6-K

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C.  20549

FORM 6-K

Report of Foreign Private Issuer

Pursuant to Rule 13a-16 or 15d-16 of

the Securities Exchange Act of 1934

For the month of April 2010

Commission File No. 1-31690

TransCanada Corporation

(Translation of Registrant's Name into English)

450 – 1 Street S.W., Calgary, Alberta, T2P 5H1, Canada

(Address of Principal Executive Offices)

Indicate by check mark whether the registrant files or will file annual reports under cover of Form 20-F or Form 40-F:

Form 20-F        ¨                    Form 40-F               þ

Indicate by check mark if the registrant is submitting the Form 6-K in paper as permitted by Regulation S-T Rule 101(b)(1): ¨

Indicate by check mark if the registrant is submitting the Form 6-K in paper as permitted by Regulation S-T Rule 101(b)(7): ¨

Exhibits 13.1 to 13.3 to this report, furnished on Form 6-K, shall be incorporated by reference into each of the following Registration Statements under the Securities Act of 1933, as amended, of the registrant: Form S-8 (File Nos. 333-5916, 333-8470, 333-9130 and 333-151736), Form F-3 (File Nos. 33-13564 and 333-6132) and Form F-10 (File Nos. 333-151781 and 333-161929).

Exhibit 99.1 to this report, furnished on Form 6-K, is furnished, not filed, and will not be incorporated by reference into any registration statement filed by the registrant under the Securities Act of 1933, as amended.

SIGNATURES

Pursuant to the requirements 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.

Dated: April 30, 2010

TRANSCANADA CORPORATION
By:	/s/ Gregory A. Lohnes
	Gregory A. Lohnes
	Executive Vice-President and
	Chief Financial Officer
By:	/s/ G. Glenn Menuz
	G. Glenn Menuz
	Vice-President and Controller

EXHIBIT INDEX

13.1	Management’s Discussion and Analysis of Financial Condition and Results of Operations of the registrant as at and for the period ended March 31, 2010.
13.2	Consolidated comparative interim unaudited financial statements of the registrant for the period ended March 31, 2010 (included in the registrant's First Quarter 2010 Quarterly Report to Shareholders).
13.3	U.S. GAAP reconciliation of the consolidated comparative interim unaudited financial statements of the registrant contained in the registrant's First Quarter 2010 Quarterly Report to Shareholders.
31.1	Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2	Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1	Certification of Chief Executive Officer regarding Periodic Report containing Financial Statements.
32.2	Certification of Chief Financial Officer regarding Periodic Report containing Financial Statements.
99.1	A copy of the registrant’s news release of April 30, 2010.

EX-13.1

EXHIBIT 13.1

TRANSCANADA CORPORATION – FIRST QUARTER 2010

QuarterlyReport to Shareholders

Management's Discussion and Analysis

Management's Discussion and Analysis (MD&A) dated April 29, 2010 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, 2010.  It should also be read in conjunction with the audited Consolidated Financial Statements and notes thereto, and the MD&A contained in TransCanada's 2009 Annual Report for the year ended December 31, 2009. 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 Corpora tion 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 2009 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 security holders 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, projects and financial performance of TransCanada and its subsidiaries, exp ectations or projections about the future, strategies and goals for growth and expansion, expected and future cash flows, costs, schedules (including anticipated construction and completion dates), 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 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 not to place undue reliance on this forward-looking information, which is given as of the date it is expressed in this MD&A or otherwise, and not to 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.

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FIRST QUARTER REPORT 2010

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 may not 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.

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

Management uses the measures of Comparable Earnings, Comparable EBITDA and Comparable EBIT to better evaluate trends in the Company’s underlying operations. Comparable Earnings, Comparable EBITDA and Comparable EBIT comprise Net Income Applicable to Common Shares, 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 and Net Income Applicable to Common Shares. Comparable Earnings Per Share is calculated by dividing Comparable Earnings by the weighted average number of common shares outstanding for the period.

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 Funds Generated from Operations table in the Liquidity and Capital Resources section of this MD&A.

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FIRST QUARTER REPORT 2010

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	Pipelines						Energy						Corporate						Total
except per share amounts)	2010			2009			2010			2009			2010			2009			2010			2009
Comparable EBITDA(1)		768			871			259			290			(26	)		(30	)		1,001			1,131
Depreciation and amortization		(253	)		(260	)		(90	)		(86	)		-			-			(343	)		(346	)
Comparable EBIT(1)		515			611			169			204			(26	)		(30	)		658			785
Specific items:
Fair value adjustments of U.S. Power derivative contracts		-			-			(28	)		-			-			-			(28	)		-
Fair value adjustments of natural gas inventory in storage and forward contracts		-			-			(21	)		(13	)		-			-			(21	)		(13	)
EBIT(1)		515			611			120			191			(26	)		(30	)		609			772
Interest expense																				(182	)		(295	)
Interest expense of joint ventures																				(16	)		(14	)
Interest income and other																				24			22
Income taxes																				(101	)		(116	)
Non-controlling interests																				(31	)		(35	)
Net Income																				303			334
Preferred share dividends																				(7	)		-
Net Income Applicable to Common Shares																				296			334
Specific items (net of tax):
Fair value adjustments of U.S. Power derivative contracts																				17			-
Fair value adjustments of natural gas inventory in storage and forward contracts																				15			9
Comparable Earnings(1)																				328			343
Net Income Per Share – Basic and Diluted (2)																			$	0.43		$	0.54

(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.

(2)	For the three months ended March 31
	(unaudited)		2010		2009
	Net Income Per Share	$	0.43	$	0.54
	Specific items (net of tax):
	Fair value adjustments of U.S. Power derivative contracts		0.03		-
	Fair value adjustments of natural gas inventory in storage and forward contracts		0.02		0.01
	Comparable Earnings Per Share(1)	$	0.48	$	0.55

TransCanada’s Net Income was $303 million and Net Income Applicable to Common Shares was $296 million or $0.43 per share in first quarter 2010 compared to $334 million or $0.54 per share in first quarter 2009. The $38 million decrease in Net Income Applicable to Common Shares reflected:

·   decreased EBIT from Pipelines primarily due to the negative impact of a weaker U.S. dollar, lower revenues from certain Other U.S. Pipelines, and higher business development costs relating to the Alaska pipeline project;

·   decreased EBIT from Energy primarily due to reduced realized power prices in Western Power, lower volumes and higher operating costs at Bruce A, and lower contracted earnings at Bécancour, partially offset by increased capacity payments at Ravenswood, higher third-party storage revenues for Natural Gas Storage and incremental earnings from Portlands Energy which went into service in April 2009; and

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FIRST QUARTER REPORT 2010

·   decreased Interest Expense primarily due to increased capitalized interest and the positive effect of a weaker U.S. dollar on U.S. dollar-denominated interest.

The decrease in Net Income Per Share in first quarter 2010 was also impacted by an 11 per cent increase in the average number of common shares outstanding, in first quarter 2010 compared to first quarter 2009, following the Company’s issuance of 58.4 million common shares in second quarter 2009.

Comparable Earnings in first quarter 2010 decreased $15 million or $0.07 per share to $328 million or $0.48 per share, compared to $343 million or $0.55 per share for the same period in 2009. Comparable Earnings in first quarter 2010 excluded net unrealized after tax losses of $17 million ($28 million pre-tax) resulting from changes in the fair value of certain U.S. Power derivative contracts. Effective January 1, 2010, these unrealized losses have been removed from Comparable Earnings as they are not representative of amounts that will be realized on settlement of the contracts. Comparative amounts in 2009 were not material and therefore were not excluded from the computation of Comparable Earnings. Comparable Earnings in first quarter 2010 and 2009 also excluded net unrealized after tax losses of $15 million ($21 million pre-tax) and $9 million ($13 million pre-tax), respectively, resulting from changes in the fair value of proprietary natural gas inventory in storage and natural gas forward purchase and sale contracts.

On a consolidated basis, the impact of changes in the value of the U.S. dollar on U.S. Pipelines and Energy EBIT is largely offset by the impact on U.S. dollar-denominated interest. The resultant net exposure is managed using derivatives, effectively reducing the Company’s exposure to changes in foreign exchange rates. The average U.S. dollar exchange rate for the three months ended March 31, 2010 was 1.04 (2009 - 1.25).

Results from each of the segments for first quarter 2010 are discussed further in the Pipelines, Energy and Corporate sections of this MD&A.

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FIRST QUARTER REPORT 2010

Pipelines

Pipelines’ Comparable EBIT and EBIT were $515 million in first quarter 2010 compared to $611 million for the same period in 2009.

Pipelines Results

(unaudited)	Three months ended March 31
(millions of dollars)	2010		2009
Canadian Pipelines
Canadian Mainline	265		284
Alberta System	175		168
Foothills	33		34
Other (TQM, Ventures LP)	13		19
Canadian Pipelines Comparable EBITDA(1)	486		505
U.S. Pipelines
ANR	120		133
GTN(2)	45		61
Great Lakes	33		44
PipeLines LP(2)(3)	26		29
Iroquois	19		23
Portland(4)	10		14
International (Tamazunchale, TransGas, Gas Pacifico/INNERGY)	10		13
General, administrative and support costs(5)	(6	)	(3	)
Non-controlling interests(6)	48		60
U.S. Pipelines Comparable EBITDA(1)	305		374
Business Development Comparable EBITDA(1)	(23	)	(8	)
Pipelines Comparable EBITDA(1)	768		871
Depreciation and amortization	(253	)	(260	)
Pipelines Comparable EBIT and EBIT(1)	515		611

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

(2)   GTN’s results include North Baja until July 1, 2009 when it was sold to PipeLines LP.

(3)   PipeLines LP’s results reflect TransCanada’s ownership interest in PipeLines LP of 38.2 per cent in first quarter 2010 (first quarter 2009 – 32.1 per cent).

(4)   Portland’s results reflect TransCanada’s 61.7 per cent ownership interest.

(5)   Represents certain costs associated with supporting the Company’s Canadian and U.S. Pipelines.

(6)   Non-controlling interests reflects Comparable EBITDA for the portions of PipeLines LP and Portland not owned by TransCanada.

Net Income for Wholly Owned Canadian Pipelines

(unaudited)	Three months ended March 31
(millions of dollars)	2010	2009
Canadian Mainline	66	66
Alberta System	38	39
Foothills	6	6

Canadian Pipelines

Canadian Mainline’s Comparable EBITDA for first quarter 2010 of $265 million decreased $19 million compared to the same period in 2009 primarily due to lower revenues as a result of lower income taxes and financial charges in the 2010 tolls, which are recovered on a flow-through basis and do not impact net income. The decrease in financial charges was primarily due to higher cost debt that matured in 2009.

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FIRST QUARTER REPORT 2010

The Alberta System’s net income was $38 million in first quarter 2010 compared to $39 million in first quarter 2009. The impact of a higher average investment base in first quarter 2010 was offset by lower earnings due to the expiration of the 2008-2009 Revenue Requirement Settlement. Net income in 2010 reflects a rate of return on common equity (ROE) of 8.75 per cent on a deemed common equity of 35 per cent.

The Alberta System's Comparable EBITDA was $175 million in first quarter 2010 compared to $168 million in the same quarter of 2009. The increase was due to higher revenues as a result of a higher return associated with an increased average investment base and a recovery of increased depreciation and income taxes, partially offset by lower earnings due to the expiration of the 2008-2009 Revenue Requirement Settlement. Depreciation and income taxes are recovered on a flow-through basis and do not impact net income.

Comparable EBITDA from Other Canadian Pipelines was $13 million for first quarter 2010 compared to $19 million for the same period in 2009. The decrease in first quarter 2010 was primarily due to an adjustment recorded in first quarter 2009 for a National Energy Board of Canada (NEB) decision to retroactively increase TQM’s allowed rate of return on capital for 2008 and 2007.

U.S. Pipelines

ANR’s Comparable EBITDA for first quarter 2010 of $120 million decreased $13 million compared to $133 million for the same period in 2009 primarily due to the negative impact of a weaker U.S. dollar, partially offset by lower operating, maintenance and administration (OM&A) costs and increased incidental natural gas and condensate sales.

GTN’s Comparable EBITDA for first quarter 2010 decreased $16 million from the same period in 2009 primarily due to the negative impact of a weaker U.S. dollar and the sale of North Baja to PipeLines LP in July 2009.

Comparable EBITDA for the remainder of the U.S. Pipelines was $140 million for first quarter 2010 compared to $180 million for the same period in 2009. The decrease was primarily due to the negative impact of a weaker U.S. dollar on U.S. Pipelines operations and lower revenues from Great Lakes, Northern Border and Portland, partially offset by the acquisition of North Baja by PipeLines LP.

Business Development

Pipelines’ Business Development Comparable EBITDA losses increased $15 million in first quarter 2010 compared to the same period in 2009 primarily due to higher business development costs related to the continued advancement of the Alaska pipeline project. The State of Alaska has agreed to reimburse certain of TransCanada’s eligible pre-construction costs, as they are incurred and approved by the state, to a maximum of US$500 million. Such reimbursements are shared proportionately with ExxonMobil, TransCanada’s joint venture partner in developing the Alaska pipeline project.

Operating Statistics

Three months ended March 31	Canadian Mainline(1)				Alberta System(2)				Foothills				ANR(3)				GTN(3)
(unaudited)	2010		2009		2010		2009		2010		2009		2010		2009		2010		2009
Average investment base  ($millions)		6,629		6,590		4,956		4,586		677		725		n/a		n/a		n/a		n/a
Delivery volumes (Bcf)
Total		560		646		938		1,027		328		323		447		491		207		195
Average per day		6.2		7.2		10.4		11.4		3.6		3.6		5.0		5.5		2.3		2.2

(1)   Canadian Mainline’s throughput volumes in the above table reflect physical deliveries to domestic and export markets. Throughput volumes reported in previous years reflected contract deliveries, however, customer contracting patterns have changed in recent years making physical deliveries a better measure of system utilization. Canadian Mainline’s physical receipts originating at the Alberta border and in Saskatchewan for the three months ended March 31, 2010 were 385 billion cubic feet (Bcf) (2009 – 472 Bcf); average per day was 4.3 Bcf (2009 – 5.3 Bcf).

(2)   Field receipt volumes for the Alberta System for the three months ended March 31, 2010 were 855 Bcf (2009 – 909 Bcf); average per day was 9.5 Bcf (2009 – 10.1 Bcf).

(3)   ANR’s and GTN’s results are not impacted by average investment base as these systems operate under fixed rate models approved by the U.S. Federal Energy Regulatory Commission.

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FIRST QUARTER REPORT 2010

Capitalized Project Costs

As at March 31, 2010, TransCanada had advanced $144 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. The NEB recently concluded the final argument hearings for the project and is expected to release its conclusions on the project’s application in September 2010. Project timing continues to be 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 r eassessment of the carrying amount of the APG advances.

Energy

Energy’s Comparable EBIT was $169 million in first quarter 2010 compared to $204 million in first quarter 2009. Comparable EBIT in first quarter 2010 excluded net unrealized losses of $28 million resulting from changes in the fair value of certain U.S. Power derivative contracts. Comparable EBIT in first quarter 2010 and 2009 also excluded net unrealized losses of $21 million and $13 million, respectively, from changes in the fair value of proprietary natural gas inventory in storage and natural gas forward purchase and sale contracts. Items excluded from Comparable Earnings are discussed further under the headings U.S. Power and Natural Gas Storage in this section.

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FIRST QUARTER REPORT 2010

Energy Results

(unaudited)	Three months ended March 31
(millions of dollars)		2010			2009
Canadian Power
Western Power			42			93
Eastern Power(1)			52			52
Bruce Power			63			99
General, administrative and support costs			(10	)		(8	)
Canadian Power Comparable EBITDA(2)			147			236
U.S. Power
Northeast Power(3)			75			42
General, administrative and support costs			(9	)		(12	)
U.S. Power Comparable EBITDA(2)			66			30
Natural Gas Storage
Alberta Storage			53			39
General, administrative and support costs			(2	)		(3	)
Natural Gas Storage Comparable EBITDA(2)			51			36
Business Development Comparable EBITDA(2)			(5	)		(12	)
Energy Comparable EBITDA(2)			259			290
Depreciation and amortization			(90	)		(86	)
Energy Comparable EBIT(2)			169			204
Specific items:
Fair value adjustments of U.S. Power derivative contracts			(28	)		-
Fair value adjustments of natural gas inventory in storage and forward contracts			(21	)		(13	)
Energy EBIT(2)			120			191

(1)   Includes Portlands Energy effective April 2009.

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

(3)   Includes phase one of Kibby Wind effective October 2009.

Western and Eastern Canadian Power

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

(unaudited)	Three months ended March 31
(millions of dollars)		2010			2009
Revenues
Western power			164			215
Eastern power			67			69
Other(3)			22			12
			253			296
Commodity Purchases Resold
Western power			(106	)		(98	)
Other(3)(4)			(5	)		(9	)
			(111	)		(107	)
Plant operating costs and other			(48	)		(44	)
General, administrative and support costs			(10	)		(8	)
Comparable EBITDA(1)			84			137

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

(2)   Includes Portlands Energy effective April 2009.

(3)   Includes sales of excess natural gas purchased for generation and thermal carbon black. Effective January 1, 2010, the net impact of derivatives used to purchase and sell natural gas to manage Western and Eastern Power’s assets is presented on a net basis in Other Revenues. Comparative results for 2009 reflect amounts reclassified from Other Commodity Purchases Resold to Other Revenues.

(4)   Includes the cost of excess natural gas not used in operations.

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FIRST QUARTER REPORT 2010

Western and Eastern Canadian Power Operating Statistics(1)

	Three months ended March 31
(unaudited)	2010	2009
Sales Volumes (GWh)
Supply
Generation
Western Power	585	605
Eastern Power	429	355
Purchased
Sundance A & B and Sheerness PPAs	2,655	2,440
Other purchases	149	185
	3,818	3,585
Sales
Contracted
Western Power	2,269	2,053
Eastern Power	445	391
Spot
Western Power	1,104	1,141
	3,818	3,585
Plant Availability
Western Power(2)	95%	91%
Eastern Power	96%	97%

(1)   Includes Portlands Energy effective April 2009.

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

Western Power’s Comparable EBITDA of $42 million and Power Revenues of $164 million in first quarter 2010 both decreased $51 million compared to the same period in 2009. These decreases were primarily due to lower revenues from the Alberta power portfolio resulting from lower overall realized power prices, partially offset by higher volumes of power sold. Average spot market power prices in Alberta decreased 35 per cent to $41 per megawatt hour (MWh) in first quarter 2010 compared to $63 per MWh in first quarter 2009.

Western Power’s Commodity Purchases Resold increased $8 million in first quarter 2010 compared to the same period in 2009 primarily due to higher purchased power volumes under the Alberta power purchase arrangements (PPAs).

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FIRST QUARTER REPORT 2010

Eastern Power’s Comparable EBITDA of $52 million in first quarter 2010 was consistent with the same period in 2009. Increased revenues due to incremental earnings from Portlands Energy, which went in service in April 2009, were offset by lower contracted earnings from Bécancour.

Plant Operating Costs and Other, which includes fuel gas consumed in generation, of $48 million for first quarter 2010 increased from the same period in 2009 primarily due to incremental fuel consumed at Portlands Energy, partially offset by lower prices for natural gas fuel in Western Power.

Western Power manages the sale of its supply volumes on a portfolio basis. A portion of its supply is sold into the spot market to assure supply in the case of an unexpected plant outage. The overall amount of spot market volumes is dependent upon the ability to transact in forward sales markets at acceptable contract terms. This approach to portfolio management helps to minimize costs in situations where Western Power would otherwise have to purchase electricity in the open market to fulfill its contractual sales obligations. Approximately 67 per cent of Western Power sales volumes were sold under contract in first quarter 2010, compared to 64 per cent in first quarter 2009. To reduce its exposure to spot market prices on uncontracted volumes, as at March 31, 2010, Western Power had entered into fixed-price power sales contracts to se ll approximately 7,000 gigawatt hours (GWh) for the remainder of 2010 and 6,100 GWh for 2011.

Eastern Power is focused on selling power under long-term contracts. In first quarter 2010 and 2009, all of Eastern Power’s sales volumes were sold under contract and are expected to continue to be 100 per cent sold under contract for 2010 and 2011.

Bruce Power

Bruce Power Results

(TransCanada’s proportionate share) (unaudited)	Three months ended March 31
(millions of dollars unless otherwise indicated)	2010		2009
Revenues(1)	225		221
Operating Expenses	(162	)	(122	)
Comparable EBITDA(2)	63		99
Bruce A Comparable EBITDA(2)	13		41
Bruce B Comparable EBITDA(2)	50		58
Comparable EBITDA(2)	63		99
Bruce Power – Other Information
Plant availability
Bruce A	65%		97%
Bruce B	98%		96%
Combined Bruce Power	87%		96%
Planned outage days
Bruce A	35		-
Bruce B	-		-
Unplanned outage days
Bruce A	26		5
Bruce B	6		8
Sales volumes (GWh)
Bruce A	989		1,495
Bruce B	2,155		2,139
	3,144		3,634
Results per MWh
Bruce A power revenues	$64		$63
Bruce B power revenues(3)	$58		$52
Combined Bruce Power revenues	$60		$57
Percentage of Bruce B output sold to spot market(4)	78%		36%

(1)   Revenues include Bruce A’s fuel cost recoveries of $5 million for the three months ended March 31, 2010 (2009 - $10 million). Revenues also include Bruce B unrealized losses of $1 million as a result of changes in the fair value of power derivatives for the three months ended March 31, 2010 (2009 – $2 million gain).

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

(3)   Includes revenues received under the floor price mechanism and contract settlements.

(4)   All of Bruce B’s output is covered by the floor price mechanism, including volumes sold to the spot market.

TransCanada’s proportionate share of Bruce Power’s Comparable EBITDA decreased $36 million to $63 million in first quarter 2010 compared to $99 million in first quarter 2009 as a result of lower volumes and increased operating expenses due to an increase in outage days, partially offset by the impact of a payment made from Bruce B to Bruce A regarding 2009 amendments to a long-term agreement with the Ontario Power Authority (OPA). The net positive impact to TransCanada reflects TransCanada’s higher percentage ownership interest in Bruce A.

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TransCanada’s proportionate share of Bruce A’s Comparable EBITDA decreased $28 million to $13 million in first quarter 2010 compared to $41 million in first quarter 2009 as a result of decreased volumes and higher operating costs due to increased planned and unplanned outages, partially offset by the payment received from Bruce B. Bruce A’s plant availability in first quarter 2010 was 65 per cent as a result of 61 outage days compared to an availability of 97 per cent and five outage days in the same period in 2009.

TransCanada’s proportionate share of Bruce B’s Comparable EBITDA decreased $8 million to $50 million in first quarter 2010 compared to $58 million in first quarter 2009 primarily due to the payment made to Bruce A, partially offset by higher realized prices resulting from the recognition of payments received pursuant to the floor price mechanism in Bruce B’s contract with the OPA.

In second quarter 2009, Bruce B’s contract with the OPA was amended such that, beginning in 2009, annual net payments received under the floor price mechanism will not be subject to repayment in future years. The support payments recognized by Bruce B in second quarter 2009 included an amount for first quarter 2009. Had this amount been included in first quarter 2009, the realized price on Bruce B revenues in first quarter 2009 would be consistent with the $58 per MWh realized in 2010.

Amounts received under the Bruce B floor price mechanism during the year are subject to repayment if the annual average spot price exceeds the annual average floor price. With respect to 2010, TransCanada currently expects spot prices to be less than the floor price for the remainder of the year, therefore, no amounts recorded in revenue in first quarter 2010 are expected to be repaid.

TransCanada’s share of Bruce Power’s generation in first quarter 2010 decreased to 3,144 GWh compared to 3,634 GWh in first quarter 2009, primarily due to an increase in the planned and unplanned outage days at Bruce A in first quarter 2010. Bruce Power units’ combined average availability was 87 per cent in first quarter 2010 compared to 96 per cent in first quarter 2009.

Under a contract with the OPA, all of the output from Bruce A in first quarter 2010 was sold at a fixed price of $64.45 per MWh (before recovery of fuel costs from the OPA) compared to $63.00 per MWh in first quarter 2009. All output from the Bruce B units were subject to a floor price of $48.76 per MWh in first quarter 2010 and $47.66 per MWh in first quarter 2009. Both the Bruce A and Bruce B contract prices are adjusted annually for inflation on April 1. Effective April 1, 2010, the fixed price for output from Bruce A increased to $64.71 per MWh and the Bruce B floor price increased to $48.96 per MWh.

Bruce B also enters into fixed-price contracts whereby Bruce B receives or pays the difference between the contract price and the spot price. Bruce B’s realized price of $58 per MWh in first quarter 2010 reflects revenues recognized from both the floor price mechanism and contract sales. A significant portion of these contracts will expire by the end of 2010, which is expected to result in lower realized prices at Bruce B for future periods. At March 31, 2010, Bruce B had sold forward approximately 1,200 GWh and 300 GWh, representing TransCanada’s proportionate share, for the remainder of 2010 and 2011, respectively.

The overall plant availability percentage in 2010 is expected to be in the mid-80s for the two operating Bruce A units and in the high 80s for the four Bruce B units. A planned outage of Bruce A Unit 3 began in late February 2010 and ended April 25, 2010. Maintenance outages of approximately eight weeks are scheduled to begin in mid-May 2010 for Bruce B Unit 6 and mid-October 2010 for Bruce B Unit 5.

As at March 31, 2010, Bruce A had incurred approximately $3.4billion in costs for the refurbishment and restart of Units 1 and 2, and approximately $0.2 billion for the refurbishment of Units 3 and 4.

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U.S. Power

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

(unaudited)	Three months ended March 31
(millions of dollars)		2010			2009
Revenues
Power(3)			241			272
Capacity			42			30
Other(3)(4)			26			46
			309			348
Commodity purchases resold(3)			(142	)		(122	)
Plant operating costs and other(4)			(92	)		(184	)
General, administrative and support costs			(9	)		(12	)
Comparable EBITDA(1)			66			30

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

(2)   Includes phase one of Kibby Wind effective October 2009.

(3)   Effective January 1, 2010, the net impact of derivatives used to purchase and sell power, natural gas and fuel oil to manage U.S. Power’s assets is presented on a net basis in Power Revenues. Comparative results for 2009 reflect amounts reclassified from Commodity Purchases Resold and Other Revenues to Power Revenues.

(4)   Includes revenues and costs related to a third-party service agreement at Ravenswood.

U.S. Power Operating Statistics(1)

	Three months ended March 31
(unaudited)	2010	2009
Sales Volumes (GWh)
Supply
Generation	891	1,168
Purchased	2,486	1,259
	3,377	2,427
Sales
Contracted	3,215	2,140
Spot	162	287
	3,377	2,427
Plant Availability	86%	58%

(1)   Includes phase one of Kibby Wind effective October 2009.

U.S. Power’s Comparable EBITDA for first quarter 2010 of $66 million increased $36 million compared to the same period in 2009. The increase was primarily due to increased capacity revenue and a 2010 adjustment of Ravenswood’s 2009 operating costs, partially offset by the impact of a weaker U.S. dollar.

U.S. Power’s Power Revenues for first quarter 2010 of $241 million decreased from $272 million for the same period in 2009 primarily due to lower realized power prices and the impact of a weaker U.S. dollar, partially offset by higher volumes of power sold.

Other Revenues of $26 million decreased $20 million in first quarter 2010 compared to the same period in 2009 due to the impact of a weaker U.S. dollar in 2010 and a decrease in revenue associated with a third-party service agreement.

Power Commodity Purchases Resold of $142 million for first quarter 2010 increased from $122 million in the same period in 2009 primarily due to an increase in the quantity of power purchased for resale under its power sales commitments, partially offset by lower contracted power prices per MWh and the impact of a weaker U.S. dollar in first quarter 2010.

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Plant Operating Costs and Other of $92 million for first quarter 2010 decreased $92 million from the same period in 2009 due to the impact of a weaker U.S. dollar, decreased asset dispatch, reduced fuel costs, lower overall maintenance costs and the Ravenswood prior year adjustment.

In first quarter 2010, 95 per cent of power sales volumes were sold under contract, compared to 88 per cent for the same period in 2009.  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, 2010, U.S. Power had entered into fixed-price power sales contracts to sell approximately 8,900 GWh for the remainder of 2010 and 6,600 GWh for 2011, including financial contracts to effectively lock in the margin on forecasted generation. Certain contracted volumes are dependent on customer usage levels and actual amounts contracted in future periods and will depend on market liquidity and other factors.

Comparable EBITDA excluded net unrealized losses of $28 million in first quarter 2010 resulting from changes in the fair value of certain U.S. Power derivative contracts. Power is purchased under forward contracts to satisfy a significant portion of U.S. Power’s wholesale, commercial and industrial power sales commitments, mitigating its exposure to fluctuations in spot market prices and effectively locking in a positive margin. In addition, power generation is managed by entering into contracts to sell a portion of power forecasted to be generated. Contracts are entered into simultaneously to purchase the fuel required to generate the power to reduce exposure to market price volatility and effectively lock in positive margins. Each of these contracts provide economic hedges which, in some cases, do not meet the specific criteria required for hedge accounting treatment and therefore are recorded at their fair value based on forward market prices. Effective January 1, 2010, the unrealized losses from these contracts have been removed from Comparable EBITDA as they are not representative of amounts that will be realized on settlement of the contracts. Comparative amounts in 2009 were not material and therefore were not excluded from the computation of Comparable EBITDA.

Natural Gas Storage

Natural Gas Storage’s Comparable EBITDA for first quarter 2010 was $51 million compared to $36 million for the same period in 2009. The $15 million increase in Comparable EBITDA in first quarter 2010 was primarily due to increased third party storage revenues as a result of higher realized seasonal natural gas price spreads. The seasonal nature of natural gas storage generally results in higher revenues in the winter season.

Comparable EBITDA excluded net unrealized losses of $21 million in first quarter 2010 (2009 – losses of $13 million) 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 proprietary 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 in each period on proprietary natural gas held in storage and these forward contracts are not representative of the amounts that will be realized on settlement. The fair value of proprietary natura l gas inventory held in storage has been measured using a weighted average of forward prices for the following four months less selling costs.

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FIRST QUARTER REPORT 2010

Other Income Statement Items

Interest Expense

(unaudited)	Three months ended March 31
(millions of dollars)		2010			2009
Interest on long-term debt(1)			296			335
Other interest and amortization			20			14
Capitalized interest			(134	)		(54	)
			182			295

(1)   Includes interest for Junior Subordinated Notes.

Interest Expense decreased $113 million to $182 million in first quarter 2010 from $295 million in first quarter 2009. The decrease reflected increased capitalized interest to finance the Company’s larger capital growth program in 2010, primarily due to Keystone construction. Interest expense also decreased due to the positive impact of a weaker U.S. dollar on U.S. dollar-denominated interest in first quarter 2010.

Income Taxes decreased to $101 million in first quarter 2010 from $116 million in first quarter 2009 primarily due to lower earnings in first quarter 2010.

Liquidity and Capital Resources

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, and to provide for planned growth. TransCanada’s liquidity position remains solid, underpinned by predictable cash flow from operations, significant cash balances on hand from common and preferred share and debt issues, as well as committed revolving bank lines of US$1.0 billion, $2.0 billion, US$1.0 billion and US$300 million, maturing in November 2010, December 2012, December 2012 and February 2013, respectively. At March 31, 2010, draws of $812 million had been made on these facilities, which also support the Company’s two commercial paper programs  in Canada. In addition, TransCanada’s proportionate share of capacity remaining available on com mitted bank facilities at TransCanada-operated affiliates was $140 million with maturity dates from 2010 through 2012.As at March 31, 2010, TransCanada had remaining capacity of $2.1 billion, $2.0 billion and US$4.0 billion under its equity, Canadian debt and U.S. debt shelf prospectuses, respectively. In lieu of making cash dividend payments, a portion of the declared common and preferred share dividends are expected to be paid in common shares issued under the Company’s Dividend Reinvestment and Share Purchase Plan (DRP). TransCanada’s liquidity, market and other risks are discussed further in the Risk Management and Financial Instruments section of this MD&A.

At March 31, 2010, the Company held Cash and Cash Equivalents of $736 million compared to $997 million at December 31, 2009. The decrease in Cash and Cash Equivalents was primarily due to capital expenditures, partially offset by cash generated by operations and proceeds from the issuance of preferred shares in first quarter 2010.

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Operating Activities

Funds Generated from Operations(1)

(unaudited)	Three months ended March 31
(millions of dollars)	2010	2009
Cash Flows
Funds generated from operations(1)	723	766
Decrease in operating working capital	109	82
Net cash provided by operations	832	848

(1)   Refer to the Non-GAAP Measures section in this MD&A for further discussion of Funds Generated from Operations.

Net Cash Provided by Operations and Funds Generated from Operations decreased $16 million and $43 million, respectively, for the three months ended March 31, 2010 compared to the same period in 2009, primarily due to a decrease in cash generated through earnings.

Investing Activities

TransCanada remains committed to executing its previously announced $22 billion capital expenditure program by the end of 2013. For the three months ended March 31, 2010, capital expenditures totalled $1.3 billion (2009 - $1.1 billion), primarily related to construction of Keystone and expenditures related to the expansion of the Alberta System, refurbishment and restart of Bruce A Units 1 and 2, and construction of Guadalajara.

Financing Activities

In March 2010, TransCanada completed a public offering of 14 million Series 3 cumulative redeemable first preferred shares, including the full exercise of an underwriters’ over-allotment option of two million shares, under its September 2009 base shelf prospectus. The preferred shares were issued at $25 per share, resulting in gross proceeds of $350 million including the over-allotment option. The holders of the preferred shares are entitled to receive fixed cumulative dividends at an annual rate of $1.00 per share, payable quarterly, yielding four per cent per annum, for the initial five year period ending June 30, 2015, with the first dividend payment scheduled for June 30, 2010. The dividend rate will reset on June 30, 2015 and every five years thereafter to a yield per annum equal to the sum of the then five year Government o f Canada bond yield and 1.28 per cent. The preferred shares are redeemable by TransCanada on or after June 30, 2015. The net proceeds of this offering are expected to be used to partially fund capital projects, for general corporate purposes and to repay short-term debt.

The Series 3 preferred shareholders will have the right to convert their shares into Series 4 cumulative redeemable first preferred shares on June 30, 2015 and on June 30 of every fifth year thereafter. The holders of Series 4 preferred shares will be entitled to receive quarterly floating rate cumulative dividends at a yield per annum equal to the sum of the then 90 day Government of Canada treasury bill rate and 1.28 per cent.

The Company is well positioned to fund its existing capital program through its growing internally-generated cash flow, its DRP and its continued access to capital markets. TransCanada will also continue to examine opportunities for portfolio management, including a greater role for PipeLines LP, in financing its capital program.

In the three months ended March 31, 2010, TransCanada issued $10 million (2009 - $3.1 billion), and retired $141 million (2009 - $482 million), of Long-Term Debt while Notes Payable increased $432 million (2009 – decreased $917 million).

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Dividends

On April 29, 2010, TransCanada's Board of Directors declared a quarterly dividend of $0.40 per share for the quarter ending June 30, 2010 on the Company’s outstanding common shares. It is payable on July 30, 2010 to shareholders of record at the close of business on June 30, 2010. In addition, quarterly dividends of $0.2875 and $0.3041 per preferred share were declared for Series 1 and Series 3 preferred shares, respectively, for the period ending June 30, 2010. The dividends are payable on June 30, 2010 to shareholders of record at the close of business on May 31, 2010.

TransCanada’s Board of Directors approved the issuance of common shares from treasury at a three per cent discount under TransCanada’s DRP for dividends payable on TransCanada’s common and preferred shares, and TCPL’s preferred shares. The Company reserves the right to alter the discount or return to fulfilling DRP participation by purchasing shares on the open market at any time. In the three months ended March 31, 2010, TransCanada issued 2.3 million (2009 - 2.1 million) common shares under its DRP, in lieu of making cash dividend payments of $78 million (2009 - $67 million).

Significant Accounting Policies and Critical Accounting Estimates

To prepare financial statements that conform with 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, 2009. For further information on the Company’s accounting policies and estimates refer to the MD&A in TransCanada's 2009 Annual Report.

Changes in Accounting Policies

The Company’s accounting policies have not changed materially from those described in TransCanada’s 2009 Annual Report. Future accounting changes that will impact the Company are as follows:

Future Accounting Changes

International Financial Reporting Standards

The Canadian Institute of Chartered Accountants' (CICA) 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. Effective January 1, 2011, the Company will begin reporting under IFRS.

TransCanada continues to progress its conversion project by scheduling training sessions and IFRS updates for employees and Directors, executing changes to information systems and business processes to accommodate IFRS accounting and reporting requirements, reviewing new IFRS developments and assessing the impact that significant differences between GAAP and IFRS will have on TransCanada.

TransCanada currently follows specific accounting policies unique to a rate-regulated business. The Company 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 Company’s IFRS project and on TransCanada’s IFRS financial results. The Company is assessing the impact of developments related to the IASB’s July 2009 Exposure Draft ‘‘Rate-Regulated Activities’’. Currently, TransCanada does not expect this Exposure Draft to be effective for 2011.

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TransCanada actively monitors the IASB’s schedule of projects, giving consideration to any proposed changes, where applicable, in its assessment of differences between IFRS and GAAP. As a result of ongoing developments related to rate-regulated accounting under IFRS as well as other areas, together with the current stage of the Company’s IFRS project, TransCanada cannot reasonably quantify the full impact that adopting IFRS will have on its financial position and future results.

Contractual Obligations

There have been no material changes to TransCanada’s contractual obligations from December 31, 2009 to March 31, 2010, 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 2009 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 of accounts receivable, the fair value of derivative assets and loans and advances receivable. The carrying amounts and fair values of these financial assets are included in Accounts Receivable and Other in the Non-Derivative Financial Instruments Summary table below. Letters of credit and cash are the primary types of security provided to support these amounts. The majority of counterparty credit exposure is with counterparties who are investment grade. At March 31, 2010, there were no significant amounts past due or impaired.

At March 31, 2010 the Company had a credit risk concentration of $339 million due from a creditworthy counterparty. This amount is expected to be fully collectible and is secured by a guarantee from the counterparty’s parent company.

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.

Natural Gas Inventory Price Risk

At March 31, 2010, the fair value of proprietary natural gas inventory held in storage, as measured using a weighted average of forward prices for the following four months less selling costs, was $54 million (December 31, 2009 - $73 million). The change in fair value of proprietary natural gas inventory in storage in the three months ended March 31, 2010 resulted in a net pre-tax unrealized loss of $24 million (2009 - loss of $23 million), which was recorded as a decrease to Revenues and Inventories. The net change in fair value of natural gas forward purchase and sale contracts in the three months ended March 31, 2010 resulted in a net pre-tax unrealized gain of $3 million (2009 - gain of $10 million), which was recorded as an increase to Revenues.

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VaR Analysis

TransCanada uses a Value-at-Risk (VaR) methodology to estimate the potential impact from its exposure to market risk on its open liquid positions. VaR represents the potential change in pre-tax earnings over a given holding period. It is calculated assuming a 95 per cent confidence level that the daily change resulting from normal market fluctuations in its open positions will not exceed the reported VaR. Although losses are not expected to exceed the statistically estimated VaR on 95 per cent of occasions, losses on the other five per cent of occasions could be substantially greater than the estimated VaR. TransCanada’s consolidated VaR was $6 million at March 31, 2010 (December 31, 2009 – $12 million). The decrease from December 31, 2009 was primarily due to decreased prices and lower open positions in the U.S. Power port folio.

Net Investment in Self-Sustaining Foreign Operations

The Company hedges its net investment in self-sustaining foreign operations (on an after-tax basis) with U.S. dollar-denominated debt, cross-currency interest rate swaps, forward foreign exchange contracts and foreign exchange options. At March 31, 2010, the Company had designated as a net investment hedge U.S. dollar-denominated debt with a carrying value of $7.7 billion (US$7.6 billion) and a fair value of $8.0 billion (US$7.9 billion). At March 31, 2010, $158 million (December 31, 2009 - $96 million) was included in Intangibles and Other Assets for the fair value of forwards and swaps used to hedge the Company’s net U.S. dollar investment in foreign operations.

The fair values and notional principal amounts for the derivatives designated as a net investment hedge were as follows:

Derivatives Hedging Net Investment in Self-Sustaining Foreign Operations

	March 31, 2010				December 31, 2009
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 2010 to 2014)		140	U.S. 2,000			86	U.S. 1,850
U.S. dollar forward foreign exchange contracts
(maturing 2010)		18	U.S. 1,030			9	U.S. 765
U.S. dollar options
(matured 2010)		-		-		1	U.S. 100
		158	U.S. 3,030			96	U.S. 2,715

(1)   Fair values equal carrying values.

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Non-Derivative Financial Instruments Summary

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

	March 31, 2010		December 31, 2009
(unaudited) (millions of dollars)	Carrying Amount	Fair Value	Carrying Amount	Fair Value
Financial Assets(1)
Cash and cash equivalents	736	736	997	997
Accounts receivable and other(2)(3)	1,363	1,402	1,432	1,483
Available-for-sale assets(2)	22	22	23	23
	2,121	2,160	2,452	2,503
Financial Liabilities(1)(3)
Notes payable	2,087	2,087	1,687	1,687
Accounts payable and deferred amounts(4)	1,638	1,638	1,538	1,538
Accrued interest	319	319	377	377
Long-term debt	16,213	19,208	16,664	19,377
Junior subordinated notes	1,005	987	1,036	976
Long-term debt of joint ventures	931	1,000	965	1,025
	22,193	25,239	22,267	24,980

(1)   Consolidated Net Income in first quarter 2010 included losses of $7 million (2009 – losses of $14 million) for fair value adjustments related to interest rate swap agreements on US$250 million (2009 – US$200 million) of long-term debt. There were no other unrealized gains or losses from fair value adjustments to the financial instruments.

(2)   At March 31, 2010, the Consolidated Balance Sheet included financial assets of $912 million (December 31, 2009 – $966 million) in Accounts Receivable, $40 million in Other Current Assets (December 31, 2009 – nil) and $433 million (December 31, 2009 - $489 million) in Intangibles and Other Assets.

(3)   Recorded at amortized cost, except for certain long-term debt which is adjusted to fair value.

(4)   At March 31, 2010, the Consolidated Balance Sheet included financial liabilities of $1,612 million (December 31, 2009 – $1,513 million) in Accounts Payable and $26 million (December 31, 2009 - $25 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 self-sustaining foreign operations, is as follows:

March 31, 2010
(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	$319			$178			-		$1			$26
Liabilities	$(251	)		$(182	)		-		$(12	)		$(73	)
Notional Values
Volumes(3)
Purchases	16,661			112			-		-			-
Sales	17,657			99			-		-			-
Canadian dollars	-			-			-		-			838
U.S. dollars	-			-			-		U.S. 612			U.S. 1,500
Cross-currency	-			-			-	47/U.S. 37				-
Net unrealized (losses)/gains in the three months ended March 31, 2010(4)	$(16	)		$2			-		-			$(4	)
Net realized gains/(losses) in the three months ended March 31, 2010(4)	$22			$(12	)		-		$8			$(4	)
Maturity dates	2010-2015		2010-2014			2010			2010-2012		2010-2018
Derivative Financial Instruments in Hedging Relationships(5)(6)
Fair Values(2)
Assets	$191			-			-		-			$10
Liabilities	$(313	)		$(53	)		-		$(48	)		$(44	)
Notional Values
Volumes(3)
Purchases	15,819			31			-		-			-
Sales	12,385			-			-		-			-
U.S. dollars	-			-			-		U.S. 120			U.S. 2,075
Cross-currency	-			-			-	136/U.S. 100				-
Net realized losses in the three months ended March 31, 2010(4)	$(7	)		$(3	)		-		-			$(10	)
Maturity dates	2010-2015			2010-2012			n/a		2010- 2014			2010-2020

(1)   All derivative financial instruments in the held-for-trading classification have been entered into for risk management 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.

(2)   Fair values equal carrying values.

(3)   Volumes for power, natural gas and oil products derivatives are in GWh, billion cubic feet (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 $7 million and a notional amount of US$150 million. Net realized gains on fair value hedges for the three months ended March 31, 2010 were $1 million and were included in Interest Expense. In first quarter 2010, 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, 2010 included losses of $8 million for changes in the 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, 2010 for discontinued cash flow hedges. No amounts have been excluded from the assessment of hedge effectiveness.

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2009
(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)(2)
Assets	$150		$107		$5			-			$25
Liabilities	$(98	)	$(112	)	$(5	)		$(66	)		$(68	)
Notional Values(2)
Volumes(3)
Purchases	15,275		238		180			-			-
Sales	13,185		194		180			-			-
Canadian dollars	-		-		-			-			574
U.S. dollars	-		-		-			U.S. 444		U.S. 1,325
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(2)	2010-2015		2010-2014		2010			2010-2012			2010-2018
Derivative Financial Instruments in Hedging Relationships(5)(6)
Fair Values(1)(2)
Assets	$175		$2		-			-			$15
Liabilities	$(148	)	$(22	)	-			$(43	)		$(50	)
Notional Values(2)
Volumes(3)
Purchases	13,641		33		-			-			-
Sales	14,311		-		-			-			-
U.S. dollars	-		-		-			U.S. 120		U.S. 1,825
Cross-currency	-		-		-		136/ U.S. 100				-
Net realized gains/(losses) in the three months ended March 31, 2009(4)	$26		$(10	)	-			-			$(7	)
Maturity dates(2)	2010-2015		2010-2014		n/a			2010-2014			2010-2020

(1)   Fair values equal carrying values.

(2)   As at December 31, 2009.

(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 $4 million and a notional amount of US$150 million at December 31, 2009. 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 changes in the 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.

TRANSCANADA [22

FIRST QUARTER REPORT 2010

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, 2010			December 31, 2009
Current
Other current assets		460			315
Accounts payable		(538	)		(340	)
Long-term
Intangibles and other assets		423			260
Deferred amounts		(438	)		(272	)

Other Risks

Additional risks faced by the Company are discussed in the MD&A in TransCanada’s 2009 Annual Report. These risks remain substantially unchanged since December 31, 2009.

Controls and Procedures

As of March 31, 2010, 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, 2010.

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

Since the disclosure in TransCanada’s 2009 Annual Report, the Company's earnings outlook for 2010 has declined due to the continued negative impact of reduced market prices for power on Energy’s results. For further information on outlook, refer to the MD&A in TransCanada’s 2009 Annual Report.

TransCanada’s issuer rating assigned by Moody’s Investors Service (Moody’s) is Baa1 with a stable outlook. TCPL’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 (S&P). DBRS and S&P have assigned ratings of Pfd-2 (low) and P-2, respectively, to TransCanada’s cumulative redeemable first preferred shares, Series 1 and 3, and S&P has assigned TransCanada an A- long-term corporate credit rating with a stable outlook.

TRANSCANADA [23

FIRST QUARTER REPORT 2010

Recent Developments

Pipelines

Keystone

Construction on the first phase of Keystone is substantially complete and commissioning continued in first quarter 2010. Commercial in service of this segment is expected to occur in second quarter 2010. The first phase of Keystone extends from Hardisty, Alberta to serve markets in Wood River and Patoka, Illinois and has an initial nominal capacity of 435,000 barrels per day (Bbl/d). As part of the NEB’s approval to begin operations, Keystone will operate at a reduced maximum operating pressure (MOP) which will reduce throughput capacity below initial nominal capacity. Within nine months from commercial in service, Keystone is required to run additional in-line inspections on the Canadian segment of the pipeline. These inspections, any remedial work and removal of the MOP restriction are expected to be completed within this nine month period.

Construction of the second phase of Keystone to expand nominal capacity to 591,000 Bbl/d and extend the pipeline to Cushing, Oklahoma, is expected to commence in second quarter 2010. Commercial in service of the second phase is expected to occur in first quarter 2011.

Keystone is planning to construct and operate an expansion and extension of the pipeline system that will provide additional capacity of 500,000 Bbl/d from Western Canada to the U.S. Gulf Coast in first quarter 2013. The Keystone expansion will extend from Hardisty, Alberta to a delivery point near existing terminals in Port Arthur, Texas. In March 2010, the NEB approved the Company’s application to construct and operate the Canadian portion of the Keystone expansion. Permits for the U.S. portion of the expansion are expected in fourth quarter 2010. Construction of the expansion facilities is anticipated to commence in first quarter 2011 following the receipt of the remaining regulatory approvals.

The total capital cost of Keystone is expected to be approximately US$12 billion. Approximately US$6 billion has been spent to date with the remaining US$6 billion to be invested between now and the end of 2012. Capital costs related to the construction of Keystone are subject to capital cost risk-and-reward sharing mechanisms with its customers.

Although commercial in service is expected to occur in second quarter 2010, TransCanada expects Keystone to begin recording EBITDA in fourth quarter 2010 when the MOP restriction on the Canadian segment is expected to be removed, with EBITDA increasing through 2011, 2012 and 2013 as subsequent phases are placed in service. Based on current long-term commitments of 910,000 Bbl/d, Keystone is expected to generate EBITDA of approximately US$1.2 billion in 2013, its first full year of commercial operation serving both the U.S. Midwest and Gulf Coast markets. If volumes increase to 1.1 million Bbl/d, the full commercial design of the system, Keystone would generate approximately US$1.5 billion of annual EBITDA. In the future, Keystone can be economically expanded from 1.1 million Bbl/d to 1.5 million Bbl/d in response to additional market d emand.

Three entities, each of which had entered into Transportation Service Agreements for the second phase of the Keystone pipeline, have filed separate Statements of Claim against certain of TransCanada's Keystone subsidiaries in the Alberta Court of Queen’s Bench, seeking declaratory relief or alternatively, damages in varying amounts. Only one of these Statements of Claim has been served on the Keystone subsidiaries.  The Company believes each of the claims to be without merit and will vigorously defend this action and the others if served. 

TRANSCANADA [24

FIRST QUARTER REPORT 2010

Alberta System

In March 2010, TransCanada completed the final phase of the North Central Corridor natural gas pipeline.  North Central Corridor consists of a 300 km (186 miles) pipeline and associated compression facilities on the northern section of the Alberta System. This project was completed ahead of schedule and under budget at a total capital cost of approximately $800 million.

In March 2010, the NEB approved TransCanada’s application for approval to construct and operate the Groundbirch natural gas pipeline. Construction is scheduled to commence in July 2010 with completion anticipated in November 2010. The total capital cost of this project is estimated to be $200 million.

In April 2010, the NEB announced that it will hold a public hearing process on an application TransCanada filed in February 2010 for approval to construct and operate the Horn River project. The public hearing process is scheduled to begin in October 2010. Subject to regulatory approvals, the Horn River project is anticipated to commence operations in second quarter 2012 with a total capital cost of approximately $310 million.

NEB ROE Formula

In October 2009, the NEB issued a decision that the RH-2-94 Decision which has formed the basis of determining tolls for certain pipelines under NEB jurisdiction since January 1, 1995 would not continue to be in effect. The NEB stated that instead of a multi-pipeline approach, the cost of capital will be determined by negotiations between pipeline companies and their shippers or by the NEB if a pipeline company files a cost of capital application. This decision impacts certain NEB regulated pipelines including the Canadian Mainline, Alberta System, Foothills and TQM. TransCanada is working with customers and interested parties to determine the cost of capital to be used in calculating tolls for 2010 on the Alberta System, Foothills and TQM. Cost of Capital discussions with stakeholders on the Canadian Mainline will commence prior to te rmination of its existing settlement on December 31, 2011. If agreements cannot be reached, applications will be filed with the NEB requesting an appropriate return on capital.

In November 2009, the Canadian Association of Petroleum Producers (CAPP) and the Industrial Gas Users Association (IGUA) sought leave to appeal the October 2009 NEB decision to the Federal Court of Appeal and named the NEB as the sole respondent. In March 2010, the Federal Court of Appeal dismissed the motion filed by CAPP and IGUA.

Alaska Open Season

In March 2010, the U.S. Federal Energy Regulatory Commission (FERC) approved the open season for TransCanada and ExxonMobil’s joint Alaska pipeline project. The open season will commence on April 30, 2010, and continue through July 30, 2010. There will be concurrent open seasons in Canada for those shippers seeking to access the pipeline in Alberta. Shippers will also have the opportunity to nominate deliveries on either the proposed pipeline to Alberta or the proposed pipeline to Valdez, Alaska.  The results of the open season are expected to be available near the end of 2010.

Great Lakes Rate Case

In November 2009, the FERC commenced an investigation, alleging that, based on a review of certain historical information, Great Lakes’ revenues might substantially exceed Great Lakes’ actual cost of service and therefore may be unjust and unreasonable.

In April 2010, the Chief Administrative Law Judge (ALJ) granted a motion filed by Great Lakes to temporarily suspend the Great Lakes rate proceeding due to an agreement in principle which was reached among Great Lakes, active participants and the FERC trial staff. The parties anticipate filing an agreement embodying the settlement terms on or about May 17, 2010, for subsequent approval by the ALJ and the FERC. In the absence of a settlement, a hearing in the investigation is scheduled for early August 2010 and an initial decision by the ALJ is expected in November 2010. The Company does not expect the rate case settlement, if reached, will have a material effect on Great Lakes’ revenues in the context of the current market environment.

TRANSCANADA [25

FIRST QUARTER REPORT 2010

Bison

In April 2010, the FERC issued a Certificate Order which requires certain submissions and approvals before approval for construction can be issued. Construction is expected to commence in second quarter 2010 with an expected in-service date of fourth quarter 2010.  The project is expected to cost US$600 million.

Energy

Oakville

Advancement continues on the 900 MW Oakville power generating station located in Oakville, Ontario. In January 2010, TransCanada released a draft Environmental Review Report (ERR) for government agency and public comment, with a  final ERR expected to be submitted to the Province of Ontario’s Ministry of the Environment in second quarter 2010. TransCanada continues to work with the local community to address concerns and the project is anticipated to be in service in first quarter 2014.

Power Transmission Line Projects

TransCanada continues to review the results of the open seasons on the proposed Zephyr and Chinook power transmission line projects and expects to announce the results in second quarter 2010. Each project would be capable of delivering primarily wind-generated power from Wyoming (Zephyr) and Montana (Chinook) to Nevada to access California and other U.S. desert southwest markets.

Share Information

As at April 27, 2010, TransCanada had 687 million issued and outstanding common shares, and 22 million and 14 million issued and outstanding Series 1 and 3 first preferred shares, respectively. In addition, there were nine million outstanding options to purchase common shares, of which seven million were exercisable as at April 27, 2010.

Selected Quarterly Consolidated Financial Data(1)

(unaudited)	2010		2009								2008
(millions of dollars except per share amounts)	First		Fourth		Third		Second		First		Fourth		Third		Second
Revenues		1,955		2,010		2,087		2,010		2,179		2,234		2,145		2,079
Net Income		303		387		345		314		334		277		390		324
Share Statistics
Net income per share – Basic	$	0.43	$	0.56	$	0.50	$	0.50	$	0.54	$	0.47	$	0.67	$	0.58
Net income per share – Diluted	$	0.43	$	0.56	$	0.50	$	0.50	$	0.54	$	0.46	$	0.67	$	0.58
Dividend declared per common share	$	0.40	$	0.38	$	0.38	$	0.38	$	0.38	$	0.36	$	0.36	$	0.36

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

TRANSCANADA [26

FIRST QUARTER REPORT 2010

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.

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, capacity payments, planned and unplanned plant outages, acquisitions and divestitures, certain fair value adjustments 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 2010, Energy’s EBIT included net unrealized losses of $28 million pre-tax ($17 million after tax) resulting from changes in the fair value of certain U.S. Power derivative contracts. Energy’s EBIT also included net unrealized losses of $21 million pre-tax ($15 million after tax) due to changes in the fair value of proprietary natural gas inventory in storage and natural gas forward purchase and sale contracts.

·   Fourth quarter 2009, Pipelines’ EBIT included a dilution gain of $29 million pre-tax ($18 million after tax) resulting from TransCanada’s reduced ownership interest in PipeLines LP after PipeLines LP issued common units to the public. Energy’s EBIT included net unrealized gains of $7 million pre-tax ($5 million after tax) due to changes in the fair value of proprietary natural gas inventory in storage and natural gas forward purchase and sale contracts. Net Income included $30 million of favourable income tax adjustments resulting from reductions in the Province of Ontario’s corporate income tax rates.

·   Third quarter 2009, Energy’s EBIT included net unrealized gains of $14 million pre-tax ($10 million after tax) due to changes in the fair value of proprietary natural gas inventory in storage and natural gas forward purchase and sale contracts.

·   Second quarter 2009, Energy’s EBIT included net unrealized losses of $7 million pre-tax ($5 million after tax) due to changes in the fair value of proprietary natural gas inventory in storage and natural gas forward purchase and sale contracts. Energy’s EBIT also included contributions from Portlands Energy, which was placed in service in April 2009, and the negative impact of Western Power’s lower overall realized power prices.

·   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 inventory in storage 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 inventory in storage and natural gas forward purchase and sale contracts. Net Income included net unrealized losses of $57 million pre-tax ($39 million after tax) due to changes in the fair value of derivatives used to manage the Company’s exposure to rising interest rates but which did not qualify as hedges for accounting purposes.

TRANSCANADA [27

FIRST QUARTER REPORT 2010

·   Third quarter 2008, Energy’s EBIT included contributions from the August 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 inventory in storage and natural gas forward purchase and sale contracts. In addition, Western Power’s EBIT increased due to higher overall realized prices and market heat rates in Alberta.

EX-13.2

EXHIBIT 13.2

Consolidated Income

(unaudited)	Three months ended March 31
(millions of dollars except number of shares and per share amounts)	2010			2009
Revenues		1,955			2,179
Operating and Other Expenses
Plant operating costs and other		747			832
Commodity purchases resold		256			229
Depreciation and amortization		343			346
		1,346			1,407
Financial Charges/(Income)
Interest expense		182			295
Interest expense of joint ventures		16			14
Interest income and other		(24	)		(22	)
		174			287
Income before Income Taxes and Non-Controlling Interests		435			485
Income Taxes
Current		81			54
Future		20			62
		101			116
Non-Controlling Interests
Non-controlling interest in PipeLines LP		22			24
Preferred share dividends of subsidiary		6			6
Non-controlling interest in Portland		3			5
		31			35
Net Income		303			334
Preferred Share Dividends		7			-
Net Income Applicable to Common Shares		296			334
Net Income Per Share
Basic and Diluted	$	0.43		$	0.54
Average Common Shares Outstanding (millions)
Basic		686			618
Diluted		687			619

See accompanying notes to the consolidated financial statements.

TRANSCANADA [29

FIRST QUARTER REPORT 2010

Consolidated Cash Flows

(unaudited)	Three months ended March 31
(millions of dollars)	2010		2009
Cash Generated From Operations
Net income	303		334
Depreciation and amortization	343		346
Future income taxes	20		62
Non-controlling interests	31		35
Employee future benefits funding in excess of expense	(32	)	(34	)
Other	58		23
	723		766
Decrease in operating working capital	109		82
Net cash provided by operations	832		848
Investing Activities
Capital expenditures	(1,276	)	(1,123	)
Acquisitions, net of cash acquired	-		(134	)
Deferred amounts and other	(216	)	(175	)
Net cash used in investing activities	(1,492	)	(1,432	)
Financing Activities
Dividends on common and preferred shares	(188	)	(156	)
Distributions paid to non-controlling interests	(27	)	(27	)
Notes payable issued/(repaid), net	432		(917	)
Long-term debt issued, net of issue costs	10		3,060
Reduction of long-term debt	(141	)	(482	)
Long-term debt of joint ventures issued	8		16
Reduction of long-term debt of joint ventures	(26	)	(23	)
Common shares issued	9		11
Preferred shares issued, net of issue costs	339		-
Net cash provided by financing activities	416		1,482
Effect of Foreign Exchange Rate Changes on Cash and Cash Equivalents	(17	)	26
(Decrease)/Increase in Cash and Cash Equivalents	(261	)	924
Cash and Cash Equivalents
Beginning of period	997		1,308
Cash and Cash Equivalents
End of period	736		2,232
Supplementary Cash Flow Information
Income taxes paid, net of refunds	4		57
Interest paid	239		263

See accompanying notes to the consolidated financial statements.

TRANSCANADA [30

FIRST QUARTER REPORT 2010

Consolidated Balance Sheet

(unaudited)	March 31,		December 31,
(millions of dollars)	2010		2009
ASSETS
Current Assets
Cash and cash equivalents		736		997
Accounts receivable		912		966
Inventories		463		511
Other		799		701
		2,910		3,175
Plant, Property and Equipment		34,111		32,879
Goodwill		3,645		3,763
Regulatory Assets		1,459		1,524
Intangibles and Other Assets		2,296		2,500
		44,421		43,841
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities
Notes payable		2,087		1,687
Accounts payable		2,605		2,195
Accrued interest		319		377
Current portion of long-term debt		636		478
Current portion of long-term debt of joint ventures		206		212
		5,853		4,949
Regulatory Liabilities		347		385
Deferred Amounts		912		743
Future Income Taxes		2,800		2,856
Long-Term Debt		15,577		16,186
Long-Term Debt of Joint Ventures		725		753
Junior Subordinated Notes		1,005		1,036
		27,219		26,908
Non-Controlling Interests
Non-controlling interest in PipeLines LP		686		705
Preferred shares of subsidiary		389		389
Non-controlling interest in Portland		81		80
		1,156		1,174
Shareholders’ Equity		16,046		15,759
		44,421		43,841

See accompanying notes to the consolidated financial statements.

TRANSCANADA [31

FIRST QUARTER REPORT 2010

Consolidated Comprehensive Income

(unaudited)	Three months ended March 31
(millions of dollars)	2010		2009
Net Income Applicable to Common Shares	296		334
Other Comprehensive (Loss)/Income, Net of Income Taxes
Change in foreign currency translation gains and losses on investments in foreign operations(1)	(147	)	(38	)
Change in gains and losses on hedges of investments in foreign operations(2)	59		-
Change in gains and losses on derivative instruments designated as cash flow hedges(3)	(77	)	27
Reclassification to net income of gains and losses on derivative instruments designated as cash flow hedges pertaining to prior periods(4)	1		4
Other Comprehensive (Loss)/Income	(164	)	(7	)
Comprehensive Income	132		327

(1)   Net of income tax expense of $30 million for the three months ended March 31, 2010 (2009 - $6 million recovery).

(2)   Net of income tax expense of $26 million for the three months ended March 31, 2010 (2009 - $4 million expense).

(3)   Net of income tax recovery of $57 million for the three months ended March 31, 2010 (2009 - $3 million recovery).

(4)   Net of income tax expense of $1 million for the three months ended March 31, 2010 (2009 - $1 million expense).

See accompanying notes to the consolidated financial statements.

TRANSCANADA [32

FIRST QUARTER REPORT 2010

Consolidated Accumulated Other Comprehensive (Loss)/Income

	Currency
(unaudited)	Translation			Cash Flow
(millions of dollars)	Adjustments			Hedges			Total
Balance at December 31, 2009		(592	)		(40	)		(632	)
Change in foreign currency translation gains and losses on investments in foreign operations(1)		(147	)		-			(147	)
Change in gains and losses on hedges of investments in foreign operations(2)		59			-			59
Change in gains and losses on derivative instruments designated as cash flow hedges(3)		-			(77	)		(77	)
Reclassification to net income of gains and losses on derivative instruments designated as cash flow hedges pertaining to prior periods(4)(5)		-			1			1
Balance at March 31, 2010		(680	)		(116	)		(796	)
Balance at December 31, 2008		(379	)		(93	)		(472	)
Change in foreign currency translation gains and losses on investments in foreign operations(1)		(38	)		-			(38	)
Change in gains and losses on hedges of investments in foreign operations(2)		-			-			-
Changes in gains and losses on derivative instruments designated as cash flow hedges(3)		-			27			27
Reclassification to net income of gains and losses on derivative instruments designated as cash flow hedges pertaining to prior periods(4)		-			4			4
Balance at March 31, 2009		(417	)		(62	)		(479	)

(1)   Net of income tax expense of $30 million for the three months ended March 31, 2010 (2009 - $6 million recovery).

(2)   Net of income tax expense of $26 million for the three months ended March 31, 2010 (2009 - $4 million expense).

(3)   Net of income tax recovery of $57 million for the three months ended March 31, 2010 (2009 - $3 million recovery).

(4)   Net of income tax expense of $1 million for the three months ended March 31, 2010 (2009 - $1 million expense).

(5)   Losses related to cash flow hedges reported in Accumulated Other Comprehensive (Loss)/Income and expected to be reclassified to Net Income in the next 12 months are estimated to be $68 million ($35 million, net of tax). These estimates assume constant commodity prices, interest rates and foreign exchange rates over time, however, the amounts reclassified will vary based on the actual value of these factors at the date of settlement.

See accompanying notes to the consolidated financial statements.

TRANSCANADA [33

FIRST QUARTER REPORT 2010

Consolidated Shareholders’ Equity

(unaudited)	Three months ended March 31
(millions of dollars)	2010		2009
Common Shares
Balance at beginning of period	11,338		9,264
Shares issued under dividend reinvestment plan	78		67
Proceeds from shares issued on exercise of stock options	9		11
Balance at end of period	11,425		9,342
Preferred Shares
Balance at beginning of period	539			-
Proceeds from shares issued under public offering, net of issue costs	342			-
Balance at end of period	881			-
Contributed Surplus
Balance at beginning of period	328		279
Issuance of stock options	1		-
Balance at end of period	329		279
Retained Earnings
Balance at beginning of period	4,186		3,827
Net income	303		334
Common share dividends	(275	)	(236	)
Preferred share dividends	(7	)	-
Balance at end of period	4,207		3,925
Accumulated Other Comprehensive (Loss)/Income
Balance at beginning of period	(632	)	(472	)
Other comprehensive (loss)/income	(164	)	(7	)
Balance at end of period	(796	)	(479	)
	3,411		3,446
Total Shareholders’ Equity	16,046		13,067

See accompanying notes to the consolidated financial statements.

TRANSCANADA [34

FIRST QUARTER REPORT 2010

Notes to Consolidated Financial Statements

(Unaudited)

1.   Significant Accounting Policies

The consolidated financial statements of TransCanada Corporation (TransCanada or the Company) have been prepared in accordance with Canadian generally accepted accounting principles (GAAP). The accounting policies applied are consistent with those outlined in TransCanada's annual audited Consolidated Financial Statements for the year ended December 31, 2009. These Consolidated Financial Statements reflect all normal recurring adjustments that are, in the opinion of management, necessary to present fairly the financial position and results of operations for the respective periods. These Consolidated Financial Statements do not include all disclosures required in the annual financial statements and should be read in conjunction with the 2009 audited Consolidated Financial Statements included in TransCanada’s 2009 Annual Report. Unl ess otherwise indicated, “TransCanada“ or “the Company“ includes TransCanada Corporation and its subsidiaries. Amounts are stated in Canadian dollars unless otherwise indicated. Certain comparative figures have been reclassified to conform with the current year’s presentation.

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.

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, capacity payments, planned and unplanned plant outages, acquisitions and divestitures, certain fair value adjustments and developments outside of the normal course of operations.

In preparing these financial statements, 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. In the opinion of management, these consolidated financial statements have been properly prepared within reasonable limits of materiality and within the framework of the Company’s significant accounting policies.

2.   Changes in Accounting Policies

The Company’s accounting policies have not changed materially from those described in TransCanada’s 2009 Annual Report. Future accounting changes that will impact the Company are as follows:

TRANSCANADA [35

FIRST QUARTER REPORT 2010

Future Accounting Changes

International Financial Reporting Standards

The Canadian Institute of Chartered Accountants' (CICA) 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. Effective January 1, 2011, the Company will begin reporting under IFRS.

TransCanada currently follows specific accounting policies unique to a rate-regulated business. The Company 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 Company’s IFRS project and on TransCanada’s IFRS financial results. The Company is assessing the impact of developments related to the IASB’s July 2009 Exposure Draft ‘‘Rate-Regulated Activities’’.

As a result of ongoing developments related to rate-regulated accounting under IFRS as well as other areas, together with the current stage of the Company’s IFRS project, TransCanada cannot reasonably quantify the full impact that adopting IFRS will have on its financial position and future results.

3.   Segmented Information

Three months ended March 31	Pipelines				Energy(1)				Corporate				Total
(unaudited)(millions of dollars)	2010		2009		2010		2009		2010		2009		2010		2009
Revenues	1,129		1,264		826		915		-		-		1,955		2,179
Plant operating costs and other	(361	)	(393	)	(360	)	(409	)	(26	)	(30	)	(747	)	(832	)
Commodity purchases resold	-		-		(256	)	(229	)	-		-		(256	)	(229	)
Depreciation and amortization	(253	)	(260	)	(90	)	(86	)	-		-		(343	)	(346	)
	515		611		120		191		(26	)	(30	)	609		772
Interest expense													(182	)	(295	)
Interest expense of joint ventures													(16	)	(14	)
Interest income and other													24		22
Income taxes													(101	)	(116	)
Non-controlling interests													(31	)	(35	)
Net Income													303		334
Preferred share dividends													(7	)	-
Net Income Applicable to Common Shares													296		334

(1)   Effective January 1, 2010, the Company records net realized and unrealized gains and losses on derivatives used to purchase and sell power, natural gas and fuel oil in order to manage Energy’s assets on a net basis in Revenues.  Comparative results for 2009 reflect amounts reclassified from Commodity Purchases Resold to Revenues.

Total Assets

(unaudited) (millions of dollars)	March 31,  2010	December 31, 2009
Pipelines	29,917	29,508
Energy	12,862	12,477
Corporate	1,642	1,856
	44,421	43,841

TRANSCANADA [36

FIRST QUARTER REPORT 2010

4.   Long-Term Debt

In the three months ended March 31, 2010, the Company capitalized interest related to capital projects of $134 million (2009 - $54 million).

5.   Share Capital

Preferred Share Issue

In March 2010, TransCanada completed a public offering of 14 million Series 3 cumulative redeemable first preferred shares, including the full exercise of an underwriters’ over-allotment option of two million shares, under its September 2009 base shelf prospectus. The preferred shares were issued at $25 per share, resulting in gross proceeds of $350 million including the over-allotment option. The holders of the preferred shares are entitled to receive fixed cumulative dividends at an annual rate of $1.00 per share, payable quarterly, yielding four per cent per annum, for the initial five year period ending June 30, 2015, with the first dividend payment scheduled for June 30, 2010. The dividend rate will reset on June 30, 2015 and every five years thereafter to a yield per annum equal to the sum of the then five year Government o f Canada bond yield and 1.28 per cent. The preferred shares are redeemable by TransCanada on or after June 30, 2015. The net proceeds of this offering are expected to be used to partially fund capital projects, for general corporate purposes and to repay short-term debt.

The Series 3 preferred shareholders will have the right to convert their shares into Series 4 cumulative redeemable first preferred shares on June 30, 2015 and on June 30 of every fifth year thereafter. The holders of Series 4 preferred shares will be entitled to receive quarterly floating rate cumulative dividends at a yield per annum equal to the sum of the then 90 day Government of Canada treasury bill rate and 1.28 per cent.

Dividend Reinvestment and Share Purchase Plan

In the three months ended March 31, 2010, TransCanada issued 2.3 million common shares (2009 – 2.1 million) under its Dividend Reinvestment and Share Purchase Plan (DRP), in lieu of making cash dividend payments totalling $78 million (2009 - $67 million). The dividends under the DRP were paid with common shares issued from treasury.

6.   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 of accounts receivable, the fair value of derivative assets and loans and advances receivable. The carrying amounts and fair values of these financial assets are included in Accounts Receivable and Other in the Non-Derivative Financial Instruments Summary table below. Letters of credit and cash are the primary types of security provided to support these amounts. The majority of counterparty credit exposure is with counterparties who are investment grade. At March 31, 2010, there were no significant amounts past due or impaired.

TRANSCANADA [37

FIRST QUARTER REPORT 2010

At March 31, 2010 the Company had a credit risk concentration of $339 million due from a creditworthy counterparty. This amount is expected to be fully collectible and is secured by a guarantee from the counterparty’s parent company.

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.

Natural Gas Inventory Price Risk

At March 31, 2010, the fair value of proprietary natural gas inventory held in storage, as measured using a weighted average of forward prices for the following four months less selling costs, was $54 million (December 31, 2009 - $73 million). The change in fair value of proprietary natural gas inventory in storage in the three months ended March 31, 2010 resulted in a net pre-tax unrealized loss of $24 million (2009 - loss of $23 million), which was recorded as a decrease to Revenues and Inventories. The net change in fair value of natural gas forward purchase and sale contracts in the three months ended March 31, 2010 resulted in a net pre-tax unrealized gain of $3 million (2009 - gain of $10 million), which was recorded as an increase to Revenues.

VaR Analysis

TransCanada uses a Value-at-Risk (VaR) methodology to estimate the potential impact from its exposure to market risk on its open liquid positions. VaR represents the potential change in pre-tax earnings over a given holding period. It is calculated assuming a 95 per cent confidence level that the daily change resulting from normal market fluctuations in its open positions will not exceed the reported VaR. Although losses are not expected to exceed the statistically estimated VaR on 95 per cent of occasions, losses on the other five per cent of occasions could be substantially greater than the estimated VaR. TransCanada’s consolidated VaR was $6 million at March 31, 2010 (December 31, 2009 – $12 million). The decrease from December 31, 2009 was primarily due to decreased prices and lower open positions in the U.S. Power port folio.

Net Investment in Self-Sustaining Foreign Operations

The Company hedges its net investment in self-sustaining foreign operations (on an after-tax basis) with U.S. dollar-denominated debt, cross-currency interest rate swaps, forward foreign exchange contracts and foreign exchange options. At March 31, 2010, the Company had designated as a net investment hedge U.S. dollar-denominated debt with a carrying value of $7.7 billion (US$7.6 billion) and a fair value of $8.0 billion (US$7.9 billion). At March 31, 2010, $158 million (December 31, 2009 - $96 million) was included in Intangibles and Other Assets for the fair value of forwards and swaps used to hedge the Company’s net U.S. dollar investment in foreign operations.

TRANSCANADA [38

FIRST QUARTER REPORT 2010

The fair values and notional principal amounts for the derivatives designated as a net investment hedge were as follows:

Derivatives Hedging Net Investment in Self-Sustaining Foreign Operations

	March 31, 2010		December 31, 2009
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 2010 to 2014)	140	U.S. 2,000	86	U.S. 1,850
U.S. dollar forward foreign exchange contracts
(maturing 2010)	18	U.S. 1,030	9	U.S. 765
U.S. dollar options
(matured 2010)	-	-	1	U.S. 100
	158	U.S. 3,030	96	U.S. 2,715

(1)   Fair values equal carrying values.

Non-Derivative Financial Instruments Summary

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

	March 31, 2010		December 31, 2009
(unaudited) (millions of dollars)	Carrying Amount	Fair Value	Carrying Amount	Fair Value
Financial Assets(1)
Cash and cash equivalents	736	736	997	997
Accounts receivable and other(2)(3)	1,363	1,402	1,432	1,483
Available-for-sale assets(2)	22	22	23	23
	2,121	2,160	2,452	2,503
Financial Liabilities(1)(3)
Notes payable	2,087	2,087	1,687	1,687
Accounts payable and deferred amounts(4)	1,638	1,638	1,538	1,538
Accrued interest	319	319	377	377
Long-term debt	16,213	19,208	16,664	19,377
Junior subordinated notes	1,005	987	1,036	976
Long-term debt of joint ventures	931	1,000	965	1,025
	22,193	25,239	22,267	24,980

(1)   Consolidated Net Income in first quarter 2010 included losses of $7 million (2009 – losses of $14 million) for fair value adjustments related to interest rate swap agreements on US$250 million (2009 – US$200 million) of long-term debt. There were no other unrealized gains or losses from fair value adjustments to the financial instruments.

(2)   At March 31, 2010, the Consolidated Balance Sheet included financial assets of $912 million (December 31, 2009 – $966 million) in Accounts Receivable, $40 million in Other Current Assets (December 31, 2009 – nil) and $433 million (December 31, 2009 - $489 million) in Intangibles and Other Assets.

(3)   Recorded at amortized cost, except for certain long-term debt which is adjusted to fair value.

(4)   At March 31, 2010, the Consolidated Balance Sheet included financial liabilities of $1,612 million (December 31, 2009 – $1,513 million) in Accounts Payable and $26 million (December 31, 2009 - $25 million) in Deferred Amounts.

TRANSCANADA [39

FIRST QUARTER REPORT 2010

Derivative Financial Instruments Summary

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

March 31, 2010
(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	$319			$178			-		$1			$26
Liabilities	$(251	)		$(182	)		-		$(12	)		$(73	)
Notional Values
Volumes(3)
Purchases	16,661			112			-		-			-
Sales	17,657			99			-		-			-
Canadian dollars	-			-			-		-			838
U.S. dollars	-			-			-		U.S. 612			U.S. 1,500
Cross-currency	-			-			-	47/U.S. 37				-
Net unrealized (losses)/gains in the three months ended March 31, 2010(4)	$(16	)		$2			-		-			$(4	)
Net realized gains/(losses) in the three months ended March 31, 2010(4)	$22			$(12	)		-		$8			$(4	)
Maturity dates	2010-2015		2010-2014			2010			2010-2012		2010-2018
Derivative Financial Instruments in Hedging Relationships(5)(6)
Fair Values(2)
Assets	$191			-			-		-			$10
Liabilities	$(313	)		$(53	)		-		$(48	)		$(44	)
Notional Values
Volumes(3)
Purchases	15,819			31			-		-			-
Sales	12,385			-			-		-			-
U.S. dollars	-			-			-		U.S. 120			U.S. 2,075
Cross-currency	-			-			-	136/U.S. 100				-
Net realized losses in the three months ended March 31, 2010(4)	$(7	)		$(3	)		-		-			$(10	)
Maturity dates	2010-2015			2010-2012			n/a		2010- 2014			2010-2020

(1)   All derivative financial instruments in the held-for-trading classification have been entered into for risk management 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.

(2)   Fair values equal carrying values.

(3)   Volumes for power, natural gas and oil products derivatives are in GWh, billion cubic feet (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 $7 million and a notional amount of US$150 million. Net realized gains on fair value hedges for the three months ended March 31, 2010 were $1 million and were included in Interest Expense. In first quarter 2010, 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, 2010 included losses of $8 million for changes in the 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, 2010 for discontinued cash flow hedges. No amounts have been excluded from the assessment of hedge effectiveness.

TRANSCANADA [40

FIRST QUARTER REPORT 2010

2009
(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)(2)
Assets	$150		$107		$5			-			$25
Liabilities	$(98	)	$(112	)	$(5	)		$(66	)		$(68	)
Notional Values(2)
Volumes(3)
Purchases	15,275		238		180			-			-
Sales	13,185		194		180			-			-
Canadian dollars	-		-		-			-			574
U.S. dollars	-		-		-			U.S. 444		U.S. 1,325
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(2)	2010-2015		2010-2014		2010			2010-2012			2010-2018
Derivative Financial Instruments in Hedging Relationships(5)(6)
Fair Values(1)(2)
Assets	$175		$2		-			-			$15
Liabilities	$(148	)	$(22	)	-			$(43	)		$(50	)
Notional Values(2)
Volumes(3)
Purchases	13,641		33		-			-			-
Sales	14,311		-		-			-			-
U.S. dollars	-		-		-			U.S. 120		U.S. 1,825
Cross-currency	-		-		-		136/ U.S. 100				-
Net realized gains/(losses) in the three months ended March 31, 2009(4)	$26		$(10	)	-			-			$(7	)
Maturity dates(2)	2010-2015		2010-2014		n/a			2010-2014			2010-2020

(1)   Fair values equal carrying values.

(2)   As at December 31, 2009.

(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 $4 million and a notional amount of US$150 million at December 31, 2009. 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 changes in the 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.

TRANSCANADA [41

FIRST QUARTER REPORT 2010

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, 2010			December 31, 2009
Current
Other current assets		460			315
Accounts payable		(538	)		(340	)
Long-term
Intangibles and other assets		423			260
Deferred amounts		(438	)		(272	)

Fair Value Hierarchy

The Company’s financial assets and liabilities recorded at fair value have been categorized into three categories based on a fair value hierarchy. Fair value of assets and liabilities included in Level I is determined by reference to quoted prices in active markets for identical assets and liabilities. Assets and liabilities in Level II include valuations using inputs other than quoted prices for which all significant outputs are observable, either directly or indirectly. This category includes fair value determined using valuation techniques, such as option pricing models and extrapolation using observable inputs. Level III valuations are based on inputs that are not readily observable and are significant to the overall fair value measurement. Long-dated commodity transactions in certain markets and the fair value of guarantees are included in this category. Long-dated commodity prices are derived with a third-party modelling tool that uses market fundamentals to derive long-term prices. The fair value of guarantees is estimated by discounting the cash flows that would be incurred if letters of credit were used in place of the guarantees.

Financial assets and liabilities measured at fair value as of March 31, 2010, including both current and non-current portions, are categorized as follows. There were no transfers between Level I and Level II in first quarter 2010.

(unaudited) (millions of dollars, pre-tax)	Quoted Prices in Active Markets (Level I)		Significant Other Observable Inputs (Level II)		Significant Unobservable Inputs (Level III)		Total
Natural Gas Inventory	-		54		-		54
Derivative Financial Instruments:
Assets	137		742		19		898
Liabilities	(205	)	(762	)	(24	)	(991	)
Available-for-sale assets	22		-		-		22
Guarantee Liabilities(1)	-		-		(9	)	(9	)
	(46	)	34		(14	)	(26	)

(1)   The fair value of guarantees is included in Deferred Amounts.

TRANSCANADA [42

FIRST QUARTER REPORT 2010

The following table presents the net change in financial assets and liabilities measured at fair value and included in the Level III fair value category:

(unaudited)
(millions of dollars, pre-tax)	Derivatives(1)		Guarantees(2)		Total
Balance at December 31, 2009	(2	)	(9	)	(11	)
New contracts(3)	(10	)	-		(10	)
Settlements	(1	)	-		(1	)
Transfers out of Level III	(5	)	-		(5	)
Change in unrealized gains recorded in Net Income	5		-		5
Change in unrealized gains recorded in Other Comprehensive Income	8		-		8
Balance at March 31, 2010	(5	)	(9	)	(14	)

(1)   The fair value of derivative assets and liabilities is presented on a net basis.

(2)   The fair value of guarantees is included in Deferred Amounts. No amounts were recognized in Net Income for the periods presented.

(3)   The total amount of net losses included in Net Income attributable to derivatives that were entered into during the period and still held at the reporting date is $1 million for the three months ended March 31, 2010.

A 10 per cent increase or 10 per cent decrease in commodity prices, with all other variables held constant, would cause a $20 million decrease or a $20 million increase, respectively, in the fair value of derivative financial instruments included in Level III and outstanding as at March 31, 2010.

A 100 basis points increase or 100 basis points decrease in the letter of credit rate, with all other variables held constant, would cause a $5 million increase or a $5 million decrease, respectively, in the fair value of guarantee liabilities outstanding as at March 31, 2010. Similarly, the effect of a 100 basis points increase or 100 basis points decrease in the discount rate on the fair value of guarantee liabilities outstanding as at March 31, 2010 would cause a $1 million decrease in the liability or a $1 million increase in the liability, respectively.

7.   Employee Future Benefits

The net benefit plan expense for the Company’s defined benefit pension plans and other post-employment benefit plans is as follows:

Three months ended March 31	Pension Benefit Plans				Other Benefit Plans
(unaudited)(millions of dollars)	2010		2009		2010	2009
Current service cost	12		11		-	-
Interest cost	23		23		2	2
Expected return on plan assets	(27	)	(25	)	-	-
Amortization of net actuarial loss	2		1		-	-
Amortization of past service costs	1		1		-	-
Net benefit cost recognized	11		11		2	2

8.   Contingencies

Amounts received under the Bruce B floor price mechanism in any year are subject to repayment if spot prices exceed the floor price. With respect to 2010, TransCanada currently expects spot prices to be less than the floor price for the remainder of the year, therefore, no amounts recorded in revenues in the first three months of 2010 are expected to be repaid.

TRANSCANADA [43

FIRST QUARTER REPORT 2010

9.   Subsequent Events

Subsequent events have been assessed up to April 29, 2010, which is the date the financial statements were available for issuance.

   TransCanada welcomes questions from shareholders and potential investors. Please telephone:

Investor Relations, at (800) 361-6522 (Canada and U.S. Mainland) or direct dial David Moneta/Myles Dougan/Terry Hook at (403) 920-7911. The investor fax line is (403) 920-2457. Media Relations: Terry Cunha/Cecily Dobson

(403) 920-7859 or (800) 608-7859.

Visit the TransCanada website at: http://www.transcanada.com.

EX-13.3

EXHIBIT 13.3

TRANSCANADA CORPORATION

RECONCILIATION TO UNITED STATES GAAP

March 31, 2010

TRANSCANADA CORPORATION

RECONCILIATION TO UNITED STATES GAAP

The unaudited consolidated financial statements of TransCanada Corporation (TransCanada or the Company) for the three months ended March 31, 2010 have been prepared in accordance with Canadian generally accepted accounting principles (GAAP), which in some respects, differ from United States (U.S.) GAAP.

The effects of significant differences between Canadian and U.S. GAAP on the Company’s consolidated financial statements for the three months ended March 31, 2010 are described below and should be read in conjunction with TransCanada’s audited consolidated financial statements for the year ended December 31, 2009, and TransCanada’s U.S. GAAP reconciliation for the year ended December 31, 2009 and TransCanada’s unaudited consolidated financial statements for the three months ended March 31, 2010 prepared in accordance with Canadian GAAP.

Reconciliation of Net Income and Comprehensive Income

(unaudited)	Three months ended March 31
(millions of dollars, except per share amounts)	2010			2009
Net Income in Accordance with Canadian GAAP		303			334
U.S. GAAP adjustments:
Net income attributable to non-controlling interests(1)		31			35
Unrealized loss on natural gas inventory held in storage(2)		24			23
Tax impact of unrealized loss on natural gas inventory held in storage		(7	)		(7	)
Tax expense due to a change in tax legislation substantively enacted in Canada(3)		(2	)		(1	)
Net Income in Accordance with U.S. GAAP		349			384
Less: net income attributable to non-controlling interests(1)		(31	)		(35	)
Less: preferred share dividends		(7	)		-
Net Income Attributable to Common Shareholders in Accordance with U.S. GAAP		311			349
Other Comprehensive (Loss)/Income in Accordance with Canadian GAAP		(164	)		(7	)
U.S. GAAP adjustments:
Change in funded status of postretirement plan liability(4)		1			1
Change in equity investment funded status of postretirement plan liability(4)		2			1
Tax impact of change in equity investment funded status of postretirement plan liability		(1	)		-
Comprehensive Income in Accordance with U.S. GAAP		149			344
Net Income Per Share in Accordance with U.S. GAAP,  Basic and Diluted	$	0.45		$	0.56

Page 2

Condensed Balance Sheet in Accordance with U.S. GAAP

(unaudited) (millions of dollars)	March 31, 2010			December 31, 2009
Current assets(2)		2,496			2,634
Long-term investments(4)(5)		4,929			4,873
Plant, property and equipment		28,852			27,695
Goodwill		3,530			3,644
Regulatory assets(4)		1,468			1,675
Intangibles and other assets (4)(6)		1,964			2,041
		43,239			42,562
Current liabilities(3)		5,377			4,471
Deferred amounts(4)(5)		1,157			899
Regulatory liabilities		299			381
Deferred income taxes(2)(4)		2,754			2,802
Long-term debt and junior subordinated notes(6)		16,692			17,335
		26,279			25,888
Shareholders’ equity:
Common shares		11,425			11,338
Preferred shares		881			539
Non-controlling interests(1)		1,156			1,174
Contributed surplus(7)		347			346
Retained earnings(2)(3)(7)		4,185			4,149
Accumulated other comprehensive (loss)/income(4)(8)		(1,034	)		(872	)
		16,960			16,674
		43,239			42,562

(1)   As required by U.S. GAAP, Non-Controlling Interests is presented in the Equity section on the Balance Sheet and on the Income Statement, Consolidated Net Income includes both the Company’s and the Non-Controlling Interests’ share of Net Income.

(2)   In accordance with Canadian GAAP, natural gas inventory held in storage is recorded at its fair value. Under U.S. GAAP, inventory is recorded at lower of cost or market.

(3)   In accordance with Canadian GAAP, the Company recorded current income tax benefits resulting from substantively enacted Canadian federal income tax legislation. Under U.S. GAAP, the legislation must be fully enacted for income tax adjustments to be recorded.

(4)   Represents the amortization of net loss and prior service cost amounts recorded in Accumulated Other Comprehensive (Loss)/Income (AOCI) for the Company’s defined benefit pension and other postretirement plans that have been previously recorded under U.S. GAAP.

(5)   Under Canadian GAAP, the Company accounts for certain investments using the proportionate consolidation basis whereby the Company’s proportionate share of assets, liabilities, revenues, expenses and cash flows are included in the Company’s financial statements.  U.S. GAAP does not allow the use of proportionate consolidation and requires that such investments be recorded on an equity accounting basis.  Information on the balances that have been proportionately consolidated is located in Note 8 to the Company’s Canadian GAAP audited consolidated financial statements for the year ended December 31, 2009.  As a consequence of using equity accounting for U.S. GAAP, the Company is required to reflect an additional liability of $318 million at March 31, 2010 (December 31, 2009 - $261 million) for the estimated fair value of certain guarantees related to debt and other performance commitments of the joint venture operations that were not required to be recorded when the underlying liability was reflected on the balance sheet under the proportionate consolidation method of accounting.

(6)   In accordance with U.S. GAAP, debt issue costs are recorded as a deferred asset rather than being included in Long-Term Debt as required by Canadian GAAP.

(7)   TC Pipelines, LP issued equity in 2009, resulting in an $18 million dilution gain after tax to the Company.  Under U.S. GAAP, the dilution gain is accounted for as an equity transaction although under Canadian GAAP, it is included in Net Income.

(8)   At March 31, 2010, AOCI in accordance with U.S. GAAP is $238 million higher than under Canadian GAAP.  The difference relates to the accounting treatment for defined benefit pension and other postretirement plans.

Page 3

Hedging Instruments and Activities

U.S. GAAP disclosures regarding derivatives are intended to provide additional information about the effect derivatives and hedging activities have on an entity’s financial position, financial performance and cash flows.  Much of the disclosure is provided in the Company’s consolidated financial statements at March 31, 2010 and December 31, 2009 prepared under Canadian GAAP.  Additional required information is provided below.

Derivatives in Cash Flow and Net Investment Hedging Relationships

Three months ended March 31, 2010	Cash Flow Hedges											Net Investment Hedges
(unaudited) (millions of dollars, pre-tax)	Power			Natural Gas			Foreign Exchange		Interest			Foreign Exchange
Amount of (losses)/gains recognized in OCI on derivative (effective portion)		(98	)		(36	)		13		(13	)		85
Amount of (losses)/gains reclassified from AOCI into income (effective portion)		(12	)		1			-		13			-	(1)
Amount of (losses)/gains recognized in income on derivative (ineffective portion and amount excluded from effectiveness testing)		(8	)		-			-		-			-	(2)

Three months ended March 31, 2009	Cash Flow Hedges											Net Investment Hedges
(unaudited) (millions of dollars, pre-tax)	Power			Natural Gas			Foreign Exchange		Interest			Foreign Exchange
Amount of (losses)/gains recognized in OCI on derivative (effective portion)		(39	)		(13	)		4		(5	)		4
Amount of gains/(losses) reclassified from AOCI into income (effective portion)		2			(7	)		-		9			-	(1)
Amount of gains/(losses) recognized in income on derivative (ineffective portion and amount excluded from effectiveness testing)		4			1			-		-			-	(2)

(1)   Location of gains/(losses) is Gains/(Losses) on Sale of Subsidiary

(2)   Location of gains/(losses) is Other Income/(Expense)

Derivative contracts entered into to manage market risk often contain financial assurances provisions that allow parties to the contracts to manage credit risk.  These provisions may require collateral to be provided if a credit-risk-related contingent event occurs, such as a downgrade in the Company’s credit rating to non-investment grade.  Based on contracts in place and market prices at March 31, 2010, the aggregate fair value of all derivative instruments with credit-risk-related contingent features that are in a net liability position is $177 million, which is recorded on the Company’s Consolidated Balance Sheet at March 31, 2010.  The Company has provided collateral on these derivative instruments of $34 million in the normal course of business.  If the credit-risk-related conti ngent features in these agreements were triggered on March 31, 2010, the Company would have been required to provide additional collateral of $143 million to its counterparties.  Collateral may also need to be provided should the fair value of derivative instruments exceed pre-defined contractual exposure limit thresholds.  The Company has sufficient liquidity in the form of cash and undrawn committed revolving bank lines to meet its contingent obligations should they arise.

Page 4

Other Fair Value Measurements

Note 18 to the Company’s 2009 audited consolidated annual financial statements at December 31, 2009, prepared under Canadian GAAP, contains fair value hierarchy information with respect to financial assets and liabilities.   Other liabilities, measured at fair value on a recurring basis, are classified in the Level III fair value category as follows:

	Three Months Ended March 31, 2010
(unaudited) (millions of dollars, pre-tax)	Asset Retirement Obligations(1)			Guarantees(2)
Balance, opening		(111	)		(270	)
Accretion		(2	)		-
Total realized and unrealized losses included in Balance Sheet		-			(64	)
New contracts entered into during the period		-			(9	)
Contracts settled during the period		-			16
Balance, closing		(113	)		(327	)

 (1) The fair value of asset retirement obligations is recognized in Plant, Property and Equipment with offsetting amounts in Accounts Payable and Deferred Amounts.  The fair value is calculated by discounting the estimated cash flows required to settle the asset retirement obligations.

  (2) The fair value of guarantees is recognized in Long-Term Investments and Deferred Amounts.  No amounts were recognized in earnings for the period.

Income Taxes

At March 31, 2010, the total unrecognized tax benefit of uncertain tax positions is approximately $55 million (December 31, 2009 - $55 million). TransCanada’s continuing practice is to recognize interest and penalties related to income tax uncertainties in income tax expense.  Included in net tax expense for the three month period ended March 31, 2010 is $1 million of interest expense and nil for penalties (March 31, 2009 - $2 million for interest expense and nil for penalties). At March 31, 2010, the Company had $17 million accrued for interest and nil accrued for penalties (December 31, 2009 - $16 million accrued for interest and nil accrued for penalties).

TransCanada expects the enactment of certain Canadian Federal tax legislation in the next twelve months.  This legislation will result in a favourable income tax adjustment of approximately $14 million.  Otherwise, subject to the results of audit examinations by taxing authorities and other legislative amendments, TransCanada does not anticipate further adjustments to the unrecognized tax benefits during the next twelve months that would have a material impact on its financial statements.

Changes in Accounting Policies

In January 2010, Financial Accounting Standards Board issued new guidance on “Fair Value Measurements and Disclosures” which requires further disclosures with respect to recurring or nonrecurring fair value measurements.  The Company adopted the required disclosures for fiscal years ending after December 15, 2009. For interim periods beginning after December 15, 2010, the guidance requires disclosure of activity in Level III including purchases, sales, issuances and settlements on a gross basis. The Company will adopt these standards for its 2010 year-end reporting by expanding its disclosure.

Page 5

EX-31.1

EXHIBIT 31.1

Certifications

I, Harold N. Kvisle, certify that:

1.         I have reviewed this quarterly report on Form 6-K of TransCanada Corporation;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the issuer as of, and for, the periods presented in this report;

4. The issuer’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the issuer and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the issuer, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the issuer’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the issuer’s internal control over financial reporting that occurred during the issuer’s most recent fiscal quarter (the issuer’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the issuer’s internal control over financial reporting; and

5. The issuer’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the issuer’s auditors and the audit committee of the issuer’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the issuer’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the issuer’s internal control over financial reporting.

Dated:	April 30, 2010	/s/ Harold N. Kvisle
		Harold N. Kvisle
		President and Chief Executive Officer

EX-31.2

EXHIBIT 31.2

Certifications

I, Gregory A. Lohnes, certify that:

1.	I have reviewed this quarterly report on Form 6-K of TransCanada Corporation;
2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the issuer as of, and for, the periods presented in this report;
4.	The issuer’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the issuer and have:
	(a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the issuer, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
	(b)	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
	(c)	Evaluated the effectiveness of the issuer’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
	(d)	Disclosed in this report any change in the issuer’s internal control over financial reporting that occurred during the issuer’s most recent fiscal quarter (the issuer’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the issuer’s internal control over financial reporting; and
5.	The issuer’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the issuer’s auditors and the audit committee of the issuer’s board of directors (or persons performing the equivalent functions):
	(a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the issuer’s ability to record, process, summarize and report financial information; and
	(b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the issuer’s internal control over financial reporting.

Dated:	April 30, 2010	/s/ Gregory A. Lohnes
		Gregory A. Lohnes
		Executive Vice-President and Chief Financial Officer

EX-32.1

EXHIBIT 32.1

TRANSCANADA CORPORATION

450 – 1st Street S.W.

Calgary, Alberta, Canada

T2P 5H1

CERTIFICATION OF CHIEF EXECUTIVE OFFICER

REGARDING PERIODIC REPORT CONTAINING

FINANCIAL STATEMENTS

I, Harold N. Kvisle, the Chief Executive Officer of TransCanada Corporation (the “Company”), in compliance with 18 U.S.C.  Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, hereby certify, in connection with the Company’s Quarterly Report as filed on Form 6-K for the period ended March 31, 2010 with the Securities and Exchange Commission (the “Report”), that:

1.	the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and
2.	the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ Harold N. Kvisle                                                                           

Harold N. Kvisle

Chief Executive Officer

April 30, 2010

EX-32.2

EXHIBIT 32.2

TRANSCANADA CORPORATION

450 – 1st Street S.W.

Calgary, Alberta, Canada

T2P 5H1

CERTIFICATION OF CHIEF FINANCIAL OFFICER

REGARDING PERIODIC REPORT CONTAINING

FINANCIAL STATEMENTS

I, Gregory A. Lohnes, the Chief Financial Officer of TransCanada Corporation (the “Company”), in compliance with 18 U.S.C.  Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, hereby certify, in connection with the Company’s Quarterly Report as filed on Form 6-K for the period ended March 31, 2010 with the Securities and Exchange Commission (the “Report”), that:

1.	the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and
2.	the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ Gregory A. Lohnes                                                                        

Gregory A. Lohnes

Chief Financial Officer

April 30, 2010

EX-99.1

EXHIBIT 99.1

TRANSCANADA CORPORATION – FIRST QUARTER 2010

Quarterly Report to Shareholders

TransCanada Reports First Quarter Comparable Earnings

of $328 Million or $0.48 Per Share,

Invested $1.3 Billion to Advance $22 Billion Capital Program

CALGARY, Alberta – April 30, 2010 – TransCanada Corporation (TSX, NYSE: TRP) (TransCanada or the Company) today announced comparable earnings for first quarter 2010 of $328 million or $0.48 per share. Net income applicable to common shares was $296 million or $0.43 per share. TransCanada’s Board of Directors also declared a quarterly dividend of $0.40 per common share for the quarter ending June 30, 2010, equivalent to $1.60 per share on an annualized basis.

“TransCanada’s pipeline, power and gas storage businesses posted solid results against the backdrop of an economy that is slowly moving toward recovery,” says Hal Kvisle, TransCanada’s president and chief executive officer.  “The company’s disciplined, low-risk approach produced comparable earnings of $328 million – within five per cent of our earnings in the first quarter of last year.  Weaker power prices and higher business development costs associated with advancing the Alaska Pipeline Project contributed to the slightly lower business unit results.  On a per share basis, lower reported earnings were primarily due to an increase in the number of shares outstanding resulting from our prudent approach to financing our unprecedented capital program.”

“TransCanada continues to make excellent progress on an outstanding suite of major projects that are part of our $22 billion capital program,” Kvisle added.  “We look forward to first oil reaching refineries in Wood River and Patoka, Illinois through our Keystone pipeline system in the coming months.  The North Central Corridor gas pipeline is now operating, our Halton Hills generating station is nearing completion and construction is set to begin this summer on our Groundbirch gas pipeline that will bring B.C. shale gas to market.”

“As we invest in the future today, our large scale, long life projects will drive long term growth in earnings and cash flow as they become operational.”

First Quarter Highlights

(All financial figures are unaudited and in Canadian dollars unless noted otherwise)

§   Comparable earnings of $328 million or $0.48 per share

§   Net income applicable to common shares of $296 million or $0.43 per share

§   Common share dividend of $0.40 per share for the quarter ending June 30, 2010

§   Comparable earnings before interest, taxes, depreciation and amortization (EBITDA) of $1,001 million

§   Funds generated from operations of $723 million

§   Invested $1.3 billion to advance unprecedented $22 billion capital program

Comparable earnings for first quarter 2010 were $328 million ($0.48 per share) compared to $343 million ($0.55 per share) in first quarter 2009.  The decrease in comparable earnings was primarily due to lower realized power prices in Western Power, lower earnings from Bruce A as a result of lower volumes and higher operating costs associated with planned and unplanned outages, and higher business development costs on the Alaska pipeline project. Partially offsetting these decreases were higher earnings from U.S. Power relating to higher capacity payments in New York, higher earnings from Natural Gas Storage, earnings from Portlands which was placed in service in April 2009 and lower net interest expense from increased capitalization of interest related to the Company’s large capital growth program.

Comparable earnings in first quarter 2010, on a per share basis, were reduced by the dilutive impact of an 11 per cent increase in the average number of common shares outstanding following the issuance of 58.4 million common shares in second quarter 2009.  Proceeds from this offering were used to partially fund capital growth projects, including the acquisition of additional interests in Keystone, for general corporate purposes and to repay short term debt.  TransCanada’s $22 billion capital program is expected to generate significant cash flow and earnings over the next five years as projects commence operations.

Notable recent developments in Pipelines, Energy and Corporate include:

Pipelines:

§   In March 2010, the National Energy Board of Canada (NEB) approved the Company’s application to construct and operate the Canadian portion of the Keystone Gulf Coast Expansion. It was a significant milestone in advancing the project. The Keystone expansion will be the first pipeline to directly connect a growing and reliable supply of Canadian crude oil to the largest refining market in North America.Shippers have committed crude oil that amounts to 75 per cent of the expansion capacity for an average term of 17 years.  This long term commitment illustrates the value the project has to TransCanada and the overall market.  Facility permits for the U.S. portion of the Keystone expansion are expected by late 2010.

§   Commissioning of the first phase of Keystone, extending from Hardisty, Alberta to Wood River and Patoka, Illinois with an initial capacity of 435,000 barrels per day (Bbl/d) continued in the first quarter of 2010 and it is expected to be placed in service in second quarter 2010.Contracted volumes of 217,500 Bbl/d will increase to 910,000 Bbl/d from 2010 through to 2013 as the Cushing and Gulf Coast phases become operational. Based on these current long-term commitments, TransCanada expects Keystone to generate EBITDA of approximately US$1.2 billion in 2013 - its first full year of commercial operation. If volumes were to increase to 1.1 million Bbl/d, the full commercial design of the system, Keystone would generate annual EBITDA of approximately US$1.5 billion. In the future, Keystone could be economically expanded from 1.1 million Bbl/d to 1.5 milli on Bbl/d to meet market demand.

§   The open season for the Alaska Pipeline Project was launched April 30, 2010. Potential shippers have 90 days to assess the merits of the open season - from May through July 2010. The Alaska Pipeline Project will provide information to potential shippers in Alaska and Canada about the project’s anticipated engineering design, commercial terms, estimated project costs and timelines. It is typical on a project of this size for bids from shippers to be conditional. The Alaska Pipeline Project will work with shippers over the summer and fall to resolve any issues within the project’s control. Other key issues such as Alaska fiscal terms and natural gas resource access at Point Thomson will need to be resolved between shippers and the State of Alaska. The results of the open season are expected to be available near the end of 2010.

§   TransCanada and the other partners involved in the Mackenzie Gas Pipeline Project continue to pursue approval of the proposed project.  The focus is on obtaining regulatory approval and the Canadian government’s support of an acceptable fiscal framework. The NEB recently concluded the final argument hearings for the project and is expected to release its conclusions on the project’s application in September 2010.

§   In March 2010, TransCanada received approval from the NEB to construct and operate the Groundbirch pipeline.  It will be a 77 kilometre (km) (48-mile) natural gas pipeline that will extend the Alberta System, connecting to natural gas supplies in the Montney shale gas formation in northeast B.C. Construction of the Groundbirch pipeline is expected to begin in July 2010 and should be complete by November 2010.  The approximate $200 million project has firm transportation contracts that will reach 1.1 billion cubic feet per day (Bcf/d) by 2014.

§   TransCanada’s Horn River project which includes 72 km (45-mile) of new pipe and the 83 km (52-mile) Ekwan pipeline to be acquired from Encana Corporation will bring B.C. shale gas to market through the Alberta System. The Ekwan pipeline acquisition is expected to close in September 2011. In April 2010, the NEB announced that it will hold a public hearing process on an application TransCanada filed in February 2010 for approval to construct and operate the Horn River project. The public hearing process is scheduled to begin in October 2010. Subject to regulatory approvals, the approximate $310 million Horn River project with commitments for contracted gas of 503 mmcf/d is expected to be operational in s econd quarter 2012.

§   TransCanada’s 160 km (99-mile) Red Earth section of the North Central Corridor (NCC) pipeline is now operating. The 140 km (87-mile) North Star section was completed in 2009, along with two compressor stations. The NCC is a 300 km (186-mile) expansion of the Alberta System that provides needed capacity to accommodate increasing natural gas supply in northwest Alberta and northeast B.C. and growing markets in Alberta. The pipeline will initially move about 800 mmcf/d of gas, with total capability of about 1.6 Bcf/d.  The project was completed ahead of schedule and under budget of approximately $800 million.

§   Bison received its Federal Energy Regulatory Commission certificate of public convenience and necessity on April 9, 2010.  Construction is expected to begin in second quarter 2010 on the 487 km (303-mile) natural gas pipeline that has shipping commitments for approximately 407 mmcf/d of gas.  The approximate US$600 million project is expected to be in service in fourth quarter 2010.

Energy:

§   Construction of the 683 megawatt (MW) Halton Hills Generating Station in Ontario is substantially complete.  Commissioning activities have begun and the facility is on schedule to begin operating in third quarter 2010. The commissioning team has safely used compressed air and nitrogen to blow clean the high pressure pipeline that supplies natural gas to the plant.

§   Construction continues on the 575 MW Coolidge Generating Station. The generating station is anticipated to be in service by the summer of 2011.

§   TransCanada continues to review the results of the open seasons on the proposed Zephyr and Chinook power transmission line projects and expects to finalize those results in second quarter 2010. Each project would be capable of delivering primarily renewable wind-generated power originating in Wyoming (Zephyr) and Montana (Chinook) to Nevada to access California and other desert southwest U.S. markets.

Corporate:

§   On April 15, 2010, Hal Kvisle announced his retirement as president and chief executive officer effective June 30, 2010. Russ Girling, currently chief operating officer, will succeed Mr. Kvisle as president and chief executive officer on July 1, 2010.

§   The Board of Directors of TransCanada declared a quarterly dividend of $0.40 per share for the quarter ending June 30, 2010, on TransCanada’s outstanding common shares.

§   In March 2010, TransCanada completed a public offering of 14 million Series 3 cumulative redeemable first preferred shares, including the full exercise of an underwriters’ over-allotment option of two million shares. The preferred shares were issued at $25 per share, resulting in gross proceeds of $350 million. The initial dividend rate is fixed for five years at four per cent per annum payable quarterly. The net proceeds of this offering were used to partially fund capital projects, for general corporate purposes and to repay short-term debt.

§   TransCanada is well positioned to fund its existing capital program through its growing internally-generated cash flow, its dividend reinvestment and share purchase plan, and its continued access to capital markets. TransCanada will also continue to examine opportunities for portfolio management, including a greater role for TC PipeLines, LP in financing its capital program.

Teleconference – Audio and Slide Presentation:

TransCanada will hold a teleconference and webcast to discuss its 2010 first quarter financial results.  Hal Kvisle, TransCanada president and chief executive officer and Greg Lohnes, executive vice-president and chief financial officer, along with other members of the TransCanada executive leadership team, will discuss the financial results and company developments, including its $22 billion capital program, before opening the call to questions from analysts and members of the media.

Event:

TransCanada first quarter 2010 financial results teleconference and webcast

Date:

Friday, April 30, 2010

Time:

1 p.m. mountain daylight time (MDT) /3 p.m. eastern daylight time (EDT)

How:

To participate in the teleconference, please call 866.223.7781 or 416.340.8018(Toronto area). Please dial in 10 minutes prior to the start of the call. No pass code is required. A live webcast of the teleconference will also be available on TransCanada’s website at www.transcanada.com.

A replay of the teleconference will be available two hours after the conclusion of the call until midnight (EDT) May 7, 2010. Please call 800.408.3053 or 416.695.5800 (Toronto area) and enter pass code 3375460#. The webcast will be archived and available for replay at www.transcanada.com.

With more than 50 years’ experience, TransCanada is a leader in the responsible development and reliable operation of North American energy infrastructure including natural gas and oil pipelines, power generation and gas storage facilities. TransCanada’s network of wholly owned natural gas pipelines extends more than 60,000 kilometres (37,000 miles), tapping into virtually all major gas supply basins in North America. TransCanada is one of the continent’s largest providers of gas storage and related services with approximately 380 billion cubic feet of storage capacity. A growing independent power producer, TransCanada owns, or has interests in, over 11,700 megawatts of power generation in Canada and the United States. TransCanada is developing one of North America’s largest oil delivery systems. TransCanada’ s common shares trade on the Toronto and New York stock exchanges under the symbol TRP. For more information visit: www.transcanada.com

Forward-Looking Information

This news release 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 security holders 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, projects 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, including anticipated construction and completion dates, 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 re gulations, 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 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. Readers are cautioned not to place undue reliance on this forward-looking information, which is given as of the date it is expressed in this news release or otherwise, and not to 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.

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 news release. 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 may not 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 prov ided to readers as additional information on TransCanada’s operating performance, liquidity and ability to generate funds to finance operations.

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

Management uses the measures of comparable earnings, comparable EBITDA and comparable EBIT to better evaluate trends in the Company’s underlying operations. Comparable earnings, comparable EBITDA and comparable EBIT comprise net income applicable to common shares, 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 fa ir value adjustments. The “Consolidated Results of Operations” table in the "Management’s Discussion and Analysis” presents a reconciliation of comparable earnings, comparable EBITDA, comparable EBIT and EBIT to net income and net income applicable to common shares. Comparable earnings per common share is calculated by dividing comparable earnings by the weighted average number of common shares outstanding for the period.

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 First Quarter 2010 Financial Highlights table in this news release.

Media Inquiries:	Cecily Dobson/Terry Cunha	403.920.7859 1.800.608.7859
Analyst Inquiries:	David Moneta/Myler Dougan/Terry Hook	403.920.7911 1.800.361.6522

First Quarter 2010 Financial Highlights

Operating Results

(unaudited)	Three months ended March 31
(millions of dollars)	2010	2009
Revenues	1,955	2,179
Comparable EBITDA(1)	1,001	1,131
Comparable EBIT(1)	658	785
EBIT(1)	609	772
Net Income	303	334
Net Income Applicable to Common Shares	296	334
Comparable Earnings(1)	328	343
Cash Flows
Funds generated from operations(1)	723	766
Decrease in operating working capital	109	82
Net cash provided by operations	832	848
Capital Expenditures	1,276	1,123
Acquisitions, Net of Cash Acquired	-	134

Common Share Statistics

	Three months ended March 31
(unaudited)	2010	2009
Net Income Per Share - Basic	$0.43	$0.54
Comparable Earnings Per Share(1)	$0.48	$0.55
Dividends Declared Per Share	$0.40	$0.38
Basic Common Shares Outstanding (millions)
Average for the period	686	618
End of period	687	619

(1)   Refer to the Non-GAAP Measures section in this news release for further discussion of comparable EBITDA, comparable EBIT, EBIT, comparable earnings, funds generated from operations and comparable earnings per share.

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