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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 July 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 o

Form 40-F x

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 o

No x

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 June 30, 2006.

13.2 Consolidated comparative interim unaudited financial statements of the registrant for the period ended June 30, 2006 (included in the registrant’s Second 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 Second 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 July 27, 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/ Gregory A. Lohnes
		Gregory A. Lohnes
		Executive Vice-President and
		Chief Financial Officer


	By:	/s/ G. Glenn Menuz
		G. Glenn Menuz
		Vice-President and Controller

July 27, 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 June 30, 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 July 27, 2006.

Exhibit 13.1

Second Quarter 2006 Financial Highlights
(unaudited)

Operating results	Three months ended June 30				Six months ended June 30
(millions of dollars)	2006		2005		2006		2005

Revenues	1,685		1,449		3,579		2,859

Net Income
Continuing operations	244		200		489		432
Discontinued operations	—		—		28		—
	244		200		517		432

Cash Flow Information
Funds generated from operations(1)	539		498		1,056		918
Increase in operating working capital	(91	)	(177	)	(93	)	(263	)
Net cash provided by operations	448		321		963		655

Capital expenditures	327		135		630		243
Acquisitions, net of cash acquired	358		632		358		632

	Three months ended June 30				Six months ended June 30
Common Share Statistics	2006		2005		2006		2005

Net Income Per Share - Basic
Continuing operations	$	0.50	$	0.41	$	1.00	$	0.89
Discontinued operations	—		—		0.06		—
	$	0.50	$	0.41	$	1.06	$	0.89

Dividends Declared Per Share	$	0.32	$	0.305	$	0.64	$	0.61

Common Shares Outstanding (millions)
Average for the period - Basic	487.7		485.9		487.6		485.6
End of period	487.8		486.5		487.8		486.5

(1) For a complete discussion on funds generated from operations, see “Non-GAAP Measures” in Management’s Discussion and Analysis of this Second Quarter 2006, Quarterly Report to Shareholders.

Management’s Discussion and Analysis

Management’s discussion and analysis (MD&A) dated July 27, 2006 should be read in conjunction with the accompanying unaudited consolidated financial statements of TransCanada Corporation (TransCanada or the company) for the six months ended June 30, 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 provided in the annual MD&A contained in TransCanada’s 2005 Annual Report.

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 as otherwise stated, 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.

Non-GAAP Measures

The company uses the measures “funds generated from operations” and “operating income” in its MD&A. These measures do not have any standardized meaning in generally accepted accounting principles (GAAP) and are therefore considered to be non-GAAP measures. These measures may not be comparable to similar measures presented by other entities. These measures have been used to provide readers with additional information on the company’s liquidity and its ability to generate funds to finance its operations.

Funds generated from operations is comprised of net cash provided by operations before changes in operating working capital. Operating income is used in the Energy segment and is comprised of revenues plus equity income less operating expenses as shown on the consolidated income statement. See the Energy section in the MD&A for a reconciliation of operating income to net earnings.

Results of Operations

Effective June 1, 2006, TransCanada revised the composition and names of its reportable business segments to Pipelines and Energy. Pipelines is principally comprised of the company’s pipelines in Canada, the United States and Mexico. Energy includes the company’s power operations, natural gas storage and liquefied natural gas (LNG) businesses in Canada and the U.S. The internal organizational structure of the company has accordingly been aligned with these segments. The segmented information has been retroactively restated to reflect the changes in reportable segments. These changes had no impact on consolidated net income.

Consolidated

Segment Results-at-a-Glance
(unaudited)

	Three months ended June 30					Six months ended June 30
(millions of dollars except per share amounts)	2006		2005			2006			2005
Pipelines
Excluding gains	134		165			291			326
Gain on sale of Northern Border Partners, L.P.interest	13		—			13			—
Gain on sale of PipeLines LP units	—		1			—			49
	147		166			304			375

Energy	97		41			197			73

Corporate	—		(7		)	(12		)	(16		)

Net Income
Continuing operations(1)	244		200			489			432
Discontinued operations	—		—			28			—
	244		200			517			432


Net Income Per Share
Continuing operations(2)	$	0.50	$	0.41		$	1.00		$	0.89
Discontinued operations	—		—			0.06			—
Basic and Diluted	$	0.50	$	0.41		$	1.06		$	0.89

	Three months ended June 30				Six months ended June 30
	2006		2005		2006		2005
(1)Net Income from Continuing Operations is comprised of:
Excluding gains	231		199		476		383
Gains on sale of Northern Border Partners, L.P. interest and PipeLines LP units	13		1		13		49
	244		200		489		432

(2)Net Income Per Share from Continuing Operations is comprised of:
Excluding gains	$	0.47	$	0.41	$	0.97	$	0.79
Gains on sale of Northern Border Partners, L.P. interest and PipeLines LP units	0.03		—		0.03		0.10
	$	0.50	$	0.41	$	1.00	$	0.89

TransCanada’s net income and net income from continuing operations (net earnings) for second quarter 2006 were $244 million or $0.50 per share compared to $200 million or $0.41 per share for second quarter 2005. The increase of $44 million or $0.09 per share was primarily due to significantly higher net earnings from the Energy business and lower net expenses in Corporate, partially offset by lower net earnings from the Pipelines business.

The increase of $56 million in Energy’s net earnings for second quarter 2006 compared to second quarter 2005 was primarily due to higher operating income from each of its existing businesses as well as a $23 million favourable impact on future income taxes arising from a reduction in Canadian federal and provincial corporate income tax rates enacted in second quarter 2006. These increases were partially offset by the loss of operating income associated with the sale of the Power LP investment in third quarter 2005.

The $7 million decrease in Corporate’s net expenses in second quarter 2006 compared to second quarter 2005 was primarily due to a $10 million favourable impact on future income taxes arising from the reduction in Canadian federal and provincial corporate income tax rates in second quarter 2006. In addition, higher year-to-date interest income and other and the favourable impact of a weaker U.S. dollar were primarily offset by higher financial charges.

Pipelines’ net earnings for second quarter 2006 decreased $19 million compared to second quarter 2005 mainly due to lower net earnings from the Canadian Mainline and Alberta System, as a result of lower rates of return on common equity (ROE) and lower average investment bases. In addition, Canadian Mainline’s net earnings in second quarter 2005 included $13 million related to 2004 as a result of a second quarter 2005 decision from the National Energy Board (NEB) on the 2004 Tolls and Tariff Application (Phase II) dealing with capital structure. These decreases were partially offset by a $13 million after-tax gain on the sale of TransCanada’s 17.5 per cent general partner interest in Northern Border Partners, L.P. to a subsidiary of ONEOK Inc. (ONEOK) in second quarter 2006.

TransCanada’s net income for the six months ended June 30, 2006 was $517 million or $1.06 per share which included net income from discontinued operations of $28 million or $0.06 per share, reflecting bankruptcy settlements with Mirant Corporation and certain of its subsidiaries (Mirant) received in first quarter 2006 related to TransCanada’s Gas Marketing business divested in 2001. Net income for the six months ended June 30, 2005 was $432 million or $0.89 per share.

TransCanada’s net earnings for the six months ended June 30, 2006 were $489 million or $1.00 per share compared to $432 million or $0.89 per share for the same period in 2005. The increase of $57 million or $0.11 per share was primarily due to significantly higher net earnings from the Energy segment and lower net expenses in Corporate, partially offset by lower net earnings from the Pipelines segment.

The increase of $124 million in Energy’s net earnings for the six months ended June 30, 2006 compared to the same period in 2005 was primarily due to higher operating income from each of its existing businesses as

well as the $23 million favourable impact on future income taxes from the reduction of Canadian federal and provincial corporate income tax rates enacted in second quarter 2006. These increases were partially offset by the loss of operating income associated with the sale of the Power LP investment in third quarter 2005.

The decrease of $4 million in Corporate’s net expenses for the six months ended June 30, 2006 compared to the same period in 2005 was primarily due to the $10 million favourable impact on future income taxes in second quarter 2006 from the reduction of Canadian federal and provincial corporate income tax rates, partially offset by higher income tax refunds and positive income tax adjustments recorded in the six months ended June 30, 2005. In addition, higher year-to-date interest income and other and the favourable impact of a weaker U.S. dollar were primarily offset by higher financial charges.

Excluding the $49 million gain on sale of PipeLines LP units in 2005 and the $13 million gain on sale of TransCanada’s general partner interest in Northern Border Partners, L.P. in 2006, Pipelines’ net earnings for the six months ended June 30, 2006 decreased $35 million compared to the same period in 2005. This decrease was primarily due to lower net earnings from the Canadian Mainline and Alberta System as a result of lower ROE and lower average investment bases in 2006 compared to 2005, the $13 million net earnings impact in second quarter 2005 related to 2004 resulting from the NEB’s decision on the Canadian Mainline’s 2004 Tolls and Tariff Application (Phase II) as well as lower net earnings from TransCanada’s Other Pipelines. These decreases were partially offset by higher net earnings from GTN which included a $29 million ($18 million after tax) bankruptcy settlement with Mirant, a former shipper on the Gas Transmission Northwest System.

Funds generated from operations of $539 million and $1,056 million for the three and six months ended June 30, 2006 increased $41 million and $138 million, respectively, when compared to the same periods in 2005.

Pipelines

The Pipelines business generated net earnings of $147 million and $304 million for the three and six months ended June 30, 2006, respectively, compared to $166 million and $375 million for the same periods in 2005.

Pipelines Results-at-a-Glance

(unaudited)

	Three months ended June 30				Six months ended June 30
(millions of dollars)	2006		2005		2006		2005
Wholly-Owned Pipelines
Canadian Mainline	61		86		120		149
Alberta System	34		37		67		74
GTN	13		16		45		39
Foothills System	6		6		11		11
BC System	1		1		3		3
	115		146		246		276

Other Pipelines
Great Lakes	11		11		23		25
Iroquois	3		3		7		7
PipeLines LP	3		1		4		5
Portland	(2	)	—		4		6
Ventures LP	3		3		6		6
TQM	1		1		3		3
TransGas	2		3		5		6
Gas Pacifico/INNERGY	3		—		4		—
Northern Development	(1	)	(1	)	(2	)	(2	)
General, administrative, support costs and other	(4	)	(2	)	(9	)	(6	)
	19		19		45		50
Gain on sale of PipeLines LP units	—		1		—		49
Gain on sale of Northern Border Partners, L.P. interest	13		—		13		—
	32		20		58		99
Net Earnings	147		166		304		375

Wholly-Owned Pipelines

Canadian Mainline’s net earnings decreased $25 million and $29 million for the three and six months ended June 30, 2006, respectively, compared to the corresponding periods in 2005. These decreases were primarily due to a lower ROE, as determined by the NEB, of 8.88 per cent in 2006 compared to 9.46 per cent in 2005, a lower average investment base, and the positive impact of the NEB’s decision on the Canadian Mainline’s 2004 Tolls and Tariff Application (Phase II) in April 2005. This NEB decision included an increase in the deemed common equity ratio from 33 per cent to 36 per cent for 2004 which was also effective for 2005 under the 2005 tolls settlement with shippers. As a result, Canadian Mainline’s net earnings in second quarter 2005 included $13 million related to 2004.

The Alberta System’s net earnings decreased $3 million and $7 million for the three and six months ended June 30, 2006, respectively, compared to the same periods in 2005. These decreases were primarily due to a lower average investment base as well as a lower ROE, as determined by the Alberta Energy and Utilities Board (EUB), in 2006 compared to 2005. Net earnings in 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 2005.

GTN’s net earnings for second quarter 2006 decreased $3 million compared to second quarter 2005 which included a $2 million positive impact related to amortization of a fair value adjustment to long-term debt as a result of the purchase of GTN in late 2004. GTN’s net earnings for the six months ended June 30, 2006 were $45 million, a $6 million increase over the same period in 2005. This was primarily due to a $29 million ($18 million after tax) bankruptcy settlement with Mirant in first quarter 2006. Lower transportation revenues negatively impacted net earnings by approximately $6 million after tax. In addition, the results for the six months ended June 30, 2005 included $6 million of net earnings related to amortization of the fair value adjustment to long-term debt.

Operating Statistics

Gas

Transmission

Canadian

Alberta

Northwest

Foothills

Six months ended June 30

Mainline(1)

System(2)

System(3)

System

BC System

(unaudited)

2006

2005

2006

2005

2006

2005

2006

2005

2006

2005

Average investment base ($ millions)

7,454

7,873

4,305

4,534

n/a

654

687

207

219

Delivery volumes (Bcf)

Total

1,534

1,437

2,026

1,936

349

383

500

520

156

162

Average per day

8.5

7.9

11.2

10.7

1.9

2.1

2.8

2.9

0.9

0.9

(1) Canadian Mainline deliveries originating at the Alberta border and in Saskatchewan for the six months ended June 30, 2006 were 1,144 Bcf (2005 - 1,044 Bcf); average per day was 6.3 Bcf (2005 - 5.8 Bcf).

(2) Field receipt volumes for the Alberta System for the six months ended June 30, 2006 were 2,070 Bcf (2005 - 1,979 Bcf); average per day was 11.4 Bcf (2005 - 10.9 Bcf).

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

Other Pipelines

TransCanada’s proportionate share of net earnings from Other Pipelines was $32 million for the three months ended June 30, 2006 compared to $20 million for the same period in 2005. Net earnings in second quarter 2006 included a $13 million after-tax gain on the sale of TransCanada’s 17.5 per cent general partner interest in Northern Border Partners, L.P. while net earnings in second quarter 2005 included a $1 million after-tax gain on sale of PipeLines LP units. Excluding these gains, net earnings for second quarter 2006 were consistent with the same quarter in 2005. Increased net earnings from Gas Pacifico/INNERGY due to natural gas curtailments experienced in 2005 and from PipeLines LP, mainly due to an additional ownership interest in Northern Border, were offset by higher support costs and lower earnings from Portland due to a provision recorded in second quarter 2006 for non-payment of contract transportation revenue from a subsidiary of Calpine Corporation that has filed for bankruptcy protection.

Net earnings for the six months ended June 30, 2006 were $58 million compared to $99 million for the corresponding period in 2005. Excluding the $13 million after-tax gain on sale of the Northern Border Partners, L.P. general partner interest recorded in 2006, and the $49 million

after-tax gain on sale of PipeLines LP units recorded in 2005, net earnings for the six months ended June 30, 2006 were $5 million lower compared to the same period in 2005. Increased net earnings from Gas Pacifico/INNERGY as a result of natural gas curtailments in 2005 were more than offset by the impact of a weaker U.S. dollar in 2006, higher support costs, and lower net earnings from Portland compared to 2005.

As at June 30, 2006, TransCanada had advanced $104 million to the Aboriginal Pipeline Group with respect to the Mackenzie Gas Pipeline Project and had capitalized $10 million related to the Keystone pipeline.

Energy

Energy Results-at-a-Glance

(unaudited)

	Three months ended June 30				Six months ended June 30
(millions of dollars)	2006		2005		2006		2005
Bruce Power	41		13		104		43
Western Power Operations	46		28		104		58
Eastern Power Operations	43		39		92		44
Natural Gas Storage	17		3		39		11
Power LP Investment	—		8		—		17
General, administrative and support costs	(35	)	(30	)	(65	)	(63	)
Operating income	112		61		274		110
Financial charges	(5	)	(3	)	(12	)	(7	)
Interest income and other	1		—		3		3
Income taxes	(11	)	(17	)	(68	)	(33	)
Net Earnings	97		41		197		73

Energy’s net earnings of $97 million in second quarter 2006 increased $56 million compared to $41 million in second quarter 2005 due to higher operating income from each of its existing businesses and the positive impact of future income tax adjustments ($23 million) resulting from a reduction in Canadian federal and provincial corporate income tax rates enacted in second quarter 2006. Partially offsetting these increases was the loss of operating income associated with the sale of the Power LP investment in third quarter 2005.

Bruce Power’s contribution to operating income increased $28 million in second quarter 2006 compared to second quarter 2005, primarily due to higher generation volumes. Lower overall realized prices partially offset the positive impact of higher volumes.

Western Power Operations’ operating income was $18 million higher in second quarter 2006 compared to second 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 of power sold.

Eastern Power Operations’ operating income was $4 million higher in second quarter 2006 compared to second quarter 2005 primarily due to a higher overall margin on the sale of power and profits earned on natural gas purchased and resold under the OSP gas supply contracts. Partially offsetting these increases was the negative impact of a weaker U.S. dollar and an increase in the total cost of generating power primarily resulting from increased fuel costs associated with an increased dispatch of the OSP facility.

Natural Gas Storage operating income increased $14 million in second quarter 2006 compared to second quarter 2005 primarily due to higher contributions from the CrossAlta natural gas storage facility as a result of increased capacity and higher natural gas storage spreads.

Energy’s net earnings for the six months ended June 30, 2006 of $197 million increased $124 million compared to $73 million for the same period in 2005. The increase was due to higher contributions from each of its existing businesses and the positive impact of reduced corporate income tax rates. Partially offsetting these increases was the loss of operating income associated with the sale of the Power LP investment in third quarter 2005.

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 facility for both periods.

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

(unaudited)

	Three months ended June 30						Six months ended June 30
(millions of dollars)	2006			2005			2006			2005
Bruce Power (100 per cent basis)
Revenues
Power	439			385			918			796
Other(2)	11			8			28			15
	450			393			946			811
Operating expenses
Operations and maintenance	(226		)	(228		)	(446		)	(433		)
Fuel	(22		)	(18		)	(42		)	(37		)
Supplemental rent	(42		)	(41		)	(85		)	(82		)
Depreciation and amortization	(34		)	(49		)	(65		)	(97		)
	(324		)	(336		)	(638		)	(649		)
Revenues, net of operating expenses	126			57			308			162
Financial charges under equity accounting	—			(17		)	—			(34		)
	126			40			308			128

TransCanada’s proportionate share	39			12			101			40
Adjustments	2			1			3			3
TransCanada’s operating income from Bruce Power(3)	41			13			104			43

Bruce Power - Other Information
Plant availability
Bruce A	63%						71%
Bruce B	94%						95%
Combined Bruce Power	84%			71%			87%			76%
Sales volumes (GWh)(4)
Bruce A - 100 per cent	2,070						4,590
Bruce B - 100 per cent	6,630						13,250
Combined Bruce Power - 100 per cent	8,700			7,299			17,840			15,520
TransCanada’s proportionate share	3,094			2,306			6,400			4,904
Results per MWh(5)
Bruce A revenues	$	58					$	58
Bruce B revenues	$	48					$	49
Combined Bruce Power revenues	$	51		$	53		$	51		$	51
Fuel	$	2		$	2		$	2		$	2
Total operating expenses(6)	$	37		$	46		$	35		$	42
Percentage of output sold to spot market	39%			49%			38%			49%

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

(2) Includes fuel cost recoveries for Bruce A of $5 million and $11 million for the three and six months ended June 30, 2006, respectively.

(3) TransCanada’s consolidated equity income included $13 million and $43 million for the three and six months ended June 30, 2005, respectively, representing TransCanada’s 31.6 per cent share of Bruce Power earnings.

(4) Gigawatt hours.

(5) Megawatt hours.

(6) Net of fuel cost recoveries.

TransCanada’s operating income of $41 million from its combined investment in Bruce Power increased $28 million in second quarter 2006 compared to second quarter 2005, primarily due to higher generation volumes and an increased ownership interest in the Bruce A facilities, effective October 31, 2005. Partially offsetting the increases was the negative impact of lower realized prices.

TransCanada’s share of Bruce Power’s generation for second quarter 2006 increased 788 GWh to 3,094 GWh compared to second quarter 2005 generation of 2,306 GWh as a result of fewer planned maintenance outage days in second quarter 2006 than in second quarter 2005 and an increased ownership interest in the Bruce A facilities. Bruce Power prices achieved during second quarter 2006 (excluding other revenues) were $51 per MWh, compared to $53 per MWh in second quarter 2005. Bruce Power’s operating expenses (net of fuel cost recoveries) in second quarter 2006 decreased to $37 per MWh from $46 per MWh in second quarter 2005 primarily due to increased output in second quarter 2006.

Approximately 50 reactor days of planned maintenance outages as well as approximately 24 reactor days of unplanned outages, including an eight day extension of a planned outage, occurred on the six operating units in second quarter 2006. In second quarter 2005, Bruce Power experienced 81 reactor days of planned maintenance outages and 61 reactor days of unplanned outages. The Bruce Power units ran at a combined average availability of 84 per cent in second quarter 2006, compared to a 71 per cent average availability during second quarter 2005.

TransCanada’s operating income from its combined investment in Bruce Power for the six months ended June 30, 2006 was $104 million compared to $43 million for the same period in 2005. The increase of $61 million was primarily due to higher sales volumes resulting from increased plant availability and an increased ownership interest in the Bruce A facilities.

Combined Bruce Power prices achieved for the six months ended June 30, 2006 (excluding other revenues) were $51 per MWh, equal to the same period in 2005. Bruce Power’s combined operating expenses (net of fuel cost recoveries) decreased to $35 per MWh for the six months ended June 30, 2006 from $42 per MWh in 2005 primarily due to increased output in 2006. The Bruce units ran at a combined average availability of 87 per cent in the six months ended June 30, 2006 compared to 76 per cent in the same period in 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 during first quarter 2006 and a planned two month maintenance outage on Bruce A Unit 4 during second quarter 2006 were completed. 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 a contract with the Ontario Power Authority (OPA), for first quarter 2006, all of the output from Bruce A was 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 were 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 6,700 GWh of output for the remainder of 2006 and 6,300 GWh of output for 2007.

Bruce A’s four unit, seven year 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 June 30, 2006, Bruce A had incurred $645 million with respect to the restart and refurbishment project.

Western Power Operations

Western Power Operations Results-at-a-Glance
(unaudited)

	Three months ended June 30				Six months ended June 30
(millions of dollars)	2006		2005		2006		2005
Revenues
Power	221		151		496		315
Other(1)	38		37		102		79
	259		188		598		394

Cost of sales
Power	(150	)	(98	)	(340	)	(208	)
Other(2)	(28	)	(22	)	(76	)	(50	)
	(178	)	(120	)	(416	)	(258	)

Other costs and expenses	(30	)	(35	)	(68	)	(68	)
Depreciation	(5	)	(5	)	(10	)	(10	)

Operating income	46		28		104		58

(1) Includes Cancarb Thermax and natural gas sales.

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

Western Power Operations Sales Volumes

(unaudited)

	Three months ended June 30		Six months ended June 30
(GWh)	2006	2005	2006	2005
Supply
Generation	438	511	1,023	1,147
Purchased
Sundance A & B and Sheerness PPAs	2,846	1,713	6,237	3,544
Other purchases	519	614	1,005	1,345
	3,803	2,838	8,265	6,036

Contracted vs. Spot
Contracted	2,407	2,462	5,158	5,147
Spot	1,396	376	3,107	889
	3,803	2,838	8,265	6,036

Western Power Operations’ operating income of $46 million in second quarter 2006 was $18 million higher compared to second quarter 2005 primarily due to incremental earnings from the December 31, 2005 acquisition of the 756 MW Sheerness PPA. Operating income was also higher due to increased margins in second quarter 2006 compared to second quarter 2005 from higher overall realized power prices and higher market heat rates on uncontracted volumes of power sold. 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 29 per cent as a result of an approximate four per cent ($2.15 per MWh) increase in spot market power prices, while average spot market natural gas prices in Alberta decreased by approximately 18 per cent ($1.25 per GJ) in second quarter 2006 compared to the same quarter in 2005. A significant portion of power sales volumes were sold into the spot market in second quarter 2006 due to the acquisition of the Sheerness PPA on December 31, 2005. 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.

Power sales revenues and power cost of sales increased in second quarter 2006 compared to second quarter 2005 primarily due to the acquisition of the Sheerness PPA, effective December 31, 2005, and higher overall realized power prices in second quarter 2006. Generation volumes of 438 GWh in second quarter 2006 decreased 73 GWh compared to second quarter 2005 primarily due to planned outages and reduced dispatch of Alberta cogeneration assets during periods of uneconomic market conditions. The Bear Creek facility is expected to return to service in third quarter 2006. Purchased power volumes and the percentage of power volumes sold into the Alberta spot market increased in second quarter 2006 compared to 2005 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 37 per cent of power sales volumes were sold into the spot market in second quarter 2006 compared to 13 per cent in second quarter 2005. To reduce its exposure to spot market prices on uncontracted volumes, as at June 30, 2006, Western Power Operations had fixed price power sales contracts to sell approximately 5,900 GWh for the remainder of 2006 and approximately 7,900 GWh for 2007.

Eastern Power Operations

Eastern Power Operations Results-at-a-Glance

(unaudited)

	Three months ended June 30				Six months ended June 30
(millions of dollars)	2006		2005		2006		2005
Revenue
Power	174		129		335		244
Other(1)	58		73		175		143
	232		202		510		387

Cost of sales
Power	(89	)	(51	)	(190	)	(113	)
Other(1)	(53	)	(74	)	(149	)	(139	)
	(142	)	(125	)	(339	)	(252	)

Other costs and expenses	(40	)	(32	)	(65	)	(81	)
Depreciation	(7	)	(6	)	(14	)	(10	)

Operating income	43		39		92		44

(1) Other includes natural gas.

Eastern Power Operations Sales Volumes
(unaudited)

	Three months ended June 30		Six months ended June 30
(GWh)	2006	2005	2006	2005
Supply
Generation	949	962	1,654	1,406
Purchased	667	494	1,397	1,305
	1,616	1,456	3,051	2,711

Contracted vs. Spot
Contracted	1,503	1,228	2,886	2,417
Spot	113	228	165	294
	1,616	1,456	3,051	2,711

Operating income in second quarter 2006 from Eastern Power Operations of $43 million increased $4 million compared to $39 million in second quarter 2005. The increase was primarily due to higher overall margins on the sale of power and profits earned on natural gas purchased and resold under the OSP gas supply contracts. Partially offsetting these increases was the negative impact of a weaker U.S. dollar and an increase in the total cost of generating power primarily resulting from increased fuel costs associated with an increased dispatch of the OSP facility.

Operating income for the six months ended June 30, 2006 was $92 million or $48 million higher than the $44 million earned over the same period in 2005. The increase was primarily due to incremental income from the April 1, 2005 acquisition of the TC Hydro generation assets, a $16 million pre-tax ($10 million after tax) first quarter 2005 one-time restructuring payment from OSP to its natural gas fuel suppliers, and margins earned in first quarter 2006 on transportation related to unutilized OSP natural gas fuel. Partially offsetting these increases was the negative impact of a weaker U.S. dollar.

Generation volumes in second quarter 2006 decreased 13 GWh to 949 GWh compared to second quarter 2005. Lower generation from the TC Hydro generation assets was mostly offset by increased dispatch of the OSP facility.

Power sales revenues of $174 million increased $45 million in second quarter 2006 compared to second quarter 2005 due to higher realized prices resulting from increased contract prices and increased sales volumes. Power cost of sales of $89 million was higher in second quarter 2006 compared to second quarter 2005 due to the impact of higher prices for purchased power. Purchased power volumes of 667 GWh were higher in second quarter 2006 due to increased sales volumes. Second quarter 2006 other revenue and other cost of sales of $58 million and $53 million, respectively, decreased year-over-year primarily as a result of increased generation from the OSP facility leading to a reduction in natural gas being resold. Other costs and expenses in second quarter 2006 of $40 million, which includes fuel gas consumed in generation, increased primarily from the prior year as a result of increased generation from the OSP facility.

In second quarter 2006, approximately seven per cent of power sales volumes were sold into the spot market compared to approximately 16 per cent in second quarter 2005. Eastern Power 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 June 30, 2006, Eastern Power Operations had entered into fixed price power sales contracts to sell approximately 2,700 GWh for the remainder of 2006 and approximately 4,400 GWh for 2007, although certain contracted volumes are dependent on customer usage levels.

Natural Gas Storage

Natural Gas Storage operating income of $17 million and $39 million for the three and six months ended June 30, 2006, increased $14 million and $28 million, respectively, compared to the same periods in 2005. The increases were primarily due to higher contributions from the CrossAlta natural gas storage facility as a result of increased capacity and higher natural gas storage spreads, and income from other contracted third party natural gas storage capacity in Alberta.

General, Administrative and Support Costs

General, administrative and support costs of $35 million and $65 million for the three and six months ended June 30, 2006 increased $5 million and $2 million, respectively, compared to the same periods in 2005. The increases were primarily due to higher business development costs. As at June 30, 2006, TransCanada had capitalized $23 million related to the Broadwater LNG project.

Power Sales Volumes and Plant Availability

Power Sales Volumes

(unaudited)

	Three months ended June 30		Six months ended June 30
(GWh)	2006	2005	2006	2005
Bruce Power(1)	3,094	2,306	6,400	4,904
Western Power Operations(2)	3,803	2,838	8,265	6,036
Eastern Power Operations(3)	1,616	1,456	3,051	2,711
Power LP Investment(4)	—	723	—	1,420
Total	8,513	7,323	17,716	15,071

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

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

(3) TC Hydro is included in Eastern Power 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 to June 30, 2005.

Weighted Average Plant Availability(1)

(unaudited)

Three months ended June 30

Six months ended June 30

2006

2005

2006

2005

Bruce Power

84%

71%

87%

76%

Western Power Operations(2)

74%

81%

82%

85%

Eastern Power Operations(3)

98%

74%

97%

81%

Power LP Investment(4)

—

86%

—

92%

All plants, excluding Bruce Power

93%

79%

93%

85%

All plants

85%

76%

88%

82%

(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) Western Power Operation’s plant availability of 74 per cent for the three months ended June 30, 2006, reflects planned maintenance outages at the MacKay River, Bear Creek and Carseland cogeneration facilities.

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

(4) Power LP is included up to June 30, 2005.

Corporate

Net expenses for the three and six months ended June 30, 2006 were nil and $12 million, respectively, compared to net expenses of $7 million and $16 million for the corresponding periods in 2005.

The $7 million decrease in net expenses for second quarter 2006 compared to the same period in 2005 was primarily due to the $10 million favourable impact on future income taxes arising from a reduction in Canadian federal and provincial corporate income tax rates in second quarter 2006. In addition, higher year-to-date interest income and other and the favourable impact of a weaker U.S. dollar were primarily offset by higher financial charges.

The $4 million decrease in net expenses for the six months ended June 30, 2006 compared to the same period in 2005 was primarily due to the $10 million favourable impact on future income taxes in second quarter 2006, partially offset by higher income tax refunds and positive income tax adjustments recorded in the six months ended June 30, 2005. In addition, higher year-to-date interest income and other and the favourable impact of a weaker U.S. dollar were primarily offset by higher financial charges.

Liquidity and Capital Resources

Funds Generated from Operations

Funds generated from operations were $539 million and $1,056 million for the three and six months ended June 30, 2006, respectively, compared with $498 million and $918 million for the same periods 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 and six months ended June 30, 2006, capital expenditures totalled $327 million (2005 – $135 million) and $630 million (2005 – $243 million), respectively, and related primarily to the restart and refurbishment of Bruce A Units 1 and 2, construction of new power plants, construction of the Tamazunchale pipeline and Edson natural gas storage facilities as well as maintenance and other capacity capital in the Pipelines business.

In the three and six months ended June 30, 2006, disposition of assets, net of current income tax, generated $23 million (2005 - $1 million) and $23 million (2005 - $102 million), respectively. The disposition in 2006 related to the sale of TransCanada’s 17.5 per cent general partner interest in Northern Border Partners, L.P. The disposition in 2005 related to the sale of PipeLines LP units.

Acquisitions for each of the three and six months ended June 30, 2006 were $358 million (2005 – $632 million). The acquisition in 2006 related to the purchase of an additional 20 per cent general partnership interest in Northern Border by PipeLines LP. The acquisitions in 2005 related to the purchase of TC Hydro generation assets and an additional 3.52 per cent interest in Iroquois.

Financing Activities

TransCanada retired $208 million and $348 million of long-term debt in the three and six months ended June 30, 2006, respectively. TransCanada issued $372 million and $1,250 million of long-term debt in the three and six months ended June 30, 2006, respectively. For the three months ended June 30, 2006, outstanding notes payable increased by $180 million while for the six months ended June 30, 2006, outstanding notes payable decreased by $453 million. Cash and short-term investments for the three months ended June 30, 2006 decreased by $47 million and for the six months ended June 30, 2006 increased by $102 million.

Dividends

On July 27, 2006, TransCanada’s Board of Directors declared a quarterly dividend of $0.32 per share for the quarter ending September 30, 2006 on the outstanding common shares. This is the 171st consecutive quarterly dividend paid by TransCanada and its subsidiary on the common shares. It is payable on October 31, 2006 to shareholders of record at the close of business on September 29, 2006.

Contractual Obligations

There have been no material changes to TransCanada’s contractual obligations from December 31, 2005 to June 30, 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 and natural gas derivatives for overall management of its asset portfolio. The fair value and notional volumes of contracts for differences and the swap, future and option contracts are shown in the tables below.

Asset/(Liability)

		June 30, 2006 (unaudited)		December 31, 2005
(millions of dollars)	Accounting Treatment	Fair Value		Fair Value

Power - swaps and contracts for differences
(maturing 2006 to 2011)	Hedge	(79	)	(130	)
(maturing 2006 to 2010)	Non-hedge	—		13
Gas - swaps, futures and options
(maturing 2006 to 2016)	Hedge	(33	)	17
(maturing 2006 to 2008)	Non-hedge	18		(11	)

Notional Volumes
June 30, 2006	Accounting	Power (GWh)		Gas (Bcf)
(unaudited)	Treatment	Purchases	Sales	Purchases	Sales

Power - swaps and contracts for differences
(maturing 2006 to 2011)	Hedge	3,732	9,008	—	—
(maturing 2006 to 2010)	Non-hedge	1,631	972	—	—
Gas - swaps, futures and options
(maturing 2006 to 2016)	Hedge	—	—	87	62
(maturing 2006 to 2008)	Non-hedge	—	—	15	21

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

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 June 30, 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 the favourable impact of Canadian federal and provincial corporate income tax rate reductions and the net income from discontinued operations as a result of bankruptcy settlements received from Mirant. Excluding these impacts, 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 Pipelines and Energy.

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

Pipelines

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. On March 15, 2006, TransCanada filed its application with the NEB for approval of this settlement and associated tolls. On April 28, 2006, the NEB approved the application as filed, thereby setting the current interim tolls in effect as final tolls for 2006.

Alberta System

In February 2006, the 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 in accordance with the Alberta System three year settlement, a revised throughput forecast and the approved rate design. The EUB approved both the 2005 and 2006 Final Rates. The 2006 Final Rates were effective April 1, 2006.

Gas Transmission Northwest System

In June 2006, the Gas Transmission Northwest System filed a rate case with FERC. The comprehensive filing requests a number of tariff changes including an increase in rates for certain services. The current rates are based on the last rate case filed in 1994. Since that time, fundamental changes in the market place have resulted in a significant amount of unsubscribed capacity.

In its filing, the Gas Transmission Northwest System is applying to FERC for authority to share the costs of unsubscribed capacity with its long-term firm shippers through a number of changes to its rates. They include:

· An increase in its full-haul, long-term, firm service rate from 26 cents per dekatherm (Dth) to 45 cents per Dth. However, the rate paid by long-term firm shippers could be lower if the Gas Transmission Northwest System is successful in remarketing unsubscribed capacity;

· New rates for seasonal long-term firm and short-term transportation services; and

· Market based rates for full-haul interruptible transportation service.

The proposed rates include an ROE of 14.5 per cent, a common equity ratio of 62.99 per cent and a depreciation rate for transmission plant of 2.76 per cent.

Other Pipelines

In April 2006, PipeLines LP closed its acquisition of an additional 20 per cent general partnership interest in Northern Border for US$307 million bringing its total general partnership interest to 50 per cent. As part of the transaction, PipeLines LP indirectly assumed approximately US$120 million of debt of Northern Border. Of the total purchase price, US$114 million was allocated to goodwill and the remainder was allocated primarily to plant, property and equipment. Northern Border became a jointly controlled entity and TransCanada commenced proportionately consolidating its investment in Northern Border on a prospective basis as of April 2006. 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.

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 after-tax gain of $13 million. The net gain was recorded in the Pipelines segment and the company recorded a $10 million income tax charge, including $12 million of current income tax expense, on this transaction.

Northern Development

Mackenzie Gas Pipeline Project public hearings are expected to conclude in April 2007. The hearings are held by a Joint Review Panel which focuses on environmental and socio-economic impacts, and the NEB which is reviewing all other matters including pipeline engineering, safety, need and economic feasibility.

In June 2006, TransCanada filed an application with the EUB, seeking approval to build natural gas transmission infrastructure in northern Alberta which would serve to connect natural gas from the Mackenzie Gas Pipeline Project to the Alberta System. The timing of construction of the proposed infrastructure remains dependent upon the timing of the Mackenzie Gas Pipeline Project.

Keystone Pipeline

In April 2006, TransCanada filed an application with the U.S. Department of State for a Presidential Permit authorizing the construction, operation and maintenance of the Keystone pipeline.

In June 2006, TransCanada and TransCanada Keystone Pipeline GP Ltd. (Keystone Ltd.) filed an application with the NEB seeking approval to

transfer a portion of the Canadian Mainline to the Keystone pipeline for the purposes of transporting crude oil from Alberta to refining centres in the U.S. Midwest. As part of the transfer application, TransCanada is also seeking approval to reduce the Canadian Mainline rate base by the net book value (NBV) of the transferred facilities and Keystone Ltd. is seeking approval to add the NBV of the facilities to the Keystone pipeline rate base. The transfer application is the first of two major regulatory applications required to obtain approvals necessary to construct the Canadian portion of the Keystone pipeline. The project will also require regulatory approvals from various U.S. agencies. The NEB has scheduled an oral public hearing on the application to commence on October 23, 2006.

TransCanada expects to file an application with the NEB for a certificate of public convenience and necessity to construct the required new facilities later this year once environmental assessment work is completed. TransCanada filed its Preliminary Information Package for the required new facilities with the NEB on July 10, 2006.

TransCanada continued to consult with stakeholders along the proposed route of the Keystone pipeline in May and June 2006. Public consultations included a series of open houses related to the proposed extension of the Keystone pipeline to Cushing, Oklahoma. TransCanada anticipates holding a binding Open Season on the proposed Cushing Extension later this year.

Energy

Bruce Power

The Bruce A restart and refurbishment project reached a key milestone in July 2006 when the Canadian Nuclear Safety Commission accepted Bruce Power’s Environmental Assessment (EA), presented at a public hearing on May 19, 2006. Completion of the EA enables Bruce Power to move to the next stage of restart activities. The restart and refurbishment project will return another 1,500 MW of generating capacity to Ontario, commencing in late 2009. Units 1 and 2 are currently being kept in a defuelled, guaranteed shutdown state.

Cartier Wind

In June 2006, Cartier Wind began construction on the 100.5 MW Anse à Valleau wind farm, the second of the six wind farms that comprise the Cartier Wind project in the Gaspé region of Québec. The Anse à Valleau wind farm is expected to deliver energy to the Hydro-Québec grid by December 2007. Construction continues on the 109.5 MW Baie des Sable wind farm and remains on schedule for completion in 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.

Portlands Energy Centre

In April 2006, the Portlands Energy Centre (PEC) commenced preliminary site work in preparation for construction of a 550 MW high efficiency, combined-cycle generating station in downtown Toronto. PEC is a partnership between TransCanada and Ontario Power Generation. The partners continue to negotiate a long-term PPA with the Ontario Power Authority.

Bécancour

Construction is nearing completion on the 550 MW Bécancour cogeneration plant with successful testing and other related start-up activities completed in late second quarter 2006. The plant, near Trois-Rivières, Québec, is scheduled to begin commercial operations in fall 2006. The facility will supply electricity to Hydro-Québec Distribution under a long-term contract as well as provide a source of competitively priced steam for adjacent industrial processes.

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 LNG receiving terminals. The project’s next significant milestone was reached on June 15, 2006 with completion of hearings before a joint review panel of the Canadian Environmental Assessment Agency and Québec’s Bureau d’audiences publiques sur l’environnement. Regulatory decisions are expected by the end of 2006 and the facility is expected to be operational in late 2009 or early 2010.

Broadwater Energy filed a Coastal Zone Management Act application with the State of New York in April 2006 relating to the proposed Broadwater LNG project in Long Island Sound. Pending regulatory approvals, Broadwater plans to begin operation in late 2010.

Natural Gas Storage

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

Share Information

As at June 30, 2006, TransCanada had 487,812,778 issued and outstanding common shares. In addition, there were 9,946,581 outstanding options to purchase common shares, of which 6,989,842 were exercisable as at June 30, 2006.

Selected Quarterly Consolidated Financial Data(1)
(unaudited)

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

Revenues	1,685		1,894		1,771		1,494		1,449		1,410		1,480		1,311
Net Income
Continuing operations	244		245		350		427		200		232		185		193
Discontinued operations	—		28		—		—		—		—		—		52
	244		273		350		427		200		232		185		245

Share Statistics
Net income per share - Basic
Continuing operations	$	0.50	$	0.50	$	0.72	$	0.88	$	0.41	$	0.48	$	0.38	$	0.40
Discontinued operations	—		0.06		—		—		—		—		—		0.11
	$	0.50	$	0.56	$	0.72	$	0.88	$	0.41	$	0.48	$	0.38	$	0.51

Net income per share - Diluted
Continuing operations	$	0.50	$	0.50	$	0.71	$	0.87	$	0.41	$	0.48	$	0.38	$	0.39
Discontinued operations	—		0.06		—		—		—		—		—		0.11
	$	0.50	$	0.56	$	0.71	$	0.87	$	0.41	$	0.48	$	0.38	$	0.50

Dividend declared per common share	$	0.32	$	0.32	$	0.305	$	0.305	$	0.305	$	0.305	$	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 Pipelines 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 Energy business, which primarily builds, owns and operates electrical power generation plants, sells electricity and invests in natural gas storage facilities, 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.

· 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. Energy recorded a $16 million pre-tax positive impact of a restructuring transaction related to power purchase contracts between OSP and Boston Edison in Eastern Power Operations.

· First quarter 2005 net earnings included a $48 million after-tax gain related to the sale of PipeLines LP units. Energy’s 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, Energy’s net earnings included contributions from the December 31, 2005 acquisition of the 756 MW Sheerness PPA.

· Second quarter 2006 net earnings included a $33 million favourable impact on future income taxes ($23 million in Energy and $10 million in Corporate) arising from a reduction in Canadian federal and provincial corporate income tax rates. Pipelines earnings included a $13 million after-tax gain related to the sale of the company’s 17.5 per cent general partner interest in Northern Border Partners, L.P.

Exhibit 13.2

Consolidated Income

(unaudited) (millions of dollars except per	Three months ended June 30						Six months ended June 30
share amounts)	2006			2005			2006			2005

Revenues	1,685			1,449			3,579			2,859

Operating Expenses
Cost of sales	337			250			842			515
Other costs and expenses	566			419			1,103			841
Depreciation	266			254			523			505
	1,169			923			2,468			1,861

Other Expenses/(Income)
Financial charges	207			208			409			415
Financial charges of joint ventures	24			16			45			33
Equity income	(6		)	(26		)	(24		)	(76		)
Interest income and other	(15		)	(4		)	(64		)	(28		)
Gain on sale of Northern Border Partners, L.P. interest	(23		)	—			(23		)	—
Gain on sale of PipeLines LP units	—			(2		)	—			(82		)
	187			192			343			262

Income from Continuing Operations before Income Taxes and Non-Controlling Interests	329			334			768			736

Income Taxes
Current	37			79			247			240
Future	37			38			(4		)	26
	74			117			243			266

Non-Controlling Interests
Preferred share dividends of subsidiary	5			5			11			11
Non-controlling interest in PipeLines LP	8			12			21			21
Other	(2		)	—			4			6
	11			17			36			38

Net Income from Continuing Operations	244			200			489			432
Net Income from Discontinued Operations	—			—			28			—
Net Income	244			200			517			432

Net Income Per Share
Continuing operations	$	0.50		$	0.41		$	1.00		$	0.89
Discontinued operations	—			—			0.06			—
Basic and Diluted	$	0.50		$	0.41		$	1.06		$	0.89

Average Shares Outstanding - Basic (millions)	487.7			485.9			487.6			485.6

Average Shares Outstanding - Diluted (millions)	490.1			488.4			490.0			488.1

See accompanying notes to the consolidated financial statements.

Consolidated Cash Flows

(unaudited)	Three months ended June 30				Six months ended June 30
(millions of dollars)	2006		2005		2006		2005

Cash Generated from Operations
Net income from continuing operations	244		200		489		432
Depreciation	266		254		523		505
Gain on sale of PipeLines LP units, net of current income tax	—		(1	)	—		(31	)
Gain on sale of Northern Border Partners, L. P. interest, net of current income tax	(11	)	—		(11	)	—
Equity income lower than/(in excess of) distributions received	(3	)	14		(7	)	(17	)
Future income taxes	37		38		(4	)	26
Non-controlling interests	11		17		36		38
Funding of employee future benefits in excess of expense	(13	)	(10	)	(15	)	(17	)
Other	8		(14	)	45		(18	)
Funds generated from operations	539		498		1,056		918
Increase in operating working capital	(91	)	(177	)	(93	)	(263	)
Net cash provided by operations	448		321		963		655

Investing Activities
Capital expenditures	(327	)	(135	)	(630	)	(243	)
Acquisitions, net of cash acquired	(358	)	(632	)	(358	)	(632	)
Disposition of assets, net of current income tax	23		1		23		102
Deferred amounts and other	(7	)	10		(16	)	50
Net cash used in investing activities	(669	)	(756	)	(981	)	(723	)

Financing Activities
Dividends on common shares	(156	)	(149	)	(305	)	(289	)
Distributions paid to non-controlling interests	(15	)	(23	)	(31	)	(38	)
Notes payable issued/(repaid), net	180		289		(453	)	533
Long-term debt issued	372		499		1,250		799
Reduction of long-term debt	(208	)	(623	)	(348	)	(952	)
Long-term debt of joint ventures issued	22		—		24		5
Reduction of long-term debt of joint ventures	(15	)	(13	)	(21	)	(17	)
Common shares issued	5		18		13		29
Net cash provided by/(used in) financing activities	185		(2	)	129		70

Effect of Foreign Exchange Rate Changes on Cash and Short-Term Investments	(11	)	20		(9	)	22

(Decrease)/Increase in Cash and Short-Term Investments	(47	)	(417	)	102		24

Cash and Short-Term Investments
Beginning of period	361		632		212		191

Cash and Short-Term Investments
End of period	314		215		314		215

Supplementary Cash Flow Information
Income taxes paid	151		115		368		307
Interest paid	224		246		434		455

See accompanying notes to the consolidated financial statements.

Consolidated Balance Sheet

	June 30, 2006		December 31,
(millions of dollars)	(unaudited)		2005

ASSETS
Current Assets
Cash and short-term investments	314		212
Accounts receivable	741		796
Inventories	249		281
Other	205		277
	1,509		1,566
Long-Term Investments	74		400
Plant, Property and Equipment	20,778		20,038
Other Assets	2,205		2,109
	24,566		24,113

LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities
Notes payable	509		962
Accounts payable	1,244		1,494
Accrued interest	232		222
Current portion of long-term debt	313		393
Current portion of long-term debt of joint ventures	136		41
	2,434		3,112
Deferred Amounts	1,168		1,196
Future Income Taxes	691		703
Long-Term Debt	10,411		9,640
Long-Term Debt of Joint Ventures	1,157		937
Preferred Securities	513		536
	16,374		16,124
Non-Controlling Interest
Preferred shares of subsidiary	389		389
Non-controlling interest in PipeLines LP	307		318
Other	77		76
	773		783
Shareholders’ Equity
Common shares	4,768		4,755
Contributed surplus	273		272
Retained earnings	2,474		2,269
Foreign exchange adjustment	(96	)	(90	)
	7,419		7,206
	24,566		24,113

See accompanying notes to the consolidated financial statements.

Consolidated Retained Earnings

(unaudited)	Six months ended June 30
(millions of dollars)	2006		2005

Balance at beginning of period	2,269		1,655
Net income	517		432
Common share dividends	(312	)	(297	)
	2,474		1,790

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

The impacts on net income of the Pipelines and Energy segments in each quarter of 2005 and first quarter 2006 are as follows.

	2005										2006
(millions of dollars)	First		Second		Third		Fourth		Total		First

Pipelines
Net Income - previously reported as Gas Transmission	211		165		148		160		684		168
Reclassifications:
Natural gas storage	(4	)	(1	)	(2	)	(9	)	(16	)	(13	)
Costs related to LNG	2		2		3		4		11		2
Net Income - revised	209		166		149		155		679		157

Energy
Net Income - previously reported as Power	30		42		292		197		561		89
Reclassifications:
Natural gas storage	4		1		2		9		16		13
Costs related to LNG	(2	)	(2	)	(3	)	(4	)	(11	)	(2	)
Net Income - revised	32		41		291		202		566		100

Net Income

Three months ended June 30	Pipelines				Energy				Corporate				Total
(unaudited - millions of dollars)	2006		2005		2006		2005		2006		2005		2006		2005
Revenues	969		1,008		716		441		—		—		1,685		1,449
Cost of sales	—		—		(337	)	(250	)	—		—		(337	)	(250	)
Other costs and expenses	(326	)	(296	)	(236	)	(122	)	(4	)	(1	)	(566	)	(419	)
Depreciation	(235	)	(233	)	(31	)	(21	)	—		—		(266	)	(254	)
	408		479		112		48		(4	)	(1	)	516		526
Financial charges and non-controlling interests	(184	)	(194	)	—		—		(34	)	(31	)	(218	)	(225	)
Financial charges of joint ventures	(19	)	(13	)	(5	)	(3	)	—		—		(24	)	(16	)
Equity income	6		13		—		13		—		—		6		26
Interest income and other	2		(1	)	1		—		12		5		15		4
Gain on sale of Northern Border Partners, L.P. interest	23		—		—		—		—		—		23		—
Gain on sale of PipeLines LP units	—		2		—		—		—		—		—		2
Income taxes	(89	)	(120	)	(11	)	(17	)	26		20		(74	)	(117	)
Continuing Operations	147		166		97		41		—		(7	)	244		200
Discontinued Operations													—		—
Net Income													244		200

Six months ended June 30	Pipelines				Energy				Corporate				Total
(unaudited - millions of dollars)	2006		2005		2006		2005		2006		2005		2006		2005
Revenues	1,946		1,988		1,633		871		—		—		3,579		2,859
Cost of sales	—		—		(842	)	(515	)	—		—		(842	)	(515	)
Other costs and expenses	(643	)	(589	)	(455	)	(249	)	(5	)	(3	)	(1,103	)	(841	)
Depreciation	(461	)	(465	)	(62	)	(40	)	—		—		(523	)	(505	)
	842		934		274		67		(5	)	(3	)	1,111		998
Financial charges and non-controlling interests	(376	)	(390	)	—		(2	)	(69	)	(61	)	(445	)	(453	)
Financial charges of joint ventures	(33	)	(28	)	(12	)	(5	)	—		—		(45	)	(33	)
Equity income	24		33		—		43		—		—		24		76
Interest income and other	34		13		3		3		27		12		64		28
Gain on sale of Northern Border Partners, L.P. interest	23		—		—		—		—		—		23		—
Gain on sale of PipeLines LP units	—		82		—		—		—		—		—		82
Income taxes	(210	)	(269	)	(68	)	(33	)	35		36		(243	)	(266	)
Continuing Operations	304		375		197		73		(12	)	(16	)	489		432
Discontinued Operations													28		—
Net Income													517		432

Total Assets

	June 30, 2006	December 31,
(millions of dollars)	(unaudited)	2005

Pipelines	18,007	17,857
Energy	5,422	5,318
Corporate	1,137	938
	24,566	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

Asset/(Liability)

		June 30, 2006 (unaudited)		December 31, 2005
(millions of dollars)	Accounting Treatment	Fair Value		Fair Value

Power - swaps and contracts for differences
(maturing 2006 to 2011)	Hedge	(79	)	(130	)
(maturing 2006 to 2010)	Non-hedge	—		13
Gas - swaps, futures and options
(maturing 2006 to 2016)	Hedge	(33	)	17
(maturing 2006 to 2008)	Non-hedge	18		(11	)

Notional Volumes		Power (GWh)		Gas (Bcf)
June 30, 2006 (unaudited)	Accounting Treatment	Purchases	Sales	Purchases	Sales

Power - swaps and contracts for differences
(maturing 2006 to 2011)	Hedge	3,732	9,008	—	—
(maturing 2006 to 2010)	Non-hedge	1,631	972	—	—
Gas - swaps, futures and options
(maturing 2006 to 2016)	Hedge	—	—	87	62
(maturing 2006 to 2008)	Non-hedge	—	—	15	21

		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

4. 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.

In April 2006, TC PipeLines, LP (PipeLines LP) borrowed US$307 million under its unsecured credit facility to finance the cash portion of the purchase price of its acquisition of an additional 20 per cent interest in Northern Border Pipeline Company (Northern Border). The credit facility has a term of two years and all amounts outstanding will be due and payable on March 31, 2008. Borrowings under the credit facility will bear interest based, at PipeLines LP’s election, on the London interbank offered rate or the base rate plus, in either case, an applicable margin.

5. Discontinued Operations

TransCanada’s net income for the six months ended June 30, 2006 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.

6. Acquisitions and Dispositions

7. Income Taxes

In second quarter 2006, TransCanada recorded a $33 million future income tax benefit ($23 million in Energy and $10 million in Corporate) as a result of a reduction in Canadian federal and provincial corporate income tax rates enacted in second quarter 2006.

8. 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 and six months ended June 30, respectively, is as follows.

Three months ended June 30	Pension Benefit Plans				Other Benefit Plans
(unaudited - millions of dollars)	2006		2005		2006		2005
Current service cost	9		8		1		1
Interest cost	16		16		2		2
Expected return on plan assets	(17	)	(16	)	(1	)	—
Amortization of net actuarial loss	7		4		—		—
Amortization of past service costs	1		—		1		—
Net benefit cost recognized	16		12		3		3

Six months ended June 30	Pension Benefit Plans				Other Benefit Plans
(unaudited - millions of dollars)	2006		2005		2006		2005
Current service cost	18		15		1		1
Interest cost	33		32		4		3
Expected return on plan assets	(35	)	(32	)	(1	)	—
Amortization of transitional obligation related to regulated business	—		—		1		1
Amortization of net actuarial loss	14		8		1		1
Amortization of past service costs	2		1		1		—
Net benefit cost recognized	32		24		7		6

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 unaudited consolidated financial statements of TransCanada Corporation (TransCanada or the Company) for the six months ended June 30, 2006 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 six months ended June 30, 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 six months ended June 30, 2006 prepared in accordance with Canadian GAAP.

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

(millions of dollars except per share	Three months ended June 30						Six months ended June 30
amounts)	2006			2005			2006			2005
Revenues	1,322			1,293			2,815			2,564
Cost of sales	267			188			632			409
Other costs and expenses	442			406			872			828
Depreciation	222			230			445			458
	931			824			1,949			1,695
	391			469			866			869
Other (income)/expenses
Equity income(1)	(99		)	(69		)	(218		)	(167		)
Other expenses(2)	182			218			361			343
Income taxes	70			118			239			264
	153			267			382			440

Net income from continuing operations - U.S. GAAP	238			202			484			429
Net income from discontinued operations - U.S. GAAP	—			—			28			—
Net Income in Accordance with U.S. GAAP	238			202			512			429
Adjustments affecting comprehensive income under U.S. GAAP
Foreign currency translation adjustment, net of tax	(2		)	5			(6		)	10
Unrealized gain/(loss) on derivatives, net of tax(3)	16			(30		)	34			(39		)
Comprehensive Income in Accordance with U.S. GAAP	252			177			540			400

Net Income Per Share in Accordance with U.S. GAAP
Continuing operations	$	0.49		$	0.42		$	0.99		$	0.88
Discontinued operations	—			—			0.06			—
Basic	$	0.49		$	0.42		$	1.05		$	0.88
Diluted	$	0.49		$	0.41		$	1.05		$	0.88

Net Income Per Share in Accordance with Canadian GAAP - Basic and Diluted	$	0.50		$	0.41		$	1.06		$	0.89
Dividends per common share	$	0.32		$	0.305		$	0.64		$	0.61

Common Shares Outstanding (millions)
Average for the period - Basic	487.7			485.9			487.6			485.6
Average for the period - Diluted	490.1			488.4			490.0			488.1

Reconciliation of Income from Continuing Operations

	Three months ended June 30				Six months ended June 30
(millions of dollars)	2006		2005		2006		2005
Net Income from Continuing Operations in Accordance with Canadian GAAP	244		200		489		432
U.S. GAAP adjustments
Unrealized (loss)/gain on energy contracts(3)	(12	)	1		(11	)	(9	)
Tax impact of unrealized (loss)/gain on energy contracts	4		(1	)	4		3
Equity investment gain(4)(5)	1		1		1		3
Tax impact of equity investment gain	—		—		—		(1	)
Unrealized gain on foreign exchange and interest rate derivatives(3)	1		1		1		1
Tax impact of unrealized gain on foreign exchange and interest rate derivatives	—		—		—		—
Net Income from Continuing Operations in Accordance with U.S. GAAP	238		202		484		429

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

	Three months ended June 30				Six months ended June 30
(millions of dollars)	2006		2005		2006		2005
Cash Generated from Operations(6)
Net cash provided by operating activities	471		271		965		535

Investing Activities
Net cash used in investing activities	(683	)	(720	)	(947	)	(628	)

Financing Activities
Net cash provided by financing activities	178		12		117		83

Effect of Foreign Exchange Rate Changes on Cash and Short-Term Investments	(8	)	20		(7	)	22
(Decrease)/Increase in Cash and Short-Term Investments	(42	)	(417	)	128		12
Cash and Short-Term Investments
Beginning of period	253		556		83		127
Cash and Short-Term Investments
End of period	211		139		211		139

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

	June 30,	December 31,
(millions of dollars)	2006	2005
Current assets(7)	1,041	1,058
Long-term investments(1)(4)(5)	2,680	2,168
Plant, property and equipment	17,167	17,348
Regulatory asset(8)	2,134	2,601
Other assets(4)	1,973	2,028
	24,995	25,203

Current liabilities(9)	2,059	2,754
Deferred amounts(3)(5)	1,282	1,298
Long-term debt(3)	10,435	9,675
Deferred income taxes(8)	2,635	3,102
Preferred securities	513	536
Non-controlling interests	773	783
Shareholders’ equity	7,298	7,055
	24,995	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 $(15)(3)	—		—		34		34
Foreign currency translation adjustment, net of tax of $(34)	(6	)	—		—		(6	)
Balance at June 30, 2006	(95	)	(77	)	(24	)	(196	)

Balance at December 31, 2004	(71	)	(26	)	(4	)	(101	)
Unrealized loss on derivatives, net of tax of $20(3)	—		—		(39	)	(39	)
Foreign currency translation adjustment, net of tax of $18	10		—		—		10
Balance at June 30, 2005	(61	)	(26	)	(43	)	(130	)

(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 $3 million for the six months ended June 30, 2006 (June 30, 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 six months ended June 30, 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 six months ended June 30, 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 June 30, 2006 was $17 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 six months ended June 30, 2006 was $1 million (June 30, 2005 - nil).

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

(7) Current assets at June 30, 2006 include derivative contracts of $30 million (December 31, 2005 - $49 million) and hedging deferrals of $61 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. A reduction in Canadian federal and provincial corporate income tax rates enacted in second quarter 2006 resulted in a decrease of $406 million in the deferred income tax liability and corresponding regulatory asset.

(9) Current liabilities at June 30, 2006 include dividends payable of $161 million (December 31, 2005 - $154 million) and current taxes payable of $168 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.

In March 2006, FASB issued SFAS No. 156 “Accounting for Servicing of Financial Assets - an amendment of FASB Statement No. 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. 156 requires recognition of a servicing asset or liability when an entity enters into arrangements to service financial instruments in certain situations. Such servicing assets or servicing liabilities are required to be initially measured at fair value, if practicable. SFAS No. 156 also allows an entity to subsequently measure its servicing assets or servicing liabilities using either an amortization method or a fair value method. Adopting the provisions under SFAS No. 156, as of January 1, 2007, is not expected to have an impact on the U.S. GAAP financial statements of the Company.

In July 2006, FASB issued FIN 48 “Accounting for Income Tax Uncertainties” which is effective for fiscal years beginning after December 15, 2006. FIN 48 clarifies, for US GAAP purposes, the accounting for uncertain tax positions. The best estimate of the impact of a company’s tax position taken for income tax return purposes is required to be recorded if it is probable of being sustained on audit. The guidance provided in FIN 48 seeks to reduce the diversity in practice associated with certain aspects of the recognition and measurement related to accounting for income taxes. TransCanada is in the process of assessing the impact of the application of FIN 48 on its US GAAP financial statements.

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 June 30				Six months ended June 30
(millions of dollars)	2006		2005		2006		2005
Income
Revenues	348		300		704		614
Other costs and expenses	(176	)	(163	)	(350	)	(309	)
Depreciation	(47	)	(40	)	(87	)	(84	)
Financial charges and other	(26	)	(28	)	(49	)	(54	)
Proportionate share of income before income taxes of long-term investments	99		69		218		167

	June 30,		December 31,
(millions of dollars)	2006		2005
Balance Sheet
Current assets	428		456
Plant, property and equipment	3,745		3,365
Other assets (net)	183		—
Current liabilities	(356	)	(319	)
Deferred amounts (net)	—		(2	)
Non-recourse debt	(1,293	)	(1,307	)
Deferred income taxes	(27	)	(25	)
Proportionate share of net assets of long-term investments	2,680		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 July 27, 2006		Harold N. Kvisle
		President and Chief Executive Officer

Exhibit 31.2

Certifications

I, Gregory A. Lohnes, 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 / Gregory A. Lohnes
Dated July 27, 2006		Gregory A. Lohnes
		Executive Vice-President and Chief Financial Officer

Exhibit 32.1

TRANSCANADA CORPORATION

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

CERTIFICATION OF CHIEF EXECUTIVE OFFICER
REGARDING PERIODIC REPORT CONTAINING
FINANCIAL STATEMENTS

I, Harold N. Kvisle, the Chief Executive Officer of TransCanada Corporation (the “Company”), in compliance with 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, hereby certify, in connection with the Company’s Quarterly Report as filed on Form 6-K for the period ended June 30, 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
		July 27, 2006

Exhibit 32.2

TRANSCANADA CORPORATION

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

CERTIFICATION OF CHIEF FINANCIAL OFFICER
REGARDING PERIODIC REPORT CONTAINING
FINANCIAL STATEMENTS

I, Gregory A. Lohnes, the Chief Financial Officer of TransCanada Corporation (the “Company”), in compliance with 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, hereby certify, in connection with the Company’s Quarterly Report as filed on Form 6-K for the period ended June 30, 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 / Gregory A. Lohnes
		Gregory A. Lohnes
		Chief Financial Officer
		July 27, 2006

Exhibit 99.1

TRANSCANADA CORPORATION – SECOND 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 Second Quarter Results
Board Declares Dividend of $0.32 per share

CALGARY, Alberta – July 27, 2006 – (TSX: TRP) (NYSE: TRP)

Second Quarter 2006 Highlights:
(All financial figures are in Canadian dollars unless noted otherwise).

· Net income from continuing operations for second quarter 2006 of $244 million or $0.50 per share.

· Funds generated from operations for second quarter 2006 of $539 million.

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

TransCanada Corporation today announced net income and net income from continuing operations (net earnings) for second quarter 2006 of $244 million or $0.50 per share, compared to $200 million or $0.41 per share for second quarter 2005. The increase was primarily due to significantly higher net earnings from the Energy segment and lower net expenses in Corporate, partially offset by lower net earnings from the Pipelines segment. Second quarter 2006 net earnings included a $33 million future income tax benefit ($23 million in the Energy segment and $10 million in Corporate) as a result of a reduction in Canadian federal and provincial corporate income tax rates and a $13 million after-tax gain related to the sale of the company’s general partnership interest in Northern Border Partners, L.P. Second quarter 2005 net earnings included $13 million related to 2004 as a result of a decision from the National Energy Board in April 2005 on Phase II of the Canadian Mainline’s 2004 Tolls and Tariff Application. Excluding these items, net earnings for second quarter 2006 increased by $11 million or $0.02 per share compared to second quarter 2005.

For the six months ended June 30, 2006, TransCanada’s net earnings were $489 million or $1.00 per share compared to $432 million or $0.89 per share for the same period in 2005. In addition to the items noted above, net earnings for the six months ended June 30, 2006 include an $18 million

after-tax bankruptcy settlement receipt from a former shipper on the Gas Transmission Northwest System and net earnings for the six months ended June 30, 2005 include an after-tax gain of $49 million on the sale of TC PipeLines, LP common units. Excluding all of the above noted items, net earnings for the six months ended June 30, 2006 increased by $55 million or $0.11 per share compared to the same period in 2005.

Net income for the six months ended June 30, 2006 includes $28 million or $0.06 per share from discontinued operations reflecting settlements received in the first quarter 2006 from bankruptcy claims related to TransCanada’s Gas Marketing business which was divested in 2001. Net income for the six months ended June 30, 2006 totalled $517 million or $1.06 per share compared to $432 million or $0.89 per share for the same period in 2005.

“TransCanada’s strong operating performance during the first six months of 2006 contributed to continued growth in earnings and funds generated from operations,” said Hal Kvisle, president and chief executive officer.

“The increase in net earnings from our Energy business is evidence that our disciplined approach to growth and value creation is working. Our focus on acquiring low-cost, competitive power facilities and developing low risk, greenfield power projects is creating real value for our shareholders,” he said. “TransCanada’s Pipelines business continued to deliver solid results although net earnings declined primarily as a result of lower rates of return on common equity and lower average investment bases on the Canadian Mainline and Alberta System.

“Going forward,” said Mr. Kvisle, “TransCanada remains focused on maximizing the long-term value of our existing asset base and prudently growing our portfolio of high quality, long-life energy infrastructure assets. We have an excellent portfolio of growth opportunities, with several projects, including the 550 megawatt Bécancour cogeneration plant, the initial phase of the 740 megawatt Cartier Wind facilities, the Edson natural gas storage facility and the Tamazunchale pipeline in Mexico, all expected to begin commercial operations by the end of the year.

“We also continue to make solid progress on the Bruce Power restart and refurbishment project and to advance the Keystone oil pipeline and the Cacouna and Broadwater LNG facilities through the regulatory process. We remain committed to pursuing pipeline opportunities to move northern frontier natural gas to growing North American markets.”

Recent Developments

Pipelines

· Construction of the 125 kilometre Tamazunchale pipeline is nearing completion and on schedule to be placed in service in December 2006. The US$181 million pipeline will transport natural gas under a long-term (26 year) contract with the Mexican Comisión Federal de Electricidad to an electricity generation station near Tamazunchale, San Luis Potosi, Mexico. Under the contract, the capacity of the Tamazunchale pipeline will be expanded beginning in 2009 to meet the needs of two additional proposed power plants.

· On June 30, 2006, the Gas Transmission Northwest System, TransCanada’s wholly-owned interstate pipeline that serves markets in the U.S. Pacific Northwest and California, filed a rate case with the U.S. Federal Energy Regulatory Commission. The comprehensive filing requested a number of tariff changes including an increase in rates for certain services. This is the Gas Transmission Northwest System’s first rate case since 1994.

· On June 26, 2006, TransCanada filed an application with the Alberta Energy and Utilities Board (EUB), seeking approval to build natural gas transmission infrastructure in northern Alberta which would serve to connect natural gas from the Mackenzie Gas Pipeline Project to the Alberta System. TransCanada is proposing construction of approximately 103 kilometres of pipeline in two separate sections in the Dickins Lake and Vardie River area at an estimated cost of $212 million. The timing of construction of the proposed infrastructure remains dependent upon the timing of the Mackenzie Gas Pipeline Project. Public hearings on the project are now anticipated to conclude in April 2007.

· On June 6, 2006, TransCanada advanced the US$2.1 billion Keystone oil pipeline project with the filing of an application with the National Energy Board (NEB) seeking approval to transfer a portion of the Canadian Mainline to the Keystone pipeline for the purpose of transporting crude oil from Alberta to refining centres in the U.S. Midwest. The transfer application is the first of two major regulatory applications required to obtain approvals necessary to construct the Canadian portion of the Keystone pipeline. The project will also require regulatory approvals from various U.S. agencies. The NEB has scheduled an oral public hearing on the application to commence on October 23, 2006.

TransCanada also continued to consult with stakeholders along the proposed route of the Keystone pipeline in May and June 2006. Public consultations included a series of open houses relating to the proposed extension of the Keystone pipeline to Cushing, Oklahoma.

TransCanada anticipates holding a binding Open Season on the proposed Cushing Extension later this year.

· Details of the natural gas contract between the State of Alaska and North Slope producers regarding the Alaska Highway Pipeline Project were made public in May 2006. The contract remains contingent on legislative approval and enactment of legislation related to State taxes on crude oil. The Alaska legislature reconvened in a special session beginning July 12, 2006 to consider the petroleum production tax legislation. TransCanada looks forward to working with the State and producers to bring Alaska natural gas to market.

· The 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 closed on April 6, 2006. As part of the series of transactions, TC PipeLines, LP acquired an additional 20 per cent interest in Northern Border bringing its total general partnership interest in Northern Border to 50 per cent. A subsidiary of TransCanada is the general partner of TC PipeLines, LP. TransCanada owns 13.4 per cent of the partnership’s common units.

Energy

· Construction is nearing completion on the 550 megawatt (MW) Bécancour cogeneration plant with successful testing and other related start-up activities completed in late second quarter 2006. The plant, near Trois-Rivières, Québec, is scheduled to begin commercial operations in fall 2006. The facility will supply electricity to Hydro-Québec Distribution under a long-term contract as well as provide a source of competitively priced steam for adjacent industrial processes.

· In June, Cartier Wind began construction on the 100.5 MW Anse à Valleau wind farm, the second of the six wind farms that comprise the Cartier Wind project in the Gaspé region of Québec. The Anse à Valleau wind farm is expected to deliver energy to the Hydro-Québec grid by December 2007. Construction continues on the 109.5 MW Baie des Sables wind farm and remains on schedule for completion in 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.

· The Bruce A restart and refurbishment project reached a key milestone on July 5, 2006 when the Canadian Nuclear Safety Commission accepted Bruce Power’s Environmental Assessment (EA), presented at a public hearing May 19, 2006. Completion of the EA enables Bruce Power to move to the next stage of restart activities. This is the first life extension undertaken on a CANDU nuclear power plant in Canada. 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.

· Construction also continues on the Edson natural gas storage facility in Alberta. The Edson facility is expected to have a working natural

gas capacity of approximately 60 petajoules and will connect to the Alberta System. Storage capacity is expected to be available commencing later this year.

· In April 2006, the Portlands Energy Centre (PEC) commenced preliminary site work in preparation for construction of a 550 MW high efficiency, combined-cycle generating station in downtown Toronto. PEC is a partnership between TransCanada and Ontario Power Generation. The partners continue to negotiate a long-term power purchase arrangement with the Ontario Power Authority.

· Hearings on the Cacouna Energy project before a joint review panel of the Canadian Environmental Assessment Agency and Québec’s Bureau d’audiences publiques sur l’environnement concluded June 15, 2006. Regulatory decisions are expected by the end of 2006. The LNG receiving terminal, designed to regasify approximately 500 million cubic feet of natural gas per day, is expected to be operational in late 2009 or early 2010. Another milestone of the project was achieved in early April with the awarding of the contract for front-end engineering and design work to an international consortium of engineering and construction firms. Cacouna Energy is a partnership between TransCanada and Petro-Canada.

· Broadwater Energy filed a Coastal Zone Management Act application with the State of New York in April 2006 relating to the proposed Broadwater LNG project in Long Island Sound. Pending regulatory approvals, Broadwater plans to begin operation in late 2010 and is designed to regasify one billion cubic feet of natural gas per day. Broadwater is a partnership between TransCanada and Shell US Gas & Power LLC.

Teleconference

TransCanada will hold a teleconference today at 2 p.m. (Mountain) / 4 p.m. (Eastern) to discuss the second 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 1-866-898-9626 or 416-340-2216 (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) August 3, 2006. Please call 1-800-408-3053 or 416-695-5800 (Toronto area) and enter passcode 3192148. 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.

Exhibit 31.1

Exhibit 31.2

Exhibit 32.1

TRANSCANADA CORPORATION

Exhibit 32.2

TRANSCANADA CORPORATION

Second Quarter 2006 Highlights:(All financial figures are in Canadian dollars unless noted otherwise).

Teleconference

About TransCanada

Second Quarter 2006 Highlights:
(All financial figures are in Canadian dollars unless noted otherwise).