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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 May 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 o Form 40-F ý

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

Yes o No ý

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

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

13.1: Management's Discussion and Analysis of Financial Condition and Results of Operations of the registrant as at and for the period ended March 31, 2005.
13.2: Consolidated comparative interim unaudited financial statements of the registrant for the three month period ended March 31, 2005 (included in the registrant's First 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 First Quarter 2005 Quarterly Report to Shareholders.

The documents listed below in this Section are furnished, not filed, as Exhibits 99.1 and 99.2. The Exhibits are being furnished, not filed, and will not be incorporated by reference into any registration statement filed by TransCanada Corporation under the Securities Act of 1933, as amended.

99.1: A copy of the Registrant's news release of April 29, 2005.
99.2: A copy of the Registrant's Report of Voting Results at the Annual Meeting of Holders of Common Shares held on April 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

May 2, 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 March 31, 2005.
13.2: Consolidated comparative interim unaudited financial statements of the registrant for the three month period ended March 31, 2005 (included in the registrant's First 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 First Quarter 2005 Quarterly Report to Shareholders.
31.1: Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2: Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1: Certification of Chief Executive Officer regarding Periodic Report containing Financial Statements.
32.2: Certification of Chief Financial Officer regarding Periodic Report containing Financial Statements.
99.1: A copy of the Registrant's news release of April 29, 2005.
99.2: A copy of the Registrant's Report of Voting Results at the Annual Meeting of Holders of Common Shares held on April 29, 2005.

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Exhibit 13.1

MANAGEMENT'S DISCUSSION AND ANALYSIS

Management's discussion and analysis (MD&A) dated April 29, 2005 should be read in conjunction with the accompanying unaudited consolidated financial statements of TransCanada Corporation (TransCanada or the company) for the three months ended March 31, 2005 and should also be read in conjunction with the audited consolidated financial statements and MD&A contained in TransCanada's 2004 Annual Report for the year ended December 31, 2004. 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.

Segment Results-at-a-Glance

	Three months ended March 31
	2005			2004
	(unaudited) (millions of dollars)
Gas Transmission		211			149
Power		30			65
Corporate		(9	)		—

Net Income		232			214

Net Income Per Share — Basic	$	0.48		$	0.44

Results of Operations

Consolidated

TransCanada's net income for first quarter 2005 was $232 million or $0.48 per share compared to $214 million or $0.44 per share for the same period in 2004. The increase of $18 million or $0.04 per share was primarily due to significantly higher net income from the Gas Transmission business resulting mainly from a gain of $48 million after tax or $0.10 per share on the sale of 3.5 million common units of TC PipeLines, LP (PipeLines LP) in first quarter 2005. Excluding this gain, Gas Transmission's net income for first quarter 2005 increased $14 million mainly due to net income of $23 million generated from the Gas Transmission Northwest System and the North Baja System (collectively GTN), which were acquired by TransCanada on November 1, 2004. This increase from GTN was partially offset by lower net income from the Alberta System and the Other Gas Transmission businesses.

A decrease of $35 million in Power's net income for first quarter 2005 compared to first quarter 2004 was primarily due to lower operating and other income from Eastern Operations and Bruce Power L.P. (Bruce Power). Operating and other income from Eastern Operations was lower by $29 million in first quarter 2005 compared to the same period in 2004 primarily as a result of a $10 million after-tax ($16 million pre-tax) cost for the restructuring of natural gas supply contracts by Ocean State Power (OSP) and a $7 million reduction in after-tax income ($12 million pre tax) as a result of the sale of the Curtis Palmer hydroelectric facilities to TransCanada Power, L.P. (Power LP) in April 2004. Bruce Power's equity income was lower mainly due to increased operating expenses.

The increase of $9 million in the Corporate segment's net expenses was mainly as a result of higher financial charges in first quarter 2005 compared to the same period in 2004, and income tax refunds and refund interest received in first quarter 2004, partially offset by certain positive tax adjustments recorded in first quarter 2005.

Funds generated from operations of $407 million for first quarter 2005 decreased $8 million compared to first quarter 2004.

Gas Transmission

The Gas Transmission business generated net income of $211 million for the quarter ended March 31, 2005 compared to $149 million for the same period in 2004.

Gas Transmission Results-at-a-Glance

		Three months ended March 31
		2005		2004
		(unaudited) (millions of dollars)
Wholly-Owned Pipelines
	Canadian Mainline	63		64
	Alberta System	37		40
	GTN⁽¹⁾	23
	Foothills System	5		6
	BC System	2		2

		130		112

Other Gas Transmission
	Great Lakes	14		17
	Iroquois	4		8
	PipeLines LP	4		4
	Portland	6		6
	Ventures LP	3		3
	TQM	2		2
	CrossAlta	5		1
	TransGas	3		3
	Northern Development	(1	)	(1	)
	General, administrative, support costs and other	(7	)	(6	)

		33		37
	Gain related to PipeLines LP	48		—

		81		37

Net Income		211		149

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

Wholly-Owned Pipelines

Canadian Mainline's first quarter 2005 net income of $63 million was $1 million lower than the same quarter in 2004. This decrease is primarily due to a lower rate of return on common equity (ROE), as determined by the National Energy Board (NEB), of 9.46 per cent in 2005 compared to 9.56 per cent in 2004 and a lower average investment base, partially offset by a prior year negative earnings adjustment of $2 million recorded in first quarter 2004. Canadian Mainline's interim tolls and net income in 2005 assume a capital structure comprised of 33 per cent deemed common equity pending the decision on the 2004 Tolls and Tariff Application (Phase II) hearing dealing with capital structure.

The Alberta System's net income of $37 million in first quarter 2005 is $3 million lower than the same quarter in 2004. The decrease is 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 return of 9.50 per cent, as prescribed by the Alberta Energy and Utilities Board (EUB), on deemed common equity of 35 per cent.

GTN, which was acquired by TransCanada in November 2004, generated net income of $23 million in first quarter 2005. The decrease of $1 million in the Foothills System's first quarter 2005 net income compared to the same period in the prior year is primarily due to a lower average investment base in 2005.

Operating Statistics

		Three months ended March 31 (unaudited)
		Canadian Mainline⁽¹⁾		Alberta System⁽²⁾		Gas Transmission Northwest System⁽³⁾		Foothills System		BC System
		2005	2004	2005	2004	2005		2005	2004	2005	2004
Average investment base ($ millions)		7,910	8,314	4,559	4,762	n/a	⁽³⁾	693	722	220	231
Delivery volumes (Bcf)
	Total	767	723	1,051	1,013	215		287	281	94	87
	Average per day	8.5	7.9	11.7	11.1	2.4		3.2	3.1	1.1	1.0

(1): Canadian Mainline deliveries originating at the Alberta border and in Saskatchewan for the three months ended March 31, 2005 were 531 Bcf (2004 — 510 Bcf); average per day was 5.9 Bcf (2004 — 5.6 Bcf).
(2): Field receipt volumes for the Alberta System for the three months ended March 31, 2005 were 965 Bcf (2004 — 950 Bcf); average per day was 10.7 Bcf (2004 — 10.4 Bcf).
(3): TransCanada acquired GTN on November 1, 2004. Both the Gas Transmission Northwest System and the North Baja System are currently operating under fixed rate models approved by the Federal Energy Regulatory Commission and, as a result, the systems' current results are not dependent on average investment base. The North Baja System's total delivery volumes were 19 Bcf; average per day was 0.2 Bcf.

Other Gas Transmission

TransCanada's proportionate share of net income from its Other Gas Transmission businesses was $81 million for the three months ended March 31, 2005 compared to $37 million for the same period in 2004. The first quarter 2005 results include a $48 million after-tax gain on sale of an approximate 20 per cent interest in PipeLines LP. Excluding this gain, net income for the quarter decreased $4 million compared to the same period in 2004. The decrease is mainly due to lower income from Iroquois primarily as a result of a positive tax adjustment recorded in first quarter 2004, and lower income from Great Lakes as a result of lower short-term revenues and higher operating and maintenance costs in first quarter 2005. Other Gas Transmission results were also negatively impacted by a weaker U.S. dollar compared to 2004. These decreases were partially offset by higher earnings from CrossAlta as a result of favourable natural gas storage market conditions. As at March 31, 2005, TransCanada had capitalized $3 million of costs related to its Broadwater liquified natural gas (LNG) project.

On March 23, 2005, TransCanada sold 3.5 million common units of PipeLines LP for net proceeds of approximately $151 million (US$124 million), resulting in an after-tax gain of approximately $48 million (US$40 million). 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 previously sold. PipeLines LP did not receive any proceeds from the sale of the common units. Subsequent to this transaction and the underwriters' exercise of their option, 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

Power Results-at-a-Glance

	Three months ended March 31
	2005		2004
	(unaudited) (millions of dollars)
Western operations	30		35
Eastern operations	5		34
Bruce Power investment	30		48
Power LP investment	9		10
General, administrative, support costs and other	(25	)	(25	)

Operating and other income	49		102
Financial charges	(4	)	(2	)
Income taxes	(15	)	(35	)

Net Income	30		65

Power's net income in first quarter 2005 of $30 million decreased $35 million compared to $65 million in first quarter 2004. The decrease resulted mainly from lower operating and other income in Eastern Operations and Bruce Power.

Eastern Operations' operating and other income was $29 million lower in first quarter 2005 compared to first quarter 2004 due to a $16 million pre-tax ($10 million after-tax) one-time contract restructuring payment from OSP to its natural gas fuel suppliers and a $12 million pre-tax ($7 million after-tax) reduction in income as a result of the sale of the Curtis Palmer hydroelectric facilities to Power LP in April 2004.

Bruce Power's equity income was lower by $18 million in first quarter 2005 compared to first quarter 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 on Units 3 and 4 in first quarter 2005 reduced the otherwise potential increase in total plant output as a result of adding a sixth operating unit. Bruce Power experienced higher operating expenses, including depreciation, in first quarter 2005 as a result of adding Unit 3. The $18 million decrease in Bruce Power's equity income reflects this increase in operating expenses, partially offset by a three per cent increase in total plant output and slightly higher realized prices.

Western Operations

Western Operations Results-at-a-Glance⁽¹⁾

		Three months ended March 31
		2005		2004
		(unaudited) (millions of dollars)
Revenue
	Power sales	164		147
	Other⁽²⁾	11		7

		175		154
Cost of sales		(109	)	(90	)
Other costs and expenses		(31	)	(22	)
Depreciation		(5	)	(7	)

Operating and other income		30		35

(1): ManChief is included until April 30, 2004.
(2): Includes Cancarb Thermax, inter-segment eliminations and miscellaneous.

Western Operations Sales Volumes⁽¹⁾

			Three months ended March 31
			2005	2004
			(unaudited) (GWh)
Generation vs. Purchased
	Generation		636	362
	Purchased
		Sundance A & B PPAs	1,831	1,812
		Other purchases⁽²⁾	731	702

			3,198	2,876

Contracted vs. Spot
	Contracted		2,685	2,678
	Spot		513	198

			3,198	2,876

(1): ManChief is included until April 30, 2004.
(2): Includes Sheerness PPA volumes.

Western Operations' operating and other income in first quarter 2005 was $30 million compared to $35 million earned in the same period in 2004. The $5 million decrease was mainly due to reduced margins in first quarter 2005 resulting from lower market heat rates on uncontracted volumes of power generated. Lower market heat rates are the result of spot market power prices in Alberta that averaged approximately $3 per megawatt hour (MWh) less, and average natural gas prices that were slightly higher, in first quarter 2005 compared to 2004. 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 power in the open market to fulfill its contractual obligations.

Western Operations' revenues increased in first quarter 2005 primarily due to the start-up of the MacKay River facility in mid-2004 and higher revenues from the Sundance power purchase arrangements (PPAs) partially offset by the sale of the ManChief plant to Power LP in April 2004. Generation volumes in first quarter 2005 increased 274 gigawatt hours (GWh) to 636 GWh primarily due to the start-up of the MacKay River facility. Partially offsetting this increase are decreases in volumes associated with unplanned outages at the Bear Creek cogeneration facility in first quarter 2005 and the sale of the ManChief plant. Revenues and cost of sales, related to the Sundance A and B PPAs, increased in 2005 primarily due to higher plant availability and higher power prices under the PPA's. Other costs and expenses were higher in 2005 primarily due to operating costs associated with the MacKay River facility. Depreciation was lower in first quarter 2005 due to the sale of the ManChief plant partially offset by the start-up of the MacKay River facility. In first quarter 2005, approximately 16 per cent of power sales volumes were sold into the spot market compared to seven per cent in 2004. To reduce its exposure to spot market prices on uncontracted volumes, Western Operations, as at March 31, 2005, had fixed price sales contracts to sell forward 7,200 GWh of power for the remainder of 2005 and 7,400 GWh of power for 2006.

Eastern Operations

Eastern Operations Results-at-a-Glance⁽¹⁾

		Three months ended March 31
		2005		2004
		(unaudited) (millions of dollars)
Revenue
	Power sales	114		146
	Other	—		1

		114		147
Cost of sales		(51	)	(76	)
Other costs and expenses		(54	)	(30	)
Depreciation		(4	)	(7	)

Operating and other income		5		34

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

Eastern Operations Sales Volumes⁽¹⁾

		Three months ended March 31
		2005	2004
		(unaudited) (GWh)
Generation vs. Purchased
	Generation	444	377
	Purchased	811	1,234

		1,255	1,611

Contracted vs. Spot
	Contracted	1,189	1,544
	Spot	66	67

		1,255	1,611

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

Operating and other income in first quarter 2005 from Eastern Operations of $5 million was $29 million lower compared to $34 million earned in the same period in 2004. The decrease was due primarily to a $16 million pre-tax ($10 million after-tax) contract restructuring payment made by OSP to its natural gas fuel suppliers and a $12 million pre-tax ($7 million after-tax) reduction in income as a result of the sale of the Curtis Palmer hydroelectric facilities to Power LP in April 2004. Partially offsetting these decreases was income from the Grandview cogeneration facility in New Brunswick which was placed in-service in January 2005. In addition, TransCanada mitigated the impact of increased fuel gas costs at OSP in first quarter 2005.

In first quarter 2005, OSP concluded negotiations with its two Canadian natural gas fuel suppliers and terminated the 20-year purchase contracts which were to expire in 2011. Pricing under the terminated purchase contracts had been subject to numerous arbitration proceedings since late 2001. The latest arbitration, in August 2004, had substantially increased OSP's cost of natural gas to a price in excess of market. New contracts were entered into with the existing natural gas suppliers, effective March 2005 and expiring in October 2008, at an agreed upon pricing mechanism based on market, which is not subject to future arbitration proceedings. As part of these arrangements, payments of $16 million were made to the natural gas suppliers. The contract restructuring was a positive event for OSP and management determined, based on current market conditions, there was no asset impairment writedown of OSP required.

Generation volumes in first quarter 2005 increased 67 GWh to 444 GWh compared to 377 GWh in 2004 primarily due to the Grandview cogeneration facility being placed into service on January 1, 2005. Partially offsetting this increase are 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. Purchased and contracted sales volumes, and the related revenues and cost of sales, decreased year-over-year primarily due to the expiration of long-term contracts held at the end of 2004. Other costs and expenses increased $24 million primarily as a result of OSP's settlement with its fuel gas suppliers and higher fuel gas costs. Depreciation in first quarter 2005 decreased from first quarter 2004 due to the sale of Curtis Palmer to Power LP in April 2004.

In first quarter 2005, approximately five per cent of power sales volumes were sold into the spot market compared to four per cent in 2004. 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, Eastern Operations, as at March 31, 2005, had entered into fixed price sales contracts to sell forward 3,600 GWh of power for the remainder of 2005 and 2,800 GWh of power for 2006. Certain contracted volumes are dependent on customer usage levels.

Bruce Power Investment

Bruce Power Results-at-a-Glance

			Three months ended March 31
			2005		2004
			(unaudited) (millions of dollars)
Bruce Power (100 per cent basis)
	Revenues		418		399

	Operating expenses
		Cash costs (materials, labour, services and fuel)	(265	)	(219	)
		Non-cash costs (depreciation and amortization)	(48	)	(31	)

			(313	)	(250	)

	Operating income		105		149
	Financial charges		(17	)	(18	)

	Income before income taxes		88		131

TransCanada's interest in Bruce Power income before income taxes			28		41
Adjustments			2		7

TransCanada's income from Bruce Power before income taxes			30		48

TransCanada's share of power output from Bruce Power for first quarter 2005 was 2,598 GWh compared to 2,530 GWh in first quarter 2004. This increase primarily reflects higher output in 2005 as a result of a reduction in unplanned outages in first quarter 2005 compared to first quarter 2004. Approximately 79 reactor days of planned maintenance outages as well as 17 reactor days of minor unplanned outages occurred in first quarter 2005. In first quarter 2004, Bruce Power experienced 49 reactor days of unplanned outages and Unit 3 was unavailable for 60 days due to completion of initial restart activities. The Bruce units ran at an average availability of 81 per cent in first quarter 2005, compared to an 80 per cent average availability during first quarter 2004. A scheduled maintenance outage on Unit 3 began on January 8, 2005 and the unit returned to service on March 8, 2005. Unit 4 began a similar planned maintenance outage on March 12, 2005 that is also expected to last approximately two months.

Overall prices achieved during first quarter 2005 were approximately $50 per MWh, compared to approximately $49 per MWh in first quarter 2004. Approximately 50 per cent of the available output was sold into Ontario's wholesale spot market in first quarter 2005 with the remainder being sold under longer term contracts. On a per unit basis, Bruce operating expenses increased to $38 per MWh in first quarter 2005 from $31 per MWh in first quarter 2004. This increase is due partly to increased outage costs, primarily related to the Units 3 and 4 planned maintenance outages. The increase in operating expenses is also the result of higher staff and lease costs in first quarter 2005, reflecting the move to a six-unit site. In addition, the completion of the Unit 3 restart has resulted in higher depreciation and lower capitalization of labour and other in-house costs in first quarter 2005.

Adjustments to TransCanada's interest in Bruce Power income before income taxes for the three months ended March 31, 2005 were lower than in 2004 primarily due to the cessation of interest capitalization upon the return to service of Unit 3 as well as lower amortization of the purchase price discrepancy related to the fair value of sales contracts in place at the time of acquisition.

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 40 per cent of planned output for the balance of 2005.

On April 15, 2005, Bruce Power experienced a transformer fire outside of the generating facility. As a result, Unit 6 went offline and some biodegradable mineral oil entered into Lake Huron, the clean up of which is close to complete. Unit 6 is expected to return to service in late May and the cost to replace the damaged transformer is not expected to be significant. Primarily as a result of this unplanned outage, overall plant availability for Bruce Power in 2005 is expected to reduce to 83 per cent from the previously reported 85 per cent.

In March 2005, a tentative agreement was reached with an Ontario provincial negotiator for the potential restart of Units 1 and 2 at Bruce Power. Details of the tentative agreement, which have been approved in principle by the Boards of Directors of the major partners of Bruce Power, are now being considered by the Ontario government.

Power LP Investment

Operating and other income of $9 million from Power LP in first quarter 2005 was $1 million lower compared to $10 million in first quarter 2004. The decrease was primarily due to TransCanada's reduced ownership interest in Power LP in 2005 (30.6 per cent compared to 35.6 per cent in first quarter 2004) and 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 into income the amortization of these deferred gains over a period through to 2017. Additional earnings from Power LP's second quarter 2004 acquisition of the Curtis Palmer and ManChief facilities partially offset these decreases.

General, Administrative, Support Costs and Other

General, administrative, support costs and other of $25 million in first quarter 2005 were comparable to the same period in 2004.

Power Sales Volumes and Plant Availability

Power Sales Volumes

	Three months ended March 31
	2005	2004
	(unaudited) (GWh)
Western operations⁽¹⁾	3,198	2,876
Eastern operations⁽¹⁾	1,255	1,611
Bruce Power investment⁽²⁾	2,598	2,530
Power LP investment⁽¹⁾⁽³⁾	697	572

Total	7,748	7,589

(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 March 31
	2005	2004
	(unaudited)
Western operations⁽²⁾	93%	99%
Eastern operations⁽²⁾	85%	98%
Bruce Power investment⁽³⁾	81%	80%
Power LP investment⁽²⁾	99%	99%
All plants, excluding Bruce Power investment	91%	89%
All plants	87%	85%

(1): Plant availability represents the percentage of time in the year 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.

In late February 2005, OSP experienced an unplanned outage affecting 50 per cent of the capacity of this facility. This outage is expected to continue into third quarter 2005. This outage is not expected to significantly impact Eastern Operations' operating income.

Corporate

Net expenses were $9 million and nil for the three months ended March 31, 2005 and 2004 respectively. The $9 million increase in net expenses is primarily due to increased interest expense on debt that was issued in 2004 and the receipt of income tax refunds and related interest in first quarter 2004. These negative variances were partially offset by certain positive tax adjustments recorded in 2005.

Liquidity and Capital Resources

Funds Generated from Operations

Funds generated from continuing operations were $407 million for the three months ended March 31, 2005 compared with $415 million for the same period 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 months ended March 31, 2005, capital expenditures totalled $108 million (2004 — $101 million) and related primarily to construction of new power plants, and maintenance and capacity capital in the Gas Transmission business.

Financing Activities

TransCanada retired $321 million of long-term debt in the three months ended March 31, 2005. In January 2005, the company issued $300 million of medium-term notes bearing interest at 5.10 per cent due in 2017. For the three months ended March 31, 2005, outstanding notes payable increased by $244 million, while cash and short-term investments increased by $438 million.

Dividends

On April 29, 2005, TransCanada's Board of Directors declared a quarterly dividend of $ 0.305 per share for the quarter ending June 30, 2005 on the outstanding common shares. This is the 166^th consecutive quarterly dividend paid by TransCanada and its subsidiary on the common shares. It is payable on July 29, 2005 to shareholders of record at the close of business on June 30, 2005.

Contractual Obligations

Power's commodity purchase obligations as disclosed in the MD&A in TransCanada's 2004 Annual Report were as follows: 2005 — $429 million, 2006 — $255 million; 2007 — $259 million; 2008 — $266 million; 2009 — $277 million and 2010⁺ — $2,658 million. Primarily as a result of new contracts in first quarter 2005, Power's commodity purchase obligations are currently estimated to be as follows: remainder of 2005 — $583 million; 2006 — $653 million; 2007 — $627 million; 2008 — $550 million; 2009 — $273 million and 2010⁺ — $2,648 million. There have been no other material changes to TransCanada's contractual obligations, including payments due for the next five years and thereafter, since December 31, 2004. 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 risk management and 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 March 31, 2005 and December 31, 2004.

Power

			March 31, 2005 (unaudited)
					December 31, 2004
Asset/(Liability) (millions of dollars)		Accounting Treatment			December 31, 2004
Asset/(Liability) (millions of dollars)		Accounting Treatment	Fair Value		Fair Value
Power — swaps
	(maturing 2005 to 2011)	Hedge	(35	)	7
	(maturing 2005)	Non-hedge	2		(2	)
Gas — swaps, futures and options
	(maturing 2005 to 2016)	Hedge	(24	)	(39	)
	(maturing 2005)	Non-hedge	(5	)	(2	)
Heat rate contracts
	(maturing 2005 to 2006)	Hedge	—		(1	)

			March 31, 2005
			Power (GWh)		Gas (Bcf)
		Accounting Treatment	Power (GWh)		Gas (Bcf)
		Accounting Treatment	Purchases	Sales	Purchases	Sales
			(unaudited)
Notional Volumes
Power — swaps
	(maturing 2005 to 2011)	Hedge	1,752	7,237	—	—
	(maturing 2005)	Non-hedge	330	—	—	—
Gas — swaps, futures and options
	(maturing 2005 to 2016)	Hedge	—	—	78	74
	(maturing 2005)	Non-hedge	—	—	3	6
Heat rate contracts
	(maturing 2005 to 2006)	Hedge	—	76	—	—

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

With respect to continuing operations, 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 first 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.

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

Total Liabilities and Shareholders' Equity		—

(1): Regulatory deferral.

Outlook

In 2005, the company expects higher net income from the Gas Transmission segment than originally anticipated as a result of the gain related to the sale of PipeLines LP units. Excluding this impact, 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 energies 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 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 toll to be charged for FT-NR, not to review its decision on disputed regulatory and legal costs and, at CAPP's request, deferred 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 March 2005, TransCanada filed an application for approval of a negotiated settlement with respect to 2005 Canadian Mainline tolls. The settlement established operating, maintenance and administration (OM&A) costs at $169.5 million with variances between actual OM&A costs in 2005 and those agreed to in the settlement accruing to TransCanada. The majority of other cost elements of the 2005 revenue requirement will be treated on a flow through basis. Further, the 2005 ROE is set at 9.46 per cent and the deemed common equity component of the Canadian Mainline's capital structure in 2005 shall be based on the NEB's decision on the Canadian Mainline's cost of capital for 2004, subject to the outcome of any review applications or appeals. On April 7, 2005, the NEB approved TransCanada's application for a negotiated settlement of 2005 Canadian Mainline tolls as filed.

Alberta System

On March 10, 2005, TransCanada reached a settlement with shippers and other interested parties with respect to the annual revenue requirements of the Alberta System for the years 2005, 2006 and 2007. The settlement encompasses all elements of the Alberta System revenue requirement, including OM&A costs, return on equity, depreciation and income and municipal taxes.

In the Alberta System settlement, OM&A costs are fixed at $193 million for 2005, $201 million for 2006, and $207 million for 2007. Any variance between actual OM&A and those agreed to in the settlement in each year will accrue to TransCanada. The majority of other cost elements of the 2005, 2006 and 2007 revenue requirements will be treated on a flow through basis. The return on equity capital will be calculated annually during the term of the settlement using the EUB formula for the purpose of establishing the annual generic rate of return for Alberta utilities on deemed common equity of 35 per cent. For 2005, the ROE under the EUB formula is 9.50 per cent. Depreciation costs will be determined using the depreciation rates and methodology that the company proposed to the EUB in its 2004 General Rate Application (GRA).

On March 21, 2005, TransCanada applied to the EUB for approval of the Alberta System settlement for 2005 to 2007. Upon EUB approval of the settlement, TransCanada intends to withdraw its motion to the Alberta Court of Appeal filed in September 2004 for leave to appeal Phase 1 of the 2004 GRA with respect to the disallowance of applied-for incentive compensation 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 through the Phase 2 proceeding of the Alberta System's 2005 GRA. The Phase 2 proceeding will address the allocation of costs among transportation services and rate design. TransCanada filed this application with the EUB on April 15, 2005.

Other Gas Transmission

Northern Development

In March 2005, TransCanada's wholly-owned subsidiary, Foothills Pipe Lines Ltd., signed a Traditional Knowledge Protocol (Protocol) with the Kaska Nation. The Protocol sets out how Kaska Traditional Knowledge will be incorporated into the planning, construction and operations of the Alaska Highway Pipeline Project.

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 specified 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 its rights were assigned to the Vermont Hydroelectric Power Authority (Vermont Hydroelectric). TransCanada has assumed this obligation and will, therefore, sell the Bellows Falls facility to Vermont Hydroelectric for US$72 million. This transaction is expected to close by the end of second quarter 2005 following receipt of regulatory approvals and the satisfaction of certain conditions under the option agreement. When the sale of the Bellows Falls facility is completed, TransCanada will have 12 dams and 36 hydroelectric generating units on two rivers in New England: the 433 MW Connecticut River system in New Hampshire and Vermont and the 84 MW Deerfield River system in Massachusetts and Vermont.

Other

In April 2005, Gas Transmission Northwest Corporation provided notice to the holders of its US$150 million 7.80 per cent Senior Unsecured Debentures (Debentures) that it will exercise its right to redeem all of the outstanding Debentures on June 1, 2005. Holders of the Debentures will be entitled to US$1,069.36 per US$1,000 principal amount. This amount includes US$30.36 representing the redemption premium and US$39.00 representing accrued and unpaid interest to the redemption date.

Share Information

As at March 31, 2005, TransCanada had 485,550,517 issued and outstanding common shares. In addition, there were 10,383,599 outstanding options to purchase common shares, of which 7,956,022 were exercisable as at March 31, 2005.

Selected Quarterly Consolidated Financial Data⁽¹⁾

		2005		2004								2003
		First		Fourth		Third		Second		First		Fourth		Third		Second
		(unaudited)
		(millions of dollars except per share amounts)
Revenues			1,305		1,407		1,247		1,278		1,266		1,319		1,391		1,311
Net Income
	Continuing operations		232		185		193		388		214		193		198		202
	Discontinued operations		—		—		52		—		—		—		50		—

			232		185		245		388		214		193		248		202

Share Statistics
Net income per share — Basic
	Continuing operations	$	0.48	$	0.38	$	0.40	$	0.80	$	0.44	$	0.40	$	0.41	$	0.42
	Discontinued operations		—		—		0.11		—		—		—		0.10		—

		$	0.48	$	0.38	$	0.51	$	0.80	$	0.44	$	0.40	$	0.51	$	0.42

Net income per share — Diluted
	Continuing operations	$	0.48	$	0.38	$	0.39	$	0.80	$	0.44	$	0.40	$	0.41	$	0.42
	Discontinued operations		—		—		0.11		—		—		—		0.10		—

		$	0.48	$	0.38	$	0.50	$	0.80	$	0.44	$	0.40	$	0.51	$	0.42

Dividend declared per common share		$	0.305	$	0.29	$	0.29	$	0.29	$	0.29	$	0.27	$	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 2004 audited consolidated financial statements included in TransCanada's 2004 Annual Report.

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.

•: Second quarter 2003 net earnings included a $19 million positive after-tax earnings impact of a June 2003 settlement with a former counterparty that had previously defaulted under power forward contracts.
•: 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 GCOC 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, thereby recording $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.

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.

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Exhibit 13.1

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Exhibit 13.2

Consolidated Income

	Three months ended March 31
	2005			2004
	(unaudited) (millions of dollars except per share amounts)
Revenues		1,305			1,266
Operating Expenses
Cost of sales		160			166
Other costs and expenses		424			368
Depreciation		250			232

		834			766

Operating Income		471			500
Other Expenses/(Income)
Financial charges		207			207
Financial charges of joint ventures		16			14
Equity income		(41	)		(58	)
Interest income and other		(24	)		(15	)
Gain related to PipeLines LP		(80	)		—

		78			148

Income before Income Taxes and Non-Controlling Interests		393			352
Income Taxes
Current		161			103
Future		(12	)		23

		149			126

Non-Controlling Interests
Preferred share dividends		6			6
Other		6			6

		12			12

Net Income		232			214

Net Income Per Share — Basic and Diluted	$	0.48		$	0.44

Average Shares Outstanding — Basic (millions)		485.2			483.4

Average Shares Outstanding — Diluted (millions)		487.9			486.1

See accompanying notes to the consolidated financial statements.

Consolidated Cash Flows

	Three months ended March 31
	2005		2004
	(unaudited) (millions of dollars)
Cash Generated From Operations
Net income	232		214
Depreciation	250		232
Gain related to PipeLines LP, net of current tax expense (Note 5)	(30	)	—
Equity income in excess of distributions received	(34	)	(51	)
Pension funding in excess of expense	(7	)	(12	)
Future income taxes	(12	)	23
Non-controlling interests	12		12
Other	(4	)	(3	)

Funds generated from operations	407		415
Increase in operating working capital	(46	)	(42	)

Net cash provided by continuing operations	361		373
Net cash provided by/(used in) discontinued operations	4		(2	)

	365		371

Investing Activities
Capital expenditures	(108	)	(101	)
Disposition of assets	151		—
Deferred amounts and other	(58	)	(47	)

Net cash used in investing activities	(15	)	(148	)

Financing Activities
Dividends	(146	)	(140	)
Notes payable issued/(repaid), net	244		(229	)
Long-term debt issued	300		665
Reduction of long-term debt	(321	)	(476	)
Non-recourse debt of joint ventures issued	5		6
Reduction of non-recourse debt of joint ventures	(7	)	(9	)
Common shares issued	11		13

Net cash provided by/(used in) financing activities	86		(170	)

Effect of Foreign Exchange Rate Changes on Cash and Short-Term Investments	2		4

Increase in Cash and Short-Term Investments	438		57
Cash and Short-Term Investments
Beginning of period	188		338

Cash and Short-Term Investments
End of period	626		395

Supplementary Cash Flow Information
Income taxes paid	192		161
Interest paid	190		172

See accompanying notes to the consolidated financial statements.

Consolidated Balance Sheet

	March 31, 2005		December 31, 2004
	(unaudited)
	(millions of dollars)
ASSETS
Current Assets
Cash and short-term investments	626		188
Accounts receivable	539		627
Inventories	170		174
Other	142		120

	1,477		1,109
Long-Term Investments	833		840
Plant, Property and Equipment	18,594		18,704
Other Assets	1,526		1,459

	22,430		22,112

LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities
Notes payable	790		546
Accounts payable	1,039		1,135
Accrued interest	234		214
Current portion of long-term debt	773		766
Current portion of non-recourse debt of joint ventures	81		83

	2,917		2,744
Deferred Amounts	848		783
Long-Term Debt	9,703		9,713
Future Income Taxes	491		509
Non-Recourse Debt of Joint Ventures	779		779
Preferred Securities	556		554

	15,294		15,082

Non-Controlling Interests
Preferred shares of subsidiary	389		389
Other	81		76

	470		465

Shareholders' Equity
Common shares	4,722		4,711
Contributed surplus	271		270
Retained earnings	1,739		1,655
Foreign exchange adjustment	(66	)	(71	)

	6,666		6,565

	22,430		22,112

See accompanying notes to the consolidated financial statements.

Consolidated Retained Earnings

	Three months ended March 31
	2005		2004
	(unaudited) (millions of dollars)
Balance at beginning of period	1,655		1,185
Net income	232		214
Common share dividends	(148	)	(140	)

	1,739		1,259

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 annual financial statements included in TransCanada's 2004 Annual Report. Amounts are stated in Canadian dollars unless otherwise indicated. Certain comparative figures have been reclassified to conform with the current period's presentation.

Since a determination of many assets, liabilities, revenues and expenses is dependent upon future events, the preparation of these consolidated financial statements requires the use of estimates and assumptions. In the opinion of Management, these consolidated financial statements have been properly prepared within reasonable limits of materiality and within the framework of the company's significant accounting policies.

2. 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 first 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.

		Increase/(Decrease)
		(unaudited — millions of dollars)
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 March 31 (unaudited — millions of dollars)
	Gas Transmission				Power				Corporate				Total
	2005		2004		2005		2004		2005		2004		2005		2004
Revenues	995		949		310		317		—		—		1,305		1,266
Cost of sales	—		—		(160	)	(166	)	—		—		(160	)	(166	)
Other costs and expenses	(306	)	(285	)	(116	)	(81	)	(2	)	(2	)	(424	)	(368	)
Depreciation	(232	)	(212	)	(18	)	(20	)	—		—		(250	)	(232	)

Operating income/(loss)	457		452		16		50		(2	)	(2	)	471		500
Financial charges and non-controlling interests	(187	)	(196	)	(2	)	(2	)	(30	)	(21	)	(219	)	(219	)
Financial charges of joint ventures	(14	)	(14	)	(2	)	—		—		—		(16	)	(14	)
Equity income	11		10		30		48		—		—		41		58
Interest income and other	14		3		3		4		7		8		24		15
Gain related to PipeLines LP	80		—		—		—		—		—		80		—
Income taxes	(150	)	(106	)	(15	)	(35	)	16		15		(149	)	(126	)

Net Income	211		149		30		65		(9	)	—		232		214

Total Assets

	March 31, 2005	December 31, 2004
	(unaudited)
	(millions of dollars)
Gas Transmission	18,144	18,410
Power	2,915	2,802
Corporate	1,367	893

Continuing Operations	22,426	22,105
Discontinued Operations	4	7

	22,430	^22,112

4. Risk Management and Financial Instruments

The following represents the material changes to the company's risk management and 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 March 31, 2005 and December 31, 2004.

			March 31, 2005 (unaudited)
					December 31, 2004
Asset/(Liability) (millions of dollars)		Accounting Treatment			December 31, 2004
Asset/(Liability) (millions of dollars)		Accounting Treatment	Fair Value		Fair Value
Power — swaps
	(maturing 2005 to 2011)	Hedge	(35	)	7
	(maturing 2005)	Non-hedge	2		(2	)
Gas — swaps, futures and options
	(maturing 2005 to 2016)	Hedge	(24	)	(39	)
	(maturing 2005)	Non-hedge	(5	)	(2	)
Heat rate contracts
	(maturing 2005 to 2006)	Hedge	—		(1	)

			March 31, 2005 (unaudited)
			Power (GWh)		Gas (Bcf)
		Accounting Treatment	Power (GWh)		Gas (Bcf)
		Accounting Treatment	Purchases	Sales	Purchases	Sales
Notional Volumes
Power — swaps
	(maturing 2005 to 2011)	Hedge	1,752	7,237	—	—
	(maturing 2005)	Non-hedge	330	—	—	—
Gas — swaps, futures and options
	(maturing 2005 to 2016)	Hedge	—	—	78	74
	(maturing 2005)	Non-hedge	—	—	3	6
Heat rate contracts
	(maturing 2005 to 2006)	Hedge	—	76	—	—

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

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. PipeLines LP did not receive any proceeds from the sale of the common units. Subsequent to this transaction and the underwriter's exercise of their option, 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.

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 months ended March 31 is as follows.

		Three months ended March 31 (unaudited — millions of dollars)
		Pension Benefit Plans				Other Benefit Plans
		2005		2004		2005	2004
Current service cost		7		7		—	—
Interest cost		16		14		1	1
Expected return on plan assets		(16	)	(14	)	—	—
	regulated business	—		—		1	1
Amortization of net actuarial loss		4		3		1	1
Amortization of past service costs		1		1		—	—

Net benefit cost recognized		12		11		3	3

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

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

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

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Exhibit 13.2

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)

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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 March 31
		2005			2004
		(millions of dollars except per share amounts)
Revenues			1,187			1,176

Cost of sales			131			143
Other costs and expenses			418			381
Depreciation			228			212

			777			736

Operating income			410			440
Other (income)/expenses
	Equity income⁽¹⁾		(88	)		(109	)
	Other expenses⁽²⁾		125			210
	Income taxes		146			126

			183			227

Net Income in Accordance with U.S. GAAP			227			213
Adjustments affecting comprehensive income under U.S. GAAP
	Foreign currency translation adjustment, net of tax		5			3
	Changes in minimum pension liability, net of tax		—			25
	Unrealized loss on derivatives, net of tax⁽³⁾		(9	)		(13	)

Comprehensive Income in Accordance with U.S. GAAP			223			228

Net Income Per Share in Accordance with U.S. GAAP — Basic and
	Diluted	$	0.47		$	0.44

Net Income Per Share in Accordance with Canadian GAAP — Basic
	and Diluted	$	0.48		$	0.44

Dividends per common share		$	0.305		$	0.29

Common Shares Outstanding (millions)
	Average for the period — Basic		485.2			483.4

	Average for the period — Diluted		487.9			486.1

Reconciliation of Net Income

		Three months ended March 31
		2005		2004
		(millions of dollars)
Net Income in Accordance with Canadian GAAP		232		214
U.S. GAAP adjustments
	Unrealized (loss)/gain on energy contracts⁽⁴⁾	(10	)	4
	Tax impact of unrealized (loss)/gain on energy contracts	4		(1	)
	Equity gain/(loss)⁽⁵⁾	2		(1	)
	Tax impact of equity gain/(loss)	(1	)	—
	Unrealized loss on foreign exchange and interest rate derivatives⁽³⁾	—		(4	)
	Tax impact of loss on foreign exchange and interest rate derivatives	—		1

Net Income in Accordance with U.S. GAAP		227		213

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

		Three months ended March 31
		2005		2004
		(millions of dollars)
Cash Generated from Operations
	Net cash provided by continuing operations	345		342
	Net cash provided by/(used in) discontinued operations	4		(2	)

		349		340
Investing Activities
	Net cash used in investing activities	(10	)	(136	)
Financing Activities
	Net cash provided by/(used in) financing activities	88		(167	)
Effect of Foreign Exchange Rate Changes on Cash and Short-Term
	Investments	2		4

Increase in Cash and Short-Term Investments		429		41
Cash and Short-Term Investments
	Beginning of period	124		283

Cash and Short-Term Investments
	End of period	553		324

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

	March 31, 2005	December 31, 2004
	(millions of dollars)
Current assets	1,265	908
Long-term investments⁽⁵⁾⁽⁶⁾	1,856	1,887
Plant, property and equipment	16,990	17,083
Regulatory asset⁽⁷⁾	2,580	2,606
Other assets	1,272	1,217

	23,963	23,701

Current liabilities⁽⁸⁾	2,765	2,573
Deferred amounts^(3)(4)(6)	835	785
Long-term debt⁽³⁾	9,733	9,753
Deferred income taxes⁽⁷⁾	2,994	3,048
Preferred securities⁽⁹⁾	556	554
Non-controlling interests	470	465
Shareholders' equity	6,610	6,523

	23,963	23,701

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

	Cumulative Translation Account		Minimum Pension Liability (SFAS No. 87)		Cash Flow Hedges (SFAS No. 133)		Total
	(millions of dollars)
Balance at December 31, 2004	(71	)	(26	)	(4	)	(101	)
Unrealized loss on derivatives, net of tax of $8⁽³⁾	—		—		(9	)	(9	)
Foreign currency translation adjustment, net of tax of $10	5		—		—		5

Balance at March 31, 2005	(66	)	(26	)	(13	)	(105	)

Balance at December 31, 2003	(40	)	(98	)	(5	)	(143	)
Changes in minimum pension liability, net of tax of $(13)	—		25		—		25
Unrealized loss on derivatives, net of tax of $7⁽³⁾	—		—		(13	)	(13	)
Foreign currency translation adjustment, net of tax of $6	3		—		—		3

Balance at March 31, 2004	(37	)	(73	)	(18	)	(128	)

(1): In accordance with U.S. GAAP, the condensed statement of consolidated income, consolidated cash flows and 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 three months ended March 31, 2005 (March 31, 2004 — $1 million).
(3): All foreign exchange and interest rate derivatives are recorded in the company's consolidated financial statements at fair value under Canadian GAAP. Under the provisions of 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 three months ended March 31, 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.
(4): Substantially all of the amounts recorded in the three months ended March 31, 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.
(5): 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.
(6): Financial Interpretation (FIN) 45 requires the recognition of a liability for the fair value of certain guarantees that require payments contingent on specified types of future events. The measurement standards of FIN 45 are applicable to guarantees entered into after January 1, 2003. For U.S. GAAP purposes, the fair value of guarantees recorded as a liability at March 31, 2005 was $9 million (December 31, 2004 — $9 million) and relates to the company's equity interest in Bruce Power L.P.
(7): 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.
(8): Current liabilities at March 31, 2005 include dividends payable of $153 million (December 31, 2004 — $146 million) and current taxes payable of $244 million (December 31, 2004 — $260 million).
(9): The fair value of the preferred securities at March 31, 2005 was $574 million (December 31, 2004 — $572 million). The company made preferred securities charges payments of $12 million for the three months ended March 31, 2005 (March 31, 2004 — $12 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 March 31
	2005		2004
	(millions of dollars)
Income
Revenues	291		275
Other costs and expenses	(141	)	(119	)
Depreciation	(40	)	(33	)
Financial charges and other	(22	)	(14	)

Proportionate share of income before income taxes of long-term investments	88		109

	March 31, 2005		December 31, 2004
	(millions of dollars)
Balance sheet
Current assets	353		361
Plant, property and equipment	2,920		3,020
Current liabilities	(197	)	(248	)
Deferred amounts (net)	(222	)	(199	)
Non-recourse debt	(979	)	(1,030	)
Deferred income taxes	(19	)	(17	)

Proportionate share of net assets of long-term investments	1,856		1,887

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Exhibit 13.3

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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 May 2, 2005		Harold N. Kvisle President and Chief Executive Officer

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Exhibit 31.1

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Exhibit 31.2

Certifications

I, Russell K. Girling, certify that:

1.

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

2.

3.

4.

(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.

(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/ RUSSELL K. GIRLING
Dated May 2, 2005		Russell K. Girling Executive Vice-President, Corporate Development and Chief Financial Officer

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Exhibit 31.2

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Exhibit 32.1

TRANSCANADA CORPORATION

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

CERTIFICATION OF CHIEF EXECUTIVE OFFICER
REGARDING PERIODIC REPORT CONTAINING
FINANCIAL STATEMENTS

I, Harold N. Kvisle, the Chief Executive Officer of TransCanada Corporation (the "Company"), in compliance with 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, hereby certify, in connection with the Company's Quarterly Report as filed on Form 6-K for the period ended March 31, 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 May 2, 2005

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Exhibit 32.1

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Exhibit 32.2

TRANSCANADA CORPORATION

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

CERTIFICATION OF CHIEF FINANCIAL OFFICER
REGARDING PERIODIC REPORT CONTAINING
FINANCIAL STATEMENTS

I, Russell K. Girling, the Chief Financial Officer of TransCanada Corporation (the "Company"), in compliance with 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, hereby certify, in connection with the Company's Quarterly Report as filed on Form 6-K for the period ended March 31, 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 May 2, 2005

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Exhibit 32.2

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Exhibit 99.1

TRANSCANADA CORPORATION — FIRST 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 First Quarter Results,
Board Declares Dividend of $0.305 per Share

CALGARY, Alberta — April 29, 2005 — (TSX: TRP) (NYSE: TRP)

First Quarter 2005 Financial Highlights:
(All financial figures are in Canadian dollars unless noted otherwise)

•: Net income for first quarter 2005 of $232 million or $0.48 per share.
•: Funds generated from operations for first quarter 2005 of $407 million.
•: Dividend of $0.305 per common share declared by the Board of Directors.

TransCanada Corporation today announced net income for first quarter 2005 of $232 million or $0.48 per share, compared to $214 million or $0.44 per share for first quarter 2004. The increase of $18 million or $0.04 per share was primarily attributable to the sale of 3.5 million common units of TC PipeLines, LP. The sale generated an after-tax gain of $48 million or $0.10 per share. Partially offsetting this gain was a reduction in income from Power of $35 million or $0.07 per share, which included a $10 million after-tax cost for the restructuring of natural gas supply contracts and the impact of the sale of the Curtis Palmer and ManChief plants in 2004.

Funds generated from operations of $407 million decreased $8 million compared to first quarter 2004.

"Since the beginning of the first quarter, we have continued to add to our portfolio of high quality energy infrastructure to build on our solid growth strategy," said Hal Kvisle, TransCanada's chief executive officer.

"For example, the USGen transaction, which we closed on April 1, will contribute to earnings for the remainder of the year. We are also pleased with the performance of the Gas Transmission Northwest and North Baja Systems which we acquired in November 2004 and contributed net income of $23 million in first quarter 2005.

"Adherence to our strategy, combined with our strong balance sheet, position us to deliver value for shareholders in the future."

During first quarter 2005, TransCanada:

•: Announced that it is developing a $200 million natural gas storage facility near Edson, Alberta.
•: Proposed a US$1.7 billion oil pipeline project to transport approximately 400,000 barrels per day of heavy crude oil from Alberta to Illinois.
•: Reached a settlement with shippers and other interested parties on 2005 tolls on its Canadian Mainline natural gas transmission system. The settlement was approved by the National Energy Board.
•: Reached a settlement with shippers and other interested parties for 2005, 2006 and 2007 regarding the annual revenue requirements of the Alberta System. This settlement requires approval by the Alberta Energy and Utilities Board.
•: Announced that Cartier Wind Energy (62 per cent owned by TransCanada) had signed long-term electricity supply contracts with Hydro-Québec Distribution for 739.5 megawatts (MW) of wind power projects. The total estimated capital cost of the projects is more than $1.1 billion.
•: Announced that wholly-owned subsidiary, Foothills Pipe Lines Ltd., had signed a protocol with the Kaska Nation establishing how Kaska traditional knowledge will be integrated into planning, construction and operations of the Alaska Highway Pipeline Project.
•: Sold 3.5 million common units of TC PipeLines, LP for $151 million, recording an after-tax gain of $48 million or $0.10 per share.
•: Reached agreement with natural gas suppliers for Ocean State Power to terminate existing natural gas supply contracts, replacing them with market price-based supply contracts, resulting in a one-time after-tax cost of $10 million or $0.02 per share.

On April 1, 2005, TransCanada closed the acquisition of hydroelectric generation assets with 567 MW of generating capacity from USGen New England, Inc. for US$505 million in cash. The Town of Rockingham exercised its option to purchase the 49 MW Bellows Falls facility for US$72 million. The Bellows Falls transaction is expected to close by end of second quarter 2005, subject to regulatory approvals and satisfaction of other conditions under the option agreement.

Teleconference

TransCanada will hold a teleconference today at 1:30 p.m. (Mountain) / 3:30 p.m. (Eastern) to discuss the first 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 1-877-211-7911 or 416-405-9310 (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 time May 6, 2005, by dialing 1-800-408-3053 or 416-695-5800 (Toronto area) and entering pass code 3147965. 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. The Company's common shares trade under the symbol TRP on the Toronto and New York stock exchanges.

First Quarter 2005 Financial Highlights
(unaudited)

Operating Results

		Three months ended March 31 (millions of dollars)
		2005		2004
Revenues			1,305		1,266
Net Income			232		214
Cash Flows
	Funds generated from operations		407		415
	Capital expenditures		108		101
		Three months ended March 31
		2005		2004
Common Share Statistics
Net Income Per Share — Basic		$	0.48	$	0.44
Dividends Declared Per Share		$	0.305	$	0.29
Common Shares Outstanding (millions)
	Average for the period		485.2		483.4
	End of period		485.6		483.9

-30-

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Exhibit 99.1

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Exhibit 99.2

TRANSCANADA CORPORATION
Annual Meeting of Holders of
Common Shares of
TransCanada Corporation (the "Issuer")

April 29, 2005

REPORT OF VOTING RESULTS
National Instrument 51-102 — Continuous Disclosure Obligations Section 11.3

Matters Voted Upon

General Business

			Outcome of Vote
1.	The election of the following nominees as directors of the Issuer for the ensuing year or until their successors are elected or appointed		Carried

	(a)	Douglas D. Baldwin
	(b)	Kevin E. Benson
	(c)	Wendy K. Dobson
	(d)	Paule Gauthier
	(e)	Kerry L. Hawkins
	(f)	S. Barry Jackson
	(g)	Paul L. Joskow
	(h)	Harold N. Kvisle
	(i)	David P. O'Brien
	(j)	Harry G. Schaefer
	(k)	W. Thomas Stephens

2.	The appointment of KPMG LLP, Chartered Accountants, as auditors of the Issuer to hold office until the next annual meeting		Carried

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Exhibit 99.2