Edgar Filing: TC PIPELINES LP

form10qlpq2080211.htm

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, 2011

¨ 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: 000-26091

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)

13710 FNB Parkway, Suite 300 Omaha, Nebraska	68154-5200
(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 ¨

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 ¨

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 ¨
Non-accelerated filer ¨ (Do not check if a smaller reporting company)	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 ¨ No x

As at August 2, 2011, there were 53,472,766 of the registrant’s common units outstanding.

TABLE OF CONTENTS

Page No.

GLOSSARY		3

PART I	FINANCIAL INFORMATION

Item 1.	Financial Statements	6

	Consolidated Statement of Income – Three and six months ended June 30, 2011 and 2010	6
	Consolidated Statement of Comprehensive Income – Three and six months ended June 30, 2011 and 2010	6
	Consolidated Balance Sheet – June 30, 2011 and December 31, 2010	7
	Consolidated Statement of Cash Flows – Six months ended June 30, 2011 and 2010	8
	Consolidated Statement of Changes in Partners’ Equity – Six months ended June 30, 2011	9
	Notes to Consolidated Financial Statements	10

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	19

Item 3.	Quantitative and Qualitative Disclosures about Market Risk	33

Item 4.	Controls and Procedures	35

PART II	OTHER INFORMATION

Item 1.	Legal Proceedings	36

Item 1A.	Risk Factors	36

Item 5	Other Information	37

Item 6.	Exhibits	38

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

GLOSSARY

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

Acquisitions	The acquisition from TAIL and TC Continental of a 25 percent interest in GTN and a 25 percent interest in Bison, respectively
Bison	Bison Pipeline LLC
Complainants	NV Energy and the PUCN, collectively
Design capacity	Pipeline capacity available to transport natural gas based on system facilities and design conditions
FERC	Federal Energy Regulatory Commission
GAAP	U.S. generally accepted accounting principles
Gas exiting the WCSB	Net of the supply of and demand for natural gas in the WCSB region that is available for transportation to downstream markets; where supply represents WCSB production adjusted for injections into and withdrawals from WCSB storage
General Partner	TC PipeLines GP, Inc.
Great Lakes	Great Lakes Gas Transmission Limited Partnership
GTN	Gas Transmission Northwest LLC
LIBOR	London Interbank Offered Rate
May 24 Order	FERC order initiating an investigation into Tuscarora’s rates pursuant to Section 5 of the NGA
MDth/d	Thousand dekatherms per day
MMcf/d	Million cubic feet per day
NGA	Natural Gas Act
North Baja	North Baja Pipeline, LLC
Northern Border	Northern Border Pipeline Company
NV Energy	Sierra Pacific Power Company d/b/a NV Energy
Other Pipes	North Baja and Tuscarora
Our pipeline systems	Great Lakes, Northern Border, GTN, Bison, North Baja and Tuscarora
Partnership	TC PipeLines, LP and its subsidiaries
Partnership Agreement	Second Amended and Restated Agreement of Limited Partnership
PUCN	Public Utilities Commission of Nevada
RREI	Rolls Royce Energy Systems, Inc.
SEC	Securities and Exchange Commission
Senior Credit Facility	TC PipeLines’ revolving credit and term loan agreement
TC Continental	TC Continental Pipeline Holdings Inc.
TransCanada	TransCanada Corporation and its subsidiaries
TAIL	TransCanada American Investments Ltd.
TCPL	TransCanada PipeLines Limited
Tuscarora	Tuscarora Gas Transmission Company
U.S.	United States of America
WCSB	Western Canada Sedimentary Basin
Yuma Lateral	An expansion of the North Baja pipeline from the Mexico/Arizona border to Yuma, Arizona

FORWARD-LOOKING STATEMENTS

The statements in this report that are not historical information, including statements concerning plans and objectives of management for future operations, economic performance or related assumptions, are 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 (Exchange Act). Forward-looking statements may include words such as “anticipate,” “estimate,” “expect,” “project,” “intend,” “plan,” “believe,” “forecast” and other words and terms of similar meaning. The absence of these words, however, does not mean that the statements are not forward-looking.

These statements reflect our current views with respect to future events, based on what we believe are reasonable assumptions. We use “our pipeline systems” when referring to the Partnership’s ownership interests in Great Lakes Gas Transmission Limited Partnership (Great Lakes), Northern Border Pipeline Company (Northern Border), Gas Transmission Northwest LLC (GTN), Bison Pipeline LLC (Bison), North Baja Pipeline, LLC (North Baja) and Tuscarora Gas Transmission Company (Tuscarora). Certain factors that could cause actual results to differ materially from those contemplated in the forward-looking statements include:

●	the ability of Great Lakes and Northern Border to continue to make cash distributions and North Baja and Tuscarora to continue to generate positive operating cash flows at their current levels;
●	the ability of GTN and Bison to make cash distributions at expected levels;
●	the impact of unsold capacity on Great Lakes, Northern Border and GTN being greater or less than expected;
●	the ability to restart the Bison Pipeline system without significant delay;
●	the competitive conditions in our industry and the ability of our pipeline systems to market pipeline capacity on favorable terms, which is affected by, among other factors: ○ future demand for and prices of natural gas; ○ level of natural gas basis differentials; ○ competitive conditions in the overall natural gas and electricity markets; ○ availability and relative cost of supplies of Canadian and United States (U.S.) natural gas, including the shale gas resources such as the Horn River and Montney deposits in Western Canada and the Bakken formation in the Midwestern U.S., along with Western Canada Sedimentary Basin (WCSB), U.S. Rockies, Mid-Continent and Marcellus natural gas developments; ○ competitive developments by U.S. and Canadian natural gas transmission companies; ○ the availability of additional storage capacity and current storage levels; ○ the level of liquefied natural gas imports; ○ weather conditions that impact supply and demand; and ○ the ability of shippers to meet creditworthiness requirements;
●	the impact of current and future laws, rulings and governmental regulations, particularly Federal Energy Regulatory Commission (FERC) regulations and rate proceedings, including the FERC’s investigation of Tuscarora’s rates, and proposed and pending legislation by Congress and proposed and pending regulations by the U.S. Environmental Protection Agency (EPA) and other regulators in the U.S. on us and our pipeline systems;
●	the changes in relative cost structures of natural gas producing basins, such as changes in royalty programs, that may prejudice the development of the WCSB;
●	decisions by other pipeline companies to advance projects that will affect our pipeline systems;
●	the regulatory, financing, construction and operational risks related to construction and operation of interstate natural gas pipelines and additional facilities;
●	our ability and that of our pipeline systems to identify and/or consummate expansion projects and other accretive growth opportunities;
●	the performance of contractual obligations by customers of our pipeline systems;
●	the imposition of entity level taxation by states on partnerships;
●	the operating hazards, natural disasters, weather-related delays, casualty losses and other matters beyond our control;
●	our ability to control operating costs, including the operations of our pipeline systems; and
●	the general economic conditions in North America, which impact: ○ the debt and equity capital markets and our ability to access these markets at reasonable costs; ○ the overall demand for natural gas by end users; and ○ natural gas prices.

Other factors described elsewhere in this document, or factors that are unknown or unpredictable, could also have material adverse effects on future results. Please also read Item 1A. “Risk Factors” in this Form 10-Q and in our Form 10-K for the year ended December 31, 2010. All forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by these factors. These forward-looking statements and information are made only as of the date of the filing of this report and except as required by applicable law, we undertake no obligation to update these forward-looking statements and information to reflect new information, subsequent events or otherwise.

PART I – FINANCIAL INFORMATION

Item 1. Financial Statements

TC PIPELINES, LP

CONSOLIDATED STATEMENT OF INCOME

(unaudited)	Three months ended June 30,						Six months ended June 30,
(millions of dollars except per common unit amounts)	2011			2010			2011			2010

Equity earnings from unconsolidated affiliates (a) (Note 3)		37.5			25.3			76.1			56.2
Transmission revenues		17.6			17.0			34.9			34.4
Operating expenses		(3.4	)		(3.3	)		(6.5	)		(6.7	)
General and administrative		(4.8	)		(1.1	)		(6.6	)		(2.4	)
Depreciation		(4.0	)		(3.7	)		(7.7	)		(7.4	)
Financial charges and other		(6.8	)		(6.5	)		(11.8	)		(12.7	)
Net income		36.1			27.7			78.4			61.4

Net income allocation (Note 7)
Common units		35.4			27.2			76.8			60.2
General partner		0.7			0.5			1.6			1.2
		36.1			27.7			78.4			61.4

Net income per common unit (Note 7)		$0.69			$0.59			$1.58			$1.30

Weighted average common units outstanding (millions)		50.9			46.2			48.6			46.2

Common units outstanding, end of the period (millions)		53.5			46.2			53.5			46.2

(a) Includes equity earnings from GTN and Bison from May 3, 2011, date of acquisition, to June 30, 2011.

CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME

(unaudited)	Three months ended June 30,				Six months ended June 30,
(millions of dollars)	2011		2010		2011		2010

Net income(a)		36.1		27.7		78.4		61.4
Other comprehensive income
Change associated with hedging transactions (Note 11)		3.0		3.0		6.9		4.6
Total comprehensive income		39.1		30.7		85.3		66.0

(a) Includes equity earnings from GTN and Bison from May 3, 2011, date of acquisition, to June 30, 2011.

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

TC PIPELINES, LP

CONSOLIDATED BALANCE SHEET

(unaudited)
(millions of dollars)	June 30, 2011			December 31, 2010
ASSETS
Current Assets
Cash and cash equivalents		1.8			3.6
Accounts receivable and other (Note 12)		8.5			8.7
		10.3			12.3
Investments in unconsolidated affiliates (Note 3)		1,591.8			1,194.8
Plant, property and equipment
(net of $132.0 accumulated depreciation; 2010 – $133.3)		305.4			312.6
Goodwill		130.2			130.2
Other assets		2.5			0.6
		2,040.2			1,650.5

LIABILITIES AND PARTNERS' EQUITY
Current Liabilities
Accounts payable and accrued liabilities		5.2			7.7
Accrued interest		1.5			1.3
Current portion of long-term debt (Note 5)		300.8			483.8
Current portion of fair value of derivative contracts (Note 11)		6.9			13.8
		314.4			506.6
Long-term debt (Note 5)		393.1			30.1
Other liabilities		1.3			1.3
		708.8			538.0
Partners' Equity (Note 6)
Common units		1,312.0			1,104.2
General partner		27.7			23.5
Accumulated other comprehensive loss		(8.3	)		(15.2	)
		1,331.4			1,112.5
		2,040.2			1,650.5

Subsequent events (Note 14)

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

TC PIPELINES, LP

CONSOLIDATED STATEMENT OF CASH FLOWS

(unaudited)	Six months ended June 30,
(millions of dollars)	2011			2010

CASH GENERATED FROM OPERATIONS
Net income		78.4			61.4
Depreciation		7.7			7.4
Amortization of other assets		1.6			0.2
Equity earnings in excess of cumulative distributions:
GTN(a)		(2.4	)		-
Bison(a)		(1.9	)		-
Increase in long-term liabilities		-			0.1
Equity allowance for funds used during construction		-			(0.2	)
(Increase)/decrease in operating working capital (Note 9)		(2.1	)		1.8
		81.3			70.7

INVESTING ACTIVITIES
Cumulative distributions in excess of equity earnings:
Great Lakes		3.3			4.3
Northern Border		15.5			11.1
Investment in Great Lakes (Note 3)		(4.3	)		(4.6	)
Acquisition of GTN and Bison (Note 4)		(538.1	)		-
Capital expenditures		(2.8	)		(8.8	)
Other assets		(3.5	)		-
		(529.9	)		2.0

FINANCING ACTIVITIES
Distributions paid (Note 8)		(70.8	)		(68.9	)
Equity issuance, net (Notes 4 & 6)		337.6			-
Long-term debt issued (Note 5)		541.4			12.0
Long-term debt repaid (Note 5)		(361.4	)		(16.2	)
		446.8			(73.1	)

Decrease in cash and cash equivalents		(1.8	)		(0.4	)
Cash and cash equivalents, beginning of period		3.6			3.1

Cash and cash equivalents, end of period		1.8			2.7

Interest payments made		2.8			4.2

(a) Represents equity earnings from May 3, 2011, date of acquisition, to June 30, 2011.

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

TC PIPELINES, LP

CONSOLIDATED STATEMENT OF CHANGES IN PARTNERS’ EQUITY

(unaudited)	Common Units					General Partner			Accumulated Other Comprehensive (Loss)/Income(a)			Partners' Equity
	(millions		(millions			(millions			(millions			(millions		(millions
	of units)		of dollars)			of dollars)			of dollars)			of units)		of dollars)

Partners' equity at December 31, 2010		46.2		1,104.2			23.5			(15.2	)		46.2		1,112.5
Net income(b)		-		76.8			1.6			-			-		78.4
Equity issuance, net (Notes 4 and 6)		7.3		330.9			6.7			-			7.3		337.6
Distributions paid		-		(69.4	)		(1.4	)		-			-		(70.8	)
Excess purchase price over net acquired assets (Note 4)		-		(130.5	)		(2.7	)		-			-		(133.2	)
Other comprehensive income		-		-			-			6.9			-		6.9
Partners' equity at June 30, 2011		53.5		1,312.0			27.7			(8.3	)		53.5		1,331.4

(a) The Partnership uses derivatives to assist in managing its exposure to interest rate risk. Based on interest rates at June 30, 2011, the amount of losses related to cash flow hedges reported in accumulated other comprehensive income that will be reclassified to net income in the next 12 months is $6.9 million, which will be offset by a reduction to interest expense of a similar amount.

(b) Includes equity earnings from GTN and Bison from May 3, 2011, date of acquisition, to June 30, 2011.

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

TC PIPELINES, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1 ORGANIZATION

TC PipeLines, LP and its subsidiaries are collectively referred to herein as “the Partnership.” In this report, references to “we,” “us” or “our” refer to the Partnership.

The Partnership owns the following interests in natural gas pipeline systems:

·	a 46.45 percent general partner interest in Great Lakes Gas Transmission Partnership (Great Lakes);

·	a 50 percent general partner interest in Northern Border Pipeline Company (Northern Border);

·	a 25 percent interest in Gas Transmission Northwest LLC (GTN), a Delaware limited liability company. GTN owns a 1,353-mile pipeline that transports natural gas from the British Columbia, Canada/Idaho border to a point at the Oregon/California border;

·	a 25 percent interest in Bison Pipeline LLC (Bison), a Delaware limited liability company. Bison owns a 303-mile pipeline that transports natural gas from the Powder River Basin in Wyoming to Northern Border’s pipeline system in North Dakota;

·	a 100 percent interest in North Baja Pipeline, LLC (North Baja); and

·	a 100 percent interest in Tuscarora Gas Transmission Company (Tuscarora).

The Partnership is managed by its General Partner, TC PipeLines GP, Inc. In addition to its aggregate two percent general partner interest in the Partnership, the General Partner owns 5,797,106 common units, together with its general partner interest, representing an effective 12.6 percent interest in the Partnership at June 30, 2011. TransCanada Corporation also indirectly holds an additional 11,287,725 common units representing a 20.7 percent limited partner interest in the Partnership at June 30, 2011.

NOTE 2 SIGNIFICANT ACCOUNTING POLICIES

(a) Basis of Presentation

The results of operations for the three and six months ended June 30, 2011 and 2010 are not necessarily indicative of the results that may be expected for a full fiscal year. The unaudited interim 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, 2010. Our significant accounting policies are consistent with those disclosed in Note 2 of the financial statements in our Annual Report on Form 10-K for the year ended December 31, 2010.

(b) Acquisitions

On May 3, 2011, the Partnership acquired a 25 percent interest in GTN and a 25 percent interest in Bison from subsidiaries of TransCanada Corporation (the Acquisitions). TransCanada Corporation and its subsidiaries are herein collectively referred to as “TransCanada.” The Acquisitions were accounted for as transactions between entities under common control, whereby the equity investments in GTN and Bison were recorded at TransCanada’s carrying values. See Note 4 for additional disclosure regarding the Acquisitions.

The preparation of financial statements in conformity with United States of America (U.S.) generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities as at 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. In the opinion of management, these consolidated financial statements have been properly prepared within reasonable limits of materiality and include all adjustments (consisting of normal recurring accruals) necessary for a fair presentation of the financial results for the interim periods presented.

NOTE 3 INVESTMENTS IN UNCONSOLIDATED AFFILIATES

Great Lakes, Northern Border, GTN and Bison are all regulated by the Federal Energy Regulatory Commission (FERC) and are operated by TransCanada. We use the equity method of accounting for our interests in our equity investees.

			Equity Earnings from Unconsolidated Affiliates								Investment in Unconsolidated Affiliates
(unaudited)			Three months ended June 30,				Six months ended June 30,				June 30,		December 31,
(millions of dollars)			2011		2010		2011		2010		2011		2010
Great Lakes	46.45	%		17.0		13.1		35.0		29.4		691.0		690.0
Northern Border(a)	50	%		16.2		12.2		36.8		26.8		489.3		504.8
GTN(b)	25	%		2.4		-		2.4		-		248.3		-
Bison(b)	25	%		1.9		-		1.9		-		163.2		-
				37.5		25.3		76.1		56.2		1,591.8		1,194.8

(a) The Partnership owns a 50 percent general partner interest in Northern Border. Equity income 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 acquisition in April 2006.

(b) Represents equity earnings from May 3, 2011, date of acquisition, to June 30, 2011.

Great Lakes

The Partnership made an equity contribution to Great Lakes of $4.2 million in the first quarter of 2011. This amount represents the Partnership’s 46.45 percent share of a $9.0 million cash call from Great Lakes to make a scheduled debt repayment. The Partnership expects to make an additional equity contribution of $4.6 million to Great Lakes in the fourth quarter of 2011. This represents the Partnership’s 46.45 percent share of an expected $10.0 million cash call from Great Lakes to make a scheduled debt repayment.

The Partnership recorded no undistributed earnings from Great Lakes for the six months ended June 30, 2011 and 2010.

The summarized financial information for Great Lakes is as follows:

(unaudited)	Three months ended June 30,						Six months ended June 30,
(millions of dollars)	2011			2010			2011			2010
Transmission revenues		63.3			62.9			133.5			135.8
Operating expenses		(15.7	)		(15.6	)		(30.0	)		(29.8	)
Depreciation and amortization		(8.0	)		(10.1	)		(16.1	)		(24.4	)
Financial charges and other		(7.5	)		(7.7	)		(15.1	)		(15.6	)
Michigan business tax		4.6			(1.2	)		3.0			(2.7	)
Net income		36.7			28.3			75.3			63.3

(unaudited)	June 30,		December 31,
(millions of dollars)	2011		2010
Assets
Current assets		82.7		83.7
Plant, property and equipment, net		832.0		846.9
Other assets		0.6		0.6
		915.3		931.2
Liabilities and Partners' Equity
Current liabilities		31.4		34.9
Deferred credits		0.4		5.6
Long-term debt, including current maturities		383.0		392.0
Partners' equity		500.5		498.7
		915.3		931.2

Northern Border

Northern Border’s distribution policy adopted in 2006 defines minimum equity to total capitalization to be used by its Management Committee to establish the timing and amount of required equity contributions. In accordance with this policy, the Partnership made a required equity contribution of $49.8 million to meet minimum equity to total capitalization requirements on July 27, 2011 and expects to make an equity contribution of approximately $5.5 million in fourth quarter 2011 to fund capital expenditures related to the Princeton Lateral Project.

The Partnership recorded no undistributed earnings from Northern Border for the six months ended June 30, 2011 and 2010.

The summarized financial information for Northern Border is as follows:

(unaudited)	Three months ended June 30,						Six months ended June 30,
(millions of dollars)	2011			2010			2011			2010
Transmission revenues		72.3			65.8			152.5			134.9
Operating expenses		(18.4	)		(19.7	)		(35.9	)		(37.7	)
Depreciation and amortization		(15.4	)		(15.4	)		(30.7	)		(30.8	)
Financial charges and other		(5.7	)		(6.0	)		(11.4	)		(12.0	)
Net income		32.8			24.7			74.5			54.4

(unaudited)	June 30,		December 31,
(millions of dollars)	2011		2010
Assets
Current assets		39.4		47.3
Plant, property and equipment, net		1,276.5		1,294.8
Other assets		22.6		22.9
		1,338.5		1,365.0
Liabilities and Partners' Equity
Current liabilities		42.0		46.7
Deferred credits		10.9		9.7
Long-term debt, including current maturities		547.6		540.6
Partners' Equity		738.0		768.0
		1,338.5		1,365.0

GTN and Bison

On May 3, 2011, the Partnership acquired a 25 percent interest in GTN and a 25 percent interest in Bison from subsidiaries of TransCanada. The Acquisitions were accounted for as transactions between entities under common control, whereby the equity investments in GTN and Bison were recorded at TransCanada’s carrying values. See Note 4 for additional disclosure regarding the Acquisitions.

The Partnership recorded undistributed earnings of $2.4 million and $1.9 million from GTN and Bison, respectively, from May 3, 2011, date of acquisition, to June 30, 2011.

NOTE 4 ACQUISITIONS

GTN and Bison Equity Investment Acquisitions

On May 3, 2011, the Partnership acquired a 25 percent interest in GTN and a 25 percent interest in Bison from subsidiaries of TransCanada for a total transaction value of $605.0 million, subject to certain closing adjustments. Both GTN and Bison are Delaware limited liability companies. The GTN pipeline system extends from an interconnection near Kingsgate, British Columbia, Canada at the Canadian border to a point near Malin, Oregon at the California border. The Bison pipeline system extends from the Powder River Basin near Gillette, Wyoming to Northern Border’s pipeline system in Morton County, North Dakota. GTN and Bison are both regulated by the FERC, and they are operated by a subsidiary of TransCanada.

The purchase price of $405.0 million for the interest in GTN less $81.3 million, which reflected 25 percent of GTN’s outstanding debt at the time of the acquisition, and $200.0 million for the interest in Bison less a $9.1 million future capital commitment to complete the Bison pipeline, was financed through a combination of (i) issuance of 7,245,000 common units to the public at $47.58 per common unit for net proceeds of $330.9 million, (ii) draw of $61.0 million on the Partnership's committed $400.0 million bridge loan facility, (iii) draw of $125.0 million on the Partnership's then existing $250.0 million senior revolving credit facility, (iv) capital contribution from the General Partner of $6.7 million, which was required to maintain the General Partner’s effective two percent general partner interest in the Partnership, and (v) approximately $14.5 million of cash on hand. In addition, the Partnership paid $23.5 million on closing, subject to certain post-closing adjustments, resulting in total cash paid of $538.1 million.

The Acquisitions were accounted for as transactions between entities under common control, whereby the equity investments in both GTN and Bison were recorded at TransCanada’s carrying values. As the fair market value paid for the GTN and Bison interests was greater than the recorded equity investments of GTN and Bison, the total excess purchase price paid of $130.9 million was recorded as a reduction to Partners’ Equity.

Yuma Lateral Asset Acquisition

Pursuant to an amendment to the acquisition agreement between the Partnership and TransCanada relating to the Partnership’s acquisition of North Baja, the Partnership agreed to make an additional payment of up to $2.4 million to TransCanada in the event that TransCanada secured additional contracts for transportation service before December 31, 2010. TransCanada secured an additional contract in July 2010 and, as a result, the Partnership paid $2.4 million to TransCanada on March 25, 2011 when the facilities associated with the additional contract were completed.

NOTE 5 CREDIT FACILITIES AND LONG-TERM DEBT

(unaudited)	June 30,		December 31,
(millions of dollars)	2011		2010

Senior Credit Facility due 2011 and 2016		314.0		483.0
4.65% Senior Notes due 2021		349.4		-
6.89% Series C Senior Notes due 2012		3.5		3.9
3.82% Series D Senior Notes due 2017		27.0		27.0
		693.9		513.9
Less: current portion of long-term debt		300.8		483.8
		393.1		30.1

On June 30, 2011, the Partnership’s senior credit facility consisted of a $300.0 million senior term loan and a $250.0 million senior revolving credit facility, maturing December 2011 (Senior Credit Facility). On June 17, 2011, $175.0 million was repaid on the senior term loan and at June 30, 2011, $300.0 million remained outstanding under the senior term loan (December 31, 2010 – $475 million). At June 30, 2011, there was $14.0 million drawn under the senior revolving credit facility (December 31, 2010 – $8.0 million). The interest rate on the Senior Credit Facility averaged 0.9 percent for the three and six months ended June 30, 2011 (2010 – 0.9 percent). After hedging activity, the interest rate incurred on the Senior Credit Facility averaged 3.5 percent and 3.7 percent for the three and six months ended June 30, 2011 (2010 – 4.2 percent and 4.2 percent). Prior to hedging activities, the interest rate was 0.6 percent at June 30, 2011 (December 31, 2010 – 0.8 percent). On July 13, 2011, the Partnership closed an amendment to its Senior Credit Facility increasing the revolving credit facility to $500.0 million with a London Interbank Offered Rate (LIBOR)-based interest rate plus a margin, and extending the maturity date of the senior revolving credit facility to July 2016. The Partnership’s $300.0 million senior term loan continues to mature in December 2011.

On June 17, 2011, the Partnership closed a $350.0 million public debt offering of 10-year, senior unsecured notes with an interest rate of 4.65 percent. Proceeds were used to repay funds borrowed under the Partnership’s bridge loan facility and to partially repay borrowings under our existing Senior Credit Facility. The senior notes mature June 15, 2021. The indenture for the notes contains customary investment grade covenants.

On May 3, 2011, the Partnership entered into an agreement with SunTrust Robinson Humphrey, Inc., as Arranger, for a 364-day senior unsecured bridge facility for up to $400.0 million to fund the Acquisitions. Borrowings under the bridge facility bore interest based, at the Partnership’s election, on the LIBOR or the prime rate plus, in either case, an applicable margin. On May 3, 2011, the Partnership drew $61.0 million to partially fund the Acquisitions. Please see Note 4 for more details on the Acquisitions. On June 17, 2011, the Partnership repaid the $61.0 million draw, and the bridge facility was cancelled. The interest rate incurred on the bridge facility was 1.7 percent.

At June 30, 2011, the Partnership was in compliance with its financial covenants, in addition to the other covenants, which include restrictions on entering into mergers, consolidations and sales of assets, granting liens, material amendments to the Partnership Agreement, incurring additional debt and distributions to unitholders.

The principal repayments required on our long-term debt as at June 30, 2011 were as follows:

(unaudited)
(millions of dollars)
2011			300.4
2012			3.1
2013			3.5
2014			3.6
2015			3.7
Thereafter			379.6
			693.9

NOTE 6 PARTNERS’ EQUITY

On May 3, 2011, the Partnership completed a public offering of 7,245,000 common units at $47.58 per common unit for gross proceeds of $344.7 million and net proceeds of $330.9 after unit issuance costs. The General Partner maintained its effective two percent general partner interest in the Partnership by contributing $6.7 million to the Partnership in connection with the offering. See Note 4 for additional information regarding the equity issuance in connection with the Acquisitions.

At June 30, 2011, Partners’ equity included 53,472,766 common units (December 31, 2010 − 46,227,766 common units), representing an aggregate 98 percent limited partner interest in the Partnership (including 5,797,106 common units held by the General Partner and an additional 11,287,725 common units held indirectly by TransCanada), and an aggregate two percent general partner interest. In aggregate, the General Partner’s interests represent an effective 12.6 percent ownership in the Partnership at June 30, 2011 (December 31, 2010 − 14.3 percent).

NOTE 7 NET INCOME PER COMMON UNIT

Net income per common unit is computed by dividing net income, after deduction of the General Partner’s allocation, by the weighted average number of common units outstanding. The General Partner’s allocation is equal to an amount based upon its 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.

Net income per common unit was determined as follows:

(unaudited)	Three months ended June 30,						Six months ended June 30,
(millions of dollars except per common unit amounts)	2011			2010			2011			2010
Net income(a)		36.1			27.7			78.4			61.4
Net income allocated to General Partner:
General Partner interest		(0.7	)		(0.5	)		(1.6	)		(1.2	)
Incentive distribution income allocation		-			-			-			-
		(0.7	)		(0.5	)		(1.6	)		(1.2	)
Net income allocable to common units		35.4			27.2			76.8			60.2
Weighted average common units outstanding (millions)		50.9			46.2			48.6			46.2
Net income per common unit		$0.69			$0.59			$1.58			$1.30

(a) Includes equity earnings from GTN and Bison from May 3, 2011, date of acquisition, to June 30, 2011.

NOTE 8 CASH DISTRIBUTIONS

For the three and six months ended June 30, 2011, the Partnership distributed $0.75 and $1.50 per common unit (2010 – $0.73 and $1.46 per common unit). The distributions paid for the three and six months ended June 30, 2011 and 2010 included no incentive distributions to the General Partner.

NOTE 9 CHANGE IN WORKING CAPITAL

(unaudited)	Six months ended June 30,
(millions of dollars)	2011			2010

Decrease in accounts receivable and other		0.2			1.7
Decrease in accounts payable and accrued liabilities		(2.5	)		-
Increase in accrued interest		0.2			0.1
(Increase)/decrease in operating working capital		(2.1	)		1.8

NOTE 10 RELATED PARTY TRANSACTIONS

The Partnership does not have any employees. The management and operating functions are provided by the General Partner. The General Partner does not receive a management fee in connection with its management of the Partnership. The Partnership reimburses the General Partner for all costs of services provided, including the costs of employee, officer and director compensation and benefits, and all other expenses necessary or appropriate to the conduct of the business of, and allocable to, the Partnership. Such costs include (i) overhead costs (such as office space and equipment) and (ii) out-of-pocket expenses related to the provision of such services. The Partnership Agreement provides that the General Partner will determine the costs that are allocable to the Partnership in any reasonable manner determined by the General Partner in its sole discretion. Total costs charged to the Partnership by the General Partner were $0.6 million and $1.2 million for the three and six months ended June 30, 2011 (2010 – $0.5 million and $1.0 million).

As operator, TransCanada’s subsidiaries provide capital and operating services to Great Lakes, Northern Border, GTN, Bison, North Baja and Tuscarora (together, “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, 2011 and 2010 by TransCanada’s subsidiaries, and amounts payable to TransCanada’s subsidiaries at June 30, 2011 and December 31, 2010, are summarized in the following tables:

(unaudited)	Three months ended June 30,				Six months ended June 30,
(millions of dollars)	2011		2010		2011		2010
Capital and operating costs charged by TransCanada's subsidiaries to:
Great Lakes		7.2		8.2		15.0		15.8
Northern Border		7.5		7.7		14.2		14.6
GTN(a)		5.8		-		5.8		-
Bison(a)		2.0		-		2.0		-
North Baja		0.9		0.7		1.8		1.4
Tuscarora		1.1		0.9		2.0		1.9
Impact on the Partnership's net income:
Great Lakes		3.3		3.5		6.8		6.9
Northern Border		3.4		3.4		6.6		6.6
GTN(a)		5.5		-		5.5		-
Bison(a)		0.8		-		0.8		-
North Baja		0.9		0.7		1.6		1.4
Tuscarora		1.1		0.9		2.0		1.8

(a) Represents operations from May 3, 2011, date of acquisition, to June 30, 2011.

(unaudited)	June 30,	December 31,
(millions of dollars)	2011	2010
Amount payable to TransCanada's subsidiaries for costs charged in the period by:
Great Lakes	2.9	3.0
Northern Border	2.6	2.2
GTN(a)	0.4	-
Bison(a)	1.2	-
North Baja	0.4	0.6
Tuscarora	0.6	0.7

(a) Represents operations from May 3, 2011, date of acquisition, to June 30, 2011.

Great Lakes earns transportation revenues from TransCanada and its affiliates under contracts, some of which are provided at discounted rates and some at maximum recourse rates. The contracts have remaining terms ranging from one to seven years. Great Lakes earned $17.8 million and $42.2 million of transportation revenues under these contracts for the three and six months ended June 30, 2011 (2010 – $40.4 million and $80.4 million). These amounts represent 28.0 percent and 31.6 percent of total revenues earned by Great Lakes for the three and six months ended June 30, 2011 (2010 – 64.2 percent and 59.2 percent). Great Lakes also earned $0.3 million and $0.6 million in affiliated rental revenue for the three and six months ended June 30, 2011 (2010 − $0.2 million and $0.3 million).

Revenue from TransCanada and its affiliates of $8.4 million and $19.9 million are included in the Partnership’s equity income from Great Lakes for the three and six months ended June 30, 2011 (2010 – $18.8 million and $37.4 million). At June 30, 2011, $7.1 million was included in Great Lakes’ receivables for transportation contracts with TransCanada and its affiliates (December 31, 2010 – $11.0 million).

NOTE 11 FINANCIAL INSTRUMENTS

The carrying value of cash and cash equivalents, accounts receivable and other, accounts payable and accrued liabilities, and accrued interest approximate their fair values because of the short maturity or duration of these instruments, or because the instruments carry a variable rate of interest or a rate that approximates current rates. The fair value of the Partnership’s long-term debt is estimated by discounting the future cash flows of each instrument at estimated current borrowing rates. The estimated fair value of the Partnership’s long-term debt at June 30, 2011 is $694.8 million (December 31, 2010 – $513.9 million).

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.

The interest rate swaps and options are structured such that the cash flows match those of the Senior Credit Facility. The notional amount hedged was $300.0 million at June 30, 2011 (December 31, 2010 – $375.0 million). $300.0 million of variable-rate debt is hedged by an interest rate swap through December 12, 2011, where the weighted average fixed interest rate paid is 4.89 percent. $75.0 million of variable-rate debt was hedged by an interest rate swap through February 28, 2011, where the fixed interest rate paid was 3.86 percent. In addition to these fixed rates, the Partnership pays an applicable margin in accordance with the Senior Credit Facility agreement.

Financial instruments are recorded at fair value on a recurring basis and are categorized into one of three categories based upon a fair value hierarchy. The Partnership has classified all of its derivative financial instruments as Level II for all periods presented where the fair value is determined by using valuation techniques that refer to observable market data or estimated market prices. At June 30, 2011, the fair value of the interest rate swaps accounted for as hedges was classified as a current liability and was negative $6.9 million (December 31, 2010 – negative $13.8 million). The fair value of the interest rate swaps was calculated using the period-end interest rate for instruments with similar features; therefore, it is expected that this fair value will fluctuate over the year as interest rates change. For the three and six months ended June 30, 2011, the Partnership recorded interest expense of $3.5 million and $7.4 million on the interest rate swaps and options (2010 – $4.1 million and $8.3 million).

NOTE 12 ACCOUNTS RECEIVABLE AND OTHER

(unaudited)	June 30,		December 31,
(millions of dollars)	2011		2010
Accounts receivable		7.6		7.6
Inventory		0.8		0.7
Prepayments		0.1		0.4
		8.5		8.7

NOTE 13 ACCOUNTING PRONOUNCEMENT

In May 2011, the Financial Accounting Standards Board issued new guidance on Accounting Standards Codification 220 – Comprehensive Income which requires reclassification adjustments on the face of the financial statements from other comprehensive income to net income. This guidance is effective for interim and annual periods beginning after December 15, 2011. The amendments should be applied retrospectively and early adoption is permitted. The Partnership is in the process of assessing the impact of the new guidance to the financial statements.

NOTE 14 SUBSEQUENT EVENTS

On July 13, 2011, the Partnership closed an amendment to its Senior Credit Facility increasing the revolving credit facility to $500.0 million with a LIBOR-based interest rate plus a margin, and extending the maturity date of the senior revolving credit facility to July 2016. The Partnership’s $300.0 million senior term loan continues to mature in December 2011.

On July 19, 2011, the board of directors of our General Partner declared the Partnership’s second quarter 2011 cash distribution in the amount of $0.77 per common unit, payable on August 12, 2011 to unitholders of record as of July 31, 2011.

On July 27, 2011, the Partnership made an equity contribution to Northern Border of $49.8 million. This amount represents the Partnership’s 50.0 percent share of a $99.6 million cash call from Northern Border in order for them to meet minimum equity to total capitalization requirements.

Great Lakes declared and paid its second quarter distribution of $39.1 million on August 1, 2011, of which the Partnership received its 46.45 percent share or $18.2 million.

Northern Border declared and paid its second quarter distribution of $41.6 million on August 1, 2011, of which the Partnership received its 50 percent share or $20.8 million.

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

The following discussion and analysis updates should be read in conjunction with our Annual Report on Form 10-K for the year ended December 31, 2010 and the unaudited financial statements and notes included in Item 1. “Financial Statements” of this Quarterly Report on Form 10-Q.

PARTNERSHIP OVERVIEW

TC PipeLines, LP is a publicly traded Delaware limited partnership formed in 1998 to acquire, own and participate in the management of energy infrastructure businesses in North America. Our common units are listed on the NASDAQ Global Select Market under the symbol ‘‘TCLP.’’ Our General Partner, TC PipeLines GP, is wholly-owned by a subsidiary of TransCanada.

We have ownership interests in six natural gas interstate pipeline systems that collectively can transport approximately 8.9 billion cubic feet per day of natural gas, including partial ownership in Great Lakes, Northern Border, GTN and Bison, and full ownership in North Baja and Tuscarora. All of these pipelines are operated under agreements with subsidiaries of TransCanada. Distributions from Great Lakes and Northern Border provide the largest portion of our distributable cash flow.

Specifically, through our subsidiaries, we own:

	Ownership		System Specifications
	Percentage	Date Acquired	Length (Miles)	Capacity (MMcf/d)
Great Lakes	46.45	February 2007	2,115	2,300 (summer design) 2,500 (winter design)
Northern Border	30.00 20.00 50.00	May 1999 April 2006	1,398	2,374
GTN	25.00	May 2011	1,353	2,900
Bison	25.00	May 2011	303	407
North Baja	100.00	July 2009	86	500 (southbound design) 600 (northbound design)
Tuscarora	49.00 49.00 2.00 100.00	September 2000 December 2006 December 2007	305	230

RECENT DEVELOPMENTS

Partnership

Partnership Cash Distribution

On April 18, 2011, the board of directors of our General Partner declared the Partnership’s first quarter 2011 cash distribution in the amount of $0.75 per common unit, payable on May 13, 2011 to unitholders of record as of April 30, 2011.

Partnership Cash Contribution

On July 27, 2011, the Partnership made an equity contribution to Northern Border of $49.8 million. This amount represents the Partnership’s 50.0 percent share of a $99.6 million cash call from Northern Border in order for Northern Border to meet minimum equity to total capitalization requirements.

GTN and Bison Acquisitions

On May 3, 2011, the Partnership acquired a 25 percent interest in GTN and a 25 percent interest in Bison from subsidiaries of TransCanada for a total transaction value of $605.0 million, subject to certain closing adjustments, referred to herein as the “Acquisitions.” Both GTN and Bison are Delaware limited liability companies. The GTN pipeline system extends from an interconnection near Kingsgate, British Columbia, Canada at the Canadian border to a point near Malin, Oregon at the California border. The Bison pipeline system extends from the Powder River Basin near Gillette, Wyoming to Northern Border’s pipeline system in Morton County, North Dakota. GTN and Bison are both regulated by the FERC, and they are operated by TransCanada.

The Acquisitions were accounted for as transactions between entities under common control, whereby the equity investments in both GTN and Bison were recorded at TransCanada’s carrying values of $245.9 million and $161.3 million, respectively. As the fair market value paid for the interests in GTN and Bison was greater than the recorded equity investments in GTN and Bison, the total excess purchase price paid of $130.9 million was recorded as a reduction to Partners’ Equity.

Debt Offering and Refinance

On June 17, 2011, the Partnership closed a $350.0 million public offering of 10-year, senior unsecured notes with an interest rate of 4.65 percent maturing June 15, 2021. The net proceeds of $347.1 million were used to repay funds borrowed under our bridge loan facility and to partially repay borrowings under our then existing senior revolving and term loan credit facility. The bridge loan facility is now fully repaid and cancelled.

On July 13, 2011, the Partnership closed an amendment to its Senior Credit Facility increasing the revolving credit facility to $500.0 million with a London Interbank Offered Rate (LIBOR)-based interest rate plus a margin, and extending the maturity date of the senior revolving credit facility to July 2016. The Partnership’s $300.0 million senior term loan continues to mature in December 2011.

Our Pipeline Systems

Tuscarora Rate Proceeding

On May 24, 2011, the FERC issued an Order (May 24 Order) initiating an investigation pursuant to Section 5 of the Natural Gas Act (NGA) to determine whether Tuscarora’s existing rates for jurisdictional services are unjust and unreasonable. The FERC initiated this proceeding following a complaint filed by the Public Utilities Commission of Nevada (PUCN) and Sierra Pacific Power Company d/b/a NV Energy (NV Energy) (collectively, Complainants). On June 23, 2011, Tuscarora filed a Request for Rehearing of the Commission’s Order; on July 8, 2011, PUCN and NV Energy filed an Answer to the Rehearing Request. The May 24 Order directed that a hearing be conducted pursuant to an accelerated timeline and that an initial decision be issued by April 27, 2012. Tuscarora is currently preparing a cost and revenue study to be filed August 8, 2011, as required by the May 24 Order. We cannot predict the outcome or potential impact of these proceedings to Tuscarora at this time.

Refer to “Regulatory Environment – FERC Rate Proceedings – Tuscarora Rate Proceeding” for additional information.

Michigan Business Tax

During the years 2008 through 2011, the State of Michigan imposed a Michigan business tax on partnerships. In addition to the Michigan business tax paid during this period, Great Lakes accrued related deferred taxes for tax timing differences. Effective for calendar years after 2011, the State has passed legislation eliminating this Michigan business tax on partnerships, treating partnerships as a tax flow through entity, and will apply a more conventional income tax system taxing partners of partnerships. As a result of this change in legislation, Great Lakes has derecognized related deferred taxes that would have otherwise been recognized in futures years. Our share of the derecognized deferred tax is a $2.7 million increase to equity income.

Bison Pipeline Line Break Incident

On July 20, 2011, a line break occurred on the Bison pipeline. The pipeline was shut down and while there was no fire, injuries or property damage, the cause of the incident is still being investigated. Physical repairs to the pipeline have been completed and a restart plan has been submitted to the Pipeline and Hazardous Materials Safety Administration. The incident is not expected to have a material impact to the Partnership's net income or cash flows.

FACTORS THAT IMPACT OUR BUSINESS

Factors that may impact demand for transportation service on any one pipeline system include the availability of natural gas supply at the pipeline system’s receipt points, the ability and willingness of natural gas shippers to utilize that system over alternative pipelines, transportation rates compared to other systems and the volume of natural gas delivered to the same market from other supply sources and storage facilities.

Prevailing market conditions and dynamic competitive factors in North America will continue to impact the value of transportation on our pipeline systems and their ability to market available capacity. Our pipeline systems actively market their available capacity and work closely with customers, including natural gas producers and end users, to ensure our pipelines are offering attractive services and competitive rates.

Supply

The primary source of natural gas transported by our pipeline systems, excluding North Baja and Bison, is the WCSB. Gas exiting the WCSB is dependent upon WCSB natural gas production levels, demand for natural gas in Western Canada, and the volume of natural gas injected into natural gas storage in Western Canada. The volume of gas exiting the WCSB was essentially flat in the second quarter of 2011 compared to the second quarter of 2010. No material change in WCSB production is expected for the remainder of 2011.

Production from natural gas basins other than the WCSB represents supply competition for WCSB natural gas. U.S. natural gas production has remained strong during the second quarter of 2011 despite a gradually declining natural gas-directed rig count. Reduced levels of gas in storage compared to last year, hotter June temperatures and increased nuclear power plant outages have supported natural gas prices. However, growth in U.S. natural gas production is expected to moderate during the second half of 2011 as a result of a reduction in the natural gas-directed rig count.

Demand

Demand for natural gas in North America is impacted by a variety of factors including weather conditions, economic conditions, government regulations and the availability and price of alternative energy sources. The demand for natural gas in the second quarter of 2011 was marginally higher than demand in the second quarter of 2010. The commodity price of natural gas trended slightly higher in the second quarter of 2011 compared to the average price in the second quarter of 2010, but continues to be tempered by the ongoing impacts of increased production from U.S. shale gas developments and moderate demand for natural gas in North America related to the economic environment. We expect that demand for natural gas will improve modestly along with the economic recovery, and that most of the growth in demand will result from increased demand for natural gas-fired electric generation.

Competition

Due to excess pipeline capacity, there is currently increased competition among natural gas pipelines for the transportation of gas exiting the WCSB. Factors impacting the competition for gas exiting the WCSB include levels of firm transportation contracts on each pipeline, demand for natural gas in the regions served by each pipeline and relative transportation values on each pipeline.

Great Lakes is substantially contracted through October 2011. Northern Border’s capacity is substantially contracted though October 2012. As a result, we expect that Great Lakes and Northern Border will have limited revenue and cash flow exposure to competitive factors, through the third quarter of 2011 and the third quarter of 2012, respectively.

Contracting

The majority of our pipeline systems’ natural gas transportation services are provided through firm service transportation contracts with a reservation charge to reserve pipeline capacity, regardless of use, for the term of the contract. The revenues associated with capacity under firm service transportation contracts are not subject to fluctuations caused by changing supply and demand conditions, competition and customers. Customers with interruptible service transportation agreements may utilize available capacity on a pipeline system after firm service transportation requests are satisfied. Interruptible service customers are assessed commodity charges (or utilization fees) based on distance and the volume of natural gas they transport.

The following table provides information with respect to the revenue composition for our pipeline systems for the three and six months ended June 30, 2011:

	Revenue Composition
	Three months ended June 30, 2011									Six months ended June 30, 2011
	Firm Contracts									Firm Contracts
	Capacity Reservation Charges			Variable Usage Fees			Interruptible Contracts & Other Services			Capacity Reservation Charges			Variable Usage Fees			Interruptible Contracts & Other Services

Great Lakes		93	%		4	%		3	%		91	%		4	%		5	%

Northern Border		91	%		7	%		2	%		91	%		7	%		2	%

GTN(a)		96	%		3	%		1	%		96	%		3	%		1	%

Bison(a)		96	%		0	%		4	%		96	%		0	%		4	%

North Baja		98	%		1	%		1	%		98	%		1	%		1	%

Tuscarora		100	%		0	%		0	%		100	%		0	%		0	%

(a) Represents the revenue composition from May 3, 2011, date of acquisition, to June 30, 2011.

New major long-haul pipeline projects are typically underpinned by contracts for an original term equal to or greater than ten years. When this original term expires, shippers typically renew on an annual basis. Terms for interruptible transportation services range from day-to-day to multiple years. With the interconnection of the Bison pipeline to Northern Border, transportation services for related capacity on Northern Border and Bison have contract terms of ten years. More than half of Great Lakes’ capacity is under contracts that expire between 2012 and 2018. However, contract renewals for the remaining Great Lakes and Northern Border contracts are generally on an annual basis. More than half of GTN pipeline’s capacity is under long-term contracts that expire between 2015 and 2028. Similarly, North Baja has long-term contracts for a substantial portion of its capacity with terms that mature between 2022 and 2031. Tuscarora has long-term contracts for the majority of its capacity with term expiries after 2016.

Average Daily Scheduled Volumes

The table below provides historical information on the average daily scheduled volumes for Great Lakes, Northern Border and GTN for the three and six months ended June 30, 2011 and 2010:

	Average Daily Scheduled Volumes (a)
	Three months ended June 30,			Six months ended June 30,
(million cubic feet per day)		2011	2010		2011	2010

Great Lakes		2,201	2,130		2,544	2,132
Northern Border		2,508	2,462		2,642	2,336
GTN(b)		1,768	1,999		1,862	2,149

(a) Average daily scheduled volumes represent volumes of natural gas, irrespective of path or distance transported, from which variable usage fee revenue is earned. Average daily scheduled volumes are not presented for Bison, North Baja and Tuscarora as cash flows and net income from these investments are primarily underpinned by long-term firm contracts and do not vary significantly with changes in utilization.

(b) The interest in GTN was acquired on May 3, 2011. Average daily scheduled volumes for periods prior to May 3, 2011 are presented for comparative information purposes only.

Great Lakes

Average daily scheduled volumes on Great Lakes’ pipeline system for the second quarter of 2011 increased to 2,201 million cubic feet per day (MMcf/d) compared to 2,130 MMcf/d for the second quarter of 2010. For the six months ended June 30, 2011, average daily scheduled volumes increased to 2,544 MMcf/d compared to 2,132 MMcf/d in 2010. Volume increases for 2011 resulted primarily from increased firm contract utilization, higher demand for interruptible transportation service and increased backhaul volumes. Volume variances related to utilization of long-term firm contracts have a minimal impact on revenue earned from these contracts.

Great Lakes’ long-haul capacity contracts are generally subject to annual renewals. Contracting occurs throughout the year; however, shippers typically contract on Great Lakes for the upcoming natural gas year starting on November 1 of each year. As a result, Great Lakes is currently fully contracted through October 2011. Great Lakes’ largest shipper, TransCanada PipeLines Limited (TCPL), has 576 thousand dekatherms per day (MDth/d) of long-haul capacity under contract expiring on October 31, 2011. Negotiations related to these contracts have resulted in 314 MDth/d being recontracted by TCPL for one year through October 31, 2012.

Northern Border

Average daily scheduled volumes on Northern Border’s pipeline system for the second quarter of 2011 increased slightly to 2,508 MMcf/d compared to 2,462 MMcf/d for the second quarter of 2010. For the six months ended June 30, 2011, average daily scheduled volumes increased to 2,642 MMcf/d compared to 2,336 MMcf/d in 2010. Demand for transportation on Northern Border improved during the second quarter and for the six months ended June 30, 2011 compared to the same periods in 2010 due to the relative economic value of Northern Border services relative to other transportation paths.

Northern Border’s capacity is generally subject to annual contract renewals, which occur throughout the year. Substantially all of Northern Border’s capacity has been sold through October 2012.

GTN

Average daily scheduled volumes on GTN’s pipeline system for the second quarter of 2011 decreased from 1,999 MMcf/d in 2010 to 1,768 for the second quarter of 2011. Similarly, the volumes for the six months ended June 30, 2011 were lower compared with the same period in 2010, with average daily scheduled volumes declining from 2,149 MMcf/d in 2010 down to 1,862 MMcf/d in 2011. The primary reason for the decrease in scheduled volumes was due to lower overall gas demand in the market areas. California and the Pacific Northwest markets benefited from significantly higher hydro availability for power generation in 2011 compared to 2010. With overall power demand relatively flat from 2010 to 2011 reliance on gas-fired power generation was lower for the three month and six month periods ending June 30, 2011.

GTN has been flowing at an annual average rate of between 1,750 and 2,050 MMcf/d since 2002. GTN currently has contracts for approximately 1,500 MMcf/d with contract expiries occurring between 2015 and 2028. Flows vary from month-to-month but annual flows have been relatively stable over the last ten years. GTN's capacity is generally subject to annual renewals, which occur throughout the year. Pacific Gas and Electric previously notified GTN that it would not renew a contract for 250 MDth/d that expires in October 2011.

Outlook

Due to the relatively short-term contract profiles for Great Lakes and Northern Border, these systems may experience operating revenue volatility. We believe Great Lakes and Northern Border to be fundamental and competitive components of the natural gas pipeline infrastructure exiting the WCSB. Great Lakes is fully contracted through October 2011. Northern Border's capacity is substantially contracted through the third quarter of 2012. In the past, Northern Border has offered selective discounts to certain transportation segments in order to optimize revenue. Northern Border expects to continue to use this approach as needed. The level of contracting and, accordingly, revenues post-October 2011 for Great Lakes and post-October 2012 for Northern Border will depend on supply, demand and competition described above.

Bison, North Baja and Tuscarora are expected to provide stable revenues as the capacity on these pipelines is contracted for the long term. Similarly, more than half of GTN pipeline’s capacity is under long-term contracts that expire between 2015 and 2028, and GTN is expected to provide stable revenues to the extent contracted and the remaining capacity maybe subject to risk and volatility due to Ruby pipeline going into service at the end of July 2011. The revenues for each of these systems are subject to FERC decisions or settlements affecting existing rates, including the outcome of the May 24 Order related to Tuscarora’s rates.

REGULATORY ENVIRONMENT

FERC Rate Proceedings

Tuscarora Rate Proceeding

On May 24, 2011, the FERC issued the May 24 Order pursuant to Section 5 of the NGA to determine whether Tuscarora’s existing rates for jurisdictional services are unjust and unreasonable. The FERC initiated this proceeding following a complaint filed by the PUCN and NV Energy. On June 23, 2011, Tuscarora filed a Request for Rehearing of the Commission’s Order; on July 8, 2011, PUCN and NV Energy filed an Answer to the Rehearing Request. The May 24 Order directed that a hearing be conducted pursuant to an accelerated timeline and that an initial decision be issued by April 27, 2012. Tuscarora is currently preparing a cost and revenue study to be filed August 8, 2011, as required by the May 24 Order. We cannot predict the impact of these proceedings to Tuscarora at this time. If the FERC were to find Tuscarora’s rates unjust and unreasonable, the outcome could adversely affect our results of operations and cash flows.

Environmental Matters

Great Lakes Requests for Information

By letter dated May 31, 2011, the EPA required Great Lakes to provide additional information regarding its natural gas compressor station number 5 located in Minnesota, as well as information regarding other natural gas compressor stations in the states of Minnesota and Michigan, as part of the EPA’s review of Great Lakes’ compliance with the Clean Air Act initiated in December 2009. The potential effects on Great Lakes that may arise as a result of this information request or the underlying review are not determinable at this time.

HOW WE EVALUATE OUR OPERATIONS

We evaluate our business primarily on the basis of the underlying operating results for each of our pipeline systems, along with a measure of Partnership cash flows. This measure does not have any standardized meaning prescribed by U.S. generally accepted accounting principles (GAAP). It is, therefore, considered to be a non-GAAP measure and is unlikely to be comparable to similar measures presented by other entities. Partnership cash flows include cash distributions from the Partnership’s equity investments, Great Lakes, Northern Border, GTN and Bison plus operating cash flows from the Partnership’s wholly-owned subsidiaries, North Baja and Tuscarora, net of Partnership costs and distributions declared to the General Partner.

RESULTS OF OPERATIONS OF TC PIPELINES, LP

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 policies and estimates during the three and six months ended June 30, 2011.

Information about our critical accounting policies and estimates is included under Item 7. “Management Discussion and Analysis of Financial Condition and Results of Operations,” in our Annual Report on Form 10-K for the year ended December 31, 2010.

Future Accounting Pronouncements

NET INCOME

To supplement our financial statements, we have presented a comparison of the earnings contribution components from each of our investments. We have presented net income in this format to enhance investors’ understanding of the way management analyzes our financial performance. We believe this summary provides a more meaningful comparison of our net income to prior years, as we account for our partially-owned pipeline systems using the equity method. The presentation of this additional information is not meant to be considered in isolation or as a substitute for results prepared in accordance with GAAP.

Partnership Results of Operations

(unaudited)	Three months ended June 30,						Six months ended June 30,
(millions of dollars)	2011			2010			2011			2010
Equity earnings:
Great Lakes		17.0			13.1			35.0			29.4
Northern Border		16.2			12.2			36.8			26.8
GTN(a)		2.4			-			2.4			-
Bison(a)		1.9			-			1.9			-
Net income from Other Pipes(b)		10.0			9.0			20.5			18.3
Partnership expenses		(11.4	)		(6.6	)		(18.2	)		(13.1	)
Net income		36.1			27.7			78.4			61.4

(a) Represents equity earnings from May 3, 2011, date of acquisition, to June 30, 2011.

(b) “Other Pipes” includes the results of North Baja and Tuscarora.

Second Quarter 2011 Compared with Second Quarter 2010

Net income increased $8.4 million to $36.1 million in the second quarter of 2011 compared to $27.7 million in the same period in 2010. This increase was primarily due to higher equity income from Great Lakes and Northern Border, and earnings from the 25 percent interests in GTN and Bison, which were acquired in May 2011. These increases were partially offset by higher Partnership costs.

Equity income from Great Lakes was $17.0 million in the second quarter of 2011, an increase of $3.9 million compared to $13.1 million for the second quarter of 2010. This increase was primarily due to the cumulative impact of a Michigan tax law change eliminating Michigan business tax at the partnership level as well as the positive impact to earnings from depreciation rate reductions arising from the Section 5 rate case settlement in May 2010.

Equity income from Northern Border was $16.2 million in the second quarter of 2011, an increase of $4.0 million compared to $12.2 million for the same period in 2010. This increase was primarily due to increased demand for transportation services in the second quarter of 2011.

Costs at the Partnership level were $11.4 million in the second quarter of 2011, an increase of $4.8 million compared to $6.6 million for the second quarter of 2010. This increase was primarily due to costs incurred relating to the GTN and Bison acquisitions along with higher financial charges in 2011 resulting from higher average debt outstanding.

Six Months Ended June 30, 2011 Compared with Six Months Ended June 30, 2010

Net income increased $17.0 million to $78.4 million for the six months ended June 30, 2011 compared to $61.4 million in the same period in 2010. This increase was primarily due to higher equity income from Great Lakes and Northern Border, earnings from GTN and Bison, and higher net income from Other Pipes partially offset by higher Partnership costs.

Equity income from Great Lakes was $35.0 million for the six months ended June 30, 2011, an increase of $5.6 million compared to $29.4 million for the same period last year. This increase was primarily due to the cumulative impact of a Michigan tax law change eliminating Michigan business tax at the partnership level and the positive impact to earnings from depreciation rate reductions arising from the Section 5 rate case settlement in May 2010. These increases were partially offset by decreased transmission revenues resulting from the Section 5 rate case settlement.

Equity income from Northern Border was $36.8 million for the six months ended June 30, 2011, an increase of $10.0 million compared to $26.8 million for the same period in 2010. This increase was primarily due to increased demand for transportation services for the six months ended June 30, 2011.

Net income from Other Pipes, which includes results from North Baja and Tuscarora, was $20.5 million for the six months ended June 30, 2011, an increase of $2.2 million compared to $18.3 million for the same period in 2010. This increase was primarily due to lower financial charges from Tuscarora as a result of lower average interest rates and lower average debt outstanding attributable to the refinancing of a portion of senior notes in December 2010.

Costs at the Partnership level were $18.2 million for the six months ended June 30, 2011, an increase of $5.1 million compared to $13.1 million for the same period in 2010. This increase was primarily due to costs incurred relating to the GTN and Bison acquisitions along with higher financial charges in 2011 resulting from higher average debt outstanding.

PARTNERSHIP CASH FLOWS

The Partnership uses the non-GAAP financial measures “Partnership cash flows” and “Partnership cash flows before General Partner distributions” as they provide measures of cash generated during the period to evaluate our cash distribution capability. As well, management uses these measures as a basis for recommendations to our General Partner’s board of directors regarding the distribution to be declared each quarter. Partnership cash flow information is presented to enhance investors’ understanding of the way that management analyzes the Partnership’s financial performance.

The Partnership calculates Partnership cash flows as net income, plus operating cash flows from the Partnership’s wholly-owned subsidiaries, North Baja and Tuscarora, and cash distributions received in excess of equity income from the Partnership’s equity investments, Great Lakes, Northern Border, GTN and Bison, net of distributions declared to the General Partner. Partnership cash flows before General Partner distributions represent Partnership cash flows prior to distributions declared to the General Partner.

Partnership cash flows and Partnership cash flows before General Partner distributions are provided as a supplement to GAAP financial results and are not meant to be considered in isolation or as substitutes for financial results prepared in accordance with GAAP.

Non-GAAP Measures

Reconciliations of Net Income to Partnership Cash Flows

(unaudited)	Three months ended June 30,						Six months ended June 30,
(millions of dollars except per common unit amounts)	2011			2010			2011			2010
Net income(a)		36.1			27.7			78.4			61.4
Add:
Cash distributions from Great Lakes(b)		21.4			18.0			38.3			33.7
Cash distributions from Northern Border(b)		26.5			21.5			52.3			37.9
Cash distributions from GTN(b)		-			-			-			-
Cash distributions from Bison(b)		-			-			-			-
Cash flows provided by Other Pipes' operating activities		12.0			14.0			25.1			25.9
		59.9			53.5			115.7			97.5
Less:
Equity earnings from unconsolidated affiliates		(37.5	)		(25.3	)		(76.1	)		(56.2	)
Other Pipes' net income		(10.0	)		(9.0	)		(20.5	)		(18.3	)
		(47.5	)		(34.3	)		(96.6	)		(74.5	)
Partnership cash flows before General Partner distributions		48.5			46.9			97.5			84.4
General Partner distributions(c)		(0.8	)		(0.7	)		(1.5	)		(1.4	)
Partnership cash flows		47.7			46.2			96.0			83.0
Cash distributions declared		(42.0	)		(34.4	)		(77.4	)		(68.9	)
Cash distributions declared per common unit(d)		$0.77			$0.73			$1.52			$1.46
Cash distributions paid		(35.4	)		(34.4	)		(70.8	)		(68.9	)
Cash distributions paid per common unit(d)		$0.75			$0.73			$1.50			$1.46

(a) Includes equity earnings of GTN and Bison from May 3, 2011, date of acquisition, to June 30, 2011.

(b) In accordance with the cash distribution policies of the respective pipeline systems, cash distributions from Great Lakes, Northern Border, GTN and Bison are based on their respective prior quarter financial results. As the interests in GTN and Bison were acquired in May 2011, no distributions were received from these investments in the second quarter of 2011.

(c) General Partner distributions represent the cash distributions declared to the General Partner with respect to its effective two percent interest plus an amount equal to incentive distributions.

(d) Cash distributions declared per common unit and cash distributions paid per common unit are computed by dividing cash distributions, after the deduction of the General Partner’s allocation, by the number of common units outstanding. The General Partner’s allocation is computed based upon the General Partner’s two percent interest plus an amount equal to incentive distributions.

Second Quarter 2011 Compared with Second Quarter 2010

Partnership cash flows increased $1.5 million to $47.7 million in the second quarter of 2011 compared to $46.2 million in the same period of 2010. This increase was primarily due to increases in cash distributions from Northern Border of $5.0 million and Great Lakes of $3.4 million, partially offset by higher costs at the Partnership level of $5.0 million relating to the acquisitions of 25 percent interests in GTN and Bison and higher financial charges.

The Partnership paid distributions of $35.4 million in the second quarter of 2011, an increase of $1.0 million compared to the same period in 2010 due to an increase in the quarterly distribution of $0.02 per common unit beginning in the third quarter of 2010.

Six Months Ended June 30, 2011 Compared with Six Months Ended June 30, 2010

Partnership cash flows increased $13.0 million to $96.0 million for the six months ended June 30, 2011 compared to $83.0 million in the same period of 2010. This increase was primarily due to increases in cash distributions from Northern Border of $14.4 million and Great Lakes of $4.6 million, partially offset by higher costs at the Partnership level of $5.1 million relating to the acquisitions of 25 percent interests in GTN and Bison.

The Partnership paid distributions of $70.8 million in the six months ended June 30, 2011, which was an increase of $1.9 million compared to the same period in 2010 due to an increase in the quarterly distribution of $0.02 per common unit beginning in the third quarter of 2010.

Other Cash Flows

On March 25, 2011, the Partnership made a payment of $2.4 million in connection with the Yuma Lateral for the additional contract secured by TransCanada when the facilities associated with the additional contract were completed.

On March 25, 2011, the Partnership made an equity contribution of $4.2 million to Great Lakes that was used to fund debt repayments.

LIQUIDITY AND CAPITAL RESOURCES OF TC PIPELINES, LP

Overview

Our principal sources of liquidity include distributions received from our investment in unconsolidated affiliates, operating cash flows from North Baja and Tuscarora and our bank credit facility. The Partnership funds its operating expenses, debt service and cash distributions primarily with operating cash flow. Long-term capital needs may be met through the issuance of long-term debt and/or equity.

Summary of the Partnership’s Contractual Obligations

Yuma Lateral – Pursuant to an amendment to the acquisition agreement between the Partnership and TransCanada relating to the Partnership’s acquisition of North Baja, the Partnership agreed to make an additional payment of up to $2.4 million to TransCanada in the event that TransCanada secured additional contracts for transportation service before December 31, 2010. TransCanada secured an additional contract in July 2010 and, as a result, the Partnership paid $2.4 million to TransCanada on March 25, 2011 when the facilities associated with the additional contract were completed.

The Partnership’s Debt and Credit Facility

The following table summarizes the Partnership’s debt and credit facility outstanding as at June 30, 2011:

	Payments Due by Period
(unaudited) (millions of dollars)	Total		Less Than 1 Year		Long-term Portion

Senior Credit Facility due 2011 and 2016		314.0		300.0		14.0
6.89% Series C Senior Notes due 2012		3.5		0.8		2.7
3.82% Series D Senior Notes due 2017		27.0		-		27.0
4.65% Senior Notes due 2021		350.0		-		350.0
		694.5		300.8		393.7

Tuscarora’s Series C and D Senior Notes 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.

Interest Rate Swaps and Options

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.

The interest rate swaps and options are structured such that the cash flows match those of the Senior Credit Facility. The notional amount hedged was $300.0 million at June 30, 2011 (December 31, 2010 – $375.0 million). Financial instruments are recorded at fair value on a recurring basis and are categorized into one of three categories based upon a fair value hierarchy. The Partnership has classified all of its derivative financial instruments as Level II for all periods presented where the fair value is determined by using valuation techniques that refer to observable market data or estimated market prices. At June 30, 2011, the fair value of the interest rate swaps accounted for as hedges was classified as a current liability and was negative $6.9 million (December 31, 2010 – negative $13.8 million). The fair value of the interest rate swaps was calculated using the period-end interest rate for instruments with similar features; therefore, it is expected that this fair value will fluctuate over the year as interest rates change. In the three months and six months ended June 30, 2011, the Partnership recorded interest expense of $3.5 million and $7.4 million on the interest rate swaps and options (2010 – $4.1 million and $8.3 million).

Capital Requirements

2011

The Partnership made an equity contribution of $4.2 million to Great Lakes in the first quarter of 2011. This amount represented the Partnership’s 46.45 percent share of a $9.0 million cash call issued by Great Lakes to make a scheduled debt repayment. The Partnership expects to make an additional equity contribution of $4.6 million to Great Lakes in the fourth quarter of 2011. This represents the Partnership’s 46.45 percent share of an expected $10.0 million cash call from Great Lakes to make a scheduled debt repayment.

Northern Border’s distribution policy adopted in 2006 defines minimum equity to total capitalization to be used by its Management Committee to establish the timing and amount of required equity contributions. In accordance with this policy, the Partnership made a required equity contribution of $49.8 million to meet the minimum equity to total capitalization requirements on July 27, 2011 and expects to make an equity contribution of approximately $5.5 million in fourth quarter 2011 to fund capital expenditures related to the Princeton Lateral Project.

To the extent the Partnership has any additional capital requirements with respect to our pipeline systems or acquisitions in the future, we expect to fund these requirements with operating cash flows, debt and/or equity.

2011 Second Quarter Cash Distribution

On July 19, 2011, the Partnership announced that the board of directors of the General Partner declared the Partnership’s second quarter 2011 cash distribution in the amount of $0.77 per common unit. The second quarter cash distribution, totaling $42.0 million, will be paid on August 12, 2011 to unitholders of record as of the close of business on July 31, 2011 in the following manner: $41.2 million to common unitholders (including $4.5 million to the General Partner as holder of 5,797,106 common units and $8.7 million to TransCanada as holder of 11,287,725 common units) and $0.8 million to the General Partner in respect of its two percent general partner interest.

LIQUIDITY AND CAPITAL RESOURCES OF OUR PIPELINE SYSTEMS

Overview

Our pipeline systems’ principal sources of liquidity are cash generated from operating activities, bank credit facilities and equity contributions from their partners. Our pipeline systems fund operating expenses, debt service and cash distributions to partners primarily with operating cash flow. Great Lakes also funds its debt repayments with cash calls to its partners.

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’ partners. The ability of our pipeline systems to access the debt capital markets under reasonable terms depends on their financial position and general market conditions.

We believe that our pipeline systems’ ability to obtain financing at reasonable rates, together with their history of consistent cash flow from operating activities, provide a solid foundation to meet their future liquidity and capital resource requirements. The Partnership’s pipeline systems monitor the creditworthiness of their customers and have credit provisions included in their tariffs that allow them to request credit support as circumstances dictate.

Summary of Great Lakes’ Contractual Obligations

The following table summarizes Great Lakes’ debt outstanding as at June 30, 2011:

	Payments Due by Period
(unaudited) (millions of dollars)	Total		Less than 1 year		Long-term Portion

8.74% series Senior Notes due 2011		10.0		10.0		-
6.73% series Senior Notes due 2012 to 2018		63.0		9.0		54.0
9.09% series Senior Notes due 2012 to 2021		100.0		-		100.0
6.95% series Senior Notes due 2019 to 2028		110.0		-		110.0
8.08% series Senior Notes due 2021 to 2030		100.0		-		100.0
		383.0		19.0		364.0

Great Lakes is required to comply with certain financial, operational and legal covenants. Under the most restrictive covenants in the Senior Note Agreements, approximately $206.0 million of Great Lakes’ partners’ capital was restricted as to distributions as at June 30, 2011 (December 31, 2010 – $211.0 million). Current maturities will be funded through cash calls to its partners. As at June 30, 2011, Great Lakes was in compliance with all of its financial covenants.

Summary of Northern Border’s Contractual Obligations

The following table summarizes Northern Border’s debt outstanding as at June 30, 2011:

	Payments Due by Period
(unaudited) (millions of dollars)	Total		Less than 1 year		Long-term Portion

$250 million Credit Agreement due 2012		198.0		198.0		-
6.24% Senior Notes due 2016		100.0		-		100.0
7.50% Senior Notes due 2021		250.0		-		250.0
		548.0		198.0		350.0

As at June 30, 2011, Northern Border had outstanding borrowings of $198.0 million under its $250.0 million revolving credit agreement and was in compliance with the covenants of the agreement. The weighted average interest rate related to the borrowings on the credit agreement was 0.55 percent at June 30, 2011 (2010 – 0.60 percent).

Northern Border had commitments of $10.1 million as at June 30, 2011 in connection with the Princeton Lateral project.

Summary of GTN’s Contractual Obligations

The following table summarizes GTN’s debt outstanding as at June 30, 2011:

	Payments Due by Period
(unaudited) (millions of dollars)	Total		Less than 1 year		Long-term Portion

5.09% Senior Notes due 2015		75.0		-		75.0
5.29% Senior Notes due 2020		100.0		-		100.0
5.69% Senior Notes due 2035		150.0		-		150.0
		325.0		-		325.0

The 2005 Note Purchase Agreement contains a covenant that limits total debt to no greater than 70 percent of total capitalization. At June 30, 2011, the total debt to total capitalization ratio was 35 percent.

The Company was in compliance with all terms and conditions of all its credit and other debt agreements at June 30, 2011.

Summary of Bison's Contractual Obligations

Bison had no outstanding debt as at June 30, 2011.

CONTINGENCIES

Legal

Various legal actions or governmental proceedings that have arisen in the ordinary course of business are pending. Our pipeline systems believe that the resolution of these issues will not have a material adverse impact on their results of operations or financial position. Please read Part II, Item 1. ‘‘Legal Proceedings’’ for additional information.

Environmental

We believe that our pipeline systems are in substantial compliance with applicable environmental laws and regulations.

Refer to “Recent Developments – Our Pipeline Systems – Great Lakes Requests for Information” for additional information.

RELATED PARTY TRANSACTIONS

Please read Note 10 within Item 1. “Financial Statements” for information regarding related party transactions.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

OVERVIEW

Market risk is the risk of loss arising from adverse changes in market rates. Our primary risk management objective is to protect earnings and cash flow and, ultimately, unitholder value. We do not use financial instruments for trading purposes.

We are exposed to market risk primarily from interest rate fluctuations. The Partnership and our pipeline systems are also exposed to other risks such as credit risk, liquidity risk and foreign exchange fluctuations. 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.

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 AND INTEREST RATE 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 debt exposes the Partnership and our pipeline systems to market risk from changes in interest rates that affect earnings and the value of the financial instruments we hold.

The Partnership and our pipeline systems use derivatives as part of our overall risk management policy to manage 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. The Partnership and our pipeline systems enter into interest rate swaps to mitigate the impact of changes in interest rates.

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 and our pipeline systems enter into option agreements to mitigate the impact of changes in interest rates.

Interest rate risk is created by fluctuations in the fair values or cash flows of financial instruments due to changes in the market interest rates. Our interest rate exposure results from our Senior Credit Facility, which is subject to variability in LIBOR interest rates. We regularly assess the impact of interest rate fluctuations on future cash flows and evaluate hedging opportunities to mitigate our interest rate risk.

Our interest rate swaps and options are structured such that the cash flows match those of the Senior Credit Facility. The notional amount hedged was $300.0 million at June 30, 2011 (December 31, 2010 – $375.0 million). $300.0 million of variable-rate debt is hedged by an interest rate swap through December 12, 2011, where the weighted average fixed interest rate paid is 4.89 percent. $75.0 million of variable-rate debt was hedged by an interest rate swap through February 28, 2011, where the fixed interest rate paid was 3.86 percent. In addition to these fixed rates, the Partnership pays an applicable margin in accordance with the Senior Credit Facility agreement.

At June 30, 2011, the fair value of the interest rate swaps accounted for as hedges was classified as a current liability and was negative $6.9 million (December 31, 2010 – negative $13.8 million). The fair value of the interest rate swaps was calculated using the period-end interest rate for instruments with similar features; therefore, it is expected that this fair value will fluctuate over the year as interest rates change.

At June 30, 2011, we had $314.0 million (December 31, 2010 – $483.0 million) outstanding on our Senior Credit Facility. Utilizing the conditions of the interest rate swaps, if LIBOR interest rates hypothetically increased by one percent (100 basis points) compared to the rates in effect at June 30, 2011, our annual interest expense would have increased and our net income would have decreased by $0.1 million; and if LIBOR interest rates hypothetically decreased to zero percent compared to the rates in effect at June 30, 2011, our annual interest expense and our net income would not have changed. These amounts have been determined by considering the impact of the hypothetical interest rates on unhedged debt outstanding as at June 30, 2011.

Northern Border utilizes both fixed-rate and variable-rate debt and is exposed to market risk due to the floating interest rates on its revolving credit facility. Northern Border regularly assesses the impact of interest rate fluctuations on future cash flows and evaluates hedging opportunities to mitigate its interest rate risk. As at June 30, 2011, 64 percent of Northern Border’s outstanding debt was at fixed rates (December 31, 2010 – 65 percent).

If interest rates hypothetically increased by one percent (100 basis points) compared with rates in effect at June 30, 2011, Northern Border’s annual interest expense would increase and its net income would decrease by approximately $2.0 million; and if interest rates hypothetically decreased to zero percent compared with rates in effect at June 30, 2011, Northern Border’s annual interest expense would decrease and its net income would increase by approximately $0.7 million.

Great Lakes, GTN and Tuscarora utilize fixed-rate debt; 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.

OTHER RISKS

The Partnership is influenced by the same factors that influence our pipeline systems. None of our pipeline systems own any of the natural gas they transport; therefore, they do not assume any of the related natural gas commodity price risk with respect to transported natural gas volumes.

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 its contracts with the Partnership or its pipeline systems. 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. At June 30, 2011, the Partnership’s maximum counterparty credit exposure consisted of accounts receivable of $7.6 million (December 31, 2010 – $7.6 million), and there were no significant amounts past due or impaired.

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 parties. Due to the deterioration of global financial markets in 2008 and 2009, we continue to closely monitor the creditworthiness of our counterparties, including financial institutions. Overall, we do not believe the Partnership has any significant concentrations of counterparty credit risk.

Liquidity risk is the risk that the Partnership and our pipeline systems will not be able to meet their 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. The Partnership has a committed revolving bank line of $250.0 million maturing in December 2011 and as at June 30, 2011, the Partnership had $14.0 million outstanding on this facility, leaving 236.0 million available. On July 13, 2011, the Partnership closed an amendment to its Senior Credit Facility increasing the revolving credit facility to $500.0 million with a LIBOR-based interest rate plus a margin, and extending the maturity date of the senior revolving credit facility to July 2016. In addition, Northern Border has a committed revolving bank line of $250.0 million maturing in April 2012 and as at June 30, 2011, $198.0 million was drawn on this facility.

The Partnership does not have any material foreign exchange risks.

Item 4. Controls and Procedures

EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES

As required by Rule 13a-15(e) under the 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 our disclosure controls and procedures, as of the end of the period covered by this report, were effective to provide reasonable assurance that the information required to be disclosed by us in the reports that we file or submit 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, 2011, 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

Item 1. Legal Proceedings

On July 27, 2009, North Baja and GTN filed arbitration with American Arbitration Association in Portland, Oregon for approximately $26 million in damages related to performance, integrity and reliability issues associated with certain equipment purchased from Rolls Royce Energy Systems, Inc. (RREI). GTN and North Baja allege that equipment purchased from RREI in 2001 is defective and that RREI breached its contract and warranties. The arbitration is in the discovery phase.

On May 24, 2011, the FERC issued the May 24 Order pursuant to Section 5 of the NGA to determine whether Tuscarora’s existing rates for jurisdictional services are unjust and unreasonable. The FERC initiated this proceeding following a complaint filed by the PUCN and NV Energy. On June 23, 2011, Tuscarora filed a Request for Rehearing of the Commission’s Order; on July 8, 2011, PUCN and NV Energy filed an Answer to the Rehearing Request. The May 24 Order directed that a hearing be conducted pursuant to an accelerated timeline and that an initial decision be issued by April 27, 2012. Tuscarora is currently preparing a cost and revenue study to be filed August 8, 2011, as required by the May 24 Order. We cannot predict the outcome or potential impact of these proceedings to Tuscarora at this time.

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

Item 1A. Risk Factors

The following updated risk factors should be read in conjunction with the risk factors disclosed in Part I, Item 1A. “Risk Factors,” in our Annual Report on Form 10-K for the year ended December 31, 2010 and Part II, Item 1A.

“Risk Factors” in our Quarterly Report on Form 10-Q for the quarter ended March 31, 2011.

Risks Inherent in Our Business

If the tariff rates of our pipeline systems were successfully challenged, our pipeline systems’ could be required to reduce their tariff rates, which would reduce our revenues and cash available for distributions.

If a customer of one of our pipeline systems were to file a complaint against our pipeline systems’ existing tariff rates, or the FERC were to initiate an investigation of our pipeline systems’ existing rates, then our pipeline systems’ rates could be subject to detailed review. If our pipeline systems’ existing rates were found to be unjust and unreasonable, they could be ordered to reduce their rates prospectively. For example, in May 2011, the PUCN and NV Energy filed a complaint alleging that Tuscarora’s existing rates for jurisdictional services are unjust and unreasonable. Any such reductions may result in lower revenues and cash flows, which could impact our ability to make distributions.

Refer to Part I, Item 2. “Management’s Discussion and Analysis of Financial Condition and Results of Operations − Regulatory Environment − FERC Rate Proceedings − Tuscarora Rate Proceeding” for additional information.

GTN may not be able to maintain existing customers or acquire new customers when its current shipper contracts expire or customers may recontract for shorter periods or at less than maximum rates.

The GTN pipeline competes for WCSB gas supplies seeking downstream markets. GTN also competes with Ruby pipeline, which went into service at the end of July 2011 and will deliver Rocky Mountain basin gas supplies into the California market. Such competition has and may continue to adversely affect GTN’s ability to extend and replace existing contracts on comparable terms, if at all. For example, Pacific Gas and Electric notified GTN that it would not renew its current contract for 250 MDth/d that expires in October 2011. If GTN is not able to maintain existing customers or contract with new customers when current shipper contracts expire, its revenue and ability to make distributions may be adversely affected.

Our pipeline systems’ indebtedness may limit their ability to borrow additional funds, make distributions to us or capitalize on business opportunities.

As at June 30, 2011, Great Lakes, Northern Border, GTN and Tuscarora had $383.0 million, $548.0 million, $325.0 million and $30.5 million of debt outstanding, respectively. Of the debt outstanding, Great Lakes, Northern Border and Tuscarora have $19.0 million, $198.0 million and $0.8 million of debt maturing in 2011, respectively. Their respective levels of debt could have important consequences to Great Lakes, Northern Border, GTN and Tuscarora as discussed in Part I, Item 1A. “Risk Factors,” in our Annual Report on Form 10-K for the year ended December 31, 2010.

Risks Inherent in an Investment in the Partnership

The Partnership’s indebtedness may limit its ability to borrow additional funds, make distributions or capitalize on business opportunities.

The conditions of the U.S. and international credit markets may adversely affect our ability to obtain credit or draw on our current credit facility. As at June 30, 2011, the Partnership had $693.9 million of debt outstanding, including the revolving credit and term loan agreement (Senior Credit Facility) and Senior Notes. These obligations could have important consequences to the Partnership as discussed in Part I, Item 1A. “Risk Factors,” in our Annual Report on Form 10-K for the year ended December 31, 2010

Item 5. Other Information

Item 6. Exhibits

No.	Description
*2.1	Agreement for Purchase and Sale of Membership Interest dated as of April 26, 2011 between TransCanada American Investments Ltd., as Seller, and TC PipeLines Intermediate Limited Partnership, as Buyer (Exhibit 2.1 to TC PipeLines, LP’s Form 8-K filed on April 27, 2011).
*2.2	Agreement for Purchase and Sale of Membership Interest dated as of April 26, 2011 between TC Continental Pipeline Holdings Inc., as Seller, and TC PipeLines Intermediate Limited Partnership, as Buyer (Exhibit 2.2 to TC PipeLines, LP’s Form 8-K filed on April 27, 2011).
*4.1	Indenture, dated as of June 17, 2011, between the Partnership and The Bank of New York Mellon, as trustee (Exhibit 4.1 to TC PipeLines, LP’s Form 8-K filed on June 17, 2011).
*4.2	Supplemental Indenture, dated as of June 17, 2011 relating to the issuance of $350,000,000 aggregate principal amount of 4.65% Senior Notes due 2021 (Exhibit 4.2 to TC PipeLines, LP’s Form 8-K filed on June 17, 2011).
*10.1	Fifth Amendment to Operating Agreement by and between Tuscarora Gas Transmission Company and TransCanada Northern Border Inc. dated December 31, 2010 (Exhibit 10.1 to TC PipeLines, LP’s Form 10-Q filed on April 27, 2011)..
*10.2	Guaranty by TransCanada Pipeline USA Ltd. dated as of April 26, 2011 with respect to the obligations of TransCanada American Investments Ltd. (Exhibit 10.1 to TC PipeLines, LP’s Form 8-K filed on April 27, 2011).
*10.3	364-Day Senior Bridge Loan Agreement, dated as of May 3, 2011, among TC PipeLines, LP, the lenders from time to time party thereto, and SunTrust Bank, as Administrative Agent (Exhibit 10.1 to TC PipeLines, LP’s Form 8-K filed on May 5, 2011).
*10.4	Guaranty by TransCanada Pipeline USA Ltd. dated as of April 26, 2011 with respect to the obligations of TC Continental Pipeline Holdings Inc. (Exhibit 10.2 to TC PipeLines, LP’s Form 8-K filed on April 27, 2011).
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.

* Indicates exhibits incorporated by reference.

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 2nd day of August 2011.

TC PIPELINES, LP

(A Delaware Limited Partnership)

By its general partner, TC PipeLines, GP, Inc.

By: /s/ Steven D. Becker

Steven D. Becker

President

TC PipeLines GP, Inc. (Principal Executive Officer)

By: /s/ Robert C. Jacobucci

Robert C. Jacobucci

Controller

TC PipeLines GP, Inc. (Principal Financial Officer)

EXHIBIT INDEX

No.	Description
*2.1	Agreement for Purchase and Sale of Membership Interest dated as of April 26, 2011 between TransCanada American Investments Ltd., as Seller, and TC PipeLines Intermediate Limited Partnership, as Buyer (Exhibit 2.1 to TC PipeLines, LP’s Form 8-K filed on April 27, 2011).
*2.2	Agreement for Purchase and Sale of Membership Interest dated as of April 26, 2011 between TC Continental Pipeline Holdings Inc., as Seller, and TC PipeLines Intermediate Limited Partnership, as Buyer (Exhibit 2.2 to TC PipeLines, LP’s Form 8-K filed on April 27, 2011).
*4.1	Indenture, dated as of June 17, 2011, between the Partnership and The Bank of New York Mellon, as trustee (Exhibit 4.1 to TC PipeLines, LP’s Form 8-K filed on June 17, 2011).
*4.2	Supplemental Indenture, dated as of June 17, 2011 relating to the issuance of $350,000,000 aggregate principal amount of 4.65% Senior Notes due 2021 (Exhibit 4.2 to TC PipeLines, LP’s Form 8-K filed on June 17, 2011).
*10.1	Fifth Amendment to Operating Agreement by and between Tuscarora Gas Transmission Company and TransCanada Northern Border Inc. dated December 31, 2010 (Exhibit 10.1 to TC PipeLines, LP’s Form 10-Q filed on April 27, 2011)..
*10.2	Guaranty by TransCanada Pipeline USA Ltd. dated as of April 26, 2011 with respect to the obligations of TransCanada American Investments Ltd. (Exhibit 10.1 to TC PipeLines, LP’s Form 8-K filed on April 27, 2011).
*10.3	364-Day Senior Bridge Loan Agreement, dated as of May 3, 2011, among TC PipeLines, LP, the lenders from time to time party thereto, and SunTrust Bank, as Administrative Agent (Exhibit 10.1 to TC PipeLines, LP’s Form 8-K filed on May 5, 2011).
*10.4	Guaranty by TransCanada Pipeline USA Ltd. dated as of April 26, 2011 with respect to the obligations of TC Continental Pipeline Holdings Inc. (Exhibit 10.2 to TC PipeLines, LP’s Form 8-K filed on April 27, 2011).
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.

* Indicates exhibits incorporated by reference.