TC PIPELINES LP - FORM 10-Q

Attached files

file	filename
EX-32.1 - CEO CERTIFICATION PURSUANT TO SECTION 906 - TC PIPELINES LP	exhibi321.htm
EX-32.2 - CFO CERTIFICATION PURSUANT TO SECTION 906 - TC PIPELINES LP	exhibit322.htm
EX-10.1 - YUMA TRANSFER AGREEMENT - TC PIPELINES LP	exhibit101.htm
EX-31.1 - CEO CERTIFICATION PURSUANT TO SECTION 302 - TC PIPELINES LP	exhibit311.htm
EX-31.2 - CFO CERTIFICATION PURSUANT TO SECTION 302 - TC PIPELINES LP	exhibit312.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, 2010

[ ] 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)

717 Texas Street, Suite 2400
Houston, Texas	77002-2761
(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, 2010, there were 46,227,766 of the registrant’s common units outstanding.

TC PIPELINES, LP

TABLE OF CONTENTS		Page No.

GLOSSARY		3

PART I	FINANCIAL INFORMATION

Item 1.	Financial Statements	4

	Consolidated Statement of Income – Three months ended March 31, 2010 and 2009
	Consolidated Statement of Comprehensive Income – Three months ended March 31, 2010 and 2009
	Consolidated Balance Sheet – March 31, 2010 and December 31, 2009
	Consolidated Statement of Cash Flows – Three months ended March 31, 2010 and 2009
	Consolidated Statement of Equity – Three months ended March 31, 2010
	Notes to Consolidated Financial Statements

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	16
	Results of Operations of TC PipeLines, LP
	Liquidity and Capital Resources of TC PipeLines, LP
	Liquidity and Capital Resources of Our Pipeline Systems

Item 3.	Quantitative and Qualitative Disclosures about Market Risk	30

Item 4.	Controls and Procedures	32

PART II	OTHER INFORMATION

Item 1.	Legal Proceedings	34

Item 1A.	Risk Factors	34

Item 6.	Exhibits	36

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:

Alberta Hub	The grouping of gas gathering lines, processing, storage facilities in large scale and also a "liquid" pricing point recognized for trading in Alberta, Canada
ASC	Accounting Standards Codification
CAA	U.S. Environmental Protection Agency's Clean Air Act
Design capacity	Pipeline capacity available to transport natural gas based on system facilities and design conditions
EPA	U.S. Environmental Protection Agency
FERC	Federal Energy Regulatory Commission
GAAP	U.S. generally accepted accounting principles
Gas exiting the WCSB	Net of the supply of and demand for natural gas in the WCSB region that is available for transportation to downstream markets; where supply represents WCSB production adjusted for injections into and withdrawals from WCSB storage
General Partner	TC PipeLines GP, Inc.
GL Cost and Revenue Study	Cost and Revenue study filed by Great Lakes with the FERC in response to the FERC's November 19, 2009 Order
GL Rate Proceeding	FERC investigation into Great Lakes' rates pursuant to Section 5 of the NGA
Great Lakes	Great Lakes Gas Transmission Limited Partnership
LIBOR	London Interbank Offered Rate
MDth/d	Thousand dekatherms per day
MMcf/d	Million cubic feet per day
NGA	Natural Gas Act
North Baja	North Baja Pipeline, LLC
Northern Border	Northern Border Pipeline Company
NOV	Notice of Violation
November 2009 Order	FERC order issued in FERC Docket No. RP10-149 on November 19, 2009 instituting GL Rate Proceeding
Other Pipes	North Baja and Tuscarora
Our pipeline systems	Great Lakes, Northern Border, North Baja and Tuscarora
Partnership	TC PipeLines, LP and its subsidiaries
Partnership Agreement	Second Amended and Restated Agreement of Limited Partnership
SEC	Securities and Exchange Commission
Senior Credit Facility	TC PipeLines' revolving credit and term loan agreement
TransCanada	TransCanada Corporation and its subsidiaries
Tuscarora	Tuscarora Gas Transmission Company
U.S.	United States of America
WCSB	Western Canada Sedimentary Basin
Yuma Lateral	An expansion of the North Baja pipeline from the Mexico/Arizona border to Yuma, Arizona

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)	2010			2009(a)

Equity income from investment in Great Lakes (Note 2)		16.3			19.5
Equity income from investment in Northern Border (Note 3)		14.6			15.6
Transmission revenues		17.4			16.8
Operating expenses		(3.4	)		(2.9	)
General and administrative		(1.3	)		(1.2	)
Depreciation		(3.7	)		(3.6	)
Financial charges, net and other		(6.2	)		(8.3	)
Net income		33.7			35.9

Net income allocation (Note 6)
Common units		33.0			28.5
General partner		0.7			3.3
		33.7			31.8

Net income per common unit (Note 6)	$	0.71		$	0.82

Weighted average common units outstanding (millions)		46.2			34.9

Common units outstanding, end of the period (millions)		46.2			34.9

(a) Recast as discussed in Note 1.

CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME

(unaudited)	Three months ended March 31,
(millions of dollars)	2010		2009

Net income(a)		33.7		35.9
Other comprehensive income/(loss)
Change associated with hedging transactions (Note 10)		1.6		1.4
Change associated with hedging transactions of investees		-		(0.1	)
		1.6		1.3
Total comprehensive income		35.3		37.2

(a) Recast as discussed in Note 1.

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

TC PIPELINES, LP

CONSOLIDATED BALANCE SHEET

(unaudited)
(millions of dollars)	March 31, 2010			December 31, 2009
Assets
Current Assets
Cash and cash equivalents		4.0			3.1
Accounts receivable and other (Note 11)		8.0			8.6
		12.0			11.7
Investment in Great Lakes (Note 2)		694.2			691.2
Investment in Northern Border (Note 3)		521.3			523.0
Plant, property and equipment
(net of $122.0 accumulated depreciation; 2009 – $118.3)		321.4			318.0
Goodwill		130.2			130.2
Other assets		0.9			1.0
		1,680.0			1,675.1

Liabilities and Partners' Equity
Current Liabilities
Accounts payable and accrued liabilities		3.3			4.5
Accrued interest		2.5			1.3
Current portion of long-term debt (Note 5)		53.4			53.4
Current portion of fair value of derivative contracts (Note 10)		13.7			12.9
		72.9			72.1
Long-term debt (Note 5)		494.9			487.9
Fair value of derivative contracts and other (Note 10)		9.3			11.6
		577.1			571.6

Partners' Equity
Common units		1,103.4			1,105.6
General partner		23.6			23.6
Accumulated other comprehensive loss		(24.1	)		(25.7	)
		1,102.9			1,103.5
		1,680.0			1,675.1

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)	2010			2009(a)

CASH GENERATED FROM OPERATIONS
Net income		33.7			35.9
Depreciation		3.7			3.6
Amortization of other assets		0.1			0.1
Equity income in excess of distributions received from Great Lakes		(0.6	)		(7.0	)
Increase in long-term liabilities		0.1			-
Equity allowance for funds used during construction		(0.2	)		0.1
Increase/(decrease) in operating working capital (Note 8)		0.6			1.0
		37.4			33.7

INVESTING ACTIVITIES
Cumulative distributions in excess of equity earnings:
Northern Border		1.7			8.6
Investment in Great Lakes		(2.3	)		-
Investment in Northern Border (Note 3)		-			(4.3	)
Capital expenditures (Note 4)		(8.5	)		(0.5	)
Increase in investing working capital (Note 8)		-			(0.1	)
		(9.1	)		3.7

FINANCING ACTIVITIES
Distributions paid (Note 7)		(34.4	)		(27.7	)
Long-term debt issued (Note 5)		10.0			-
Long-term debt repaid (Note 5)		(3.0	)		-
Due to North Baja's former parent		-			(5.1	)
		(27.4	)		(32.8	)

(Decrease)/increase in cash and cash equivalents		0.9			4.6
Cash and cash equivalents, beginning of period		3.1			8.4

Cash and cash equivalents, end of period		4.0			13.0

Interest payments made		2.4			4.8

(a) Recast as discussed in Note 1.

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

TC PIPELINES, LP

CONSOLIDATED STATEMENT OF CHANGES IN PARTNERS’ EQUITY

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

Partners' equity at December 31, 2009	46.2	1,105.6		23.6		(25.7	)	46.2	1,103.5
Net income	-	33.0		0.7		-		-	33.7
Distributions paid	-	(33.7	)	(0.7	)	-		-	(34.4	)
Excess purchase price over acquired assets(b)	-	(1.5	)	-		-		-	(1.5	)
Other comprehensive income	-	-		-		1.6		-	1.6
Partners' equity at March 31, 2010	46.2	1,103.4		23.6		(24.1)		46.2	1,102.9

(a) The Partnership uses derivatives to assist in managing its exposure to interest rate risk. Based on interest rates at March 31, 2010, 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 $13.7 million, which will be offset by a reduction to interest expense of a similar amount.

(b) Accounting adjustment for common control transaction. See Note 4 for details.

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

TC PIPELINES, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1 ORGANIZATION

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

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

The results of operations for the three months ended March 31, 2010 and 2009 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, 2009. 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, 2009.

On July 1, 2009, the Partnership acquired a 100 per cent interest in North Baja Pipeline, LLC (North Baja), a Delaware limited liability company, from a wholly-owned subsidiary of TransCanada Corporation. TransCanada Corporation and its subsidiaries are herein collectively referred to as “TransCanada.” Because North Baja was acquired from TransCanada, the acquisition was accounted for as a transaction between entities under common control, similar to a pooling of interests, whereby the assets and liabilities of North Baja were recorded at TransCanada’s carrying value and the Partnership’s historical financial information was recast to include the acquired entity for all periods presented. The effect of recasting the Partnership’s consolidated financial statements to account for the common control transaction increased the Partnership’s net income by $4.1 million from amounts previously reported for the three months ended March 31, 2009.

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 TransCanada.

On November 19, 2009, the FERC issued an order in FERC Docket No. RP10-149 (November 2009 Order) instituting an investigation pursuant to Section 5 of the Natural Gas Act (GL Rate Proceeding). The FERC alleged, based on a review of certain historical information, that Great Lakes’ revenues might substantially exceed Great Lakes’ actual cost of service and therefore may be unjust and unreasonable. On February 4, 2010, Great Lakes filed a cost and revenue study (GL Cost and Revenue Study) in response to the November 2009 Order. The GL Cost and Revenue Study reflects the increased risk of de-contracting on the Great Lakes system, which may result in decreases to overall long-term, daily and short-term firm transportation revenues, and interruptible transportation revenues, as compared to prior periods.

On April 16, 2010, Great Lakes filed a Motion to Suspend Procedural Schedule (the Motion) indicating that an agreement in principle has been reached among Great Lakes, active participants and the FERC trial staff. The Motion requests a temporary suspension of the GL Rate Proceeding schedule for all parties to permit the drafting of a stipulation and agreement, and the Motion was granted by the Chief Administrative Law Judge on the same day. The parties are negotiating the settlement terms and anticipate filing a binding, written stipulation and agreement embodying the settlement’s terms on or about May 17, 2010, for subsequent approval by the Administrative Law Judge and the FERC. Until the filing of the written stipulation and agreement, the terms of a settlement will remain confidential. In the absence of a settlement, a hearing in the GL Rate Proceeding is scheduled for early August 2010 and an initial decision by the Administrative Law Judge is expected in November 2010. Any of the following elements of Great Lakes’ rate structure may be affected in settlement or litigation, including but not limited to: firm transportation, interruptible transportation and/or incremental rates; revenues; depreciation; and interruptible transportation revenue sharing. A revised rate structure as a result of a settlement, if reached, would be in place as early as the second quarter of 2010.

We currently do not expect that the rate case settlement, if reached, will have a material effect on Great Lakes’ revenues in the context of the current market environment. However, the ultimate impact on revenues will remain confidential until the stipulation and agreement is approved by the Administrative Law Judge and the FERC.

We use the equity method of accounting for our interest in Great Lakes. Great Lakes had no undistributed earnings for the three months ended March 31, 2010 and 2009.

In the first quarter of 2010, the Partnership made an equity contribution of $2.3 million to Great Lakes, representing the Partnership’s first installment of its 46.45 per cent share of a $10.0 million cash call issued by Great Lakes to expand backhaul capacity from St. Clair to Emerson. The second installment for the remaining balance is due on or before June 30, 2010.

The following tables contain summarized financial information of Great Lakes:

Summarized Consolidated Great Lakes Balance Sheet
(unaudited)	March 31,		December 31,
(millions of dollars)	2010		2009
Assets
Cash and cash equivalents		-		0.1
Other current assets		88.9		83.0
Plant, property and equipment, net		860.9		873.3
		949.8		956.4
Liabilities and Partners' Equity
Current liabilities		36.2		40.3
Deferred credits		4.0		3.8
Long-term debt, including current maturities		402.0		411.0
Partners' capital		507.6		501.3
		949.8		956.4

Summarized Consolidated Great Lakes Income Statement
(unaudited)	Three months ended March 31,
(millions of dollars)	2010			2009
Transmission revenues		72.9			82.5
Operating expenses		(14.2	)		(16.0	)
Depreciation		(14.3	)		(14.6	)
Financial charges, net and other		(7.9	)		(8.2	)
Michigan business tax		(1.5	)		(1.8	)
Net income		35.0			41.9

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 the 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 three months ended March 31, 2010 and 2009.

On February 2, 2009, Northern Border received a Notice of Violation (NOV) from the U.S. Environmental Protection Agency (EPA) alleging that Northern Border was in violation of certain regulations pursuant to the Clean Air Act (CAA) regarding a compressor station on its system. On April 1, 2010, Northern Border received indication from the EPA that it does not intend to file a complaint against Northern Border with respect to the NOV. Northern Border expects no further action from the EPA regarding this NOV.

The following tables contain summarized financial information of Northern Border:

Summarized Northern Border Balance Sheet
(unaudited)	March 31,			December 31,
(millions of dollars)	2010			2009
Assets
Cash and cash equivalents		17.1			16.9
Other current assets		23.8			30.2
Plant, property and equipment, net		1,329.2			1,343.1
Other assets		24.0			24.2
		1,394.1			1,414.4
Liabilities and Partners' Equity
Current liabilities		39.2			38.0
Deferred credits and other		10.8			8.3
Long-term debt, including current maturities		543.6			564.6
Partners' equity
Partners' capital		803.5			806.6
Accumulated other comprehensive loss		(3.0	)		(3.1	)
		1,394.1			1,414.4

Summarized Northern Border Income Statement
(unaudited)	Three months ended March 31,
(millions of dollars)	2010			2009
Transmission revenues		69.1			74.5
Operating expenses		(18.0	)		(18.5	)
Depreciation		(15.4	)		(15.3	)
Financial charges, net and other		(6.0	)		(9.1	)
Net income		29.7			31.6

NOTE 4 ASSET ACQUISITIONS

Yuma Lateral Asset Purchase

At the time of the July 1, 2009 acquisition of North Baja from TransCanada, TransCanada had begun an expansion project of the North Baja pipeline from the Mexico/Arizona border to Yuma, Arizona (Yuma Lateral). The Partnership agreed to acquire the expansion facilities and contracts for an additional sum up to $10.0 million, if TransCanada completed the project by June 30, 2010. On March 5, 2010, the Partnership acquired the expansion facilities and contracts in place at that time for a purchase price of $7.6 million. The Yuma Lateral was placed into service on March 13, 2010. The North Baja acquisition agreement provides that an additional payment of up to $2.4 million will be made to TransCanada in the event that any other shippers contract for services on the Yuma Lateral before June 30, 2010.

The Yuma Lateral asset purchase was accounted for as a transaction between entities under common control, similar to a pooling of interests, whereby the assets acquired were recorded at TransCanada’s carrying value. As the fair value paid for the Yuma Lateral assets of $7.6 million was greater than the $6.1 million recorded as Plant, property and equipment, the excess purchase price paid of $1.5 million was recorded as a reduction to Partners’ Equity.

NOTE 5 CREDIT FACILITIES AND LONG-TERM DEBT

(unaudited)	March 31,		December 31,
(millions of dollars)	2010		2009

Senior Credit Facility due 2011		491.0		484.0
7.13% Series A Senior Notes due 2010		48.2		48.2
7.99% Series B Senior Notes due 2010		4.4		4.4
6.89% Series C Senior Notes due 2012		4.7		4.7
		548.3		541.3
Less: current portion of long-term debt		53.4		53.4
		494.9		487.9

The Partnership’s Senior Credit Facility consists of a $475.0 million senior term loan and a $250.0 million senior revolving credit facility. At March 31, 2010, there was $16.0 million drawn under the senior revolving credit facility (2009 – $nil). The interest rate on the Senior Credit Facility averaged 0.9 per cent for the three months ended March 31, 2010 (2009 – 2.4 per cent). After hedging activity, the interest rate incurred on the Senior Credit Facility averaged 4.3 per cent for the three months ended March 31, 2010 (2009 – 5.1 per cent). Prior to hedging activities, the interest rate was 1.1 per cent at March 31, 2010 (2009 – 1.9 per cent). At March 31, 2010, the Partnership was in compliance with its financial covenants, in addition to the other covenants which include restrictions on entering into mergers, consolidations and sales of assets, granting liens, material amendments to the Partnership Agreement, incurring additional debt and distributions to unitholders.

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

(unaudited)
(millions of dollars)
2010	53.4
2011	491.8
2012	3.1
	548.3

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 amounts)	2010			2009
Net income(a)		33.7			35.9
North Baja's contribution prior to acquisition		-			(4.1	)
Net income allocated to partners(b)		33.7			31.8

Net income allocated to general partner:
General partner interest		(0.7	)		(0.6	)
Incentive distribution income allocation		-			(2.7	)
		(0.7	)		(3.3	)
Net income allocable to common units		33.0			28.5
Weighted average common units outstanding (millions)		46.2			34.9
Net income per common unit	$	0.71		$	0.82

(a) Recast as discussed in Note 1.

(b) Net income allocated to partners excludes North Baja’s earnings prior to the Partnership’s acquisition of North Baja on July 1, 2009, as the earnings of North Baja prior to that date were allocated to TransCanada and were not allocable to either the general partner or common units.

NOTE 7 CASH DISTRIBUTIONS

For the three months ended March 31, 2010, the Partnership distributed $0.73 per common unit (2009 – $0.705 per common unit). The distributions paid for the three months ended March 31, 2010 included incentive distributions to the general partner in the amount of $nil (2009 – $2.7 million).

NOTE 8 CHANGE IN WORKING CAPITAL

(unaudited)	Three months ended March 31,
(millions of dollars)	2010			2009(a)

Decrease/(increase) in accounts receivable and other		0.6			(0.9	)
(Decrease)/increase in accounts payable		(1.2	)		1.0
Increase in accrued interest		1.2			0.8
		0.6			0.9
Increase in investing working capital		-			(0.1	)
Decrease in operating working capital		0.6			1.0

(a) Recast as discussed in Note 1.

NOTE 9 RELATED PARTY TRANSACTIONS

The Partnership does not have any employees. The management and operating functions are provided by the general partner. The general partner does not receive a management fee in connection with its management of the Partnership. The Partnership reimburses the general partner for all costs of services provided, including the costs of employee, officer and director compensation and benefits, and all other expenses necessary or appropriate to the conduct of the business of, and allocable to, the Partnership. Such costs include (i) overhead costs (such as office space and equipment) and (ii) out-of-pocket expenses related to the provision of such services. The Partnership Agreement provides that the general partner will determine the costs that are allocable to the Partnership in any reasonable manner determined by the general partner in its sole discretion. Total costs charged to the Partnership by the general partner were $0.5 million for the three months ended March 31, 2010 (2009 – $0.4 million).

As operator, TransCanada and its affiliates provide capital and operating services to Great Lakes, Northern Border, North Baja 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, and property and liability insurance costs.

Costs charged to our pipeline systems for the three months ended March 31, 2010 and 2009 by TransCanada and its affiliates and amounts payable to TransCanada and its affiliates at March 31, 2010 and 2009 are summarized in the following tables:

(unaudited)	Three months ended March 31,
(millions of dollars)	2010		2009

Costs charged by TransCanada and its affiliates:
Great Lakes		7.6		7.3
Northern Border		6.9		6.3
North Baja(a)		0.8		0.8
Tuscarora		0.9		0.7
Impact on the Partnership's net income:
Great Lakes		3.4		3.2
Northern Border		3.2		2.9
North Baja(a)		0.7		0.6
Tuscarora		0.9		0.7


(unaudited)	March 31,		December 31,
(millions of dollars)		2010		2009

Amount payable to TransCanada and its affiliates for costs charged in the period:
Great Lakes		2.9		6.6
Northern Border		2.1		2.6
North Baja		0.4		0.4
Tuscarora		0.9		0.6

(a) Recast as discussed in Note 1.

Great Lakes earns transportation revenues from TransCanada and its affiliates under contracts with fixed prices relative to the recourse rate. The contracts have remaining terms ranging from one to eight years. Great Lakes earned $40.0 million of transportation revenues under these contracts for the three months ended March 31, 2010 (2009 – $37.3 million). This amount represents 54.9 per cent of total revenues earned by Great Lakes for the three months ended March 31, 2010 (2009 – 43.4 per cent).

Affiliated revenue of $18.6 million is included in the Partnership’s equity income from Great Lakes for the three months ended March 31, 2010 (2009 – $17.3 million). At March 31, 2010, $12.9 million was included in Great Lakes’ receivables in regards to the transportation contracts with TransCanada and its affiliates (December 31, 2009 – $12.9 million).

NOTE 10 DERIVATIVE FINANCIAL INSTRUMENTS

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

The Partnership’s long-term debt results in exposures to changing interest rates. The Partnership uses derivatives to assist in managing its exposure to interest rate risk.

The interest rate swaps and options are structured such that the cash flows match those of the Senior Credit Facility. The notional amount hedged was $375.0 million at March 31, 2010 (December 31, 2009 – $375.0 million). $300.0 million of variable-rate debt is hedged by an interest rate swap through December 12, 2011, where the weighted average fixed interest rate paid is 4.89 per cent. $75.0 million of variable-rate debt is hedged by an interest rate swap through February 28, 2011, where the fixed interest rate paid is 3.86 per cent. In addition to these fixed rates, the Partnership pays an applicable margin in accordance with the Senior Credit Facility.

Under Accounting Standards Codification (ASC) 820 – Fair Value Measurements and Disclosures, financial instruments are recorded at fair value on a recurring basis and are categorized into one of three categories based upon a fair value hierarchy. The Partnership has classified all of its derivative financial instruments as Level II where the fair value is determined by using valuation techniques that refer to observable market data or estimated market prices. At March 31, 2010, the fair value of the interest rate swaps accounted for as hedges was negative $22.2 million (December 31, 2009 – negative $23.8 million), of which $13.7 million is classified as a current liability (December 31, 2009 – $12.9 million). The fair value of the interest rate swaps was calculated using the period end interest rate; therefore, it is expected that this fair value will fluctuate over the year as interest rates change. For the three months ended March 31, 2010, the Partnership recorded interest expense of $4.2 million on the interest rate swaps and options (2009 – $3.2 million).

NOTE 11 ACCOUNTS RECEIVABLE AND OTHER

(unaudited)	March 31,		December 31,
(millions of dollars)	2010		2009
Accounts receivable		6.8		7.4
Inventory		0.6		0.6
Prepayments		0.4		0.5
Other assets		0.2		0.1
		8.0		8.6

NOTE 12 SUBSEQUENT EVENTS

On April 22, 2010, the Partnership filed an automatic universal shelf registration statement on Form S-3 (ASR) with the Securities and Exchange Commission which replaces the universal shelf registration filed in December 2008. The ASR will allow the Partnership to issue an indeterminate amount of securities of the Partnership, including both senior and subordinated debt securities and/or common units representing limited partnership interests in the Partnership. The ASR was effective immediately upon filing and will expire April 22, 2013.

Great Lakes declared and will pay its first quarter distribution of $38.8 million on May 3, 2010, of which the Partnership will receive its 46.45 per cent share or $18.0 million.

Northern Border declared and will pay its first quarter distribution of $42.9 million on May 3, 2010, of which the Partnership will receive its 50 per cent share or $21.5 million.

On April 13, 2010, Northern Border and Bison Pipeline LLP (Bison) entered into an Interconnect Agreement in which Bison will pay $1.4 million for the estimated costs of the interconnect at Northern Border Compressor Station No.6.

The Partnership has evaluated subsequent events from April 1, 2010 through April 30, 2010, which represents the date the financial statements were issued.

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 (the Partnership), along with those of our pipeline systems. We use “our pipeline systems” when referring to the Partnership’s ownership interests in Great Lakes Gas Transmission Limited Partnership (Great Lakes), Northern Border Pipeline Company (Northern Border), North Baja Pipeline, LLC (North Baja) and Tuscarora Gas Transmission Company (Tuscarora).

FORWARD-LOOKING STATEMENTS

The statements in this report that are not historical information, including statements concerning plans and objectives of management for future operations, economic performance or related assumptions, are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. 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, although no assurance can be given that these views will prove to be correct. Certain factors that could cause actual results to differ materially from those contemplated in the forward-looking statements include:

●	changes in the ability of Great Lakes and Northern Border to continue to make distributions and North Baja and Tuscarora to continue to generate positive operating cash flows 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;

o	availability and relative cost of supplies of Canadian and United States (U.S.) natural gas, including the shale gas resources such as the Horn River and Montney deposits in Western Canada, along with U.S. Rockies, Mid-Continent, and Marcellus gas developments;

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

o	the availability of additional storage capacity and current storage levels;

o	the level of liquefied natural gas imports;

o	weather conditions that impact supply and demand; and

o	the ability of shippers to meet credit worthiness requirements;

●

the impact of current and future laws, rulings and governmental regulations, particularly Federal Energy Regulatory Commission (FERC) regulations and rate proceedings, and proposed and pending legislation by Congress and proposed and pending regulations by the U.S. Environmental Protection Agency (EPA) on us and our pipeline systems;

● ●	the ability of Great Lakes to negotiate a stipulation and agreement in the Great Lakes rate proceeding; changes in relative cost structures of natural gas producing basins, such as changes in royalty programs, that may impact the development of the Western Canada Sedimentary Basin (WCSB);

●	decisions 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 and additional facilities;

●	the ability of our pipeline systems to identify and/or consummate expansion projects which are accretive growth opportunities for the Partnership;

●	the 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 Partnership’s ability to identify and/or consummate accretive growth opportunities from TransCanada Corporation or others;

●	our ability to control operating costs and the ability of TransCanada Corporation to complete its reorganization of U.S. pipeline operations, including the operations of our pipeline systems, and realize cost savings; and

●	general economic conditions in North America, which impact:

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

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, 2009. 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 publicly or revise any forward-looking statements, whether as a result of new information, future events or otherwise.

The following discussion and analysis should be read in conjunction with our Annual Report on Form 10-K for the year ended December 31, 2009 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

We are a publicly traded Delaware limited partnership formed in 1998 by TransCanada PipeLines Limited to acquire, own and participate in the management of energy infrastructure businesses 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 “the Partnership.” In this report, references to “we”, “us” or “our” refer to the Partnership. TransCanada PipeLines Limited is a wholly-owned subsidiary of TransCanada Corporation (which, together with its subsidiaries, is referred to as TransCanada).

The general partner of the Partnership is TC PipeLines GP, Inc., a wholly-owned subsidiary of TransCanada.

To date, our investments have been in interstate natural gas pipeline systems that transport natural gas to a variety of markets in the United States, Eastern Canada and Mexico. Our pipeline systems derive their operating revenue from the transportation of natural gas. They are regulated by the FERC and are operated by TransCanada. Our investments are summarized below.

	Ownership		System Specifications
	Percentage	Date Acquired	Length (Miles)	Capacity (MMcf/d)
Great Lakes	46.45	February 2007	2,115	2,400 (summer design) 2,500 (winter design)
Northern Border	30.00 20.00 50.00	May 1999 April 2006	1,249	2,400 (design)
North Baja	100.00	July 2009	80	500 (FERC licensed southbound) 600 (northbound design)
Tuscarora	49.00 49.00 2.00 100.00	September 2000 December 2006 December 2007	240	230 (design)

RECENT DEVELOPMENTS

Partnership

Shelf Filing

On April 22, 2010, the Partnership filed an automatic universal shelf registration statement with the Securities and Exchange Commission (SEC) which replaces the universal shelf registration filed in December 2008. See “Liquidity and Capital Resources of TC PipeLines, LP” within Item 2. for further information with respect to this filing.

Yuma Lateral Expansion Acquisition

At the time of our July 1, 2009 acquisition of North Baja from TransCanada, TransCanada had begun a project to expand the North Baja pipeline from the Mexico/Arizona border to Yuma, Arizona (Yuma Lateral). We agreed to acquire the expansion facilities and contracts for an additional sum of up to $10.0 million, if TransCanada completed the project by June 30, 2010. On March 5, 2010, we acquired the expansion facilities and contracts in place at that time for a purchase price of $7.6 million. The Yuma Lateral was placed into service on March 13, 2010. The North Baja acquisition agreement provides that an additional payment of up to $2.4 million will be made to TransCanada in the event any other shippers contract for services on the Yuma Lateral before June 30, 2010.

Our Pipeline Systems

Great Lakes Rate Proceeding

On April 16, 2010, Great Lakes filed a Motion to Suspend Procedural Schedule (the Motion) indicating that an agreement in principle had been reached among Great Lakes, active participants and the FERC trial staff in its Natural Gas Act (NGA) Section 5 Rate Proceeding initiated by the FERC in November 2009. The Motion was granted by the Chief Administrative Law Judge on the same day. The parties anticipate filing a binding, written stipulation and agreement embodying the settlement’s terms on or about May 17, 2010, for subsequent approval by the Administrative Law Judge and the FERC.

See “Government Regulation” within this section for more information with respect to this proceeding and the Motion.

FACTORS THAT IMPACT OUR BUSINESS

Our general partner interests in Great Lakes and Northern Border, and our ownership of North Baja and Tuscarora represent our only material assets at March 31, 2010. As a result, we are dependent upon our pipeline systems for our results of operations and all of our available cash. 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. These factors determine our ability to maintain a prudent level of available cash to make distributions to our unitholders, fund future growth, and broaden our asset base in a disciplined and focused manner. Cash flows from our investments are dependent upon the ability of Great Lakes and Northern Border to make distributions to us and of North Baja and Tuscarora to generate positive operating cash flows.

We believe our strong financial position, including available unused capacity on our credit facility, gives us the capacity to pursue opportunities to grow in a sustained and disciplined manner for the long-term benefit of our unitholders.

FACTORS THAT IMPACT THE BUSINESS OF OUR PIPELINE SYSTEMS

Our pipeline systems provide natural gas transportation services to their customers. The majority of these services are provided through firm service transportation contracts with a reservation charge to reserve pipeline capacity, regardless of use, for the term of the contract. The revenues associated with capacity under firm service transportation contracts are not subject to fluctuations caused by changing supply and demand conditions, competition, and customers for the term of the contract.

The following table provides information with respect to the proportion of capacity subscribed under firm contracts and their weighted average remaining contract life as at April 1, 2010 for our pipeline systems.

		As at April 1, 2010
	Our Ownership Interest	Firm Contracted Capacity %(a)	Weighted Average Remaining Contract Life (in Years)(c)
Great Lakes	46.45%	87%	1.9

Northern Border	50%	75%	2.4

North Baja	100%	(b) 79% southbound 64% northbound	16.5

Tuscarora	100%	97%	10.4

(a)Firm contracted capacity is calculated based upon contracted capacity compared to design capacity for Great Lakes and Northern Border, North Baja northbound transportation and Tuscarora, and compared to FERC licensed capacity for North Baja southbound transportation.

(b)Due to North Baja's bi-directional nature, it can contract for both southbound and northbound capacity separately and concurrently.

(c)Weighted average remaining contract life is weighted based upon maximum daily quantity in the contracts.

Key factors that impact the business of our pipeline systems are the level of capacity under firm contracts and related term, supply of and demand for natural gas in the markets in which our pipeline systems operate, competition, and customers and the mix of services they require. Government regulation of natural gas pipelines is also a major factor impacting the business of our pipeline systems. These factors are discussed in more detail below.

When there is capacity that is not contracted under firm service transportation contracts, there is exposure to fluctuations in earnings caused by changes in certain of the key factors key factors discussed above. Our North Baja and Tuscarora pipeline systems have little risk of fluctuations in revenues as a result of their strong contracted capacity position under long-term contracts.

Government regulation of natural gas pipelines includes, among others, regulation of the terms of and rates for interstate natural gas transportation services, environmental issues, and pipeline safety and integrity.

Natural Gas Supply and Demand

The ongoing impacts of decreased demand for natural gas in North America related to the economic environment, increased production from U.S. shale gas developments and high levels of natural gas in storage continued to hold commodity prices for natural gas at low levels over the first quarter as compared to the first quarter of 2009. We expect these pressures on natural gas commodity prices to continue through the remainder of 2010.

The primary source of natural gas transported by our pipeline systems, excluding North Baja, is the WCSB. “Gas exiting the WCSB” is the term we use to represent the net of the supply of and demand for natural gas in the WCSB region. It is dependent upon WCSB natural gas production levels, demand for natural gas in Western Canada, and natural gas storage capacity and demand for natural gas storage injection in Western Canada. Gas exiting the WCSB was lower in the first quarter of 2010 compared to the same period in 2009, due mainly to decreased production. Lower WCSB production is expected to continue through the remainder of 2010 as a result of a decline in drilling and exploration activity for natural gas in the basin over the last two years, mainly due to lower natural gas prices.

Factors which may support increased WCSB production in the future include strengthening gas prices and reduced royalty costs, which would support exploration and development of new fields in Western Canada by WCSB natural gas producers. Drilling in the WCSB is expected to recover in the future when gas prices stabilize and exploration and development costs become more economical through factors such as more efficient and productive drilling. Over the long term, we expect WCSB natural gas producers will direct significant resources toward development of unconventional resources such as shale gas and coalbed methane. Additional natural gas supply from the Alberta Hub is expected to be available in the future when new pipeline projects associated with the Montney and Horn River shale gas regions in Western Canada are constructed, or if the longer term potential associated with the proposed development of the Mackenzie Delta in Northern Canada and the North Slope in Alaska is realized.

Levels of Western Canadian natural gas in storage and U.S. working gas storage levels at the end of the first quarter of 2010 continued to be at the record highs experienced throughout 2009. The winter season is usually a period of withdrawals from storage. However, there were lower storage withdrawals in Western Canada in the first quarter of 2010 relative to the same period in 2009, which contributed to reduced volumes of gas exiting the WCSB. Weather related demand in the first quarter of 2010 did not result in sufficient storage withdrawals in the U.S. market storage areas to offset the high levels of natural gas in storage at the beginning of the winter heating season. The high demand period for storage injection usually begins in the spring and extends through most of the summer. However, high levels of natural gas already in storage in the market regions are expected to reduce demand for transportation services related to storage injection during the remainder of 2010. High overall storage levels have a dampening effect on natural gas prices, which in turn contributes to reduced production.

Continued strengthening of the North American economy and decreased natural gas inventories resulting from reduced production levels and seasonal weather related demand are factors that would positively affect natural gas prices in the near term.

North America’s demand for natural gas is expected to rise as the economy returns to growth mode. The relative environmental merits of natural gas versus other carbon based forms of energy are also expected to increase the demand for natural gas in the future.

U.S. natural gas production slightly increased over the last two quarters, mainly due to the enhanced productivity of new wells being drilled to develop unconventional resources in the lower 48 states. Production from natural gas basins other than the WCSB represents supply competition for WCSB natural gas. Overall, U.S. natural gas production is expected to decrease somewhat for the 2010 year as a whole compared to recent years. Production from individual natural gas basins in North America will depend on factors that include natural gas drilling activity, well production rates, and relative operating costs. Reduced natural gas drilling activity in North America as a whole is expected to contribute to lower production overall.

Demand for Transportation Services and Contracting

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 availability of natural gas supply at the pipeline system’s receipt points, the ability and willingness of natural gas shippers to utilize that system over alternative pipelines, relative transportation rates, and the volume of natural gas delivered to markets supplied by that system 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. Contracted capacity and system throughput are measures of demand for natural gas transportation services.

The reduced level of gas exiting the WCSB has resulted in excess pipeline capacity serving the WCSB. We anticipate there will be excess natural gas pipeline capacity serving the WCSB for the foreseeable future and therefore competition for gas exiting the WCSB will continue. In this environment, there is little incentive for shippers to make long-term commitments for capacity and the trend towards shorter term contracts is expected to continue for Great Lakes and Northern Border. As a result, there may be increased volatility and seasonality with respect to throughput and revenues for these pipelines.

Prevailing market conditions and dynamic competitive factors in North America, particularly reduced gas exiting the WCSB, increased supply from other supply basins to our pipeline systems’ market areas, and the economic environment affecting the demand for natural gas, have reduced the value of transportation on our pipeline systems and their ability to market available capacity. We expect the downward pressure on transportation values for our pipeline systems to continue through 2010.

Great Lakes

Great Lakes’ average contracted capacity was 94 per cent of its average design capacity for the first quarter of 2010, compared to 100 per cent in the first quarter of 2009. As at April 1, 2010, 87 per cent of its average design capacity was contracted on a firm basis with a weighted average remaining contract life of 1.9 years. In the absence of new contracting, beginning November 1, 2010, Great Lakes will have additional long haul capacity available of 440 thousand dekatherms per day (MDth/d) as a result of contract expiries, which will result in the average design capacity contracted on a firm basis decreasing to 67 per cent. Great Lakes’ revenue may decline from November 1, 2010 onward if it is required to discount rates to recontract or is unable to recontract its expiring capacity.

Scheduled throughput on Great Lakes’ pipeline system for the first quarter of 2010 decreased to 2,133 MMcf/d compared to 2,549 MMcf/d for the same period in 2009 primarily due to underutilization of long-term firm contracts related to reduced gas exiting WCSB, along with warm weather in the market area which reduced transportation related to storage withdrawals and reduced demand for short-term transportation services due to substantial reductions in transportation values. Decreases in throughput related to underutilization of long-term firm contracts have a minimal impact on revenue earned from these contracts. When the level of long-term firm contracts decreases beginning in November 2010, Great Lakes may experience increased volatility in revenues as a result of changes in throughput.

Reduced demand for short-term services resulted in greater levels of discounting in the first quarter of 2010. Great Lakes is expected to continue discounting short-term transportation capacity as needed to optimize revenue. Lower sales of short-term contracts and increased discounting reduce revenues earned from sales of short-term transportation services.

Northern Border

Northern Border’s average contracted capacity was 63 per cent of its design capacity for the first quarter of 2010, compared to 82 per cent for the first quarter of 2009. Competition for supply from the WCSB and increased deliveries of natural gas to Midwest markets from other supply sources continue to impact Northern Border’s ability to contract available capacity. These supply and demand factors are expected to maintain competitive pressures in the Midwest markets on WCSB sourced natural gas, as discussed further under “Competition.” Northern Border was negatively impacted in the first quarter of 2010 by the incremental supply in the Chicago market from new infrastructure that went into service in 2009, as low transportation values on the eastern leg of the Northern Border system into Chicago resulted in shippers with capacity on that portion of the system electing to deliver to an upstream delivery location which negatively impacts Northern Border’s ability to contract upstream capacity. Scheduled throughput on Northern Border’s pipeline system in the first quarter of 2010 was 2,209 MMcf/d compared to 2,181 MMcf/d in the first quarter of 2009. The slight incremental scheduled throughput in the first quarter of 2010 relative to the same period in 2009 was primarily due to increased short haul transportation services which have lower transportation rates than long haul transportation services. As well, Northern Border continued to discount transportation capacity in the first quarter of 2010. Northern Border expects to continue discounting available transportation capacity as needed to optimize revenue. As at April 1, 2010, Northern Border had approximately 75 per cent of its design capacity contracted, decreasing to approximately 50 per cent by the end of the second quarter. The weighted average remaining life of Northern Border’s contracts at April 1, 2010 was 2.4 years.

TransCanada’s Bison Pipeline will extend from the Powder River Basin producing region in Wyoming to an interconnection with the Northern Border system in Morton County, North Dakota. TransCanada expects the project to be placed into service in the fourth quarter of 2010. When completed, this project will increase Northern Border’s supply diversity as the interconnection will provide access to a new competitively-priced natural gas supply source for Northern Border’s shippers. Over the long term, this should enhance utilization of Northern Border’s pipeline system. Shippers on the Bison Pipeline have executed 10 year contracts for approximately 407 MMcf/d of capacity on the Northern Border system from Port of Morgan, Montana to Ventura, Iowa, commencing on the in-service date of the Bison Pipeline. When the Bison Pipeline is completed, this would increase Northern Border’s average contracted capacity and weighted average contract life. We expect that some or all of the volumes from the Bison Pipeline may displace existing shipments from the WCSB. As such, any impact to Northern Border’s revenues will be dependent upon the overall demand for transportation to the markets served by Northern Border.

Competition

There is currently increased competition among natural gas pipelines for gas exiting the WCSB due to excess pipeline capacity. Factors impacting the competition for gas exiting the WCSB include levels of firm transportation contracts on each pipeline, demand for natural gas in the regions served by each pipeline, and relative transportation values on each pipeline which are impacted by their transportation rates. Currently, factors impacting the competition for gas exiting the WCSB include high natural gas storage levels in Eastern Canada, Michigan and California, and as well as changes in basis differential for each of the pipelines accessing the WCSB resulting from new pipeline infrastructure recently placed into service.

Our pipeline systems compete primarily with other interstate and intrastate pipelines in the transportation of natural gas. Competition among natural gas pipelines is based primarily on transportation charges and proximity to natural gas supply areas and markets. New natural gas supplies from unconventional sources, such as shale, and new pipeline projects in the U.S. moving additional natural gas supply from the Rockies basin and from the Mid-Continent Shales have increased the supply competition in the markets served by our pipeline systems. This additional supply delivered to Midwest and Eastern markets is displacing traditional supply in the markets served by our pipeline systems. Supply competition from other natural gas sources has impacted demand for transportation on our pipeline systems. As well, growth in supplies available from other natural gas producing regions has impacted prices for natural gas delivered to some of the markets our pipeline systems serve relative to other market regions. Increased competition within the North American natural gas industry has resulted in a trend towards shorter term contracting as customers assess and choose the markets which optimize their netback prices.

Supply competition in the Midwest markets from the Rockies Express Pipeline, along with deliveries from other supply sources via interconnecting pipelines continued to negatively impact demand for Northern Border’s transportation services in the first quarter of 2010, which resulted in increased discounting of sales of available capacity. The supply competition in the Midwest markets is expected to continue to impact demand for Northern Border’s transportation services through the remainder of 2010.

Government Regulation

Federal Energy Regulatory Commission – Natural gas transportation is regulated by the FERC and other federal and state regulatory agencies, including the Department of Transportation. FERC regulatory policies govern the rates that pipelines are permitted to charge customers for interstate transportation of natural gas. The operation and maintenance of our pipeline systems are also regulated by the federal and state regulatory agencies.

The FERC-approved rate designs used by our pipeline systems are based upon firm and interruptible services. Customers with firm service transportation agreements pay a fee known as a reservation charge to reserve pipeline capacity, regardless of use, for the term of their contracts. Firm service transportation customers may also pay a variable fee that is based on the distance and volume of natural gas they transport. Customers with interruptible service transportation agreements may utilize available capacity on a pipeline system after firm service transportation requests are satisfied. Interruptible service customers are assessed a variable fee based on distance and volume of natural gas they transport. The majority of our pipeline systems’ revenue is generated from firm service transportation agreements.

Great Lakes Rate Proceeding – On November 19, 2009, the FERC issued an order in FERC Docket No. RP10-149 (November 2009 Order) instituting an investigation pursuant to Section 5 of the NGA (GL Rate Proceeding). The FERC alleged, based on a review of certain historical information, that Great Lakes’ revenues might substantially exceed Great Lakes’ actual cost of service and therefore may be unjust and unreasonable. On February 4, 2010, Great Lakes filed a cost and revenue study (GL Cost and Revenue Study) in response to the November 2009 Order. The GL Cost and Revenue Study reflects the increased risk of de-contracting on the Great Lakes system which may result in decreases to overall long-term, daily and short-term firm transportation revenues, and interruptible transportation revenues, as compared to prior periods.

We currently do not expect that the rate case settlement, if reached, will have a material effect on Great Lakes’ revenues in the context of the current market environment. See the Great Lakes discussion under “Demand for Transportation Services and Contracting” in this section. However, the ultimate impact on revenues will remain confidential until the stipulation and agreement is approved by the Administrative Law Judge and the FERC.

Air Emissions – The Clean Air Act (CAA) and comparable state laws regulate emissions of air pollutants from various industrial sources, including compressor stations, and also impose various monitoring and reporting requirements.

By letter dated December 28, 2009, the EPA required Great Lakes to provide information regarding its natural gas compressor stations in the states of Minnesota, Wisconsin and Michigan as part of the EPA’s review of Great Lakes’ compliance with the CAA. Great Lakes is in the process of preparing its response and providing the information, all of which is due by May 29, 2010. Any issues that may arise as a result of this information request are not determinable at this time.

On February 2, 2009, Northern Border received a Notice of Violation (NOV) from the EPA alleging that Northern Border was in violation of certain regulations pursuant to the CAA regarding a compressor station on its system. On April 1, 2010, Northern Border received indication from the EPA that it does not intend to file a complaint against Northern Border with respect to the NOV. Northern Border expects no further action from the EPA regarding this NOV.

HOW WE EVALUATE OUR OPERATIONS

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

RESULTS OF OPERATIONS OF TC PIPELINES, LP

Critical Accounting Policies and Estimates

The preparation of financial statements in accordance with GAAP requires us to make estimates and assumptions with respect to values or conditions which cannot be known with certainty, that affect the reported amount of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the financial statements. Such estimates and assumptions also affect the reported amounts of revenue and expenses during the reporting period. Although we believe these estimates and assumptions are reasonable, actual results could differ. There were no significant changes to the Partnership’s critical accounting policies and estimates during the three months ended March 31, 2010.

Information about our critical accounting estimates is included under Item 7. “Management Discussion and Analysis of Financial Condition and Results of Operations,” in our Annual Report on Form 10-K for the year ended December 31, 2009.

NET INCOME

The Partnership uses the non-GAAP financial measure “Net income prior to recast” as a financial performance measure. Net income prior to recast excludes North Baja’s net income for periods prior to July 1, 2009, the date on which the Partnership acquired North Baja. The acquisition of North Baja from TransCanada was accounted for as a transaction under common control, similar to a pooling of interests, whereby the Partnership’s historical financial information was recast to include the net income of North Baja for all periods presented, which included income that did not accrue to the Partnership’s general partner interest or to the Partnership’s common units, but rather accrued to North Baja’s former parent.

Net income prior to recast is presented to enhance investors’ understanding of the way management analyzes the Partnership’s financial performance. Net income prior to recast is provided as a supplement to GAAP financial results and is not meant to be considered in isolation or as a substitute for financial results prepared in accordance with GAAP.

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

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, 2010															For the three months ended March 31, 2009
(unaudited) (millions of dollars)	PipeLP			Other Pipes(a)			Corp(b)			GLGT			NBPC(c)			PipeLP			Other Pipes(a)			Corp(b)			GLGT			NBPC(c)
Transmission revenues		17.4			17.4			-			72.9			69.1			8.4			8.4			-		82.5			74.5
Operating expenses		(3.4	)		(3.4	)		-			(14.2	)		(18.0	)		(1.4	)		(1.4	)		-		(16.0		)	(18.5		)
General and administrative		(1.3	)		-			(1.3	)		-		-				(1.2	)		-			(1.2	)	-			-
		12.7			14.0			(1.3	)		58.7		51.1				5.8			7.0			(1.2	)	66.5			56.0
Depreciation		(3.7	)		(3.7	)		-			(14.3	)	(15.4		)		(1.8	)		(1.8	)		-		(14.6		)	(15.3		)
Financial charges, net and other		(6.2	)		(1.0	)		(5.2	)		(7.9	)	(6.0		)		(7.3	)		(1.1	)		(6.2	)	(8.2		)	(9.1		)
Michigan business tax		-			-			-			(1.5	)	-				-			-			-		(1.8		)	-
											35.0			29.7											41.9			31.6
Equity income		30.9			-			-			16.3			14.6			35.1			-			-			19.5			15.6
Net income prior to recast		33.7			9.3			(6.5	)		16.3			14.6			31.8			4.1			(7.4	)		19.5			15.6
North Baja's contribution prior to acquisition(d)		-			-			-			-			-			4.1			4.1			-			-			-
Net income(d)		33.7			9.3			(6.5	)		16.3			14.6			35.9			8.2			(7.4	)		19.5			15.6

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

(b) “Corp” includes the costs of the Partnership, but excludes the costs of its subsidiaries.

(c) The Partnership owns a 50 per cent general partner interest in Northern Border. Equity income from Northern Border includes the 12-year 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.

(d) The acquisition of North Baja from TransCanada was accounted for as a transaction between entities under common control, similar to a pooling of interests, whereby the assets and liabilities of North Baja were recorded at TransCanada's carrying value and the Partnership’s historical financial information was recast to include North Baja for all periods presented on a consolidated basis.

First Quarter 2010 Compared with First Quarter 2009

Net income decreased $2.2 million to $33.7 million in the first quarter of 2010 compared to $35.9 million in the first quarter of 2009. Excluding the contribution from North Baja prior to the acquisition, net income prior to recast increased $1.9 million to $33.7 million in the first quarter of 2010 compared to $31.8 million in first quarter of 2009. This increase was primarily due to net income of $5.4 million from North Baja which was partially offset by lower equity income from Great Lakes and Northern Border.

Equity income from Great Lakes was $16.3 million in the first quarter of 2010, a decrease of $3.2 million compared to $19.5 million in the first quarter of 2009. The decrease in equity income was primarily due to decreased transmission revenues. Great Lakes’ transmission revenues for the three months ended March 31, 2010 decreased $9.6 million compared to the same period last year, primarily due to decreased demand for short-term transportation services. Operating expenses decreased $1.8 million primarily due to lower pipeline maintenance and overhaul costs and lower property taxes.

Equity income from Northern Border was $14.6 million in the first quarter 2010, a decrease of $1.0 million compared to the same period in 2009. The decrease in equity income was primarily due to decreased transmission revenues partially offset by reduced financial charges. Northern Border’s transmission revenues decreased $5.4 million due to increased discounting of transportation rates for volumes transported. Financial charges, net and other decreased $3.1 million in first quarter of 2010 compared to the same period in 2009 primarily due to lower effective interest rates and average debt outstanding.

Net income from Other Pipes, which includes results from North Baja and Tuscarora, was $9.3 million in the first quarter of 2010, an increase of $1.1 million compared to the first quarter of 2009. Excluding the contribution of $4.1 million from North Baja prior to the acquisition, net income from Other Pipes increased $5.2 million in the first quarter 2010. This increase was primarily due to North Baja, which contributed $5.4 million to net income in the first quarter of 2010.

Costs at the Partnership level were $6.5 million in the first quarter of 2010, a decrease of $0.9 million compared to the same period in 2009. This decrease was primarily due to lower financial charges, net and other as a result of lower effective interest rates.

PARTNERSHIP CASH FLOWS

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

Partnership cash flows include cash distributions from the Partnership’s equity investments, Great Lakes and Northern Border, plus operating cash flows from the Partnership’s wholly-owned subsidiaries, North Baja (post-acquisition) and Tuscarora, net of Partnership costs and distributions declared to the general partner.

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

Non-GAAP Measures

Reconciliations of Net Income to Net Income Prior to Recast and Partnership Cash Flows

(unaudited)	Three months ended March 31,
(millions of dollars except per common unit amounts)	2010			2009
Net income(a)		33.7			35.9
North Baja's contribution prior to acquisition(a)		-			(4.1	)
Net income prior to recast		33.7			31.8
Add:
Cash distributions from Great Lakes(b)		15.7			12.5
Cash distributions from Northern Border(b)		16.4			24.2
Cash flows provided by North Baja's operating activities		4.7			-
Cash flows provided by Tuscarora's operating activities		7.2			7.2
		44.0			43.9
Less:
Equity income from investment in Great Lakes		(16.3	)		(19.5	)
Equity income from investment in Northern Border		(14.6	)		(15.6	)
North Baja's net income		(5.4	)		-
Tuscarora's net income		(3.9	)		(4.1	)
		(40.2	)		(39.2	)
Partnership cash flows before general partner distributions		37.5			36.5
General partner distributions(c)		(0.7	)		(3.2	)
Partnership cash flows		36.8			33.3
Cash distributions declared		(34.4	)		(27.7	)
Cash distributions declared per common unit(d)	$	0.730		$	0.705
Cash distributions paid		(34.4	)		(27.7	)
Cash distributions paid per common unit(d)	$	0.730		$	0.705

(a) The acquisition of North Baja from TransCanada was accounted for as a transaction between entities under common control, similar to a pooling of interests, whereby the assets and liabilities of North Baja were recorded at TransCanada’s carrying value and the Partnership’s historical financial information was recast to include North Baja for all periods presented on a consolidated basis.

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

(c) General partner distributions represent the cash distributions declared to the general partner with respect to its two per cent interest plus an amount equal to incentive distributions.

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

First Quarter 2010 Compared with First Quarter 2009

Partnership cash flows increased $3.5 million to $36.8 million in the first quarter of 2010 compared to $33.3 million in same period of 2009. This increase was primarily due to $4.7 million of cash flows provided by North Baja’s operating activities in the first quarter of 2010, an increase of $3.2 million in cash distributions from Great Lakes, a decrease of $2.7 million in general partner distributions resulting from the restructuring of incentive distribution rights on July 1, 2009, and reduced Partnership financial charges of $0.9 million. These positive factors were partially offset by decreased cash distributions from Northern Border of $7.8 million.

The Partnership paid distributions of $34.4 million in the first quarter of 2010, an increase of $6.7 million compared to 2009, due to an increase in the number of common units outstanding, in addition to increases in quarterly per common unit distribution amounts.

Other Cash Flows

On March 5, 2010, we acquired the Yuma Lateral expansion facilities and contracts in place at that time for a purchase price of $7.6 million. The Yuma Lateral was placed into service on March 13, 2010.

LIQUIDITY AND CAPITAL RESOURCES OF TC PIPELINES, LP

Overview

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

Summary of the Partnership’s Contractual Obligations

Yuma Lateral – At the time of our July 1, 2009 acquisition of North Baja from TransCanada, TransCanada had begun an expansion project of the North Baja pipeline from the Mexico/Arizona border to Yuma, Arizona. We agreed to acquire the expansion facilities and contracts for an additional sum up to $10.0 million, if TransCanada completed the project by June 30, 2010. On March 5, 2010, we acquired the expansion facilities and contracts in place at that time for a purchase price of $7.6 million. The Yuma Lateral was placed into service on March 13, 2010. The North Baja acquisition agreement provides that an additional payment of up to $2.4 million will be made to TransCanada in the event that any other shippers contract for services on the Yuma Lateral before June 30, 2010.

The Partnership’s Debt and Credit Facility

The following table summarizes the Partnership’s debt and credit facility outstanding as of March 31, 2010:

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

Senior Credit Facility due 2011		491.0		-		491.0
7.13% Series A Senior Notes due 2010		48.2		48.2		-
7.99% Series B Senior Notes due 2010		4.4		4.4		-
6.89% Series C Senior Notes due 2012		4.7		0.8		3.9
		548.3		53.4		494.9

The Partnership has a $475.0 million senior term loan and a $250.0 million senior revolving credit facility (together, Senior Credit Facility). There was $491.0 million outstanding under the Senior Credit Facility at March 31, 2010 (December 31, 2009 – $484.0 million). The interest rate on the Senior Credit Facility averaged 0.9 per cent for the three months ended March 31, 2010 (2009 – 2.4 per cent). After hedging activity, the interest rate incurred on the Senior Credit Facility averaged 4.3 per cent for the three months ended March 31, 2010 (2009 – 5.1 per cent). Prior to hedging activities, the interest rate was 1.1 per cent at March 31, 2010 (2009 – 1.9 per cent). At March 31, 2010, the Partnership was in compliance with all of its financial covenants, in addition to the other covenants which include restrictions on entering into mergers, consolidations and sales of assets, granting liens, material amendments to the Partnership Agreement, incurring additional debt and distributions to unitholders.

Series A, B and C Senior Notes are secured by Tuscarora’s transportation contracts, supporting agreements and substantially all of Tuscarora’s property. The note purchase agreements contain certain provisions that include, among other items, limitations on additional indebtedness and distributions to partners. On December 21, 2010, the Series A and B Senior Notes will mature. As market conditions dictate, the Partnership intends to refinance this debt with either fixed-rate or variable-rate debt.

Interest Rate Swaps and Options

The Partnership’s long-term debt results in exposures to changing interest rates. The Partnership uses derivatives to assist in managing its exposure to interest rate risk.

The interest rate swaps and options are structured such that the cash flows match those of the Senior Credit Facility. The notional amount hedged was $375.0 million at March 31, 2010 (December 31, 2009 – $375.0 million). Under Accounting Standards Codification (ASC) 820 – Fair Value Measurements and Disclosures, financial instruments are recorded at fair value on a recurring basis and are categorized into one of three categories based upon a fair value hierarchy. The Partnership has classified all of its derivative financial instruments as Level II where the fair value is determined by using valuation techniques that refer to observable market data or estimated market prices. At March 31, 2010, the fair value of the interest rate swaps accounted for as hedges was negative $22.2 million (December 31, 2009 – negative $23.8 million), of which $13.7 million is classified as a current liability (December 31, 2009 – $12.9 million). The fair value of the interest rate swaps was calculated using the period end interest rate; therefore, it is expected that this fair value will fluctuate over the year as interest rates change. In the three months ended March 31, 2010, the Partnership recorded interest expense of $4.2 million on the interest rate swaps and options (2009 – $3.2 million).

Capital Requirements

On April 22, 2010, the Partnership filed an automatic universal shelf registration statement on Form S-3 (ASR) with the SEC which replaces the universal shelf registration filed in December 2008. The ASR will allow the Partnership to issue an indeterminate amount of securities of the Partnership, including both senior and subordinated debt securities and/or common units representing limited partnership interests in the Partnership. The ASR was effective immediately upon filing and will expire April 22, 2013.

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

2010 First Quarter Cash Distribution

On April 20, 2010, the Partnership announced that the Board of Directors of the general partner declared the Partnership’s first quarter 2010 cash distribution in the amount of $0.73 per common unit. The first quarter cash distribution, totaling $34.4 million, will be paid on May 14, 2010 to unitholders of record as of April 30, 2010 in the following manner: $33.7 million to common unitholders (including $4.2 million to the general partner as holder of 5,797,106 common units and $8.2 million to TransCanada as holder of 11,287,725 common units) and $0.7 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 sources of liquidity are cash generated from operating activities, bank credit facilities and equity contributions from their partners. Our pipeline systems fund operating expenses, debt service and cash distributions to partners primarily with operating cash flow.

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

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 that allow them to request credit support as circumstances dictate.

Summary of Great Lakes’ Contractual Obligations

The following table summarizes Great Lakes’ debt outstanding as of March 31, 2010:

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

8.74% series Senior Notes due 2010 to 2011		20.0		10.0		10.0
6.73% series Senior Notes due 2011 to 2018		72.0		9.0		63.0
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
		402.0		19.0		383.0

Great Lakes is required to comply with certain financial, operational and legal covenants. Under the most restricted covenants in the Senior Note Agreements, approximately $216.0 million of Great Lakes’ partners’ capital was restricted as to distributions as of March 31, 2010 (December 31, 2009 – $221.0 million). Current maturities will be paid out of operating cash flows. As at March 31, 2010, Great Lakes was in compliance with all of its financial covenants.

Summary of Northern Border’s Contractual Obligations

The following table summarizes Northern Border’s debt outstanding as of March 31, 2010:

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

$250 million credit agreement due 2012		194.0		-		194.0
6.24% Senior Notes due 2016		100.0		-		100.0
7.50% Senior Notes due 2021		250.0		-		250.0
		544.0		-		544.0

As of March 31, 2010, Northern Border had outstanding borrowings of $194.0 million under its $250 million revolving credit agreement and was in compliance with the covenants of the agreement. The weighted average interest rate related to the borrowings on the credit agreement was 0.50 percent at March 31, 2010.

CONTINGENCIES

Legal

On April 16, 2010, Great Lakes filed a Motion to Suspend Procedural Schedule (the Motion) in its GL Rate Proceeding indicating that an agreement in principle has been reached among Great Lakes, active participants and the FERC trial staff. The Motion requests a temporary suspension of the GL Rate Proceeding schedule for all parties to permit the drafting of a stipulation and agreement, and the Motion was granted by the Chief Administrative Law Judge on the same day. The parties are negotiating the settlement terms and anticipate filing a binding, written stipulation and agreement embodying the settlement’s terms on or about May 17, 2010, for subsequent approval by the Administrative Law Judge and the FERC. Until the filing of the written stipulation and agreement, the terms of the settlement will remain confidential. In the absence of a settlement, a hearing in the GL Rate Proceeding is scheduled for early August 2010 and an initial decision by the Administrative Law Judge is expected in November 2010. Any of the following elements of Great Lakes’ rate structure may be affected in settlement or litigation, including but not limited to: firm transportation, interruptible transportation and/or incremental rates; revenues; depreciation; and interruptible transportation revenue sharing.

Please read Part II, Item 1. “Legal Proceedings” for additional information with respect to this proceeding and the Motion.

Environmental

RELATED PARTY TRANSACTIONS

Please read Note 9 within Item 1. “Financial Statements” for additional information regarding related party transactions.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

OVERVIEW

We are exposed to market risk primarily from interest rate fluctuations. Additionally, the Partnership and our pipeline systems are also exposed to other risks such as credit risk, liquidity risk, foreign exchange fluctuations and changes to natural gas prices related to the calculation of a Minnesota fuel tax, which we have determined to be less material to us and our pipeline systems. Our exposure to market risk discussed below includes forward-looking statements and is not necessarily indicative of actual results, which may not represent the maximum possible gains and losses that may occur, since actual gains and losses will differ from those estimated, based on actual market conditions.

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

In accordance with ASC 815 – Derivatives and Hedging, 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 the fair value of financial instruments are recognized in earnings unless the instrument qualifies as a hedge under ASC 815 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 within established policies and procedures. Derivative contracts used to manage market risk generally consist of the following:

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

●

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

Interest rate risk is created by fluctuations in the fair values or cash flows of financial instruments due to changes in the market interest rates. Our interest rate exposure results from our Senior Credit Facility, which is subject to variability in 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.

Our interest rate swaps and options are structured such that the cash flows match those of the Senior Credit Facility. The notional amount hedged was $375.0 million at March 31, 2010 (December 31, 2009 – $375.0 million). $300.0 million of variable-rate debt is hedged by an interest rate swap for the period from March 12, 2007 through December 12, 2011, where the weighted average fixed interest rate paid is 4.89 per cent. $75.0 million of variable-rate debt is hedged by an interest rate swap for the period from February 29, 2008 through February 28, 2011, where the fixed interest rate paid is 3.86 per cent. In addition to these fixed rates, the Partnership pays an applicable margin in accordance with the Senior Credit Facility.

At March 31, 2010, the fair value of the interest rate swaps accounted for as hedges was negative $22.2 million (December 31, 2009 – negative $23.8 million), of which $13.7 million is classified as a current liability (December 31, 2009 – $12.9 million). The fair value of the interest rate swaps was 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, 2010, we had $491.0 million (December 31, 2009 – $484.0 million) outstanding on our Senior Credit Facility. Utilizing the conditions of the interest rate swaps, if LIBOR interest rates hypothetically increased by one per cent (100 basis points) compared to the rates in effect at March 31, 2010, our annual interest expense would have increased and our net income would have decreased by $1.2 million; and if LIBOR interest rates hypothetically decreased to zero compared to the rates in effect at March 31, 2010, our annual interest expense would have decreased and our net income would have increased by $0.4 million. These amounts have been determined by considering the impact of the hypothetical interest rates on unhedged debt outstanding as of March 31, 2010.

Northern Border utilizes both fixed-rate and variable-rate debt and is exposed to market risk due to the floating interest rates on its revolving credit facility. Northern Border regularly assesses the impact of interest rate fluctuations on future cash flows and evaluates hedging opportunities to mitigate its interest rate risk. As of March 31, 2010, 64.0 per cent of Northern Border’s outstanding debt was at fixed rates (December 31, 2009 – 62.0 per cent).

If interest rates hypothetically increased by one per cent (100 basis points) compared with rates in effect at March 31, 2010, Northern Border’s annual interest expense would increase and its net income would decrease by approximately $2.1 million; and if interest rates hypothetically decreased to zero per cent compared with rates in effect at March 31, 2010, Northern Border’s annual interest expense would decrease and its net income would increase by approximately $0.5 million.

Great Lakes and Tuscarora utilize fixed-rate debt; therefore, they are not exposed to market risk due to floating interest rates. Interest rate risk does not apply to North Baja, as it currently does not have any debt.

OTHER RISKS

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

Counterparty credit risk represents the financial loss that the Partnership and our pipeline systems would experience if a counterparty to a financial instrument failed to meet its obligations in accordance with the terms and conditions of its contracts with the Partnership or its pipeline systems. Our maximum counterparty credit exposure with respect to financial instruments at the balance sheet date consists primarily of the carrying amount, which approximates fair value, of non-derivative financial assets, such as accounts receivable, as well as the fair value of derivative financial assets. At March 31, 2010, the Partnership’s maximum counterparty credit exposure consisted of accounts receivable of $8.0 million (December 31, 2009 – $5.4 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. Due to the deterioration of global financial markets in 2008 and 2009, we continue to closely monitor the creditworthiness of our counterparties, including financial institutions. Overall, we do not believe the Partnership 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 become due. Our approach to managing liquidity risk is to ensure that we always have sufficient cash and credit facilities to meet our obligations when due, under both normal and stressed conditions, without incurring unacceptable losses or damage to our reputation. At March 31, 2010, the Partnership has a committed revolving bank line of $250.0 million maturing in December 2011. As of March 31, 2010, the outstanding balance on this facility was $16.0 million. In addition, at March 31, 2010, Northern Border has a committed revolving bank line of $250.0 million maturing in April 2012. As of March 31, 2010, $194.0 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 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 $0.5 million.

The Partnership does not have any material foreign exchange risks.

Item 4. Controls and Procedures

EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES

As required by Rule 13a-15(e) under the Exchange Act, the management of our General Partner, including the Principal Executive Officer and Principal Financial Officer, evaluated as of the end of the period covered by this report the effectiveness of our disclosure controls and procedures. There are inherent limitations to the effectiveness of any system of disclosure controls and procedures, including the possibility of human error and the circumvention or overriding of the controls and procedures. Accordingly, even effective disclosure controls and procedures may only provide reasonable assurance of achieving their control objectives. Based upon and as of the date of the evaluation, the management of our General Partner, including the Principal Executive Officer and Principal Financial Officer, concluded that our disclosure controls and procedures, as of the end of the period covered by this report, were effective to provide reasonable assurance that information required to be disclosed by us in reports that we file or submit under the Exchange Act is (a) recorded, processed, summarized and reported within the time periods specified by the rules and forms and (b) accumulated and communicated to management of our General Partner, including the Principal Executive Officer and Principal Financial Officer, to allow timely decisions regarding required disclosure.

Changes in Internal Control over Financial Reporting

During the quarter ended March 31, 2010, 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

Item 1. Legal Proceedings

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

Item 1A. Risk Factors

The following updated risk factors should be read in conjunction with the risk factors disclosed in Part I, Item 1A. “Risk Factors,” in our Annual Report on Form 10-K for the year ended December 31, 2009.

Risks Inherent in Our Business

Our pipeline systems are subject to regulation by agencies, including the FERC, which could have an adverse impact on our ability to establish transportation rates that would allow recovery of the full cost of operating our pipeline systems, including a reasonable return, and our ability to make distributions.

Under the Natural Gas Act (NGA), interstate transportation rates must be just, reasonable and not unduly discriminatory. Our pipeline systems are subject to extensive regulation by the FERC, the U.S. Department of Transportation, and other federal, state and local regulatory agencies. Regulatory actions taken by these agencies have the potential to adversely affect our pipeline systems’ profitability. Federal regulation extends to such matters as:

●	rates and charges;

●	operating terms and conditions of service including creditworthiness requirements;

●	types of services our pipeline systems may offer to their customers;

●	construction of new facilities;

●	extension or abandonment of service and facilities;

●	accounts and records;

●	depreciation and amortization policies;

●	income tax allowance policies;

●	acquisition and disposition of facilities;

●	initiation and discontinuation of services;

●	standards of conduct business relations with certain affiliates; and

●	integrity and safety of our pipeline systems and related operations.

Given the extent of regulation by the FERC and potential changes to regulations, we cannot predict:

●	the federal regulations under which our pipeline systems will operate in the future;

●	the effect that regulation will have on financial position, results of operations and cash flows of our pipeline systems and ourselves; or

●	whether our cash flow will be adequate to make distributions to unitholders.

Tuscarora is currently operating under a rate settlement which precludes a party to the rate settlement from bringing any rate actions prior to May 31, 2010. Northern Border is required to file a new rate proceeding on or before December 31, 2012.

Action by the FERC on currently pending regulatory matters as well as matters arising in the future could adversely affect our pipeline systems' abilities to establish or charge rates that would cover future increase in their costs, such as additional costs related to environmental matters including any climate change regulation, or even to continue to collect rates that cover current costs, including a reasonable return. We cannot assure unitholders that our pipeline systems will be able to recover all of their costs through existing or future rates.

Should our pipeline systems fail to comply with all applicable FERC administered statutes, rules, regulations and orders, our pipeline systems could be subject to substantial penalties and fines. Under the Energy Policy Act of 2005, the FERC has civil penalty authority under the NGA to impose penalties for current violations of up to $1 million per day for each violation.

Finally, we cannot give any assurance regarding the future regulations under which our pipeline systems will operate their natural gas transportation businesses or the effect such regulations could ultimately have on our financial condition, results of operations and cash flows.

Item 6. Exhibits

No. Description

10.1	Yuma Transfer Agreement dated March 5, 2010 by and between Gas Transmission Northwest Corporation and North Baja Pipeline, LLC.

31.1	Certification of Principal Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2	Certification of Principal Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.1	Certification of Principal Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32.2	Certification of Principal Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized on this 30th day of April 2010.

TC PIPELINES, LP

(A Delaware Limited Partnership)

by its general partner, TC PipeLines GP, Inc.

By: /s/ Mark A.P. Zimmerman

Mark A.P. Zimmerman

President

TC PipeLines GP, Inc. (Principal Executive Officer)

By: /s/ Robert C. Jacobucci

Robert C. Jacobucci

Controller

TC PipeLines GP, Inc. (Principal Financial Officer)

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