Exhibit 4.208
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FOURTH QUARTER 2002
Quarterly Report to Shareholders
Consolidated Results-at-a-Glance
(unaudited) |
| Three months ended December 31 |
| Year ended December 31 |
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| 2002 |
| 2001* |
| 2002 |
| 2001* |
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Net Income/(Loss) Applicable to Common Shares |
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Continuing operations |
| 180 |
| 166 |
| 747 |
| 686 |
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Discontinued operations |
| — |
| 20 |
| — |
| (67 | ) | |||||
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| 180 |
| 186 |
| 747 |
| 619 |
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Net Income/(Loss) Per Share - Basic |
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Continuing operations |
| $ | 0.37 |
| $ | 0.35 |
| $ | 1.56 |
| $ | 1.44 |
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Discontinued operations |
| — |
| 0.05 |
| — |
| (0.14 | ) | |||||
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| $ | 0.37 |
| $ | 0.40 |
| $ | 1.56 |
| $ | 1.30 |
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* Restated, see note 2, Accounting Changes, in the Notes to the Consolidated Financial Statements.
Management’s Discussion and Analysis
On January 28, 2003, the Board of Directors of TransCanada PipeLines Limited (TransCanada or the company) raised the quarterly dividend on the company's common shares from $0.25 per share to $0.27 per share, an increase of eight per cent, for the quarter ended March 31, 2003.
The following discussion and analysis should be read in conjunction with the accompanying consolidated financial statements of TransCanada and the notes thereto.
Results of Operations
Consolidated
TransCanada’s net income applicable to common shares from continuing operations (net earnings) for the year ended December 31, 2002 was $747 million or $1.56 per share compared to $686 million or $1.44 per share in 2001. The increase of $61 million or $0.12 per share in 2002 compared to 2001 is primarily due to higher earnings from the Transmission business and reduced expenses in the Corporate segment, partially offset by lower
earnings from the Power segment. In 2001, the Power segment earnings reflected the significant market opportunities created by high market prices and power price volatility. In June 2002, TransCanada received the National Energy Board (NEB) decision on its Fair Return application (Fair Return decision) to determine the cost of capital to be included in the calculation of 2001 and 2002 final tolls on its Canadian Mainline. The results for
the year ended December 31, 2002 include after-tax net income of $36 million or $0.08 per share, representing the impact of the Fair Return decision for 2001 ($16 million) and 2002 ($20 million). The results also include $7 million relating to TransCanada’s proportionate share of a favourable ruling in Great Lakes with respect to Minnesota use tax paid in prior years.
Net income applicable to common shares for the year ended December 31, 2002 was $747 million or $1.56 per share compared to $619 million or $1.30 per share in 2001. The 2001 results included a net loss from discontinued operations of $67 million or $0.14 per share.
TransCanada’s net earnings for fourth quarter 2002 were $180 million or $0.37 per share compared to $166 million or $0.35 per share for fourth quarter 2001. The increase of $14 million or $0.02 per share in the fourth quarter is mainly attributable to stronger results from the Transmission segment and lower expenses in the Corporate segment, offset by lower earnings from the Power segment.
Net income applicable to common shares for fourth quarter 2002 was $180 million or $0.37 per share compared to $186 million or $0.40 per share for fourth quarter 2001. The fourth quarter 2001 results include a positive $20 million or $0.05 per share after-tax adjustment to the provision for loss on discontinued operations.
Funds generated from continuing operations of $1,827 million for the year ended December 31, 2002 increased by $203 million in comparison to 2001. Funds generated from continuing operations of $467 million for fourth quarter 2002 increased $106 million compared to the fourth quarter last year.
The company has chosen to expense stock options and the impact of this accounting change, which has been recorded in the fourth quarter 2002, was a $2 million charge to net income in the three months and year ended December 31, 2002.
Effective third quarter 2002, the company adopted accrual accounting for energy trading contracts, changing from its previous policy of mark-to-market accounting for these contracts. This accounting change has been applied retroactively with restatement of prior periods (see note 2, Accounting Changes, in the Notes to Consolidated Financial Statements). The cumulative effect of this accounting change as at January 1, 2001 was a decrease in retained earnings of $20 million. Net income for the year ended December 31, 2001 included a positive adjustment of $11 million. Under accrual accounting, net income for the year ended
December 31, 2002 is $13 million higher than would have been reported under mark-to-market accounting.
Segment Results-at-a-Glance |
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(unaudited) |
| Three months ended December 31 |
| Year ended December 31 |
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| 2002 |
| 2001 |
| 2002 |
| 2001 |
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Transmission |
| 162 |
| 153 |
| 653 |
| 585 |
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Power |
| 30 |
| 35 |
| 146 |
| 168 |
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Corporate |
| (12 | ) | (22 | ) | (52 | ) | (67 | ) |
Continuing operations |
| 180 |
| 166 |
| 747 |
| 686 |
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Discontinued operations |
| — |
| 20 |
| — |
| (67 | ) |
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Net Income Applicable to Common Shares |
| 180 |
| 186 |
| 747 |
| 619 |
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Transmission
The Transmission business generated net earnings of $162 million and $653 million for the three months and year ended December 31, 2002, respectively.
Transmission Results-at-a-Glance |
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(unaudited) |
| Three months ended December 31 |
| Year ended December 31 |
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| 2002 |
| 2001 |
| 2002 |
| 2001 |
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Wholly-Owned Pipelines |
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Alberta System |
| 56 |
| 59 |
| 214 |
| 204 |
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Canadian Mainline |
| 75 |
| 70 |
| 307 |
| 274 |
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BC System |
| 2 |
| 1 |
| 6 |
| 5 |
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| 133 |
| 130 |
| 527 |
| 483 |
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North American Pipeline Ventures |
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Great Lakes |
| 17 |
| 15 |
| 66 |
| 56 |
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TC PipeLines, LP |
| 5 |
| 4 |
| 17 |
| 15 |
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Iroquois |
| 3 |
| 4 |
| 18 |
| 16 |
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Portland |
| — |
| — |
| 2 |
| (1 | ) |
Foothills |
| 4 |
| 5 |
| 17 |
| 20 |
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Trans Québec & Maritimes |
| 2 |
| 2 |
| 8 |
| 8 |
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Northern Development |
| (1 | ) | (3 | ) | (6 | ) | (9 | ) |
Other |
| (1 | ) | (4 | ) | 4 |
| (3 | ) |
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| 29 |
| 23 |
| 126 |
| 102 |
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Net earnings |
| 162 |
| 153 |
| 653 |
| 585 |
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Wholly-Owned Pipelines
The Alberta System’s net earnings of $56 million in fourth quarter 2002 decreased $3 million compared to $59 million in the same quarter of 2001 primarily due to recognition in fourth quarter 2001 of incentive earnings from operating cost efficiencies related to 2001. Net earnings for the year ended December 31, 2002 increased $10 million when compared to the prior year, primarily due to an interest refund relating to a prior year income tax reassessment, and the expiry of TransCanada’s transition support costs with respect to the Alberta System’s Products & Pricing Agreement which ended in the first quarter of 2002. TransCanada is currently in negotiations with Alberta System customers on the 2003 revenue requirement. TransCanada plans to file an application for approval of the Alberta System 2003 revenue requirement and final 2003 tolls, rates and charges with the Alberta Energy and Utilities Board (EUB) by February 28, 2003.
The Canadian Mainline’s net earnings have increased $5 million and $33 million, respectively, for the three months and year ended December 31, 2002 when compared to the corresponding periods in 2001. Net earnings in 2002 reflect the impact of the Fair Return decision which included an increase in the deemed common equity ratio from 30 to 33 per cent, effective January 1, 2001. The increase in earnings from the Fair Return decision was partially offset by a decline in the rate of return on common equity from 9.61 per cent in 2001 to 9.53 per cent in 2002 and a lower average
investment base. The NEB has scheduled a hearing to commence February 24, 2003 to consider the Canadian Mainline 2003 Tolls and Tariff Application. In September 2002, TransCanada also filed with the NEB a request for review and variance of the Fair Return decision and that the final Canadian Mainline 2003 Tolls and Tariff Application reflect the review and variance decision. The NEB has not yet responded to TransCanada’s review and variance request.
Operating Statistics |
| Alberta |
| Canadian |
| BC |
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| 2002 |
| 2001 |
| 2002 |
| 2001 |
| 2002 |
| 2001 |
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Average investment base ($millions) |
| 5,074 |
| 5,183 |
| 8,884 |
| 9,176 |
| 211 |
| 204 |
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Delivery volumes (Bcf) |
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Total |
| 4,146 |
| 4,059 |
| 2,630 |
| 2,450 |
| 371 |
| 395 |
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Average per day |
| 11.4 |
| 11.1 |
| 7.2 |
| 6.7 |
| 1.0 |
| 1.1 |
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*Field receipt volumes for the Alberta System for the year ended December 31, 2002 were 4,101 Bcf (2001 - 4,170 Bcf); average per day were 11.2 Bcf (2001 - 11.4 Bcf).
**Canadian Mainline deliveries originating at the Alberta border and in Saskatchewan for the year ended December 31, 2002 were 2,221 Bcf (2001 - 2,098 Bcf); average per day were 6.1 Bcf (2001 - 5.7 Bcf).
North American Pipeline Ventures
TransCanada’s proportionate share of net earnings from its other Transmission businesses was $29 million and $126 million for the three months and year ended December 31, 2002, respectively. This represents increases of $6 million and $24 million, respectively, compared to the same periods in 2001.
Higher net earnings for the year ended December 31, 2002 reflect TransCanada’s $7 million share of a favourable ruling in Great Lakes related to Minnesota use tax paid in prior years. Excluding the impact of the Great Lakes favourable ruling, the increase in full year 2002 net earnings was mainly due to higher transportation margins, favourable foreign exchange rates on stronger operating results from U.S. pipeline affiliates and TransCanada’s increased ownership interests in Iroquois and Portland acquired in second quarter 2001. In addition, net earnings related to TransCanada’s share of other ventures, including CrossAlta gas storage facilities (CrossAlta), Ventures LP and TransGas de Occidente, increased $7 million in 2002 when compared to the prior year.
The $6 million increase in fourth quarter 2002 compared to 2001 is mainly due to lower northern development costs and increased contributions from CrossAlta and Great Lakes.
Power
Power Results-at-a-Glance |
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(unaudited) |
| Three months ended December 31 |
| Year ended December 31 |
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| 2002 |
| 2001 |
| 2002 |
| 2001 |
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Power LP investment |
| 9 |
| 10 |
| 36 |
| 39 |
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Northeastern U.S. operations |
| 35 |
| 55 |
| 149 |
| 159 |
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Western operations |
| 30 |
| 15 |
| 131 |
| 149 |
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General, administrative and support costs |
| (25 | ) | (18 | ) | (73 | ) | (49 | ) |
Operating and other income |
| 49 |
| 62 |
| 243 |
| 298 |
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Financial charges |
| (4 | ) | (9 | ) | (13 | ) | (24 | ) |
Income taxes |
| (15 | ) | (18 | ) | (84 | ) | (106 | ) |
Net earnings |
| 30 |
| 35 |
| 146 |
| 168 |
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Power’s net earnings of $146 million for the year ended December 31, 2002 were $22 million lower when compared to 2001. Net earnings of $30 million in fourth quarter 2002 decreased $5 million compared to $35 million in fourth quarter 2001.
Operating and other income from the investment in TransCanada Power, L.P. (Power LP) for the three months ended December 31, 2002 was comparable to the same period in 2001. For the year ended December 31, 2002, earnings were $3 million lower when compared to 2001, primarily due to an unplanned outage at the Williams Lake plant in the first half of 2002 and a reduction in TransCanada’s ownership interest from 41.6 per cent to 35.6 per cent in Power LP, effective October 2001.
Operating and other income from the Northeastern U.S. Operations decreased $10 million and $20 million, for the year and three months ended December 31, 2002, respectively, compared to the same periods in 2001. The decrease is primarily due to lower revenues under long-term power sales arrangements in 2002 and TransCanada’s ability to capitalize on market opportunities in fourth quarter 2001. The annual decrease is partially offset by income from a full year ownership in 2002 of the Curtis Palmer Hydroelectric Company, L.P., which was acquired in July 2001.
Operating and other income from Western Operations of $30 million for the three months ended December 31, 2002 was $15 million higher than the same period in 2001. Results in 2002 included income from the December 2001 acquisition of a 50 per cent interest in the Sundance B power purchase arrangement (PPA), the January 2002 commercial start up of the Redwater and Carseland plants, the November 2002 acquisition of the ManChief plant, and lower contract prices on the sale of output from the Sundance A PPA compared to 2001. Operating and other income for the year ended December 31, 2002 is $18 million lower than 2001, mainly due to lower contract prices for the Sundance A PPA in 2002 and TransCanada’s ability in the first half of 2001 to take advantage of market opportunities created by high market prices and power price volatility. These decreases are partially offset by income from the Sundance B PPA and the Redwater, Carseland and ManChief plants.
The increase in general, administrative and support costs for the three months and year ended December 31, 2002 compared to the same periods in 2001 includes increased project development costs and reflects the continuing investment in the Power business.
Corporate
Net expenses were $12 million and $22 million for the three months ended December 31, 2002 and 2001, respectively. Net expenses were $52 million for the year ended December 31, 2002 compared to $67 million for 2001.
Results for the year ended December 31, 2001 included a positive adjustment of $5 million to foreign currency gains reflecting the January 1, 2002 required retroactive adoption of an accounting change issued by the Canadian Institute of Chartered Accountants related to foreign currency translation. There was no impact of this accounting change in the three months ended December 31, 2001 nor in the year ended December 31, 2002.
Net expenses for fourth quarter 2002 have improved by $10 million compared to fourth quarter 2001, and results for the full year 2002, excluding the impact of the foreign currency accounting change, have improved by $20 million compared to 2001. These improvements are primarily due to lower general and administrative expenses to support discontinued operations and the positive impact of lower interest rates offset by increased Corporate financial charges resulting from the Fair Return decision.
Discontinued Operations
The Board of Directors approved a plan in July 2001 to dispose of the company’s Gas Marketing business. The company’s exit from Gas Marketing was substantially completed by December 31, 2001. As described in Management’s Discussion and Analysis in TransCanada’s 2001 Annual Report, the company remains contingently liable pursuant to obligations under certain energy trading contracts that relate to the divested Gas Marketing business. At December 31, 2002, TransCanada reviewed the provision for loss on discontinued operations, including the approximately $100 million of deferred after-tax gains and remaining obligations related to the Gas Marketing business, and concluded the provision and continued deferral of the gains were appropriate. As a result, there was no earnings impact related to discontinued operations in 2002.
Liquidity and Capital Resources
Funds Generated from Operations
Funds generated from continuing operations of $1,827 million for the year ended December 31, 2002 increased by $203 million in comparison to 2001. Funds generated from continuing operations of $467 million for fourth quarter 2002 increased $106 million compared to the fourth quarter last year.
TransCanada’s ability to generate adequate amounts of cash and cash equivalents in the short term and the long term when needed, and to maintain capacity to provide for planned growth remains substantially unchanged since December 31, 2001.
Investing Activities
In the three months and year ended December 31, 2002, capital expenditures, excluding acquisitions, totalled $202 million (2001 - $174 million) and $599 million (2001 - $492 million),
respectively, and related primarily to maintenance and capacity capital in the Transmission business and ongoing construction of the Bear Creek and MacKay River power plants in Alberta. In fourth quarter 2002, TransCanada acquired the ManChief power plant for $209 million. Acquisitions for the year ended December 31, 2002 totalled $228 million compared to $585 million in 2001.
Financing Activities
TransCanada used a portion of its cash resources to fund debt maturities of $486 million and reduce notes payable by $46 million in 2002.
In the fourth quarter 2002, TransCanada filed shelf prospectuses in Canada and the United States qualifying for issuance of $2 billion of common shares, preferred shares and/or debt securities including medium term notes and US$1 billion of common shares, preferred shares and/or debt securities, respectively. Any offer to sell securities under these shelf prospectuses will only be made by means of prospectus supplements filed with the appropriate securities regulatory authorities.
During the fourth quarter 2002, TransCanada established a new $1.5 billion syndicated credit facility, replacing existing lines set to expire in mid-2003.
Dividends
On January 28, 2003, TransCanada’s Board of Directors declared a quarterly dividend of $0.27 per share for the quarter ended March 31, 2003 on the outstanding common shares. This is the 157th consecutive quarterly dividend paid by TransCanada on its common shares, and is payable on April 30, 2003 to shareholders of record at the close of business on March 31, 2003. The Board also declared regular dividends on TransCanada’s preferred shares.
Discontinued Operations
Net cash provided by discontinued operating activities was $59 million for the year ended December 31, 2002 compared with net cash used in discontinued operating activities of $659 million in 2001. The significant amount of net cash used in the year ended December 31, 2001 was primarily in the Gas Marketing business and included the return in 2001 of margin cash received in 2000, the settlement of natural gas trading losses and other working capital adjustments.
There were no dispositions of discontinued operations in the year ended December 31, 2002 compared to dispositions of $1,170 million in 2001.
Risk Management
With respect to continuing operations, TransCanada’s market risk remains substantially unchanged since December 31, 2001. However, with the deterioration in the creditworthiness of a number of counterparties since December 31, 2001, TransCanada has and will continue to mitigate this heightened credit risk with additional financial assurances, including letters of credit and/or cash. The company has retained certain exposures as a result of the divestiture of the Gas Marketing business. See explanation in Results of Operations - Discontinued Operations. For further information on risks, refer to Management’s Discussion and Analysis in TransCanada’s 2001 Annual Report.
TransCanada manages market and credit risk exposures in accordance with its corporate risk policies and position limits. The policies and limits are designed to mitigate the risk of significant loss. The company’s primary market risks result from volatility in commodity prices, interest rates and foreign currency exchange rates. The company is also exposed to risk of loss due to the failure of counterparties to meet their financial obligations.
Controls and Procedures
Within 90 days prior to the filing of this quarterly report, TransCanada’s management evaluated the effectiveness of the design and operation of the company’s disclosure controls and procedures (disclosure controls) and internal controls for financial reporting purposes (internal controls). Based on that evaluation, the Chief Executive Officer and the Chief Financial Officer have concluded that:
• TransCanada’s disclosure controls are effective in ensuring that material information relating to TransCanada is made known to management on a timely basis, and is included in this quarterly report; and
• TransCanada’s internal controls are effective in providing assurance that the financial statements for this quarter are fairly presented in accordance with Canadian generally accepted accounting principles.
To the best of these officers’ knowledge and belief, there have been no significant changes in internal controls or in other
factors that could significantly affect internal controls subsequent to the date on which such evaluation was completed in connection with this quarterly report.
Critical Accounting Policy
TransCanada’s critical accounting policy is the use of regulatory accounting for its regulated operations which remains unchanged since December 31, 2001. For further information on this critical accounting policy, refer to Management’s Discussion and Analysis in TransCanada’s 2001 Annual Report.
Outlook
The outlook for the company’s segments remains relatively unchanged since December 31, 2001. For further information on outlook, refer to Management’s Discussion and Analysis in TransCanada’s 2001 Annual Report.
The company’s earnings and cash flow combined with a strong balance sheet continue to provide the financial flexibility for TransCanada to make disciplined investments in its core businesses of Transmission and Power. Credit ratings on the company’s senior unsecured debt assigned by Dominion Bond Rating Service Limited (DBRS), Moody’s Investors Service (Moody’s) and Standard & Poor’s are
currently A, A2 and A-, respectively. On December 23, 2002, Standard & Poor’s placed its rating on TransCanada’s senior unsecured debt on ‘CreditWatch’ with negative implications. DBRS and Moody’s continue to maintain a ‘stable’ outlook.
Other Recent Developments
Transmission
Wholly-Owned Pipelines
In December 2002, the EUB approved interim tolls for 2003 on the Alberta System. TransCanada is currently in negotiation with Alberta System customers on the 2003 revenue requirement. TransCanada plans to file an application for approval of the Alberta System 2003 revenue requirement and final 2003 tolls, rates and charges with the EUB by February 28, 2003.
In December 2002, TransCanada’s Mainline interim tolls were approved by the NEB. The NEB is scheduled to commence a public hearing beginning on February 24, 2003 to consider TransCanada’s application for approval of 2003 tolls.
North American Pipeline Ventures
In January 2003, Portland Natural Gas Transmission System received U.S. Federal Energy Regulatory Commission approval, subject to a public comment period, on new tolls which are effective retroactive to April 2002.
Power
In November 2002, TransCanada completed its acquisition of the ManChief power plant from El Paso for $209 million. The ManChief power plant is a simple-cycle, two-turbine facility located near Brush, Colorado and has a generating capacity of 300 megawatts (MW). The entire output of the plant is sold under long-term tolling contracts that expire in 2012.
In December 2002, TransCanada reached an agreement under which affiliates of TransCanada will acquire a 31.6 per cent interest in Bruce Power Limited Partnership (Bruce Power) and an approximate 33.3 per cent interest in Bruce Power Inc., the general partner of Bruce Power, from British Energy plc (BE) for approximately $376 million. TransCanada will also fund a one-third share ($75 million) of a $225 million accelerated deferred rent payment to Ontario Power Generation (OPG). Currently, BE and Cameco Corporation (Cameco) indirectly hold the interests in Bruce Power together with the Power Workers’ Union and The Society of Energy
Professionals. TransCanada, as part of a consortium that includes Cameco and BPC Generation Infrastructure Trust, a trust established by the Ontario Municipal Employees Retirement System, expects to close the transaction in February 2003 pending necessary consents and regulatory approval. The Bruce Power facility is made up of two nuclear plants - Bruce B and Bruce A. Bruce B consists of four reactors, currently generating 3,140 MW. Bruce A consists of four 769 MW reactors, which are currently not operating. Two of the Bruce A units are expected to be restarted and online by the summer of 2003. Bruce Power is a tenant under a lease on the facility which expires in 2018 with an option to extend the lease by up to 25 years. The Bruce Power facility will continue to be managed and operated by the management and staff of Bruce Power. Spent fuel and decommissioning liabilities remain the responsibility of OPG.
In December 2002, TransCanada and OPG announced the formation of Portlands Energy Centre L.P., a 50/50 partnership. The partnership will assess the viability of developing a 550 MW combined cycle natural gas-fuelled cogeneration facility which would be located in the Portlands area of Toronto’s downtown waterfront.
Forward-Looking Information
Certain information in this quarterly report 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.