Exhibit 13.1

Third Quarter 2006 Financial Highlights
(unaudited)

Operating Results	Three months ended September 30			Nine months ended September 30
(millions of dollars)	2006		2005	2006		2005

Revenues	1,850		1,494	5,429		4,353

Net Income
Continuing operations	293		427	782		859
Discontinued operations	—		—	28		—
	293		427	810		859

Cash Flows
Funds generated from operations (1)	662		503	1,718		1,421
(Increase)/decrease in operating working capital	(43	)	90	(136	)	(173	)
Net cash provided by operations	619		593	1,582		1,248

Capital expenditures	372		166	1,002		409
Acquisitions, net of cash acquired	—		—	358		632

	Three months ended September 30				Nine months ended September 30
Common Share Statistics	2006		2005		2006		2005

Net Income Per Share – Basic
Continuing operations	$	0.60	$	0.88	$	1.60	$	1.77
Discontinued operations	—		—		0.06		—
	$	0.60	$	0.88	$	1.66	$	1.77

Dividends Declared Per Share	$	0.32	$	0.305	$	0.96	$	0.915

Common Shares Outstanding (millions)
Average for the period	487.9		486.7		487.7		485.9
End of period	488.4		487.0		488.4		487.0

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

Management’s Discussion and Analysis

Management’s discussion and analysis (MD&A) dated October 30, 2006 should be read in conjunction with the accompanying unaudited consolidated financial statements of TransCanada Corporation (TransCanada or the company) for the three and nine months ended September 30, 2006. It should also be read in conjunction with the audited consolidated financial statements and the MD&A contained in TransCanada’s 2005 Annual Report for the year ended December 31, 2005. Additional information relating to TransCanada, including the company’s Annual Information Form and continuous disclosure documents, is available on SEDAR at www.sedar.com under TransCanada Corporation. Amounts are stated in Canadian dollars unless otherwise indicated. Capitalized and abbreviated terms that are used but not otherwise defined herein have the meanings provided in the annual MD&A contained in TransCanada’s 2005 Annual Report.

Forward-Looking Information

Certain information in this MD&A includes forward-looking statements. All forward-looking statements are based on TransCanada’s beliefs and assumptions based on information available at the time the assumptions were made. Forward-looking statements relate to, among other things, anticipated financial performance, business prospects, strategies, regulatory developments, new services, market forces, commitments and technological developments. By its nature, such forward-looking information is subject to various risks and uncertainties, including those material risks discussed in the MD&A contained in TransCanada’s 2005 Annual Report under “Gas Transmission – Business Risks” and “Power – Business Risks”, which could cause TransCanada’s actual results and experience to differ materially from the anticipated results or other expectations expressed. The material assumptions in making these forward-looking statements are disclosed in this MD&A under the heading “Outlook” and in the MD&A contained in the company’s 2005 Annual Report under the headings “TransCanada Overview”, “TransCanada’s Strategy”, “Gas Transmission – Opportunities and Developments”, “Gas Transmission – Outlook”, “Power – Opportunities and Developments” and “Power – Outlook”. Readers are cautioned not to place undue reliance on this forward-looking information, which is given as of the date it is expressed in this MD&A or as otherwise stated. TransCanada undertakes no obligation to update publicly or revise any forward-looking information, whether as a result of new information, future events or otherwise, except as required by law.

Non-GAAP Measures

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

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

Results of Operations

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

Consolidated

Segment Results-at-a-Glance

(unaudited)

	Three months ended September 30					Nine months ended September 30
(millions of dollars except per share amounts)	2006		2005			2006		2005
Pipelines
Excluding gains	130		149			421		475
Gain on sale of Northern Border Partners, L.P. interest	—		—			13		—
Gain on sale of PipeLines LP units	—		—			—		49
	130		149			434		524
Energy
Excluding gains	123		98			320		171
Gains related to Power LP	—		193			—		193
	123		291			320		364
Corporate	40		(13		)	28		(29		)
Net Income
Continuing operations (1)	293		427			782		859
Discontinued operations	—		—			28		—
	293		427			810		859

Net Income Per Share
Continuing operations (2)	$	0.60	$	0.88		$	1.60	$	1.77
Discontinued operations	—		—			0.06		—
Basic	$	0.60	$	0.88		$	1.66	$	1.77
Diluted	$	0.60	$	0.87		$	1.65	$	1.76

(1)Net Income from Continuing Operations is comprised of:
Excluding gains	293		234			769		617
Gains related to Northern Border Partners, L.P. interest, PipeLines LP units and Power LP	—		193			13		242
	293		427			782		859
(2)Net Income Per Share from Continuing
Operations is comprised of:
Excluding gains	$	0.60	$	0.48		$	1.57	$	1.27
Gains related to Northern Border Partners, L.P. interest, PipeLines LP units and Power LP	—		0.40			0.03		0.50
	$	0.60	$	0.88		$	1.60	$	1.77

TransCanada’s net income and net income from continuing operations (net earnings) for third quarter 2006 were $293 million or $0.60 per share compared to $427 million or $0.88 per share for third quarter 2005. The 2006 net earnings were lower than 2005 by $134 million or $0.28 per share, primarily due to after-tax gains of $193 million or $0.40 per share from the sale of the company’s interest in Power LP to EPCOR Utilities Inc. (EPCOR) in third quarter 2005. Excluding these gains, the company reported a decrease in Corporate’s net expenses and an increase in Energy’s net earnings, partially offset by a decrease in Pipelines’ net earnings.

The $53 million decrease in Corporate’s net expenses in third quarter 2006 compared to third quarter 2005 was primarily due to an income tax benefit of approximately $50 million on the resolution of certain income

tax matters with taxation authorities and changes in estimates during the quarter.

Excluding the gains related to the sale of the Power LP interest in third quarter 2005, Energy’s net earnings for third quarter 2006 increased $25 million compared to third quarter 2005 primarily due to higher operating income from Eastern and Western Power Operations and Natural Gas Storage, partially offset by lower operating income from Bruce Power.

Pipelines’ net earnings for third quarter 2006 decreased $19 million primarily due to lower net earnings from the Canadian Mainline and Alberta System as a result of lower rates of return on common equity (ROE) and lower average investment bases. Net earnings from TransCanada’s Other Pipelines for third quarter 2006 decreased $6 million compared to third quarter 2005 primarily due to the impact of a weaker U.S. dollar and higher project development and support costs, partially offset by increased net earnings from Portland.

TransCanada’s net income for the nine months ended September 30, 2006 was $810 million or $1.66 per share, which included net income from discontinued operations of $28 million or $0.06 per share reflecting bankruptcy settlements with Mirant Corporation and certain of its subsidiaries (Mirant) received in first quarter 2006 related to TransCanada’s Gas Marketing business divested in 2001. Net income for the nine months ended September 30, 2005 was $859 million or $1.77 per share.

TransCanada’s net earnings for the nine months ended September 30, 2006 were $782 million or $1.60 per share compared to $859 million or $1.77 per share for the same period in 2005. The decrease of $77 million or $0.17 per share was primarily due to gains recognized on the sales of PipeLines LP units and the company’s interest in Power LP in 2005.

Excluding the $49 million after-tax gain on the sale of PipeLines LP units in 2005 and the $13 million after-tax gain on the sale of TransCanada’s general partner interest in Northern Border Partners, L.P. in 2006, Pipelines’ net earnings for the nine months ended September 30, 2006 decreased $54 million compared to the same period in 2005. This decrease was primarily due to lower net earnings from the Canadian Mainline and Alberta System as a result of lower ROE and lower average investment bases in 2006, compared to 2005. In addition, the 2005 net earnings included a positive adjustment of $13 million related to 2004, resulting from the April 2005 National Energy Board (NEB) decision on Canadian Mainline’s 2004 Tolls and Tariff Application (Phase II). As well, TransCanada’s Other Pipelines experienced lower net earnings in 2006, compared to 2005. These decreases were partially offset by higher net earnings from GTN, which included an $18 million ($29 million pre-tax) bankruptcy settlement with Mirant, a former shipper on the Gas Transmission Northwest System.

Excluding the $193 million after-tax gains related to the sale of the Power LP interest in 2005, Energy’s net earnings for the nine months ended September 30, 2006 increased $149 million compared to the same period in 2005, primarily due to higher operating

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

The decrease of $57 million in Corporate’s net expenses for the nine months ended September 30, 2006 compared to the same period in 2005 was primarily due to the income tax benefit of approximately $50 million in third quarter 2006, as well as a $10 million favourable impact on future income taxes in second quarter 2006 arising from reductions in Canadian federal and provincial income tax rates.

Results from each business segment for the three and nine months ended September 30, 2006 are discussed further in the “Pipelines”, “Energy” and “Corporate” sections of this MD&A.

Funds generated from operations of $662 million and $1,718 million for the three and nine months ended September 30, 2006 increased $159 million and $297 million respectively, when compared to the same periods in 2005.

Pipelines

The Pipelines business generated net earnings of $130 million and $434 million for the three and nine months ended September 30, 2006, respectively, compared to $149 million and $524 million for the same periods in 2005.

PipelinesResults-at-a-Glance

(unaudited)

	Three months ended September 30				Nine months ended September 30
(millions of dollars)	2006		2005		2006		2005
Wholly-Owned Pipelines
Canadian Mainline	59		67		179		216
Alberta System	35		38		102		112
GTN	12		14		57		53
Foothills System	5		5		16		16
BCSystem	2		2		5		5
	113		126		359		402
Other Pipelines
Great Lakes	10		11		33		36
Iroquois	4		7		11		14
Portland	6		1		10		7
PipeLines LP	(1	)	2		3		7
Ventures LP	3		3		9		9
TQM	2		2		5		5
TransGas	3		2		8		8
Gas Pacifico/INNERGY	1		2		5		2
Northern Development	(1	)	(1	)	(3	)	(3	)
General, administrative, support costs and other	(10	)	(6	)	(19	)	(12	)
	17		23		62		73
Gain on sale of Northern Border Partners, L.P. interest,	—		—		13		—
Gain on sale of PipeLines LP units	—		—		—		49
	17		23		75		122
Net Earnings	130		149		434		524

Wholly-Owned Pipelines

Canadian Mainline’s third quarter 2006 net earnings decreased $8 million compared to third quarter 2005 primarily due to a lower ROE, as determined by the NEB, of 8.88 per cent in 2006 compared to 9.46 per cent in 2005, and a lower average investment base. Net earnings for the nine months ended September 30, 2006 decreased $37 million compared to the corresponding period in 2005. This decrease was due to a combination of a lower ROE and a lower average investment base in 2006, compared to 2005. In addition, the 2005 net earnings included a positive adjustment of $13 million related to 2004, as a result of the NEB’s decision in April 2005 on Canadian Mainline’s 2004 Tolls and Tariff Application (Phase II). This NEB decision included an increase in the deemed common equity ratio from 33 per cent to 36 per cent for 2004 which was also effective for 2005 under the 2005 tolls settlement with shippers.

The Alberta System’s net earnings of $35 million and $102 million for the three and nine months ended September 30, 2006 decreased $3 million and $10 million, respectively, compared to the same periods in 2005. The decreases were primarily due to a lower investment base and a lower ROE in 2006. Net earnings in 2006 reflect an ROE of 8.93 per cent on a deemed common equity of 35

per cent compared to an ROE of 9.50 per cent on a deemed common equity of 35 per cent in 2005.

GTN’s net earnings for the three months ended September 30, 2006 were $12 million, a $2 million decrease from the same period in 2005. This decrease was primarily due to lower transportation revenues in 2006. GTN’s net earnings for the nine months ended September 30, 2006 were $57 million, a $4 million increase over the same period in 2005. This increase was primarily due to an $18 million bankruptcy settlement ($29 million pre-tax) in first quarter 2006 with Mirant, a former shipper on the Gas Transmission Northwest System. Partially offsetting this increase were lower transportation revenues, the negative impact of a weaker U.S. dollar and a provision for non-payment of contract transportation revenue from a subsidiary of Calpine Corporation that has filed for bankruptcy protection.

Operating Statistics

Gas Transmission

Canadian

Alberta

Northwest

Nine months ended September 30

Mainline(1)

System(2)

System (3)

Foothills System

BCSystem

(unaudited)

2006

2005

2006

2005

2006

2005

2006

2005

2006

2005

Average investment base ($ millions)

7,450

7,839

4,293

4,478

n/a

n/a

649

683

207

218

Delivery volumes (Bcf)

Total

2,209

2,181

3,033

2,918

592

581

795

788

256

236

Average per day

8.1

8.0

11.1

10.7

2.2

2.1

2.9

2.9

0.9

0.9

(1) Canadian Mainline deliveries originating at the Alberta border and in Saskatchewan for the nine months ended September 30, 2006 were 1,694 Bcf (2005 – 1,605 Bcf); average per day was 6.2 Bcf (2005 – 5.9 Bcf).

(2) Field receipt volumes for the Alberta Systemfor the nine months ended September 30, 2006 were 3,133 Bcf (2005 – 3,010 Bcf); average per day was 11.5 Bcf (2005 – 11.0 Bcf).

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

Other Pipelines

TransCanada’s proportionate share of net earnings from Other Pipelines was $17 million for the three months ended September 30, 2006 compared to $23 million for the same period in 2005. Increased net earnings from Portland, primarily due to a bankruptcy settlement received in third quarter 2006, were more than offset by the impact of higher project development and support costs in 2006, lower net earnings from Iroquois reflecting customer bankruptcy settlements received in third quarter 2005 and lower net earnings from PipeLines LP.

Net earnings for the nine months ended September 30, 2006 were $75 million compared to $122 million for the corresponding period in 2005. Excluding the $13 million gain on the sale of the Northern Border Partners, L.P. interest in 2006, and the $49 million gain on the sale of PipeLines LP units in 2005, year-to-date net earnings were $11 million lower compared to the same period in 2005. Increased net earnings from Portland due to the bankruptcy settlement received in third quarter 2006 were partially offset by provisions recorded in second and third quarter 2006 for non-payment of contract transportation revenue from a subsidiary of Calpine Corporation that has filed for bankruptcy protection. This increase was more than offset by bankruptcy settlements received by Iroquois in third quarter 2005, a weaker U.S. dollar, reduced ownership in PipeLines LP and higher support costs. In addition, Gas Pacifico/INNERGY generated higher earnings in 2006 as a result of natural gas curtailments that negatively affected 2005 net earnings.

As at September 30, 2006, TransCanada had advanced $111 million to the Aboriginal Pipeline Group with respect to the Mackenzie Gas Pipeline Project and had capitalized $21 million related to the Keystone pipeline.

Energy

Energy Results-at-a-Glance

(unaudited)

	Three months ended September 30				Nine months ended September 30
(millions of dollars)	2006		2005		2006		2005
Bruce Power	72		99		176		142
Western Power Operations	84		32		188		90
Eastern Power Operations	40		25		132		69
Natural Gas Storage	24		4		63		15
Power LP Investment	—		12		—		29
General, administrative and support costs	(35	)	(30	)	(100	)	(93	)
Operating income	185		142		459		252
Financial charges	(5	)	—		(17	)	(7	)
Interest income and other	2		2		5		5
Income taxes	(59	)	(46	)	(127	)	(79	)
	123		98		320		171
Gains related to Power LP	—		193		—		193
Net Earnings	123		291		320		364

Energy’s net earnings were $123 million in third quarter 2006, compared to $291 million in third quarter 2005. In third quarter 2005, TransCanada recognized gains of $193 million on the sale of the Power LP interest.

Excluding the gains of $193 million in 2005, Energy’s net earnings of $123 million in third quarter 2006 increased $25 million compared to $98 million in third quarter 2005 due to higher operating income from Western and Eastern Power Operations and Natural Gas Storage. Partially offsetting these increases were lower operating income from Bruce Power and the loss of income associated with the sale of the Power LP interest in third quarter 2005.

Bruce Power’s contribution to operating income decreased $27 million in third quarter 2006 compared to third quarter 2005, primarily due to lower overall realized prices, partially offset by higher generation volumes.

Western Power Operations’ operating income was $52 million higher in third quarter 2006 compared to third quarter 2005 primarily due to incremental earnings from the December 31, 2005 acquisition of the 756 megawatt (MW) Sheerness power purchase arrangement (PPA) and improved margins from higher overall realized power prices and higher market heat rates on uncontracted volumes of power sold.

Eastern Power Operations’ operating income was $15 million higher in third quarter 2006 compared to third quarter 2005 primarily due to higher overall margins on higher power sales volumes and increased generation from the TC Hydro facilities resulting from higher water flows.

Natural Gas Storage operating income increased $20 million in third quarter 2006 compared to third quarter 2005 primarily due to higher contributions from CrossAlta as a result of increased storage capacity and higher natural gas storage spreads.

Excluding the gains of $193 million on the sale of the Power LP interest in 2005, Energy’s net earnings for the nine months ended September 30, 2006 of $320 million increased $149 million compared to $171 million for the same period in 2005. The increase was due to higher contributions from each of its existing businesses and the $23 million decrease in future income taxes resulting from reductions in Canadian federal and provincial corporate income tax rates enacted in second quarter 2006. Partially offsetting these increases was the loss of operating income associated with the sale of the Power LP interest in third quarter 2005 and reduced earnings due to a weaker U.S. dollar.

Bruce Power

Effective October 31, 2005, TransCanada increased its interest in the Bruce A units through the formation of the Bruce A partnership. Bruce A subleases its facilities from Bruce B. TransCanada commenced proportionately consolidating its investments in Bruce A and Bruce B effective October 31, 2005. The following Bruce Power financial results reflect the operations of the full six-unit facility for both periods.

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

(unaudited)

	Three months ended September 30						Nine months ended September 30
	2006			2005			2006			2005
Bruce Power (100 per cent basis)
(millions of dollars)
Revenues
Power	478			635			1,396			1,431
Other (2)	15			7			43			22
	493			642			1,439			1,453
Operating expenses
Operations and maintenance	(210		)	(207		)	(656		)	(640		)
Fuel	(26		)	(21		)	(68		)	(58		)
Supplemental rent	(42		)	(41		)	(127		)	(123		)
Depreciation and amortization	(34		)	(48		)	(99		)	(145		)
	(312		)	(317		)	(950		)	(966		)
Revenues, net of operating expenses	181			325			489			487
Financial charges under equity accounting	—			(18		)	—			(52		)
	181			307			489			435

TransCanada’s proportionate share	69			97			170			137
Adjustments	3			2			6			5
TransCanada’s operating income from
Bruce Power(3)	72			99			176			142

Bruce Power – Other Information
Plant availability
Bruce A	86		%				76		%
Bruce B	92		%				94		%
Combined Bruce Power	90		%	88		%	88		%	80		%
Sales volumes (GWh) (4)
Bruce A – 100 per cent	2,850						7,440
Bruce B – 100 per cent	6,540						19,790
Combined Bruce Power – 100 per cent	9,390			9,130			27,230			24,648
TransCanada’s proportionate share	3,448			2,882			9,848			7,786
Results per MWh (5)
Bruce A revenues	$	59					$	58
Bruce B revenues	$	48					$	49
Combined Bruce Power revenues	$	51		$	70		$	51		$	58
Fuel	$	3		$	2		$	2		$	2
Total operating expenses (6)	$	32		$	35		$	34		$	39
Percentage of output sold to spot market	33		%	60		%	37		%	53		%

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

(2) Includes fuel cost recoveries for Bruce A of $9 million and $19 million, respectively, for the three and nine months ended September 30, 2006.

(3) TransCanada’s consolidated equity income includes $99 million and $142 million, respectively, for the three and nine months ended September 30, 2005 representing TransCanada’s 31.6 per cent share of Bruce Power earnings for the period.

(4) Gigawatt hours.

(5) Megawatt hours.

(6) Net of fuel cost recoveries.

TransCanada’s operating income of $72 million from its combined investment in Bruce Power decreased $27 million in third quarter 2006 compared to third quarter 2005, primarily due to the negative impact of lower realized prices, partially offset by the positive impact of higher generation volumes.

TransCanada’s share of Bruce Power’s generation for third quarter 2006 increased 566 GWh to 3,448 GWh compared to third quarter 2005 generation of 2,882 GWh as a result of fewer planned maintenance outage days in third quarter 2006 compared to third quarter 2005 and an increased ownership interest in the Bruce A facilities. Bruce Power prices achieved during third quarter 2006 (excluding other revenues) were $51 per MWh, compared to $70 per MWh in third quarter 2005. Bruce Power’s operating expenses (net of fuel cost recoveries) in third quarter 2006 decreased to $32 per MWh from $35 per MWh in third quarter 2005 primarily due to increased output in third quarter 2006.

Approximately 22 reactor days of planned maintenance outages as well as approximately 20 reactor days of unplanned outages occurred on the six operating units in third quarter 2006. In third quarter 2005, Bruce Power experienced 32 reactor days of planned maintenance outages and 21 reactor days of unplanned outages. The Bruce Power units ran at a combined average availability of 90 per cent in third quarter 2006, compared to an 88 per cent average availability during third quarter 2005.

TransCanada’s operating income from its combined investment in Bruce Power for the nine months ended September 30, 2006 was $176 million compared to $142 million for the same period in 2005. The increase of $34 million was primarily due to higher sales volumes resulting from increased plant availability and an increased ownership interest in the Bruce A facilities.

Combined Bruce Power prices achieved for the nine months ended September 30, 2006 (excluding other revenues) were $51 per MWh compared to $58 per MWh for the same period in 2005. Bruce Power’s combined operating expenses (net of fuel cost recoveries) decreased to $34 per MWh for the nine months ended September 30, 2006 from $39 per MWh in 2005 primarily due to increased output in 2006. The Bruce units ran at a combined average availability of 88 per cent in the nine months ended September 30, 2006 compared to 80 per cent in the same period of 2005.

The overall plant availability percentage in 2006 is still expected to be in the low 90s for the four Bruce B units and in the low 80s for the two operating Bruce A units. A planned one month maintenance outage on Bruce A Unit 3 during first quarter 2006 and a planned two month maintenance outage on Bruce A Unit 4 during second quarter 2006 were completed. The planned maintenance outage for 2006 for Bruce B Unit 8 began in September 2006 and is expected to last approximately two months.

Income from Bruce B is directly impacted by the fluctuations in wholesale spot market prices for electricity. Income from both Bruce A and Bruce B units is impacted by overall plant availability, which in turn is impacted by scheduled and unscheduled maintenance. As a result of a contract with the Ontario Power Authority (OPA), in first quarter 2006 all of the output from Bruce A was sold at a

fixed price of $57.37 per MWh (before recovery of fuel costs from the OPA) and sales from the Bruce B Units 5 to 8 were subject to a floor price of $45 per MWh. Both of these reference prices are adjusted annually on April 1 for inflation and other potential adjustments in accordance with the terms of the contract with OPA. Effective April 1, 2006, the Bruce A price is $58.63 per MWh and the Bruce B floor price is $45.99 per MWh. Payments received pursuant to the Bruce B floor price mechanism may be subject to refund dependent on spot prices over the term of the contract. Bruce B net earnings included no amounts received under this floor mechanism to date. To further reduce its exposure to spot market prices, Bruce B has entered into fixed price sales contracts to sell forward approximately 3,300 GWh of output for the remainder of 2006 and 6,700 GWh of output for 2007.

The capital cost of Bruce A’s four unit, seven year restart and refurbishment project is expected to total approximately $4.25 billion with TransCanada’s share being approximately $2.125 billion. As at September 30, 2006, Bruce A had incurred $806 million with respect to the restart and refurbishment project.

Western Power Operations

Western Power Operations Results-at-a-Glance

(unaudited)

	Three months ended September 30				Nine months ended September 30
(millions of dollars)	2006		2005		2006		2005
Revenues
Power	311		165		807		480
Other (1)	32		29		134		108
	343		194		941		588
Cost of sales
Power	(194	)	(105	)	(534	)	(313	)
Other (1)	(27	)	(17	)	(103	)	(67	)
	(221	)	(122	)	(637	)	(380	)
Other costs and expenses	(32	)	(34	)	(100	)	(102	)
Depreciation	(6	)	(6	)	(16	)	(16	)
Operating income	84		32		188		90

(1) Other includes Cancarb Thermax and natural gas.

Western Power Operations Sales Volumes

(unaudited)

	Three months ended September 30		Nine months ended September 30
(GWh)	2006	2005	2006	2005
Supply
Generation	599	544	1,622	1,691
Purchased
Sundance A & B and Sheerness PPAs	3,283	1,593	9,520	5,137
Other purchases	455	658	1,460	2,003
	4,337	2,795	12,602	8,831
Contracted vs. Spot
Contracted	2,818	2,423	7,976	7,570
Spot	1,519	372	4,626	1,261
	4,337	2,795	12,602	8,831

Western Power Operations’ operating income of $84 million and $188 million for the three and nine months ended September 30, 2006 increased $52 million and $98 million, respectively, compared to the same periods in 2005. These increases were primarily due to incremental earnings from the December 31, 2005 acquisition of the 756 MW Sheerness PPA and increased margins from a combination of higher overall realized power prices and higher market heat rates on uncontracted volumes of power sold. The market heat rate is determined by dividing the average price of power per MWh by the average price of natural gas per gigajoule (GJ) for a given period. Market heat rates in third quarter 2006 increased by approximately 141 per cent as a result of an approximate 42 per

cent ($27.95 per MWh) increase in spot market power prices, while average spot market natural gas prices in Alberta decreased by approximately 39 per cent ($3.45 per GJ) compared to the same quarter in 2005. A significant portion of power sales volumes were sold by the company into the spot market in third quarter 2006, compared to 2005, due to the acquisition of the Sheerness PPA on December 31, 2005. TransCanada manages the sale of its supply volumes on a portfolio basis. Depending on market conditions, TransCanada will commit a portion of this supply to long-term sales arrangements with the remaining volumes subject to spot market price volatility. This approach to portfolio management assists in minimizing costs in situations where TransCanada would otherwise have to purchase electricity in the open market to fulfill its contractual sales obligations.

Power revenues and cost of sales increased in third quarter 2006 compared to third quarter 2005 primarily due to the acquisition of the Sheerness PPA, effective December 31, 2005, and higher overall realized power prices in third quarter 2006. Generation volumes of 599 GWh in third quarter 2006 increased 55 GWh compared to third quarter 2005 primarily due to the return to service of the Bear Creek facility in August 2006 and planned maintenance outages at the Carseland facility in 2005. The company’s purchased power volumes and percentage of power volumes sold in the Alberta spot market increased in third quarter 2006 compared to 2005 due to the acquisition of the Sheerness PPA. A significant portion of the Sheerness PPA purchased volumes were not sold under contract and were subject to spot market prices. As a result, approximately 35 per cent of power sales volumes were sold into the spot market in third quarter 2006 compared to 13 per cent in third quarter 2005. To reduce its exposure to spot market prices on uncontracted volumes, as at September 30, 2006, Western Power Operations had fixed price power sales contracts to sell approximately 3,200 GWh for the remainder of 2006 and approximately 10,300 GWh for 2007.

Eastern Power Operations

Eastern Power Operations Results-at-a-Glance

(unaudited)

	Three months ended September 30				Nine months ended September 30
(millions of dollars)	2006		2005		2006		2005
Revenue
Power	192		136		527		380
Other (1)	49		111		224		254
	241		247		751		634
Cost of sales
Power	(94	)	(70	)	(284	)	(183	)
Other (1)	(47	)	(98	)	(196	)	(237	)
	(141	)	(168	)	(480	)	(420	)
Other costs and expenses	(53	)	(46	)	(118	)	(127	)
Depreciation	(7	)	(8	)	(21	)	(18	)
Operating income	40		25		132		69

(1) Other includes natural gas.

Eastern Power Operations Sales Volumes

(unaudited)

	Three months ended September 30		Nine months ended September 30
(GWh)	2006	2005	2006	2005
Supply
Generation	1,039	600	2,693	2,006
Purchased	934	833	2,331	2,138
	1,973	1,433	5,024	4,144
Contracted vs. Spot
Contracted	1,829	1,348	4,715	3,765
Spot	144	85	309	379
	1,973	1,433	5,024	4,144

Eastern Power Operations’ operating income was $15 million higher in third quarter 2006 compared to third quarter 2005 primarily due to higher overall margins on higher sales volumes and increased generation from the TC Hydro facilities resulting from higher water flows. The 550 MW Bécancour cogeneration plant was placed in service in late third quarter 2006 and therefore its contribution to operating income was not significant.

Operating income for the nine months ended September 30, 2006 was $132 million or $63 million higher than the $69 million earned in the same period of 2005. The increase was primarily due to incremental income from the April 1, 2005 acquisition of the TC Hydro generation assets, a $10 million ($16 million pre-tax) first quarter 2005 one-time restructuring payment from OSP to its natural gas fuel suppliers, margins earned in first quarter 2006 on transportation related to unutilized OSP natural gas fuel, higher overall margins on higher power sales volumes and profits earned on natural gas purchased and resold under the OSP gas supply contracts. Partially offsetting these increases was the negative impact of a weaker U.S. dollar in 2006 compared to 2005.

Generation volumes in third quarter 2006 increased 439 GWh to 1,039 GWh compared to third quarter 2005 due to increased dispatch of the OSP facility, increased output from the TC Hydro generation assets resulting from higher water flows and the placing in service of the Bécancour facility.

Power revenues of $192 million increased $56 million in third quarter 2006 compared to third quarter 2005 due to increased sales volumes and higher realized prices. Power cost of sales of $94 million was higher in third quarter 2006 compared to third quarter 2005 due to the impact of increased purchased volumes and higher prices. Purchased power volumes of 934 GWh were higher in third quarter 2006 to supply increased sales volumes. Third quarter 2006 other revenue and other cost of sales of $49 million and $47 million, respectively, decreased year-over-year primarily as a result of a reduction in the quantity of natural gas being resold under the OSP natural gas sales contracts and lower gas prices. Other costs and expenses in third quarter 2006 of $53 million, which includes fuel gas consumed in generation, increased from the prior year primarily as a result of the placing in service of the Bécancour facility.

In third quarter 2006, approximately seven per cent of power sales volumes were sold into the spot market compared to approximately six per cent in third quarter 2005. Eastern Power Operations is focused on selling the majority of its power under contract to wholesale, commercial and industrial customers while managing a portfolio of power supplies sourced from its own generation and wholesale power purchases. To reduce its exposure to spot market prices, as at September 30, 2006, Eastern Power Operations had entered into fixed price power sales contracts to sell approximately 2,500 GWh for the remainder of 2006 and approximately 9,600 GWh for 2007, although certain contracted volumes are dependent on customer usage levels.

Power Sales Volumes and Plant Availability

Power SalesVolumes

(unaudited)

	Three months ended September 30		Nine months ended September 30
(GWh)	2006	2005	2006	2005
Bruce Power (1)	3,448	2,882	9,848	7,786
Western Power Operations (2)	4,337	2,795	12,602	8,831
Eastern Power Operations (3)	1,973	1,433	5,024	4,144
Power LP Investment (4)	—	445	—	1,865
Total	9,758	7,555	27,474	22,626

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

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

(3) TCHydro is included in Eastern Power Operations effective April 1, 2005. Bécancour is included in Eastern Power Operations effective September 17, 2006.

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

Weighted Average Plant Availability (1)

(unaudited)

	Three months ended September 30				Nine months ended September 30
	2006		2005		2006		2005
Bruce Power	90	%	88	%	88	%	80	%
Western Power Operations	94	%	89	%	86	%	86	%
Eastern Power Operations (2)	98	%	84	%	97	%	81	%
Power LP Investment (3)			96	%			93	%
All plants, excluding Bruce Power	97	%	88	%	94	%	85	%
All plants	93	%	89	%	90	%	81	%

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

(2) TC Hydro is included in Eastern Power Operations effective April 1, 2005. Bécancour is included in Eastern Power Operations effective September 17, 2006.

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

Natural Gas Storage

Natural Gas Storage operating income of $24 million and $63 million for the three and nine months ended September 30, 2006, respectively, increased $20 million and $48 million, respectively, compared to the same periods in 2005. The increases were primarily due to higher contributions from CrossAlta as a result of increased capacity and higher natural gas storage spreads, and income from other contracted third party natural gas storage capacity in Alberta.

General, Administrative and Support Costs

General, administrative and support costs of $35 million and $100 million for the three and nine months ended September 30, 2006,

respectively, increased $5 million and $7 million compared to the same periods in 2005. The increases were primarily due to higher business development costs.

As at September 30, 2006, TransCanada had capitalized $26 million related to the Broadwater LNG project.

Corporate

Net earnings from Corporate for the three and nine months ended September 30, 2006 were $40 million and $28 million, respectively, compared to net expenses of $13 million and $29 million for the same periods in 2005.

The $53 million decrease in net expenses for third quarter 2006, compared to the same period in 2005, was primarily due to an income tax benefit of approximately $50 million on the resolution of certain income tax matters with taxation authorities and changes in estimates during the quarter.

The $57 million decrease in net expenses for the nine months ended September 30, 2006, compared to the same period in 2005, was primarily due to the $50 million income tax benefit in third quarter 2006, as well as a $10 million favourable impact on future income taxes arising from reductions in Canadian federal and provincial corporate income tax rates enacted in second quarter 2006. In addition, net earnings were positively impacted by increased interest income and other and the favourable impact of a weaker U.S. dollar. Partially offsetting these decreases in net expenses were income tax refunds and positive income tax adjustments recorded in the nine months ended September 30, 2005.

Liquidity and Capital Resources

Funds Generated from Operations

Funds generated from operations were $662 million and $1,718 million for the three and nine months ended September 30, 2006, respectively, compared to $503 million and $1,421 million for the same periods in 2005.

TransCanada expects that its ability to generate adequate amounts of cash in the short and long term, when needed, and to maintain financial capacity and flexibility to provide for planned growth remains substantially unchanged since December 31, 2005.

Investing Activities

In the three and nine months ended September 30, 2006, capital expenditures totalled $372 million (2005 – $166 million) and $1,002 million (2005 – $409 million), respectively, and related primarily to the restart and refurbishment of Bruce A Units 1 and 2, construction of new power plants, the Tamazunchale pipeline and the Edson natural gas storage facilities as well as maintenance and other capacity capital expenditures in the Pipelines business.

Acquisitions for the nine months ended September 30, 2006 were $358 million (2005 – $632 million). In second quarter 2006, PipeLines LP acquired an additional 20 per cent general partnership interest in Northern Border. In 2005, TransCanada acquired TC

Hydro generation assets and an additional 3.52 per cent interest in Iroquois.

In the three and nine months ended September 30, 2006, disposition of assets, net of current income tax, generated nil (2005 – $444 million) and $23 million (2005 – $546 million), respectively. The disposition in 2006 related to the sale of TransCanada’s 17.5 per cent general partner interest in Northern Border Partners, L.P. The dispositions in 2005 related to the sale of TransCanada’s ownership interest in Power LP and PipeLines LP units.

Financing Activities

TransCanada retired $4 million and $352 million of long-term debt in the three and nine months ended September 30, 2006, respectively. TransCanada issued $1,250 million of long-term debt in the nine months ended September 30, 2006. For the three months ended September 30, 2006, notes payable increased $4 million while, for the nine months ended September 30, 2006, notes payable decreased $449 million.

In October 2006, the company issued $400 million of 4.65 per cent medium-term notes, due October 2016. The proceeds were used to reduce the company’s notes payable.

Cash and short-term investments for the three and nine months ended September 30, 2006 increased $28 million and $130 million, respectively.

Dividends

On October 30, 2006, TransCanada’s Board of Directors declared a quarterly dividend of $0.XX per share for the quarter ending December 31, 2006 on the outstanding common shares. This is the 172nd consecutive quarterly dividend paid by TransCanada and its subsidiary on the common shares. It is payable on January 31, 2007 to shareholders of record at the close of business on December 29, 2006.

Contractual Obligations

Energy’s future capital expenditure obligations at September 30, 2006 increased compared to December 31, 2005, primarily as a result of TransCanada’s commitment with OPA to construct the Portland Energy Centre (PEC), as discussed in the Other Recent Developments section of this MD&A.

Other than the PEC commitment, there have been no material changes to TransCanada’s contractual obligations from December 31, 2005 to September 30, 2006, including payments due for the next five years and thereafter. For further information on these contractual obligations, refer to the MD&A in TransCanada’s 2005 Annual Report.

Financial and Other Instruments

The following represents the material changes to the company’s financial instruments since December 31, 2005.

Energy Price Risk Management

The company executes power, natural gas and heat rate derivatives for overall management of its asset portfolio. Heat rate contracts are contracts for the sale or purchase of power that are priced based on a natural gas index. The fair value and notional volumes of contracts for differences and the swap, future, option and heat rate contracts are shown in the tables below.

Power

Asset/(Liability)

		September 30, 2006
		(unaudited)		December 31, 2005
	Accounting	Fair		Fair
(millions of dollars)	Treatment	Value		Value
Power – swaps and contracts for differences
(maturing 2006 to 2011)	Hedge	(89	)	(130	)
(maturing 2006 to 2010)	Non-hedge	(6	)	13
Gas – swaps and futures
(maturing 2006 to 2016)	Hedge	(58	)	17
(maturing 2006 to 2008)	Non-hedge	26		(11	)

Notional Volumes
September 30, 2006	Accounting	Power (GWh)		Gas (Bcf)
(unaudited)	Treatment	Purchases	Sales	Purchases	Sales
Power – swaps and contracts for differences
(maturing 2006 to 2011)	Hedge	4,946	11,189	—	—
(maturing 2006 to 2010)	Non-hedge	1,465	917	—	—
Gas – swaps and futures
(maturing 2006 to 2016)	Hedge	—	—	81	60
(maturing 2006 to 2008)	Non-hedge	—	—	15	20
Heat rate contracts
(maturing 2006)	Non-hedge	—	12	—	—


Notional Volumes	Accounting	Power (GWh)		Gas (Bcf)
December 31, 2005	Treatment	Purchases	Sales	Purchases	Sales
Power – swaps and contracts for differences	Hedge	2,566	7,780	—	—
	Non-hedge	1,332	456	—	—

Gas – swaps and futures	Hedge	—	—	91	69
	Non-hedge	—	—	15	18

Certain of the company’s joint ventures use power derivatives to manage energy price risk exposures. The company’s proportionate share of the fair value of these outstanding power sales derivatives at September 30, 2006 was $55 million (December 31, 2005 – $(38) million) and relates to contracts which cover the period 2006 to 2010. The company’s proportionate share of the notional sales volumes associated with this exposure at September 30, 2006 was 4,500 GWh (December 31, 2005 – 2,058 GWh).

Risk Management

TransCanada’s market, financial and counterparty risks remain substantially unchanged since December 31, 2005. For further information on risks, refer to the MD&A in TransCanada’s 2005 Annual Report.

Controls and Procedures

As of September 30, 2006, TransCanada’s management, together with TransCanada’s President and Chief Executive Officer and Chief Financial Officer, evaluated the effectiveness of the design and operation of the company’s disclosure controls and procedures. Based on this evaluation, the President and Chief Executive Officer and the Chief Financial Officer of TransCanada have concluded and reaffirmed that the disclosure controls and procedures are effective.

There were no changes in TransCanada’s internal control over financial reporting during the most recent fiscal quarter that have materially affected or are reasonably likely to materially affect TransCanada’s internal control over financial reporting.

Critical Accounting Policy

TransCanada’s critical accounting policy, which remains unchanged since December 31, 2005, is the use of regulatory accounting for its regulated operations. For further information on this critical accounting policy, refer to the MD&A in TransCanada’s 2005 Annual Report.

Critical Accounting Estimates

Since a determination of many assets, liabilities, revenues and expenses is dependent upon future events, the preparation of the

company’s consolidated financial statements requires the use of estimates and assumptions which have been made using careful judgment. TransCanada’s critical accounting estimate from December 31, 2005 continues to be depreciation expense. For further information on this critical accounting estimate, refer to the MD&A in TransCanada’s 2005 Annual Report.

Outlook

In 2006, TransCanada expects higher net income than originally anticipated due to the income tax benefit of approximately $50 million on the resolution of certain income tax matters with taxation authorities and changes in estimates during the quarter, the $33 million favourable impact of Canadian federal and provincial corporate income tax rate reductions, improved Energy results to date and net income from discontinued operations as a result of bankruptcy settlements received from Mirant. Excluding these impacts, the company’s outlook is relatively unchanged since December 31, 2005. For further information on outlook, refer to the MD&A in TransCanada’s 2005 Annual Report.

In 2006, TransCanada will continue to direct its resources towards long-term growth opportunities that will strengthen its financial performance and create long-term value for shareholders. The company’s net income and cash flow combined with a strong balance sheet continue to provide the financial flexibility for TransCanada to make disciplined investments in its core businesses of Pipelines and Energy.

TransCanada’s issuer rating assigned by Moody’s Investors Service (Moody’s) is A3 with a stable outlook. Credit ratings on TransCanada PipeLines Limited’s (TCPL) senior unsecured debt assigned by Dominion Bond Rating Service Limited (DBRS), Moody’s and Standard & Poor’s remain at A, A2 and A-, respectively. DBRS and Moody’s both maintain a ‘stable’ outlook on their ratings and Standard & Poor’s maintains a ‘negative’ outlook on its rating.

Other Recent Developments

Pipelines

Wholly-Owned Pipelines

Gas Transmission Northwest System

In June 2006, the Gas Transmission Northwest System filed a rate case with the FERC. The comprehensive filing requests a number of tariff changes including an increase in rates for transportation services. The current rates are based on the last rate case filed in 1994. The proposed rates include an ROE of 14.5 per cent, a common equity ratio of 62.99 per cent and a depreciation rate for the transmission plant of 2.76 per cent.

GTN anticipates receiving a procedural order from the FERC in first quarter 2007, and this order will establish a timeline for GTN’s rate case proceedings.

North Baja Pipeline Expansion

On February 7, 2006, TransCanada’s North Baja Pipeline filed an application with the FERC to expand and modify its existing system to facilitate the importation of more than 2.7 billion cubic feet per day (Bcf/d) of regasified LNG from Mexico into the California and Arizona markets. Specifically, North Baja proposes to modify its existing system to accommodate bi-directional natural gas flow, construct a new meter station and a 36 inch pipeline interconnect with Southern California Gas Company (SoCal Gas), construct approximately 74 kilometres of lateral facilities to serve electric generation facilities, and loop its entire approximate 129 kilometres existing system with a combination of 42 inch and 48 inch diameter pipeline. On October 6, 2006, the FERC issued a preliminary determination approving all aspects of North Baja’s proposal other than those related to environmental issues, which will be the subject of a future order.

Tamazunchale

In September 2006, TransCanada entered the commissioning phase of construction of its Tamazunchale pipeline in east-central Mexico. The 130 kilometre pipeline is expected to begin commercial operations in December 2006 and will initially transport 170 million cubic feet per day (mmcf/d) of natural gas from the PEMEX gas pipeline system near Naranjos, Veracruz, Mexico to an electricity generation station near Tamazunchale, San Luis Potosi, Mexico. Under the current contract with the Comisión Federal de Electricidad, the capacity of the Tamazunchale pipeline will be expanded beginning in 2009 to approximately 430 mmcf/d to meet the needs of two additional proposed power plants near Tamazunchale.

Other Pipelines

In September 2006, Northern Border reached a settlement with its participant customers regarding its pending rate case before the FERC. The settlement, which establishes maximum long-term rates and charges for transportation on the Northern Border system and is supported by the FERC trial staff, was certified by the administrative law judge presiding over the case and forwarded to the FERC for approval. The approval process is expected to be completed by late 2006.

Northern Development

Mackenzie Gas Pipeline Project public hearings are expected to conclude in April 2007. The hearings are held by a Joint Review Panel, which focuses on environmental and socio-economic impacts, and the NEB, which is reviewing all other matters including pipeline engineering, safety, need and economic feasibility. Concurrently, the project proponents are re-assessing the capital cost estimate and construction schedule for the project, in light of overall industry cost escalations and labour shortages.

Keystone Pipeline

In April 2006, TransCanada filed an application with the U.S. Department of State for a Presidential Permit authorizing the

construction, operation and maintenance of the Keystone pipeline. In September 2006, the Department of State issued a formal notice of the application as well as a Notice of Intent to prepare an Environmental Impact Statement for the project.

In June 2006, TransCanada Keystone Pipeline LP (Keystone LP) filed a petition with the Illinois Commerce Commission for a certificate authorizing the pipeline and granting authority to exercise eminent domain. The matter is expected to go to hearing in mid-November 2006.

In June 2006, TransCanada and Keystone LP filed an application with the NEB seeking approval to transfer a portion of the Canadian Mainline to the Keystone pipeline. As part of the transfer application, TransCanada is also seeking approval to reduce Canadian Mainline’s rate base by the net book value (NBV) of the transferred facilities and Keystone LP is seeking approval to add the NBV of the facilities to the Keystone pipeline rate base. The transfer application is the first of two major regulatory applications required to obtain approvals necessary to construct the Canadian portion of the Keystone pipeline. An oral public hearing on the application commenced on October 23, 2006.

TransCanada filed its Preliminary Information Package for the required new facilities with the NEB in July 2006. TransCanada expects to file an application with the NEB for a certificate of public convenience and necessity to construct the required new facilities later this year once environmental assessment work is completed. The project will also require regulatory approvals from various U.S. agencies.

Energy

Bruce Power

The Bruce A restart and refurbishment project reached another key milestone in third quarter 2006 with the delivery of the first three of 16 steam generators that will be installed in Units 1 and 2 as part of the restart project. The restart of Units 1 and 2 is expected to return another 1,500 MW of generating capacity to Ontario with the first unit expected to restart in late 2009. Bruce Power also plans to replace the eight steam generators in each of Units 3 and 4. Based on results from recent inspections, it is expected that the steam generators in Unit 4 can continue to operate until 2010 and then be replaced. The refurbishment of Unit 3 is expected to begin in late 2009.

In August 2006, Bruce Power filed an application with the Canadian Nuclear Safety Commission to prepare the Bruce site for potential future construction of new reactors at the facility.

Cartier Wind

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

December 2007. TransCanada has a 62 per cent interest in the Cartier Wind project which was awarded six projects by Hydro-Québec Distribution in October 2004 representing a total of 739.5 MW.

Portlands Energy Centre

In third quarter 2006, Portlands Energy Centre L.P. (Portlands Energy) signed a 20 year Accelerated Clean Energy Supply (ACES) contract with OPA for a 550 MW high-efficiency, combined-cycle natural gas generation plant to be constructed in downtown Toronto. Portlands Energy is a limited partnership between Ontario Power Generation and TransCanada with both parties having a 50 per cent interest. The capital cost of PEC is estimated to be approximately $730 million. PEC is expected to be operational in simple-cycle mode, delivering 340 MW of electricity to the City of Toronto to meet peak summer demand beginning June 1, 2008 with full completion expected in second quarter 2009.

Bécancour

In September 2006, construction was completed on the 550 MW Bécancour cogeneration plant. The plant, near Trois-Rivières, Québec, was placed in service in late third quarter 2006 and began fulfilling its obligations to supply electricity to Hydro-Québec Distribution under a long-term contract.

Cacouna

The Canadian Environmental Assessment Agency and the Bureau des Audiences Publiques sur l’Environnement (BAPE) joint review panel on the proposed Cacouna Energy project requested an extension to consider additional documents and refinements to this proposed project. Cacouna Energy anticipates receiving government approvals in early 2007. Cacouna Energy is a partnership between TransCanada and Petro-Canada. The proposed terminal would be capable of receiving, storing, and re-gasifying imported LNG with an average throughput capacity of approximately 500 mmcf/d of natural gas.

Broadwater

The U.S. Coast Guard released its Waterways Suitability Report on the Broadwater Energy project on September 22, 2006. The report determined that the proposed LNG facility in the New York State waters of Long Island Sound can be operated safely and securely and has provided a series of mitigation measures. This report represents another key milestone in the ongoing regulatory review of the Broadwater Energy project. Broadwater Energy is a partnership between TransCanada and Shell U.S. Gas & Power. The Broadwater terminal would be capable of receiving, storing, and re-gasifying imported LNG with an average send-out capacity of approximately one Bcf/d of natural gas.

Edson

Construction of the Edson natural gas storage facility in Alberta was substantially complete at the end of third quarter 2006 and commissioning will take place in fourth quarter 2006. Storage capacity is expected to be available later this year. The Edson facility is expected to have a working natural gas capacity of approximately 60 petajoules and will connect to the Alberta System.

Share Information

As at September 30, 2006, TransCanada had 488,358,307 issued and outstanding common shares. In addition, there were 9,417,680 outstanding options to purchase common shares, of which 6,496,607 were exercisable as at September 30, 2006.

Selected Quarterly Consolidated Financial Data(1)

(unaudited)

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

Revenues	1,850		1,685		1,894		1,771		1,494		1,449		1,410		1,480
Net Income
Continuing operations	293		244		245		350		427		200		232		185
Discontinued operations	—		—		28		—		—		—		—		—
	293		244		273		350		427		200		232		185

Share Statistics
Net income per share – Basic
Continuing operations	$	0.60	$	0.50	$	0.50	$	0.72	$	0.88	$	0.41	$	0.48	$	0.38
Discontinued operations	—		—		0.06		—		—		—		—		—
	$	0.60	$	0.50	$	0.56	$	0.72	$	0.88	$	0.41	$	0.48	$	0.38
Net income per share – Diluted
Continuing operations	$	0.60	$	0.50	$	0.50	$	0.71	$	0.87	$	0.41	$	0.48	$	0.38
Discontinued operations	—		—		0.06		—		—		—		—		—
	$	0.60	$	0.50	$	0.56	$	0.71	$	0.87	$	0.41	$	0.48	$	0.38
Dividend declared per common share	$	0.32	$	0.32	$	0.32	$	0.305	$	0.305	$	0.305	$	0.305	$	0.29

(1) The selected quarterly consolidated financial data has been prepared in accordance with Canadian GAAP. Certain comparative figures have been reclassified to conformwith the current year’s presentation. For a discussion on the factors affecting the comparability of the financial data, including discontinued operations, refer to Note 1, Note 2 and Note 23 of TransCanada’s 2005 audited consolidated financial statements.

Factors Impacting Quarterly Financial Information

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

In the Energy business, which primarily builds, owns and operates electrical power generation plants, sells electricity and invests in natural gas storage facilities, quarter over quarter revenues and net earnings are affected by seasonal weather conditions, customer demand, market prices, planned and unplanned plant outages as well as items outside of the normal course of operations.

Significant items which impacted the last eight quarters’ net earnings are as follows.

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

· First quarter 2005 net earnings included a $49 million after-tax gain related to the sale of PipeLines LP units. Energy’s earnings included a $10 million after-tax cost for the restructuring of natural gas supply contracts by OSP. In addition, Bruce Power’s equity income was lower than previous quarters due to the impact of planned maintenance outages and the increase in operating costs as a result of moving to a six-unit operation.

· Second quarter 2005 net earnings included $21 million ($13 million related to 2004 and $8 million related to the six months ended June 30, 2005) with respect to the NEB’s decision on Canadian Mainline’s 2004 Tolls and Tariff Application (Phase II). On April 1, 2005, TransCanada completed the acquisition of TC Hydro generation assets from USGen New England, Inc. Bruce Power’s equity income was lower than previous quarters due to the continuing impact of planned maintenance outages and an unplanned maintenance outage on Unit 6 relating to a transformer fire.

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

· Fourth quarter 2005 net earnings included a $115 million after-tax gain on sale of Paiton Energy. In addition, Bruce A was formed and Bruce Power’s results were proportionately consolidated effective October 31, 2005.

· First quarter 2006 net earnings included an $18 million after-tax bankruptcy claim settlement received by the Gas Transmission Northwest System. In addition, Energy’s net earnings included contributions from the December 31, 2005 acquisition of the 756 MW Sheerness PPA.

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

· Third quarter 2006 net earnings included an income tax benefit of approximately $50 million on the resolution of certain income tax matters with taxation authorities and changes in estimates during the quarter.