10-Q

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

x QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended June 30, 2016

or

¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from           to         

Commission File Number:  001-35358

TC PipeLines, LP

(Exact name of registrant as specified in its charter)

Delaware	52-2135448
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification Number)

700 Louisiana Street, Suite 700 Houston, Texas	77002-2761
(Address of principle executive offices)	(Zip code)

877-290-2772

(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

Yes x                    No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

Yes x                    No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer x	Accelerated filer o
Non-accelerated filer o	Smaller reporting company o
(Do not check if a smaller reporting
company)

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

Yes o                    No x

As of August 2, 2016, there were 65,937,080 of the registrant’s common units outstanding.

TC PIPELINES, LP

		Page No.
TABLE OF CONTENTS
PART I	FINANCIAL INFORMATION
Item 1.	Financial Statements (Unaudited)	5
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	25
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	35
Item 4.	Controls and Procedures	37
PART II	OTHER INFORMATION
Item 1.	Legal Proceedings	37
Item 1A.	Risk Factors	38
Item 6.	Exhibits	40
	Signatures	41

All amounts are stated in United States dollars unless otherwise indicated.

2

DEFINITIONS

The abbreviations, acronyms, and industry terminology used in this quarterly report are defined as follows:

2013 Term Loan Facility	TC PipeLines, LP’s term loan credit facility under a term loan agreement dated July 1, 2013
2015 GTN Acquisition	Partnership’s acquisition of the remaining 30 percent interest in GTN on April 1, 2015
2015 Term Loan Facility	TC PipeLines, LP’s term loan credit facility under a term loan agreement dated September 30, 2015
ASC	Accounting Standards Codification
ASU	Accounting Standards Update
ATM program	At-the-market equity issuance program
Bison	Bison Pipeline LLC
Carty Lateral	GTN lateral pipeline in north-central Oregon that delivers natural gas to a power plant owned by Portland General Electric Company
Consolidated Subsidiaries	GTN, Bison, North Baja and Tuscarora
DOT	U.S. Department of Transportation
EBITDA	Earnings Before Interest, Tax, Depreciation and Amortization
EPA	U.S. Environmental Protection Agency
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission
GAAP	U.S. generally accepted accounting principles
General Partner	TC PipeLines GP, Inc.
Great Lakes	Great Lakes Gas Transmission Limited Partnership
GTN	Gas Transmission Northwest LLC
IDRs	Incentive Distribution Rights
ILPs	Intermediate Limited Partnerships
LIBOR	London Interbank Offered Rate
NGA	Natural Gas Act of 1938
North Baja	North Baja Pipeline, LLC
Northern Border	Northern Border Pipeline Company
Our pipeline systems	Our ownership interests in GTN, Northern Border, Bison, Great Lakes, North Baja, Tuscarora, and PNGTS
Partnership	TC PipeLines, LP including its subsidiaries, as applicable
Partnership Agreement	Third Amended and Restated Agreement of Limited Partnership of the Partnership
PHMSA	U.S. Department of Transportation Pipeline and Hazardous Materials Safety Administration
PNGTS	Portland Natural Gas Transmission System
PNGTS Acquisition	Partnership’s acquisition of a 49.9 percent interest in PNGTS, effective January 1, 2016
SEC	Securities and Exchange Commission
Senior Credit Facility	TC PipeLines, LP’s senior facility under revolving credit agreement as amended and restated, dated November 20, 2012
Short-Term Loan Facility	TC PipeLines, LP’s short-term loan facility under loan agreement dated October 1, 2014
TransCanada	TransCanada Corporation and its subsidiaries
Tuscarora	Tuscarora Gas Transmission Company
U.S.	United States of America
VIEs	Variable Interest Entities

Unless the context clearly indicates otherwise, TC PipeLines, LP and its subsidiaries are collectively referred to in this quarterly report as “we,” “us,” “our” and “the Partnership.” We use “our pipeline systems” and “our pipelines” when referring to the Partnership’s ownership interests in Gas Transmission Northwest LLC (GTN), Northern Border Pipeline Company (Northern Border), Bison Pipeline LLC (Bison), Great Lakes Gas Transmission Limited Partnership (Great Lakes), North Baja Pipeline, LLC (North Baja), Tuscarora Gas Transmission Company (Tuscarora) and Portland Natural Gas Transmission System (PNGTS).

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PART I

FORWARD-LOOKING STATEMENTS AND CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

This report includes certain forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. Forward-looking statements are identified by words and phrases such as: “anticipate,” “assume, “ “estimate,” “expect,” “project,” “intend,” “plan,” “believe,” “forecast,” “should,” “predict,” “could,” “will,” “may,” and other terms and expressions of similar meaning. The absence of these words, however, does not mean that the statements are not forward-looking. These statements are based on management’s beliefs and assumptions and on currently available information and include, but are not limited to, statements regarding anticipated financial performance, future capital expenditures, liquidity, market or competitive conditions, regulations, organic or strategic growth opportunities, contract renewals and ability to market open capacity, business prospects, outcome of regulatory proceedings and cash distributions to unitholders.

Forward-looking statements involve risks and uncertainties that may cause actual results to differ materially from the results predicted. Factors that could cause actual results and our financial condition to differ materially from those contemplated in forward-looking statements include, but are not limited to:

·the ability of our pipeline systems to sell available capacity on favorable terms and renew expiring contracts which are affected by, among other factors:

·demand for natural gas;

·changes in relative cost structures and production levels of natural gas producing basins;

·natural gas prices and regional differences;

·weather conditions;

·availability and location of natural gas supplies in Canada and the United States (U.S.) in relation to our pipeline systems;

·competition from other pipeline systems;

·natural gas storage levels; and

·rates and terms of service;

·the performance by the shippers of their contractual obligations on our pipeline systems;

·the outcome and frequency of rate proceedings or settlement negotiations on our pipeline systems;

·changes in the taxation of master limited partnerships by state or federal governments such as final adoption of proposed regulations narrowing the sources of income qualifying for partnership tax treatment or the elimination of pass-through taxation or tax deferred distributions;

·increases in operational or compliance costs resulting from changes in laws and governmental regulations affecting our pipeline systems, particularly regulations issued by the Federal Energy Regulatory Commission (FERC), the U.S. Environmental Protection Agency (EPA) and U.S. Department of Transportation (DOT);

·the impact of recent significant declines in oil and natural gas prices, including the effects on the creditworthiness of our shippers;

·our ongoing ability to grow distributions through acquisitions, accretive expansions or other growth opportunities, including the timing, terms and closure of future potential acquisitions;

·the outcome of TransCanada’s master limited partnership (MLP) strategy review;

·potential conflicts of interest between TC PipeLines GP, Inc., our general partner (General Partner), TransCanada and us;

·the impact of any impairment charges;

·cybersecurity threats, acts of terrorism and related disruptions;

·the impact of new accounting pronouncements;

·operating hazards, casualty losses and other matters beyond our control;

·potential of claims for rescission or loss in connection with certain sales under our at-the-market equity issuance program (ATM program); and

·the level of our indebtedness, including the indebtedness of our pipeline systems, and the availability of capital.

These and other risks are described elsewhere in this Form 10-Q, including the risks described in greater detail in Part II, Item 1A “Risk Factors” and those described in Part I, Item 1A. “Risk Factors” in our Form 10-K for the year ended December 31, 2015. All forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by these factors. All forward-looking statements are made only as of the date made and, except as required by applicable law, we undertake no obligation to update any forward-looking statements to reflect new information, subsequent events or other changes.

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PART I — FINANCIAL INFORMATION

Item 1.Financial Statements

TC PIPELINES, LP

CONSOLIDATED STATEMENTS OF INCOME

	Three months ended						Six months ended
(unaudited)	June 30,						June 30,
(millions of dollars, except per common unit amounts)	2016			2015			2016			2015
Transmission revenues	89			85			175			172
Equity earnings (Note 4)	22			15			64			46
Operation and maintenance expenses	(12		)	(13		)	(22		)	(24		)
Property taxes	(5		)	(5		)	(10		)	(11		)
General and administrative	(2		)	(1		)	(4		)	(4		)
Depreciation	(22		)	(21		)	(43		)	(42		)
Financial charges and other (Note 14)	(16		)	(16		)	(33		)	(29		)
Net income	54			44			127			108
Net income attributable to non-controlling interests	—			—			—			7
Net income attributable to controlling interests	54			44			127			101
Net income attributable to controlling interest allocation
Common units	50			42			121			98
General Partner	3			2			5			3
Class B units	1			—			1			—
	54			44			127			101
Net income per common unit (Note 8) — basic and diluted	$	0.76		$	0.66		$	1.86		$	1.53
Weighted average common units outstanding — basic and diluted (millions)	65.5			63.8			64.9			63.7
Common units outstanding, end of period (millions)	65.9			64.0			65.9			64.0

The accompanying notes are an integral part of these consolidated financial statements.

5

TC PIPELINES, LP

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

	Three months ended			Six months ended
(unaudited)	June 30,			June 30,
(millions of dollars)	2016		2015	2016		2015
Net income	54		44	127		108
Other comprehensive income
Change in fair value of cash flow hedges (Note 12)	(1	)	—	(3	)	(1	)
Reclassification to net income of gains and losses on cash flow hedges (Note 12)	—		—	—		—
Comprehensive income	53		44	124		107
Comprehensive income attributable to non-controlling interests	—		—	—		7
Comprehensive income attributable to controlling interests	53		44	124		100

The accompanying notes are an integral part of these consolidated financial statements.

6

TC PIPELINES, LP

CONSOLIDATED BALANCE SHEETS

(unaudited)
(millions of dollars)	June 30, 2016		December 31, 2015
ASSETS
Current Assets
Cash and cash equivalents	40		39
Accounts receivable and other (Note 13)	35		35
Distribution receivable from affiliate (Note 11)	4		—
Inventories	7		7
	86		81
Equity investments (Note 4)	1,047		965
Plant, property and equipment
(Net of $850 accumulated depreciation; 2015 - $811)	1,913		1,949
Goodwill	130		130
Other assets (Note 3)	—		1
	3,176		3,126
LIABILITIES AND PARTNERS’ EQUITY
Current Liabilities
Accounts payable and accrued liabilities	26		32
Accounts payable to affiliates (Note 11)	5		5
Accrued interest	9		8
Current portion of long-term debt (Note 5)	15		14
	55		59
Long-term debt (Notes 3 and 5)	1,938		1,889
Other liabilities	29		27
	2,022		1,975
Common units subject to rescission (Note 7)	83		—
Partners’ Equity
Common units	955		1,021
Class B units (Note 7)	96		107
General partner	25		25
Accumulated other comprehensive loss	(5	)	(2	)
Controlling interests	1,071		1,151
	3,176		3,126

Contingencies (Note 15)

Variable Interest Entities (Note 17)

Subsequent Events (Note 18)

The accompanying notes are an integral part of these consolidated financial statements.

7

TC PIPELINES, LP

CONSOLIDATED STATEMENT OF CASH FLOWS

	Six months ended
(unaudited)	June 30,
(millions of dollars)	2016		2015
Cash Generated From Operations
Net income	127		108
Depreciation	43		42
Amortization of debt issue costs reported as interest expense (Note 3)	1		1
Equity allowance for funds used during construction	—		(1	)
Equity earnings in excess of cumulative distributions:
PNGTS	(4	)	—
Change in operating working capital (Note 10)	3		1
	170		151
Investing Activities
Cumulative distributions in excess of equity earnings:
Northern Border	25		13
Great Lakes	17		10
Investment in Great Lakes	(4	)	(4	)
Acquisition of the remaining 30 percent interest in GTN	—		(264	)
Acquisition of PNGTS (Note 6)	(193	)	—
Capital expenditures	(18	)	(12	)
Other	2		(1	)
	(171	)	(258	)
Financing Activities
Distributions paid (Note 9)	(119	)	(110	)
Distributions paid to Class B units (Note 7)	(12	)	—
Distributions paid to non-controlling interests	—		(9	)
Common unit issuance, net	—		26
Common unit issuance subject to rescission, net (Note 7)	83		—
Equity contribution by the General Partner	—		2
Long-term debt issued, net of discount (Note 5)	205		424
Long-term debt repaid (Note 5)	(155	)	(205	)
Debt issuance costs	—		(3	)
	2		125
Increase in cash and cash equivalents	1		18
Cash and cash equivalents, beginning of period	39		26
Cash and cash equivalents, end of period	40		44

The accompanying notes are an integral part of these consolidated financial statements.

8

TC PIPELINES, LP

CONSOLIDATED STATEMENT OF CHANGES IN PARTNERS’ EQUITY

										Accumulated
										Other
	Limited Partners							General		Comprehensive		Total
(unaudited)	Common Units				Class B Units			Partner		Loss (a)		Equity
	(millions of units)		(millions of  dollars)		(millions of units)	(millions of dollars)		(millions of  dollars)		(millions of  dollars)		(millions of  dollars)
Partners’ Equity at December 31, 2015	64.3		1,021		1.9	107		25		(2	)	1,151
Net income	—		121		—	1		5		—		127
Other Comprehensive Loss	—		—		—	—		—		(3	)	(3	)
Common unit issuance subject to rescission, net (Note 7)	1.6		81		—	—		2		—		83
Reclassification of common unit issuance subject to rescission, net (Note 7)	(1.6	)	(81	)	—	—		(2	)	—		(83	)
Acquisition of PNGTS (Note 6)	—		(72	)	—	—		(1	)	—		(73	)
Distributions	—		(115	)	—	(12	)	(4	)	—		(131	)
Partners’ Equity at June 30, 2016	64.3		955		1.9	96		25		(5	)	1,071

(a)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 $2 million. These estimates assume constant interest rates over time; however, the amounts reclassified will vary based on actual value of interest rates at the date of settlement.

The accompanying notes are an integral part of these consolidated financial statements.

9

TC PIPELINES, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

NOTE 1ORGANIZATION

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.

NOTE 2SIGNIFICANT 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, 2016 and 2015 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 financial statements and notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2015. 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, 2015, except as described in Note 3, Accounting Pronouncements.

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.

NOTE 3ACCOUNTING PRONOUNCEMENTS

Effective January 1, 2016

Consolidation

In February 2015, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) No. 2015-02 “Consolidation (Topic 810),” an amendment of previously issued guidance on consolidation. This updated guidance requires that an entity evaluate whether it should consolidate certain legal entities. All legal entities are subject to reevaluation under the revised consolidation model. This guidance became effective beginning January 1, 2016 and was applied retrospectively to all financial statements presented. The application of this guidance did not result in any change to the Partnership’s consolidation conclusions. Refer to Note 17, Variable Interest Entities.

Imputation of interest

In April 2015, the FASB issued ASU No. 2015-03 “Interest — Imputation of Interest (Subtopic 835-30),” an amendment of previously issued guidance on imputation of interest. This updated guidance requires debt issuance costs be presented in the balance sheet as a direct deduction from the carrying amount of debt liabilities, consistent with debt discount or premiums. In addition, amortization of debt issuance costs should be reported as interest expense. The recognition and measurement for debt issuance costs would not be affected. This guidance is effective from January 1, 2016 and was applied retrospectively resulting in a reclassification of debt issuance costs previously recorded in other assets to an offset of their respective debt liabilities on the Partnership’s consolidated balance sheet. Amortization of debt issuance costs was reported as interest expense in all periods presented in the Partnership’s consolidated statement of income.

10

As a result of the application of ASU No. 2015-03 and similar to the presentation of debt discounts, debt issuance costs of $7 million at December 31, 2015 previously reported as other assets in the balance sheet were reclassified as an offset against their respective debt liabilities.

Earnings per share

In April 2015, the FASB issued ASU No. 2015-06 “Earnings Per Share (Topic 260),” an amendment of previously issued guidance on earnings per share (EPS) as it is being calculated by master limited partnerships. This updated guidance specifies that for purposes of calculating historical EPS under the two-class method, the earnings (losses) of a transferred business before the date of a dropdown transaction should be allocated entirely to the general partner interest, and previously reported EPS of the limited partners would not change as a result of a dropdown transaction. Qualitative disclosures about how the rights to the earnings (losses) differ before and after the dropdown transaction occurs are also required. This guidance became effective from January 1, 2016 and applies to all dropdown transactions requiring recast. The retrospective application of this guidance did not have a material impact on the Partnership’s consolidated financial statements as our current accounting policy is consistent with the new guidance.

Business combinations

In September 2015, the FASB issued ASU No. 2015-16 “Business Combinations (Topic 805),” which replaces the requirement that an acquirer in a business combination account for measurement period adjustments retrospectively with a requirement that an acquirer recognize adjustments to the provisional amounts that are identified during the measurement period in the reporting period in which the adjustment amounts are determined. The amended guidance requires that the acquirer record, in the same period’s financial statements, the effect on earnings of changes in depreciation, amortization, or other income effects, if any, as a result of the change to the provisional amounts, calculated as if the accounting had been completed at the acquisition date. The new guidance is effective January 1, 2016 and was applied prospectively. The application of this guidance did not have a material impact on the Partnership’s consolidated financial statements.

Future accounting changes

Revenue from contracts with customers

In May 2014, the FASB issued ASU No. 2014-09 “Revenue from Contracts with Customers (Topic 606).” This guidance supersedes the revenue recognition requirements in Topic 605, Revenue Recognition and most industry-specific guidance. This new guidance requires that an entity recognizes revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the company expects to be entitled in exchange for those goods or services. On July 9, 2015, the FASB voted to defer the effective date by one year to December 15, 2017 for annual reporting periods beginning after that date. The FASB also voted to permit early adoption of the standard, but not before the original effective date of December 15, 2016. This new guidance, once effective, allows two methods in which the amendment can be applied: (1) retrospectively to each prior reporting period presented, or (2) retrospectively with the cumulative effect recognized at the date of initial application. This guidance supersedes the current revenue recognition requirements and most industry-specific guidance. The core principle relating to the new guidance requires that an entity recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the company expects to be entitled in exchange for those goods or services. To achieve the core principle, a five step process is required:

1) Identify the contract with the customer

2) Identify the performance obligations in the contract

3) Determine the transaction price

4) Allocate the transaction price to the performance obligations

5) Recognize revenue when (or as) each performance obligations is satisfied

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The new guidance also specifies the accounting for some costs to obtain or fulfill a contract, as well as enhanced disclosure requirements.  The Partnership is currently identifying existing customer contracts or groups of contracts that are within the scope of the new guidance and that will require an assessment in order to determine any impact on its consolidated financial statements.

Leases

In February 2016, the FASB issued ASU No. 2016-03 “Leases (Topic 842).” The new guidance requires lessees to recognize most leases, including operating leases, on the balance sheet as lease assets and lease liabilities. In addition, lessees will be required to reassess assumptions associated with existing leases as well as to provide expanded qualitative and quantitative disclosures. The new standard does not make extensive changes to lessor accounting. The new guidance is effective January 1, 2019 and will be applied using a modified retrospective approach. The Partnership is currently identifying existing lease agreements that are within the scope of the new guidance that may have an impact on its consolidated financial statements.

Equity method and joint ventures

In March 2016, the FASB issued ASU No. 2016-07 “Investments — Equity Method and Joint Ventures (Topic 323)” that simplifies the transition to equity method accounting. The new guidance eliminates the requirement to retroactively apply the equity method of accounting when an increase in ownership interest in an investment qualifies for equity method accounting. This new guidance is effective January 1, 2017 and will be applied prospectively. The Partnership does not expect the adoption of this new standard to have a material impact on its consolidated financial statements.

NOTE 4EQUITY INVESTMENTS

Northern Border, Great Lakes and Portland Natural Gas Transmission System (PNGTS) are regulated by FERC and are operated by subsidiaries of TransCanada. 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 3, Accounting Pronouncements and Note 17, Variable Interest Entities.

	Ownership		Equity Earnings from Unconsolidated Affiliates				Investments in Unconsolidated Affiliates
	Interest at		Three months		Six Months
(unaudited)	June 30,		ended June 30,		ended June 30,		June 30,	December 31,
(millions of dollars)	2016		2016	2015	2016	2015	2016	2015
Northern Border (a)	50	%	16	15	34	34	455	480
Great Lakes	46.45	%	4	—	19	12	472	485
PNGTS (b)	49.90	%	2	—	11	—	120	—
			22	15	64	46	1,047	965

(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 additional 20 percent interest acquisition in April 2006.

(b)On January 1, 2016, the Partnership acquired a 49.9 percent interest in PNGTS (Refer to Note 6). For the three and six months ended June 30, 2016, the Partnership recorded no undistributed earnings from PNGTS.

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Northern Border

The Partnership did not have undistributed earnings from Northern Border for the three and six months ended June 30, 2016 and 2015.

The summarized financial information for Northern Border is as follows:

(unaudited)
(millions of dollars)	June 30, 2016		December 31, 2015
ASSETS
Cash and cash equivalents	16		27
Other current assets	34		33
Plant, property and equipment, net	1,108		1,124
Other assets (a)	15		16
	1,173		1,200
LIABILITIES AND PARTNERS’ EQUITY
Current liabilities	40		39
Deferred credits and other	27		26
Long-term debt, including current maturities, net (a)	429		409
Partners’ equity
Partners’ capital	679		728
Accumulated other comprehensive loss	(2	)	(2	)
	1,173		1,200

(a)As a result of the application of ASU No. 2015-03 and similar to the presentation of debt discounts, debt issuance costs of $2 million at December 31, 2015 previously reported as other assets in the balance sheet were reclassified as an offset against their respective debt liabilities.

	Three months ended				Six months ended
(unaudited)	June 30,				June 30,
(millions of dollars)	2016		2015		2016		2015
Transmission revenues	70		69		144		144
Operating expenses	(18	)	(18	)	(35	)	(34	)
Depreciation	(15	)	(14	)	(29	)	(29	)
Financial charges and other	(6	)	(6	)	(11	)	(11	)
Net income	31		31		69		70

Great Lakes

The Partnership made an equity contribution to Great Lakes of $4 million in the first quarter of 2016. 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, 2016 and 2015.

13

The summarized financial information for Great Lakes is as follows:

(unaudited)
(millions of dollars)	June 30, 2016	December 31, 2015
ASSETS
Current assets	53	86
Plant, property and equipment, net	721	727
	774	813
LIABILITIES AND PARTNERS’ EQUITY
Current liabilities	29	31
Long-term debt, including current maturities, net (a)	288	297
Partners’ equity	457	485
	774	813

(a)The application of ASU No. 2015-03 did not have a material effect on Great Lakes’ financial statements.

	Three months ended				Six months ended
(unaudited)	June 30,				June 30,
(millions of dollars)	2016		2015		2016		2015
Transmission revenues	36		28		97		76
Operating expenses	(15	)	(14	)	(30	)	(25	)
Depreciation	(7	)	(7	)	(14	)	(14	)
Financial charges and other	(5	)	(6	)	(11	)	(12	)
Net income	9		1		42		25

NOTE 5DEBT AND CREDIT FACILITIES

(unaudited) (millions of dollars)	June 30, 2016	December 31, 2015	Weighted Average Interest Rate for the Six Months Ended June 30, 2016
TC PipeLines, LP Senior Credit Facility due 2017	250	200	1.69	%
TC PipeLines, LP 2013 Term Loan Facility due 2018	500	500	1.69	%
TC PipeLines, LP 2015 Term Loan Facility due 2018	170	170	1.58	%
TC PipeLines, LP 4.65% Unsecured Senior Notes due 2021	350	350	4.65	%(b)
TC PipeLines, LP 4.375% Unsecured Senior Notes due 2025	350	350	4.375	%(b)
GTN 5.29% Unsecured Senior Notes due 2020	100	100	5.29	%(b)
GTN 5.69% Unsecured Senior Notes due 2035	150	150	5.69	%(b)
GTN Unsecured Term Loan Facility due 2019	65	75	1.38	%
Tuscarora Unsecured Term Loan due 2019	10	—	1.57	%
Tuscarora 3.82% Series D Senior Notes due 2017	16	16	3.82	%(b)
	1,961	1,911
Less: unamortized debt issuance costs and debt discount (a)	8	8
Less: current portion	15	14
	1,938	1,889

(a)As a result of the application of ASU No. 2015-03 and similar to the presentation of debt discounts, debt issuance costs of $7 million at December 31, 2015 previously reported as other assets in the balance sheet were reclassified as an offset against debt. Refer to Note 3, Accounting Pronouncements.

(b)Fixed interest rate

The Partnership’s Senior Credit Facility consists of a $500 million senior revolving credit facility with a banking syndicate, maturing November 20, 2017, under which $250 million was outstanding at June 30, 2016 (December 31, 2015 - $200 million), leaving $250 million available for future borrowing.

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After hedging activity, the interest rate incurred on the 2013 Term Loan Facility averaged 2.31 percent and 2.25 percent for the three and six months ended June 30, 2016, respectively (2015 — 1.84 percent). Prior to hedging activities, the LIBOR-based interest rate was 1.71 percent at June 30, 2016 (December 31, 2015 — 1.50 percent).

The 2013 Term Loan Facility and the 2015 Term Loan Facility (Term Loan Facilities) and the Senior Credit Facility require the Partnership to maintain a certain leverage ratio (debt to adjusted cash flow [net income plus cash distributions received, extraordinary losses, interest expense, expense for taxes paid or accrued, and depreciation and amortization expense less equity earnings and extraordinary gains]) no greater than:

·5.50 to 1.00 for the quarters ending June 30, 2016 to September 30, 2016;

·5.00 to 1.00 for the quarter ending December 31, 2016 and each subsequent 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 4.37 to 1.00 as of June 30, 2016.

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, 2016 was 43.7 percent.

On  April  29,  2016,  Tuscarora  entered  into  a $9.5  million  unsecured  variable  rate  term  loan  facility which requires  yearly principal  payments  until  its  maturity  on  April  29,  2019.  The variable interest is based on LIBOR plus an applicable margin and was 1.59 percent at June 30, 2016.

Tuscarora’s Series D Senior Notes, which require yearly principal payments until maturity, are secured by Tuscarora’s transportation contracts, supporting agreements and substantially all of Tuscarora’s property. The note purchase agreements contain certain provisions that include, among other items, limitations on additional indebtedness and distributions to partners. The Series D Senior Notes contain a covenant that limits total debt to no greater than 45 percent of Tuscarora’s total capitalization.  Tuscarora’s total debt to total capitalization ratio at June 30, 2016 was 24 percent. Additionally, the Series D Senior Notes require 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 3.00 to 1.00. The ratio was 4.57 to 1.00 as of June 30, 2016.

At June 30, 2016, the Partnership was in compliance with its financial covenants, in addition to the other covenants which include restrictions on entering into mergers, consolidations and sales of assets, granting liens, material amendments to the Third Amended and Restated Agreement of Limited Partnership (Partnership Agreement), incurring additional debt and distributions to unitholders.

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

(unaudited)
(millions of dollars)
2016	4
2017	273
2018	691
2019	43
2020	100
Thereafter	850
	1,961

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NOTE 6ACQUISITION

PNGTS Acquisition

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

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

The acquisition was accounted for as a transaction between entities under common control, whereby the equity investment in PNGTS was recorded at TransCanada’s carrying value.

The net purchase price was allocated as follows:

(unaudited) (millions of dollars)
Net Purchase Price (a)	193
Less: TransCanada’s carrying value of PNGTS’ net assets at January 1, 2016	120
Excess purchase price (b)	73

(a)Total purchase price of $228 million less the assumption of $35 million of proportional PNGTS debt by the Partnership.

(b)The excess purchase price of $73 million was recorded as a reduction in Partners’ Equity.

NOTE 7PARTNERS’ EQUITY

ATM equity issuance program

In the six months ended June 30, 2016, we issued 1,619,631 common units under our ATM program generating net proceeds of approximately $81 million, plus $2 million from the General Partner to maintain its effective two percent interest. The commissions to our sales agents for the six months ended June 30, 2016 were approximately $823,000. The net proceeds were used for general partnership purposes.

On July 29, 2016, we filed a new shelf registration with the Securities Exchange Commission (SEC) to register an additional $400 million of common units. On August 2, 2016, we requested accelerated effectiveness of the amended shelf registration statement.

Common unit issuance subject to rescission

On July 17, 2014, the SEC declared effective a registration statement (the Registration Statement) that we had filed to cover sales of Common Units under our ATM program. On February 26, 2016, at the time of the filing of the 2015 Form 10-K, we believed that the Partnership continued to be eligible to use the effective Registration Statement to sell Common Units under our ATM program.  However, we have been advised by the SEC on June 23, 2016 that as a result of the untimely filing of an employee-related Form 8-K on October 28, 2015, which was not filed via  EDGAR until 6:02 p.m. Eastern Time (32 minutes after the 5:30 p.m. Eastern Time cutoff), the Partnership was ineligible to use the Registration Statement after the filing of the 2015 Form 10-K.

Because the Partnership  was ineligible to continue using the Registration Statement following the filing of the 2015 Form 10-K, it is possible that the sales of an aggregate 1,619,631 Common Units under the Registration Statement (the ATM Common Units), which were sold between March 8, 2016 and May 19, 2016 at per Common Unit prices ranging from $47.00 to $54.95, may be deemed to have been unregistered sales of securities.  If it is determined that persons who purchased the ATM Common Units from the Partnership after February 26, 2016, purchased such

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Common Units in an offering deemed to be unregistered, then to the extent there may have been a violation of federal securities laws such persons may be entitled to rescission rights, pursuant to which they could be entitled to recover the amount paid for such ATM Common Units, plus interest (based on the statutory rate under applicable state law), less the amount of any distributions.  If such investor has sold any of the ATM Common Units purchased by the investor, then the investor would be entitled to recover the difference between the amount paid for such ATM Common Units and the amount at which such ATM Common Units were sold, assuming the investor’s ATM Common Units were sold at a loss, plus interest and less the amount of any distributions. If all of the investors who purchased the ATM Common Units from the Partnership after February 26, 2016 continue to own all of the ATM Common Units and were to demand rescission of their purchases, and such investors were in fact found to be entitled to such rescission, then we would be obligated to repay approximately $82,334,015, plus interest, less the amount of any distributions.  The Securities Act generally requires that any claim brought for a violation of Section 5 of the Securities Act be brought within one year of the violation.

As a result, at June 30, 2016, the Partnership classified all the 1.6 million common units issued under its ATM program after February 26, 2016 up to and including June 30, 2016, which may be subject to rescission rights, outside of equity given the potential redemption feature which is not within the control of the Partnership. These units are treated as outstanding for financial reporting purposes.

The total amount transferred  outside of equity was approximately $83 million which includes interest and less distributions paid and includes our General Partner’s share to maintain its effective two percent interest.

Class B units issued to TransCanada

The Class B Units we issued on April 1, 2015 to finance a portion of the 2015 GTN Acquisition represent a limited partner interest in us and entitle TransCanada to an annual distribution based on 30 percent of GTN’s annual distributions as follows: (i) 100 percent of distributions above $20 million through March 31, 2020; and (ii) 25 percent of distributions above $20 million thereafter.

For the year ending December 31, 2016, the Class B units’ equity account will be increased by the excess of 30 percent of GTN’s distributions over the annual threshold of $20 million until such amount is declared for distribution and paid in the first quarter of 2017. During the six months ended June 30, 2016, 30 percent of GTN’s total distributable cash flow was $21 million. As a result of exceeding the $20 million threshold, the Class B units’ equity account was increased by $1 million (Refer to Note 8).

For the year ended December 31, 2015, the Class B distribution was $12 million and was declared and paid in the first quarter of 2016.

NOTE 8NET INCOME PER COMMON UNIT

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

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

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

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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)	2016			2015			2016			2015
Net income attributable to controlling interests	54			44			127			101
Net income attributable to the General Partner	(1		)	(1		)	(2		)	(2		)
Incentive distributions allocated to the General Partner (a)	(2		)	(1		)	(3		)	(1		)
Net income attributable to the Class B units (b)	(1		)	—			(1		)	—
Net income allocated to common units	50			42			121			98
Weighted average common units outstanding (millions) — basic and diluted	65.5		(c)	63.8			64.9		(c)	63.7
Net income per common unit — basic and diluted	$	0.76		$	0.66		$	1.86		$	1.53

(a)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.

(b)As discussed in Note 7, the Class B units entitle TransCanada to a distribution which is an amount based on 30 percent of GTN’s distributions after achieving certain annual thresholds. The distribution will be payable in the first quarter with respect to the prior year’s distributions. Consistent with the application of Accounting Standards Codification (ASC) Topic 260 — “Earnings per share”, the Partnership allocated a portion of net income attributable to controlling interest to the Class B units upon 30 percent of GTN’s total distributable cash flows exceeding $20 million for the year ending December 31, 2016.  During the six months ended June 30, 2016, 30 percent of GTN’s total distributable cash flow was $21 million.  As a result of exceeding the $20 million threshold, $1 million of net income attributable to controlling interests was allocated to the Class B units (Refer to Note 7). During the same period in 2015, no allocation was made to the Class B units as the threshold level of $15 million for the nine month period ending December 31, 2015 had not been exceeded.

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

NOTE 9CASH DISTRIBUTIONS

In the three and six months ended June 30, 2016, the Partnership distributed $0.89 and $1.78 per common unit, respectively (2015 — $0.84 and $1.68 per common unit) for a total of $60 million and $119 million, respectively (2015 - $55 million and $110 million). The distributions paid in the three and six months ended June 30, 2016 included an IDR payment to the General Partner of approximately $1 million and $2 million, respectively (2015 - $0.3 million and $0.6 million). 

NOTE 10CHANGE IN OPERATING WORKING CAPITAL

(unaudited)	Six months ended June 30,
(millions of dollars)	2016	2015
Change in accounts receivable and other	—	4
Change in accounts payable and accrued liabilities (a)	2	(2	)
Change in accounts payable to affiliates	—	(5	)
Change in accrued interest	1	4
Change in operating working capital	3	1

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

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NOTE 11RELATED PARTY TRANSACTIONS

The Partnership does not have any employees. The management and operating functions are provided by the General Partner. The General Partner does not receive a management fee in connection with its management of the Partnership. The Partnership reimburses the General Partner for all costs of services provided, including the costs of employee, officer and director compensation and benefits, and all other expenses necessary or appropriate to the conduct of the business of, and allocable to, the Partnership. Such costs include (i) overhead costs (such as office space and equipment) and (ii) out-of-pocket expenses related to the provision of such services. The Partnership Agreement provides that the General Partner will determine the costs that are allocable to the Partnership in any reasonable manner determined by the General Partner in its sole discretion. Total costs charged to the Partnership by the General Partner were $1 million and $2 million for the three and six months ended June 30, 2016, respectively.   Total costs charged to the Partnership by the General Partner were $1 million for both the three and six months ended June 30, 2015.

As operator of our pipelines, 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.

Capital and operating costs charged to our pipeline systems for the three and six months ended June 30, 2016 and 2015 by TransCanada’s subsidiaries and amounts payable to TransCanada’s subsidiaries at June 30, 2016 and December 31, 2015 are summarized in the following tables:

	Three months ended		Six months ended
(unaudited)	June 30,		June 30,
(millions of dollars)	2016	2015	2016	2015
Capital and operating costs charged by TransCanada’s subsidiaries to:
Great Lakes (a)	7	8	14	14
Northern Border (a)	9	9	15	16
PNGTS (a), (c)	2	—	4	—
GTN (a), (b)	7	8	13	14
Bison (d)	1	1	—	2
North Baja	1	2	2	3
Tuscarora	1	1	2	2
Impact on the Partnership’s net income:
Great Lakes	3	3	6	6
Northern Border	3	4	6	7
PNGTS (c)	1	—	2	—
GTN (b)	6	7	11	11
Bison	1	1	2	2
North Baja	1	1	2	2
Tuscarora	1	1	2	2

(unaudited)
(millions of dollars)	June 30, 2016	December 31, 2015
Net amounts payable to TransCanada’s subsidiaries is as follows:
Great Lakes (a)	3	3
Northern Border (a)	3	5
PNGTS (a)	1	—
GTN	3	3
Bison	1	—
North Baja	—	—
Tuscarora	1	1

(a)Represents 100 percent of the costs.

(b)In April 2015, the Partnership acquired the remaining 30 percent interest in GTN.

(c)In January 2016, the Partnership acquired 49.9 percent interest in PNGTS.

(d)Net of proceeds of $1 million from the sale of excess pipe (at cost) to an affiliate.

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Great Lakes earns transportation revenues from TransCanada and its affiliates, some of which are provided at discounted rates and some of which are at maximum recourse rates. Great Lakes earned $23 million and $69 million of transportation revenues under these contracts for the three and six months ended June 30, 2016, respectively (2015 - $18 million and $47 million). These amounts represent 64 percent and 71 percent of total revenues earned by Great Lakes for the three and six months ended June 30, 2016, respectively (2015 — 63 percent and 62 percent). Great Lakes also earned $1 million of affiliated rental revenue for the three and six months ended June 30, 2016 (2015 — $1 million).

Accordingly, revenue from TransCanada and its affiliates of $10 million and $32 million are included in the Partnership’s equity earnings from Great Lakes for the three and six months ended June 30, 2016, respectively (2015 - $8 million and $22 million). At June 30, 2016, $9 million was included in Great Lakes’ receivables in regards to the transportation contracts with TransCanada and its affiliates (December 31, 2015 - $17 million).

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

On June 16, 2016, PNGTS declared its second quarter 2016 distribution of $8 million, of which the Partnership received its 49.9 percent share or $4 million on July 18, 2016.

NOTE 12FAIR VALUE MEASUREMENTS

(a) Fair Value Hierarchy

Under ASC 820, Fair Value Measurements and Disclosures, fair value measurements are characterized in one of three levels based upon the 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.

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Long-term debt is recorded at amortized cost and classified in Level 2 of the fair value hierarchy for fair value disclosure purposes. Interest rate derivative assets and liabilities are classified in Level 2 for all periods presented where the fair value is determined by using valuation techniques that refer to observable market data or estimated market prices.  The estimated fair value of the Partnership’s debt as at June 30, 2016 and December 31, 2015 was $1,994 million and $1,873 million, respectively.

The ATM Common units which may be subject to rescission rights, as discussed more fully in Note 7, were measured using the original issuance price, plus statutory interest and less any distributions paid. This fair value measurement is classified as Level 2.

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

The interest rate swaps are structured such that the cash flows of the derivative instruments match those of the variable rate of interest on the 2013 Term Loan Facility. The Partnership hedged interest payments on the variable-rate 2013 Term Loan Facility with interest rate swaps maturing July 1, 2018, at a weighted average fixed interest rate of 2.31 percent. At June 30, 2016, the fair value of the interest rate swaps accounted for as cash flow hedges was a liability of $5 million (both on a gross and net basis) (December 31, 2015 - $1 million). The Partnership did not record any amounts in net income related to ineffectiveness for interest rate hedges for the three and six months ended June 30, 2016 and 2015. The change in fair value of interest rate derivative instruments recognized in other comprehensive income was a loss of $1 million and a loss of $3 million for the three and six months ended June 30, 2016, respectively (2015 — nil and a loss of $1 million). For the three and six months ended June 30, 2016, the net realized loss related to the interest rate swaps was $1 million, and was included in financial charges and other (2015 — nil and $1 million).  Refer to Note 14 — Financial Charges and Other.

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, 2016 and December 31, 2015.

(c) Other

As discussed more fully in Note 16, we performed a discounted cash flow analysis to assess, for possible impairment, the $82 million of goodwill related to our acquisition of Tuscarora. The estimated fair value measurement is classified as Level 3. In the determination of the fair value, we used internal forecasts for expected future cash flows and applied appropriate discount rates. The determination of expected future cash flows involved significant assumptions and estimates regarding revenue, operating and maintenance costs and future growth capital.

NOTE 13ACCOUNTS RECEIVABLE AND OTHER

(unaudited)
(millions of dollars)	June 30, 2016	December 31, 2015
Trade accounts receivable, net of allowance of nil	30	31
Other	5	4
	35	35

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NOTE 14FINANCIAL CHARGES AND OTHER

	Three months ended			Six months ended
(unaudited)	June 30,			June 30,
(millions of dollars)	2016		2015	2016		2015
Interest Expense (a)	16		16	33		29
Net realized loss related to the interest rate swaps	1		—	1		1
Other Income	(1	)	—	(1	)	(1	)
	16		16	33		29

(a)Effective January 1, 2016, interest expense includes debt issuance costs and amortization of discount costs. Refer to Note 3, - Accounting Pronouncements.

NOTE 15CONTINGENCIES

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 and certain Essar affiliates (collectively, Essar) for breach of its monthly payment obligation under its transportation services agreement with Great Lakes. Great Lakes sought to recover approximately $33 million for past and future payments due under the agreement. On September 16, 2015, following a jury trial, the federal district court judge entered a judgment in the amount of $32.9 million in favor of Great Lakes.  On September 20, 2015, Essar appealed the decision to the United States Court of Appeals for the 8th Circuit (8th Circuit) based on an allegation of improper jurisdiction and a number of other rulings by the federal district judge. Essar was required to post a performance bond for the full value of the judgment pending appeal. Both parties have filed their briefs. In July 2016, Essar filed for Bankruptcy and asked the 8th Circuit Court of Appeals to stay the appeal pending the bankruptcy proceeding. Great Lakes will file a request with the 8th Circuit Court of Appeals to deny the stay.  Because Great Lakes has a performance bond for the full amount of the judgment, the bankruptcy proceeding is not expected to impact the ability of Great Lakes to receive payment of a final award.

Employees Retirement System of the City of St. Louis v. TC PipeLines GP, Inc., et al. — On October 13, 2015, an alleged unitholder of the Partnership filed a class action and derivative complaint in the Delaware Court of Chancery (Chancery Court) against the General Partner, TransCanada American Investments, Ltd. (TAIL) and TransCanada, and the Partnership as a nominal defendant.   The complaint alleges direct and derivative claims for breach of contract, breach of the duty of good faith and fair dealing, aiding and abetting breach of contract, and tortious interference in connection with the 2015 GTN Acquisition, including the issuance by the Partnership of $95 million in Class B Units and amendments to the Partnership Agreement to provide for the issuance of the Class B Units.   Plaintiff seeks, among other things, to enjoin future issuances of Class B Units to TransCanada or any of its subsidiaries, disgorgement of certain distributions to the General Partner, TransCanada and any related entities, return of some or all of the Class B Units to the Partnership, rescission of the amendments to the Partnership Agreement, monetary damages and attorney fees.   To the extent the claims are derivative, the Partnership would be the beneficiary of any monetary award.  The Partnership does not expect legal fees or the impact of the decision on plaintiffs’ other requests to be material.  In April 2016, the Chancery Court granted the Partnership and other defendants’ motion to dismiss the plaintiffs’ complaint.  The plaintiff has appealed the decision to dismiss its claims.  The appeal is expected to be heard in late-2016.

NOTE 16GOODWILL AND REGULATORY

On January 21, 2016, the FERC issued an Order (the January 21 Order) initiating an investigation pursuant to Section 5 of the Natural Gas Act of 1938 (NGA) to determine whether Tuscarora’s existing rates for jurisdictional services are just and reasonable. On July 15, 2016, Tuscarora filed a petition with FERC requesting approval of the Stipulation and Agreement of Settlement (Tuscarora Settlement) that, if approved, will resolve the Section 5 rate review initiated by FERC in January 2016. Under the terms of the Tuscarora Settlement, Tuscarora’s system-wide unit rate will initially decrease by 16 percent, with an anticipated effective date of August 1, 2016. Unless superseded by a subsequent rate case or settlement, this rate will remain in effect for three years, after which time the unit rate will decrease an additional seven percent for an additional three years. The settlement does not contain

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a rate moratorium and requires Tuscarora to file to establish new rates no later than six years following the effective date of the initial settlement rates.

We believe there is a high probability that the Tuscarora settlement will be approved as filed, and as a result, the expected reduction in Tuscarora’s future cash flows constituted a triggering event that led us to evaluate, for possible impairment, the $82 million of goodwill related to our acquisition of Tuscarora.

Our analysis resulted in the estimated fair value of Tuscarora exceeding its carrying value but the excess was less than 10 percent. The fair value was measured using a discounted cash flow analysis and included revenue expected from Tuscarora’s current contracting level together with other opportunities on the system. There is a risk that reductions in future cash flow forecasts as a result of Tuscarora not being able to maintain its current contracting level and/or not being able to realize other opportunities on the system, together with adverse changes in other key assumptions such as projected operating costs and other future growth capital, could result in a future impairment of the goodwill balance relating to Tuscarora.

NOTE 17  VARIABLE INTEREST ENTITIES

In the normal course of business, the Partnership must re-evaluate its legal entities under the newly effective 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 and PNGTS 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, 2016		December 31, 2015
ASSETS (LIABILITIES) *
Accounts receivable and other	21		25
Inventories	6		6
Equity investments	1,047		965
Plant, property and equipment	859		872
Other assets	2		2
Accounts payable and accrued liabilities	(18	)	(26	)
Accounts payable to affiliates, net	(18	)	(6	)
Accrued interest	(1	)	(1	)
Current portion of long-term debt	(15	)	(14	)
Long-term debt	(325	)	(326	)
Other liabilities	(25	)	(24	)

*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.

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NOTE 18SUBSEQUENT EVENTS

Management of the Partnership has reviewed subsequent events through August 4, 2016, 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 21, 2016, the board of directors of our General Partner declared the Partnership’s second quarter 2016 cash distribution in the amount of $0.94 per common unit payable on August 12, 2016 to unitholders of record as of August 1, 2016. The declared distribution reflects a $0.05 per common unit increase to the Partnership’s first quarter 2016 quarterly distribution and will include an IDR payment to our General Partner amounting to approximately $2 million.

Northern Border declared its June 2016 distribution of $13 million on July 11, 2016, of which the Partnership will receive its 50 percent share or $6.5 million on July 29, 2016.

Great Lakes declared its second quarter 2016 distribution of $12 million on July 19, 2016, of which the Partnership will receive its 46.45 percent share or $6 million on August 1, 2016.

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Item 2.   Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis should be read in conjunction with the unaudited financial statements and notes included in Item 1. “Financial Statements” of this Quarterly Report on Form 10-Q, as well as our Annual Report on Form 10-K for the year ended December 31, 2015.

RECENT BUSINESS DEVELOPMENTS

Cash Distributions —

On April 21, 2016, the board of directors of our General Partner declared the Partnership’s first quarter 2016 cash distribution in the amount of $0.89 per common unit, and was paid on May 13, 2016 to unitholders of record as of May 2, 2016. The first quarter 2016 cash distribution included an IDR payment to our General Partner amounting to approximately $1 million.

On July 21, 2016, the board of directors of our General Partner declared the Partnership’s second quarter 2016 cash distribution in the amount of $0.94 per common unit payable on August 12, 2016 to unitholders of record as of August 1, 2016. The declared distribution reflects a $0.05 per common unit increase to the first quarter 2016 quarterly distribution and will include an IDR payment to our General Partner amounting to approximately $2 million.

PNGTS - On January 1, 2016, the Partnership acquired a 49.9 percent interest in PNGTS from a subsidiary of TransCanada. The total purchase price of the PNGTS Acquisition was $228 million and consisted of $193 million in cash (including the final purchase price adjustment of $5 million) and the assumption of $35 million in proportional PNGTS debt. This transaction adds a new market geography for us, further diversifying our cash flow stream and extending our breadth of operations.

Tuscarora rate case - On January 21, 2016, the FERC issued an Order (the January 21 Order) initiating an investigation pursuant to Section 5 of the NGA to determine whether Tuscarora’s existing rates for jurisdictional services are just and reasonable. On July 15, 2016, Tuscarora filed a petition with FERC requesting approval of the Tuscarora Settlement that, if approved, will resolve the Section 5 rate review initiated by FERC in January 2016. Under the terms of the Tuscarora Settlement, Tuscarora’s system-wide unit rate will initially decrease by 16 percent, with an anticipated effective date of August 1, 2016. Unless superseded by a subsequent rate case or settlement, this rate will remain in effect for three years, after which time the unit rate will decrease an additional seven percent per year for an additional three years. The settlement does not contain a rate moratorium and requires Tuscarora to file to establish new rates no later than six years following the effective date of the initial settlement rates. While this new rate structure will reduce Tuscarora’s future cash flows, the achievement of rate certainty helps ensure predictable cash flows and enhances Tuscarora’s long term value.

ATM program — On July 29, 2016, we filed a new shelf registration statement with the SEC to register an additional $400 million of common units under our ATM Program. On August 2, 2016, we requested accelerated effectiveness of the amended shelf registration statement.

Outlook of Our Business

TransCanada, the ultimate parent company of our General Partner, is currently executing a large capital program that includes approximately $25 billion Canadian of near-term growth opportunities that are expected to be complete by 2018. Over the medium to longer-term, TransCanada is also advancing over $45 billion Canadian of commercially secured large-scale projects, and various other initiatives backed by long-term contracts or cost-of-service business models.

The Partnership has been advised that TransCanada has retained a financial advisor to assist in developing its MLP strategy.  A decision on the MLP strategy is expected to be communicated later in 2016.  TransCanada does not anticipate any dropdowns to the Partnership until the review has been completed.

The Partnership’s financial performance continues to benefit from its recent acquisitions, including the acquisition of an interest in PNGTS from TransCanada. Despite uncertainty in energy commodity prices, our portfolio of seven FERC-regulated interstate natural gas pipelines is expected to deliver generally stable results in 2016 due to ship-or-pay contracts with creditworthy customers.

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RESULTS OF OPERATIONS

Our equity interests in Northern Border, Great Lakes, and effective January 1, 2016, PNGTS, and ownership of GTN, Bison, North Baja and Tuscarora were our only material sources of income during the period. Therefore, our results of operations and cash flows were influenced by, and reflect the same factors that influenced, our pipeline systems.

	Three months ended								Six months ended
(unaudited)	June 30,				$		%		June 30,				$		%
(millions of dollars)	2016		2015		Change*		Change*		2016		2015		Change*		Change*
Transmission revenues	89		85		4		5	%	175		172		3		2	%
Equity earnings from unconsolidated affiliates	22		15		7		47	%	64		46		18		39	%
Operating, maintenance and administrative	(19	)	(19	)	—		—		(36	)	(39	)	3		8	%
Depreciation	(22	)	(21	)	(1	)	(5	)%	(43	)	(42	)	(1	)	(2	)%
Financial charges and other	(16	)	(16	)	—		—		(33	)	(29	)	(4	)	(14	)%
Net income	54		44		10		23	%	127		108		19		18	%
Net income attributable to non-controlling interests	—		—		—		—		—		7		7		100	%
Net income attributable to controlling interests	54		44		10		23	%	127		101		26		26	%

* Positive number represents a favorable change; bracketed or negative number represents an unfavorable change

Three Months Ended June 30, 2016 compared to Same Period in 2015

The Partnership’s net income attributable to controlling interests was higher by $10 million or 23 percent due to higher revenues from our wholly owned subsidiaries together with higher equity earnings from unconsolidated affiliates partially offset by increase in costs:

Transmission revenues - the $4 million increase was primarily due to the net effect of:

·higher discretionary revenues on GTN from short-term services sold to its customers;

·new revenues from GTN’s Carty lateral system which was placed in service in October 2015; and

·lower transportation rates on GTN as a result of the settlement reached with its customers effective July 1, 2015.

Earnings from equity investments - the $7 million increase was mainly attributable to:

·higher equity earnings from Great Lakes mainly due to higher transportation revenues resulting from higher levels of contracted volumes; and

·the acquisition of a 49.9 percent interest in PNGTS effective January 1, 2016.

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Six Months Ended June 30, 2016 compared to Same Period in 2015

The Partnership’s net income attributable to controlling interests was higher by $26 million or 26 percent mainly due to the following:

Transmission revenues - the $3 million increase was primarily due to the net effect of:

·higher discretionary revenues on GTN from short-term services sold to its customers;

·new revenues from GTN’s Carty lateral system which was placed in service in October 2015; and

·lower transportation rates on GTN as a result the settlement reached with its customers effective July 1, 2015.

Earnings from Equity Investments. The $18 million increase was mainly attributable to:

·higher equity earnings from Great Lakes mainly due to higher transportation revenues during the period as a result of a timing difference on the recognition of $14.1 million in deferred revenues from ANR contracts during the previous period (refer to Note 11 within Item 1. “Financial Statement” for further information) and higher levels of contracted volumes; and

·the acquisition of a 49.9 percent interest in PNGTS effective January 1, 2016.

Operating, maintenance and administrative.  The $3 million decrease was primarily due to lower operating and maintenance costs on our wholly owned subsidiaries as a result of a business restructuring initiative by TransCanada, our General Partner, and operator of our pipeline systems.

Financial charges and other. The $4 million increase was mainly attributable to additional borrowings to fund a portion of recent acquisitions.

Net income attributable to non-controlling interests. The $7 million change was due to the 2015 GTN acquisition effective April 1, 2015, whereby the Partnership now owns 100 percent of GTN.

Net Income Attributable to Common Units and Net Income per Common Unit

As discussed in Note 8 Net Income per Common Unit within Item 1. “Financial Statements,” we allocated $1million of the Partnership’s net income attributable to common units to the Class B units in the second quarter of 2016, representing the excess of 30 percent of GTN’s distribution over the 2016 threshold level of $20 million. This allocation reduced net income per common unit by approximately two cents for both the three and six months ended June 30, 2016.

Additionally, as the threshold level for 2016 has now been exceeded as described above, we expect to allocate 30 percent of GTN’s third and fourth quarter distributable cash flows to the Class B units.

During the same period in 2015, no allocation was made to the Class B units as the threshold level of $15 million for the nine month period ending December 31, 2015 had not been exceeded.

Please read also Note 7 within Item 1. “Financial Statements” for additional disclosures on the Class B units.

LIQUIDITY AND CAPITAL RESOURCES

Overview

Our principal sources of liquidity and cash flows include distributions received from our investments in partially owned affiliates, operating cash flows from our subsidiaries, public offerings of debt and equity, term loans and our bank credit facility. The Partnership funds its operating expenses, debt service and cash distributions (including those distributions made to TransCanada through our General Partner and as holder of all our Class B units) primarily with operating cash flow. Long-term capital needs may be met through the issuance of long-term debt and/or equity. Overall, we believe that our pipeline systems’ ability to obtain financing at reasonable rates, together with a history of consistent cash flow from operating activities, provide a solid foundation to meet future liquidity and capital requirements. We expect to be able to fund our liquidity requirements, including our distributions and required debt repayments, at the Partnership level over the next 12 months utilizing our cash flow and, if required, our existing Senior Credit Facility.

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The following table sets forth the available borrowing capacity under the Partnership’s Senior Credit Facility

(unaudited) (millions of dollars)	June 30, 2016	December 31, 2015
Total capacity under the Senior Credit Facility	500	500
Less: Outstanding borrowings under the Senior Credit Facility	250	200
Available capacity under the Senior Credit Facility	250	300

Our pipeline systems’ principal sources of liquidity are cash generated from operating activities, long-term debt offerings, bank credit facilities and equity contributions from their owners. Our pipeline systems have historically funded operating expenses, debt service and cash distributions to their owners primarily with operating cash flow. However, since the fourth quarter of 2010, Great Lakes has funded its debt repayments with cash calls to its owners.

Capital expenditures are funded by a variety of sources, including cash generated from operating activities, borrowings under bank credit facilities, issuance of senior unsecured notes or equity contributions from our pipeline systems’ owners. The ability of our pipeline systems to access the debt capital markets under reasonable terms depends on their financial position and general market conditions.

The Partnership’s pipeline systems monitor the creditworthiness of their customers and have credit provisions included in their tariffs which, although limited by FERC, allow them to request credit support as circumstances dictate.

Cash Flow Analysis for the Six Months Ended June 30, 2016 compared to Same Period in 2015

	Six months ended
(unaudited)	June 30,
(millions of dollars)	2016		2015
Net cash provided by (used in):
Operating activities	170		151
Investing activities	(171	)	(258	)
Financing activities	2		125
Net increase in cash and cash equivalents	1		18
Cash and cash equivalents at beginning of the period	39		26
Cash and cash equivalents at end of the period	40		44

Operating Cash Flows

Net cash provided by operating activities increased by $19 million in the six months ended June 30, 2016 compared to the same period in 2015 primarily due higher earnings as discussed in more detail in the “Results of Operations” section.

Investing Cash Flows

Net cash used in investing activities decreased by $87 million in the six months ended June 30, 2016 compared to the same period in 2015 as we invested a lesser amount for our most recent acquisition of PNGTS compared to our investment during the same period in 2015. In 2015, we paid $264 million to acquire the remaining 30 percent interest in GTN compared to $193 million paid for the acquisition of a 49.9 percent interest in PNGTS in 2016.

Other factors impacting our investing cash flows in the six months ended June 30, 2016 compared to the same period in 2015 were as follows:

·higher net distributions in 2016 from our equity investments; offset by

·higher capital expenditures in 2016 due to the timing of expenditures related to the construction of the Carty Lateral.

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Financing Cash Flows

Net cash provided by financing activities decreased by $123 million in the six months ended June 30, 2016 compared to the same period in 2015 primarily due to the net effect of:

·$169 million decrease in net issuances of debt in 2016 as compared with 2015;

·$57 million increase in our ATM equity issuances in 2016 as compared with 2015;

·$9 million increase in distributions paid to our common units including our General Partner’s effective two percent share and its related IDRs;

·$12 million of distributions paid to Class B units in 2016; and

·$9 million of distributions paid to TransCanada as the non-controlling interest owner of GTN until March 31, 2015.

Other Cash Flow Matters

The Partnership made an equity contribution to Great Lakes of $4 million in the first quarter of 2016. 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 expects to make an additional $5 million equity contribution to Great Lakes in the fourth quarter of 2016 to further fund debt repayments.

Northern Border has $100 million of senior notes due in August 2016 and this amount will be refinanced with a draw on the Northern Border Credit Agreement.

Our equity investee PNGTS has $11 million of scheduled debt repayments in for the remainder of 2016, of which the Partnership’s share is approximately $6 million. While PNGTS debt repayments are not funded with cash calls to its owners, PNGTS has historically funded its scheduled debt repayments by adjusting its available cash for distribution, which effectively reduces the net cash that will be received by the Partnership as distributions from PNGTS.

Additionally, PNGTS is restricted under the terms of their note purchase agreement from making cash distributions to its partners unless certain conditions are met. Before a distribution can be made, the debt service reserve account must be fully funded and the PNGTS debt service coverage ratio for the preceding and succeeding twelve months must be 1.30 or greater.

GTN has commitments of $2 million as of June 30, 2016 in connection with the closeout costs relating to the Carty Lateral project, various capital overhauls and other capital projects.

North Baja has commitments of $1 million as of June 30, 2016 in connection with a pipe replacement project.

2016 Second Quarter Cash Distribution

On July 21, 2016, the board of directors of our General Partner declared the Partnership’s second quarter 2016 cash distribution in the amount of $0.94 per common unit payable on August 12, 2016 to unitholders of record as of August 1, 2016.  Please read Item 2. “Management Discussion and Analysis of Financial Condition and Results of Operations - Recent Business Developments.”

EBITDA and Distributable Cash Flow

We use certain non-GAAP financial measures that do not have any standardized meaning under GAAP because we believe they enhance the understanding of our operating performance.  We use EBITDA and Distributable Cash Flow as non-GAAP measures.

EBITDA is an approximate performance measure of our operating cash flow during the current earnings period and reconciles directly to the most comparable GAAP measure of net income. It measures our earnings before deducting interest, depreciation and amortization, net income attributable to non-controlling interests, and it includes earnings from our equity investments.  We use EBITDA as a proxy of our operating cash flow and current operating profitability.

Total distributable cash flow and distributable cash flow provide performance measures of distributable cash generated during the current earnings period and reconcile directly to the most comparable GAAP measure of net income.

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Total distributable cash flow includes EBITDA plus:

·Distributions from our equity investments

less:

·Earnings from our equity investments,

·Equity allowance for funds used during construction (Equity AFUDC),

·Interest expense,

·Distributions to non-controlling interests, and

·Maintenance capital expenditures.

Distributable cash flow is computed net of distributions declared to the General Partner and distributions allocable to Class B units. Distributions declared to the General Partner are based on its effective two percent interest plus an amount equal to incentive distributions. Distributions allocable to the Class B units in 2016 equal 30 percent of GTN’s distributable cash flow less $20 million (2015 — less $15 million).

Distributable cash flow information and EBITDA are performance measures presented to assist investors in evaluating our business performance. We believe these measures provide additional meaningful information in evaluating our financial performance and cash generating performance.

The non-GAAP measures described above are provided as a supplement to GAAP financial results and are not meant to be considered in isolation or as substitutes for financial information prepared in accordance with GAAP. Additionally, these measures as presented may not be comparable to similarly titled measures of other companies.

The following table represents a reconciliation of our EBITDA, Total distributable cash flow and Distributable cash flow to the most directly comparable GAAP financial measure, Net income, for the periods presented:

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Reconciliations of Net Income to Distributable Cash Flow

	Three months ended				Six months ended
(unaudited)	June 30,				June 30,
(millions of dollars)	2016		2015		2016		2015
Net income	54		44		127		108
Add:
Interest expense (a)	17		16		34		30
Depreciation and amortization	22		21		43		42
EBITDA	93		81		204		180
Add:
Distributions from equity investments(b) (e)
Northern Border	21		21		44		47
Great Lakes	6		3		23		17
PNGTS (c)	4		—		10		—
	31		24		77		64
Less:
Equity earnings:
Northern Border	(16	)	(15	)	(34	)	(34	)
Great Lakes	(4	)	—		(19	)	(12	)
PNGTS (c)	(2	)	—		(11	)	—
	(22	)	(15	)	(64	)	(46	)
Less:
Equity AFUDC	—		(1	)	—		(1	)
Interest expense	(17	)	(16	)	(34	)	(30	)
Distributions to non-controlling interests (d)	—		—		—		(11	)
Maintenance capital expenditures (e)	(5	)	(5	)	(6	)	(6	)
Total Distributable Cash Flow (f)	80		68		177		150
General Partner distributions declared (g)	(3	)	(2	)	(5	)	(3	)
Distributions allocable to Class B units (h)	(1	)	—		(1	)	—
Distributable Cash Flow (f)	76		66		171		147

(a)Interest expense as presented here includes net realized loss related to interest rate swaps. Please read Notes 3 and 14 within Item 1. “Financial Statements” for information

(b)Amounts here are calculated in accordance with the cash distribution policies of these entities. Distributions from each of our equity investments represent our respective share of these entities’ quarterly distributable cash during the current reporting period.

(c)Our equity investee PNGTS has $22 million of senior secured notes payment due in 2016, of which the Partnership’s share is approximately $11 million. While PNGTS debt repayments are not funded with cash calls to its owners, PNGTS has historically funded its scheduled debt repayments and other cash needs such as tax payments, by adjusting its available cash for distribution, which effectively reduces the net cash that we will receive as distributions from PNGTS.  Accordingly, this amount is net of our 49.9 percent share of the total debt repayment of PNGTS amounting to approximately $5.5 million during the quarter, resulting in a net distribution decrease of approximately $3 million.

(d)Distributions to non-controlling interests represent our respective share of quarterly distributable cash during the current reporting period not owned by us.

(e)The Partnership’s maintenance capital expenditures include cash expenditures made to maintain, over the long term, our assets’ operating capacity, system integrity and reliability.  Accordingly, this amount represents the Partnership’s and its consolidated subsidiaries maintenance capital expenditures and does not include the Partnership’s share of maintenance capital expenditures on our equity investments. Such amounts are reflected in “Distributions from equity investments” as those amounts are withheld by those entities from their quarterly distributable cash.

(f)“Total Distributable Cash Flow” and “Distributable Cash Flow” represent the amount of distributable cash generated by the Partnership’s subsidiaries and equity investments during the current earnings period and thus reconcile directly

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to the net income amount presented. The calculation differs from the previous non-GAAP measure “Partnership Cash Flows before General Partner distributions” and “Partnership Cash Flows” as the previously used measures primarily reflected cash received during the period through distributions from our subsidiaries and equity investments that were generated from the prior quarter’s financial results. The amounts reflected here have been adjusted to reflect the calculation as described above and to present the comparable “Total Distributable Cash Flow” and “Distributable Cash Flow” from the previous period.

(g)Distributions declared to the General Partner for the three and six months ended June 30, 2016 included an incentive distribution of approximately $2 million and $3 million, respectively. Distributions declared to the General Partner for the three and six months ended June 30, 2015 included an incentive distribution of approximately $1 million for both periods.

(h)During the six months ended June 30, 2016, 30 percent of GTN’s total distributions were $21 million. As a result of exceeding the $20 million threshold, $1 million was allocated to the Class B units in the second quarter of 2016 representing the amount that exceeded the threshold level of $20 million. As the threshold level for 2016 has now been exceeded, we expect to allocate 30 percent of distributable cash flow of GTN for the third and fourth quarter to the Class B units.

During the same period in 2015, no allocation was made to the Class B units as the threshold level of $15 million for the nine month period ending December 31, 2015 had not been exceeded.

Please read Notes 7 and 8 within Item 1. “Financial Statements” for additional disclosures on the Class B units.

Second Quarter 2016 Compared with Second Quarter 2015

Our EBITDA increased by $12 million compared to the same period in 2015 mainly due to higher transmission revenues and higher earnings from our equity investments as discussed in more detail in the Results of Operations section.

Our Distributable cash flow increased by $10 million in the first quarter of 2016 compared to the same period in 2015 primarily due to the same factors that impacted our EBITDA.

Six Months Ended June 30, 2016 Compared With Six Months Ended June 30, 2015

Our EBITDA increased by $24 million compared to the same period in 2015 mainly due to higher transmission revenues, higher earnings from our equity investments and lower operating costs as discussed in more detail in the Results of Operations section.

Distributable cash flow increased by $24 million in the six months ended June 30, 2016 compared to the same period in 2015 primarily due to the net effect of:

·higher EBITDA;

·no distributions paid to non-controlling interest as a result of the Partnership owning 100 percent of GTN beginning April 1, 2015;

·higher interest expense related to higher borrowings as a result of the recent acquisitions;

·higher General Partner distributions due to higher IDRs in the current period; and

·distributions allocable to the Class B units during the current period.

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Contractual Obligations

The Partnership’s contractual obligations related to debt as of June 30, 2016 included the following:

	Payments Due by Period
(unaudited) (millions of dollars)	Total	Less than 1 Year	1-3 Years	4-5 Years	More than 5 Years	Weighted Average Interest Rate for the Six Months Ended June 30, 2016
TC PipeLines, LP Senior Credit Facility due 2017	250	—	250	—	—	1.69	%
TC PipeLines, LP 2013 Term Loan Facility due 2018	500	—	500	—	—	1.69	%
TC PipeLines, LP 2015 Term Loan Facility due 2018	170	—	170	—	—	1.58	%
TC PipeLines, LP 4.65% Senior Notes due 2021, net	350	—	—	350	—	4.65	%(a)
TC PipeLines, LP 4.375% Senior Notes due 2025, net	350	—	—	—	350	4.375	%(a)
GTN 5.29% Unsecured Senior Notes due 2020	100	—	—	100	—	5.29	%(a)
GTN 5.69% Unsecured Senior Notes due 2035	150	—	—	—	150	5.69	%(a)
GTN Unsecured Term Loan Facility due 2019	65	10	55	—	—	1.38	%
Tuscarora Unsecured Term Loan Facility due 2019	10	1	9	—	—	1.57	%
Tuscarora 3.82% Series D Senior Notes due 2017	16	4	12	—	—	3.82	%(a)
	1,961	15	996	450	500

(a)Fixed interest rate

The Partnership’s long-term debt results in exposures to changing interest rates. The Partnership uses derivatives to assist in managing its exposure to interest rate risk. Refer to Item 3. “Quantitative and Qualitative Disclosures About Market Risk” section for additional information regarding the derivatives.

The fair value of the Partnership’s long-term debt is estimated by discounting the future cash flows of each instrument at estimated current borrowing rates. The estimated fair value of the Partnership’s debt at June 30, 2016 was $1,994 million.

Please read Note 5 within Item 1. “Financial Information” for additional information regarding the Partnership’s debt.

Northern Border’s contractual obligations related to debt as of June 30, 2016 included the following:

	Payments Due by Period
(unaudited) (millions of dollars)	Total	Less than 1 Year	1-3 Years	4-5 Years	More than 5 Years	Weighted Average Interest Rate for the Six Months Ended June 30, 2016
6.24% Senior Notes due 2016 (b)	100	100	—	—	—	6.24	%(a)
7.50% Senior Notes due 2021	250	—	—	—	250	7.50	%(a)
$200 million Credit Agreement due 2020	81	—	—	81	—	1.60	%
	431	100	—	81	250

(a)Fixed interest rate

(b)Expected to be refinanced with a draw on the existing $200 million Credit Agreement

As of June 30, 2016, $81 million was outstanding under Northern Border’s $200 million revolving credit agreement, leaving $119 million available for future borrowings. At June 30, 2016, Northern Border was in compliance with all of its financial covenants.

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Northern Border has commitments of $6 million as of June 30, 2016 in connection with various capital overhaul and other capital projects.

Great Lakes’ contractual obligations related to debt as of June 30, 2016 included the following:

	Payments Due by Period
(unaudited) (millions of dollars)	Total	Less than 1 Year	1-3 Years	4-5 Years	More than 5 Years	Weighted Average Interest Rate for the Six Months Ended June 30, 2016
6.73% series Senior Notes due 2017 to 2018	18	9	9	—	—	6.73	%(a)
9.09% series Senior Notes due 2016 and 2021	60	10	20	20	10	9.09	%(a)
6.95% series Senior Notes due 2019 and 2028	110	—	11	22	77	6.95	%(a)
8.08% series Senior Notes due 2021 and 2030	100	—	—	10	90	8.08	%(a)
	288	19	40	52	177

(a)Fixed rate

Great Lakes is required to comply with certain financial, operational and legal covenants. Under the most restrictive covenants in the senior note agreements, approximately $155 million of Great Lakes’ partners’ capital was restricted as to distributions as of June 30, 2016 (December 31, 2015 — $160 million). Great Lakes was in compliance with all of its financial covenants at June 30, 2016.

Great Lakes has commitments of $4 million as of June 30, 2016 primarily in connection with capital overhaul projects and pipeline integrity.

PNGTS’ contractual obligations related to debt as of June 30, 2016 included the following:

	Payments Due by Period
(unaudited) (millions of dollars)	Total	Less than 1 Year	1-3 Years	4-5 Years	More than 5 Years	Weighted Average Interest Rate for the Six Months Ended June 30, 2016
5.90% Senior Secured Notes due 2018	58	22	36	—	—	5.90	%(a)
	58	22	36	—	—

(a)Fixed rate

PNGTS is restricted under the terms of their note purchase agreement from making cash distributions to its partners unless certain conditions are met. Before a distribution can be made, the debt service reserve account must be fully funded and the PNGTS debt service coverage ratio for the preceding and succeeding twelve months must be 1.30 or greater. PNGTS was in compliance with all of its financial covenants at June 30, 2016.

Critical Accounting Policies and Estimates

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 and the disclosure of contingent assets and liabilities at the date of the financial statements. Such estimates and assumptions also affect the reported amounts of revenue and expenses during the reporting period. Although we believe these estimates and assumptions are reasonable, actual results could differ. There were no significant changes to the Partnership’s critical accounting estimates during the three and six months ended June 30, 2016. Information about our critical accounting estimates is included in our Annual Report on Form 10-K for the year ended December 31, 2015.

Our significant accounting policies have remained unchanged since December 31, 2015 except as described in Note 3 within Item 1. “Financial Statements,” of this quarterly report on Form 10-Q. A summary of our significant accounting policies can be found in our Annual Report on Form 10-K for the year ended December 31, 2015.

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Tuscarora Goodwill

As discussed more fully in Note 16, within Item 1. “Financial Statements,” of this quarterly report on Form 10-Q, we believe there is a high probability that the Tuscarora settlement will be approved as filed, and as a result, the expected reduction in Tuscarora’s future cash flows constituted a triggering event that led us to evaluate, for possible impairment, the $82 million of goodwill related to our acquisition of Tuscarora.

Our analysis resulted in the estimated fair value of Tuscarora exceeding its carrying value but the excess was less than 10 percent. The fair value was measured using a discounted cash flow analysis and included revenue expected from Tuscarora’s current contracting level together with other opportunities on the system. There is a risk that reductions in future cash flow forecasts as a result of Tuscarora not being able to maintain its current contracting level and/or not being able to realize other opportunities on the system together with adverse changes in other key assumptions such as projected operating costs and other future growth capital could result in a future impairment of the goodwill balance relating to Tuscarora.

RELATED PARTY TRANSACTIONS

Please read Note 11 within Item 1. “Financial Statements” for information regarding related party transactions.

Item 3.Quantitative and Qualitative Disclosures About Market Risk

OVERVIEW

The Partnership and our pipeline systems are exposed to market risk, counterparty credit risk, and liquidity risk. Our exposure to market risk discussed below includes forward-looking statements and is not necessarily indicative of actual results, which may not represent the maximum possible gains and losses that may occur, since actual gains and losses will differ from those estimated, based on actual market conditions.

Our primary risk management objective is to mitigate the impact of these risks on earnings and cash flow, and ultimately, unitholder value. We do not use financial instruments for trading purposes.

We record derivative financial instruments on the balance sheet as assets and liabilities at fair value. We estimate the fair value of derivative financial instruments using available market information and appropriate valuation techniques. Changes in the fair value of derivative financial instruments are recognized in earnings unless the instrument qualifies as a hedge and meets specific hedge accounting criteria. Qualifying derivative financial instruments’ gains and losses may offset the hedged items’ related results in earnings for a fair value hedge or be deferred in accumulated other comprehensive income for a cash flow hedge.

MARKET RISK

From time to time, and in order to finance our business and that of our pipeline systems, the Partnership and our pipeline systems issue debt to invest in growth opportunities and provide for ongoing operations. The issuance of floating rate debt exposes the Partnership and our pipeline systems to market risk from changes in interest rates which affect earnings and the value of the financial instruments we hold.

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. We regularly assess the impact of interest rate fluctuations on future cash flows and evaluate hedging opportunities to mitigate our interest rate risk.

As of June 30, 2016, the Partnership’s interest rate exposure resulted from our floating rate Senior Credit Facility, 2015 Term Loan Facility, GTN’s Unsecured Term Facility and Tuscarora’s Unsecured Term Facility, under which $495 million, or 25 percent, of our outstanding debt was subject to variability in LIBOR interest rates. As of December 31, 2015, the Partnership’s interest rate exposure resulted from our floating rate Senior Credit Facility, unhedged portion of 2013 Term Loan Facility amounting to $350 million and Short-Term Loan Facility under which $795 million, or 42 percent, of our outstanding debt was subject to variability in LIBOR interest rates.  As of June 30, 2016, the variable interest rate exposure related to 2013 Term Loan Facility was hedged by fixed interest rate swap arrangements. If interest rates hypothetically increased (decreased) by one percent, 100 basis points, compared with rates in effect at June 30, 2016, our annual interest expense would increase (decrease) and net income would decrease (increase) by approximately $5 million.

35

As of June 30, 2016, $81 million, or 19 percent, of Northern Border’s outstanding debt was subject to floating rates (December 31, 2015 — $61 million or 15 percent). If interest rates hypothetically increased (decreased) by one percent, 100 basis points, compared with rates in effect at June 30, 2016, Northern Border’s annual interest expense would increase (decrease) and its net income would decrease (increase) by approximately $1 million.

GTN’s Unsecured Senior Notes, Northern Border’s Senior Notes, all of Great Lakes’ debt, all of PNGTS’ debt and Tuscarora’s Series D debt are subject to fixed rates; therefore, they are not exposed to market risk due to floating interest rates. Interest rate risk does not apply to Bison and North Baja as they currently do not have any debt.

The Partnership and our pipeline systems use derivatives as part of our overall risk management policy to assist in managing exposures to market risk resulting from these activities within established policies and procedures. Derivative contracts used to manage market risk generally consist of the following:

·Swaps — contractual agreements between two parties to exchange streams of payments over time according to specified terms.

·Options — contractual agreements to convey the right, but not the obligation, for the purchaser to buy or sell a specific amount of a financial instrument at a fixed price, either at a fixed date or at any time within a specified period.

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, 2016, the fair value of the interest rate swaps accounted for as cash flow hedges was a liability of $5 million (both on a gross and net basis) (December 31, 2015 - $1 million). The Partnership did not record any amounts in net income related to ineffectiveness for interest rate hedges for the three and six months ended June 30, 2016 and 2015. The change in fair value of interest rate derivative instruments recognized in other comprehensive income was a loss of $1 million and a loss of $3 million for the three and six months ended June 30, 2016, respectively (2015 — nil and a loss of $1 million). For the three and six months ended June 30, 2016, the net realized loss related to the interest rate swaps was $1 million, and was included in financial charges and other (2015 — nil and $1 million).

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, 2016 and December 31, 2015.

OTHER RISKS

Counterparty credit risk represents the financial loss that the Partnership and our pipeline systems would experience if a counterparty to a financial instrument failed to meet its obligations in accordance with the terms and conditions of the financial instruments with the Partnership or its pipeline systems. The Partnership and our pipeline systems have significant credit exposure to financial institutions as they provide committed credit lines and critical liquidity in the interest rate derivative market, as well as letters of credit to mitigate exposures to non-creditworthy customers. The Partnership closely monitors the creditworthiness of our counterparties, including financial institutions. However, we cannot predict to what extent our business would be impacted by uncertainty in energy commodity prices, including possible declines in our customers’ creditworthiness.

Our maximum counterparty credit exposure with respect to financial instruments at the balance sheet date consists primarily of the carrying amount, which approximates fair value, of non-derivative financial assets, such as accounts receivable, as well as the fair value of derivative financial assets. We review our accounts receivable regularly and record allowances for doubtful accounts using the specific identification method. At June 30, 2016, we had not incurred any significant credit losses and had no significant amounts past due or impaired. At June 30, 2016, the Partnership’s maximum counterparty credit exposure consisted of accounts receivable of $35 million and two of our customers, Anadarko Energy Services Company and Pacific Gas and Electric Company owed us approximately $4 million and $3 million, respectively, which represented greater than 10 percent of our trade accounts receivable.

36

Liquidity risk is the risk that the Partnership and our pipeline systems will not be able to meet our financial obligations as they become due. Our approach to managing liquidity risk is to ensure that we always have sufficient cash and credit facilities to meet our obligations when due, under both normal and stressed conditions, without incurring unacceptable losses or damage to our reputation. At June 30, 2016, the Partnership had a committed revolving bank line of $500 million maturing in 2017 and the outstanding balance on this facility was $250 million. In addition, at June 30, 2016, Northern Border had a committed revolving bank line of $200 million maturing in 2020 and $81 million was drawn.

Item 4.Controls and Procedures

EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES

As required by Rule 13a-15(e) under the Securities Exchange Act of 1934, as amended (“Exchange Act”) the management of our General Partner, including the principal executive officer and principal financial officer, evaluated as of the end of the period covered by this report the effectiveness of our disclosure controls and procedures. There are inherent limitations to the effectiveness of any system of disclosure controls and procedures, including the possibility of human error and the circumvention or overriding of the controls and procedures. The Partnership’s disclosure controls and procedures are designed to provide reasonable assurance of achieving their objectives. Based upon and as of the date of the evaluation, the management of our General Partner, including the principal executive officer and principal financial officer, concluded that the Partnership’s disclosure controls and procedures as of the end of the period covered by this quarterly report were effective to provide reasonable assurance that the information required to be disclosed by the Partnership in the reports that it files or submits under the Exchange Act, is (a) recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms and (b) accumulated and communicated to the management of our General Partner, including the principal executive officer and principal financial officer, to allow timely decisions regarding required disclosure.

Changes in Internal Control Over Financial Reporting

During the quarter ended June 30, 2016, there was no change in the Partnership’s internal control over financial reporting that has materially affected or is reasonably likely to materially affect our internal control over financial reporting.

PART II — OTHER INFORMATION

Item 1.                 Legal Proceedings

We are involved in various legal proceedings that arise in the ordinary course of business, as well as proceedings that we consider material under federal securities regulations. For additional information on other legal and environmental proceedings affecting the Partnership, please refer to Part 1 - Item 3 of the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2015.

Great Lakes v. Essar Steel Minnesota LLC, et al. — A description of this legal proceeding can be found in Notes to Consolidated Financial Statements —Note 15 Contingencies in Part I, Item 1, of this Quarterly Report on Form 10-Q, and is incorporated herein by reference.

Employees Retirement System of City of St Louis -  A description of this legal proceeding can be found in Notes to Consolidated Financial Statements —Note 15 Contingencies in Part I, Item 1, of this Quarterly Report on Form 10-Q, and is incorporated herein by reference.

In addition to the above written matter, we and our pipeline systems are parties to lawsuits and governmental proceedings that arise in the ordinary course of our business.

37

Item 1A.Risk Factors

TransCanada’s strategic review of its MLP strategy could materially impact the Partnership’s strategic direction, business and results of operations.

In connection with TransCanada’s July 1, 2016 acquisition of Columbia Pipeline Group and its general and limited partner interest in Columbia Pipeline Partners LP, the Partnership has been advised that TransCanada has retained a financial advisor to assist in developing TransCanada’s strategy regarding master limited partnerships.  A decision on TransCanada’s MLP strategy is expected to be communicated by the end of 2016.  TransCanada has also advised that it does not anticipate any transactions involving the sale of assets or equity interests to the Partnership until the strategic review has been completed.  The results of this review could materially impact the strategic direction of the Partnership as well as its business and results of operations.

To the extent there may have been a violation of federal securities laws, we may be subject to claims for rescission or damages in connection with certain sales of our Common Units to certain investors who participated in our ATM offering program after the filing of our Annual Report on Form 10-K for the year-ended December 31, 2015.

On July 17, 2014, the SEC declared effective the Registration Statement that we had filed to cover sales of Common Units under the ATM program. On February 26, 2016, at the time of the filing of the 2015 Form 10-K, we believed that the Partnership continued to be eligible to use the effective Registration Statement to sell Common Units under our ATM program.  However, we have been advised by the staff of the SEC on June 23, 2016 that as a result of the filing of an employee-related Form 8-K on October 28, 2015, which was not filed via EDGAR until 6:02 p.m. Eastern Time (32 minutes after the 5:30 p.m. Eastern Time cutoff), the Partnership was ineligible to use the Registration Statement after the filing of the 2015 Form 10-K.

Because the Partnership was ineligible to continue using the Registration Statement following the filing of the 2015 Form 10-K, it is possible that the sales of an aggregate 1,619,631 Common Units under the Registration Statement (the ATM Common Units), which were sold between March 8, 2016 and May 19, 2016 at per Common Unit prices ranging from $47.00 to $54.95, may be deemed to have been unregistered sales of securities.  If it is determined that persons who purchased the ATM Common Units from the Partnership after February 26, 2016, purchased such Common Units in an offering deemed to be unregistered, then to the extent there may have been a violation of federal securities laws such persons may be entitled to rescission rights, pursuant to which they could be entitled to recover the amount paid for such ATM Common Units, plus interest (based on the statutory rate under applicable state law), less the amount of any distributions.  If such investor has sold any of the ATM Common Units purchased by the investor, then the investor would be entitled to recover the difference between the amount paid for such ATM Common Units and the amount at which such ATM Common Units were sold, assuming the investor’s ATM Common Units were sold at a loss, plus interest and less the amount of any distributions. If all of the investors who purchased the ATM Common Units from the Partnership after February 26, 2016 continue to own all of the ATM Common Units and were to demand rescission of their purchases, and such investors were in fact found to be entitled to such rescission, then we would be obligated to repay approximately $82,334,015, plus interest, less the amount of any distributions.  The Securities Act generally requires that any claim brought for a violation of Section 5 of the Securities Act be brought within one year of the violation.

We are unable to predict the likelihood of any claims or actions being brought against us related to these events.

Rates and other terms of service for our pipeline systems are subject to approval and potential adjustment by FERC, which could limit their ability to recover all costs of capital and operations and negatively impact their rate of return, results of operations and cash available for distribution.

Our pipeline systems are subject to extensive regulation over virtually all aspects of their business, including the types and terms of services they may offer to their customers, construction of new facilities, creation, modification or abandonment of services or facilities, and the rates that they can charge to shippers. Under the NGA, their rates must be just, reasonable and not unduly discriminatory.

In July 2016, the United States Court of Appeals for the District of Columbia Circuit issued its opinion in United Airlines, Inc., et al. v. FERC, finding that FERC had acted arbitrarily and capriciously when it failed to demonstrate that permitting an interstate petroleum products pipeline organized as a limited partnership to include an income tax allowance in the cost of service underlying its rates in addition to the discounted cash flow return on equity would

38

not result in the pipeline partnership owners double-recovering their income taxes. The court vacated FERC’s order and remanded to FERC to consider mechanisms for demonstrating that there is no double recovery as a result of the income tax allowance. There is not likely to be a definitive resolution of these issues for some time, and the ultimate outcome of this proceeding is not certain and could result in changes going forward to FERC’s treatment of income tax allowances in the cost of service or to the discounted cash flow return on equity. Depending upon the resolution of these issues, the cost of service rates of our interstate natural gas pipelines could be affected to the extent it proposes new rates or changes to its existing rates or if its rates are subject to complaint or challenged by FERC.

Accordingly, actions by FERC relating to rates charged on our natural gas pipeline systems, or to the terms and conditions of service on those systems, could adversely affect our ability to recover all of their current or future costs and could negatively impact their rate of return, results of operations and cash available for distribution.

Recent pipeline safety legislation and proposed regulations could result in more stringent requirements on our facilities and systems that could trigger significant capital and operating costs.

On June 22, 2016, The President signed into law important new legislation entitled “Protecting our Infrastructure of Pipelines and Enhancing Safety Act of 2016” (PIPES Act). The PIPES Act reauthorizes the Pipeline and Hazardous Materials Safety Administration (PHMSA) through 2019, and facilitates greater pipeline safety by providing PHMSA with emergency order authority, including authority to issue prohibitions and safety measures on owners and operators of gas or hazardous liquid pipeline facilities to address imminent hazardous, without prior notice or an opportunity for a hearing, as well as enhanced release reporting requirements, requiring a review of both natural gas and hazardous liquid integrity management programs, and mandating the creation of a working group to consider the development of an information-sharing system related to integrity risk analyses.

The PIPES Act also requires that PHMSA publish periodic updates on the status of those mandates outstanding from the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 (2011 Act), of which approximately half remain to be completed. The mandates yet to be acted upon include requiring certain shut-off valves on transmission lines, mapping all high consequence areas, and shortening the deadline for accident and incident notifications.

Additionally, the PIPES Act mandates that PHMSA issue, within two years, minimum safety standards for underground natural gas storage facilities and that PHMSA conduct post-inspection briefings with owners or operators of a gas or hazardous liquid facility within 30 days of an inspection and provide written preliminary findings within 90 days.

We continue to evaluate the impact, if any, of this new statute, in light of the many new PHMSA initiatives and mandates. At this time, we cannot predict the ultimate impact of this legislation on our operations; however, the adoption of any new legislation or regulations regarding increased pipeline safety could cause us to incur increased capital and operating costs, which costs could be significant.

39

Item 6.Exhibits

Exhibits designated by an asterisk (*) are filed herewith and those designated with asterisks (**) are furnished herewith; all exhibits not so designated are incorporated herein by reference to a prior filing as indicated.

No.	Description
3.1	Third Amended and Restated Agreement of Limited Partnership of TC PipeLines, LP dated April 1, 2015 (Incorporated by reference from Exhibit 3.1 to TC PipeLines, LP’s Form 8-K filed April 1, 2015).
3.2	Certificate of Limited Partnership of TC PipeLines, LP (Incorporated by reference to Exhibit 3.2 to TC PipeLines, LP’s Form S-1 Registration Statement, filed on December 30, 1998).
31.1*	Certification of Principal Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*	Certification of Principal Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1**	Certification of Principal Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2**	Certification of Principal Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101.INS*	XBRL Instance Document.
101.SCH*	XBRL Taxonomy Extension Schema Document.
101.CAL*	XBRL Taxonomy Extension Calculation Linkbase Document.
101.DEF*	XBRL Taxonomy Definition Linkbase Document.
101.LAB*	XBRL Taxonomy Extension Label Linkbase Document.
101.PRE*	XBRL Taxonomy Extension Presentation Linkbase Document.

40

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized on this 4th day of August 2016.

TC PIPELINES, LP
(A Delaware Limited Partnership)
by its General Partner, TC PipeLines GP, Inc.
By:	/s/ Brandon Anderson
	Brandon Anderson
	President
	TC PipeLines GP, Inc. (Principal Executive Officer)
By:	/s/ Nathaniel A. Brown
	Nathaniel A. Brown
	Controller
	TC PipeLines GP, Inc. (Principal Financial Officer)

41

EXHIBIT INDEX

Exhibits designated by an asterisk (*) are filed herewith and those designated with asterisks (**) are furnished herewith; all exhibits not so designated are incorporated herein by reference to a prior filing as indicated.

No.	Description
3.1	Third Amended and Restated Agreement of Limited Partnership of TC PipeLines, LP dated April 1, 2015 (Incorporated by reference from Exhibit 3.1 to TC PipeLines, LP’s Form 8-K filed April 1, 2015).
3.2	Certificate of Limited Partnership of TC PipeLines, LP (Incorporated by reference to Exhibit 3.2 to TC PipeLines, LP’s Form S-1 Registration Statement, filed on December 30, 1998).
31.1*	Certification of Principal Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*	Certification of Principal Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1**	Certification of Principal Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2**	Certification of Principal Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101.INS*	XBRL Instance Document.
101.SCH*	XBRL Taxonomy Extension Schema Document.
101.CAL*	XBRL Taxonomy Extension Calculation Linkbase Document.
101.DEF*	XBRL Taxonomy Definition Linkbase Document.
101.LAB*	XBRL Taxonomy Extension Label Linkbase Document.
101.PRE*	XBRL Taxonomy Extension Presentation Linkbase Document.

42

EX-31.1

Exhibit 31.1

CERTIFICATION OF

PRINCIPAL EXECUTIVE OFFICER

I, Brandon Anderson, certify that:

1.I have reviewed this quarterly report on Form 10-Q of TC PipeLines, LP;

2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a)designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b)designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c)evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d)disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a)all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b)any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Dated:  August 4, 2016

/s/ Brandon Anderson

Brandon Anderson

Principal Executive Officer and President

TC PipeLines GP, Inc., as General Partner of TC PipeLines, LP

EX-31.2

Exhibit 31.2

CERTIFICATION OF

PRINCIPAL FINANCIAL OFFICER

I, Nathaniel A. Brown, certify that:

1.I have reviewed this quarterly report on Form 10-Q of TC PipeLines, LP;

2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a)designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b)designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c)evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d)disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a)all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b)any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Dated:  August 4, 2016

/s/ Nathaniel A. Brown

Nathaniel A. Brown

Principal Financial Officer and Controller

TC PipeLines GP, Inc., as General Partner of TC PipeLines, LP

EX-32.1

Exhibit 32.1

CERTIFICATION OF

PRINCIPAL EXECUTIVE OFFICER

I, Brandon Anderson, Principal Executive Officer and President of TC PipeLines GP, Inc., the General Partner of TC PipeLines, LP (the Partnership), in compliance with 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 hereby certify, to the best of my knowledge, in connection with the Partnership’s Quarterly Report on Form 10-Q for the period ended June 30, 2016 as filed with the Securities and Exchange Commission (the Report) on the date hereof, that:

·the Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

·the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Partnership.

Dated: August 4, 2016	/s/ Brandon Anderson
	Brandon Anderson
	Principal Executive Officer and President
	TC PipeLines GP, Inc., as General Partner of TC PipeLines, LP

EX-32.2

Exhibit 32.2

CERTIFICATION OF

PRINCIPAL FINANCIAL OFFICER

I, Nathaniel A. Brown, Principal Financial Officer and Controller of TC PipeLines GP, Inc., the General Partner of TC PipeLines, LP (the Partnership), in compliance with 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 hereby certify, to the best of my knowledge, in connection with the Partnership’s Quarterly Report on Form 10-Q for the period ended June 30, 2016 as filed with the Securities and Exchange Commission (the Report) on the date hereof, that:

·the Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

·the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Partnership.

Dated: August 4, 2016	/s/ Nathaniel A. Brown
	Nathaniel A. Brown
	Principal Financial Officer and Controller
	TC PipeLines GP, Inc., as General Partner of TC PipeLines, LP

XML

Document and Entity Information - shares	6 Months Ended
	Jun. 30, 2016	Aug. 02, 2016
Document and Entity Information
Entity Registrant Name	TC PIPELINES LP
Entity Central Index Key	0001075607
Document Type	10-Q
Document Period End Date	Jun. 30, 2016
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		65,937,080
Document Fiscal Year Focus	2016
Document Fiscal Period Focus	Q2

XML

CONSOLIDATED STATEMENTS OF INCOME - USD ($) shares in Millions, $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Transmission revenues	$ 89	$ 85	$ 175	$ 172
Equity earnings (Note 4)	22	15	64	46
Operation and maintenance expenses	(12)	(13)	(22)	(24)
Property taxes	(5)	(5)	(10)	(11)
General and administrative	(2)	(1)	(4)	(4)
Depreciation	(22)	(21)	(43)	(42)
Financial charges and other (Note 14)	(16)	(16)	(33)	(29)
Net income	54	44	127	108
Net income attributable to non-controlling interests				7
Net income attributable to controlling interests	54	44	127	101
Net income attributable to controlling interest allocation
General Partner	3	2	5	3
Net income attributable to controlling interests	54	44	127	101
Common units
Net income attributable to controlling interest allocation
Limited partners	$ 50	$ 42	$ 121	$ 98
Net income per common unit (Note 8) - basic (in dollars per unit)	$ 0.76	$ 0.66	$ 1.86	$ 1.53
Net income per common unit (Note 8) - diluted (in dollars per unit)	$ 0.76	$ 0.66	$ 1.86	$ 1.53
Weighted average common units outstanding - basic (in units)	65.5	63.8	64.9	63.7
Weighted average common units outstanding - diluted (in units)	65.5	63.8	64.9	63.7
Common units outstanding, end of period (in units)	65.9	64.0	65.9	64.0
Class B units
Net income attributable to controlling interest allocation
Limited partners	$ 1		$ 1

XML

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
Net income	$ 54	$ 44	$ 127	$ 108
Other comprehensive income
Change in fair value of cash flow hedges (Note 12)	(1)		(3)	(1)
Comprehensive income	53	44	124	107
Comprehensive income attributable to non-controlling interests				7
Comprehensive income attributable to controlling interests	$ 53	$ 44	$ 124	$ 100

XML

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions	Jun. 30, 2016	Dec. 31, 2015
Current Assets
Cash and cash equivalents	$ 40	$ 39
Accounts receivable and other (Note 13)	35	35
Distribution receivable from affiliate (Note 11)	4
Inventories	7	7
Total current assets	86	81
Equity investments (Note 4)	1,047	965
Plant, property and equipment (Net of $850 accumulated depreciation; 2015 - $811)	1,913	1,949
Goodwill	130	130
Other assets (Note 3)		1
Total assets	3,176	3,126
Current Liabilities
Accounts payable and accrued liabilities	26	32
Accounts payable to affiliates (Note 11)	5	5
Accrued interest	9	8
Current portion of long-term debt (Note 5)	15	14
Total current liabilities	55	59
Long-term debt (Notes 3 and 5)	1,938	1,889
Other liabilities	29	27
Total liabilities	2,022	1,975
Common units subject to rescission	83
Partners' Equity
General partner	25	25
Accumulated other comprehensive loss	(5)	(2)
Controlling interests	1,071	1,151
Total liabilities and partners' equity	3,176	3,126
Common units
Partners' Equity
Limited partner	955	1,021
Class B units
Partners' Equity
Limited partner	$ 96	$ 107

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CONSOLIDATED BALANCE SHEET (Parenthetical) $ in Millions	Jun. 30, 2016 USD ($)
CONSOLIDATED BALANCE SHEETS
Accumulated depreciation	$ 850

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CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015
Cash Generated From Operations
Net income	$ 127	$ 108
Depreciation	43	42
Amortization of debt issue costs reported as interest expense (Note 3)	1	1
Equity allowance for funds used during construction		(1)
Change in operating working capital (Note 10)	3	1
Total cash generated from operations	170	151
Investing Activities
Acquisition of the remaining 30 percent interest in GTN		(264)
Capital expenditures	(18)	(12)
Other	2	(1)
Total investing activities	(171)	(258)
Financing Activities
Distributions paid to non-controlling interests		(9)
Common unit issuance, net		26
Common unit issuance subject to rescission, net (Note 7)	83
Equity contribution by the General Partner		2
Long-term debt issued, net of discount (Note 5)	205	424
Long-term debt repaid (Note 5)	(155)	(205)
Debt issuance costs		(3)
Total financing activities	2	125
Increase in cash and cash equivalents	1	18
Cash and cash equivalents, beginning of period	39	26
Cash and cash equivalents, end of period	40	44
Class B units
Financing Activities
Distributions paid (Note 7)	(12)
Common units and General Partner interest combined
Financing Activities
Distributions paid (Note 9)	(119)	(110)
Northern Border
Investing Activities
Cumulative distributions in excess of equity earnings	25	13
Great Lakes
Investing Activities
Cumulative distributions in excess of equity earnings	17	10
Investment in Great Lakes / Acquisition of PNGTS (Note 6)	(4)	$ (4)
Portland Natural Gas Transmission System
Cash Generated From Operations
Equity earnings in excess of cumulative distributions	(4)
Investing Activities
Investment in Great Lakes / Acquisition of PNGTS (Note 6)	$ (193)

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CONSOLIDATED STATEMENTS OF CASH FLOWS (Parenthetical)	Jun. 30, 2016	Apr. 01, 2015
GTN | Transaction between entities under common control | Former parent, TransCanada subsidiaries
Acquisitions
Interest acquired (as a percent)	30.00%	30.00%

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CONSOLIDATED STATEMENT OF CHANGES IN PARTNERS' EQUITY - 6 months ended Jun. 30, 2016 - USD ($) shares in Millions, $ in Millions	Limited Partners Common units	Limited Partners Class B units	General Partner	Accumulated Other Comprehensive Loss	[1]	Total
Partners' Equity at beginning of period at Dec. 31, 2015	$ 1,021	$ 107	$ 25	$ (2)		$ 1,151
Partners' Equity at beginning of period (in units) at Dec. 31, 2015	64.3	1.9
Increase (Decrease) in Partners' Equity
Net income	$ 121	$ 1	5			127
Other Comprehensive Loss				(3)		(3)
Common unit issuance subject to rescission, net (Note 7)	$ 81		2			83
Common unit issuance subject to rescission, net (Note 7) (in units)	1.6
Reclassification of common unit issuance subject to rescission, net (Note 7)	$ (81)		(2)			(83)
Reclassification of common unit issuance subject to rescission, net (Note 7) (in units)	(1.6)
Acquisition of PNGTS (Note 6)	$ (72)		(1)			(73)
Distributions	(115)	(12)	(4)			(131)
Partners' Equity at end of period at Jun. 30, 2016	$ 955	$ 96	$ 25	$ (5)		$ 1,071
Partners' Equity at end of period (in units) at Jun. 30, 2016	64.3	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 $2 million. These estimates assume constant interest rates over time; however, the amounts reclassified will vary based on actual value of interest rates at the date of settlement.

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CONSOLIDATED STATEMENT OF CHANGES IN PARTNERS' EQUITY (Parenthetical) $ in Millions	6 Months Ended
	Jun. 30, 2016 USD ($)
Losses related to cash flow hedges reported in Accumulated Other Comprehensive Loss
Losses expected to be reclassified to Net Income in the next 12 months	$ 2

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ORGANIZATION

6 Months Ended

Jun. 30, 2016

ORGANIZATION

ORGANIZATION

NOTE 1ORGANIZATION

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.

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SIGNIFICANT ACCOUNTING POLICIES

6 Months Ended

Jun. 30, 2016

SIGNIFICANT ACCOUNTING POLICIES

SIGNIFICANT ACCOUNTING POLICIES

NOTE 2SIGNIFICANT 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, 2016 and 2015 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 financial statements and notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2015. 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, 2015, except as described in Note 3, Accounting Pronouncements.

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.

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ACCOUNTING PRONOUNCEMENTS

6 Months Ended

Jun. 30, 2016

ACCOUNTING PRONOUNCEMENTS

ACCOUNTING PRONOUNCEMENTS

NOTE 3ACCOUNTING PRONOUNCEMENTS

Effective January 1, 2016

Consolidation

In February 2015, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) No. 2015-02 “Consolidation (Topic 810),” an amendment of previously issued guidance on consolidation. This updated guidance requires that an entity evaluate whether it should consolidate certain legal entities. All legal entities are subject to reevaluation under the revised consolidation model. This guidance became effective beginning January 1, 2016 and was applied retrospectively to all financial statements presented. The application of this guidance did not result in any change to the Partnership’s consolidation conclusions. Refer to Note 17, Variable Interest Entities.

Imputation of interest

In April 2015, the FASB issued ASU No. 2015-03 “Interest — Imputation of Interest (Subtopic 835-30),” an amendment of previously issued guidance on imputation of interest. This updated guidance requires debt issuance costs be presented in the balance sheet as a direct deduction from the carrying amount of debt liabilities, consistent with debt discount or premiums. In addition, amortization of debt issuance costs should be reported as interest expense. The recognition and measurement for debt issuance costs would not be affected. This guidance is effective from January 1, 2016 and was applied retrospectively resulting in a reclassification of debt issuance costs previously recorded in other assets to an offset of their respective debt liabilities on the Partnership’s consolidated balance sheet. Amortization of debt issuance costs was reported as interest expense in all periods presented in the Partnership’s consolidated statement of income.

As a result of the application of ASU No. 2015-03 and similar to the presentation of debt discounts, debt issuance costs of $7 million at December 31, 2015 previously reported as other assets in the balance sheet were reclassified as an offset against their respective debt liabilities.

Earnings per share

In April 2015, the FASB issued ASU No. 2015-06 “Earnings Per Share (Topic 260),” an amendment of previously issued guidance on earnings per share (EPS) as it is being calculated by master limited partnerships. This updated guidance specifies that for purposes of calculating historical EPS under the two-class method, the earnings (losses) of a transferred business before the date of a dropdown transaction should be allocated entirely to the general partner interest, and previously reported EPS of the limited partners would not change as a result of a dropdown transaction. Qualitative disclosures about how the rights to the earnings (losses) differ before and after the dropdown transaction occurs are also required. This guidance became effective from January 1, 2016 and applies to all dropdown transactions requiring recast. The retrospective application of this guidance did not have a material impact on the Partnership’s consolidated financial statements as our current accounting policy is consistent with the new guidance.

Business combinations

In September 2015, the FASB issued ASU No. 2015-16 “Business Combinations (Topic 805),” which replaces the requirement that an acquirer in a business combination account for measurement period adjustments retrospectively with a requirement that an acquirer recognize adjustments to the provisional amounts that are identified during the measurement period in the reporting period in which the adjustment amounts are determined. The amended guidance requires that the acquirer record, in the same period’s financial statements, the effect on earnings of changes in depreciation, amortization, or other income effects, if any, as a result of the change to the provisional amounts, calculated as if the accounting had been completed at the acquisition date. The new guidance is effective January 1, 2016 and was applied prospectively. The application of this guidance did not have a material impact on the Partnership’s consolidated financial statements.

Future accounting changes

Revenue from contracts with customers

In May 2014, the FASB issued ASU No. 2014-09 “Revenue from Contracts with Customers (Topic 606).” This guidance supersedes the revenue recognition requirements in Topic 605, Revenue Recognition and most industry-specific guidance. This new guidance requires that an entity recognizes revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the company expects to be entitled in exchange for those goods or services. On July 9, 2015, the FASB voted to defer the effective date by one year to December 15, 2017 for annual reporting periods beginning after that date. The FASB also voted to permit early adoption of the standard, but not before the original effective date of December 15, 2016. This new guidance, once effective, allows two methods in which the amendment can be applied: (1) retrospectively to each prior reporting period presented, or (2) retrospectively with the cumulative effect recognized at the date of initial application. This guidance supersedes the current revenue recognition requirements and most industry-specific guidance. The core principle relating to the new guidance requires that an entity recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the company expects to be entitled in exchange for those goods or services. To achieve the core principle, a five step process is required:

1) Identify the contract with the customer

2) Identify the performance obligations in the contract

3) Determine the transaction price

4) Allocate the transaction price to the performance obligations

5) Recognize revenue when (or as) each performance obligations is satisfied

The new guidance also specifies the accounting for some costs to obtain or fulfill a contract, as well as enhanced disclosure requirements.  The Partnership is currently identifying existing customer contracts or groups of contracts that are within the scope of the new guidance and that will require an assessment in order to determine any impact on its consolidated financial statements.

Leases

In February 2016, the FASB issued ASU No. 2016-03 “Leases (Topic 842).” The new guidance requires lessees to recognize most leases, including operating leases, on the balance sheet as lease assets and lease liabilities. In addition, lessees will be required to reassess assumptions associated with existing leases as well as to provide expanded qualitative and quantitative disclosures. The new standard does not make extensive changes to lessor accounting. The new guidance is effective January 1, 2019 and will be applied using a modified retrospective approach. The Partnership is currently identifying existing lease agreements that are within the scope of the new guidance that may have an impact on its consolidated financial statements.

Equity method and joint ventures

In March 2016, the FASB issued ASU No. 2016-07 “Investments — Equity Method and Joint Ventures (Topic 323)” that simplifies the transition to equity method accounting. The new guidance eliminates the requirement to retroactively apply the equity method of accounting when an increase in ownership interest in an investment qualifies for equity method accounting. This new guidance is effective January 1, 2017 and will be applied prospectively. The Partnership does not expect the adoption of this new standard to have a material impact on its consolidated financial statements.

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EQUITY INVESTMENTS

6 Months Ended

Jun. 30, 2016

EQUITY INVESTMENTS

EQUITY INVESTMENTS

NOTE 4EQUITY INVESTMENTS

Northern Border, Great Lakes and Portland Natural Gas Transmission System (PNGTS) are regulated by FERC and are operated by subsidiaries of TransCanada. 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 3, Accounting Pronouncements and Note 17, Variable Interest Entities.

	Ownership		Equity Earnings from Unconsolidated Affiliates				Investments in Unconsolidated Affiliates
	Interest at		Three months		Six Months
(unaudited)	June 30,		ended June 30,		ended June 30,		June 30,	December 31,
(millions of dollars)	2016		2016	2015	2016	2015	2016	2015
Northern Border (a)	50	%	16	15	34	34	455	480
Great Lakes	46.45	%	4	—	19	12	472	485
PNGTS (b)	49.90	%	2	—	11	—	120	—
			22	15	64	46	1,047	965

(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 additional 20 percent interest acquisition in April 2006.

(b) On January 1, 2016, the Partnership acquired a 49.9 percent interest in PNGTS (Refer to Note 6). For the three and six months ended June 30, 2016, the Partnership recorded no undistributed earnings from PNGTS.

Northern Border

The Partnership did not have undistributed earnings from Northern Border for the three and six months ended June 30, 2016 and 2015.

The summarized financial information for Northern Border is as follows:

(unaudited)
(millions of dollars)	June 30, 2016		December 31, 2015
ASSETS
Cash and cash equivalents	16		27
Other current assets	34		33
Plant, property and equipment, net	1,108		1,124
Other assets (a)	15		16
	1,173		1,200
LIABILITIES AND PARTNERS’ EQUITY
Current liabilities	40		39
Deferred credits and other	27		26
Long-term debt, including current maturities, net (a)	429		409
Partners’ equity
Partners’ capital	679		728
Accumulated other comprehensive loss	(2	)	(2	)
	1,173		1,200

(a) As a result of the application of ASU No. 2015-03 and similar to the presentation of debt discounts, debt issuance costs of $2 million at December 31, 2015 previously reported as other assets in the balance sheet were reclassified as an offset against their respective debt liabilities.

	Three months ended				Six months ended
(unaudited)	June 30,				June 30,
(millions of dollars)	2016		2015		2016		2015
Transmission revenues	70		69		144		144
Operating expenses	(18	)	(18	)	(35	)	(34	)
Depreciation	(15	)	(14	)	(29	)	(29	)
Financial charges and other	(6	)	(6	)	(11	)	(11	)
Net income	31		31		69		70

Great Lakes

The Partnership made an equity contribution to Great Lakes of $4 million in the first quarter of 2016. 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, 2016 and 2015.

The summarized financial information for Great Lakes is as follows:

(unaudited)
(millions of dollars)	June 30, 2016	December 31, 2015
ASSETS
Current assets	53	86
Plant, property and equipment, net	721	727
	774	813
LIABILITIES AND PARTNERS’ EQUITY
Current liabilities	29	31
Long-term debt, including current maturities, net (a)	288	297
Partners’ equity	457	485
	774	813

(a) The application of ASU No. 2015-03 did not have a material effect on Great Lakes’ financial statements.

	Three months ended				Six months ended
(unaudited)	June 30,				June 30,
(millions of dollars)	2016		2015		2016		2015
Transmission revenues	36		28		97		76
Operating expenses	(15	)	(14	)	(30	)	(25	)
Depreciation	(7	)	(7	)	(14	)	(14	)
Financial charges and other	(5	)	(6	)	(11	)	(12	)
Net income	9		1		42		25

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DEBT AND CREDIT FACILITIES

6 Months Ended

Jun. 30, 2016

DEBT AND CREDIT FACILITIES

DEBT AND CREDIT FACILITIES

NOTE 5DEBT AND CREDIT FACILITIES

(unaudited) (millions of dollars)	June 30, 2016	December 31, 2015	Weighted Average Interest Rate for the Six Months Ended June 30, 2016
TC PipeLines, LP Senior Credit Facility due 2017	250	200	1.69	%
TC PipeLines, LP 2013 Term Loan Facility due 2018	500	500	1.69	%
TC PipeLines, LP 2015 Term Loan Facility due 2018	170	170	1.58	%
TC PipeLines, LP 4.65% Unsecured Senior Notes due 2021	350	350	4.65	%(b)
TC PipeLines, LP 4.375% Unsecured Senior Notes due 2025	350	350	4.375	%(b)
GTN 5.29% Unsecured Senior Notes due 2020	100	100	5.29	%(b)
GTN 5.69% Unsecured Senior Notes due 2035	150	150	5.69	%(b)
GTN Unsecured Term Loan Facility due 2019	65	75	1.38	%
Tuscarora Unsecured Term Loan due 2019	10	—	1.57	%
Tuscarora 3.82% Series D Senior Notes due 2017	16	16	3.82	%(b)
	1,961	1,911
Less: unamortized debt issuance costs and debt discount (a)	8	8
Less: current portion	15	14
	1,938	1,889

(a) As a result of the application of ASU No. 2015-03 and similar to the presentation of debt discounts, debt issuance costs of $7 million at December 31, 2015 previously reported as other assets in the balance sheet were reclassified as an offset against debt. Refer to Note 3, Accounting Pronouncements.

(b) Fixed interest rate

The Partnership’s Senior Credit Facility consists of a $500 million senior revolving credit facility with a banking syndicate, maturing November 20, 2017, under which $250 million was outstanding at June 30, 2016 (December 31, 2015 - $200 million), leaving $250 million available for future borrowing.

After hedging activity, the interest rate incurred on the 2013 Term Loan Facility averaged 2.31 percent and 2.25 percent for the three and six months ended June 30, 2016, respectively (2015 — 1.84 percent). Prior to hedging activities, the LIBOR-based interest rate was 1.71 percent at June 30, 2016 (December 31, 2015 — 1.50 percent).

The 2013 Term Loan Facility and the 2015 Term Loan Facility (Term Loan Facilities) and the Senior Credit Facility require the Partnership to maintain a certain leverage ratio (debt to adjusted cash flow [net income plus cash distributions received, extraordinary losses, interest expense, expense for taxes paid or accrued, and depreciation and amortization expense less equity earnings and extraordinary gains]) no greater than:

· 5.50 to 1.00 for the quarters ending June 30, 2016 to September 30, 2016;

· 5.00 to 1.00 for the quarter ending December 31, 2016 and each subsequent 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 4.37 to 1.00 as of June 30, 2016.

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, 2016 was 43.7 percent.

On  April  29,  2016,  Tuscarora  entered  into  a $9.5  million  unsecured  variable  rate  term  loan  facility which requires  yearly principal  payments  until  its  maturity  on  April  29,  2019.  The variable interest is based on LIBOR plus an applicable margin and was 1.59 percent at June 30, 2016.

Tuscarora’s Series D Senior Notes, which require yearly principal payments until maturity, are secured by Tuscarora’s transportation contracts, supporting agreements and substantially all of Tuscarora’s property. The note purchase agreements contain certain provisions that include, among other items, limitations on additional indebtedness and distributions to partners. The Series D Senior Notes contain a covenant that limits total debt to no greater than 45 percent of Tuscarora’s total capitalization.  Tuscarora’s total debt to total capitalization ratio at June 30, 2016 was 24 percent. Additionally, the Series D Senior Notes require 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 3.00 to 1.00. The ratio was 4.57 to 1.00 as of June 30, 2016.

At June 30, 2016, the Partnership was in compliance with its financial covenants, in addition to the other covenants which include restrictions on entering into mergers, consolidations and sales of assets, granting liens, material amendments to the Third Amended and Restated Agreement of Limited Partnership (Partnership Agreement), incurring additional debt and distributions to unitholders.

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

(unaudited)
(millions of dollars)
2016	4
2017	273
2018	691
2019	43
2020	100
Thereafter	850
	1,961

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ACQUISITION

6 Months Ended

Jun. 30, 2016

ACQUISITION

ACQUISITION

NOTE 6ACQUISITION

PNGTS Acquisition

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

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

The acquisition was accounted for as a transaction between entities under common control, whereby the equity investment in PNGTS was recorded at TransCanada’s carrying value.

The net purchase price was allocated as follows:

(unaudited) (millions of dollars)
Net Purchase Price (a)	193
Less: TransCanada’s carrying value of PNGTS’ net assets at January 1, 2016	120
Excess purchase price (b)	73

(a) Total purchase price of $228 million less the assumption of $35 million of proportional PNGTS debt by the Partnership.

(b) The excess purchase price of $73 million was recorded as a reduction in Partners’ Equity.

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PARTNERS' EQUITY

6 Months Ended

Jun. 30, 2016

PARTNERS' EQUITY

PARTNERS' EQUITY

NOTE 7PARTNERS’ EQUITY

ATM equity issuance program

In the six months ended June 30, 2016, we issued 1,619,631 common units under our ATM program generating net proceeds of approximately $81 million, plus $2 million from the General Partner to maintain its effective two percent interest. The commissions to our sales agents for the six months ended June 30, 2016 were approximately $823,000. The net proceeds were used for general partnership purposes.

On July 29, 2016, we filed a new shelf registration with the Securities Exchange Commission (SEC) to register an additional $400 million of common units. On August 2, 2016, we requested accelerated effectiveness of the amended shelf registration statement.

Common unit issuance subject to rescission

On July 17, 2014, the SEC declared effective a registration statement (the Registration Statement) that we had filed to cover sales of Common Units under our ATM program. On February 26, 2016, at the time of the filing of the 2015 Form 10-K, we believed that the Partnership continued to be eligible to use the effective Registration Statement to sell Common Units under our ATM program.  However, we have been advised by the SEC on June 23, 2016 that as a result of the untimely filing of an employee-related Form 8-K on October 28, 2015, which was not filed via  EDGAR until 6:02 p.m. Eastern Time (32 minutes after the 5:30 p.m. Eastern Time cutoff), the Partnership was ineligible to use the Registration Statement after the filing of the 2015 Form 10-K.

Because the Partnership  was ineligible to continue using the Registration Statement following the filing of the 2015 Form 10-K, it is possible that the sales of an aggregate 1,619,631 Common Units under the Registration Statement (the ATM Common Units), which were sold between March 8, 2016 and May 19, 2016 at per Common Unit prices ranging from $47.00 to $54.95, may be deemed to have been unregistered sales of securities.  If it is determined that persons who purchased the ATM Common Units from the Partnership after February 26, 2016, purchased such Common Units in an offering deemed to be unregistered, then to the extent there may have been a violation of federal securities laws such persons may be entitled to rescission rights, pursuant to which they could be entitled to recover the amount paid for such ATM Common Units, plus interest (based on the statutory rate under applicable state law), less the amount of any distributions.  If such investor has sold any of the ATM Common Units purchased by the investor, then the investor would be entitled to recover the difference between the amount paid for such ATM Common Units and the amount at which such ATM Common Units were sold, assuming the investor’s ATM Common Units were sold at a loss, plus interest and less the amount of any distributions. If all of the investors who purchased the ATM Common Units from the Partnership after February 26, 2016 continue to own all of the ATM Common Units and were to demand rescission of their purchases, and such investors were in fact found to be entitled to such rescission, then we would be obligated to repay approximately $82,334,015, plus interest, less the amount of any distributions.  The Securities Act generally requires that any claim brought for a violation of Section 5 of the Securities Act be brought within one year of the violation.

As a result, at June 30, 2016, the Partnership classified all the 1.6 million common units issued under its ATM program after February 26, 2016 up to and including June 30, 2016, which may be subject to rescission rights, outside of equity given the potential redemption feature which is not within the control of the Partnership. These units are treated as outstanding for financial reporting purposes.

The total amount transferred  outside of equity was approximately $83 million which includes interest and less distributions paid and includes our General Partner’s share to maintain its effective two percent interest.

Class B units issued to TransCanada

The Class B Units we issued on April 1, 2015 to finance a portion of the 2015 GTN Acquisition represent a limited partner interest in us and entitle TransCanada to an annual distribution based on 30 percent of GTN’s annual distributions as follows: (i) 100 percent of distributions above $20 million through March 31, 2020; and (ii) 25 percent of distributions above $20 million thereafter.

For the year ending December 31, 2016, the Class B units’ equity account will be increased by the excess of 30 percent of GTN’s distributions over the annual threshold of $20 million until such amount is declared for distribution and paid in the first quarter of 2017. During the six months ended June 30, 2016, 30 percent of GTN’s total distributable cash flow was $21 million. As a result of exceeding the $20 million threshold, the Class B units’ equity account was increased by $1 million (Refer to Note 8).

For the year ended December 31, 2015, the Class B distribution was $12 million and was declared and paid in the first quarter of 2016.

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NET INCOME PER COMMON UNIT

6 Months Ended

Jun. 30, 2016

NET INCOME PER COMMON UNIT

NET INCOME PER COMMON UNIT

NOTE 8NET INCOME PER COMMON UNIT

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

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

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

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)	2016			2015			2016			2015
Net income attributable to controlling interests	54			44			127			101
Net income attributable to the General Partner	(1		)	(1		)	(2		)	(2		)
Incentive distributions allocated to the General Partner (a)	(2		)	(1		)	(3		)	(1		)
Net income attributable to the Class B units (b)	(1		)	—			(1		)	—
Net income allocated to common units	50			42			121			98
Weighted average common units outstanding (millions) — basic and diluted	65.5		(c)	63.8			64.9		(c)	63.7
Net income per common unit — basic and diluted	$	0.76		$	0.66		$	1.86		$	1.53

(a) 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.

(b) As discussed in Note 7, the Class B units entitle TransCanada to a distribution which is an amount based on 30 percent of GTN’s distributions after achieving certain annual thresholds. The distribution will be payable in the first quarter with respect to the prior year’s distributions. Consistent with the application of Accounting Standards Codification (ASC) Topic 260 — “Earnings per share”, the Partnership allocated a portion of net income attributable to controlling interest to the Class B units upon 30 percent of GTN’s total distributable cash flows exceeding $20 million for the year ending December 31, 2016.  During the six months ended June 30, 2016, 30 percent of GTN’s total distributable cash flow was $21 million.  As a result of exceeding the $20 million threshold, $1 million of net income attributable to controlling interests was allocated to the Class B units (Refer to Note 7). During the same period in 2015, no allocation was made to the Class B units as the threshold level of $15 million for the nine month period ending December 31, 2015 had not been exceeded.

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

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CASH DISTRIBUTIONS

6 Months Ended

Jun. 30, 2016

CASH DISTRIBUTIONS

CASH DISTRIBUTIONS

NOTE 9CASH DISTRIBUTIONS

In the three and six months ended June 30, 2016, the Partnership distributed $0.89 and $1.78 per common unit, respectively (2015 — $0.84 and $1.68 per common unit) for a total of $60 million and $119 million, respectively (2015 - $55 million and $110 million). The distributions paid in the three and six months ended June 30, 2016 included an IDR payment to the General Partner of approximately $1 million and $2 million, respectively (2015 - $0.3 million and $0.6 million). 

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CHANGE IN OPERATING WORKING CAPITAL

6 Months Ended

Jun. 30, 2016

CHANGE IN OPERATING WORKING CAPITAL

CHANGE IN OPERATING WORKING CAPITAL

NOTE 10CHANGE IN OPERATING WORKING CAPITAL

(unaudited)	Six months ended June 30,
(millions of dollars)	2016	2015
Change in accounts receivable and other	—	4
Change in accounts payable and accrued liabilities (a)	2	(2	)
Change in accounts payable to affiliates	—	(5	)
Change in accrued interest	1	4
Change in operating working capital	3	1

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

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RELATED PARTY TRANSACTIONS

6 Months Ended

Jun. 30, 2016

RELATED PARTY TRANSACTIONS

RELATED PARTY TRANSACTIONS

NOTE 11RELATED PARTY TRANSACTIONS

The Partnership does not have any employees. The management and operating functions are provided by the General Partner. The General Partner does not receive a management fee in connection with its management of the Partnership. The Partnership reimburses the General Partner for all costs of services provided, including the costs of employee, officer and director compensation and benefits, and all other expenses necessary or appropriate to the conduct of the business of, and allocable to, the Partnership. Such costs include (i) overhead costs (such as office space and equipment) and (ii) out-of-pocket expenses related to the provision of such services. The Partnership Agreement provides that the General Partner will determine the costs that are allocable to the Partnership in any reasonable manner determined by the General Partner in its sole discretion. Total costs charged to the Partnership by the General Partner were $1 million and $2 million for the three and six months ended June 30, 2016, respectively.   Total costs charged to the Partnership by the General Partner were $1 million for both the three and six months ended June 30, 2015.

As operator of our pipelines, 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.

Capital and operating costs charged to our pipeline systems for the three and six months ended June 30, 2016 and 2015 by TransCanada’s subsidiaries and amounts payable to TransCanada’s subsidiaries at June 30, 2016 and December 31, 2015 are summarized in the following tables:

	Three months ended		Six months ended
(unaudited)	June 30,		June 30,
(millions of dollars)	2016	2015	2016	2015
Capital and operating costs charged by TransCanada’s subsidiaries to:
Great Lakes (a)	7	8	14	14
Northern Border (a)	9	9	15	16
PNGTS (a), (c)	2	—	4	—
GTN (a), (b)	7	8	13	14
Bison (d)	1	1	—	2
North Baja	1	2	2	3
Tuscarora	1	1	2	2
Impact on the Partnership’s net income:
Great Lakes	3	3	6	6
Northern Border	3	4	6	7
PNGTS (c)	1	—	2	—
GTN (b)	6	7	11	11
Bison	1	1	2	2
North Baja	1	1	2	2
Tuscarora	1	1	2	2

(unaudited)
(millions of dollars)	June 30, 2016	December 31, 2015
Net amounts payable to TransCanada’s subsidiaries is as follows:
Great Lakes (a)	3	3
Northern Border (a)	3	5
PNGTS (a)	1	—
GTN	3	3
Bison	1	—
North Baja	—	—
Tuscarora	1	1

(a) Represents 100 percent of the costs.

(b) In April 2015, the Partnership acquired the remaining 30 percent interest in GTN.

(c) In January 2016, the Partnership acquired 49.9 percent interest in PNGTS.

(d) Net of proceeds of $1 million from the sale of excess pipe (at cost) to an affiliate.

Great Lakes earns transportation revenues from TransCanada and its affiliates, some of which are provided at discounted rates and some of which are at maximum recourse rates. Great Lakes earned $23 million and $69 million of transportation revenues under these contracts for the three and six months ended June 30, 2016, respectively (2015 - $18 million and $47 million). These amounts represent 64 percent and 71 percent of total revenues earned by Great Lakes for the three and six months ended June 30, 2016, respectively (2015 — 63 percent and 62 percent). Great Lakes also earned $1 million of affiliated rental revenue for the three and six months ended June 30, 2016 (2015 — $1 million).

Accordingly, revenue from TransCanada and its affiliates of $10 million and $32 million are included in the Partnership’s equity earnings from Great Lakes for the three and six months ended June 30, 2016, respectively (2015 - $8 million and $22 million). At June 30, 2016, $9 million was included in Great Lakes’ receivables in regards to the transportation contracts with TransCanada and its affiliates (December 31, 2015 - $17 million).

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

On June 16, 2016, PNGTS declared its second quarter 2016 distribution of $8 million, of which the Partnership received its 49.9 percent share or $4 million on July 18, 2016.

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FAIR VALUE MEASUREMENTS

6 Months Ended

Jun. 30, 2016

FAIR VALUE MEASUREMENTS

FAIR VALUE MEASUREMENTS

NOTE 12FAIR VALUE MEASUREMENTS

(a) Fair Value Hierarchy

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

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

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

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

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

(b) Fair Value of Financial Instruments

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

Long-term debt is recorded at amortized cost and classified in Level 2 of the fair value hierarchy for fair value disclosure purposes. Interest rate derivative assets and liabilities are classified in Level 2 for all periods presented where the fair value is determined by using valuation techniques that refer to observable market data or estimated market prices.  The estimated fair value of the Partnership’s debt as at June 30, 2016 and December 31, 2015 was $1,994 million and $1,873 million, respectively.

The ATM Common units which may be subject to rescission rights, as discussed more fully in Note 7, were measured using the original issuance price, plus statutory interest and less any distributions paid. This fair value measurement is classified as Level 2.

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

The interest rate swaps are structured such that the cash flows of the derivative instruments match those of the variable rate of interest on the 2013 Term Loan Facility. The Partnership hedged interest payments on the variable-rate 2013 Term Loan Facility with interest rate swaps maturing July 1, 2018, at a weighted average fixed interest rate of 2.31 percent. At June 30, 2016, the fair value of the interest rate swaps accounted for as cash flow hedges was a liability of $5 million (both on a gross and net basis) (December 31, 2015 - $1 million). The Partnership did not record any amounts in net income related to ineffectiveness for interest rate hedges for the three and six months ended June 30, 2016 and 2015. The change in fair value of interest rate derivative instruments recognized in other comprehensive income was a loss of $1 million and a loss of $3 million for the three and six months ended June 30, 2016, respectively (2015 — nil and a loss of $1 million). For the three and six months ended June 30, 2016, the net realized loss related to the interest rate swaps was $1 million, and was included in financial charges and other (2015 — nil and $1 million).  Refer to Note 14 — Financial Charges and Other.

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, 2016 and December 31, 2015.

(c) Other

As discussed more fully in Note 16, we performed a discounted cash flow analysis to assess, for possible impairment, the $82 million of goodwill related to our acquisition of Tuscarora. The estimated fair value measurement is classified as Level 3. In the determination of the fair value, we used internal forecasts for expected future cash flows and applied appropriate discount rates. The determination of expected future cash flows involved significant assumptions and estimates regarding revenue, operating and maintenance costs and future growth capital.

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ACCOUNTS RECEIVABLE AND OTHER

6 Months Ended

Jun. 30, 2016

ACCOUNTS RECEIVABLE AND OTHER

ACCOUNTS RECEIVABLE AND OTHER

NOTE 13ACCOUNTS RECEIVABLE AND OTHER

(unaudited)
(millions of dollars)	June 30, 2016	December 31, 2015
Trade accounts receivable, net of allowance of nil	30	31
Other	5	4
	35	35

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FINANCIAL CHARGES AND OTHER

6 Months Ended

Jun. 30, 2016

FINANCIAL CHARGES AND OTHER

FINANCIAL CHARGES AND OTHER

NOTE 14FINANCIAL CHARGES AND OTHER

	Three months ended			Six months ended
(unaudited)	June 30,			June 30,
(millions of dollars)	2016		2015	2016		2015
Interest Expense (a)	16		16	33		29
Net realized loss related to the interest rate swaps	1		—	1		1
Other Income	(1	)	—	(1	)	(1	)
	16		16	33		29

(a) Effective January 1, 2016, interest expense includes debt issuance costs and amortization of discount costs. Refer to Note 3, - Accounting Pronouncements.

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CONTINGENCIES

6 Months Ended

Jun. 30, 2016

CONTINGENCIES

CONTINGENCIES

NOTE 15CONTINGENCIES

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 and certain Essar affiliates (collectively, Essar) for breach of its monthly payment obligation under its transportation services agreement with Great Lakes. Great Lakes sought to recover approximately $33 million for past and future payments due under the agreement. On September 16, 2015, following a jury trial, the federal district court judge entered a judgment in the amount of $32.9 million in favor of Great Lakes.  On September 20, 2015, Essar appealed the decision to the United States Court of Appeals for the 8th Circuit (8th Circuit) based on an allegation of improper jurisdiction and a number of other rulings by the federal district judge. Essar was required to post a performance bond for the full value of the judgment pending appeal. Both parties have filed their briefs. In July 2016, Essar filed for Bankruptcy and asked the 8th Circuit Court of Appeals to stay the appeal pending the bankruptcy proceeding. Great Lakes will file a request with the 8th Circuit Court of Appeals to deny the stay.  Because Great Lakes has a performance bond for the full amount of the judgment, the bankruptcy proceeding is not expected to impact the ability of Great Lakes to receive payment of a final award.

Employees Retirement System of the City of St. Louis v. TC PipeLines GP, Inc., et al. — On October 13, 2015, an alleged unitholder of the Partnership filed a class action and derivative complaint in the Delaware Court of Chancery (Chancery Court) against the General Partner, TransCanada American Investments, Ltd. (TAIL) and TransCanada, and the Partnership as a nominal defendant.   The complaint alleges direct and derivative claims for breach of contract, breach of the duty of good faith and fair dealing, aiding and abetting breach of contract, and tortious interference in connection with the 2015 GTN Acquisition, including the issuance by the Partnership of $95 million in Class B Units and amendments to the Partnership Agreement to provide for the issuance of the Class B Units.   Plaintiff seeks, among other things, to enjoin future issuances of Class B Units to TransCanada or any of its subsidiaries, disgorgement of certain distributions to the General Partner, TransCanada and any related entities, return of some or all of the Class B Units to the Partnership, rescission of the amendments to the Partnership Agreement, monetary damages and attorney fees.   To the extent the claims are derivative, the Partnership would be the beneficiary of any monetary award.  The Partnership does not expect legal fees or the impact of the decision on plaintiffs’ other requests to be material.  In April 2016, the Chancery Court granted the Partnership and other defendants’ motion to dismiss the plaintiffs’ complaint.  The plaintiff has appealed the decision to dismiss its claims.  The appeal is expected to be heard in late-2016.

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GOODWILL AND REGULATORY

6 Months Ended

Jun. 30, 2016

GOODWILL AND REGULATORY

GOODWILL AND REGULATORY

NOTE 16GOODWILL AND REGULATORY

On January 21, 2016, the FERC issued an Order (the January 21 Order) initiating an investigation pursuant to Section 5 of the Natural Gas Act of 1938 (NGA) to determine whether Tuscarora’s existing rates for jurisdictional services are just and reasonable. On July 15, 2016, Tuscarora filed a petition with FERC requesting approval of the Stipulation and Agreement of Settlement (Tuscarora Settlement) that, if approved, will resolve the Section 5 rate review initiated by FERC in January 2016. Under the terms of the Tuscarora Settlement, Tuscarora’s system-wide unit rate will initially decrease by 16 percent, with an anticipated effective date of August 1, 2016. Unless superseded by a subsequent rate case or settlement, this rate will remain in effect for three years, after which time the unit rate will decrease an additional seven percent for an additional three years. The settlement does not contain a rate moratorium and requires Tuscarora to file to establish new rates no later than six years following the effective date of the initial settlement rates.

We believe there is a high probability that the Tuscarora settlement will be approved as filed, and as a result, the expected reduction in Tuscarora’s future cash flows constituted a triggering event that led us to evaluate, for possible impairment, the $82 million of goodwill related to our acquisition of Tuscarora.

Our analysis resulted in the estimated fair value of Tuscarora exceeding its carrying value but the excess was less than 10 percent. The fair value was measured using a discounted cash flow analysis and included revenue expected from Tuscarora’s current contracting level together with other opportunities on the system. There is a risk that reductions in future cash flow forecasts as a result of Tuscarora not being able to maintain its current contracting level and/or not being able to realize other opportunities on the system, together with adverse changes in other key assumptions such as projected operating costs and other future growth capital, could result in a future impairment of the goodwill balance relating to Tuscarora.

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VARIABLE INTEREST ENTITIES

6 Months Ended

Jun. 30, 2016

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 newly effective 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 and PNGTS 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, 2016		December 31, 2015
ASSETS (LIABILITIES) *
Accounts receivable and other	21		25
Inventories	6		6
Equity investments	1,047		965
Plant, property and equipment	859		872
Other assets	2		2
Accounts payable and accrued liabilities	(18	)	(26	)
Accounts payable to affiliates, net	(18	)	(6	)
Accrued interest	(1	)	(1	)
Current portion of long-term debt	(15	)	(14	)
Long-term debt	(325	)	(326	)
Other liabilities	(25	)	(24	)

*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.

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SUBSEQUENT EVENTS

6 Months Ended

Jun. 30, 2016

SUBSEQUENT EVENTS

SUBSEQUENT EVENTS

NOTE 18SUBSEQUENT EVENTS

Management of the Partnership has reviewed subsequent events through August 4, 2016, 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 21, 2016, the board of directors of our General Partner declared the Partnership’s second quarter 2016 cash distribution in the amount of $0.94 per common unit payable on August 12, 2016 to unitholders of record as of August 1, 2016. The declared distribution reflects a $0.05 per common unit increase to the Partnership’s first quarter 2016 quarterly distribution and will include an IDR payment to our General Partner amounting to approximately $2 million.

Northern Border declared its June 2016 distribution of $13 million on July 11, 2016, of which the Partnership will receive its 50 percent share or $6.5 million on July 29, 2016.

Great Lakes declared its second quarter 2016 distribution of $12 million on July 19, 2016, of which the Partnership will receive its 46.45 percent share or $6 million on August 1, 2016.

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SIGNIFICANT ACCOUNTING POLICIES (Policies)

6 Months Ended

Jun. 30, 2016

SIGNIFICANT ACCOUNTING POLICIES

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.

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EQUITY INVESTMENTS (Tables)

6 Months Ended

Jun. 30, 2016

EQUITY INVESTMENTS

Schedule of equity investments and summarized financial information for equity investees

	Ownership		Equity Earnings from Unconsolidated Affiliates				Investments in Unconsolidated Affiliates
	Interest at		Three months		Six Months
(unaudited)	June 30,		ended June 30,		ended June 30,		June 30,	December 31,
(millions of dollars)	2016		2016	2015	2016	2015	2016	2015
Northern Border (a)	50	%	16	15	34	34	455	480
Great Lakes	46.45	%	4	—	19	12	472	485
PNGTS (b)	49.90	%	2	—	11	—	120	—
			22	15	64	46	1,047	965

(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 additional 20 percent interest acquisition in April 2006.

(b) On January 1, 2016, the Partnership acquired a 49.9 percent interest in PNGTS (Refer to Note 6). For the three and six months ended June 30, 2016, the Partnership recorded no undistributed earnings from PNGTS.

Northern Border

EQUITY INVESTMENTS

Schedule of equity investments and summarized financial information for equity investees

(unaudited)
(millions of dollars)	June 30, 2016		December 31, 2015
ASSETS
Cash and cash equivalents	16		27
Other current assets	34		33
Plant, property and equipment, net	1,108		1,124
Other assets (a)	15		16
	1,173		1,200
LIABILITIES AND PARTNERS’ EQUITY
Current liabilities	40		39
Deferred credits and other	27		26
Long-term debt, including current maturities, net (a)	429		409
Partners’ equity
Partners’ capital	679		728
Accumulated other comprehensive loss	(2	)	(2	)
	1,173		1,200

(a) As a result of the application of ASU No. 2015-03 and similar to the presentation of debt discounts, debt issuance costs of $2 million at December 31, 2015 previously reported as other assets in the balance sheet were reclassified as an offset against their respective debt liabilities.

	Three months ended				Six months ended
(unaudited)	June 30,				June 30,
(millions of dollars)	2016		2015		2016		2015
Transmission revenues	70		69		144		144
Operating expenses	(18	)	(18	)	(35	)	(34	)
Depreciation	(15	)	(14	)	(29	)	(29	)
Financial charges and other	(6	)	(6	)	(11	)	(11	)
Net income	31		31		69		70

Great Lakes

EQUITY INVESTMENTS

Schedule of equity investments and summarized financial information for equity investees

(unaudited)
(millions of dollars)	June 30, 2016	December 31, 2015
ASSETS
Current assets	53	86
Plant, property and equipment, net	721	727
	774	813
LIABILITIES AND PARTNERS’ EQUITY
Current liabilities	29	31
Long-term debt, including current maturities, net (a)	288	297
Partners’ equity	457	485
	774	813

(a) The application of ASU No. 2015-03 did not have a material effect on Great Lakes’ financial statements.

	Three months ended				Six months ended
(unaudited)	June 30,				June 30,
(millions of dollars)	2016		2015		2016		2015
Transmission revenues	36		28		97		76
Operating expenses	(15	)	(14	)	(30	)	(25	)
Depreciation	(7	)	(7	)	(14	)	(14	)
Financial charges and other	(5	)	(6	)	(11	)	(12	)
Net income	9		1		42		25

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DEBT AND CREDIT FACILITIES (Tables)

6 Months Ended

Jun. 30, 2016

DEBT AND CREDIT FACILITIES

Schedule of debt and credit facilities

(unaudited) (millions of dollars)	June 30, 2016	December 31, 2015	Weighted Average Interest Rate for the Six Months Ended June 30, 2016
TC PipeLines, LP Senior Credit Facility due 2017	250	200	1.69	%
TC PipeLines, LP 2013 Term Loan Facility due 2018	500	500	1.69	%
TC PipeLines, LP 2015 Term Loan Facility due 2018	170	170	1.58	%
TC PipeLines, LP 4.65% Unsecured Senior Notes due 2021	350	350	4.65	%(b)
TC PipeLines, LP 4.375% Unsecured Senior Notes due 2025	350	350	4.375	%(b)
GTN 5.29% Unsecured Senior Notes due 2020	100	100	5.29	%(b)
GTN 5.69% Unsecured Senior Notes due 2035	150	150	5.69	%(b)
GTN Unsecured Term Loan Facility due 2019	65	75	1.38	%
Tuscarora Unsecured Term Loan due 2019	10	—	1.57	%
Tuscarora 3.82% Series D Senior Notes due 2017	16	16	3.82	%(b)
	1,961	1,911
Less: unamortized debt issuance costs and debt discount (a)	8	8
Less: current portion	15	14
	1,938	1,889

(a) As a result of the application of ASU No. 2015-03 and similar to the presentation of debt discounts, debt issuance costs of $7 million at December 31, 2015 previously reported as other assets in the balance sheet were reclassified as an offset against debt. Refer to Note 3, Accounting Pronouncements.

(b) Fixed interest rate

Schedule of principal repayments required on debt

(unaudited)
(millions of dollars)
2016	4
2017	273
2018	691
2019	43
2020	100
Thereafter	850
	1,961

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ACQUISITION (Tables)

6 Months Ended

Jun. 30, 2016

Portland Natural Gas Transmission System

EQUITY INVESTMENTS

Schedule of net purchase price of equity investment in PNGTS

(unaudited) (millions of dollars)
Net Purchase Price (a)	193
Less: TransCanada’s carrying value of PNGTS’ net assets at January 1, 2016	120
Excess purchase price (b)	73

(a) Total purchase price of $228 million less the assumption of $35 million of proportional PNGTS debt by the Partnership.

(b) The excess purchase price of $73 million was recorded as a reduction in Partners’ Equity.

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NET INCOME PER COMMON UNIT (Tables)

6 Months Ended

Jun. 30, 2016

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)	2016			2015			2016			2015
Net income attributable to controlling interests	54			44			127			101
Net income attributable to the General Partner	(1		)	(1		)	(2		)	(2		)
Incentive distributions allocated to the General Partner (a)	(2		)	(1		)	(3		)	(1		)
Net income attributable to the Class B units (b)	(1		)	—			(1		)	—
Net income allocated to common units	50			42			121			98
Weighted average common units outstanding (millions) — basic and diluted	65.5		(c)	63.8			64.9		(c)	63.7
Net income per common unit — basic and diluted	$	0.76		$	0.66		$	1.86		$	1.53

(a) 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.

(b) As discussed in Note 7, the Class B units entitle TransCanada to a distribution which is an amount based on 30 percent of GTN’s distributions after achieving certain annual thresholds. The distribution will be payable in the first quarter with respect to the prior year’s distributions. Consistent with the application of Accounting Standards Codification (ASC) Topic 260 — “Earnings per share”, the Partnership allocated a portion of net income attributable to controlling interest to the Class B units upon 30 percent of GTN’s total distributable cash flows exceeding $20 million for the year ending December 31, 2016.  During the six months ended June 30, 2016, 30 percent of GTN’s total distributable cash flow was $21 million.  As a result of exceeding the $20 million threshold, $1 million of net income attributable to controlling interests was allocated to the Class B units (Refer to Note 7). During the same period in 2015, no allocation was made to the Class B units as the threshold level of $15 million for the nine month period ending December 31, 2015 had not been exceeded.

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

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CHANGE IN OPERATING WORKING CAPITAL (Tables)

6 Months Ended

Jun. 30, 2016

CHANGE IN OPERATING WORKING CAPITAL

Schedule of change in operating working capital

(unaudited)	Six months ended June 30,
(millions of dollars)	2016	2015
Change in accounts receivable and other	—	4
Change in accounts payable and accrued liabilities (a)	2	(2	)
Change in accounts payable to affiliates	—	(5	)
Change in accrued interest	1	4
Change in operating working capital	3	1

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

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RELATED PARTY TRANSACTIONS (Tables)

6 Months Ended

Jun. 30, 2016

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)	2016	2015	2016	2015
Capital and operating costs charged by TransCanada’s subsidiaries to:
Great Lakes (a)	7	8	14	14
Northern Border (a)	9	9	15	16
PNGTS (a), (c)	2	—	4	—
GTN (a), (b)	7	8	13	14
Bison (d)	1	1	—	2
North Baja	1	2	2	3
Tuscarora	1	1	2	2
Impact on the Partnership’s net income:
Great Lakes	3	3	6	6
Northern Border	3	4	6	7
PNGTS (c)	1	—	2	—
GTN (b)	6	7	11	11
Bison	1	1	2	2
North Baja	1	1	2	2
Tuscarora	1	1	2	2

Summary of amount payable to related party for costs charged

(unaudited)
(millions of dollars)	June 30, 2016	December 31, 2015
Net amounts payable to TransCanada’s subsidiaries is as follows:
Great Lakes (a)	3	3
Northern Border (a)	3	5
PNGTS (a)	1	—
GTN	3	3
Bison	1	—
North Baja	—	—
Tuscarora	1	1

(a) Represents 100 percent of the costs.

(b) In April 2015, the Partnership acquired the remaining 30 percent interest in GTN.

(c) In January 2016, the Partnership acquired 49.9 percent interest in PNGTS.

(d) Net of proceeds of $1 million from the sale of excess pipe (at cost) to an affiliate.

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ACCOUNTS RECEIVABLE AND OTHER (Tables)

6 Months Ended

Jun. 30, 2016

ACCOUNTS RECEIVABLE AND OTHER

Schedule of accounts receivable and other

(unaudited)
(millions of dollars)	June 30, 2016	December 31, 2015
Trade accounts receivable, net of allowance of nil	30	31
Other	5	4
	35	35

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FINANCIAL CHARGES AND OTHER (Tables)

6 Months Ended

Jun. 30, 2016

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)	2016		2015	2016		2015
Interest Expense (a)	16		16	33		29
Net realized loss related to the interest rate swaps	1		—	1		1
Other Income	(1	)	—	(1	)	(1	)
	16		16	33		29

(a) Effective January 1, 2016, interest expense includes debt issuance costs and amortization of discount costs. Refer to Note 3, - Accounting Pronouncements.

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VARIABLE INTEREST ENTITIES (Tables)

6 Months Ended

Jun. 30, 2016

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, 2016		December 31, 2015
ASSETS (LIABILITIES) *
Accounts receivable and other	21		25
Inventories	6		6
Equity investments	1,047		965
Plant, property and equipment	859		872
Other assets	2		2
Accounts payable and accrued liabilities	(18	)	(26	)
Accounts payable to affiliates, net	(18	)	(6	)
Accrued interest	(1	)	(1	)
Current portion of long-term debt	(15	)	(14	)
Long-term debt	(325	)	(326	)
Other liabilities	(25	)	(24	)

*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.

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ORGANIZATION - Ownership Interests in Natural Gas Pipeline Systems (Details)	6 Months Ended
	Jun. 30, 2016 LimitedPartnership
ORGANIZATION
Number of intermediate limited partnerships through which pipeline assets are owned	3

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ACCOUNTING PRONOUNCEMENTS - Imputation of Interest (Details) - USD ($) $ in Millions	Jun. 30, 2016	Dec. 31, 2015
ACCOUNTING PRONOUNCEMENTS
Other assets		$ 1
Long-term debt	$ 1,938	1,889
ASU 2015-03, Interest - Imputation of Interest | Adjustment
ACCOUNTING PRONOUNCEMENTS
Other assets		(7)
Long-term debt		$ (7)

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EQUITY INVESTMENTS (Details) - USD ($) $ in Millions	1 Months Ended	3 Months Ended			6 Months Ended
	Apr. 30, 2006	Jun. 30, 2016	Mar. 31, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015	Jul. 18, 2016	Jan. 01, 2016	Dec. 31, 2015
EQUITY INVESTMENTS
Equity Earnings		$ 22		$ 15	$ 64	$ 46
Equity Investments		$ 1,047			$ 1,047				$ 965
Great Lakes
EQUITY INVESTMENTS
Total cash call issued to fund debt repayment			$ 9
Northern Border
EQUITY INVESTMENTS
Ownership interest (as a percent)		50.00%			50.00%
Equity Earnings		$ 16		15	$ 34	34
Equity Investments		455			455				480
Amortization period of transaction fee	12 years
Transaction fee	$ 10
Additional ownership interest acquired (as a percent)	20.00%
Assets
Cash and cash equivalents		16			16				27
Other current assets		34			34				33
Plant, property and equipment, net		1,108			1,108				1,124
Other assets		15			15				16
Assets, total		1,173			1,173				1,200
LIABILITIES AND PARTNERS' EQUITY
Current liabilities		40			40				39
Deferred credits and other		27			27				26
Long-term debt, including current maturities, net		429			429				409
Partners' equity
Partners' equity		679			679				728
Accumulated other comprehensive loss		(2)			(2)				(2)
Liabilities and Partners' Equity, total		1,173			1,173				1,200
Revenues (expenses)
Transmission revenues		70		69	144	144
Operating expenses		(18)		(18)	(35)	(34)
Depreciation		(15)		(14)	(29)	(29)
Financial charges and other		(6)		(6)	(11)	(11)
Net income		$ 31		31	$ 69	70
Great Lakes
EQUITY INVESTMENTS
Ownership interest (as a percent)		46.45%	46.45%		46.45%
Equity Earnings		$ 4			$ 19	12
Equity Investments		472			472				485
Equity contribution			$ 4		4	4
Assets
Current assets		53			53				86
Plant, property and equipment, net		721			721				727
Assets, total		774			774				813
LIABILITIES AND PARTNERS' EQUITY
Current liabilities		29			29				31
Long-term debt, including current maturities, net		288			288				297
Partners' equity
Partners' equity		457			457				485
Liabilities and Partners' Equity, total		774			774				813
Revenues (expenses)
Transmission revenues		36		28	97	76
Operating expenses		(15)		(14)	(30)	(25)
Depreciation		(7)		(7)	(14)	(14)
Financial charges and other		(5)		(6)	(11)	(12)
Net income		$ 9		$ 1	$ 42	$ 25
Portland Natural Gas Transmission System
EQUITY INVESTMENTS
Ownership interest (as a percent)		49.90%			49.90%		49.90%	49.90%
Equity Earnings		$ 2			$ 11
Equity Investments		120			120
Undistributed earnings		$ 0			0
Equity contribution					$ 193
ASU 2015-03, Interest - Imputation of Interest | Adjustment | Northern Border
Assets
Other assets									(2)
LIABILITIES AND PARTNERS' EQUITY
Long-term debt, including current maturities, net									$ (2)

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DEBT AND CREDIT FACILITIES - Amounts Outstanding and Description of Terms (Details)	3 Months Ended		6 Months Ended
	Jun. 30, 2016 USD ($)	Jun. 30, 2015	Jun. 30, 2016 USD ($) entity	Jun. 30, 2015 USD ($)	Apr. 29, 2016 USD ($)	Dec. 31, 2015 USD ($)
Credit facilities, short-term loan facility and long-term debt
Other assets						$ 1,000,000
Debt and credit facilities	$ 1,961,000,000		$ 1,961,000,000			1,911,000,000
Less: unamortized debt issuance costs and debt discount	8,000,000		8,000,000			8,000,000
Less: current portion	15,000,000		15,000,000			14,000,000
Long-term debt	$ 1,938,000,000		1,938,000,000			1,889,000,000
Amount borrowed			$ 205,000,000	$ 424,000,000
Senior Credit Facility and the Term Loan Facilities due in 2018
Credit facilities, short-term loan facility and long-term debt
Leverage ratio, actual (as a percent)	437.00%		437.00%
Senior Credit Facility and the Term Loan Facilities due in 2018 | 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 and the Term Loan Facilities due in 2018 | 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 and the Term Loan Facilities due in 2018 | 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 and the Term Loan Facilities due in 2018 | 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 2017
Credit facilities, short-term loan facility and long-term debt
Debt and credit facilities	$ 250,000,000		$ 250,000,000			200,000,000
Weighted Average Interest Rate (as a percent)			1.69%
Maximum borrowing capacity	500,000,000		$ 500,000,000
Amount outstanding under credit facility	250,000,000		250,000,000			200,000,000
Remaining borrowing capacity	250,000,000		250,000,000
Term loan | TC PipeLines, LP 2013 Term Loan Facility due 2018
Credit facilities, short-term loan facility and long-term debt
Debt and credit facilities	$ 500,000,000		$ 500,000,000			$ 500,000,000
Weighted Average Interest Rate (as a percent)			1.69%
Term loan | TC PipeLines, LP 2013 Term Loan Facility due 2018 | LIBOR borrowings | LIBOR
Credit facilities, short-term loan facility and long-term debt
Debt interest rate, at period end (as a percent)	1.71%		1.71%			1.50%
Term loan | TC PipeLines, LP 2013 Term Loan Facility due 2018 | 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%	1.84%	2.25%	1.84%
Term loan | TC PipeLines, LP 2015 Term Loan Facility due 2018
Credit facilities, short-term loan facility and long-term debt
Debt and credit facilities	$ 170,000,000		$ 170,000,000			$ 170,000,000
Weighted Average Interest Rate (as a percent)			1.58%
Unsecured debt | TC PipeLines, LP 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%			4.65%
Debt and credit facilities	$ 350,000,000		$ 350,000,000			$ 350,000,000
Weighted Average Interest Rate (as a percent)			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%			4.375%
Debt and credit facilities	$ 350,000,000		$ 350,000,000			$ 350,000,000
Weighted Average Interest Rate (as a percent)			4.375%
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%			5.29%
Debt and credit facilities	$ 100,000,000		$ 100,000,000			$ 100,000,000
Weighted Average Interest Rate (as a percent)			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%			5.69%
Debt and credit facilities	$ 150,000,000		$ 150,000,000			$ 150,000,000
Weighted Average Interest Rate (as a percent)			5.69%
Unsecured debt | GTN Term Loan Facility due 2019
Credit facilities, short-term loan facility and long-term debt
Debt and credit facilities	65,000,000		$ 65,000,000			$ 75,000,000
Weighted Average Interest Rate (as a percent)			1.38%
Unsecured debt | Tuscarora Term Loan due 2019
Credit facilities, short-term loan facility and long-term debt
Debt and credit facilities	$ 10,000,000		$ 10,000,000
Weighted Average Interest Rate (as a percent)			1.57%
Secured debt | Tuscarora 3.82% Series D Senior Notes due 2017
Credit facilities, short-term loan facility and long-term debt
Stated interest rate (as a percent)	3.82%		3.82%			3.82%
Debt and credit facilities	$ 16,000,000		$ 16,000,000			$ 16,000,000
Weighted Average Interest Rate (as a percent)			3.82%
GTN | Unsecured debt | Senior Notes and Term Loan Facility due 2019
Credit facilities, short-term loan facility and long-term debt
Percentage of debt to total capitalization, actual	43.70%		43.70%
GTN | Unsecured debt | Senior Notes and Term Loan Facility due 2019 | Maximum
Credit facilities, short-term loan facility and long-term debt
Percentage of debt to total capitalization, covenant			70.00%
Tuscarora Gas Transmission Company | Unsecured debt | Tuscarora Term Loan due 2019
Credit facilities, short-term loan facility and long-term debt
Amount of debt					$ 9,500,000
Tuscarora Gas Transmission Company | Unsecured debt | Tuscarora Term Loan due 2019 | LIBOR
Credit facilities, short-term loan facility and long-term debt
Debt interest rate, at period end (as a percent)	1.59%		1.59%
Tuscarora Gas Transmission Company | Unsecured debt | Tuscarora 3.82% Series D Senior Notes due 2017
Credit facilities, short-term loan facility and long-term debt
Percentage of debt to total capitalization, actual	24.00%		24.00%
Debt Service Coverage, Actual (as a percent)			457.00%
Tuscarora Gas Transmission Company | Unsecured debt | Tuscarora 3.82% Series D Senior Notes due 2017 | Minimum
Credit facilities, short-term loan facility and long-term debt
Debt Service Coverage, covenant (as a percent)			300.00%
Tuscarora Gas Transmission Company | Unsecured debt | Tuscarora 3.82% Series D Senior Notes due 2017 | Maximum
Credit facilities, short-term loan facility and long-term debt
Percentage of debt to total capitalization, covenant			45.00%
ASU 2015-03, Interest - Imputation of Interest | Adjustment
Credit facilities, short-term loan facility and long-term debt
Other assets						(7,000,000)
Long-term debt						$ (7,000,000)

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DEBT AND CREDIT FACILITIES - Principal Payments Required (Details) $ in Millions	Jun. 30, 2016 USD ($)
Principal repayments required on debt
2016	$ 4
2017	273
2018	691
2019	43
2020	100
Thereafter	850
Total debt	$ 1,961

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ACQUISITION - Acquisition of Ownership Interest in PNGTS (Details) - Portland Natural Gas Transmission System - USD ($) $ in Millions		6 Months Ended
	Jan. 01, 2016	Jun. 30, 2016	Jul. 18, 2016
Acquisition
Interest acquired (as a percent)	49.90%	49.90%	49.90%
Net purchase price		$ 193
TransCanada | Transaction between entities under common control
Acquisition
Total purchase price	$ 228
Net purchase price	193
Purchase price adjustments	5
Assumption of proportional debt	35
Additional contingent payment, minimum	5
Additional contingent payment, maximum	$ 50
Period following closing date during which additional payments may be required	15 years

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ACQUISITION - Net Purchase Price of PNGTS (Details) - USD ($) $ in Millions		6 Months Ended
	Jan. 01, 2016	Jun. 30, 2016
EQUITY INVESTMENTS
Reduction in Partners' Equity		$ 73
Portland Natural Gas Transmission System
EQUITY INVESTMENTS
Net purchase price		$ 193
Transaction between entities under common control | TransCanada | Portland Natural Gas Transmission System
EQUITY INVESTMENTS
Net purchase price	$ 193
Less: TransCanada's carrying value of PNGTS' net assets	(120)
Excess purchase price	73
Total purchase price	228
Proportional debt	35
Common units and General Partner interest combined | Transaction between entities under common control | TransCanada | Portland Natural Gas Transmission System
EQUITY INVESTMENTS
Reduction in Partners' Equity	$ 73

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PARTNERS' EQUITY - ATM Equity Issuance Program (Details) - USD ($)		3 Months Ended		4 Months Ended		6 Months Ended
	Jul. 29, 2016	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2016	Jun. 30, 2016	Jun. 30, 2015
Partners' Equity
Net proceeds from public offering of common units						$ 83,000,000
Common units issuance subject to rescission net						83,000,000
General Partner
Partners' Equity
Net proceeds from public offering of common units						2,000,000
Common units issuance subject to rescission net						$ 2,000,000
TC PipeLines GP, Inc. | General Partner
Partners' Equity
Ownership interest in the Partnership (as a percent)		2.00%	2.00%			2.00%	2.00%
ATM Equity Issuance Program | Common units
Partners' Equity
Units sold						1,619,631
Net proceeds from public offering of common units						$ 81,000,000
Sales agent commissions						823,000
Amended shelf registation with SEC	$ 400,000,000
Common units issuance subject to rescission net				$ 82,334,015
ATM Equity Issuance Program | TC PipeLines GP, Inc. | General Partner
Partners' Equity
Equity contribution						$ 2,000,000
ATM Equity Issuance Program | Minimum | Common units
Partners' Equity
Common units (price per unit)				$ 47.00
ATM Equity Issuance Program | Maximum | Common units
Partners' Equity
Common units (price per unit)				$ 54.95
Period of time for Section 5 Securities violations to be filed within					1 year

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PARTNERS' EQUITY - Class B Units (Details) - USD ($)	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Mar. 31, 2016	Jun. 30, 2016	Jun. 30, 2015
Class B units
Partners' Equity
Net income allocated to limited partners	$ 1,000,000		$ 1,000,000
Distribution declared		$ 12,000,000
Distribution paid		$ 12,000,000	12,000,000
GTN
Partners' Equity
30% of GTN's distributable cash flow			$ 21,000,000
GTN | TransCanada | Distributions | Class B units
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			$ 20,000,000
Percentage applied to GTN's distributions above threshold after March 31, 2020			25.00%
Percentage applied to GTN's distributable cash flow for the twelve month period ending December 31, 2016			30.00%
30% of GTN's distributable cash flow			$ 21,000,000	$ 0

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NET INCOME PER COMMON UNIT - General Partner Effective Interest and Allocated Incentive Distributions (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Partners' Equity
Incentive distributions allocated to the General Partner	$ 2	$ 1	$ 3	$ 1
TC PipeLines GP, Inc. | General Partner
Partners' Equity
General partner interest (as a percent)	2.00%	2.00%	2.00%	2.00%

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NET INCOME PER COMMON UNIT - Terms of Class B Unit Distributions and Determination of Net Income per Common Unit (Details) - USD ($) $ / shares in Units, shares in Millions	3 Months Ended		6 Months Ended		9 Months Ended	12 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015	Dec. 31, 2015	Dec. 31, 2016
Net income (loss) per common unit
Net income attributable to controlling interests	$ 54,000,000	$ 44,000,000	$ 127,000,000	$ 101,000,000
Net income attributable to the General Partner	(1,000,000)	(1,000,000)	(2,000,000)	(2,000,000)
Incentive distributions attributable to the General Partner	(2,000,000)	(1,000,000)	(3,000,000)	(1,000,000)
Class B units
Net income (loss) per common unit
Net income allocated to limited partners	1,000,000		1,000,000
Common units
Net income (loss) per common unit
Net income allocated to limited partners	$ 50,000,000	$ 42,000,000	$ 121,000,000	$ 98,000,000
Weighted average common units outstanding - basic (in units)	65.5	63.8	64.9	63.7
Weighted average common units outstanding - diluted (in units)	65.5	63.8	64.9	63.7
Net income per common unit - basic (in dollars per unit)	$ 0.76	$ 0.66	$ 1.86	$ 1.53
Net income per common unit - diluted (in dollars per unit)	$ 0.76	$ 0.66	$ 1.86	$ 1.53
GTN
Distributions
30% of GTN's distributable cash flow			$ 21,000,000
GTN | Class B units | TransCanada | Distributions
Distributions
Percentage applied to GTN's distributable cash flow for the twelve month period ending December 31, 2016			30.00%
Threshold of GTN's total distributable cash flows for payment to Class B units			$ 20,000,000
Prorated threshold of GTN's distributions for payment to Class B units					$ 15,000,000	$ 20,000,000
30% of GTN's distributable cash flow			$ 21,000,000	$ 0

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CASH DISTRIBUTIONS - Distributions Paid (Details) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Distributions
Incentive distribution paid to the General Partner	$ 1.0	$ 0.3	$ 2.0	$ 0.6
Common units
Distributions
Per Unit Distribution, paid (in dollars per unit)	$ 0.89	$ 0.84	$ 1.78	$ 1.68
Common units and General Partner interest combined
Distributions
Total cash distribution	$ 60.0	$ 55.0	$ 119.0	$ 110.0
TC PipeLines GP, Inc. | General Partner
Distributions
Limited Liability Company (LLC) or Limited Partnership (LP), Managing Member or General Partner, Ownership Interest	2.00%	2.00%	2.00%	2.00%

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CHANGE IN OPERATING WORKING CAPITAL - Components (Details) - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015
CHANGE IN OPERATING WORKING CAPITAL
Change in accounts receivable and other		$ 4
Change in accounts payable and accrued liabilities	$ 2	(2)
Change in accounts payable to affiliates		(5)
Change in accrued interest	1	4
Change in operating working capital	$ 3	$ 1

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CHANGE IN OPERATING WORKING CAPITAL - GTN's Carty Lateral Construction Accrual (Details) - USD ($) $ in Millions	3 Months Ended	6 Months Ended		12 Months Ended
	Mar. 31, 2016	Jun. 30, 2016	Jun. 30, 2015	Dec. 31, 2015
Non-cash items
Capital expenditures		$ 18	$ 12
GTN
Non-cash items
Accruals for capital expenditures				$ 10
Capital expenditures	$ 10

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RELATED PARTY TRANSACTIONS (Details) - USD ($) $ in Millions			3 Months Ended			4 Months Ended	6 Months Ended		12 Months Ended
	Jun. 30, 2016	Dec. 31, 2015	Jun. 30, 2016	Dec. 31, 2015	Jun. 30, 2015	May 03, 2015	Jun. 30, 2016	Jun. 30, 2015	Dec. 31, 2014	Jul. 18, 2016	Mar. 31, 2016	Jan. 01, 2016	Apr. 01, 2015
Capital and operating costs charged to the pipeline systems and amount payable
Net amounts payable	$ 5.0	$ 5.0	$ 5.0	$ 5.0			$ 5.0
Great Lakes
Capital and operating costs charged to the pipeline systems and amount payable
Interest acquired (as a percent)	46.45%		46.45%				46.45%				46.45%
Northern Border
Capital and operating costs charged to the pipeline systems and amount payable
Interest acquired (as a percent)	50.00%		50.00%				50.00%
Portland Natural Gas Transmission System
Capital and operating costs charged to the pipeline systems and amount payable
Interest acquired (as a percent)	49.90%		49.90%				49.90%			49.90%		49.90%
General Partner | Reimbursement of costs of services provided
Capital and operating costs charged to the pipeline systems and amount payable
Costs charged			$ 1.0		$ 1.0		$ 2.0	$ 1.0
TransCanada's subsidiaries | Great Lakes
Capital and operating costs charged to the pipeline systems and amount payable
Net amounts payable	$ 3.0	3.0	3.0	3.0			3.0
Net amounts (receivable)	$ (9.0)	$ (17.0)	(9.0)	(17.0)			(9.0)
Percentage of capital and operating costs charged	100.00%	100.00%
Amount included in receivables from related party	$ 9.0	$ 17.0	9.0	17.0			9.0
TransCanada's subsidiaries | Great Lakes | Capital and operating costs
Capital and operating costs charged to the pipeline systems and amount payable
Costs charged			$ 7.0		$ 8.0		$ 14.0	$ 14.0
Percentage of capital and operating costs charged			100.00%		100.00%		100.00%	100.00%
TransCanada's subsidiaries | Great Lakes | Transportation contracts
Capital and operating costs charged to the pipeline systems and amount payable
Revenues from related party			$ 23.0		$ 18.0		$ 69.0	$ 47.0
TransCanada's subsidiaries | Great Lakes | Transportation contracts | Total revenues | Customer concentration risk
Capital and operating costs charged to the pipeline systems and amount payable
Percent of total revenues			64.00%		63.00%		71.00%	62.00%
TransCanada's subsidiaries | Great Lakes | Affiliated rental revenue
Capital and operating costs charged to the pipeline systems and amount payable
Revenues from related party			$ 1.0		$ 1.0		$ 1.0	$ 1.0
TransCanada's subsidiaries | Northern Border
Capital and operating costs charged to the pipeline systems and amount payable
Net amounts payable	$ 3.0	$ 5.0	3.0	5.0			3.0
Percentage of capital and operating costs charged	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			$ 9.0		$ 9.0		$ 15.0	$ 16.0
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	$ 1.0		$ 1.0				$ 1.0
Percentage of capital and operating costs charged	100.00%
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			$ 2.0				$ 4.0
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	$ 3.0	$ 3.0	$ 3.0	3.0			$ 3.0
TransCanada's subsidiaries | GTN | Capital and operating costs
Capital and operating costs charged to the pipeline systems and amount payable
Costs charged			7.0		$ 8.0		13.0	$ 14.0
Impact on the Partnership's net income attributable to controlling interests			$ 6.0		$ 7.0		$ 11.0	$ 11.0
Percentage of capital and operating costs charged			100.00%		100.00%		100.00%	100.00%
TransCanada's subsidiaries | Bison
Capital and operating costs charged to the pipeline systems and amount payable
Net amounts payable	1.0		$ 1.0				$ 1.0
TransCanada's subsidiaries | Bison | Capital and operating costs
Capital and operating costs charged to the pipeline systems and amount payable
Costs charged			1.0		$ 1.0			$ 2.0
Impact on the Partnership's net income attributable to controlling interests			1.0		1.0		2.0	2.0
Net proceeds from the sale of excess pipe to an affiliate							1.0
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			1.0		2.0		2.0	3.0
Impact on the Partnership's net income attributable to controlling interests			1.0		1.0		2.0	2.0
TransCanada's subsidiaries | Tuscarora Gas Transmission Company
Capital and operating costs charged to the pipeline systems and amount payable
Net amounts payable	$ 1.0	$ 1.0	1.0	1.0			1.0
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			1.0		1.0		2.0	2.0
Impact on the Partnership's net income attributable to controlling interests			1.0		1.0		2.0	2.0
TransCanada's subsidiaries | Great Lakes
Capital and operating costs charged to the pipeline systems and amount payable
Revenue from TransCanada and its affiliates included in the Partnership's equity earnings			10.0		8.0		32.0	22.0
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			3.0		3.0		6.0	6.0
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			3.0		$ 4.0		6.0	$ 7.0
TransCanada's subsidiaries | Portland Natural Gas Transmission System | Capital and operating costs
Capital and operating costs charged to the pipeline systems and amount payable
Impact on the Partnership's net income attributable to controlling interests			$ 1.0				$ 2.0
Former parent, TransCanada subsidiaries | Transaction between entities under common control | GTN
Capital and operating costs charged to the pipeline systems and amount payable
Interest acquired (as a percent)	30.00%		30.00%				30.00%						30.00%
ANR Pipeline Company | Great Lakes | Firm service between Michigan and Wisconsin
Capital and operating costs charged to the pipeline systems and amount payable
Deferred revenue related to services performed						$ 14.0			$ 9.0
Deferred revenue recognized				$ 23.0

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RELATED PARTY TRANSACTIONS - Distribution from Affiliate (Details) - USD ($) $ in Millions			6 Months Ended
	Jul. 18, 2016	Jun. 16, 2016	Jun. 30, 2016	Jan. 01, 2016
Related party transactions
Partnership distribution			$ 131
Portland Natural Gas Transmission System
Related party transactions
Ownership interest (as a percent)	49.90%		49.90%	49.90%
Distribution declared | Portland Natural Gas Transmission System
Related party transactions
Partnership distribution		$ 8
Cash Distribution Paid | Portland Natural Gas Transmission System
Related party transactions
Partnership's share of distributions declared and payable by investee	$ 4

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FAIR VALUE MEASUREMENTS - Estimated Fair Value of Debt (Details) - USD ($) $ in Millions	Jun. 30, 2016	Dec. 31, 2015
Fair Value | Level 2
Financial Instruments
Fair value of debt	$ 1,994	$ 1,873

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FAIR VALUE MEASUREMENTS - Interest Rate Swaps (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015	Dec. 31, 2015
Interest rate derivatives
Goodwill	$ 130		$ 130		$ 130
Tuscarora Gas Transmission Company
Interest rate derivatives
Goodwill	$ 82		$ 82
Interest rate swaps | Term loan | TC PipeLines, LP 2013 Term Loan Facility due 2018
Interest rate derivatives
Weighted average fixed interest rate (as a percent)	2.31%		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	$ 1	$ 0	$ 3	$ 1
Hedges of cash flows | Interest rate swaps | Financial charges and other.
Interest rate derivatives
Net realized loss related to the interest rate swaps	1	$ 0	1	$ 1
Designated as hedge | Interest rate swaps | Recurring fair value measurement | Level 2
Interest rate derivatives
Fair value of derivatives, gross	5		5		1
Fair value of derivatives, net	$ 5		$ 5		$ 1

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ACCOUNTS RECEIVABLE AND OTHER (Details) - USD ($) $ in Millions	Jun. 30, 2016	Dec. 31, 2015
ACCOUNTS RECEIVABLE AND OTHER
Trade accounts receivable, net of allowance of nil	$ 30	$ 31
Other	5	4
Accounts receivable and other	35	35
Trade accounts receivable, allowance	$ 0	$ 0

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FINANCIAL CHARGES AND OTHER (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
FINANCIAL CHARGES AND OTHER
Interest Expense	$ 16	$ 16	$ 33	$ 29
Net realized loss related to the interest rate swaps	1		1	1
Other Income	(1)		(1)	(1)
Financial charges and other	$ 16	$ 16	$ 33	$ 29

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CONTINGENCIES (Details) - USD ($) $ in Millions	Sep. 16, 2015	Apr. 01, 2015	Oct. 29, 2009
Former parent, TransCanada subsidiaries | Transaction between entities under common control | GTN | Partnership interest | Class B units
Contingencies
Equity issuance		$ 95.0
Great Lakes v. Essar Steel Minnesota LLC, et al. | Great Lakes | Essar
Contingencies
Recovery sought			$ 33.0
Judgement awarded	$ 32.9

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GOODWILL AND REGULATORY (Details) - USD ($) $ in Millions	Aug. 01, 2016	Jun. 30, 2016	Dec. 31, 2015
Goodwill and Regulatory Matters
Goodwill		$ 130	$ 130
Tuscarora Gas Transmission Company
Goodwill and Regulatory Matters
Goodwill		82
Tuscarora Gas Transmission Company | Tuscarora Settlement | FERC
Goodwill and Regulatory Matters
Decrease of system-wide unit rate (as a percent)	16.00%
Terms of the settlement	Unless superseded by a subsequent rate case or settlement, this rate will remain in effect for three years, after which time the unit rate will decrease an additional seven percent for an additional three years.
Goodwill		$ 82
Tuscarora Gas Transmission Company | Tuscarora Settlement | FERC | Maximum
Goodwill and Regulatory Matters
Estimated Fair value over carrying value (as a percent)		10.00%
Tuscarora Gas Transmission Company | Tuscarora Settlement | FERC | Minimum
Goodwill and Regulatory Matters
Term to establish new rates	6 years

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VARIABLE INTEREST ENTITIES - Consolidated VIEs (Details) - USD ($) $ in Millions	Jun. 30, 2016	Dec. 31, 2015
ASSETS (LIABILITIES)
Accounts receivable and other	$ 35	$ 35
Inventories	7	7
Equity investments	1,047	965
Plant, property and equipment	1,913	1,949
Other assets		1
Accounts payable and accrued liabilities	(26)	(32)
Accounts payable to affiliates	(5)	(5)
Accrued interest	(9)	(8)
Current portion of long-term debt	(15)	(14)
Long-term debt	(1,938)	(1,889)
Other liabilities	(29)	(27)
Consolidated VIEs | Restricted VIEs
ASSETS (LIABILITIES)
Accounts receivable and other	21	25
Inventories	6	6
Equity investments	1,047	965
Plant, property and equipment	859	872
Other assets	2	2
Accounts payable and accrued liabilities	(18)	(26)
Accounts payable to affiliates	(18)	(6)
Accrued interest	(1)	(1)
Current portion of long-term debt	(15)	(14)
Long-term debt	(325)	(326)
Other liabilities	$ (25)	$ (24)

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SUBSEQUENT EVENTS - Quarter Distribution per Common Unit (Details)	Jul. 21, 2016 $ / shares
Subsequent event | Common units
Distributions
Distribution (in dollars per unit)	$ 0.94

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SUBSEQUENT EVENTS - Unconsolidated Affiliate Distributions (Details) - USD ($) $ / shares in Units, $ in Millions						3 Months Ended		6 Months Ended
	Aug. 01, 2016	Jul. 29, 2016	Jul. 21, 2016	Jul. 19, 2016	Jul. 11, 2016	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015	Mar. 31, 2016
Subsequent events
Partnership distribution								$ 131.0
Distribution Made to General Partner, Incentive Cash Distributions Paid						$ 1.0	$ 0.3	2.0	$ 0.6
General Partner IDRs paid						$ 1.0	$ 0.3	$ 2.0	$ 0.6
Northern Border
Subsequent events
Ownership interest (as a percent)						50.00%		50.00%
Great Lakes
Subsequent events
Ownership interest (as a percent)						46.45%		46.45%		46.45%
Subsequent event | Distribution declared
Subsequent events
Distribution Made to General Partner, Incentive Cash Distributions Paid			$ 2.0
General Partner IDRs paid			$ 2.0
Increase to Partnership's quarterly distribution (per unit)			$ 0.05
Subsequent event | Distribution declared | Northern Border
Subsequent events
Partnership distribution					$ 13.0
Subsequent event | Distribution declared | Great Lakes
Subsequent events
Partnership distribution				$ 12.0
Subsequent event | Cash Distribution Paid | Northern Border
Subsequent events
Partnership's share of distributions		$ 6.5
Subsequent event | Cash Distribution Paid | Great Lakes
Subsequent events
Partnership's share of distributions	$ 6.0