Exhibit 13.1

Management’s Discussion and Analysis

Management’s discussion and analysis (MD&A) dated October 31, 2005 should be read in conjunction with the accompanying unaudited consolidated financial statements of TransCanada Corporation (TransCanada or the company) for the nine months ended September 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 September 30					Nine months ended September 30
(millions of dollars except per share amounts)	2005			2004		2005			2004
Gas Transmission Net Earnings
Excluding gains	148			134		475			422
Gain related to PipeLines LP	—			—		49			—
Gain related to Millennium	—			—		—			7
	148			134		524			429
Power Net Earnings
Excluding gains	99			51		171			178
Gains related to Power LP	193			—		193			187
	292			51		364			365
Corporate	(13		)	8		(29		)	1
Net Income
Continuing Operations (1)	427			193		859			795
Discontinued Operations	—			52		—			52
	427			245		859			847
Net Income Per Share
Continuing Operations (2)	$	0.88		$	0.40	$	1.77		$	1.64
Discontinued Operations	—			0.11		—			0.11
Basic	$	0.88		$	0.51	$	1.77		$	1.75
Diluted	$	0.87		$	0.50	$	1.76		$	1.74

(1)Net Income from Continuing Operations is comprised of:
Excluding gains	234		193		617		601
Gains related to PipeLines LP, Power LP and Millennium	193		—		242		194
	427		193		859		795
(2)Net Income Per Share from Continuing Operations is comprised of:
Excluding gains	$	0.48	$	0.40	$	1.27	$	1.24
Gains related to PipeLines LP, Power LP and Millennium	0.40		—		0.50		0.40
	$	0.88	$	0.40	$	1.77	$	1.64

TransCanada’s net income for third quarter 2005 was $427 million or $0.88 per share compared to $245 million or $0.51 per share for the same period in 2004.  Net income for third quarter 2004 included net income from discontinued operations of $52 million or $0.11 per share, reflecting income recognized on the initially deferred gains relating to the disposition of the company’s Gas Marketing business in 2001.

Net income from continuing operations (net earnings) for third quarter 2005 of $427 million or $0.88 per share increased by $234 million or $0.48 per share compared to $193 million or $0.40 per share for third quarter 2004. This increase was due to significantly higher net earnings from the Power business, primarily resulting from an after-tax gain of $193 million or $0.40 per share from the sale of the company’s interest in TransCanada Power, L.P. (Power LP) to EPCOR Utilities Inc. (EPCOR).

Excluding the $193 million gain related to the sale of Power LP, net earnings for third quarter 2005 increased $41 million or $0.08 per share compared to third quarter 2004, to $234 million or $0.48 per share.  This was due to increases of $48 million in net earnings from the Power business and $14 million in net earnings from the Gas Transmission business for third quarter 2005, partially offset by an increase of $21 million in net expenses in the Corporate segment.  The increase in Power’s net earnings was primarily due to higher equity income from Bruce Power L.P. (Bruce Power) and higher operating and other income from Eastern Operations as a result of contributions from TransCanada Hydro Northeast, Inc. (TC Hydro), which holds the assets acquired from USGen New England, Inc. (USGen) in April 2005.  These increases were partially offset by lower operating and other income from Western Operations.  The increase in net earnings from the Gas Transmission business was primarily due to $14 million generated from the Gas Transmission Northwest System and the North Baja System (collectively GTN), which were acquired by TransCanada on November 1, 2004.  Corporate’s net expenses increased in third quarter 2005 compared to third quarter 2004 due to a $12 million after-tax adjustment recorded in third quarter 2004 resulting from the release of previously established restructuring provisions as well as higher interest expense on higher average long-term debt and commercial paper balances in 2005.

TransCanada’s net income for the nine months ended September 30, 2005 was $859 million or $1.77 per share compared to $847 million or $1.75 per share for the comparable period in 2004.   Net income

2

for the nine months ended September 30, 2004 included net income from discontinued operations of $52 million or $0.11 per share.

TransCanada’s net earnings for the nine months ended September 30, 2005 were $859 million or $1.77 per share compared to $795 million or $1.64 per share for the comparable period in 2004.  Net earnings for the nine months ended September 30, 2005 included after-tax gains of $193 million related to the sale of the company’s interest in Power LP and $49 million related to the sale of TC PipeLines, LP (PipeLines LP) units, while net earnings for the nine months ended September 30, 2004 included after-tax gains of $187 million related to the sale of the ManChief and Curtis Palmer assets to 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 $242 million recorded in the nine months ended September 30, 2005 and total gains of $194 million recorded in the nine months ended September 30, 2004, net earnings for the nine months ended September 30, 2005 increased $16 million or $0.03 per share compared to the same period in 2004, to $617 million or $1.27 per share.  This was mainly due to an increase in net earnings from the Gas Transmission business partially offset by an increase in net expenses in the Corporate segment and a decrease in Power’s net earnings.

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 $53 million increase in net earnings from the Gas Transmission business for the nine months ended September 30, 2005 compared to the same period in 2004 was primarily attributable to $53 million of net earnings generated from GTN.  In addition, Gas Transmission’s net earnings for the nine months ended September 30, 2005 included approximately $30 million ($13 million related to 2004 and $17 million related to the nine months ended September 30, 2005) as a result of the April 2005 National Energy Board (NEB) decision on the Canadian Mainline’s 2004 Tolls and Tariff Application (Phase II).  This decision dealt with capital structure and included an increase in the deemed common equity ratio to 36 per cent from 33 per cent for 2004, which is also effective under the 2005 tolls settlement.  The increase in Canadian Mainline’s earnings for the nine months ended September 30, 2005 from this decision was partially offset by the combination of a lower average investment base and a decrease in the approved rate of return on common equity in 2005 compared to 2004.

3

The increase in net expenses of $30 million in the Corporate segment in the nine months ended September 30, 2005 compared to the same period in 2004 was due to increased interest expense on higher average long-term debt and commercial paper balances in 2005 as well as the release in third quarter 2004 of previously established restructuring provisions.

Excluding the above-mentioned $193 million gain related to the sale of Power LP in third quarter 2005 and $187 million of gains related to Power LP in the first nine months of 2004, Power’s net earnings for the nine months ended September 30, 2005 decreased $7 million as a result of lower contributions from Western and Eastern Operations partially offset by higher equity income from Bruce Power.

Funds generated from operations of $489 million and $1,375 million for the three and nine months ended September 30, 2005 increased $102 million and $191 million, respectively, when compared to the same periods in 2004.

4

Gas Transmission

The Gas Transmission business generated net earnings of $148 million and $524 million for the three and nine months ended September 30, 2005, respectively, compared to $134 million and $429 million for the same periods in 2004.

Gas Transmission Results-at-a-Glance
(unaudited)	Three months ended September 30				Nine months ended September 30
(millions of dollars)	2005		2004		2005		2004
Wholly-Owned Pipelines
Canadian Mainline	67		71		216		201
Alberta System	38		31		112		110
GTN (1)	14				53
Foothills System	5		6		16		17
BC System	2		2		5		5
	126		110		402		333
Other Gas Transmission
Great Lakes	11		12		36		43
Iroquois	7		3		14		14
PipeLines LP	2		4		7		13
Portland	1		—		7		6
Ventures LP	3		3		9		10
TQM	2		2		5		6
CrossAlta	5		4		12		6
TransGas	2		3		8		9
Northern Development	(1	)	(1	)	(3	)	(3	)
General, administrative, support costs and other	(10	)	(6	)	(22	)	(15	)
	22		24		73		89
Gain related to PipeLines LP	—		—		49		—
Gain related to Millennium	—		—		—		7
	22		24		122		96
Net Earnings	148		134		524		429

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

Wholly-Owned Pipelines

The Canadian Mainline’s third quarter 2005 net earnings decreased $4 million compared to third quarter 2004. The decrease in net earnings is due to a combination of a lower average investment base in 2005, a lower approved rate of return on common equity of 9.46 per cent in 2005 compared to 9.56 per cent in 2004 and lower earnings related to operating costs savings in 2005 compared to 2004, partially offset by an increase in the deemed common equity ratio.  The NEB’s decision on the Canadian Mainline’s 2004 Tolls

5

and Tariff Application (Phase II) in April 2005 included an increase in the deemed common equity ratio from 33 to 36 per cent for 2004 which is also effective for 2005 under the 2005 tolls settlement.  Net earnings for the nine months ended September 30, 2005 increased $15 million compared to the corresponding period in 2004.  As a result of the NEB decision that increased the deemed common equity to 36 per cent from 33 per cent, Canadian Mainline’s 2005 net earnings for the nine months ended September 30, 2005 increased $30 million ($13 million related to 2004 and $17 million related to the first nine months of 2005) compared to the same period in 2004. However, this earnings increase is partially offset by the combination of a lower average investment base in 2005 and 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. 

The Alberta System’s net earnings of $38 million in third quarter 2005 increased $7 million compared to $31 million in the same quarter of 2004.  Net earnings for the nine months ended September 30, 2005 increased $2 million compared to the same period in 2004.  The increases were primarily due to lower earnings in 2004 as a result of the 2004 General Rate Application (GRA) decision in August 2004 which disallowed certain costs. These increases were partially offset by a lower investment base and a lower approved rate of return on common equity in 2005.  During 2005, the Alberta System is operating under a negotiated settlement with its shippers.  Net earnings reflect a rate of return, as prescribed by the Alberta Energy and Utilities Board (EUB), of 9.50 per cent in 2005 compared to a rate of return of 9.60 per cent in 2004 on deemed common equity of 35 per cent.

GTN, which was acquired by TransCanada in November 2004, generated net earnings of $14 million in third quarter 2005 and $53 million in the nine months ended September 30, 2005. 

6

Operating Statistics

					Gas
					Transmission
	Canadian				Northwest
Nine months ended September 30	Mainline (1)		Alberta System (2)		System (3)		Foothills System		BC System
(unaudited)	2005	2004	2005	2004	2005		2005	2004	2005	2004
Average investment base ($ millions)	7,839	8,233	4,478	4,642	n/a	(3)	683	718	218	229
Delivery volumes (Bcf)
Total	2,181	1,947	2,918	2,872	581		788	844	236	255
Average per day	8.0	7.1	10.7	10.5	2.1		2.9	3.1	0.9	0.9

(1)Canadian Mainline deliveries originating at the Alberta border and in Saskatchewan for the nine months ended September 30, 2005 were 1,605 Bcf (2004 - 1,503 Bcf); average per day was 5.9 Bcf (2004 - 5.5 Bcf).

(2)Field receipt volumes for the Alberta System for the nine months ended September 30, 2005 were 3,010 Bcf (2004 - 2,959 Bcf); average per day was 11.0 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 earnings from its Other Gas Transmission businesses was $22 million for the three months ended September 30, 2005 compared to $24 million for the same period in 2004.  The $2 million decrease compared to the prior period was mainly due to higher general, administrative, support costs and other, lower earnings from PipeLines LP due to the reduced ownership interest and the negative impact of a weaker U.S. dollar.  Partially offsetting these decreases was the impact of Iroquois customer bankruptcy settlements recognized in third quarter 2005.

Net earnings for the nine months ended September 30, 2005 were $122 million compared to $96 million for the corresponding period in 2004.  Excluding the $49 million gain on sale of PipeLines LP units recorded in 2005, and the $7 million gain on sale of Millennium recorded in 2004, net earnings for the nine months ended September 30, 2005 were $16 million lower compared to the same period in 2004.  The decrease was due to the impact of a weaker U.S. dollar in 2005, higher general, administrative, support costs and other, lower earnings from PipeLines LP, and lower earnings from Great Lakes as a result of lower short-term revenues and higher operating and maintenance costs.  These decreases were partially offset by higher earnings from CrossAlta as a result of more favourable natural gas storage market conditions in 2005.  In addition, the impact of the Iroquois customer bankruptcy settlements recognized in third quarter 2005 was offset by a positive tax adjustment recorded in first quarter 2004.

7

As at September 30, 2005, TransCanada had capitalized $13 million of costs related to its Broadwater liquified natural gas (LNG) project.

Power

Power Results-at-a-Glance
(unaudited)	Three months ended September 30				Nine months ended September 30
(millions of dollars)	2005		2004		2005		2004
Bruce Power investment	99		29		142		125
Western operations	32		43		90		113
Eastern operations	25		21		69		77
Power LP investment	12		6		29		22
General, administrative, support costs and other	(23	)	(21	)	(74	)	(70	)
Operating and other income	145		78		256		267
Financial charges	—		(4	)	(7	)	(9	)
Income taxes	(46	)	(23	)	(78	)	(80	)
	99		51		171		178
Gains related to Power LP	193		—		193		187
Net Earnings	292		51		364		365

Power’s net earnings in third quarter 2005 of $292 million increased $241 million compared to third quarter 2004.  Gains related to the sale of Power LP accounted for $193 million of this increase.  Excluding these gains, Power’s net earnings in third quarter 2005 of $99 million increased $48 million compared to the same period in 2004, primarily due to $46 million of higher after-tax equity earnings from Bruce Power.  In addition, higher operating and other income from Eastern Operations and Power LP was offset by a decreased contribution from Western Operations.

Bruce Power’s pre-tax equity income increased by $70 million to $99 million in third quarter 2005 compared to third quarter 2004 primarily due to higher realized power prices on uncontracted volumes sold into Ontario’s wholesale spot market.  Realized prices in third quarter 2005 were $70 per megawatt hour (MWh) or $25 per MWh higher than the same period in 2004.  Generation volumes of 9.1 terawatt hours (TWh) and a capacity factor of 88 per cent were higher compared to 8.7 TWh and a capacity factor of 85 per cent in third quarter 2004.

Eastern Operations’ operating and other income was $4 million higher in third quarter 2005 compared to third quarter 2004 primarily due to contributions from TC Hydro, which represents the hydroelectric generation assets acquired from USGen on April 1, 2005, and from the Grandview cogeneration facility placed in-service in January 2005.  Partially offsetting these increases was a loss of margin primarily associated with the expiration of long-term

8

sales contracts held at the end of 2004 which did not carry over into 2005.

Power LP’s operating and other income was $6 million higher in third quarter 2005 compared to the same period in 2004 due to the combined impact of accounting for the Power LP investment as an asset held for sale and improved operating results at its Ontario facilities, partially offset by the impact of TransCanada’s sale of this investment on August 31, 2005.

Western Operations’ operating and other income was $11 million lower in third quarter 2005 compared to third quarter 2004 primarily due to recognition in third quarter 2004 of income from the MacKay River plant which was previously deferred for the first six months of 2004.  Operating and other income was also lower due to fee revenues earned in third quarter 2004 from Power LP’s acquisition of facilities and reduced margins in third quarter 2005 from lower market heat rates on uncontracted volumes of power generated.  Partially offsetting these decreases were higher contributions from the Sundance A&B power purchase arrangements (PPAs) primarily due to higher plant availability. 

Net earnings for the nine months ended September 30, 2005 of $364 million approximated net earnings in the same period in 2004.  Excluding the Power LP-related gains of $193 million and $187 million in 2005 and 2004, respectively, Power’s net earnings for the nine months ended September 30, 2005 of $171 million decreased $7 million compared to $178 million in 2004.  Higher equity income from Bruce Power was more than offset by reduced contributions from Western and Eastern Operations.

9

Bruce Power Investment

Bruce Power Results-at-a-Glance
(unaudited)	Three months ended September 30				Nine months ended September 30
(millions of dollars)	2005		2004		2005		2004
Bruce Power (100 per cent basis)
Revenues	642		395		1,453		1,228
Operating expenses
Cash costs (materials, labour, services and fuel)	(269	)	(254	)	(821	)	(716	)
Non-cash costs (depreciation and amortization)	(48	)	(43	)	(145	)	(117	)
	(317	)	(297	)	(966	)	(833	)
Operating income	325		98		487		395
Financial charges	(18	)	(17	)	(52	)	(50	)
Income before income taxes	307		81		435		345
TransCanada’s interest in Bruce Power income before income taxes	97		26		137		109
Adjustments	2		3		5		16
TransCanada’s income from Bruce Power before income taxes	99		29		142		125

TransCanada’s share of Bruce Power’s income before income taxes (equity income) was $70 million higher in third quarter 2005 compared to third quarter 2004 primarily due to higher realized power prices in third quarter 2005 which averaged $70 per MWh compared to $45 per MWh in third quarter 2004.  Slightly higher generation volumes in third quarter 2005 also contributed to the higher income.

TransCanada’s share of power output from Bruce Power for third quarter 2005 increased to 2,882 gigawatt hours (GWh) compared to 2,765 GWh in third quarter 2004.  This increase primarily reflected fewer planned and forced maintenance outages compared to third quarter 2004.

Approximately 32 reactor days of planned maintenance outages as well as 23 reactor days of unplanned outages occurred in third quarter 2005.  In third quarter 2004, Bruce Power experienced 55 reactor days of planned maintenance outages and 13 reactor days of unplanned outages.  The Bruce units ran at an average availability of 88per cent in third quarter 2005, compared to an 85 per cent average availability during third quarter 2004.  Unit 7 returned to service mid-August 2005 following a planned maintenance inspection that began on May 7, 2005.  The unit was offline for 98 days including a 12 day unplanned extension to the outage.  During third quarter 2005, Unit 3 was taken offline for 11 days to make repairs to the reactor regulating system. Unit 5 was taken offline on October 8, 2005 to begin its planned maintenance inspection, which is expected to last approximately two months. 

Overall prices achieved during third quarter 2005 were $70 per MWh, compared to $45 per MWh in third quarter 2004.  Approximately 60 per cent of the available output was sold into Ontario’s

10

wholesale spot market during third quarter 2005 with the remainder being sold under longer term contracts.  Bruce Power’s operating expenses increased slightly to $35 per MWh in third quarter 2005 from $34 per MWh in third quarter 2004.  Adjustments to TransCanada’s interest in Bruce Power’s equity income for the three and nine months ended September 30, 2005 were lower than in 2004 primarily due to a lower amortization of the purchase price allocated to the fair value of sales contracts in place at the time of acquisition. The adjustment for the nine months ended September 30, 2005 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 nine months ended September 30, 2005 was $142 million compared to $125 million for the same period in 2004.  Prices realized for the nine months ended September 30, 2005 were $58 per MWh compared to $46 per MWh for the same period in 2004. Approximately 53 per cent of the available output was sold into Ontario’s wholesale spot market during the first nine months of 2005 with the remainder being sold under longer term contracts.  Bruce Power’s operating expenses increased to $39 per MWh for the nine months ended September 30, 2005 from $32 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 to sell forward 3.2 TWh of output for the balance of 2005 and approximately 13 TWh of 2006 output from the Bruce B units has also been sold under fixed-price sales contracts.  Overall plant availability for the six Bruce units in 2005 is expected to be 83 per cent.

Bruce Power made a total of $165 million in cash distributions to its partners in third quarter 2005.  TransCanada’s share was $52 million. For the nine months ended September 30, 2005, the total distributions to partners were $215 million, of which TransCanada’s share was $68 million.  No distributions were made to partners in 2004.  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.

On October 17, 2005, TransCanada announced that Bruce Power and the Ontario Power Authority (OPA), entered into a long-term agreement whereby Bruce Power will refurbish and restart the currently idle Units 1 and 2, extend the operating life of Unit 3

11

by replacing its steam generators and fuel channels when required and replace the steam generators on Unit 4.  Bruce Power’s capital program for the restart and refurbishment work is expected to total approximately $4.25 billion and TransCanada’s approximate $2.125 billion share will be financed through capital contributions over the period from 2005 to 2011.  A capital cost risk and reward sharing schedule with OPA is in place for spending below or in excess of the $4.25 billion base case estimate of Bruce A restart and refurbishment.  As a result of the agreement between Bruce Power and the OPA, and Cameco Corporation’s decision not to participate in the restart and refurbishment program, a new partnership has been created. The new Bruce Power A Limited Partnership (BALP) will sublease the Bruce A facilities, which are comprised of Units 1 to 4, from Bruce Power. The effect of these transactions is that TransCanada and BPC Generation Infrastructure Trust each incurred a net cash outlay of approximately $100 million and each owns a 47.4 per cent interest in BALP.  The remaining 5.2 per cent is owned by the Power Worker’s Union and The Society of Energy Professionals.  The day-to-day operations of the Bruce facility will be unaffected by the formation of BALP and TransCanada continues to own 31.6 per cent of the Bruce B facilities (Units 5 to 8).  The agreement and above transactions were completed October 31, 2005 with the receipt of a favourable tax ruling from the Canada Revenue Agency. 

Work to restart Units 1 and 2 will begin immediately with the first unit expected to be online in 2009, subject to approval by the Canadian Nuclear Safety Commission.  Restarting Units 1 and 2 which have a capacity of approximately 1,500 megawatts (MW) will boost the Bruce facilities’ overall output to more than 6,200 MW.

As a result of the contract with the OPA, all of the output from Bruce A, effective upon closing, will be sold at a fixed price of $57.37 per MWh, adjusted annually for inflation, before a recovery of fuel costs which will be flowed through to the OPA.  As part of the contract, sales from the Bruce B Units 5 to 8 are subject to a floor price of $45 per MWh, adjusted annually for inflation.  Any receipts by Bruce Power under this floor price mechanism are refunded if prices subsequently increase above the $45 per MWh floor price.

As a result of reorganizing Bruce Power, TransCanada expects to proportionately consolidate its investment in both Bruce Power and BALP on a prospective basis from closing.

12

Western Operations

Western Operations Results-at-a-Glance (1)
(unaudited)	Three months ended September 30				Nine months ended September 30
(millions of dollars)	2005		2004		2005		2004
Revenue
Power	165		132		480		446
Other (2)	29		24		108		87
	194		156		588		533
Cost of sales
Power	(105	)	(71	)	(313	)	(274	)
Other (2)	(17	)	(9	)	(67	)	(47	)
	(122	)	(80	)	(380	)	(321	)
Other costs and expenses	(34	)	(28	)	(102	)	(82	)
Depreciation	(6	)	(5	)	(16	)	(17	)
Operating and other income	32		43		90		113

(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.

13

Western Operations Sales Volumes (1)
(unaudited)	Three months ended September 30		Nine months ended September 30
(GWh)	2005	2004	2005	2004
Supply
Generation	544	680	1,691	1,432
Purchased
Sundance A & B PPAs	1,593	1,388	5,137	5,084
Other purchases (2)	658	686	2,003	2,043
	2,795	2,754	8,831	8,559
Contracted vs. Spot
Contracted	2,423	2,503	7,570	7,858
Spot	372	251	1,261	701
	2,795	2,754	8,831	8,559

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

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

Western Operations’ operating and other income of $32 million in third quarter 2005 was $11 million lower compared to the same period in 2004.  This decrease was mainly due to recognition in third quarter 2004 of income from the MacKay River facility which was previously deferred for the first six months of 2004.  Operating and other income was also lower due to fee revenues earned in third quarter 2004 from Power LP and reduced margins in third quarter 2005 from lower market heat rates on uncontracted volumes of power generated.  Market heat rates decreased by approximately 20 per cent in the quarter as a result of an approximate 50 per cent ($3 per gigajoule) increase in spot market natural gas prices in Alberta in third quarter 2005 compared to the same period in 2004, while average spot market power prices increased by approximately 23 per cent ($12 per MWh). Partially offsetting these decreases were higher contributions from the Sundance A&B PPAs primarily due to higher plant availability.  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.

Operating and other income for the nine months ended September 30, 2005 was $90 million or $23 million lower compared to $113 million earned in the same period in 2004.  This decrease was primarily due to reduced margins from lower market heat rates on uncontracted volumes of power generated and fee revenues earned in 2004 from Power LP.

14

Western Operations’ power sales revenues, power cost of sales and associated purchased volumes increased in third quarter 2005 compared to third quarter 2004 primarily due to higher plant availability at Sundance A & B as a result of lower maintenance outages.  Power sales revenues also increased as a result of higher realized prices in third quarter 2005.  Other costs and expenses of $34 million, which includes fuel gas consumed in generation, were higher in third quarter 2005 primarily due to higher fuel costs at the MacKay River facility resulting from higher natural gas prices and higher generation output.  Generation volumes of 544 GWh in third quarter 2005 decreased 136 GWh compared to third quarter 2004 primarily due to planned maintenance outages in 2005 at Carseland and an unplanned outage at Bear Creek.   Partially offsetting these decreases were higher generation volumes from MacKay River resulting from outages in third quarter 2004.  Bear Creek has experienced certain operational difficulties in 2005 and, as a result, has not been fully available throughout much of the first nine months of 2005.  Power earnings in 2005 have not been significantly impacted by the operational difficulties at Bear Creek.  Technical evaluation continues and possible long-term solutions are being studied.  In third 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 September 30, 2005, Western Operations had fixed price sales contracts to sell forward approximately 2,800 GWh for the remainder of 2005 and approximately 8,000 GWh for 2006.

15

Eastern Operations

Eastern Operations Results-at-a-Glance (1)
(unaudited)	Three months ended September 30				Nine months ended September 30
(millions of dollars)	2005		2004		2005		2004
Revenue
Power	136		139		380		415
Other (2)	111		51		254		168
	247		190		634		583
Cost of sales
Power	(70	)	(83	)	(183	)	(228	)
Other (2)	(98	)	(52	)	(237	)	(157	)
	(168	)	(135	)	(420	)	(385	)
Other costs and expenses	(46	)	(30	)	(127	)	(105	)
Depreciation	(8	)	(4	)	(18	)	(16	)
Operating and other income	25		21		69		77

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

(2)Other includes natural gas.

Eastern Operations Sales Volumes (1)
(unaudited)	Three months ended September 30		Nine months ended September 30
(GWh)	2005	2004	2005	2004
Supply
Generation	600	302	2,006	1,102
Purchased	833	1,329	2,138	3,614
	1,433	1,631	4,144	4,716
Contracted vs. Spot
Contracted	1,348	1,581	3,765	4,581
Spot	85	50	379	135
	1,433	1,631	4,144	4,716

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

Operating and other income in third quarter 2005 from Eastern Operations of $25 million was $4 million higher compared to $21 million earned in third quarter 2004. The increase was primarily due to income from the April 1, 2005 acquisition of the TC Hydro hydroelectric generation assets and from the Grandview cogeneration facility placed in-service in January 2005.  Partially offsetting these increases was a loss of margin primarily associated with the expiration of long-term sales contracts held at the end of 2004 which did not carry over into 2005.

Operating and other income for the nine months ended September 30, 2005 was $69 million or $8 million lower than the $77 million earned in 2004. Incremental income from the acquisition of the TC 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,

16

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 and a loss of margin primarily associated with the expiration of long-term sales contracts.  The contract restructuring at OSP reduced the term of the long-term natural gas supply contracts 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 natural gas for OSP.

Generation volumes in third quarter 2005 increased 298 GWh to 600 GWh compared to 302 GWh in 2004 primarily due to the acquisition of the TC Hydro assets and the placing into service of the Grandview cogeneration facility.  Partially offsetting these increases was reduced generation from the OSP facility.  In third quarter 2005, OSP Phase I returned to service after a six month unplanned maintenance outage and OSP Phase II commenced a planned maintenance outage expected to continue into first quarter 2006.

Eastern Operations’ power sales revenues of $136 million decreased $3 million in third quarter 2005 due to lower contracted sales volumes partially offset by higher realized prices.  Sales volumes of 1,433 GWh for third quarter 2005 were lower than the same period in 2004 due primarily to the expiration of long-term sales contracts held at the end of 2004 which did not carry over into 2005.  Power’s cost of sales of $70 million was lower in third quarter 2005 due to the impact of lower purchased power volumes partially offset by higher prices for purchased power.  Purchased power volumes of 833 GWh were lower in third quarter 2005 due to lower contracted sales volumes and the impact of power generation from the purchase of the TC Hydro assets.  Volumes generated from the TC 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 natural gas purchased and resold from the new natural gas supply contracts at OSP.  Other costs and expenses of $46 million, which include fuel gas consumed in generation, increased $16 million primarily due to higher fuel costs at the OSP facility and operating costs of the TC Hydro assets acquired in 2005.

o

In third quarter 2005, approximately six per cent of power sales volumes were sold into the spot market compared to approximately three per cent in third quarter 2004 reflecting the sale of a portion of the generation from the TC Hydro assets into the spot market.  Eastern Operations is focused on selling the majority of its power under contract to wholesale, commercial and industrial customers while managing a portfolio of power supplies sourced from its own generation and wholesale power purchases.  To reduce its exposure to spot market prices, as at September 30, 2005, Eastern Operations had entered into fixed price sales contracts to sell forward approximately 1,400 GWh of power for the remainder of

17

2005 and approximately 3,300 GWh of power for 2006.  Certain contracted volumes are dependent on customer usage levels.

Power LP Investment

Power LP’s operating and other income was $6 million higher in third quarter 2005 compared to the same period in 2004 primarily due to the combined impact of accounting for the Power LP investment as an asset held for sale and improved operating results at its Ontario facilities. Operating and other income for the nine months ended September 30, 2005 was $7 million higher compared to the same period 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, improved operating results and the impact of accounting for the Power LP investment as an asset held for sale.  Partially offsetting these increases was the impact of TransCanada’s sale of this investment on August 31, 2005, a reduced ownership interest in Power LP in 2005, 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.

General, Administrative, Support Costs and Other

General, administrative, support costs and other of $23 million in third quarter 2005 were $2 million higher than in third quarter 2004.  These costs were $74 million for the nine months ended September 30, 2005 or $4 million higher compared to the same period in 2004.

18

Power Sales Volumes and Plant Availability

Power Sales Volumes
(unaudited)	Three months ended September 30		Nine months ended September 30
(GWh)	2005	2004	2005	2004
Bruce Power investment (1)	2,882	2,765	7,786	8,257
Western operations (2)	2,795	2,754	8,831	8,559
Eastern operations (2)	1,433	1,631	4,144	4,716
Power LP investment (2) (3)	445	642	1,865	1,750
Total	7,555	7,792	22,626	23,282

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

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

(3)TransCanada operated and managed Power LP until August 31, 2005. The volumes in the table represent 100 percent of Power LP’s sales volumes up to August 31, 2005.

Weighted Average Plant Availability (1)	Three months ended September 30				Nine months ended September 30
(unaudited)	2005		2004		2005		2004
Bruce Power investment (2)	88	%	85	%	80	%	85	%
Western operations (3)	89	%	94	%	86	%	96	%
Eastern operations (3) (4)	84	%	98	%	81	%	97	%
Power LP investment (3) (5)	96	%	97	%	93	%	97	%
All plants, excluding Bruce Power investment	88	%	97	%	85	%	96	%
All plants	89	%	92	%	81	%	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)Unit 3 is included effective March 1, 2004.

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

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

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

Corporate

Net expenses for the three and nine months ended September 30, 2005 were $13 million and $29 million, respectively, compared to net income of $8 million and $1 million for the corresponding periods in 2004. 

The $21 million increase in Corporate's net expenses for third quarter 2005 compared to the same period in 2004 was primarily due to a $12 million after-tax adjustment in third quarter 2004 as a result of the release of previously established restructuring provisions and higher interest expense on higher average long-term debt and commercial paper balances in 2005.

The $30 million increase in Corporate's net expenses for the nine months ended September 30, 2005 compared to the same period in 2004 was primarily due to increased interest expense on higher average long-term debt and commercial paper balances in 2005 as well as the release in third quarter 2004 of previously established restructuring provisions.

19

Income tax refunds and related interest in the nine months ended September 30, 2004 were comparable to income tax refunds and positive tax adjustments recorded in the nine months ended September 30, 2005.

Liquidity and Capital Resources

Funds Generated from Operations

Funds generated from operations were $489 million and $1,375 million for the three and nine months ended September 30, 2005, respectively, compared with $387 million and $1,184 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 nine months ended September 30, 2005, capital expenditures, excluding acquisitions, totalled $166 million (2004 - $97 million) and $409 million (2004 - $291 million), respectively, and related primarily to construction of new power plants as well as maintenance and capacity capital in the Gas Transmission business.  

In the three and nine months ended September 30, 2005, disposition of assets generated $523 million (2004 - nil) and $676 million (2004 - $408 million), respectively.  The dispositions in 2005 relate to the sale of TransCanada’s ownership interest in Power LP and PipeLines LP units while the dispositions in 2004 relate primarily to the sale of ManChief and Curtis Palmer to Power LP.

Acquisitions for the nine months ended September 30, 2005 were $632 million (2004 - $63 million), and relate to the acquisition of the TC Hydro assets and the purchase of an additional 3.52 per cent ownership interest in Iroquois Gas Transmission System L.P. 

Financing Activities

TransCanada retired $5 million and $941 million of long-term debt in the three and nine months ended September 30, 2005, respectively.  TransCanada issued $799 million of long-term debt in the nine months ended September 30, 2005.  On June 1, 2005, Gas Transmission Northwest Corporation (GTNC) redeemed all of its outstanding US$150 million 7.80 per cent Senior Unsecured Debentures and US$250 million 7.10 per cent Senior Unsecured Notes.  On the same date, GTNC completed a US$400 multi-tranche

20

private placement of senior debt with a weighted average interest rate of 5.28 per cent and weighted average life of approximately 18 years.  For the nine months ended September 30, 2005, outstanding notes payable decreased by $163 million, while cash and short-term investments increased by $53 million. 

Dividends

On October 31, 2005, TransCanada’s Board of Directors declared a quarterly dividend of $0.305 per share for the quarter ending December 31, 2005 on the outstanding common shares.  This is the 168^th consecutive quarterly dividend paid by TransCanada and its subsidiary on the common shares.  It is payable on January 31, 2006 to shareholders of record at the close of business on December 30, 2005.

Contractual Obligations

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

Purchase Obligations
(unaudited - millions of dollars)	2005 (1)	2006	2007	2008	2009	2010+
Power
Commodity purchases (2)	289	797	706	596	273	2,648
Capital expenditures (3)	82	185	70	3	1	—
Other (4)	22	60	49	32	29	114
	393	1,042	825	631	303	2,762

(1)Includes purchase obligations for the three 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 September 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.

21

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 September 30, 2005  and December 31, 2004.

Power

		September 30, 2005
		(unaudited)		December 31, 2004
Asset/(Liability)	Accounting	Fair		Fair
(millions of dollars)	Treatment	Value		Value
Power - swaps
(maturing 2005 to 2011)	Hedge	(123	)	7
(maturing 2005 to 2010)	Non-hedge	19		(2	)
Gas - swaps, futures and options
(maturing 2005 to 2016)	Hedge	(13	)	(39	)
(maturing 2005 to 2008)	Non-hedge	(16	)	(2	)
Heat rate contracts
(maturing 2005 to 2006)	Hedge	—		(1	)

22

Notional Volumes
September 30, 2005	Accounting	Power (GWh)		Gas (Bcf)
(unaudited)	Treatment	Purchases	Sales	Purchases	Sales
Power - swaps
(maturing 2005 to 2011)	Hedge	911	6,366	—	—
(maturing 2005 to 2010)	Non-hedge	1,206	220	—	—
Gas - swaps, futures and options
(maturing 2005 to 2016)	Hedge	—	—	80	71
(maturing 2005 to 2008)	Non-hedge	—	—	26	21
Heat rate contracts
(maturing 2005 to 2006)	Hedge	—	44	—	—
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 September 30, 2005, 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.

23

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 third 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.

24

(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

Outlook

In 2005, the company expects higher net income from the Gas Transmission segment than originally anticipated primarily as a result of the $49 million after-tax gain related to the sale of PipeLines LP units.  The company also expects higher Power net income in 2005 than originally anticipated primarily as a result of the $193 million after-tax gain on sale of Power LP and the approximately $115 million after-tax gain on sale of the company’s investment in PT Paiton Energy Company (Paiton Energy), expected in fourth quarter 2005.  For further information on Paiton Energy, please refer to Other Recent Developments.  In addition, primarily as a result of higher realized power prices in 2005 compared to 2004, TransCanada expects higher earnings from Bruce Power than originally anticipated. 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 remain at A, A2 and A-, respectively.  DBRS and Moody’s both maintain a ‘stable’ outlook on their ratings and Standard & Poor’s maintains a ‘negative’ outlook on its rating.

25

Other Recent Developments

Gas Transmission

Wholly-Owned Pipelines

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 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 commenced a hearing for Phase II on October 4, 2005.  The two week oral hearing on Phase II concluded October 19 with written argument and reply due November 10 and November 24, respectively.

Other Gas Transmission

Cacouna

In September 2005, the village of Cacouna, Québec, voted 57.2 per cent in favour of an LNG terminal to be built in the area.  The Cacouna Energy joint venture between Petro-Canada and TransCanada was originally announced in September 2004 and proposes a $660 million project at Gros Cacouna harbour on the St. Lawrence River, capable of receiving, storing and regasifying imported LNG with an average send-out capacity of approximately 500 million cubic feet per day of natural gas.  TransCanada will operate the facility, while Petro-Canada will contract for all of the capacity and supply the LNG.

Regulatory applications have been made with the federal, provincial and municipal governments and the relevant decisions are anticipated in late 2006.  Should approvals be received, construction will commence soon thereafter with a terminal in-service date expected by late 2009.

Power

TransCanada Hydro Northeast, Inc.

On April 1, 2005, TransCanada closed its acquisition of hydroelectric generation assets, with total generating capacity of

26

567 MW, from USGen for US$505 million, subject to closing adjustments. 

The 49 MW Bellows Falls facility was one of the hydro facilities purchased by TransCanada and was the subject of a purchase option in favour of the Town of Rockingham (the Town). This agreement provided the Town with an option to purchase the facility for US$72 million. The option was exercised in December 2004 and the Town assigned the option agreement to the Vermont Hydroelectric Power Authority for the purposes of financing the Town’s acquisition of the Bellows Falls facility.  The closing under the option agreement contained many conditions precedent, in particular that the relevant government approvals be obtained, including the approval of the Vermont Public Service Board and the United States Federal Energy Regulatory Commission.  As these conditions precedent were not satisfied before the deadline outlined in the option agreement, the option agreement was terminated in September 2005.  As a result, TransCanada continues to own and operate the 49 MW Bellows Falls hydroelectric facility.

Power LP

On August 31, 2005,  TransCanada closed the sale of its interest in Power LP to EPCOR for net proceeds of $523 million. In third quarter 2005, TransCanada realized an after-tax gain of $193 million from this sale. The net gain was recorded in the Power segment and the company recorded a $52 million tax charge, including $79 million of current income tax expense, on this transaction. EPCOR’s acquisition includes 14.5 million limited partnership 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 the management and operations agreements governing the ongoing operation of Power LP’s generation assets.  Following the close of the transaction, the name of the partnership changed from TransCanada Power, L.P. to EPCOR Power L.P. (the Partnership).

Effective upon the closing of the sale, TransCanada was no longer the general partner of the Partnership and TransCanada and its affiliates ceased to own Partnership units.  In addition, approximately 100 TransCanada employees, who provided management, operations and maintenance services under the contract to the Partnership, became EPCOR employees. 

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, subject to adjustments.  TransCanada

27

originally purchased its interest in Paiton Energy in 1996.  Paiton Energy owns two 615 MW coal-fired plants in East Java, Indonesia.  Pending various approvals, this transaction is expected to close in fourth quarter 2005.  Upon closing, TransCanada expects to realize an after-tax gain on sale of approximately $115 million.

Share Information

As at September 30, 2005, TransCanada had 486,974,317 issued and outstanding common shares.  In addition, there were 8,959,799 outstanding options to purchase common shares, of which 6,546,223 were exercisable as at September 30, 2005.

28

Selected Quarterly Consolidated Financial Data (1)

(unaudited)	2005						2004								2003
(millions of dollars except per share amounts)	Third		Second		First		Fourth		Third		Second		First		Fourth
Revenues	1,491		1,444		1,407		1,478		1,307		1,344		1,356		1,375
Net Income
Continuing operations	427		200		232		185		193		388		214		193
Discontinued operations	—		—		—		—		52		—		—		—
	427		200		232		185		245		388		214		193
Share Statistics
Net income per share - Basic
Continuing operations	$	0.88	$	0.41	$	0.48	$	0.38	$	0.40	$	0.80	$	0.44	$	0.40
Discontinued operations	—		—		—		—		0.11		—		—		—
	$	0.88	$	0.41	$	0.48	$	0.38	$	0.51	$	0.80	$	0.44	$	0.40
Net income per share - Diluted
Continuing operations	$	0.87	$	0.41	$	0.48	$	0.38	$	0.39	$	0.80	$	0.44	$	0.40
Discontinued operations	—		—		—		—		0.11		—		—		—
	$	0.87	$	0.41	$	0.48	$	0.38	$	0.50	$	0.80	$	0.44	$	0.40
Dividend declared per common share	$	0.305	$	0.305	$	0.305	$	0.29	$	0.29	$	0.29	$	0.29	$	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 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.

•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

29

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 hydroelectric generation 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.

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

Forward-Looking Information

Certain information in this quarterly report is forward-looking and is subject to important risks and uncertainties.  The results

30

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.

31