View Filing Data

Other comprehensive income

$ 166

177

ATM equity issuances, net (Note 8)

$ 39

ATM equity issuances, net (Note 8) (in units)

0.7

Distributions

$ (117)

$ (15)

(6)

(3)

(141)

Partners' Equity at end of year at Jun. 30, 2018

$ 912

$ 95

$ 22

$ 15

$ 111

$ 1,155

Partners' Equity at end of year (in units) at Jun. 30, 2018

71.3

1.9

[1]

Gains (Losses) related to cash flow hedges reported in Accumulated Other Comprehensive Income and expected to be reclassified to Net income in the next 12 months are estimated to be $3 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 CHANGES IN PARTNERS' EQUITY (Parenthetical) $ in Millions	6 Months Ended
	Jun. 30, 2018 USD ($)
CONSOLIDATED STATEMENT OF CHANGES IN PARTNERS' EQUITY
Gains (Losses) related to cash flow hedges in AOCI expected to be reclassified to Net income in the next 12 months	$ 3

ORGANIZATION	6 Months Ended
ORGANIZATION	Jun. 30, 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	6 Months Ended
SIGNIFICANT ACCOUNTING POLICIES	Jun. 30, 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 and six months ended June 30, 2018 and 2017 are not necessarily indicative of the results that may be expected over 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. 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	6 Months Ended
ACCOUNTING PRONOUNCEMENTS	Jun. 30, 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. Effective January 1, 2018, the new guidance was applied using the modified retrospective transition method, and did not result in any material differences in the amount and timing of revenue recognition. Refer to Note 6 - Revenues, for further information related to the impact of adopting the new guidance and the Partnership’s updated accounting policies related to revenue recognition from contracts with customers. Hedge Accounting In August 2017, the FASB issued new guidance on hedge accounting, making more financial and nonfinancial hedging strategies eligible for hedge accounting. The new guidance amends the presentation requirements relating to the change in fair value of a derivative and additional disclosure requirements include cumulative basis adjustments for fair value hedges and the effect of hedging on individual statement of income line items. This new guidance is effective January 1, 2019 with early adoption permitted. The Partnership has elected to prospectively 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 such that, in order for the arrangement to qualify as a lease, the lessor is required to have both (1) the right to obtain substantially all of the economic benefits from the use of the asset and (2) the right to direct the use of the asset. The new guidance also establishes a right-of-use (ROU) model that requires a lessee to recognize a ROU asset and corresponding lease liability on the balance sheet for all leases with a term longer than 12 months. 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 Partnership continues to monitor and analyze additional guidance and clarifications provided by the FASB. 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 has substantially completed an analysis and preliminary inventory listing of existing lease agreements, and continues to analyze contracts that may contain leases. The Partnership continues to evaluate the financial impact of the application of the new guidance on its consolidated financial statements. The Partnership has also selected a system solution and is in the testing stage of its implementation. The Partnership continues to assess process changes necessary to compile the information to meet the recognition and disclosure requirements of the new guidance. Goodwill Impairment In January 2017, the FASB issued new guidance on simplifying the test for goodwill impairment by eliminating the requirement to calculate the implied fair value of goodwill to measure the impairment charge. Instead, entities will record an impairment charge based on the excess of a reporting unit’s carrying amount over its fair value. This new guidance is effective January 1, 2020 and will be applied prospectively, however, early adoption is permitted. The Partnership is currently evaluating the timing and impact of the adoption of this guidance. 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

6 Months Ended

Jun. 30, 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 on Treatment of Income Taxes (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 (ADIT) and bonus depreciation. On July 18, 2018, FERC issued (1) an Order on Rehearing of the Revised Policy Statement (Order on Rehearing) dismissing rehearing requests related to the Revised Policy Statement and (2) a Final Rule adopting and revising procedures from, and clarifying aspects of, the NOPR (collectively, the “2018 FERC Actions”). The Final Rule will become effective September 13, 2018, and is subject to requests for further rehearing and clarification. Each is further described below.

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

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

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

Final Rule on Tax Law Changes for Interstate Natural Gas Companies

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

make a limited Natural Gas Act (NGA) Section 4 filing to reduce its rates by the reduction in its cost of service shown in its FERC Form No. 501-G. For any pipeline electing this option, FERC guarantees a three-year moratorium on NGA Section 5 rate investigations if the pipeline’s FERC Form 501-G shows the pipeline’s estimated ROE as being12 percent or less. Under the Final Rule and notwithstanding the Revised Policy Statement, a pipeline organized as an MLP is not required to eliminate its income tax allowance but, instead, can reduce its rates to reflect the reduction in the maximum corporate tax rate. Alternatively, the MLP pipeline can eliminate its tax allowance, along with its ADIT used for rate-making purposes. In situations where the ADIT balance is a liability, this elimination would have the effect of increasing the pipeline’s rate base used for rate-making purposes;

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 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; and

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

We continue to evaluate this Final Rule and our next course of action, however, we do not expect an immediate or a retroactive impact from the Final Rule or the Revised Policy Statement described above.

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

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

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

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 property, plant 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 2018 FERC Actions are implemented through individual rate proceedings or settlements, and we have fully evaluated our respective alternatives to minimize any negative impact 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 property, plant 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 implemented through the individual rate proceeding or settlement, could result in an impairment charge to our equity method goodwill on Great Lakes which amounted to $260 million at June 30, 2018 (December 31, 2017 — $260 million). Additionally, given that 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 June 30, 2018 (December 31, 2017 - $82 million) related to Tuscarora could be negatively impacted by the 2018 FERC Actions once implemented through the individual rate proceeding or settlement.

EQUITY INVESTMENTS

6 Months Ended

Jun. 30, 2018

DEBT AND CREDIT FACILITIES

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		Six Months
(unaudited)	June 30,		ended June 30,		ended June 30,		June 30,	December 31,
(millions of dollars)	2018		2018	2017	2018	2017	2018	2017

Northern Border (a)	50	%	15	15	32	34	505	512
Great Lakes	46.45	%	12	6	36	23	485	479
Iroquois(b)	49.34	%	9	3	27	3	221	222

			36	24	95	60	1,211	1,213

^(a)

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

^(b)

Equity earnings from Iroquois is net of the 29-year amortization of a $10 million purchase price discrepancy assumed by the Partnership from TransCanada at the time of the 2017 Acquisition.

Distributions from Equity Investments

Distributions received from equity investments for the three and six months ended June 30, 2018 were $56 million and $101 million, respectively (2017 — $40 million and $68 million) of which $2.6 million and $5.2 million, respectively, (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 and six months ended June 30, 2018 and 2017.

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

(unaudited)
(millions of dollars)	June 30, 2018		December 31, 2017

ASSETS
Cash and cash equivalents	11		14
Other current assets	34		36
Plant, property and equipment, net	1,056		1,063
Other assets	14		14

	1,115		1,127


LIABILITIES AND PARTNERS’ EQUITY
Current liabilities	37		38
Deferred credits and other	33		31
Long-term debt, net (a)	264		264
Partners’ capital	782		795
Accumulated other comprehensive loss	(1	)	(1	)

	1,115		1,127

^(a)

No current maturities as of June 30, 2018 and December 31, 2017.

	Three months ended				Six months ended
(unaudited)	June 30,				June 30,
(millions of dollars)	2018		2017		2018		2017

Transmission revenues	68		69		140		144
Operating expenses	(19	)	(18	)	(38	)	(36	)
Depreciation	(15	)	(15	)	(30	)	(30	)
Financial charges and other	(4	)	(5	)	(7	)	(9	)

Net income	30		31		65		69

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 and six months ended June 30, 2018 and 2017.

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

(unaudited)
(millions of dollars)	June 30, 2018	December 31, 2017

ASSETS
Current assets	89	107
Plant, property and equipment, net	695	701

	784	808


LIABILITIES AND PARTNERS’ EQUITY
Current liabilities	49	75
Net long-term debt, including current maturities (a)	250	259
Other long term liabilities	—	1
Partners’ equity	485	473

	784	808

^(a)

Includes current maturities of $21 million as of June 30, 2018 (December 31, 2017 - $19 million).

	Three months ended				Six months ended
(unaudited)	June 30,				June 30,
(millions of dollars)	2018		2017		2018		2017

Transmission revenues	53		41		134		103
Operating expenses	(15	)	(17	)	(32	)	(30	)
Depreciation	(8	)	(7	)	(16	)	(14	)
Financial charges and other	(5	)	(5	)	(9	)	(10	)

Net income	25		12		77		49

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 and six months ended June 30, 2018, the Partnership received distributions from Iroquois amounting to $14 million and $28 million, respectively, which includes the Partnership’s 49.34 percent share of the Iroquois unrestricted cash distribution amounting to approximately $2.6 million and $5.2 million, respectively. 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 second quarter 2018 distribution of $29 million on July 25, 2018, of which the Partnership received its 49.34 percent share of $14 million on August 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 and six months ended June 30, 2018 and 2017.

The summarized financial information provided to us by Iroquois for the period from the June 1, 2017 acquisition date through June 30, 2018 is as follows:

(unaudited)
(millions of dollars)	June 30, 2018	December 31, 2017

ASSETS
Cash and cash equivalents	100	86
Other current assets	26	36
Plant, property and equipment, net	584	591
Other assets	10	8

	720	721


LIABILITIES AND PARTNERS’ EQUITY
Current liabilities	17	17
Net long-term debt, including current maturities (a)	327	329
Other non-current liabilities	13	9
Partners’ equity	363	366

	720	721

^(a)

Includes current maturities of $145 million as of June 30, 2018 (December 31, 2017 - $4 million).

(unaudited) (millions of dollars)	Three months ended June 30, 2018		One month ended June 30, 2017		Six months ended June 30, 2018		One month ended June 30, 2017

Transmission revenues	44		14		105		14
Operating expenses	(14	)	(5	)	(28	)	(5	)
Depreciation	(7	)	(2	)	(15	)	(2	)
Financial charges and other	(4	)	(1	)	(7	)	(1	)

Net income	19		6		55		6

REVENUES

6 Months Ended

Jun. 30, 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 and six months ended June 30, 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 contracts.

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

At June 30, 2018, had legacy U.S. GAAP been applied, there would be no change in the Partnership’s reported balance sheet and income statement line items.

Contract Balances

(unaudited-millions of dollars)	June 30, 2018	January 1, 2018

Receivables from contracts with customers(a)	37	40
Contract assets(b)	—	—

^(a)

Recorded as Trade accounts receivable and reported as Accounts receivable and other in the consolidated balance sheet (Refer also to Note 14)

^(b)

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. The Partnership did not have any Contract assets at January 1, 2018 and June 30, 2018.

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:

The original expected duration of the contract is one year or less.

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.

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

6 Months Ended

Jun. 30, 2018

DEBT AND CREDIT FACILITIES

NOTE 7 DEBT AND CREDIT FACILITIES

(unaudited) (millions of dollars)	June 30, 2018	Weighted Average Interest Rate for the Six Months Ended June 30, 2018		December 31, 2017		Weighted Average Interest Rate for the Year Ended December 31, 2017

TC PipeLines, LP
Senior Credit Facility due 2021	140	2.99	%	185		2.41	%
2013 Term Loan Facility due 2022	500	3.02	%	500		2.33	%
2015 Term Loan Facility due 2020	170	2.91	%	170		2.22	%
4.65% Unsecured Senior Notes due 2021	350	4.65	%(a)	350		4.65	%(a)
4.375% Unsecured Senior Notes due 2025	350	4.375	%(a)	350		4.375	%(a)
3.90% Unsecured Senior Notes due 2027	500	3.90	%(a)	500		3.90	%(a)
GTN
5.29% Unsecured Senior Notes due 2020	100	5.29	%(a)	100		5.29	%(a)
5.69% Unsecured Senior Notes due 2035	150	5.69	%(a)	150		5.69	%(a)
Unsecured Term Loan Facility due 2019	35	2.71	%	55		2.02	%
PNGTS
Revolving Credit Facility due 2023	—	—		—		—
5.90% Senior Secured Notes due 2018	—	—		30	(b)	5.90	%(a)
Tuscarora
Unsecured Term Loan due 2020	25	2.87	%	25		2.27	%

	2,320			2,415
Less: unamortized debt issuance costs and debt discount	12			12
Less: current portion	36			51	(b)

	2,272			2,352

^(a)

Fixed interest rate

^(b)

Includes the PNGTS portion due at December 31, 2017 amounting to $5.8 million that was paid on January 2, 2018.

TC PipeLines, LP

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 $140 million was outstanding at June 30, 2018 (December 31, 2017 - $185 million), leaving $360 million available for future borrowing. The LIBOR-based interest rate on the Senior Credit Facility was 3.24 percent at June 30, 2018 (December 31, 2017 — 2.62 percent).

As of June 30, 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 3.24 percent at June 30, 2018 (December 31, 2017 — 2.62 percent).

The LIBOR-based interest rate on the 2015 Term Loan Facility was 3.13 percent at June 30, 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 4.28 to 1.00 as of June 30, 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 June 30, 2018 was 42.3 percent. The LIBOR-based interest rate on the GTN’s Unsecured Term Loan Facility was 2.93 percent at June 30, 2018 (December 31, 2017 — 2.31 percent).

PNGTS

On April 5, 2018, PNGTS entered into a revolving credit agreement under which PNGTS has the ability to borrow up to $125 million with a variable interest rate based on LIBOR (Revolving Credit Facility). 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 primarily to fund the costs of the PXP expansion project and to finance PNGTS’ other funding needs.

On May 10, 2018, PNGTS paid the remaining principal balance of its 5.90% Senior Secured Notes due 2018 (2003 Senior Secured Notes) using its available cash.

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 June 30, 2018, the ratio was 11.2 to 1.00.

The LIBOR-based interest rate on the Tuscarora’s Unsecured Term Loan Facility was 3.11 percent at June 30, 2018 (December 31, 2017 — 2.49 percent).

At June 30, 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 a 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 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		1
2019		36
2020		293
2021		490
2022		500
Thereafter		1,000

		2,320

PARTNERS' EQUITY	6 Months Ended
PARTNERS' EQUITY	Jun. 30, 2018
PARTNERS' EQUITY
PARTNERS' EQUITY	NOTE 8 PARTNERS’ EQUITY ATM equity issuance program (ATM program) During the six months ended June 30, 2018, we issued 0.7 million common units under our ATM program (none during the three months ended June 30, 2018) 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 six months ended June 30, 2018 were nil. The net proceeds were used for general partnership purposes. Class B units issued to TransCanada The Class B Units 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 the 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 six months ended June 30, 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

6 Months Ended

Jun. 30, 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 and six months ended June 30, 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:

	Three months ended						Six months ended
(unaudited)	June 30,						June 30,
(millions of dollars, except per common unit amounts)	2018			2017			2018			2017

Net income attributable to controlling interests	73			55			169			132
Net income attributable to PNGTS’ former parent (a)	—			—			—			(2		)

Net income attributable to General and Limited Partners	73			55			169			130
Incentive distributions allocated to the General Partner (b)	—			(3		)	—			(5		)

Net income attributable to the General Partner and common units	73			52			169			125
Net income attributable to General Partner’s two percent interest	(1		)	(2		)	(3		)	(3		)

Net income attributable to common units	72			50			166			122
Weighted average common units outstanding (millions) – basic and diluted	71.3			68.9			71.2			68.6
Net income per common unit – basic and diluted	$	1.00		$	0.73		$	2.33		$	1.78

^(a)

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.

^(b)

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.

CASH DISTRIBUTIONS	6 Months Ended
CASH DISTRIBUTIONS	Jun. 30, 2018
CASH DISTRIBUTIONS
CASH DISTRIBUTIONS	NOTE 10 CASH DISTRIBUTIONS During the three and six months ended June 30, 2018, the Partnership distributed $0.65 and $1.65 per common unit, respectively, (June 30, 2017 — $0.94 and $1.88 per common unit, respectively) for a total of $47 million and $123 million, respectively, (June 30, 2017 - $68 million and $135 million, respectively). The distribution paid to our General Partner during the three months ended June 30, 2018 for its effective two percent general partner interest was $1 million (June 30, 2017 - $1 million for the effective two percent interest and a $2 million IDR payment). The General Partner did not receive any distributions in respect of its IDRs in the second quarter 2018. The distribution paid to our General Partner during the six months ended June 30, 2018 for its effective two percent general partner interest was $3 million along with an IDR payment of $3 million for a total distribution of $6 million (June 30, 2017 - $2 million for the effective two percent interest and a $4 million IDR payment).

CHANGE IN OPERATING WORKING CAPITAL

6 Months Ended

Jun. 30, 2018

CHANGE IN OPERATING WORKING CAPITAL

CHANGE IN OPERATING WORKING CAPITAL

NOTE 11 CHANGE IN OPERATING WORKING CAPITAL

(unaudited)	Six months ended June 30,
(millions of dollars)	2018		2017

Change in accounts receivable and other	2		11
Change in other current assets	(1	)	2
Change in accounts payable and accrued liabilities (a)	(6	)	(5	)
Change in accounts payable to affiliates	—		(2	)
Change in accrued interest	—		1

Change in operating working capital	(5	)	7

^(a)

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

RELATED PARTY TRANSACTIONS

6 Months Ended

Jun. 30, 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 and six months ended June 30, 2018 and 2017, total costs charged to the Partnership by the General Partner were $1 million and $2 million, respectively.

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

Capital and operating costs charged to our pipeline systems, except for Iroquois, for the three and six months ended June 30, 2018 and 2017 by TransCanada’s subsidiaries and amounts payable to TransCanada’s subsidiaries at June 30, 2018 and December 31, 2017 are summarized in the following tables:

	Three months ended		Six months ended
(unaudited)	June 30,		June 30,
(millions of dollars)	2018	2017	2018	2017

Capital and operating costs charged by TransCanada’s subsidiaries to:
Great Lakes (a)	16	9	24	17
Northern Border (a)	9	10	18	20
GTN	8	9	16	16
Bison	1	1	3	2
North Baja	1	1	2	2
Tuscarora	1	1	2	2
PNGTS	2	2	4	4
Impact on the Partnership’s net income:
Great Lakes (a)	7	4	11	7
Northern Border (a)	4	4	8	7
GTN	7	7	14	14
Bison	1	1	3	2
North Baja	1	1	2	2
Tuscarora	1	1	2	2
PNGTS	1	1	2	2

(unaudited)
(millions of dollars)	June 30, 2018	December 31, 2017

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

^(a)

Represents 100 percent of the costs.

^(b)

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 and six months ended June 30, 2018, Great Lakes earned 72 percent and 70 percent, respectively, of transportation revenues from TransCanada and its affiliates (2017 — 43 percent and 57 percent, respectively).

At June 30, 2018, $3 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 recorded an estimated revenue sharing provision amounting to $40 million. During the second quarter of 2018, the refund was settled with its customers and a significant portion of the refund was with its affiliates. Under the terms of the 2017 Great Lakes Settlement, beginning in 2018, its revenue sharing provision was eliminated (Refer to our Annual Report on Form 10-K for the year ended December 31, 2017).

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

PNGTS

PNGTS earns transportation revenues from TransCanada and its affiliates. For both three and six months ended June 30, 2018, PNGTS earned approximately $1 million of its transportation revenues from TransCanada and its affiliates (2017 — nil).

At June 30, 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 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 June 30, 2018, the total costs incurred by these affiliates was approximately $15 million.

FAIR VALUE MEASUREMENTS

6 Months Ended

Jun. 30, 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 June 30, 2018 and December 31, 2017 was $2,311 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 June 30, 2018, the fair value of the interest rate swaps accounted for as cash flow hedges was an asset of $15 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 loss of $1 million and a gain of $6 million for the three and six months ended June 30, 2018, respectively (2017 — nil and gain of $1 million). During the three and six months ended June 30, 2018, gain of $3 million was reclassified from other comprehensive income to net income (2017 — loss of $1 million). For the three and six months ended June 30, 2018, the net realized gain related to the interest rate swaps was $1 million and $2 million, respectively, 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. During the fourth quarter of 2017, the Partnership implemented an interest rate hedging strategy that hedged the $500 million 2013 Term Loan until its October 2, 2022 maturity using forward starting swaps at an average rate of 3.26 percent.

The Partnership has no master netting agreements; however, it has derivative contracts containing provisions with rights of offset. The Partnership has elected to present the fair value of derivative instruments with the right to offset on a gross basis in the balance sheet. Had the Partnership elected to present these instruments on a net basis, there would be no effect on the consolidated balance sheet as of June 30, 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 was amortized against earnings over the life of the PNGTS Senior Secured Notes. On May 10, 2018, PNGTS paid the remaining principal balance of its 2003 Senior Secured Notes using its available cash and, as a result, our 61.71 percent proportionate share of the net unamortized loss on PNGTS included in other comprehensive income was all amortized against earnings (December 31, 2017 - $1 million). For the three and six months ended June 30, 2018, our 61.71 percent proportionate share of the amortization of realized loss on derivative instruments was $1 million (2017 - $1 million).

ACCOUNTS RECEIVABLE AND OTHER

6 Months Ended

Jun. 30, 2018

ACCOUNTS RECEIVABLE AND OTHER

ACCOUNTS RECEIVABLE AND OTHER

NOTE 14 ACCOUNTS RECEIVABLE AND OTHER

(unaudited)
(millions of dollars)	June 30, 2018	December 31, 2017

Trade accounts receivable, net of allowance of nil	37	40
Imbalance receivable from affiliates	1	1
Other	2	1

	40	42

FINANCIAL CHARGES AND OTHER

6 Months Ended

Jun. 30, 2018

FINANCIAL CHARGES AND OTHER

FINANCIAL CHARGES AND OTHER

NOTE 15 FINANCIAL CHARGES AND OTHER

	Three months ended				Six months ended
(unaudited)	June 30,				June 30,
(millions of dollars)	2018		2017		2018		2017

Interest Expense (a)	24		19		48		36
PNGTS’ amortization of loss on derivative instruments (Note 13)	2		1		2		1
Net realized gain related to the interest rate swaps	(1	)	—		(2	)	—
Other Income	(2	)	(1	)	(2	)	(1	)

	23		19		46		36

^(a)

Includes amortization of debt issuance costs and discount costs.

CONTINGENCIES	6 Months Ended
CONTINGENCIES	Jun. 30, 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 June 30, 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 June 30, 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

6 Months Ended

Jun. 30, 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)	June 30, 2018		December 31, 2017

ASSETS (LIABILITIES) *
Cash and cash equivalents	7		19
Accounts receivable and other	27		30
Inventories	7		6
Other current assets	6		5
Equity investments	1,211		1,213
Plant, property and equipment, net	1,117		1,133
Other assets	2		1
Accounts payable and accrued liabilities	(18	)	(24	)
Accounts payable to affiliates, net	(44	)	(42	)
Distributions payable	—		(1	)
Accrued interest	(3	)	(2	)
Current portion of long-term debt	(36	)	(51	)
Long-term debt	(273	)	(308	)
Other liabilities	(27	)	(26	)
Deferred state income tax	(10	)	(10	)

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

INCOME TAXES

6 Months Ended

Jun. 30, 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 June 30, 2018 and December 31, 2017 relate primarily to utility plant. At June 30, 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		Six months ended
(unaudited)	June 30,		June 30,
(millions of dollars)	2018	2017	2018	2017

State income taxes
Current	—	—	1	1
Deferred	—	—	—	—

	—	—	1	1

SUBSEQUENT EVENTS	6 Months Ended
SUBSEQUENT EVENTS	Jun. 30, 2018
SUBSEQUENT EVENTS
SUBSEQUENT EVENTS	NOTE 19 SUBSEQUENT EVENTS Management of the Partnership has reviewed subsequent events through August 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 July 26, 2018, the board of directors of the General Partner declared the Partnership’s second quarter 2018 cash distribution in the amount of $0.65 per common unit payable on August 15, 2018 to unitholders of record as of August 6, 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 second quarter 2018. This distribution and our first quarter 2018 distribution each represent a 35 percent reduction compared 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 impact of the 2018 FERC Actions on our future operating performance and cash flows. Northern Border declared its June 2018 distribution of $12 million on July 11, 2018, of which the Partnership received its 50 percent share or $6 million on July 31, 2018. Great Lakes declared its second quarter 2018 distribution of $29 million on July 17, 2018, of which the Partnership received its 46.45 percent share or $13 million on August 1, 2018. PNGTS declared its second quarter 2018 distribution of $3 million on July 20, 2018, of which $1 million will be paid to its non-controlling interest owner on August 1, 2018.

SIGNIFICANT ACCOUNTING POLICIES (Policies)	6 Months Ended
SIGNIFICANT ACCOUNTING POLICIES (Policies)	Jun. 30, 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.
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)

6 Months Ended

Jun. 30, 2018

Schedule of equity investments and summarized financial information for equity investees

	Ownership		Equity Earnings				Equity Investments
	Interest at		Three months		Six Months
(unaudited)	June 30,		ended June 30,		ended June 30,		June 30,	December 31,
(millions of dollars)	2018		2018	2017	2018	2017	2018	2017

Northern Border (a)	50	%	15	15	32	34	505	512
Great Lakes	46.45	%	12	6	36	23	485	479
Iroquois(b)	49.34	%	9	3	27	3	221	222

			36	24	95	60	1,211	1,213

^(a)

^(b)

Equity earnings from Iroquois is net of the 29-year amortization of a $10 million purchase price discrepancy assumed by the Partnership from TransCanada at the time of the 2017 Acquisition.

Northern Border

Schedule of equity investments and summarized financial information for equity investees

(unaudited)
(millions of dollars)	June 30, 2018		December 31, 2017

ASSETS
Cash and cash equivalents	11		14
Other current assets	34		36
Plant, property and equipment, net	1,056		1,063
Other assets	14		14

	1,115		1,127


LIABILITIES AND PARTNERS’ EQUITY
Current liabilities	37		38
Deferred credits and other	33		31
Long-term debt, net (a)	264		264
Partners’ capital	782		795
Accumulated other comprehensive loss	(1	)	(1	)

	1,115		1,127

^(a)

No current maturities as of June 30, 2018 and December 31, 2017.

	Three months ended				Six months ended
(unaudited)	June 30,				June 30,
(millions of dollars)	2018		2017		2018		2017

Transmission revenues	68		69		140		144
Operating expenses	(19	)	(18	)	(38	)	(36	)
Depreciation	(15	)	(15	)	(30	)	(30	)
Financial charges and other	(4	)	(5	)	(7	)	(9	)

Net income	30		31		65		69

Great Lakes

Schedule of equity investments and summarized financial information for equity investees

(unaudited)
(millions of dollars)	June 30, 2018	December 31, 2017

ASSETS
Current assets	89	107
Plant, property and equipment, net	695	701

	784	808


LIABILITIES AND PARTNERS’ EQUITY
Current liabilities	49	75
Net long-term debt, including current maturities (a)	250	259
Other long term liabilities	—	1
Partners’ equity	485	473

	784	808

^(a)

Includes current maturities of $21 million as of June 30, 2018 (December 31, 2017 - $19 million).

	Three months ended				Six months ended
(unaudited)	June 30,				June 30,
(millions of dollars)	2018		2017		2018		2017

Transmission revenues	53		41		134		103
Operating expenses	(15	)	(17	)	(32	)	(30	)
Depreciation	(8	)	(7	)	(16	)	(14	)
Financial charges and other	(5	)	(5	)	(9	)	(10	)

Net income	25		12		77		49

Iroquois

Schedule of equity investments and summarized financial information for equity investees

(unaudited)
(millions of dollars)	June 30, 2018	December 31, 2017

ASSETS
Cash and cash equivalents	100	86
Other current assets	26	36
Plant, property and equipment, net	584	591
Other assets	10	8

	720	721


LIABILITIES AND PARTNERS’ EQUITY
Current liabilities	17	17
Net long-term debt, including current maturities (a)	327	329
Other non-current liabilities	13	9
Partners’ equity	363	366

	720	721

^(a)

Includes current maturities of $145 million as of June 30, 2018 (December 31, 2017 - $4 million).

(unaudited) (millions of dollars)	Three months ended June 30, 2018		One month ended June 30, 2017		Six months ended June 30, 2018		One month ended June 30, 2017

Transmission revenues	44		14		105		14
Operating expenses	(14	)	(5	)	(28	)	(5	)
Depreciation	(7	)	(2	)	(15	)	(2	)
Financial charges and other	(4	)	(1	)	(7	)	(1	)

Net income	19		6		55		6

REVENUES (Tables)

6 Months Ended

Jun. 30, 2018

REVENUES

Schedule of contract balances

(unaudited-millions of dollars)	June 30, 2018	January 1, 2018

Receivables from contracts with customers(a)	37	40
Contract assets(b)	—	—

^(a)

Recorded as Trade accounts receivable and reported as Accounts receivable and other in the consolidated balance sheet (Refer also to Note 14)

^(b)

DEBT AND CREDIT FACILITIES (Tables)

6 Months Ended

Jun. 30, 2018

DEBT AND CREDIT FACILITIES

Schedule of debt and credit facilities

(unaudited) (millions of dollars)	June 30, 2018	Weighted Average Interest Rate for the Six Months Ended June 30, 2018		December 31, 2017		Weighted Average Interest Rate for the Year Ended December 31, 2017

TC PipeLines, LP
Senior Credit Facility due 2021	140	2.99	%	185		2.41	%
2013 Term Loan Facility due 2022	500	3.02	%	500		2.33	%
2015 Term Loan Facility due 2020	170	2.91	%	170		2.22	%
4.65% Unsecured Senior Notes due 2021	350	4.65	%(a)	350		4.65	%(a)
4.375% Unsecured Senior Notes due 2025	350	4.375	%(a)	350		4.375	%(a)
3.90% Unsecured Senior Notes due 2027	500	3.90	%(a)	500		3.90	%(a)
GTN
5.29% Unsecured Senior Notes due 2020	100	5.29	%(a)	100		5.29	%(a)
5.69% Unsecured Senior Notes due 2035	150	5.69	%(a)	150		5.69	%(a)
Unsecured Term Loan Facility due 2019	35	2.71	%	55		2.02	%
PNGTS
Revolving Credit Facility due 2023	—	—		—		—
5.90% Senior Secured Notes due 2018	—	—		30	(b)	5.90	%(a)
Tuscarora
Unsecured Term Loan due 2020	25	2.87	%	25		2.27	%

	2,320			2,415
Less: unamortized debt issuance costs and debt discount	12			12
Less: current portion	36			51	(b)

	2,272			2,352

^(a)

Fixed interest rate

^(b)

Includes the PNGTS portion due at December 31, 2017 amounting to $5.8 million that was paid on January 2, 2018.

Schedule of principal repayments required on debt

(unaudited)
(millions of dollars)

2018		1
2019		36
2020		293
2021		490
2022		500
Thereafter		1,000

		2,320

NET INCOME PER COMMON UNIT (Tables)

6 Months Ended

Jun. 30, 2018

NET INCOME PER COMMON UNIT

Schedule of net income per common unit

	Three months ended						Six months ended
(unaudited)	June 30,						June 30,
(millions of dollars, except per common unit amounts)	2018			2017			2018			2017

Net income attributable to controlling interests	73			55			169			132
Net income attributable to PNGTS’ former parent (a)	—			—			—			(2		)

Net income attributable to General and Limited Partners	73			55			169			130
Incentive distributions allocated to the General Partner (b)	—			(3		)	—			(5		)

Net income attributable to the General Partner and common units	73			52			169			125
Net income attributable to General Partner’s two percent interest	(1		)	(2		)	(3		)	(3		)

Net income attributable to common units	72			50			166			122
Weighted average common units outstanding (millions) – basic and diluted	71.3			68.9			71.2			68.6
Net income per common unit – basic and diluted	$	1.00		$	0.73		$	2.33		$	1.78

^(a)

^(b)

CHANGE IN OPERATING WORKING CAPITAL (Tables)

6 Months Ended

Jun. 30, 2018

CHANGE IN OPERATING WORKING CAPITAL

Schedule of change in operating working capital

(unaudited)	Six months ended June 30,
(millions of dollars)	2018		2017

Change in accounts receivable and other	2		11
Change in other current assets	(1	)	2
Change in accounts payable and accrued liabilities (a)	(6	)	(5	)
Change in accounts payable to affiliates	—		(2	)
Change in accrued interest	—		1

Change in operating working capital	(5	)	7

^(a)

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

RELATED PARTY TRANSACTIONS (Tables)

6 Months Ended

Jun. 30, 2018

RELATED PARTY TRANSACTIONS

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

	Three months ended		Six months ended
(unaudited)	June 30,		June 30,
(millions of dollars)	2018	2017	2018	2017

Capital and operating costs charged by TransCanada’s subsidiaries to:
Great Lakes (a)	16	9	24	17
Northern Border (a)	9	10	18	20
GTN	8	9	16	16
Bison	1	1	3	2
North Baja	1	1	2	2
Tuscarora	1	1	2	2
PNGTS	2	2	4	4
Impact on the Partnership’s net income:
Great Lakes (a)	7	4	11	7
Northern Border (a)	4	4	8	7
GTN	7	7	14	14
Bison	1	1	3	2
North Baja	1	1	2	2
Tuscarora	1	1	2	2
PNGTS	1	1	2	2

Summary of amount payable to related party for costs charged

(unaudited)
(millions of dollars)	June 30, 2018	December 31, 2017

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

^(a)

Represents 100 percent of the costs.

^(b)

Excludes any amounts owed to affiliates relating to revenue sharing. See discussion below.

ACCOUNTS RECEIVABLE AND OTHER (Tables)

6 Months Ended

Jun. 30, 2018

ACCOUNTS RECEIVABLE AND OTHER

Schedule of accounts receivable and other

(unaudited)
(millions of dollars)	June 30, 2018	December 31, 2017

Trade accounts receivable, net of allowance of nil	37	40
Imbalance receivable from affiliates	1	1
Other	2	1

	40	42

FINANCIAL CHARGES AND OTHER (Tables)

6 Months Ended

Jun. 30, 2018

FINANCIAL CHARGES AND OTHER

Schedule of components of financial charges and other

	Three months ended				Six months ended
(unaudited)	June 30,				June 30,
(millions of dollars)	2018		2017		2018		2017

Interest Expense (a)	24		19		48		36
PNGTS’ amortization of loss on derivative instruments (Note 13)	2		1		2		1
Net realized gain related to the interest rate swaps	(1	)	—		(2	)	—
Other Income	(2	)	(1	)	(2	)	(1	)

	23		19		46		36

^(a)

Includes amortization of debt issuance costs and discount costs.

VARIABLE INTEREST ENTITIES (Tables)

6 Months Ended

Jun. 30, 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)	June 30, 2018		December 31, 2017

ASSETS (LIABILITIES) *
Cash and cash equivalents	7		19
Accounts receivable and other	27		30
Inventories	7		6
Other current assets	6		5
Equity investments	1,211		1,213
Plant, property and equipment, net	1,117		1,133
Other assets	2		1
Accounts payable and accrued liabilities	(18	)	(24	)
Accounts payable to affiliates, net	(44	)	(42	)
Distributions payable	—		(1	)
Accrued interest	(3	)	(2	)
Current portion of long-term debt	(36	)	(51	)
Long-term debt	(273	)	(308	)
Other liabilities	(27	)	(26	)
Deferred state income tax	(10	)	(10	)

- Definition

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

+ References + Details

INCOME TAXES (Tables)

6 Months Ended

Jun. 30, 2018

INCOME TAXES

Schedule of state income taxes of PNGTS

	Three months ended		Six months ended
(unaudited)	June 30,		June 30,
(millions of dollars)	2018	2017	2018	2017

State income taxes
Current	—	—	1	1
Deferred	—	—	—	—

	—	—	1	1

ORGANIZATION - Ownership Interests in Natural Gas Pipeline Systems (Details)	6 Months Ended
	Jun. 30, 2018 LimitedPartnership
ORGANIZATION
Number of intermediate limited partnerships through which pipeline assets are owned	3

REGULATORY (Details) - USD ($) $ in Millions	6 Months Ended	12 Months Ended
REGULATORY (Details) - USD ($) $ in Millions	Jun. 30, 2018	Dec. 31, 2017
FERC \| Maximum
REGULATORY
Estimated ROE		12.00%
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) - USD ($)
$ in Millions

1 Months Ended

3 Months Ended

6 Months Ended

12 Months Ended

Aug. 01, 2018

Jul. 25, 2018

Jun. 30, 2017

Apr. 30, 2006

Jun. 30, 2018

Mar. 31, 2018

Jun. 30, 2017

Jun. 30, 2018

Jun. 30, 2017

Dec. 31, 2017

Jul. 31, 2018

Jun. 01, 2017

$ 36.0

$ 24.0

$ 95.0

$ 60.0

1,211.0

$ 1,213.0

Distributions from Equity Investments

36.0

$ 51.0

Distributions received from equity investments

56.0

40.0

101.0

68.0

Distributions from equity investments

96.0

68.0

Return on investment distribution classified as investing activities

2.6

0.0

5.0

0.0

TransCanada

Amortization period of purchase price discrepancy

29 years

Purchase price discrepancy

$ 10.0

Great Lakes

Total cash call issued to fund debt repayment

$ 9.0

$ 21.0

19.0

Iroquois

49.34%

Distributions from Equity Investments

$ 145.0

4.0

Distributions from equity investments

$ 14.0

14.0

28.0

Return on investment distribution classified as investing activities

$ 2.6

$ 5.2

Limited partners, Distribution declared

$ 29.0

Northern Border

50.00%

^[1]

50.00%

^[1]

50.00%

^[1]

$ 15.0

15.0

$ 32.0

34.0

Amortization period of transaction fee

^[1]

505.0

512.0

12 years

Transaction fee

$ 10.0

Additional ownership interest acquired (as a percent)

20.00%

Assets

Cash and cash equivalents

11.0

14.0

Other current assets

34.0

36.0

Plant, property and equipment, net

1,056.0

1,063.0

Other assets

14.0

Assets, total

1,115.0

1,127.0

Deferred credits and other

Current liabilities

37.0

38.0

33.0

31.0

Net long-term debt, including current maturities

264.0

Partners' capital

782.0

795.0

Accumulated other comprehensive loss

(1.0)

Liabilities and Partners' Equity, total

1,115.0

1,127.0

Revenues (expenses)

Transmission revenues

68.0

69.0

140.0

144.0

Operating expenses

(19.0)

(18.0)

(38.0)

(36.0)

Depreciation

(15.0)

(30.0)

Financial charges and other

(4.0)

(5.0)

(7.0)

(9.0)

$ 30.0

31.0

$ 65.0

69.0

Great Lakes

46.45%

$ 12.0

6.0

$ 36.0

23.0

Plant, property and equipment, net

485.0

479.0

Equity contribution

$ 4.0

4.0

Assets

Current assets

89.0

107.0

695.0

701.0

Assets, total

784.0

808.0

Net long-term debt, including current maturities

Current liabilities

49.0

75.0

250.0

259.0

Other non-current liabilities

0.0

1.0

Partners' capital

485.0

473.0

Liabilities and Partners' Equity, total

784.0

808.0

Revenues (expenses)

Transmission revenues

53.0

41.0

134.0

103.0

Operating expenses

(15.0)

(17.0)

(32.0)

(30.0)

Depreciation

(8.0)

(7.0)

(16.0)

(14.0)

Financial charges and other

(5.0)

(9.0)

(10.0)

$ 25.0

12.0

$ 77.0

49.0

Iroquois

49.34%

$ 9.0

3.0

$ 27.0

3.0

Cash and cash equivalents

221.0

222.0

Undistributed earnings

0.0

$ 0.0

0.0

$ 0.0

Assets

100.0

86.0

Other current assets

26.0

36.0

Plant, property and equipment, net

584.0

591.0

Other assets

10.0

8.0

Assets, total

720.0

721.0

Net long-term debt, including current maturities

Current liabilities

17.0

327.0

329.0

Other non-current liabilities

13.0

9.0

Partners' capital

363.0

366.0

Liabilities and Partners' Equity, total

720.0

$ 721.0

Revenues (expenses)

Transmission revenues

$ 14.0

44.0

105.0

Operating expenses

(5.0)

(14.0)

(28.0)

Depreciation

(2.0)

(7.0)

(15.0)

Financial charges and other

(1.0)

(4.0)

(7.0)