View Filing Data

Accounts receivable and other (Note 21)

$ 33

Inventories

Other

Total current assets

Equity investments (Note 5)

1,196

1,213

Property, plant and equipment, net (Note 7)

1,529

2,123

Goodwill (Note 4)

130

Accounts payable and accrued liabilities

TOTAL ASSETS

2,899

3,559

Current Liabilities

Accounts payable to affiliates (Note 18)

Accrued interest

Distributions payable

Total current liabilities

100

Long-term debt (Note 9)

2,072

2,352

Deferred state income taxes (Note 24)

Other liabilities (Note 10)

Total liabilities

2,200

2,491

Partners' Equity (Note 11)

General partner

Accumulated other comprehensive income (loss) (AOCI) (Note 12)

Controlling interests

591

963

Non-controlling interest

108

105

Total partners' equity

^[1]

699

1,068

TOTAL LIABILITIES AND PARTNERS' EQUITY

2,899

3,559

Partners' Equity (Note 11)

Limited partner

462

824

Partners' Equity (Note 11)

Limited partner

$ 108

$ 110

[1]	Recast to consolidate PNGTS (Refer to Notes 2 and 8).

CONSOLIDATED STATEMENTS OF OPERATIONS
shares in Millions, $ in Millions

12 Months Ended

Dec. 31, 2018

USD ($)

$ / shares

Dec. 31, 2017

USD ($)

$ / shares

Dec. 31, 2016

USD ($)

$ / shares

^[1]

Impairment of long lived assets (Note 7)

$ 549

$ 422

$ 426

Equity earnings (Note 5)

173

124

(537)

Impairment of goodwill (Note 4)

(59)

Operation and maintenance expenses

(67)

(58)

Property taxes

(28)

(27)

General and administrative

(6)

(8)

(7)

Financial charges and other (Note 13)

(97)

(96)

(92)

(82)

(71)

Net income (loss) before taxes

(164)

264

Income taxes (Note 24)

(1)

Net Income (loss)

(165)

^[1]

263

^[1]

263

Net income attributable to non-controlling interests

Net income (loss) attributable to controlling interests

(182)

252

248

Net income (loss) attributable to controlling interest allocation (Note 14)

General Partner

(4)

TransCanada and its subsidiaries

Net income attributable to controlling interests

(182)

252

248

Net income (loss) attributable to controlling interest allocation (Note 14)

Net income (loss) per common unit (Note 14) - basic and diluted | $ / shares

$ (191)

$ 219

$ 211

$ (2.68)

^[2]

$ 3.16

^[2]

$ 3.21

^[2]

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

71.3

69.2

65.7

Common units outstanding, end of year | shares

71.3

70.6

67.4

[1]	Recast to consolidate PNGTS (Refer to Notes 2 and 8).
[2]	Net income (loss) per common unit prior to recast (Refer to Note 2).

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

12 Months Ended

Dec. 31, 2018

Dec. 31, 2017

Dec. 31, 2016

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

Net income (loss)

^[1]

$ (165)

$ 263

Other comprehensive income (loss)

Change in fair value of cash flow hedges (Notes 12 and 20)

(2)

^[1]

Reclassification to net income of gains and losses on cash flow hedges (Notes 12 and 20)

(2)

^[1]

Amortization of realized loss on derivative instrument (Notes 12 and 20)

^[1]

Other comprehensive income on equity investments (Note 12)

(1)

Comprehensive income (loss)

(162)

270

265

^[1]

Comprehensive income attributable to non-controlling interests

^[1]

Comprehensive income (loss) attributable to controlling interests

$ (179)

$ 259

$ 249

^[1]

[1]	Recast to consolidate PNGTS (Refer to Notes 2 and 8).

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

12 Months Ended

Dec. 31, 2018

Dec. 31, 2017

Dec. 31, 2016

Cash Generated from Operations

Net income (loss)

^[1]

$ (165)

$ 263

Impairment of long lived assets (Note 7)

^[1]

537

Impairment of goodwill (Note 4)

Amortization of debt issue costs reported as interest expense (Note 13)

^[1]

Amortization of realized loss on derivative instrument (Note 20)

^[1]

Equity earnings from equity investments (Note 5)

(173)

(124)

(97)

^[1]

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

188

140

153

^[1]

Change in other long term liabilities

(2)

Equity allowance for funds used during construction

(1)

Change in operating working capital (Note 16)

(3)

(2)

(1)

^[1]

Cash generated from operations

540

376

417

^[1]

Distribution received from Iroquois as return of investment (Note 5)

Capital expenditures

(40)

(29)

^[1]

Other

^[1]

Investing activities

(35)

(761)

(230)

^[1]

Financing Activities

Distributions paid (Note 15)

(218)

(284)

(250)

^[1]

Distributions paid to non-controlling interests

(14)

(5)

(12)

^[1]

Distributions paid to former parent of PNGTS

(1)

(9)

^[1]

Common unit issuance, net (Note 11)

176

^[1]

Common unit issuance subject to rescission, net (Note 11)

^[1]

Long-term debt issued, net of discount (Note 9)

219

802

209

^[1]

Long-term debt repaid (Note 9)

(516)

(310)

(270)

^[1]

Debt issuance costs

(1)

(2)

(1)

^[1]

Financing activities

(505)

354

(178)

^[1]

Increase/(decrease) in cash and cash equivalents

(31)

^[1]

Cash and cash equivalents, beginning of year

^[1]

Cash and cash equivalents, end of year

^[1]

Interest payments paid

^[1]

State income taxes paid

^[1]

Supplemental information about non-cash investing and financing activities

Accrued capital expenditures

Distributions paid to Class B units (Notes 11 and 15)

Financing Activities

(15)

(22)

(12)

^[1]

Equity earnings from equity investments (Note 5)

Cash Generated from Operations

(68)

(67)

(69)

(83)

Equity earnings from equity investments (Note 5)

Cash Generated from Operations

(59)

(31)

(28)

$ (9)

(9)

^[1]

Portland Natural Gas Transmission System And Iroquois Acquisition

^[1]

$ (193)

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

$ (646)

[1]	Recast to consolidate PNGTS (Refer to Notes 2 and 8).

CONSOLIDATED STATEMENTS OF CASH FLOWS (Parenthetical)	Dec. 31, 2018	Aug. 01, 2017	Jun. 01, 2017	Jan. 01, 2016
Iroquois
Interest acquired (as a percent)	49.34%	49.34%	49.34%
PNGTS
Interest acquired (as a percent)			11.81%	49.90%
Interest acquired (as a percent)			11.81%	49.90%

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

PNGTS

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

PNGTS

General Partner

Portland Natural Gas Transmission System And Iroquois Acquisition

General Partner

Accumulated Other Comprehensive Income (Loss)

^[2],[3]

PNGTS

^[1]

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]

Non-controlling interest

Equity of former parent of PNGTS

^[2]

Total

^[1]

$ 1,021

$ 107

$ 25

$ (4)

$ 91

$ 151

$ 1,391

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

^[1]

64.3

1.9

Increase (Decrease) in Partners' Equity

Other comprehensive income

^[1]

$ 211

$ 22

263

^[1]

ATM equity issuances, net (Note 11)

$ 82

$ 2

$ 84

ATM equity issuances, net (Note 11) (in units)

1.5

Common unit issuance subject to rescission, net (Note 11)

^[4]

$ 81

^[1]

Common unit issuance subject to rescission, net (Note 11) (in units)

^[4]

1.6

Reclassification of common unit issuance subject to rescission, net (Note 11)

^[4]

$ (81)

(2)

(83)

^[1]

Acquisition of interests (note 8)

$ (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

Other comprehensive income

$ 219

$ 15

^[1]

263

^[1]

^[1]

ATM equity issuances, net (Note 11)

$ 173

176

ATM equity issuances, net (Note 11) (in units)

3.2

Reclassification of common units no longer subject to rescission (Note 11)

^[1]

Acquisition of interests (note 8)

$ (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

105

1,068

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

^[1]

70.6

1.9

Increase (Decrease) in Partners' Equity

Other comprehensive income

$ (191)

$ 13

(4)

^[1]

(165)

^[1]

^[1]

ATM equity issuances, net (Note 11)

$ 39

$ 1

$ 40

ATM equity issuances, net (Note 11) (in units)

0.7

Distributions

(210)

(15)

(8)

(14)

^[1]

(247)

^[1]

Partners' Equity at end of year at Dec. 31, 2018

$ 462

$ 108

$ 13

$ 8

$ 108

^[1]

$ 699

^[1]

Partners' Equity at end of year (in units) at Dec. 31, 2018

71.3

1.9

[1]	Recast to consolidate PNGTS (Refer to Notes 2 and 8).
[2]	Equity of Former Parent of PNGTS.
[3]	Gains or (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]	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, 2018 USD ($)
Gains (Losses) related to cash flow hedges in AOCI expected to be reclassified to Net income in the next 12 months	$ 2

ORGANIZATION

12 Months Ended

Dec. 31, 2018

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.

At December 31, 2018, 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 and an intermediate general partnership, TC PipeLines Intermediate GP, LLC:


Pipeline	Length	Description	Ownership
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	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	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	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	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

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 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 MNOC, a wholly owned subsidiary of MNE. MNE is a subsidiary of Enbridge Inc.	61.71 percent

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	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

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 a two percent general partner interest in the Partnership at December 31, 2018. TransCanada also indirectly holds an additional 11,287,725 common units, for a total ownership of approximately 24 percent of our outstanding common units and 100 percent of our Class B units at December 31, 2018 (Refer to Note 11).

SIGNIFICANT ACCOUNTING POLICIES	12 Months Ended
SIGNIFICANT ACCOUNTING POLICIES	Dec. 31, 2018
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 U.S. 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, 2018 and 2017 and the results of its operations, cash flows and changes in partners’ equity for the years ended December 31, 2018, 2017 and 2016. (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, with the exception of 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 8). As a result of the Partnership owning 61.71 percent of PNGTS, the Partnership’s 2016 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 a 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 8). Accordingly, this transaction was accounted for as a transaction between entities under common control, similar to a 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 was eliminated as a result of consolidating PNGTS for all periods presented. Refer to Note 8 for additional disclosure regarding the 2016 PNGTS Acquisition. (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) Property, plant and Equipment Property, plant 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 of our subsidiaries’ assets is based on rates approved by FERC from the pipelines’ last rate proceeding and 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 on the average cost of debt and equity. Capitalized carrying costs for AFUDC debt and equity are reflected as an increase in the cost of property, plant 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 property, plant 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 The Partnership’s revenues are generated from contractual arrangements for committed capacity and from transportation of natural gas which are treated as a bundled performance obligation. Revenues earned from firm contracted capacity arrangements are recognized ratably over the term of the contract regardless of the amount of natural gas that is transported. Transportation revenues for interruptible or volumetric-based services are recognized when the service is performed. Revenues are invoiced and paid on a monthly basis. The Partnership’s pipeline systems do not take ownership of the natural gas that is transported for customers. Revenues from contracts with customers are recognized net of any taxes collected from customers, which are subsequently remitted to governmental authorities. The Partnership's pipeline systems are subject to FERC regulations and, as a result, a portion of revenues collected may be subject to refund if invoiced during an interim period when a rate proceeding is ongoing. Allowances for these potential refunds are recognized using management's best estimate based on the facts and circumstances of the proceeding. Any allowances that are recognized during the proceeding process are refunded or retained, as applicable, at the time a regulatory decision becomes final. (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 U.S. 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 operations, is includable in the U.S. 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 for impairment on an annual basis or more frequently if any indicators of impairment are evident. The Partnership can initially assess qualitative factors to determine whether events or changes in circumstances indicate that the goodwill might be impaired and if the Partnership concludes that it is not more likely than not that fair value of the reporting unit is greater than its carrying value, the Partnership will then perform the quantitative goodwill impairment test. The Partnership can also elect to proceed directly to the quantitative goodwill impairment test for any of its reporting units. If the quantitative goodwill impairment test is performed, the Partnership compares the fair value of the reporting unit to its carrying value, including its goodwill. If the carrying value of a reporting unit including its goodwill exceeds its fair value, goodwill impairment is measured at the amount by which the reporting unit’s carrying value exceeds its fair value. 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, with the exception of 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. 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. 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. 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 any 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’s assets have indeterminate lives and, accordingly, has recorded no asset retirement obligation as of December 31, 2018 and 2017. (r) Government Regulation At December 31, 2018, the Partnership had regulatory assets amounting to $2 million reported on the balance sheet as part of other current assets and $2 million regulatory liabilities reported on the balance sheet as part of accounts payable and accrued liabilities both representing volumetric fuel tracker assets that are settled with in-kind exchanges with customers on a continued basis (2017 – nil). Long-term regulatory liabilities are included on the balance sheet as part of other liabilities (refer to Note 10). AFUDC is capitalized and included in property, plant and equipment.

ACCOUNTING PRONOUNCEMENTS	12 Months Ended
ACCOUNTING PRONOUNCEMENTS	Dec. 31, 2018
ACCOUNTING PRONOUNCEMENTS
ACCOUNTING PRONOUNCEMENTS	NOTE 3 ACCOUNTING PRONOUNCEMENTS Changes in Accounting Policies effective January 1, 2018 Revenue from contracts with customers In 2014, the Financial Accounting Standards Board (FASB) issued new guidance on revenue from contracts with customers. The new guidance requires that an entity recognize revenue from these contracts in accordance with a prescribed model. This model is used to depict the transfer of promised goods or services to customers in amounts that reflect the total consideration to which it expects to be entitled during the term of the contract in exchange for those promised goods or services. Goods or services that are promised to a customer are referred to as the Partnership's "performance obligations." The total consideration to which the Partnership expects to be entitled can include fixed and variable amounts. The Partnership has variable revenue that is subject to factors outside the Partnership’s influence, such as market volatility, actions of third parties and weather conditions. The Partnership considers this variable revenue to be "constrained" as it cannot be reliably estimated, and therefore recognizes variable revenue when the service is provided. The Partnership has elected to utilize the practical expedient of recognizing revenue as invoiced, also known as the “right to invoice” practical expedient. The new guidance also requires additional disclosures about the nature, amount, timing and uncertainty of revenue recognition and the related cash flows. Effective January 1, 2018, the new guidance was applied using the modified retrospective transition method, and did not result in any material differences in the amount and timing of revenue recognition. Refer to Note 6 - Revenues, for further information related to the impact of adopting the new guidance and the Partnership’s updated accounting policies related to revenue recognition from contracts with customers. 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 operations line items. This new guidance is effective January 1, 2019 with early adoption permitted. The Partnership has elected to early adopt this guidance and prospectively applied this guidance effective January 1, 2018. The application of this guidance did not have a material impact on its consolidated financial statements. Goodwill Impairment In January 2017, the FASB issued new guidance on simplifying the test for goodwill impairment by eliminating Step 2 of the impairment test, which is 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 with early adoption is permitted. The Partnership elected to adopt this guidance effective fourth quarter of 2018 as it simplifies the goodwill impairment test. The guidance was applied prospectively and used in its 2018 annual goodwill impairment testing. Future accounting changes Leases In February 2016, the FASB issued new guidance on the accounting for leases. The new guidance amends the definition of a lease such that, in order for an arrangement to qualify as a lease, the lessee is required 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. 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. Lessees will classify leases as finance or operating, with classification affecting the pattern of expense recognition in the statement of operations. The new guidance does not make extensive changes to lessor accounting. In January 2018, the FASB issued an optional practical expedient, to be applied upon transition, to omit the evaluation of land easements not previously accounted for as leases that existed or expired prior to the entity's adoption of the new lease guidance. An entity that elects this practical expedient is required to apply it consistently to all of its existing or expired land easements not previously accounted for as leases. The Partnership will apply this practical expedient upon transition to the new standard. The new guidance is effective January 1, 2019, with early adoption permitted. The Partnership will adopt the new standard on its effective date. A modified retrospective transition approach is required, applying the new standard to all leases existing at the date of initial application being January 1, 2019. In July 2018, the FASB issued a transition option allowing entities to not apply the new guidance, including disclosure requirements, to the comparative periods they present in their financial statements in the year of adoption. The Partnership will apply this transition option and use the effective date as the date of initial application. Consequently, financial information will not be updated and disclosures required under the new standard will not be provided for dates and periods before January 1, 2019. The Partnership will elect the package of practical expedients which permits entities not to reassess prior conclusions about lease identification, lease classification and initial direct costs under the rules of the new standard. The Partnership will elect all of the new standard’s available transition practical expedients. The Partnership believes that the primary effects of adoption will relate to the recognition of new ROU assets and lease liabilities on the Partnership’s balance sheet for its operating leases and new disclosures about the Partnership’s leasing activities. The guidance will not impact the Partnership’s income statement. The Partnership’s adoption of this guidance will not have a material impact on its consolidated financial statements. The new standard also provides practical expedients for a Partnership’s ongoing accounting. The Partnership will elect the short-term lease recognition exemption for all leases. This means, for those leases that qualify, the Partnership will not recognize ROU assets or lease liabilities. The Partnership will also elect the practical expedient to not separate lease and non-lease components for all leases for which the Partnership is the lessee. Measurement of credit losses on financial instruments In June 2016, the FASB issued new guidance that significantly changes how entities measure credit losses for most financial assets and certain other financial instruments that are not measured at fair value through net income (loss). The new guidance amends the impairment model of financial instruments basing it on expected losses rather than incurred losses. These expected credit losses will be recognized as an allowance rather than as a direct write down of the amortized cost basis. The new guidance is effective January 1, 2020 and will be applied using a modified retrospective approach. We are currently evaluating the impact of the adoption of this guidance and have not yet determined the effect on our consolidated financial statements. Fair Value Measurement In August 2018, the FASB issued new guidance that amends certain disclosure requirements for the fair value measurements as part of its disclosure framework project. This new guidance is effective January 1, 2020, however, early adoption of certain or all requirements is permitted. The Partnership is currently evaluating the impact of adoption of this guidance and has not yet determined the effect on its consolidated financial statements. Consolidation In October 2018, the FASB issued new guidance for determining whether fees paid to decision makers and service providers are variable interests for indirect interests held through related parties under common control. This new guidance is effective January 1, 2020, and will be applied on a retrospective basis. The Partnership is currently evaluating the timing and impact of adoption of this guidance.

GOODWILL AND REGULATORY

12 Months Ended

Dec. 31, 2018

GOODWILL AND REGULATORY

GOODWILL AND REGULATORY

NOTE 4 GOODWILL AND REGULATORY

In December 2016, FERC issued Docket No. PL17-1-000 which is an NOI Regarding the Commission’s Policy for Recovery of Income Tax Costs requesting initial comments regarding how to address any “double recovery” resulting from FERC’s current income tax allowance and rate of return policies that had been in effect since 2005.

Docket No. PL17-1-000 is a direct response to United Airlines, Inc., et al. v. FERC (United), a decision issued by the U.S. Court of Appeals for the District of Columbia Circuit in July 2016 in which the D.C. Circuit directed FERC to explain how a pass-through entity such as an MLP receiving a tax allowance and a return on equity derived from the discounted cash flow (DCF) methodology did not result in “double recovery” of taxes.

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 including a reduction of the U.S. federal corporate income tax rate. Under the 2017 Tax Act, we continue to be a non-taxable limited partnership for U.S. federal income tax purposes, and federal 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 with respect to U.S. federal income taxes as a result of the 2017 Tax Act.

On March 15, 2018, FERC issued the following: (1) the Revised Policy Statement, (2) the NOPR and (3) the NOI. On July 18, 2018, FERC issued (1) an Order on Rehearing and (2) a Final Rule adopting and revising procedures from, and clarifying aspects of, the NOPR. On November 15, 2018, FERC issued the Excess ADIT Policy Statement, addressing certain issues raised in the NOI issued on March 15, 2018. Each of the 2018 FERC Actions is further described below.

FERC Revised Policy Statement on Income Tax Allowance Cost Recovery in MLP Pipeline Rates

The Revised Policy Statement changes FERC’s long-standing policy allowing income tax amounts to be included in rates subject to cost-of-service rate regulation for pipelines owned by an MLP. The Revised Policy Statement creates a presumption that entities whose earnings are not taxed through a corporation should not be permitted to recover an income tax allowance in their regulated cost-of-service rates.

On July 18, 2018, FERC dismissed requests for rehearing and provided clarification of the Revised Policy Statement. In this Order on Rehearing, FERC noted that an MLP owned pipeline is not automatically precluded in a future proceeding from arguing and providing evidentiary support that it is entitled to an income tax allowance in its cost-of-service rates. Additionally, FERC provided guidance regarding ADIT for MLP pipelines and other pass through entities. FERC found that to the extent an entity’s income tax allowance should be eliminated from rates, it must also eliminate its existing ADIT balance from its rate base. As a result, the Revised Policy Statement also precludes the recognition and subsequent amortization of any related regulatory assets or liabilities that might have otherwise impacted rates charged to customers as the refund or collection of excess or deficient deferred income tax assets or liabilities.

Final Rule on FERC Rate Changes for Interstate Natural Gas Companies

The Final Rule established a schedule by which interstate pipelines must have either (i) filed a new uncontested rate settlement or (ii) filed a one-time report, called FERC Form No. 501-G, that quantified the rate impact of the 2017 Tax Act on FERC regulated pipelines and the impact of the Revised Policy Statement on pipelines held by MLPs. Pipelines filing the one-time report had four options:

Option 1: make a limited NGA Section 4 filing to reduce its rates by the reduction in its cost of service shown in its FERC Form No. 501-G. For any pipeline electing this option, FERC guaranteed a three-year moratorium on NGA Section 5 rate investigations if the pipeline’s FERC Form 501-G showed the pipeline’s estimated ROE as being 12 percent or less. Under the Final Rule and notwithstanding the Revised Policy Statement, a pipeline organized as an MLP is not required to eliminate its income tax allowance but, instead can reduce its rates to reflect the reduction in the maximum corporate tax rate. Alternatively, the MLP pipeline can eliminate its tax allowance, along with its ADIT used for rate-making purposes. In situations where the ADIT balance is a liability, this elimination would have the effect of increasing the pipeline’s rate base used for rate-making purposes;

Option 2: commit to file either a pre-packaged uncontested rate settlement or a general Section 4 rate case if it believed that using the limited Section 4 option would not result in just and reasonable rates. If the pipeline committed to file by December 31, 2018, FERC would not initiate a Section 5 investigation of its rates prior to that date;

Option 3: file a statement explaining its rationale for why it did not believe the pipeline's rates must change; and

Option 4: take no action. FERC would then consider whether to initiate a Section 5 investigation of any pipeline that had not submitted a limited Section 4 rate filing or committed to file a general Section 4 rate case.

NOI Regarding the Effect of the 2017 Tax Act on Commission-Jurisdictional Rates

In the NOI, FERC sought comments to determine what additional action as a result of the 2017 Tax Act, if any, was required by FERC related to the ADIT that were reserved in anticipation of being paid to the IRS, but which no longer accurately reflected the future income tax liability. The NOI also sought comments on the elimination of bonus depreciation for regulated natural gas pipelines and other effects of the 2017 Tax Act on regulated rates or earnings.

As noted above, FERC's Order on Rehearing provided guidance regarding ADIT for MLP pipelines, finding that if an MLP pipeline's income tax allowance is eliminated from its cost-of-service rates, then its existing ADIT balance used for rate-making purposes should also be eliminated from its cost-of-service rates.

As noted above, on November 15, 2018, FERC issued the Excess ADIT Policy Statement addressing certain (but not all) issues raised in the NOI. The Excess ADIT Policy Statement clarified the FERC accounts in which pipelines should record amortization of excess and/or deficient ADIT for accounting and rate-making purposes.

The Excess ADIT Policy Statement also addressed how to disclose reversals of ADIT account balances in FERC’s annual financial report filings. The policy statement also stated that, for those pipelines that continue to have an income tax allowance, excess/deficient ADIT associated with an asset that is sold or retired after December 31, 2017 must continue to be amortized in rates even after the sale or retirement of the asset.

Filings required by the Final Rule

Prior to the 2018 FERC Actions, the Partnership’s pipeline systems did not have a requirement to file or adjust their rates earlier than 2022 as a result of their existing rate settlements. However, several of our pipeline systems accelerated such adjustments as a result of the 2018 FERC Actions as summarized in the table below.


	Form 501-G Filing Option	Impact on Maximum Rates	Moratorium and Mandatory Filing Requirements and Other Considerations
Great Lakes	Option 1; accepted by FERC	2.0% rate reduction effective February 1, 2019	No moratorium in effect; comeback provision with new rates to be effective by October 1, 2022
GTN	Settlement approved by FERC on November 30, 2018 eliminating the requirement to file Form 501-G	A refund of $10 million to its firm customers in 2018; 10.0% rate reduction effective January 1, 2019; additional rate reduction of 6.6% effective January 1, 2020 through December 31, 2021; These reductions will replace the 8.3% rate reduction in 2020 agreed to as part of the last settlement in 2015	Moratorium on rate changes until December 31, 2021; comeback provision with new rates to be effective by January 1, 2022
Northern Border	Option 1; accepted by FERC	2.0% rate reduction effective February 1, 2019; proposed additional 2.0% rate reduction effective January 1, 2020	No moratorium in effect; comeback provision with new rates to be effective by July 1, 2024
Bison	Option 3	No rate change proposed	No moratorium or comeback provisions
Iroquois	Option 3; subsequently reached a settlement with customers and a notice of settlement-in-principle was filed with FERC on January 9, 2019.	Expected to reduce rates by the impact of the 2017 Tax Act as shown on Form 501-G	Likely to be reaffirmed with the settlement
PNGTS	Option 3; accepted by FERC	No rate change proposed	No moratorium or comeback provisions
North Baja	Option 1; accepted by FERC	10.8% rate reduction effective December 1, 2018	No moratorium or comeback provisions; approximately 90% of North Baja's contracts are negotiated; 10.8% reduction on maximum rate contracts only
Tuscarora	Option 1; subsequently reached a settlement with customers and a notice of settlement-in-principle was filed with FERC on January 29, 2019	Expected to be finalized with the settlement	Expected to be finalized with the settlement

Rate settlements

As noted in the above table, new rate settlements were entered into by GTN, Tuscarora and Iroquois to address the issues that came out of the 2018 FERC Actions. The terms of the settlements are outlined below:

GTN

On October 16, 2018, GTN filed a rate settlement with FERC to address the changes proposed by the 2018 FERC Actions within its rates via an amendment to its prior settlement in 2015. The 2018 GTN Settlement decreased GTN’s existing maximum transportation rates by 10 percent effective January 1, 2019 until December 31, 2019. The existing maximum rates will decrease by an additional 6.6 percent for the period January 1, 2020 through December 31, 2021. GTN is required to have new rates in effect on January 1, 2022. Furthermore, GTN and its customers have agreed upon a moratorium on further rate changes until December 31, 2021. The 2018 GTN Settlement will also reflect an elimination of tax allowance previously recovered in rates along with ADIT for rate-making purposes. The uncontested settlement, which was approved by FERC on November 30, 2018, relieved GTN of its obligation to file a Form 501-G.

As part of the 2018 GTN Settlement, GTN has also agreed to issue a refund of approximately $10 million allocated amongst firm customers from January 1, 2018 to October 31, 2018 (2018 GTN Rate Refund). As a result of this, the Partnership established a $10 million provision for this revenue sharing as an offset against revenue in the income statement. The corresponding refund liability was paid by GTN before December 31, 2018.

Tuscarora

On December 6, 2018, Tuscarora elected to make a limited NGA Section 4 filing to reduce its maximum rates by approximately 1.7 percent and eliminate its deferred income tax balances previously used for rate setting (Option 1). On January 29, 2019, Tuscarora notified FERC that it had reached a settlement-in-principle with its customers to address the changes proposed by the 2018 FERC Actions. Moratorium provisions and other terms such as comeback provisions are still being finalized but Tuscarora agreed to continue reducing its existing maximum system rates by 1.7 percent effective February 1, 2019 as noted in its limited NGA Section filing.

Iroquois

On December 6, 2018, Iroquois submitted its FERC Form No. 501-G in response to the FERC Final Rule along with an explanation as to why rate changes were not required (Option 3). On January 9, 2019, Iroquois notified FERC that it had reached a settlement-in-principle with its customers to address the changes proposed by the 2018 FERC Actions. Iroquois has agreed to reduce its existing maximum system rates by the impact of the 2017 Tax Act changes as shown in Iroquois’ Form 501-G filed with FERC.

Tuscarora Goodwill Impairment

As noted above, in the fourth quarter of 2018, Tuscarora initiated its regulatory approach in response to the 2018 FERC Actions, resulting in a reduction in its maximum rates. In connection with our annual goodwill impairment analysis, we evaluated Tuscarora’s future revenues as well as changes to other valuation assumptions responsive to Tuscarora’s commercial environment, which included estimates related to discount rates and earnings multiples. In doing so, we incorporated the expected impact of Tuscarora’s regulatory approach in response to the 2018 FERC Actions, in which it elected to make a limited NGA Section 4 filing to reduce its maximum rates and eliminate its deferred income tax balances previously used for rate setting. Additionally, we have considered in our overall conclusion the outcome of the January 2019 settlement-in-principle reached by Tuscarora with its customers.

Our analysis resulted in the estimated fair value of Tuscarora not exceeding its carrying value, including goodwill. The fair value was measured using a discounted cash flow approach whereby the expected cashflows were discounted using a risk adjusted discount rate to determine fair value.

As a result, we recorded a goodwill impairment charge amounting to $59 million against Tuscarora’s goodwill balance of $82 million. The impairment charge was recorded in the Impairment of goodwill line on the Consolidated statement of operations and reduced our total consolidated goodwill balance from $130 million to $71 million. There is a risk that adverse changes in our key assumptions could result in an additional future impairment on Tuscarora’s remaining goodwill of $23 million.

EQUITY INVESTMENTS

12 Months Ended

Dec. 31, 2018

PROPERTY, PLANT AND EQUIPMENT

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.


	Ownership
	Interest at		Equity Earnings (b)			Equity Investments
	December 31,		Year ended December 31			December 31
(millions of dollars)	2018		2018	2017	2016(c)	2018	2017
Northern Border(a)	50.00	%	68	67	69	497	512
Great Lakes	46.45	%	59	31	28	489	479
Iroquois	49.34	%	46	26	—	210	222
			173	124	97	1,196	1,213

^(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.

^(c)

Recast to eliminate equity earnings from PNGTS and consolidate PNGTS (Refer to Notes 2 and 8).

Distributions from Equity Investments

Distributions received from equity investments for the year ended December 31, 2018 were $198 million (2017 - $145 million; 2016 - $153 million) of which $10 million (2017 - $5 million and 2016 - 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 a subsidiary of ONEOK, Inc. TC PipeLines Intermediate Limited Partnership, as one of the general partners, may be exposed to the commitments and contingencies of Northern Border. The Partnership effectively holds a 100% percent 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, 2018, 2017 and 2016. At December 31, 2018 the Partnership had a $115 million (December 31, 2017 - $115 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.

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


December 31 (millions of dollars)	2018	2017

Assets
Cash and cash equivalents	10	14
Other current assets	36	36
Property, plant and equipment, net	1,037	1,063
Other assets	13	14
	1,096	1,127

Liabilities and Partners’ Equity
Current liabilities	34	38
Deferred credits and other	35	31
Long-term debt, net (a)	264	264
Partners’ equity
Partners’ capital	764	795
Accumulated other comprehensive loss	(1)	(1)
	1,096	1,127


Year ended December 31 (millions of dollars)	2018	2017	2016

Transmission revenues	289	291	292
Operating expenses	(78)	(78)	(72)
Depreciation	(60)	(59)	(59)
Financial charges and other	(15)	(18)	(21)
Net income	136	136	140

^(a)

No current maturities as of December 31, 2018 or 2017.

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 effectively holds a 100 percent partnership interest in TC GL Intermediate Limited Partnership.

The Partnership recorded no undistributed earnings from Great Lakes for the years ended December 31, 2018, 2017, and 2016.

The Partnership made equity contributions to Great Lakes of $4 million and $5 million in the first and fourth quarter of 2018, 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.

At December 31, 2018, the equity method goodwill balance related to Great Lakes amounted to $260 million (December 31, 2017 - $260 million). The equity method goodwill relates to the Partnership’s February 2007 acquisition of a 46.45 percent general partner interest in Great Lakes and is the difference between the carrying value of our investment in Great Lakes and the underlying equity in Great Lakes’ net assets.

During the fourth quarter of 2018, Great Lakes finalized its regulatory approach in response to the 2018 FERC Actions and elected to make a limited NGA section 4 filing with FERC to reduce its maximum rates and eliminate its tax allowance and deferred income tax balances previously used for rate setting. As a result of this action, and because the estimated fair value of our investment in Great Lakes exceeded its carrying value by less than 10 percent in its 2017 valuation, we performed a quantitative test to determine if there was other than temporary decline in Great Lakes’ fair value. At December 31, 2018, the estimation of the fair value of our remaining equity investment in Great Lakes was completed and we concluded the fair value of our investment exceeded its current carrying value by more than 10 percent.

The assumptions we used in the analysis related to the estimated fair value of our equity investment in Great Lakes included expected results from its limited NGA Section 4 filing, revenue opportunities on the system as well as changes to other valuation assumptions responsive to Great Lakes’ commercial environment, which includes estimates related to discount rates and earnings multiples. Although our analysis indicated that evolving market conditions and other factors relevant to Great Lakes’ long-term financial performance have been positive, there is a risk that reductions in future cash flow forecasts or adverse changes in other key assumptions could result in an impairment of the carrying value of our investment in Great Lakes.

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


December 31 (millions of dollars)	2018	2017

Assets
Current assets	75	107
Property, plant and equipment, net	689	701
	764	808

Liabilities and Partners’ Equity
Current liabilities	26	75
Long-term debt, net (a)	240	259
Other long-term liabilities	4	1
Partners’ equity	494	473
	764	808


Year ended December 31 (millions of dollars)	2018	2017	2016

Transmission revenues	246	181	179
Operating expenses	(68)	(66)	(69)
Depreciation	(32)	(29)	(28)
Financial charges and other	(18)	(20)	(21)
Net income	128	66	61

^(a)

Includes current maturities of $21 million as of December 31, 2018 (December 31, 2017 - $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, 2018, The Partnership received distributions from Iroquois amounting to $56 million (2017 - $27 million) which includes the Partnership’s 49.34 percent share of the Iroquois unrestricted cash distribution amounting to approximately $10 million (2017 - $5 million) (Refer to Note 8). 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 year ended December 31, 2018 and for the period from June 1, 2017, acquisition date, through December 31, 2017. At December 31, 2018 and 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, 2018 is as follows:


December 31 (millions of dollars)	2018	2017

ASSETS
Cash and cash equivalents	80	86
Other current assets	32	36
Property, plant and equipment, net	581	591
Other assets	8	8
	701	721

LIABILITIES AND PARTNERS’ EQUITY
Current liabilities	19	17
Net long-term debt, net (a)	325	329
Other non-current liabilities	14	9
Partners’ equity	343	366
	701	721


		Period of 7 months
	Year ended	ended December 31,
(millions of dollars)	December 31, 2018	2017
Transmission revenues	194	110
Operating expenses	(57)	(32)
Depreciation	(29)	(17)
Financial charges and other	(14)	(9)
Net income	94	52

^(a)

Includes current maturities of $146 million as of December 31, 2018 (December 31, 2017 - $4 million).

REVENUES	12 Months Ended
REVENUES	Dec. 31, 2018
REVENUES
REVENUES	NOTE 6 REVENUES On January 1, 2018, the Partnership adopted new FASB guidance on revenue from contracts with customers using the modified retrospective transition method for all contracts that were in effect on the date of adoption. The reported results for all periods in 2018 reflect the application of the new guidance, while the reported results for all periods in 2017 and 2016 were prepared under previous revenue recognition guidance which is referred to herein as "legacy U.S. GAAP". Disaggregation of Revenues For the year ended December 31, 2018, virtually all of the Partnership’s revenues were from capacity arrangements and transportation contracts with customers as discussed under Note 2 - Significant Accounting Policies. During the fourth quarter of 2018, Bison received an unsolicited offer from Tenaska regarding the termination of its contract. Also during 2018, through a Permanent Capacity Release Agreement, Tenaska assumed Anadarko’s ship-or-pay contract obligation on Bison, which was the largest contract on Bison. Bison and Tenaska mutually agreed to terms which included a non-refundable payment to Bison of $95.4 million in December 2018 in exchange for the termination of all its contract obligations with Bison. Following the amendment of its tariff to enable this transaction, another customer executed a similar agreement to terminate its contract on Bison in exchange for a non-refundable payment to Bison of approximately $2.0 million in December 2018. At the termination of the contracts, Bison was released from performing any future services with the two customers and as such, the amounts received were recorded in revenue in 2018. Accordingly, the Partnership considers the $97 million received as a result of the contract terminations as revenue from capacity and transportation contracts with customers and therefore no further disaggregation of revenue is needed (See also related discussion under Note 7 - Plant Property and Equipment). As noted under Note 2 - Significant Accounting Policies, a portion of our revenues collected may be subject to refund when a rate proceeding is ongoing or as part of a rate case settlement with customers. We use our best estimate based on the facts and circumstances of the proceeding to provide for allowances for these potential refunds in the revenue we recognized. Accordingly, as part of the 2018 GTN Settlement, we have issued the 2018 GTN Rate Refund and recognized a $10 million offset against revenue in the income statement (See also Note 4 for more information). Financial Statement Impact of Adopting Revenue from Contracts with Customers The Partnership adopted the new guidance using the modified retrospective transition method. As a practical expedient under this transition method, the Partnership is not required to analyze completed contracts at the date of adoption. The adoption of the new guidance did not have a material impact on the Partnership’s previously reported consolidated financial statements at December 31, 2017. Pro-forma Financial Statements under Legacy U.S. GAAP At December 31, 2018, had legacy U.S. GAAP been applied, there would be no change in the Partnership’s reported balance sheet and income statement line items. Contract Balances All of the Partnership’s contract balances pertain to receivable from contracts with customers amounting to $44 million at December 31, 2018 and $40 million at January 1, 2018 and are both recorded as Trade accounts receivable and reported as Accounts receivable and other in the Partnership’s Consolidated Balance Sheet (Refer to Note 21). Additionally, our accounts receivable represents the Partnership’s unconditional right to recognize revenue for services completed which includes billed and unbilled accounts. Future revenue from remaining performance obligations When the right to invoice practical expedient is applied, the guidance does not require disclosure of information related to future revenue from remaining performance obligations therefore no additional disclosure is required. Additionally, in the application of the right to invoice practical expedient, the Partnership’s revenues from regulated capacity arrangements are recognized based on rates specified in the contract. Therefore, the amount invoiced, which includes the capacity contracted and variable volume of natural gas transported, corresponds directly to the value the customer received. These revenues are recognized on a monthly basis once the Partnership’s performance obligation to provide capacity has been satisfied.

PROPERTY, PLANT AND EQUIPMENT

12 Months Ended

Dec. 31, 2018

PROPERTY, PLANT AND EQUIPMENT

NOTE 7 PROPERTY, PLANT AND EQUIPMENT

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


	2018				2017
			Accumulated	Net Book			Accumulated	Net Book
December 31 (millions of dollars)	Cost		Depreciation	Value	Cost		Depreciation	Value
Pipeline	1,901	-	(876)	1,025	2,577	-	(962)	1,615
Compression	550	-	(182)	368	533	-	(165)	368
Metering and other	176	-	(52)	124	182	-	(54)	128
Construction in progress	12	-	—	12	12	-	—	12
	2,639	-	(1,110)	1,529	3,304	-	(1,181)	2,123

Impairment of Bison’s long-lived assets

With the advanced payments to Bison and related cancellation of certain customer transportation contracts as noted under Note 6-Revenues, Bison’s future revenue will be reduced by approximately $47 million per year in both 2019 and 2020. Additionally, natural gas is currently not flowing on Bison as a result of the relative cost advantage of WCSB - and Bakken - sourced gas versus Rockies production. Since its inception in January 2011, Bison has not experienced a decrease in its revenue as its original ten-year contracts included ship-or-pay terms that resulted in payment to Bison regardless of gas flows. The customer contract cancellations coupled with the persistence of unfavorable market conditions which have inhibited system flows have prompted management to re-evaluate the carrying value of Bison’s long-lived assets.

Although the Partnership continues to evaluate alternatives for recontracting or redevelopment of Bison, management is currently unable to quantify the future cash flows of a viable, operating plan beyond the remaining customer contracts’ expiry in January 2021, and accordingly the Partnership evaluated for impairment the carrying value of its property, plant and equipment on Bison at December 31, 2018. The Partnership will continue to maintain Bison to stand ready for redevelopment and has concluded that the remaining obligations of Bison, primarily in the form of ad valorem tax obligations and operating and maintenance costs, exceed the net cash inflows that management currently considers probable and estimable.

Based on these factors, during the fourth quarter of 2018, the Partnership recognized an impairment charge of $537 million relating to the remaining carrying value of Bison’s property, plant and equipment after determining that it was no longer recoverable. The impairment charge was recorded under Impairment of long-lived assets line on the Consolidated statement of operations.

ACQUISITIONS

12 Months Ended

Dec. 31, 2018

DEBT AND CREDIT FACILITIES

ACQUISITIONS

NOTE 8 ACQUISITIONS

2017 Acquisition

On June 1, 2017, the Partnership acquired from subsidiaries of TransCanada a 49.34 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, which expired on January 3, 2019. 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 9) 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 of this acquisition transaction. The Partnership is expected to receive the $28.4 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 21, 2019, the Partnership has received approximately $18.1 million of the expected $28.4 million, of which $2.6 million was received as of February 21, 2019 (Refer to Note 25), 10.3 million in 2018 and 5.2 million in 2017.

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 2016 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.

DEBT AND CREDIT FACILITIES

12 Months Ended

Dec. 31, 2018

DEBT AND CREDIT FACILITIES

NOTE 9 DEBT AND CREDIT FACILITIES


		Weighted Average					Weighted Average
		Interest Rate for the					Interest Rate for the
		Year Ended					Year Ended
(millions of dollars)	2018	December 31, 2018			2017		December 31, 2017
TC PipeLines, LP
Senior Credit Facility due 2021	40	3.14	%		185		2.41	%
2013 Term Loan Facility due 2022	500	3.23	%		500		2.33	%
2015 Term Loan Facility due 2020	—	—			170		2.22	%
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)	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	35	2.93	%		55		2.02	%
PNGTS
Revolving Credit Facility due 2023	19	3.55	%		—		—
5.90% Senior Secured Notes due 2018	—	—			30		5.90	%	(a)
Tuscarora
Unsecured Term Loan due 2020	24	3.10	%		25		2.27	%
North Baja
Unsecured Term Loan due 2021	50	3.54	%		—		—
	2,118				2,415
Less:unamortized debt issuance costs and debt discount	10				12
Less: current portion	36				51	(b)
	2,072				2,352

^(a)

Fixed interest rate.

^(b)

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 $40 million was outstanding at December 31, 2018 (December 31, 2017 - $185 million), leaving $460 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 3.77 percent at December 31, 2018 (December 31, 2017 – 2.62 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 a dropdown transaction with TransCanada in 2013, 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 U.S. 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, 2018, 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 3.26 percent (2017 - 2.31 percent). Prior to hedging activities, the LIBOR-based interest rate was 3.60 percent at December 31, 2018 (December 31, 2017 – 2.62 percent).

In December 2018, the Partnership fully repaid its 2015 Term Loan Facility using proceeds primarily from Bison’s early contract termination with two of its customers (Refer to Notes 6 and 17) and available cash.

The Senior Credit Facility and the 2013 Term Loan 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 3.12 to 1.00 as of December 31, 2018.

The Senior Credit Facility and the 2013 Term Loan Facility 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 2013 Term Loan Facility may become immediately due and payable.

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

PNGTS

On April 5, 2018, PNGTS entered into a revolving credit agreement under which PNGTS has the ability to borrow up to $125 million with a variable interest rate based on LIBOR. The credit agreement matures on April 5, 2023 and requires PNGTS to maintain a leverage ratio not greater than 5.00 to 1.00. The leverage ratio was 0.35 to 1.00 as of December 31, 2018. The facility is utilized primarily to fund the costs of the PXP expansion project and to finance PNGTS’ other funding needs. As of December 31, 2018, $19 million was drawn on the Revolving Credit Facility and the LIBOR-based interest rate was 3.60 percent.

GTN

On June 1, 2015, GTN entered into a $75 million unsecured variable rate term loan facility (GTN 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 GTN Unsecured Term Loan Facility was 3.30 percent at December 31, 2018 (December 31, 2017 – 2.31 percent). GTN’s Unsecured Senior Notes, along with the GTN Unsecured Term 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, 2018 is 42.8 percent.

Tuscarora

On August 21, 2017, Tuscarora refinanced all of its outstanding debt by amending its existing Unsecured Term Loan Facility (Tuscarora 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. The Tuscarora 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, 2018, the ratio was 10.29 to 1.00.

The LIBOR-based interest rate on the Tuscarora Unsecured Term Loan Facility was 3.47 percent at December 31, 2018 (December 31, 2017 —2.49 percent).

North Baja

On December 19, 2018, North Baja entered into a $50 million unsecured variable rate term loan facility, which matures on December 19, 2021. The net proceeds were used for general partnership purposes. The variable interest rate is based on LIBOR plus an applicable margin. The LIBOR-based interest rate on this term loan facility was 3.54 percent at December 31, 2018. North Baja’s Term Loan Facility contains a covenant that limits total debt to no greater than 70 percent of North Baja’s total capitalization. North Baja’s total debt to total capitalization ratio at December 31, 2018 is 37.7 percent.

Partnership (TC PipeLines, LP and its subsidiaries)

At December 31, 2018, 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)
2019		36
2020		123
2021		440
2022		500
2023		19
Thereafter		1,000
		2,118

OTHER LIABILITIES

12 Months Ended

Dec. 31, 2018

OTHER LIABILITIES

OTHER LIABILITIES

NOTE 10 OTHER LIABILITIES


December 31 (millions of dollars)	2018	2017

Regulatory liabilities	27	26
Other liabilities	2	3
	29	29

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 on 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, 2018
PARTNERS' EQUITY
PARTNERS' EQUITY	NOTE 11 PARTNERS’ EQUITY At December 31, 2018, the Partnership had 71,306,396 common units outstanding, of which 54,221,565 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 a 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 2018, the Partnership issued 0.7 million common units under the ATM Program generating net proceeds of approximately $39 million, plus an additional $1 million from the General Partner to maintain its effective two percent interest. The commissions to our sales agents were nil. The net proceeds were used to repay a portion of the borrowings under the Senior Credit Facility and for general partnership purposes. 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. 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. 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, the amount associated with these rights was reclassified back to partners’ equity. At December 31, 2018, there were no outstanding common units subject to rescission on the Partnership’s consolidated balance sheet. Issuance of Class B units The Class B Units issued on April 1, 2015 to finance a portion of the Partnership’s acquisition of the remaining 30 percent interest from TransCanada represent a limited partner interest in us and entitle TransCanada to an annual distribution based on 30 percent of GTN’s annual distributions as follows: (i) 100 percent of distributions above $20 million through March 31, 2020; and (ii) 25 percent of distributions above $20 million thereafter . 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. Additionally, the Class B Distribution was reduced by 35 percent, which is equivalent to the percentage by which distributions payable to the common units were reduced in 2018. The Class B Reduction was implemented during the first quarter of 2018 following the Partnership’s common unit distribution reduction of 35 percent from its fourth quarter 2017 distribution level per common unit. The Class B Reduction will continue to apply for any particular calendar year until distributions payable in respect of common units for such calendar year equal or exceed $3.94 per common unit. The Class B units’ equity account is increased by the “Class B Distribution”, less the “Class B Reduction”, if any until such amount is declared for distribution and paid every first quarter of the subsequent year. For the years ended December 31, 2018, 2017 and 2016, the Class B units’ equity account was increased by $13 million, $15 million and $22 million, respectively. (Refer to Notes 14 and 15).

ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)

12 Months Ended

Dec. 31, 2018

ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)

ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)

NOTE 12 ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)

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


	Cash flow	Equity
(millions of dollars)	hedges	Investments	Total
Balance at December 31, 2015(a)	(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 20)(a)	1	—	1
Net other comprehensive income (a)	2	—	2
Balance at December 31, 2016(a)	(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 20)	1	—	1
Other comprehensive income - effects of Iroquois' retirement benefit plans	—	1	1
Net other comprehensive income	6	1	7
Balance at December 31, 2017	4	1	5
Change in fair value of cash flow hedges	(2)	—	(2)
Amounts reclassified from AOCI	5	—	5
PNGTS’ amortization of realized loss on derivative instrument (Note 20)	1	—	1
Other comprehensive income (loss) - effects of Iroquois’ retirement benefit plans	—	(1)	(1)
Net other comprehensive income (loss)	4	(1)	3
Balance as of December 31, 2018	8	—	8

^(a)

Recast to consolidate PNGTS (Refer to in Notes 2 and 8). Additionally, AOCI as presented here is net of non-controlling interest on PNGTS.

FINANCIAL CHARGES AND OTHER

12 Months Ended

Dec. 31, 2018

FINANCIAL CHARGES AND OTHER

FINANCIAL CHARGES AND OTHER

NOTE 13 FINANCIAL CHARGES AND OTHER


Year ended December 31 (millions of dollars)	2018	2017	2016(a)

Interest expense (b)	95	83	69
Net realized loss related to the interest rate swaps	(2)	—	3
PNGTS' amortization of realized loss on derivative instrument (Note 20)	1	1	1
Other	(2)	(2)	(2)
	92	82	71

^(a)

Recast to consolidate PNGTS (Refer to Notes 2 and 8).

^(b)

Interest expense includes amortization of debt issuance costs and discount costs.

NET INCOME (LOSS) PER COMMON UNIT

12 Months Ended

Dec. 31, 2018

NET INCOME (LOSS) PER COMMON UNIT

NET INCOME (LOSS) PER COMMON UNIT

NOTE 14 NET INCOME (LOSS) 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 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 15).

The amount allocable to the Class B units is based upon 30 percent of GTN’s distributable cash flow during the year ended December 31, 2018 after certain annual thresholds and adjustments (Refer to Note 11).

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


(millions of dollars, except per common unit amounts)	2018		2017		2016

Net income (loss) attributable to controlling interests (a)		(182)		252		248
Net income attributable to PNGTS' former parent (a)(b)		—		(2)		(4)
Net income (loss) allocable to General Partner and Limited Partners		(182)		250		244
Incentive distributions attributable to the General Partner (c)		—		(12)		(7)
Net income attributable to the Class B units (d)		(13)		(15)		(22)
Net income (loss) allocable to the General Partner and common units		(195)		223		215
Net (income) loss allocable to the General Partner's two percent interest		4		(4)		(4)
Net income (loss) attributable to common units		(191)		219		211
Weighted average common units outstanding (millions) – basic and diluted		71.3		69.2		65.7	(e)
Net income (loss) per common unit – basic and diluted(f)	$	(2.68)	$	3.16	$	3.21

^(a)

Recast to consolidate PNGTS in 2016 (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 11, 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 and Class B Reduction. 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 distribution in an amount equal to 30 percent of GTN’s total distributable cash flows during the year ended December 31, 2018 less the threshold level of $20 million (2017 and 2016 - less $20 million) and less the Class B Reduction. The Class B Reduction did not apply during 2017 and 2016. During the year ended December 31, 2018, 30 percent of GTN’s total distributable cash flow was $40 million. After applying the $20 million annual threshold and the Class B Reduction of $7 million, $13 million of net income attributable to controlling interests was allocated to the Class B units at December 31, 2018 (2017 - $15 million; 2016 - $22 million).

^(e)

Includes the common units subject to rescission. These units are treated as outstanding for financial reporting purposes (Refer to Note 11).

^(f)

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

CASH DISTRIBUTIONS

12 Months Ended

Dec. 31, 2018

CASH DISTRIBUTIONS

CASH DISTRIBUTIONS

NOTE 15 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 after providing for Class B distributions based on the specified target distribution levels. The percentage interests set forth below for our General Partner include its IDRs and effective two percent general partner interest through December 31, 2018 and two percent general partner interest thereafter and assume our General Partner has contributed any additional capital necessary to maintain its two percent general partner interest. The percentage interest distributions to the General Partner illustrated below that are in excess of its two percent general partner interest represent the IDRs.


		Marginal Percentage
		Interest in Distribution
	Total Quarterly Distribution	Common		General
	Per Unit Target Amount	Unitholders		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
		Per Unit		Common		Class B						Total Cash
Declaration Date	Payment Date	Distribution		Units		Units (b)		2%		IDRs (a)		Distribution
1/21/2016	2/12/2016	$	0.89	$	57	$	12	$	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	$	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	2/13/2018	$	1.00	$	71	$	15	$	2	$	3	$	91
5/1/2018	5/15/2018	$	0.65	$	46	$	—	$	1	$	—	$	47
7/26/2018	8/15/2018	$	0.65	$	46	$	—	$	1	$	—	$	47
10/23/2018	11/14/2018	$	0.65	$	46	$	—	$	1	$	—	$	47
1/22/2019 (c)	2/11/2019 (c)	$	0.65	$	46	$	13	$	1	$	—	$	60

^(a)

The distributions paid during the year ended December 31, 2018 included incentive distributions to the General Partner of $3 million (2017 - $10 million, 2016 - $6 million).

^(b)

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 and adjustments (refer to Note 11)

^(c)

On February 11, 2019, we paid a cash distribution of $0.65 per unit on our outstanding common units to unitholders of record at the close of business on February 1, 2019 (refer to Note 25).

CHANGE IN OPERATING WORKING CAPITAL

12 Months Ended

Dec. 31, 2018

CHANGE IN OPERATING WORKING CAPITAL

CHANGE IN OPERATING WORKING CAPITAL

NOTE 16 CHANGE IN OPERATING WORKING CAPITAL


Year Ended December 31 (millions of dollars)	2018	2017	2016(b)
Change in accounts receivable and other	(6)	4	(4)
Change in other current assets	(1)	2	(4)
Change in accounts payable and accrued liabilities (a)	3	(7)	5
Change in accounts payable to affiliates	1	(3)	—
Change in accrued interest	—	2	2
Change in operating working capital	(3)	(2)	(1)

^(a)

Excludes certain non-cash items primarily related to capital accruals and dropdown costs.

^(b)

Recast to consolidate PNGTS (Refer to Notes 2 and 8).

TRANSACTIONS WITH MAJOR CUSTOMERS

12 Months Ended

Dec. 31, 2018

TRANSACTIONS WITH MAJOR CUSTOMERS

TRANSACTIONS WITH MAJOR CUSTOMERS

NOTE 17 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 revenues for the years ended December 31, 2018, 2017 and 2016:


Year Ended December 31 (millions of dollars)	2018		2017		2016
Anadarko/Tenaska customer group (d)	144	(d)	48		48
Pacific Gas (c)	32	(a)(b)	33	(a)(b)	36

At December 31, 2018 and 2017, Anadarko owed the Partnership approximately $4 million, which is approximately 10 percent of our consolidated trade accounts receivable (Refer to Note 2).

^(a)

Less than 10 percent of trade accounts receivable

^(b)

Less than 10 percent of consolidated revenue

^(c)

On January 29, 2019, GTN’s largest customer, Pacific Gas, filed for Chapter 11 bankruptcy protection. The Partnership’s accounts receivable from Pacific Gas at December 31, 2018 has been collected and for the year ended December 31, 2018, Pacific Gas accounted for approximately 6 percent of Partnership’s consolidated revenue.

^(d)

As noted under Note 6, Tenaska assumed Anadarko’s ship-or-pay contract obligation on Bison. After assuming the transportation obligation, Bison accepted an offer from Tenaska to buy out its contract. For the year ended December 31, 2018, the amount reported here are both revenues from Anadarko and Tenaska since the revenue earned by the Partnership from these customers are essentially coming from the same contract.

RELATED PARTY TRANSACTIONS

12 Months Ended

Dec. 31, 2018

RELATED PARTY TRANSACTIONS

RELATED PARTY TRANSACTIONS

NOTE 18 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, 2018 (2017 - $4 million, 2016 - $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, 2018, 2017 and 2016 by TransCanada’s subsidiaries and amounts payable to TransCanada’s subsidiaries at December 31, 2018 and 2017 are summarized in the following tables:


Year ended December 31 (millions of dollars)	2018	2017	2016
Capital and operating costs charged by TransCanada’s subsidiaries to:
Great Lakes (a)	44	36	30
Northern Border(a)	36	43	32
PNGTS (a)(b)	9	9	8
GTN	34	34	27
Bison	6	6	2
North Baja	4	4	4
Tuscarora	4	4	5
Impact on the Partnership’s net income attributable to controlling interests:
Great Lakes	19	15	13
Northern Border	16	16	12
PNGTS (b)	5	5	5
GTN	28	29	24
Bison	6	6	3
North Baja	4	4	4
Tuscarora	4	4	4


December 31 (millions of dollars)	2018	2017
Amount payable to TransCanada’s subsidiaries for costs charged in the year by:
Great Lakes (a)	3	3
Northern Border(a)	3	4
PNGTS (a)	1	1
GTN	4	3
Bison	1	1
North Baja	—	—
Tuscarora	1	—

^(a)

Represents 100 percent of the costs.

^(b)

Recast to consolidate PNGTS for the year ended December 31, 2016 (Refer to Note 2).

Great Lakes

Great Lakes earns significant transportation revenues from TransCanada and its affiliates, some of which are provided at discounted rates, negotiated rates and some at maximum rates. For the year ended December 31, 2018, Great Lakes earned 73 percent of its transportation revenues from TransCanada and its affiliates (2017 -- 57 percent; 2016 -- 68 percent). Additionally, included in Great Lakes’ other revenues were cost recovery charges to its affiliates for use of office space in the building it owns and is less than one percent of its total revenues in 2018 (2017 – 1 percent; 2016 – 1 percent).

At December 31, 2018, $18 million was included in Great Lakes’ receivables in regards to the transportation contracts with TransCanada and its affiliates (December 31, 2017 – $20 million).

During 2017, Great Lakes operated under a FERC approved 2013 rate settlement that included a revenue sharing mechanism that required Great Lakes to share with its customers certain percentages of any qualifying revenues earned above certain ROEs. During the second quarter of 2018, the refund was settled with its customers and a significant portion of the refund was with its affiliates. Under the terms of the 2017 Great Lakes Settlement, beginning in 2018, the revenue sharing was eliminated.

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, 2018 and 2017, Great Lakes had outstanding receivables from this arrangement amounting to $36 million and $64 million, respectively.

Great Lakes has a long-term transportation agreement with TransCanada’s Canadian Mainline that commenced on November 1, 2017 for a ten-year period and allows TransCanada to transport up to 0.711 billion cubic feet of natural gas per day on the Great Lakes system. This contract, which contains volume reduction options up to full contract quantity beginning in year three, was a direct benefit from TransCanada’s long-term fixed price service on its Canadian Mainline that was launched in 2017. For the year ended December 31, 2018 and 2017, the total revenue earned by Great Lakes on this contract was $76 million and $13 million, respectively.

During the second quarter of 2018, Great Lakes reached an agreement on the terms of new long-term transportation capacity contracts with its affiliate, ANR Pipeline Company. The contracts are for a term of 15 years from November 2021 to October 31, 2036 with a total contract value of approximately $1.3 billion. The contracts contain reduction options (i) at any time on or before April 1, 2019 for any reason and (ii) any time before April 2021, if TransCanada is not able to secure the required regulatory approval related to anticipated expansion projects.

PNGTS

For the years ended December 31, 2018, 2017 and 2016, PNGTS provided transportation services to a related party. Revenues from TransCanada Energy Ltd., a subsidiary of TransCanada, for 2018, 2017 and 2016 were approximately $1 million, $1 million and $2 million, respectively. At December 31, 2018, PNGTS had nil outstanding receivables from TransCanada Energy Ltd. in the consolidated balance sheets (December 31, 2017 – nil).

In connection with anticipated future commercial opportunities, PNGTS has entered into an arrangement with its affiliates regarding the construction of certain facilities on their systems that will be required to fulfill future contracts on the PNGTS’ system. In the event the anticipated developments do not proceed, PNGTS will be required to reimburse its affiliates for any costs incurred related to the development of these facilities. As of December 31, 2018, the total costs incurred by these affiliates was approximately $47 million (December 31, 2017 - $3 million).

QUARTERLY FINANCIAL DATA (unaudited)

12 Months Ended

Dec. 31, 2018

QUARTERLY FINANCIAL DATA (unaudited)

QUARTERLY FINANCIAL DATA (unaudited)

NOTE 19 QUARTERLY FINANCIAL DATA (unaudited)

The following sets forth selected unaudited financial data for the four quarters in 2018 and 2017:


Quarter ended (millions of dollars except per common unit amounts)	Mar 31		Jun 30		Sept 30			Dec 31
2018
Transmission revenues		115		111		103	(b)		220	(c)
Equity earnings		59		36		34			44
Net income (loss)		102		75		65			(406)
Net income (loss) attributable to controlling interests		96		73		62			(413)
Net income (loss) per common unit	$	1.32	$	1.00	$	0.79		$	(5.80)
Cash distributions paid to common units (a)		76		47		47			47
Cash distribution paid to Class B units		15		—		—			—
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 distributions paid to common units(a)		68		68		74			74
Cash distribution paid to Class B units		22		—		—			—

^(a)

Distributions paid to common units includes our general partner’s two percent share and IDRs.

^(b)

Net of a $9 million provision for revenue sharing recognized as part of the 2018 GTN Settlement, in which GTN agreed to issue a refund of $10 million allocated amongst its firm customers from January 1, 2018 to October 1, 2018 (Refer to Note 4).

^(c)

Net of a $1 million provision for revenue sharing recognized as part of the 2018 GTN Settlement, in which GTN agreed to issue a refund of $10 million allocated amongst its firm customers from January 1, 2018 to October 1, 2018 (Refer to Note 4). This amount also includes the $97 million proceeds received by Bison from the termination of certain customer contracts (Refer to Note 6).

FAIR VALUE MEASUREMENTS

12 Months Ended

Dec. 31, 2018

FAIR VALUE MEASUREMENTS

FAIR VALUE MEASUREMENTS

NOTE 20 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 are classified as Level 1 in fair value hierarchy. Accordingly, the carrying values 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 as a Level 2 of the fair value hierarchy for fair value disclosure purposes. Interest rate derivative assets and liabilities are classified as a 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, 2018 and December 31, 2017 was $2,101 million and $2,475 million, respectively.

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

The Partnership’s interest rate swaps are structured such that the cash flows of the derivative instruments match those of the variable rate of interest on the 2013 Term Loan Facility. From January 1 to June 30, 2018, the Partnership hedged interest payments on the variable-rate 2013 Term Loan Facility with interest rate swaps at a weighted average fixed interest rate of 2.31 percent. Beginning July 1, 2018 and until its October 2, 2022 maturity, the 2013 Term Loan Facility was hedged using forward starting interest rate swaps at an average rate of 3.26 percent.

At December 31, 2018, the fair value of the interest rate swaps accounted for as cash flow hedges was an asset of $8 million (on both gross and net basis). 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). The change in fair value of interest rate derivative instruments recognized in other comprehensive income was a loss of $2 million for the year ended December 31, 2018 (2017 – gain of $5 million and 2016 – gain of $3 million). During the year ended December 31, 2018, the amount reclassified from other comprehensive income to net income was a gain of $5 million (2017 – nil and 2016 – loss of $2 million). In 2018, the net realized gain related to the interest rate swaps was $2 million, and was included in financial charges and other (2017 – nil, 2016 – gain of $3 million). Refer to Note 13 -- Financial Charges and Other.

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 no effect on the consolidated balance sheet as of December 31, 2018 and 2017.

In anticipation of a debt refinancing in 2003, PNGTS entered into forward interest rate swap agreements to hedge the interest rate on its 5.90 % 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. At December 31, 2018, and as a result of the repayment of the 5.90% Senior Secured Notes, the remaining balance of the $20.9 million realized loss in AOCI included in other comprehensive income at the termination date was fully amortized against earnings. For the years ended December 31, 2018, 2017 and 2016, our 61.71 percent proportionate share of the amortization of realized loss on derivative instruments was $1 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, 2018, we had not incurred any significant credit losses and had no significant amounts past due or impaired. At December 31, 2018, we had a credit risk concentration on one of our customers and the amount owed is approximately 10 percent of our trade accounts receivable and consolidated revenues (refer also to Note 17 for more details).

The estimated fair value measurements on Tuscarora’s goodwill, Bison’s long-lived assets and our equity investment in Great Lakes, are classified as Level 3. In the determination of fair value utilized in the recoverability assessments for the respective assets, 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 Notes 4 (Tuscarora), 5 (Great Lakes) and 7 (Bison).

ACCOUNTS RECEIVABLE AND OTHER

12 Months Ended

Dec. 31, 2018

ACCOUNTS RECEIVABLE AND OTHER

ACCOUNTS RECEIVABLE AND OTHER

NOTE 21 ACCOUNTS RECEIVABLE AND OTHER


December 31 (millions of dollars)	2018	2017
Trade accounts receivable, net of allowance of nil	44	40
Imbalance receivable from affiliates	2	1
Other	2	1
	48	42

CONTINGENCIES	12 Months Ended
CONTINGENCIES	Dec. 31, 2018
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. -- In 2009, Great Lakes filed suit in the U.S. District Court, District of Minnesota, against Essar Steel 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. Following Great Lakes’ several unsuccessful attempts at recovering the payments through the U.S. federal court system, Essar Minnesota subsequently filed for bankruptcy in July 2016 and a performance bond was released into the bankruptcy court proceedings. In 2017, after Great Lakes came to an agreement with creditors on an allowed claim, the bankruptcy court approved Great Lakes’ claim in the amount of $31.5 million. The Foreign Essar Affiliates have not filed for bankruptcy and the case against the Foreign Essar Affiliates in Minnesota state court remains pending. At December 31, 2018, Great Lakes’ is unable to estimate the timing or the extent to which its claims in bankruptcy and state court will be recoverable, therefore, it did not recognize any gain contingency on its outstanding claim against Essar and the Essar Foreign Affiliates. Additionally, Great Lakes has concluded that the future recovery on this claim is remote. Additionally, at December 31, 2018, the Partnership is not aware of any contingent liabilities that would have a material adverse effect on the Partnership’s financial condition, results of operations or cash flows.

VARIABLE INTEREST ENTITIES (VIEs)

12 Months Ended

Dec. 31, 2018

VARIABLE INTEREST ENTITIES (VIEs)

VARIABLE INTEREST ENTITIES (VIEs)

NOTE 23 VARIABLE INTEREST ENTITIES (VIEs)

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 intermediate partnerships and mainly 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 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, Iroquois, and effective December 31, 2018, North Baja 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:


	December 31,	December 31,
(millions of dollars)	2018(a)	2017(b)

ASSETS (LIABILITIES)
Cash and cash equivalents	16	19
Accounts receivable and other	39	30
Inventories	8	6
Other current assets	6	5
Equity investments	1,196	1,213
Property, plant and equipment	1,240	1,133
Other assets	1	1
Accounts payable and accrued liabilities	(33)	(24)
Accounts payable to affiliates, net	(40)	(42)
Distributions payable	—	(1)
Accrued interest	(2)	(2)
Current portion of long-term debt	(36)	(51)
Long-term debt	(341)	(308)
Other liabilities	(27)	(26)
Deferred state income tax	(9)	(10)

^(a)

Bison, an asset held through our consolidated VIEs, is excluded at December 31, 2018 as the assets of this entity can be used for purposes other than the settlement of the VIE’s obligations.

^(b)

North Baja, which is also asset held through our consolidated VIEs, and Bison, are excluded at December 31, 2017 as the assets of these entities can be used for purposes other than the settlement of the VIE's obligations.

INCOME TAXES

12 Months Ended

Dec. 31, 2018

INCOME TAXES

INCOME TAXES

NOTE 24 INCOME TAXES

The Partnership’s income taxes relate to business profits tax (BPT) levied at the partnership (PNGTS) level by the state of New Hampshire (NH). 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, 2018, 2017 and 2016 relate primarily to utility plant. The NH BPT effective tax rate was 3.5 percent for the year ended December 31, 2018, and 3.8 percent for the periods ended December 31, 2017 and 2016, 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)	2018	2017	2016(a)

State income taxes
Current	2	1	1
Deferred	(1)	—	—
	1	1	1

^(a)

Recast to consolidate PNGTS (Refer to Notes 2 and 8).

SUBSEQUENT EVENTS	12 Months Ended
SUBSEQUENT EVENTS	Dec. 31, 2018
SUBSEQUENT EVENTS
SUBSEQUENT EVENTS	NOTE 25 SUBSEQUENT EVENTS Management of the Partnership has reviewed subsequent events through February 21, 2019, 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 22, 2019, the board of directors of our General Partner declared the Partnership's fourth quarter 2018 cash distribution in the amount of $0.65 per common unit and was paid on February 11, 2019 to unitholders of record as of February 1, 2019. The declared distribution totaled $47 million and is payable in the following manner: $46 million to common unitholders (including $4 million to the General Partner as a holder of 5,797,106 common units and $7 million to another subsidiary of TransCanada as holder of 11,287,725 common units) and $1 million to the General Partner for its two percent general partner interest. The General Partner did not receive any distributions in respect of its IDRs for the fourth quarter 2018. On January 22, 2019, the board of directors of our General Partner declared its annual distribution to Class B units in the amount of $13 million which was paid on February 11, 2018. The Class B distribution represents an amount equal to 30 percent of GTN's distributable cash flow during the year ended December 31, 2018 less $20 million and the Class B Reduction. Northern Border Northern Border declared its December 2018 distribution of $18 million on January 7, 2019, of which the Partnership received its 50 percent share or $9 million on January 31, 2019. Northern Border declared its January 2019 distribution of $20 million on February 14, 2019, of which the Partnership will receive its 50 percent share or $10 million on February 28, 2019. Great Lakes Great Lakes declared its fourth quarter 2018 distribution of $36 million on January 15, 2019, of which the Partnership received its 46.45 percent share or $17 million on February 1, 2019. Iroquois Iroquois declared its fourth quarter 2018 distribution of $28 million on January 22, 2019, of which the Partnership received its 49.34 percent share or $14 million on February 1, 2019. The $14 million includes our proportionate share of Iroquois’ unrestricted cash amounting to $2.6 million (refer to Note 8). PNGTS PNGTS declared its fourth quarter 2018 distribution of $19 million on January 9, 2019, of which $7 million was paid to its non-controlling interest owner on January 31, 2018.

SIGNIFICANT ACCOUNTING POLICIES (Policies)	12 Months Ended
SIGNIFICANT ACCOUNTING POLICIES (Policies)	Dec. 31, 2018
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, with the exception of 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 8). As a result of the Partnership owning 61.71 percent of PNGTS, the Partnership’s 2016 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 a 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 8). Accordingly, this transaction was accounted for as a transaction between entities under common control, similar to a 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 was eliminated as a result of consolidating PNGTS for all periods presented. Refer to Note 8 for additional disclosure regarding the 2016 PNGTS Acquisition.
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.
Property, plant and Equipment	(g) Property, plant and Equipment Property, plant 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 of our subsidiaries’ assets is based on rates approved by FERC from the pipelines’ last rate proceeding and 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 on the average cost of debt and equity. Capitalized carrying costs for AFUDC debt and equity are reflected as an increase in the cost of property, plant 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 property, plant 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 The Partnership’s revenues are generated from contractual arrangements for committed capacity and from transportation of natural gas which are treated as a bundled performance obligation. Revenues earned from firm contracted capacity arrangements are recognized ratably over the term of the contract regardless of the amount of natural gas that is transported. Transportation revenues for interruptible or volumetric-based services are recognized when the service is performed. Revenues are invoiced and paid on a monthly basis. The Partnership’s pipeline systems do not take ownership of the natural gas that is transported for customers. Revenues from contracts with customers are recognized net of any taxes collected from customers, which are subsequently remitted to governmental authorities. The Partnership's pipeline systems are subject to FERC regulations and, as a result, a portion of revenues collected may be subject to refund if invoiced during an interim period when a rate proceeding is ongoing. Allowances for these potential refunds are recognized using management's best estimate based on the facts and circumstances of the proceeding. Any allowances that are recognized during the proceeding process are refunded or retained, as applicable, at the time a regulatory decision becomes final.
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 U.S. 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 operations, is includable in the U.S. 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 for impairment on an annual basis or more frequently if any indicators of impairment are evident. The Partnership can initially assess qualitative factors to determine whether events or changes in circumstances indicate that the goodwill might be impaired and if the Partnership concludes that it is not more likely than not that fair value of the reporting unit is greater than its carrying value, the Partnership will then perform the quantitative goodwill impairment test. The Partnership can also elect to proceed directly to the quantitative goodwill impairment test for any of its reporting units. If the quantitative goodwill impairment test is performed, the Partnership compares the fair value of the reporting unit to its carrying value, including its goodwill. If the carrying value of a reporting unit including its goodwill exceeds its fair value, goodwill impairment is measured at the amount by which the reporting unit’s carrying value exceeds its fair value. 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, with the exception of 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. 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. 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. 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 any 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’s assets have indeterminate lives and, accordingly, has recorded no asset retirement obligation as of December 31, 2018 and 2017.
Government Regulation	(r) Government Regulation At December 31, 2018, the Partnership had regulatory assets amounting to $2 million reported on the balance sheet as part of other current assets and $2 million regulatory liabilities reported on the balance sheet as part of accounts payable and accrued liabilities both representing volumetric fuel tracker assets that are settled with in-kind exchanges with customers on a continued basis (2017 – nil). Long-term regulatory liabilities are included on the balance sheet as part of other liabilities (refer to Note 10). AFUDC is capitalized and included in property, plant and equipment.

ORGANIZATION (Tables)

12 Months Ended

Dec. 31, 2018

ORGANIZATION

Schedule of ownership interests in natural gas pipeline systems


Pipeline	Length	Description	Ownership
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	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	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	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	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

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 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 MNOC, a wholly owned subsidiary of MNE. MNE is a subsidiary of Enbridge Inc.	61.71 percent

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	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

GOODWILL AND REGULATORY (Tables)

12 Months Ended

Dec. 31, 2018

GOODWILL AND REGULATORY

Summary of adjustments as a result of the FERC Actions


	Form 501-G Filing Option	Impact on Maximum Rates	Moratorium and Mandatory Filing Requirements and Other Considerations
Great Lakes	Option 1; accepted by FERC	2.0% rate reduction effective February 1, 2019	No moratorium in effect; comeback provision with new rates to be effective by October 1, 2022
GTN	Settlement approved by FERC on November 30, 2018 eliminating the requirement to file Form 501-G	A refund of $10 million to its firm customers in 2018; 10.0% rate reduction effective January 1, 2019; additional rate reduction of 6.6% effective January 1, 2020 through December 31, 2021; These reductions will replace the 8.3% rate reduction in 2020 agreed to as part of the last settlement in 2015	Moratorium on rate changes until December 31, 2021; comeback provision with new rates to be effective by January 1, 2022
Northern Border	Option 1; accepted by FERC	2.0% rate reduction effective February 1, 2019; proposed additional 2.0% rate reduction effective January 1, 2020	No moratorium in effect; comeback provision with new rates to be effective by July 1, 2024
Bison	Option 3	No rate change proposed	No moratorium or comeback provisions
Iroquois	Option 3; subsequently reached a settlement with customers and a notice of settlement-in-principle was filed with FERC on January 9, 2019.	Expected to reduce rates by the impact of the 2017 Tax Act as shown on Form 501-G	Likely to be reaffirmed with the settlement
PNGTS	Option 3; accepted by FERC	No rate change proposed	No moratorium or comeback provisions
North Baja	Option 1; accepted by FERC	10.8% rate reduction effective December 1, 2018	No moratorium or comeback provisions; approximately 90% of North Baja's contracts are negotiated; 10.8% reduction on maximum rate contracts only
Tuscarora	Option 1; subsequently reached a settlement with customers and a notice of settlement-in-principle was filed with FERC on January 29, 2019	Expected to be finalized with the settlement	Expected to be finalized with the settlement

EQUITY INVESTMENTS (Tables)

12 Months Ended

Dec. 31, 2018

Schedule of equity investments and summarized financial information for equity investees


	Ownership
	Interest at		Equity Earnings (b)			Equity Investments
	December 31,		Year ended December 31			December 31
(millions of dollars)	2018		2018	2017	2016(c)	2018	2017
Northern Border(a)	50.00	%	68	67	69	497	512
Great Lakes	46.45	%	59	31	28	489	479
Iroquois	49.34	%	46	26	—	210	222
			173	124	97	1,196	1,213

^(a)

^(b)

^(c)

Recast to eliminate equity earnings from PNGTS and consolidate PNGTS (Refer to Notes 2 and 8).

Schedule of equity investments and summarized financial information for equity investees


December 31 (millions of dollars)	2018	2017

Assets
Cash and cash equivalents	10	14
Other current assets	36	36
Property, plant and equipment, net	1,037	1,063
Other assets	13	14
	1,096	1,127

Liabilities and Partners’ Equity
Current liabilities	34	38
Deferred credits and other	35	31
Long-term debt, net (a)	264	264
Partners’ equity
Partners’ capital	764	795
Accumulated other comprehensive loss	(1)	(1)
	1,096	1,127


Year ended December 31 (millions of dollars)	2018	2017	2016

Transmission revenues	289	291	292
Operating expenses	(78)	(78)	(72)
Depreciation	(60)	(59)	(59)
Financial charges and other	(15)	(18)	(21)
Net income	136	136	140

^(a)

No current maturities as of December 31, 2018 or 2017.

Schedule of equity investments and summarized financial information for equity investees


December 31 (millions of dollars)	2018	2017

Assets
Current assets	75	107
Property, plant and equipment, net	689	701
	764	808

Liabilities and Partners’ Equity
Current liabilities	26	75
Long-term debt, net (a)	240	259
Other long-term liabilities	4	1
Partners’ equity	494	473
	764	808


Year ended December 31 (millions of dollars)	2018	2017	2016

Transmission revenues	246	181	179
Operating expenses	(68)	(66)	(69)
Depreciation	(32)	(29)	(28)
Financial charges and other	(18)	(20)	(21)
Net income	128	66	61

^(a)

Includes current maturities of $21 million as of December 31, 2018 (December 31, 2017 - $19 million).

Schedule of equity investments and summarized financial information for equity investees


December 31 (millions of dollars)	2018	2017

ASSETS
Cash and cash equivalents	80	86
Other current assets	32	36
Property, plant and equipment, net	581	591
Other assets	8	8
	701	721

LIABILITIES AND PARTNERS’ EQUITY
Current liabilities	19	17
Net long-term debt, net (a)	325	329
Other non-current liabilities	14	9
Partners’ equity	343	366
	701	721


		Period of 7 months
	Year ended	ended December 31,
(millions of dollars)	December 31, 2018	2017
Transmission revenues	194	110
Operating expenses	(57)	(32)
Depreciation	(29)	(17)
Financial charges and other	(14)	(9)
Net income	94	52

^(a)

Includes current maturities of $146 million as of December 31, 2018 (December 31, 2017 - $4 million).

PROPERTY, PLANT AND EQUIPMENT (Tables)

12 Months Ended

Dec. 31, 2018

PROPERTY, PLANT AND EQUIPMENT

Schedule of property, plant and equipment


	2018				2017
			Accumulated	Net Book			Accumulated	Net Book
December 31 (millions of dollars)	Cost		Depreciation	Value	Cost		Depreciation	Value
Pipeline	1,901	-	(876)	1,025	2,577	-	(962)	1,615
Compression	550	-	(182)	368	533	-	(165)	368
Metering and other	176	-	(52)	124	182	-	(54)	128
Construction in progress	12	-	—	12	12	-	—	12
	2,639	-	(1,110)	1,529	3,304	-	(1,181)	2,123

ACQUISITION (Tables)

12 Months Ended

Dec. 31, 2018

Schedule of purchase price


(millions of dollars)
Net Purchase Price (a)		593
Less: TransCanada’s carrying value of Iroquois at June 1, 2017		223
Excess purchase price (b)		370

^(a)

^(b)

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

Schedule of purchase price allocation


(millions of dollars)
Current assets		25
Property, plant and equipment, net		294
Current liabilities		(4)
Deferred state income taxes		(10)
Long-term debt, including current portion		(41)
		264
Non-controlling interest		(100)
Carrying value of pre-existing Investment in PNGTS		(132)
TransCanada’s carrying value of the acquired 11.81 percent interest at June 1, 2017		32
Excess purchase price over net assets acquired (a)		21
Total cash consideration (b)		53

^(a)

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

^(b)

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

Schedule of net 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.

DEBT AND CREDIT FACILITIES (Tables)

12 Months Ended

Dec. 31, 2018

DEBT AND CREDIT FACILITIES

Schedule of debt and credit facilities


		Weighted Average					Weighted Average
		Interest Rate for the					Interest Rate for the
		Year Ended					Year Ended
(millions of dollars)	2018	December 31, 2018			2017		December 31, 2017
TC PipeLines, LP
Senior Credit Facility due 2021	40	3.14	%		185		2.41	%
2013 Term Loan Facility due 2022	500	3.23	%		500		2.33	%
2015 Term Loan Facility due 2020	—	—			170		2.22	%
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)	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	35	2.93	%		55		2.02	%
PNGTS
Revolving Credit Facility due 2023	19	3.55	%		—		—
5.90% Senior Secured Notes due 2018	—	—			30		5.90	%	(a)
Tuscarora
Unsecured Term Loan due 2020	24	3.10	%		25		2.27	%
North Baja
Unsecured Term Loan due 2021	50	3.54	%		—		—
	2,118				2,415
Less:unamortized debt issuance costs and debt discount	10				12
Less: current portion	36				51	(b)
	2,072				2,352

^(a)

Fixed interest rate.

^(b)

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)
2019		36
2020		123
2021		440
2022		500
2023		19
Thereafter		1,000
		2,118

OTHER LIABILITIES (Tables)

12 Months Ended

Dec. 31, 2018

OTHER LIABILITIES

Schedule of other liabilities


December 31 (millions of dollars)	2018	2017

Regulatory liabilities	27	26
Other liabilities	2	3
	29	29

ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) (Tables)

12 Months Ended

Dec. 31, 2018

ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)

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


	Cash flow	Equity
(millions of dollars)	hedges	Investments	Total
Balance at December 31, 2015(a)	(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 20)(a)	1	—	1
Net other comprehensive income (a)	2	—	2
Balance at December 31, 2016(a)	(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 20)	1	—	1
Other comprehensive income - effects of Iroquois' retirement benefit plans	—	1	1
Net other comprehensive income	6	1	7
Balance at December 31, 2017	4	1	5
Change in fair value of cash flow hedges	(2)	—	(2)
Amounts reclassified from AOCI	5	—	5
PNGTS’ amortization of realized loss on derivative instrument (Note 20)	1	—	1
Other comprehensive income (loss) - effects of Iroquois’ retirement benefit plans	—	(1)	(1)
Net other comprehensive income (loss)	4	(1)	3
Balance as of December 31, 2018	8	—	8

^(a)

Recast to consolidate PNGTS (Refer to in Notes 2 and 8). Additionally, AOCI as presented here is net of non-controlling interest on PNGTS.

FINANCIAL CHARGES AND OTHER (Tables)

12 Months Ended

Dec. 31, 2018

FINANCIAL CHARGES AND OTHER

Schedule of components of financial charges and other


Year ended December 31 (millions of dollars)	2018	2017	2016(a)

Interest expense (b)	95	83	69
Net realized loss related to the interest rate swaps	(2)	—	3
PNGTS' amortization of realized loss on derivative instrument (Note 20)	1	1	1
Other	(2)	(2)	(2)
	92	82	71

^(a)

Recast to consolidate PNGTS (Refer to Notes 2 and 8).

^(b)

Interest expense includes amortization of debt issuance costs and discount costs.

NET INCOME (LOSS) PER COMMON UNIT (Tables)

12 Months Ended

Dec. 31, 2018

NET INCOME (LOSS) PER COMMON UNIT

Schedule of net income (loss) per common unit


(millions of dollars, except per common unit amounts)	2018		2017		2016

Net income (loss) attributable to controlling interests (a)		(182)		252		248
Net income attributable to PNGTS' former parent (a)(b)		—		(2)		(4)
Net income (loss) allocable to General Partner and Limited Partners		(182)		250		244
Incentive distributions attributable to the General Partner (c)		—		(12)		(7)
Net income attributable to the Class B units (d)		(13)		(15)		(22)
Net income (loss) allocable to the General Partner and common units		(195)		223		215
Net (income) loss allocable to the General Partner's two percent interest		4		(4)		(4)
Net income (loss) attributable to common units		(191)		219		211
Weighted average common units outstanding (millions) – basic and diluted		71.3		69.2		65.7	(e)
Net income (loss) per common unit – basic and diluted(f)	$	(2.68)	$	3.16	$	3.21

^(a)

Recast to consolidate PNGTS in 2016 (Refer to Note 2).

^(b)

^(c)

^(d)

^(e)

Includes the common units subject to rescission. These units are treated as outstanding for financial reporting purposes (Refer to Note 11).

^(f)

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

CASH DISTRIBUTIONS (Tables)

12 Months Ended

Dec. 31, 2018

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	Common		General
	Per Unit Target Amount	Unitholders		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


				Limited Partners				General Partner
		Per Unit		Common		Class B						Total Cash
Declaration Date	Payment Date	Distribution		Units		Units (b)		2%		IDRs (a)		Distribution
1/21/2016	2/12/2016	$	0.89	$	57	$	12	$	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	$	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	2/13/2018	$	1.00	$	71	$	15	$	2	$	3	$	91
5/1/2018	5/15/2018	$	0.65	$	46	$	—	$	1	$	—	$	47
7/26/2018	8/15/2018	$	0.65	$	46	$	—	$	1	$	—	$	47
10/23/2018	11/14/2018	$	0.65	$	46	$	—	$	1	$	—	$	47
1/22/2019 (c)	2/11/2019 (c)	$	0.65	$	46	$	13	$	1	$	—	$	60

^(a)

The distributions paid during the year ended December 31, 2018 included incentive distributions to the General Partner of $3 million (2017 - $10 million, 2016 - $6 million).

^(b)

^(c)

On February 11, 2019, we paid a cash distribution of $0.65 per unit on our outstanding common units to unitholders of record at the close of business on February 1, 2019 (refer to Note 25).

CHANGE IN OPERATING WORKING CAPITAL (Tables)

12 Months Ended

Dec. 31, 2018

CHANGE IN OPERATING WORKING CAPITAL

Schedule of change in operating working capital


Year Ended December 31 (millions of dollars)	2018	2017	2016(b)
Change in accounts receivable and other	(6)	4	(4)
Change in other current assets	(1)	2	(4)
Change in accounts payable and accrued liabilities (a)	3	(7)	5
Change in accounts payable to affiliates	1	(3)	—
Change in accrued interest	—	2	2
Change in operating working capital	(3)	(2)	(1)

^(a)

Excludes certain non-cash items primarily related to capital accruals and dropdown costs.

^(b)

Recast to consolidate PNGTS (Refer to Notes 2 and 8).

TRANSACTIONS WITH MAJOR CUSTOMERS (Tables)

12 Months Ended

Dec. 31, 2018

TRANSACTIONS WITH MAJOR CUSTOMERS

Schedule of revenues from major customers


Year Ended December 31 (millions of dollars)	2018		2017		2016
Anadarko/Tenaska customer group (d)	144	(d)	48		48
Pacific Gas (c)	32	(a)(b)	33	(a)(b)	36

At December 31, 2018 and 2017, Anadarko owed the Partnership approximately $4 million, which is approximately 10 percent of our consolidated trade accounts receivable (Refer to Note 2).

^(a)

Less than 10 percent of trade accounts receivable

^(b)

Less than 10 percent of consolidated revenue

^(c)

^(d)

RELATED PARTY TRANSACTIONS (Tables)

12 Months Ended

Dec. 31, 2018

RELATED PARTY TRANSACTIONS

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


Year ended December 31 (millions of dollars)	2018	2017	2016
Capital and operating costs charged by TransCanada’s subsidiaries to:
Great Lakes (a)	44	36	30
Northern Border(a)	36	43	32
PNGTS (a)(b)	9	9	8
GTN	34	34	27
Bison	6	6	2
North Baja	4	4	4
Tuscarora	4	4	5
Impact on the Partnership’s net income attributable to controlling interests:
Great Lakes	19	15	13
Northern Border	16	16	12
PNGTS (b)	5	5	5
GTN	28	29	24
Bison	6	6	3
North Baja	4	4	4
Tuscarora	4	4	4

Summary of amount payable to related party for costs charged


Year ended December 31 (millions of dollars)	2018	2017	2016
Capital and operating costs charged by TransCanada’s subsidiaries to:
Great Lakes (a)	44	36	30
Northern Border(a)	36	43	32
PNGTS (a)(b)	9	9	8
GTN	34	34	27
Bison	6	6	2
North Baja	4	4	4
Tuscarora	4	4	5
Impact on the Partnership’s net income attributable to controlling interests:
Great Lakes	19	15	13
Northern Border	16	16	12
PNGTS (b)	5	5	5
GTN	28	29	24
Bison	6	6	3
North Baja	4	4	4
Tuscarora	4	4	4


December 31 (millions of dollars)	2018	2017
Amount payable to TransCanada’s subsidiaries for costs charged in the year by:
Great Lakes (a)	3	3
Northern Border(a)	3	4
PNGTS (a)	1	1
GTN	4	3
Bison	1	1
North Baja	—	—
Tuscarora	1	—

^(a)

Represents 100 percent of the costs.

^(b)

Recast to consolidate PNGTS for the year ended December 31, 2016 (Refer to Note 2).

QUARTERLY FINANCIAL DATA (unaudited) (Tables)

12 Months Ended

Dec. 31, 2018

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
2018
Transmission revenues		115		111		103	(b)		220	(c)
Equity earnings		59		36		34			44
Net income (loss)		102		75		65			(406)
Net income (loss) attributable to controlling interests		96		73		62			(413)
Net income (loss) per common unit	$	1.32	$	1.00	$	0.79		$	(5.80)
Cash distributions paid to common units (a)		76		47		47			47
Cash distribution paid to Class B units		15		—		—			—
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 distributions paid to common units(a)		68		68		74			74
Cash distribution paid to Class B units		22		—		—			—

^(a)

Distributions paid to common units includes our general partner’s two percent share and IDRs.

^(b)

^(c)

ACCOUNTS RECEIVABLE AND OTHER (Tables)

12 Months Ended

Dec. 31, 2018

ACCOUNTS RECEIVABLE AND OTHER

Schedule of accounts receivable and other


December 31 (millions of dollars)	2018	2017
Trade accounts receivable, net of allowance of nil	44	40
Imbalance receivable from affiliates	2	1
Other	2	1
	48	42

VARIABLE INTEREST ENTITIES (VIEs) (Tables)

12 Months Ended

Dec. 31, 2018

VARIABLE INTEREST ENTITIES (VIEs)

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


	December 31,	December 31,
(millions of dollars)	2018(a)	2017(b)

ASSETS (LIABILITIES)
Cash and cash equivalents	16	19
Accounts receivable and other	39	30
Inventories	8	6
Other current assets	6	5
Equity investments	1,196	1,213
Property, plant and equipment	1,240	1,133
Other assets	1	1
Accounts payable and accrued liabilities	(33)	(24)
Accounts payable to affiliates, net	(40)	(42)
Distributions payable	—	(1)
Accrued interest	(2)	(2)
Current portion of long-term debt	(36)	(51)
Long-term debt	(341)	(308)
Other liabilities	(27)	(26)
Deferred state income tax	(9)	(10)

^(a)

Bison, an asset held through our consolidated VIEs, is excluded at December 31, 2018 as the assets of this entity can be used for purposes other than the settlement of the VIE’s obligations.

^(b)

- 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, 2018

INCOME TAXES

Schedule of state income taxes of PNGTS


Year ended December 31 (millions of dollars)	2018	2017	2016(a)

State income taxes
Current	2	1	1
Deferred	(1)	—	—
	1	1	1

^(a)

Recast to consolidate PNGTS (Refer to Notes 2 and 8).

ORGANIZATION - Ownership Interests in Natural Gas Pipeline Systems (Details)	12 Months Ended
	Dec. 31, 2018 LimitedPartnership mi
Organization
Number of intermediate limited partnerships through which pipeline assets are owned \| LimitedPartnership	3
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
Organization
Length of pipeline owned (in miles)	86
Ownership interest (as a percent)	100.00%
Tuscarora
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%
Northern Border \| ONEOK Partners, L.P.
Organization
Remaining ownership interest (as a percent)	50.00%
PNGTS
Organization
Length of pipeline owned (in miles)	295
Ownership interest (as a percent)	61.71%
PNGTS \| Maritimes and Northeast Pipeline LLC
Organization
Length of pipeline owned (in miles)	107
Ownership interest (as a percent)	32.00%
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%
Iroquois Gas \| TransCanada
Organization
Ownership interest (as a percent)	0.66%
Iroquois Gas \| Dominion Midstream
Organization
Ownership interest (as a percent)	25.93%
Iroquois Gas \| Dominion Resources
Organization
Ownership interest (as a percent)	24.07%
Iroquois Gas \| TransCanada
Organization
Remaining ownership interest (as a percent)	50.66%
Northern New England Investment \| PNGTS
Organization
Remaining noncontrolling ownership interest (as a percent)	38.29%

ORGANIZATION - Capitalization (Details) - shares

12 Months Ended

Dec. 31, 2018

Dec. 31, 2017

Dec. 31, 2016

General Partner | TC PipeLines GP, Inc.

71,300,000

70,600,000

67,400,000

^[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 | TransCanada

71,306,396

Limited partner interest (as a percent)

24.00%

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

Limited Partners | Common Units | TransCanada

5,797,106

Limited Partners | Class B Units | TransCanada

11,287,725

Limited partner interest (as a percent)

1,900,000

100.00%

[1]	Recast to consolidate PNGTS (Refer to Notes 2 and 8).

SIGNIFICANT ACCOUNTING POLICIES - Ownership Interests Acquired (Details)	Jun. 01, 2017	Jan. 01, 2016
PNGTS
Acquisitions
Interest acquired (as a percent)	11.81%	49.90%
Ownership interest, including acquired interest (as a percent)	61.71%
Ownership interest (as a percent)	11.81%	49.90%
Iroquois
Acquisitions
Interest acquired (as a percent)	49.34%
Former parent, TransCanada subsidiaries \| PNGTS \| Transaction between entities under common control
Acquisitions
Interest acquired (as a percent)		49.90%
PNGTS
Acquisitions
Ownership interest, including acquired interest (as a percent)	61.71%

SIGNIFICANT ACCOUNTING POLICIES - Useful Lives of Property, Plant and Equipment (Details)	12 Months Ended
	Dec. 31, 2018
Pipeline facilities and compression equipment \| Minimum
Property, Plant and Equipment
Estimated useful lives	20 years
Pipeline facilities and compression equipment \| Maximum
Property, Plant and Equipment
Estimated useful lives	77 years
Metering and other \| Minimum
Property, Plant and Equipment
Estimated useful lives	5 years
Metering and other \| Maximum
Property, Plant and Equipment
Estimated useful lives	77 years

SIGNIFICANT ACCOUNTING POLICIES - Asset Retirement Obligation and Regulatory Assets (Details) - USD ($)	Dec. 31, 2018	Dec. 31, 2017
Accounts receivable and other
Regulatory assets and liabilities
Regulatory assets	$ 2,000,000	$ 0
Accounts payable and accrued liabilities
Regulatory assets and liabilities
Regulatory liabilities	2,000,000
Pipeline
Asset Retirement Obligation
Asset retirement liabilities	$ 0	$ 0

GOODWILL AND REGULATORY (Details) - USD ($) $ in Millions			3 Months Ended		11 Months Ended	12 Months Ended		24 Months Ended	47 Months Ended	54 Months Ended
GOODWILL AND REGULATORY (Details) - USD ($) $ in Millions	Dec. 06, 2018	Dec. 01, 2018	Dec. 31, 2018	Sep. 30, 2018	Dec. 31, 2019	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2021	Dec. 31, 2022	Jun. 30, 2024	Dec. 31, 2020	Oct. 16, 2018	Dec. 31, 2017
REGULATORY
Provision for revenue sharing							$ 10
Goodwill impairment charge							59
Goodwill			$ 71				71						$ 130
Great Lakes \| FERC
REGULATORY
Decrease in rate (as a percent)									2.00%
GTN \| FERC
REGULATORY
Decrease in rate (as a percent)						10.00%		6.60%
Amount agreed to issue as refund to customers from January 1 to October 31, 2018												$ 10
Provision for revenue sharing			1	$ 9
Settlement rate reduced (as a percent)											8.30%
Northern Border \| FERC
REGULATORY
Decrease in rate (as a percent)					2.00%					2.00%
Tuscarora
REGULATORY
Goodwill			23				23
North Baja
REGULATORY
Decrease in rate (as a percent)		10.80%
Number of contracts negotiated (as a percent)		90.00%
Tuscarora
REGULATORY
Decrease in rate (as a percent)	1.70%
Goodwill impairment charge							59
Goodwill			$ 82				$ 82

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

1 Months Ended

3 Months Ended

6 Months Ended

7 Months Ended

12 Months Ended

Sep. 01, 2017

Jun. 01, 2017

Jun. 30, 2017

Apr. 30, 2006

Dec. 31, 2018

Sep. 30, 2018

Jun. 30, 2018

Mar. 31, 2018

Dec. 31, 2017

Sep. 30, 2017

Jun. 30, 2017

Mar. 31, 2017

Dec. 31, 2017

Dec. 31, 2018

Dec. 31, 2017

Dec. 31, 2016

Aug. 01, 2017

$ 44

$ 34

$ 36

$ 59

$ 37

$ 27

$ 24

$ 36

$ 173

$ 124

$ 97

^[1]

1,196

1,213

$ 1,213

1,196

1,213

Distributions from Equity Investments

$ 36

Distributions received from equity investments

198

145

153

Return on investment distribution classified as investing activities

$ 10

50.00%

50.00%

46.45%

Great Lakes | Minimum

Excess of estimated fair value over carrying value (as a percent)

10.00%

Nonrecurring fair value measurement

Equity Method Investment, Other than Temporary Impairment

$ 0

ONEOK Partners, L.P. | Northern Border

50.00%

50.00%

50.00%

Capital contribution to reduce the outstanding balance of revolver debt

$ 83

$ 166

Total cash call issued to fund debt repayment

$ 10

$ 21

Assets

Other current assets

581

701

325

Other non-current liabilities

146

$ 4

146

$ 4

343

$ 701

701

Revenues (expenses)

110

194

Operating expenses

(32)

(57)

(17)

(29)

(9)

(14)

Distributions from Equity Investments

$ 52

Return on investment distribution classified as investing activities

$ 10

Percentage less than of which fair value exceeded carrying value

46.45%

10.00%

$ 59

$ 31

$ 489

$ 479

489

479

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

$ 4

^[1]

Undistributed earnings

260

Assets

Current assets

107

689

701

689

701

764

808

764

808

Other non-current liabilities

240

259

240

259

494

473

494

473

$ 764

808

764

808

Revenues (expenses)

246

181

179

Operating expenses

(68)

(66)

(69)

(32)

(29)

(28)

(18)

(20)

(21)

Great Lakes | TransCanada

$ 128

53.55%

49.34%

$ 46

$ 210

222

210

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

$ 0

$ 41

Additional consideration on surplus cash

$ 28

Assets

Other current assets

591

721

Other non-current liabilities

329

366

Distributions from Equity Investments

721

Return on investment distribution classified as investing activities

$ 10

TC PipeLines Intermediate Limited Partnership | Northern Border

TC PipeLines Intermediate Limited Partnership | Great Lakes

100.00%

100.00%

50.00%

$ 68

Amortization period of transaction fee

$ 497

512

497

512

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

Assets

Other current assets

1,037

1,063

1,037

1,063

1,096

1,127

1,096

1,127

Deferred credits and other

264

Accumulated other comprehensive loss

764

795

764

795

(1)

$ 1,096

$ 1,127

1,096

1,127

Revenues (expenses)

289

291

292

Operating expenses

(78)

(72)

(60)

(59)

(15)

(18)

(21)

$ 136

$ 140

[1]	Recast to consolidate PNGTS (Refer to Notes 2 and 8).

REVENUES - Disaggregation of Revenues (Details) $ in Millions	1 Months Ended	3 Months Ended	12 Months Ended
	Dec. 31, 2018 USD ($) customer	Dec. 31, 2018 USD ($)	Dec. 31, 2018 USD ($)	Jan. 01, 2018 USD ($)
Disaggregation of Revenues
Provision for revenue sharing			$ 10.0
Contract balances	$ 44.0	$ 44.0	44.0	$ 40.0
Bison
Disaggregation of Revenues
Non-refundable receipt from contract termination			$ 97.0
Number of customers that terminated transportation agreement \| customer	2
Bison \| Tenaska
Disaggregation of Revenues
Non-refundable receipt from contract termination	$ 95.4
Bison \| Another customer
Disaggregation of Revenues
Non-refundable receipt from contract termination		$ 2.0

PROPERTY, PLANT AND EQUIPMENT (Details) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
PROPERTY, PLANT AND EQUIPMENT
Cost	$ 2,639	$ 3,304
Accumulated Depreciation	(1,110)	(1,181)
Net Book Value	1,529	2,123
Pipeline
PROPERTY, PLANT AND EQUIPMENT
Cost	1,901	2,577
Accumulated Depreciation	(876)	(962)
Net Book Value	1,025	1,615
Compression
PROPERTY, PLANT AND EQUIPMENT
Cost	550	533
Accumulated Depreciation	(182)	(165)
Net Book Value	368	368
Metering and other
PROPERTY, PLANT AND EQUIPMENT
Cost	176	182
Accumulated Depreciation	(52)	(54)
Net Book Value	124	128
Construction in progress
PROPERTY, PLANT AND EQUIPMENT
Cost	12	12
Net Book Value	$ 12	$ 12

PROPERTY, PLANT AND EQUIPMENT - Property, Plant and Equipment Impairment in Bison (Details) - USD ($) $ in Millions	1 Months Ended	3 Months Ended	12 Months Ended
	Jan. 31, 2011	Dec. 31, 2018	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Schedule of Investments [Line Items]
Impairment of long-lived assets					$ 537
Bison
Schedule of Investments [Line Items]
Reduction in future revenue			$ 47	$ 47
Original contracts term	10 years
Bison
Schedule of Investments [Line Items]
Impairment of long-lived assets		$ 537

ACQUISITIONS - 2017 Acquisition and 2016 PNGTS Acquisition (Details)

12 Months Ended

19 Months Ended

Feb. 21, 2019

USD ($)

Aug. 01, 2017

USD ($)

item

Jun. 01, 2017

USD ($)

Jan. 01, 2016

USD ($)

Dec. 31, 2018

USD ($)

Dec. 31, 2017

USD ($)

Dec. 31, 2016

USD ($)

Feb. 21, 2019

USD ($)

Return on investment distribution classified as investing activities

$ 10,000,000

$ 5,000,000

$ 0

Ownership interest, including acquired interest (as a percent)

61.71%

Interest acquired (as a percent)

49.34%

Option to acquire (as a percent)

0.66

Amount of final purchase price adjustments

$ 19,000,000

Additional consideration on surplus cash

28,000,000

Purchase price before assumption of debt

710,000,000

Outstanding debt

164,000,000

Payment for option to acquire

1,000

Return on investment distribution classified as investing activities

$ 10,000,000

5,000,000

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

Net purchase price

710,000,000

Reduction in partner's equity under equity method investments

370,000,000

Iroquois | PNGTS

Amount of final purchase price adjustments

Purchase price

765,000,000

$ 50,000,000

Iroquois | Investing Activities

Expected return on investment distribution classified as investing activities

$ 28,400,000

Number of quarters for distribution of surplus cash | item

Iroquois | TransCanada

Expected return on investment distribution classified as investing activities

$ 28,000,000

Iroquois | Cash Distribution Paid

Return on investment distribution classified as investing activities

$ 2,600,000

$ 10,300,000

$ 5,200,000

$ 18,100,000

Interest acquired (as a percent)

11.81%

49.90%

Ownership interest, including acquired interest (as a percent)

61.71%

Interest acquired by Partnership (as a percent)

11.81%

49.90%

Purchase price

$ 55,000,000

Amount of final purchase price adjustments

3,000,000

Outstanding debt

5,000,000

Net purchase price

Net purchase price

^[1]

$ 193,000,000

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

PNGTS | TransCanada | Transaction between entities under common control

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

Total purchase price

$ 228,000,000

Net purchase price

Net purchase price

193,000,000

PNGTS purchase price

Total cash consideration

193,000,000

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 8).

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

1 Months Ended

12 Months Ended

Apr. 05, 2018

USD ($)

Aug. 21, 2017

USD ($)

May 25, 2017

USD ($)

Jul. 02, 2013

USD ($)

Jul. 01, 2013

USD ($)

Dec. 31, 2018

USD ($)

customer

Dec. 31, 2018

USD ($)

Dec. 31, 2017

USD ($)

Dec. 31, 2016

USD ($)

^[1]

Dec. 19, 2018

USD ($)

Jun. 01, 2015

USD ($)

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

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

$ 2,118.0

$ 2,415.0

Less: unamortized debt issuance costs and debt discount

10.0

12.0

Less: current portion

36.0

51.0

Long-term debt

$ 2,072.0

2,072.0

2,352.0

Proceeds from Issuance of Long-term Debt

$ 219.0

802.0

$ 209.0

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

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

Leverage ratio, actual (as a percent)

3.12%

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)

550.00%

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

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

Leverage ratio, covenant (as a percent)

500.00%

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

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

$ 40.0

$ 185.0

Maximum borrowing capacity

3.14%

2.41%

500.0

$ 500.0

Amount outstanding under credit facility

40.0

$ 185.0

Remaining borrowing capacity

460.0

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

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

Increase in credit facility

$ 500.0

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

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

Revolving credit facility | PNGTS Revolving Credit Facility due 2023

3.77%

2.62%

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

$ 19.0

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

3.55%

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

$ 500.0

3.23%

2.33%

Borrowings under the facility

$ 500.0

$ 500.0

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

3.60%

2.62%

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

3.26%

2.31%

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

$ 170.0

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

2.22%

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

4.65%

$ 350.0

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%

$ 350.0

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

4.375%

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

3.90%

$ 500.0

3.90%

Unsecured debt | GTN 5.29% Senior Notes due 2020

$ 500.0

Net proceeds

$ 497.0

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

Unsecured debt | Tuscarora Term Loan due 2020

5.69%

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

24.0

$ 24.0

$ 25.0

Unsecured debt | North Baja Term Loan Due 2021

3.10%

2.27%

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

$ 50.0

Secured debt | PNGTS 5.90% Senior Secured Notes due 2018

3.54%

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

5.90%

$ 30.0

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

5.90%

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

$ 100.0

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

5.29%

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

150.0

$ 150.0

GTN | Unsecured debt | Term Loan Facility due 2019

5.69%

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

$ 35.0

$ 55.0

2.93%

2.02%

3.30%

2.31%

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

$ 75.0

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

Percentage of debt to total capitalization, covenant

42.80%

70.00%

PNGTS | PNGTS 5.90% Senior Secured Notes due 2018

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

Payment of principal amount on secured notes

$ 5.8

PNGTS | Revolving credit facility

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

Interest rate (as a percent)

3.60%

PNGTS | Secured debt | Maximum

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

Leverage ratio, covenant (as a percent)

5.00%

PNGTS | Secured debt | LIBOR

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

Maximum borrowing capacity

$ 125.0

PNGTS | 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

Amount outstanding under credit facility

$ 19.0

PNGTS | 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)

0.35%

Tuscarora | Unsecured debt | Tuscarora Term Loan due 2020

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

Tuscarora | Unsecured debt | Tuscarora Term Loan due 2020 | Minimum

$ 25.0

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

Debt service coverage, covenant (as a percent)

3.00%

10.29%

Tuscarora | Unsecured debt | Tuscarora Term Loan due 2020 | LIBOR

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

North Baja | Unsecured debt

3.47%

2.49%

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

3.54%

North Baja | Unsecured debt | Maximum

$ 50.0

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

Percentage of debt to total capitalization, covenant

37.70%

70.00%

Bison

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

Number of customers that terminated transportation agreement | customer

[1]	Recast to consolidate PNGTS (Refer to Notes 2 and 8).

DEBT AND CREDIT FACILITIES - Principal Payments Required (Details) $ in Millions	Dec. 31, 2018 USD ($)
Principal repayments required on debt
2019	$ 36
2020	123
2021	440
2022	500
2023	19
Thereafter	1,000
Total debt	$ 2,118

OTHER LIABILITIES (Details) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
OTHER LIABILITIES
Regulatory liabilities	$ 27	$ 26
Other liabilities	2	3
Other liabilities, total	$ 29	$ 29

PARTNERS' EQUITY - Ownership (Details) - shares

12 Months Ended

Dec. 31, 2018

Dec. 31, 2017

Dec. 31, 2016

Common Units | Limited Partners

71,300,000

70,600,000

67,400,000

^[1]

TransCanada | Common Units | Limited Partners

71,306,396

TransCanada | Class B Units | Limited Partners

24.00%

1,900,000

Non-affiliates | Common Units | Limited Partners

100.00%

TC PipeLines GP, Inc. | General Partner

54,221,565

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

11,287,725

[1]	Recast to consolidate PNGTS (Refer to Notes 2 and 8).

PARTNERS' EQUITY - ATM Equity Issuance Program (Details) shares in Millions, $ in Millions		2 Months Ended	12 Months Ended
	Aug. 05, 2016 USD ($) item	May 19, 2016 shares	Dec. 31, 2018 USD ($) shares	Dec. 31, 2017 USD ($) shares	Dec. 31, 2016 USD ($) shares	Aug. 31, 2014 USD ($)
TC PipeLines GP, Inc. \| General Partner
PARTNERS' EQUITY
Ownership interest in the Partnership (as a percent)			2.00%	2.00%	2.00%
ATM Equity Issuance Program \| Common Units
PARTNERS' EQUITY
Aggregate offering price of units						$ 200.0
Units sold \| shares			0.7	3.2	3.1
Net proceeds from issuance of common units			$ 39.0	$ 173.0	$ 164.0
Sales agent commissions			0.0	2.0	2.0
Reclassification of common unit issuance subject to rescission, net (in units) \| shares		1.6
Common units subject to rescission			0.0
ATM Equity Issuance Program \| TC PipeLines GP, Inc. \| General Partner
PARTNERS' EQUITY
Equity contribution			$ 1.0	$ 3.0	$ 3.0
Equity Distribution Agreement (EDA) \| Common Units
PARTNERS' EQUITY
Amended shelf registration with SEC	$ 400.0
Number of financial institutions \| item	5

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

12 Months Ended

Nov. 14, 2018

Aug. 15, 2018

May 15, 2018

Feb. 13, 2018

Nov. 14, 2017

Aug. 11, 2017

May 15, 2017

Feb. 14, 2017

Nov. 14, 2016

Aug. 12, 2016

May 13, 2016

Feb. 12, 2016

Apr. 01, 2015

Dec. 31, 2018

Dec. 31, 2017

Dec. 31, 2016

$ 15

$ 22

$ 12

$ 15

$ 22

$ 12

^[1]

$ 46

$ 71

$ 70

$ 69

$ 65

$ 64

$ 63

$ 62

$ 58

$ 57

$ (191)

219

211

^[1]

TransCanada

Remaining ownership interest (as a percent)

30.00%

TransCanada | Distributions | Class B Units

Percentage of reduction in distributions payable

35.00%

TransCanada | Distributions | Common Units

Percentage of reduction in distributions payable

35.00%

Minimum distribution payable per common unit

$ 3.94

GTN | TransCanada | Distributions | Class B Units

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

30.00%

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

100.00%

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

$ 20

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

25.00%

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

$ 20

30% of GTN's distributable cash flow

$ 40

Percentage applied to GTN's distributable cash flow

30.00%

[1]	Recast to consolidate PNGTS (Refer to Notes 2 and 8).

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

12 Months Ended

Dec. 31, 2018

Dec. 31, 2017

Dec. 31, 2016

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

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

$ 963

(2)

$ 5

$ 3

^[1]

PNGTS' amortization of realized loss on derivative instrument (Note 20)

^[1]

^[1]

Accumulated Other Comprehensive Income (Loss)

591

963

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

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

(2)

(4)

(2)

Amounts reclassified from AOCI

(2)

PNGTS' amortization of realized loss on derivative instrument (Note 20)

Other comprehensive income (loss) - effects of Iroquois' retirement benefit plans

(1)

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

(2)

Cash flow hedges

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

(2)

(4)

(2)

Amounts reclassified from AOCI

(2)

PNGTS' amortization of realized loss on derivative instrument (Note 20)

$ (2)

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

Other comprehensive income (loss) - effects of Iroquois' retirement benefit plans

(1)

$ (1)

Net realized loss related to the interest rate swaps

$ 1

[1]	Recast to consolidate PNGTS (Refer to Notes 2 and 8).

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

12 Months Ended

Dec. 31, 2018

Dec. 31, 2017

Dec. 31, 2016

FINANCIAL CHARGES AND OTHER

Interest Expense

$ 95

$ 83

$ 69

(2)

PNGTS' amortization of realized loss on derivative instrument (Note 20)

Other

(2)

$ 92

$ 82

$ 71

^[1]

[1]	Recast to consolidate PNGTS (Refer to Notes 2 and 8).

NET INCOME (LOSS) PER COMMON UNIT - General Partner Effective Interest and Allocated Incentive Distributions (Details)	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
TC PipeLines GP, Inc. \| General Partner
PARTNERS' EQUITY
General partner interest (as a percent)	2.00%	2.00%	2.00%

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

3 Months Ended

12 Months Ended

Dec. 31, 2018

Sep. 30, 2018

Jun. 30, 2018

Mar. 31, 2018

Dec. 31, 2017

Sep. 30, 2017

Jun. 30, 2017

Mar. 31, 2017

Dec. 31, 2018

Dec. 31, 2017

Dec. 31, 2016

Net income (loss) attributable to controlling interests

$ (182)

$ 252

$ 248

^[1]

Net income attributable to PNGTS' former parent

(2)

(4)

Net income (loss) attributable to General and Limited Partners

(182)

250

244

Incentive distributions attributable to the General Partner

(12)

(7)

Net income attributable to the General Partner and common units

(195)

223

215

Net income (loss) attributable to General Partner's two percent interest

(4)

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

$ (5.80)

$ 0.79

$ 1.00

$ 1.32

$ 0.77

$ 0.61

$ 0.73

$ 1.05

Weighted average common units outstanding - basic (in units)

$ (191)

$ 219

$ 211

^[1]

71.3

69.2

65.7

^[1]

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

^[2]

$ (2.68)

$ 3.16

$ 3.21

^[1]

GTN | Class B Units | TransCanada | Distributions

Net income (loss) attributable to controlling interests

$ (13)

$ (15)

$ (22)

Distributions

Percentage applied to GTN's distributable cash flow

30.00%

30% of GTN's distributable cash flow

$ 40

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

$ 20

Reduction in distribution

$ 7

[1]	Recast to consolidate PNGTS (Refer to Notes 2 and 8).
[2]	Net income (loss) per common unit prior to recast (Refer to Note 2).

CASH DISTRIBUTIONS - Quarterly Distributions (Details)	12 Months Ended
CASH DISTRIBUTIONS - Quarterly Distributions (Details)	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
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%

CASH DISTRIBUTIONS - General Partner Distribution Incentives (Details)	12 Months Ended
	Dec. 31, 2018 $ / shares
Minimum Quarterly Distribution
Partners' Equity
Total Quarterly Distribution Per Unit Target Amount (in dollars per unit)	$ 0.45
Minimum Quarterly Distribution \| Limited Partners \| Common Units
Partners' Equity
Marginal Percentage Interest in Distribution, Common Unitholders (as a percent)	98.00%
Minimum Quarterly Distribution \| General Partner
Partners' Equity
Marginal Percentage Interest in Distribution, General Partner (includes IDRs)	2.00%
First Target Distribution \| Minimum
Partners' Equity
Total Quarterly Distribution Per Unit Target Amount (in dollars per unit)	$ 0.45
First Target Distribution \| Maximum
Partners' Equity
Total Quarterly Distribution Per Unit Target Amount (in dollars per unit)	$ 0.81
First Target Distribution \| Limited Partners \| Common Units
Partners' Equity
Marginal Percentage Interest in Distribution, Common Unitholders (as a percent)	98.00%
First Target Distribution \| General Partner
Partners' Equity
Marginal Percentage Interest in Distribution, General Partner (includes IDRs)	2.00%
Second Target Distribution \| Minimum
Partners' Equity
Total Quarterly Distribution Per Unit Target Amount (in dollars per unit)	$ 0.81
Second Target Distribution \| Maximum
Partners' Equity
Total Quarterly Distribution Per Unit Target Amount (in dollars per unit)	$ 0.88
Second Target Distribution \| Limited Partners \| Common Units
Partners' Equity
Marginal Percentage Interest in Distribution, Common Unitholders (as a percent)	85.00%
Second Target Distribution \| General Partner
Partners' Equity
Marginal Percentage Interest in Distribution, General Partner (includes IDRs)	15.00%
Thereafter
Partners' Equity
Total Quarterly Distribution Per Unit Target Amount (in dollars per unit)	$ 0.88
Thereafter \| Limited Partners \| Common Units
Partners' Equity
Marginal Percentage Interest in Distribution, Common Unitholders (as a percent)	75.00%
Thereafter \| General Partner
Partners' Equity
Marginal Percentage Interest in Distribution, General Partner (includes IDRs)	25.00%

CASH DISTRIBUTIONS - Distributions by Payment Date (Details) - USD ($)
$ / shares in Units, $ in Millions

3 Months Ended

12 Months Ended

Feb. 11, 2019

Jan. 22, 2019

Nov. 14, 2018

Aug. 15, 2018

May 15, 2018

Feb. 13, 2018

Nov. 14, 2017

Aug. 11, 2017

May 15, 2017

Feb. 14, 2017

Nov. 14, 2016

Aug. 12, 2016

May 13, 2016

Feb. 12, 2016

Apr. 01, 2015

Dec. 31, 2018

Sep. 30, 2018

Jun. 30, 2018

Mar. 31, 2018

Dec. 31, 2017

Sep. 30, 2017

Jun. 30, 2017

Mar. 31, 2017

Dec. 31, 2018

Dec. 31, 2017

Dec. 31, 2016

General Partner IDRs paid

General Partner 2% paid

$ 1

$ 2

$ 1

$ 2

$ 1

$ 2

$ 1

$ 3

$ 10

$ 6

$ 47

$ 91

$ 74

$ 68

$ 90

$ 66

$ 65

$ 60

$ 71

218

284

250

^[1]

Per Unit Distribution, paid (in dollars per unit)

$ 0.65

$ 1.00

$ 0.94

$ 0.89

$ 46

$ 71

$ 70

$ 69

$ 65

$ 64

$ 63

$ 62

$ 58

$ 57

$ 47

$ 76

$ 74

$ 68

$ 15

$ 22

$ 12

$ 15

$ 22

$ 12

^[1]

GTN | Class B Units | TransCanada | Distributions

$ 15

$ 22

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%

Subsequent Events

General Partner 2% paid

$ 1

Subsequent Events | Common Units

$ 60

Per Unit Distribution, declared (in dollars per unit)

$ 0.65

Per Unit Distribution, paid (in dollars per unit)

$ 0.65

Subsequent Events | Class B Units

$ 46

Total Cash Distribution

Limited Partners, Distribution declared

$ 13

Change in accounts receivable and other

$ 13

[1]	Recast to consolidate PNGTS (Refer to Notes 2 and 8).

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

12 Months Ended

Dec. 31, 2018

Dec. 31, 2017

Dec. 31, 2016

CHANGE IN OPERATING WORKING CAPITAL

$ (6)

$ 4

$ (4)

Change in other current assets

(1)

(4)

Change in accounts payable and other current liabilities

(7)

Change in accounts payable to affiliates

(3)

Change in accrued interest

Change in operating working capital (Note 15)

$ (3)

$ (2)

$ (1)

^[1]

[1]	Recast to consolidate PNGTS (Refer to Notes 2 and 8).

TRANSACTIONS WITH MAJOR CUSTOMERS (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Transactions with major customers
Trade accounts receivable	$ 44	$ 40
Total revenues \| Pacific Gas
Transactions with major customers
Percent of consolidate revenue	6.00%
Total revenues \| Customer concentration risk \| Anadarko/Tenaska customer group
Transactions with major customers
Revenues	$ 144	48	$ 48
Total revenues \| Customer concentration risk \| Pacific Gas
Transactions with major customers
Revenues	32	33	$ 36
Accounts receivable and other \| Amounts owed by major customers \| Anadarko Energy Services Company
Transactions with major customers
Trade accounts receivable	$ 4	$ 4

RELATED PARTY TRANSACTIONS (Details) $ in Millions		1 Months Ended	3 Months Ended	12 Months Ended
RELATED PARTY TRANSACTIONS (Details) $ in Millions	Nov. 01, 2017	Sep. 21, 2017 Bcf	Jun. 30, 2018 USD ($)	Dec. 31, 2018 USD ($)	Dec. 31, 2017 USD ($)	Dec. 31, 2016 USD ($)
Capital and operating costs charged to the pipeline systems and amount payable
Net amounts payable				$ 6	$ 5
Amount included in receivables from related party				2	1
General Partner \| Reimbursement of costs of services provided
Capital and operating costs charged to the pipeline systems and amount payable
Costs charged				4	4	$ 3
TransCanada's subsidiaries \| Great Lakes
Capital and operating costs charged to the pipeline systems and amount payable
Net amounts payable				3	3
Amount included in receivables from related party				18	20
TransCanada's subsidiaries \| Great Lakes \| Capital and operating costs
Capital and operating costs charged to the pipeline systems and amount payable
Costs charged				44	36	30
Impact on the Partnership's net income attributable to controlling interests				19	15	$ 13
Amount included in receivables from related party				$ 36	$ 64
TransCanada's subsidiaries \| Great Lakes \| Transportation contracts \| Total net revenues \| Customer concentration risk
Capital and operating costs charged to the pipeline systems and amount payable
Percent of total revenues				73.00%	57.00%	68.00%
TransCanada's subsidiaries \| Great Lakes \| Affiliated rental revenue
Capital and operating costs charged to the pipeline systems and amount payable
Percent of total revenues					1.00%	1.00%
TransCanada's subsidiaries \| Great Lakes \| Affiliated rental revenue \| Maximum
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
Net amounts payable				$ 3	$ 4
TransCanada's subsidiaries \| Northern Border \| Capital and operating costs
Capital and operating costs charged to the pipeline systems and amount payable
Costs charged				36	43	$ 32
Impact on the Partnership's net income attributable to controlling interests				16	16	12
TransCanada's subsidiaries \| PNGTS
Capital and operating costs charged to the pipeline systems and amount payable
Net amounts payable				1	1
TransCanada's subsidiaries \| PNGTS \| Capital and operating costs
Capital and operating costs charged to the pipeline systems and amount payable
Costs charged				9	9	8
Impact on the Partnership's net income attributable to controlling interests				5	5	5
TransCanada's subsidiaries \| PNGTS \| Transportation contracts
Capital and operating costs charged to the pipeline systems and amount payable
Amount included in receivables from related party				0
Revenues from related party				1	1	2
TransCanada's subsidiaries \| GTN
Capital and operating costs charged to the pipeline systems and amount payable
Net amounts payable				4	3
TransCanada's subsidiaries \| GTN \| Capital and operating costs
Capital and operating costs charged to the pipeline systems and amount payable
Costs charged				34	34	27
Impact on the Partnership's net income attributable to controlling interests				$ 28	$ 29	$ 24
Percentage of capital and operating costs charged				100.00%	100.00%	100.00%
TransCanada's subsidiaries \| Bison
Capital and operating costs charged to the pipeline systems and amount payable
Net amounts payable				$ 1	$ 1
TransCanada's subsidiaries \| Bison \| Capital and operating costs
Capital and operating costs charged to the pipeline systems and amount payable
Costs charged				6	6	$ 2
Impact on the Partnership's net income attributable to controlling interests				6	6	3
TransCanada's subsidiaries \| North Baja \| Capital and operating costs
Capital and operating costs charged to the pipeline systems and amount payable
Costs charged				4	4	4
Impact on the Partnership's net income attributable to controlling interests				4	4	4
TransCanada's subsidiaries \| Tuscarora
Capital and operating costs charged to the pipeline systems and amount payable
Net amounts payable				1
TransCanada's subsidiaries \| Tuscarora \| Capital and operating costs
Capital and operating costs charged to the pipeline systems and amount payable
Costs charged				4	4	5
Impact on the Partnership's net income attributable to controlling interests				4	4	$ 4
TransCanada \| Great Lakes
Capital and operating costs charged to the pipeline systems and amount payable
Termination options beginning	3 years
TransCanada \| Great Lakes \| Transportation contracts
Capital and operating costs charged to the pipeline systems and amount payable
Contract term	10 years
Total revenue earned				76	13
TransCanada \| PNGTS
Capital and operating costs charged to the pipeline systems and amount payable
Amount included in receivables from related party					0
ANR Pipeline Company \| Great Lakes \| Transportation contracts
Capital and operating costs charged to the pipeline systems and amount payable
Transportation capacity per day \| Bcf		0.711
ANR Pipeline Company \| Great Lakes \| Transportation contracts
Capital and operating costs charged to the pipeline systems and amount payable
Contract term			15 years
Total contract value			$ 1,300
Affiliates \| PNGTS \| Construction of facilities
Capital and operating costs charged to the pipeline systems and amount payable
Reimbursement of costs				$ 47	$ 3

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

3 Months Ended

12 Months Ended

Nov. 14, 2018

Aug. 15, 2018

May 15, 2018

Feb. 13, 2018

Nov. 14, 2017

Aug. 11, 2017

May 15, 2017

Feb. 14, 2017

Nov. 14, 2016

Aug. 12, 2016

May 13, 2016

Feb. 12, 2016

Dec. 31, 2018

Sep. 30, 2018

Jun. 30, 2018

Mar. 31, 2018

Dec. 31, 2017

Sep. 30, 2017

Jun. 30, 2017

Mar. 31, 2017

Dec. 31, 2018

Dec. 31, 2017

Dec. 31, 2016

Oct. 16, 2018

Net income (loss) attributable to controlling interests

$ 220

$ 103

$ 111

$ 115

$ 109

$ 100

$ 101

$ 112

$ 549

$ 422

$ 426

^[1]

Equity earnings

173

124

^[1]

Net income (loss)

(406)

102

$ (413)

$ 62

$ 73

$ 96

$ 66

$ 54

$ 55

$ 77

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

$ (5.80)

$ 0.79

$ 1.00

$ 1.32

$ 0.77

$ 0.61

$ 0.73

$ 1.05

Provision for revenue sharing

$ 47

$ 91

$ 74

$ 68

$ 90

$ 66

$ 65

$ 60

$ 71

218

$ 284

$ 250

^[1]

$ 10

TC PipeLines GP, Inc. | General Partner

General partner interest (as a percent)

2.00%

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

^[2]

$ (2.68)

$ 3.16

$ 3.21

^[1]

$ 47

$ 76

$ 74

$ 68

$ 15

$ 22

GTN | FERC

Provision for revenue sharing

$ 1

$ 9

Amount agreed to issue as refund to customers from January 1 to October 31, 2018

$ 10

Bison

Contract Termination Proceeds

$ 97

[1]	Recast to consolidate PNGTS (Refer to Notes 2 and 8).
[2]	Net income (loss) per common unit prior to recast (Refer to Note 2).

FAIR VALUE MEASUREMENTS - Estimated Fair Value of Debt (Details) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Fair Value \| Level 2
Financial Instruments
Fair value of debt	$ 2,101	$ 2,475

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

12 Months Ended

Dec. 31, 2018

USD ($)

item

Dec. 31, 2017

USD ($)

Dec. 31, 2016

USD ($)

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

$ (2.0)

$ 5.0

$ 3.0

^[1]

Amortization of derivatives gain

2.0

(3.0)

Amortization of derivatives loss

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

Secured debt | PNGTS 5.90% Senior Secured Notes due 2018

$ 500.0

500.0

30.0

5.90%

Other Comprehensive Income (Loss), Cash Flow Hedge, Gain (Loss), before Reclassification, after Tax

20.9

Payments for derivative instruments

$ 20.9

Interest rate swaps | January 1 to June 30, 2018 | Term loan | TC PipeLines, LP 2013 Term Loan Facility due 2022

Weighted average fixed interest rate (as a percent)

2.31%

Interest rate swaps | July 1, 2018 to October 2, 2022 | Term loan | TC PipeLines, LP 2013 Term Loan Facility due 2022

Weighted average fixed interest rate (as a percent)

3.26%

Hedges of cash flows | Interest rate swaps

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

$ (2.0)

5.0

3.0

Net realized gain (loss) on reclassified from other comprehensive income

5.0

0.0

2.0

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

Amortization of derivatives gain

2.0

0.0

(3.0)

Amortization of derivatives loss

0.0

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

Fair value of derivative asset, gross

8.0

5.0

Fair value of derivative asset, net

8.0

5.0

Amortization of derivatives loss

$ 1.0