Exhibit 13.1

Second Quarter 2006 Financial Highlights
(unaudited)

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

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

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

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

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

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

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

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

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

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

Management’s Discussion and Analysis

Management’s discussion and analysis (MD&A) dated July 27, 2006 should be read in conjunction with the accompanying unaudited consolidated financial statements of TransCanada Corporation (TransCanada or the company) for the six months ended June 30, 2006. It should also be read in conjunction with the audited consolidated financial statements and the MD&A contained in TransCanada’s 2005 Annual Report for the year ended December 31, 2005. Additional information relating to TransCanada, including the company’s Annual Information Form and continuous disclosure documents, is available on SEDAR at www.sedar.com under TransCanada Corporation. Amounts are stated in Canadian dollars unless otherwise indicated. Capitalized and abbreviated terms that are used but not otherwise defined herein have the meanings provided in the annual MD&A contained in TransCanada’s 2005 Annual Report.

Forward-Looking Information

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

Non-GAAP Measures

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

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

Results of Operations

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

Consolidated

Segment Results-at-a-Glance
(unaudited)

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

Energy	97		41			197			73

Corporate	—		(7		)	(12		)	(16		)

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


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

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

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

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

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

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

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

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

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

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

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

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

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

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

Pipelines

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

Pipelines Results-at-a-Glance

(unaudited)

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

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

Wholly-Owned Pipelines

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

The Alberta System’s net earnings decreased $3 million and $7 million for the three and six months ended June 30, 2006, respectively, compared to the same periods in 2005. These decreases were primarily due to a lower average investment base as well as a lower ROE, as determined by the Alberta Energy and Utilities Board (EUB), in 2006 compared to 2005. Net earnings in 2006 reflected an ROE of 8.93 per cent on deemed common equity of 35 per cent compared to an ROE of 9.50 per cent on deemed common equity of 35 per cent in 2005.

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

Operating Statistics

Gas

Transmission

Canadian

Alberta

Northwest

Foothills

Six months ended June 30

Mainline(1)

System(2)

System(3)

System

BC System

(unaudited)

2006

2005

2006

2005

2006

2005

2006

2005

2006

2005

Average investment base ($ millions)

7,454

7,873

4,305

4,534

n/a

654

687

207

219

Delivery volumes (Bcf)

Total

1,534

1,437

2,026

1,936

349

383

500

520

156

162

Average per day

8.5

7.9

11.2

10.7

1.9

2.1

2.8

2.9

0.9

0.9

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

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

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

Other Pipelines

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

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

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

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

Energy

Energy Results-at-a-Glance

(unaudited)

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

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

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

Western Power Operations’ operating income was $18 million higher in second quarter 2006 compared to second quarter 2005 primarily due to incremental earnings from the December 31, 2005 acquisition of the 756 megawatt (MW) Sheerness power purchase arrangement (PPA) and improved margins from higher overall realized power prices and higher market heat rates on uncontracted volumes of power sold.

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

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

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

Bruce Power

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

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

(unaudited)

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

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

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

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

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

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

(4) Gigawatt hours.

(5) Megawatt hours.

(6) Net of fuel cost recoveries.

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

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

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

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

Combined Bruce Power prices achieved for the six months ended June 30, 2006 (excluding other revenues) were $51 per MWh, equal to the same period in 2005. Bruce Power’s combined operating expenses (net of fuel cost recoveries) decreased to $35 per MWh for the six months ended June 30, 2006 from $42 per MWh in 2005 primarily due to increased output in 2006. The Bruce units ran at a combined average availability of 87 per cent in the six months ended June 30, 2006 compared to 76 per cent in the same period in 2005.

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

Income for Bruce B is directly impacted by fluctuations in wholesale spot market prices for electricity. Income from both Bruce A and Bruce B units is impacted by overall plant availability, which in turn is impacted by scheduled and unscheduled maintenance. As a result of a contract with the Ontario Power Authority (OPA), for first quarter 2006, all of the output from Bruce A was sold at a fixed price of $57.37 per MWh (before recovery of fuel costs from the OPA) and sales from the Bruce B Units 5 to 8 were subject to a floor price of $45 per MWh. Both of these reference prices are adjusted annually on April 1 for inflation and other potential adjustments per the terms of the contract with OPA. Effective April 1, 2006, the Bruce A fixed price is $58.63 per MWh and the Bruce B floor price is $45.99 per MWh. To further reduce its exposure to spot market prices, Bruce B has entered into fixed price sales contracts to sell forward approximately 6,700 GWh of output for the remainder of 2006 and 6,300 GWh of output for 2007.

Bruce A’s four unit, seven year capital program for the restart and refurbishment project is expected to total approximately $4.25 billion with TransCanada’s share being approximately $2.125 billion. As at June 30, 2006, Bruce A had incurred $645 million with respect to the restart and refurbishment project.

Western Power Operations

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

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

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

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

Operating income	46		28		104		58

(1) Includes Cancarb Thermax and natural gas sales.

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

Western Power Operations Sales Volumes

(unaudited)

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

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

Western Power Operations’ operating income of $46 million in second quarter 2006 was $18 million higher compared to second quarter 2005 primarily due to incremental earnings from the December 31, 2005 acquisition of the 756 MW Sheerness PPA. Operating income was also higher due to increased margins in second quarter 2006 compared to second quarter 2005 from higher overall realized power prices and higher market heat rates on uncontracted volumes of power sold. The market heat rate is determined by dividing the average price of power per MWh by the average price of natural gas per gigajoule (GJ) for a given period. Market heat rates increased by approximately 29 per cent as a result of an approximate four per cent ($2.15 per MWh) increase in spot market power prices, while average spot market natural gas prices in Alberta decreased by approximately 18 per cent ($1.25 per GJ) in second quarter 2006 compared to the same quarter in 2005. A significant portion of power sales volumes were sold into the spot market in second quarter 2006 due to the acquisition of the Sheerness PPA on December 31, 2005. TransCanada manages the sale of its supply volumes on a portfolio basis. Depending on market conditions, TransCanada will commit a portion of this supply to long-term sales arrangements with the remaining volumes subject to spot market price volatility. This approach to portfolio management assists in minimizing costs in situations where TransCanada would otherwise have to purchase electricity in the open market to fulfill its contractual sales obligations.

Power sales revenues and power cost of sales increased in second quarter 2006 compared to second quarter 2005 primarily due to the acquisition of the Sheerness PPA, effective December 31, 2005, and higher overall realized power prices in second quarter 2006. Generation volumes of 438 GWh in second quarter 2006 decreased 73 GWh compared to second quarter 2005 primarily due to planned outages and reduced dispatch of Alberta cogeneration assets during periods of uneconomic market conditions. The Bear Creek facility is expected to return to service in third quarter 2006. Purchased power volumes and the percentage of power volumes sold into the Alberta spot market increased in second quarter 2006 compared to 2005 due to the acquisition of the Sheerness PPA. A significant portion of the Sheerness PPA purchased volumes were not sold under contract and were subject to spot market prices. As a result, approximately 37 per cent of power sales volumes were sold into the spot market in second quarter 2006 compared to 13 per cent in second quarter 2005. To reduce its exposure to spot market prices on uncontracted volumes, as at June 30, 2006, Western Power Operations had fixed price power sales contracts to sell approximately 5,900 GWh for the remainder of 2006 and approximately 7,900 GWh for 2007.

Eastern Power Operations

Eastern Power Operations Results-at-a-Glance

(unaudited)

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

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

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

Operating income	43		39		92		44

(1) Other includes natural gas.

Eastern Power Operations Sales Volumes
(unaudited)

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

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

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

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

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

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

In second quarter 2006, approximately seven per cent of power sales volumes were sold into the spot market compared to approximately 16 per cent in second quarter 2005. Eastern Power Operations is focused on

selling the majority of its power under contract to wholesale, commercial and industrial customers while managing a portfolio of power supplies sourced from its own generation and wholesale power purchases. To reduce its exposure to spot market prices, as at June 30, 2006, Eastern Power Operations had entered into fixed price power sales contracts to sell approximately 2,700 GWh for the remainder of 2006 and approximately 4,400 GWh for 2007, although certain contracted volumes are dependent on customer usage levels.

Natural Gas Storage

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

General, Administrative and Support Costs

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

Power Sales Volumes and Plant Availability

Power Sales Volumes

(unaudited)

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

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

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

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

(4) TransCanada operated and managed Power LP until August 31, 2005. The volumes in the table represent 100 per cent of Power LP’s sales volumes to June 30, 2005.

Weighted Average Plant Availability(1)

(unaudited)

Three months ended June 30

Six months ended June 30

2006

2005

2006

2005

Bruce Power

84%

71%

87%

76%

Western Power Operations(2)

74%

81%

82%

85%

Eastern Power Operations(3)

98%

74%

97%

81%

Power LP Investment(4)

—

86%

—

92%

All plants, excluding Bruce Power

93%

79%

93%

85%

All plants

85%

76%

88%

82%

(1) Plant availability represents the percentage of time in

the period that the plant is available to generate power, even if the plant is not operating, reduced by planned and unplanned outages.

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

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

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

Corporate

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

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

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

Liquidity and Capital Resources

Funds Generated from Operations

Funds generated from operations were $539 million and $1,056 million for the three and six months ended June 30, 2006, respectively, compared with $498 million and $918 million for the same periods in 2005.

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

Investing Activities

In the three and six months ended June 30, 2006, capital expenditures totalled $327 million (2005 – $135 million) and $630 million (2005 – $243 million), respectively, and related primarily to the restart and refurbishment of Bruce A Units 1 and 2, construction of new power plants, construction of the Tamazunchale pipeline and Edson natural gas storage facilities as well as maintenance and other capacity capital in the Pipelines business.

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

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

Financing Activities

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

Dividends

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

Contractual Obligations

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

Financial and Other Instruments

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

Energy Price Risk Management

The company executes power and natural gas derivatives for overall management of its asset portfolio. The fair value and notional volumes of contracts for differences and the swap, future and option contracts are shown in the tables below.

Asset/(Liability)

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

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

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

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

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

Power - swaps and contracts for differences	Hedge	2,566	7,780	—	—
	Non-hedge	1,332	456	—	—

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

Risk Management

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

Controls and Procedures

As of June 30, 2006, TransCanada’s management, together with TransCanada’s President and Chief Executive Officer and Chief Financial

Officer, evaluated the effectiveness of the design and operation of the company’s disclosure controls and procedures. Based on this evaluation, the President and Chief Executive Officer and the Chief Financial Officer of TransCanada have concluded that the disclosure controls and procedures are effective.

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

Critical Accounting Policy

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

Critical Accounting Estimates

Since a determination of many assets, liabilities, revenues and expenses is dependent upon future events, the preparation of the company’s consolidated financial statements requires the use of estimates and assumptions which have been made using careful judgment. TransCanada’s critical accounting estimate from December 31, 2005 continues to be depreciation expense. For further information on this critical accounting estimate, refer to the MD&A in TransCanada’s 2005 Annual Report.

Outlook

In 2006, TransCanada expects higher net income than originally anticipated due to the favourable impact of Canadian federal and provincial corporate income tax rate reductions and the net income from discontinued operations as a result of bankruptcy settlements received from Mirant. Excluding these impacts, the company’s outlook is relatively unchanged since December 31, 2005. For further information on outlook, refer to the MD&A in TransCanada’s 2005 Annual Report.

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

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

Other Recent Developments

Pipelines

Wholly-Owned Pipelines

Canadian Mainline

In March 2006, TransCanada reached a settlement with its customers and other interested parties with respect to its 2006 tolls on the Canadian Mainline. On March 15, 2006, TransCanada filed its application with the NEB for approval of this settlement and associated tolls. On April 28, 2006, the NEB approved the application as filed, thereby setting the current interim tolls in effect as final tolls for 2006.

Alberta System

In February 2006, the EUB issued its decision on the 2005 General Rate Application (GRA) Phase II which determined the allocation of 2005 approved costs among transportation services and rate design. The decision approved the 2005 rate design as applied for.

In March 2006, TransCanada filed for 2005 Final Rates and 2006 Final Rates with the EUB. The 2005 Final Rates as filed are the same as the 2005 Interim Rates since there were no changes to the rate design required in the EUB decision on the 2005 GRA Phase II. The 2006 Final Rates filed with the EUB are based on the 2006 revenue requirement, including deferrals from 2005 in accordance with the Alberta System three year settlement, a revised throughput forecast and the approved rate design. The EUB approved both the 2005 and 2006 Final Rates. The 2006 Final Rates were effective April 1, 2006.

Gas Transmission Northwest System

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

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

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

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

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

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

Other Pipelines

In April 2006, PipeLines LP closed its acquisition of an additional 20 per cent general partnership interest in Northern Border for US$307 million bringing its total general partnership interest to 50 per cent. As part of the transaction, PipeLines LP indirectly assumed approximately US$120 million of debt of Northern Border. Of the total purchase price, US$114 million was allocated to goodwill and the remainder was allocated primarily to plant, property and equipment. Northern Border became a jointly controlled entity and TransCanada commenced proportionately consolidating its investment in Northern Border on a prospective basis as of April 2006. As part of the transaction, and effective by early second quarter 2007, a subsidiary of TransCanada will become the operator of Northern Border which is currently operated by a subsidiary of ONEOK.

Concurrent with this transaction, TransCanada closed the sale of its 17.5 per cent general partner interest in Northern Border Partners, L.P. to a subsidiary of ONEOK, for net proceeds of approximately US$30 million, resulting in an after-tax gain of $13 million. The net gain was recorded in the Pipelines segment and the company recorded a $10 million income tax charge, including $12 million of current income tax expense, on this transaction.

Northern Development

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

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

Keystone Pipeline

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

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

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

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

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

Energy

Bruce Power

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

Cartier Wind

In June 2006, Cartier Wind began construction on the 100.5 MW Anse à Valleau wind farm, the second of the six wind farms that comprise the Cartier Wind project in the Gaspé region of Québec. The Anse à Valleau wind farm is expected to deliver energy to the Hydro-Québec grid by December 2007. Construction continues on the 109.5 MW Baie des Sable wind farm and remains on schedule for completion in December 2006. TransCanada has a 62 per cent interest in the Cartier Wind project which was awarded six projects by Hydro-Québec Distribution in October 2004 representing a total of 739.5 MW.

Portlands Energy Centre

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

Bécancour

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

Liquefied Natural Gas

In early April 2006, Cacouna Energy, a partnership between TransCanada and Petro-Canada, awarded a contract for front-end engineering and design work to an international consortium of engineering and construction firms with experience in the development of LNG receiving terminals. The project’s next significant milestone was reached on June 15, 2006 with completion of hearings before a joint review panel of the Canadian Environmental Assessment Agency and Québec’s Bureau d’audiences publiques sur l’environnement. Regulatory decisions are expected by the end of 2006 and the facility is expected to be operational in late 2009 or early 2010.

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

Natural Gas Storage

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

Share Information

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

Selected Quarterly Consolidated Financial Data(1)
(unaudited)

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

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

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

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

Dividend declared per common share	$	0.32	$	0.32	$	0.305	$	0.305	$	0.305	$	0.305	$	0.29	$	0.29

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

Factors Impacting Quarterly Financial Information

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

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

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

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

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

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

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

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

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

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

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