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 November 2005

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.

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.

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The documents listed below in this Section and filed as Exhibits 13.1 to 13.3 to this Form 6-K are hereby filed with the Securities and Exchange Commission for the purpose of being and hereby are incorporated by reference into the following registration statements filed by TransCanada Corporation under the Securities Act of 1933, as amended.

13.1         Management’s Discussion and Analysis of Financial Condition and Results of Operations of the registrant as at and for the period ended September 30, 2005.

13.2         Consolidated comparative interim unaudited financial statements of the registrant for the nine month period ended September 30, 2005 (included in the registrant’s Third Quarter 2005 Quarterly Report to Shareholders).

13.3         U.S. GAAP reconciliation of the consolidated comparative interim unaudited financial statements of the registrant contained in the registrant’s Third Quarter 2005 Quarterly Report to Shareholders.

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The document listed below in this Section is furnished, not filed, as Exhibit 99.1.  The Exhibit 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.

99.1         A copy of the Registrant’s news release of November 1, 2005.

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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.

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EXHIBIT INDEX

13.1         Management’s Discussion and Analysis of Financial Condition and Results of Operations of the registrant as at and for the period ended September 30, 2005.

13.2         Consolidated comparative interim unaudited financial statements of the registrant for the nine month period ended September 30, 2005 (included in the registrant’s Third Quarter 2005 Quarterly Report to Shareholders).

13.3         U.S. GAAP reconciliation of the consolidated comparative interim unaudited financial statements of the registrant contained in the registrant’s Third Quarter 2005 Quarterly Report to Shareholders.

31.1         Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2         Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.1         Certification of Chief Executive Officer regarding Periodic Report containing Financial Statements.

32.2         Certification of Chief Financial Officer regarding Periodic Report containing Financial Statements.

99.1         A copy of the Registrant’s news release of November 1, 2005.

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Exhibit 13.1

Management’s Discussion and Analysis

Management’s discussion and analysis (MD&A) dated October 31, 2005 should be read in conjunction with the accompanying unaudited consolidated financial statements of TransCanada Corporation (TransCanada or the company) for the nine months ended September 30, 2005. It should also be read in conjunction with the MD&A contained in TransCanada’s 2004 Annual Report for the year ended December 31, 2004 as well as the restated 2004 audited consolidated financial statements.  Additional information relating to TransCanada, including the company’s Annual Information Form and continuous disclosure documents, is available on SEDAR at www.sedar.com under TransCanada Corporation.  Amounts are stated in Canadian dollars unless otherwise indicated.

Results of Operations

Consolidated

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

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

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

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

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

TransCanada’s net earnings for the nine months ended September 30, 2005 were $859 million or $1.77 per share compared to $795 million or $1.64 per share for the comparable period in 2004.  Net earnings for the nine months ended September 30, 2005 included after-tax gains of $193 million related to the sale of the company’s interest in Power LP and $49 million related to the sale of TC PipeLines, LP (PipeLines LP) units, while net earnings for the nine months ended September 30, 2004 included after-tax gains of $187 million related to the sale of the ManChief and Curtis Palmer assets to Power LP and the recognition of dilution gains resulting from a reduction in TransCanada’s ownership interest in Power LP and other previously deferred gains, as well as a $7 million after-tax gain on sale of the company’s equity interest in the Millennium Pipeline project (Millennium).

Excluding the total gains of $242 million recorded in the nine months ended September 30, 2005 and total gains of $194 million recorded in the nine months ended September 30, 2004, net earnings for the nine months ended September 30, 2005 increased $16 million or $0.03 per share compared to the same period in 2004, to $617 million or $1.27 per share.  This was mainly due to an increase in net earnings from the Gas Transmission business partially offset by an increase in net expenses in the Corporate segment and a decrease in Power’s net earnings.

Excluding the $49 million after-tax gain on sale of PipeLines LP units in 2005 and the $7 million after-tax gain on sale of the company’s equity interest in Millennium in 2004, the $53 million increase in net earnings from the Gas Transmission business for the nine months ended September 30, 2005 compared to the same period in 2004 was primarily attributable to $53 million of net earnings generated from GTN.  In addition, Gas Transmission’s net earnings for the nine months ended September 30, 2005 included approximately $30 million ($13 million related to 2004 and $17 million related to the nine months ended September 30, 2005) as a result of the April 2005 National Energy Board (NEB) decision on the Canadian Mainline’s 2004 Tolls and Tariff Application (Phase II).  This decision dealt with capital structure and included an increase in the deemed common equity ratio to 36 per cent from 33 per cent for 2004, which is also effective under the 2005 tolls settlement.  The increase in Canadian Mainline’s earnings for the nine months ended September 30, 2005 from this decision was partially offset by the combination of a lower average investment base and a decrease in the approved rate of return on common equity in 2005 compared to 2004.

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

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

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

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Gas Transmission

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

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

Wholly-Owned Pipelines

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

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and Tariff Application (Phase II) in April 2005 included an increase in the deemed common equity ratio from 33 to 36 per cent for 2004 which is also effective for 2005 under the 2005 tolls settlement.  Net earnings for the nine months ended September 30, 2005 increased $15 million compared to the corresponding period in 2004.  As a result of the NEB decision that increased the deemed common equity to 36 per cent from 33 per cent, Canadian Mainline’s 2005 net earnings for the nine months ended September 30, 2005 increased $30 million ($13 million related to 2004 and $17 million related to the first nine months of 2005) compared to the same period in 2004. However, this earnings increase is partially offset by the combination of a lower average investment base in 2005 and a decrease in the approved rate of return on common equity to 9.46 per cent in 2005 from 9.56 per cent in 2004. 

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

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

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Operating Statistics

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

(2)          Field receipt volumes for the Alberta System for the nine months ended September 30, 2005 were 3,010 Bcf (2004 - 2,959 Bcf); average per day was 11.0 Bcf (2004 - 10.8 Bcf).

(3)          TransCanada acquired the Gas Transmission Northwest System on November 1, 2004.  The system is currently operating under a fixed rate model approved by the United States Federal Energy Regulatory Commission and, as a result, the system’s current results are not dependent on average investment base.

Other Gas Transmission

TransCanada’s proportionate share of net earnings from its Other Gas Transmission businesses was $22 million for the three months ended September 30, 2005 compared to $24 million for the same period in 2004.  The $2 million decrease compared to the prior period was mainly due to higher general, administrative, support costs and other, lower earnings from PipeLines LP due to the reduced ownership interest and the negative impact of a weaker U.S. dollar.  Partially offsetting these decreases was the impact of Iroquois customer bankruptcy settlements recognized in third quarter 2005.

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

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

Power

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

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

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

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

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

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

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

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Bruce Power Investment

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

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

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

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

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wholesale spot market during third quarter 2005 with the remainder being sold under longer term contracts.  Bruce Power’s operating expenses increased slightly to $35 per MWh in third quarter 2005 from $34 per MWh in third quarter 2004.  Adjustments to TransCanada’s interest in Bruce Power’s equity income for the three and nine months ended September 30, 2005 were lower than in 2004 primarily due to a lower amortization of the purchase price allocated to the fair value of sales contracts in place at the time of acquisition. The adjustment for the nine months ended September 30, 2005 was also lower due to the cessation of interest capitalization upon the return to service of Unit 3 in March 2004.

Pre-tax equity income for the nine months ended September 30, 2005 was $142 million compared to $125 million for the same period in 2004.  Prices realized for the nine months ended September 30, 2005 were $58 per MWh compared to $46 per MWh for the same period in 2004. Approximately 53 per cent of the available output was sold into Ontario’s wholesale spot market during the first nine months of 2005 with the remainder being sold under longer term contracts.  Bruce Power’s operating expenses increased to $39 per MWh for the nine months ended September 30, 2005 from $32 per MWh for the same period in 2004.  This was the result of reduced output as well as higher maintenance costs, higher depreciation and lower capitalization of labour and other in-house costs following the restart of Unit 3.

Equity income from Bruce Power is directly impacted by fluctuations in wholesale spot market prices for electricity as well as overall plant availability, which in turn, is impacted by scheduled and unscheduled maintenance.  To reduce its exposure to spot market prices, Bruce Power has entered into fixed price sales contracts to sell forward 3.2 TWh of output for the balance of 2005 and approximately 13 TWh of 2006 output from the Bruce B units has also been sold under fixed-price sales contracts.  Overall plant availability for the six Bruce units in 2005 is expected to be 83 per cent.

Bruce Power made a total of $165 million in cash distributions to its partners in third quarter 2005.  TransCanada’s share was $52 million. For the nine months ended September 30, 2005, the total distributions to partners were $215 million, of which TransCanada’s share was $68 million.  No distributions were made to partners in 2004.  The partners have agreed that all excess cash will be distributed on a monthly basis and that separate cash calls will be made for major capital projects.

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

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

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

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

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

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Western Operations

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

(2)          Other revenue includes Cancarb Thermax and natural gas sales. Other cost of sales includes the cost of natural gas sold.

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

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

Western Operations’ operating and other income of $32 million in third quarter 2005 was $11 million lower compared to the same period in 2004.  This decrease was mainly due to recognition in third quarter 2004 of income from the MacKay River facility which was previously deferred for the first six months of 2004.  Operating and other income was also lower due to fee revenues earned in third quarter 2004 from Power LP and reduced margins in third quarter 2005 from lower market heat rates on uncontracted volumes of power generated.  Market heat rates decreased by approximately 20 per cent in the quarter as a result of an approximate 50 per cent ($3 per gigajoule) increase in spot market natural gas prices in Alberta in third quarter 2005 compared to the same period in 2004, while average spot market power prices increased by approximately 23 per cent ($12 per MWh). Partially offsetting these decreases were higher contributions from the Sundance A&B PPAs primarily due to higher plant availability.  A significant portion of plant generation in Western Operations is sold under long-term contract to mitigate price risk.  Some output is intentionally not committed under long-term contract to assist in managing Power’s overall portfolio of generation.  This approach to portfolio management assists in minimizing costs in situations where TransCanada would otherwise have to purchase electricity in the open market to fulfill its contractual obligations.

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

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Western Operations’ power sales revenues, power cost of sales and associated purchased volumes increased in third quarter 2005 compared to third quarter 2004 primarily due to higher plant availability at Sundance A & B as a result of lower maintenance outages.  Power sales revenues also increased as a result of higher realized prices in third quarter 2005.  Other costs and expenses of $34 million, which includes fuel gas consumed in generation, were higher in third quarter 2005 primarily due to higher fuel costs at the MacKay River facility resulting from higher natural gas prices and higher generation output.  Generation volumes of 544 GWh in third quarter 2005 decreased 136 GWh compared to third quarter 2004 primarily due to planned maintenance outages in 2005 at Carseland and an unplanned outage at Bear Creek.   Partially offsetting these decreases were higher generation volumes from MacKay River resulting from outages in third quarter 2004.  Bear Creek has experienced certain operational difficulties in 2005 and, as a result, has not been fully available throughout much of the first nine months of 2005.  Power earnings in 2005 have not been significantly impacted by the operational difficulties at Bear Creek.  Technical evaluation continues and possible long-term solutions are being studied.  In third quarter 2005, approximately 13 per cent of power sales volumes were sold into the spot market compared to approximately nine per cent for the same period in 2004. To reduce its exposure to spot market prices on uncontracted volumes, as at September 30, 2005, Western Operations had fixed price sales contracts to sell forward approximately 2,800 GWh for the remainder of 2005 and approximately 8,000 GWh for 2006.

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Eastern Operations

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

(2)          Other includes natural gas.

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

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

Operating and other income for the nine months ended September 30, 2005 was $69 million or $8 million lower than the $77 million earned in 2004. Incremental income from the acquisition of the TC Hydro assets and income from the Grandview cogeneration facility were more than offset by a $16 million pre-tax ($10 million after-tax) contract restructuring payment made by Ocean State Power (OSP) to its natural gas fuel suppliers in first quarter 2005,

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a $16 million pre-tax ($10 million after-tax) reduction in income as a result of the sale of Curtis Palmer to Power LP in April 2004 and a loss of margin primarily associated with the expiration of long-term sales contracts.  The contract restructuring at OSP reduced the term of the long-term natural gas supply contracts by approximately three years (now ending in October 2008) and adjusted the pricing to track spot pricing of natural gas at the Niagara delivery point versus the previously arbitrated pricing that had resulted in above-market cost of natural gas for OSP.

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

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

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

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

Power LP Investment

Power LP’s operating and other income was $6 million higher in third quarter 2005 compared to the same period in 2004 primarily due to the combined impact of accounting for the Power LP investment as an asset held for sale and improved operating results at its Ontario facilities. Operating and other income for the nine months ended September 30, 2005 was $7 million higher compared to the same period in 2004.  The increase was primarily due to additional earnings from Power LP’s 2004 acquisitions of the Curtis Palmer, ManChief, Mamquam and Queen Charlotte facilities, improved operating results and the impact of accounting for the Power LP investment as an asset held for sale.  Partially offsetting these increases was the impact of TransCanada’s sale of this investment on August 31, 2005, a reduced ownership interest in Power LP in 2005, and the effect of the recognition in second quarter 2004 of all previously deferred gains resulting from the removal of the Power LP redemption obligation.

General, Administrative, Support Costs and Other

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

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Power Sales Volumes and Plant Availability

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

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

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

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

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

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

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

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

Corporate

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

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

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

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

Liquidity and Capital Resources

Funds Generated from Operations

Funds generated from operations were $489 million and $1,375 million for the three and nine months ended September 30, 2005, respectively, compared with $387 million and $1,184 million for the same periods in 2004.

TransCanada expects that its ability to generate adequate amounts of cash in the short term and the long term, when needed, and to maintain financial capacity and flexibility to provide for planned growth remains substantially unchanged since December 31, 2004.

Investing Activities

In the three and nine months ended September 30, 2005, capital expenditures, excluding acquisitions, totalled $166 million (2004 - $97 million) and $409 million (2004 - $291 million), respectively, and related primarily to construction of new power plants as well as maintenance and capacity capital in the Gas Transmission business.  

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

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

Financing Activities

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

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

Dividends

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

Contractual Obligations

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

(1)          Includes purchase obligations for the three months ending December 31, 2005.

(2)          Commodity purchases include fixed and variable components. The variable components are estimates and are subject to variability in plant production, market prices, and regulatory tariffs.

(3)          Amounts are estimates and are subject to variability based on timing of construction and project enhancements.

(4)          Includes estimates of certain amounts which are subject to change depending on plant fired hours, the consumer price index, actual plant maintenance costs, plant salaries as well as changes in regulated rates for transportation.

There have been no other material changes to TransCanada’s contractual obligations from December 31, 2004 to September 30, 2005, including payments due for the next five years and thereafter.  For further information on these contractual obligations, refer to the MD&A in TransCanada’s 2004 Annual Report.

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Financial and Other Instruments

The following represents the material changes to the company’s financial instruments since December 31, 2004.

Energy Price Risk Management

The company executes power, natural gas and heat rate derivatives in order to manage exposure and risks associated with its overall asset portfolio.  Heat rate contracts are contracts for the sale or purchase of power that are priced based on a natural gas index.  The fair values and notional volumes of the swap, option, future and heat rate contracts are shown in the tables below.  In accordance with the company’s accounting policy, each of the derivatives in the table below is recorded on the balance sheet at its fair value at September 30, 2005  and December 31, 2004.

Power