exhibit131may12009.htm

EX-13.1 2 exhibit131may12009.htm EXHIBIT 13.1 MANAGEMENT'S DISCUSSION AND ANALYSIS exhibit131may12009.htm

Exhibit 13.1

TRANSCANADA CORPORATION – FIRST QUARTER 2009

Quarterly Report to Shareholders

Management's Discussion and Analysis

Management's Discussion and Analysis (MD&A) dated April 30, 2009 should be read in conjunction with the accompanying unaudited Consolidated Financial Statements of TransCanada Corporation (TransCanada or the Company) for the three months ended March 31, 2009. It should also be read in conjunction with the audited Consolidated Financial Statements and notes thereto, and the MD&A contained in TransCanada's 2008 Annual Report for the year ended December 31, 2008. Additional information relating to TransCanada, including the Company's Annual Information Form and other continuous disclosure documents, is available on SEDAR at www.sedar.com under TransCanada Corporation. Unless otherwise indicated, "TransCanada" or "the Company" includes TransCanada Corporation and its subsidiaries. Amounts are stated in Canadian dollars unless otherwise indicated. Capitalized and abbreviated terms that are used but not otherwise defined herein are identified in the Glossary of Terms contained in TransCanada’s 2008 Annual Report.

Forward-Looking Information

This MD&A may contain certain information that is forward looking and is subject to important risks and uncertainties. The words "anticipate", "expect", "believe", "may", "should", "estimate", "project", "outlook", "forecast" or other similar words are used to identify such forward-looking information. Forward-looking statements in this document are intended to provide TransCanada shareholders and potential investors with information regarding TransCanada and its subsidiaries, including management’s assessment of TransCanada’s and its subsidiaries’ future financial and operational plans and outlook. Forward-looking statements in this document may include, among others, statements regarding the anticipated business prospects and financial performance of TransCanada and its subsidiaries, expectations or projections about the future, strategies and goals for growth and expansion, expected and future cash flows, costs, schedules, operating and financial results and expected impact of future commitments and contingent liabilities. All forward-looking statements reflect TransCanada’s beliefs and assumptions based on information available at the time the statements were made. Actual results or events may differ from those predicted in these forward-looking statements. Factors that could cause actual results or events to differ materially from current expectations include, among others, the ability of TransCanada to successfully implement its strategic initiatives and whether such strategic initiatives will yield the expected benefits, the operating performance of the Company’s pipeline and energy assets, the availability and price of energy commodities, capacity payments, regulatory processes and decisions, changes in environmental and other laws and regulations, competitive factors in the pipeline and energy sectors, construction and completion of capital projects, labour, equipment and material costs, access to capital markets, interest and currency exchange rates, technological developments and the current economic conditions in North America. By its nature, forward-looking information is subject to various risks and uncertainties, which could cause TransCanada's actual results and experience to differ materially from the anticipated results or expectations expressed. Additional information on these and other factors is available in the reports filed by TransCanada with Canadian securities regulators and with the U.S. Securities and Exchange Commission (SEC). Readers are cautioned to not place undue reliance on this forward-looking information, which is given as of the date it is expressed in this quarterly report or otherwise, and to not use future-oriented information or financial outlooks for anything other than their intended purpose. TransCanada undertakes no obligation to update publicly or revise any forward-looking information, whether as a result of new information, future events or otherwise, except as required by law.

TRANSCANADA [2

FIRST QUARTER REPORT 2009

Non-GAAP Measures

TransCanada uses the measures "comparable earnings", "comparable earnings per share", "earnings before interest, taxes, depreciation and amortization" (EBITDA), "comparable EBITDA", "earnings before interest and taxes" (EBIT), "comparable EBIT" and "funds generated from operations" in this MD&A. These measures do not have any standardized meaning prescribed by Canadian generally accepted accounting principles (GAAP). They are, therefore, considered to be non-GAAP measures and are unlikely to be comparable to similar measures presented by other entities. Management of TransCanada uses these non-GAAP measures to improve its ability to compare financial results among reporting periods and to enhance its understanding of operating performance, liquidity and ability to generate funds to finance operations. These non-GAAP measures are also provided to readers as additional information on TransCanada’s operating performance, liquidity and ability to generate funds to finance operations.

Management uses the measures of comparable earnings, EBITDA and EBIT to better evaluate trends in the Company’s underlying operations. Comparable earnings, comparable EBITDA and comparable EBIT comprise net income, EBITDA and EBIT, respectively, adjusted for specific items that are significant, but are not reflective of the Company’s underlying operations in the period. Specific items are subjective, however, management uses its judgement and informed decision-making when identifying items to be excluded in calculating comparable earnings, comparable EBITDA and comparable EBIT, some of which may recur. Specific items may include but are not limited to certain income tax refunds and adjustments, gains or losses on sales of assets, legal and bankruptcy settlements, and certain fair value adjustments. The table in the Consolidated Results of Operations section of this MD&A presents a reconciliation of comparable earnings, comparable EBITDA, comparable EBIT and EBIT to Net Income. Comparable earnings per share is calculated by dividing comparable earnings by the weighted average number of shares outstanding for the period.

EBITDA is an approximate measure of the Company’s operating cash flow. EBITDA comprises earnings before deducting interest and other financial charges, income taxes, depreciation and amortization, and non-controlling interests. EBIT is a measure of the Company’s earnings from ongoing operations. EBIT comprises earnings before deducting interest and other financial charges, income taxes and non-controlling interests.

Funds generated from operations comprises net cash provided by operations before changes in operating working capital. A reconciliation of funds generated from operations to net cash provided by operations is presented in the "Liquidity and Capital Resources" section of this MD&A.

Financial Information Presentation

Effective January 1, 2009, TransCanada revised the information presented in the tables of this MD&A to better reflect the operating and financing structure of the Company. The Pipelines and Energy results summaries are presented geographically by separating the Canadian and U.S. portions of each segment. The Company believes this new format more clearly describes the financial performance of its business units. The new format presents EBITDA and EBIT as the Company believes these measures provide increased transparency and more useful information with respect to the performance of the Company’s individual assets. To conform with this new presentation:

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FIRST QUARTER REPORT 2009

•	certain income and expense amounts pertaining to operations that were previously classified on the Consolidated Statement of Income as Other Expenses/(Income) are now included in Operating and Other Expenses/(Income);

•	depreciation expense has been redefined as Depreciation and Amortization expense, and includes amortization for power purchase arrangements (PPA) of $14 million in first quarter 2009 (2008 - $14 million), which was previously included in Commodity Purchases Resold;

•	certain support services costs previously allocated to Pipelines and Energy of $31 million in first quarter 2009 (2008 - $26 million) will now be included in Corporate; and

•	amounts related to interest and other financial charges, income taxes, interest and other income, and non-controlling interests will no longer be reported on a segmented basis.

Segmented information has been retroactively reclassified to reflect these changes. These changes had no impact on reported consolidated Net Income.

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FIRST QUARTER REPORT 2009

Consolidated Results of Operations

Reconciliation of Comparable Earnings, Comparable EBITDA, Comparable EBIT and EBIT to Net Income

For the three months ended March 31
(unaudited) (millions of dollars except per	Pipelines						Energy						Corporate						Total
share amounts)	2009			2008			2009			2008			2009			2008			2009			2008

Comparable EBITDA(1)		871			802			290			287			(30	)		(22	)		1,131			1,067
Depreciation and amortization		(260	)		(254	)		(86	)		(56	)		-			-			(346	)		(310	)
Comparable EBIT(1)		611			548			204			231			(30	)		(22	)		785			757
Specific items:
Fair value adjustment of natural gas storage inventory and forward contracts		-			-			(13	)		(17	)		-			-			(13	)		(17	)
Calpine bankruptcy settlements		-			279			-			-			-			-			-			279
GTN lawsuit settlement		-			17			-			-			-			-			-			17
Writedown of Broadwater LNG project costs		-			-			-			(41	)		-			-			-			(41	)
EBIT(1)		611			844			191			173			(30	)		(22	)		772			995
Interest expense																				(295	)		(218	)
Financial charges of joint ventures																				(14	)		(16	)
Interest income and other																				22			11
Income taxes																				(116	)		(252	)
Non-controlling interests																				(35	)		(71	)
Net Income																				334			449

Specific items (net of tax):
Fair value adjustment of natural gas storage inventory and forward contracts																				9			12
Calpine bankruptcy settlements																				-			(152	)
GTN lawsuit settlement																				-			(10	)
Writedown of Broadwater LNG project costs																				-			27
Comparable Earnings(1)																				343			326

Net Income Per Share(2)
Basic and Diluted																			$	0.54		$	0.83

(1)	Refer to the Non-GAAP Measures section in this MD&A for further discussion of comparable EBITDA, comparable EBIT, EBIT, comparable earnings and comparable earnings per share.

		For the three months ended March 31
(2)		2009		2008

	Net Income Per Share	$	0.54	$	0.83
	Specific items (net of tax):
	Fair value adjustment of natural gas storage inventory and forward contracts		0.01		0.02
	Calpine bankruptcy settlements		-		(0.28	)
	GTN lawsuit settlement		-		(0.02	)
	Writedown of Broadwater LNG project costs		-		0.05
	Comparable Earnings Per Share(2)	$	0.55	$	0.60

TransCanada’s net income in first quarter 2009 was $334 million or $0.54 per share compared to $449 million or $0.83 per share in first quarter 2008. Net income decreased $115 million primarily due to:

•

decreased contribution from Pipelines due to $152 million of after-tax gains ($279 million pre-tax) on shares received by GTN and Portland for Calpine bankruptcy settlements and proceeds from a GTN lawsuit settlement of $10 million after tax ($17 million pre-tax) received in first quarter 2008. The impact of these items on the Pipelines segment was partially offset by the positive impact of a stronger U.S. dollar on Pipelines’ U.S. operations.

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FIRST QUARTER REPORT 2009

•

increased contribution from Energy due to the positive impact of a $27 million after-tax ($41 million pre-tax) writedown of costs capitalized for the Broadwater liquefied natural gas (LNG) project in first quarter 2008 and increased contribution from Bruce Power and Eastern Power. These positive impacts in Energy were offset by decreased contributions from Natural Gas Storage and U.S. Power.

•	decreased contribution from Corporate due to higher support services costs; and

•	increased interest expense due to debt issuances throughout 2008 and first quarter 2009 offset by decreased income tax expense due to a reduced pre-tax income as noted above.

Earnings per share in first quarter 2009 was further reduced due to an increased number of shares outstanding following the Company’s share issuances in second and fourth quarter 2008.

Comparable earnings in first quarter 2009 were $343 million or $0.55 per share compared to $326 million or $0.60 per share for the same period in 2008. Comparable earnings in first quarter 2009 and 2008 excluded $9 million after tax ($13 million pre-tax) and $12 million after tax ($17 million pre-tax), respectively, of net unrealized losses resulting from changes in the fair value of proprietary natural gas storage inventory and natural gas forward purchase and sale contracts. In addition, comparable earnings in first quarter 2008 excluded the $152 million of Calpine bankruptcy settlements, the $10 million GTN lawsuit settlement and the $27 million writedown of Broadwater LNG project costs.

Comparable EBIT was $785 million in first quarter 2009 compared to $757 million in first quarter 2008. The increase in comparable EBIT of $28 million was primarily due to an increase in Pipelines, partially offset by decreases in Energy and Corporate. Results from each of the segments for the three months ended March 31, 2009 are discussed further in the Pipelines, Energy and Corporate sections of this MD&A.

Pipelines

The Pipelines business generated comparable EBIT of $611 million in first quarter 2009 compared to $548 million in first quarter 2008. Comparable EBIT for first quarter 2008 excluded $279 million of gains received by GTN and Portland for the Calpine bankruptcy settlements and $17 million of proceeds received by GTN from a lawsuit settlement with a software supplier.

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FIRST QUARTER REPORT 2009

Pipelines Results

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

Canadian Pipelines
Canadian Mainline	284		290
Alberta System	168		179
Foothills	34		35
Other (TQM, Ventures LP)	19		13
Canadian Pipelines Comparable EBITDA(1)	505		517

U.S. Pipelines
ANR	133		102
GTN	61		52
Great Lakes	44		36
PipeLines LP(2)	24		19
Iroquois	23		15
Portland(2)	14		12
International (Tamazunchale, TransGas, INNERGY/Gas Pacifico)	13		10
General, administrative and support costs(3)	(3	)	(5	)
Non-controlling interests(2)	65		54
U.S. Pipelines Comparable EBITDA(1)	374		295

Business Development Comparable EBITDA(1)	(8	)	(10	)

Pipelines Comparable EBITDA(1)	871		802
Depreciation and amortization	(260	)	(254	)
Pipelines Comparable EBIT(1)	611		548
Specific items:
Calpine bankruptcy settlements(4)	-		279
GTN lawsuit settlement	-		17
Pipelines EBIT(1)	611		844

(1)	Refer to the Non-GAAP Measures section in this MD&A for further discussion of comparable EBITDA, comparable EBIT and EBIT.

(2)	PipeLines LP and Portland results reflect TransCanada’s 32.1 per cent and 61.7 per cent ownership interests, respectively. The non-controlling interests reflect amounts not owned by TransCanada.

(3)	Represents costs associated with the Company’s Canadian and foreign non-wholly owned pipelines.

(4)	GTN and Portland received shares of Calpine with an initial value of $154 million and $103 million, respectively, from the bankruptcy settlements with Calpine. These shares were subsequently sold for an additional gain of $22 million.

Net Income for Wholly Owned Canadian Pipelines

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

Canadian Mainline	66	68
Alberta System	39	32
Foothills	6	7

Canadian Pipelines

Canadian Mainline’s first quarter 2009 net income of $66 million decreased $2 million compared to $68 million in first quarter 2008 primarily as a result of a lower average investment base and a lower rate of return on common equity (ROE) as determined by the National Energy Board (NEB), of 8.57 per cent in 2009 compared to 8.71 per cent in 2008. First quarter 2009 EBITDA of $284 million decreased $6 million compared to $290 million in first quarter 2008 due to lower revenues as a result of recovery of a lower overall return on rate base in 2009. Decreases in net income and EBITDA were partially offset by lower operations, maintenance and administrative (OM&A) costs.

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FIRST QUARTER REPORT 2009

The Alberta System's net income was $39 million in first quarter 2009 compared to $32 million in the same quarter of 2008 and reflects the impact of a 2008-2009 settlement approved by the Alberta Utilities Commission (AUC) in December 2008. The Alberta System’s EBITDA was $168 million in first quarter 2009 compared to $179 million in the same quarter of 2008. The decrease was primarily due to lower revenues as a result of lower depreciation approved in the settlement, partially offset by the impact of increased earnings due to the settlement.

TransCanada’s proportionate share of EBITDA from Other Canadian Pipelines was $19 million for the three months ended March 31, 2009 compared to $13 million for the same period in 2008. The increase was primarily due to a March 2009 NEB decision to increase TQM’s allowed rate of return on capital for the years 2007 and 2008.

U.S. Pipelines

ANR’s EBITDA in first quarter 2009 was $133 million compared to $102 million in first quarter 2008. The increase of $31 million was primarily due to a stronger U.S. dollar. In addition, ANR’s higher revenues from new growth projects were partially offset by higher OM&A costs.

GTN’s EBITDA for first quarter 2009 of $61 million increased $9 million compared to $52 million from the same period in 2008 primarily due to a stronger U.S. dollar and lower OM&A expenses in first quarter 2009.

EBITDA for the remainder of the U.S. pipelines was $180 million for the three months ended March 31, 2009 compared to $141 million for the same period in 2008. The increase was primarily due to a stronger U.S. dollar in 2009.

Operating Statistics

Three months ended March 31	Canadian Mainline(1)				Alberta System(2)				Foothills				ANR(3)				GTN System(3)
(unaudited)	2009		2008		2009		2008		2009		2008		2009		2008		2009		2008

Average investment base ($millions)		6,590		7,176		4,586		4,224		725		765		n/a		n/a		n/a		n/a
Delivery volumes (Bcf)
Total		1,004		928		1,018		1,065		323		388		491		472		195		213
Average per day		11.2		10.2		11.3		11.7		3.6		4.3		5.5		5.2		2.2		2.3

(1)	Canadian Mainline’s physical receipts originating at the Alberta border and in Saskatchewan for the three months ended March 31, 2009 were 472 billion cubic feet (Bcf) (2008 – 493 Bcf); average per day was 5.2 Bcf (2008 – 5.4 Bcf).

(2)	Field receipt volumes for the Alberta System for the three months ended March 31, 2009 were 909 Bcf (2008 – 947 Bcf); average per day was 10.1 Bcf (2008 – 10.4 Bcf).

(3)	ANR’s and the GTN System’s results are not impacted by average investment base as these systems operate under fixed rate models approved by the FERC.

Capitalized Project Costs

At March 31, 2009, Other Assets included $122 million and $49 million of capitalized costs related to the Keystone pipeline system expansion to the U.S. Gulf Coast and the Bison pipeline project, respectively.

As at March 31, 2009, TransCanada had advanced $141 million to the Aboriginal Pipeline Group (APG) with respect to the Mackenzie Gas Pipeline Project (MGP). TransCanada and the other co-venture companies involved in the MGP continue to pursue approval of the proposed project, focusing on obtaining regulatory approval and the Canadian government’s support of an acceptable fiscal framework. Discussions with the Canadian government are continuing, but project timing remains uncertain. In the event the co-venture group is unable to reach an agreement with the government on an acceptable fiscal framework, the parties will need to determine the appropriate next steps for the project. For TransCanada, this may result in a reassessment of the carrying amount of the APG advances.

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FIRST QUARTER REPORT 2009

Energy

Energy’s comparable EBIT was $204 million in first quarter 2009 compared to $231 million in first quarter 2008. Comparable EBIT excluded net unrealized losses of $13 million and $17 million in first quarter 2009 and 2008, respectively, resulting from changes in the fair value of proprietary natural gas storage inventory and natural gas forward purchase and sale contracts. In addition, comparable EBIT in first quarter 2008 excluded the $41 million writedown of costs previously capitalized for the Broadwater LNG project.

Energy Results

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

Canadian Power
Western Power			93			99
Eastern Power			52			35
Bruce Power			99			54
General, administrative and support costs			(8	)		(7	)
Canadian Power Comparable EBITDA(1)			236			181

U.S. Power(2)
Northeast Power			42			64
General, administrative and support costs			(12	)		(9	)
U.S. Power Comparable EBITDA(1)			30			55

Natural Gas Storage
Alberta Storage			39			69
General, administrative and support costs			(3	)		(2	)
Natural Gas Storage Comparable EBITDA(1)			36			67

Business Development Comparable EBITDA(1)			(12	)		(16	)

Energy Comparable EBITDA(1)			290			287
Depreciation and amortization			(86	)		(56	)
Energy Comparable EBIT(1)			204			231
Specific items:
Fair value adjustments of natural gas storage inventory and forward contracts			(13	)		(17	)
Writedown of Broadwater LNG project costs			-			(41	)
Energy EBIT(1)			191			173

(1)	Refer to the Non-GAAP Measures section in this MD&A for further discussion of comparable EBITDA, comparable EBIT and EBIT.

(2)	Includes Ravenswood effective August 2008.

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FIRST QUARTER REPORT 2009

Western and Eastern Canadian Power Comparable EBITDA(1)(2)

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

Revenues
Western power			215			295
Eastern power			69			52
Other(3)			49			17
			333			364
Commodity Purchases Resold
Western power			(98	)		(156	)
Eastern power			-			(2	)
Other(4)			(46	)		(13	)
			(144	)		(171	)

Plant operating costs and other			(44	)		(59	)
General, administrative and support costs			(8	)		(7	)
Comparable EBITDA(2)			137			127

(1)	Includes Carleton effective November 2008.

(2)	Refer to the Non-GAAP Measures section in this MD&A for further discussion of comparable EBITDA.

(3)	Other revenue includes sales of natural gas and thermal carbon black.

(4)	Other commodity purchases resold includes the cost of natural gas sold.

Western and Eastern Canadian Power Operating Statistics(1)

	Three months ended March 31
(unaudited)	2009	2008

Sales Volumes (GWh)
Supply
Generation
Western Power	605	629
Eastern Power	355	286
Purchased
Sundance A & B and Sheerness PPAs	2,440	3,359
Other purchases	185	315
	3,585	4,589
Sales
Contracted
Western Power	2,053	3,074
Eastern Power	391	332
Spot
Western Power	1,141	1,183
	3,585	4,589
Plant Availablity
Western Power(2)	91%	92%
Eastern Power	97%	98%

(1)	Includes Carleton effective November 2008.

(2)	Excludes facilities that provide power to TransCanada under PPAs.

Western Power’s EBITDA of $93 million in first quarter 2009 decreased $6 million compared to $99 million in first quarter 2008. The decrease was primarily due to lower contracted and uncontracted volumes of power sold in Alberta resulting from lower plant availability under the PPAs, partially offset by lower PPA costs per megawatt hour (MWh).

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FIRST QUARTER REPORT 2009

Eastern Power’s EBITDA of $52 million increased $17 million compared to $35 million in first quarter 2008 due to increased revenue from Bécancour and the Carleton wind farm at Cartier Wind, which went into service in November 2008.

In first quarter 2009, Other Revenue and Other Commodity Purchases Resold of $49 million and $46 million, respectively, increased compared to first quarter 2008 as a result of an increase in the quantity of natural gas being resold in Eastern Power.

Plant Operating Costs and Other of $44 million, which includes fuel gas consumed in generation, decreased in first quarter 2009 from the same period in 2008 primarily due to lower natural gas prices in Western Power.

Western Power manages the sale of its supply volumes on a portfolio basis. A portion of its supply is held for sale in the spot market for operational reasons and the amount of supply volumes eventually sold into the spot market is dependent upon the ability to transact in forward sales markets at acceptable contract terms. This approach to portfolio management assists in minimizing costs in situations where Western Power would otherwise have to purchase electricity in the open market to fulfill its contractual sales obligations. Approximately 64 per cent of Western Power sales volumes were sold under contract in first quarter 2009, compared to 72 per cent in first quarter 2008. To reduce its exposure to spot market prices on uncontracted volumes, as at March 31, 2009, Western Power had entered into fixed-price power sales contracts to sell approximately 6,500 gigawatt hours (GWh) for the remainder of 2009 and 5,500 GWh for 2010.

Eastern Power is focused on selling power under long-term contracts. As a result, in first quarter 2009 and 2008, 100 per cent of Eastern Power sales volumes were sold under contract and will continue to be fully sold under contract for 2009 and 2010.

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FIRST QUARTER REPORT 2009

Bruce Power Results

(TransCanada’s proportionate share) (unaudited)	Three months ended March 31
(millions of dollars unless otherwise indicated)	2009		2008

Revenues(1)(2)	221		185

Operating Expenses(2)	(122	)	(131	)

Comparable EBITDA(3)	99		54

Bruce A Comparable EBITDA(3)	41		35
Bruce B Comparable EBITDA(3)	58		19
Comparable EBITDA(3)	99		54

Bruce Power – Other Information
Plant availability
Bruce A	97	%	93	%
Bruce B	96	%	72	%
Combined Bruce Power	96	%	79	%
Planned outage days
Bruce A	-		7
Bruce B	-		50
Unplanned outage days
Bruce A	5		1
Bruce B	8		33
Sales volumes (GWh)
Bruce A	1,495		1,496
Bruce B	2,139		1,624
	3,634		3,120
Results per MWh
Bruce A power revenues	$63		$60
Bruce B power revenues	$52		$56
Combined Bruce Power revenues	$57		$57
Combined Bruce Power operating expenses(4)	$30		$41
Percentage of Bruce B output sold to spot market	25	%	28	%

(1)	Revenue includes Bruce A’s fuel cost recoveries of $10 million for the three months ended March 31, 2009 (2008 - $6 million). Also includes gains of $2 million as a result of changes in fair value of held-for-trading derivatives for the three months ended March 31, 2009 (2008 - $3 million loss).

(2)	Includes adjustments to eliminate the effects of inter-partnership transactions between Bruce A and Bruce B.

(3)	Refer to the Non-GAAP Measures section in this MD&A for further discussion of comparable EBITDA.

(4)	Net of fuel cost recoveries and excluding depreciation.

TransCanada’s proportionate share of Bruce Power’s comparable EBITDA increased $45 million in first quarter 2009 compared to first quarter 2008 primarily due to increased revenues resulting from higher output and lower operating costs, both as a result of fewer outage days.

TransCanada’s proportionate share of Bruce A’s comparable EBITDA increased $6 million in first quarter 2009 compared to first quarter 2008 as a result of higher contract prices.

TransCanada’s proportionate share of Bruce B’s comparable EBITDA increased $39 million in first quarter 2009 compared to first quarter 2008 due to increased output and lower operating costs, partially offset by lower realized prices. The increase in output was due to a decrease in the number of outage days in first quarter 2009 compared to first quarter 2008.

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FIRST QUARTER REPORT 2009

TransCanada’s share of Bruce Power’s generation in first quarter 2009 increased to 3,634 GWh compared to 3,120 GWh in first quarter 2008. The Bruce Power units ran at a combined average availability of 96 per cent in first quarter 2009, compared to 79 per cent in first quarter 2008.

In mid-April 2009, an approximate six week outage of Bruce B Unit 8 commenced. An approximate six week maintenance outage of Bruce A Unit 4 and an approximate one month outage of Bruce A Unit 3 have been rescheduled from March 2009 to September 2009.

Pursuant to the terms of a contract with the Ontario Power Authority (OPA), all of the output from Bruce A in first quarter 2009 was sold at a fixed price of $63.00 per MWh (before recovery of fuel costs from the OPA) compared to $59.69 per MWh in first quarter 2008. Sales from the Bruce B Units 5 to 8 were subject to a floor price of $47.66 per MWh in first quarter 2009 and $46.82 per MWh in first quarter 2008. Both the Bruce A and Bruce B reference prices are adjusted annually for inflation on April 1. Effective April 1, 2009, the fixed price for output from Bruce A increased by $1.45 per MWh, subject to inflation adjustments from October 31, 2005, resulting in a Bruce A price of $64.45 per MWh and the Bruce B floor price increased to $48.76 per MWh. Payments received pursuant to the Bruce B floor price mechanism are subject to a recapture payment dependent on annual spot prices over the term of the contract. Bruce B EBITDA has not included any amounts received under this floor price mechanism to date. To reduce its exposure to spot market prices, as at March 31, 2009, Bruce B had entered into fixed price sales contracts to sell forward approximately 8,350 GWh for the remainder of 2009 and 7,560 GWh for 2010.

As at March 31, 2009, Bruce A had incurred $2.7 billion in costs to date for the refurbishment and restart of Units 1 and 2, and approximately $0.2 billion for the refurbishment of Units 3 and 4.

U.S. Power Comparable EBITDA(1)(2)

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

Revenues
Power			340			226
Other(3)(4)			172			82
			512			308
Commodity Purchases Resold
Power			(155	)		(134	)
Other(5)			(148	)		(66	)
			(303	)		(200	)
Plant operating costs and other(4)			(167	)		(44	)
General, administrative and support costs			(12	)		(9	)
Comparable EBITDA(2)			30			55

(1)	Includes Ravenswood effective August 2008.

(2)	Refer to the Non-GAAP Measures section in this MD&A for further discussion of comparable EBITDA.

(3)	Other revenue includes sales of natural gas.

(4)	Includes activity at Ravenswood related to a third-party owned steam production facility operated by TransCanada on behalf of the plant owner.

(5)	Other commodity purchases resold includes the cost of natural gas sold.

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FIRST QUARTER REPORT 2009

U.S. Power Sales Operating Statistics(1)

	Three months ended March 31
(unaudited)	2009	2008

Sales Volumes (GWh)
Supply
Generation	1,168	800
Purchased	1,259	1,478
	2,427	2,278
Sales
Contracted	1,786	2,180
Spot	641	98
	2,427	2,278

Plant Availability	58%	93%

(1)	Includes Ravenswood effective August 2008.

U.S. Power’s EBITDA of $30 million in first quarter 2009 decreased $25 million compared to $55 million in first quarter 2008 primarily due to decreased water flows at TC Hydro and an expected loss at Ravenswood. These decreases were partially offset by higher realized prices on sales to commercial and industrial customers in New England and the positive impact of a stronger U.S. dollar in first quarter 2009. The expected loss at Ravenswood is the result of seasonally lower capacity payments relative to total expected capacity payments for the year, as well as the impact of a forced outage affecting Unit 30. The unit is currently undergoing repair and is expected back in service in second quarter 2009.

U.S. Power’s power revenues of $340 million in first quarter 2009 increased $114 million compared to first quarter 2008 due to the incremental impact from Ravenswood and the positive impact of the stronger U.S. dollar.

Power Commodity Purchases Resold of $155 million in first quarter 2009 increased $21 million compared to the same period in 2008 primarily due to the impact of the stronger U.S. dollar in first quarter 2009 and a higher overall cost per GWh on purchased power volumes. These increases were partially offset by lower purchased power volumes as a result of decreased demand by commercial and industrial customers.

Other Revenue and Other Commodity Purchases Resold of $172 million and $148 million, respectively, increased in first quarter 2009 compared to first quarter 2008 as a result of an increase in the quantity of natural gas being resold and the impact of a stronger U.S. dollar. In addition, other revenues increased as a result of incremental revenues earned related to a steam generating facility at Ravenswood.

Plant Operating Costs and Other of $167 million, which includes fuel gas consumed in generation, increased $123 million in first quarter 2009 compared to the same period in 2008 due to the incremental costs from Ravenswood.

In first quarter 2009, 26 per cent of power sales volumes were sold into the spot market, compared to four per cent in first quarter 2008, as there were no power sales contracts in place for Ravenswood extending beyond 2008 at the time of acquisition. U.S. Power is focused on selling the majority of its power under contract to wholesale, commercial and industrial customers, while managing a portfolio of power supplies sourced from its own generation and wholesale power purchases. To reduce its exposure to spot market prices on uncontracted volumes, as at March 31, 2009, U.S. Power had entered into fixed-price power sales contracts to sell approximately 5,000 GWh for the remainder of 2009 and 4,100 GWh for 2010, although certain contracted volumes are dependent on customer usage levels. Actual amounts contracted in future periods will depend on market liquidity and other factors.

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FIRST QUARTER REPORT 2009

Natural Gas Storage

Natural Gas Storage’s comparable EBITDA of $36 million in first quarter 2009 decreased $31 million compared to $67 million in first quarter 2008. The decrease was due to lower withdrawal activity and reduced sales of proprietary natural gas at the Edson facility compared to the same period in 2008.

Comparable EBITDA excluded net unrealized losses of $13 million and $17 million in first quarter 2009 and 2008, respectively, resulting from changes in the fair value of proprietary natural gas inventory in storage and natural gas forward purchase and sale contracts. TransCanada manages its natural gas storage earnings by simultaneously entering into a forward purchase of natural gas for injection into storage and an offsetting forward sale of natural gas for withdrawal at a later period, thereby locking in future positive margins and effectively eliminating exposure to price movements of natural gas. Fair value adjustments recorded each period on proprietary natural gas held in storage inventory and these forward contracts are not representative of the amounts that will be realized on settlement.

Depreciation and Amortization

Depreciation and Amortization in first quarter 2009 increased $30 million compared to first quarter 2008 primarily due to the acquisition of Ravenswood in August 2008.

Corporate

Corporate’s EBIT for the three months ended March 31, 2009 was a loss of $30 million compared to a loss of $22 million for the same period in 2008. The increase in Corporate’s EBIT loss was primarily due to higher support services costs in 2009, reflecting a growing asset base and inflation, as well as a third party reimbursement of certain costs in first quarter 2008.

Other Income Statement Items

Interest Expense

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

Interest on long-term debt(1)			335			248
Other interest and amortization			14			(3	)
Capitalized interest			(54	)		(27	)
			295			218

(1)	Includes interest for Junior Subordinated Notes.

TransCanada’s Interest Expense of $295 million in first quarter 2009 increased $77 million compared to $218 million in first quarter 2008. The increase was primarily due to new debt issues of US$1.5 billion and $500 million in August 2008 and US$2 billion and $700 million in January and February 2009, respectively. In addition, U.S. dollar-denominated interest expense increased due to the impact of a stronger U.S. dollar. These increases were partially offset by increased capitalization of interest to finance the Company’s larger capital spending program in 2009.

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FIRST QUARTER REPORT 2009

On a consolidated basis, the positive impact of a stronger U.S. dollar on U.S. Pipelines and Energy results is almost fully offset by the net negative impact on U.S. interest expense and other non-operational expenses, thereby effectively reducing the Company’s exposure to changes in foreign exchange.

Interest Income and Other was $22 million for first quarter 2009 compared to $11 million for the same period in 2008. The increase of $11 million was primarily due to higher gains from changes in the fair value of derivatives used to manage the Company’s exposure to foreign exchange rate fluctuations.

Income Taxes were $116 million for first quarter 2009 compared to $252 million for the same period in 2008. The decrease in income taxes was primarily due to the first quarter 2008 Calpine bankruptcy settlements, as well as higher tax rate differentials and other positive tax adjustments in 2009.

Non-Controlling Interests of $35 million in first quarter 2009 decreased $36 million compared to $71 million in the same period of 2008 primarily due to the non-controlling interests’ portion of Portland’s Calpine bankruptcy settlement in first quarter 2008.

Liquidity and Capital Resources

Global Market Conditions

Despite uncertainty in global financial markets, TransCanada’s financial position remains sound and consistent with recent years as does its ability to generate cash in the short and long term to provide liquidity, maintain financial capacity and flexibility, as well as provide for planned growth. TransCanada’s liquidity position remains solid, underpinned by highly predictable cash flow from operations, significant cash balances on hand from recent debt issues, as well as committed revolving bank lines of US$1.0 billion, $2.0 billion and US$300 million, maturing in November 2010, December 2012 and February 2013, respectively. To date, no draws have been made on these facilities as TransCanada has maintained continuous access to the Canadian commercial paper market on competitive terms. An additional $50 million and US$324 million of capacity remains available on committed bank facilities at TransCanada-operated affiliates with maturity dates from 2010 through 2012. In addition, common shares are expected to be issued under the Company’s Dividend Reinvestment and Share Purchase Plan (DRP) in lieu of making cash dividend payments.

At March 31, 2009, the Company held cash and cash equivalents of $2.2 billion compared to $1.3 billion at December 31, 2008. The increase in cash and cash equivalents was primarily due to proceeds from the issuance of long-term debt in first quarter 2009.

Operating Activities

Funds Generated from Operations(1)

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

Cash Flows
Funds generated from operations(1)	766	922
Decrease in operating working capital	78	6
Net cash provided by operations	844	928

(1)	Refer to the Non-GAAP Measures section in this MD&A for further discussion of funds generated from operations.

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FIRST QUARTER REPORT 2009

Net Cash Provided by Operations decreased $84 million in first quarter 2009 compared to the same period in 2008. Excluding the $152 million of after-tax proceeds received from the Calpine bankruptcy settlements in first quarter 2008, Funds Generated From Operations in first quarter 2009 were consistent with first quarter 2008.

Investing Activities

Acquisitions, net of cash acquired of $8 million, were $134 million in first quarter 2009 (2008 - $2 million). In accordance with TransCanada’s agreement to increase its ownership interest in Keystone to 79.99 per cent from 50 per cent, TransCanada has funded 100 per cent of the $459 million of the Keystone project cash calls since December 31, 2008. This has resulted in an acquisition of an incremental nine per cent ownership for a total cost of $142 million, bringing TransCanada’s interest to 71 per cent at March 31, 2009 from 62 per cent at December 31, 2008.

TransCanada remains committed to executing its previously announced $19 billion capital expenditure program over the next four years. For the three months ended March 31, 2009, capital expenditures totalled $1.1 billion (2008 - $460 million), primarily related to the Keystone pipeline system, expansion of the Alberta System, refurbishment and restart of Bruce A Units 1 and 2, and construction of Kibby Wind, Halton Hills, Coolidge and Portlands Energy.

Financing Activities

In the three months ended March 31, 2009, TransCanada issued $3.1 billion (2008 - $112 million) and retired $482 million (2008 - $394 million) of long-term debt while notes payable decreased $917 million (2008 – decreased $30 million).

On April 23, 2009, TCPL filed a $2.0 billion Canadian Medium-Term Notes shelf prospectus to replace a March 2007 $1.5 billion Canadian Medium-Term Notes shelf prospectus, which expired in April 2009.

On February 17, 2009, TCPL issued Medium-Term Notes of $300 million and $400 million maturing in February 2014 and February 2039, respectively, and bearing interest at 5.05 per cent and 8.05 per cent, respectively. These notes were issued under the $1.5 billion debt shelf prospectus filed in March 2007.

On January 9, 2009, TCPL issued Senior Unsecured Notes of US$750 million and US$1.25 billion maturing in January 2019 and January 2039, respectively, and bearing interest at 7.125 per cent and 7.625 per cent, respectively. These notes were issued under a US$3.0 billion debt shelf prospectus filed in January 2009, which now has capacity of US$1.0 billion remaining.

Dividends

On April 30, 2009, TransCanada's Board of Directors declared a quarterly dividend of $0.38 per share for the quarter ending June 30, 2009 on the Company’s outstanding common shares. It is payable on July 31, 2009 to shareholders of record at the close of business on June 30, 2009.

TransCanada’s Board of Directors also approved the issuance of common shares from treasury at a three per cent discount under TransCanada’s DRP for the dividends payable on July 31, 2009. The Company reserves the right to alter the discount or return to purchasing shares on the open market at any time. In the three months ended March 31, 2009, TransCanada issued 2.1 million common shares under its DRP, in lieu of making cash dividend payments of $67 million.

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FIRST QUARTER REPORT 2009

Significant Accounting Policies and Critical Accounting Estimates

To prepare financial statements that conform with Canadian GAAP, TransCanada is required to make estimates and assumptions that affect both the amount and timing of recording assets, liabilities, revenues and expenses since the determination of these items may be dependent on future events. The Company uses the most current information available and exercises careful judgement in making these estimates and assumptions.

TransCanada's significant accounting policies and critical accounting estimates have remained unchanged since December 31, 2008. For further information on the Company’s accounting policies and estimates refer to the MD&A in TransCanada's 2008 Annual Report.

Changes in Accounting Policies

The Company’s accounting policies have not changed materially from those described in TransCanada’s 2008 Annual Report except as follows:

2009 Accounting Changes

Rate-Regulated Operations

Effective January 1, 2009, the temporary exemption was withdrawn from the Canadian Institute of Chartered Accountants (CICA) Handbook Section 1100 “Generally Accepted Accounting Principles”, which permitted the recognition and measurement of assets and liabilities arising from rate regulation. In addition, Section 3465 “Income Taxes” was amended to require the recognition of future income tax assets and liabilities for rate-regulated entities. The Company chose to adopt accounting policies consistent with the U.S. Financial Accounting Standards Board’s Financial Accounting Standard (FAS) 71 “Accounting for the Effects of Certain Types of Regulation”. As a result, TransCanada retained its current method of accounting for its rate-regulated operations, except that TransCanada will be required to recognize future income tax assets and liabilities, instead of using the taxes payable method, and will record an offsetting adjustment to regulatory assets and liabilities. As a result of adopting this accounting change, additional future income tax liabilities and a regulatory asset in the amount of $1.4 billion were recorded in each of Future Income Taxes and Other Assets, respectively.

Adjustments to the first quarter 2009 financial statements have been made in accordance with the transitional provisions for Section 3465, which required a cumulative adjustment in the current period to future income taxes and a regulatory asset. Restatement of prior periods’ financial statements was not permitted under Section 3465.

Intangible Assets

Effective January 1, 2009, the Company adopted CICA Handbook Section 3064 “Goodwill and Intangible Assets”, which replaced Section 3062 “Goodwill and Other Intangible Assets”. Section 3064 gives guidance on the recognition of intangible assets as well as the recognition and measurement of internally developed intangible assets. In addition, Section 3450 “Research and Development Costs” was withdrawn from the Handbook. Adopting this accounting change did not have a material effect on the Company’s financial statements.

Credit Risk and the Fair Value of Financial Assets and Financial Liabilities

Effective January 1, 2009, the Company adopted the accounting provisions of Emerging Issues Committee (EIC) Abstract EIC 173, “Credit Risk and the Fair Value of Financial Assets and Financial Liabilities”. Under EIC 173 an entity’s own credit risk and the credit risk of its counterparties is taken into account in determining the fair value of financial assets and financial liabilities, including derivative instruments. Adopting this accounting change did not have a material effect on the Company’s financial statements.

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FIRST QUARTER REPORT 2009

Future Accounting Changes

International Financial Reporting Standards

The CICA’s Accounting Standards Board announced that Canadian publicly accountable enterprises are required to adopt International Financial Reporting Standards (IFRS), as issued by the International Accounting Standards Board (IASB), effective January 1, 2011. TransCanada is currently considering the impact a conversion to IFRS or U.S. GAAP would have on its accounting systems and financial statements. TransCanada’s conversion project includes an analysis of project structure and governance, resources and training, analysis of key GAAP differences and a phased approach to the assessment of current accounting policies and conversion implementation. TransCanada continues to progress its conversion project by scheduling training sessions and IFRS updates for employees, and continuing to assess the impact that significant GAAP or IFRS differences may have on TransCanada.

Under existing Canadian GAAP, TransCanada follows specific accounting policies unique to a rate-regulated business. TransCanada is actively monitoring developments regarding potential future guidance on the applicability of certain aspects of rate-regulated accounting under IFRS. Developments in this area could have a significant effect on the scope of the project and on TransCanada’s financial results. The IASB is currently expected to issue an exposure draft on rate-regulated accounting in July 2009.

At the current stage of the project, TransCanada cannot reasonably determine the full impact that adopting IFRS would have on its financial position and future results.

Contractual Obligations

Other than commitments for future debt and interest payments relating to debt issuances and redemptions discussed in the "Financing Activities" section of this MD&A, there have been no other material changes to TransCanada’s contractual obligations from December 31, 2008 to March 31, 2009, including payments due for the next five years and thereafter. For further information on these contractual obligations, refer to the MD&A in TransCanada’s 2008 Annual Report.

Financial Instruments and Risk Management

TransCanada continues to manage and monitor its exposure to market, counterparty credit and liquidity risk.

Counterparty Credit and Liquidity Risk

TransCanada’s maximum counterparty credit exposure with respect to financial instruments at the balance sheet date, without taking into account security held, consisted 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. Letters of credit and cash are the primary types of security relating to these amounts. The Company does not have significant concentrations of counterparty credit risk with any individual counterparties and the majority of counterparty credit exposure is with counterparties who are investment grade. At March 31, 2009, there were no significant amounts past due or impaired.

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TransCanada has significant exposures to financial institutions as they provide committed credit lines as well as critical liquidity in the foreign exchange and interest rate derivative and energy wholesale markets, and letters of credit to mitigate TransCanada’s exposures to non-creditworthy counterparties.

As the uncertainty in the global financial markets persists, TransCanada has continued to closely monitor and reassess the creditworthiness of its counterparties, including financial institutions. This has resulted in TransCanada reducing or mitigating its exposure to certain counterparties where it is deemed warranted and permitted under contractual terms. As part of its ongoing operations, TransCanada must balance its market and counterparty credit risks when making business decisions.

The Company continues to manage its liquidity risk by ensuring sufficient cash and credit facilities are available to meet its operating and capital expenditure obligations when due, under both normal and stressed economic conditions. Further discussion of the Company’s ability to manage its cash and credit facilities is provided in the “Liquidity and Capital Resources” section in this MD&A.

Natural Gas Inventory

At March 31, 2009, the fair value of proprietary natural gas inventory held in storage as measured by the one-month forward price for natural gas less selling costs was $38 million (December 31, 2008 - $76 million). These amounts are included in Inventories. The change in fair value of proprietary natural gas inventory in the three months ended March 31, 2009 resulted in a net unrealized loss of $23 million, which was recorded as a decrease to Revenues and Inventories (2008 - gain of $59 million). The net change in fair value of natural gas forward purchase and sales contracts in the three months ended March 31, 2009 resulted in a net unrealized gain of $10 million (2008 - loss of $76 million), which was included in Revenues.

Net Investment in Self-Sustaining Foreign Operations

The Company hedges its net investment in self-sustaining foreign operations with U.S. dollar-denominated debt, cross-currency swaps, forward foreign exchange contracts and options. At March 31, 2009, the Company had designated as a net investment hedge U.S. dollar-denominated debt with a carrying value of $9.6 billion (US$7.6 billion) and a fair value of $8.5 billion (US$6.7 billion). At March 31, 2009, Deferred Amounts included $277 million for the fair value of derivatives used to hedge the Company’s net U.S. dollar investment in foreign operations.

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FIRST QUARTER REPORT 2009

Information for the derivatives used to hedge the Company’s net investment in its foreign operations is as follows:

Derivatives Hedging Net Investment in Foreign Operations

	March 31, 2009					December 31, 2008
Asset/(Liability) (unaudited) (millions of dollars)	Fair Value(1)			Notional or Principal Amount		Fair Value(1)			Notional or Principal Amount

U.S. dollar cross-currency swaps
(maturing 2009 to 2014)(2)		(280	)	U.S. 1,550			(218	)	U.S. 1,650
U.S. dollar forward foreign exchange contracts
(maturing 2009)(2)		3		U.S. 210			(42	)	U.S. 2,152
U.S. dollar options
(matured 2009)		-			-		6		U.S. 300

		(277	)	U.S. 1,760			(254	)	U.S. 4,102

(1)	Fair values are equal to carrying values.

(2)	As at March 31, 2009.

Non-Derivative Financial Instruments Summary

The carrying and fair values of non-derivative financial instruments were as follows:

	March 31, 2009				December 31, 2008
(unaudited) (millions of dollars)	Carrying Amount		Fair Value		Carrying Amount		Fair Value

Financial Assets(1)
Cash and cash equivalents		2,232		2,232		1,308		1,308
Accounts receivable and other assets(2)(3)		1,207		1,207		1,404		1,404
Available-for-sale assets(2)		28		28		27		27
		3,467		3,467		2,739		2,739

Financial Liabilities(1)(3)
Notes payable		800		800		1,702		1,702
Accounts payable and deferred amounts(4)		1,334		1,334		1,372		1,372
Accrued interest		403		403		359		359
Long-term debt and junior subordinated notes		20,379		19,871		17,367		16,152
Long-term debt of joint ventures		1,086		1,065		1,076		1,052
		24,002		23,473		21,876		20,637

(1)	Consolidated Net Income in 2009 and 2008 included unrealized gains or losses of nil for the fair value adjustments to each of these financial instruments.

(2)	At March 31, 2009, the Consolidated Balance Sheet included financial assets of $1,070 million (December 31, 2008 – $1,257 million) in Accounts Receivable and $165 million (December 31, 2008 - $174 million) in Other Assets.

(3)	Recorded at amortized cost.

(4)	At March 31, 2009, the Consolidated Balance Sheet included financial liabilities of $1,313 million (December 31, 2008 – $1,350 million) in Accounts Payable and $21 million (December 31, 2008 - $22 million) in Deferred Amounts.

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Derivative Financial Instruments Summary

Information for the Company’s derivative financial instruments, excluding hedges of the Company’s net investment in foreign operations, is as follows:

March 31, 2009
(unaudited) (all amounts in millions unless otherwise indicated)	Power			Natural Gas			Oil Products			Foreign Exchange			Interest

Derivative Financial Instruments Held for Trading(1)
Fair Values(2)
Assets	$	202		$	223		$	8		$	28		$	53
Liabilities	$	(127	)	$	(270	)		-		$	(41	)	$	(115	)
Notional Values
Volumes(3)
Purchases		5,313			230			180			-			-
Sales		7,165			184			324			-			-
Canadian dollars		-			-			-			-			1,016
U.S. dollars		-			-			-		U.S. 459			U.S. 1,575
Japanese yen (in billions)		-			-			-		JPY 2.9				-
Cross-currency		-			-			-		227/U.S. 157				-

Net unrealized gains/(losses) in the three months ended March 31, 2009(4)	$	21		$	(35	)	$	7		$	1			-

Net realized gains/(losses) in the three months ended March 31, 2009(4)	$	10		$	26		$	(3	)	$	6		$	(4	)

Maturity dates		2009-2014			2009-2013			2009-2010			2009-2012			2009-2018

Derivative Financial Instruments in Hedging Relationships(5)(6)
Fair Values(2)
Assets	$	200		$	1			-		$	2		$	8
Liabilities	$	(203	)	$	(34	)		-		$	(21	)	$	(80	)
Notional Values
Volumes(3)
Purchases		10,470			13			-			-			-
Sales		11,463			-			-			-			-
Canadian dollars		-			-			-			-			-
U.S. dollars		-			-			-		U.S. 10			U.S. 1,225
Cross-currency		-			-			-		136/U.S. 100				-

Net realized gains/(losses) in the three months ended March 31, 2009(4)	$	26		$	(10	)		-			-		$	(7	)

Maturity dates		2009-2014			2009-2012			n/a			2009-2013			2009-2013

(1)

All derivative financial instruments in the held-for-trading classification have been entered into for risk management and risk reduction purposes and are subject to the Company’s risk management strategies, policies and limits. These include derivatives that have not been designated as hedges or do not qualify for hedge accounting treatment but have been entered into as economic hedges to manage the Company’s exposures to market risk, including purchases and sales of natural gas related to the Company’s natural gas storage business.

(2)

Fair values are equal to carrying values.

(3)	Volumes for power, natural gas and oil products derivatives are in GWh, Bcf and thousands of barrels, respectively.

(4)

Realized and unrealized gains and losses on power, natural gas and oil products derivative financial instruments held for trading are included in Revenues. Realized and unrealized gains and losses on interest rate and foreign exchange derivative financial instruments held for trading are included in Interest Expense and Interest Income and Other, respectively. The effective portion of unrealized gains and losses on derivative financial instruments in hedging relationships are initially recognized in Other Comprehensive Income, and are reclassified to Revenues, Interest Expense and Interest Income and Other, as appropriate, as the original hedged item settles.

(5)

All hedging relationships are designated as cash flow hedges except for interest-rate derivative financial instruments designated as fair value hedges with a fair value of $8 million and a notional amount of US$50 million. Net realized gains on fair value hedges for the three months ended March 31, 2009 were $1 million and were included in Interest Expense. In first quarter 2009, the Company did not record any amounts in Net Income related to ineffectiveness for fair value hedges.

(6)

Net Income for the three months ended March 31, 2009 included gains of $5 million for the changes in fair value of power and natural gas cash flow hedges that were ineffective in offsetting the change in fair value of their related underlying positions. There were no gains or losses included in Net Income for the three months ended March 31, 2009 for discontinued cash flow hedges. No amounts have been excluded from the assessment of hedge effectiveness.

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2008
(unaudited) (all amounts in millions unless otherwise indicated)	Power			Natural Gas			Oil Products			Foreign Exchange			Interest

Derivative Financial Instruments Held for Trading
Fair Values(1)(4)
Assets	$	132		$	144		$	10		$	41		$	57
Liabilities	$	(82	)	$	(150	)	$	(10	)	$	(55	)	$	(117	)
Notional Values(4)
Volumes(2)
Purchases		4,035			172			410			-			-
Sales		5,491			162			252			-			-
Canadian dollars		-			-			-			-			1,016
U.S. dollars		-			-			-		U.S. 479			U.S. 1,575
Japanese yen (in billions)		-			-			-		JPY 4.3				-
Cross-currency		-			-			-		227/U.S. 157				-

Net unrealized gains/(losses) in the three months ended March 31, 2008(3)	$	(3	)	$	(18	)		-		$	(9	)	$	(4	)

Net realized gains/(losses) in the three months ended March 31, 2008(3)	$	1		$	26			-		$	5		$	3

Maturity dates(4)		2009-2014			2009-2011		2009				2009-2012			2009-2018

Derivative Financial Instruments in Hedging Relationships(5)(6)
Fair Values(1)(4)
Assets	$	115			-			-		$	2		$	8
Liabilities	$	(160	)	$	(18	)		-		$	(24	)	$	(122	)
Notional Values (4)
Volumes(2)
Purchases		8,926			9			-			-			-
Sales		13,113			-			-			-			-
Canadian dollars		-			-			-			-			50
U.S. dollars		-			-			-		U.S. 15			U.S. 1,475
Cross-currency		-			-			-		136/U.S. 100				-

Net realized gains/(losses) in the three months ended March 31, 2008(3)	$	(1	)	$	8			-			-		$	1

Maturity dates(4)		2009-2014			2009-2011			n/a			2009-2013			2009-2019

(1)	Fair values are equal to carrying values.

(2)	Volumes for power, natural gas and oil products derivatives are in GWh, Bcf and thousands of barrels, respectively.

(3)

(4)	As at December 31, 2008.

(5)

All hedging relationships are designated as cash flow hedges except for interest-rate derivative financial instruments designated as fair value hedges with a fair value of $8 million and notional amounts of $50 million and US$50 million at December 31, 2008. There were no net realized gains or losses on fair value hedges for the three months ended March 31, 2008. In first quarter 2008, the Company did not record any amounts in Net Income related to ineffectiveness for fair value hedges.

(6)

Net Income for the three months ended March 31, 2008 included gains of $2 million for the changes in fair value of power and natural gas cash flow hedges that were ineffective in offsetting the change in fair value of their related underlying positions. There were no gains or losses included in Net Income for the three months ended March 31, 2008 for discontinued cash flow hedges. No amounts have been excluded from the assessment of hedge effectiveness.

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Balance Sheet Presentation of Derivative Financial Instruments

The fair value of the derivative financial instruments in the Company’s Balance Sheet was as follows:

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

Current
Other current assets		503			318
Accounts payable		(532	)		(298	)

Long-term
Other assets		222			191
Deferred amounts		(636	)		(694	)

Other Risks

Additional risks faced by the Company are discussed in the MD&A in TransCanada’s 2008 Annual Report. These risks remain substantially unchanged since December 31, 2008.

Controls and Procedures

As of March 31, 2009, an evaluation was carried out under the supervision of, and with the participation of management, including the President and Chief Executive Officer and the Chief Financial Officer, of the effectiveness of TransCanada’s disclosure controls and procedures as defined under the rules adopted by the Canadian securities regulatory authorities and by the SEC. Based on this evaluation, the President and Chief Executive Officer and the Chief Financial Officer concluded that the design and operation of TransCanada’s disclosure controls and procedures were effective as at March 31, 2009.

During the recent fiscal quarter, there have been no changes in TransCanada’s internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, TransCanada’s internal control over financial reporting.

Outlook

The recent economic turmoil and deterioration of financial markets in North America is having a slowing effect on certain aspects of the North American economy. TransCanada does not expect this to have a material effect on the Company’s financial position, access to capital markets, committed projects or corporate strategy.

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FIRST QUARTER REPORT 2009

Since the disclosure in TransCanada’s 2008 Annual Report, the Company's earnings outlook for 2009 has declined due to the negative impact of reduced market prices for power on Energy’s results. With respect to the Pipelines segment, although the global economic downturn has an impact on throughput on certain pipelines and on some drilling activities, the short-term financial outlook for the Company’s Pipelines segment is not expected to be materially impacted as the pipeline assets are generally underpinned by contracts or earn a regulated rate of return.

TransCanada completed the issuance of $3.1 billion of long-term debt in first quarter 2009 and $1.1 billion of common shares at the end of 2008. While these offerings will impact future net income and earnings per share through carrying costs and dilution, when combined with $0.8 billion of operating cash flow in first quarter 2009, they have contributed to a cash balance of $2.2 billion at March 31, 2009 and are expected to provide much of the necessary financing for the Company’s 2009 capital expenditure program. This strategy of strengthening TransCanada’s liquidity and financial position through its ability to successfully access capital markets in very volatile and uncertain economic times has reduced the Company’s future financing risk around its committed growth program, however, it is also expected to result in a reduction to the Company’s net income in 2009 as the cash is held in secure temporary investments prior to its ultimate utilization. For further information on outlook, refer to the MD&A in TransCanada’s 2008 Annual Report.

Since December 31, 2008, there have been no changes to TransCanada’s credit ratings. TransCanada’s issuer rating assigned by Moody’s Investors Service (Moody’s) is Baa1 with a stable outlook. TransCanada PipeLines Limited’s senior unsecured debt is rated A with a stable outlook by DBRS, A3 with a stable outlook by Moody’s and A- with a stable outlook by Standard and Poor’s.

Recent Developments

Pipelines

Canadian Mainline

On April 9, 2009, the NEB approved TransCanada’s application for 2009 final tolls on the Canadian Mainline, effective May 1, 2009. The tolls reflect the terms of a five-year settlement with the NEB effective from 2007 to 2011 which incorporates the NEB’s ROE formula of 8.57 per cent on deemed common equity of 40 per cent.

Alberta System

On February 26, 2009, the NEB determined that the Alberta System is within federal jurisdiction and is subject to regulation by the NEB under the National Energy Board Act (Canada), effective April 29, 2009. As a result of changing from AUC to NEB jurisdiction, TransCanada withdrew from the AUC’s 2009 Generic Cost of Capital proceeding.

The Alberta System is currently operating under interim tolls approved by the AUC effective January 1, 2009. TransCanada will work with stakeholders to migrate the 2008 - 2009 Revenue Requirement Settlement to NEB jurisdiction. Following these discussions, TransCanada will apply to the NEB for approval of final 2009 tolls for the Alberta System.

In May 2009, the first section of the North Central Corridor expansion is expected to be completed at a total capital cost of approximately $400 million. Construction of the remaining sections and associated facilities will continue throughout 2009 with final completion of the North Central Corridor expansion anticipated in April 2010.

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FIRST QUARTER REPORT 2009

On February 26, 2009, TransCanada announced the successful completion of a binding open season, securing support for firm transportation contracts for a pipeline to connect new shale gas supply in the Horn River basin north of Fort Nelson, B.C. to the Alberta System. The contracts are expected to commence in 2011 and increase to 378 million cubic feet per day (mmcf/d) by second quarter 2013. Combined with the Montney volumes of 1.1 billion cubic feet per day (Bcf/d) by 2014, this represents a total of 1.5 Bcf/d of new transportation capacity out of this region.

TQM

On March 19, 2009, TQM received the NEB’s decision on its cost of capital application for the years 2007 and 2008, which requested the approval of an 11 per cent return on 40 per cent deemed common equity. In its decision, the NEB granted TQM’s request to vary from the Multi-pipeline Cost of Capital Decision (RH-2-94) based on changes in financial markets and economic conditions and set a 6.4 per cent after-tax weighted average cost of capital (ATWACC) for each of the two years. The decision granted TQM an aggregate return on capital, leaving it to TQM to choose its optimal capital structure. This decision equates to a 9.85 per cent return on 40 per cent deemed common equity in 2007 and a 9.75 per cent return on 40 per cent deemed common equity in 2008. Prior to the decision, TQM was subject to the NEB ROE formula of 8.46 and 8.71 for 2007 and 2008, respectively, on deemed common equity of 30 per cent established in the RH-2-94 decision.

In April 2009, TQM filed an application with the NEB for final tolls for 2007 and 2008, and expects to recover the variance between interim and final tolls for 2007 and 2008 in 2009.

On March 23, 2009, the NEB issued a letter requesting comment on whether it should initiate a multi-pipeline review of the RH-2-94 decision pursuant to the National Energy Board Act (Canada). The RH-2-94 decision established an ROE formula, tied to 10 year and 30 year Government of Canada bond rates, that has formed the basis of determining tolls for pipelines under NEB jurisdiction since January 1, 1995. Comments are due May 25, 2009 and subsequent initiatives by the NEB are expected to be based on the comments submitted.

Keystone Pipeline System

TransCanada has agreed to increase its equity ownership in the Keystone partnerships to 79.99 per cent with ConocoPhillips’ equity ownership being reduced concurrently to 20.01 per cent. In accordance with this agreement, TransCanada is funding 100 per cent of the construction expenditures until the participants’ project capital contributions are aligned with the revised ownership interests. At March 31, 2009 and December 31, 2008, TransCanada’s equity ownership in the Keystone partnerships was approximately 71 per cent and 62 per cent, respectively.

Certain parties that have volume commitments for the Keystone expansion had options to acquire up to a combined 15 per cent ownership interest in the Keystone partnerships. If these options were not exercised, ConocoPhillips had an option to increase its ownership interest up to 32.51 per cent. None of these options were exercised and the target ownership between TransCanada and ConocoPhillips remains at 79.99 per cent and 20.01 per cent, respectively.

On February 27, 2009, TransCanada filed an application with the NEB to construct and operate the Canadian portion of the Keystone expansion to the U.S. Gulf Coast. A public hearing is anticipated to occur in September 2009 and a decision from the NEB is expected in early 2010.

A Presidential permit, an Environmental Impact Statement and several state permits are required to construct and operate the U.S. portion of the Keystone extension to the U.S. Gulf Coast. Permit applications have been filed with the respective jurisdictions and approvals are expected in second quarter 2010.

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FIRST QUARTER REPORT 2009

Bison

The Bison pipeline project filed an application with the FERC on April 20, 2009 for the right to construct, own and operate the pipeline. The project is expected to have a capital cost of US$610 million and will consist of approximately 486 kilometres (302 miles) of natural gas pipeline designed to transport natural gas from the Powder River Basin in Wyoming to the Midwest U.S. market with a contracted capacity of 407 mmcf/d with potential expandability of up to approximately 1 Bcf/d.

Energy

Portlands Energy

Portlands Energy was fully commissioned on April 22, 2009 under budget. The power plant, which is 50 per cent owned by TransCanada, is able to provide 550 MW of electricity under a 20-year Accelerated Clean Air Supply contract with the Ontario Power Authority.

Broadwater

In April 2009, the U.S. Department of Commerce issued a decision upholding New York State’s objection to the proposed construction and operation of the Broadwater LNG project, a joint venture between TransCanada and Shell US Gas and Power. The Broadwater Energy partnership is currently assessing the ruling and considering its options with respect to this project.

Share Information

As at March 31, 2009, TransCanada had 619 million issued and outstanding common shares. In addition, there were 9 million outstanding options to purchase common shares, of which 7 million were exercisable as at March 31, 2009.

Selected Quarterly Consolidated Financial Data(1)

(unaudited)	2009		2008								2007
(millions of dollars except per share amounts)	First		Fourth		Third		Second		First		Fourth		Third		Second

Revenues		2,380		2,332		2,137		2,017		2,133		2,189		2,187		2,208
Net Income		334		277		390		324		449		377		324		257

Share Statistics
Net income per share – Basic	$	0.54	$	0.47	$	0.67	$	0.58	$	0.83	$	0.70	$	0.60	$	0.48
Net income per share – Diluted	$	0.54	$	0.46	$	0.67	$	0.58	$	0.83	$	0.70	$	0.60	$	0.48

Dividend declared per common share	$	0.38	$	0.36	$	0.36	$	0.36	$	0.36	$	0.34	$	0.34	$	0.34

(1)	The selected quarterly consolidated financial data has been prepared in accordance with Canadian GAAP. Certain comparative figures have been reclassified to conform with the current year’s presentation.

Factors Impacting Quarterly Financial Information

In Pipelines, which consists primarily of the Company's investments in regulated pipelines and regulated natural gas storage facilities, annual revenues and net income fluctuate over the long term based on regulators' decisions and negotiated settlements with shippers. Generally, quarter-over-quarter revenues and net income during any particular fiscal year remain relatively stable with fluctuations resulting from adjustments being recorded due to regulatory decisions and negotiated settlements with shippers, seasonal fluctuations in short-term throughput volumes on U.S. pipelines, acquisitions and divestitures, and developments outside of the normal course of operations.

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FIRST QUARTER REPORT 2009

In Energy, which consists primarily of the Company’s investments in electrical power generation plants and non-regulated natural gas storage facilities, quarter-over-quarter revenues and net income are affected by seasonal weather conditions, customer demand, market prices, planned and unplanned plant outages, acquisitions and divestitures, and developments outside of the normal course of operations.

Significant developments that impacted the last eight quarters' EBIT and Net Income are as follows:

·	First quarter 2009, Energy’s EBIT included net unrealized losses of $13 million pre-tax ($9 million after tax) due to changes in the fair value of proprietary natural gas storage inventory and natural gas forward purchase and sale contracts.

Fourth quarter 2008, Energy’s EBIT included net unrealized gains of $7 million pre-tax ($6 million after tax) due to changes in the fair value of proprietary natural gas storage inventory and natural gas forward purchase and sale contracts. Corporate’s EBIT included net unrealized losses of $57 million pre-tax ($39 million after tax) for changes in the fair value of derivatives, which are used to manage the Company’s exposure to rising interest rates but do not qualify as hedges for accounting purposes.

·	Third quarter 2008, Energy’s EBIT included contributions from the August 26, 2008 acquisition of Ravenswood. Net Income included favourable income tax adjustments of $26 million from an internal restructuring and realization of losses.

Second quarter 2008, Energy’s EBIT included net unrealized gains of $12 million pre-tax ($8 million after tax) due to changes in the fair value of proprietary natural gas storage inventory and natural gas forward purchase and sale contracts. In addition, Western Power’s revenues and EBIT increased due to higher overall realized prices and market heat rates in Alberta.

First quarter 2008, Pipelines’ EBIT included $279 million pre-tax ($152 million after tax) from the Calpine bankruptcy settlements received by GTN and Portland, and proceeds of $17 million pre-tax ($10 million after tax) from a lawsuit settlement. Energy’s EBIT included a writedown of $41 million pre-tax ($27 million after tax) of costs related to the Broadwater LNG project and net unrealized losses of $17 million pre-tax ($12 million after tax) due to changes in the fair value of proprietary natural gas storage inventory and natural gas forward purchase and sale contracts.

Fourth quarter 2007, Net Income included $56 million of favourable income tax adjustments resulting from reductions in Canadian federal income tax rates and other legislative changes. Energy’s EBIT increased due to a $16 million pre-tax ($14 million after-tax) gain on sale of land previously held for development. Pipelines’ EBIT increased as a result of recording incremental earnings related to a rate case settlement reached for the GTN System, effective January 1, 2007. Energy’s EBIT included net unrealized gains of $15 million pre-tax ($10 million after tax) due to changes in the fair value of proprietary natural gas storage inventory and natural gas forward purchase and sale contracts.

·	Third quarter 2007, Net Income included $15 million of favourable income tax reassessments and associated interest income relating to prior years.

·	Second quarter 2007, Net Income included $16 million related to favourable income tax adjustments resulting from reductions in Canadian federal income tax rates. Pipelines’ EBIT increased as a result of a settlement reached on the Canadian Mainline, which was approved by the NEB in May 2007.