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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 2005

COMMISSION FILE No. 1-31690

TransCanada Corporation

(Translation of Registrant’s Name into English)

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

(Address of Principal Executive Offices)

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

Form 20-F

Form 40-F

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

Yes

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

Form		Registration No.
S-8		33-00958
S-8		333-5916
S-8		333-8470
S-8		333-9130
F-3		33-13564
F-3		333-6132

13.1 Management’s Discussion and Analysis of Financial Condition and Results of Operations of the registrant as at and for the period ended June 30, 2005.

13.2 Consolidated comparative interim unaudited financial statements of the registrant for the six month period ended June 30, 2005 (included in the registrant’s Second Quarter 2005 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 2005 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 29, 2005.

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

	TRANSCANADA CORPORATION


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


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


July 29, 2005

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, 2005.

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 29, 2005.

Exhibit 13.1

Management’s Discussion and Analysis

Management’s discussion and analysis (MD&A) dated July 28, 2005 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, 2005. It should also be read in conjunction with the MD&A contained in TransCanada’s 2004 Annual Report for the year ended December 31, 2004 as well as the restated 2004 audited consolidated financial statements. 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.

Results of Operations

Consolidated

Segment Results-at-a-Glance
(unaudited)	Three months ended June 30						Six months ended June 30
(millions of dollars except per share amounts)	2005			2004			2005			2004
GasTransmission Net Income
Excluding gains	164			139			327			288
Gain related to PipeLines LP	1			—			49			—
Gain related to Millennium	—			7			—			7
	165			146			376			295
Power Net Income
Excluding gains	42			62			72			127
Gains related to Power LP	—			187			—			187
	42			249			72			314
Corporate	(7		)	(7		)	(16		)	(7		)

Net Income (1)	200			388			432			602

Net Income Per Share - Basic and Diluted	$	0.41		$	0.80		$	0.89		$	1.24

(1)Net Income iscomprised of:
Excluding gains	199	194	383	408
Gains related to PipeLines LP, Power LP and Millennium	1	194	49	194
	200	388	432	602

TransCanada’s net income for second quarter 2005 was $200 million or $0.41 per share compared to $388 million or $0.80 per share for the same period in 2004. The decrease of $188 million or $0.39 per share was primarily due to the recording in second quarter 2004 of $187 million of after-tax gains relating to the sale of the ManChief and Curtis Palmer assets to TransCanada Power, L.P.

(Power LP) and the recognition of dilution gains resulting from a reduction in TransCanada’s ownership interest in Power LP and other previously deferred gains, as well as a $7 million after-tax gain on sale of the company’s equity interest in the Millennium Pipeline project (Millennium).

Excluding the total gains of $194 million recorded in second quarter 2004 related to Power LP and Millennium and $1 million recorded in second quarter 2005 related to TC PipeLines, LP (PipeLines LP), net income for second quarter 2005 increased $5 million to $199 million compared to second quarter 2004. This was mainly due to a $25 million increase in Gas Transmission’s net income for second quarter 2005, partially offset by a decrease of $20 million in Power’s net income. The increase in Gas Transmission’s net income was primarily due to net income of approximately $21 million ($13 million related to 2004 and $8 million related to the first six months of 2005) recorded in second quarter 2005 as a result of the decision from the National Energy Board (NEB) on the Canadian Mainline’s 2004 Tolls and Tariff Application (Phase II) dealing with capital structure which increased deemed equity thickness to 36 per cent from 33 per cent effective January 1, 2004. In addition, $16 million was generated from the Gas Transmission Northwest System and the North Baja System (collectively GTN), which were acquired by TransCanada on November 1, 2004. The decrease in Power’s net income was primarily due to lower equity income from Bruce Power L.P. (Bruce Power) and lower operating and other income from Western Operations, partially offset by higher operating and other income from Eastern Operations as a result of the USGen New England, Inc. (USGen) acquisition. Corporate net expenses for second quarter 2005 were consistent with the prior year second quarter.

TransCanada’s net income for the six months ended June 30, 2005 was $432 million or $0.89 per share compared to $602 million or $1.24 per share for the comparable period in 2004. The decrease of $170 million or $0.35 per share in the first six months of 2005 compared to the same period in 2004 was primarily due to the 2004 gains related to Power LP and, in 2005, lower Power net income and higher net expenses in the Corporate segment, partially offset by higher net income from the Gas Transmission business.

Excluding the above-mentioned $187 million of gains related to Power LP in the first six months of 2004, Power net income for the six months ended June 30, 2005 decreased $55 million as a result of lower equity income from Bruce Power and reduced contributions from Eastern and Western Operations.

The increase in net expenses of $9 million in the Corporate segment in the six months ended June 30, 2005 was primarily as a result of higher interest expense compared to the same period in

2004. In second quarter 2005, this higher interest expense was primarily offset by income tax refunds and certain positive income tax adjustments.

Excluding the $49 million after-tax gain on sale of PipeLines LP units in 2005 and the $7 million after-tax gain on sale of the company’s equity interest in Millennium in 2004, the $39 million increase in net income in the Gas Transmission business for the six months ended June 30, 2005 compared to the same period in 2004 was primarily attributable to $39 million generated from GTN.

Funds generated from operations of $479 million and $886 million for the three and six months ended June 30, 2005 increased $97 million and $89 million, respectively, when compared to the same periods in 2004.

Gas Transmission

The Gas Transmission business generated net income of $165 million and $376 million for the three and six months ended June 30, 2005, respectively, compared to $146 million and $295 million for the same periods in 2004.

Gas Transmission Results-at-a-Glance
(unaudited)	Three months ended June 30				Six months ended June 30
(millions of dollars)	2005		2004		2005		2004
Wholly-Owned Pipelines
Canadian Mainline	86		66		149		130
Alberta System	37		39		74		79
GTN (1)	16				39
Foothills System	6		5		11		11
BC System	1		1		3		3
	146		111		276		223
Other Gas Transmission
Great Lakes	11		14		25		31
Iroquois	3		3		7		11
PipeLines LP	1		5		5		9
Portland	—		—		6		6
Ventures LP	3		4		6		7
TQM	1		2		3		4
CrossAlta	2		1		7		2
TransGas	3		3		6		6
Northern Development	(1	)	(1	)	(2	)	(2	)
General, administrative, support costs and other	(5	)	(3	)	(12	)	(9	)
	18		28		51		65
Gain related to PipeLines LP	1		—		49		—
Gain related to Millenium	—		7		—		7
	19		35		100		72

Net Income	165		146		376		295

(1) TransCanada acquired GTN on November 1, 2004.

Wholly-Owned Pipelines

The Canadian Mainline’s net income increased $20 million and $19 million for the three and six months ended June 30, 2005, respectively, when compared to the corresponding periods in 2004. This increase reflects the impact of the NEB’s decision on the Canadian Mainline’s 2004 Tolls and Tariff Application (Phase II) in April 2005, which included an increase in the deemed common equity ratio from 33 per cent to 36 per cent for 2004 and which is also effective for 2005 under the 2005 tolls settlement with

shippers, partially offset by a decrease in the approved rate of return on common equity to 9.46 per cent in 2005 from 9.56 per cent in 2004. As a result of the NEB decision, Canadian Mainline’s net income increased $21 million ($13 million related to 2004 and $8 million related to the first six months of 2005) in second quarter 2005.

The Alberta System’s net income of $37 million in second quarter 2005 is $2 million lower than the same quarter in 2004. Net income for the six months ended June 30, 2005 decreased $5 million compared to the same period in 2004. These decreases were primarily due to a lower investment base in 2005 as well as a lower approved rate of return in 2005. Net income in 2005 reflects a rate of return of 9.50 per cent, as prescribed by the Alberta Energy and Utilities Board (EUB), on deemed common equity of 35 per cent compared to a rate of return of 9.60 per cent in 2004.

GTN, which was acquired by TransCanada in November 2004, generated net income of $16 million in second quarter 2005 and $39 million in the six months ended June 30, 2005. Net income for the Foothills System for the three and six months ended June 30, 2005 is comparable to the same period in the prior year.

Operating Statistics

Gas

Transmission

Canadian

Northwest

Six months ended June 30

Mainline (1)

Alberta System (2)

System (3)

Foothills System

BC System

(unaudited)

2005

2004

2005

2004

2005

2004

2005

2004

Average investment base ($ millions)

7,873

8,274

4,534

4,719

n/a

(3)

687

722

219

230

Delivery volumes (Bcf)

Total

1,437

1,355

1,936

1,925

383

520

552

162

162

Average per day

7.9

7.4

10.7

10.6

2.1

2.9

3.0

0.9

0.9

(1) Canadian Mainline deliveries originating at the Alberta border and in Saskatchewan for the six months ended June 30, 2005 were 1,044 Bcf (2004 - 1,016 Bcf); average per day was 5.8 Bcf (2004 - 5.6 Bcf).

(2) Field receipt volumes for the Alberta System for the six months ended June 30, 2005 were 1,979 Bcf (2004 - - 1,958 Bcf); average per day was 10.9 Bcf (2004 - 10.8 Bcf).

(3) TransCanada acquired the Gas Transmission Northwest System on November 1, 2004. The system is currently operating under a fixed rate model approved by the United States Federal Energy Regulatory Commission and, as a result, the system’s current results are not dependent on average investment base.

Other Gas Transmission

TransCanada’s proportionate share of net income from its Other Gas Transmission businesses was $19 million for the three months ended June 30, 2005 compared to $35 million for the same period in 2004. The second quarter 2004 results include a $7 million after-tax gain on sale of the company’s equity interest in Millennium.

Excluding this gain, and the $1 million after-tax gain on sale of additional units of PipeLines LP recorded in second quarter 2005, income for second quarter 2005 decreased $10 million compared to the same period in 2004. The decrease was mainly due to lower earnings from PipeLines LP reflecting a reduced ownership interest, lower earnings from Great Lakes as a result of lower short-term revenues and higher operating and maintenance costs, as well as the negative impact of a weaker U.S. dollar on the company’s U.S. operations.

Net income for the six months ended June 30, 2005 was $100 million compared to $72 million for the corresponding period in 2004. Excluding the $49 million after-tax gain on sale of PipeLines LP units recorded in 2005, and the $7 million after-tax gain on sale of Millennium recorded in 2004, year-to-date earnings are $14 million lower compared to the same period in 2004. The decrease is due to lower earnings from Great Lakes, lower earnings from Iroquois primarily due to a tax adjustment recorded in first quarter 2004 and lower earnings from PipeLines LP reflecting a reduced ownership interest. Results were also negatively impacted by a weaker U.S. dollar in 2005. These decreases were partially offset by higher earnings from CrossAlta as a result of favourable conditions in the natural gas storage market.

As at June 30, 2005, TransCanada had capitalized $8 million of costs related to its Broadwater liquified natural gas (LNG) project.

Power

Power Results-at-a-Glance
(unaudited)	Three months ended June 30				Six months ended June 30
(millions of dollars)	2005		2004		2005		2004
Western operations	28		35		58		70
Eastern operations	39		22		44		56
Bruce Power investment	13		48		43		96
Power LP investment	8		6		17		16
General, administrative, support costs and other	(26	)	(24	)	(51	)	(49	)
Operating and other income	62		87		111		189
Financial charges	(3	)	(3	)	(7	)	(5	)
Income taxes	(17	)	(22	)	(32	)	(57	)
	42		62		72		127
Gains related to Power LP(after tax)	—		187		—		187

Net Income	42		249		72		314

Power’s net income in second quarter 2005 of $42 million decreased $207 million compared to second quarter 2004, primarily due to $187 million of gains related to Power LP in second quarter 2004.

Excluding these gains, Power’s net income of $42 million for second quarter 2005 decreased $20 million compared to $62 million for the same period in 2004. Higher operating and other income from Eastern Operations partially offset lower operating and other income from Bruce Power and Western Operations.

Eastern Operations’ operating and other income was $17 million higher in second quarter 2005 compared to second quarter 2004 primarily due to the acquisition of hydroelectric generation assets from USGen on April 1, 2005.

Bruce Power’s equity income was lower by $35 million in second quarter 2005 compared to second quarter 2004 primarily due to lower generation volumes and higher costs resulting from a planned maintenance outage on Unit 7 (54 days) and an unplanned maintenance outage on Unit 6 (27 days) as a result of a transformer fire outside the generating facility. Higher realized power prices in second quarter 2005 partially offset the impact of the lower generation volumes as well as increased outage and operating costs.

Western Operations’ operating and other income was $7 million lower in second quarter 2005 compared to second quarter 2004 primarily due to fee revenues earned in 2004 on the sale of ManChief and Curtis Palmer to Power LP and reduced margins from lower market heat rates on uncontracted volumes of power generated.

Net income for the six months ended June 30, 2005 of $72 million decreased $242 million compared to $314 million in 2004. Excluding the $187 million of Power LP-related gains in 2004, Power’s net income for the six months ended June 30, 2005 of $72 million decreased $55 million compared to $127 million in 2004 as a result of lower equity income from Bruce Power and reduced operating and other income from Eastern and Western Operations.

Western Operations

Western Operations Results-at-a-Glance (1)
(unaudited)	Three months ended June 30				Six months ended June 30
(millions of dollars)	2005		2004		2005		2004
Revenue
Power	151		167		315		314
Other (2)	37		30		79		63
	188		197		394		377
Cost of sales
Power	(102	)	(113	)	(217	)	(203	)
Other (2)	(18	)	(14	)	(41	)	(38	)
	(120	)	(127	)	(258	)	(241	)
Other costs and expenses	(35	)	(30	)	(68	)	(54	)
Depreciation	(5	)	(5	)	(10	)	(12	)

Operating and other income	28		35		58		70

(1) ManChief is included until April 30, 2004.

(2) Other revenue includes Cancarb Thermax and natural gas sales. Other cost of sales includes the cost of natural gas sold.

Western Operations Sales Volumes (1)
(unaudited)	Three months ended June 30		Six months ended June 30
(GWh)	2005	2004	2005	2004
Supply
Generation	511	390	1,147	752
Purchased
Sundance A & B PPAs	1,713	1,885	3,544	3,696
Other purchases (2)	614	654	1,345	1,357
	2,838	2,929	6,036	5,805
Contracted vs. Spot
Contracted	2,462	2,677	5,147	5,355
Spot	376	252	889	450
	2,838	2,929	6,036	5,805

(1) ManChief is included until April 30, 2004.

(2) Includes Sheerness Power Purchase Arrangement (PPA) volumes.

Western Operations’ operating and other income of $28 million and $58 million for the three and six months ended June 30, 2005 was $7 million and $12 million lower, respectively, compared to the same periods in 2004. The decreases were mainly due to fee revenues earned in second quarter 2004 on the sale of ManChief and Curtis Palmer to Power LP and reduced margins resulting from lower market heat rates on uncontracted volumes of power generated. Lower market heat rates were the result of weak spot market power prices in Alberta that averaged approximately $9 per megawatt hour (MWh) less in second quarter 2005 and $6 per MWh less for the six months ended June 30, 2005, compared to the same periods in 2004, while average natural gas prices were slightly higher. A significant portion of plant generation in Western Operations is sold under long-term contract to mitigate price risk. Some output

is intentionally not committed under long-term contract to assist in managing Power’s overall portfolio of generation. 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 obligations.

Western Operations’ power sales revenues and power cost of sales decreased in second quarter 2005 primarily due to lower plant availability as a result of maintenance outages at Sundance B. Power sales revenues also decreased as a result of lower contracted and spot market prices realized in second quarter 2005. Partially offsetting this decrease were revenues from the 2004 start-up of the MacKay River facility. Other costs and expenses were higher in second quarter 2005 primarily due to operating costs associated with the MacKay River facility. Generation volumes in second quarter 2005 increased 121 gigawatt hours (GWh) to 511 GWh primarily due to the start-up of the MacKay River facility, partially offset by a decrease in volumes associated with unplanned outages at the Bear Creek cogeneration facility. In second quarter 2005, approximately 13 per cent of power sales volumes were sold into the spot market compared to approximately nine per cent for the same period in 2004. To reduce its exposure to spot market prices on uncontracted volumes, as at June 30, 2005, Western Operations had fixed price sales contracts to sell forward approximately 5,100 GWh for the remainder of 2005 and approximately 8,000 GWh for 2006.

Eastern Operations

Eastern Operations Results-at-a-Glance (1)
(unaudited)	Three months ended June 30				Six months ended June 30
(millions of dollars)	2005		2004		2005		2004
Revenue
Power	129		130		244		276
Other (2)	73		52		143		117
	202		182		387		393
Cost of sales
Power	(51	)	(66	)	(113	)	(145	)
Other (2)	(74	)	(49	)	(139	)	(105	)
	(125	)	(115	)	(252	)	(250	)
Other costs and expenses	(32	)	(40	)	(81	)	(75	)
Depreciation	(6	)	(5	)	(10	)	(12	)

Operating and other income	39		22		44		56

(1) Curtis Palmer is included until April 30, 2004.

(2) Other includes natural gas.

Eastern Operations Sales Volumes (1)
(unaudited)	Three months ended June 30		Six months ended June 30
(GWh)	2005	2004	2005	2004
Supply
Generation	962	423	1,406	800
Purchased	494	1,051	1,305	2,285
	1,456	1,474	2,711	3,085
Contracted vs. Spot
Contracted	1,228	1,456	2,417	3,000
Spot	228	18	294	85
	1,456	1,474	2,711	3,085

(1) Curtis Palmer is included until April 30, 2004.

Operating and other income in second quarter 2005 from Eastern Operations of $39 million was $17 million higher compared to $22 million earned in the same period in 2004. The increase was due primarily to income from the acquisition of hydroelectric generation assets (hydro assets) from USGen on April 1, 2005 and from the Grandview cogeneration facility which was placed in service in January 2005. Partially offsetting these increases was the loss of income associated with the sale of the Curtis Palmer hydroelectric facilities to Power LP in April 2004.

Operating and other income for the six months ended June 30, 2005 was $44 million or $12 million lower than the $56 million earned in 2004. Income from the acquisition of the hydro assets and income from the Grandview cogeneration facility were more than offset by a $16 million pre-tax ($10 million after-tax) contract restructuring payment made by Ocean State Power (OSP) to its natural gas fuel suppliers in first quarter 2005 and a $16 million pre-tax ($10 million after-tax) reduction in income as a result of the sale of Curtis Palmer to Power LP in April 2004. The contract restructuring at OSP reduced the term of the long-term gas supply contracts with its suppliers by approximately three years (now ending in October 2008) and adjusted the pricing to track spot pricing of natural gas at the Niagara delivery point versus the previously arbitrated pricing that had resulted in above-market cost of gas for OSP.

Generation volumes in second quarter 2005 increased 539 GWh to 962 GWh compared to 423 GWh in 2004 primarily due to the acquisition of the hydro assets and the placing in-service of the Grandview cogeneration facility. Partially offsetting these increases were decreases in volumes associated with the sale of the Curtis Palmer hydroelectric facility to Power LP in April 2004 and reduced generation from the OSP facility.

Power sales revenues of $129 million and sales volumes of 1,456 GWh for second quarter 2005 were consistent with the same period in 2004. Power sales revenues and volumes sold from the new hydro

assets and Grandview were offset by the loss of revenues and volumes from the sale of Curtis Palmer, the expiration of long-term sales contracts held at the end of 2004 which did not carry-over into 2005, and an unplanned outage at OSP. This outage is expected to continue into third quarter 2005. Realized average power prices were consistent in second quarter of 2004 and 2005. Power cost of sales of $51 million and purchased volumes of 494 GWh were lower in second quarter 2005 due to the impact of the purchase of the hydro assets. Volumes generated from the hydro assets reduced some of the requirement to purchase power to fulfill contractual sales obligations. Other revenue and cost of sales increased year-over-year primarily as a result of gas purchased and resold from new gas supply contracts at OSP. Other costs and expenses of $32 million, which includes fuel gas consumed in generation, decreased $8 million primarily due to lower fuel costs from reduced dispatch at the OSP facility.

In second quarter 2005, approximately 16 per cent of power sales volumes were sold into the spot market compared to approximately one per cent in 2004 reflecting the sale to the spot market of a portion of the generation of the the hydro assets acquired on April 1, 2005. Eastern Operations is focused on selling the majority of its power under contract to wholesale, commercial and industrial customers while managing a portfolio of power supplies sourced from its own generation, wholesale power purchases and power purchased from Power LP’s Castleton plant. To reduce its exposure to spot market prices, as at June 30, 2005, Eastern Operations had entered into fixed price sales contracts to sell forward approximately 2,800 GWh of power for the remainder of 2005 and approximately 3,300 GWh of power for 2006. Certain contracted volumes are dependent on customer usage levels.

Bruce Power Investment

Bruce Power Results-at-a-Glance
(unaudited)	Three months ended June 30				Six months ended June 30
(millions of dollars)	2005		2004		2005		2004
Bruce Power (100 per cent basis)
Revenues	393		434		811		833
Operating expenses
Cash costs (materials, labour, services and fuel)	(287	)	(243	)	(552	)	(462	)
Non-cash costs (depreciation and amortization)	(49	)	(43	)	(97	)	(74	)
	(336	)	(286	)	(649	)	(536	)
Operating income	57		148		162		297
Financial charges	(17	)	(15	)	(34	)	(33	)
Income before income taxes	40		133		128		264

TransCanada’s interest in Bruce Power income before income taxes	12		42		40		83
Adjustments	1		6		3		13
TransCanada’s income from Bruce Power before income taxes	13		48		43		96

TransCanada’s share of Bruce Power’s income before income taxes (equity income) was lower by $35 million in second quarter 2005 compared to second quarter 2004 primarily due to lower generation volumes and higher costs resulting from a planned maintenance outage on Unit 7 (54 days) and Unit 4 (27 days) and an unplanned maintenance outage on Unit 6 (29 days) relating to a transformer fire outside the generating facility. Higher realized power prices in second quarter 2005 partially offset the reduction in revenues from lower generation volumes and an increase in outage and operating costs.

TransCanada’s share of power output from Bruce Power for second quarter 2005 was 2,306 GWh compared to 2,962 GWh in second quarter 2004. This decrease primarily reflects lower output in 2005 as a result of an increase in planned maintenance outages compared to second quarter 2004 as well as lost output as a result of the Unit 6 transformer fire outage in second quarter 2005. On April 15, 2005, Bruce Power experienced a transformer fire outside of the generating facility. As a result, Unit 6 went offline and, after the successful replacement of its main output transformer, was returned to service on May 14, 2005.

Approximately 81 reactor days of planned maintenance outages as well as 57 reactor days of unplanned outages (including the Unit 6 outage of 29 days) occurred in second quarter 2005. In second quarter 2004, Bruce Power experienced 36 reactor days of planned maintenance outages and four reactor days of unplanned outages. The Bruce units ran at an average availability of 71 per cent in second quarter 2005, compared to a 92 per cent average availability during second quarter 2004. Unit 4 returned to service on April 28, 2005 following a planned maintenance

inspection that began on March 12, 2005. Unit 7 was taken offline on May 7, 2005 to begin its planned maintenance outage, including the completion of major Spacer Location and Relocation work and turbine replacement, which is expected to last about three months.

Overall prices achieved during second quarter 2005 were $53 per MWh, compared to $46 per MWh in second quarter 2004. Prices realized for the six months ending June 30, 2005 were $51 per MWh compared to $47 per MWh for the same period in 2004. Approximately 49 per cent of the available output was sold into Ontario’s wholesale spot market during the first six months of 2005 with the remainder being sold under longer term contracts. Bruce Power’s operating expenses increased to $46 per MWh in second quarter 2005 from $30 per MWh in second quarter 2004. This $16 per MWh increase was due to reduced output and increased outage costs, primarily related to the Unit 7 and Unit 4 planned maintenance outages as well as the forced outage at Unit 6. Adjustments to TransCanada’s interest in Bruce Power’s income before income taxes for the three and six months ended June 30, 2005 were lower than in 2004 primarily due to lower amortization of the purchase price allocated to the fair value of sales contracts in place at the time of acquisition. The six months ended June 30, 2005 adjustment was also lower due to the cessation of interest capitalization upon the return to service of Unit 3 in March 2004.

Pre-tax equity income for the six months ended June 30, 2005 was $43 million compared to $96 million for the same period in 2004. Effective March 1, 2004, Bruce Power moved from a five-unit operation to a six-unit operation with the commercial startup of Unit 3. Planned maintenance outages, as well as the forced outage due to the April 15, 2005 transformer fire at Unit 6 and other minor forced outages, reduced the otherwise potential increase in total plant output as a result of adding a sixth operating unit. This lower output resulted in reduced sales revenue from that achieved in 2004 which was partially offset by higher realized sales prices for the six months ended June 30, 2005. Bruce Power’s operating expenses increased to $42 per MWh for the six months ended June 30, 2005 from $31 per MWh for the same period in 2004. This was the result of reduced output as well as higher maintenance costs, higher depreciation and lower capitalization of labour and other in-house costs following the restart of Unit 3.

Equity income from Bruce Power is directly impacted by fluctuations in wholesale spot market prices for electricity as well as overall plant availability, which in turn, is impacted by scheduled and unscheduled maintenance. To reduce its exposure to spot market prices, Bruce Power has entered into fixed price sales contracts for approximately 36 per cent of planned output for the balance of 2005. Bruce Power expects a two month planned

maintenance outage on Unit 5 in fourth quarter 2005. Overall plant availability for Bruce Power in 2005 is expected to remain at 83 per cent.

In June 2005, Bruce Power made a $50 million cash distribution to its partners (TransCanada’s share was $16 million). The partners have agreed that all excess cash will be distributed on a monthly basis and that separate cash calls will be made for major capital projects.

Bruce Power continues to negotiate an agreement with the Ontario government for the potential restart of Units 1 and 2 at Bruce Power.

Power LP Investment

Power LP’s operating and other income of $8 million and $17 million for the three and six months ended June 30, 2005, was $2 million and $1 million higher, respectively, compared to the same periods in 2004. The increase was primarily due to additional earnings from Power LP’s 2004 acquisitions of the Curtis Palmer, ManChief, Mamquam and Queen Charlotte facilities. Partially offsetting this increase was TransCanada’s reduced ownership interest in Power LP in 2004 and the effect of the recognition in second quarter 2004 of all previously deferred gains resulting from the removal of the Power LP redemption obligation. Prior to the removal of the redemption obligation, TransCanada was recognizing the amortization of these deferred gains into income over a period through to 2017.

General, Administrative, Support Costs and Other

General, administrative, support costs and other of $26 million in second quarter 2005 and $51 million for the six months ended June 30, 2005 were both $2 million higher compared to the same periods in 2004 primarily due to the negative impact of TransCanada’s proportionate share of Power LP’s unrealized foreign exchange losses on its U.S. dollar denominated debt.

Power Sales Volumes and Plant Availability

Power Sales Volumes
(unaudited)	Three months ended June 30		Six months ended June 30
(GWh)	2005	2004	2005	2004
Western operations (1)	2,838	2,929	6,036	5,805
Eastern operations (1)	1,456	1,474	2,711	3,085
Bruce Power investment (2)	2,306	2,962	4,904	5,492
Power LP investment (1)(3)	723	536	1,420	1,108
Total	7,323	7,901	15,071	15,490

(1) ManChief and Curtis Palmer volumes are included in Power LP investment effective April 30, 2004.

(2) Sales volumes reflect TransCanada’s 31.6 per cent share of Bruce Power output.

(3) TransCanada operates and manages Power LP. The volumes in the table represent 100 percent of Power LP’s sales volumes.

Weighted Average Plant Availability (1)	Three months ended June 30				Six months ended June 30
(unaudited)	2005		2004		2005		2004
Western operations (2)	83	%	93	%	88	%	96	%
Eastern operations (2)	80	%	95	%	79	%	97	%
Bruce Power investment (3)	71	%	92	%	76	%	86	%
Power LP investment (2)	87	%	96	%	92	%	97	%
All plants, excluding Bruce Power investment	83	%	95	%	86	%	97	%
All plants	79	%	94	%	82	%	92	%

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

(2) ManChief and Curtis Palmer are included in Power LP investment effective April 30, 2004.

(3) Unit 3 is included effective March 1, 2004.

Corporate

Net expenses for the three and six months ended June 30, 2005 were $7 million and $16 million, respectively, compared to net expenses of $7 million for each of the corresponding periods in 2004.

For the three months ended June 30, 2005, net expenses were comparable to the same period in the prior year. Income tax refunds and positive tax adjustments in second quarter 2005 were offset by tax adjustments recorded in second quarter 2004 and higher interest expense on long-term debt that was issued in late 2004 and on higher commercial paper balances in 2005.

The $9 million increase for the six months ended June 30, 2005 compared to the same period in 2004 was primarily due to increased interest expense on long-term debt that was issued in 2004 as well as on higher commercial paper balances in 2005. Income tax refunds and related interest in the six months ended June 30, 2004 were comparable to income tax refunds and positive tax adjustments recorded in the six months ended June 30, 2005.

Liquidity and Capital Resources

Funds Generated from Operations

Funds generated from operations were $479 million and $886 million for the three and six months ended June 30, 2005, respectively, compared with $382 million and $797 million for the same periods in 2004.

TransCanada expects that its ability to generate adequate amounts of cash in the short term and the long term, when needed, and to maintain financial capacity and flexibility to provide for planned growth remains substantially unchanged since December 31, 2004.

Investing Activities

In the three and six months ended June 30, 2005, capital expenditures, excluding acquisitions, totalled $135 million (2004 - $93 million) and $243 million (2004 - $194 million), respectively, and related primarily to construction of new power plants, and maintenance and capacity capital in the Gas Transmission business.

In the three and six months ended June 30, 2005, disposition of assets generated $2 million (2004 - $408 million) and $153 million (2004 - $408 million), respectively. The disposition in 2005 related to the sale of PipeLines LP units and the dispositions in 2004 related primarily to the sale of ManChief and Curtis Palmer to Power LP.

Acquisitions for the three and six months ended June 30, 2005 were $632 million (2004 – $14 million) and related to the purchase of USGen hydro assets and the acquisition of an additional 3.52 per cent interest in Iroquois Gas Transmission System L.P. (Iroquois).

Financing Activities

TransCanada retired $615 million and $936 million of long-term debt in the three and six months ended June 30, 2005, respectively. TransCanada issued $499 million and $799 million of long-term debt in the three and six months ended June 30, 2005, respectively. Please refer to Other Recent Developments – Other for further information on long-term debt. For the six months ended June 30, 2005, outstanding notes payable increased by $533 million, while cash and short-term investments increased by $22 million.

Dividends

On July 28, 2005, TransCanada’s Board of Directors declared a quarterly dividend of $0.305 per share for the quarter ending September 30, 2005 on the outstanding common shares. This is the 167th consecutive quarterly dividend paid by TransCanada and its subsidiary on the common shares. It is payable on October 31, 2005 to shareholders of record at the close of business on September 30, 2005.

Contractual Obligations

Primarily as a result of new contracts in the six months ended June 30, 2005, Power’s future purchase obligations are estimated at June 30, 2005 to be as follows.

Purchase Obligations
(unaudited - millions of dollars)	2005 (1)	2006	2007	2008	2009	2010+
Power
Commodity purchases (2)	393	632	627	556	278	2,658
Capital expenditures (3)	269	181	66	1	1	—
Other (4)	24	43	32	23	28	113
	686	856	725	580	307	2,771

(1) Includes purchase obligations for the six months ending December 31, 2005.

(2) Commodity purchases include fixed and variable components. The variable components are estimates and are subject to variability in plant production, market prices, and regulatory tariffs.

(3) Amounts are estimates and are subject to variability based on timing of construction and project enhancements.

(4) Includes estimates of certain amounts which are subject to change depending on plant fired hours, the consumer price index, actual plant maintenance costs, plant salaries as well as changes in regulated rates for transportation.

There have been no other material changes to TransCanada’s contractual obligations from December 31, 2004 to June 30, 2005, 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 2004 Annual Report.

Financial and Other Instruments

The following represents the material changes to the company’s financial instruments since December 31, 2004.

Energy Price Risk Management

The company executes power, natural gas and heat rate derivatives in order to manage exposure and risks associated with its overall asset portfolio. Heat rate contracts are contracts for the sale or purchase of power that are priced based on a natural gas index. The fair values and notional volumes of the swap, option, future and heat rate contracts are shown in the tables below. In accordance with the company’s accounting policy, each of the

derivatives in the table below is recorded on the balance sheet at its fair value at June 30, 2005 and December 31, 2004.

Power

		June 30, 2005
		(unaudited)		December 31, 2004
Asset/(Liability)	Accounting	Fair		Fair
(millions of dollars)	Treatment	Value		Value

Power - swaps
(maturing 2005 to 2011)	Hedge	(60	)	7
(maturing 2005 to 2010)	Non-hedge	2		(2	)
Gas - swaps, futures and options
(maturing 2005 to 2016)	Hedge	(27	)	(39	)
(maturing 2005 to 2006)	Non-hedge	1		(2	)
Heat rate contracts
(maturing 2005 to 2006)	Hedge	—		(1	)

Notional Volumes
June 30, 2005	Accounting	Power (GWh)		Gas (Bcf)
(unaudited)	Treatment	Purchases	Sales	Purchases	Sales

Power - swaps
(maturing 2005 to 2011)	Hedge	1,299	7,177	—	—
(maturing 2005 to 2010)	Non-hedge	878	—	—	—
Gas - swaps, futures and options
(maturing 2005 to 2016)	Hedge	—	—	85	73
(maturing 2005 to 2006)	Non-hedge	—	—	5	7
Heat rate contracts
(maturing 2005 to 2006)	Hedge	—	55	—	—

Notional Volumes	Accounting	Power (GWh)		Gas (Bcf)
December 31, 2004	Treatment	Purchases	Sales	Purchases	Sales

Power - swaps	Hedge	3,314	7,029	—	—
	Non-hedge	438	—	—	—

Gas - swaps, futures and options	Hedge	—	—	80	84
	Non-hedge	—	—	5	8

Heat rate contracts	Hedge	—	229	2	—

Risk Management

TransCanada’s market, financial and counterparty risks remain substantially unchanged since December 31, 2004. For further information on risks, refer to the MD&A in TransCanada’s 2004 Annual Report.

Controls and Procedures

As of the end of the period covered by this quarterly report, 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, 2004, 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 2004 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, 2004 continues to be depreciation expense. For further information on this critical accounting estimate, refer to the MD&A in TransCanada’s 2004 Annual Report.

Accounting Change

Financial Instruments — Disclosure and Presentation

Effective January 1, 2005, the company adopted the provisions of the Canadian Institute of Chartered Accountants’ amendment to the existing Handbook Section ”Financial Instruments — Disclosure and Presentation” which provides guidance for classifying certain financial instruments that embody obligations that may be settled by issuance of the issuer’s equity shares as debt when the instrument does not establish an ownership relationship. In accordance with this amendment, TransCanada reclassified the non-controlling interest component of preferred securities as long-term debt.

This accounting change was applied retroactively with restatement of prior periods. The impact of this change on TransCanada’s net income in second quarter 2005 and prior periods was nil.

The impact of the accounting change on the company’s consolidated balance sheet as at December 31, 2004 is as follows.

(unaudited - millions of dollars)	Increase/(Decrease)
Deferred Amounts (1)	135
Preferred Securities	535
Non-Controlling Interest
Preferred securities of subsidiary	(670	)
Total Liabilities and Shareholders’ Equity	—

(1) Regulatory deferral

U.S. GAAP Restatement

In second quarter 2005, the company restated Note 22 (U.S. GAAP) to the 2004 consolidated financial statements. TransCanada records its investment in Power LP using the proportionate consolidation method for Canadian generally accepted accounting principles (GAAP) purposes and as an equity investment for U.S. GAAP purposes. During the period from 1997 to April 2004, the company was obligated to fund the redemption of Power LP units in 2017. As a result, under both Canadian and U.S. GAAP, TransCanada accounted for the issuance of units by Power LP to third parties as a sale of a future net revenue stream and the resulting gains were deferred and amortized to income over the period to 2017. The redemption obligation was removed in April 2004 and the unamortized gains were recognized as income.

For U.S. GAAP purposes, under the provisions of the U.S. Securities and Exchange Commission’s Staff Accounting Bulletin Topic 5:H, certain transactions involving Power LP, in the period 1997 to 2001, should have been accounted for as dilution gains rather than as sales of a future net revenue stream. As the company was committed to fund the

redemption of the Power LP units, these gains should have been recorded, on an after-tax basis, as equity transactions in shareholders’ equity. This has been corrected on a retroactive basis. The correction had no impact on the accumulated shareholders’ equity at December 31, 2004 for U.S. GAAP purposes. The impact on previously reported income amounts for U.S. GAAP purposes is as follows.

(millions of dollars except per share amounts)	2004		2003		2002
Decrease in:

Income from continuing operations	135		10		10

Net Income	135		10		10

Net Income per share in accordance with U.S. GAAP
Continuing Operations	$	0.28	$	0.02	$	0.02
Discontinued Operations	—		—		—

Basic	$	0.28	$	0.02	$	0.02
Diluted	$	0.28	$	0.02	$	0.02

TransCanada’s restated 2004 audited consolidated financial statements will be available in Canada on SEDAR at www.sedar.com and in the U.S. on EDGAR at www.sec.gov. under TransCanada Corporation and are available on the company’s website at www.transcanada.com.

Outlook

In 2005, the company expects higher net income from the Gas Transmission segment than originally anticipated as a result of the $49 million after-tax gain related to the sale of PipeLines LP units. In addition, the company expects higher Power net income in 2005 than originally anticipated as a result of the expected gains on sale of the Power LP of approximately $200 million after tax and the company’s investment in PT Paiton Energy Company (Paiton Energy) of approximately $115 million after tax. For further information on these transactions, please refer to Other Recent Developments. Excluding these impacts, the company’s outlook is relatively unchanged since December 31, 2004. For further information on outlook, refer to the MD&A in TransCanada’s 2004 Annual Report.

In 2005, TransCanada will continue to direct its resources towards long-term growth opportunities that will strengthen its financial performance and create long-term value for shareholders. The company’s net income and cash flow combined with a strong balance sheet continue to provide the financial flexibility for TransCanada to make disciplined investments in its core businesses of Gas Transmission and Power.

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

Other Recent Developments

Gas Transmission

Wholly-Owned Pipelines

Canadian Mainline

In November 2004, the Canadian Association of Petroleum Producers (CAPP) filed an application with the NEB to review and vary its decision on the Canadian Mainline’s 2004 Tolls and Tariff Application with respect to three items:

• non-renewable firm transportation (FT-NR) service;

• long-term incentive compensation; and

• regulatory and legal costs.

On February 18, 2005, the NEB decided to review its decision on the tolls to be charged for FT-NR, not to review its decision on disputed regulatory and legal costs and, at CAPP’s request, to defer its consideration of a review of its decision regarding long-term incentive compensation. On April 13, 2005, CAPP filed notice with the NEB to withdraw the portion of its application dealing with long-term incentive compensation. The NEB heard oral arguments in Calgary in late April 2005 to consider tolling issues with respect to FT-NR. In a decision issued May 30, 2005, the NEB overturned its initial ruling that FT-NR be tolled on a biddable basis with a floor price equal to the 100 per cent load factor toll for Firm Transportation (FT) Service and determined that it should be offered at the same toll as FT.

In April 2005, TransCanada received the NEB’s decision on the Canadian Mainline’s 2004 Tolls and Tariff Application (Phase II). The NEB, in its decision, approved an increase in the deemed common equity component of the Canadian Mainline’s capital structure from 33 per cent to 36 per cent for 2004 which is also effective for 2005 under the 2005 tolls settlement with shippers. This increase in the common equity component is expected to increase TransCanada’s 2005 net income by approximately $29 million, of which $13 million relates to 2004 and $16 million relates to 2005. The return on equity for the Canadian Mainline remains at 9.56 per cent for 2004 and 9.46 per cent for 2005.

On May 30, 2005, in compliance with the NEB’s decision regarding TransCanada’s 2004 Mainline Tolls and Tariff Application (Phase II), TransCanada filed a separate final tolls application with the NEB for 2004 and 2005. On June 23, 2005, the NEB issued its decision approving the 2004 and 2005 final tolls applications as filed.

Alberta System

On June 7, 2005, the EUB granted approval of a negotiated settlement for the Alberta System’s 2005-2007 Revenue Requirement. As stipulated in the settlement, following the approval of the settlement, TransCanada withdrew its motion filed with the Alberta Court of Appeal for leave to appeal Decision 2004-069 which dealt with Phase I of the 2004 General Rate Application (GRA). TransCanada also agreed that it would not pursue a review and variance application on the EUB’s findings regarding incentive compensation and long-term incentive costs.

TransCanada will continue to charge interim tolls for 2005 for transportation service on the Alberta System. The interim tolls, approved by the EUB in December 2004, will remain in effect until final tolls are established following the Phase II proceeding of the Alberta System’s 2005 GRA. In this second phase of the EUB’s rate making process, the allocation of 2005 approved costs among transportation services and rate design are determined. The EUB has scheduled a hearing for Phase II during fourth quarter 2005.

Other Gas Transmission

Tamazunchale Pipeline Project

In June 2005, Mexico’s Comisión Federal de Eletricidad (CFE) awarded a contract to TransCanada to construct, own and operate a 36 inch, 125 kilometre natural gas pipeline in east central Mexico. The Tamazunchale Pipeline will extend from the facilities of Pemex Gas near Naranjos, Veracruz and transport natural gas under a 26 year contract with the CFE to an electricity generation station near Tamazunchale, San Luis Potosi. This approximately US$181 million project will initially transport volumes of 170 million cubic feet per day (mmcf/d). Under the terms of the contract, the capacity of the Tamazunchale Pipeline will be expanded to 430 mmcf/d commencing in 2009 to meet additional requirements of two additional proposed power plants near Tamazunchale. TransCanada has commenced project and construction activities with a planned in-service date of December 1, 2006.

Iroquois

In June 2005, TransCanada closed the acquisition of a 3.52 per cent ownership interest in Iroquois from a subsidiary of Goldman Sachs & Co. for US$13.6 million, subject to post-closing adjustments. This acquisition increased TransCanada’s ownership interest in Iroquois from 40.96 per cent to 44.48 per cent.

Power

USGen New England, Inc.

On April 1, 2005, TransCanada closed its acquisition of hydroelectric generation assets, with total generating capacity of 567 megawatts (MW), from USGen for US$505 million, subject to closing adjustments.

There was an existing agreement in place between the Town of Rockingham (the Town) and USGen which provided the Town with an option to purchase the 49MW Bellows Falls facility for US$72 million. The option was exercised in December 2004 and the Town assigned its rights and obligations under the option agreement to the Vermont Hydroelectric Power Authority (Vermont Hydroelectric). TransCanada assumed the obligations of USGen under the option on April 1, 2005. Although the option was exercised, closing remains subject to certain regulatory approvals as well as other conditions specified in the option agreement. The Vermont Public Service Board issued its approval in June 2005, which approval was conditioned on a further vote of Town residents in which at least a majority of the votes cast had to approve the transaction. On July 12, 2005, the vote took place but did not achieve the requisite majority. That rejection does not, of itself, terminate the option. The Town is scheduled to have another vote on this matter in August 2005.

Power LP

In May 2005, TransCanada announced that it had entered into an agreement with EPCOR Utilities Inc. (EPCOR) whereby EPCOR will purchase TransCanada’s interest in Power LP for $529 million. EPCOR’s acquisition includes 14.5 million units of Power LP, representing 30.6 per cent of the outstanding units; 100 per cent ownership of the General Partner of Power LP; and management and operations’ agreements governing the ongoing operation of Power LP’s generation assets.

The Boards of Directors of each of TransCanada, EPCOR and Power LP have approved this transaction. This transaction is expected to close in third quarter 2005 pending receipt of regulatory approvals. TransCanada expects to realize an after-tax gain of approximately $200 million from this sale. TransCanada will

continue to operate and maintain Power LP’s power plants until closing.

Paiton Energy

In June 2005, TransCanada reached an agreement to sell its approximate 11 per cent interest in Paiton Energy to subsidiaries of The Tokyo Electric Power Company for US$103 million ($127 million), subject to adjustments. TransCanada originally purchased its interest in Paiton Energy in 1996. Paiton Energy owns two 615 megawatt coal-fired plants in East Java, Indonesia. Pending various approvals, this transaction is expected to close in third quarter 2005. Upon closing, TransCanada expects to realize an after-tax gain of approximately $115 million.

Other

On June 1, 2005, Gas Transmission Northwest Corporation (GTNC) redeemed all of its outstanding US$150 million 7.80 per cent Senior Unsecured Debentures (Debentures) and US$250 million 7.10 per cent Senior Unsecured Notes. As a consequence, upon application by GTNC, the Debentures were de-listed from the New York Stock Exchange and GTNC no longer has any securities registered under U.S. securities laws.

On June 1, 2005, GTNC completed a US$400 million multi-tranche private placement of senior debt with a weighted average interest rate of 5.28 per cent and weighted average life of approximately 18 years.

Share Information

As at June 30, 2005, TransCanada had 486,465,247 issued and outstanding common shares. In addition, there were 9,468,869 outstanding options to purchase common shares, of which 7,055,293 were exercisable as at June 30, 2005.

Selected Quarterly Consolidated Financial Data (1)

(unaudited)	2005				2004								2003
(millions of dollars except per share amounts)	Second		First		Fourth		Third		Second		First		Fourth		Third

Revenues	1,444		1,407		1,478		1,307		1,344		1,356		1,375		1,454
Net Income
Continuing operations	200		232		185		193		388		214		193		198
Discontinued operations	—		—		—		52		—		—		—		50
	200		232		185		245		388		214		193		248

Share Statistics
Net income per share — Basic
Continuing operations	$	0.41	$	0.48	$	0.38	$	0.40	$	0.80	$	0.44	$	0.40	$	0.41
Discontinued operations	—		—		—		0.11		—		—		—		0.10
	$	0.41	$	0.48	$	0.38	$	0.51	$	0.80	$	0.44	$	0.40	$	0.51
Net income per share — Diluted
Continuing operations	$	0.41	$	0.48	$	0.38	$	0.39	$	0.80	$	0.44	$	0.40	$	0.41
Discontinued operations	—		—		—		0.11		—		—		—		0.10
	$	0.41	$	0.48	$	0.38	$	0.50	$	0.80	$	0.44	$	0.40	$	0.51

Dividend declared per common share	$	0.305	$	0.305	$	0.29	$	0.29	$	0.29	$	0.29	$	0.27	$	0.27

(1) The selected quarterly consolidated financial data has been prepared in accordance with Canadian GAAP. For a discussion on the factors affecting the comparability of the financial data, including discontinued operations, refer to Note 1 and Note 21 of TransCanada’s restated 2004 audited consolidated financial statements.

Factors Impacting Quarterly Financial Information

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

In the Power business, which consists primarily of the company’s investments in electrical power generation plants, 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.

• Third quarter 2003 net earnings included TransCanada’s $11 million share of a positive future income tax benefit adjustment recognized by TransGas.

• First quarter 2004 net earnings included approximately $12 million of income tax refunds and related interest.

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

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

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

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

• Second quarter 2005 net earnings included $21 million ($13 million related to 2004 and $8 million related to the six months ended June 30, 2005) with respect to the NEB’s decision on TransCanada’s 2004 Mainline Tolls and Tariff Application (Phase II). On April 1, 2005, TransCanada completed the acquisition of hydro assets from USGen. 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.

Forward-Looking Information

Certain information in this quarterly report is forward-looking and is subject to important risks and uncertainties. The results or events predicted in this information may differ from actual results or events. Factors which could cause actual results or events to differ materially from current expectations include, among other things, the ability of TransCanada to successfully implement its strategic initiatives and whether such strategic initiatives will yield the expected benefits, the availability and price of energy commodities, regulatory decisions, competitive factors in the pipeline and power industry sectors, and the prevailing economic conditions in North America. For additional information on these and other factors, see the reports filed by TransCanada with Canadian securities regulators and with the United States Securities and Exchange Commission. TransCanada disclaims any intention or obligation to update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.

Exhibit 13.2

Consolidated Income

(unaudited)	Three months ended June 30						Six months ended June 30
(millions of dollars except per share amounts)	2005			2004			2005			2004

Revenues	1,444			1,344			2,851			2,700

Operating Expenses
Cost of sales	245			242			510			491
Other costs and expenses	423			398			844			773
Depreciation	253			232			503			464
	921			872			1,857			1,728

Operating Income	523			472			994			972

Other Expenses/(Income)
Financial charges	208			210			415			417
Financial charges of joint ventures	16			16			32			30
Equity income	(17		)	(59		)	(58		)	(117		)
Interest income and other	(4		)	(9		)	(28		)	(24		)
Gain related to PipeLines LP	(2		)	—			(82		)	—
Gains related to Power LP	—			(197		)	—			(197		)
Gain related to Millennium	—			(7		)	—			(7		)
	201			(46		)	279			102

Income before Income Taxes and Non-Controlling Interests	322			518			715			870

Income Taxes
Current	79			127			240			230
Future	38			(2		)	26			21
	117			125			266			251

Non-Controlling Interests
Preferred share dividends	5			5			11			11
Other	—			—			6			6
	5			5			17			17

Net Income	200			388			432			602

Net Income Per Share - Basic and Diluted	$	0.41		$	0.80		$	0.89		$	1.24

Average Shares Outstanding - Basic (millions)	485.9			484.0			485.6			483.7

Average Shares Outstanding - Diluted (millions)	488.4			486.6			488.1			486.3

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)	2005		2004		2005		2004

Cash Generated From Operations
Net income	200		388		432		602
Depreciation	253		232		503		464
Gain related to PipeLines LP, net of current tax expense (Note 5)	(1	)	—		(31	)	—
Gains related to Power LP	—		(197	)	—		(197	)
Gain related to Millennium	—		(7	)	—		(7	)
Equity income lower than/(in excess of) distributions received	8		(39	)	(26	)	(90	)
Pension funding (in excess of)/lower than expense	(10	)	13		(17	)	1
Future income taxes	38		(2	)	26		21
Non-controlling interests	5		5		17		17
Other	(14	)	(11	)	(18	)	(14	)
Funds generated from operations	479		382		886		797
Increase in operating working capital	(176	)	(38	)	(218	)	(82	)
Net cash provided by operations	303		344		668		715

Investing Activities
Capital expenditures	(135	)	(93	)	(243	)	(194	)
Acquisitions, net of cash acquired	(632	)	(14	)	(632	)	(14	)
Disposition of assets	2		408		153		408
Deferred amounts and other	3		33		(55	)	(14	)
Net cash (used in)/ provided by investing activities	(762	)	334		(777	)	186

Financing Activities
Dividends	(154	)	(150	)	(300	)	(290	)
Notes payable issued/(repaid), net	289		(72	)	533		(301	)
Long-term debt issued	499		—		799		665
Reduction of long-term debt	(615	)	(25	)	(936	)	(501	)
Non-recourse debt of joint ventures issued	—		81		5		87
Reduction of non-recourse debt of joint ventures	(14	)	(3	)	(21	)	(12	)
Partnership units of joint ventures issued	—		88		—		88
Common shares issued	18		4		29		17
Net cash provided by/(used in) financing activities	23		(77	)	109		(247	)

Effect of Foreign Exchange Rate Changes on Cash and Short-Term Investments	20		(1	)	22		3

(Decrease)/Increase in Cash and Short-Term Investments	(416	)	600		22		657

Cash and Short-Term Investments
Beginning of period	626		395		188		338

Cash and Short-Term Investments
End of period	210		995		210		995

Supplementary Cash Flow Information
Income taxes paid	115		91		307		252
Interest paid	238		221		428		393

See accompanying notes to the consolidated financial statements.

Consolidated Balance Sheet

	June 30, 2005		December 31,
(millions of dollars)	(unaudited)		2004

ASSETS
Current Assets
Cash and short-term investments	210		188
Accounts receivable	537		627
Inventories	239		174
Other	153		120
	1,139		1,109
Long-Term Investments	830		840
Plant, Property and Equipment	19,184		18,704
Other Assets	1,490		1,459
	22,643		22,112

LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities
Notes payable	1,079		546
Accounts payable	885		1,135
Accrued interest	220		214
Current portion of long-term debt	391		766
Current portion of non-recourse debt of joint ventures	73		83
	2,648		2,744
Deferred Amounts	851		783
Long-Term Debt	10,014		9,713
Future Income Taxes	562		509
Non-Recourse Debt of Joint Ventures	798		779
Preferred Securities	564		554
	15,437		15,082
Non-Controlling Interests
Preferred shares of subsidiary	389		389
Other	77		76
	466		465
Shareholders’ Equity
Common shares	4,740		4,711
Contributed surplus	271		270
Retained earnings	1,790		1,655
Foreign exchange adjustment	(61	)	(71	)
	6,740		6,565
	22,643		22,112

See accompanying notes to the consolidated financial statements.

Consolidated Retained Earnings

(unaudited)	Six months ended June 30
(millions of dollars)	2005		2004

Balance at beginning of period	1,655		1,185
Net income	432		602
Common share dividends	(297	)	(281	)

	1,790		1,506

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 financial statements for the year ended December 31, 2004 except as stated below. 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 restated 2004 annual financial statements. 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. Accounting Change

Financial Instruments – Disclosure and Presentation

Effective January 1, 2005, the company adopted the provisions of the Canadian Institute of Chartered Accountants amendment to the existing Handbook Section “Financial Instruments – Disclosure and Presentation” which provides guidance for classifying certain financial instruments that embody obligations that may be settled by issuance of the issuer’s equity shares as debt when the instrument does not establish an ownership relationship. In accordance with this amendment, TransCanada reclassified the non-controlling interest component of preferred securities as long-term debt.

This accounting change was applied retroactively with restatement of prior periods. The impact of this change on TransCanada’s net income in second quarter 2005 and prior periods was nil.

The impact of the accounting change on the company’s consolidated balance sheet as at December 31, 2004 is as follows.

(unaudited - millions of dollars)	Increase/(Decrease)
Deferred Amounts (1)	135
Preferred Securities	535
Non-Controlling Interest Preferred securities of subsidiary	(670	)
Total Liabilities and Shareholders’ Equity	—

(1) Regulatory deferral

3. Segmented Information

Three months ended June 30	GasTransmission				Power				Corporate				Total
(unaudited - millions of dollars)	2005		2004		2005		2004		2005		2004		2005		2004
Revenues	1,032		948		412		396		—		—		1,444		1,344
Cost of sales	—		—		(245	)	(242	)	—		—		(245	)	(242	)
Other costs and expenses	(324	)	(298	)	(98	)	(99	)	(1	)	(1	)	(423	)	(398	)
Depreciation	(233	)	(215	)	(20	)	(17	)	—		—		(253	)	(232	)
Operating income/(loss)	475		435		49		38		(1	)	(1	)	523		472
Financial charges and non-controlling interests	(182	)	(193	)	—		(2	)	(31	)	(20	)	(213	)	(215	)
Financial charges of joint ventures	(13	)	(15	)	(3	)	(1	)	—		—		(16	)	(16	)
Equity income	4		11		13		48		—		—		17		59
Interest income and other	(1	)	2		—		1		5		6		4		9
Gain related to PipeLines LP	2		—		—		—		—		—		2		—
Gains related to Power LP	—		—		—		197		—		—		—		197
Gain related to Millennium	—		7		—		—		—		—		—		7
Income taxes	(120	)	(101	)	(17	)	(32	)	20		8		(117	)	(125	)
Net Income	165		146		42		249		(7	)	(7	)	200		388

Six months ended June 30	GasTransmission				Power				Corporate				Total
(unaudited - millions of dollars)	2005		2004		2005		2004		2005		2004		2005		2004

Revenues	2,027		1,897		824		803		—		—		2,851		2,700
Cost of sales	—		—		(510	)	(491	)	—		—		(510	)	(491	)
Other costs and expenses	(630	)	(583	)	(211	)	(187	)	(3	)	(3	)	(844	)	(773	)
Depreciation	(465	)	(427	)	(38	)	(37	)	—		—		(503	)	(464	)
Operating income/(loss)	932		887		65		88		(3	)	(3	)	994		972
Financial charges and non-controlling interests	(369	)	(389	)	(2	)	(4	)	(61	)	(41	)	(432	)	(434	)
Financial charges of joint ventures	(27	)	(29	)	(5	)	(1	)	—		—		(32	)	(30	)
Equity income	15		21		43		96		—		—		58		117
Interest income and other	13		5		3		5		12		14		28		24
Gain related to PipeLines LP	82		—		—		—		—		—		82		—
Gains related to Power LP	—		—		—		197		—		—		—		197
Gain related to Millennium	—		7		—		—		—		—		—		7
Income taxes	(270	)	(207	)	(32	)	(67	)	36		23		(266	)	(251	)
Net Income	376		295		72		314		(16	)	(7	)	432		602

Total Assets	June 30, 2005	December 31,
(millions of dollars)	(unaudited)	2004
Gas Transmission	18,140	18,410
Power	3,589	2,802
Corporate	914	900
	22,643	22,112

4. Risk Management and Financial Instruments

The following represents the material changes to the company’s financial instruments since December 31, 2004.

Energy Price Risk Management

The company executes power, natural gas and heat rate derivatives for overall management of its asset portfolio. Heat rate contracts are contracts for the sale or purchase of power that are priced based on a natural gas index. The fair values and notional volumes of the swap, option, future and heat rate contracts are shown in the tables below. In accordance with the company’s accounting policy, each of the derivatives in the table below is recorded on the balance sheet at its fair value at June 30, 2005 and December 31, 2004.

Power

		June 30, 2005
		(unaudited)		December 31, 2004
Asset/(Liability)	Accounting	Fair		Fair
(millions of dollars)	Treatment	Value		Value

Power - swaps
(maturing 2005 to 2011)	Hedge	(60	)	7
(maturing 2005 to 2010)	Non-hedge	2		(2	)
Gas - swaps, futures and options
(maturing 2005 to 2016)	Hedge	(27	)	(39	)
(maturing 2005 to 2006)	Non-hedge	1		(2	)
Heat rate contracts
(maturing 2005 to 2006)	Hedge	—		(1	)

Notional Volumes
June 30, 2005	Accounting	Power (GWh)		Gas (Bcf)
(unaudited)	Treatment	Purchases	Sales	Purchases	Sales

Power - swaps
(maturing 2005 to 2011)	Hedge	1,299	7,177	—	—
(maturing 2005 to 2010)	Non-hedge	878	—	—	—
Gas - swaps, futures and options
(maturing 2005 to 2016)	Hedge	—	—	85	73
(maturing 2005 to 2006)	Non-hedge	—	—	5	7
Heat rate contracts
(maturing 2005 to 2006)	Hedge	—	55	—	—

Notional Volumes	Accounting	Power (GWh)		Gas (Bcf)
December 31, 2004	Treatment	Purchases	Sales	Purchases	Sales

Power - swaps	Hedge	3,314	7,029	—	—
	Non-hedge	438	—	—	—

Gas - swaps, futures and options	Hedge	—	—	80	84
	Non-hedge	—	—	5	8

Heat rate contracts	Hedge	—	229	2	—

5. Dispositions

PipeLines LP

In March 2005, TransCanada sold 3.5 million common units of TC PipeLines, LP (PipeLines LP) for US$37.04 per unit, resulting in net proceeds to the company of approximately $151 million and an after-tax gain of approximately $48 million. The net gain was recorded in the Gas Transmission segment and the company recorded a $32 million tax charge, including $50 million of current income tax expense, on this transaction. In April 2005, underwriters purchased an additional 74,200 common units, exercising, in part, their option to purchase up to 525,000 additional units on the same terms and conditions as the 3.5 million common units already sold and an additional net after-tax gain of $1 million was recorded in the Gas Transmission segment. Subsequent to these transactions, TransCanada continues to own a 13.4 per cent interest in PipeLines LP represented by the general partner interest of 2.0 per cent as well as an 11.4 per cent limited partner interest.

Power LP

In May 2005, TransCanada announced that it had entered into an agreement with EPCOR Utilities Inc. (EPCOR) whereby EPCOR will purchase TransCanada’s interest in TransCanada Power, L.P. (Power LP) for $529 million. EPCOR’s acquisition includes 14.5 million units of Power LP, representing 30.6 per cent of the outstanding units; 100 per cent ownership of the General Partner of Power LP; and management and operations’ agreements governing the ongoing operation of Power LP’s generation assets.

Paiton Energy

In June 2005, TransCanada reached an agreement to sell its approximate 11 per cent interest in PT Paiton Energy Company (Paiton Energy) to subsidiaries of The Tokyo Electric Power Company for US$103 million ($127 million), subject to adjustments. TransCanada originally purchased its interest in Paiton Energy in 1996. Paiton Energy owns two 615 megawatt coal-fired plants in East Java, Indonesia. Pending various approvals, this transaction is expected to close in third quarter 2005. Upon closing,

TransCanada expects to realize an after-tax gain of approximately $115 million.

6. 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 and six months ended June 30 is as follows.

Three months ended June 30	Pension Benefit Plans				Other Benefit Plans
(unaudited - millions of dollars)	2005		2004		2005	2004
Current service cost	8		7		1	1
Interest cost	16		14		2	2
Expected return on plan assets	(16	)	(13	)	—	—
Amortization of transitional obligation related to regulated business	—		—		—	—
Amortization of net actuarial loss	4		3		—	—
Amortization of past service costs	—		—		—	—
Net benefit cost recognized	12		11		3	3

Six months ended June 30	Pension Benefit Plans				Other Benefit Plans
(unaudited - millions of dollars)	2005		2004		2005	2004
Current service cost	15		14		1	1
Interest cost	32		28		3	3
Expected return on plan assets	(32	)	(27	)	—	—
Amortization of transitional obligation related to regulated business	—		—		1	1
Amortization of net actuarial loss	8		6		1	1
Amortization of past service costs	1		1		—	—
Net benefit cost recognized	24		22		6	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 at (403) 920-7911. The investor fax line is (403) 920-2457. Media Relations: Kurt Kadatz/Hejdi Feick at (403) 920-7859

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

Exhibit 13.3

TRANSCANADA CORPORATION

U.S. GAAP CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

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

	Three months ended June 30						Six months ended June 30
(millions of dollars except per share amounts)	2005			Restated 2004			2005			Restated 2004
Revenues	1,333			1,237			2,622			2,503
Cost of sales	226			212			462			438
Other costs and expenses	417			399			832			787
Depreciation	230			210			458			422
	873			821			1,752			1,647
Operating income	460			416			870			856
Other (income)/expenses
Equity income(1)	(57		)	(99		)	(145		)	(208		)
Other expenses(2)(3)	197			184			322			397
Dilution gain(3)	—			(40		)	—			(40		)
Income taxes	118			126			264			252
	258			171			441			401

Net Income in Accordance with U.S. GAAP	202			245			429			455
Adjustments affecting comprehensive income under U.S. GAAP
Foreign currency translation adjustment, net of tax	5			4			10			7
Changes in minimum pension liability, net of tax	—			25			—			50
Unrealized loss on derivatives, net of tax(4)	(30		)	(16		)	(39		)	(29		)
Comprehensive Income in Accordance with U.S. GAAP	177			258			400			483

Net Income Per Share in Accordance with U.S.
Basic	$	0.42		$	0.51		$	0.88		$	0.94
Diluted	$	0.41		$	0.50		$	0.88		$	0.93

Net Income Per Share in Accordance with Canadian GAAP – Basic and Diluted	$	0.41		$	0.80		$	0.89		$	1.24

Dividends per common share	$	0.305		$	0.29		$	0.61		$	0.58

Common Shares Outstanding (millions)
Average for the period - Basic	485.9			484.0			485.6			483.7
Average for the period - Diluted	488.4			486.6			488.1			486.3

Reconciliation of Net Income

	Three months ended June 30				Six months ended June 30
(millions of dollars)	2005		Restated 2004		2005		Restated 2004
Net Income in Accordance with Canadian GAAP	200		388		432		602
U.S. GAAP adjustments
Unrealized gain/(loss) on energy contracts(5)	1		(1	)	(9	)	3
Tax impact of unrealized gain/(loss) on energy contracts	(1	)	—		3		(1	)
Equity gain/(loss)(6)	1		(2	)	3		(3	)
Tax impact of equity gain/(loss)	—		1		(1	)	1
Unrealized gain/(loss) on foreign exchange and interest rate derivatives(4)	1		(7	)	1		(11	)
Tax impact of gain/(loss) on foreign exchange and interest rate derivatives	—		3		—		4
Deferred income taxes(7)	—		(5	)	—		(5	)
Amortization of deferred gains related to Power LP(3)	—		—		—		(3	)
Deferred gains related to Power LP(3)	—		(132	)	—		(132	)
Net Income in Accordance with U.S. GAAP	202		245		429		455

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)	2005		2004		2005		2004
Cash Generated from Operations
Net cash provided by operating activities	261		301		610		641
Investing Activities
Net cash (used in)/provided by investing activities	(736	)	541		(746	)	405
Financing Activities
Net cash provided by/(used in) financing activities	37		(243	)	125		(410	)
Effect of Foreign Exchange Rate Changes on Cash and Short-Term Investments	20		(1	)	22		3
(Decrease)/Increase in Cash and Short-Term Investments	(418	)	598		11		639
Cash and Short-Term Investments
Beginning of period	553		324		124		283
Cash and Short-Term Investments
End of period	135		922		135		922

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

(millions of dollars)	June 30, 2005	December 31, 2004
Current assets	943	908
Long-term investments(6)(8)	1,853	1,887
Plant, property and equipment	17,543	17,083
Regulatory asset(9)	2,509	2,606
Other assets	1,222	1,217
	24,070	23,701

Current liabilities(10)	2,524	2,573
Deferred amounts(4)(5)(8)	837	785
Long-term debt(4)	10,041	9,753
Deferred income taxes(9)	2,982	3,048
Preferred securities(11)	564	554
Non-controlling interests	466	465
Shareholders’ equity	6,656	6,523
	24,070	23,701

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, 2004	(71	)	(26	)	(4	)	(101	)

Unrealized loss on derivatives, net of tax of $20(4)	—		—		(39	)	(39	)
Foreign currency translation adjustment, net of tax of $18	10		—		—		10

Balance at June 30, 2005	(61	)	(26	)	(43	)	(130	)

Balance at December 31, 2003	(40	)	(98	)	(5	)	(143	)

Changes in minimum pension liability, net of tax of $(26)	—		50		—		50
Unrealized loss on derivatives, net of tax of $12(4)	—		—		(29	)	(29	)
Foreign currency translation adjustment, net of tax of $13	7		—		—		7

Balance at June 30, 2004	(33	)	(48	)	(34	)	(115	)

(1) In accordance with U.S. GAAP, the condensed statement of consolidated income, consolidated cash flows and consolidated balance sheet of TransCanada Corporation (TransCanada or the company) are prepared using the equity method of accounting for joint ventures. Excluding the impact of other U.S. GAAP adjustments, the use of the proportionate consolidation method of accounting for joint ventures, as required under Canadian GAAP, results in the same net income and shareholders’ equity.

(2) Other expenses included an allowance for funds used during construction of $1 million for the six months ended June 30, 2005 (June 30, 2004 - $1 million).

(3) The company records its investment in TransCanada Power, L.P. (Power LP) using the proportionate consolidation method for Canadian GAAP purposes and as an equity investment for U.S. GAAP purposes. During the period from 1997 to April 2004, the company was obligated to fund the redemption of Power LP units in 2017. As a result, under Canadian GAAP, TransCanada accounted for the issuance of units by Power LP to third parties as a sale of a future net revenue stream and the resulting gains were deferred and amortized to income over the period to 2017. The redemption obligation was removed in April 2004 and the unamortized gains were recognized as income. Under U.S. GAAP, any such gains in the period from 1997 to April 2004 are characterized as dilution gains and, because the company was committed to fund the redemption of the units, the gains are recorded, on an after-tax basis, as equity transactions in shareholders’ equity.

The company’s accounting policy for dilution gains is to record them as income for both Canadian and U.S. GAAP purposes, however, U.S. GAAP requires such gains to be recorded directly in equity if there is a contemplation of reacquisition of units. With the removal of the redemption obligation in April 2004, subsequent issuances of units by Power LP are accounted for as dilution gains in income for both Canadian and U.S. GAAP purposes.

(4) 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 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 derivatives 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 recognized in earnings each period. Substantially all of the amounts recorded in the six months ended June 30, 2005 and 2004 as differences between U.S. and Canadian GAAP, for net income, relate to the differences in accounting treatment with respect to the hedged items and, for comprehensive income, relate to cash flow hedges.

(5) Substantially all of the amounts recorded in the six months ended June 30, 2005 and 2004 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 trading contracts in the U.S. and Canada.

(6) 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. (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 Power, L.P., 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.

(7) Under U.S. GAAP, SFAS No. 109 “Accounting for Income Taxes” requires that a deferred tax liability be recognized for an excess of the amount for financial reporting over the tax basis of an investment in a 50 per cent or less owned investee.

(8) 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, 2005 was $9 million (December 31, 2004 - $9 million) and relates to the company’s equity interest in Bruce Power L.P.

(9) 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.

(10) Current liabilities at June 30, 2005 include dividends payable of $154 million (December 31, 2004 - $146 million) and current taxes payable of $194 million (December 31, 2004 - $260 million).

(11) The fair value of the preferred securities at June 30, 2005 was $589 million (December 31, 2004 - $572 million). The company made preferred securities charges payments of $24 million for the six months ended June 30, 2005 (June 30, 2004 - $24 million).

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)	2005		2004		2005		2004
Income
Revenues	278		304		569		579
Other costs and expenses	(158	)	(148	)	(299	)	(267	)
Depreciation	(36	)	(40	)	(76	)	(73	)
Financial charges and other	(27	)	(17	)	(49	)	(31	)
Proportionate share of income before income taxes of long-term investments	57		99		145		208

(millions of dollars)	June 30, 2005		December 31, 2004
Balance sheet
Current assets	308		361
Plant, property and equipment	2,973		3,020
Current liabilities	(173	)	(248	)
Deferred amounts (net)	(245	)	(199	)
Non-recourse debt	(991	)	(1,030	)
Deferred income taxes	(19	)	(17	)
Proportionate share of net assets of long-term investments	1,853		1,887

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 29, 2005	Harold N. Kvisle
	President and Chief Executive Officer

Exhibit 31.2

Certifications

I, Russell K. Girling, certify that:

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

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

	/ s / Russell K. Girling
Dated July 29, 2005	Russell K. Girling
	Executive Vice-President, Corporate Development and Chief Financial Officer

Exhibit 32.1

TRANSCANADA CORPORATION

450 – 1^st Street S.W.

Calgary, Alberta, Canada

T2P 5H1

CERTIFICATION OF CHIEF EXECUTIVE OFFICER

REGARDING PERIODIC REPORT CONTAINING

FINANCIAL STATEMENTS

I, Harold N. Kvisle, the Chief Executive Officer of TransCanada Corporation (the “Company”), in compliance with 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, hereby certify, in connection with the Company’s Quarterly Report as filed on Form 6-K for the period ended June 30, 2005 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 29, 2005

Exhibit 32.2

TRANSCANADA CORPORATION

450 – 1^st Street S.W.

Calgary, Alberta, Canada

T2P 5H1

CERTIFICATION OF CHIEF FINANCIAL OFFICER

REGARDING PERIODIC REPORT CONTAINING

FINANCIAL STATEMENTS

I, Russell K. Girling, the Chief Financial Officer of TransCanada Corporation (the “Company”), in compliance with 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, hereby certify, in connection with the Company’s Quarterly Report as filed on Form 6-K for the period ended June 30, 2005 with the Securities and Exchange Commission (the “Report”), that:

1. the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

2. the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

	/ s / Russell K. Girling
	Russell K. Girling
	Chief Financial Officer
	July 29, 2005

Exhibit 99.1

TRANSCANADA CORPORATION – SECOND QUARTER 2005

Quarterly Report to Shareholders

Media Inquiries:	Kurt Kadatz/Hejdi Feick	(403) 920-7859
		(800) 608-7859
Analyst Inquiries:	David Moneta	(403) 920-7911

TransCanada Announces Second Quarter Results,

Board Declares Dividend of $0.305 per Share

CALGARY, Alberta – July 29, 2005 – (TSX: TRP) (NYSE: TRP)

Second Quarter 2005 Highlights:

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

• Net income for second quarter 2005 of $200 million or $0.41 per share.

• Funds generated from operations for second quarter 2005 of $479 million.

• Dividend of $0.305 per common share declared by the Board of Directors.

TransCanada Corporation today announced net income for second quarter 2005 of $200 million or $0.41 per share, compared to $388 million or $0.80 per share for second quarter 2004. The decrease of $188 million or $0.39 per share was primarily due to the recording in second quarter 2004 of $187 million of after-tax gains relating to the sale of the ManChief and Curtis Palmer assets to TransCanada Power, L.P. (Power LP) and the recognition of dilution gains resulting from a reduction in TransCanada’s ownership interest in Power LP and other previously deferred gains, as well as a $7 million after-tax gain on sale of the company’s equity interest in the Millennium Pipeline project.

Excluding the total gains of $194 million recorded in second quarter 2004 and $1 million recorded in second quarter 2005, net income for second quarter 2005 increased $5 million to $199 million compared to second quarter 2004. The increase was mainly due to higher net income from Gas Transmission which benefited from a National Energy Board (NEB) decision on the Canadian Mainline’s 2004 Tolls and Tariff Application (Phase II) effective from January 1, 2004, as well as contributions from the Gas Transmission Northwest System and the North Baja System which were acquired by TransCanada in fourth quarter 2004. The higher net income in Gas Transmission was partially offset by a decrease of $20 million in Power’s net income, primarily due to lower equity income from Bruce Power L.P. and lower operating and other income from Western Operations, partially offset by higher operating and other income from Eastern Operations.

For the first six months of 2005, TransCanada’s net income was $432 million or $0.89 per share, compared to $602 million or $1.24 per share for the same period in 2004. The decrease of $170 million or $0.35 per share was mainly the result of significantly higher net income in the Power business in 2004 resulting mainly from the gains related to Power LP.

“Through the second quarter 2005, TransCanada continued to identify and evaluate opportunities to further strengthen its position as a leading energy infrastructure company in North America,” said Hal Kvisle, TransCanada’s chief executive officer.

“Over the long term, we continue to see significant, high quality opportunities to grow and create value for shareholders through greenfield developments and acquisitions.”

During the second quarter, TransCanada:

• Closed its acquisition of hydroelectric generation assets, with total generating capacity of 567 megawatts, from USGen New England, Inc. for US$505 million in cash, subject to closing adjustments.

• Received the NEB’s decision on the Canadian Mainline’s 2004 Tolls and Tariff Application (Phase II). In its decision, the NEB approved an increase in the deemed common equity component of the Canadian Mainline’s capital structure from 33 per cent to 36 per cent for 2004, which is also effective for 2005 under the 2005 tolls settlement with shippers. TransCanada had applied for deemed common equity of 40 per cent.

• Entered into an agreement with EPCOR Utilities Inc. (EPCOR) whereby EPCOR will acquire TransCanada’s interest in Power LP (TSX: TPL.UN) for $529 million. The transaction is expected to close in third quarter 2005, subject to regulatory approvals. Upon closing, TransCanada expects to realize an after-tax gain of approximately $200 million from this sale.

• Was awarded a contract by Mexico’s Comisión Federal de Electricidad (CFE) to construct, own and operate a 36 inch, 125 kilometre natural gas pipeline in east-central Mexico. TransCanada expects to invest approximately US$181 million in the project.

• Closed the acquisition of a 3.52 per cent ownership interest in Iroquois from a subsidiary of Goldman Sachs & Co. for US$13.6 million, subject to post-closing adjustments. This acquisition increased TransCanada’s ownership interest from 40.96 per cent to 44.48 per cent.

• Announced an agreement to sell its approximate 11 per cent interest in PT Paiton Energy Company (Paiton Energy) in Indonesia to subsidiaries of The Tokyo Electric Power Company for US$103 million ($127 million) subject to adjustments. The transaction is expected to close in third quarter 2005, subject to approvals. Upon closing, TransCanada expects to realize an after-tax gain of approximately $115 million.

U.S. GAAP restatement

The company is refiling its 2004 consolidated financial statements, which contain a restated Note 22 (U.S. GAAP), with securities regulators in Canada and the United States. The restatement relates to the reporting of TransCanada’s investment in Power LP. For U.S. generally accepted accounting principles (GAAP) purposes, certain transactions involving Power LP, in the period 1997 to 2001, should have been accounted for differently than under Canadian GAAP. This has been corrected on a retroactive basis. The restated Note has no impact on TransCanada’s 2004 financial statements as reported under Canadian GAAP or on total shareholders’ equity at December 31, 2004 as prepared under U.S. GAAP.

Consolidated financial statements for the year ended December 31, 2004 containing the restated Note will be filed on SEDAR and EDGAR and are available at www.transcanada.com. Printed copies may be obtained from TransCanada by calling (403) 920-2000.

Teleconference

TransCanada will hold a teleconference today at 9 a.m. (Mountain) / 11 a.m. (Eastern) to discuss the second quarter 2005 financial

results and general developments and issues concerning the Company. Analysts, members of the media and other interested parties wanting to participate should phone 1-866-546-6145 or 416-406-4206 (Toronto area) at least 10 minutes prior to the start of the teleconference. No passcode is required. A live audio 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 5, 2005 by dialing 1-800-408-3053 or 416-695-5800 (Toronto area) and entering passcode 3158123. The webcast will be archived and available for replay.

About TransCanada

TransCanada is a leading North American energy company. TransCanada is focused on natural gas transmission and power services with employees who are expert in these businesses. TransCanada’s network of approximately 41,000 kilometres (25,600 miles) of pipeline transports the majority of Western Canada’s natural gas production to the fastest growing markets in Canada and the United States. TransCanada owns, controls or is constructing approximately 5,700 megawatts of power generation – an amount of power that can meet the needs of about 5.7 million average households. TransCanada announced in May that it plans to sell its interest in TransCanada Power, L.P., which owns a 744 megawatt power portfolio. The Company’s common shares trade under the symbol TRP on the Toronto and New York stock exchanges.

Second Quarter 2005 Financial Highlights

(unaudited)

Operating Results	Three months ended June 30		Six months ended June 30
(millions of dollars)	2005	2004	2005	2004

Revenues	1,444	1,344	2,851	2,700

Net Income	200	388	432	602

Cash Flows
Funds generated from operations	479	382	886	797
Capital expenditures	135	93	243	194
Acquisitions, net of cash acquired	632	14	632	14

	Three months ended June 30				Six months ended June 30
Common Share Statistics	2005		2004		2005		2004

Net Income Per Share - Basic and Diluted	$	0.41	$	0.80	$	0.89	$	1.24

Dividends Declared Per Share	$	0.305	$	0.29	$	0.61	$	0.58

Common Shares Outstanding (millions)
Average for the period	485.9		484.0		485.6		483.7
End of period	486.5		484.2		486.5		484.2