EX-99.1 2 a06-3783_1ex99d1.htm NEWS RELEASE DATED JANUARY 31, 2006

Exhibit 99.1

News Release dated January 31, 2006

TransCanada Corporation

Media Inquiries:	Jennifer Varey	(403) 920-7859
		(800) 608-7859
Analyst Inquiries:	David Moneta/Myles Dougan	(403) 920-7911

News Release

TransCanada Reports 2005 Net Income of $1.2 Billion

Board of Directors Increases Quarterly Dividend

CALGARY, Alberta –January 31, 2006 – (TSX: TRP) (NYSE: TRP)

Fourth Quarter and Year-End 2005 Financial Highlights

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

• Quarterly dividend of $0.32 per common share declared by the Board of Directors, an increase of five per cent

• Net income, excluding gains, for fourth quarter 2005 of $235 million or $0.48 per share, an increase of 27 per cent

• Net income, excluding gains, for the year ended December 31, 2005 of $852 million or $1.75 per share, an increase of eight per cent

• Funds generated from operations for fourth quarter 2005 of $530 million, an increase of 12 per cent; for the year ended December 31, 2005, $1,951 million, an increase of 15 per cent

The Board of Directors of TransCanada Corporation (TransCanada or the company) today declared a quarterly dividend of $0.32 per common share for the quarter ending March 31, 2006, a five per cent increase over the $0.305 paid in each of the previous four quarters. The dividend is payable on April 28, 2006 to shareholders of record at the close of business on March 31, 2006. This is the sixth consecutive annual increase in the common share dividend.

TransCanada today announced net income and net income from continuing operations (net earnings) for fourth quarter 2005 of $350 million or $0.72 per share. Excluding an after-tax gain of $115 million or $0.24 per share from the sale of the company’s interest in PT Paiton Energy Company (Paiton Energy), net earnings were $235 million or $0.48 per share, an increase of $50 million or $0.10 per share compared to $185 million or $0.38 per share for fourth quarter 2004.

For the year ended December 31, 2005, TransCanada’s net income was $1,209 million or $2.49 per share compared to $1,032 million or $2.13 per share for 2004. Net earnings for 2005 included gains

related to the sales of TransCanada Power, L.P. (Power LP), Paiton Energy and units of TC PipeLines, LP (PipeLines, LP), while net earnings for 2004 included gains on sales of the ManChief and Curtis Palmer assets to Power LP and the company’s equity interest in Millenium. Excluding total gains of $357 million recorded in 2005 and total gains of $194 million recorded in 2004, net earnings for 2005 of $852 million or $1.75 per share increased $66 million or $0.13 per share compared to 2004.

Funds generated from operations for fourth quarter 2005 were $530 million, an increase of $55 million compared to fourth quarter 2004. Funds generated from operations for the year ended December 31, 2005 were $1,951 million, an increase of $248 million compared to 2004.

“TransCanada’s strong 2005 results are the direct result of significant capital investments over the past six years,” said Hal Kvisle, TransCanada’s chief executive officer. “We have invested approximately $8.5 billion over that period to grow our North American gas transmission and power businesses. In doing so, we have sustained our gas transmission earnings and built a substantial and profitable power generation business.

“Events over the past year have reinforced the critical need for new gas and power infrastructure in many parts of North America. TransCanada continues to play a vital role in the continental energy market through our extensive natural gas transmission network and our growing fleet of power generation facilities,” said Mr. Kvisle.

“In 2005, TransCanada invested approximately $2.1 billion in our core businesses. Notable acquisitions included the Sheerness Power Purchase Arrangement and the Northeast US Hydro assets. Key development projects include Bruce Power, the Bécancour cogeneration plant, the Cartier Wind power project and the Keystone oil pipeline. Longer-term initiatives relate to the transmission of northern natural gas and the development of liquefied natural gas facilities. Acquisitions, active projects and longer-term initiatives will all contribute to further strengthening our position as a leading North American energy infrastructure company.

“Our success is the direct result of our expertise in our core businesses, our experience in the responsible and reliable operation of large-scale energy infrastructure, and our financial strength. For our shareholders, that has meant another year of solid growth in earnings and cash flow, and a total annual return on their investment of approximately 28 per cent. For the sixth year in a row, confidence in our growth prospects has enabled TransCanada’s Board of Directors to increase the dividend paid to shareholders to $1.28 on an annual basis,” said Mr. Kvisle.

During the fourth quarter of 2005 and the first month of 2006, TransCanada:

FOURTH QUARTER NEWS RELEASE 2005

• Announced in October that Bruce Power (being the collective investments in Bruce Power A L.P. (Bruce A) and Bruce Power L.P. (Bruce B)) and the Ontario Power Authority (OPA), a Crown Corporation of the Province of Ontario, entered into a long-term agreement on the restart and refurbishment of the Bruce A units. The capital program for the restart and refurbishment work is expected to total approximately $4.25 billion. As owner of a 47.9 per cent interest in the newly formed Bruce A (along with BPC Generation Infrastructure Trust (BPC) – 47.9 per cent, and the Power Workers’ Union Trust No. 1 and The Society of Energy Professionals Trust – together, 4.2 per cent) TransCanada’s approximate share of the capital program is $2.125 billion and will be financed through capital contributions to 2011. With the restart of Units 1 and 2, Bruce Power’s output capacity is expected to rise by approximately 1,500 megawatts (MW) to more than 6,200 MW.

• In November, signed a Memorandum of Understanding with ConocoPhillips Company and ConocoPhillips Pipe Line Company (CPPL) (a wholly owned subsidiary of ConocoPhillips Company) which commits ConocoPhillips Company to ship crude oil on the proposed Keystone oil pipeline (Keystone), and gives CPPL the right to acquire up to a fifty per cent participating interest in the pipeline. On January 31, 2006, TransCanada announced it has secured firm, long-term contracts totalling 340,000 barrels per day through the binding Open Season held during the fourth quarter. The Keystone pipeline, expected to cost approximately US$2.1 billion, will be capable of transporting approximately 435,000 barrels per day of crude oil from Hardisty, Alberta to Patoka, Illinois through a 2,950 kilometre pipeline system.

• Acquired the remaining rights and obligations of the 756 megawatt Sheerness Power Purchase Arrangement (PPA) from the Alberta Balancing Pool for $585 million. The remaining term of the PPA is approximately 15 years. The acquisition closed on December 30, 2005.

• Closed the sale of its 11 per cent interest in Paiton Energy to subsidiaries of The Tokyo Electric Power Company for gross proceeds of US$103 million ($122 million). Paiton Energy owns two 615 MW coal-fired power plants in East Java, Indonesia.

• Received support from the Canadian Association of Petroleum Producers (CAPP) and other stakeholders for an increase in the deemed common equity ratio from 30 per cent to 36 per cent on TransCanada’s Foothills and BC Systems, effective January 1, 2006. On December 21, 2005, The National Energy Board (NEB) approved the Foothills System 2006 tolls, reflecting a deemed common equity of 36 per cent, as final tolls. BC System tolls have been authorized on an interim basis, with no issues raised with respect to the capital structure.

• Continued to advance the Bécancour and Cartier Wind power projects. Construction of the 550 MW Bécancour cogeneration

plant near Trois Rivières, Québec remains on schedule to begin operations in September 2006. The 740 MW Cartier Wind project, 62 per cent owned by TransCanada, continued to award construction contracts in November and December and construction is scheduled to begin in March 2006. Located in the Gaspésie region of Québec, the first of the six projects that make up Cartier Wind is anticipated to be operational beginning in December 2006 with the remaining projects continuing through 2012.

• Issued, in January 2006, through its wholly owned subsidiary TransCanada PipeLines Limited (TCPL), $300 million of five-year medium-term notes bearing interest of 4.3 per cent under its Canadian base shelf program. Proceeds from the offering were used to reduce commercial paper outstanding.

• On behalf of the Broadwater Energy project, filed a formal application on January 30, 2006 with the U.S. Federal Energy Regulatory Commission (FERC) for federal approval to construct and operate the Broadwater project. The proposed facility, which would be located in the New York State waters of Long Island Sound, would be capable of receiving, storing, and re-gasifying imported liquefied natural gas with an average annual send-out capacity of approximately one billion cubic feet (bcf) a day of natural gas. The estimated cost of construction is US$700 million to US$1 billion. Broadwater is being developed jointly by TransCanada and Shell US Gas and Power.

• The Mackenzie Gas Pipeline Project has continued to progress. The public hearings phase of the regulatory process commenced in late January 2006 and is expected to continue throughout the year.

Results of Operations

Operating Results	Three months ended December 31				Year ended December 31
(millions of dollars)	2005		2004		2005		2004

Revenues	1,771		1,480		6,124		5,497
Net Income
Continuing operations	350		185		1,209		980
Discontinued operations	—		—		—		52
	350		185		1,209		1,032
Cash Flows
Funds generated from operations	530		475		1,951		1,703
Increase/(decrease) in working capital	124		(23	)	(49	)	29
Net cash provided by operations	654		452		1,902		1,732

Capital expenditures	(345	)	(203	)	(754	)	(530	)
Acquisitions, net of cash acquired	(685	)	(1,453	)	(1,317	)	(1,516	)
Dispositions, net of current tax	125		2		671		410

	Three months ended December 31				Year ended December 31
Common Share Statistics	2005		2004		2005		2004

Net Income Per Share – Basic
Continuing operations	$	0.72	$	0.38	$	2.49	$	2.02
Discontinued operations	—		—		—		0.11
	$	0.72	$	0.38	$	2.49	$	2.13

Dividends Declared Per Share	$	0.305	$	0.29	$	1.22	$	1.16

Common Shares Outstanding (millions)
Average for the period – Basic	487.1		484.7		486.2		484.1
End of period	487.2		484.9		487.2		484.9

Consolidated

Segment Results-at-a–Glance	Three months ended December 31						Year ended December 31
(millions of dollars except per share amounts)	2005			2004			2005			2004
Gas Transmission Net Earnings
Excluding gains	160			157			635			579
Gain on sale of PipeLines LPunits	—			—			49			—
Gain on sale of Millennium	—			—			—			7
	160			157			684			586
Power Net Earnings
Excluding gains	82			31			253			209
Gain on sale of Paiton Energy	115			—			115			—
Gains related to Power L P	—			—			193			187
	197			31			561			396
Corporate	(7		)	(3		)	(36		)	(2		)

Net Income
Continuing Operations (1)	350			185			1,209			980
Discontinued Operations	—			—			—			52
	350			185			1,209			1,032
Net Income Per Share
Continuing Operations (2)	$	0.72		$	0.38		$	2.49		$	2.02
Discontinued Operations	—			—			—			0.11
Basic	$	0.72		$	0.38		$	2.49		$	2.13
Diluted	$	0.71		$	0.38		$	2.47		$	2.12
(1) Net Income from Continuing Operations:
Excluding gains	235			185			852			786
Gains related to Paiton Energy, PipeLines LP, Power LP and Millennium	115			—			357			194
	350			185			1,209			980
(2) Net Income Per Share from Continuing Operations :
Excluding gains	$	0.48		$	0.38		$	1.75		$	1.62
Gains related to Paiton Energy, PipeLines LP, Power LP and Millennium	0.24			—			0.74			0.40
	$	0.72		$	0.38		$	2.49		$	2.02

Net income and net earnings for fourth quarter 2005 of $350 million or $0.72 per share increased by $165 million or $0.34 per share compared to $185 million or $0.38 per share for fourth quarter 2004. This increase was due to significantly higher net earnings from the Power business, including an after-tax gain of $115 million or $0.24 per share from the sale of Paiton Energy.

Excluding the $115 million gain on sale of Paiton Energy, net income and net earnings for fourth quarter 2005 increased $50 million or $0.10 per share compared to fourth quarter 2004, to $235 million or $0.48 per share. This was due to increases of $51 million and $3 million in net earnings from the Power and Gas Transmission businesses, respectively, partially offset by an increase of $4 million in net expenses in the Corporate segment.

The increase in Power’s net earnings was primarily due to higher operating and other income from Bruce Power and Eastern Operations. The increase in net earnings from the Gas Transmission business was primarily due to higher earnings from the Gas Transmission Northwest System and the North Baja System (collectively GTN), acquired on November 1, 2004. Corporate’s net expenses increased in fourth quarter 2005 compared to fourth quarter 2004 primarily due to increased net interest costs, partially offset by an income tax refund in fourth quarter 2005.

TransCanada’s net income for the year ended December 31, 2005 was $1,209 million or $2.49 per share compared to $1,032 million or $2.13 per share for 2004. Net income for 2004 included net income from discontinued operations of $52 million or $0.11 per share.

TransCanada’s net earnings for the year ended December 31, 2005 were $1,209 million or $2.49 per share compared to $980 million or $2.02 per share for 2004. Net earnings for 2005 included after-tax gains of $193 million on the sale of the company’s interest in Power LP, $115 million on the sale of Paiton Energy and $49 million on the sale of PipeLines LP units, while net earnings for 2004 included after-tax gains of $187 million on the sale of the ManChief and Curtis Palmer assets to Power LP and the recognition of dilution gains resulting from a reduction in TransCanada’s ownership interest in Power LP and other previously deferred gains, as well as a $7 million after-tax gain on sale of the company’s equity interest in Millennium.

Excluding the total gains of $357 million recorded in 2005 and total gains of $194 million recorded in 2004, net earnings for 2005 of $852 million or $1.75 per share increased $66 million or $0.13 per share compared to 2004. This was mainly due to an increase in net earnings from the Gas Transmission and Power businesses, partially offset by an increase in net expenses in the Corporate segment.

Excluding the gains on sales of PipeLines LP units in 2005 and the Millennium interest in 2004, the $56 million increase in net earnings from the Gas Transmission business for 2005 compared to 2004 was primarily attributable to a $57 million increase as a result of a full year of net earnings from GTN. In addition, Gas Transmission’s net earnings for 2005 included approximately $35 million ($13 million related to 2004 and $22 million related to the year ended December 31, 2005) as a result of the April 2005 NEB decision on the Canadian Mainline’s 2004 Tolls and Tariff Application (Phase II). This decision dealt with capital structure and included an increase in the deemed common equity ratio to 36 per cent from 33 per cent for 2004, which was also effective for 2005 under the 2005 tolls settlement. The increase in Canadian Mainline’s earnings for 2005 as a result of this NEB decision was partially offset by a combination of a lower average investment base, lower earnings related to operating cost savings and a decrease in the approved rate of return on common equity (ROE) in 2005 compared to 2004. These increases in net earnings

were partially offset by lower earnings from TransCanada’s Other Gas Transmission businesses.

Excluding the above-mentioned gains related to the company’s investments in Power LP in 2004 and 2005 and Paiton Energy in 2005, Power’s net earnings for 2005 increased $44 million as a result of higher operating and other income from Bruce Power and Eastern Operations, partially offset by lower contributions from Western Operations and higher general, administrative, support costs and other.

The increase in net expenses of $34 million in the Corporate segment in 2005 compared to 2004 was primarily due to increased interest expense on higher average long-term debt and commercial paper balances in 2005 as well as the release in third quarter 2004 of previously established restructuring provisions.

Funds generated from operations of $530 million for fourth quarter 2005 increased $55 million compared to fourth quarter 2004. Funds generated from operations of $1,951 million for the year ended December 31, 2005 increased $248 million when compared to 2004.

Gas Transmission

The Gas Transmission business generated net earnings of $160 million and $684 million for the three months and year ended December 31, 2005, respectively, compared to $157 million and $586 million for the comparable periods in 2004.

Gas Transmission Results-at-a–Glance	Three months ended December 31				Year ended December 31
(millions of dollars)	2005		2004		2005		2004
Wholly-Owned Pipelines
Canadian Mainline	67		71		283		272
Alberta System	38		40		150		150
GTN (1)	18		14		71		14
Foothills System	5		5		21		22
BC System	1		2		6		7
	129		132		531		465
Other Gas Transmission
Great Lakes	10		12		46		55
Iroquois	3		3		17		17
PipeLines LP	2		3		9		16
Portland	4		4		11		10
Ventures LP	3		5		12		15
TQM	2		2		7		8
CrossAlta	7		7		19		13
TransGas	3		2		11		11
Northern Development	(1	)	(3	)	(4	)	(6	)
General, administrative, support costs and other	(2	)	(10	)	(24	)	(25	)
	31		25		104		114
Gain on sale of PipeLines LP units	—		—		49		—
Gain on sale of Millennium	—		—		—		7
	31		25		153		121
Net Earnings	160		157		684		586

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

Wholly-Owned Pipelines

The Canadian Mainline’s fourth quarter 2005 net earnings decreased $4 million compared to fourth quarter 2004. The decrease in net earnings was due to a combination of a lower average investment base in 2005, a lower approved rate of return on common equity of 9.46 per cent in 2005 compared to 9.56 per cent in 2004 and lower operating cost savings in 2005 compared to 2004, partially offset by an increase in the deemed common equity ratio. The NEB’s decision on the Canadian Mainline’s 2004 Tolls and Tariff Application (Phase II) in April 2005 included an increase in the deemed common equity ratio from 33 to 36 per cent for 2004 which was also effective for 2005 under the 2005 tolls settlement. Net earnings for the year ended December 31, 2005 increased $11 million compared to 2004. As a result of the NEB decision that increased the deemed common equity to 36 per cent from 33 per cent, Canadian Mainline’s 2005 net earnings increased $35 million ($13 million related to 2004 and $22 million related to 2005) compared to 2004 net earnings. This earnings increase was partially offset by the combination of a lower average investment base, lower operating cost savings in 2005 compared to 2004 and the lower approved ROE in 2005.

The Alberta System’s net earnings of $38 million in fourth quarter 2005 decreased $2 million compared to $40 million in fourth quarter 2004. Net earnings of $150 million for the year ended December 31, 2005 were consistent with net earnings for 2004. The decrease in fourth quarter net earnings was primarily due to a lower investment base and a lower approved ROE in 2005. Net earnings for the year remained unchanged as the impacts of a lower investment base and a lower approved ROE in 2005 were offset by the impact on 2004 net earnings of disallowed costs in the Alberta Energy and Utilities Board (EUB) decision on Phase 1 of the 2004 General Rate Application (GRA). Net earnings in 2004 and 2005 reflect an ROE of 9.60 and 9.50 per cent, respectively, as prescribed by the EUB, on deemed common equity of 35 per cent.

GTN was acquired by TransCanada on November 1, 2004 and generated net earnings of $18 million and $71 million for the three months and year ended December 31, 2005, respectively, compared to $14 million for the two months ended December 31, 2004.

Operating Statistics

Canadian

Gas Transmission

Year ended

Mainline (1)

Alberta System (2)

Northwest System (3)

Foothills System

BC System

December 31

2005

2004

2005

2004

2005

2004

2005

2004

2005

2004

Average investment base ($ millions)

7,807

8,196

4,446

4,619

n/a

n/a

680

714

216

228

Delivery volumes (Bcf)

Total

2,997

2,621

3,999

3,909

777

181

1,051

1,139

321

360

Average per day

8.2

7.2

11.0

10.7

2.1

3.0

2.9

3.1

0.9

1.0

(1) Canadian Mainline deliveries originating at the Alberta border and in Saskatchewan in 2005 were 2,215 Bcf (2004 – 2,017 Bcf); average per day was 6.1 Bcf (2004 – 5.5 Bcf).

(2) Field receipt volumes for the Alberta System in 2005 were 4,034 Bcf (2004 – 3,952 Bcf); average per day was 11.1 Bcf (2004 – 10.8 Bcf).

(3) TransCanada acquired the Gas Transmission Northwest System on November 1, 2004. The delivery volumes for 2004 represent November and December 2004 throughput. The system is currently operating under a fixed rate model approved by FERC and, as a result, the system’s current results are not dependent on average investment base.

Other Gas Transmission

TransCanada’s proportionate share of net earnings from Other Gas Transmission was $31 million for the three months ended December 31, 2005 compared to $25 million for the same period in 2004. The $6 million increase compared to the prior period was primarily due to lower project development costs expensed in fourth quarter 2005 resulting from capitalization of costs of the Broadwater and Keystone projects in 2005 and higher earnings from Gas Pacifico. These increases were partially offset by lower earnings from Great Lakes and Ventures LP.

Net earnings from Other Gas Transmission for the year ended December 31, 2005 were $153 million compared to $121 million for 2004. Excluding the gain on sale of PipeLines LP units in 2005 and Millennium in 2004, net earnings for 2005 were $10 million

lower compared to 2004. The decrease was due to lower net earnings from Great Lakes as a result of lower short-term revenues and higher operating and maintenance costs, and lower net earnings from PipeLines LP as a result of the reduced ownership interest. Results were also negatively impacted by a weaker U.S. dollar in 2005. These decreases were partially offset by higher earnings from CrossAlta as a result of increased capacity and favourable natural gas storage market conditions in 2005.

As at December 31, 2005, TransCanada had $87 million of advances to the Aboriginal Pipeline Group (APG) with respect to the Mackenzie Gas Pipeline Project, and had capitalized $19 million of costs related to the Broadwater project and $6 million related to the Keystone project.

Power

Power Results-at-a–Glance	Three months ended December 31				Year ended December 31
(millions of dollars)	2005		2004		2005		2004
Bruce Power	53		5		195		130
Western operations	33		25		123		138
Eastern operations	68		31		137		108
Power LP investment	—		7		29		29
General, administrative, support costs and other	(28	)	(19	)	(102	)	(89	)
Operating and other income	126		49		382		316
Financial charges	(4	)	(4	)	(11	)	(13	)
Income taxes	(40	)	(14	)	(118	)	(94	)
	82		31		253		209
Gains related to Power LP and Paiton Energy	115		—		308		187
Net Earnings	197		31		561		396

Power’s net earnings of $197 million in fourth quarter 2005 increased $166 million compared to $31 million in fourth quarter 2004. The gain on sale of Paiton Energy accounted for $115 million of this increase. Excluding this gain, Power’s net earnings in fourth quarter 2005 of $82 million increased $51 million compared to the same period in 2004, primarily due to higher operating and other income from Bruce Power and Eastern Operations.

Bruce Power’s contribution to operating and other income increased by $48 million in fourth quarter 2005 compared to fourth quarter 2004, primarily due to higher realized power prices on uncontracted volumes sold into Ontario’s wholesale spot market, higher generation volumes and an increased ownership interest in the Bruce A facilities effective October 31, 2005.

Western Operations’ operating and other income was $8 million higher in fourth quarter 2005 compared to fourth quarter 2004 primarily due to increased margins in fourth quarter 2005 as a

result of higher market heat rates on uncontracted volumes of power sold. Partially offsetting this increase was lower contributions from the Bear Creek cogeneration facility which remained on an unplanned outage throughout the quarter.

Eastern Operations’ operating and other income was $37 million higher in fourth quarter 2005 compared to fourth quarter 2004 primarily due to contributions from TransCanada Hydro Northeast, Inc. (TC Hydro), which holds the hydroelectric generation assets acquired from USGen New England, Inc. on April 1, 2005, and from the Grandview cogeneration facility placed into service in January 2005. Partially offsetting these increases was a fourth quarter 2004 positive impact due to a restructuring transaction relating to Ocean State Power (OSP) power purchase contracts and the loss of operating income associated with the expiration of certain long-term sales contracts in 2004.

General, administrative, support costs and other increased $9 million in fourth quarter 2005 compared to fourth quarter 2004 primarily due to higher business development costs expensed in 2005 and the positive impact in fourth quarter 2004 of the recognition of unrealized foreign exchange gains on Power LP’s U.S. dollar denominated debt.

Net earnings for the year ended December 31, 2005 of $561 million increased $165 million compared to $396 million in 2004. Excluding the gain on sale of Paiton Energy of $115 million in 2005 and gains related to Power LP of $193 million and $187 million in 2005 and 2004, respectively, Power’s net earnings for the year ended December 31, 2005 of $253 million increased $44 million compared to $209 million in 2004. The increase was primarily due to higher operating and other income from Bruce Power and Eastern Operations, partially offset by reduced contributions from Western Operations and higher general, administrative, support costs and other.

Bruce Power

On October 31, 2005, Bruce Power and the OPA, completed a long-term agreement whereby Bruce A will refurbish and restart the currently idle Units 1 and 2, extend the operating life of Unit 3 by replacing its steam generators and fuel channels when required and replace the steam generators on Unit 4. As a result of the agreement between Bruce Power and the OPA, and Cameco Corporation’s decision not to participate in the restart and refurbishment program, a new partnership was created. The new Bruce A partnership subleases the Bruce A facilities, which are comprised of Units 1 to 4, from Bruce B. The effect of these transactions was that TransCanada and BPC each incurred a net cash outlay of approximately $100 million after each receiving a special distribution of $200 million. As at December 31, 2005, TransCanada and BPC each owned a 47.9 per cent interest in Bruce A. The remaining 4.2 per cent is owned by the Power Workers’ Union Trust No. 1 and The Society of Energy Professionals Trust.

The day-to-day operations of the Bruce Power facility are expected to be unaffected by the formation of the Bruce A partnership and TransCanada continues to own 31.6 per cent of the Bruce B Units 5 to 8.

Upon reorganizing, both Bruce A and Bruce B became jointly controlled entities and TransCanada proportionately consolidated these investments on a prospective basis from October 31, 2005. The following Bruce Power financial results reflect the operations of the full six-unit operation for all periods. The Bruce Power information below includes adjustments to eliminate the effects of intercompany transactions between Bruce A and Bruce B.

Bruce Power Results-at-a-Glance

	Three months ended December 31						Year ended December 31
(millions of dollars)	2005			2004			2005			2004
Bruce Power (100 per cent basis)
Revenues
Power	476			351			1,907			1,563
Other (1)	13			4			35			20
	489			355			1,942			1,583
Operating expenses
Operations and maintenance	(231		)	(244		)	(871		)	(793		)
Fuel	(19		)	(17		)	(77		)	(68		)
Supplemental rent	(41		)	(40		)	(164		)	(156		)
Depreciation and amortization	(53		)	(44		)	(198		)	(161		)
	(344		)	(345		)	(1,310		)	(1,178		)
Operating income	145			10			632			405
Financial charges under equity accounting – to October 31, 2005	(6		)	(17		)	(58		)	(67		)
	139			(7		)	574			338
TransCanada’s proportionate share	51			(2		)	188			107
Adjustments	2			7			7			23
TransCanada’s operating and other income from
Bruce Power (2)	53			5			195			130

Bruce Power – Other Information
Plant availability	79		%	72		%	80		%	82		%
Sales volumes (GWh) (3)
Bruce Power – 100 per cent	8,300			7,500			32,900			33,600
TransCanada’s proportionate share	2,946			2,351			10,732			10,608
Results per MWh (4)
Power revenues	$	57		$	47		$	58		$	47
Fuel	$	2		$	2		$	2		$	2
Total operating expenses (5)	$	41		$	46		$	40		$	35
Percentage of output sold to spot market	35		%	47		%	49		%	52		%

(1) Includes fuel cost recoveries for Bruce A of $4 million for the three months and year ended December 31, 2005.

(2) TransCanada’s consolidated equity income includes $168 million and $26 million which represents TransCanada’s 31.6 per cent share of Bruce Power earnings for the ten months and one month ended October 31, 2005, respectively.

(3) Gigawatt hours

(4) Megawatt hours

(5) Net of cost recoveries

TransCanada’s operating and other income from its combined investment in Bruce Power increased $48 million in fourth quarter 2005 compared to fourth quarter 2004, primarily due to higher realized power prices on uncontracted volumes sold into Ontario’s wholesale spot market, higher generation volumes and an increased ownership interest in Bruce A. TransCanada’s share of Bruce Power’s combined generation for fourth quarter 2005 increased 595 GWh to 2,946 GWh compared to fourth quarter 2004 generation of 2,351 GWh as a result of fewer planned maintenance outage days in fourth quarter 2005 than during the same period in 2004.

Combined Bruce Power prices achieved during fourth quarter 2005 (excluding other revenues) were $57 per MWh, compared to $47 per MWh in fourth quarter 2004. Combined Bruce Power operating expenses (net of fuel cost recoveries) in fourth quarter 2005 decreased to $41 per MWh from $46 MWh in fourth quarter 2004 primarily due to increased output in fourth quarter 2005.

Approximately 66 reactor days of planned maintenance outages as well as 35 reactor days of unplanned outages occurred on the six operating units in fourth quarter 2005. In fourth quarter 2004, Bruce Power experienced 100 reactor days of planned maintenance outages and 35 reactor days of unplanned outages. The Bruce Power units ran at a combined average availability of 79 per cent in fourth quarter 2005, compared to a 72 per cent average availability during fourth quarter 2004. Unit 5 returned to service in December 2005 after a 75 day outage, including a nine day unplanned extension to the outage. During fourth quarter 2005, there were minor unplanned outages on Units 3, 4 and 6. All of those units were returned to service during the quarter and as at December 31, 2005, all six Bruce Power units were operating.

TransCanada’s operating and other income from its combined investment in Bruce Power for the year ended December 31, 2005 was $195 million compared to $130 million for 2004. The increase of $65 million was primarily due to higher realized prices in 2005 and was offset in part by higher maintenance costs, higher depreciation and lower capitalization of labour and other in-house costs following the restart of Unit 3 in first quarter 2004. Adjustments to TransCanada’s combined interest in Bruce Power’s income before income taxes for the three months and year ended December 31, 2005 were lower than in the comparable periods in 2004 primarily due to a lower amortization of the purchase price allocated to the fair value of sales contracts in place at the time of acquisition.

Combined Bruce Power prices achieved during the year ended December 31, 2005 (excluding other revenues) were $58 per MWh compared to $47 per MWh in 2004. Bruce Power’s combined operating expenses (net of fuel cost recoveries) increased to $40 per MWh for the year ended December 31, 2005 from $35 per MWh in 2004. This was primarily the result of one additional planned maintenance outage in 2005 compared to 2004 as well as higher maintenance costs, higher depreciation and lower capitalization of

labour and other in-house costs following the restart of Unit 3. The Bruce units ran at a combined average availability of 80 per cent in 2005, compared to 82 per cent in 2004.

Income from Bruce B is directly impacted by fluctuations in wholesale spot market prices for electricity and 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. To reduce its exposure to spot market prices, Bruce B has entered into fixed price sales contracts to sell forward approximately 13 terawatt hours (TWh) of 2006 output and 3.6 TWh of 2007 output. As a result of the contract with the OPA, all of the output from Bruce A will be sold at a fixed price of $57.37 per MWh, before recovery of fuel costs from the OPA. Under the terms of the arrangement between Bruce A and the OPA, effective October 31, 2005 Bruce A receives a contract price for power generated, where the price is adjusted for inflation annually on April 1 and capital cost variances associated with the restart and refurbishment project but will not vary with changes in the wholesale price of power in the Ontario market. The Bruce A fixed price may also be adjusted to reflect cost savings and cost overruns associated with the Bruce A restart and refurbishment project. As part of this contract, sales from the Bruce B Units 5 to 8 are subject to a floor price of $45 per MWh, adjusted annually for inflation on April 1. Receipts by Bruce B under this floor price mechanism are refundable if prices subsequently increase above the floor price.

The overall plant availability percentage in 2006, for planning purposes, is 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 outage on Bruce A Unit 3 is scheduled to last approximately one month during first quarter 2006 and a two month planned maintenance outage of Bruce A Unit 4 is expected to commence in second quarter 2006. 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.

Bruce Power made cash distributions, excluding the special distribution, of $185 million to its partners in fourth quarter 2005. TransCanada’s share was $58 million. For the year ended December 31, 2005, cash distributions, excluding the special distribution, to partners were $400 million of which TransCanada’s share was $126 million. No distributions were made to partners in 2004. The partners have agreed that all excess cash from both Bruce A and Bruce B will be distributed on a monthly basis and that separate cash calls will be made for major capital projects, including the Bruce A refurbishment project.

Bruce Power’s capital program for the restart and refurbishment work is expected to total approximately $4.25 billion and TransCanada’s approximate $2.125 billion share will be financed through capital contributions to 2011. A capital cost risk and reward sharing schedule with OPA is in place for spending below or in excess of the $4.25 billion base case estimate. Work to

restart Units 1 and 2 has commenced with the first unit expected to be online in 2009, subject to approval by the Canadian Nuclear Safety Commission. Restarting Units 1 and 2, which have a combined capacity of approximately 1,500 MW, will boost the Bruce facilities’ overall output to more than 6,200 MW. As at December 31, 2005, Bruce A had capitalized $324 million with respect to the refurbishment project.

Western Operations

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

	Three months ended December 31				Year ended December 31
(millions of dollars)	2005		2004		2005		2004
Revenue
Power	235		160		715		606
Other (2)	50		33		158		120
	285		193		873		726
Cost of sales
Power	(163	)	(103	)	(476	)	(377	)
Other (3)	(37	)	(17	)	(104	)	(64	)
	(200	)	(120	)	(580	)	(441	)
Other costs and expenses	(47	)	(43	)	(149	)	(125	)
Depreciation	(5	)	(5	)	(21	)	(22	)
Operating and other income	33		25		123		138

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

(2) Includes Cancarb Thermax and natural gas sales.

(3) Includes the cost of natural gas sold.

Western Operations Sales Volumes (1)

	Three months ended December 31		Year ended December 31
(GWh)	2005	2004	2005	2004
Supply
Generation	554	673	2,245	2,105
Purchased
Sundance A & B PPAs	1,837	1,757	6,974	6,842
Other purchases	684	706	2,687	2,748
	3,075	3,136	11,906	11,695
Contracted vs. Spot
Contracted	2,804	2,848	10,374	10,705
Spot	271	288	1,532	990
	3,075	3,136	11,906	11,695

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

Western Operations’ operating and other income of $33 million in fourth quarter 2005 was $8 million higher compared to fourth quarter 2004. Operating and other income was higher primarily due to increased margins in fourth quarter 2005 from higher market heat rates on uncontracted volumes of power generated. 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 21 per cent in the quarter as a result of an approximate 112 per cent ($61.65 per MWh) increase in spot market power prices in fourth quarter 2005 compared to the same period in 2004, while average spot market natural gas prices in Alberta increased by approximately 75 per cent ($4.60 per GJ). Partially offsetting the positive impact of the increase in market heat rates was lower contributions from the Bear Creek cogeneration facility which remained on an unplanned outage throughout the quarter. A significant portion of plant generation in Western Operations in 2005 was sold under long-term contract to mitigate price risk, although some output was intentionally not committed under long-term contract to assist in managing the overall portfolio of generation in Alberta. This approach to portfolio management assists in minimizing costs in situations where TransCanada would otherwise have to purchase electricity in the open market to fulfill its contractual obligations.

Operating and other income for the year ended December 31, 2005 was $123 million or $15 million lower compared to $138 million earned in 2004. This decrease was primarily due to reduced margins in 2005 resulting from overall lower market heat rates on uncontracted volumes of power generated, fee revenues earned in 2004 from Power LP, and lower contributions from Bear Creek.

Western Operations’ power sales revenues and power cost of sales increased in fourth quarter 2005 compared to fourth quarter 2004 primarily due to higher realized prices in fourth quarter 2005. Generation volumes of 554 GWh in fourth quarter 2005 decreased 119 GWh compared to fourth quarter 2004 primarily due to a planned maintenance outage in 2005 at MacKay River and an unplanned outage

at Bear Creek. Bear Creek continued to experience operational difficulties in fourth quarter 2005 and technical evaluation continues regarding a long-term solution. In fourth quarter of 2005 and 2004, approximately nine per cent of power sales volumes were sold into the spot market. To reduce its exposure to spot market prices on uncontracted volumes, as at December 31, 2005, Western Operations had fixed price sales contracts to sell approximately 9,800 GWh for 2006 and approximately 6,000 GWh for 2007.

Eastern Operations

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

	Three months ended December 31				Year ended December 31
(millions of dollars)	2005		2004		2005		2004
Revenue
Power	125		120		505		535
Other (2)	158		70		412		238
	283		190		917		773
Cost of sales
Power	(32	)	(60	)	(215	)	(288	)
Other (2)	(136	)	(54	)	(373	)	(211	)
	(168	)	(114	)	(588	)	(499	)
Other costs and expenses	(40	)	(41	)	(167	)	(146	)
Depreciation	(7	)	(4	)	(25	)	(20	)
Operating and other income	68		31		137		108

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

(2) Other includes natural gas.

Eastern Operations Sales Volumes (1)

	Three months ended December 31		Year ended December 31
(GWh)	2005	2004	2005	2004
Supply
Generation	873	365	2,879	1,467
Purchased	489	1,117	2,627	4,731
	1,362	1,482	5,506	6,198
Contracted vs. Spot
Contracted	1,154	1,473	4,919	6,055
Spot	208	9	587	143
	1,362	1,482	5,506	6,198

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

Operating and other income in fourth quarter 2005 from Eastern Operations of $68 million was $37 million higher compared to $31 million in fourth quarter 2004. The increase was primarily due to income resulting from the April 1, 2005 acquisition of the TC Hydro hydroelectric generation assets and from the Grandview cogeneration facility placed into service in January 2005. Partially offsetting these increases was a $16 million pre-tax ($10 million after-tax) restructuring transaction gain in fourth

quarter 2004 relating to power purchase contracts and a loss of operating income primarily associated with the expiration of certain long-term sales contracts in 2004.

Operating and other income for the year ended December 31, 2005 was $137 million or $29 million higher than the $108 million earned in 2004. Incremental income from the acquisition of the TC Hydro assets and income from the Grandview cogeneration facility were the primary reasons for the increase. Partially offsetting these increases were a $16 million pre-tax ($10 million after-tax) contract restructuring payment made by OSP to its natural gas fuel suppliers in first quarter 2005, a $16 million pre-tax ($10 million after-tax) reduction in income as a result of the sale of Curtis Palmer to Power LP in April 2004 and a loss of operating income primarily associated with the expiration of long-term sales contracts. The contract restructuring at OSP reduced the term of the long-term natural gas supply contracts by approximately three years (now ending in October 2008) and adjusted the pricing to track spot market pricing of natural gas at the Niagara delivery point instead of the previously arbitrated pricing that had resulted in above-market cost of natural gas for OSP.

Generation volumes in fourth quarter 2005 increased 508 GWh to 873 GWh compared to fourth quarter 2004 primarily due to the acquisition of the TC Hydro assets and the placing into service of the Grandview cogeneration facility. Partially offsetting these increases was reduced generation from the OSP facility resulting from a planned maintenance outage at OSP Phase II which was completed in January 2006.

Eastern Operations’ power sales revenues of $125 million increased $5 million in fourth quarter 2005 due to higher realized prices resulting from increased sales generation volumes into a higher priced wholesale spot market partially offset by lower volumes sold. The increased sales to the wholesale spot market were primarily due to high water flows through the TC Hydro facilities. Sales volumes of 1,362 GWh for fourth quarter 2005 were lower than the same period in 2004 due primarily to the expiration of certain long-term sales contracts in 2004. Power cost of sales of $32 million was lower in fourth quarter 2005 due to the impact of lower purchased power volumes partially offset by higher prices for purchased power. Purchased power volumes of 489 GWh were significantly lower in fourth quarter 2005 due to lower contracted sales volumes and the incremental power generation from the purchase of the TC Hydro assets. Volumes generated from the TC Hydro assets reduced the requirement to purchase power to fulfill contractual sales obligations. Fourth quarter 2005 other revenue and other cost of sales of $158 million and $136 million, respectively, increased year-over-year primarily as a result of natural gas purchased and resold under the new natural gas supply contracts at OSP. Other costs and expenses in fourth quarter 2005 of $40 million, which include fuel gas consumed in generation, was relatively unchanged from the prior year as the operating costs of the TC Hydro assets were offset by a decrease in fuel usage costs at the OSP facility.

In fourth quarter 2005, approximately 15 per cent of power sales volumes were sold into the spot market compared to approximately one per cent in fourth quarter 2004 reflecting the sale of a portion of the generation from the TC Hydro assets into the spot market. Eastern Operations is focused on selling the majority of its power under contract to wholesale, commercial and industrial customers while managing a portfolio of power supplies sourced from its own generation and wholesale power purchases. To reduce its exposure to spot market prices, as at December 31, 2005, Eastern Operations had entered into fixed price sales contracts to sell approximately 5,000 GWh of power for 2006 and approximately 3,500 GWh of power for 2007, although certain contracted volumes are dependent on customer usage levels.

General, Administrative, Support Costs and Other

General, administrative, support costs and other of $28 million and $102 million for the three months and year ended December 31, 2005, respectively, increased $9 million and $13 million, respectively, compared to the same periods in 2004. The increases were primarily due to higher business development costs expensed in 2005 and the positive impact in 2004 of the recognition of unrealized foreign exchange gains on Power LP’s U.S. dollar denominated debt.

Sales Volumes and Plant Availability

Power Sales Volumes

	Three months ended December 31		Year ended December 31
(GWh)	2005	2004	2005	2004
Bruce Power (1)	2,946	2,351	10,732	10,608
Western operations (2)	3,075	3,136	11,906	11,695
Eastern operations (2)	1,362	1,482	5,506	6,198
Power LP investment (2) (3)	—	669	1,865	2,419
Total	7,383	7,638	30,009	30,920

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

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

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

	Three months ended December 31				Year ended December 31
Weighted Average Plant Availability (1)	2005		2004		2005		2004
Bruce Power (2)	79	%	72	%	80	%	82	%
Western operations (3)	81	%	92	%	85	%	95	%
Eastern operations (3) (4)	90	%	88	%	83	%	95	%
Power LP investment (3) (5)	—		98	%	94	%	97	%
All plants, excluding Bruce Power investment	88	%	93	%	87	%	96	%
All plants	84	%	85	%	84	%	90	%

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

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

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

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

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

Corporate

Net expenses for the three months and year ended December 31, 2005 were $7 million and $36 million, respectively, compared to $3 million and $2 million for the corresponding periods in 2004.

The $4 million increase in Corporate net expenses for the three months ended December 31, 2005 compared to the same period in 2004 was primarily due to increased net interest costs offset by an income tax refund received in fourth quarter 2005 relating to prior years.

The $34 million increase in net expenses in 2005 compared to 2004 was primarily due to increased interest expense on higher average long-term debt and commercial paper balances in 2005 as well as the release in third quarter 2004 of previously established restructuring provisions. Income tax refunds and positive tax adjustments were comparable in 2004 and 2005.

Other Recent Developments

Gas Transmission

Wholly-Owned Pipelines

Canadian Mainline

During fourth quarter 2005, the NEB announced that the formula-based ROE for 2006 is 8.88 per cent. In December 2005, the NEB approved the tolls for transportation services that TransCanada proposed to charge on an interim basis, effective January 1, 2006. TransCanada is currently engaged in settlement discussions with its stakeholders on matters related to the Canadian Mainline’s 2006 tolls and tariff.

Alberta System

TransCanada continued to charge interim tolls throughout 2005 for transportation service on the Alberta System. The interim tolls, approved by the EUB in December 2004, will remain in effect until final tolls are established following the Phase II proceeding of the Alberta System’s 2005 GRA. In this second phase of the EUB’s rate making process, the allocation of 2005 approved costs among transportation services and rate design will be determined. The EUB commenced a hearing for Phase II on October 4, 2005. The two week oral hearing on Phase II concluded October 19 with written argument and reply filed November 10 and November 24, respectively. A decision is expected in February 2006.

During fourth quarter 2005, the EUB announced that the formula-based ROE for 2006 is 8.93 per cent.

Foothills and BC Systems

Following an agreement with CAPP and other stakeholders to increase the deemed equity component of the capital structure from 30 per cent to 36 per cent for the Foothills and BC Systems and discussions with its shippers on those two systems, on December 2, 2005, TransCanada filed applications with the NEB for final 2006 tolls. Both the Foothills System and BC System 2006 toll applications reflect a deemed common equity ratio of 36 per cent. On December 21, 2005, the NEB approved the Foothills System 2006 tolls as final tolls, effective January 1, 2006. On the BC System, no issue was raised with respect to the capital structure; however a concern was raised with respect to proposed pricing of Short-Term Firm Service (STFS). Therefore, the NEB approved the applied-for BC System tolls on an interim basis, effective January 1, 2006, pending the final resolution of the STFS concern.

Other Gas Transmission

Keystone

In November 2005, TransCanada signed a Memorandum of Understanding with ConocoPhillips Company and CPPL which commits ConocoPhillips Company to ship crude oil on the proposed Keystone pipeline, and gives CPPL the right to acquire up to a fifty per cent ownership interest in the pipeline. On January 31, 2006, TransCanada announced it has secured firm, long-term contracts totalling 340,000 barrels per day through the binding Open Season held during fourth quarter 2005. The Keystone pipeline, expected to cost approximately US$2.1 billion, will be capable of transporting approximately 435,000 barrels per day of crude oil from Hardisty, Alberta to Patoka, Illinois through a 2,950 kilometre pipeline system.

Broadwater

TransCanada, on behalf of the Broadwater Energy project, filed on January 30, 2006, a formal application with FERC for federal approval to construct and operate the Broadwater project. The

proposed facility, which would be located in the New York State waters of Long Island Sound, would be capable of receiving, storing, and re-gasifying imported liquefied natural gas with an average annual send-out capacity of approximately one bcf a day of natural gas. The estimated cost of construction is US$700 million to $1 billion. Broadwater is being developed jointly by TransCanada and Shell US Gas and Power.

Mackenzie

The Mackenzie Gas Pipeline Project continued to progress in fourth quarter 2005, with substantial milestones being achieved in reaching agreement with certain of the northern aboriginal groups as to the terms of land access for the pipeline right of way. In late 2005, the project proponents agreed to proceed to the public hearings phase of the regulatory process. Hearings in this respect commenced in January, 2006 and are expected to continue throughout the year.

In 2003, TransCanada entered into an agreement with the Mackenzie Valley Aboriginal Pipeline Limited Partnership (known as the APG) by which TransCanada agreed to finance the APG’s one-third share of the pipeline pre-development costs associated with the Mackenzie Gas Pipeline Project. TransCanada’s advances to the APG were originally estimated to total approximately $90 million, with an acknowledgement that these costs could rise as a result of project delays and increased project costs. Given that the project has experienced delays and is entering into a protracted regulatory hearing process, the total loan advances by TransCanada on behalf of the APG are currently forecast to increase to approximately $145 million. As at December 31, 2005, TransCanada had funded $87 million of this advance.

Power

Sheerness PPA

Effective December 31, 2005, TransCanada acquired the remaining rights and obligations of the 756 MW Sheerness PPA from the Alberta Balancing Pool for $585 million. There is an approximate 15 year term remaining on the PPA.

Other

Canadian Medium-Term Notes Issue

In January 2006, the company’s wholly-owned subsidiary, TCPL, issued $300 million of five-year medium-term notes bearing interest of 4.3 per cent under its Canadian base shelf program.

Calpine Corporation

Calpine Corporation and certain of its subsidiaries (Calpine) filed for bankruptcy protection on December 20, 2005. Calpine has transportation contracts on certain of TransCanada’s Canadian and

U.S. pipelines. TransCanada presently holds the maximum financial assurances allowable under the respective tariffs. To date, Calpine has not accepted or rejected their transportation contracts. TransCanada is monitoring the Calpine bankruptcy closely regarding any actions/decisions that take place and their impacts.

Consolidated Income

	Three months ended December 31						Year ended December 31
(millions of dollars except per share amounts)	2005			2004			2005			2004
Revenues	1,771			1,480			6,124			5,497

Operating Expenses
Cost of sales	368			234			1,168			940
Other costs and expenses	576			460			1,889			1,615
Depreciation	265			246			1,017			948
	1,209			940			4,074			3,503
Operating Income	562			540			2,050			1,994

Other Expenses/(Income)
Financial charges	211			221			836			858
Financial charges of joint ventures	17			15			66			63
Equity income	(51		)	(26		)	(247		)	(213		)
Interest income and other	(14		)	(1		)	(63		)	(59		)
Gain on sale of Paiton Energy	(118		)	—			(118		)	—
Gains related to Power LP	—			—			(245		)	(197		)
Gain on sale of PipeLines LP units	—			—			(82		)	—
Gain on sale of Millennium	—			—			—			(7		)
	45			209			147			445
Income from Continuing Operations before Income
Taxes and Non-Controlling Interests	517			331			1,903			1,549

Income Taxes
Current	121			85			550			414
Future	22			39			60			77
	143			124			610			491
Non-Controlling Interests
Preferred share dividends	5			5			22			22
Other	19			17			62			56
	24			22			84			78
Net Income from Continuing Operations	350			185			1,209			980
Net Income from Discontinued Operations	—			—			—			52
Net Income	350			185			1,209			1,032

Net Income Per Share
Basic
Continuing operations	$	0.72		$	0.38		$	2.49		$	2.02
Discontinued operations	—			—			—			0.11
	$	0.72		$	0.38		$	2.49		$	2.13
Diluted
Continuing operations	$	0.71		$	0.38		$	2.47		$	2.01
Discontinued operations	—			—			—			0.11
	$	0.71		$	0.38		$	2.47		$	2.12
Average Shares Outstanding (millions)
Basic	487.1			484.7			486.2			484.1
Diluted	490.4			487.1			489.1			486.7

Consolidated Cash Flows

	Three months ended December 31				Year ended December 31
(millions of dollars)	2005		2004		2005		2004

Cash Generated From Operations
Net income from continuing operations	350		185		1,209		980
Depreciation	265		246		1,017		948
Gain on sale of Paiton Energy, net of current tax	(121	)	—		(121	)	—
Gain on sale of PipeLines LP units, net of current tax	—		—		(31	)	—
Gains related to Power LP, net of current tax	—		—		(166	)	(197	)
Gain on sale of Millennium, net of current tax	—		—		—		(7	)
Equity income in excess of distributions received	(1	)	(3	)	(71	)	(113	)
Future income taxes	22		39		60		77
Non-controlling interests	24		22		84		78
Pension funding in excess of expense	(4	)	(8	)	(9	)	(29	)
Other	(5	)	(6	)	(21	)	(34	)
Funds generated from operations	530		475		1,951		1,703
Decrease/(increase) in operating working capital	124		(23	)	(49	)	29
Net cash provided by operations	654		452		1,902		1,732

Investing Activities
Capital expenditures	(345	)	(203	)	(754	)	(530	)
Acquisitions, net of cash acquired	(685	)	(1,453	)	(1,317	)	(1,516	)
Disposition of assets, net of current tax	125		2		671		410
Deferred amounts and other	(29	)	(4	)	64		(12	)
Net cash used in investing activities	(934	)	(1,658	)	(1,336	)	(1,648	)

Financing Activities
Dividends on common shares	(148	)	(139	)	(586	)	(552	)
Distributions paid to non-controlling interest	(12	)	(20	)	(74	)	(87	)
Notes payable issued, net	579		546		416		179
Long-term debt issued	—		398		799		1,090
Reduction of long-term debt	(151	)	(487	)	(1,113	)	(1,005	)
Long-term debt of joint ventures issued	33		79		38		217
Reduction of long-term debt of joint ventures	(61	)	(94	)	(80	)	(112	)
Partnership units of joint ventures issued	—		—		—		88
Common shares issued	5		7		44		32
Net cash provided by/(used in) financing activities	245		290		(556	)	(150	)

Effect of Foreign Exchange Rate Changes on Cash
and Short-Term Investments	1		(31	)	11		(87	)
(Decrease)/Increase in Cash and Short-Term Investments	(34	)	(947	)	21		(153	)
Cash and Short-Term Investments
Beginning of period	246		1,138		191		344
Cash and Short-Term Investments
End of period	212		191		212		191

Consolidated Balance Sheet

(millions of dollars)	December 31, 2005		December 31, 2004

ASSETS
Current Assets
Cash and short-term investments	212		191
Accounts receivable	796		616
Inventories	281		174
Other	277		120
	1,566		1,101
Long-Term Investments	400		1,098
Plant, Property and Equipment	20,038		18,764
Other Assets	2,109		1,459
	24,113		22,422

LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities
Notes payable	962		546
Accounts payable	1,494		1,135
Accrued interest	222		214
Current portion of long-term debt	393		774
Current portion of long-term debt of joint ventures	41		85
	3,112		2,754
Deferred Amounts	1,196		783
Future Income Taxes	703		509
Long-Term Debt	9,640		9,749
Long-term Debt of Joint Ventures	937		808
Preferred Securities	536		554
	16,124		15,157
Non-Controlling Interests
Preferred shares of subsidiary	389		389
Other	394		311
	783		700
Shareholders’ Equity
Common shares	4,755		4,711
Contributed surplus	272		270
Retained earnings	2,269		1,655
Foreign exchange adjustment	(90	)	(71	)
	7,206		6,565
	24,113		22,422

Consolidated Retained Earnings

	Year ended December 31
(millions of dollars)	2005		2004

Balance at beginning of year	1,655		1,185
Net income	1,209		1,032
Common share dividends	(595	)	(562	)
	2,269		1,655

Segmented Information

Three months ended December 31	Gas Transmission				Power				Corporate				Total
(millions of dollars)	2005		2004		2005		2004		2005		2004		2005		2004
Revenues	1,086		1,077		685		403		—		—		1,771		1,480
Cost of sales	—		—		(368	)	(234	)	—		—		(368	)	(234	)
Other costs and expenses	(389	)	(349	)	(187	)	(111	)	—		—		(576	)	(460	)
Depreciation	(235	)	(229	)	(30	)	(17	)	—		—		(265	)	(246	)
Operating income/(loss)	462		499		100		41		—		—		562		540
Financial charges and non-controlling interests	(200	)	(228	)	—		(2	)	(35	)	(13	)	(235	)	(243	)
Financial charges of joint ventures	(13	)	(13	)	(4	)	(2	)	—		—		(17	)	(15	)
Equity income	25		21		26		5		—		—		51		26
Interest income and other	4		2		—		3		10		(4	)	14		1
Gain on sale of Paiton Energy	—		—		118		—		—		—		118		—
Income taxes	(118	)	(124	)	(43	)	(14	)	18		14		(143	)	(124	)
Net Income from Continuing Operations	160		157		197		31		(7	)	(3	)	350		185
Net Income from Discontinued Operations													—		—
Net Income													350		185

Year ended December 31	Gas Transmission				Power				Corporate				Total
(millions of dollars)	2005		2004		2005		2004		2005		2004		2005		2004

Revenues	4,163		3,929		1,961		1,568		—		—		6,124		5,497
Cost of sales	—		—		(1,168	)	(940	)	—		—		(1,168	)	(940	)
Other costs and expenses	(1,380	)	(1,228	)	(505	)	(384	)	(4	)	(3	)	(1,889	)	(1,615	)
Depreciation	(938	)	(876	)	(79	)	(72	)	—		—		(1,017	)	(948	)
Operating income/(loss)	1,845		1,825		209		172		(4	)	(3	)	2,050		1,994
Financial charges and non-controlling interests	(788	)	(848	)	(2	)	(9	)	(130	)	(79	)	(920	)	(936	)
Financial charges of joint ventures	(57	)	(59	)	(9	)	(4	)	—		—		(66	)	(63	)
Equity income	79		83		168		130		—		—		247		213
Interest income and other	25		8		5		14		33		37		63		59
Gain on sale of Paiton Energy	—		—		118		—		—		—		118		—
Gains related to Power LP	—		—		245		197		—		—		245		197
Gain on sale of PipeLines LP units	82		—		—		—		—		—		82		—
Gain on sale of Millennium	—		7		—		—		—		—				7
Income taxes	(502	)	(430	)	(173	)	(104	)	65		43		(610	)	(491	)
Net Income from Continuing Operations	684		586		561		396		(36	)	(2	)	1,209		980
Net Income from Discontinued Operations													—		52
Net Income													1,209		1,032

Teleconference – Audio and Slide Presentation

TransCanada will hold a teleconference today at 11 a.m. (Mountain) / 1 p.m. (Eastern) to discuss the fourth quarter 2005 financial results and general developments and issues concerning the company. Analysts, members of the media and other interested parties wanting to participate should phone 1-866-226-1799 or 416-340-2220 (Toronto area) at least 10 minutes prior to the start of the teleconference. No passcode is required. A live audio and slide presentation webcast of the teleconference will also be available on TransCanada’s website at www.transcanada.com.

The conference will begin with a short address by members of TransCanada’s executive management, followed by a question and answer period for investment analysts. A question and answer period for members of the media will immediately follow.

A replay of the teleconference will be available two hours after the conclusion of the call until midnight (Eastern) February 7, 2006 by dialing 1-800-408-3053 or 416-695-5800 (Toronto area) and entering passcode 3173826. The webcast will be archived and available for replay on www.transcanada.com.

About TransCanada

TransCanada is a leader in the responsible development and reliable operation of North American energy infrastructure. TransCanada’s network of approximately 41,000 kilometres (25,600 miles) of pipeline transports the majority of Western Canada’s natural gas production to key Canadian and U.S. markets. A growing independent power producer, TransCanada owns, or has interests in, approximately 6,700 megawatts of power generation in Canada and the United States. TransCanada’s common shares trade on the Toronto and New York stock exchanges under the symbol TRP.

Forward-Looking Information

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

TransCanada welcomes questions from shareholders and potential investors.

Please telephone:

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

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