Edgar Filing: TC PIPELINES LP

tclp10q04302008.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 March 31, 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		(I.R.S. Employer Identification Number)
or organization)

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

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	13
	Results of Operations of TC PipeLines	17
	Liquidity and Capital Resources of TC PipeLines	20
	Liquidity and Capital Resources of our Pipeline Systems	21

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	23

Item 4.	Controls and Procedures	24

PART II	OTHER INFORMATION

Item 1A.	Risk Factors	24

Item 6.	Exhibits	26

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:

Bcf/d……………………………......	Billion cubic feet per day
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
Great Lakes……………………........	Great Lakes Gas Transmission Limited Partnership
GTN……………………………........	Gas Transmission Northwest Corporation
LIBOR…………………………........	London Interbank Offered Rate
MLP……………………………........	Master Limited Partnership
MMcf/d……………………….........	Million cubic feet per day
NOPR………………………….........	Notice of Proposed Rulemaking
Northern Border……………….......	Northern Border Pipeline Company
Our pipeline systems………….......	Great Lakes, Northern Border and Tuscarora
ROE……………………………........	Return on equity
SEC…………………………….........	Securities and Exchange Commission
SFAS…………………………..........	Statement of Financial Accounting Standards
TCNB………………………….........	TransCanada Northern Border Inc.
TransCanada…………………........	TransCanada Corporation and its subsidiaries
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 March 31,
(millions of dollars except per common unit amounts)	2008			2007

Equity income from investment in Great Lakes (Note 2)		18.6			7.0
Equity income from investment in Northern Border (Note 3)		19.5			17.8
Transmission revenues		6.9			6.9
Operating expenses		(2.2	)		(2.0	)
Depreciation		(1.6	)		(1.6	)
Financial charges, net and other		(7.6	)		(8.1	)
Net income		33.6			20.0

Net income allocation
Common units		31.0			19.0
General partner		2.6			1.0
		33.6			20.0

Net income per common unit (Note 6)		$0.89			$0.77

Weighted average common units outstanding (millions)		34.9			24.6

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

Consolidated Statement of Comprehensive Income

(unaudited)	Three months ended March 31,
(millions of dollars)	2008			2007

Net income		33.6			20.0
Other comprehensive loss
Change associated with current period hedging transactions (Note 9)		(12.3	)		(1.2	)
Change associated with current period hedging transactions of investees		(1.6	)		(0.3	)
		(13.9	)		(1.5	)
Total comprehensive income		19.7			18.5

See accompanying notes to the consolidated financial statements.

TC PipeLines, LP

Consolidated Balance Sheet

(unaudited)
(millions of dollars)	March 31, 2008			December 31, 2007
ASSETS
Current Assets
Cash and short-term investments		1.6			7.5
Accounts receivable and other		3.5			4.2
		5.1			11.7
Investment in Great Lakes (Note 2)		728.1			721.1
Investment in Northern Border (Note 3)		536.6			541.9
Plant, property and equipment (net of $63.3 million accumulated depreciation, 2007 - $61.7 million)		137.2			134.1
Goodwill		81.7			81.7
Other assets		1.9			2.1
		1,490.6			1,492.6

LIABILITIES AND PARTNERS' EQUITY
Current Liabilities
Bank indebtedness		-			1.4
Accounts payable		5.3			4.8
Accrued interest		3.6			3.0
Current portion of long-term debt (Note 5)		4.6			4.6
		13.5			13.8
Other long-term liabilities		22.1			9.9
Long-term debt (Note 5)		560.8			568.8
		596.4			592.5
Partners' Equity
Common units		900.1			892.3
General partner		19.3			19.1
Accumulated other comprehensive loss		(25.2	)		(11.3	)
		894.2			900.1
		1,490.6			1,492.6

Subsequent events (Note 10)

See accompanying notes to the consolidated financial statements.

TC PipeLines, LP

Consolidated Statement of Cash Flows

(unaudited)	Three months ended March 31,
(millions of dollars)	2008			2007

CASH GENERATED FROM OPERATIONS
Net income		33.6			20.0
Depreciation		1.6			1.6
Amortization of other assets		0.1			0.1
Equity income in excess of distributions received from Great Lakes		-			(7.0	)
Increase in long-term liabilities		0.1			-
Equity allowance for funds used during construction		(0.2	)		-
Decrease in operating working capital		0.4			1.0
		35.6			15.7

INVESTING ACTIVITIES
Reduction in the return of capital from Great Lakes		(7.0	)		-
Return of capital from Northern Border (Note 3)		3.6			4.4
Investment in Great Lakes (Note 2)		-			(733.3	)
Investment in Tuscarora, net of cash acquired (Note 4)		-			0.1
Capital expenditures		(4.5	)		(0.6	)
Other assets		-			(1.1	)
		(7.9	)		(730.5	)

FINANCING ACTIVITIES
Distributions paid		(25.6	)		(11.3	)
Equity issuances, net		-			607.3
Long-term debt issued		-			133.0
Long-term debt repaid (Note 5)		(8.0	)		(9.0	)
		(33.6	)		720.0

(Decrease)/increase in cash and short-term investments		(5.9	)		5.2
Cash and short-term investments, beginning of period		7.5			4.6

Cash and short-term investments, end of period		1.6			9.8

Interest payments made		7.1			5.6

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	-	31.0	2.6	-	-	33.6
Distributions paid	-	(23.2)	(2.4)	-	-	(25.6)
Other comprehensive loss	-	-	-	(13.9)	-	(13.9)

Partners' equity at March 31, 2008	34.9	900.1	19.3	(25.2)	34.9	894.2


(1) Based on interest rates at March 31, 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 $7.0 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 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 months ended March 31, 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. Amounts are stated in U.S. dollars.

Note 2 Investment in Great Lakes

On February 22, 2007, we acquired a 46.45 per cent general partner interest in Great Lakes Gas Transmission Limited Partnership (Great Lakes). On the same day, a wholly-owned subsidiary of TransCanada Corporation (TransCanada) became 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 the period ended March 31, 2008 (period February 23, 2007 to March 31, 2007 - $7.0 million).

The following tables contain summarized financial information of Great Lakes:

Summarized Consolidated Great Lakes Income Statement
(unaudited)	Three months ended March 31,			For the period from February 23 to March 31,
(millions of dollars)	2008			2007
Transmission revenues		79.7			30.4
Operating expenses		(15.1	)		(6.1	)
Depreciation		(14.6	)		(5.9	)
Financial charges, net and other		(8.2	)		(3.4	)
Michigan business tax		(1.7	)		-
Net income		40.1			15.0

Summarized Consolidated Great Lakes Balance Sheet
(unaudited)	March 31,		December 31,
(millions of dollars)	2008		2007
Assets
Cash and short-term investments		60.6		32.0
Other current assets		44.3		55.5
Plant, property and equipment, net		957.3		969.2
		1,062.2		1,056.7
Liabilities and Partners' Equity
Current liabilities		41.1		50.7
Deferred credits		0.4		0.4
Long-term debt, including current maturities		440.0		440.0
Partners' capital		580.7		565.6
		1,062.2		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 periods ended March 31, 2008 and 2007.

The following tables contain summarized financial information of Northern Border:

Summarized Northern Border Income Statement
(unaudited)	Three months ended March 31,
(millions of dollars)	2008			2007
Transmission revenues		83.8			79.6
Operating expenses		(19.4	)		(17.8	)
Depreciation		(15.2	)		(15.3	)
Financial charges, net and other		(9.7	)		(10.4	)
Net income		39.5			36.1

Summarized Northern Border Balance Sheet
(unaudited)	March 31,			December 31,
(millions of dollars)	2008			2007
Assets
Cash and short-term investments		18.1			22.9
Other current assets		34.5			39.8
Plant, property and equipment, net		1,415.0			1,428.3
Other assets		24.8			23.9
		1,492.4			1,514.9
Liabilities and Partners' Equity
Current liabilities		45.9			53.4
Deferred credits and other		11.2			8.1
Long-term debt, including current maturities		607.3			615.3
Partners' equity
Partners' capital		833.7			840.5
Accumulated other comprehensive loss		(5.7	)		(2.4	)
		1,492.4			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 investment in Tuscarora.

The following tables contain summarized financial information of Tuscarora:

Summarized Tuscarora Income Statement
(unaudited)	Three months ended March 31,
(millions of dollars)	2008			2007
Transmission revenues		6.9			6.9
Operating expenses		(1.2	)		(1.2	)
Depreciation		(1.6	)		(1.6	)
Financial charges, net and other		(0.9	)		(1.2	)
Net income		3.2			2.9

Summarized Tuscarora Balance Sheet
(unaudited)	March 31,		December 31,
(millions of dollars)	2008		2007
Assets
Cash and short-term investments		-		6.1
Other current assets		9.2		2.6
Plant, property and equipment, net		137.2		134.1
Other assets		0.5		0.6
		146.9		143.4
Liabilities and Partners' Equity
Current liabilities		6.4		6.1
Long-term debt, including current maturities		66.4		66.4
Partners' capital		74.1		70.9
		146.9		143.4

Summarized Tuscarora Cash Flow Statement
(unaudited)	Three months ended March 31,
(millions of dollars)	2008			2007
Cash flows provided by operating activities		6.6			5.1
Cash flows used in investing activities		(4.5	)		(0.6	)
Cash flows used in financing activities		(8.2	)		-
Decrease/(increase) in cash and short-term investments		(6.1	)		4.5
Cash and short-term investments, beginning of period		6.1			2.9
Cash and short-term investments, end of period		-			7.4

Note 5 Credit Facility and Long-Term Debt

(unaudited)	March 31,		December 31,
(millions of dollars)	2008		2007

Senior Credit Facility		499.0		507.0
Series A Senior Notes due 2010		54.5		54.5
Series B Senior Notes due 2010		5.5		5.5
Series C Senior Notes due 2012		6.4		6.4
		565.4		573.4

We had $499.0 million outstanding under the Senior Credit Facility at March 31, 2008 (December 31, 2007 - $507.0 million). The interest rate on the Senior Credit Facility averaged 5.02 per cent for the three months ended March 31, 2008 (2007 - 6.12 per cent). After hedging activity, the interest rate incurred on the Senior Credit Facility averaged 5.28 per cent for the three months ended March 31, 2008 (2007 – 5.98 per cent). Prior to hedging activities, the interest rate was 3.52 per cent at March 31, 2008 (December 31, 2007 – 5.62 per cent). At March 31, 2008, we were in compliance with our financial covenants.

Annual maturities of the long-term debt are as follows: 2008 - $4.6 million; 2009 - $4.4 million; 2010 - $53.5 million; 2011 - $499.8 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, adjusted to reflect 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 March 31,
(millions of dollars except per unit amounts)	2008			2007
Net income		33.6			20.0
Net income allocated to general partner
General partner interest		(0.7	)		(0.4	)
Incentive distribution income allocation		(1.9	)		(0.6	)
		(2.6	)		(1.0	)
Net income allocable to common units		31.0			19.0
Weighted average common units outstanding (millions)		34.9			24.6
Net income per common unit	$	0.89		$	0.77

Note 7 Cash Distributions

For the three months ended March 31, 2008, we distributed $0.665 per common unit (2007 – $0.60 per common unit). The distributions for the three months ended March 31, 2008 included incentive distributions to the general partner of $1.9 million (2007 - $0.6 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 or other compensation 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 for the three months ended March 31, 2008 (2007 - $0.4 million).

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. On December 19, 2006, the Partnership acquired an additional 49 per cent general partner interest in Tuscarora. In connection with this transaction, TCNB became the operator of 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 benefit costs, property and liability insurance costs, and transition costs. Total costs charged to our pipeline systems during the three months ended March 31, 2008 and 2007 by TransCanada and its affiliates and amounts owed to TransCanada and its affiliates at March 31, 2008 and December 31, 2007 are summarized in the following table:

(unaudited)	Three months ended March 31,
(millions of dollars)	2008		2007

Costs charged by TransCanada and its affiliates:
Great Lakes(1)		7.3		4.1
Northern Border		6.8		-
Tuscarora		1.1		0.1
Impact on the Partnership's net income:
Great Lakes(1)		3.4		1.9
Northern Border		3.3		-
Tuscarora		0.7		0.1

(1) The amounts disclosed for Great Lakes are for the period February 23 to March 31, 2007.

(unaudited)	March 31,		December 31,
(millions of dollars)	2008		2007

Amount owed to TransCanada and its affiliates:
Great Lakes		4.7		1.9
Northern Border		2.2		3.0
Tuscarora		4.1		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 $30.3 million of transportation revenues under these contracts for the three months ended March 31, 2008 (February 23, 2007 to March 31, 2007 - $12.9 million). This amount represents 38.1 per cent of total revenues earned by Great Lakes for the three months ended March 31, 2008 (February 23, 2007 to March 31, 2007 – 42.4 per cent). $14.1 million of this transportation revenue is included in our equity income from Great Lakes for the three months ended March 31, 2008 (February 23, 2007 to March 31, 2007 - $6.0 million). At March 31, 2008, $9.6 million is included in Great Lakes’ receivables in regards to the transportation contracts with TransCanada and its affiliates (December 31, 2007 - $10.0 million).

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 during the three months ended March 31, 2008 (2007 - $300.0 million). At March 31, 2008, the fair value of the interest rate swaps and options accounted for as hedges was negative $22.1 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 the interest rate swaps and option 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 months ended March 31, 2008, we recorded interest expense of $0.3 million in regards to the interest rate swaps and options.

Note 10 Subsequent Events

On April 17, 2008, the Board of Directors of the general partner declared the Partnership’s first quarter 2008 cash distribution in the amount of $0.70 per common unit, payable on May 15, 2008, to unitholders of record on April 30, 2008. The cash distribution represents an increase over the previous quarter of $0.035 per common unit, or $0.14 per unit per annum, to an indicated annual cash distribution of $2.80 per common unit.

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

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:

future demand for and prices of natural gas;

competitive conditions in the overall natural gas and electricity markets;

availability of supplies of Canadian and U.S. natural gas;

availability of additional storage capacity and current storage levels;

weather conditions; and

competitive developments by Canadian and U.S. natural gas transmission companies;

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 results of the Bison Pipeline Project Open Season and whether or not Northern Border proceeds with the project;

performance of contractual obligations by customers of our pipeline systems;

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 FERC regulations, on us and our pipeline systems;

our ability to control operating costs; and

prevailing economic conditions, including conditions of 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 for the quarter ended March 31, 2008. 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 discusses the results of operations and liquidity and capital resources of TC PipeLines, along with those of Great Lakes, Northern Border and Tuscarora (together “our pipeline systems”) as a result of the Partnership’s ownership interests.

The following discussion and analysis should be read in conjunction with our unaudited financial statements and notes thereto included elsewhere in this report. See Item 1. “Financial Statements”. 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, 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 general 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 our wholly-owned subsidiary.

Our general partner interests in Great Lakes, Northern Border and Tuscarora represent our only material assets at March 31, 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 (GTN), 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 first quarter of 2008 as compared to the same period last year; however, the impact of this decline on any given pipeline is dependent upon market conditions in the markets those pipelines serve. The decline in WCSB gas available for export did not negatively impact throughput on our pipeline systems during the first quarter of 2008 due to favorable market conditions. There are some factors that may mitigate this decline in the future such as strengthening gas prices, clarification of the recently announced Alberta Royalty Regime as it affects natural gas production, and announcements regarding potential natural gas supply discoveries associated with shale gas plays in Western Canada.

Western U.S. demand for Canadian natural gas may decrease this summer due to above normal snowpack in that region, which could cause gas-fired electric generation to be displaced with hydroelectric generation. Canadian natural gas displaced by hydroelectric generation in the Western U.S. is viewed as a positive market fundamental for Great Lakes and Northern Border, potentially increasing Midwestern and Eastern U.S. demand for transportation services on Great Lakes and Northern Border in the upcoming summer months. Tuscarora is generally unaffected by the shift to hydroelectric generation because of its long-term contracts.

The replacement of below normal natural gas storage inventories in Canada could reduce demand for transportation services on Northern Border in the upcoming summer months. However, reduced storage inventories generally increases demand for Great Lakes’ transportation, as customers use Great Lakes during the summer months to access and fill storage locations adjacent to its pipeline.

Contracting

For the period ending March 31, 2008, Great Lakes’ average contracted capacity compared to design capacity was 114 per cent. For March 2007, Great Lakes’ average contracted capacity compared to design capacity was 113 per cent. At March 31, 2008, 93 per cent of capacity was contracted on a firm basis for the remainder of the year. At March 31, 2008, the weighted average remaining life of Great Lakes’ firm transportation contracts was 2.4 years.

Northern Border’s average contracted capacity was 106 per cent and 103 per cent of its design capacity for the three months ended March 31, 2008 and 2007, respectively. At March 31, 2008, approximately 64 per cent of Northern Border’s design capacity was contracted on a firm basis for the remainder of the year. At March 31, 2008, the weighted average contract life of Northern Border’s firm transportation contracts was 1.1 years.

RECENT DEVELOPMENTS

Northern Border

Bison Pipeline Project – On April 4, 2008, Northern Border announced that its wholly-owned subsidiary, Bison Pipeline LLC, is conducting a binding open season for potential shippers to request firm pipeline capacity on a proposed new pipeline system. Should this project be built, it will provide another transportation source for Northern Border shippers to export natural gas supply from the Rockies basin.

It is anticipated that the Bison Pipeline Project will consist of approximately 289 miles of 24-inch diameter pipeline, compression and related facilities, originating at the natural gas gathering facilities of Fort Union Gas Gathering, L.L.C. and Bighorn Gas Gathering, LLC near Dead Horse, Wyoming. The pipeline would extend in a northeasterly direction to its terminus in Morton County, North Dakota near Northern Border’s Compressor Station No. 6. The initial capacity of the Bison Pipeline Project is anticipated to be approximately 400 million cubic feet per day (MMcf/d) with a maximum capacity of 660 MMcf/d. However, the ultimate capacity of the pipeline will be determined by the level of binding shipper commitments. The projected in-service date for the Bison Pipeline Project is November 15, 2010. It is estimated that this project will cost approximately $498 million. The final transportation rates and potential revenue are dependent upon the final project scope and shipper demand for the project, which may be affected by competition from other proposed pipeline projects to transport natural gas from the Rockies basin. The Bison Pipeline Project is contingent on the results of the binding open season and regulatory approvals.

Demand Outlook – As anticipated, demand for Northern Border’s transportation services is being affected by additional supply in Midwestern markets. Interim service of the Western segment of the Rockies Express Pipeline from Weld County, Colorado to Brown County, Kansas began in January 2008, and full service of the Western segment to Audrain County, Missouri is expected to begin in May 2008. The Western segment of the Rockies Express Pipeline did not impact volumes and rates during the first quarter as Northern Border’s sustainable capacity was fully contracted through the end of the winter season and demand due to cold weather increased daily capacity sales. However, with throughput on the Rockies Express Pipeline ramping up to over one billion cubic feet per day (Bcf/d) combined with lower demand in the spring shoulder months, Northern Border now expects lower throughput and greater discounting through this period, which is expected to lead to a reduction in revenue. We anticipate that increased demand during the summer for cooling and refilling of storage in the Mid-Continent and neighboring market regions will dampen the impact of this new supply on Northern Border’s capacity sales. The Eastern segment of the Rockies Express Pipeline, from Missouri to Ohio, is expected to be placed in service by June 2009, and is anticipated to transport natural gas further east, potentially mitigating excess supply in Northern Border’s market.

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 of 40,000 Dekatherms per day (Dth/d) will generate approximately $5.8 million of annual revenue.

REGULATORY DEVELOPMENTS

Energy Affiliates – In November 2003, the FERC adopted revised standards of conduct which govern the relationships between regulated interstate natural gas pipelines and their energy affiliates. The new standards of conduct were designed to prevent interstate natural gas pipelines from giving any undue preference to their energy affiliates and ensure that transmission service is provided on a nondiscriminatory basis. In November 2006, the United States Court of Appeals for the District of Columbia vacated the FERC’s order regarding standards of conduct for energy affiliates of natural gas pipelines and remanded the matter back to the FERC. On January 9, 2007, the FERC issued Order No. 690, Standards of Conduct for Transmission Providers (the Interim Rule) as the Commission’s interim response to the Appeals Court decision. The Interim Rule reduced the application of the standards of conduct for interstate natural gas pipelines to the relationship between the pipelines and their marketing affiliates as defined in the FERC’s rules that were in effect prior to the current regulations and made certain other revisions that were subject to the appeal. Requests for clarifications, and in the alternative, rehearing of the Interim Rule have been filed. On January 18, 2007, the FERC issued a Notice of Proposed Rulemaking (NOPR), which if accepted as the final rule, would have made permanent the Interim Rule’s applicability of the standards of conduct to govern the relationship between interstate natural gas pipelines and their marketing affiliates. However, on March 21, 2008, FERC substantially revised the Notice of Proposed Rulemaking to modify the approach proposed in the initial NOPR. The Commission's goal is to provide clearer guidance in three areas. These areas are independent functioning rules for transmission and marketing employees, no-conduit rules to prevent the communication of transmission information to marketing affiliates and transparency rules that would take certain information out from under the no-conduit rules by contemporaneously posting on a pipeline's Internet website. The NOPR is currently the subject matter of a comment period and is subject to change. Therefore, we cannot predict the impact or timing of a final rule.

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 used to determine the appropriate returns on equity (ROE) under the Discounted Cash Flow (DCF) model for natural gas and oil pipelines. The proposed policy statement would permit the inclusion of master limited partnerships (MLPs) in the proxy group for purposes of calculating returns on equity under the DCF analysis. On April 17, 2008, the FERC issued a final policy statement (Policy Statement) in this proceeding, which concluded that (1) MLPs should be included in the ROE proxy group for both oil and gas pipelines; (2) there should be no cap on the level of distributions included in the FERC’s current DCF methodology; (3) the Institutional Brokers Estimated System forecasts should remain the

basis for the short-term growth forecast used in the DCF calculation; (4) there should be an adjustment to the long-term growth rate used to calculate the equity cost of capital for an MLP, which will be set at 50 per cent of the long-term GDP growth rate, rather than the full long-term GDP growth rate currently used for corporations; and (5) there should be no modification to the current respective two-thirds and one-third weightings of the short- and long-term growth factors. Moreover, the Commission will not explore other methods for determining a pipeline’s equity cost of capital at this time. The Commission also concludes that this Policy Statement should govern all gas and oil pipeline rate proceedings. The impact to pipelines will be determined on a case by case basis and the impact on our pipeline systems cannot be determined at this time and will not be known until their next rate case.

RESULTS OF OPERATIONS OF TC PIPELINES

Critical Accounting Policies and Estimates

The preparation of financial statements in accordance with GAAP requires us to make estimates and assumptions with respect to values or conditions which cannot be known with certainty, that affect the reported amount of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the financial statements. Such estimates and assumptions also affect the reported amounts of revenue and expenses during the reporting period. Although we believe these estimates and assumptions are reasonable, actual results could differ. There were no significant changes to our critical accounting policies and estimates during the three months ended March 31, 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 Financial Accounting Standards Board (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.

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.


	For the three months ended March 31, 2008
(unaudited)													Northern
(millions of dollars)	Partnership			Tuscarora(1)			Corporate			Great Lakes			Border (2)
Transmission revenues		6.9			6.9			-			79.7			83.8
Operating expenses		(2.2	)		(1.2	)		(1.0	)		(15.1	)		(19.4	)
		4.7			5.7			(1.0	)		64.6			64.4
Depreciation		(1.6	)		(1.6	)		-			(14.6	)		(15.2	)
Financial charges, net and other		(7.6	)		(0.9	)		(6.7	)		(8.2	)		(9.7	)
Michigan business tax		-			-			-			(1.7	)		-
											40.1			39.5
Equity income		38.1			-			-			18.6			19.5
Net income		33.6			3.2			(7.7	)		18.6			19.5

(1) TC PipeLines owns a 100 per cent general partner interest in Tuscarora following the acquisition of an additional two per cent interest on December 31, 2007.

(2) TC PipeLines owns a 50 per cent general partner interest in Northern Border. Equity income from Northern Border includes amortization of a $10 million transaction fee paid to the operator of Northern Border at the time of the additional 20 per cent acquisition in April 2006.

	For the three months ended March 31, 2007
(unaudited)										Great Lakes(3)			Northern
(millions of dollars)	Partnership			Tuscarora			Corporate			Feb 23 - Mar 31			Border(4)
Transmission revenues		6.9			6.9			-			30.4			79.6
Operating expenses		(2.0	)		(1.2	)		(0.8	)		(6.1	)		(17.8	)
		4.9			5.7			(0.8	)		24.3			61.8
Depreciation		(1.6	)		(1.6	)		-			(5.9	)		(15.3	)
Financial charges, net and other		(8.1	)		(1.2	)		(6.9	)		(3.4	)		(10.4	)
											15.0			36.1
Equity income		24.8			-			-			7.0			17.8
Net income		20.0			2.9			(7.7	)		7.0			17.8

(3) TC PipeLines acquired a 46.45 per cent general partner interest in Great Lakes on February 22, 2007.

(4) TC PipeLines owns a 50 per cent general partner interest in Northern Border. Equity income from Northern Border includes amortization of a $10 million transaction fee paid to the operator of Northern Border at the time of the additional 20 per cent acquisition in April 2006.

First Quarter 2008 Compared with First Quarter 2007

Net income increased $13.6 million, or 68 per cent, to $33.6 million in the first quarter of 2008, compared to $20.0 million in the first quarter of 2007. This was primarily due to increased equity income from Great Lakes in 2008.

Equity income from Great Lakes was $18.6 million in the first quarter of 2008, an increase of $11.6 million or 166 per cent, compared to $7.0 million for the period February 23 to March 31, 2007. The increase in equity income, which was in line with our expectations, was primarily due to a full quarter of income contribution in 2008 as compared to 37 days in the first quarter of 2007. In the first quarter of 2008, Great Lakes recorded Michigan business tax of $1.7 million, which is a new partnership level tax. The Partnership’s share of the Michigan business tax was $0.8 million.

Equity income from Northern Border was $19.5 million in the first quarter of 2008, an increase of $1.7 million or ten per cent, compared to $17.8 million in the same period last year. Northern Border’s net income increased $3.4 million, or nine per cent, to $39.5 million in the first quarter of 2008 compared to $36.1 million in the first quarter of 2007. The increase in net income was primarily due to increased transmission revenues, partially offset by increased operating

expenses. Transmission revenues increased $4.2 million for the three months ended March 31, 2008 compared to the same period last year due primarily to an increase in overall volumes sold. Operating expenses increased $1.6 million for the three months ended March 31, 2008 compared to the same period last year primarily due to increased general and administrative expenses and increased expense related to the over recovery of the compressor usage surcharge, partially offset by decreased taxes other than income.

Tuscarora’s net income for the first quarter of 2008 of $3.2 million was consistent with the same period in the prior year.

The Partnership’s operating expenses and financial charges, net and other on a non-consolidated basis for the first quarter of 2008 were consistent with the same period last year.

Partnership Cash Flows

To supplement our financial statements, we disclose “Partnership cash flows”. We have presented this additional information to enhance investors’ understanding of the way that management analyzes our financial performance. We believe this summary provides a more meaningful comparison of our financial performance to prior periods, as Partnership cash flows fund the cash distributions that we pay to our unitholders. 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.

(unaudited)	Three months ended March 31,
(millions of dollars except per common unit amounts)	2008			2007
Total cash distributions received (a)		34.7			22.2
Cash flows provided by Tuscarora's operating activities		6.6			5.1
Partnership costs (b)		(7.7	)		(7.7	)
Partnership cash flows (b)		33.6			19.6
Partnership cash flows per common unit	$	0.96		$	0.80
Cash distributions declared		(27.4	)		(24.9	)
Cash distributions declared per common unit	$	0.70		$	0.65
Cash distributions paid		(25.6	)		(11.3	)
Cash distributions paid per common unit	$	0.665		$	0.600

(a) Reconciliation of non-GAAP financial measure: Total cash distributions received is a non-GAAP financial measure which is the sum of equity income from investment in Great Lakes, less equity income in excess of distributions received from Great Lakes, less reduction in the return of capital from Great Lakes, plus equity income from investment in Northern Border and return of capital from Northern Border. It is provided as a supplement to results reported in accordance with GAAP. Management believes that this is a meaningful measure to assist investors in evaluating the levels of cash distributions from our investments. Below is a reconciliation of total cash distributions received to GAAP financial measures:

	Three months ended March 31,
(millions of dollars)	2008			2007
Equity income from investment in Great Lakes		18.6			7.0
Equity income in excess of distributions received from Great Lakes		-			(7.0	)
Reduction in the return of capital from Great Lakes		(7.0	)		-
Cash distributions from Great Lakes		11.6			-

Equity income from investment in Northern Border		19.5			17.8
Return of capital from Northern Border		3.6			4.4
Cash distributions from Northern Border		23.1			22.2

Total cash distributions received		34.7			22.2

(b) Reconciliation of non-GAAP financial measure: Partnership cash flows is a non-GAAP financial measure which is the sum of cash distributions received and cash flows from Tuscarora's operating activities less Partnership costs. We exclude Tuscarora's costs from the Partnership costs so that investors may evaluate our costs independent of costs directly attributable to our investments. Management believes that this is a useful measure to assist investors in evaluating the Partnership's cash flow from its operating activities. A reconciliation of Partnership costs is summarized below:

	Three months ended March 31,
(millions of dollars)	2008			2007
Operating expenses		2.2			2.0
Financial charges, net and other		7.6			8.1
Less:
Operating expenses and financial charges from Tuscarora		(2.1	)		(2.4	)
Partnership costs		7.7			7.7

First Quarter 2008 Compared with First Quarter 2007

Partnership cash flows increased $14.0 million, or 71 per cent, to $33.6 million for the first quarter of 2008, compared to $19.6 million for the same period of last year. This increase was primarily a result of cash distributions received from Great Lakes, which contributed $11.6 million in the first quarter of 2008 compared to $nil in the same period of last year. Cash flows provided by Tuscarora’s operating activities increased $1.5 million for the three months ended March 31, 2008 compared to the same period in the prior year primarily due to a reduction in operating working capital. Cash distributions received from Northern Border increased $0.9 million in the first quarter of 2008 compared to the same period last year.

Excluding the reduction in the return of capital from Great Lakes and the return of capital from Northern Border, we used $4.5 million of cash flows for investing activities for the first quarter of 2008 compared to $734.9 for the first quarter of 2007. Tuscarora made capital expenditures of $4.5 million during the three months ended March 31, 2008 related to the compressor station expansion project in Likely, California. We acquired our 46.45 per cent general partner interest in Great Lakes during the first quarter of 2007 for $733.3 million.

We used $33.6 million of cash flows from financing activities in the first quarter of 2008. Distributions paid by us increased $14.3 million, or 127 per cent, to $25.6 million for the three months ended March 31, 2008 compared to $11.3 million for the same period in the prior year due to the increased number of common units outstanding and increases in quarterly per common unit distribution amounts. We paid $25.6 million in distributions in the first quarter of 2008 in the following manner: $23.2 million to common unitholders (including $1.4 million to the general partner as holder of 2,035,106 common units and $5.8 million to TransCan Northern Ltd. as holder of 8,678,045 common units), $1.9 million to the general partner as holder of the incentive distribution rights, and $0.5 million to the general partner in respect of its two per cent general partner interest.

We repaid $8.0 million of the outstanding balance on our Senior Credit Facility during the first quarter of 2008 compared to $9.0 million during the same period last year. In the first quarter of 2007, the acquisition of Great Lakes was primarily financed through a private placement of common units and a contribution made by our general partner to maintain its two per cent general interest for total net proceeds of $607.3 million. We funded the balance of the consideration paid with a draw on our Senior Credit Facility of $133.0 million.

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 flow 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 March 31, 2008:

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

Senior Credit Facility		499.0		-		499.0
Series A Senior Notes due 2010		54.5		3.3		51.2
Series B Senior Notes due 2010		5.5		0.5		5.0
Series C Senior Notes due 2012		6.4		0.8		5.6
Total		565.4		4.6		560.8

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 during the three months ended March 31, 2008 (2007 - $300.0 million). At March 31, 2008, the fair value of the interest rate swaps and options accounted for as hedges was negative $22.1 million (December 31, 2007 – negative $9.8 million). Effective January 1, 2008, we adopted the provisions of 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 the interest rate swaps and option 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 months ended March 31, 2008, we recorded interest expense of $0.3 million in regards to the interest rate swaps and options.

2008 First Quarter Cash Distribution

On April 17, 2008, the Board of Directors of the general partner declared the Partnership’s 2008 first quarter cash distribution. The first quarter cash distribution will be paid on May 15, 2008 to unitholders of record as of April 30, 2008, totaling $27.4 million and will be paid in the following manner: $24.4 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), $2.5 million to the general partner as holder of the incentive distribution rights, and $0.5 million to the general partner in respect of its two per cent general partner interest.

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.

Debt of Great Lakes

The following table summarizes Great Lakes’ debt outstanding as of March 31, 2008:

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

8.74% series Senior Notes due 2007 to 2011		40.0		10.0		30.0
9.09% series Senior Notes due 2012 to 2021		100.0		-		100.0
6.73% series Senior Notes due 2009 to 2018		90.0		9.0		81.0
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 restricted covenants in the Senior Note Agreements, approximately $237.0 million of Great Lakes’ partners’ capital was restricted as to distributions as of March 31, 2008. In addition, Great Lakes is required to maintain a minimum consolidated tangible net worth of $175 million. At March 31, 2008, Great Lakes was in compliance with all of its financial covenants.

Debt and Credit Facility of Northern Border

The following table summarizes Northern Border’s debt and credit facility outstanding as of March 31, 2008:

	Payments Due by Period
(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)		158.0		-		158.0
Total		608.0		-		608.0

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

As of March 31, 2008, Northern Border had outstanding borrowings of $158 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 its credit agreement was 3.49 per cent at March 31, 2008.

Interest Rate Collar Agreement

At March 31, 2008, Northern Border’s balance sheet reflected an unrealized loss of approximately $4.8 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. Since inception, Northern Border has not recognized any amounts in income due to ineffectiveness of the Collar Agreement. During the three months ended March 31, 2008, Northern Border recorded interest expense of $0.3 million under the Collar Agreement.

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 March 31, 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 March 31, 2008, the fair value of our interest rate swaps and options accounted for as hedges was negative $22.1 million.

At March 31, 2008, we had $499.0 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 compared to the rates in effect as of March 31, 2008, our annual interest expense would have increased and our net income would have decreased by $0.2 million; and if LIBOR interest rates hypothetically decreased by one per cent compared to the rates in effect as of March 31, 2008, our annual interest expense would have decreased and our net income would have increased by $0.2 million. This amount has been determined by considering the impact of the hypothetical interest rates on variable rate borrowings outstanding as of March 31, 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 March 31, 2008, 74 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 compared with rates in effect as of March 31, 2008, Northern Border’s annual interest expense would increase and its net income would decrease by approximately $1.6 million; and if interest rates hypothetically decreased one per cent compared with rates in effect as of March 31, 2008, Northern Border’s annual interest expense would decrease and its net income would increase by approximately $0.2 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 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 March 31, 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.

Our pipeline systems may undertake expansion and build projects which involve significant risks that could adversely affect our business.

Our pipeline systems have several major expansion and new build projects planned or underway, including Northern Border’s approximate $498 million proposed Bison Pipeline Project and the $17 million Des Plaines Compression Project. 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 and other areas of our pipeline systems’ businesses may suffer as a result of the diversion of their management’s attention and other resources from their other business concerns. 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 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 first quarter of 2008, Great Lakes recorded a Michigan business tax of $1.7 million relating to a new partnership level tax, of which the Partnership’s share of the tax was $0.8 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	Transportation Service Agreement FT8945 between Great Lakes Gas Transmission Limited Partnership and TransCanada PipeLines Limited, dated February 1, 2008.
23.1	Consent of Independent Registered Public Accounting Firm.
23.2	Consent of Independent Registered Public Accounting Firm.
23.3	Consent of Independent Registered Public Accounting Firm.
23.4	Consent of Independent Registered Public Accounting Firm.
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.
99.1	Consolidated Balance Sheets of TC PipeLines GP, Inc. as of December 31, 2007 and 2006.

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:	April 30, 2008	By:	/s/ Russell K. Girling Russell K. Girling Chairman, Chief Executive Officer and Director TC PipeLines GP, Inc. (Principal Executive Officer)
Date:	April 30, 2008	By:	/s/ Amy W. Leong Amy W. Leong Controller TC PipeLines GP, Inc. (Principal Financial Officer)