Edgar Filing: TC PIPELINES LP

tclpform10qapril302009.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, 2009

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

Yes [ ] 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, 2009, 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, 2009 and 2008	4
	Consolidated Statement of Comprehensive Income – Three months ended March 31, 2009 and 2008	4
	Consolidated Balance Sheet – March 31, 2009 and December 31, 2008	5
	Consolidated Statement of Cash Flows – Three months ended March 31, 2009 and 2008	6
	Consolidated Statement of Changes in Partners’ Equity – Three months ended March 31, 2009	7
	Notes to Consolidated Financial Statements	8

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	14

	Results of Operations of TC PipeLines	19
	Liquidity and Capital Resources of TC PipeLines	22
	Liquidity and Capital Resources of our Pipeline Systems	23

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	25

Item 4.	Controls and Procedures	27

PART II	OTHER INFORMATION

Item 1A.	Risk Factors	27

Item 6.	Exhibits	28

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:

Collar Agreement………………......	Northern Border's interest rate collar agreement
EPA……………………………......	United States Environmental Protection Agency
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
IDRs…………………………........	Incentive Distribution Rights
LIBOR…………………………........	London Interbank Offered Rate
MMcf/d……………………….........	Million cubic feet per day
NBPC……………………….............	Northern Border Pipeline Company
Net WCSB Flows to Markets..........	Net of the supply of and demand for WCSB natural gas that is available for transportation to downstream markets; where supply represents WCSB production adjusted for injections into and withdrawals from WCSB storage
Northern Border……………….......	Northern Border Pipeline Company
Our pipeline systems………….......	Great Lakes, Northern Border and Tuscarora
Partnership…………………............	TC PipeLines, LP and its subsidiaries
PipeLP ...............................................	TC PipeLines, LP and its subsidiaries
REX East…………………………...	Eastern segment of the Rockies Express Pipeline
REX West…………………………..	Western segment of the Rockies Express Pipeline
Senior Credit Facility……………....	TC PipeLine's revolving credit and term loan agreement
SFAS…………………………..........	Statement of Financial Accounting Standards
TC PipeLines……………………..	TC PipeLines, LP and its subsidiaries
TGTC..................................................	Tuscarora Gas Transmission Company
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)	2009			2008

Equity income from investment in Great Lakes (Note 2)		19.5			18.6
Equity income from investment in Northern Border (Note 3)		15.6			19.5
Transmission revenues		8.4			6.9
Operating expenses		(2.6	)		(2.2	)
Depreciation		(1.8	)		(1.6	)
Financial charges, net and other		(7.3	)		(7.6	)
Net income		31.8			33.6

Net income allocation
Common units		28.5			30.4
General partner		3.3			3.2
		31.8			33.6

Net income per common unit (Note 6)	$	0.82		$	0.87

Weighted average common units outstanding (millions)		34.9			34.9

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)	2009			2008

Net income		31.8			33.6
Other comprehensive income/(loss)
Change associated with hedging transactions (Note 9)		1.4			(12.3	)
Change associated with hedging transactions of investees		(0.1	)		(1.6	)
		1.3			(13.9	)
Total comprehensive income		33.1			19.7

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

TC PipeLines, LP

Consolidated Balance Sheet

(unaudited)
(millions of dollars)	March 31, 2009			December 31, 2008
ASSETS
Current Assets
Cash and cash equivalents		13.0			8.4
Accounts receivable and other		2.8			3.4
		15.8			11.8
Investment in Great Lakes (Note 2)		711.5			704.5
Investment in Northern Border (Note 3)		510.5			514.8
Plant, property and equipment (net of $70.3 accumulated		132.5			134.2
depreciation, 2008 - $68.5)
Goodwill		81.7			81.7
Other assets		1.4			1.5
		1,453.4			1,448.5

LIABILITIES AND PARTNERS' EQUITY
Current Liabilities
Accounts payable		2.2			2.2
Accrued interest		2.9			2.1
Current portion of long-term debt (Note 5)		4.4			4.4
Current portion of fair value of derivative contracts (Note 9)		12.0			11.8
		21.5			20.5
Fair value of derivative contracts and other (Note 9)		18.5			20.0
Long-term debt (Note 5)		532.4			532.4
		572.4			572.9
Partners' Equity
Common units		895.4			891.4
General partner		19.2			19.1
Accumulated other comprehensive loss		(33.6	)		(34.9	)
		881.0			875.6
		1,453.4			1,448.5

Subsequent events (Note 12)

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

TC PipeLines, LP

Consolidated Statement of Cash Flows

(unaudited)	Three months ended March 31,
(millions of dollars)	2009			2008

CASH GENERATED FROM OPERATIONS
Net income		31.8			33.6
Depreciation		1.8			1.6
Amortization of other assets		0.1			0.1
Equity income in excess of distributions received from Great Lakes		(7.0	)		(7.0	)
Increase in long-term liabilities		-			0.1
Equity allowance for funds used during construction		-			(0.2	)
Decrease/(increase) in operating working capital (Note 10)		1.5			(0.2	)
		28.2			28.0

INVESTING ACTIVITIES
Cumulative distributions in excess of equity earnings:
Northern Border		8.6			3.6
Investment in Northern Border (Note 3)		(4.3	)		-
Capital expenditures		(0.1	)		(4.5	)
(Increase)/decrease in investing working capital (Note 10)		(0.1	)		0.6
		4.1			(0.3	)

FINANCING ACTIVITIES
Distributions paid (Note 7)		(27.7	)		(25.6	)
Long-term debt repaid (Note 5)		-			(8.0	)
		(27.7	)		(33.6	)

Increase/(decrease) in cash and cash equivalents		4.6			(5.9	)
Cash and cash equivalents, beginning of period		8.4			7.5

Cash and cash equivalents, end of period		13.0			1.6

Interest payments made		3.2			7.0

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

TC PipeLines, LP

Consolidated Statement of Changes in Partners’ Equity

(unaudited)	Common Units					General Partner			Accumulated Other Comprehensive (Loss)/Income (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, 2008		34.9		891.4			19.1			(34.9	)		34.9		875.6
Net income		-		28.5			3.3			-			-		31.8
Distributions paid		-		(24.5	)		(3.2	)		-			-		(27.7	)
Other comprehensive income		-		-			-			1.3			-		1.3
Partners' equity at March 31, 2009		34.9		895.4			19.2			(33.6	)		34.9		881.0

(1) TC PipeLines, LP uses derivatives to assist in managing its exposure to interest rate risk. Based on interest rates at March 31, 2009, 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 $12.0 million, which will be offset by a reduction to interest expense of a similar amount.

The accompanying notes are an integral part of these 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 months ended March 31, 2009 and 2008 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, 2008. 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, 2008. Certain comparative figures have been reclassified to conform to the current period’s presentation.

Note 2 Investment in Great Lakes

We own a 46.45 per cent general partner interest in Great Lakes Gas Transmission Limited Partnership (Great Lakes). Great Lakes is regulated by the Federal Energy Regulatory Commission (FERC) and is operated by a wholly-owned subsidiary of TransCanada Corporation. TransCanada and its subsidiaries are herein collectively referred to as “TransCanada”.

We use the equity method of accounting for our interest in Great Lakes. Great Lakes had no undistributed earnings for the periods ended March 31, 2009 and 2008.

The following tables contain summarized financial information of Great Lakes:

Summarized Consolidated Great Lakes Income Statement

(unaudited)	Three months ended March 31,
(millions of dollars)	2009			2008
Transmission revenues		82.5			79.7
Operating expenses		(16.0	)		(15.1	)
Depreciation		(14.6	)		(14.6	)
Financial charges, net and other		(8.2	)		(8.2	)
Michigan business tax		(1.8	)		(1.7	)
Net income		41.9			40.1

Summarized Consolidated Great Lakes Balance Sheet
(unaudited)	March 31,		December 31,
(millions of dollars)	2009		2008
Assets
Cash and cash equivalents		3.1		1.6
Other current assets		93.0		80.2
Plant, property and equipment, net		909.8		923.4
		1,005.9		1,005.2
Liabilities and Partners' Equity
Current liabilities		37.4		43.0
Deferred credits		2.7		2.3
Long-term debt, including current maturities		421.0		430.0
Partners' capital		544.8		529.9
		1,005.9		1,005.2

Note 3 Investment in Northern Border

We own a 50 per cent general partner interest in Northern Border Pipeline Company (Northern Border). Northern Border is regulated by FERC and is operated by TransCanada.

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, 2009 and 2008.

The following tables contain summarized financial information of Northern Border:

Summarized Northern Border Income Statement
(unaudited)	Three months ended March 31,
(millions of dollars)	2009			2008
Transmission revenues		74.5			83.8
Operating expenses		(18.5	)		(19.4	)
Depreciation		(15.3	)		(15.2	)
Financial charges, net and other		(9.1	)		(9.7	)
Net income		31.6			39.5

Summarized Northern Border Balance Sheet
(unaudited)	March 31,			December 31,
(millions of dollars)	2009			2008
Assets
Cash and cash equivalents		23.1			21.6
Other current assets		30.2			39.1
Plant, property and equipment, net		1,379.8			1,390.8
Other assets		24.9			24.5
		1,458.0			1,476.0
Liabilities and Partners' Equity
Current liabilities		44.1			48.7
Deferred credits and other		11.1			11.2
Long-term debt, including current maturities		625.5			630.4
Partners' equity
Partners' capital		783.2			791.4
Accumulated other comprehensive loss		(5.9	)		(5.7	)
		1,458.0			1,476.0

Note 4 Investment in Tuscarora

The Partnership wholly-owns Tuscarora Gas Transmission Company (Tuscarora). Tuscarora is regulated by FERC and operated by TransCanada.

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)	2009			2008
Transmission revenues		8.4			6.9
Operating expenses		(1.4	)		(1.2	)
Depreciation		(1.8	)		(1.6	)
Financial charges, net and other		(1.1	)		(0.9	)
Net income		4.1			3.2

Summarized Tuscarora Balance Sheet
(unaudited)	March 31,		December 31,
(millions of dollars)	2009		2008
Assets
Other current assets		10.0		3.1
Plant, property and equipment, net		132.5		134.2
Other assets		0.3		0.3
		142.8		137.6
Liabilities and Partners' Equity
Current liabilities		3.1		2.0
Long-term debt, including current maturities		61.8		61.8
Partners' capital		77.9		73.8
		142.8		137.6

Summarized Tuscarora Cash Flow Statement
(unaudited)	Three months ended March 31,
(millions of dollars)	2009			2008
Cash flows provided by operating activities		7.2			6.0
Cash flows used in investing activities		(0.2	)		(4.0	)
Cash flows used in financing activities		(7.0	)		(8.1	)
Decrease in cash and cash equivalents		-			(6.1	)
Cash and cash equivalents, beginning of period		-			6.1
Cash and and cash equivalents, end of period		-			-

Note 5 Credit Facility and Long-Term Debt

(unaudited)	March 31,		December 31,
(millions of dollars)	2009		2008

Senior Credit Facility		475.0		475.0
7.13% Series A Senior Notes due 2010		51.3		51.3
7.99% Series B Senior Notes due 2010		5.0		5.0
6.89% Series C Senior Notes due 2012		5.5		5.5
		536.8		536.8

TC PipeLines’ revolving credit and term loan agreement (Senior Credit Facility) consists of a $475.0 million senior term loan and a $250.0 million senior revolving credit facility. At March 31, 2009, no draws were made on our senior revolving credit facility, leaving $250.0 million available for future borrowings. The interest rate on the Senior Credit Facility averaged 2.44 per cent for the three months ended March 31, 2009 (2008 – 5.02 per cent). After hedging activity, the interest rate incurred on the Senior Credit Facility averaged 5.06 per cent for the three months ended March 31, 2009 (2008 – 5.28 per cent). Prior to hedging activities, the interest rate was 1.85 per cent at March 31, 2009 (December 31, 2008 – 2.67 per cent). At March 31, 2009, we were in compliance with our financial covenants.

The principal repayments required on the long term debt are as follows:

(unaudited)
(millions of dollars)
2009	4.4
2010	53.5
2011	475.8
2012	3.1
	536.8

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 March 31,
(millions of dollars except per unit)	2009			2008
Net income		31.8			33.6
Net income allocated to general partner
General partner interest		(0.6	)		(0.7	)
Incentive distribution income allocation		(2.7	)		(2.5	)
		(3.3	)		(3.2	)
Net income allocable to common units		28.5			30.4
Weighted average common units outstanding (millions)		34.9			34.9
Net income per common unit	$	0.82		$	0.87

Effective January 1, 2009, the Partnership adopted the provisions of EITF 07-4 “Application of the Two-Class Method under FASB Statement No. 128, Earnings per share, to Master Limited Partnerships”.

According to the new standard, for purposes of calculating the net income per common unit, the net income must be reduced by the amount of available cash that will be distributed with respect to that period. Any undistributed income must be allocated to the various interest holders based on the contractual provisions of the partnership agreement. Under the partnership agreement, for any quarterly period, the participation of the incentive distribution rights (IDRs) is limited to available cash distributions declared. Accordingly, the undistributed net income has been allocated to the general partner’s two per cent interest and the common unitholders.

The restrospective application of EITF 07-4 impacted the amount of net income allocated to the IDR holder in the first quarter of 2008 as the amount previously allocated to the IDR holder was based on the cash distribution paid in that period and will now be based on the amount declared for the period. This resulted in the net income per common unit for the first quarter of 2008 being reduced from $0.89 to $0.87.

Note 7 Cash Distributions

For the three months ended March 31, 2009, we distributed $0.705 per common unit (2008 – $0.665 per common unit). The distributions for the three months ended March 31, 2009 included incentive distributions to the general partner of $2.7 million (2008 - $1.9 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 $0.4 million for the three months ended March 31, 2009 (2008 - $0.5 million).

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.

Total costs charged to our pipeline systems during the three months ended March 31, 2009 and 2008 by TransCanada and its affiliates and amounts owed to TransCanada and its affiliates at March 31, 2009 and December 31, 2008 are summarized in the following tables:

(unaudited)	Three months ended March 31,
(millions of dollars)	2009		2008

Costs charged by TransCanada and its affiliates:
Great Lakes		7.3		7.3
Northern Border		6.3		6.8
Tuscarora		0.7		1.1
Impact on the Partnership's net income:
Great Lakes		3.2		3.4
Northern Border		2.9		3.3
Tuscarora		0.7		0.7


(unaudited)	March 31,		December 31,
(millions of dollars)	2009		2008

Amount owed to TransCanada and its affiliates:
Great Lakes		3.4		4.5
Northern Border		2.8		2.8
Tuscarora		0.9		0.8

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 $37.3 million of transportation revenues under these contracts for the three months ended March 31, 2009 (2008 - $30.3 million). This amount represents 43.4 per cent of total revenues earned by Great Lakes for the three months ended March 31, 2009 (2008 – 38.1 per cent). $17.3 million of affiliated revenue is included in our equity income from Great Lakes for the three months ended March 31, 2009 (2008 - $14.1 million). At March 31, 2009, $60.2 million was included in Great Lakes’ receivables from affiliates, of which $12.2 million related to the transportation contracts with TransCanada and its affiliates (December 31, 2008 - $12.5 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 during the three months ended March 31, 2009 was $475 million, unchanged from the same period last year. At March 31, 2009, the fair value of the interest rate swaps and options accounted for as hedges was negative $30.4 million (December 31, 2008 – negative $31.7 million). Under Statement of Financial Accounting Standards (SFAS) 157, financial instruments are recorded at fair value on a recurring basis. 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 months ended March 31, 2009, we recorded interest expense of $3.2 million (March 31, 2008 - $0.3 million) in regards to the interest rate swaps and options.

Note 10 Changes in Working Capital

(unaudited)	Three months ended March 31,
(millions of dollars)	2009			2008

Decrease in accounts receivable and other		0.6			0.7
Decrease in bank indebtedness		-			(1.4	)
Increase in accounts payable		-			0.5
Increase in accrued interest		0.8			0.6
		1.4			0.4
(Increase)/decrease in investing working capital		(0.1	)		0.6
Decrease/(increase) in operating working capital		1.5			(0.2	)

Note 11 Accounting Pronouncements

The Partnership adopted the provision of SFAS No. 157-2, Effective Date of FASB Statement No. 157 (SFAS No. 157-2), for all non-financial assets and liabilities measured on a recurring basis, effective January 1, 2009. The adoption of SFAS No. 157-2 had no material impact on our results of operations or financial position for the quarter ending March 31, 2009.

The Emerging Issues Task Force of the Financial Accounting Standards Board (FASB) issued EITF 07-4, “Application of the Two-Class Method under FASB Statement No. 128, Earnings per share, to Master Limited Partnerships,” which was ratified by the FASB in March 2008. EITF 07-4 is effective for fiscal years beginning after December 15, 2008. The Partnership adopted the provisions of EITF 07-4 effective January 1, 2009. Refer to Note 6 for the impact to our financial statements.

The Partnership adopted the provisions of SFAS No. 161, Disclosures about Derivatives Instruments and Hedging activities-an amendment of FASB Statement No. 133, effective January 1, 2009. There was no material effect on the Partnerships’ disclosure following adoption of this standard.

Note 12 Subsequent Events

On April 17, 2009, the Board of Directors of the general partner declared the Partnership’s first quarter 2009 cash distribution in the amount of $0.705 per common unit, payable on May 15, 2009, to unitholders of record on April 30, 2009.

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	level of natural gas basis differentials;

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

availability of supplies of Canadian and United States (U.S.) natural gas, including newly discovered natural gas developments such as the Horn River and Montney shale gas developments in Western Canada, U.S. Rockies and U.S. Mid-Continent shale gas developments, and the Marcellus shale gas developments;

o	availability of additional storage capacity and current storage levels;

o	level of liquefied natural gas imports;

o	weather conditions that impact supply and demand;

o	ability of shippers to meet credit worthiness requirements; and

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

·	changes in relative cost structures of natural gas producing basins, such as changes in royalty programs, that may prejudice the development of the Western Canada Sedimentary Basin (WCSB);

·	the decision by other pipeline companies to advance projects which will affect our pipeline systems and the regulatory, financing and construction risks related to construction of interstate natural gas pipelines;

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

·	the imposition of entity level taxation by states 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, and proposed and pending legislation by Congress and the Environmental Protection Agency (EPA) related to green house gas emissions on us and our pipeline systems;

·	our ability to control operating costs; and

·	the severity and length of the current economic downturn, which impacts:

o	the debt and equity capital markets and our ability to access these markets;

o	the overall demand for natural gas by end users; and

o	natural gas prices

Other factors described elsewhere in this document, or factors that are unknown or unpredictable, could also have material adverse effects on future results. Please also read Item 1A. “Risk Factors” in our annual report on Form 10-K for the year ended December 31, 2008. All forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by these factors. These forward-looking statements and information are made only as of the date of the filing of this report, and except as required by applicable law, we undertake no obligation to update these forward-looking statements and information to reflect new information, subsequent events or otherwise.

The following discussion and analysis should be read in conjunction with our 2008 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, 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. TransCanada and its subsidiaries are herein collectively referred to as “TransCanada”.

We own a 46.45 per cent general partner interest in Great Lakes. 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 general partner interest is held by ONEOK Partners, L.P., a publicly traded limited partnership that is controlled by ONEOK, Inc.

We own a 100 per cent general partner interest in Tuscarora.

Our general partner interests in Great Lakes, Northern Border and Tuscarora represent our only material assets at March 31, 2009. 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 in the Powder River Basin of Wyoming and Montana, as well as 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 OUR BUSINESS

Key factors that impact our business are the cash flows received from our investments and our ability to maintain a strong and balanced financial position. Cash flows from our investments are dependent upon the ability of Great Lakes and Northern Border to make distributions to us and of Tuscarora to generate positive operating cash flows. Partnership cash flows from our investments are necessary to fund distributions to our unitholders. A strong financial position will ensure that we are able to maintain a prudent level of available cash to make distributions to our unitholders.

FACTORS THAT IMPACT THE BUSINESS OF OUR PIPELINE SYSTEMS

Our pipeline systems provide natural gas transportation services to their customers. Key factors that impact their business 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. These factors are discussed in more detail below.

Supply and Demand of Natural Gas

Our pipeline systems depend upon the continued availability of natural gas production and reserves in the regions we access, primarily the WCSB. Our pipeline systems provide their customers with natural gas transportation services to market demand areas. The net WCSB Flows to Markets are dependent upon natural gas production levels, demand for natural gas in Western Canada, and storage capacity for Western Canadian natural gas and demand for storage injection. The net WCSB Flows to Markets were lower in the first quarter of 2009 compared to the same period in 2008, due mainly to a decrease in production and combined with an increase in Western Canadian demand. Western Canadian demand increased mainly due to demand related to oil sands production activities as well as an increase in electric power generation demand associated with unseasonably cool weather conditions. U.S. natural gas production, a supply competitor to the WCSB, continues to be strong, mainly due to the development of unconventional reserves in the lower 48 states.

Decreases in WCSB production are expected to continue throughout the remainder of 2009 due to a decline in drilling and exploration activity by WCSB producers, mainly related to the sharp reductions in commodity prices which began in the last half of 2008 and continued into the first quarter of 2009. Natural gas prices are expected to continue to be under pressure during the remainder of 2009 due to declining oil prices, declining natural gas demand, current levels of gas in storage and the general economic slowdown. The impact of depressed natural gas prices is impacting production from all producing regions. Continued low oil and gas commodity prices, combined with restrictions on liquidity and access to capital, have contributed to the postponement and/or cancellation of certain oil sands projects, which could decrease Western Canadian demand for WCSB natural gas.

Factors which may mitigate declines related to WCSB production in the future include strengthening gas prices and decreases in oil prices as they affect demand from Alberta oil sands production. We expect WCSB producers will continue to explore and develop new fields in Western Canada as well as direct significant activity at unconventional resources such as coal bed methane and shale gas. Additional Canadian natural gas supply sources may be available in the future if new pipeline projects associated with the Montney and Horn River shale gas regions in Western Canada, the Mackenzie Delta in Northern Canada and the North Slope of Alaska are constructed.

Factors which may impact the overall demand for natural gas include weather conditions, economic conditions, government regulation, availability and price of alternative energy sources, fuel conservation measures, and technological advances in fuel economy and energy generation devices. Although demand for natural gas is expected to decline in North America in 2009 with the current economic downturn, we expect a demand increase in the long term. In certain sectors, such as the electric generation sector, lower natural gas prices lead to an expected increase in demand for natural gas.

Western Canadian natural gas in storage is currently above five year averages. U.S. working gas storage levels are also at near record high levels. High levels of injection into Western Canadian gas storage result in less WCSB gas available for export while high U.S. gas storage levels impact the demand for natural gas in the market areas that storage serves. High overall storage levels have a dampening effect on natural gas prices which in turn impacts ongoing production.

Demand for natural gas transportation service on our pipeline systems is directly related to the activity in the natural gas markets served by these systems. Factors that may impact demand for transportation service on any one system include the ability and willingness of natural gas shippers to utilize one system over alternative pipelines, transportation rates, and the volume of natural gas delivered to markets from other supply sources and storage facilities. The impact of changes in demand for natural gas transportation services on operating revenues for our pipeline systems is dependent upon the extent to which capacity has been contracted under long term firm contracts.

Net WCSB Flows to Markets is one of the factors which impacts the throughput on our pipeline systems. However, the activity in the natural gas markets served by our pipeline systems was the major factor affecting throughput of our pipeline systems for the first quarter of 2009 compared to the first quarter of 2008. We cannot predict the impact of any continued declines in net WCSB Flows to Markets and uncertain market conditions are expected to continue to affect throughput for the remainder of 2009.

Throughput on the Great Lakes pipeline system in the first quarter of 2009 [average 2,549 million cubic feet per day (MMcf/d)] was higher compared to the same period in 2008 (average 2,444 MMcf/d). Increases in short term and discretionary volumes more than offset the underutilization of firm contracts. Decreases in throughput related to underutilization of firm contracts have a minimal impact on revenue.

Throughput on Northern Border declined in the first quarter of 2009 (average 1,993 MMcf/d) relative to the same period in 2008 (average 2,452 MMcf/d) as the Midwest markets served by Northern Border continued to be impacted by the incremental supply from the Rockies natural gas basins transported to these markets on the western segment of the Rockies Express Pipeline (REX West). In addition to overall decreased demand due to the weaker economy, demand for natural gas in Northern Border's market was further impacted by warmer weather in the first quarter of 2009. Decreased overall demand reduces the ability to contract available pipeline capacity serving this market area.

Tuscarora’s transportation capacity is substantially all contracted under long term firm contracts. Therefore, although throughput may vary, there is a minimal impact on revenue.

Customers and Contracting

Great Lakes’ average contracted capacity was 106 per cent of its design capacity for the first quarter of 2009 compared to 104 percent in 2008. At March 31, 2009, 95 per cent of its average design capacity was contracted on a firm basis for the remainder of the year and the weighted average remaining life of firm transport contracts was 2.6 years. Great Lakes’ competitive rate combined with strong spread values between Alberta and Dawn, Ontario continued to support strong transportation values for Great Lakes, which was sold out of long term firm capacity for the winter season and was also able to take advantage of daily sales in the short term market.

Northern Border’s average contracted capacity was 87 per cent of its design capacity for the first quarter of 2009 compared to 106 per cent for the same period last year. As at March 31, 2009, Northern Border had approximately 60 percent of its design capacity uncontracted beginning in the second quarter of 2009 through the remainder of 2009. Prevailing market conditions and competitive factors in North America, including the Rockies Express Pipeline, will continue to impact the value of Northern Border’s transportation and its ability to market available capacity. Northern Border expects to continue to discount transportation capacity as needed to optimize revenue. As at March 31, 2009, the weighted average remaining life of Northern Border’s firm transportation contracts was 2.0 years.

Tuscarora operates under long-term contracts and had 100 per cent of its design capacity contracted for the first quarter of 2009. As at March 31, 2009, 98 per cent of its design capacity was contracted on a firm basis for the remainder of the year with a weighted average remaining life of 11.4 years.

Competition

Our pipeline systems compete primarily with other interstate and intrastate pipelines in the transportation of natural gas. Additionally, supply competition from other natural gas sources can impact demand for transportation on our pipeline systems. Growth in supplies available from other natural gas producing regions can impact prices for natural gas delivered to some of the markets our pipeline systems serve relative to other market regions.

Factors impacting the competition for WCSB gas available for export during the remainder of 2009 will include relatively low natural gas storage levels in Eastern Canada and low levels of hydro-electric power generation in the Northwestern U.S., which will result in an increased demand for natural gas fired power generation in that region.

Changes in North American gas flow patterns are expected as a result of new pipeline projects which will change the supply competition in the markets served by our pipeline systems. REX West introduced new gas supplies from the Rockies gas basin into the markets served by Northern Border in the second quarter of 2008.

The Eastern segment of the Rockies Express Pipeline (REX East), from Missouri to Ohio, will transport natural gas further east. This is expected to create additional supply in the markets Great Lakes serves, but may also provide opportunities for Great Lakes to market its Eastern zone capacity for storage injection and withdrawal. The in-service of REX East could mitigate excess supply in Northern Border’s Ventura market which may improve opportunities for the marketing of this capacity, but may also increase supply to the Chicago market. Rockies Express Pipeline has announced that interconnects on REX East are expected to be placed in service in the second and fourth quarters of 2009.

Two new pipeline projects are expected to go into service in the second quarter of 2009 to transport volumes from the lower Mid-Continent east to the existing Gulf Coast pipeline infrastructure. These new projects could introduce new supply to the Chicago market, Eastern U.S. markets, or Gulf Coast markets, depending upon demand. Additional supply in the Chicago market may continue to impact Northern Border’s ability to contract upstream available capacity for the remainder of 2009 if natural gas flows to Chicago materially decrease.

RECENT DEVELOPMENTS

Northern Border

Des Plaines Project – Northern Border’s compressor station and interconnect facilities project went into service in March 2009, with a final cost of approximately $17 million, which was within the original cost estimate. The project is fully subscribed under long-term compression and transportation contracts. The new contract is expected to generate approximately $3.0 million in annual revenue.

RESULTS OF OPERATIONS OF TC PIPELINES

Critical Accounting Policies and Estimates

The preparation of financial statements in accordance with U.S. 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 three months ended March 31, 2009.

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, 2008.

Recent Accounting Pronouncements

The Partnership adopted the provision of Statement of Financial Accounting Standards (SFAS) No. 157-2, Effective Date of FASB Statement No. 157 (SFAS No. 157-2), for all non-financial assets and liabilities measured on a recurring basis, effective January 1, 2009. The adoption of SFAS No. 157-2 had no material impact on our results of operations or financial position for the quarter ending March 31, 2009.

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 March 31, 2009
(millions of dollars)	PipeLP			TGTC			Other			GLGT			NBPC(1)
Transmission revenues		8.4			8.4			-			82.5			74.5
Operating expenses		(2.6	)		(1.4	)		(1.2	)		(16.0	)		(18.5	)
		5.8			7.0			(1.2	)		66.5			56.0
Depreciation		(1.8	)		(1.8	)		-			(14.6	)		(15.3	)

Financial charges, net and other		(7.3	)		(1.1	)		(6.2	)		(8.2	)		(9.1	)
Michigan business tax		-			-			-			(1.8	)		-
											41.9			31.6
Equity income		35.1			-			-			19.5			15.6
Net income		31.8			4.1			(7.4	)		19.5			15.6


(unaudited)	For the three months ended March 31, 2008
(millions of dollars)	PipeLP			TGTC			Other			GLGT			NBPC(1)
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 50 per cent general partner interest in Northern Border. 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.

First Quarter 2009 Compared with First Quarter 2008

Net income was $31.8 million in the first quarter of 2009, a decrease of $1.8 million compared to $33.6 million in the first quarter of 2008. This decrease is primarily due to lower equity income from Northern Border in 2009.

Equity income from Great Lakes increased $0.9 million to $19.5 million in the first quarter of 2009, compared to $18.6 million in the first quarter of 2008. At Great Lakes’ level, net income increased $1.8 million compared to the first quarter of 2008, primarily due to an increase in transmission revenues partially offset by higher operating expenses. Great Lakes’ transmission revenues for the three months ended March 31, 2009 increased $2.8 million compared to the same period last year, primarily due to increases in sales of short-term services, partially offset by decreased long-term services as a result of contract non-renewals on the eastern portion of the pipeline system. Operating expenses increased $0.9 million due primarily to higher pipeline maintenance and overhaul costs.

Equity income from Northern Border was $15.6 million in the first quarter of 2009, a decrease of $3.9 million compared to $19.5 million in the same period last year. At Northern Border’s level, net income decreased $7.9 million to $31.6 million in the first quarter of 2009, compared to $39.5 million in the first quarter of 2008. The decrease in net income was primarily due to decreased transmission revenues, partially offset by lower operating expenses. Transmission revenues decreased by $9.3 million for the three months ended March 31, 2009 compared to the same period last year primarily due to reduced system utilization as Northern Border which continues to be negatively impacted by the incremental natural gas supply from the Rockies Basin into the Mid-Continent market as a result of the in-service of REX West. Operating expenses decreased $0.9 million for the three months ended March 31, 2009 compared to the same period last year as a result of decreased general and administrative expenses.

Tuscarora’s net income of $4.1 million for the first quarter of 2009 represented an increase of $0.9 million compared to $3.2 million in the same period last year. This increase was primarily due to higher transmission revenues resulting from the Likely compressor station expansion project that went into service on April 1, 2008.

The Partnership’s operating expenses and financial charges, net and other on a non-consolidated basis for the first quarter of 2009 were consistent with the same period last year.

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 March 31,
(millions of dollars except per common unit amounts)	2009			2008
Net Income		31.8			33.6
Add:
Cash flows provided by Tuscarora's operating activities		7.2			6.0
Cash distributions from Great Lakes (1)		12.5			11.6
Cash distributions from Northern Border (1)		24.2			23.1
		43.9			40.7
Less:
Tuscarora's net income		(4.1	)		(3.2	)
Equity income from investment in Great Lakes		(19.5	)		(18.6	)
Equity income from investment in Northern Border		(15.6	)		(19.5	)
		(39.2	)		(41.3	)
Partnership cash flows		36.5			33.0
Partnership cash flows allocated to general partner (2)		(3.2	)		(3.0	)
Partnership cash flows allocated to common units		33.3			30.0
Cash distributions declared		(27.7	)		(27.4	)
Cash distributions declared per common unit (3)	$	0.705		$	0.700
Cash distributions paid		(27.7	)		(25.6	)
Cash distributions paid per common unit (3)	$	0.705		$	0.665
Weighted average common units outstanding (millions)		34.9			34.9

(1) In accordance with the cash distribution policies of the respective pipeline assets, cash distributions from Great Lakes and Northern Border are based on their respective prior quarter financial results.

(2) Partnership cash flows allocated to general partner represents the cash distributions declared to the general partner with respect to its two per cent interest plus an amount equal to incentive distributions. Previously, Partnership cash flows allocated to general partner were based on the cash distributions paid to the general partner during the quarter; however, this has been changed to align with the requirements of EITF 07-4. As a result, Partnership cash flows allocated to general partner in first quarter of 2008 increased from $2.4 million to $3.0 million.

(3) 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.

First Quarter 2009 Compared with First Quarter 2008

Partnership cash flows increased $3.5 million to $36.5 million for the first quarter of 2009 compared to $33.0 million for the same period of last year. This increase was primarily a result of increased cash flows provided by Tuscarora’s operating activities, and larger cash distributions received from Northern Border and Great Lakes. Cash flows provided by Tuscarora’s operating activities increased $1.2 million for the three months ended March 31, 2009 compared to the same period in the prior year, primarily due to higher transmission revenues resulting from the Likely Compressor Station expansion that went into service on April 1, 2008. Northern Border’s increased distribution was primarily due to a reduction in maintenance capital expenditures and lower interest expenses. Great Lakes’ increased distribution was primarily due to a reduction in maintenance capital expenditures.

During the three months ended March 31, 2009, the Partnership made an equity contribution of $4.3 million to Northern Border, representing the Partnership’s 50 per cent share of an $8.6 million cash call issued by Northern Border to complete the Des Plaines Project.

The Partnership paid distributions of $27.7 million in the first quarter of 2009, an increase of $2.1 million compared to $25.6 million for the same period in the prior year due to an increase in the quarterly per common unit distribution amounts.

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, 2009:

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

Senior Credit Facility due 2011	475.0	-	475.0
7.13% Series A Senior Notes due 2010	51.3	3.1	48.2
7.99% Series B Senior Notes due 2010	5.0	0.5	4.5
6.89% Series C Senior Notes due 2012	5.5	0.8	4.7
Total	536.8	4.4	532.4

TC Pipelines’ revolving credit and term loan agreement (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 2.44 per cent for the three months ended March 31, 2009 (2008 – 5.02 per cent). After hedging activity, the interest rate incurred on the Senior Credit Facility averaged 5.06 per cent for the three months ended March 31, 2009 (2008 – 5.28 per cent). Prior to hedging activities, the interest rate was 1.85 per cent at March 31, 2009 (December 31, 2008 – 2.67 per cent). At March 31, 2009, we were in compliance with our financial covenants.

Interest Rate Swaps and Options

The interest rate swaps and options are structured such that the cash flows match those of the Senior Credit Facility. The notional amount hedged during the three months ended March 31, 2009 was $475.0 million, unchanged from the same period last year. At March 31, 2009, the fair value of the interest rate swaps and options accounted for as hedges was negative $30.4 million (December 31, 2008 – negative $31.7 million). Under SFAS 157, 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 months ended March 31, 2009, we recorded interest expense of $3.2 million (March 31, 2008 - $0.3 million) in regards to the interest rate swaps and options.

2009 First Quarter Cash Distribution

On April 17, 2009, the Board of Directors of the general partner declared the Partnership’s 2009 first quarter cash distribution in the amount of $0.705 per common unit. This cash distribution, totaling $27.7 million, will be paid on May 15, 2009 to unitholders of record as of April 30, 2009, in the following manner: $24.5 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), $2.7 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.

2009 Capital Requirements

Northern Border’s distribution policy adopted in 2006 defines minimum equity to total capitalization to be used by its Management Committee to establish the timing and amount of required equity contributions. In accordance with this policy, Northern Border currently estimates an equity contribution of approximately $76 million in the balance of 2009, of which the Partnership’s share would be approximately $38 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 sources of liquidity are cash generated from operating activities, bank credit facilities and equity contributions from their partners. 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 unsecured notes or equity contributions from our pipeline systems’ partners. The ability of our pipeline systems to access the debt capital markets under reasonable terms depends on their financial position, credit ratings and market conditions.

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

Debt of Great Lakes

The following table summarizes Great Lakes’ debt outstanding as of March 31, 2009:

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

8.74% series Senior Notes due 2007 to 2011	30.0	10.0	20.0
6.73% series Senior Notes due 2009 to 2018	81.0	9.0	72.0
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	421.0	19.0	402.0

Great Lakes is required to comply with certain financial, operational and legal covenants. Under the most restrictive covenants in the Senior Note Agreements, approximately $227.0 million of Great Lakes’ partners’ capital was restricted as to distributions as of March 31, 2009 (December 31, 2008 - $232.0 million). As at March 31, 2009, 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, 2009:

	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)	176.0	-	176.0
Total	626.0	200.0	426.0

(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, 2009, Northern Border had outstanding borrowings of $176.0 million under its $250.0 million revolving credit agreement and was in compliance with the covenants of the agreement. The weighted average interest rate related to the borrowings on its credit agreement was 1.29 per cent at March 31, 2009.

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 intends to refinance the senior notes with a combination of partner equity contributions, fixed-rate and variable-rate debt.

Interest Rate Collar Agreement

At March 31, 2009, Northern Border’s balance sheet reflected an unrealized loss of approximately $3.4 million with a corresponding increase to accumulated other comprehensive loss related to the changes in fair value of its interest rate collar agreement (the “Collar Agreement”) since inception. During the three months ended March 31, 2009, Northern Border recorded interest expense of $0.9 million under the Collar Agreement. Hedge ineffectiveness had no impact on income for the three months ended March 31, 2009.

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. Our primary risk management objective is to protect earnings and cash flow, and ultimately unitholder value. We do not use financial instruments for trading purposes.

In accordance with SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, (SFAS No. 133) 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.

MARKET RISK AND INTEREST RATE RISK

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

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

·	Swaps – contractual agreements between two parties to exchange streams of payments over time according to specified terms. The Partnership and our pipeline systems enter into interest rate swaps to mitigate the impact of changes in interest rates.

Options – contractual agreements to convey the right, but not the obligation, for the purchaser to buy or sell a specific amount of a financial instrument at a fixed price, either at a fixed date or at any time within a specified period. The Partnership and our pipeline systems enter into option agreements to mitigate the impact of changes in interest rates.

Interest rate risk is created by fluctuations in the fair values or cash flows of financial instruments due to changes in the market interest rates. Our interest rate exposure results from our Senior Credit Facility, which is subject to variability in 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, 2009 was $475.0 million (December 31, 2008 - $475.0 million). $300.0 million of variable-rate debt is hedged by an interest rate swap during the period from March 12, 2007 through December 12, 2011, where the weighted average fixed interest rate paid is 4.89 per cent. $100.0 million of variable-rate debt is hedged by an interest rate option during the period from May 22, 2007 through May 22, 2009 at an interest rate range between a weighted average floor of 4.09 per cent and a cap of 5.35 per cent. $75.0 million of variable-rate debt is hedged by an interest rate swap during the period from February 29, 2008 through February 28, 2011, where the fixed interest rate paid is 3.86 per cent. 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, 2009, the fair value of the Partnership’s interest rate swaps and options accounted for as hedges was negative $30.4 million (December 31, 2008 – negative $31.7 million), of which $12.0 million is classified as a current liability (December 31, 2008 - $11.8 million). The fair value of the interest rate swaps and options is calculated using the period-end interest rate; therefore, it is expected that this fair value will fluctuate over the year as interest rates change.

At March 31, 2009, we had $475.0 million (December 31, 2008 - $475.0 million) outstanding on our Senior Credit Facility. Utilizing the conditions of the interest rate swaps and options, if LIBOR interest rates hypothetically increased or decreased by one per cent (100 basis points) compared to the rates in effect as of March 31, 2009, our annual interest expense for the quarter ended March 31, 2009 would be unchanged, as all of our outstanding debt at March 31, 2009 was hedged using interest rates swaps and options.

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, 2009, 72 per cent of Northern Border’s outstanding debt was at fixed rates (December 31, 2008 – 71 per cent). Northern Border utilizes its Collar Agreement to limit the variability of the interest rate on $140.0 million of variable-rate borrowings through October 30, 2009 to a range between a floor of 4.35 per cent and a cap of 5.36 per cent.

Utilizing the conditions of the Collar Agreement, if interest rates hypothetically increased by one per cent (100 basis points) compared with rates in effect as of March 31, 2009, Northern Border’s annual interest expense would increase and its net income would decrease by approximately $0.4 million (2008 - $0.2 million); and if interest rates hypothetically decreased by one per cent (100 basis points) compared with rates in effect as of March 31, 2009, Northern Border’s annual interest expense would decrease and its net income would increase by approximately $0.4 million (2008 - $0.2 million).

Northern Border has $200.0 million of senior notes maturing September 1, 2009. It intends to refinance the senior notes with a combination of equity contributions from its partners, fixed-rate and variable-rate debt. Prevailing market conditions could impact the terms of the refinancing.

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.

Counterparty credit risk represents the financial loss that the Partnership and our pipeline systems would experience if a counterparty to a financial instrument failed to meet its obligations in accordance with the terms and conditions of its contracts with the Partnership or its pipeline systems. Our maximum counterparty credit exposure with respect to financial instruments at the balance sheet date consist primarily of the carrying amount, which approximates fair value, of non-derivative financial assets, such as accounts receivable, as well as the fair value of derivative financial assets. At March 31, 2009, the Partnership’s maximum counterparty credit exposure consisted of accounts receivable of $2.9 million (December 31, 2008 - $2.9 million).

The Partnership and our pipeline systems have significant credit exposure to financial institutions as they provide committed credit lines and critical liquidity in the interest rate derivative market, as well as letters of credit to mitigate exposures to non-creditworthy parties. During the deterioration of global financial markets in 2008 and 2009, we continued to closely monitor the creditworthiness of our counterparties, including financial institutions. Overall, we do not believe the Partnership and our pipeline systems have any significant concentrations of counterparty credit risk.

Liquidity risk is the risk that the Partnership and our pipeline systems will not be able to meet our financial obligations as they fall due. Our approach to managing liquidity risk is to ensure that we always have sufficient cash and credit facilities to meet our obligations when due, under both normal and stressed conditions, without incurring unacceptable losses or damage to our reputation. At March 31, 2009, the Partnership has a committed revolving bank line of $250.0 million maturing in December 2011. As of March 31, 2009, no draws were made on this facility. In addition, at March 31, 2009, Northern Border has a committed revolving bank line of $250.0 million maturing in April 2012. As of March 31, 2009, $176.0 million was drawn on this facility.

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 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, 2009, 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 risk factors disclosed in part I, Item 1A, “Risk Factors”, in our annual report on Form 10-K for the year ended December 31, 2008.

Item 6. Exhibits

No. Description

10.1	Market Center Service Agreement MC11987 between Great Lakes Gas Transmission Limited Partnership and TransCanada Gas Storage USA Inc., dated February 27, 2009.

10.2	Transportation Service Agreement IT11986 between Great Lakes Gas Transmission Limited Partnership and TransCanada Gas Storage USA Inc., dated February 27, 2009.

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, 2008 and 2007.

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, 2009	By:	/s/ Russell K. Girling Russell K. Girling Chairman, Chief Executive Officer and Director TC PipeLines GP, Inc. (Principal Executive Officer)
Date:	April 30, 2009	By:	/s/ Amy W. Leong Amy W. Leong Controller TC PipeLines GP, Inc. (Principal Financial Officer)