TransCanada Reports 2004 Net Income of $1.032 Billion; Board of Direct

    News Editors

    CALGARY, Alberta--(BUSINESS WIRE)--Feb. 1, 2005--TransCanada (TSX:TRP) (NYSE:TRP) :

    Fourth Quarter and Year-End 2004 Financial Highlights

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

    - The Board of Directors of TransCanada Corporation (TransCanada or the company) today declared a quarterly dividend of $0.305 per common share for the quarter ending March 31, 2005, a 5.2 per cent increase over the $0.29 paid in each of the previous four quarters. The dividend is payable on April 29, 2005 to shareholders of record at the close of business on March 31, 2005. This is the fifth consecutive annual increase in the common share dividend.

    - TransCanada's net income for fourth quarter 2004 was $185 million or $0.38 per share compared to $193 million or $0.40 per share for fourth quarter 2003.

    - For the year ended December 31, 2004, TransCanada's net income was $1,032 million or $2.13 per share, including net income from discontinued operations of $52 million or $0.11 per share. This compares to $851 million or $1.76 per share for 2003, including net income from discontinued operations of $50 million or $0.10 per share.

    - Funds generated from continuing operations for fourth quarter 2004 were $467 million, an increase of $64 million compared to fourth quarter 2003. Funds generated from continuing operations for the year ended December 31, 2004 were $1,674 million, a decrease of $136 million compared to 2003.

    Hal Kvisle, TransCanada's chief executive officer said, "It has been a year of steady performance for TransCanada. We delivered solid operating and financial results, and invested approximately $2.6 billion, including the assumption of debt, in our core businesses of gas transmission and power generation.

    "TransCanada's strong overall performance in 2004 was achieved despite the negative impacts of disappointing decisions from the Alberta Energy and Utilities Board related to the Alberta System and an unfavourable arbitration decision on Ocean State Power gas supply costs. In 2005, we will remain focussed on addressing these issues.

    "We will also continue to implement our core strategies to grow our North American operations. That consistency, combined with our strong balance sheet, and skilled and dedicated team of people, will ensure we are well-positioned to continue to capture opportunities that create significant long-term value for our shareholders," said Mr. Kvisle. "Our announcements during the fourth quarter are excellent examples of the initiatives we are undertaking to strengthen our financial performance and create long-term value."

    During the fourth quarter 2004, TransCanada:

    - Closed the purchase of the 2,174-kilometre Gas Transmission Northwest System and the 128-kilometre North Baja System (collectively GTN) for US$1.7 billion including US$0.5 billion of assumed debt.

    - Announced it will proceed with the purchase of hydroelectric generation assets from USGen New England (USGen) with a total generating capacity of 567 megawatts (MW) for US$505 million. The acquisition is subject to regulatory approvals and the pending sale of the 49 MW Bellows Falls hydroelectric facility to the Vermont Hydroelectric Power Authority (Vermont Hydroelectric). If Vermont Hydroelectric acquires Bellows Falls, on which it has exercised its option to purchase, TransCanada's purchase price would be reduced by US$72 million.

    - Completed construction of the Grandview cogeneration plant, a 90 MW gas-fired power plant in New Brunswick. The project was completed on time and within budget.

    - Announced that Hydro-Quebec Distribution awarded Cartier Wind Energy Inc. (Cartier Wind) six projects totalling 739.5 MW. They are scheduled to be commissioned between 2006 and 2012. In January 2005, TransCanada and its partner, Innergex II Inc., acquired the 20 per cent interest previously held by RES Canada resulting in TransCanada holding a 62 per cent interest and Innergex II Inc. having a 38 per cent interest.

    - Announced plans to develop an offshore liquefied natural gas (LNG) regasification facility in the New York State waters of Long Island Sound with Shell US Gas & Power LLC (Shell). Construction is subject to federal and state regulatory approvals.

    - Announced in January 2005 it is developing a $200 million natural gas storage facility near Edson, Alberta. The 50 billion cubic feet (Bcf) facility will connect to TransCanada's Alberta System. The company has also secured 40 Bcf of existing Alberta-based gas storage capacity from a third party.

    TransCanada's fourth quarter news release, including unaudited financial information, replaces the fourth quarter Report to Shareholders filed by the company in prior years. TransCanada expects to issue its 2004 annual report in mid-March.

Results of Operations

Operating Results Three months ended Year ended December 31 December 31 (millions of dollars except 2004 2003 2004 2003 per share amounts) (unaudited) (unaudited) ----------------------------------------- -------- -------- --------

Revenues 1,394 1,319 5,107 5,357

Net Income Continuing operations 185 193 980 801 Discontinued operations - - 52 50 -------- -------- -------- -------- 185 193 1,032 851 -------- -------- -------- -------- -------- -------- -------- --------

Net Income Per Share - Basic Continuing operations $0.38 $0.40 $2.02 $1.66 Discontinued operations - - 0.11 0.10 -------- -------- -------- -------- $0.38 $0.40 $2.13 $1.76 -------- -------- -------- -------- -------- -------- -------- --------

Cash Flows Funds generated from continuing operations 467 403 1,674 1,810 Capital expenditures 185 127 476 391 Acquisitions, net of cash acquired 1,453 23 1,516 570

Dividends Declared Per Share $0.29 $0.27 $1.16 $1.08

Common Shares Outstanding Average for the period 484.7 482.8 484.1 481.5 End of period 484.9 483.2 484.9 483.2 --------------------------------------------------------------------

Consolidated

Segment Results-at-a-Glance Three months ended Year ended December 31 December 31 2004 2003 2004 2003 (millions of dollars) (unaudited) (unaudited) ----------------------------------------- -------- -------- -------- Gas Transmission 157 160 586 622 Power 31 44 396 220 Corporate (3) (11) (2) (41) -------- -------- -------- -------- Continuing operations 185 193 980 801 Discontinued operations - - 52 50 -------- -------- -------- -------- Net Income 185 193 1,032 851 -------- -------- -------- -------- -------- -------- -------- --------

    Net income and net income from continuing operations (net earnings) for fourth quarter 2004 for TransCanada were $185 million or $0.38 per share compared to $193 million or $0.40 per share for the same period in 2003. This decrease was primarily due to lower net earnings from the Power and Gas Transmission businesses, partially offset by lower net expenses in the Corporate segment.

    Net earnings in the Power business for fourth quarter 2004 decreased $13 million compared to fourth quarter 2003 primarily due to lower earnings from Western Operations and Eastern Operations. Lower net earnings of $3 million in the Gas Transmission business for fourth quarter 2004 compared to the same period in 2003 were primarily due to a decline in the Alberta System's net earnings which reflect the impacts of the Alberta Energy and Utilities Board (EUB) decisions in 2004 on Phase I of the 2004 General Rate Application (GRA) and Generic Cost of Capital (GCOC). In addition, a decline in the Canadian Mainline's net earnings resulted primarily from a lower rate of return on common equity and a lower average investment base. These decreases were partially offset by net earnings of $14 million from GTN which was acquired by TransCanada on November 1, 2004. The decrease in net expenses in the Corporate segment was mainly due to the positive effects of various tax adjustments and foreign exchange impacts.

    TransCanada's net income for the year ended December 31, 2004 was $1,032 million or $2.13 per share including net income from discontinued operations of $52 million or $0.11 per share, compared to $851 million or $1.76 per share for 2003 including net income from discontinued operations of $50 million or $0.10 per share.

    TransCanada's net earnings for the year ended December 31, 2004 were $980 million or $2.02 per share compared to $801 million or $1.66 per share for 2003. The increase of $179 million or $0.36 per share in 2004 was primarily due to significantly higher net earnings from the Power business. In addition, lower net expenses in the Corporate segment offset the lower net earnings from the Gas Transmission business.

    The increased Power earnings are primarily due to the second quarter 2004 gain of $15 million after tax ($25 million pre tax) or $0.03 per share on the sale of the ManChief and Curtis Palmer assets to TransCanada Power, L.P. (Power LP) and the recognition of $172 million or $0.36 per share of dilution and other gains resulting from a reduction in TransCanada's ownership interest in Power LP and the removal of Power LP's obligation, in 2017, to redeem units not owned by TransCanada. TransCanada was required to fund this redemption, therefore the removal of Power LP's obligation eliminates this requirement.

    Excluding the above-mentioned $187 million of combined gains included in net earnings related to Power LP and the recognition in second quarter 2003 of a $19 million after-tax settlement with a former counterparty, Power's net earnings for the year ended December 31, 2004 were $8 million higher than 2003. Higher net earnings from TransCanada's investment in Bruce Power L.P. (Bruce Power) were partially offset by lower contributions from Eastern Operations and the impact of TransCanada's reduced ownership in Power LP.

    The lower net earnings of $36 million in the Gas Transmission business for the year ended December 31, 2004 compared to the prior year were primarily due to lower earnings from the Alberta System and Canadian Mainline, partially offset by earnings from GTN, higher earnings from certain Other Gas Transmission investments and a $7 million gain on sale of the company's equity interest in the Millennium Pipeline project (Millennium) in second quarter 2004. The 2003 net earnings included $11 million of future income tax benefits recognized by TransGas de Occidente S.A. (TransGas).

    The decrease in net expenses of $39 million in the Corporate segment for the year ended December 31, 2004 was primarily due to income tax related items in 2004 and the release in third quarter 2004 of previously established restructuring provisions. These positive variances were partially offset by additional interest costs due to the issuance of new debt in late 2003 and in 2004.

    Funds generated from continuing operations of $467 million for fourth quarter 2004 increased $64 million compared to fourth quarter 2003. Funds generated from continuing operations of $1,674 million for the year ended December 31, 2004 decreased $136 million compared to the same period in 2003, mainly as a result of higher current income tax expense in 2004 compared to 2003.

    Gas Transmission

    The Gas Transmission business generated net earnings of $157 million and $586 million for the quarter and year ended December 31, 2004, respectively, compared to $160 million and $622 million for the comparable periods in 2003.

Gas Transmission Three months ended Year ended Results-at-a-Glance December 31 December 31 2004 2003 2004 2003 (millions of dollars) (unaudited) (unaudited) ----------------------------------------- -------- -------- -------- Wholly-Owned Pipelines Canadian Mainline 71 75 272 290 Alberta System 40 54 150 190 GTN (1) 14 14 Foothills System (2) 5 6 22 20 BC System 2 2 7 6 -------- -------- -------- -------- 132 137 465 506 -------- -------- -------- -------- Other Gas Transmission Great Lakes 12 14 55 52 Iroquois 3 3 17 18 TC PipeLines, LP 3 4 16 15 Portland (3) 4 4 10 11 Ventures LP 5 3 15 10 Trans Quebec & Maritimes 2 2 8 8 CrossAlta 7 2 13 6 TransGas 2 2 11 22 Northern Development (3) (2) (6) (4) General, administrative, support costs and other (10) (9) (18) (22) -------- -------- -------- -------- 25 23 121 116 -------- -------- -------- -------- Net earnings 157 160 586 622 -------- -------- -------- -------- -------- -------- -------- --------

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

    (2) The remaining ownership interests in the Foothills System, previously not held by TransCanada, were acquired on August 15, 2003.

    (3) TransCanada increased its ownership interest in Portland to 43.4 per cent from 33.3 per cent on September 29, 2003 and to 61.7 per cent from 43.4 per cent on December 3, 2003.

    Wholly-Owned Pipelines

    The Canadian Mainline's net earnings decreased $4 million and $18 million for the quarter and year ended December 31, 2004, respectively, when compared to the corresponding periods in 2003. The decrease in net earnings was primarily due to a lower rate of return on common equity of 9.56 per cent in 2004 compared to 9.79 per cent in 2003, and a lower average investment base in 2004. Earnings and interim tolls in 2004 were based on a capital structure including a 33 per cent deemed common equity.

    The Alberta System's net earnings of $40 million in fourth quarter 2004 decreased $14 million compared to $54 million in the same quarter of 2003. Net earnings for the year ended December 31, 2004 decreased $40 million compared to 2003. These decreases were primarily due to the impacts of the EUB decisions in respect of Phase I of the 2004 GRA in August 2004 and the GCOC proceeding in July 2004. In the GRA decision, the EUB disallowed approximately $24 million pre tax of operating costs associated with the operation of the pipeline. The company believes these are necessary costs that it will reasonably and prudently incur for the safe, reliable, and efficient operation of the Alberta System. In September 2004, TransCanada filed with the Alberta Court of Appeal for leave to appeal the EUB's decision on Phase I of the 2004 GRA. Subsequently, at the request of TransCanada, the Court of Appeal adjourned the appeal for an indefinite period of time while TransCanada considers the merits of a Review and Variance application to the EUB in respect of 2004 costs, and works toward a negotiated settlement of future years' tolls with its customers. The GCOC decision resulted in a lower return on deemed common equity in 2004 compared to earnings implicit in the 2003 negotiated settlement which included a fixed revenue requirement component, before non-routine adjustments, of $1.277 billion. Earnings in 2004 reflect a return of 9.60 per cent on deemed common equity of 35 per cent as approved in the GCOC decision.

    On November 1, 2004, TransCanada closed the purchase of GTN from National Energy & Gas Transmission Inc. for US$1.7 billion, including US$0.5 billion of assumed debt. The acquisition was accounted for using the purchase method of accounting and the financial results were consolidated with those of TransCanada subsequent to the acquisition date. GTN contributed $14 million of net earnings in fourth quarter 2004.

    The Foothills System's net earnings of $22 million for the year ended December 31, 2004 were $2 million higher than in 2003 reflecting TransCanada's acquisition in August 2003 of the remaining ownership interests in Foothills not held previously.

Operating Statistics Gas Transmission Canadian Alberta Northwest Year ended December 31 Mainline (1) System (2) System (3) (unaudited) 2004 2003 2004 2003 2004 ------------------------- ------------- ------------- ------------ Average investment base ($ millions) 8,196 8,565 4,619 4,878 n/a (3) Delivery volumes (Bcf) Total 2,621 2,628 3,909 3,883 181 Average per day 7.2 7.2 10.7 10.6 3.0 --------------------------------------------------------------------

Foothills Year ended December 31 System (4) BC System (unaudited) 2004 2003 2004 2003 --------------------------------------- ------------- ------------ Average investment base ($ millions) 714 739 228 236 Delivery volumes (Bcf) Total 1,139 1,110 360 325 Average per day 3.1 3.0 1.0 0.9 --------------------------------------------------------------------

    (1) Canadian Mainline deliveries originating at the Alberta border and in Saskatchewan for the year ended December 31, 2004 were 2,017 Bcf (2003 - 2,055 Bcf); average per day was 5.5 Bcf (2003 - 5.6 Bcf).

    (2) Field receipt volumes for the Alberta System for the year ended December 31, 2004 were 3,952 Bcf (2003 - 3,892 Bcf); average per day was 10.8 Bcf (2003 - 10.7 Bcf).

    (3) TransCanada acquired GTN on November 1, 2004. Both the Gas Transmission Northwest System and the North Baja System are currently operating under fixed rate models approved by the Federal Energy Regulatory Commission and, as a result, the systems' current results are not dependent on average investment base. The North Baja System's total delivery volumes were 13 Bcf; average per day was 0.2 Bcf. The delivery volumes represent November and December 2004 throughput.

    (4) The remaining interests in the Foothills System were acquired in August 2003. The delivery volumes in the table represent 100 per cent of Foothills.

    Other Gas Transmission

    TransCanada's proportionate share of net earnings from its Other Gas Transmission businesses was $25 million for the three months ended December 31, 2004 compared to $23 million for the same period in 2003. The $2 million increase was primarily due to higher earnings from CrossAlta as a result of favourable gas storage market conditions as well as higher earnings from Ventures LP. These increases were partially offset by the impact of a weaker U.S. dollar.

    Net earnings for the year ended December 31, 2004 were $121 million compared to $116 million in 2003. Excluding the $7 million gain on sale of Millennium recognized in 2004 and the $11 million of future income tax benefits recognized by TransGas in 2003, earnings in 2004 were $9 million higher compared to 2003. The increase was due to higher earnings from CrossAlta due to favourable gas storage market conditions and Ventures LP as a result of the expansion completed in 2003. In addition, earnings from Great Lakes increased as a result of successful marketing of short-term services. These increases were partially offset by the impact of a weaker U.S. dollar.

Power

Power Results-at-a-Glance Three months ended Year ended December 31 December 31 2004 2003 2004 2003 (millions of dollars) (unaudited) (unaudited) ----------------------------------------- -------- -------- -------- Western operations 25 31 138 160 Eastern operations 31 36 108 127 Bruce Power investment 5 7 130 99 Power LP investment 7 9 29 35 General, administrative, support costs and other (19) (20) (89) (86) -------- -------- -------- -------- Operating and other income 49 63 316 335 Financial charges (4) (4) (13) (12) Income taxes (14) (15) (94) (103) -------- -------- -------- -------- 31 44 209 220 Gains related to Power LP (after tax) - - 187 - -------- -------- -------- -------- Net earnings 31 44 396 220 -------- -------- -------- -------- -------- -------- -------- --------

    Power's net earnings in fourth quarter 2004 of $31 million decreased $13 million compared to $44 million in fourth quarter 2003 primarily due to lower earnings from Western Operations and Eastern Operations.

    Net earnings for the year ended December 31, 2004 of $396 million increased $176 million compared to $220 million in 2003 primarily due to the $187 million of gains related to Power LP recorded in second quarter 2004. During second quarter 2004, TransCanada completed the sale of the ManChief and Curtis Palmer power facilities to Power LP for US$402.6 million, excluding closing adjustments, resulting in an after-tax gain on sale of $15 million (pre-tax gain of $25 million). At a meeting in April 2004, Power LP unitholders approved these acquisitions and the removal of Power LP's obligation to redeem all units not owned by TransCanada in 2017. TransCanada was required to fund this redemption, thus the removal of Power LP's obligation eliminates this requirement. In addition, in second quarter 2004, Power LP issued 8.1 million subscription receipts which were subsequently converted into partnership units and TransCanada contributed $20 million of the net proceeds of $286.8 million that Power LP realized from this issue. The net impact of this issue reduced TransCanada's ownership interest in Power LP from 35.6 per cent to 30.6 per cent. As a result of these events, TransCanada recognized dilution and other gains of $172 million in second quarter 2004, $132 million of which were previously deferred and were being amortized into income to 2017. Dilution gains arose when TransCanada's ownership interest in Power LP was decreased as a result of the Power LP issuing new partnership units at a market price in excess of TransCanada's per unit carrying value of the investment.

    The 2003 results included recognition in Western Operations in second quarter 2003 of a $31 million pre-tax ($19 million after-tax) settlement with a former counterparty which defaulted in 2001 under power forward contracts. Excluding this settlement and the $187 million of gains related to Power LP in 2004, Power's net earnings for the year ended December 31, 2004 of $209 million increased $8 million compared to $201 million in 2003. Pre-tax equity income from Bruce Power of $130 million in 2004 increased $31 million compared to TransCanada's period of ownership in 2003 and was partially offset by lower contributions from Eastern Operations and Power LP investment.

    Western Operations

    Operating and other income from Western Operations in fourth quarter 2004 of $25 million was $6 million lower compared to the $31 million earned in the same period in 2003. The decrease was mainly due to a reduction in income from ManChief following the sale of the plant to Power LP in April 2004, cumulative operating cost adjustments settled in fourth quarter 2004 at the recently placed in-service MacKay River cogeneration plant, and reduced margins resulting from lower market heat rates on uncontracted volumes.

    Operating and other income for the year ended December 31, 2004 of $138 million was $22 million lower compared to the same period in 2003. The decrease was mainly due to the 2003 settlement with a former counterparty under power forward contracts, as well as reduced income from ManChief following the sale of the plant to Power LP in April 2004. Partially offsetting these decreases were contributions from the MacKay River plant, fees earned with respect to Power LP's asset acquisitions in 2004 and the impact of higher net margins achieved in second and third quarter 2004 on the overall portfolio.

    Eastern Operations

    Operating and other income from Eastern Operations in fourth quarter 2004 of $31 million was $5 million lower compared to $36 million earned in the same period in 2003. The decrease was primarily due to a reduction in income as a result of the sale of the Curtis Palmer hydroelectric facilities to Power LP in April 2004, the unfavourable impact of higher natural gas fuel costs at Ocean State Power (OSP), earnings recorded in 2003 on the Cobourg temporary generation facility and a weaker U.S. Dollar in 2004 compared to 2003. Partially offsetting these reductions was a $16 million pre-tax positive impact of a restructuring transaction related to power purchase contracts between OSP and Boston Edison Company (Boston Edison). In fourth quarter 2004, TransCanada closed a transaction with Boston Edison resulting in TransCanada assuming a 23.5 per cent share of the OSP power purchase contracts and recognized earnings from the effective date of April 1, 2004.

    Management has concluded its review of the operating plan for OSP with respect to the negative impacts of an arbitration received in August 2004 whereby OSP's cost of fuel gas substantially increased to a price in excess of market. The outcome of a fourth arbitration is expected by the end of third quarter 2005. At December 31, 2004, there was no impairment of OSP, however, there existed uncertainty with respect to the outcome of this arbitration process and future market conditions. Should the fourth arbitration decision continue to support a pricing mechanism for fuel gas in excess of market price and if anticipated market conditions do not change substantially, management expects the negative impact of continued above-market gas prices could result in an asset impairment write-down of the OSP facility. The net carrying value of OSP at December 31, 2004 was approximately US$150 million.

    Operating and other income for the year ended December 31, 2004 was $108 million or $19 million lower than the $127 million earned in 2003. This decrease was mainly due to a reduction in income from the sale of the Curtis Palmer hydroelectric facilities to Power LP in April 2004, the unfavourable impact of higher natural gas fuel costs at OSP and a weaker U.S. dollar in 2004. Partially offsetting these decreases were the net revenues recorded in fourth quarter 2004 related to the restructuring of the OSP power purchase contracts with Boston Edison.

    Bruce Power Investment

Bruce Power Results-at-a-Glance Three months ended Year ended December 31 December 31 2004 2003 2004 2003 (millions of dollars) (unaudited) (unaudited) ----------------------------------------- -------- -------- -------- Bruce Power (100 per cent basis) Revenues 355 269 1,583 1,208 Operating expenses (345) (254) (1,178) (853) -------- -------- -------- -------- Operating income 10 15 405 355 Financial charges (17) (20) (67) (69) -------- -------- -------- -------- Income before income taxes (7) (5) 338 286 -------- -------- -------- -------- -------- -------- -------- --------

TransCanada's interest in Bruce Power income before income taxes (1) (2) (1) 107 65 Adjustments 7 8 23 34 -------- -------- -------- -------- TransCanada's income from Bruce Power before income taxes 5 7 130 99 -------- -------- -------- -------- -------- -------- -------- --------

    (1) TransCanada acquired its 31.6 per cent interest in Bruce Power on February 14, 2003. Bruce Power's 100 per cent income before income taxes from February 14, 2003 to December 31, 2003 was $205 million.

    Bruce Power contributed $5 million of pre-tax equity income in fourth quarter 2004 compared to $7 million in fourth quarter 2003. TransCanada's share of power output for fourth quarter 2004 was 2,351 gigawatt hours (GWh) compared to 1,846 GWh in fourth quarter 2003. This increase primarily reflects higher output in 2004 as a result of the restart of Bruce A Unit 4 in fourth quarter 2003 and Unit 3 in first quarter 2004, which expanded Bruce Power's capacity by approximately 1,500 MW. Several maintenance outages occurred in fourth quarter 2004 which partially offset the increased output from Units 3 and 4. Overall prices achieved during fourth quarter 2004 were approximately $47 per megawatt hour (MWh), compared to $45 per MWh in fourth quarter 2003. Approximately 47 per cent of the output was sold into Ontario's wholesale spot market in fourth quarter 2004, as compared to approximately 30 per cent in fourth quarter 2003, with the remainder being sold under longer term contracts.

    On a per unit basis, Bruce operating expenses increased to $46 per MWh in fourth quarter 2004 from $43 per MWh in fourth quarter 2003. This increase was partly due to expenses related to the feasibility study on the restart of Bruce A Units 1 and 2. The total amounts expensed by Bruce Power in fourth quarter and full year 2004 related to the Units 1 and 2 restart feasibility study were $10 million and $16 million, respectively. The increase in total operating expenses was also the result of higher outage, fuel, depreciation and staff expenses in 2004, reflecting the move to a six- versus four-unit operation. Annual operating expenses per MWh were relatively constant for 2003 and 2004, however fourth quarter 2004 output was reduced due to planned work on the vacuum building outage and Unit 6 as well as unplanned outage days which resulted in higher operating expenses on a per MWh basis in fourth quarter 2004.

    Adjustments to TransCanada's interest in Bruce Power income before income taxes for the quarter and year ended December 31, 2004 were lower than the same periods in 2003 primarily due to the cessation of interest capitalization upon the return to service of the Bruce A units.

    Pre-tax equity income for the year ended December 31, 2004 was $130 million compared to $99 million for the same period in 2003. This increase was primarily due to higher output in 2004 as a result of the return to service of the two Bruce A units as well as a full year of earnings in 2004 compared to earnings from February 14 to December 31 in 2003, reflecting TransCanada's period of ownership in 2003. In 2004, TransCanada was not required to make any cash contributions to Bruce Power and did not receive any cash distributions from this investment.

    Operating expenses for the year ended December 31, 2004 were $35 per MWh compared to $36 per MWh for the period February 14 to December 31, 2003. Average realized prices in the year ended December 31, 2004 were $47 per MWh compared to $48 per MWh during TransCanada's period of ownership in 2003. Approximately 52 per cent of Bruce Power's output for the year ended December 31, 2004 was sold into Ontario's wholesale spot market.

    The Bruce units ran at an average availability of 72 per cent in fourth quarter 2004, compared to an average availability during fourth quarter 2003 of 73 per cent reflecting slightly higher planned and unplanned maintenance outage hours in fourth quarter 2004. Availability for the year ended December 31, 2004 was 82 per cent compared to 83 per cent for the period from February 14 to December 31, 2003. A scheduled maintenance outage on Unit 6 began on September 11, 2004 and the unit returned to service on December 3, 2004. Unit 5 returned to service on November 3, 2004 after it had been kept offline following the vacuum building outage that began in third quarter 2004 in order to perform maintenance on its primary heat transport pump.

    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 for approximately 36 per cent of planned output for 2005. Bruce Power's operating expenses in 2005 are expected to increase from 2004 due to higher depreciation and amortization on the A units, higher outage costs and higher fuel costs.

    The average availability in 2005 is expected to be 85 per cent compared to 82 per cent achieved in 2004. Unit 3 began its first planned maintenance outage on January 8, 2005 and is expected to be offline for approximately two months. Unit 4 is scheduled to go offline later in first quarter 2005 for a similar inspection program. Maintenance outages of approximately two to three months each are also planned for two other units in 2005. One outage is expected to begin in second quarter 2005 and the other outage is expected to begin in third quarter 2005.

    Power LP Investment

    Operating and other income from TransCanada's investment in Power LP of $7 million and $29 million for the quarter and year ended December 31, 2004 was $2 million and $6 million lower, respectively, compared to the same periods in 2003. Additional earnings from Power LP's second quarter 2004 acquisition of the Curtis Palmer and ManChief facilities were more than offset by the impact of TransCanada's reduced ownership interest in Power LP in April 2004 (30.6 per cent compared to 35.6 per cent) and the recognition in second quarter 2004 of $132 million of previously deferred gains resulting from the removal of the Power LP redemption obligation. Prior to the removal of the redemption obligation, Power was recognizing into income the amortization of these deferred gains over a period through to 2017.

    General, Administrative, Support Costs and Other

    General, administrative, support costs and other decreased $1 million in fourth quarter 2004 compared to fourth quarter 2003. General, administrative, support costs and other for the year ended December 31, 2004 of $89 million were $3 million higher compared to 2003 primarily due to higher support costs resulting from the Company's focus on growing the Power business. These higher support costs were mostly offset by the positive impacts of the recognition of unrealized foreign exchange gains on Power LP's U.S. dollar denominated debt and lower business development expenditures.

Power Sales Volumes Three months ended Year ended (unaudited) December 31 December 31 (GWh) 2004 2003 2004 2003 ----------------------------------------- -------- -------- -------- Western operations (1) 3,136 2,986 11,695 12,296 Eastern operations (1) 1,482 1,780 6,198 6,906 Bruce Power investment (2) 2,351 1,846 10,608 6,655 Power LP investment (1) 669 549 2,419 2,153 -------- -------- -------- -------- Total 7,638 7,161 30,920 28,010 -------------------------------------------------------------------- --------------------------------------------------------------------

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

    (2) Acquired on February 14, 2003. Sales volumes reflect TransCanada's 31.6 per cent share of Bruce Power output from the date of acquisition.

Weighted Average Plant Three months ended Year ended Availability (1) December 31 December 31 (unaudited) 2004 2003 2004 2003 ----------------------------------------- -------- -------- -------- Western operations (2) 92% 94% 95% 93% Eastern operations (2) 88% 99% 95% 94% Bruce Power investment (3) 72% 73% 82% 83% Power LP investment (2) 98% 98% 97% 96% All plants 85% 89% 90% 90% -------------------------------------------------------------------- --------------------------------------------------------------------

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

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

    (3) Comparative 2003 percentage is calculated from the February 14, 2003 date of acquisition. Bruce A Unit 4 is included effective November 1, 2003 and Bruce A Unit 3 is included effective March 1, 2004.

    Corporate

    Net expenses for the quarter and year ended December 31, 2004 were $3 million and $2 million, respectively, compared to $11 million and $41 million for the corresponding periods in 2003.

    The $8 million decrease in Corporate net expenses for the three months ended December 31, 2004 compared to the same period in 2003 was primarily due to the positive impacts of income tax and foreign exchange related items.

    The $39 million decrease in net expenses in 2004 compared to 2003 was primarily due to the positive impacts of income tax and foreign exchange related items throughout 2004 and the third quarter 2004 release of previously established restructuring provisions.


    Other Recent Developments

    Gas Transmission

    Wholly-Owned Pipelines

    Alberta System

    In its GCOC decision, the EUB set a generic return on equity (ROE) for 2004 at 9.60 per cent for all Alberta utilities. The EUB also decided that the generic ROE will be adjusted on an annual basis by 75 per cent of the change in long-term Canada bonds, consistent with the approach used by the National Energy Board (NEB). During fourth quarter 2004, the EUB announced that the generic ROE for 2005 will be 9.50 per cent.

    In its decision on Phase I of the 2004 GRA, the EUB directed TransCanada to make a compliance filing recalculating the revenue requirement to reflect the EUB's decision. In November 2004, the EUB approved the compliance filing.

    Phase II of the 2004 GRA, dealing primarily with rate design and services, was filed in December 2003. In October 2004, the EUB issued a decision on Phase II. The EUB essentially approved all of the existing rate design and cost accountability measures for 2004. As well, the Fuel Policy, Gas Balancing Agreement extension and proposed tariff amendments were approved. The EUB also directed TransCanada to file a 2005 GRA-Phase II application on or before April 1, 2005 to address certain cost allocation issues. In the compliance filing for Phase II, TransCanada requested that the interim tolls for 2004 be approved as final tolls for 2004. The EUB approved the Phase II compliance filing on December 14, 2004.

    On December 15, 2004, the Phase I GRA for 2005 was filed with the EUB. TransCanada is continuing to pursue a negotiated revenue settlement with its shippers, and if successful will replace or amend the application.

    In December 2004, the EUB approved TransCanada's application to charge interim tolls for transportation service, effective January 1, 2005. Final tolls for 2005 will be determined based on the EUB decisions on the 2005 GRA.

    Canadian Mainline

    The 2004 Tolls and Tariff Application (the 2004 Application) for the Canadian Mainline was filed with the NEB in January 2004, and included a request for an 11 per cent return on a 40 per cent deemed common equity component. In light of a Federal Court of Appeal decision, TransCanada informed the NEB that it would no longer contest the NEB's ROE formula in the 2004 Application and revised the 2004 Application to reflect the formula-based ROE of 9.56 per cent on 40 per cent deemed common equity. In September 2004, the NEB issued its decision in respect of Phase I of the 2004 tolls and tariff proceeding in which all issues brought forward in the 2004 Application were considered with the exception of cost of capital. The NEB approved virtually all cost elements in the 2004 Application as well as a new non-renewable firm transportation (FT-NR) service and suspended the fuel gas incentive program for 2004. Phase II of the proceeding, in which capital structure is being considered, commenced in fourth quarter 2004 and is currently on-going. The hearing is expected to conclude in February 2005 with an NEB decision to follow in second quarter 2005.

    In November 2004, the Canadian Association of Petroleum Producers filed an application with the NEB to review and vary its Phase I decision with respect to the following:

    - approving tolls for FT-NR to be determined on a biddable basis;

    - allowing TransCanada to include all forecast long-term incentive compensation costs in its 2004 cost of service;

    - allowing TransCanada to recover through tolls certain regulatory and legal costs relating to review and appeal proceedings.

    As a first step, the NEB has requested comments from parties involved in the Phase I hearing on whether there is a doubt as to the correctness of its decision such that it ought to be reviewed. If the NEB decides to review its decision, it will proceed to consider the merits of the review application and whether to confirm, vary or rescind its decision.

    TransCanada is currently engaged in settlement discussions with its stakeholders on matters related to the Canadian Mainline's 2005 tolls and tariff. TransCanada intends to file an application with the NEB for approval of the 2005 tolls and tariff in first quarter 2005.

    The Canadian Mainline charged interim tolls for transportation service throughout 2004. Upon receipt of the NEB's decision on cost of capital arising from Phase II of the 2004 Canadian Mainline tolls and tariff proceeding, the 2004 tolls will be finalized. In December 2004, the NEB approved the tolls for transportation services that TransCanada proposed to charge on an interim basis, effective January 1, 2005, pending the NEB's decision in respect of the Canadian Mainline's 2005 Tolls and Tariff Application which will be filed in first quarter 2005.

    During fourth quarter 2004, the NEB announced that the formula-based ROE for 2005 is 9.46 per cent.

    Liquefied Natural Gas

    In November 2004, TransCanada and Shell announced plans to jointly develop an offshore LNG regasification terminal, named Broadwater Energy, in the New York State waters of Long Island Sound. The proposed floating storage and regasification unit would be located approximately 15 kilometres off the Long Island coast and 18 kilometres off the Connecticut coast. The proposed terminal would be capable of receiving, storing, and regasifying imported LNG with an average send-out capacity of approximately one Bcf per day of natural gas. Broadwater Energy LLC, an entity which will be owned 50 per cent by TransCanada, will own and operate the facility, while Shell will own the capacity and supply the LNG. The estimated cost of construction is expected to be approximately US$700 million.

    Construction of the facility is subject to regulatory approval from Federal and State governments. The regulatory approval process is expected to take approximately two to three years. TransCanada and Shell have filed a request with the Federal Energy Regulatory Commission to initiate a six-to-nine month public review of the Broadwater proposal. Provided the necessary approvals are received, it is expected the facility will be in service in late 2010.

    Gas Storage

    TransCanada is developing a $200 million natural gas storage project near Edson, Alberta. The Edson facility will have a capacity of approximately 50 Bcf and will connect to TransCanada's Alberta System. In addition, the company has recently secured a long-term contract with a third party for up to 40 Bcf of existing Alberta-based storage capacity, ramping up from approximately 20 Bcf in 2005 to 30 Bcf in 2006 and to 40 Bcf in 2007. TransCanada intends to be providing fee-based gas storage services directly to customers by April 2005, with additional capacity available from the Edson facility commencing early in second quarter 2006, on a phased-in basis. Upon completion of the Edson facility, TransCanada will own or control 110 Bcf, or approximately one third, of the storage capacity in Alberta.

    Power

    Grandview Cogeneration Facility

    Construction of the Grandview facility, a 90 MW natural gas-fired cogeneration power plant on the site of the Irving Oil Refinery in Saint John, New Brunswick, was completed on time and within budget by the end of December 2004. The facility supplies power and exhaust heat to the Irving Oil petroleum refinery.

    Cartier Wind Energy Inc.

    In October 2004, Hydro-Quebec Distribution awarded Cartier Wind six projects representing a total of 739.5 MW. The projects are distributed in various communities of the administrative region of Gaspesie, Iles-de-la-Madeleine and the Regional County Municipality of Matane and are expected to be commissioned between 2006 and 2012 at a total cost of approximately $1.2 billion. In January 2005, TransCanada and its partner, Innergex II Inc., acquired the 20 per cent interest previously held by RES Canada resulting in TransCanada holding a 62 per cent interest and Innergex II Inc. having a 38 per cent interest.

    USGen New England, Inc.

    In September 2004, USGen and TransCanada signed an Asset Purchase Agreement for TransCanada to purchase hydroelectric generation assets in New England with a total generating capacity of 567 MW for US$505 million. USGen is a subsidiary of NEGT and voluntarily filed for protection under Chapter 11 of the U.S. Bankruptcy Code in July 2003. Through a court-sanctioned auction process in accordance with customary bidding procedures, USGen sought offers that were higher or otherwise better than the TransCanada agreement. No qualified competing bids were received by the court-ordered deadline therefore the auction originally scheduled for December 9, 2004 did not take place.

    In December 2004, the Town of Rockingham, Vermont exercised its option with USGen to purchase the 49 MW Bellows Falls hydroelectric facility and assigned its rights to Vermont Hydroelectric. If Vermont Hydroelectric acquires Bellows Falls, TransCanada's purchase price would be reduced by US$72 million.

    All bankruptcy court approvals have been granted, however other regulatory approvals and conditions will need to be met prior to closing. The transaction is expected to close in the first half of 2005 and is expected to be immediately accretive to earnings and cash flow.

    Bruce Power

    TransCanada, together with its Bruce Power partners, is evaluating a potential investment in the refurbishment of the 680 MW Point Lepreau nuclear generating station in New Brunswick. Also, the feasibility study to examine the potential restart of Bruce A Units 1 and 2 is ongoing. Bruce Power continues talks with a provincially appointed negotiator regarding the potential restart.

    Other

    In fourth quarter 2004, shelf prospectuses in Canada and the U.S. were filed by the company for the issuance of $1.5 billion of medium-term notes and US$1.0 billion of debt securities, respectively. In January 2005, $300 million of 12-year, 5.10 per cent medium-term notes were issued under the Canadian shelf prospectus.

Consolidated Income

Three months ended Year ended December 31 December 31 (millions of dollars except 2004 2003 2004 2003 per share amounts) (unaudited) (unaudited) ----------------------------------------- -------- -------- -------- Revenues 1,394 1,319 5,107 5,357

Operating Expenses Cost of sales 144 159 539 692 Other costs and expenses 466 434 1,635 1,682 Depreciation 245 222 945 914 -------- -------- -------- -------- 855 815 3,119 3,288 -------- -------- -------- -------- Operating Income 539 504 1,988 2,069

Other Expenses/(Income) Financial charges 209 202 810 821 Financial charges of joint ventures 15 14 60 77 Equity income (15) (14) (171) (165) Interest income and other - (16) (65) (60) Gains related to Power LP - - (197) - -------- -------- -------- -------- 209 186 437 673 -------- -------- -------- --------

Income from Continuing Operations before Income Taxes and Non-Controlling Interests 330 318 1,551 1,396 Income Taxes Current 89 126 431 305 Future 39 (18) 77 230 -------- -------- -------- -------- 128 108 508 535 -------- -------- -------- --------

Non-Controlling Interests Preferred securities charges 8 10 31 36 Preferred share dividends 5 5 22 22 Other 4 2 10 2 -------- -------- -------- -------- Net Income from Continuing Operations 185 193 980 801 Net Income from Discontinued Operations - - 52 50 -------- -------- -------- -------- Net Income 185 193 1,032 851 -------- -------- -------- -------- -------- -------- -------- --------

Net Income Per Share Basic Continuing operations $0.38 $0.40 $2.02 $1.66 Discontinued operations - - 0.11 0.10 -------- -------- -------- -------- $0.38 $0.40 $2.13 $1.76 -------- -------- -------- -------- -------- -------- -------- -------- Diluted Continuing operations $0.38 $0.40 $2.01 $1.66 Discontinued operations - - 0.11 0.10 -------- -------- -------- -------- $0.38 $0.40 $2.12 $1.76 -------- -------- -------- -------- -------- -------- -------- -------- Average Shares Outstanding - Basic (millions) 484.7 482.8 484.1 481.5 -------- -------- -------- -------- -------- -------- -------- -------- Average Shares Outstanding - Diluted (millions) 487.1 485.5 486.7 483.9 -------- -------- -------- -------- -------- -------- -------- --------

Consolidated Cash Flows

Three months ended Year ended December 31 December 31 2004 2003 2004 2003 (millions of dollars) (unaudited) (unaudited) ----------------------------------------- -------- -------- -------- Cash Generated From Operations Net income from continuing operations 185 193 980 801 Depreciation 245 222 945 914 Future income taxes 39 (18) 77 230 Gains related to Power LP - - (197) - Equity income in excess of distributions received (4) (3) (123) (119) Non-controlling interests 17 17 63 60 Pension funding in excess of expense 16 (13) (29) (65) Other (31) 5 (42) (11) -------- -------- -------- -------- Funds generated from continuing operations 467 403 1,674 1,810 (Increase)/decrease in operating working capital (26) 29 34 112 -------- -------- -------- -------- Net cash provided by continuing operations 441 432 1,708 1,922 Net cash provided by/(used in) discontinued operations 3 - (6) (17) -------- -------- -------- -------- 444 432 1,702 1,905 -------- -------- -------- -------- Investing Activities Capital expenditures (185) (127) (476) (391) Acquisitions, net of cash acquired (1,453) (23) (1,516) (570) Disposition of assets 2 - 410 - Deferred amounts and other 2 58 (24) (138) -------- -------- -------- -------- Net cash used in investing activities (1,634) (92) (1,606) (1,099) -------- -------- -------- --------

Financing Activities Dividends and preferred securities charges (158) (150) (623) (588) Notes payable issued/(repaid), net 546 (341) 179 (62) Long-term debt issued 377 455 1,042 930 Reduction of long-term debt (487) (358) (997) (744) Non-recourse debt of joint ventures issued 86 - 233 60 Reduction of non-recourse debt of joint ventures (93) (16) (113) (71) Common shares issued 7 16 32 65 Partnership units of joint ventures issued - - 88 - Redemption of junior subordinated debentures - - - (218) -------- -------- -------- -------- Net cash provided by/(used in) financing activities 278 (394) (159) (628) -------- -------- -------- --------

-------- -------- -------- -------- Effect of Foreign Exchange Rate Changes on Cash and Short-Term Investments (32) (15) (87) (52) -------- -------- -------- --------

(Decrease)/Increase in Cash and Short-Term Investments (944) (69) (150) 126

Cash and Short-Term Investments Beginning of period 1,132 407 338 212 -------- -------- -------- -------- Cash and Short-Term Investments End of period 188 338 188 338 -------- -------- -------- -------- -------- -------- -------- --------

Consolidated Balance Sheet

December 31, 2004 December 31, 2003 (millions of dollars) (unaudited) ------------------------------------------------- ----------------- ASSETS Current Assets Cash and short-term investments 188 338 Accounts receivable 627 605 Inventories 174 165 Other 120 88 ----------------- ----------------- 1,109 1,196 Long-Term Investments 840 733 Plant, Property and Equipment 18,704 17,415 Other Assets 1,477 1,357 ----------------- ----------------- 22,130 20,701 ----------------- ----------------- ----------------- ----------------- ------------------------------------------------- -----------------

LIABILITIES AND SHAREHOLDERS' EQUITY Current Liabilities Notes payable 546 367 Accounts payable 1,135 1,087 Accrued interest 214 208 Current portion of long-term debt 766 550 Current portion of non-recourse debt of joint ventures 83 19 ----------------- ----------------- 2,744 2,231 Deferred Amounts 666 561 Long-Term Debt 9,713 9,465 Future Income Taxes 509 427 Non-Recourse Debt of Joint Ventures 779 761 Preferred Securities 19 22 ----------------- ----------------- 14,430 13,467 ----------------- ----------------- Non-Controlling Interests Preferred securities of subsidiary 670 672 Preferred shares of subsidiary 389 389 Other 76 82 ----------------- ----------------- 1,135 1,143 ----------------- ----------------- Shareholders' Equity Common shares 4,711 4,679 Contributed surplus 270 267 Retained earnings 1,655 1,185 Foreign exchange adjustment (71) (40) ----------------- ----------------- 6,565 6,091 ----------------- ----------------- 22,130 20,701 ----------------- ----------------- ----------------- -----------------

Consolidated Retained Earnings

Year ended December 31 2004 2003 (millions of dollars) (unaudited) -------------------------------------------------------- ---------- Balance at beginning of year 1,185 854 Net income 1,032 851 Common share dividends (562) (520) ---------- ---------- 1,655 1,185 ---------- ---------- ---------- ----------

Segmented Information

Three Gas months ended Transmission Power Corporate Total December 31 -------------- ------- ----------- -------- (unaudited - millions of dollars) 2004 2003 2004 2003 2004 2003 2004 2003 --------------- ------ ----- ----- ----- ---- ---- ---- ---- Revenues 1,075 982 319 337 - - 1,394 1,319 Cost of sales - - (144) (159) - - (144) (159) Other costs and expenses (349) (326) (117) (106) - (2) (466) (434) Depreciation (228) (202) (17) (20) - - (245) (222) ----- ---- ---- ---- ---- ---- ----- ----- Operating income/(loss) 498 454 41 52 - (2) 539 504 Financial charges and non-controlling interests (211) (193) (2) (4) (13) (22) (226) (219) Financial charges of joint ventures (13) (14) (2) - - - (15) (14) Equity income 10 7 5 7 - - 15 14 Interest income and other 1 6 3 4 (4) 6 - 16 Income taxes (128) (100) (14) (15) 14 7 (128) (108) ----- ---- ---- ---- ---- ---- ----- ----- Continuing Operations 157 160 31 44 (3) (11) 185 193 ----- ---- ---- ---- ---- ---- ----- ---- ---- ---- ---- ---- Discontinued Operations - - ----- ----- Net Income 185 193 ----- ----- ----- -----

Gas Year ended Transmission Power Corporate Total December 31 -------------- ------- ----------- -------- (unaudited - millions of dollars) 2004 2003 2004 2003 2004 2003 2004 2003 --------------- ------ ----- ----- ----- ---- ---- ---- ---- Revenues 3,917 3,956 1,190 1,401 - - 5,107 5,357 Cost of sales - - (539) (692) - - (539) (692) Other costs and expenses (1,225)(1,270) (407) (405) (3) (7)(1,635)(1,682) Depreciation (873) (831) (72) (82) - (1) (945) (914) ----- ----- ---- ---- ---- ---- ----- ----- Operating income/(loss) 1,819 1,855 172 222 (3) (8) 1,988 2,069 Financial charges and non-controlling interests (785) (781) (9) (11) (79) (89) (873) (881) Financial charges of joint ventures (56) (76) (4) (1) - - (60) (77) Equity income 41 66 130 99 - - 171 165 Interest income and other 14 17 14 14 37 29 65 60 Gains related to Power LP - - 197 - - - 197 - Income taxes (447) (459) (104) (103) 43 27 (508) (535) ----- ---- ---- ---- ---- ---- ----- ----- Continuing Operations 586 622 396 220 (2) (41) 980 801 ----- ---- ---- ---- ---- ---- ----- ---- ---- ---- ---- ---- Discontinued Operations 52 50 ----- ----- Net Income 1,032 851 ------ ----- ------ -----

    Teleconference - 12:00 p.m. (Mountain) / 2:00 p.m. (Eastern)

    TransCanada will hold a teleconference today at 12:00 p.m. (Mountain) / 2:00 p.m. (Eastern), Feburary 1, 2005 to discuss the fourth quarter 2004 financial results, and general developments and issues concerning the company. Analysts, members of the media and other interested parties wanting to participate in the call should dial 1-877-295-2825 or 416-405-8532 (Toronto area) at least 10 minutes prior to the start of the call. No pass code is required. A live audio webcast of the teleconference will also be available on TransCanada's website (www.transcanada.com).

    The teleconference 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 time February 8, 2005. Please call 1-800-408-3053 or 416-695-5800 (Toronto area) and enter passcode 3135828. The webcast will be archived and available for replay on www.transcanada.com.

    About TransCanada

    TransCanada is a leading North American energy company. TransCanada is focused on natural gas transmission and power services with employees who are expert in these businesses. TransCanada's network of approximately 41,000 kilometres (25,600 miles) of pipeline transports the majority of Western Canada's natural gas production to the fastest growing markets in Canada and the United States. TransCanada owns, controls or is constructing more than 4,700 MW of power generation - an amount of power that can meet the needs of about 4.7 million average households. The Company's common shares trade under the symbol TRP on the Toronto and New York stock exchanges. Visit TransCanada on the Internet at www.transcanada.com for more information.

    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, 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.

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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: Hejdi Feick/Kurt Kadatz at (403) 920-7859

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

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    TRANSCANADA (NYSE:TRP) (TSX:TRP)

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CONTACT: TransCanada Media Inquiries Hejdi Feick/Kurt Kadatz (403) 920-7859 or (800) 608-7859 OR Investor & Analyst Inquiries David Moneta (403) 920-7911 Website: www.transcanada.com

KEYWORD: NEW YORK INTERNATIONAL CANADA INDUSTRY KEYWORD: OIL/GAS ENERGY EARNINGS SOURCE: TRANSCANADA

Copyright Business Wire 2005