Edgar Filing: TC PIPELINES LP

tclpform10qnovember32008.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 September 30, 2008

[ ] 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
Omaha, Nebraska	68154-5200
(Address of principal executive offices)		(Zip code)

	877-290-2772
	(Registrant's telephone number, including area code)

Indicate by check mark if 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 is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See 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 of November 3, 2008, there were 34,856,086 of the registrant’s common units outstanding.

TC PIPELINES, LP

		Page No.
TABLE OF CONTENTS

PART I	FINANCIAL INFORMATION

	Glossary	3

Item 1.	Financial Statements

	Consolidated Statement of Income – Three and nine months ended September 30, 2008 and 2007	4
	Consolidated Statement of Comprehensive Income – Three and nine months ended September 30, 2008 and 2007	4
	Consolidated Balance Sheet – September 30, 2008 and December 31, 2007	5
	Consolidated Statement of Cash Flows – Nine months ended September 30, 2008 and 2007	6
	Consolidated Statement of Changes in Partners’ Equity – Nine months ended September 30, 2008	7
	Notes to Consolidated Financial Statements	8

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	15

	Results of Operations of TC PipeLines	21
	Liquidity and Capital Resources of TC PipeLines	25
	Liquidity and Capital Resources of our Pipeline Systems	27

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	29

Item 4.	Controls and Procedures	30

PART II	OTHER INFORMATION

Item 1A.	Risk Factors	31

Item 6.	Exhibits	33

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:

ANR ……………………………......	ANR Pipeline Company
Bcf/d……………………………......	Billion cubic feet per day
Bison Project…………………......	Bison Pipeline Project
Chicago IV.........................................	Northern Border's proposed expansion project
Collar Agreement.............................	Northern Border's zero cost interest rate collar agreement
DCF……………………………........	Discounted cash flow
Dth/d……………………………......	Dekatherms per day
FASB…………………………..........	Financial Accounting Standards Board
FERC…………………………..........	Federal Energy Regulatory Commission
GAAP…………………………........	U.S. generally accepted accounting principles
GLGT.............…………………........	Great Lakes Gas Transmission Limited Partnership
Great Lakes......................................	Great Lakes Gas Transmission Limited Partnership
INGAA…………………………........	Interstate Natural Gas Association of America
LIBOR…………………………........	London Interbank Offered Rate
MLP……………………………........	Master Limited Partnership
MMcf/d……………………….........	Million cubic feet per day
NBPC……………………….............	Northern Border Pipeline Company
Northern Border……………….......	Northern Border Pipeline Company
Our pipeline systems………….......	Great Lakes, Northern Border and Tuscarora
Partnership…………………............	TC PipeLines, LP and its subsidiaries
Pathfinder Project.............................	Pathfinder Pipeline Project
REX East…………………………...	Eastern segment of the Rockies Express Pipeline
REX West…………………………..	Western segment of the Rockies Express Pipeline
ROE……………………………........	Return on equity
ROFR...................................................	Right of first refusal
SEC…………………………….........	Securities and Exchange Commission
SFAS…………………………..........	Statement of Financial Accounting Standards
TC Pipelines………………………..	TC PipeLines, LP and its subsidiaries
TCNB………………………….........	TransCanada Northern Border Inc.
TGTC..................................................	Tuscarora Gas Transmission Company
TransCanada…………………........	TransCanada Corporation and its subsidiaries
TSA.....................................................	Transportation Security Administration
Tuscarora………………………......	Tuscarora Gas Transmission Company
U.S……………………………..........	United States of America
WCSB…………………………........	Western Canada Sedimentary Basin

PART I – FINANCIAL INFORMATION

Item 1. Financial Statements

TC PipeLines, LP

Consolidated Statement of Income

(unaudited)	Three months ended September 30,						Nine months ended September 30,
(millions of dollars except per common unit amounts)	2008			2007			2008			2007

Equity income from investment in Great Lakes (Note 2)		12.0			14.2			44.4			34.3
Equity income from investment in Northern Border (Note 3)		19.9			16.2			48.1			44.3
Transmission revenues		8.2			6.7			23.3			20.3
Operating expenses		(2.3	)		(2.2	)		(6.8	)		(6.4	)
Depreciation		(1.8	)		(1.6	)		(5.1	)		(4.7	)
Financial charges, net and other		(7.7	)		(8.7	)		(22.8	)		(25.5	)
Net income		28.3			24.6			81.1			62.3

Net income allocation
Common units		25.1			22.4			72.5			57.0
General partner		3.2			2.2			8.6			5.3
		28.3			24.6			81.1			62.3

Net income per common unit (Note 6)	$	0.72		$	0.64		$	2.08		$	1.81

Weighted average common units outstanding (millions)		34.9			34.9			34.9			31.5

Common units outstanding, end of the period (millions)		34.9			34.9			34.9			34.9

Consolidated Statement of Comprehensive Income

(unaudited)	Three months ended September 30,						Nine months ended September 30,
(millions of dollars)	2008			2007			2008			2007

Net income		28.3			24.6			81.1			62.3
Other comprehensive loss
Change associated with hedging transactions (Note 9)		(1.3	)		(7.0	)		(1.7	)		(2.3	)
Change associated with hedging transactions of investees		-			(0.5	)		(0.7	)		(0.9	)
		(1.3	)		(7.5	)		(2.4	)		(3.2	)
Total comprehensive income		27.0			17.1			78.7			59.1

See accompanying notes to the consolidated financial statements.

TC PipeLines, LP

Consolidated Balance Sheet

(unaudited)
(millions of dollars)	September 30, 2008			December 31, 2007
ASSETS
Current Assets
Cash and short-term investments		11.0			7.5
Accounts receivable and other		3.7			4.2
		14.7			11.7
Investment in Great Lakes (Note 2)		710.5			721.1
Investment in Northern Border (Note 3)		517.2			541.9
Plant, property and equipment (net of $66.8 accumulated depreciation, 2007 - $61.7)		135.6			134.1
Goodwill		81.7			81.7
Other assets		1.6			2.1
		1,461.3			1,492.6

LIABILITIES AND PARTNERS' EQUITY
Current Liabilities
Bank indebtedness		-			1.4
Accounts payable		2.2			4.8
Accrued interest		3.5			3.0
Current portion of long-term debt (Note 5)		4.5			4.6
Other current liabilities		0.5			-
		10.7			13.8
Other long-term liabilities		11.0			9.9
Long-term debt (Note 5)		541.6			568.8
		563.3			592.5
Partners' Equity
Common units		892.6			892.3
General partner		19.1			19.1
Accumulated other comprehensive loss		(13.7	)		(11.3	)
		898.0			900.1
		1,461.3			1,492.6


Subsequent events (Note 12)

See accompanying notes to the consolidated financial statements.

TC PipeLines, LP

Consolidated Statement of Cash Flows

(unaudited)	Nine months ended September 30,
(millions of dollars)	2008			2007

CASH GENERATED FROM OPERATIONS
Net income		81.1			62.3
Depreciation		5.1			4.7
Amortization of other assets		0.4			0.3
Non-controlling interests		-			0.2
Increase in long-term liabilities		0.1			-
Equity allowance for funds used during construction		(0.2	)		-
Increase in operating working capital (Note 10)		(0.2	)		(0.7	)
		86.3			66.8

INVESTING ACTIVITIES
Return of capital from Great Lakes (Note 2)		10.6			6.7
Return of capital from Northern Border (Note 3)		23.9			18.2
Investment in Great Lakes (Note 2)		-			(733.0	)
Investment in Northern Border (Note 3)		-			(7.5	)
Capital expenditures		(6.4	)		(4.4	)
Other assets		-			(1.1	)
(Increase)/decrease in investing working capital (Note 10)		(2.8	)		1.2
		25.3			(719.9	)

FINANCING ACTIVITIES
Distributions paid		(80.8	)		(61.3	)
Equity issuances, net		-			607.0
Long-term debt issued		4.0			152.5
Long-term debt repaid (Note 5)		(31.3	)		(34.9	)
		(108.1	)		663.3

Increase in cash and short-term investments		3.5			10.2
Cash and short-term investments, beginning of period		7.5			4.6

Cash and short-term investments, end of period		11.0			14.8

Interest payments made		17.9			23.9

See accompanying notes to the consolidated financial statements.

TC PipeLines, LP

Consolidated Statement of Changes in Partners’ Equity

(unaudited)	Common Units					General Partner			Accumulated Other Comprehensive Loss (1)			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, 2007		34.9		892.3			19.1			(11.3	)		34.9		900.1
Net income		-		72.5			8.6			-			-		81.1
Distributions paid		-		(72.2	)		(8.6	)		-			-		(80.8	)
Other comprehensive loss		-		-			-			(2.4	)		-		(2.4	)
Partners' equity at September 30, 2008		34.9		892.6			19.1			(13.7	)		34.9		898.0

(1)

TC PipeLines, LP uses derivatives to assist in managing its exposure to interest rate risk. Based on interest rates at September 30, 2008, 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 $3.8 million, which will be offset by a reduction to interest expense of a similar amount.

See accompanying notes to the consolidated financial statements.

TC PipeLines, LP

Notes to Consolidated Financial Statements

Note 1

Organization and Significant Accounting Policies

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

The preparation of financial statements in conformity with United States of America (U.S.) generally accepted accounting principles (GAAP) 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.

The results of operations for the three and nine months ended September 30, 2008 and 2007 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, 2007. 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, 2007. Certain comparative figures have been reclassified to conform to the current period’s presentation.

Note 2

Investment in Great Lakes

On February 22, 2007, we acquired a 46.45 per cent partner interest in Great Lakes Gas Transmission Limited Partnership (Great Lakes). On the same day, a wholly-owned subsidiary of TransCanada Corporation (TransCanada) acquired 100 per cent ownership of the operator of Great Lakes. Great Lakes is regulated by the Federal Energy Regulatory Commission (FERC).

We use the equity method of accounting for our interest in Great Lakes. Great Lakes had no undistributed earnings for either the nine months ended September 30, 2008 or the period February 23, 2007 to September 30, 2007.

The following tables contain summarized financial information for Great Lakes:

Summarized Consolidated Great Lakes Income Statement (unaudited)	Three months ended September 30,						Nine months ended September 30,			For the period February 23 to September 30,
(millions of dollars)	2008			2007			2008			2007
Transmission revenues		66.7			65.6			213.9			162.2
Operating expenses		(17.1	)		(12.6	)		(45.9	)		(34.0	)
Depreciation		(14.7	)		(14.5	)		(43.9	)		(34.9	)
Financial charges, net and other		(8.0	)		(8.1	)		(24.4	)		(19.5	)
Michigan business tax		(1.2	)		-			(4.2	)		-
Net income		25.7			30.4			95.5			73.8

Summarized Consolidated Great Lakes Balance Sheet
(unaudited)	September 30,		December 31,
(millions of dollars)	2008		2007
Assets
Cash and short-term investments		1.1		32.0
Other current assets		100.6		55.5
Plant, property and equipment, net		931.9		969.2
		1,033.6		1,056.7
Liabilities and Partners' Equity
Current liabilities		49.0		50.7
Deferred credits		1.7		0.4
Long-term debt, including current maturities		440.0		440.0
Partners' capital		542.9		565.6
		1,033.6		1,056.7

Note 3

Investment in Northern Border

We own a 50 per cent general partner interest in Northern Border Pipeline Company (Northern Border). Effective April 1, 2007, TransCanada Northern Border Inc. (TCNB), a wholly-owned subsidiary of TransCanada, became the operator of Northern Border. Northern Border is regulated by the FERC.

We use the equity method of accounting for our interest in Northern Border. Northern Border had no undistributed earnings for the nine months ended September 30, 2008 and 2007.

The following tables contain summarized financial information for Northern Border:

Summarized Northern Border Income Statement (unaudited)	Three months ended September 30,						Nine months ended September 30,
(millions of dollars)	2008			2007			2008			2007
Transmission revenues		67.7			79.6			212.8			228.0
Operating expenses		(19.3	)		(21.6	)		(57.5	)		(61.7	)
Depreciation		(15.3	)		(15.1	)		(45.8	)		(45.6	)
Financial charges, net and other		7.1			(10.2	)		(12.1	)		(30.9	)
Net income		40.2			32.7			97.4			89.8

Summarized Northern Border Balance Sheet
(unaudited)	September 30,			December 31,
(millions of dollars)	2008			2007
Assets
Cash and short-term investments		18.6			22.9
Other current assets		31.1			39.8
Plant, property and equipment, net		1,398.3			1,428.3
Other assets		25.5			23.9
		1,473.5			1,514.9
Liabilities and Partners' Equity
Current liabilities		53.0			53.4
Deferred credits and other		9.2			8.1
Long-term debt, including current maturities		621.4			615.3
Partners' equity
Partners' capital		793.8			840.5
Accumulated other comprehensive loss		(3.9	)		(2.4	)
		1,473.5			1,514.9

Note 4

Investment in Tuscarora

As of December 31, 2007, we acquired the remaining two per cent general partner interest in Tuscarora Gas Transmission Company (Tuscarora), thereby making it a wholly-owned subsidiary. Tuscarora is operated by TCNB and is regulated by the FERC.

We use the consolidation method of accounting for our ownership of Tuscarora.

The following tables contain summarized financial information for Tuscarora:

Summarized Tuscarora Income Statement (unaudited)	Three months ended September 30,						Nine months ended September 30,
(millions of dollars)	2008			2007			2008			2007
Transmission revenues		8.2			6.7			23.3			20.3
Operating expenses		(1.4	)		(1.2	)		(3.7	)		(3.7	)
Depreciation		(1.8	)		(1.6	)		(5.1	)		(4.7	)
Financial charges, net and other		(1.1	)		(1.0	)		(3.1	)		(3.4	)
Net income		3.9			2.9			11.4			8.5

Summarized Tuscarora Balance Sheet (unaudited)	September 30,		December 31,
(millions of dollars)	2008		2007
Assets
Cash and short-term investments		-		6.1
Other current assets		13.6		2.6
Plant, property and equipment, net		135.6		134.1
Other assets		0.3		0.6
		149.5		143.4
Liabilities and Partners' Equity
Current liabilities		3.1		6.1
Long-term debt, including current maturities		64.1		66.4
Partners' capital		82.3		70.9
		149.5		143.4

Summarized Tuscarora Cash Flow Statement (unaudited)	Three months ended September 30,					Nine months ended September 30,
(millions of dollars)	2008			2007		2008			2007
Cash flows provided by operating activities		7.2			4.6		17.3			13.5
Cash flows (used in)/provided by investing activities		(1.3	)		0.6		(9.2	)		(3.1	)
Cash flows used in financing activities		(5.8	)		-		(14.2	)		(2.4	)
Increase/(decrease) in cash and short-term investments		-			5.2		(6.1	)		8.0
Cash and short-term investments, beginning of period		-			5.7		6.1			2.9
Cash and short-term investments, end of period		-			10.9		-			10.9

Note 5

Credit Facility and Long-Term Debt

(unaudited)	September 30,		December 31,
(millions of dollars)	2008		2007

Senior Credit Facility		482.0		507.0
7.13% Series A Senior Notes due 2010		52.9		54.5
7.99% Series B Senior Notes due 2010		5.3		5.5
6.89% Series C Senior Notes due 2012		5.9		6.4
		546.1		573.4

The Senior Credit Facility consists of a $475.0 million senior term loan and a $250.0 million senior revolving credit facility. At September 30, 2008, $7.0 million was outstanding under our senior revolving credit facility, leaving $243.0 million available for future borrowings. The interest rate on the Senior Credit Facility averaged 3.31 per cent for the three months ended September 30, 2008 (2007 – 5.97 per cent), while for the nine months ended September 30, 2008 the interest rate on the Senior Credit Facility averaged 3.93 per cent (2007 – 6.02 per cent). After hedging activity, the interest rate incurred on the Senior Credit Facility averaged 5.23 per cent for the three months ended September 30, 2008 (2007 – 5.70 per cent) and 5.18 per cent for the nine months ended September 30, 2008 (2007 – 5.52 per cent). Prior to hedging activities, the interest rate was 3.36 per cent at September 30, 2008 (December 31, 2007 – 5.62 per cent). At September 30, 2008, we were in compliance with our financial covenants.

Annual maturities are as follows: 2008 - $2.3 million; 2009 - $4.4 million; 2010 - $53.5 million; 2011 - $482.8 million; and, thereafter - $3.1 million.

Note 6

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 the general partner’s two per cent interest, plus an amount equal to incentive distributions. Incentive distributions are received by 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 September 30,						Nine months ended September 30,
(millions of dollars except per unit)	2008			2007			2008			2007
Net income		28.3			24.6			81.1			62.3
Net income allocated to general partner
General partner interest		(0.6	)		(0.4	)		(1.6	)		(1.2	)
Incentive distribution income allocation		(2.6	)		(1.8	)		(7.0	)		(4.1	)
		(3.2	)		(2.2	)		(8.6	)		(5.3	)
Net income allocable to common units		25.1			22.4			72.5			57.0
Weighted average common units outstanding (millions)		34.9			34.9			34.9			31.5
Net income per common unit	$	0.72		$	0.64		$	2.08		$	1.81

Note 7

Cash Distributions

For the three and nine months ended September 30, 2008, we distributed $0.705 and $2.07 per common unit (2007 – $0.655 and $1.905 per common unit). The distributions for the three and nine months ended September 30, 2008 included incentive distributions to the general partner of $2.6 million and $7.0 million (2007 - $1.8 million and $4.1 million).

Note 8

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 $0.5 million and $1.6 million for the three and nine months ended September 30, 2008 (2007 - $0.5 million and $1.4 million).

TCNB became the operator of Northern Border effective April 1, 2007. The operator of Great Lakes became a wholly-owned subsidiary of TransCanada through TransCanada’s acquisition of Great Lakes Gas Transmission Company on February 22, 2007. TCNB also became the operator of Tuscarora, as part of the December 19, 2006 acquisition of an additional 49 per cent general partner interest in Tuscarora. TransCanada and its affiliates provide capital and operating services to Great Lakes, Northern Border and Tuscarora (together, “our pipeline systems”). TransCanada and its affiliates incur costs on behalf of our pipeline systems, including, but not limited to, employee salary and benefit costs, property and liability insurance costs, and transition costs. Total costs charged to our pipeline systems during the three and nine months ended September 30, 2008 and 2007 by TransCanada and its affiliates and amounts owed to TransCanada and its affiliates at September 30, 2008 and December 31, 2007 are summarized in the following tables:

(unaudited)	Three months ended September 30,				Nine months ended September 30,
(millions of dollars)	2008		2007		2008		2007 (1)

Costs charged by TransCanada and its affiliates:
Great Lakes		8.2		5.2		23.4		22.2
Northern Border		7.5		7.4		23.5		14.9
Tuscarora		0.9		0.8		2.9		1.7
Impact on the Partnership's net income:
Great Lakes		3.6		2.4		10.1		10.3
Northern Border		3.2		3.7		9.6		7.5
Tuscarora		0.7		0.8		2.0		1.7

(1) The amounts disclosed for Great Lakes are for the period February 23 to September 30, 2007. The amounts disclosed for Northern Border are for the period April 1 to September 30, 2007.


(unaudited)	September 30,		December 31,
(millions of dollars)	2008		2007

Amount owed to TransCanada and its affiliates:
Great Lakes		8.1		1.9
Northern Border		5.1		3.0
Tuscarora		0.5		3.5

Great Lakes earns transportation revenues from TransCanada and its affiliates under fixed price contracts with remaining terms ranging from one to ten years. Great Lakes earned $40.5 million of transportation revenues under these contracts for the three months ended September 30, 2008 (2007 - $32.4 million). This amount represents 61 per cent of total revenues earned by Great Lakes for the three months ended September 30, 2008 (2007 - 50 per cent). $18.8 million of this transportation revenue is included in our equity income from Great Lakes for the three months ended September 30, 2008 (2007 - $15.1 million).

Great Lakes earned $108.7 million of transportation revenues from TransCanada and its affiliates for the nine months ended September 30, 2008 (February 23, 2007 to September 30, 2007 - $81.5 million). This amount represents 51 per cent of total revenues earned by Great Lakes for the nine months ended September 30, 2008 (February 23, 2007 to September 30, 2007 - 50 per cent). $50.5 million of this transportation revenue is included in our equity income from Great Lakes for the nine months ended September 30, 2008 (February 23, 2007 to September 30, 2007 - $37.9 million). At September 30, 2008, $13.4 million is included in Great Lakes’ receivables in regards to the transportation contracts with TransCanada and its affiliates (December 31, 2007 - $10.0 million).

In August 2008, Northern Border sold its wholly-owned subsidiary, Bison Pipeline LLC, to TransCanada for $20.0 million. In connection with this transaction, Northern Border recorded a gain on sale of $16.1 million, of which the Partnership’s share is $8.1 million. The proposed 297-mile, 24-inch diameter Bison pipeline system would extend from natural gas gathering facilities located in the Powder River Basin in Wyoming to a point of interconnection with the Northern Border pipeline system in Morton County, North Dakota.

Northern Border’s Des Plaines Project consists of the construction, ownership and operation of interconnect facilities, including a 1,600 horsepower compressor facility near Joliet, Illinois. In June 2008, in connection with the Des Plaines Project, Northern Border and ANR Pipeline Company (ANR), a wholly-owned subsidiary of TransCanada, have entered into an Interconnect Agreement, which provides that Northern Border will reimburse ANR for the cost of the interconnect facilities to be owned by ANR. In June, Northern Border paid ANR $0.5 million and it is estimated that additional costs to complete the interconnect will be $0.1 million. Northern Border will be responsible for the final costs to construct the interconnect and any difference between the final actual costs and the estimated amounts paid will be remitted by or refunded to Northern Border.

Note 9

Derivative Financial Instruments

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 $475.0 million at September 30, 2008 (December 31, 2007 - $400.0 million). At September 30, 2008, the fair value of the interest rate swaps and options accounted for as hedges was negative $11.5 million (December 31, 2007 – negative $9.8 million). Effective January 1, 2008, we adopted the provisions of Statement of Financial Accounting Standards (SFAS) No. 157, Fair Value Measurements (SFAS 157). Under SFAS 157, these financial assets and liabilities that are recorded at fair value on a recurring basis are categorized into one of three categories based upon a fair value hierarchy. We have classified all of our derivative financial instruments as level II where the fair value is determined by using valuation techniques that refer to observable market data or estimated market prices. During the three and nine months ended September 30, 2008, we recorded interest expense of $2.4 million and $4.7 million, respectively, in regards to the interest rate swaps and options. We recorded interest income of $0.4 million and $0.8 million for the three and nine months ended September 30, 2007, respectively, in regards to the interest rate swaps and options.

Note 10

Changes in Working Capital

(unaudited)	Nine months ended September 30,
(millions of dollars)	2008			2007

Decrease/(increase) in accounts receivable and other		0.5			(2.4	)
Decrease in bank indebtedness		(1.4	)		-
Decrease in accounts payable		(2.6	)		(0.3	)
Increase in accrued interest		0.5			3.2
		(3.0	)		0.5

Note 11

Accounting Pronouncements

In May 2008, the Financial Accounting Standards Board (FASB) issued SFAS No. 162, The Hierarchy of Generally Accepted Accounting Principles (SFAS No. 162) which codifies the sources of accounting principles and the related framework to be utilized in preparing financial statements in conformity with GAAP. The requirements of this standard are not expected to have a material impact on our results of operations or financial position.

In March 2008, the FASB issued SFAS No. 161, Disclosures about Derivative Instruments and Hedging Activities (SFAS No. 161) as an amendment to SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities.

SFAS No. 161 requires that objectives for using derivative instruments be disclosed in terms of underlying risk and accounting designation. SFAS No. 161 is effective for our fiscal year beginning January 1, 2009, and we are currently evaluating its applicability to our results of operations and financial position.

Note 12

Subsequent Events

On October 17, 2008, the Board of Directors of the general partner declared the Partnership’s third quarter 2008 cash distribution in the amount of $0.705 per common unit, payable on November 14, 2008, to unitholders of record on October 31, 2008. The cash distribution represents an annual cash distribution of $2.82 per common unit.

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

The following discusses the results of operations and liquidity and capital resources of TC PipeLines, LP, along with those of Great Lakes Gas Transmission Limited Partnership (Great Lakes), Northern Border Pipeline Company (Northern Border) and Tuscarora Gas Transmission Company (Tuscarora), (together “our pipeline systems”), as a result of the Partnership’s ownership interests.

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 and Section 21E of the 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. 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 distributions at their current levels;

·	the impact of unsold capacity on Great Lakes and Northern Border being greater or less than expected;

·	competitive conditions in our industry and the ability of our pipeline systems to market pipeline capacity on favorable terms, which is affected by:

o	future demand for and prices of natural gas;

o	competitive conditions in the overall natural gas and electricity markets;

o	availability of supplies of Canadian and United States (U.S.) natural gas;

o	the oversupply of natural gas in the Mid-continent market;

o	availability of additional storage capacity and current storage levels;

o	weather conditions;

o	competitive developments by Canadian and U.S. natural gas transmission companies, including the construction of the Eastern segment of the Rockies Express Pipeline (REX East) to Clarington, Ohio; and

o	development of newly discovered natural gas plays such as the Horn River and Montney shale gas plays in Western Canada, the Louisiana Haynesville shale gas play, and the Marcellus shale gas play in West Virginia, Pennsylvania, and New York.

·	the Alberta (Canada) government’s decision to implement a new royalty regime effective January 2009 may affect the amount of exploration and drilling in the Western Canada Sedimentary Basin (WCSB);

·	the decision by TransCanada to advance the Pathfinder Pipeline Project or the Bison Pipeline Project and the regulatory, financing and construction risks related to construction of interstate natural gas pipelines;

the successful completion, timing, cost, scope and future financial performance of our pipeline systems’ expansion projects could differ materially from our expectations due to availability of contractors or equipment, weather, difficulties or delays in obtaining regulatory approvals or denied applications, land owner opposition, the lack of adequate materials, labor difficulties or shortages, expansion costs that are higher than anticipated and numerous other factors beyond our control;

·	performance of contractual obligations by customers of our pipeline systems;

·	the imposition of state income taxes on partnerships;

·	operating hazards, natural disasters, weather-related delays, casualty losses and other matters beyond our control;

·	the impact of current and future laws, rulings and governmental regulations, particularly Federal Energy Regulatory Commission (FERC) regulations, on us and our pipeline systems;

·	our ability to control operating costs; and

·	prevailing economic conditions, including the current uncertainty in the global economic markets, that impact the capital and equity markets and our ability to access these markets.

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 our annual report on Form 10-K for the year ended December 31, 2007 and Item 1A. “Risk Factors” of this report. All forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by these factors. The forward-looking statements and information is 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.

The following discussion and analysis should be read in conjunction with our 2007 Annual Report on Form 10-K and the unaudited financial statements and notes thereto included in Item 1. “Financial Statements” of this Quarterly Report on Form 10-Q. All amounts are stated in U.S. dollars.

PARTNERSHIP OVERVIEW

TC PipeLines, LP was formed in 1998 as a Delaware limited partnership by TransCanada PipeLines Limited, a wholly-owned subsidiary of TransCanada Corporation (collectively referred to herein as TransCanada), to acquire, own and participate in the management of energy infrastructure assets in North America. Our strategic focus is on delivering stable, sustainable cash distributions to our unitholders and finding opportunities to increase cash distributions while maintaining a low risk profile.

TC PipeLines, LP and its subsidiaries are collectively referred to herein as “TC PipeLines” or “the Partnership.” In this report, references to “we”, “us” or “our” collectively refer to TC PipeLines or the Partnership. The general partner of the Partnership is TC PipeLines GP, Inc., a wholly-owned subsidiary of TransCanada.

We own a 46.45 per cent partner interest in Great Lakes, which we acquired on February 22, 2007 from El Paso Corporation. The other 53.55 per cent general partner interest in Great Lakes is held by TransCanada.

We own a 50 per cent general partner interest in Northern Border, while the other 50 per cent interest is held by ONEOK Partners, L.P., a publicly traded limited partnership that is controlled by ONEOK, Inc.

As of December 31, 2007, we acquired the remaining two per cent general partner interest in Tuscarora, thereby making it a wholly-owned subsidiary.

Our partner interests in Great Lakes, Northern Border and Tuscarora represent our only material assets at September 30, 2008. As a result, we are dependent upon our pipeline systems for all of our available cash. Our pipeline systems derive their operating revenue from transportation of natural gas.

Great Lakes Overview

Great Lakes is a Delaware limited partnership formed in 1990. Great Lakes was originally constructed as an operational loop of the TransCanada Mainline Northern Ontario system. Great Lakes receives natural gas from TransCanada at the Canadian border near Emerson, Manitoba and extends across Minnesota, Northern Wisconsin and Michigan, and redelivers gas to TransCanada at the Canadian border at Sault Ste. Marie, Michigan and St. Clair, Michigan.

Northern Border Overview

Northern Border is a Texas general partnership formed in 1978. Northern Border transports natural gas from the Canadian border near Port of Morgan, Montana to a terminus near North Hayden, Indiana. Additionally, Northern Border transports natural gas produced in the Williston Basin of Montana and North Dakota and the Powder River Basin of Wyoming and Montana and synthetic gas produced at the Dakota Gasification plant in North Dakota.

Tuscarora Overview

Tuscarora is a Nevada general partnership formed in 1993. Tuscarora originates at an interconnection point with existing facilities of Gas Transmission Northwest Corporation, a wholly-owned subsidiary of TransCanada, near Malin, Oregon and runs southeast through Northeastern California and Northwestern Nevada. Tuscarora’s pipeline system terminates near Wadsworth, Nevada. Along its route, deliveries are made in Oregon, Northern California and Northwestern Nevada.

FACTORS THAT IMPACT THE BUSINESS OF OUR PIPELINE SYSTEMS

Key factors that impact the business of our pipeline systems are the supply of and demand for natural gas in the markets in which our pipeline systems operate; the customers of our pipeline systems and the mix of services they require; competition; and government regulation of natural gas pipelines.

Supply and Demand of Natural Gas

Our pipeline systems depend upon the WCSB for the majority of the natural gas that they transport. Overall flows out of the WCSB were lower for the nine months ended September 30, 2008 as compared to the same period last year, due mainly to a decrease in production, and an increase in Canadian demand. WCSB exports are expected to be lower for the remainder of the year. Factors which may mitigate declines related to WCSB production in the future include strengthening gas prices, decreases in oil prices as they affect demand from Alberta oil sands operations, continued clarification of the Alberta Royalty Regime to take effect January 1, 2009 as it affects natural gas production, and announcements regarding potential natural gas supply discoveries in the Horn River and Montney shale gas plays in Western Canada. Reduced supplies available for Canadian export affects all U.S. pipelines that import natural gas from Canada, but the impact on our pipeline systems will depend upon competitive factors and prevailing market conditions in each of the markets that our pipeline systems serve. Flows on Great Lakes’ pipeline system in the third quarter of 2008 were consistent with flows in the third quarter of 2007 due to annual contracts and reduced storage inventories which resulted in strong demand for transportation to Michigan and Ontario storage locations. As expected, flows on Northern Border’s pipeline system in the third quarter of 2008 were lower than the third quarter of 2007.

The Rockies Express Pipeline is a proposed 1,679-mile natural gas pipeline system from Rio Blanco County, Colorado, to Monroe County, Ohio. The Western segment of the Rockies Express Pipeline (REX West) from Weld County, Colorado to Audrain County, Missouri went into full service in May 2008. REX West has had a minimal impact on Great Lakes; however, it has caused excess natural gas supply from the Rockies Basin to flow into the Mid-Continent market, which is the market served by Northern Border. Consequently, there is less demand for WCSB supply in the Mid-Continent market which has had a negative impact on Northern Border’s flows and sales of available capacity in the second and third quarters of 2008. It is anticipated that increased winter demand will dampen the impact of REX West deliveries into the Mid-Continent that has increased supply in Northern Border’s market region.

REX East is planned to extend from Audrain County, Missouri to Clarington, located in Monroe County, Ohio. Once in-service, REX East should improve the competitive position of Canadian supply with gas sourced from other supply basins, including the Rockies Basin, into the Mid-Continent, which may potentially mitigate some of the excess supply in the Mid-Continent market. REX East will compete with Great Lakes in some markets, but will also potentially create demand for Great Lakes’ transportation of natural gas from REX East seeking access to and from storage locations in Michigan. It is now anticipated that the partial in-service and full in-service of REX East will occur in the second and fourth quarters of 2009, respectively. Although there can be no assurance on the timing or impact of REX East, we believe that any positive impact on the market Northern Border serves will not occur until 2010.

There are many proposed natural gas pipeline projects that, if built, would impact the markets served by our pipeline systems. Two proposed projects, the Pathfinder Pipeline Project (Pathfinder Project) and the Bison Pipeline Project (Bison Project), if built, would diversify Northern Border’s natural gas supply sources and provide another transportation source for shippers to export natural gas supply from the Rockies Basin. Please see the Recent Developments disclosure in this section for information on the Bison Project and the Pathfinder Project.

Reduced storage inventories in Eastern Canada and the U.S. supported demand for Great Lakes’ transportation, as customers utilized Great Lakes’ transportation to access and fill storage locations adjacent to its pipeline in the last quarter.

Great Lakes’ future transportation values have continued to increase throughout this year, partially due to the increase in TransCanada Mainline tolls, and partially because of strong spread values between Alberta and Dawn, Ontario. As a result, Great Lakes sold new and renewed long and short haul contracts at maximum tariff rates for the next two years. However, now that Michigan and Ontario storage fill is approaching capacity, as expected for this time of year, daily and short term transportation values are decreasing.

Discoveries of new gas fields, such as the Horn River Basin and Montney gas plays in Western Canada may increase the amount of Canadian natural gas available for export. Recently, TransCanada gauged interest for new natural gas transportation service connecting the Horn River and Montney areas to its Alberta System. TransCanada received requests for gas transmission service exceeding one billion cubic feet per day (Bcf/d) for each area by 2012. Following this, TransCanada launched two binding open seasons seeking requests for firm transportation service from customers for the Groundbirch Project (a pipeline project designed to connect the Montney area of North East British Columbia to TransCanada’s Alberta System) and the Horn River Project (a pipeline project designed to connect the Horn River area of North East British Columbia to TransCanada’s Alberta system). The Groundbirch Project has an estimated in-service date of late 2010, while the Horn River Project has an estimate in-service date of early 2011. These gas plays, as well as the development of the Louisiana Haynesville shale gas play and the discovery of the Marcellus shale gas play in West Virginia, Pennsylvania, and New York in the U.S. will affect competitive factors and market conditions in the natural gas industry.

Contracting

Great Lakes – Great Lakes’ average contracted capacity for the quarter ended September 30, 2008 was 98 per cent of its design capacity (2007 – 98 per cent). For the nine months ended September 30, 2008, Great Lakes’ average contracted capacity was 104 per cent of its design capacity (period of March 1, 2007 to September 30, 2007 - 100 per cent). At September 30, 2008, 103 per cent of capacity was contracted on a firm basis for the remainder of the year and the weighted average remaining life of firm transportation contracts was 2.1 years.

In the third quarter of 2008, Great Lakes sold all of its available long haul capacity beginning November 1, 2008 for one year at maximum rates, sold available annual short haul capacity in Michigan at maximum rates for one to two year terms, and sold its available winter seasonal long haul capacity at maximum rates.

Northern Border – Northern Border’s average contracted capacity for the quarter ended September 30, 2008 was 79 per cent of its design capacity (2007 - 102 per cent). For the nine months ended September 30, 2008, Northern Border’s average contracted capacity was 86 per cent of its design capacity (2007 - 96 per cent). At September 30, 2008, approximately 78 per cent of Northern Border’s design capacity was contracted on a firm basis for the remainder of the year and the weighted average remaining contract life of firm transportation contracts was 2.0 years.

At January 1, 2009, Northern Border’s total amount of available transportation capacity is expected to be approximately 800 million cubic feet per day (MMcf/d). Northern Border’s capacity to Chicago remains attractive and continues to be fully contracted and legacy contracts set to expire in the near term have been renewed. Additionally, related to a proposed expansion project, Northern Border renewed approximately 350 MMcf/d at maximum and discounted rates, for terms ranging from five to twelve years for various transportation paths to Chicago. See additional information below in Recent Developments – Chicago IV Project for more information.

Prevailing market conditions and increasing competitive factors in North America, including REX West, have caused Northern Border to experience a reduction in its revenues due to lower capacity sales and greater discounting of its rates. These factors, as well as expirations of certain long term contracts, will continue to impact Northern Border’s ability to market its available capacity into 2009. Northern Border expects to continue to discount transportation capacity as needed to optimize revenue.

Northern Border has executed long-term contracts of approximately 400 MMcf/d sold at a discounted rate from Port of Morgan, Montana to Ventura, Iowa contingent upon either the Bison Project or Pathfinder Project going forward. These contracts would be effective at the successful project’s in-service date projected for late 2010.

Tuscarora - Tuscarora’s average contracted capacity for the quarter ended September 30, 2008 was 98 per cent of its design capacity (2007 – 95 per cent). For the nine months ended September 30, 2008, Tuscarora’s average contracted capacity was 98 per cent of its design capacity (2007 – 96 per cent). At September 30, 2008, approximately 99 per cent of Tuscarora’s design capacity was contracted on a firm basis for the remainder of the year and the weighted average remaining contract life of firm transportation contracts was 12.0 years.

RECENT DEVELOPMENTS

Northern Border

Bison Project – On September 3, 2008, Northern Border announced the sale of its wholly-owned subsidiary, Bison Pipeline LLC, to TransCanada Pipeline USA Ltd., a wholly-owned subsidiary of TransCanada for $20.0 million. Distributions paid by Northern Border to its partners in the third quarter included a special distribution in the amount of $16.4 million, of which the Partnership’s share was $8.2 million. As a part of the transaction, TransCanada has assumed the obligations of Northern Border related to the Bison Project, and is continuing to solicit commercial support for the Bison Project.

The assets and obligations of Bison Pipeline LLC included executed precedent agreements subject to certain shipper contingencies, as well as regulatory, environmental and engineering activities completed to date on the Bison Project. Shippers on the Bison Project have executed contracts for capacity on the Northern Border system from Port of Morgan, Montana, to Ventura, Iowa, subject to the in-service date of the Bison Project. Project subscription that is subject to the upstream capacity condition is approximately 400 MMcf/d.

The proposed 297-mile, 24-inch diameter Bison pipeline system would extend from natural gas gathering facilities located in the Powder River Basin in Wyoming to a point of interconnection with the Northern Border pipeline system in Morton County, North Dakota. The initial capacity of the Bison Project is anticipated to be approximately 400 MMcf/d. The projected in-service date is late 2010.

The proposed Pathfinder Project is an approximately 673-mile, 36-inch diameter interstate pipeline that would transport natural gas northeast from Meeker, Colorado, through Montana to the Northern Border pipeline system in North Dakota for delivery into the Ventura and Chicago-area markets. The capacity is between 1.2 to 1.6 Bcf/d. In September 2008, Enterprise Product Partners L.P. terminated their previously-announced commitment to become a 50 per cent partner in Pathfinder with a 500 MMcf/d shipping commitment. TransCanada is continuing to work with prospective Pathfinder shippers to advance this project.

The success of either the Bison or Pathfinder Projects is dependent upon many factors, and there is no certainty that either of these projects will be constructed. For further information regarding the risks related to the construction projects, please refer to the Risk Factors sections in our 2007 Annual Report on Form 10-K and in this report.

Proposed Expansion Project (Chicago IV) – Northern Border conducted a binding open season seeking interest in an expansion project from Harper, Iowa to Manhattan, Illinois and received binding shipper commitments. The proposed expansion capacity was subject to a one-time adjustment right to reduce the Chicago IV commitments resulting from the right of first refusal (ROFR) process in current shipper contracts. During a ROFR process, its bidders are able to obtain existing capacity with similar terms. If the Chicago IV bidders reduce their commitments, it could eliminate the need for an expansion project. Northern Border renewed approximately 350 MMcf/d at maximum and discount rates, for terms ranging from 5 to 12 years for various transportation paths to Chicago.

Des Plaines Project – In February 2008, Northern Border filed with the FERC to construct, own and operate interconnect facilities, including a 1,600 horsepower compressor facility near Joliet, Illinois. It is estimated that the Des Plaines Project will cost approximately $18 million and will be financed by a combination of debt and equity. In June 2008, the FERC issued its environmental assessment report for the Des Plaines Project and no comments were filed during the comment period. A certificate order by FERC authorizing construction of the Des Plaines Project was received on July 25, 2008. Northern Border commenced construction on the Des Plaines Project on September 8, 2008, and it is now expected the facilities will be placed into service by early 2009.

Tuscarora

Compressor Station Expansion Project – Tuscarora’s compressor station expansion project to support Sierra Pacific Power Company’s Tracy Combined Cycle Power Plant went into service on April 1, 2008, with a final cost within the original cost estimate. The new contract for 40,000 Dth/d for a term of 22-1/2 years will generate approximately $5.8 million of annual revenue.

REGULATORY DEVELOPMENTS

Composition of Proxy Groups for Rates of Return Determinations – On July 19, 2007, the FERC issued a policy statement proposing to update its standards regarding the composition of proxy groups for determining the appropriate returns on equity (ROE) for natural gas and oil pipelines, which is used by pipelines to establish rates for services. On April 17, 2008, the FERC issued a policy statement (2008 Policy Statement) that allows master limited partnerships (MLPs) to be included in a proxy group used to determine a pipeline’s ROE. The 2008 Policy Statement is effective immediately and provides that there should be no cap on the level of distributions included in the current Discounted Cash Flow (DCF) methodology for MLPs, but there should be an adjustment to the long-term growth rate used to calculate DCF for an MLP (halving the long-term GDP factor which has a one-third weighting in the total growth rate computation in the DCF methodology).

The impact of applying this new policy to our pipeline systems will not be known until one of our pipeline systems files a rate case.

Promotion of a More Efficient Capacity Release Market Docket No. RM08-1 – On June 19, 2008, the FERC issued a Final Rule to modify capacity release regulations (Capacity Release Final Rule). The Capacity Release Final Rule, in addition to other items, allows market-based pricing for short-term capacity releases by shippers through a permanent lifting of the maximum rate cap on short-term capacity releases (of one year or less terms). The Capacity Release Final Rule was effective July 30, 2008.

While implementation of the Capacity Release Final Rule is not expected to have a significant impact on our pipeline systems, the Interstate Natural Gas Association of America (INGAA), of which our pipeline systems are members, filed on July 21, 2008 a request for rehearing of the Capacity Release Final Rule, contending that as the FERC removed the rate cap for short-term released capacity, it should also remove the rate cap for short-term pipeline capacity. INGAA notes that short-term released capacity and short-term pipeline capacity compete in the same market, and argues that removing the rate cap for short-term released capacity and maintaining the cap for short-term pipeline capacity results in a bifurcated and distorted short-term capacity market. On August 15, 2008, the FERC agreed to further consider the issues raised in the rehearing request. A FERC Order is pending on this matter.

Homeland Security – The Department of Homeland Security Appropriations Act of 2007 required the Transportation Security Administration (TSA) to issue regulations establishing risk-based performance standards for the security of chemical and industrial facilities, including oil and gas facilities that were deemed to present high levels of security risk. The TSA will conduct a critical facility identification process, which will include our pipeline systems, anticipated in 2009 or 2010. The TSA has also released a draft of the Pipeline Security Guidelines, which is likely to become regulation in 2009 or 2010. These guidelines distinguish between baseline security requirements for all pipeline facilities and enhanced measures for identified critical facilities. Based on the draft guidelines it is not anticipated that if our pipeline systems are deemed to be critical facilities that there would be a significant additional costs related to compliance.

RESULTS OF OPERATIONS OF TC PIPELINES

Critical Accounting Policies and Estimates

The preparation of financial statements in accordance with Generally Accepted Accounting Principles (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 our critical accounting policies and estimates during the nine months ended September 30, 2008.

Information about our critical accounting estimates is included under Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” in our Annual Report on Form 10-K for the year ended December 31, 2007.

Recent Accounting Pronouncements

In March 2008, the FASB issued Statement of Financial Accounting Standards (SFAS) No. 161, Disclosures about Derivative Instruments and Hedging Activities (SFAS No. 161) as an amendment to SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities. SFAS No. 161 requires that objectives for using derivative instruments be disclosed in terms of underlying risk and accounting designation. SFAS No. 161 is effective for our fiscal year beginning January 1, 2009, and we are currently evaluating its applicability to our results of operations and financial position.

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 in order 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 periods, 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.

The shaded areas in the tables below disclose the results from Great Lakes and Northern Border, representing 100 per cent of each entity's operations for the given period.


(unaudited)	For the three months ended September 30, 2008															For the nine months ended September 30, 2008
(millions of dollars)	PipeLP			TGTC(1)			Other			GLGT(2)			NBPC(3)			PipeLP			TGTC(1)			Other			GLGT(2)			NBPC(3)
Transmission revenues		8.2			8.2			-			66.7			67.7			23.3			23.3			-			213.9			212.8
Operating expenses		(2.3	)		(1.4	)		(0.9	)		(17.1	)		(19.3	)		(6.8	)		(3.7	)		(3.1	)		(45.9	)		(57.5	)
		5.9			6.8			(0.9	)		49.6			48.4			16.5			19.6			(3.1	)		168.0			155.3
Depreciation		(1.8	)		(1.8	)		-			(14.7	)		(15.3	)		(5.1	)		(5.1	)		-			(43.9	)		(45.8	)
Financial charges, net and other		(7.7	)		(1.1	)		(6.6	)		(8.0	)		7.1			(22.8	)		(3.1	)		(19.7	)		(24.4	)		(12.1	)
Michigan business tax		-			-			-			(1.2	)		-			-			-			-			(4.2	)		-
											25.7			40.2												95.5			97.4
Equity income		31.9			-			-			12.0			19.9			92.5			-			-			44.4			48.1
Net income		28.3			3.9			(7.5	)		12.0			19.9			81.1			11.4			(22.8	)		44.4			48.1


(unaudited)	For the three months ended September 30, 2007															For the nine months ended September 30, 2007
(millions of dollars)	PipeLP			TGTC(1)			Other			GLGT(2)			NBPC(3)			PipeLP			TGTC(1)			Other			GLGT(2)			NBPC(3)
Transmission revenues		6.7			6.7			-			65.6			79.6			20.3			20.3			-			162.2			228.0
Operating expenses		(2.2	)		(1.2	)		(1.0	)		(12.6	)		(21.6	)		(6.4	)		(3.7	)		(2.7	)		(34.0	)		(61.7	)
		4.5			5.5			(1.0	)		53.0			58.0			13.9			16.6			(2.7	)		128.2			166.3
Depreciation		(1.6	)		(1.6	)		-			(14.5	)		(15.1	)		(4.7	)		(4.7	)		-			(34.9	)		(45.6	)
Financial charges, net and other		(8.7	)		(1.0	)		(7.7	)		(8.1	)		(10.2	)		(25.5	)		(3.4	)		(22.1	)		(19.5	)		(30.9	)
											30.4			32.7												73.8			89.8
Equity income		30.4			-			-			14.2			16.2			78.6			-			-			34.3			44.3
Net income		24.6			2.9			(8.7	)		14.2			16.2			62.3			8.5			(24.8	)		34.3			44.3

(1) The Partnership owns a 100 per cent general partner interest in Tuscarora Gas Transmission Company (Tuscarora or TGTC) following the acquisition of an additional two per cent interest on December 31, 2007.

(2) The Partnership acquired a 46.45 per cent partner interest in Great Lakes Gas Transmission Limited Partnership (Great Lakes or GLGT) on February 22, 2007.

(3) The Partnership owns a 50 per cent general partner interest in Northern Border Pipeline Company (Northern Border or NBPC). Equity income from Northern Border includes amortization of a $10.0 million transaction fee paid to the operator of Northern Border at the time of the additional 20 per cent acquisition in April 2006.

Third Quarter 2008 compared with Third Quarter 2007

Net income increased $3.7 million, or 15 per cent, to $28.3 million in the third quarter of 2008, compared to $24.6 million in the third quarter of 2007. This increase was primarily due to higher equity income from Northern Border, increased Tuscarora transmission revenues and lower financial charges, net and other, partially offset by decreased equity income from Great Lakes.

Equity income from Great Lakes was $12.0 million in the third quarter of 2008, a decrease of $2.2 million or 15 per cent, compared to $14.2 million for the same period last year. The decrease in equity income was primarily due to increased operating expenses and Michigan business tax (a partnership level tax that was instituted in 2008), partially offset by increased transmission revenues. At Great Lakes’ level, operating expenses increased $4.5 million for the three months ended September 30, 2008 compared to the same period last year primarily due to higher taxes other than income, costs related to system integration expenditures and increased pipeline maintenance costs. Michigan business tax of $1.2 million was recorded for the three months ended September 30, 2008. Great Lakes’ transmission revenues increased $1.1 million for the three months ended September 30, 2008 compared to the same period last year due primarily to higher short-term revenues from increased sales of daily transport capacity.

Equity income from Northern Border was $19.9 million in the third quarter of 2008, an increase of $3.7 million or 23 per cent, compared to $16.2 million in the same period last year. This is primarily due to a $16.1 million gain on sale of Bison Pipeline LLC and decreased operating expenses, partially offset by lower transmission revenues. At Northern Border’s level, operating expenses decreased $2.3 million for the three months ended September 30, 2008 compared to the same period last year primarily due to decreased maintenance costs, decreased electric compressor charges related to lower capacity utilization and decreased taxes other than income. Northern Border’s transmission revenues decreased $11.9 million, or 15 per cent, for the three months ended September 30, 2008 compared to the same period last year due primarily to a decrease in system utilization mainly related to natural gas supply from the Rockies Basin into the Mid-Continent market from the in-service of REX West.

Tuscarora’s net income was $3.9 million in the third quarter of 2008, an increase of $1.0 million or 34 per cent, compared to $2.9 million in the same period last year. The increase in net income is primarily due to increased transmission revenues resulting from a new firm transportation service contract which supported the Likely compressor station expansion project that went into service on April 1, 2008.

Financial charges, net and other were $7.7 million in the third quarter of 2008, a decrease of $1.0 million or 11 per cent, compared to $8.7 million in the same period last year. This decrease relates primarily to lower interest rates and lower average debt outstanding, partially offset by losses on interest rate derivatives over the same period in 2007.

Nine Months Ended September 30, 2008 compared with Nine Months Ended September 30, 2007

Net income increased $18.8 million, or 30 per cent, to $81.1 million for the nine months ended September 30, 2008, compared to $62.3 million in the same period of 2007. The increase in net income was primarily due to increased equity income from Great Lakes and Northern Border, higher Tuscarora transmission revenues and lower financial charges, net and other.

Equity income from Great Lakes was $44.4 million for the nine months ended September 30, 2008, an increase of $10.1 million or 29 per cent, compared to $34.3 million for the period February 23 to September 30, 2007. The increase in equity income was primarily due to a full first quarter of income contribution in 2008 as compared to 37 days in the first quarter of 2007. In addition, Great Lakes’ transmission revenues increased primarily due to increased sales of short term transport capacity, partially offset by costs related to system integration expenditures and increased pipe integrity costs. In the nine months ended September 30, 2008, Great Lakes recorded Michigan business tax of $4.2 million, which is a new partnership level tax that was instituted in 2008.

Equity income from Northern Border was $48.1 million for the nine months ended September 30, 2008, an increase of $3.8 million or 9 per cent, compared to $44.3 million in the same period of 2007. The increase in equity income is primarily due to a $16.1 million gain on sale of Bison Pipeline LLC, and decreased operating expenses, partially offset by lower transmission revenues. At Northern Border’s level, operating expenses decreased by $4.2 million in the nine months ended September 30, 2008 compared to the same period last year. This decrease in operating expenses is primarily due to decreased taxes other than income and a $2.3 million transition related charge in 2007 related to the reimbursement for shared equipment and furnishings, partially offset by increased general and administrative expenses and electric compressor charges. Northern Border’s transmission revenues decreased by $15.2 million in the nine months ended September 30, 2008 compared to the same period in 2007. This decrease was primarily due to a decrease in contracted capacity mainly related to natural gas supply from the Rockies Basin into the Mid-Continent market from the in-service of REX West.

Tuscarora’s net income was $11.4 million for the nine months ended September 30, 2008, an increase of $2.9 million or 34 per cent, compared to $8.5 million in the same period of 2007. The increase in net income is primarily due to increased Tuscarora transmission revenues resulting from a new firm transportation service contract which supported the Likely compressor station expansion that went into service on April 1, 2008.

Financial charges, net and other were $22.8 million for the nine months ended September 30, 2008, a decrease of $2.7 million, or 11 per cent, compared to $25.5 million for the same period of 2007. This decrease relates primarily to lower interest rates and lower average debt outstanding, partially offset by losses on interest rate derivatives over the same period in 2007.

Partnership Cash Flows

The Partnership uses the non-GAAP financial measures ‘Partnership cash flows’ and ‘Partnership cash flows allocated to common units’ as financial performance measures. As the Partnership’s financial performance underpins the availability of cash flows to fund the cash distributions that the Partnership pays to its unitholders, the Partnership believes these are key measures of the available cash flows to its unitholders. The following Partnership cash flows information is presented to enhance investors’ understanding of the way that management analyzes the Partnership’s financial performance. Partnership cash flows and Partnership cash flows allocated to common units are provided as a supplement to financial results and are not meant to be considered in isolation or as substitutes for financial results prepared in accordance with GAAP.

(unaudited)	Three months ended September 30,						Nine months ended September 30,
(millions of dollars except per common unit amounts)	2008			2007			2008			2007
Net Income		28.3			24.6			81.1			62.3
Add:
Cash flows provided by Tuscarora's operating activities		7.2			4.6			17.3			13.5
Cash distributions from Great Lakes		19.3			17.4			55.0			41.0
Cash distributions from Northern Border		22.6			14.8			72.0			62.5
		49.1			36.8			144.3			117.0
Less:
Tuscarora's net income		(3.9	)		(2.9	)		(11.4	)		(8.5	)
Equity income from investment in Great Lakes		(12.0	)		(14.2	)		(44.4	)		(34.3	)
Equity income from investment in Northern Border		(19.9	)		(16.2	)		(48.1	)		(44.3	)
		(35.8	)		(33.3	)		(103.9	)		(87.1	)
Partnership cash flows		41.6			28.1			121.5			92.2
Partnership cash flows allocated to general partner (1)		(3.2	)		(2.3	)		(8.6	)		(5.3	)
Partnership cash flows allocated to common units		38.4			25.8			112.9			86.9
Cash distributions declared		(27.8	)		(25.4	)		(83.0	)		(75.4	)
Cash distributions declared per common unit (2)	$	0.705		$	0.660		$	2.110		$	1.965
Cash distributions paid		(27.8	)		(25.1	)		(80.8	)		(61.3	)
Cash distributions paid per common unit (2)	$	0.705		$	0.655		$	2.070		$	1.905
Weighted average common units outstanding (millions)		34.9			34.9			34.9			31.5

(1) Partnership cash flows allocated to general partner represents the cash distributions paid to the general partner with respect to its two per cent interest plus an amount equal to incentive distributions.

(2) 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 per cent interest plus an amount equal to incentive distributions.

Third Quarter 2008 compared with Third Quarter 2007

Partnership cash flows increased $13.5 million, or 48 per cent, to $41.6 million for the third quarter of 2008, compared to $28.1 million for the same period last year. This increase was primarily due to higher cash distributions received from Great Lakes and Northern Border, increased cash flows provided by Tuscarora’s operating activities and lower costs at the Partnership level. Cash distributions from Great Lakes and Northern Border increased by $9.7 million in total for the three months ended September 30, 2008 compared with the same period last year. This increase in cash distributions was primarily due to the special distribution of $8.2 million received from Northern Border in relation to the gain on sale of Bison Pipeline LLC. Cash flows provided by Tuscarora’s operating activities increased by $2.6 million for the quarter ended September 30, 2008 compared with the same period last year primarily due to higher transmission revenues resulting from the Likely compressor station expansion project that went into service on April 1, 2008. Costs at the Partnership level decreased by $1.2 million for the quarter ended September 30, 2008 compared with the same period last year primarily due to lower interest rates and lower average debt outstanding, partially offset by losses on interest rate derivatives over the same period in 2007.

During the three months ended September 30, 2008, Tuscarora made capital expenditures of $1.0 million related to the compressor station expansion project in Likely, California compared to $0.9 million for the same period last year. In the third quarter of 2007, a net $1.8 million was received related to the Great Lakes acquisition closing adjustments.

The Partnership paid distributions of $27.8 million in the third quarter of 2008, an increase of $2.7 million, or 11 per cent, compared to $25.1 million for the same period in the prior year due to increases in quarterly per common unit distribution amounts. We repaid a net $3.0 million of the outstanding balance on our debt during the third quarter of 2008 compared to a net issuance of debt of $1.0 million during the same period last year.

Nine Months Ended September 30, 2008 compared with Nine Months Ended September 30, 2007

Partnership cash flows increased $29.3 million, or 32 per cent, to $121.5 million for the nine months ended September 30, 2008, compared to $92.2 million for the same period last year. This increase was primarily a result of increased cash distributions from Great Lakes and Northern Border, increased cash flows provided by Tuscarora’s operating activities and decreased costs at the Partnership level.

Cash distributions from Great Lakes were $55.0 million for the nine months ended September 30, 2008, an increase of $14.0 million compared to $41.0 million for the same period last year. The increase in cash distributions from Great Lakes is due primarily to a full nine months of ownership in 2008 compared to the period of February 23 to September 30 for 2007. Cash distributions from Northern Border increased $9.5 million for the nine months ended September 30, 2008 compared to the same period in the prior year due primarily to the special distribution of $8.2 million received from Northern Border in relation to the gain on sale of Bison Pipeline LLC. Cash flows provided by Tuscarora’s operating activities increased $3.8 million for the nine months ended September 30, 2008 compared to the same period in the prior year primarily due to the financial results from the Likely compressor station expansion project that went into service on April 1, 2008. Costs at the Partnership level decreased by $2.0 million for the nine months ended September 30, 2008 compared with the same period last year primarily due to lower average debt outstanding and lower interest rates, partially offset by losses on interest rate derivatives and increased general and administrative costs.

During the nine months ended September 30, 2008, Tuscarora made capital expenditures of $6.4 million related to the compressor station expansion project in Likely, California compared to $4.4 million for the same period last year. In February 2007, the Partnership acquired a 46.45 per cent interest in Great Lakes from El Paso Corporation for $733.0 million in cash. In April 2007, the Partnership made a contribution of $7.5 million to Northern Border, representing the Partnership’s 50 per cent share of a $15.0 million cash call issued by Northern Border.

The Partnership paid distributions of $80.8 million for the nine months ended September 30, 2008, an increase of $19.5 million, or 32 per cent, compared to $61.3 million for the same period in the prior year due to the increase in the number of common units outstanding, in addition to increases in quarterly per common unit distribution amounts. We repaid a net $27.3 million of the outstanding balance on our debt during the nine months ended September 30, 2008. In 2007, net equity issuances provided $607.0 million, including the general partner’s contribution to maintain its two per cent interest, to acquire Great Lakes. The Partnership funded the balance of the acquisition cost with a draw on its senior credit facility.

LIQUIDITY AND CAPITAL RESOURCES OF TC PIPELINES

Overview

Our principal sources of liquidity include distributions received from our investments in Great Lakes and Northern Border, operating cash flows from 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.

The Partnership’s Debt and Credit Facility

The following table summarizes our debt and credit facility outstanding as of September 30, 2008:

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

Senior Credit Facility		482.0		-		482.0
7.13% Series A Senior Notes due 2010		52.9		3.2		49.7
7.99% Series B Senior Notes due 2010		5.3		0.5		4.8
6.89% Series C Senior Notes due 2012		5.9		0.8		5.1
Total		546.1		4.5		541.6

The Senior Credit Facility consists of a $475.0 million senior term loan and a $250.0 million senior revolving credit facility. The interest rate on the Senior Credit Facility averaged 3.31 per cent for the three months ended September 30, 2008 (2007 – 5.97 per cent), while for the nine months ended September 30, 2008 the interest rate on the Senior Credit Facility averaged 3.93 per cent (2007 – 6.02 per cent). After hedging activity, the interest rate incurred on the Senior Credit Facility averaged 5.23 per cent for the three months ended September 30, 2008 (2007 – 5.70 per cent) and 5.18 per cent for the nine months ended September 30, 2008 (2007 – 5.52 per cent). Prior to hedging activities, the interest rate was 3.36 per cent at September 30, 2008 (December 31, 2007 – 5.62 per cent). At September 30, 2008, we were in compliance with our financial covenants.

In spite of the current volatility in the capital markets, neither the Partnership nor its pipeline systems have experienced significant impacts to liquidity or access to the credit markets, although continued volatility in the capital markets may increase costs associated with borrowing.

The Partnership views its core banking group as high quality and has a well-established relationship with these institutions. As of November 3, 2008, the Partnership had no outstanding borrowings under the $250.0 million revolving portion of the Senior Credit Facility. The Partnership has an existing $250.0 million debt and equity shelf expiring December 1, 2008 which it expects to renew in the fourth quarter 2008. This will supplement the $250.0 million of capacity available under the Partnership’s existing revolving credit and term loan facility which expires on December 12, 2011.

Interest Rate Swaps and Options

We use derivatives to assist in managing our 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 $475.0 million at September 30, 2008 (December 31, 2007 - $400.0 million). At September 30, 2008, the fair value of the interest rate swaps and options accounted for as hedges was negative $11.5 million (December 31, 2007 – negative $9.8 million). Effective January 1, 2008, we adopted the provisions of Statement of Financial Accounting Standards (SFAS) No. 157, Fair Value Measurements (SFAS 157). Under SFAS 157, these financial assets and liabilities that are recorded at fair value on a recurring basis are categorized into one of three categories based upon a fair value hierarchy. We have classified all our derivative financial instruments as level II where the fair value is determined by using valuation techniques that refer to observable market data or estimated market prices. During the three and nine months ended September 30, 2008, we recorded interest expense of $2.4 million and $4.7 million, respectively, in regards to the interest rate swaps and options. We recorded interest income of $0.4 million and $0.8 million for the three and nine months ended September 30, 2007, respectively, in regards to the interest rate swaps and options.

2008 Third Quarter Cash Distribution

On October 17, 2008, the Board of Directors of the general partner declared the Partnership’s 2008 third quarter cash distribution. The third quarter cash distribution will be paid on November 14, 2008 to unitholders of record as of October 31, 2008, totaling $27.8 million and will be paid in the following manner: $24.6 million to common unitholders (including $1.4 million to the general partner as holder of 2,035,106 common units and $6.1 million to TransCan Northern Ltd. as holder of 8,678,045 common units), $2.6 million to the general partner as holder of the incentive distribution rights, and $0.6 million to the general partner in respect of its two per cent general partner interest.

2009 Capital Requirements

Northern Border’s distribution policy adopted in 2006 defines minimum equity to total capitalization to be used by the Management Committee to establish the timing and amount of required equity contributions. In accordance with this policy and in anticipation of the equity financing of Northern Border's Des Plaines Project, Northern Border currently estimates an equity contribution of approximately $85 million in the upcoming year, of which the Partnership's share would be approximately $43 million. The Partnership expects to finance this equity contribution with a combination of debt and operating cash flows.

LIQUIDITY AND CAPITAL RESOURCES OF OUR PIPELINE SYSTEMS

Overview

Our pipeline systems’ principal source of liquidity is cash generated from operating activities and bank credit facilities. Our pipeline systems fund their operating expenses, debt service and cash distributions to partners primarily with operating cash flow.

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

Our pipeline systems believe that their ability to obtain financing at reasonable rates and 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, which allow them to request credit support as circumstances dictate. Additionally, Northern Border has established relationships with high-quality banks, which are involved in its revolving credit facility and provide liquidity for Northern Border’s operating needs.

Debt of Great Lakes

The following table summarizes Great Lakes’ debt outstanding as of September 30, 2008:

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

8.74% series Senior Notes due 2008 to 2011		40.0		10.0		30.0
6.73% series Senior Notes due 2009 to 2018		90.0		9.0		81.0
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
Total		440.0		19.0		421.0

Great Lakes is required to comply with certain financial, operational and legal covenants. Under the most restrictive covenants in the Senior Note Agreements, approximately $237.0 million of Great Lakes’ partners’ capital was restricted as to distributions as of September 30, 2008. At September 30, 2008, Great Lakes was in compliance with all of its financial covenants.

Debt, Credit Facility and Contractual Obligations of Northern Border

The following table summarizes Northern Border’s debt and credit facility outstanding as of September 30, 2008:

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

7.75% senior notes due 2009		200.0		200.0		-
7.50% senior notes due 2021		250.0		-		250.0
$250 million credit agreement due 2012(a)		172.0		-		172.0
Total		622.0		200.0		422.0

(a) Northern Border is required to pay a facility fee of 0.05% on the principal commitment amount of its credit agreement.

Revolving Credit Agreement

As of September 30, 2008, Northern Border had outstanding borrowings of $172.0 million under its $250 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 2.99 per cent at September 30, 2008.

Senior Notes due 2009

On September 1, 2009, the $200.0 million 7.75 per cent senior notes will mature. As market conditions dictate, Northern Border will finance the repayment by use of fixed-rate debt, variable-rate debt or a combination of fixed-rate and variable-rate debt.

Interest Rate Collar Agreement

At September 30, 2008, Northern Border’s balance sheet reflected an unrealized loss of approximately $2.2 million with a corresponding increase to accumulated other comprehensive loss related to the changes in fair value of its zero cost interest rate collar agreement (the “Collar Agreement”) since inception. During the three and nine months ended September 30, 2008, Northern Border recorded interest expense of $0.5 million and $1.3 million, respectively, under the Collar Agreement. Hedge ineffectiveness had no impact on income for the three and nine months ended September 30, 2008.

Contractual Obligations

Northern Border has commitments totaling approximately $2.2 million in relation to the Des Plaines Project at September 30, 2008, with total expected costs to be approximately $18 million. Half of the project costs will be financed under Northern Border’s credit facility and the other half by equity contributions from its partners. See section entitled “Recent Developments” in Item 2. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” for further discussion of this project.

RELATED PARTY TRANSACTIONS

Please read Note 8 within Item 1. “Financial Statements” for additional information regarding related party transactions.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

OVERVIEW

Our exposure to market risk discussed below includes forward-looking statements and represents an estimate of possible changes in future earnings that would occur assuming hypothetical future movements in interest rates. Our views on market risk are not necessarily indicative of actual results that may occur and do not represent the maximum possible gains and losses that may occur, since actual gains and losses will differ from those estimated, based on actual fluctuations in interest rates and the timing of transactions.

We are exposed to market risk due to interest rate fluctuations. Market risk is the risk of loss arising from adverse changes in market rates. We utilize financial instruments to manage the risks of certain identifiable or anticipated transactions to achieve a more predictable cash flow. Our risk management function follows established policies and procedures to monitor interest rates to ensure our hedging activities mitigate market risks. We do not use financial instruments for trading purposes.

In accordance with SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities we record financial instruments on the balance sheet as assets and liabilities based on fair value. We estimate the fair value of financial instruments using available market information and appropriate valuation techniques. Changes in financial instruments’ fair value are recognized in earnings unless the instrument qualifies as a hedge under SFAS No. 133 and meets specific hedge accounting criteria. Qualifying 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.

INTEREST RATE RISK

Our interest rate exposure results from our Senior Credit Facility, which is subject to variability in London Interbank Offered Rate (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. The notional amount hedged at September 30, 2008 was $475.0 million. The interest rate swaps and options are structured such that the cash flows match those of the Senior Credit Facility. The fair value of interest rate derivatives has been calculated using period-end market rates. At September 30, 2008, the fair value of our interest rate swaps and options accounted for as hedges was negative $11.5 million.

At September 30, 2008, we had $482.0 million outstanding on our Senior Credit Facility. Utilizing the conditions of the interest rate swaps and options, if LIBOR interest rates hypothetically increased by one per cent (100 basis points) compared to the rates in effect as of September 30, 2008, 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 by one per cent (100 basis points) compared to the rates in effect as of September 30, 2008, our annual interest expense would have decreased and our net income would have increased by $0.1 million. This amount has been determined by considering the impact of the hypothetical interest rates on variable rate borrowings outstanding as of September 30, 2008.

Northern Border utilizes both fixed-rate and variable-rate debt and is exposed to market risk due to the floating interest rates on its 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 of September 30, 2008, 72 per cent of Northern Border’s outstanding debt was at fixed rates. Northern Border utilizes its Collar Agreement to limit the variability of the interest rate on $140.0 million of variable-rate borrowings.

Utilizing the conditions of the Collar Agreement, if interest rates hypothetically increased one per cent (100 basis points) compared with rates in effect as of September 30, 2008, Northern Border’s annual interest expense would increase and its net income would decrease by approximately $0.3 million; and if interest rates hypothetically decreased one per cent (100 basis points) compared with rates in effect as of September 30, 2008, Northern Border’s annual interest expense would decrease and its net income would increase by approximately $0.3 million.

Great Lakes and Tuscarora utilize fixed-rate debt; therefore, they are not exposed to market risk due to floating interest rates.

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.

The state of Minnesota currently requires Great Lakes to pay use tax on the value of the shipper provided compressor fuel burned in its Minnesota compressor engines. Great Lakes is subject to primarily commodity price volatility and some volume volatility in determining the amount of use tax owed. If natural gas prices changed by $1 per million British thermal units, Great Lakes’ annual use tax expense would change by approximately $0.7 million.

The Partnership does not have any material foreign currency exchange risks.

Item 4. Controls and Procedures

EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES

Based on their evaluation of the Partnership’s disclosure controls and procedures as of the end of the period covered by this quarterly report, the principal executive officer and principal financial officer of the general partner of the Partnership have concluded that the Partnership’s disclosure controls and procedures were effective in ensuring that the information required to be disclosed by the Partnership in the reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s (SEC’s) rules and forms and that information required to be disclosed by the Partnership in the reports that the Partnership files or submits under the Exchange Act is accumulated and communicated to the management of the general partner of the Partnership, including the principal executive officer and principal financial officer, as appropriate to allow timely decisions regarding required disclosure.

Changes in Internal Control over Financial Reporting

During the quarter ended September 30, 2008, there has been no change in the Partnership’s internal control over financial reporting that has materially affected or is reasonably likely to materially affect our internal control over financial reporting.

PART II – OTHER INFORMATION

Item 1A. Risk Factors

Our business is subject to the risks described below and 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, 2007.

The following new risk factor 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, 2007:

The current capital and credit market conditions may adversely affect the Partnership or our pipeline systems’ access to capital and cost of capital.

Access to capital markets is important to the Partnership to enable it to execute its business strategies, which include seeking opportunities to undertake accretive acquisitions and organic growth projects, and maximize the value of our existing portfolio of pipeline systems. Access to capital markets is important to our pipeline systems’ ability to operate and Northern Border expects to refinance $200 million of Senior Notes in 2009. In October 2008, the general economic and capital market conditions in the United States and other parts of the world have deteriorated significantly and have adversely affected access to capital and increased the cost of capital. If these conditions continue or become worse, the Partnership’s and our pipeline systems’ future cost of debt and equity capital, and future access to capital markets could be adversely affected.

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, 2007:

The long-term financial conditions of our pipeline systems are dependent on the continued availability of Western Canadian natural gas for import into the U.S. and the market demand for these volumes. Competition from pipelines that deliver natural gas from other supply sources to our pipeline systems’ market areas could cause our pipeline systems to discount their rates or otherwise experience a reduction in their revenues.

The development of additional natural gas reserves requires significant capital expenditures by others for exploration and development drilling and the installation of production, gathering, storage, transportation and other facilities that permit natural gas to be produced and delivered to pipelines that interconnect with our pipeline systems. High exploration and production costs, low prices for natural gas, regulatory limitations such as royalty frameworks, or the lack of available capital for these projects could adversely affect the development of additional reserves in Western Canada and the production in the WCSB.

Volumes available for export out of the WCSB depend in part on the internal demand for Canadian natural gas which may increase as a result of increased demand for electricity generation and other industrial requirements, including the development of oil sands projects, which may require substantial amounts of natural gas. This higher internal demand may reduce the amount of gas available for import into the U.S. In the longer term, a portion of the Alberta hub gas supply may come from proposed gas pipelines from the North Slope of Alaska and the Mackenzie Delta of Canada and from the continued growth of coal bed methane projects. Cancellation or delays in the construction of such pipelines or such projects could adversely affect the volumes available for export in the long term.

If the availability of Alberta hub natural gas was to decline, existing shippers on our pipeline systems may be unlikely to extend their contracts and our pipeline systems may be unable to find replacement shippers for lost capacity. Furthermore, additional natural gas reserves may not be developed in commercial quantities and in sufficient amounts to fill the capacities of each of our pipeline systems.

In addition, existing customers may not extend their contracts if the cost of delivered natural gas from other producing regions into the markets served by our pipeline systems is lower than the cost of natural gas delivered by our pipeline systems. Our pipeline systems face increased competition from other pipelines that provide access for our shippers to capacity from the U.S. Rocky Mountain Region. The Rockies Express Pipeline owned by Rockies Express Pipeline LLC is being constructed in two phases and the planned terminus is in Clarington, Ohio. REX West is completed and is currently delivering gas to interconnects in the Midwestern region. The full in-service of REX West in May 2008 has resulted in significant downward pressure on natural gas prices in the Mid-continent Region, and is having a negative impact on demand for Northern Border’s transport and may have an impact on Great Lakes in the future.

REX East is planned to extend from Audrain County, Missouri to Clarington in Monroe County, Ohio. Once in-service, REX East should improve the competitive position of Canadian supply with Mid-Continent sourced gas, potentially mitigating some of the excess supply in the Mid-Continent market. REX East will compete in some of Great Lakes’ markets, but will also potentially create demand for Great Lakes’ transportation of natural gas from REX East seeking access to and from storage locations in Michigan. It is now anticipated that the partial in-service and full in-service of REX East will occur in the second and fourth quarters of 2009, respectively. Although there can be no assurance on the timing or impact of REX East, we believe that any positive impact on the market Northern Border serves will not occur until 2010.

An increase in competition in the key markets served by our pipeline systems could arise from new ventures or expanded operations from existing competitors. Our financial performance depends to a large extent on the capacity contracted on our pipeline systems. Decreases in the volumes transported by our pipeline systems, whether caused by supply or demand factors in the markets these pipeline systems serve, competition or otherwise, can directly and adversely affect our revenues and results of operations.

Our pipeline systems may undertake expansion and build projects which involve significant risks that could adversely affect our business. Additionally, the Bison Project and the Pathfinder Project have inherently similar risks that may impact their success and therefore the potential volumes to be delivered to Northern Border.

Our pipeline systems have expansion and new build projects planned or underway, including Northern Border’s $18 million Des Plaines Project. Additionally, expansion and new build projects, such as the Bison and/or Pathfinder Projects that would potentially deliver gas to Northern Border, are subject to a variety of factors outside their control, such as weather, natural disasters, delays in obtaining key materials and difficulties in obtaining permits and rights-of-way or other regulatory approvals, as well as the performance by third party contractors may result in increased costs or delays in construction. Cost overruns or delays in completing a project could result in reduced transportation rates and liquidated damages to customers, as well as lost revenue opportunities. In addition, we cannot be certain that, if completed, these projects will perform in accordance with our expectations. Each of these risks could have a material adverse effect on our results of operations and cash flows.

If our pipeline systems were to become subject to a material amount of entity level taxation for state tax purposes, then our pipeline systems’ operating cash flow and cash available for distribution to us and for other business needs would be reduced.

Our pipeline systems are partnerships or tax flow through entities, and as such they generally have not been subject to income tax at the entity level. Several states have either adopted or are evaluating a variety of ways to subject partnerships to entity level taxation. For example, in the nine months ended September 30, 2008, Great Lakes recorded a Michigan business tax of $4.2 million relating to a new partnership level tax, of which the Partnership’s share of the tax was $2.0 million. Imposition of such taxes on our pipeline systems will reduce the cash available for distribution to us and for other business needs by our pipeline systems.

Unitholders will likely be subject to state and local taxes as a result of an investment in units.

In addition to federal income taxes, unitholders will likely be subject to other taxes, including state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we do business or own property. We may be required to withhold income taxes with respect to income allocable or distributions made to our unitholders. In addition, unitholders may be required to file state and local income tax returns and pay state and local income taxes in some or all of the jurisdictions in which we do business or own property and may be subject to penalties for failure to comply with those requirements. It is the unitholders’ responsibility to file all required United States federal, state and local tax returns. Counsel has not rendered an opinion on the state or local tax consequences of an investment in us.

Item 6. Exhibits

No. Description

10.1	Membership Interest Purchase Agreement as of August 28, 2008, by and between Northern Border Pipeline Company and TransCanada Pipeline USA Ltd.

10.2	First Amendment to Amended and Restated Revolving Credit Agreement dated as of July 31, 2008 between Northern Border Pipeline Company and the lenders named therein.

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.

SIGNATURES

Pursuant to the requirements of the Securities and Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

		TC PipeLines, LP
		(a Delaware Limited Partnership)
		By:	TC PipeLines GP, Inc., its general partner
Date:	November 3, 2008	By:	/s/ Russell K. Girling Russell K. Girling Chairman, Chief Executive Officer and Director TC PipeLines GP, Inc. (Principal Executive Officer)
Date:	November 3, 2008	By:	/s/ Amy W. Leong Amy W. Leong Controller TC PipeLines GP, Inc. (Principal Financial Officer)