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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 2006

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

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): o

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): o

Indicate by check mark whether the registrant by furnishing the information contained in this Form is also thereby furnishing the information to the Commission pursuant to Rule 12g3-2(b) under the Securities Exchange Act of 1934.

Yes

The documents listed below in this Section and filed as Exhibits 13.1 to 13.3 to this Form 6-K are hereby filed with the Securities and Exchange Commission for the purpose of being and hereby are incorporated by reference into the following registration statements filed by TransCanada Corporation under the Securities Act of 1933, as amended.

Form		Registration No.

S-8		33-00958
S-8		333-5916
S-8		333-8470
S-8		333-9130
F-3		33-13564
F-3		333-6132

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, 2006.

13.2 Consolidated comparative interim unaudited financial statements of the registrant for the period ended March 31, 2006 (included in the registrant’s First Quarter 2006 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 2006 Quarterly Report to Shareholders.

The document listed below in this Section is furnished, not filed, as Exhibit 99.1. The Exhibit is being furnished, not filed, and will not be incorporated by reference into any registration statement filed by TransCanada Corporation under the Securities Act of 1933, as amended.

99.1 A copy of the Registrant’s news release of April 28, 2006.

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.

	TRANSCANADA CORPORATION


	By:	/s/ Russell K. Girling
		Russell K. Girling
		Executive Vice-President, Corporate
		Development and Chief Financial Officer


	By:	/s/ Lee G. Hobbs
		Lee G. Hobbs
		Vice-President and Controller

April 28, 2006

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, 2006.

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 28, 2006.

Exhibit 13.1

Management’s Discussion and Analysis

Management’s discussion and analysis (MD&A) dated April 27, 2006 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, 2006. It should also be read in conjunction with the audited consolidated financial statements and the MD&A contained in TransCanada’s 2005 Annual Report for the year ended December 31, 2005. Additional information relating to TransCanada, including the company’s Annual Information Form and continuous disclosure documents, is available on SEDAR at www.sedar.com under TransCanada Corporation. Amounts are stated in Canadian dollars unless otherwise indicated. Capitalized and abbreviated terms that are used but not otherwise defined herein have the meanings given to these terms in the annual MD&A contained in TransCanada’s 2005 Annual Report.

Results of Operations Consolidated

Segment Results-at-a-Glance

Three months ended March 31 (unaudited) (millions of dollars except per share amounts)	2006			2005
Gas Transmission
Excluding gains	168			163
Gain on sale of PipeLines LP units	—			48
	168			211
Power	89			30

Corporate	(12		)	(9		)
Net Income
Continuing operations (1)	245			232
Discontinued operations	28			—
	273			232

Net Income Per Share
Continuing operations (2)	$	0.50		$	0.48
Discontinued operations	0.06			—

Basic and Diluted	$	0.56		$	0.48

(1) Net Income from Continuing Operations is comprised of:
Excluding gains	245		184
Gain on sale of PipeLines LP units	—		48
	245		232
(2) Net Income Per Share from Continuing Operations is comprised of:
Excluding gains	$	0.50	$	0.38
Gain on sale of PipeLines LP units	—		0.10
	$	0.50	$	0.48

TransCanada’s net income for first quarter 2006 was $273 million or $0.56 per share. This includes net and certain of it's subsidiaries income from discontinued operations of $28 million or $0.06 per share, reflecting bankruptcy settlements with Mirant Corporation (Mirant) received in first quarter 2006 related to TransCanada’s Gas Marketing business divested in 2001. Net income for first quarter 2005 was $232 million or $0.48 per share.

TransCanada’s net income from continuing operations (net earnings) for first quarter 2006 of $245 million or $0.50 per share increased by $13 million or $0.02 per share compared to $232 million or $0.48 per share for the same quarter in 2005. The increase was primarily due to significantly higher net earnings from the Power segment, partially offset by a $48 million or $0.10 per share gain on sale of the TC PipeLines, LP (PipeLines LP) units in first quarter 2005. Excluding this gain, the company reported increases in Gas Transmission earnings and Corporate net expenses compared to first quarter 2005.

The increase of $59 million in Power’s net earnings for first quarter 2006 compared to first quarter 2005 was primarily due to higher operating and other income from Bruce Power, Western Operations and Eastern Operations, partially offset by the loss of operating and other income associated with the sale of the Power LP investment in third quarter 2005.

Excluding the gain on sale of PipeLines LP units in first quarter 2005, Gas Transmission’s net earnings for first quarter 2006 increased $5 million primarily due to higher net earnings from GTN as a result of a $29 million bankruptcy settlement ($18 million after tax) with Mirant, a former shipper on the Gas Transmission Northwest System. In addition, TransCanada’s Other Gas Transmission businesses had higher net earnings mainly due to improved natural gas storage net earnings. These increases were partially offset by lower net earnings from the Canadian Mainline and Alberta System, primarily as a result of lower rates of return on common equity (ROE) and lower average investment bases in first quarter 2006 compared to first quarter 2005.

The increase of $3 million in Corporate’s net expenses in first quarter 2006 was primarily due to increased interest costs.

Funds generated from operations of $517 million for first quarter 2006 increased $97 million compared to first quarter 2005.

Forward-Looking Information

Certain information in this MD&A includes forward-looking statements. All forward-looking statements are based on TransCanada’s beliefs and assumptions based on information available at the time the assumptions were made. Forward-looking statements relate to, among other things,

anticipated financial performance, business prospects, strategies, regulatory developments, new services, market forces, commitments and technological developments. By its nature, such forward-looking information is subject to various risks and uncertainties, including those material risks discussed in the MD&A contained in TransCanada’s 2005 Annual Report under “Gas Transmission – Business Risks” and “Power – Business Risks”, which could cause TransCanada’s actual results and experience to differ materially from the anticipated results or other expectations expressed. The material assumptions in making these forward-looking statements are disclosed in this MD&A under the heading “Outlook” and in the MD&A contained in the 2005 Annual Report under the headings “Overview and Strategic Priorities”, “Gas Transmission – Opportunities and Developments”, “Gas Transmission – Outlook”, “Power – Opportunities and Developments” and “Power – Outlook”. 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 TransCanada undertakes no obligation to update publicly or revise any forward-looking information, whether as a result of new information, future events or otherwise.

Gas Transmission

The Gas Transmission business generated net earnings of $168 million for the quarter ended March 31, 2006 compared to $211 million for the same quarter in 2005.

Gas Transmission Results-at-a-Glance

Three months ended March 31 (unaudited) (millions of dollars)	2006		2005
Wholly-Owned Pipelines
Canadian Mainline	59		63
Alberta System	33		37
GTN	32		23
Foothills System	5		5
BC System	2		2
	131		130
Other Gas Transmission
Great Lakes	12		14
Iroquois	4		4
PipeLines LP	1		4
Portland	6		6
Ventures LP	3		3
TQM	2		2
CrossAlta and other natural gas storage	14		5
TransGas	3		3
Northern Development	(1	)	(1	)
General, administrative, support costs and other	(7	)	(7	)
	37		33
Gain on sale of PipeLines LP units	—		48
	37		81
Net Earnings	168		211

Wholly-Owned Pipelines

Canadian Mainline’s first quarter 2006 net earnings of $59 million decreased $4 million compared to first quarter 2005. This decrease was primarily due to a lower ROE, as determined by the National Energy Board (NEB), of 8.88 per cent in 2006 compared to 9.46 per cent in 2005 and a lower average investment base. The net earnings decline related to ROE and average investment base was partially offset by an increase in the deemed common equity ratio from 33 to 36 per cent as determined by the NEB in its decision, released in April 2005, on the Canadian Mainline’s 2004 Tolls and Tariff Application (Phase II).

The Alberta System’s net earnings of $33 million in first quarter 2006 decreased $4 million compared to $37 million in first quarter 2005. The decrease was primarily due to a lower average investment base as well as a lower ROE in 2006 compared to 2005. Net earnings in first quarter 2006 reflected an ROE of 8.93 per cent on deemed common equity of 35 per cent compared to an ROE of 9.50 per cent on deemed common equity of 35 per cent in first quarter 2005.

GTN’s first quarter 2006 net earnings of $32 million were $9 million higher than net earnings for first quarter 2005 primarily due to a $29 million bankruptcy settlement ($18 million after tax) in first quarter 2006 with Mirant, a former shipper on the Gas Transmission Northwest System, partially offset by lower transportation revenues and the impact of a weaker U.S. dollar in first quarter 2006. In addition, first quarter 2005 results included $4 million of net earnings related to the amortization of the fair value adjustment on long-term debt included in the GTN purchase price allocation in late 2004.

Operating Statistics

Three months ended March 31

Canadian
Mainline (1)

Alberta System
(2)

Gas
Transmission
Northwest
System (3)

Foothills
System

BC System

(unaudited)

2006

2005

2006

2005

2006

2005

2006

2005

2006

2005

Average investment base ($millions)

7,471

7,910

4,319

4,559

n/a

n/a

(3)

661

693

209

220

Delivery volumes (Bcf)

Total

829

767

1,062

1,051

171

215

263

287

Average per day

9.2

8.5

11.8

11.7

1.9

2.4

2.9

3.2

0.9

1.1

(1) Canadian Mainline deliveries originating at the Alberta border and in Saskatchewan for the three months ended March 31, 2006 were 584 Bcf (2005 - 531 Bcf); average per day was 6.5 Bcf (2005 - 5.9 Bcf).

(2) Field receipt volumes for the Alberta System for the three months ended March 31, 2006 were 1,021 Bcf (2005 - 965 Bcf); average per day was 11.3 Bcf (2005 - 10.7 Bcf).

(3) The Gas Transmission Northwest System operates under a fixed rate model approved by the United States Federal Energy Regulatory Commission and, as a result, the system’s current results are not dependent on average investment base.

Other Gas Transmission

TransCanada’s proportionate share of net earnings from Other Gas Transmission was $37 million for the three months ended March 31, 2006 compared to $81 million for the same period in 2005. First quarter 2005 results included a $48 million after-tax gain on the sale of PipeLines LP units. Excluding this gain, net earnings for first quarter 2006 increased $4 million compared to the same period in 2005. The increase was mainly due to higher net earnings from CrossAlta as a result of increased capacity and higher natural gas storage spreads, and a contribution from other contracted third party natural gas storage capacity in Alberta. These increases were partially offset by the negative impact of a weaker U.S. dollar in first quarter 2006 and lower net earnings from PipeLines LP due to a lower ownership

interest in 2006.

As at March 31, 2006, TransCanada had advanced $96 million to the Aboriginal Pipeline Group with respect to the Mackenzie Gas Pipeline Project, and had capitalized $21 million of costs related to the Broadwater project and $8 million related to the Keystone pipeline.

Power

Power Results-at-a-Glance

Three months ended March 31 (unaudited) (millions of dollars)	2006		2005
Bruce Power	63		30
Western Operations	58		30
Eastern Operations	49		5
Power LP Investment	—		9
General, administrative, support costs and other	(25	)	(28	)
Operating and other income	145		46
Financial charges	(7	)	(4	)
Interest income and other	2		3
Income taxes	(51	)	(15	)
Net Earnings	89		30

Power’s net earnings of $89 million in first quarter 2006 increased $59 million compared to $30 million reported in first quarter 2005 due to higher operating and other income from Bruce Power, Western Operations and Eastern Operations, partially offset by the loss of operating and other income associated with the sale of the Power LP investment in third quarter 2005.

Bruce Power’s contribution to operating and other income increased $33 million in first quarter 2006 compared to first quarter 2005, primarily due to higher generation volumes, higher overall realized prices and an increased ownership interest in the Bruce A facilities, effective October 31, 2005.

Western Operations’ operating and other income was $28 million higher in first quarter 2006 compared to first quarter 2005 primarily due to incremental earnings from the December 31, 2005 acquisition of the 756 megawatt (MW) Sheerness power purchase arrangement (PPA) and improved margins from higher overall realized power prices and higher market heat rates on uncontracted volumes sold.

Eastern Operations’ operating and other income was $44 million higher in first quarter 2006 compared to first quarter 2005 primarily due to contributions from the TC Hydro generation assets acquired on April 1, 2005, margins earned in 2006 on transportation related to unutilized OSP natural gas fuel and a first quarter 2005 one-time contract restructuring payment from OSP to its natural gas fuel suppliers.

Bruce Power

Effective October 31, 2005, TransCanada increased its interest in the Bruce A units through the formation of the Bruce A partnership. Bruce A subleases its facilities from Bruce B. TransCanada commenced

proportionately consolidating its investments in Bruce A and Bruce B effective October 31, 2005. The following Bruce Power financial results reflect the operations of the full six-unit operation for both periods.

Bruce Power Results-at-a-Glance(1)

Three months ended March 31 (unaudited) (millions of dollars)	2006			2005
Bruce Power (100 per cent basis)
Revenues
Power	479			411
Other (2)	17			7
	496			418
Operating expenses
Operations and maintenance	(220		)	(205		)
Fuel	(20		)	(19		)
Supplemental rent	(43		)	(41		)
Depreciation and amortization	(31		)	(48		)
	(314		)	(313		)
Operating income	182			105
Financial charges under equity accounting	—			(17		)
	182			88

TransCanada’s proportionate share	62			28
Adjustments	1			2
TransCanada’s operating and other income from
Bruce Power(3)	63			30

Bruce Power - Other Information
Plant availability
Bruce A	78		%
Bruce B	95		%
Combined Bruce Power	90		%	81		%
Sales volumes (GWh) (4)
Bruce A - 100 per cent	2,520
Bruce B - 100 per cent	6,620
Combined Bruce Power - 100 per cent	9,140			8,221
TransCanada’s proportionate share	3,306			2,598
Results per MWh (5)
Bruce A revenues	$	57
Bruce B revenues	$	50
Combined Bruce Power revenues	$	52		$	50
Fuel	$	2		$	2
Total operating expenses (6)	$	34		$	38
Percentage of output sold to spot market	38		%	50		%

(1) All information in the table includes adjustments to eliminate the effects of intercompany transactions between Bruce A and Bruce B.

(2) Includes fuel cost recoveries for Bruce A of $6 million for the three months ended March 31, 2006.

(3) TransCanada’s consolidated equity income included $30 million for the three months ended March 31, 2005 representing TransCanada’s 31.6 per cent share of Bruce Power earnings for the period.

(4) Gigawatt hours.

(5) Megawatt hours.

(6) Net of cost recoveries.

TransCanada’s operating and other income of $63 million from its combined investment in Bruce Power increased $33 million in first quarter 2006 compared to first quarter 2005, primarily due to higher generation volumes, higher overall realized prices and an increased ownership interest in the Bruce A facilities, effective October 31, 2005. TransCanada’s share of Bruce Power’s generation for first quarter 2006 increased 708 GWh to 3,306 GWh compared to first quarter 2005 generation of 2,598 GWh as a result of fewer planned maintenance outage days in first quarter 2006 than in first quarter 2005 and an increased ownership interest in the Bruce A facilities.

Bruce Power prices achieved during first quarter 2006 were $52 per MWh, compared to $50 per MWh in first quarter 2005. Bruce Power operating expenses (net of fuel cost recoveries) in first quarter 2006 decreased to $34 per MWh from $38 MWh in first quarter 2005 primarily due to increased output in first quarter 2006 combined with costs incurred in first quarter 2005 related to one additional planned maintenance outage compared to the same quarter in 2006.

Approximately 30 reactor days of planned maintenance outages as well as 13 reactor days of unplanned outages occurred on the six operating units in first quarter 2006. In first quarter 2005, Bruce Power experienced 70 reactor days of planned maintenance outages and 25 reactor days of unplanned outages. The Bruce Power units ran at a combined average availability of 90 per cent in first quarter 2006, compared to an 81 per cent average availability during first quarter 2005.

The overall plant availability percentage in 2006 is still expected to be in the low 90s for the four Bruce B units and in the low 80s for the two operating Bruce A units. A planned one month maintenance outage on Bruce A Unit 3 was completed during first quarter 2006 and a planned two month maintenance outage of Bruce A Unit 4 commenced on April 22, 2006. The only planned maintenance outage for 2006 for Bruce B is an approximate two month outage scheduled for Unit 8 beginning in third quarter 2006.

Income for Bruce B is directly impacted by fluctuations in wholesale spot market prices for electricity. Income from both Bruce A and Bruce B units is impacted by overall plant availability, which in turn is impacted by scheduled and unscheduled maintenance. As a result of the contract with the Ontario Power Authority (OPA), all of the output from Bruce A is sold at a fixed price of $57.37 per MWh (before recovery of fuel costs from the OPA) and sales from the Bruce B Units 5 to 8 are subject to a floor price of $45 per MWh. Both of these reference prices are adjusted annually on April 1 for inflation and other potential adjustments per the terms of the contract with OPA. Effective April 1, 2006, the Bruce A fixed price is $58.63 per MWh and the Bruce B floor price is $45.99 per MWh. To further reduce its

exposure to spot market prices, Bruce B has entered into fixed price sales contracts to sell forward approximately 9,900 GWh of output for the remainder of 2006 and 5,100 GWh of output for 2007.

Bruce A’s capital program for the restart and refurbishment project is expected to total approximately $4.25 billion with TransCanada’s share being approximately $2.125 billion. As at March 31, 2006, Bruce A had incurred $468 million with respect to the restart and refurbishment project.

Western Operations

Western Operations Results-at-a-Glance

Three months ended March 31 (unaudited) (millions of dollars)	2006		2005
Revenue
Power	275		164
Other (1)	64		42
	339		206
Cost of sales
Power	(190	)	(110	)
Other (2)	(48	)	(28	)
	(238	)	(138	)
Other costs and expenses	(38	)	(33	)
Depreciation	(5	)	(5	)

Operating and other income	58		30

(1) Includes Cancarb Thermax and natural gas sales.

(2) Other cost of sales includes the cost of natural gas sold.

Western Operations Sales Volumes

Three months ended March 31 (unaudited) (GWh)	2006	2005
Supply
Generation	585	636
Purchased
Sundance A & B and Sheerness PPAs	3,391	1,831
Other purchases	486	731
	4,462	3,198
Contracted vs. Spot
Contracted	2,022	2,685
Spot	2,440	513
	4,462	3,198

Western Operations’ operating and other income of $58 million in first quarter 2006 was $28 million higher compared to first quarter 2005 primarily due to incremental earnings from the December 31, 2005 acquisition of the 756 MW Sheerness PPA. Operating and other income was also higher due to increased margins in first quarter 2006 compared to first quarter 2005 from higher overall realized power prices and

higher market heat rates on uncontracted volumes of power generated. The market heat rate is determined by dividing the average price of power per MWh by the average price of natural gas per gigajoule (GJ) for a given period. Market heat rates increased by approximately 11 per cent as a result of an approximate 24 per cent ($10.85 per MWh) increase in spot market power prices in first quarter 2006 compared to the same quarter in 2005, while average spot market natural gas prices in Alberta increased by approximately 10 per cent ($0.65 per GJ). A significant portion of power sales volumes were sold into the spot market in first quarter 2006 due to the acquisition of the Sheerness PPA. TransCanada manages the sale of its supply volumes on a portfolio basis. Depending on market conditions, TransCanada will commit a portion of this supply to long-term sales arrangements with the remaining volumes subject to spot market price volatility. This approach to portfolio management assists in minimizing costs in situations where TransCanada would otherwise have to purchase electricity in the open market to fulfill its contractual sales obligations.

Western Operations’ power sales revenues and power cost of sales increased in first quarter 2006 compared to first quarter 2005 primarily due to the acquisition of the Sheerness PPA, effective December 31, 2005, and higher overall realized power prices in first quarter 2006. Generation volumes of 585 GWh in first quarter 2006 decreased 51 GWh compared to first quarter 2005 primarily due to reduced dispatch from the MacKay River facility. The Bear Creek facility is expected to be back in service in mid-2006. Purchased power volumes and the percentage of power volumes sold into the Alberta spot market increased in first quarter 2006 due to the acquisition of the Sheerness PPA. A significant portion of the Sheerness PPA purchased volumes were not sold under contract and were subject to spot market prices. As a result, approximately 55 per cent of power sales volumes were sold into the spot market in first quarter 2006 compared to 16 per cent in first quarter 2005. To reduce its exposure to spot market prices on uncontracted volumes, as at March 31, 2006, Western Operations had fixed price sales contracts to sell approximately 7,800 GWh of power for the remainder of 2006 and approximately 6,000 GWh of power for 2007.

Eastern Operations

Eastern Operations Results-at-a-Glance

Three months ended March 31 (unaudited) (millions of dollars)	2006		2005
Revenue
Power	161		115
Other (1)	117		70
	278		185
Cost of sales
Power	(101	)	(62	)
Other (1)	(96	)	(65	)
	(197	)	(127	)
Other costs and expenses	(25	)	(49	)
Depreciation	(7	)	(4	)

Operating and other income	49		5

(1) Other includes natural gas.

Eastern Operations Sales Volumes

Three months ended March 31 (unaudited) (GWh)	2006	2005
Supply
Generation	705	444
Purchased	730	811
	1,435	1,255
Contracted vs. Spot
Contracted	1,383	1,189
Spot	52	66
	1,435	1,255

Operating and other income in first quarter 2006 from Eastern Operations of $49 million was $44 million higher compared to $5 million in first quarter 2005. The increase was primarily due to incremental income from the TC Hydro generation assets acquired on April 1, 2005, margins earned in 2006 on transportation related to unutilized OSP natural gas fuel and a $16 million pre-tax ($10 million after-tax) first quarter 2005 one-time contract restructuring payment from OSP to its natural gas fuel suppliers.

Generation volumes in first quarter 2006 increased 261 GWh to 705 GWh compared to first quarter 2005 primarily due to the acquisition of the TC Hydro assets. Partially offsetting these increases was reduced generation from the OSP facility due to a mild winter in 2006.

Eastern Operations’ power sales revenues of $161 million increased $46 million in first quarter 2006 primarily due to higher realized prices and higher sales volumes. Power cost of sales of $101 million was higher in first quarter 2006 due to the impact of higher prices for purchased power, partially offset by lower purchased power volumes. Purchased power volumes of 730 GWh were lower in first quarter 2006 compared to first quarter 2005 due to the incremental power generation from the TC Hydro assets. Volumes generated from these hydroelectric assets reduced

the requirement to purchase power to fulfill contractual sales obligations. First quarter 2006 other revenue and other cost of sales of $117 million and $96 million, respectively, increased year-over-year primarily as a result of natural gas purchased and resold under the new natural gas supply contracts at OSP. Other costs and expenses in first quarter 2006 of $25 million, which include fuel gas consumed in generation, decreased from the prior year as the incremental operating costs of the TC Hydro assets were more than offset by a decrease in fuel costs at the OSP facility including the one-time contract restructuring payment of $16 million in first quarter 2005 to its natural gas fuel suppliers.

In first quarter 2006, approximately four per cent of power sales volumes were sold into the spot market compared to approximately five per cent in first quarter 2005. Eastern Operations 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, as at March 31, 2006, Eastern Operations had entered into fixed price sales contracts to sell approximately 3,800 GWh of power for the remainder of 2006 and approximately 3,500 GWh of power for 2007, although certain contracted volumes are dependent on customer usage levels.

Power Sales Volumes and Plant Availability

Power Sales Volumes

Three months ended March 31 (unaudited) (GWh)	2006	2005
Bruce Power (1)	3,306	2,598
Western Operations (2)	4,462	3,198
Eastern Operations (3)	1,435	1,255
Power LP Investment (4)	—	697
Total	9,203	7,748

(1) Sales volumes reflect TransCanada’s proportionate share of Bruce Power output.

(2) The Sheerness PPA is included in Western Operations, effective December 31, 2005.

(3) TC Hydro is included in Eastern Operations, effective April 1, 2005.

(4) TransCanada operated and managed Power LP until August 31, 2005. The volumes in the table represent 100 per cent of Power LP’s sales volumes in first quarter 2005.

Weighted Average Plant Availability (1)

Three months ended March 31 (unaudited)	2006		2005
Bruce Power	90	%	81	%
Western Operations (2)	90	%	89	%
Eastern Operations (3)	95	%	85	%
Power LP Investment (4)	—		99	%
All plants, excluding Bruce Power	94	%	91	%
All plants	91	%	87	%

(1) Plant availability represents the percentage of time in the period that the plant is available to generate power, even if the plant is not operating, reduced by planned and unplanned outages.

(2) The Sheerness PPA is included in Western Operations, effective December 31, 2005.

(3) TC Hydro is included in Eastern Operations, effective April 1, 2005.

(4) Power LP is included up to August 31, 2005.

Corporate

Net expenses were $12 million and $9 million for the three months ended March 31, 2006 and 2005, respectively. The $3 million increase in net expenses is primarily due to increased interest costs.

Liquidity and Capital Resources

Funds Generated from Operations

Funds generated from operations were $517 million for the three months ended March 31, 2006 compared to $420 million for the same period in 2005.

TransCanada expects that its ability to generate adequate amounts of cash in the short and long term, when needed, and to maintain financial capacity and flexibility to provide for planned growth remains substantially unchanged since December 31, 2005.

Investing Activities

In the three months ended March 31, 2006, capital expenditures totalled $303 million (2005 - $108 million) and related primarily to the restart and refurbishment of Bruce A Units 1 and 2, construction of new power plants, construction of Tamazunchale and Edson and maintenance and other capacity capital in the Gas Transmission business.

In the three months ended March 31, 2006, there was no disposition of assets (2005 - $101 million, net of current tax expense). The disposition in 2005 relates to the sale of PipeLines LP units.

Financing Activities

TransCanada retired $140 million of long-term debt in the three months ended March 31, 2006. In January 2006, the company issued $300 million of 4.3 per cent medium-term notes due 2011 and in March 2006, the company issued US$500 million of 5.85 per cent senior unsecured notes due 2036. For the three months ended March 31, 2006, outstanding notes payable decreased by $633 million, while cash and short-term investments increased by $149 million.

Dividends

On April 27, 2006, TransCanada’s Board of Directors declared a quarterly dividend of $0.32 per share for the quarter ending June 30, 2006 on the outstanding common shares. This is the 170th consecutive quarterly dividend paid by TransCanada and its subsidiary on the common shares. It is payable on July 31, 2006 to shareholders of record at the close of business on June 30, 2006.

Contractual Obligations

There have been no material changes to TransCanada’s contractual obligations from December 31, 2005 to March 31, 2006, 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 2005 Annual Report.

Financial and Other Instruments

The following represents the material changes to the company’s financial instruments since December 31, 2005.

Energy Price Risk Management

The company executes power, natural gas and heat rate derivatives for overall management of its asset portfolio. Heat rate contracts are contracts for the sale or purchase of power that are priced based on a natural gas index. The fair value and notional volumes of contracts for differences and the swap, future, option and heat rate contracts are shown in the tables below.

Power

		March 31, 2006		December 31, 2005
		(unaudited)
Asset/(Liability)	Accounting	Fair		Fair
(millions of dollars)	Treatment	Value		Value

Power - swaps and contracts for differences
(maturing 2006 to 2011)	Hedge	(77	)	(130	)
(maturing 2006 to 2010)	Non-hedge	6		13
Gas - swaps, futures and options
(maturing 2006 to 2016)	Hedge	(20	)	17
(maturing 2006 to 2008)	Non-hedge	5		(11	)
Heat rate contracts
(maturing 2006)	Non-hedge	—		—

Notional Volumes	Power (GWh)			Gas (Bcf)
March 31, 2006 (unaudited)	Accounting Treatment	Purchases	Sales	Purchases	Sales

Power - swaps and contracts for differences
(maturing 2006 to 2011)	Hedge	2,572	8,899	—	—
(maturing 2006 to 2010)	Non-hedge	1,365	1,035	—	—
Gas - swaps, futures and options
(maturing 2006 to 2016)	Hedge	—	—	91	63
(maturing 2006 to 2008)	Non-hedge	—	—	17	20
Heat rate contracts
(maturing 2006)	Non-hedge	—	26	—	—

	Power (GWh)			Gas (Bcf)
Notional Volumes December 31, 2005	Accounting Treatment	Purchases	Sales	Purchases	Sales

Power - swaps and contracts for differences	Hedge	2,566	7,780	—	—
	Non-hedge	1,332	456	—	—

Gas - swaps, futures and options	Hedge	—	—	91	69
	Non-hedge	—	—	15	18

Heat rate contracts	Non-hedge	—	35	—	—

Risk Management

TransCanada’s market, financial and counterparty risks remain substantially unchanged since December 31, 2005. For further information on risks, refer to the MD&A in TransCanada’s 2005 Annual

Report.

Controls and Procedures

As of March 31, 2006, TransCanada’s management, together with TransCanada’s President and Chief Executive Officer and Chief Financial Officer, evaluated the effectiveness of the design and operation of the company’s disclosure controls and procedures. Based on this evaluation, the President and Chief Executive Officer and the Chief Financial Officer of TransCanada have concluded that the disclosure controls and procedures are effective.

There were no changes in TransCanada’s internal control over financial reporting during the most recent fiscal quarter that have materially affected or are reasonably likely to materially affect TransCanada’s internal control over financial reporting.

Critical Accounting Policy

TransCanada’s critical accounting policy, which remains unchanged since December 31, 2005, is the use of regulatory accounting for its regulated operations. For further information on this critical accounting policy, refer to the MD&A in TransCanada’s 2005 Annual Report.

Critical Accounting Estimates

Since a determination of many assets, liabilities, revenues and expenses is dependent upon future events, the preparation of the company’s consolidated financial statements requires the use of estimates and assumptions which have been made using careful judgment. TransCanada’s critical accounting estimate from December 31, 2005 continues to be depreciation expense. For further information on this critical accounting estimate, refer to the MD&A in TransCanada’s 2005 Annual Report.

Outlook

In 2006, TransCanada expects higher net income than originally anticipated due to net income from discontinued operations as a result of bankruptcy settlements received from Mirant related to the divested Gas Marketing business. Excluding this impact, the company’s outlook is relatively unchanged since December 31, 2005. For further information on outlook, refer to the MD&A in TransCanada’s 2005 Annual Report.

In 2006, TransCanada will continue to direct its resources towards long-term growth opportunities that will strengthen its financial

performance and create long-term value for shareholders. The company’s net income and cash flow combined with a strong balance sheet continue to provide the financial flexibility for TransCanada to make disciplined investments in its core businesses of Gas Transmission and Power.

TransCanada’s issuer rating assigned by Moody’s Investors Service (Moody’s) is A3 with a stable outlook. Credit ratings on TransCanada PipeLines Limited’s (TCPL) senior unsecured debt assigned by Dominion Bond Rating Service Limited (DBRS), Moody’s and Standard & Poor’s remain at A, A2 and A-, respectively. DBRS and Moody’s both maintain a ‘stable’ outlook on their ratings and Standard & Poor’s maintains a ‘negative’ outlook on its rating.

Other Recent Developments

Gas Transmission

Wholly-Owned Pipelines

Canadian Mainline

In March 2006, TransCanada reached a settlement with its customers and other interested parties with respect to its 2006 tolls on the Canadian Mainline. The settlement results in a revenue requirement of approximately $1.8 billion for 2006.

The settlement establishes the Canadian Mainline’s fixed operating, maintenance and administration (OM&A) costs for 2006 at $174 million, which is six per cent higher than the OM&A costs of $164 million incurred in 2005. Any variance between actual OM&A costs and those agreed to in the settlement will accrue to TransCanada. The settlement also provides TransCanada with an opportunity to realize modest additional net earnings through performance-based incentive arrangements. These incentive arrangements are focused on certain cost management activities and the management of fuel, and provide mutual benefits to both TransCanada and its customers. There is no change in the Canadian Mainline depreciation rates or methodology from 2005 to 2006.

The settlement included an ROE of 8.88 per cent, as determined for 2006 under the NEB’s return adjustment formula, on a deemed common equity ratio of 36 per cent.

Interim tolls will continue to be charged for transportation service on the Canadian Mainline until final tolls are approved by the NEB pursuant to this settlement. With NEB approval, the terms of this settlement will be effective January 1, 2006 for one year. In March 2006, TransCanada filed its application with the NEB for approval of this settlement and associated tolls.

Alberta System

In February 2006, the Alberta Energy and Utilities Board (EUB) issued its decision on the 2005 General Rate Application (GRA) Phase II which determined the allocation of 2005 approved costs among transportation services and rate design. The decision approved the 2005 rate design as applied for.

In March 2006, TransCanada filed for 2005 Final Rates and 2006 Final Rates with the EUB. The 2005 Final Rates as filed are the same as the 2005 Interim Rates since there were no changes to the rate design required in the EUB decision on the 2005 GRA Phase II. The 2006 Final Rates filed with the EUB are based on the 2006 revenue requirement, including deferrals from 2005 as per the Alberta System three year settlement, a revised throughput forecast and the approved rate design.

Other Gas Transmission

In April 2006, PipeLines LP closed its acquisition of an additional 20 per cent general partnership interest in Northern Border for approximately US$297 million plus US$10 million in transaction costs payable to a subsidiary of TransCanada, bringing its total general partnership interest to 50 per cent. As part of the transaction, PipeLines LP also indirectly assumed approximately US$120 million of debt of Northern Border. The transaction was effective as of December 31, 2005. As part of the transaction, and effective by early second quarter 2007, a subsidiary of TransCanada will become the operator of Northern Border which is currently operated by a subsidiary of ONEOK Inc. (ONEOK).

Concurrent with this transaction, TransCanada closed the sale of its 17.5 per cent general partner interest in Northern Border Partners, L.P. to a subsidiary of ONEOK, for net proceeds of approximately US$30 million, resulting in an expected after-tax gain of approximately $10 million to be recorded in second quarter 2006.

Northern Development

Public hearings commenced in January 2006 on the Mackenzie Gas Pipeline Project which includes a proposed 1,194 kilometre natural gas pipeline system along the Mackenzie Valley of Canada’s Northwest Territories that will connect northern onshore natural gas fields with North American markets. The hearings take a two-stage approach with a Joint Review Panel focusing on environmental and socio-economic impacts, and the NEB reviewing all other matters including engineering, safety, need and economic feasibility. The hearings are scheduled in a number of locations throughout the Mackenzie Valley and Alberta through to December 2006. The company plans to seek approval from the EUB in second quarter 2006 to build certain related interconnecting facilities in northwest Alberta.

Keystone Pipeline

In March and April 2006, TransCanada announced that it will host a series of open house meetings in March, April and May to provide stakeholders along portions of the proposed corridor of the Keystone pipeline with information and updates about the crude oil pipeline project and to solicit feedback. TransCanada has also commenced meeting with potentially affected landowners and landowners adjacent to the proposed pipeline route on an individual basis.

In response to interest from customers, TransCanada is also considering possible extensions of the Keystone pipeline north to Fort Saskatchewan, Alberta and south through Kansas to Cushing, Oklahoma. Open houses along the contemplated extension to Cushing are planned for later this year.

Public and stakeholder consultation and detailed environmental assessments and field studies along with engineering work will continue throughout 2006. On April 20, 2006, TransCanada filed with the U.S. Department of State an application for a Presidential Permit authorizing the construction, operation and maintenance of the Keystone pipeline. Various other major regulatory applications are currently being prepared for submission in Canada and the U.S. Construction is expected to start in 2008, with commercial operations expected to begin by fourth quarter 2009.

Liquefied Natural Gas

In early April 2006, Cacouna Energy, a partnership between TransCanada and Petro-Canada, awarded a contract for front-end engineering and design work to an international consortium of engineering and construction firms with experience in the development of liquefied natural gas receiving terminals. The project’s next significant milestone is hearings before a joint review panel of the Canadian Environmental Assessment Agency and Québec’s Bureau d’audiences publiques sur l’environnement scheduled to begin May 8, 2006. Pending regulatory approval, construction is expected to begin in 2007 with the facility becoming operational in late 2009 or early 2010.

Share Information

As at March 31, 2006, TransCanada had 487,596,632 issued and outstanding common shares. In addition, there were 9,551,717 outstanding options to purchase common shares, of which 7,196,894 were exercisable as at March 31, 2006.

Selected Quarterly Consolidated Financial Data (1)

(unaudited)	2006		2005								2004
(millions of dollars except per share amounts)	First		Fourth		Third		Second		First		Fourth		Third		Second

Revenues	1,894		1,771		1,494		1,449		1,410		1,480		1,311		1,347
Net Income
Continuing operations	245		350		427		200		232		185		193		388
Discontinued operations	28		—		—		—		—		—		52		—
	273		350		427		200		232		185		245		388

Share Statistics
Net income per share - Basic
Continuing operations	$	0.50	$	0.72	$	0.88	$	0.41	$	0.48	$	0.38	$	0.40	$	0.80
Discontinued operations	0.06		—		—		—		—		—		0.11		—
	$	0.56	$	0.72	$	0.88	$	0.41	$	0.48	$	0.38	$	0.51	$	0.80
Net income per share - Diluted
Continuing operations	$	0.50	$	0.71	$	0.87	$	0.41	$	0.48	$	0.38	$	0.39	$	0.80
Discontinued operations	0.06		—		—		—		—		—		0.11		—
	$	0.56	$	0.71	$	0.87	$	0.41	$	0.48	$	0.38	$	0.50	$	0.80
Dividend declared per common share	$	0.32	$	0.305	$	0.305	$	0.305	$	0.305	$	0.29	$	0.29	$	0.29

(1) The selected quarterly consolidated financial data has been prepared in accordance with Canadian GAAP. Certain comparative figures have been reclassified to conform with the current year’s presentation. For a discussion on the factors affecting the comparability of the financial data, including discontinued operations, refer to Note 1, Note 2 and Note 23 of TransCanada’s 2005 audited consolidated financial statements.

Factors Impacting Quarterly Financial Information

In the Gas Transmission business, which consists primarily of the company’s investments in regulated pipelines, annual revenues and net earnings fluctuate over the long term based on regulators’ decisions and negotiated settlements with shippers. Generally, quarter over quarter revenues and net earnings during any particular fiscal year remain relatively stable with fluctuations arising as a result of adjustments being recorded due to regulatory decisions and negotiated settlements with shippers and due to items outside of the normal course of operations.

In the Power business, which builds, owns and operates electrical power generation plants and sells electricity, quarter over quarter revenues and net earnings are affected by seasonal weather conditions, customer demand, market prices, planned and unplanned plant outages as well as items outside of the normal course of operations.

Significant items which impacted the last eight quarters’ net earnings are as follows.

• Second quarter 2004 net earnings included after-tax gains related to Power LP of $187 million, of which $132 million were previously deferred and were being amortized into income to 2017.

• In third quarter 2004, the EUB’s decisions on the Generic Cost of Capital and Phase I of the 2004 GRA resulted in lower earnings for the Alberta System compared to the previous quarters. In addition, third quarter 2004 included a $12 million after-tax adjustment related to the release of previously established restructuring provisions and recognition of $8 million of non-capital loss carry forwards.

• In fourth quarter 2004, TransCanada completed the acquisition of GTN and recorded $14 million of net earnings from the November 1, 2004 acquisition date. Power recorded a $16 million pre-tax positive impact of a restructuring transaction related to power purchase contracts between OSP and Boston Edison in Eastern Operations.

• First quarter 2005 net earnings included a $48 million after-tax gain related to the sale of PipeLines LP units. Power earnings included a $10 million after-tax cost for the restructuring of natural gas supply contracts by OSP. In addition, Bruce Power’s equity income was lower than previous quarters due to the impact of planned maintenance outages and the increase in operating costs as a result of moving to a six-unit operation.

• Second quarter 2005 net earnings included $21 million ($13 million related to 2004 and $8 million related to the six months ended June 30, 2005) with respect to the NEB’s decision on the Canadian Mainline’s 2004 Tolls and Tariff Application (Phase II). On April 1, 2005, TransCanada completed the acquisition of TC Hydro generation assets from USGen New England, Inc. Bruce Power’s equity income was lower than previous quarters due to the continuing impact of planned maintenance outages and an unplanned maintenance outage on Unit 6 relating to a transformer fire.

• Third quarter 2005 net earnings included a $193 million after-tax gain related to the sale of the company’s ownership interest in Power LP. In addition, Bruce Power’s equity income increased from prior quarters due to higher realized power prices and slightly higher generation volumes.

• Fourth quarter 2005 net earnings included a $115 million after-tax gain on sale of Paiton Energy. In addition, Bruce A was formed and Bruce Power’s results were proportionately consolidated effective October 31.

• First quarter 2006 net earnings included an $18 million after-tax bankruptcy claim settlement received by the Gas Transmission Northwest System. In addition, Power’s net earnings included contributions from the December 31, 2005 acquisition of the 756 MW Sheerness PPA.

Exhibit 13.2

Consolidated Income

Three months ended March 31 (unaudited) (millions of dollars except per share amounts)	2006			2005
Revenues	1,894			1,410

Operating Expenses
Cost of sales	505			265
Other costs and expenses	537			422
Depreciation	257			251
	1,299			938
Operating Income	595			472

Other Expenses/(Income)
Financial charges	202			207
Financial charges of joint ventures	21			17
Equity income	(18		)	(50		)
Interest income and other	(49		)	(24		)
Gain on sale of PipeLines LP units	—			(80		)
	156			70
Income from Continuing Operations before Income
Taxes and Non-Controlling Interests	439			402

Income Taxes
Current	210			161
Future	(41		)	(12		)
	169			149
Non-Controlling Interests
Preferred share dividends of subsidiary	6			6
Non-controlling interest in PipeLines LP	13			9
Other	6			6
	25			21

Net Income from Continuing Operations	245			232
Net Income from Discontinued Operations (Note 5)	28			—
Net Income	273			232

Net Income Per Share
Continuing operations	$	0.50		$	0.48
Discontinued operations	$	0.06		—
Basic and Diluted	$	0.56		$	0.48

Average Shares Outstanding - Basic (millions)	487.4			485.2

Average Shares Outstanding - Diluted (millions)	490.1			487.9

See accompanying notes to the consolidated financial statements.

Consolidated Cash Flows

Three months ended March 31 (unaudited) (millions of dollars)	2006		2005

Cash Generated from Operations
Net income from continuing operations	245		232
Depreciation	257		251
Gain on sale of PipeLines LP units, net of current income tax	—		(30	)
Equity income in excess of distributions received	(4	)	(31	)
Future income taxes	(41	)	(12	)
Non-controlling interests	25		21
Funding of employee future benefits in excess of expense	(2	)	(7	)
Other	37		(4	)
Funds generated from operations	517		420
Increase in operating working capital	(2	)	(86	)
Net cash provided by operations	515		334

Investing Activities
Capital expenditures	(303	)	(108	)
Disposition of assets, net of current income tax	—		101
Deferred amounts and other	(9	)	40
Net cash (used in)/provided by investing activities	(312	)	33

Financing Activities
Dividends on common shares	(149	)	(140	)
Distributions paid to non-controlling interests	(16	)	(15	)
Notes payable (repaid)/issued, net	(633	)	244
Long-term debt issued	878		300
Reduction of long-term debt	(140	)	(329	)
Long-term debt of joint ventures issued	2		5
Reduction of long-term debt of joint ventures	(6	)	(4	)
Common shares issued	8		11
Net cash (used in)/provided by financing activities	(56	)	72

Effect of Foreign Exchange Rate Changes on Cash and Short-Term Investments	2		2

Increase in Cash and Short-Term Investments	149		441

Cash and Short-Term Investments
Beginning of period	212		191

Cash and Short-Term Investments
End of period	361		632

Supplementary Cash Flow Information
Income taxes paid	217		192
Interest paid	199		196

See accompanying notes to the consolidated financial statements.

Consolidated Balance Sheet

	March 31, 2006		December 31,
(millions of dollars)	(unaudited)		2005


ASSETS
Current Assets
Cash and short-term investments	361		212
Accounts receivable	700		796
Inventories	219		281
Other	281		277
	1,561		1,566
Long-Term Investments	419		400
Plant, Property and Equipment	20,090		20,038
Other Assets	2,049		2,109
	24,119		24,113

LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities
Notes payable	329		962
Accounts payable	1,340		1,494
Accrued interest	231		222
Current portion of long-term debt	533		393
Current portion of long-term debt of joint ventures	37		41
	2,470		3,112
Deferred Amounts	1,149		1,196
Future Income Taxes	661		703
Long-Term Debt	10,249		9,640
Long-Term Debt of Joint Ventures	935		937
Preferred Securities	537		536
	16,001		16,124
Non-Controlling Interests
Preferred shares of subsidiary	389		389
Non-controlling interest in PipeLines LP	320		318
Other	82		76
	791		783
Shareholders’ Equity
Common shares	4,763		4,755
Contributed surplus	272		272
Retained earnings	2,386		2,269
Foreign exchange adjustment	(94	)	(90	)
	7,327		7,206
	24,119		24,113

See accompanying notes to the consolidated financial statements.

Consolidated Retained Earnings

Three months ended March 31 (unaudited)
(millions of dollars)	2006		2005

Balance at beginning of period	2,269		1,655
Net income	273		232
Common share dividends	(156	)	(148	)

	2,386		1,739

See accompanying notes to the consolidated financial statements.

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, 2005. 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 2005 audited consolidated financial statements included in TransCanada’s 2005 Annual Report. Amounts are stated in Canadian dollars unless otherwise indicated. Certain comparative figures have been reclassified to conform with the current period’s presentation.

Since a determination of many assets, liabilities, revenues and expenses is dependent upon future events, the preparation of these consolidated financial statements requires the use of 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. Segmented Information

Three months ended March 31	Gas Transmission				Power				Corporate				Total
(unaudited - millions of dollars)	2006		2005		2006		2005		2006		2005		2006		2005
Revenues	1,088		998		806		412		—		—		1,894		1,410
Cost of sales	(70	)	—		(435	)	(265	)	—		—		(505	)	(265	)
Other costs and expenses	(340	)	(307	)	(196	)	(113	)	(1	)	(2	)	(537	)	(422	)
Depreciation	(227	)	(233	)	(30	)	(18	)	—		—		(257	)	(251	)
Operating income/(loss)	451		458		145		16		(1	)	(2	)	595		472
Financial charges and non-controlling interests	(192	)	(196	)	—		(2	)	(35	)	(30	)	(227	)	(228	)
Financial charges of joint ventures	(14	)	(15	)	(7	)	(2	)	—		—		(21	)	(17	)
Equity income	18		20		—		30		—		—		18		50
Interest income and other	32		14		2		3		15		7		49		24
Gain on sale of PipeLines LP units	—		80		—		—		—		—		—		80
Income taxes	(127	)	(150	)	(51	)	(15	)	9		16		(169	)	(149	)
Continuing Operations	168		211		89		30		(12	)	(9	)	245		232
Discontinued Operations													28		—
Net Income													273		232

Total Assets

	March 31, 2006	December 31,
(millions of dollars)	(unaudited)	2005

Gas Transmission	18,077	18,252
Power	4,920	4,923
Corporate	1,122	938
	24,119	24,113

3. Risk Management and Financial Instruments

The following represents the material changes to the company’s financial instruments since December 31, 2005.

Energy Price Risk Management

POWER

		March 31, 2006		December 31, 2005
		(unaudited)
Asset/(Liability)	Accounting	Fair		Fair
(millions of dollars)	Treatment	Value		Value

Power - swaps and contracts for differences
(maturing 2006 to 2011)	Hedge	(77	)	(130	)
(maturing 2006 to 2010)	Non-hedge	6		13
Gas - swaps, futures and options
(maturing 2006 to 2016)	Hedge	(20	)	17
(maturing 2006 to 2008)	Non-hedge	5		(11	)
Heat rate contracts
(maturing 2006)	Non-hedge	—		—

Notional Volumes	Power (GWh)			Gas (Bcf)
March 31, 2006 (unaudited)	Accounting Treatment	Purchases	Sales	Purchases	Sales

Power - swaps and contracts for differences
(maturing 2006 to 2011)	Hedge	2,572	8,899	—	—
(maturing 2006 to 2010)	Non-hedge	1,365	1,035	—	—
Gas - swaps, futures and options
(maturing 2006 to 2016)	Hedge	—	—	91	63
(maturing 2006 to 2008)	Non-hedge	—	—	17	20
Heat rate contracts
(maturing 2006)	Non-hedge	—	26	—	—

	Power (GWh)			Gas (Bcf)
Notional Volumes December 31, 2005	Accounting Treatment	Purchases	Sales	Purchases	Sales

Power - swaps and contracts for differences	Hedge	2,566	7,780	—	—
	Non-hedge	1,332	456	—	—

Gas - swaps, futures and options	Hedge	—	—	91	69
	Non-hedge	—	—	15	18

Heat rate contracts	Non-hedge	—	35	—	—

Long-Term Debt

In January 2006, the company issued $300 million of 4.3 per cent medium-term notes due 2011 and in March 2006, the company issued US$500 million of 5.85 per cent senior unsecured notes due 2036.

Discontinued Operations

TransCanada’s net income includes $28 million or $0.06 per share of net income from discontinued operations, reflecting settlements received in first quarter 2006 from bankruptcy claims related to TransCanada’s Gas Marketing business divested in 2001.

Employee Future Benefits

The net benefit plan expense for the company’s defined benefit pension plans and other post-employment benefit plans for the three months ended March 31 is as follows.

Three months ended March 31	Pension Benefit Plans				Other Benefit Plans
(unaudited - millions of dollars)	2006		2005		2006	2005
Current service cost	9		7		—	—
Interest cost	17		16		2	1
Expected return on plan assets	(18	)	(16	)	—	—
Amortization of transitional obligation related to regulated business	—		—		1	1
Amortization of net actuarial loss	7		4		1	1
Amortization of past service costs	1		1		—	—
Net benefit cost recognized	16		12		4	3

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

Investor Relations, at 1-800-361-6522 (Canada and U.S. Mainland) or direct dial David Moneta/Myles Dougan at (403) 920-7911. The investor fax line is (403) 920-2457. Media Relations: Jennifer Varey at (403) 920-7859

Visit TransCanada’s Internet site at: http://www.transcanada.com

Exhibit 13.3

TRANSCANADA CORPORATION

RECONCILIATION TO UNITED STATES GAAP

The first quarter 2006 unaudited consolidated financial statements of TransCanada Corporation (TransCanada or the Company) have been prepared in accordance with Canadian generally accepted accounting principles (GAAP), which in some respects differ from U.S. GAAP. The effects of these differences on the Company’s consolidated financial statements for the three months ended March 31, 2006 are provided in the following U.S. GAAP condensed consolidated financial statements which should be read in conjunction with TransCanada’s audited consolidated financial statements for the year ended December 31, 2005 and unaudited consolidated financial statements for the three months ended March 31, 2006 prepared in accordance with Canadian GAAP.

Condensed Statement of Consolidated Income and Comprehensive Income in Accordance with U.S. GAAP(1)

	Three months ended March 31
(millions of dollars except per share amounts)	2006			2005
Revenues	1,493			1,271
Cost of sales	365			221
Other costs and expenses	430			422
Depreciation	223			228
	1,018			871
Operating income	475			400
Other (income)/expenses
Equity income(1)	(119		)	(98		)
Other expenses(2)	179			125
Income taxes	169			146
	229			173

Net income from continuing operations - U.S. GAAP	246			227
Net income from discontinued operations - U.S. GAAP	28			-
Net Income in Accordance with U.S. GAAP	274			227
Adjustments affecting comprehensive income under U.S. GAAP
Foreign currency translation adjustment, net of tax	(4		)	5
Unrealized gain/(loss) on derivatives, net of tax(3)	18			(9		)
Comprehensive Income in Accordance with U.S. GAAP	288			223

Net Income Per Share in Accordance with U.S. GAAP
Continuing operations	$	0.50		$	0.47
Discontinued operations	0.06			-
Basic and Diluted	$	0.56		$	0.47

Net Income Per Share in Accordance with Canadian GAAP – Basic and Diluted	$	0.56		$	0.48
Dividends per common share	$	0.32		$	0.305

Common Shares Outstanding (millions)
Average for the period – Basic	487.4			485.2
Average for the period - Diluted	490.1			487.9

Reconciliation of Income from Continuing Operations

	Three months ended March 31
(millions of dollars)	2006	2005
Net Income from Continuing Operations in Accordance with Canadian GAAP	245	232
U.S. GAAP adjustments
Unrealized gain/(loss) on energy contracts(3)	1	(10	)
Tax impact of unrealized gain/(loss) on energy contracts	—	4
Equity gain(4)(5)	—	2
Tax impact of equity gain	—	(1	)
Net income from Continuing Operations in Accordance with U.S. GAAP	246	227

Condensed Statement of Consolidated Cash Flows in Accordance with U.S. GAAP(1)

	Three months ended March 31
(millions of dollars)	2006		2005
Cash Generated from Operations(6)
Net cash provided by operating activities	494		264

Investing Activities
Net cash (used in)/provided by investing activities	(264	)	92

Financing Activities
Net cash (used in)/provided by financing activities	(61	)	71

Effect of Foreign Exchange Rate Changes on Cash and Short-Term Investments	1		2
Increase in Cash and Short-Term Investments	170		429
Cash and Short-Term Investments
Beginning of period	83		127
Cash and Short-Term Investments
End of period	253		556

Condensed Balance Sheet in Accordance with U.S. GAAP(1)

	March 31,	December 31,
(millions of dollars)	2006	2005
Current assets(7)	1,103	1,058
Long-term investments(4)(5)	2,284	2,168
Plant, property and equipment	17,343	17,348
Regulatory asset(8)	2,576	2,601
Other assets(4)	2,025	2,028
	25,331	25,203

Current liabilities(9)	2,181	2,754
Deferred amounts(3)(5)	1,304	1,298
Long-term debt(3)	10,278	9,675
Deferred income taxes(8)	3,045	3,102
Preferred securities	537	536
Non-controlling interests	791	783
Shareholders’ equity	7,195	7,055
	25,331	25,203

Statement of Other Comprehensive Income in Accordance with U.S. GAAP

(millions of dollars)	Cumulative Translation Account		Minimum Pension Liability (SFAS No. 87)		Cash Flow Hedges (SFAS No. 133)		Total
Balance at December 31, 2005	(89	)	(77	)	(58	)	(224	)
Unrealized gain on derivatives, net of tax of $(10)(3)	—		—		18		18
Foreign currency translation adjustment, net of tax of $3	(4	)	—		—		(4	)
Balance at March 31, 2006	(93	)	(77	)	(40	)	(210	)

Balance at December 31, 2004	(71	)	(26	)	(4	)	(101	)
Unrealized loss on derivatives, net of tax of $8(3)	—		—		(9	)	(9	)
Foreign currency translation adjustment, net of tax of $10	5		—		—		5
Balance at March 31, 2005	(66	)	(26	)	(13	)	(105	)

(1) In accordance with U.S. GAAP, the Condensed Statement of Consolidated Income, Statement of Consolidated Cash Flows and Consolidated Balance Sheet of TransCanada are prepared using the equity method of accounting for joint ventures.

(2) Other expenses included an allowance for funds used during construction of $1 million for the three months ended March 31, 2006 (March 31, 2005 - $1 million).

(3) All foreign exchange and interest rate derivatives are recorded in the Company’s consolidated financial statements at fair value under Canadian GAAP. Under the provisions of Statement of Financial Accounting Standards (SFAS) No. 133 “Accounting for Derivatives and Hedging Activities”, all derivatives are recognized as assets and liabilities on the balance sheet and measured at fair value. For derivatives designated as fair value hedges, changes in the fair value are recognized in earnings together with an equal or lesser amount of changes in the fair value of the hedged item attributable to the hedged risk. For derivatives designated as cash flow hedges, changes in the fair value of the derivative that are effective in offsetting the hedged risk are recognized in other comprehensive income until the hedged item is recognized in earnings. Any ineffective portion of the change in fair value is also recognized in earnings each period. Substantially all of the amounts recorded in the three months ended March 31, 2006 and 2005 as differences between U.S. and Canadian GAAP, for income from continuing operations, relate to the differences in accounting treatment with respect to the hedged item and, for comprehensive income, relate to cash flow hedges.

Substantially all of the amounts recorded in the three months ended March 31, 2006 and 2005 as differences between U.S. and Canadian GAAP in respect of energy contracts relate to gains and losses on derivative energy contracts for periods before they were documented as hedges for purposes of U.S. GAAP and to differences in accounting with respect to physical energy contracts.

(4) Under Canadian GAAP, pre-operating costs incurred during the commissioning phase of a new project are deferred until commercial production levels are achieved. After such time, those costs are amortized over the estimated life of the project. Under U.S. GAAP, such costs are expensed as incurred. Certain start-up costs incurred by Bruce Power L.P. (Bruce B), an equity investment, are required to be expensed under U.S. GAAP. Under both Canadian GAAP and U.S. GAAP, interest is capitalized on expenditures relating to construction of development projects actively being prepared for their intended use. In Bruce B, under U.S. GAAP, the carrying value of development projects against which interest is capitalized is lower due to the expensing of pre-operating costs.

(5) Financial Interpretation (FIN) 45 requires the recognition of a liability for the fair value of certain guarantees that require payments contingent on specified types of future events. The measurement standards of FIN 45 are applicable to guarantees entered into after January 1, 2003. For U.S. GAAP purposes, the fair value of guarantees recorded as a liability at March 31, 2006 was $18 million (December 31, 2005 - $17 million) and relates to the Company’s equity interest in Bruce B and Bruce Power A L.P. The net income impact with respect to the guarantees for the three months ended March 31, 2006 was nil (March 31, 2005 – nil).

(6) In accordance with U.S. GAAP, all current taxes are included in cash generated from operations.

(7) Current assets at March 31, 2006 include derivative contracts of $33 million (December 31, 2005 - $49 million) and hedging deferrals of $64 million (December 31, 2005 - $93 million).

(8) Under U.S. GAAP, the Company is required to record a deferred income tax liability for its cost-of-service regulated businesses. As these deferred income taxes are recoverable through future revenues, a corresponding regulatory asset is recorded for U.S. GAAP purposes.

(9) Current liabilities at March 31, 2006 include dividends payable of $162 million (December 31, 2005 - $154 million) and current taxes payable of $257 million (December 31, 2005 - $251 million).

Other

In May 2005, the Financial Accounting Standards Board (FASB) issued SFAS No 154 “Accounting Changes and Error Corrections – a replacement of APB Opinion No. 20 and SFAS No. 3” which is effective for fiscal years beginning after December 15, 2005. SFAS No. 154 changes the requirements for the accounting for and reporting of a change in accounting principle and error correction. It establishes, unless impracticable, retrospective application as the required method for reporting a change in accounting principle in the absence of explicit transition requirements specific to the newly adopted accounting principle. Adopting the provisions under SFAS No. 154, as of January 1, 2006, has had no impact on the U.S. GAAP financial statements of the Company.

In February 2006, FASB issued SFAS No. 155 “Accounting for Certain Hybrid Financial Instruments - an amendment of SFAS No. 133 and 140” which is effective for fiscal years beginning after September 15, 2006. Earlier adoption is permitted as of the beginning of an entity's fiscal year, provided the entity has not yet issued financial statements, including interim statements for any interim period, for that fiscal year. SFAS No. 155 permits fair value remeasurement of any hybrid instrument that contains an embedded derivative that otherwise would require bifurcation. Adopting the provisions under SFAS No. 155, as of January 1, 2007, is not expected to have an impact on the U.S. GAAP financial statements of the Company.

Summarized Financial Information of Long-Term Investments

The following summarized financial information of long-term investments includes those investments that are accounted for by the equity method under U.S. GAAP (including those that are accounted for by the proportionate consolidation method under Canadian GAAP).

	Three months ended March 31
(millions of dollars)	2006		2005
Income
Revenues	356		314
Other costs and expenses	(174	)	(146	)
Depreciation	(40	)	(44	)
Financial charges and other	(23	)	(26	)
Proportionate share of income before income taxes of long-term investments	119		98

	March 31,		December 31,
(millions of dollars)	2006		2005
Balance Sheet
Current assets	444		456
Plant, property and equipment	3,426		3,365
Other assets (net)	15		—
Current liabilities	(274	)	(319	)
Deferred amounts (net)	—		(2	)
Non-recourse debt	(1,300	)	(1,307	)
Deferred income taxes	(27	)	(25	)
Proportionate share of net assets of long-term investments	2,284		2,168

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 registrant as of, and for, the periods presented in this report;

4. The registrant’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)) for the registrant 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 registrant, 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) evaluated the effectiveness of the registrant’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

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

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’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 registrant’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 registrant’s internal control over financial reporting.

	/s/ Harold N. Kvisle
Dated April 28, 2006	Harold N. Kvisle
	President and Chief Executive Officer

Exhibit 31.2

Certifications

I, Russell K. Girling, certify that:

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

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

	/s/ Russell K. Girling
Dated April 28, 2006	Russell K. Girling
	Executive Vice-President, Corporate Development and Chief Financial Officer

Exhibit 32.1

TRANSCANADA CORPORATION

450 – 1^st 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, 2006 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 28, 2006

Exhibit 32.2

TRANSCANADA CORPORATION

450 – 1^st Street S.W.

Calgary, Alberta, Canada

T2P 5H1

CERTIFICATION OF CHIEF FINANCIAL OFFICER

REGARDING PERIODIC REPORT CONTAINING

FINANCIAL STATEMENTS

I, Russell K. Girling, 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, 2006 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/ Russell K. Girling
	Russell K. Girling
	Chief Financial Officer
	April 28, 2006

Exhibit 99.1

TRANSCANADA CORPORATION – FIRST QUARTER 2006

Quarterly Report to Shareholders

Media Inquiries:		Jennifer Varey	(403) 920-7859	(800) 608-7859
Analyst Inquiries:		David Moneta/Myles Dougan	(403) 920-7911	(800) 361-6522

TransCanada Announces First Quarter Results,

Board Declares Dividend of $0.32 per Share

CALGARY, Alberta – April 28, 2006 – (TSX: TRP) (NYSE: TRP)

First Quarter 2006 Highlights:

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

• Net income from continuing operations for first quarter 2006 of $245 million or $0.50 per share

• Funds generated from operations for first quarter 2006 of $517 million

• Dividend of $0.32 per common share declared by the Board of Directors

TransCanada Corporation today announced net income from continuing operations (net earnings) for first quarter 2006 of $245 million or $0.50 per share, an increase of $13 million or $0.02 per share compared to $232 million or $0.48 per share for first quarter 2005. Net earnings in first quarter 2006 included a $29 million bankruptcy settlement receipt ($18 million after tax or $0.04 per share) from a former shipper on the Gas Transmission Northwest System. Net earnings in first quarter 2005 include an after-tax gain of $48 million or $0.10 per share on the sale of TC PipeLines, LP (PipeLines LP) common units.

TransCanada also recorded net income from discontinued operations in first quarter 2006 of $28 million or $0.06 per share reflecting settlements received from bankruptcy claims related to TransCanada’s Gas Marketing business which was divested in 2001. Net income for first

quarter 2006 from continuing and discontinued operations totalled $273 million or $0.56 per share.

Funds generated from operations in first quarter 2006 were $517 million, compared with $420 million for the same period in 2005.

“Strong earnings in the first quarter were driven by significantly higher net earnings from TransCanada’s Power business,” said Hal Kvisle, chief executive officer. “Our acquisition of the Sheerness Power Purchase Arrangement and TC Hydro generation assets and our increased interest in the Bruce A units in 2005, combined with strong operating performance across most of our power operations, delivered a quarter-over-quarter increase in net earnings of almost 200 per cent.”

In Gas Transmission, net earnings from the Canadian wholly-owned pipelines declined due to the impact of lower regulated returns on equity and lower average investment bases. This decline was partially offset by the increase in deemed common equity ratio on the Canadian Mainline to 36 per cent from 33 per cent. TransCanada realized higher net earnings on the Gas Transmission Northwest System as a result of a bankruptcy settlement. Natural gas storage delivered strong earnings, capitalizing on high seasonal natural gas price differentials and the resulting increased demand within Alberta for natural gas storage services.

“Over the course of the year we will continue to execute our strategy of prudent, disciplined growth in our Gas Transmission and Power businesses in markets we know and in businesses where we enjoy genuine competitive advantage,” said Mr. Kvisle. “Our successful execution of those strategies to date has generated solid returns for our shareholders. In building a portfolio of strategically located, high quality assets, TransCanada is positioned exceptionally well to capture the opportunities created by the critical need for new North American energy infrastructure.”

Recent Developments

Gas Transmission:

• TransCanada, directly and indirectly, entered into a series of transactions that will result in a subsidiary of TransCanada becoming the operator of Northern Border Pipeline Company (Northern Border) in early second quarter 2007. As part of the series of transactions, PipeLines LP acquired an additional 20 per cent interest in Northern Border from Northern Border Partners, L.P., bringing its total general partnership interest in Northern Border to 50 per cent. These transactions closed on April 6, 2006 with an effective date of December 31, 2005.

• Through its subsidiary, North Baja Pipeline LLC, TransCanada filed an application with the Federal Energy Regulatory Commission (FERC) in early February for a certificate for a two-phase expansion of its existing natural gas pipeline in southern California and the construction of a new pipeline lateral in California’s Imperial Valley. The expansion positions TransCanada to capture opportunities from the growth of liquefied natural gas (LNG) facilities on the West Coast. Shippers have indicated their commercial support for the projects by signing precedent agreements in support of the expansion plan as filed with the FERC.

• In mid-March, TransCanada reached a settlement with its customers and other interested parties regarding 2006 tolls on the Canadian Mainline. The settlement results in a revenue requirement of approximately $1.8 billion for 2006. Subject to National Energy Board (NEB) approval of the settlement, the annualized benchmark Eastern Zone toll for 2006 is expected to be 94.5 cents per gigajoule.

• Construction continues on the 130 kilometre Tamazunchale Pipeline in east-central Mexico. TransCanada anticipates completing construction and beginning commercial operations as scheduled in December 2006.

• Construction also continues on the Edson natural gas storage facility in Alberta. The Edson facility is expected to have a capacity of approximately 60 petajoules (PJ) and will connect to the Alberta System. Storage capacity is expected to be available commencing later this year.

Northern Development:

• Public hearings commenced in January 2006 on the Mackenzie Gas Pipeline Project which includes a proposed 1,194 kilometre natural gas pipeline system along the Mackenzie Valley of Canada’s Northwest Territories that will connect northern onshore natural gas fields with North American markets. The hearings take a two-stage approach with the Joint Review Panel focusing on environmental and socio-economic impacts, and the NEB reviewing all other matters including engineering, safety, need and economic feasibility. The hearings are scheduled in a number of locations throughout the Mackenzie Valley and Alberta through to December 2006. TransCanada plans to seek approval from the Alberta Energy and Utilities Board (EUB) in second quarter 2006 to build certain related interconnecting facilities in northwest Alberta.

• In mid-February, the State of Alaska announced that agreement had been reached between the State and North Slope producers with respect to the Alaska natural gas pipeline. The agreement is contingent on legislative approval and enactment of legislation related to State taxes on crude oil. Details of the natural gas deal have not yet been made public. TransCanada looks forward to working with the State and the producers to bring Alaska natural gas to market.

Keystone Crude Oil Pipeline:

• On April 20, 2006, TransCanada filed with the U.S. Department of State an application for a Presidential Permit authorizing the construction, operation and maintenance of the cross-border facilities associated with the proposed US$2.1 billion Keystone pipeline that will transport crude oil from Alberta to U.S. midwest refineries. On January 31, 2006, TransCanada announced that it had secured firm, long-term contracts on the proposed pipeline totalling 340,000 barrels per day with a duration averaging 18 years. Stakeholder consultations, detailed environmental assessments and field studies along with engineering work will continue throughout 2006. Major regulatory applications are currently being prepared for submission in Canada and the U.S. Construction is anticipated to start in 2008, with commercial operations expected to begin by fourth quarter 2009.

Liquefied Natural Gas:

• In early April, Cacouna Energy, a partnership between TransCanada and Petro-Canada, awarded a contract for front-end engineering and design work to an international consortium of engineering and construction firms with experience in the development of LNG receiving terminals. The project’s next significant milestone is

hearings before a joint review panel of the Canadian Environmental Assessment Agency and Québec’s Bureau d’audiences publiques sur l’environnement scheduled to begin May 8, 2006. Pending regulatory approval, construction is expected to begin in 2007 with the facility becoming operational in late 2009 or early 2010.

• At the end of January, Broadwater Energy filed an application with the FERC for approval of the construction and operation of the proposed Broadwater LNG project in Long Island Sound. Broadwater plans to begin operation in late 2010 and is designed to regasify one billion cubic feet of natural gas per day. The filing marks the next step in a comprehensive public and regulatory review of the project that began in November 2004. Broadwater is a partnership between TransCanada and Shell US Gas & Power LLC.

Power:

• Cartier Wind began construction in March 2006 on the 110 megawatt (MW) Baie-des-Sables wind farm, the first of the six wind farms that make up the Cartier Wind project in the Gaspé region of Québec. The Baie-des-Sables wind farm is expected to deliver energy to the Hydro-Québec grid by December 2006. TransCanada has a 62 per cent interest in the Cartier Wind project which was awarded six projects by Hydro-Québec Distribution in October 2004 representing a total of 739.5 MW.

• With its partner, Ontario Power Generation, TransCanada continues to advance the Portlands Energy Centre (PEC) project to build a high efficiency, 550 MW combined-cycle generating station in downtown Toronto. In February 2006, the Ontario Minister of Energy directed the Ontario Power Authority to negotiate a contract to buy the output of the proposed PEC project. The Ontario Ministry of Environment approved PEC in the spring of 2005 following extensive studies, expert reviews, applications and public consultations.

• Construction is nearing completion on the 550 MW Bécancour cogeneration plant near Trois-Rivières, Québec with testing and related start-up activities anticipated to begin in May 2006. The plant remains on schedule to begin commercial operations in fall 2006. The facility will supply electricity to Hydro-Québec Distribution under long-term contracts as well as provide a source of competitively priced steam for industrial processes.

• Throughout the first quarter, Bruce Power continued preparatory work on the project to restart Bruce A Units 1 and 2. On May 19, 2006, the Canadian Nuclear Safety Commission is scheduled to hold a one-day public hearing to consider the results of an Environmental Assessment screening of the proposed Bruce A restart. The restart and refurbishment project, initially announced in October 2005, will return another 1,500 MW of generating capacity to Ontario, commencing in late 2009.

Teleconference

TransCanada will hold a teleconference today at 1 p.m. (Mountain) / 3 p.m. (Eastern) to discuss the first quarter 2006 financial results and general developments and issues concerning the company. Analysts, members of the media and other interested parties wanting to participate should phone 1-866-226-1799 or 416-340-2220 (Toronto area) at least 10 minutes prior to the start of the teleconference. No passcode is required. A live webcast of the teleconference will also be available on TransCanada’s website at www.transcanada.com.

The conference will begin with a short address by members of

TransCanada’s executive management, followed by a question and answer period for investment analysts. A question and answer period for members of the media will immediately follow.

A replay of the teleconference will be available two hours after the conclusion of the call until midnight (Eastern) May 5, 2006. Please call 1-800-408-3053 or 416-695-5800 (Toronto area) and enter passcode 3182874. The webcast will be archived and available for replay on www.transcanada.com.

About TransCanada

TransCanada is a leader in the responsible development and reliable operation of North American energy infrastructure. TransCanada’s network of more than 41,000 kilometres (25,600 miles) of wholly owned pipeline transports the majority of Western Canada’s natural gas production to key Canadian and U.S. markets. A growing independent power producer, TransCanada owns, or has interests in, approximately 6,700 megawatts of power generation in Canada and the United States. TransCanada’s common shares trade on the Toronto and New York stock exchanges under the symbol TRP.

First Quarter 2006 Financial Highlights

(unaudited)

Operating Results

Three months ended March 31
(millions of dollars)	2006		2005

Revenues	1,894		1,410

Net Income
Continuing operations	245		232
Discontinued operations	28		—
	273		232

Cash Flows
Funds generated from operations	517		420
Increase in working capital	(2	)	(86	)
Net cash provided by operations	515		334

Capital expenditures	303		108

Common Share Statistics

Three months ended March 31	2006		2005

Net Income Per Share - Basic and Diluted
Continuing operations	$	0.50	$	0.48
Discontinued operations	0.06		—
	$	0.56	$	0.48

Dividends Declared Per Share	$	0.32	$	0.305

Common Shares Outstanding (millions)
Average for the period	487.4		485.2
End of period	487.6		485.6