SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C.  20549

FORM 6-K

REPORT OF FOREIGN PRIVATE ISSUER

PURSUANT TO RULE 13a-16 OR 15d-16 OF THE SECURITIES EXCHANGE ACT OF 1934

For the month of January 2006

COMMISSION FILE No. 1-31690

TransCanada Corporation

(Translation of Registrant’s Name into English)

450 – 1 Street S.W., Calgary, Alberta, T2P 5H1, Canada

(Address of Principal Executive Offices)

Indicate by check mark whether the registrant files or will file annual reports under cover of Form 20-F or Form 40-F.

Form 20-F                                           o                                    Form 40-F                                      0;     ý

Indicate by check mark if the registrant is submitting the Form 6-K in paper as permitted by Regulation S-T Rule 101(b)(1): o

Indicated by check mark if the registrant is submitting the Form 6-K in paper as permitted by Regulation S-T Rule 101(b)(7): o

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

Yes                            o                                    No                                ý

Attached as Exhibit 99.1 to this Form 6-K is a copy of the Registrant’s news release of January 31, 2006.  This news release is being furnished, not filed, and will not be incorporated by reference into any registration statement filed by TransCanada Corporation under the Securities Act of 1933, as amended.

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

2

EXHIBIT INDEX

3

Exhibit 99.1

News Release dated January 31, 2006

TransCanada Corporation

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

3

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.

4

Results of Operations

5

Consolidated

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.

6

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

7

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.

8

(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.

9

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

(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

10

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’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

11

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.

12

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.

13

Bruce Power Results-at-a-Glance

(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

14

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

15

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

16

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)

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

(2)   Includes Cancarb Thermax and natural gas sales.

(3)   Includes the cost of natural gas sold.

17

Western Operations Sales Volumes (1)

(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

18

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)

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

(2) Other includes natural gas.

Eastern Operations Sales Volumes (1)

(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

19

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.

20

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