800,000

Interest acquired by Partnership (as a percent)

11.81%

49.90%

61.71%

Amount of final purchase price adjustments

$ 3,000,000

Property, plant and equipment, net

55,000,000

$ 193,000,000

^[1]

Outstanding debt

5,000,000

PNGTS purchase price

Current assets

25,000,000

294,000,000

Deferred state income taxes

(4,000,000)

(10,000,000)

Long-term debt, including current portion

(41,000,000)

Net assets

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 | TransCanada | Transaction between entities under common control

Total purchase price

$ 228,000,000

Less: TransCanada's carrying value of non-controlling interest

193,000,000

PNGTS purchase price

120,000,000

Excess purchase price

73,000,000

Purchase price adjustments

5,000,000

Additional contingent payment, minimum

5,000,000

Assumption of proportional debt

35,000,000

Additional contingent payment, maximum

$ 50,000,000

Period following closing date during which additional payments may be required

15 years

[1]	Recast to consolidate PNGTS (Refer to Notes 2 and 7).

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

9 Months Ended

12 Months Ended

Feb. 14, 2017

Feb. 12, 2016

Apr. 01, 2015

Dec. 31, 2015

Dec. 31, 2017

Dec. 31, 2016

Dec. 31, 2015

Mar. 31, 2015

^[1]

$ 2,000,000

GTN

Reduction in Partners' Equity

^[2]

264,000,000

^[1]

359,000,000

TransCanada | GTN

Noncontrolling interest

Remaining noncontrolling ownership interest (as a percent)

30.00%

$ 2,000,000

2,000,000

General Partner | GTN

Reduction in Partners' Equity

3,000,000

GTN | Former parent, TransCanada subsidiaries | Transaction between entities under common control

Purchase price adjustments

30.00%

$ 11,000,000

Purchase price

457,000,000

Total cash consideration

264,000,000

Assumption of proportional debt

98,000,000

Less: TransCanada's carrying value of non-controlling interest

359,000,000

232,000,000

Excess purchase price

127,000,000

GTN | Former parent, TransCanada subsidiaries | Transaction between entities under common control | Previously reported

GTN | Former parent, TransCanada subsidiaries | Transaction between entities under common control | General Partner

Purchase price

446,000,000

Reduction in Partners' Equity

$ 127,000,000

Partnership interest | Class B Units | GTN | Former parent, TransCanada subsidiaries | Transaction between entities under common control

Value per unit (in dollars per unit)

Units issued (in units)

1,900,000

$ 50

Equity issuance

$ 95,000,000

GTN | Class B Units | TransCanada | Distributions

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

30.00%

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

100.00%

Threshold of 30 percent of GTN's annual distributions for payment to Class B units at specified percentage

$ 20,000,000

15,000,000

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

25.00%

Percentage applied to GTN's distributable cash flow

30.00%

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

$ 20,000,000

$ 15,000,000

$ 20,000,000

$ 15,000,000

[1]	Recast to consolidate PNGTS (Refer to Notes 2 and 7).
[2]	Recast to consolidate PNGTS (Refer to Notes 2 and 7).

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

12 Months Ended

Jan. 02, 2018

Aug. 21, 2017

May 25, 2017

Jan. 03, 2017

Sep. 30, 2015

Mar. 13, 2015

Jul. 02, 2013

Jul. 01, 2013

Dec. 31, 2017

Dec. 31, 2016

Dec. 31, 2015

^[1]

Jun. 01, 2015

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

Less: unamortized debt issuance costs and debt discount

$ 12,000,000

$ 9,000,000

Less: current portion

51,000,000

52,000,000

^[1]

Total credit facilities, short-term loan facility and long-term debt

2,415,000,000

1,920,000,000

2,352,000,000

1,859,000,000

^[1]

3,000,000

1,000,000

^[1],[2]

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

2,415,000,000

Amount borrowed

$ 802,000,000

209,000,000

^[1]

$ 618,000,000

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

Leverage ratio, actual (as a percent)

4.70%

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

2 years

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)

5.50%

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, Senior Credit Facility due 2021

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

$ 185,000,000

$ 160,000,000

Maximum borrowing capacity

2.41%

1.72%

$ 500,000,000

Amount outstanding under credit facility

185,000,000

$ 160,000,000

Remaining borrowing capacity

315,000,000

Revolving credit facility | TC PipeLines, Senior Credit Facility due 2021 | Maximum

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

Increase in credit facility

$ 500,000,000

Revolving credit facility | TC PipeLines, 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 2022

2.62%

1.92%

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

$ 500,000,000

2.33%

1.73%

Borrowings under the facility

$ 500,000,000

$ 500,000,000

Term loan | TC PipeLines, LP 2013 Term Loan Facility due 2022 | Base rate borrowings | Federal funds rate

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

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

0.50%

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

Term loan | TC PipeLines, LP 2013 Term Loan Facility due 2022 | Base rate borrowings | Base rate | Minimum

1.00%

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

Term loan | TC PipeLines, LP 2013 Term Loan Facility due 2022 | Base rate borrowings | Base rate | Maximum

0.125%

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

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

1.00%

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

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

2.62%

1.87%

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

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

1.125%

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

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

2.00%

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

2.31%

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

$ 170,000,000

2.22%

1.63%

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

$ 170,000,000

Amount borrowed

$ 170,000,000

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

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

2.51%

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

4.375%

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

$ 350,000,000

Net proceeds

$ 346,000,000

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

3.90%

$ 500,000,000

3.90%

Unsecured debt | GTN 5.29% Senior Notes due 2020

$ 500,000,000

Net proceeds

$ 497,000,000

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

Unsecured debt | GTN 5.69% Senior Notes due 2035

5.29%

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

Secured debt | PNGTS 5.90% Senior Secured Notes due 2018

5.69%

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

5.90%

$ 30,000,000

$ 53,000,000

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

5.90%

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

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

3.82%

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

Payment of principal amount on secured notes

$ 5,800,000

$ 5,500,000

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

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

Debt Service, number of months of guarantee

6 months

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

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

Debt service coverage, covenant (as a percent)

1.72%

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

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

Debt service coverage, covenant (as a percent)

1.30%

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

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

Debt service coverage, actual (as a percent)

1.53%

GTN | Unsecured debt | GTN 5.29% Senior Notes due 2020

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

$ 100,000,000

GTN | Unsecured debt | GTN 5.69% Senior Notes due 2035

5.29%

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

$ 150,000,000

GTN | Unsecured debt | GTN Term Loan Facility due 2019

5.69%

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

$ 55,000,000

$ 65,000,000

2.02%

1.43%

2.31%

1.57%

GTN | Unsecured debt | GTN Term Loan Facility due 2019 | Maximum

$ 75,000,000

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

Percentage of debt to total capitalization, covenant

44.60%

70.00%

Tuscarora Gas Transmission Company | Tuscarora Term Loan due 2020

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

$ 25,000,000

$ 10,000,000

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

2.27%

1.64%

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

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

$ 25,000,000

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

Debt service coverage, covenant (as a percent)

3.00%

11.09%

Tuscarora Gas Transmission Company | Unsecured debt | Tuscarora Term Loan due 2020 | LIBOR

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

Tuscarora Gas Transmission Company | Secured debt | Tuscarora 3.82% Series D Senior Notes due 2017

2.49%

1.90%

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

$ 12,000,000

3.82%

[1]	Recast to consolidate PNGTS (Refer to Notes 2 and 7).
[2]	Recast to consolidate PNGTS (Refer to Notes 2 and 7).

DEBT AND CREDIT FACILITIES - Principal Payments Required (Details) $ in Millions	Dec. 31, 2017 USD ($)
Principal repayments required on debt
2018	$ 51
2019	36
2020	293
2021	535
2022	500
Thereafter	1,000
Total debt	$ 2,415

OTHER LIABILITIES (Details) - USD ($)
$ in Millions

Dec. 31, 2017

Dec. 31, 2016

OTHER LIABILITIES

Regulatory liabilities

$ 26

$ 25

Other liabilities

Other liabilities, total

$ 29

$ 28

^[1]

[1]	Recast to consolidate PNGTS (Refer to Notes 2 and 7).

PARTNERS' EQUITY - Ownership (Details) - shares

12 Months Ended

Apr. 01, 2015

Dec. 31, 2017

Dec. 31, 2016

Dec. 31, 2015

Common Units | Limited Partners

70,600,000

67,400,000

^[1],[2]

64,300,000

^[1]

Non-affiliates | Common Units | Limited Partners

70,573,423

TC PipeLines GP, Inc. | General Partner

53,488,592

IDRs ownership (as a percent)

100.00%

Ownership interest in the Partnership (as a percent)

2.00%

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

TransCanada Corporation and subsidiaries | Common Units | Limited Partners

5,797,106

TransCanada | Common Units | Limited Partners

17,084,831

Ownership interest in the Partnership (as a percent)

11,287,725

24.20%

TransCanada | Class B Units | Limited Partners

Ownership interest in the Partnership (as a percent)

1,900,000

100.00%

[1]	Recast to consolidate PNGTS (Refer to Notes 2 and 7).
[2]	Recast to consolidate PNGTS (Refer to Notes 2 and 7).

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

2 Months Ended

12 Months Ended

Aug. 05, 2016

USD ($)

item

Apr. 01, 2015

USD ($)

May 19, 2016

Dec. 31, 2017

USD ($)

Dec. 31, 2016

USD ($)

Dec. 31, 2015

USD ($)

Aug. 31, 2014

USD ($)

Common units subject to rescission

^[1]

$ 2.0

^[2],[3]

$ 83.0

TC PipeLines GP, Inc. | General Partner

$ 2.0

Ownership interest in the Partnership (as a percent)

2.00%

ATM Equity Issuance Program

Net proceeds from issuance of common units

^[1]

$ 176.0

$ 84.0

$ 44.0

ATM Equity Issuance Program | General Partner

Net proceeds from issuance of common units

$ 3.0

$ 2.0

$ 1.0

ATM Equity Issuance Program | Common Units

Aggregate offering price of units

$ 200.0

Units sold | shares

3.2

3.1

0.7

Net proceeds from issuance of common units

$ 173.0

$ 164.0

$ 43.0

Sales agent commissions

2.0

0.4

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

1.6

Common units subject to rescission

0.0

$ 83.0

Common units | shares

1.6

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

Equity Distribution Agreement (EDA) | Common Units

$ 3.0

$ 1.0

Amended shelf registration with SEC

$ 400.0

Number of financial institutions | item

[1]	Recast to consolidate PNGTS (Refer to Notes 2 and 7).
[2]	Recast to consolidate PNGTS (Refer to Notes 2 and 7).
[3]	Recast to consolidate PNGTS (Refer to Notes 2 and 7).

PARTNERS' EQUITY - Class B Units (Details) - Class B Units - USD ($)			9 Months Ended	12 Months Ended
	Feb. 12, 2016	Apr. 01, 2015	Dec. 31, 2015	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
PARTNERS' EQUITY
Net income attributable to limited partners				$ 15,000,000	$ 22,000,000	$ 12,000,000
GTN \| TransCanada \| Distributions
PARTNERS' EQUITY
Portion of GTN's annual distributions to which the Class B units are entitled to receive a percentage share of the distributions above threshold (as a percent)		30.00%		30.00%
Percentage applied to GTN's distributable cash flow	30.00%		30.00%	30.00%
Threshold of GTN's total distributable cash flows for payment to Class B units		$ 20,000,000		$ 20,000,000	$ 20,000,000	$ 15,000,000

ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) (Details) - USD ($)
$ in Millions

12 Months Ended

Dec. 31, 2017

Dec. 31, 2016

Dec. 31, 2015

Changes in accumulated other comprehensive income (loss) (AOCI) by component

Partners' Equity at beginning of year

^[1],[2]

$ 1,144

Change in fair value of cash flow hedges

$ 3

^[2]

PNGTS' Amortization of realized loss on derivative financial instrument (Note 19)

^[2]

$ 1

^[2]

^[3]

Accumulated Other Comprehensive Income (Loss)

963

1,144

^[1],[2]

Changes in accumulated other comprehensive income (loss) (AOCI) by component

Partners' Equity at beginning of year

(2)

(4)

(5)

Change in fair value of cash flow hedges

Amounts reclassified from AOCI

(2)

PNGTS' Amortization of realized loss on derivative financial instrument (Note 19)

Other comprehensive income - effects of Iroquois' retirement benefit plans

Changes in accumulated other comprehensive income (loss) (AOCI) by component

(2)

(4)

Cash flow hedges

Partners' Equity at beginning of year

(2)

(4)

(5)

Change in fair value of cash flow hedges

Amounts reclassified from AOCI

(2)

PNGTS' Amortization of realized loss on derivative financial instrument (Note 19)

$ (2)

$ (4)

Changes in accumulated other comprehensive income (loss) (AOCI) by component

Other comprehensive income - effects of Iroquois' retirement benefit plans

Net realized loss related to the interest rate swaps

$ 1

[1]	Recast to consolidate PNGTS (Refer to Notes 2 and 7).
[2]	Recast to consolidate PNGTS (Refer to Notes 2 and 7).
[3]	Recast to consolidate PNGTS (Refer to Notes 2 and 7).

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

12 Months Ended

Dec. 31, 2017

Dec. 31, 2016

Dec. 31, 2015

FINANCIAL CHARGES AND OTHER

Interest Expense

$ 83

$ 69

$ 65

PNGTS' amortization of realized loss on derivative instrument (Note 19)

(2)

(5)

$ 82

$ 71

^[1]

$ 63

^[1]

[1]	Recast to consolidate PNGTS (Refer to Notes 2 and 7).

NET INCOME PER COMMON UNIT - General Partner Effective Interest and Allocated Incentive Distributions (Details)		12 Months Ended
	Apr. 01, 2015	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
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

3 Months Ended

9 Months Ended

12 Months Ended

Feb. 14, 2017

Feb. 12, 2016

Apr. 01, 2015

Dec. 31, 2017

Sep. 30, 2017

Jun. 30, 2017

Mar. 31, 2017

Dec. 31, 2016

Sep. 30, 2016

Jun. 30, 2016

Mar. 31, 2016

Dec. 31, 2015

Dec. 31, 2017

Dec. 31, 2016

Dec. 31, 2015

Net income attributable to PNGTS' former parent

$ 252,000,000

$ 248,000,000

^[1]

$ 37,000,000

^[1]

(2,000,000)

(4,000,000)

(24,000,000)

Net income allocable to General Partner and Limited Partners

250,000,000

244,000,000

13,000,000

Incentive distributions attributable to the General Partner

(12,000,000)

(7,000,000)

(3,000,000)

Net income (loss) allocable to the General Partner and common units

223,000,000

215,000,000

(2,000,000)

Net income allocable to the General Partner's two percent interest

(4,000,000)

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

$ 0.77

$ 0.61

$ 0.73

$ 1.05

$ 0.70

$ 0.65

$ 0.76

$ 1.10

Net income (loss) attributable to common units

15,000,000

22,000,000

12,000,000

Net income (loss) attributable to common units

$ 219,000,000

$ 211,000,000

^[1]

$ (2,000,000)

^[1]

Weighted average common units outstanding - basic (in units)

69.2

65.7

^[1]

63.9

^[1]

Weighted average common units outstanding - diluted (in units)

69.2

65.7

63.9

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

^[2]

$ 3.16

$ 3.21

^[1]

$ (0.03)

^[1]

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

$ 3.16

$ 3.21

$ (0.03)

GTN | Class B Units | TransCanada | Distributions

$ (15,000,000)

$ (22,000,000)

$ (12,000,000)

Percentage applied to GTN's distributable cash flow

30.00%

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

$ 20,000,000

$ 15,000,000

$ 20,000,000

$ 15,000,000

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

30.00%

30% of GTN's distributable cash flow

$ 35,000,000

[1]	Recast to consolidate PNGTS (Refer to Notes 2 and 7).
[2]	Net income per common unit prior to recast (Refer to Note 2).

CASH DISTRIBUTIONS - Quarterly Distributions (Details)		12 Months Ended
CASH DISTRIBUTIONS - Quarterly Distributions (Details)	Apr. 01, 2015	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Cash distributions
Period after the end of each quarter within which quarterly cash distributions to partners are to be paid		45 days
General Partner \| TC PipeLines GP, Inc.
Cash distributions
General partner interest (as a percent)	2.00%	2.00%	2.00%	2.00%

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

12 Months Ended

Dec. 31, 2017

Dec. 31, 2016

^[1],[2]

Dec. 31, 2015

^[1]

Limited Partners | Common Units

70,600,000

67,400,000

64,300,000

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

70,573,423

Minimum Quarterly Distribution

5,797,106

Total Quarterly Distribution Per Unit Target Amount (in dollars per unit)

$ 0.45

Minimum Quarterly Distribution | Limited Partners | Common Units

Marginal Percentage Interest in Distribution, Common Unitholders (as a percent)

98.00%

Minimum Quarterly Distribution | General Partner

Marginal Percentage Interest in Distribution, General Partner (includes IDRs)

2.00%

First Target Distribution | Minimum

Total Quarterly Distribution Per Unit Target Amount (in dollars per unit)

$ 0.45

First Target Distribution | Maximum

Total Quarterly Distribution Per Unit Target Amount (in dollars per unit)

$ 0.81

First Target Distribution | Limited Partners | Common Units

Marginal Percentage Interest in Distribution, Common Unitholders (as a percent)

98.00%

First Target Distribution | General Partner

Marginal Percentage Interest in Distribution, General Partner (includes IDRs)

2.00%

Second Target Distribution | Minimum

Total Quarterly Distribution Per Unit Target Amount (in dollars per unit)

$ 0.81

Second Target Distribution | Maximum

Total Quarterly Distribution Per Unit Target Amount (in dollars per unit)

$ 0.88

Second Target Distribution | Limited Partners | Common Units

Marginal Percentage Interest in Distribution, Common Unitholders (as a percent)

85.00%

Second Target Distribution | General Partner

Marginal Percentage Interest in Distribution, General Partner (includes IDRs)

15.00%

Thereafter | Minimum

Total Quarterly Distribution Per Unit Target Amount (in dollars per unit)

$ 0.88

Thereafter | Limited Partners | Common Units

Marginal Percentage Interest in Distribution, Common Unitholders (as a percent)

75.00%

Thereafter | General Partner

Marginal Percentage Interest in Distribution, General Partner (includes IDRs)

25.00%

[1]	Recast to consolidate PNGTS (Refer to Notes 2 and 7).
[2]	Recast to consolidate PNGTS (Refer to Notes 2 and 7).

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

3 Months Ended

9 Months Ended

12 Months Ended

Feb. 23, 2018

Feb. 13, 2018

Jan. 23, 2018

Nov. 14, 2017

Oct. 24, 2017

Aug. 11, 2017

Jul. 20, 2017

May 15, 2017

Apr. 25, 2017

Feb. 14, 2017

Jan. 23, 2017

Nov. 14, 2016

Oct. 20, 2016

Aug. 12, 2016

Jul. 21, 2016

May 13, 2016

Apr. 21, 2016

Feb. 12, 2016

Jan. 21, 2016

Nov. 13, 2015

Oct. 22, 2015

Aug. 14, 2015

Jul. 23, 2015

May 15, 2015

Apr. 23, 2015

Apr. 01, 2015

Feb. 13, 2015

Jan. 22, 2015

Dec. 31, 2017

Sep. 30, 2017

Jun. 30, 2017

Mar. 31, 2017

Dec. 31, 2016

Sep. 30, 2016

Jun. 30, 2016

Mar. 31, 2016

Dec. 31, 2015

Dec. 31, 2017

Dec. 31, 2016

Dec. 31, 2015

General Partner 2% paid

$ 1,000,000

$ 2,000,000

$ 1,000,000

$ 2,000,000

$ 1,000,000

$ 2,000,000

$ 1,000,000

3,000,000

2,000,000

1,000,000

$ 10,000,000

$ 6,000,000

$ 2,000,000

$ 74,000,000

$ 68,000,000

$ 90,000,000

$ 66,000,000

$ 65,000,000

$ 60,000,000

$ 71,000,000

$ 59,000,000

$ 55,000,000

284,000,000

250,000,000

^[1]

228,000,000

^[1]

Per Unit Distribution, declared (in dollars per unit)

$ 1.00

$ 0.94

$ 0.89

$ 0.84

Per Unit Distribution, paid (in dollars per unit)

$ 1.00

$ 0.94

$ 0.89

$ 0.84

$ 70,000,000

$ 69,000,000

$ 65,000,000

$ 64,000,000

$ 63,000,000

$ 62,000,000

$ 58,000,000

$ 57,000,000

$ 56,000,000

$ 54,000,000

$ 70,000,000

$ 69,000,000

$ 65,000,000

$ 64,000,000

$ 63,000,000

$ 62,000,000

$ 58,000,000

$ 57,000,000

$ 56,000,000

$ 54,000,000

$ 74,000,000

$ 68,000,000

$ 66,000,000

$ 65,000,000

$ 60,000,000

$ 59,000,000

$ 22,000,000

$ 12,000,000

22,000,000

$ 12,000,000

$ 22,000,000

12,000,000

^[1]

GTN | Class B Units | TransCanada | Distributions

$ 22,000,000

$ 12,000,000

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

30.00%

Percentage applied to GTN's distributable cash flow

30.00%

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

$ 20,000,000

$ 15,000,000

$ 20,000,000

$ 15,000,000

Subsequent Events

General Partner 2% paid

$ 2,000,000

3,000,000

Subsequent Events | Common Units

$ 91,000,000

Total Cash Distribution

$ 76,000,000

Per Unit Distribution, declared (in dollars per unit)

$ 1.00

Per Unit Distribution, paid (in dollars per unit)

$ 1.00

$ 71,000,000

Subsequent Events | Class B Units

$ 71,000,000

15,000,000

Subsequent Events | GTN | Class B Units | TransCanada | Distributions

15,000,000

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

$ 20,000,000

[1]	Recast to consolidate PNGTS (Refer to Notes 2 and 7).

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

12 Months Ended

Dec. 31, 2017

Dec. 31, 2016

Dec. 31, 2015

CHANGE IN OPERATING WORKING CAPITAL

Change in accounts receivable and other

$ 4

$ (4)

$ 6

Change in other current assets

(4)

(1)

Change in accounts payable and accrued liabilities

(7)

(2)

Change in accounts payable to affiliates

(3)

(15)

Change in state income taxes payable

(5)

Change in accrued interest

(3)

Change in operating working capital

$ (2)

$ (1)

^[1]

$ (20)

^[1]

[1]	Recast to consolidate PNGTS (Refer to Notes 2 and 7).

TRANSACTIONS WITH MAJOR CUSTOMERS (Details) - USD ($)
$ in Millions

3 Months Ended

12 Months Ended

Dec. 31, 2017

Sep. 30, 2017

Jun. 30, 2017

Mar. 31, 2017

Dec. 31, 2016

Sep. 30, 2016

Jun. 30, 2016

Mar. 31, 2016

Dec. 31, 2017

Dec. 31, 2016

Dec. 31, 2015

Trade accounts receivable

Revenues

$ 109

$ 100

$ 101

$ 112

$ 111

$ 103

$ 101

$ 111

$ 422

$ 426

^[1],[2]

$ 417

^[1]

Total revenues | Customer concentration risk | Anadarko Energy Services Company

Total revenues | Customer concentration risk | Pacific Gas and Electric Company

Revenues

Accounts receivable and other | Amounts owed by major customers | Anadarko Energy Services Company

Revenues

$ 42

Trade accounts receivable

$ 4

[1]	Recast to consolidate PNGTS (Refer to Notes 2 and 7).
[2]	Recast to consolidate PNGTS (Refer to Notes 2 and 7).

RELATED PARTY TRANSACTIONS (Details)
$ in Millions

1 Months Ended

3 Months Ended

4 Months Ended

12 Months Ended

Sep. 21, 2017

Bcf

Apr. 24, 2017

Dec. 31, 2015

USD ($)

May 03, 2015

USD ($)

Dec. 31, 2017

USD ($)

Dec. 31, 2016

USD ($)

Dec. 31, 2015

USD ($)

Dec. 31, 2014

USD ($)

Feb. 28, 2018

Feb. 01, 2018

Jan. 31, 2018

Sep. 01, 2017

Aug. 01, 2017

Jun. 01, 2017

Jan. 31, 2017

Jan. 01, 2016

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

$ 5

$ 8

^[1],[2]

49.34%

Provision for rate refund (liability)

^[1]

$ (101)

Great Lakes Settlement | NEB

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

Term of contract

10 years

Termination options beginning

3 years

Total revenue earned

$ 13

Great Lakes Settlement | NEB | Maximum

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

Transportation capacity per day | Bcf

0.711

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

61.71%

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

Percentage of refund paid to shippers

46.45%

Refund paid to shippers

$ 7

86.00%

Estimated revenue sharing provision

$ 40

Provision for rate refund (liability)

$ 8

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%

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

TransCanada's subsidiaries | Great Lakes

$ 4

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

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

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

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

$ 15

$ 13

100.00%

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

$ 64

$ 27

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

Percent of total revenues

57.00%

68.00%

71.00%

TransCanada's subsidiaries | Great Lakes | Affiliated rental revenue

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

Percent of total revenues

1.00%

TransCanada's subsidiaries | Northern Border

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

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

$ 4

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

$ 43

$ 32

$ 36

TransCanada's subsidiaries | Portland Natural Gas Transmission System

100.00%

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

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

$ 1

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

$ 9

$ 8

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

100.00%

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

Revenues from related party

$ 3

TransCanada's subsidiaries | GTN

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

TransCanada's subsidiaries | GTN | Capital and operating costs

$ 3

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

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

$ 29

$ 24

$ 25

TransCanada's subsidiaries | Bison

100.00%

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

TransCanada's subsidiaries | Bison | Capital and operating costs

$ 1

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

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

$ 4

$ 6

$ 3

$ 4

TransCanada's subsidiaries | North Baja Pipeline, LLC

100.00%

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

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

$ 1

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

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

$ 4

$ 5

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

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

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

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

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

$ 5

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

$ 2

ANR Pipeline Company | Great Lakes | Firm service between Michigan and Wisconsin

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

Deferred revenue related to services performed

$ 14

$ 9

Deferred revenue recognized

$ 23

Affiliates | Portland Natural Gas Transmission System | Construction of facilities

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

Development expenses incurred by affiliates

$ 3

[1]	Recast to consolidate PNGTS (Refer to Notes 2 and 7).
[2]	Recast to consolidate PNGTS (Refer to Notes 2 and 7).

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

3 Months Ended

12 Months Ended

Nov. 14, 2017

Aug. 11, 2017

May 15, 2017

Feb. 14, 2017

Nov. 14, 2016

Aug. 12, 2016

May 13, 2016

Feb. 12, 2016

Nov. 13, 2015

Aug. 14, 2015

May 15, 2015

Apr. 01, 2015

Feb. 13, 2015

Dec. 31, 2017

Sep. 30, 2017

Jun. 30, 2017

Mar. 31, 2017

Dec. 31, 2016

Sep. 30, 2016

Jun. 30, 2016

Mar. 31, 2016

Dec. 31, 2017

Dec. 31, 2016

Dec. 31, 2015

$ 109

$ 100

$ 101

$ 112

$ 111

$ 103

$ 101

$ 111

$ 422

$ 426

^[1],[2]

$ 417

^[1]

Equity earnings

124

^[1]

Net income per common unit (in dollars per unit)

$ 66

$ 54

$ 55

$ 77

$ 61

$ 58

$ 55

$ 74

252

248

^[1],[2]

^[1]

$ 0.77

$ 0.61

$ 0.73

$ 1.05

$ 0.70

$ 0.65

$ 0.76

$ 1.10

TC PipeLines GP, Inc. | General Partner

$ 74

$ 68

$ 90

$ 66

$ 65

$ 60

$ 71

$ 59

$ 55

$ 284

$ 250

^[1]

$ 228

^[1]

General partner interest (as a percent)

2.00%

Net income per common unit (in dollars per unit)

^[3]

$ 3.16

$ 3.21

^[1]

$ (0.03)

^[1]

$ 74

$ 68

$ 66

$ 65

$ 60

$ 59

$ 22

$ 12

[1]	Recast to consolidate PNGTS (Refer to Notes 2 and 7).
[2]	Recast to consolidate PNGTS (Refer to Notes 2 and 7).
[3]	Net income per common unit prior to recast (Refer to Note 2).

FAIR VALUE MEASUREMENTS - Estimated Fair Value of Debt (Details) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Fair Value \| Level 2
Financial Instruments
Fair value of debt	$ 2,475	$ 1,963

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

12 Months Ended

Dec. 31, 2017

USD ($)

item

Dec. 31, 2016

USD ($)

Dec. 31, 2015

USD ($)

Mar. 31, 2017

USD ($)

Change in fair value of interest rate derivative instruments recognized in other comprehensive income (loss)

$ 1.0

^[1]

$ 1.0

^[1]

Amortization of derivatives loss

1.0

$ 1.0

Accounts receivable

Maximum counterparty credit exposure

$ 0.0

Number of credit risk customers | item

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

Amount of forward starting swaps hedged

$ 500.0

$ 500.0

Average rate of forward starting swaps

3.26%

Payments for derivative instruments

$ 20.9

Net unamortized loss included in other comprehensive income

61.71%

$ 1.0

$ 2.0

Amortization of derivatives loss

$ 0.8

0.8

$ 0.8

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

Change in fair value of interest rate derivative instruments recognized in other comprehensive income (loss)

$ 5.0

2.0

0.0

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

Net realized loss related to the interest rate swaps

0.0

3.0

$ 2.0

Hedges of cash flows | Interest rate swaps | Level 2

Fair value of derivative asset, gross

5.0

Fair value of derivative asset, net

5.0

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

Fair value of derivative asset, gross

1.0

Fair value of derivative liability, gross

1.0

Fair value of derivative asset, net

$ 5.0

Fair value of derivative liability, net

$ 0.0

[1]	Recast to consolidate PNGTS (Refer to Notes 2 and 7).

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

Dec. 31, 2017

Dec. 31, 2016

ACCOUNTS RECEIVABLE AND OTHER

Trade accounts receivable, net of allowance of nil

$ 40

$ 44

Imbalance receivable from affiliates

Accounts receivable and other

$ 42

$ 47

^[1]

[1]	Recast to consolidate PNGTS (Refer to Notes 2 and 7).

REGULATORY (Details)
$ in Millions

1 Months Ended

12 Months Ended

Jan. 06, 2017

item

Aug. 01, 2016

Apr. 24, 2017

Dec. 31, 2017

USD ($)

Oct. 01, 2017

Dec. 31, 2016

USD ($)

Great Lakes Settlement | FERC

$ 130

^[1]

Settlement rate reduced (as a percent)

27.00%

Great Lakes Settlement | NEB

Termination options beginning

Term of contract

10 years

3 years

Northern Border Rate Case | FERC

Number of compression units | item

GTN | FERC

Decrease of system-wide unit rate (as a percent)

10.00%

Additional decrease of unit rate (as a percent)

8.00%

Tuscarora Gas Transmission Company

Tuscarora Gas Transmission Company | FERC

$ 82

Additional decrease of unit rate (as a percent)

7.00%

Tuscarora Gas Transmission Company | Tuscarora Settlement | FERC

Decrease of system-wide unit rate (as a percent)

17.00%

[1]	Recast to consolidate PNGTS (Refer to Notes 2 and 7).

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

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

Dec. 31, 2017

Dec. 31, 2016

Dec. 31, 2015

^[1]

Dec. 31, 2014

^[1]

ASSETS (LIABILITIES)

Accounts receivable and other

$ 33

$ 64

^[1]

$ 55

$ 153

^[1]

Inventories

^[1],[2]

Plant, property and equipment

^[1],[2]

Equity investments

1,213

918

^[1]

2,123

2,180

^[1]

Accounts payable and accrued liabilities

^[1],[2]

(31)

(29)

^[1],[2]

Accounts payable to affiliates, net

(5)

(8)

^[1],[2]

Distributions payable

(1)

(3)

^[1],[2]

Accrued interest

(12)

(10)

^[1],[2]

Current portion of long-term debt

(51)

(52)

^[1]

Consolidated VIEs | Restricted VIEs

(2,352)

(1,859)

^[1]

Other liabilities

(29)

(28)

^[1]

ASSETS (LIABILITIES)

Accounts receivable and other

Inventories

Plant, property and equipment

Equity investments

1,213

918

1,133

1,146

Accounts payable and accrued liabilities

(24)

(21)

Accounts payable to affiliates, net

(42)

(32)

Distributions payable

(1)

(3)

Accrued interest

(2)

Current portion of long-term debt

(51)

(52)

Deferred state income tax

(308)

(337)

Other liabilities

(26)

(25)

$ (10)

[1]	Recast to consolidate PNGTS (Refer to Notes 2 and 7).
[2]	Recast to consolidate PNGTS (Refer to Notes 2 and 7).

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

12 Months Ended

Dec. 31, 2017

Dec. 31, 2016

Dec. 31, 2015

State income taxes

Deferred

^[1]

$ 4

Total state income taxes

$ 1

^[1],[2]

$ 2

^[1]

Effective income tax rate (as a percent)

Income Taxes

3.80%

State income taxes

Current

$ 1

$ (2)

Deferred

Total state income taxes

$ 1

$ 2

[1]	Recast to consolidate PNGTS (Refer to Notes 2 and 7).
[2]	Recast to consolidate PNGTS (Refer to Notes 2 and 7).

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

12 Months Ended

Feb. 28, 2018

Feb. 23, 2018

Feb. 14, 2018

Feb. 13, 2018

Feb. 01, 2018

Jan. 31, 2018

Jan. 23, 2018

Jan. 22, 2018

Jan. 10, 2018

Jan. 08, 2018

Jan. 02, 2018

Nov. 14, 2017

Oct. 24, 2017

Aug. 11, 2017

Jul. 20, 2017

May 15, 2017

Apr. 25, 2017

Feb. 14, 2017

Jan. 23, 2017

Nov. 14, 2016

Oct. 20, 2016

Aug. 12, 2016

Jul. 21, 2016

May 13, 2016

Apr. 21, 2016

Feb. 12, 2016

Jan. 21, 2016

Nov. 13, 2015

Oct. 22, 2015

Aug. 14, 2015

Jul. 23, 2015

May 15, 2015

Apr. 23, 2015

Feb. 13, 2015

Jan. 22, 2015

Dec. 31, 2017

Dec. 31, 2016

Dec. 31, 2015

Sep. 01, 2017

Aug. 01, 2017

Jun. 01, 2017

Jan. 31, 2017

Jan. 01, 2016

49.34%

$ 3.0

$ 2.0

$ 1.0

$ 10.0

$ 6.0

$ 2.0

^[1]

310.0

276.0

268.0

Return on investment distribution classified as investing activities

140.0

153.0

^[2]

119.0

^[2]

$ 5.0

0.0

50.00%

46.45%

11.81%

49.90%

49.34%

50.00%

Portland Natural Gas Transmission System | Note Purchase Agreement | 2003 Senior Secured Notes

61.71%

Total amount due on senior secured notes

$ 6.0

Payment of principal amount on secured notes

6.0

Payment of interest on secured notes

$ 0.0

Subsequent Events

Total cash distribution

$ 76.0

Subsequent Events | Distribution declared | Northern Border

$ 3.0

Subsequent Events | Distribution declared | Great Lakes

$ 15.0

Subsequent Events | Distribution declared | Iroquois

$ 20.0

Subsequent Events | Cash Distribution Paid | Northern Border

$ 29.0

$ 17.0

Subsequent Events | Cash Distribution Paid | Great Lakes

$ 9.0

$ 7.0

Subsequent Events | Cash Distribution Paid | Iroquois

$ 9.0

Return on investment distribution classified as investing activities

14.0

$ 2.6

TC PipeLines GP, Inc. | Subsequent Events

$ 16.0

$ 10.0

^[1]

$ 7.0

^[1]

General Partner cash distributions

$ 5.0

Total distribution for General Partner interest

$ 2.0

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

2.00%

$ 3.0

Per Unit Distribution, declared (in dollars per unit)

$ 1.00

$ 0.94

$ 0.89

$ 0.84

$ 70.0

$ 69.0

$ 65.0

$ 64.0

$ 63.0

$ 62.0

$ 58.0

$ 57.0

$ 56.0

$ 54.0

70,600,000

67,400,000

^[2],[3]

64,300,000

^[2]

Common Units | Subsequent Events

$ 70.0

$ 69.0

$ 65.0

$ 64.0

$ 63.0

$ 62.0

$ 58.0

$ 57.0

$ 56.0

$ 54.0

Per Unit Distribution, declared (in dollars per unit)

$ 1.00

71.0

Common Units | Limited Partners

$ 71.0

70,573,423

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

$ 268.0

$ 240.0

^[1]

$ 221.0

^[1]

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

6.0

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

5,797,106

Common Units | TransCanada | Subsequent Events

5,797,106

Common Units | TransCanada | Limited Partners

$ 11.0

Common Units | TransCanada | Limited Partners | Subsequent Events

11,287,725