TC Pipelines (TCP) 10-Q 2 May 18 2018 Q1 Quarterly report Financial data

Document and Entity Information

Document and Entity Information - shares	3 Months Ended
	Mar. 31, 2018	May 01, 2018
Document and Entity Information
Entity Registrant Name	TC PIPELINES LP
Entity Central Index Key	1,075,607
Document Type	10-Q
Document Period End Date	Mar. 31, 2018
Amendment Flag	false
Current Fiscal Year End Date	--12-31
Entity Current Reporting Status	Yes
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		71,306,396
Document Fiscal Year Focus	2,018
Document Fiscal Period Focus	Q1

CONSOLIDATED STATEMENTS OF INCO

CONSOLIDATED STATEMENTS OF INCOME - USD ($) shares in Millions, $ in Millions		3 Months Ended
		Mar. 31, 2018	Mar. 31, 2017
Transmission revenues		$ 115	$ 112	[1]
Equity earnings (Note 5)		59	36	[1]
Operation and maintenance expenses		(16)	(14)	[1]
Property taxes		(7)	(7)	[1]
General and administrative		(1)	(2)	[1]
Depreciation and amortization		(24)	(24)	[1]
Financial charges and other (Note 15)		(23)	(17)	[1]
Net income before taxes		103	84	[1]
Income taxes (Note 18)		(1)	(1)	[1]
Net Income		102	83	[1]
Net income attributable to non-controlling interest		6	6	[1]
Net income attributable to controlling interests		96	77	[1]
Net income attributable to controlling interest allocation (Note 9)
General Partner		2	3	[1]
TransCanada, as former parent of PNGTS	[1]		2
Net income attributable to controlling interests		96	77	[1]
Common Units
Net income attributable to controlling interest allocation (Note 9)
Net income attributable to common units		$ 94	$ 72	[1]
Net income per common unit (Note 9) - basic and diluted (in dollars per unit)	[2]	$ 1.32	$ 1.05	[1]
Weighted average common units outstanding - basic (in units)		71.2	68.3	[1]
Common units outstanding, end of period		71.3	68.6	[1]
[1]	Recast to consolidate PNGTS (Refer to Note 2).
[2]	Net income per common unit prior to recast (Refer to Note 2).

CONSOLIDATED STATEMENTS OF COMP

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017	[1]
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
Net income	$ 102	$ 83
Other comprehensive income
Change in fair value of cash flow hedges (Note 13)	7	1
Comprehensive income	109	84
Comprehensive income attributable to non-controlling interests	6	6
Comprehensive income attributable to controlling interests	$ 103	$ 78
[1]	Recast to consolidate PNGTS (Refer to Note 2).

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions	Mar. 31, 2018	Dec. 31, 2017
Current Assets
Cash and cash equivalents	$ 68	$ 33
Accounts receivable and other (Note 14)	36	42
Contract assets (Note 6)	7
Distribution receivable (Note 5)	14
Inventories	7	8
Other	11	7
Total current assets	143	90
Equity investments (Note 5)	1,217	1,213
Plant, property and equipment (Net of $1,205 accumulated depreciation; 2017 - $1,181)	2,105	2,123
Goodwill	130	130
Other assets	9	3
Total assets	3,604	3,559
Current Liabilities
Accounts payable and accrued liabilities	35	31
Accounts payable to affiliates (Note 12)	6	5
Distributions payable	2	1
Accrued interest	21	12
Current portion of long-term debt (Note 7)	45	51
Total current liabilities	109	100
Long-term debt, net (Note 7)	2,332	2,352
Deferred state income taxes (Note 18)	10	10
Other liabilities	29	29
Total liabilities	2,480	2,491
Partners' Equity
Accumulated other comprehensive income (AOCI)	12	5
Controlling interests	1,015	963
Non-controlling interests	109	105
Total partners' equity	1,124	1,068
Total liabilities and partners' equity	3,604	3,559
Common Units
Partners' Equity
Limited partner	886	824
Class B Units
Partners' Equity
Limited partner	95	110
General partner	$ 22	$ 24

CONSOLIDATED BALANCE SHEETS (Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Millions	Mar. 31, 2018	Dec. 31, 2017
CONSOLIDATED BALANCE SHEETS
Accumulated depreciation	$ 1,205	$ 1,181

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Millions		3 Months Ended
		Mar. 31, 2018	Mar. 31, 2017
Cash Generated From Operations
Net income		$ 102	$ 83	[1]
Depreciation		24	24	[1]
Amortization of debt issue costs reported as interest expense		1	1	[1]
Equity earnings from equity investments (Note 5)		(59)	(36)	[1]
Distributions received from operating activities of equity investments (Note 5)		43	28	[1]
Change in operating working capital (Note 11)		6	7	[1]
Net Cash Provided by (Used in) Operating Activities		117	107	[1]
Investing Activities
Distribution received from Iroquois as return of investment (Note 5)		2	0
Capital expenditures		(2)	(7)	[1]
Net Cash Provided by (Used in) Investing Activities		(4)	(11)	[1]
Financing Activities
Distributions paid (Note 10)		(76)	(68)	[1]
Distributions paid to non-controlling interests		(1)	(2)	[1]
Common unit issuance, net (Note 8)		40	71	[1]
Long-term debt issued, net of discount (Note 7)		75
Long-term debt repaid (Note 7)		(101)	(61)	[1]
Total financing activities		(78)	(83)	[1]
Decrease in cash and cash equivalents		(35)	(13)	[1]
Cash and cash equivalents, beginning of period		33	64	[1]
Cash and cash equivalents, end of period		68	77	[1]
Class B Units
Financing Activities
Distributions paid to Class B units (Note 8)		(15)	(22)	[1]
Great Lakes
Cash Generated From Operations
Equity earnings from equity investments (Note 5)		(24)	(17)
Investing Activities
Investment/Acquisition of interests		$ (4)	(4)	[1]
Portland Natural Gas Transmission System
Financing Activities
Distributions paid to former parent of PNGTS	[1]		$ (1)
[1]	Recast to consolidate PNGTS (Refer to Note 2).

CONSOLIDATED STATEMENT OF CHANG

CONSOLIDATED STATEMENT OF CHANGES IN PARTNERS' EQUITY - 3 months ended Mar. 31, 2018 - USD ($) shares in Millions, $ in Millions	ATM Equity Issuance ProgramCommon Units	Limited PartnersCommon Units	Limited PartnersClass B Units	General Partner	Accumulated Other Comprehensive Income	[1]	Non-controlling interests	Total
Partners' Equity at beginning of year at Dec. 31, 2017		$ 824	$ 110	$ 24	$ 5		$ 105	$ 1,068
Partners' Equity at beginning of year (in units) at Dec. 31, 2017		70.6	1.9
Increase (Decrease) in Partners' Equity
Net income		$ 94		2			6	102
Other comprehensive income					7			7
ATM equity issuances, net (Note 8)	$ 39	$ 39		1				40
ATM equity issuances, net (Note 8) (in units)		0.7
Distributions		$ (71)	$ (15)	(5)			(2)	(93)
Partners' Equity at end of year at Mar. 31, 2018		$ 886	$ 95	$ 22	$ 12		$ 109	$ 1,124
Partners' Equity at end of year (in units) at Mar. 31, 2018		71.3	1.9
[1]	Losses related to cash flow hedges reported in Accumulated Other Comprehensive Loss and expected to be reclassified to Net income in the next 12 months are estimated to be $4 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.

CONSOLIDATED STATEMENT OF CHAN8

CONSOLIDATED STATEMENT OF CHANGES IN PARTNERS' EQUITY (Parenthetical) $ in Millions	3 Months Ended
	Mar. 31, 2018USD ($)
CONSOLIDATED STATEMENT OF CHANGES IN PARTNERS' EQUITY
Losses expected to be reclassified to Net income in the next 12 months	$ 4

ORGANIZATION

ORGANIZATION	3 Months Ended
	Mar. 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. The Partnership owns its pipeline assets through three intermediate limited partnerships (ILPs), TC GL Intermediate Limited Partnership, TC PipeLines Intermediate Limited Partnership and TC Tuscarora Intermediate Limited Partnership.

SIGNIFICANT ACCOUNTING POLICIES

SIGNIFICANT ACCOUNTING POLICIES	3 Months Ended
	Mar. 31, 2018
SIGNIFICANT ACCOUNTING POLICIES
SIGNIFICANT ACCOUNTING POLICIES	NOTE 2 SIGNIFICANT ACCOUNTING POLICIES The accompanying financial statements and related notes have been prepared in accordance with United States generally accepted accounting principles (GAAP) and amounts are stated in U.S. dollars. The results of operations for the three months ended March 31, 2018 and 2017 are not necessarily indicative of the results that may be expected for the full fiscal year. The accompanying financial statements should be read in conjunction with the audited financial statements and notes thereto for the year ended December 31, 2017 included in our Annual Report on Form 10-K. That report contains a more comprehensive summary of the Partnership’s significant accounting policies. In the opinion of management, the accompanying financial statements contain all of the appropriate adjustments, all of which are normally recurring adjustments unless otherwise noted, and considered necessary to present fairly the financial position of the Partnership, the results of operations and cash flows for the respective periods. Our significant accounting policies are consistent with those disclosed in our Annual Report on Form 10-K for the year ended December 31, 2017, except as described in Note 3, Accounting Pronouncements. Basis of Presentation The Partnership consolidates its interests in entities over which it is able to exercise control. To the extent there are interests owned by other parties, these interests are included in non-controlling interests. The Partnership uses the equity method of accounting for its investments in entities over which it is able to exercise significant influence. Acquisitions by the Partnership from TransCanada are considered common control transactions. When businesses are acquired from TransCanada that will be consolidated by the Partnership, the historical financial statements are required to be recast, except net income per common unit, to include the acquired entities for all periods presented. When the Partnership acquires an asset or an investment from TransCanada, which will be accounted for by the equity method, the financial information is not required to be recast and the transaction is accounted for prospectively from the date of the acquisition. On June 1, 2017, the Partnership acquired from a subsidiary of TransCanada an additional 11.81 percent interest in PNGTS, that resulted in the Partnership owning a 61.71 percent interest in PNGTS. As a result of the Partnership owning a 61.71 percent interest in PNGTS, the Partnership’s historical financial information has been recast, except net income per common unit, to consolidate PNGTS for all the periods presented in the Partnership’s consolidated financial statements. Additionally, this acquisition was accounted for as transaction between entities under common control, similar to pooling of interests, whereby the assets and liabilities of PNGTS were recorded at TransCanada’s carrying value. Also, on June 1, 2017, the Partnership acquired from subsidiaries of TransCanada a 49.34 percent interest in Iroquois. Accordingly, this transaction was accounted for as a transaction between entities under common control, similar to pooling of interest, whereby the equity investment in Iroquois was recorded at TransCanada’s carrying value and was accounted for prospectively from the date of acquisition. Use of Estimates The preparation of financial statements requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities as of the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Although management believes these estimates are reasonable, actual results could differ from these estimates.

ACCOUNTING PRONOUNCEMENTS

ACCOUNTING PRONOUNCEMENTS	3 Months Ended
	Mar. 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 new guidance also requires additional disclosures about the nature, amount, timing and uncertainty of revenue recognition and the related cash flows. The new guidance was effective January 1, 2018, 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 income line items. This new guidance is effective January 1, 2019 with early adoption permitted. The Partnership has elected to apply this guidance effective January 1, 2018. Application of this guidance did not have a material impact on its consolidated financial statements. 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 requiring the customer to have both (1) the right to obtain substantially all of the economic benefits from the use of the asset and (2) the right to direct the use of the asset in order for the arrangement to qualify as a lease. The new guidance also establishes a right-of-use (ROU) model that requires a lessee to recognize a ROU asset and corresponding lease liability on the balance sheet for all leases with a term longer than 12 months. Leases will be classified as finance or operating, with classification affecting the pattern and classification of expense recognition in the income statement. The new guidance does not make extensive changes to lessor accounting. In January 2018, the FASB issued new guidance on accounting for land easements which provides an optional transition practical expedient to not evaluate existing or expired land easements not accounted for as leases prior to entity’s adoption of the new 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 new guidance is effective on January 1, 2019, with early adoption permitted. A modified retrospective transition approach is required for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements, with certain practical expedients available. The Partnership is continuing to identify and analyze existing lease agreements to determine the effect of adoption of the new guidance on its consolidated financial statements. The Partnership is also addressing system and process changes necessary to compile the information to meet the recognition and disclosure requirements of the new guidance. The Partnership continues to monitor and analyze additional guidance and clarification provided by FASB. Goodwill Impairment In January 2017, the FASB issued new guidance on simplifying the test for goodwill impairment by eliminating the requirement to calculate the implied fair value of goodwill to measure the impairment charge. Instead, entities will record an impairment charge based on the excess of a reporting unit’s carrying amount over its fair value. This new guidance is effective January 1, 2020 and will be applied prospectively, however, early adoption is permitted. 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. 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.

REGULATORY

REGULATORY	3 Months Ended
	Mar. 31, 2018
REGULATORY
REGULATORY	NOTE 4 REGULATORY In December 2016, FERC issued a Notice of Inquiry (NOI) Regarding the Commission’s Policy for Recovery of Income Tax Costs (Docket No. PL17-1-000) 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 H.R.1, originally known as the Tax Cuts and Jobs Act (the “2017 Tax Act”). This legislation provides for major changes to U.S. corporate federal tax law including a reduction of the federal corporate income tax rate. We are a non-taxable limited partnership for 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 federal income taxes as a result of the 2017 Tax Act. On March 15, 2018, FERC issued (1) a revised Policy Statement to address the treatment of income taxes for ratemaking purposes for MLPs, (2) a Notice of Proposed Rulemaking (NOPR) proposing interstate pipelines file a one-time report to quantify the impact of the federal income tax rate reduction and the revised Policy Statement could have on a pipeline’s Return on Equity (ROE) assuming a single-issue adjustment to a pipeline’s rates, and (3) an NOI seeking comment on how FERC should address changes related to accumulated deferred income taxes and bonus depreciation (collectively, the “2018 FERC Actions”). Each is further described below. FERC Revised Policy Statement on Income Tax Allowance Cost Recovery in MLP Pipeline Rates FERC changed its long-standing policy on the treatment of income tax amounts to be included in pipeline rates and other assets subject to cost of service rate regulation held within an MLP. The revised Policy Statement no longer permits entities organized as MLPs to recover an income tax allowance in their cost of service rates. TransCanada filed a Request for Clarification and If Necessary Rehearing of FERC’s revised Policy Statement on April 16, 2018, addressing concerns over the lack of clarity around entities with ownership shared between an MLP and a corporation as well as other related concerns. In the request, TransCanada sought clarification or rehearing on several bases: that FERC erred in not assessing the propriety of income tax allowances for pipelines on a case-by-case basis; that FERC overturned applicable legal precedent expressly not affected by United ; that FERC failed to consider the effects of its revised policy on industry; and that FERC failed to exhibit reasoned decision making or to support its decision with substantial evidence on the record. NOPR on Tax Law Changes for Natural Gas Companies The NOPR proposes that by a deadline to be set in final rule-making, interstate pipelines must either file a new uncontested settlement or comply with a rule that would require companies to file a one-time report, called FERC Form No. 501-G, that quantifies the rate impact of 2017 Tax Act and, with respect to pipelines held by MLPs, the FERC’s revised Policy Statement. Concurrent with filing the one-time report, each pipeline would have four options: · make a limited Natural Gas Act Section 4 filing to reduce its rates by the percentage reduction in its cost of service shown in its FERC Form No. 501-G · commit to file either a pre-packaged uncontested rate settlement or a general Section 4 rate case if it believes that using the limited Section 4 option will not result in just and reasonable rates. If the pipeline commits to file either by December 31, 2018, FERC will not initiate a Natural Gas Act Section 5 investigation of its rates prior to that date · file a statement explaining its rationale for why it does not believe the pipeline’s rates must change · take no action other than filing the one-time 501-G report. FERC would then consider whether to initiate a Section 5 investigation of any pipeline that has not submitted a limited Section 4 rate reduction filing or committed to file a general Section 4 rate case. TransCanada submitted comments on the NOPR on April 25, 2018. Following the requisite public comment period, we expect FERC to issue final order(s) in the late summer or early fall of 2018. We continue to evaluate this NOPR and our next course of action, however, we do not expect an immediate or a retroactive impact from the NOPR or the revised Policy Statement described above. NOI Regarding the Effect of the 2017 Tax Act on Commission-Jurisdictional Rates In the NOI, FERC seeks comment to determine what additional action as a result of the 2017 Tax Act, if any, is required by FERC related to accumulated deferred income taxes collected from shippers in anticipation of ultimately being paid to the Internal Revenue Service, but which no longer accurately reflect the future income tax liability. The NOI also seeks comment on the elimination of bonus depreciation for regulated natural gas pipelines and other effects of the 2017 Tax Act. We plan to submit comments in response to the NOI by the due date of May 21, 2018. Impairment Considerations As noted under Note 2, the preparation of financial statements in accordance with GAAP requires us to make estimates and assumptions with respect to values or conditions, which cannot be known with certainty, that affect the reported amount of assets and liabilities at the date of the financial statements. Although we believe these estimates and assumptions are reasonable, actual results could differ. We review plant, property and equipment and equity investments for impairment whenever events or changes in circumstances indicate the carrying value of the asset may not be recoverable. Goodwill is tested for impairment on an annual basis or more frequently if events or changes in circumstance indicate that it might be impaired. We can initially make this assessment based on qualitative factors. If we conclude that it is not more likely than not that the fair value of the reporting unit is less than its carrying value, an impairment test is not performed. Until the proposed 2018 FERC Actions are finalized, implementation requirements are clarified, including the applicability to assets partially-owned by a MLP or held in non-MLP structures, and we have fully evaluated our respective alternatives to minimize the potential negative impact of the 2018 FERC Actions on our future operating performance and cash flows, we believe that it is not more likely than not that the fair values of our reporting units are less than their respective carrying values. Therefore, a goodwill impairment test was not performed. Also, we have determined there is no indication that the carrying values of plant, property and equipment and equity investments potentially impacted by the 2018 FERC Actions are not recoverable. We will continue to monitor developments and assess our goodwill for impairment. We will also review our property, plant and equipment and equity investments for recoverability as new information becomes available. At December 31, 2017, the estimated fair value of our investment in Great Lakes exceeded its carrying value by less than 10 percent. There is a risk that the 2018 FERC Actions, once finalized, could result in an impairment charge to our equity method goodwill on Great Lakes amounting to $260 million at March 31, 2018 (December 31, 2017 — $260 million). Additionally, since the estimated fair value of Tuscarora exceeded its carrying value by less than 10 percent in its most recent valuation, there is also a risk that the $82 million goodwill at March 31, 2018 (December 31, 2017 - $82 million) related to Tuscarora could be negatively impacted by the 2018 FERC Actions.

EQUITY INVESTMENTS

EQUITY INVESTMENTS	3 Months Ended
	Mar. 31, 2018
EQUITY INVESTMENTS
EQUITY INVESTMENTS	NOTE 5 EQUITY INVESTMENTS The Partnership has equity interests in Northern Border, Great Lakes and Iroquois. The pipeline systems owned by these entities are regulated by FERC. The pipeline systems of Northern Border and Great Lakes are operated by subsidiaries of TransCanada. The Iroquois pipeline system is operated by Iroquois Pipeline Operating Company, a wholly owned subsidiary of Iroquois. The Partnership uses the equity method of accounting for its interests in its equity investees. The Partnership’s equity investments are held through our ILPs that are considered to be variable interest entities (VIEs) (Refer to Note 17). Ownership Equity Earnings Equity Investments Interest at Three months (unaudited) March 31, ended March 31, March 31, December 31, (millions of dollars) 2018 2018 2017 2018 2017 Northern Border (a) % Great Lakes % Iroquois (b) % — (a) Equity earnings from Northern Border is net of the 12-year amortization of a $10 million transaction fee paid to the operator of Northern Border at the time of the Partnership’s acquisition of an additional 20 percent interest in April 2006. (b) The Partnership acquired a 49.34% interest in Iroquois on June 1, 2017. Distributions from Equity Investments Distributions received from equity investments for the quarter ended March 31, 2018 were $45 million (2017 — $28 million;) of which $2 million (2017 - 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 did not have undistributed earnings from Northern Border for the three months ended March 31, 2018 and 2017. The summarized financial information provided to us by Northern Border is as follows: (unaudited) (millions of dollars) March 31, 2018 December 31, 2017 ASSETS Cash and cash equivalents Other current assets Plant, property and equipment, net Other assets LIABILITIES AND PARTNERS’ EQUITY Current liabilities Deferred credits and other Long-term debt, net (a) Partners’ equity Partners’ capital Accumulated other comprehensive loss ) ) Three months ended (unaudited) March 31, (millions of dollars) 2018 2017 Transmission revenues Operating expenses ) ) Depreciation ) ) Financial charges and other ) ) Net income (a) No current maturities as of March 31, 2018 and December 31, 2017. Great Lakes The Partnership made an equity contribution to Great Lakes of $4 million in the first quarter of 2018. This amount represents the Partnership’s 46.45 percent share of a $9 million cash call from Great Lakes to make a scheduled debt repayment. The Partnership did not have undistributed earnings from Great Lakes for the three months ended March 31, 2018 and 2017. The summarized financial information provided to us by Great Lakes is as follows: (unaudited) (millions of dollars) March 31, 2018 December 31, 2017 ASSETS Current assets Plant, property and equipment, net LIABILITIES AND PARTNERS’ EQUITY Current liabilities Net long-term debt, including current maturities (a) Other long term liabilities — Partners’ equity Three months ended (unaudited) March 31, (millions of dollars) 2018 2017 Transmission revenues Operating expenses ) ) Depreciation ) ) Financial charges and other ) ) Net income (a) Includes current maturities of $21 million as of March 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. During the three months ended March 31, 2018, the Partnership received distributions from Iroquois amounting to $14 million which includes the Partnership’s 49.34 percent share of the Iroquois unrestricted cash distribution amounting to approximately $2 million. The unrestricted cash does not represent a distribution of Iroquois’ cash from operations during the period and therefore it was reported as distributions received as return of investment in the Partnership’s consolidated statement of cash flows. Iroquois declared its first quarter 2018 distribution of $29 million on March 7, 2018, of which the Partnership received its 49.34 percent share or $14 million on May 1, 2018. The distribution includes our 49.34 percent share of the Iroquois unrestricted cash distribution amounting to approximately $2.6 million. The Partnership did not have undistributed earnings from Iroquois for the three months ended March 31, 2018. The summarized financial information provided to us by Iroquois for the period from the June 1, 2017 acquisition date through March 31, 2018 is as follows: (unaudited) (millions of dollars) March 31, 2018 December 31, 2017 ASSETS Cash and cash equivalents Other current assets Plant, property and equipment, net Other assets LIABILITIES AND PARTNERS’ EQUITY Current liabilities Net long-term debt, including current maturities (a) Other non-current liabilities Partners’ equity (unaudited) Three months (millions of dollars) March 31, 2018 Transmission revenues Operating expenses ) Depreciation ) Financial charges and other ) Net income (a) Includes current maturities of $4 million as of March 31, 2018 (December 31, 2017 - $4 million).

REVENUES

REVENUES	3 Months Ended
	Mar. 31, 2018
REVENUES
REVENUES	NOTE 6 REVENUES In 2014, the FASB issued new guidance on revenue from contracts with customers. The Partnership adopted the new guidance on January 1, 2018 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 were prepared under previous revenue recognition guidance which is referred to herein as “legacy U.S. GAAP”. Disaggregation of Revenues For the three months ended March 31, 2018, virtually all of the Partnership’s revenues were from Capacity Arrangements and Transportation Contracts with customers as discussed in more detail below. Capacity Arrangements and Transportation Contracts The Partnership’s performance obligations in its contracts with customers consist primarily of capacity arrangements and natural gas transportation. 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. The Partnership has elected to utilize the practical expedient of recognizing revenue as invoiced. 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. 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. 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 As required by the new revenue recognition guidance, the following tables illustrate the pro-forma impact on the affected line items of the consolidated balance sheet, as at March 31, 2018, had legacy U.S. GAAP been applied (the income statement line items were not affected): March 31, 2018 (unaudited-millions of dollars) As reported Pro-forma using Balance Sheet Accounts receivable and other Contract assets — Contract Balances (unaudited-millions of dollars) March 31, 2018 January 1, 2018 Receivables from contracts with customers Contract assets — Contract assets primarily relate to the Partnership’s right to recognize revenues for services completed but not invoiced at the reporting date. Any change in Contract assets is primarily related to the transfer to Accounts receivable when the right to recognize revenue becomes unconditional and the customer is invoiced as well as when revenue increases but remains to be invoiced. Future revenue from remaining performance obligations As required by the new revenue recognition guidance, the Partnership is required to provide disclosure on future revenue allocated to remaining performance obligations on our contracts with customers that have not yet been recognized. However, all of the Partnership’s contracts qualify for the use of a practical expedient listed below and therefore no disclosure on future revenues from remaining performance obligations is necessary: 1) The original expected duration of the contract is one year or less. 2) The Partnership recognizes revenue from the contract that is equal to the amount invoiced. This is referred to as the ‘right to invoice’ practical expedient. 3) The variable revenue generated from the contract is allocated entirely to a wholly unsatisfied performance obligation or to a wholly unsatisfied promise to transfer a distinct good or service that forms part of a single performance obligation in a series. A single performance obligation in a series occurs when the promises under a contract are a series of distinct services that are substantially the same and have the same pattern of transfer to the customer over time. 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 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. In addition, the Partnership considers interruptible transportation service revenues to be variable revenues as volumes cannot be estimated. These variable revenues are recognized on a monthly basis when the Partnership’s performance obligation of natural gas deliveries is made at the agreed-upon delivery point. Lastly, future revenues from the Partnership’s firm capacity contracts include fixed revenues for the time periods when current rate settlements are in effect, which is approximately one to four years. Many of these contracts are long-term in nature and revenues from the remaining performance obligations on these contracts will be recognized using the FERC approved rates once the performance obligation to provide capacity has been satisfied.

DEBT AND CREDIT FACILITIES

DEBT AND CREDIT FACILITIES	3 Months Ended
	Mar. 31, 2018
DEBT AND CREDIT FACILITIES
DEBT AND CREDIT FACILITIES	NOTE 7 DEBT AND CREDIT FACILITIES (unaudited) March 31, Weighted Average December 31, Weighted Average TC PipeLines, LP Senior Credit Facility due 2021 % % 2013 Term Loan Facility due 2022 % % 2015 Term Loan Facility due 2020 % % 4.65% Unsecured Senior Notes due 2021 % (a) % (a) 4.375% Unsecured Senior Notes due 2025 % (a) % (a) 3.90 % Unsecured Senior Notes due 2027 % (a) % (a) GTN 5.29% Unsecured Senior Notes due 2020 % (a) % (a) 5.69% Unsecured Senior Notes due 2035 % (a) % (a) Unsecured Term Loan Facility due 2019 % % PNGTS 5.90% Senior Secured Notes due 2018 (b) % (a) (c ) % (a) Tuscarora Unsecured Term Loan due 2020 % % Less: unamortized debt issuance costs and debt discount Less: current portion (b) (c) (a) Fixed interest rate (b) Includes the PNGTS portion due at March 31, 2018 amounting to $6.1 million that was paid on April 2, 2018. (c) Includes the PNGTS portion due at December 31, 2017 amounting to $5.8 million that was paid on January 2, 2018. TC PipeLines, LP The Partnership’s Senior Credit Facility consists of a $500 million senior revolving credit facility with a banking syndicate, maturing November 10, 2021, under which $165 million was outstanding at March 31, 2018 (December 31, 2017 - $185 million), leaving $335 million available for future borrowing. The LIBOR-based interest rate on the Senior Credit Facility was 2.92 percent at March 31, 2018 (December 31, 2017 — 2.62 percent). As of March 31, 2018, the variable interest rate exposure related to the 2013 Term Loan Facility was hedged by fixed interest rate swap arrangements and our effective interest rate was 2.31 percent (December 31, 2017 — 2.31 percent). Prior to hedging activities, the LIBOR-based interest rate on the 2013 Term Loan Facility was 2.92 percent at March 31, 2018 (December 31, 2017 — 2.62 percent). The LIBOR-based interest rate on the 2015 Term Loan Facility was 2.81 percent at March 31, 2018 (December 31, 2017 — 2.51 percent). The 2013 Term Loan Facility and the 2015 Term Loan Facility (collectively, the Term Loan Facilities) and the Senior Credit Facility require the Partnership to maintain a certain leverage ratio (debt to adjusted cash flow [net income plus cash distributions received, extraordinary losses, interest expense, expense for taxes paid or accrued, and depreciation and amortization expense less equity earnings and extraordinary gains]) no greater than 5.00 to 1.00 for each fiscal quarter, except for the fiscal quarter and the two following fiscal quarters in which one or more acquisitions has been executed, in which case the leverage ratio is to be no greater than 5.50 to 1.00. The leverage ratio was 4.56 to 1.00 as of March 31, 2018. GTN GTN’s Unsecured Senior Notes, along with GTN’s Unsecured Term Loan Facility contain a covenant that limits total debt to no greater than 70 percent of GTN’s total capitalization. GTN’s total debt to total capitalization ratio at March 31, 2018 was 44 percent. The LIBOR-based interest rate on the GTN’s Unsecured Term Loan Facility was 2.61 percent at March 31, 2018 (December 31, 2017 — 2.31 percent). PNGTS PNGTS’ Senior Secured Notes are secured by the PNGTS long-term firm shipper contracts and its partners’ pledge of their equity and a guarantee of debt service for six months. PNGTS is restricted under the terms of its note purchase agreement from making cash distributions unless certain conditions are met. Before a distribution can be made, the debt service reserve account must be fully funded and PNGTS’ debt service coverage ratio for the preceding and succeeding twelve months must be 1.30 or greater. At March 31, 2018, the debt service coverage ratio was 1.65 for the twelve preceding months and 2.14 for the twelve succeeding months. Therefore, PNGTS was not restricted to make any cash distributions. 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 facility will be utilized to fund the costs of the PXP expansion project, including the repayment of the existing 5.90% Senior Notes. Tuscarora Tuscarora’s Unsecured Term Loan contains a covenant that requires Tuscarora to maintain a debt service coverage ratio (cash available from operations divided by a sum of interest expense and principal payments) of greater than or equal to 3.00 to 1.00. As of March 31, 2018, the ratio was 11.2 to 1.00. The LIBOR-based interest rate on the Tuscarora’s Unsecured Term Loan Facility was 2.79 percent at March 31, 2018 (December 31, 2017 — 2.49 percent). At March 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 Third Amended and Restated Agreement of Limited Partnership (Partnership Agreement), incurring additional debt and distributions to unitholders. Refer also to Note 19 for important information relating to distribution reduction to retain cash that will be used to fund ongoing capital expenditures and the repayment of debt to levels that prudently manage our financial metrics in response to the potential negative impact of the 2018 FERC Actions on our future operating performance and cashflows. The principal repayments required of the Partnership on its debt are as follows: (unaudited) (millions of dollars) 2018 2019 2020 2021 2022 Thereafter

PARTNERS' EQUITY

PARTNERS' EQUITY	3 Months Ended
	Mar. 31, 2018
PARTNERS' EQUITY
PARTNERS' EQUITY	NOTE 8 PARTNERS’ EQUITY ATM equity issuance program (ATM program) During the three months ended March 31, 2018, we issued 0.7 million common units under our ATM program generating net proceeds of approximately $39 million, plus $1 million contributed by the General Partner to maintain its effective two percent general partner interest. The commissions to our sales agents in the three months ended March 31, 2018 were nil. The net proceeds were used for general partnership purposes. Class B units issued to TransCanada The Class B Units we issued on April 1, 2015 to finance a portion of the 2015 GTN Acquisition represent a limited partner interest in us and entitle TransCanada to an annual distribution based on 30 percent of GTN’s annual distributions as follows: (i) 100 percent of distributions above $20 million through March 31, 2020; and (ii) 25 percent of distributions above $20 million thereafter. Additionally, the Class B distribution will be further reduced by the percentage by which distributions payable to common units is reduced for the calendar year (Class B Reduction). For the year ending December 31, 2018, the Class B units’ equity account will be increased by the excess of 30 percent of GTN’s distributions less the annual threshold of $20 million and the Class B Reduction and until such amount is declared for distribution and paid in the first quarter of 2019. During the three months ended March 31, 2018, the threshold was not exceeded. For the year ended December 31, 2017, the Class B distribution was $15 million and was declared and paid in the first quarter of 2018.

NET INCOME PER COMMON UNIT

NET INCOME PER COMMON UNIT	3 Months Ended
	Mar. 31, 2018
NET INCOME PER COMMON UNIT
NET INCOME PER COMMON UNIT	NOTE 9 NET INCOME PER COMMON UNIT Net income per common unit is computed by dividing net income attributable to controlling interests, after deduction of net income attributable to PNGTS’ former parent, amounts attributable to the General Partner and Class B units, by the weighted average number of common units outstanding. The amount allocable to the General Partner equals an amount based upon the General Partner’s effective two percent general partner interest, plus an amount equal to incentive distributions. Incentive distributions are paid to the General Partner if quarterly cash distributions on the common units exceed levels specified in the Partnership Agreement. The amount allocable to the Class B units in 2018 equals 30 percent of GTN’s distributable cash flow during the year ended December 31, 2018 less $20 million and the Class B Reduction (December 31, 2017 —$20 million). During the three months ended March 31, 2018 and 2017, no amounts were allocated to the Class B units as the annual threshold was not exceeded. Net income per common unit was determined as follows: (unaudited) Three months ended March 31, (millions of dollars, except per common unit amounts) 2018 2017 Net income attributable to controlling interests (a) Net income attributable to PNGTS’ former parent (b) — ) (a) Net income allocable to General Partner and Limited Partners Net income attributable to the General Partner ) ) Incentive distributions attributable to the General Partner (c) — ) Net income attributable to common units Weighted average common units outstanding (millions) — basic and diluted Net income per common unit — basic and diluted $ $ (d) (a) Recast to consolidate PNGTS (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) Net income per common unit prior to recast (Refer to Note 2).

CASH DISTRIBUTIONS

CASH DISTRIBUTIONS	3 Months Ended
	Mar. 31, 2018
CASH DISTRIBUTIONS
CASH DISTRIBUTIONS	NOTE 10 CASH DISTRIBUTIONS During the three months ended March 31, 2018, the Partnership distributed $1.00 per common unit (March 31, 2017 — $0.94 per common unit) for a total of $76 million (March 31, 2017 - $68 million). The distribution paid to our General Partner during the three months ended March 31, 2018 for its effective two percent general partner interest was $2 million along with an IDR payment of $3 million for a total distribution of $5 million (March 31, 2017 - $2 million for the effective two percent interest and a $2 million IDR payment).

CHANGE IN OPERATING WORKING CAP

CHANGE IN OPERATING WORKING CAPITAL	3 Months Ended
	Mar. 31, 2018
CHANGE IN OPERATING WORKING CAPITAL
CHANGE IN OPERATING WORKING CAPITAL	NOTE 11 CHANGE IN OPERATING WORKING CAPITAL (unaudited) Three months ended March 31, (millions of dollars) 2018 2017 (a) Change in accounts receivable and other — Change in other current assets ) Change in accounts payable and accrued liabilities — ) Change in accounts payable to affiliates — ) Change in accrued interest Change in operating working capital (a) Recast to consolidate PNGTS (Refer to Note 2).

RELATED PARTY TRANSACTIONS

RELATED PARTY TRANSACTIONS	3 Months Ended
	Mar. 31, 2018
RELATED PARTY TRANSACTIONS
RELATED PARTY TRANSACTIONS	NOTE 12 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 conduct the business of, and allocable to, the Partnership. Such costs include (i) overhead costs (such as office space and equipment) and (ii) out-of-pocket expenses related to the provision of such services. The Partnership Agreement provides that the General Partner will determine the costs that are allocable to the Partnership in any reasonable manner determined by the General Partner in its sole discretion. For both the three months ended March 31, 2018 and 2017, total costs charged to the Partnership by the General Partner were $1 million. As operator of our pipelines except Iroquois, TransCanada’s subsidiaries provide capital and operating services to our pipeline systems. TransCanada’s subsidiaries incur costs on behalf of our pipeline systems, including, but not limited to, employee salary and benefit costs, and property and liability insurance costs. The Iroquois pipeline system is operated by Iroquois Pipeline Operating Company, a wholly owned subsidiary of Iroquois. Therefore, Iroquois does not receive any capital and operating services from TransCanada. Capital and operating costs charged to our pipeline systems, except for Iroquois, for the three months ended March 31, 2018 and 2017 by TransCanada’s subsidiaries and amounts payable to TransCanada’s subsidiaries at March 31, 2018 and December 31, 2017 are summarized in the following tables: Three months ended (unaudited) March 31, (millions of dollars) 2018 2017 Capital and operating costs charged by TransCanada’s subsidiaries to: Great Lakes (a) Northern Border (a) GTN Bison North Baja Tuscarora PNGTS (a) (b) Impact on the Partnership’s net income: Great Lakes Northern Border GTN Bison North Baja Tuscarora PNGTS (b) (unaudited) (millions of dollars) March 31, 2018 December 31, 2017 Net amounts payable to TransCanada’s subsidiaries is as follows: Great Lakes (a) (c) Northern Border (a) GTN Bison North Baja — — Tuscarora — — PNGTS (a) (a) Represents 100 percent of the costs. (b) Recast to consolidate PNGTS (Refer to Note 2). (c) Excludes any amounts owed to affiliates relating to revenue sharing. See discussion below. Great Lakes Great Lakes earns significant transportation revenues from TransCanada and its affiliates, some of which are provided at discounted rates and some at maximum recourse rates. For the three months ended March 31, 2018, Great Lakes earned 68 percent of transportation revenues from TransCanada and its affiliates (2017 — 67 percent). At March 31, 2018, $10 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. For the year ended December 31, 2017, Great Lakes has recorded an estimated revenue sharing provision amounting to $40 million, a significant amount of which will be payable to its affiliates. Under the terms of the 2017 Great Lakes Settlement, beginning 2018, its revenue sharing provision was eliminated (Refer to our Annual Report on form 10-K for the year ended December 31, 2017). PNGTS PNGTS earns transportation revenues from TransCanada and its affiliates. For the three months ended March 31, 2018, PNGTS earned approximately $1 million of its transportation revenues from TransCanada and its affiliates (2017 — nil). At March 31, 2018, nil was included in PNGTS’ receivables in regards to the transportation contracts with TransCanada and its affiliates (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. At March 31, 2018, the total costs incurred by these affiliates was approximately $5 million.

FAIR VALUE MEASUREMENTS

FAIR VALUE MEASUREMENTS	3 Months Ended
	Mar. 31, 2018
FAIR VALUE MEASUREMENTS
FAIR VALUE MEASUREMENTS	NOTE 13 FAIR VALUE MEASUREMENTS (a) Fair Value Hierarchy Under Accounting Standards Codification (ASC) 820, Fair Value Measurements and Disclosures , fair value measurements are characterized in one of three levels based upon the inputs used to arrive at the measurement. The three levels of the fair value hierarchy are as follows: · Level 1 inputs are quoted prices (unadjusted) in active markets for identical assets or liabilities that we have the ability to access at the measurement date. · Level 2 inputs are inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly. · Level 3 inputs are unobservable inputs for the asset or liability. When appropriate, valuations are adjusted for various factors including credit considerations. Such adjustments are generally based on available market evidence. In the absence of such evidence, management’s best estimate is used. (b) Fair Value of Financial Instruments The carrying value of cash and cash equivalents, accounts receivable and other, accounts payable and accrued liabilities, accounts payable to affiliates and accrued interest approximate their fair values because of the short maturity or duration of these instruments, or because the instruments bear a variable rate of interest or a rate that approximates current rates. The fair value of the Partnership’s debt is estimated by discounting the future cash flows of each instrument at estimated current borrowing rates. The fair value of interest rate derivatives is calculated using the income approach, which uses period-end market rates and applies a discounted cash flow valuation model. Long-term debt is recorded at amortized cost and classified as Level 2 of the fair value hierarchy for fair value disclosure purposes. Interest rate derivative assets and liabilities are classified as 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 March 31, 2018 and December 31, 2017 was $2,408 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. The Partnership hedged interest payments on the variable-rate 2013 Term Loan Facility with interest rate swaps maturing July 1, 2018, at a weighted average fixed interest rate of 2.31 percent. At March 31, 2018, the fair value of the interest rate swaps accounted for as cash flow hedges was an asset of $12 million (both on a 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 gain of $7 million for the three months ended March 31, 2018 (2017 — gain of $1 million). For the three months ended March 31, 2018, the net realized gain related to the interest rate swaps was $1 million, and was included in financial charges and other (2017 - nil) (Refer to Note 15). The Partnership’s $500 million 2013 Term Loan is hedged using fixed interest rate swaps until July 1, 2018 at an average rate of 2.31 percent. From July 2, 2018 until its October 2, 2022 maturity, it will be hedged using forward starting swaps at an average rate of 3.26 percent. The Partnership has no master netting agreements; however, it has derivative contracts containing provisions with rights of offset. The Partnership has elected to present the fair value of derivative instruments with the right to offset on a gross basis in the balance sheet. Had the Partnership elected to present these instruments on a net basis, there would be no effect on the consolidated balance sheet as of March 31, 2018 (net asset of $5 million as of December 31, 2017). In anticipation of a debt refinancing in 2003, PNGTS entered into forward interest rate swap agreements to hedge the interest rate on its Senior Secured Notes due in 2018. These interest rate swaps were used to manage the impact of interest rate fluctuations and qualified as derivative financial instruments in accordance with Accounting Standards Codification (ASC) 815, Derivatives and Hedging . PNGTS settled its position with a payment of $20.9 million to counterparties at the time of the refinancing and recorded the realized loss in accumulated other comprehensive income as of the termination date. The previously recorded loss is currently being amortized against earnings over the life of the PNGTS Senior Secured Notes. At March 31, 2018, our 61.71 percent proportionate share of net unamortized loss on PNGTS included in other comprehensive income was $1 million (December 31, 2017 - $1 million). For the three months ended March 31, 2018 and 2017, our 61.71 percent proportionate share of the amortization of realized loss on derivative instruments was nil.

ACCOUNTS RECEIVABLE AND OTHER

ACCOUNTS RECEIVABLE AND OTHER	3 Months Ended
	Mar. 31, 2018
ACCOUNTS RECEIVABLE AND OTHER
ACCOUNTS RECEIVABLE AND OTHER	NOTE 14 ACCOUNTS RECEIVABLE AND OTHER (unaudited) (millions of dollars) March 31, 2018 December 31, 2017 Trade accounts receivable, net of allowance of nil Imbalance receivable from affiliates Other

FINANCIAL CHARGES AND OTHER

FINANCIAL CHARGES AND OTHER	3 Months Ended
	Mar. 31, 2018
FINANCIAL CHARGES AND OTHER
FINANCIAL CHARGES AND OTHER	NOTE 15 FINANCIAL CHARGES AND OTHER Three months ended (unaudited) March 31, (millions of dollars) 2018 2017 (b) Interest expense (a) Net realized gain related to the interest rate swaps ) — (a) Includes amortization of debt issuance costs and discount costs. (b) Recast to consolidate PNGTS (Refer to Note 2).

CONTINGENCIES

CONTINGENCIES	3 Months Ended
	Mar. 31, 2018
CONTINGENCIES
CONTINGENCIES	NOTE 16 CONTINGENCIES Great Lakes v. Essar Steel Minnesota LLC, et al . — On October 29, 2009, Great Lakes filed suit in the U.S. District Court, District of Minnesota, against Essar Minnesota LLC (Essar Minnesota) and certain Foreign Essar Affiliates (collectively, Essar) for breach of its monthly payment obligation under its transportation services agreement with Great Lakes. Great Lakes sought to recover approximately $33 million for past and future payments due under the agreement. In September 2015, the federal district court judge entered a judgment in the amount of $32.9 million in favor of Great Lakes. Essar successfully appealed this decision to the United States Court of Appeals for the Eighth Circuit (Eighth Circuit) based on an allegation of improper jurisdiction and various other rulings by the federal district judge. The Eighth Circuit vacated Great Lakes’ judgment against Essar finding that there was no federal jurisdiction. In May 2017, the federal district court awarded Essar Minnesota approximately $1.2 million for costs, including recovery of the premium for the performance bond Essar was required to post pending appeal. Essar Minnesota filed for bankruptcy in July 2016. Following Essar’s successful appeal and award of $1.2 million of costs, Great Lakes was required to release the $1.2 million into the bankruptcy estates. Great Lakes filed a claim against Essar Minnesota in the bankruptcy court. The bankruptcy court approved Great Lakes’ unsecured claim in the amount of $31.5 million in April 2017. Great Lakes is unable to estimate the timing or the extent to which its claim will be recoverable in the bankruptcy proceedings. The Foreign Essar Affiliates have not filed for bankruptcy and Great Lakes’ case against the Foreign Essar Affiliates in Minnesota state court remains pending. The Foreign Essar Affiliates gave an offer of judgment (Offer of Judgment) in the federal district court proceeding whereby the Foreign Essar Affiliates agreed to satisfy any judgment awarded to Great Lakes. The Foreign Essar Affiliates dispute that the Offer of Judgment is enforceable because the federal court judgment was vacated on appeal. Great Lakes has obtained a consent order from the bankruptcy court permitting it to petition the state court to enforce the Offer of Judgment. If unsuccessful in state court, Great Lakes can return to bankruptcy court for an order permitting it to proceed to trial in state court on its claims under the transportation services agreement against the Foreign Essar Affiliates. At March 31, 2018, Great Lakes is unable to estimate the timing or the extent to which its claim will be recoverable in the bankruptcy proceedings, therefore, it did not recognize any gain contingency on its outstanding claim against Essar. Additionally, at March 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

VARIABLE INTEREST ENTITIES	3 Months Ended
	Mar. 31, 2018
VARIABLE INTEREST ENTITIES
VARIABLE INTEREST ENTITIES	NOTE 17 VARIABLE INTEREST ENTITIES In the normal course of business, the Partnership must re-evaluate its legal entities under the current consolidation guidance to determine if those that are considered to be VIEs are appropriately consolidated or if they should be accounted for under other GAAP. A variable interest entity (VIE) is a legal entity that does not have sufficient equity at risk to finance its activities without additional subordinated financial support or is structured such that equity investors lack the ability to make significant decisions relating to the entity’s operations through voting rights or do not substantively participate in the gains or losses of the entity. A VIE is appropriately consolidated if the Partnership is considered to be the primary beneficiary. The VIE’s primary beneficiary is the entity that has both (1) the power to direct the activities of the VIE that most significantly impact the VIEs economic performance and (2) the obligation to absorb losses or the right to receive benefits from the VIE that could potentially be significant to the VIE. As a result of its analysis, the Partnership continues to consolidate all legal entities in which it has a variable interest and for which it is considered to be the primary beneficiary. VIEs where the Partnership is not the primary beneficiary, but has a variable interest in the entity, are accounted for as equity investments. Consolidated VIEs The Partnership’s consolidated VIEs consist of the Partnership’s ILPs that hold interests in the Partnership’s pipeline systems. After considering the purpose and design of the ILPs and the risks that they were designed to create and pass through to the Partnership, the Partnership has concluded that it is the primary beneficiary of these ILPs because of the significant amount of variability that it absorbs from the ILPs’ economic performance. The assets and liabilities held through these VIEs that are not available to creditors of the Partnership and whose investors have no recourse to the credit of the Partnership are held through GTN, Tuscarora, Northern Border, Great Lakes, PNGTS and Iroquois due to their third party debt. The following table presents the total assets and liabilities of these entities that are included in the Partnership’s consolidated balance sheets: (unaudited) (millions of dollars) March 31, 2018 December 31, 2017 ASSETS (LIABILITIES) * Cash and cash equivalents Accounts receivable and other Contract assets — Inventories Other current assets Equity investments Plant, property and equipment, net Other assets Accounts payable and accrued liabilities ) ) Accounts payable to affiliates, net ) ) Distributions payable ) ) State taxes payable ) — Accrued interest ) ) Current portion of long-term debt ) ) Long-term debt ) ) Other liabilities ) ) Deferred state income tax ) ) *North Baja and Bison, which are also assets held through our consolidated VIEs, are excluded as the assets of these entities can be used for purposes other than the settlement of the VIE’s obligations.

INCOME TAXES

INCOME TAXES	3 Months Ended
	Mar. 31, 2018
INCOME TAXES
INCOME TAXES	NOTE 18 INCOME TAXES The Partnership’s income taxes relate to business profits tax (BPT) levied at the partnership (PNGTS) level by the state of New Hampshire. As a result of the BPT, PNGTS recognizes deferred taxes related to temporary differences between the financial statement carrying amount of existing assets and liabilities and their respective tax bases. The deferred taxes at March 31, 2018 and December 31, 2017 relate primarily to utility plant. At March 31, 2018 and December 31, 2017 the New Hampshire BPT effective tax rate was 3.8 percent for both periods and was applied to PNGTS’ taxable income. Three months ended (unaudited) March 31, (millions of dollars) 2018 2017 (a) State income taxes Current Deferred — — (a) Recast to consolidate PNGTS (Refer to Note 2).

SUBSEQUENT EVENTS

SUBSEQUENT EVENTS	3 Months Ended
	Mar. 31, 2018
SUBSEQUENT EVENTS
SUBSEQUENT EVENTS	NOTE 19 SUBSEQUENT EVENTS Management of the Partnership has reviewed subsequent events through May 2, 2018, the date the financial statements were issued, and concluded there were no events or transactions during this period that would require recognition or disclosure in the consolidated financial statements other than what is disclosed here and/or those already disclosed in the preceding notes. On May 1, 2018, the board of directors of the General Partner declared the Partnership’s first quarter 2018 cash distribution in the amount of $0.65 per common unit payable on May 15, 2018 to unitholders of record as of May 9, 2018. 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 effective two percent general partner interest. The General Partner did not receive any distributions in respect of its IDRs for the first quarter 2018. This distribution represents a 35 percent reduction to the Partnership’s fourth quarter 2017 distribution of $1.00 per common unit. Cash retained by the Partnership will be used to fund ongoing capital expenditures and the repayment of debt to levels that prudently manage our financial metrics in response to the potential negative impact of the 2018 FERC Actions on our future operating performance and cashflows. Northern Border declared its March 2018 distribution of $8.8 million on April 12, 2018, of which the Partnership received its 50 percent share or $4.4 million on April 30, 2018. Great Lakes declared its first quarter 2018 distribution of $54.8 million on April 16, 2018, of which the Partnership received its 46.45 percent share or $25.5 million on May 1, 2018.

SIGNIFICANT ACCOUNTING POLICI28

SIGNIFICANT ACCOUNTING POLICIES (Policies)	3 Months Ended
	Mar. 31, 2018
SIGNIFICANT ACCOUNTING POLICIES
Basis of Presentation - Consolidation and equity method of accounting	Basis of Presentation The Partnership consolidates its interests in entities over which it is able to exercise control. To the extent there are interests owned by other parties, these interests are included in non-controlling interests. The Partnership uses the equity method of accounting for its investments in entities over which it is able to exercise significant influence.
Basis of Presentation - Transactions between entities under common control	Acquisitions by the Partnership from TransCanada are considered common control transactions. When businesses are acquired from TransCanada that will be consolidated by the Partnership, the historical financial statements are required to be recast, except net income per common unit, to include the acquired entities for all periods presented. When the Partnership acquires an asset or an investment from TransCanada, which will be accounted for by the equity method, the financial information is not required to be recast and the transaction is accounted for prospectively from the date of the acquisition. On June 1, 2017, the Partnership acquired from a subsidiary of TransCanada an additional 11.81 percent interest in PNGTS, that resulted in the Partnership owning a 61.71 percent interest in PNGTS. As a result of the Partnership owning a 61.71 percent interest in PNGTS, the Partnership’s historical financial information has been recast, except net income per common unit, to consolidate PNGTS for all the periods presented in the Partnership’s consolidated financial statements. Additionally, this acquisition was accounted for as transaction between entities under common control, similar to pooling of interests, whereby the assets and liabilities of PNGTS were recorded at TransCanada’s carrying value. Also, on June 1, 2017, the Partnership acquired from subsidiaries of TransCanada a 49.34 percent interest in Iroquois. Accordingly, this transaction was accounted for as a transaction between entities under common control, similar to pooling of interest, whereby the equity investment in Iroquois was recorded at TransCanada’s carrying value and was accounted for prospectively from the date of acquisition.
Use of Estimates	Use of Estimates The preparation of financial statements requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities as of the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Although management believes these estimates are reasonable, actual results could differ from these estimates.

EQUITY INVESTMENTS (Tables)

EQUITY INVESTMENTS (Tables)	3 Months Ended
	Mar. 31, 2018
EQUITY INVESTMENTS
Schedule of equity investments and summarized financial information for equity investees	Ownership Equity Earnings Equity Investments Interest at Three months (unaudited) March 31, ended March 31, March 31, December 31, (millions of dollars) 2018 2018 2017 2018 2017 Northern Border (a) % Great Lakes % Iroquois (b) % — (a) Equity earnings from Northern Border is net of the 12-year amortization of a $10 million transaction fee paid to the operator of Northern Border at the time of the Partnership’s acquisition of an additional 20 percent interest in April 2006. (b) The Partnership acquired a 49.34% interest in Iroquois on June 1, 2017.
Northern Border
EQUITY INVESTMENTS
Schedule of equity investments and summarized financial information for equity investees	(unaudited) (millions of dollars) March 31, 2018 December 31, 2017 ASSETS Cash and cash equivalents Other current assets Plant, property and equipment, net Other assets LIABILITIES AND PARTNERS’ EQUITY Current liabilities Deferred credits and other Long-term debt, net (a) Partners’ equity Partners’ capital Accumulated other comprehensive loss ) ) Three months ended (unaudited) March 31, (millions of dollars) 2018 2017 Transmission revenues Operating expenses ) ) Depreciation ) ) Financial charges and other ) ) Net income (a) No current maturities as of March 31, 2018 and December 31, 2017.
Great Lakes
EQUITY INVESTMENTS
Schedule of equity investments and summarized financial information for equity investees	(unaudited) (millions of dollars) March 31, 2018 December 31, 2017 ASSETS Current assets Plant, property and equipment, net LIABILITIES AND PARTNERS’ EQUITY Current liabilities Net long-term debt, including current maturities (a) Other long term liabilities — Partners’ equity Three months ended (unaudited) March 31, (millions of dollars) 2018 2017 Transmission revenues Operating expenses ) ) Depreciation ) ) Financial charges and other ) ) Net income (a) Includes current maturities of $21 million as of March 31, 2018 (December 31, 2017 - $19 million).
Iroquois
EQUITY INVESTMENTS
Schedule of equity investments and summarized financial information for equity investees	(unaudited) (millions of dollars) March 31, 2018 December 31, 2017 ASSETS Cash and cash equivalents Other current assets Plant, property and equipment, net Other assets LIABILITIES AND PARTNERS’ EQUITY Current liabilities Net long-term debt, including current maturities (a) Other non-current liabilities Partners’ equity (unaudited) Three months (millions of dollars) March 31, 2018 Transmission revenues Operating expenses ) Depreciation ) Financial charges and other ) Net income (a) Includes current maturities of $4 million as of March 31, 2018 (December 31, 2017 - $4 million).

REVENUES (Tables)

REVENUES (Tables)	3 Months Ended
	Mar. 31, 2018
Balance Sheet
Schedule of contract balances	(unaudited-millions of dollars) March 31, 2018 January 1, 2018 Receivables from contracts with customers Contract assets —
ASU 2014-09
Balance Sheet
Schedule of impact of the adoption of the new revenue recognition guidance	March 31, 2018 (unaudited-millions of dollars) As reported Pro-forma using Balance Sheet Accounts receivable and other Contract assets —

DEBT AND CREDIT FACILITIES (Tab

DEBT AND CREDIT FACILITIES (Tables)	3 Months Ended
	Mar. 31, 2018
DEBT AND CREDIT FACILITIES
Schedule of debt and credit facilities	(unaudited) March 31, Weighted Average December 31, Weighted Average TC PipeLines, LP Senior Credit Facility due 2021 % % 2013 Term Loan Facility due 2022 % % 2015 Term Loan Facility due 2020 % % 4.65% Unsecured Senior Notes due 2021 % (a) % (a) 4.375% Unsecured Senior Notes due 2025 % (a) % (a) 3.90 % Unsecured Senior Notes due 2027 % (a) % (a) GTN 5.29% Unsecured Senior Notes due 2020 % (a) % (a) 5.69% Unsecured Senior Notes due 2035 % (a) % (a) Unsecured Term Loan Facility due 2019 % % PNGTS 5.90% Senior Secured Notes due 2018 (b) % (a) (c ) % (a) Tuscarora Unsecured Term Loan due 2020 % % Less: unamortized debt issuance costs and debt discount Less: current portion (b) (c) (a) Fixed interest rate (b) Includes the PNGTS portion due at March 31, 2018 amounting to $6.1 million that was paid on April 2, 2018. (c) 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	(unaudited) (millions of dollars) 2018 2019 2020 2021 2022 Thereafter

NET INCOME PER COMMON UNIT (Tab

NET INCOME PER COMMON UNIT (Tables)	3 Months Ended
	Mar. 31, 2018
NET INCOME PER COMMON UNIT
Schedule of net income per common unit	(unaudited) Three months ended March 31, (millions of dollars, except per common unit amounts) 2018 2017 Net income attributable to controlling interests (a) Net income attributable to PNGTS’ former parent (b) — ) (a) Net income allocable to General Partner and Limited Partners Net income attributable to the General Partner ) ) Incentive distributions attributable to the General Partner (c) — ) Net income attributable to common units Weighted average common units outstanding (millions) — basic and diluted Net income per common unit — basic and diluted $ $ (d) (a) Recast to consolidate PNGTS (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) Net income per common unit prior to recast (Refer to Note 2).

CHANGE IN OPERATING WORKING C33

CHANGE IN OPERATING WORKING CAPITAL (Tables)	3 Months Ended
	Mar. 31, 2018
CHANGE IN OPERATING WORKING CAPITAL
Schedule of change in operating working capital	(unaudited) Three months ended March 31, (millions of dollars) 2018 2017 (a) Change in accounts receivable and other — Change in other current assets ) Change in accounts payable and accrued liabilities — ) Change in accounts payable to affiliates — ) Change in accrued interest Change in operating working capital (a) Recast to consolidate PNGTS (Refer to Note 2).

RELATED PARTY TRANSACTIONS (Tab

RELATED PARTY TRANSACTIONS (Tables)	3 Months Ended
	Mar. 31, 2018
RELATED PARTY TRANSACTIONS
Summary of capital and operating costs charged to pipeline systems by related party	Three months ended (unaudited) March 31, (millions of dollars) 2018 2017 Capital and operating costs charged by TransCanada’s subsidiaries to: Great Lakes (a) Northern Border (a) GTN Bison North Baja Tuscarora PNGTS (a) (b) Impact on the Partnership’s net income: Great Lakes Northern Border GTN Bison North Baja Tuscarora PNGTS (b)
Summary of amount payable to related party for costs charged	(unaudited) (millions of dollars) March 31, 2018 December 31, 2017 Net amounts payable to TransCanada’s subsidiaries is as follows: Great Lakes (a) (c) Northern Border (a) GTN Bison North Baja — — Tuscarora — — PNGTS (a) (a) Represents 100 percent of the costs. (b) Recast to consolidate PNGTS (Refer to Note 2). (c) Excludes any amounts owed to affiliates relating to revenue sharing. See discussion below.

ACCOUNTS RECEIVABLE AND OTHER (

ACCOUNTS RECEIVABLE AND OTHER (Tables)	3 Months Ended
	Mar. 31, 2018
ACCOUNTS RECEIVABLE AND OTHER
Schedule of accounts receivable and other	(unaudited) (millions of dollars) March 31, 2018 December 31, 2017 Trade accounts receivable, net of allowance of nil Imbalance receivable from affiliates Other

FINANCIAL CHARGES AND OTHER (Ta

FINANCIAL CHARGES AND OTHER (Tables)	3 Months Ended
	Mar. 31, 2018
FINANCIAL CHARGES AND OTHER
Schedule of components of financial charges and other	Three months ended (unaudited) March 31, (millions of dollars) 2018 2017 (b) Interest expense (a) Net realized gain related to the interest rate swaps ) — (a) Includes amortization of debt issuance costs and discount costs. (b) Recast to consolidate PNGTS (Refer to Note 2).

VARIABLE INTEREST ENTITIES (Tab

VARIABLE INTEREST ENTITIES (Tables)	3 Months Ended
	Mar. 31, 2018
VARIABLE INTEREST ENTITIES
Schedule of assets and liabilities held through VIEs whose assets cannot be used for purposes other settlement of their obligations	(unaudited) (millions of dollars) March 31, 2018 December 31, 2017 ASSETS (LIABILITIES) * Cash and cash equivalents Accounts receivable and other Contract assets — Inventories Other current assets Equity investments Plant, property and equipment, net Other assets Accounts payable and accrued liabilities ) ) Accounts payable to affiliates, net ) ) Distributions payable ) ) State taxes payable ) — Accrued interest ) ) Current portion of long-term debt ) ) Long-term debt ) ) Other liabilities ) ) Deferred state income tax ) ) *North Baja and Bison, which are also assets held through our consolidated VIEs, are excluded as the assets of these entities can be used for purposes other than the settlement of the VIE’s obligations.

INCOME TAXES (Tables)

INCOME TAXES (Tables)	3 Months Ended
	Mar. 31, 2018
INCOME TAXES
Schedule of state income taxes of PNGTS	Three months ended (unaudited) March 31, (millions of dollars) 2018 2017 (a) State income taxes Current Deferred — — (a) Recast to consolidate PNGTS (Refer to Note 2).

ORGANIZATION - Ownership Intere

ORGANIZATION - Ownership Interests in Natural Gas Pipeline Systems (Details)-10Q	3 Months Ended
	Mar. 31, 2018LimitedPartnership
ORGANIZATION
Number of intermediate limited partnerships through which pipeline assets are owned	3

SIGNIFICANT ACCOUNTING POLICI40

SIGNIFICANT ACCOUNTING POLICIES - Basis of Presentation (Details)	Mar. 31, 2018	[1]	Jun. 01, 2017
Portland Natural Gas Transmission System
ACQUISITIONS
Interest acquired by Partnership (as a percent)			11.81%
Iroquois
ACQUISITIONS
Ownership interest (as a percent)	49.34%		49.34%
Portland Natural Gas Transmission System
ACQUISITIONS
Ownership interest (as a percent)			61.71%
[1]	The Partnership acquired a 49.34% interest in Iroquois on June 1, 2017.

REGULATORY (Details)

REGULATORY (Details) - USD ($) $ in Millions	3 Months Ended	12 Months Ended
	Mar. 31, 2018	Dec. 31, 2017
Tuscarora Gas Transmission Company | Maximum
REGULATORY
Percentage of fair value exceeding its carrying value		10.00%
Tuscarora Gas Transmission Company | FERC
REGULATORY
Goodwill impairment charge	$ 82	$ 82
Great Lakes | Maximum
REGULATORY
Percentage of fair value exceeding its carrying value		10.00%
Great Lakes | FERC
REGULATORY
Goodwill impairment charge	$ 260	$ 260

EQUITY INVESTMENTS (Details)

EQUITY INVESTMENTS (Details) - USD ($) $ in Millions		May 01, 2018	Mar. 07, 2018	Apr. 30, 2006	Mar. 31, 2018		Mar. 31, 2017		Apr. 30, 2018	Dec. 31, 2017	Jun. 01, 2017
EQUITY INVESTMENTS
Equity Earnings					$ 59		$ 36	[1]
Equity Investments					1,217					$ 1,213
LIABILITIES AND PARTNERS' EQUITY
Current portion of long-term debt (Note 7)					45					51
Distributions from Equity Investments
Distributions received from equity investments					45		28
Distributions from equity investments					43		28	[1]
Return on investment distribution classified as investing activities					2		0
Great Lakes
EQUITY INVESTMENTS
Total cash call issued to fund debt repayment					9
LIABILITIES AND PARTNERS' EQUITY
Current portion of long-term debt (Note 7)					$ 21					19
Iroquois
EQUITY INVESTMENTS
Ownership interest (as a percent)		49.34%			49.34%						49.34%
LIABILITIES AND PARTNERS' EQUITY
Current portion of long-term debt (Note 7)					$ 4					4
Revenues (expenses)
Transmission revenues					60
Operating expenses					(14)
Depreciation					(7)
Financial charges and other					(4)
Net income					35
Distributions from Equity Investments
Distributions from equity investments		$ 14			14
Return on investment distribution classified as investing activities		$ 2.6			$ 2
Limited partners, Distribution declared			$ 29
Northern Border
EQUITY INVESTMENTS
Ownership interest (as a percent)					50.00%	[2]			50.00%
Equity Earnings	[2]				$ 17		19
Equity Investments	[2]				507					512
Amortization period of transaction fee				12 years
Transaction fee				$ 10
Additional ownership interest acquired (as a percent)				20.00%
Assets
Cash and cash equivalents					22					14
Other current assets					35					36
Plant, property and equipment, net					1,059					1,063
Other assets					14					14
Assets, total					1,130					1,127
LIABILITIES AND PARTNERS' EQUITY
Current liabilities					50					38
Deferred credits and other					32					31
Net long-term debt, including current maturities					264					264
Partners' equity
Partners' capital					785					795
Accumulated other comprehensive loss					(1)					(1)
Liabilities and Partners' Equity, total					1,130					1,127
Revenues (expenses)
Transmission revenues					72		74
Operating expenses					(19)		(17)
Depreciation					(15)		(15)
Financial charges and other					(4)		(4)
Net income					$ 34		38
Great Lakes
EQUITY INVESTMENTS
Ownership interest (as a percent)		46.45%			46.45%
Equity Earnings					$ 24		17
Equity Investments					499					479
Equity contribution					4		4	[1]
Assets
Current assets					129					107
Plant, property and equipment, net					699					701
Assets, total					828					808
LIABILITIES AND PARTNERS' EQUITY
Current liabilities					63					75
Net long-term debt, including current maturities					250					259
Current portion of long-term debt (Note 7)					0					0
Other non-current liabilities										1
Partners' equity
Partners' capital					515					473
Liabilities and Partners' Equity, total					828					808
Revenues (expenses)
Transmission revenues					81		63
Operating expenses					(17)		(14)
Depreciation					(8)		(7)
Financial charges and other					(4)		(5)
Net income					$ 52		$ 37
Iroquois
EQUITY INVESTMENTS
Ownership interest (as a percent)					49.34%	[3]					49.34%
Equity Earnings	[3]				$ 18
Equity Investments	[3]				211					222
Undistributed earnings					0
Assets
Cash and cash equivalents					105					86
Other current assets					32					36
Plant, property and equipment, net					589					591
Other assets					9					8
Assets, total					735					721
LIABILITIES AND PARTNERS' EQUITY
Current liabilities					50					17
Net long-term debt, including current maturities					329					329
Other non-current liabilities					12					9
Partners' equity
Partners' capital					344					366
Liabilities and Partners' Equity, total					$ 735					$ 721
[1]	Recast to consolidate PNGTS (Refer to Note 2).
[2]	OwnershipEquity EarningsEquity InvestmentsInterest atThree months(unaudited)March 31, ended March 31, March 31, December 31, (millions of dollars)2018    2018201720182017Northern Border (a) 50% 17  19 507 512Great Lakes 46.45% 24 17 499 479Iroquois(b) 49.34% 18  — 211 222  59  36 1,217 1,213Equity earnings from Northern Border is net of the 12-year amortization of a $10 million transaction fee paid to the operator of Northern Border at the time of the Partnership’s acquisition of an additional 20 percent interest in April 2006.
[3]	The Partnership acquired a 49.34% interest in Iroquois on June 1, 2017.

REVENUES - Financial Statement

REVENUES - Financial Statement Impact of Adopting Revenue from Contracts with Customers (Details) - USD ($) $ in Millions	Mar. 31, 2018	Dec. 31, 2017
Balance Sheet
Accounts receivable and other	$ 36	$ 42
Contract assets	7
ASU 2014-09 | Pro-forma using Legacy U.S. GAAP
Balance Sheet
Accounts receivable and other	$ 43

REVENUES - Contract Balances (D

REVENUES - Contract Balances (Details) - USD ($) $ in Millions	Mar. 31, 2018	Jan. 01, 2018
Contract Balances
Receivables from contracts with customers	$ 31	$ 40
Contract assets	$ 7

REVENUES - Future revenues from

REVENUES - Future revenues from remaining performance obligations (Details)	3 Months Ended
	Mar. 31, 2018
Revenue, practical expedient
Revenue, Remaining Performance Obligation, Optional Exemption, Performance Obligation	true
Minimum
Revenue performance
Current rate settlement term	1 year
Maximum
Revenue performance
Current rate settlement term	4 years

DEBT AND CREDIT FACILITIES - Am

DEBT AND CREDIT FACILITIES - Amounts Outstanding and Description of Terms (Details) $ in Millions	Apr. 05, 2018USD ($)	Aug. 21, 2017	Mar. 31, 2018USD ($)entity	Dec. 31, 2017USD ($)
Credit facilities, short-term loan facility and long-term debt
Debt and credit facilities			$ 2,389	$ 2,415
Less: unamortized debt issuance costs and debt discount			12	12
Less: current portion			45	51
Long-term debt			$ 2,332	2,352
Senior Credit Facility due in 2021 and the Term Loan Facilities due in 2020 and 2022 | Minimum
Credit facilities, short-term loan facility and long-term debt
Leverage ratio, actual (as a percent)			456.00%
Senior Credit Facility due in 2021 and the Term Loan Facilities due in 2020 and 2022 | Debt agreement covenants, initial period after occurrence of acquisition
Credit facilities, short-term loan facility and long-term debt
Additional period immediately following the fiscal quarter in which a specified material acquisition occurs			6 months
Senior Credit Facility due in 2021 and the Term Loan Facilities due in 2020 and 2022 | Debt agreement covenants, initial period after occurrence of acquisition | Minimum
Credit facilities, short-term loan facility and long-term debt
Number of acquisitions | entity			1
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
Debt and credit facilities			$ 165	$ 185
Weighted average interest rate (as a percent)			2.85%	2.41%
Maximum borrowing capacity			$ 500
Amount outstanding under credit facility			165	$ 185
Remaining borrowing capacity			$ 335
Revolving credit facility | TC PipeLines, LP Senior Credit Facility due 2021 | LIBOR
Credit facilities, short-term loan facility and long-term debt
Debt interest rate, at period end (as a percent)			2.92%	2.62%
Term loan | 2013 Term Loan Facility due 2018
Credit facilities, short-term loan facility and long-term debt
Debt and credit facilities			$ 500
Term loan | TC PipeLines, LP 2013 Term Loan Facility due 2022
Credit facilities, short-term loan facility and long-term debt
Debt and credit facilities			$ 500	$ 500
Weighted average interest rate (as a percent)			2.86%	2.33%
Term loan | TC PipeLines, LP 2013 Term Loan Facility due 2022 | LIBOR borrowings | LIBOR
Credit facilities, short-term loan facility and long-term debt
Debt interest rate, at period end (as a percent)			2.92%	2.62%
Term loan | TC PipeLines, LP 2013 Term Loan Facility due 2022 | LIBOR borrowings | LIBOR | Hedges of cash flows | Interest rate swaps
Credit facilities, short-term loan facility and long-term debt
Weighted average interest rate (as a percent)			2.31%	2.31%
Term loan | TC PipeLines, LP 2015 Term Loan Facility due 2020
Credit facilities, short-term loan facility and long-term debt
Debt and credit facilities			$ 170	$ 170
Weighted average interest rate (as a percent)			2.75%	2.22%
Term loan | TC PipeLines, LP 2015 Term Loan Facility due 2020 | LIBOR
Credit facilities, short-term loan facility and long-term debt
Debt interest rate, at period end (as a percent)			2.81%	2.51%
Unsecured debt | 4.65% Senior Notes due 2021
Credit facilities, short-term loan facility and long-term debt
Stated interest rate (as a percent)			4.65%	4.65%
Debt and credit facilities			$ 350	$ 350
Weighted average interest rate (as a percent)			4.65%	4.65%
Unsecured debt | TC PipeLines, LP 4.375% Senior Notes due 2025
Credit facilities, short-term loan facility and long-term debt
Stated interest rate (as a percent)			4.375%	4.375%
Debt and credit facilities			$ 350	$ 350
Weighted average interest rate (as a percent)			4.375%	4.375%
Unsecured debt | TC PipeLines, LP 3.90% Senior Notes due 2027
Credit facilities, short-term loan facility and long-term debt
Stated interest rate (as a percent)			3.90%	3.90%
Debt and credit facilities			$ 500	$ 500
Weighted average interest rate (as a percent)			3.90%	3.90%
Unsecured debt | GTN 5.29% Senior Notes due 2020
Credit facilities, short-term loan facility and long-term debt
Stated interest rate (as a percent)			5.29%	5.29%
Debt and credit facilities			$ 100	$ 100
Weighted average interest rate (as a percent)			5.29%	5.29%
Unsecured debt | GTN 5.69% Senior Notes due 2035
Credit facilities, short-term loan facility and long-term debt
Stated interest rate (as a percent)			5.69%	5.69%
Debt and credit facilities			$ 150	$ 150
Weighted average interest rate (as a percent)			5.69%	5.69%
Unsecured debt | Term Loan Facility due 2019
Credit facilities, short-term loan facility and long-term debt
Debt and credit facilities			$ 55	$ 55
Weighted average interest rate (as a percent)			2.55%	2.02%
Unsecured debt | Tuscarora Term Loan due 2020
Credit facilities, short-term loan facility and long-term debt
Debt and credit facilities			$ 25	$ 25
Weighted average interest rate (as a percent)			2.73%	2.27%
Unsecured debt | Tuscarora Term Loan due 2020 | LIBOR
Credit facilities, short-term loan facility and long-term debt
Debt interest rate, at period end (as a percent)			2.79%	2.49%
Secured debt | PNGTS 5.90% Senior Secured Notes due 2018
Credit facilities, short-term loan facility and long-term debt
Stated interest rate (as a percent)			5.90%	5.90%
Debt and credit facilities			$ 24	$ 30
Weighted average interest rate (as a percent)			5.90%	5.90%
GTN | Unsecured debt | Senior Notes and Term Loan Facility due 2019
Credit facilities, short-term loan facility and long-term debt
Debt interest rate, at period end (as a percent)			2.61%	2.31%
Percentage of debt to total capitalization, actual			44.00%
GTN | Unsecured debt | Senior Notes and Term Loan Facility due 2019 | Maximum
Credit facilities, short-term loan facility and long-term debt
Percentage of debt to total capitalization, covenant			70.00%
Portland Natural Gas Transmission System | 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			$ 6.1	$ 5.8
Portland Natural Gas Transmission System | Secured debt | PNGTS 5.90% Senior Secured Notes due 2018
Credit facilities, short-term loan facility and long-term debt
Debt Service, number of months of guarantee			6 months
Portland Natural Gas Transmission System | Secured debt | PNGTS 5.90% Senior Secured Notes due 2018 | Maximum
Credit facilities, short-term loan facility and long-term debt
Leverage ratio, covenant (as a percent)	500.00%
Portland Natural Gas Transmission System | Secured debt | PNGTS 5.90% Senior Secured Notes due 2018 | Debt agreement covenants, preceding twelve months
Credit facilities, short-term loan facility and long-term debt
Debt service coverage, actual (as a percent)			1.65%
Portland Natural Gas Transmission System | Secured debt | PNGTS 5.90% Senior Secured Notes due 2018 | Debt agreement covenants, preceding twelve months | Minimum
Credit facilities, short-term loan facility and long-term debt
Debt service coverage, covenant (as a percent)			130.00%
Portland Natural Gas Transmission System | Secured debt | PNGTS 5.90% Senior Secured Notes due 2018 | Debt agreement covenants, succeeding twelve months
Credit facilities, short-term loan facility and long-term debt
Debt service coverage, actual (as a percent)			2.14%
Portland Natural Gas Transmission System | Secured debt | PNGTS 5.90% Senior Secured Notes due 2018 | Debt agreement covenants, succeeding twelve months | Minimum
Credit facilities, short-term loan facility and long-term debt
Debt service coverage, covenant (as a percent)			130.00%
Portland Natural Gas Transmission System | Secured debt | PNGTS 5.90% Senior Secured Notes due 2018 | LIBOR
Credit facilities, short-term loan facility and long-term debt
Maximum borrowing capacity	$ 125
Tuscarora Gas Transmission Company | Unsecured Term Loan Facility | Tuscarora Term Loan due 2020 | Minimum
Credit facilities, short-term loan facility and long-term debt
Debt service coverage, covenant (as a percent)		300.00%
Debt service coverage, actual (as a percent)			112.00%

DEBT AND CREDIT FACILITIES - Pr

DEBT AND CREDIT FACILITIES - Principal Payments Required (Details) $ in Millions	Mar. 31, 2018USD ($)
Principal repayments required on debt
2,018	$ 45
2,019	36
2,020	293
2,021	515
2,022	500
Thereafter	1,000
Total debt	$ 2,389

PARTNERS' EQUITY - ATM Equity I

PARTNERS' EQUITY - ATM Equity Issuance Program (Details) - USD ($) shares in Millions, $ in Millions	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
PARTNERS' EQUITY
Net proceeds from issuance of common units	$ 40
General Partner
PARTNERS' EQUITY
Net proceeds from issuance of common units	$ 1
TC PipeLines GP, Inc. | General Partner
PARTNERS' EQUITY
Ownership interest in the Partnership (as a percent)	2.00%	2.00%
ATM Equity Issuance Program | Common Units
PARTNERS' EQUITY
Units sold	0.7
Sales agent commissions	$ 0
Net proceeds from issuance of common units	39
ATM Equity Issuance Program | TC PipeLines GP, Inc. | General Partner
PARTNERS' EQUITY
Equity contribution	$ 1

PARTNERS' EQUITY - Class B Unit

PARTNERS' EQUITY - Class B Units (Details) - Class B Units - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017	[1]
PARTNERS' EQUITY
Limited Partners, Distributions paid	$ 15	$ 22
Distributions
PARTNERS' EQUITY
Limited Partners, Distributions paid	$ 15
GTN | TransCanada | Distributions
PARTNERS' EQUITY
Portion of GTN's annual distributions to which the Class B units are entitled to receive a percentage share of the distributions above threshold (as a percent)	30.00%
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%
[1]	Recast to consolidate PNGTS (Refer to Note 2).

NET INCOME PER COMMON UNIT - Ge

NET INCOME PER COMMON UNIT - General Partner Effective Interest and Allocated Incentive Distributions (Details)	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
TC PipeLines GP, Inc. | General Partner
PARTNERS' EQUITY
General partner interest (as a percent)	2.00%	2.00%

NET INCOME PER COMMON UNIT- Ter

NET INCOME PER COMMON UNIT- Terms of Class B Unit Distributions and Determination of Net Income (Loss) per Common Unit (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions		3 Months Ended			12 Months Ended
		Mar. 31, 2018	Mar. 31, 2017		Dec. 31, 2017
Net income (loss) per common unit
Net income attributable to controlling interests		$ 96	$ 77	[1]
Net income attributable to PNGTS' former parent	[1]		(2)
Net income allocable to General Partner and Limited Partners		96	75
Net income attributable to the General Partner		(2)	(1)
Incentive distributions attributable to the General Partner			(2)
Common Units
Net income (loss) per common unit
Net income attributable to common units		$ 94	$ 72	[1]
Weighted average common units outstanding - basic (in units)		71.2	68.3	[1]
Weighted average common units outstanding - diluted (in units)		71.2	68.3
Net income (loss) per common unit - basic (in dollars per unit)	[2]	$ 1.32	$ 1.05	[1]
Net income (loss) per common unit - diluted (in dollars per unit)		$ 1.32	$ 1.05
GTN | Class B Units | TransCanada | Distributions
Distributions
Percentage applied to GTN's distributable cash flow		30.00%
Net income attributable to controlling interests		$ 0	$ 0
Threshold of GTN's distributions for payment to Class B units		$ 20			$ 20
Portion of GTN's annual distributions to which the Class B units are entitled to receive a percentage share of the distributions above threshold (as a percent)		30.00%
[1]	Recast to consolidate PNGTS (Refer to Note 2).
[2]	Net income per common unit prior to recast (Refer to Note 2).

CASH DISTRIBUTIONS - Distributi

CASH DISTRIBUTIONS - Distributions Paid (Details) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Common Units
Partners' Equity
Per Unit Distribution, paid (in dollars per unit)	$ 1	$ 0.94
Total cash distribution	$ 76	$ 68
Common units and General Partner interest combined
Partners' Equity
Total distribution of general partner interest and IDR payment	5
TC PipeLines GP, Inc. | General Partner
Partners' Equity
Total distribution for General Partner interest	$ 2	$ 2
General partner interest (as a percent)	2.00%	2.00%
TC PipeLines GP, Inc. | Common units and General Partner interest combined
Partners' Equity
Incentive distribution paid to the General Partner	$ 3	$ 2

CHANGE IN OPERATING WORKING C53

CHANGE IN OPERATING WORKING CAPITAL - Components (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
CHANGE IN OPERATING WORKING CAPITAL
Change in accounts receivable and other		$ 7
Change in other current assets	$ (3)	1
Change in accounts payable and accrued liabilities		(3)
Change in accounts payable to affiliates		(1)
Change in accrued interest	9	3
Change in operating working capital	$ 6	$ 7	[1]
[1]	Recast to consolidate PNGTS (Refer to Note 2).

RELATED PARTY TRANSACTIONS (Det

RELATED PARTY TRANSACTIONS (Details) - USD ($) $ in Millions	3 Months Ended				6 Months Ended		12 Months Ended
	Mar. 31, 2018	Jun. 30, 2017	Mar. 31, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016	Dec. 31, 2017
Capital and operating costs charged to the pipeline systems and amount payable
Net amounts payable	$ 6						$ 5
Amount included in receivables from related party	3						1
Great Lakes
Capital and operating costs charged to the pipeline systems and amount payable
Estimated revenue sharing provision							40
General Partner | Reimbursement of costs of services provided
Capital and operating costs charged to the pipeline systems and amount payable
Costs charged	1		$ 1
TransCanada's subsidiaries | Great Lakes
Capital and operating costs charged to the pipeline systems and amount payable
Net amounts payable	3						3
Percentage of capital and operating costs charged		100.00%		100.00%	100.00%	100.00%
Amount included in receivables from related party	10						20
TransCanada's subsidiaries | Great Lakes | Capital and operating costs
Capital and operating costs charged to the pipeline systems and amount payable
Costs charged	$ 9		$ 8
Percentage of capital and operating costs charged	100.00%		100.00%
TransCanada's subsidiaries | Northern Border
Capital and operating costs charged to the pipeline systems and amount payable
Net amounts payable	$ 4						4
Percentage of capital and operating costs charged		100.00%		100.00%	100.00%	100.00%
TransCanada's subsidiaries | Northern Border | Capital and operating costs
Capital and operating costs charged to the pipeline systems and amount payable
Costs charged	9		$ 10
Percentage of capital and operating costs charged		100.00%		100.00%	100.00%	100.00%
TransCanada's subsidiaries | Portland Natural Gas Transmission System
Capital and operating costs charged to the pipeline systems and amount payable
Net amounts payable	1						1
Amount included in receivables from related party	0						0
TransCanada's subsidiaries | Portland Natural Gas Transmission System | Capital and operating costs
Capital and operating costs charged to the pipeline systems and amount payable
Costs charged	2		2
TransCanada's subsidiaries | Iroquois
Capital and operating costs charged to the pipeline systems and amount payable
Percentage of capital and operating costs charged		100.00%			100.00%
TransCanada's subsidiaries | Iroquois | Capital and operating costs
Capital and operating costs charged to the pipeline systems and amount payable
Percentage of capital and operating costs charged		100.00%			100.00%
TransCanada's subsidiaries | GTN
Capital and operating costs charged to the pipeline systems and amount payable
Net amounts payable	3						3
TransCanada's subsidiaries | GTN | Capital and operating costs
Capital and operating costs charged to the pipeline systems and amount payable
Costs charged	8		7
Impact on the Partnership's net income attributable to controlling interests	8		7
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	2		1
Impact on the Partnership's net income attributable to controlling interests	2		1
TransCanada's subsidiaries | North Baja Pipeline, LLC | Capital and operating costs
Capital and operating costs charged to the pipeline systems and amount payable
Costs charged	1		1
Impact on the Partnership's net income attributable to controlling interests	1		1
TransCanada's subsidiaries | Tuscarora Gas Transmission Company | Capital and operating costs
Capital and operating costs charged to the pipeline systems and amount payable
Costs charged	1		1
Impact on the Partnership's net income attributable to controlling interests	1		1
TransCanada's subsidiaries | Great Lakes | Capital and operating costs
Capital and operating costs charged to the pipeline systems and amount payable
Impact on the Partnership's net income attributable to controlling interests	$ 4		$ 3
TransCanada's subsidiaries | Great Lakes | Transportation contracts | Total net revenues | Customer concentration risk
Capital and operating costs charged to the pipeline systems and amount payable
Percent of total revenues	68.00%		67.00%
TransCanada's subsidiaries | Northern Border | Capital and operating costs
Capital and operating costs charged to the pipeline systems and amount payable
Impact on the Partnership's net income attributable to controlling interests	$ 4		$ 3
TransCanada's subsidiaries | Portland Natural Gas Transmission System | Capital and operating costs
Capital and operating costs charged to the pipeline systems and amount payable
Impact on the Partnership's net income attributable to controlling interests	1		$ 1
TransCanada's subsidiaries | Portland Natural Gas Transmission System | Transportation contracts
Capital and operating costs charged to the pipeline systems and amount payable
Revenues from related party	1						$ 0
Affiliates | Portland Natural Gas Transmission System
Capital and operating costs charged to the pipeline systems and amount payable
Net amounts payable	$ 5

FAIR VALUE MEASUREMENTS - Estim

FAIR VALUE MEASUREMENTS - Estimated Fair Value of Debt (Details) - USD ($) $ in Millions	Mar. 31, 2018	Dec. 31, 2017
Fair Value | Level 2
Financial Instruments
Fair value of debt	$ 2,408	$ 2,475

FAIR VALUE MEASUREMENTS - Inter

FAIR VALUE MEASUREMENTS - Interest Rate Swaps (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017	Dec. 31, 2017
Interest rate derivatives
Fair value of derivative asset, net			$ 5
Debt and credit facilities	$ 2,389		2,415
Term loan | 2013 Term Loan Facility due 2018
Interest rate derivatives
Debt and credit facilities	500
Term loan | TC PipeLines, LP 2013 Term Loan Facility due 2022
Interest rate derivatives
Debt and credit facilities	500		$ 500
Average rate of forward starting swaps			3.26%
Portland Natural Gas Transmission System
Interest rate derivatives
Payments for derivative instruments	$ 20.9
Interest acquired (as a percent)	61.71%
Net unamortized loss included in other comprehensive income	$ 1		$ 1
Amortization of derivatives loss	$ 0	$ 0
Interest rate swaps | Term loan | 2013 Term Loan Facility due 2018
Interest rate derivatives
Weighted average fixed interest rate (as a percent)	2.31%
Hedges of cash flows | Interest rate swaps
Interest rate derivatives
Change in fair value of interest rate derivative instruments recognized in other comprehensive income (loss)	$ 7	1
Hedges of cash flows | Interest rate swaps | Financial charges and other
Interest rate derivatives
Net realized gain related to the interest rate swaps	(1)	$ 0
Hedges of cash flows | Interest rate swaps | Recurring fair value measurement | Level 2
Interest rate derivatives
Fair value of derivative asset, gross			5
Fair value of derivative asset, net			$ 5
Designated as hedge | Interest rate swaps | Recurring fair value measurement | Level 2
Interest rate derivatives
Fair value of derivative asset, gross	12
Fair value of derivative asset, net	$ 12

ACCOUNTS RECEIVABLE AND OTHER57

ACCOUNTS RECEIVABLE AND OTHER (Details) - USD ($) $ in Millions	Mar. 31, 2018	Dec. 31, 2017
ACCOUNTS RECEIVABLE AND OTHER
Trade accounts receivable, net of allowance of nil	$ 31	$ 40
Imbalance receivable from affiliates	3	1
Other	2	1
Accounts receivable and other	36	42
Trade accounts receivable, allowance	$ 0	$ 0

FINANCIAL CHARGES AND OTHER (De

FINANCIAL CHARGES AND OTHER (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
FINANCIAL CHARGES AND OTHER
Interest expense	$ 24	$ 17
Net realized gain related to the interest rate swaps	(1)
Financial charges and other	$ 23	$ 17	[1]
[1]	Recast to consolidate PNGTS (Refer to Note 2).

CONTINGENCIES (Details)

CONTINGENCIES (Details) - Great Lakes v. Essar Steel Minnesota LLC, et al. - Great Lakes - USD ($) $ in Millions	Oct. 29, 2009	May 31, 2017	Apr. 30, 2017	Jul. 31, 2016	Sep. 30, 2015
Contingencies
Judgement awarded			$ 31.5
Amount released into bankruptcy estates				$ 1.2
Essar
Contingencies
Recovery sought	$ 33
Judgement awarded		$ 1.2			$ 32.9

VARIABLE INTEREST ENTITIES - Co

VARIABLE INTEREST ENTITIES - Consolidated VIEs (Details) - USD ($) $ in Millions	Mar. 31, 2018	Dec. 31, 2017	Mar. 31, 2017	[1]	Dec. 31, 2016	[1]
ASSETS (LIABILITIES)
Cash and cash equivalents	$ 68	$ 33	$ 77		$ 64
Accounts receivable and other	36	42
Contract assets	7
Inventories	7	8
Other current assets	11	7
Equity investments	1,217	1,213
Plant, property and equipment, net	2,105	2,123
Other assets	9	3
Accounts payable and accrued liabilities	(35)	(31)
Accounts payable to affiliates, net	(6)	(5)
Distributions payable	(2)	(1)
Accrued interest	(21)	(12)
Current portion of long-term debt	(45)	(51)
Long-term debt	(2,332)	(2,352)
Other liabilities	(29)	(29)
Consolidated VIEs | Restricted VIEs
ASSETS (LIABILITIES)
Cash and cash equivalents	31	19
Accounts receivable and other	23	30
Contract assets	7
Inventories	6	6
Other current assets	6	5
Equity investments	1,217	1,213
Plant, property and equipment, net	1,126	1,133
Other assets	1	1
Accounts payable and accrued liabilities	(26)	(24)
Accounts payable to affiliates, net	(29)	(42)
Distributions payable	(2)	(1)
State taxes payable	(1)
Accrued interest	(5)	(2)
Current portion of long-term debt	(45)	(51)
Long-term debt	(308)	(308)
Other liabilities	(27)	(26)
Deferred state income tax	$ (10)	$ (10)
[1]	Recast to consolidate PNGTS (Refer to Note 2).

INCOME TAXES (Details)

INCOME TAXES (Details) - USD ($) $ in Millions	3 Months Ended			12 Months Ended
	Mar. 31, 2018	Mar. 31, 2017		Dec. 31, 2017
State income taxes
Total state income taxes	$ 1	$ 1	[1]
Portland Natural Gas Transmission System
Income Taxes
Effective income tax rate (as a percent)	3.80%			3.80%
State income taxes
Current	$ 1	1
Total state income taxes	$ 1	$ 1
[1]	Recast to consolidate PNGTS (Refer to Note 2).

SUBSEQUENT EVENTS - Distributio

SUBSEQUENT EVENTS - Distributions (Details) - USD ($) $ / shares in Units, $ in Millions	May 15, 2018	May 01, 2018	Apr. 30, 2018	Apr. 16, 2018	Apr. 12, 2018	Mar. 31, 2018		Mar. 31, 2017		Jun. 01, 2017
Distributions
Partnership distribution						$ 93
Partnership's share of distributions						$ 43		$ 28	[1]
Northern Border
Distributions
Ownership interest (as a percent)			50.00%			50.00%	[2]
Great Lakes
Distributions
Ownership interest (as a percent)		46.45%				46.45%
Portland Natural Gas Transmission System
Distributions
Ownership interest (as a percent)										61.71%
Subsequent Events
Distributions
Total cash distribution		$ 47
Percentage of reduction in cash distributions		35.00%
Subsequent Events | Distribution declared | Northern Border
Distributions
Partnership distribution					$ 8.8
Subsequent Events | Distribution declared | Great Lakes
Distributions
Partnership distribution				$ 54.8
Subsequent Events | Cash Distribution Paid | Northern Border
Distributions
Partnership's share of distributions			$ 4.4
Subsequent Events | Cash Distribution Paid | Great Lakes
Distributions
Partnership's share of distributions		$ 25.5
General Partner
Distributions
Partnership distribution						$ 5
TC PipeLines GP, Inc. | Subsequent Events
Distributions
General Partner cash distributions	$ 1
Ownership interest (as a percent)		2.00%
Common Units
Distributions
Total cash distribution						$ 76		$ 68
Number of units						71,300,000		68,600,000	[1]
Common Units | Subsequent Events
Distributions
Per Unit Distribution, declared (in dollars per unit)		$ 0.65
Limited partners, Distribution declared	46
Reduction in distribution per common unit		$ 1
Common Units | Limited Partners
Distributions
Partnership distribution						$ 71
Common Units | TC PipeLines GP, Inc. | Subsequent Events
Distributions
Limited Partners, Distributions paid	4
Common Units | TC PipeLines GP, Inc. | Limited Partners
Distributions
Number of units		5,797,106
Common Units | TransCanada | Subsequent Events
Distributions
Limited Partners, Distributions paid	$ 7
Common Units | TransCanada | TC PipeLines GP, Inc.
Distributions
Number of units		11,287,725
[1]	Recast to consolidate PNGTS (Refer to Note 2).
[2]	OwnershipEquity EarningsEquity InvestmentsInterest atThree months(unaudited)March 31, ended March 31, March 31, December 31, (millions of dollars)2018    2018201720182017Northern Border (a) 50% 17  19 507 512Great Lakes 46.45% 24 17 499 479Iroquois(b) 49.34% 18  — 211 222  59  36 1,217 1,213Equity earnings from Northern Border is net of the 12-year amortization of a $10 million transaction fee paid to the operator of Northern Border at the time of the Partnership’s acquisition of an additional 20 percent interest in April 2006.