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,

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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.

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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).

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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	82	94
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

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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.

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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

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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.

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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.

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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

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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

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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.

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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

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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.

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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.

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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.

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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

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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

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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.

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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.

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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.

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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.

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•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.

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