Exhibit 4.217
FIRST QUARTER 2003
Quarterly Report to Shareholders
Consolidated Results-at-a-Glance
Three months ended March 31 (unaudited) |
| 2003 |
| 2002 |
| ||
Net Income Applicable to Common Shares |
| 208 |
| 187 |
| ||
|
|
|
|
|
| ||
Net Income Per Share - Basic and Diluted |
| $ | 0.43 |
| $ | 0.39 |
|
Management’s Discussion and Analysis
The following discussion and analysis should be read in conjunction with the accompanying unaudited consolidated financial statements of TransCanada PipeLines Limited (TransCanada or the company) for the three months ended March 31, 2003 and the notes thereto.
Results of Operations
Consolidated
TransCanada’s net income applicable to common shares for the three months ended March 31, 2003 was $208 million or $0.43 per share compared to $187 million or $0.39 per share for first quarter 2002. The increase of $21 million or $0.04 per share in first quarter 2003 compared to first quarter 2002 was primarily due to higher earnings from the Power business and reduced net expenses in the Corporate segment, partially offset by lower earnings from the Transmission segment. In first quarter 2003, the Power segment earnings included $27 million related to TransCanada’s earnings from its investment in Bruce Power L.P. (Bruce) which was acquired by TransCanada in February 2003. The lower earnings in the Transmission segment were primarily due to the decline in the
Alberta System’s net earnings reflecting the one-year fixed 2003 revenue requirement settlement reached between TransCanada and its stakeholders in February 2003.
Funds generated from operations of $457 million for the three months ended March 31, 2003 were consistent with the same period in the prior year.
Segment Results-at-a-Glance
Three months ended March 31 (unaudited) |
| 2003 |
| 2002 |
|
Transmission |
| 158 |
| 163 |
|
Power |
| 63 |
| 41 |
|
Corporate |
| (13 | ) | (17 | ) |
|
|
|
|
|
|
Net Income Applicable to Common Shares |
| 208 |
| 187 |
|
Transmission
The Transmission business generated net earnings of $158 million and $163 million for the three months ended March 31, 2003 and 2002, respectively.
Transmission Results-at-a-Glance
Three months ended March 31 (unaudited) |
| 2003 |
| 2002 |
|
Wholly-Owned Pipelines |
|
|
|
|
|
Alberta System |
| 42 |
| 50 |
|
Canadian Mainline |
| 71 |
| 68 |
|
BC System |
| 2 |
| 2 |
|
|
| 115 |
| 120 |
|
North American Pipeline Ventures |
|
|
|
|
|
Great Lakes |
| 17 |
| 22 |
|
TC PipeLines, LP |
| 3 |
| 4 |
|
Iroquois |
| 7 |
| 5 |
|
Portland |
| 7 |
| 1 |
|
Foothills |
| 4 |
| 5 |
|
Trans Québec & Maritimes |
| 2 |
| 2 |
|
CrossAlta |
| 3 |
| 5 |
|
Northern Development |
| (1 | ) | (1 | ) |
Other |
| 1 |
| — |
|
|
| 43 |
| 43 |
|
Net earnings |
| 158 |
| 163 |
|
Wholly-Owned Pipelines
The Alberta System’s net earnings of $42 million in first quarter 2003 decreased $8 million compared to $50 million in the same quarter of 2002. The decrease in net earnings is primarily due to lower earnings as a result of the one-year 2003 revenue requirement settlement which includes a fixed revenue
requirement component of $1.277 billion compared to a fixed revenue requirement component of $1.347 billion in 2002. The Alberta System’s annual net earnings in 2003 are expected to be lower by approximately $40 million after tax compared to annual 2002 net earnings of $214 million.
The Canadian Mainline’s net earnings have increased $3 million for the three months ended March 31, 2003 when compared to the corresponding period in 2002. The increase in 2003 net earnings is mainly due to the National Energy Board’s decision on TransCanada’s Fair Return application (Fair Return decision) which included an increase in the deemed common equity ratio from 30 to 33 per cent, effective January 1, 2001. The Fair Return decision was made in June 2002, and was therefore not reflected in first quarter 2002 earnings. Earnings in first quarter 2003 also reflect an increase in the approved rate of return on common equity from 9.53 per cent in 2002 to 9.79 per cent in 2003, partially offset by a lower average investment base. The NEB hearing which commenced February 26, 2003 to consider the Canadian Mainline 2003 Tolls and Tariff Application is still in process.
Operating Statistics
Three months ended March 31 (unaudited) |
| Alberta |
| Canadian |
| BC |
| ||||||
|
| 2003 |
| 2002 |
| 2003 |
| 2002 |
| 2003 |
| 2002 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average investment base ($millions) |
| 4,966 |
| 5,088 |
| 8,692 |
| 8,974 |
| 238 |
| 200 |
|
Delivery volumes (Bcf) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
| 1,061 |
| 1,067 |
| 805 |
| 697 |
| 61 |
| 105 |
|
Average per day |
| 11.8 |
| 11.9 |
| 8.9 |
| 7.7 |
| 0.7 |
| 1.2 |
|
*Field receipt volumes for the Alberta System for the three months ended March 31, 2003 were 956 Bcf (2002 - 997 Bcf); average per day were 10.6 Bcf (2002 - 11.1 Bcf).
**Canadian Mainline deliveries originating at the Alberta border and in Saskatchewan for the three months ended March 31, 2003 were 592 Bcf (2002 - 552 Bcf); average per day were 6.6 Bcf (2002 - 6.1 Bcf).
North American Pipeline Ventures
TransCanada’s proportionate share of net earnings of $43 million from its other Transmission businesses for the three months ended March 31, 2003 was consistent with the same period in 2002.
Net earnings for the three months ended March 31, 2002 included TransCanada’s $7 million share of a favourable ruling for Great Lakes related to Minnesota use tax paid in prior years. Excluding the impact of the Great Lakes favourable ruling in 2002, net earnings for the three months ended March 31, 2003 increased mainly due to higher earnings from Portland which included a depreciation adjustment related to 2002 and higher tolls in first quarter 2003 compared to first quarter 2002, both as a result of Portland’s rate settlement in early 2003.
Power
Power Results-at-a-Glance
Three months ended March 31 (unaudited) |
| 2003 |
| 2002 |
|
Western operations |
| 43 |
| 34 |
|
Northeastern U.S. operations |
| 25 |
| 41 |
|
Bruce Power L.P. investment |
| 38 |
| — |
|
Power LP investment |
| 11 |
| 10 |
|
General, administrative and support costs |
| (21 | ) | (17 | ) |
Operating and other income |
| 96 |
| 68 |
|
Financial charges |
| (2 | ) | (3 | ) |
Income taxes |
| (31 | ) | (24 | ) |
Net earnings |
| 63 |
| 41 |
|
Power’s net earnings of $63 million for the three months ended March 31, 2003 were $22 million higher when compared to the same period in 2002. Strong earnings from the recently acquired interest in Bruce and the addition of the ManChief plant in late 2002 were the major contributors to this increase, partially offset by lower earnings from the Northeastern U.S. Operations.
Operating and other income from Western Operations of $43 million for the three months ended March 31, 2003 was $9 million higher compared to the same period in 2002 mainly due to the acquisition of the ManChief facility in November 2002 and lower electricity transmission tariffs.
Operating and other income from the Northeastern U.S. Operations was $16 million lower for first quarter 2003 compared to first quarter 2002. The decrease is primarily due to the higher cost of fuel gas at Ocean State Power (OSP) and subsequent limited opportunity to resell gas at a profit, and lower water flows from the Curtis Palmer hydroelectric facility.
In December 2002, OSP concluded an arbitration process with respect to its cost of fuel gas, which substantially increased the cost of fuel for December 2002 through to March 2003. A decision was received on a second arbitration in late March 2003, effective April 2003. This decision is not materially different from the December 2002 decision.
Power completed the acquisition of a 31.6 per cent interest in Bruce on February 14, 2003. Bruce consists of two nuclear plants. Bruce B has four reactors currently generating a total of 3,140 megawatts (MW). Bruce A consists of four 769 MW reactors which are not operating, however, two units are currently undergoing restart activities. Bruce contributed $38 million of equity income ($27 million after tax) in first quarter 2003 from the date of acquisition with an achieved average selling price of $63/MW hour. The four Bruce B units ran at 100 per cent availability during the entire first quarter 2003, the best performance in the plant’s history, and approximately 45 per cent of this output was sold into Ontario’s wholesale spot market. The $38 million contribution reflected strong plant performance and higher than expected market prices in the wholesale spot market as a result of colder than normal weather conditions and increased demand for electricity.
Given the expected critical demand for power in Ontario this summer, Bruce has accelerated its restart activities to ensure the two Bruce A units are available during this critical period. The expectation is that the facility should have full production from the two Bruce A units by the end of June 2003. As a result of these additional efforts, the total restart costs to be incurred by Bruce are expected to be approximately 20 per cent higher than the previous estimate of $450 million (TransCanada's 31.6 per cent share—$142 million), which was comprised of $400 million for the Bruce A Restart Project and $50 million of deferred startup costs.
Equity income from Bruce is directly impacted by fluctuations in 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 has entered into fixed price sales contracts for approximately 1,600 MW of output for the remainder of 2003. There is a planned maintenance outage at one of the four Bruce B units for most of the second quarter 2003, which will reduce quarterly output accordingly. Similarly, there is an approximate one month planned outage at one Bruce B unit and one Bruce A unit in the third and fourth quarter 2003, respectively.
Operating and other income from the investment in TransCanada Power, L.P. was slightly higher for the three months ended March 31, 2003 compared to the same period in 2002, mainly due to increased earnings from the Ontario plants and the unplanned outage that occurred at the Williams Lake plant in first quarter 2002.
Power Sales Volumes*
Three months ended March 31 (unaudited) |
| 2003 |
| 2002 |
|
|
|
|
|
|
|
Western operations |
| 2,614 |
| 2,828 |
|
Northeastern U.S. operations |
| 1,669 |
| 1,152 |
|
Bruce Power L.P. investment |
| 1,087 |
| — |
|
Power LP investment |
| 565 |
| 571 |
|
Total |
| 5,935 |
| 4,551 |
|
*Power sales volumes include TransCanada’s share of Bruce Power L.P. (31.6 per cent) and Sundance B power purchase arrangement (50 per cent) output.
Weighted Average Plant Availability
Three months ended March 31 (unaudited) |
| 2003 |
| 2002 |
|
Western operations |
| 98 | % | 98 | % |
Northeastern U.S. operations |
| 84 | % | 99 | % |
Bruce Power L.P. investment |
| 100 | % | — |
|
Power LP investment |
| 98 | % | 93 | % |
All plants |
| 96 | % | 97 | % |
Corporate
Net expenses were $13 million and $17 million for the three months ended March 31, 2003 and 2002, respectively. This $4 million improvement is primarily due to the positive impact of lower interest costs in first quarter 2003 compared to the same period in the prior year.
Liquidity and Capital Resources
Funds Generated from Operations
Funds generated from operations of $457 million for first quarter 2003 are consistent with the same period in the prior year.
TransCanada expects that its ability to generate sufficient 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 is adequate, and remains substantially unchanged since December 31, 2002.
Investing Activities
In the three months ended March 31, 2003, capital expenditures, excluding acquisitions, totalled $76 million (2002 - $117 million) and related primarily to Iroquois’ ongoing Eastchester Expansion project into New York City, maintenance and capacity capital in wholly-owned pipelines and ongoing construction of the MacKay River power plant in Alberta. Acquisitions for the three months ended March 31, 2003 totalled $409 million (2002 - nil) and were almost entirely comprised of the acquisition of a 31.6 per cent interest in Bruce for $376 million plus closing adjustments.
Financing Activities
TransCanada used a portion of its cash resources to fund long-term debt maturities of $9 million. The company issued notes payable of $209 million in first quarter 2003.
Dividends
On April 25, 2003, TransCanada’s Board of Directors declared a quarterly dividend of $0.27 per share for the quarter ending June 30, 2003 on the outstanding common shares. This is the 158th consecutive quarterly dividend paid by TransCanada on its common shares, and is payable on July 31, 2003 to shareholders of record at the close of business on June 30, 2003. The Board also declared regular dividends on TransCanada’s preferred shares.
Risk Management
With respect to continuing operations, TransCanada’s market, financial and counterparty risks remain substantially unchanged since December 31, 2002. The company has retained certain exposures as a result of the divestiture of the Gas Marketing business. For further information on risks, refer to Management’s Discussion and Analysis in TransCanada’s 2002 Annual Report.
The processes within TransCanada’s risk management function are designed to ensure that risks are properly identified, quantified, reported and managed. Risk management strategies, policies and limits are designed to ensure TransCanada’s risk-taking is consistent with its business objectives and risk tolerance. Risks are managed within limits ultimately established by the Board of Directors and implemented by senior management, monitored by risk management personnel and audited by internal audit personnel.
TransCanada manages market risk exposures in accordance with its corporate market risk policy and position limits. The company’s primary market risks result from volatility in commodity prices,
interest rates, foreign currency exchange rates and the failure of counterparties to meet contractual 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, which remains unchanged since December 31, 2002, is the use of regulatory accounting for its regulated operations. For further information on this critical accounting policy, refer to Management’s Discussion and Analysis in TransCanada’s 2002 Annual Report.
Critical Accounting Estimates
Since a determination of many assets, liabilities, revenues and expenses is dependent upon future events, the preparation of the company’s consolidated financial statements requires the use of estimates and assumptions which have been made using careful judgment. TransCanada’s critical accounting estimates, which remain unchanged since December 31, 2002, are depreciation expense and certain deferred after-tax gains and remaining obligations related to the Gas Marketing business. For further information on these critical accounting estimates, refer to Management’s Discussion and Analysis in TransCanada’s 2002 Annual Report.
Outlook
The strong contribution from Bruce in first quarter 2003 is expected to result in higher Power net earnings in 2003 than originally anticipated. The company does not expect its quarterly net earnings from Bruce to continue at this rate for the remaining quarters of 2003. The outlook for the company’s other segments remains relatively unchanged since December 31, 2002. For further information on outlook, refer to Management’s Discussion and Analysis in TransCanada’s 2002 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. Standard & Poor’s has placed its rating of 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
Canadian Mainline
In February 2003, the NEB denied the September 2002 request made by TransCanada for a review and variance of the Fair Return decision. TransCanada maintains that the Fair Return decision does not recognize the long-term business risks of the Canadian Mainline. On March 21, 2003, TransCanada applied to the Federal Court of Appeal for leave to appeal the Fair Return decision. If TransCanada’s leave to appeal application is successful, the appeal will go forward to the Federal Court of Appeal. TransCanada is basing its leave to appeal application on two questions of law.
The NEB hearing which commenced February 26, 2003 to consider the Canadian Mainline 2003 Tolls and Tariff Application is still in process. In this application, TransCanada is requesting approval of a higher composite depreciation rate, introduction of a new tolling zone in southwestern Ontario, an increase to the Interruptible Transportation bid floor price and cost/efficiency incentive mechanisms.
Alberta System
In February 2003, TransCanada reached a settlement regarding the 2003 revenue requirement for the Alberta System. The settlement is the result of a consultative process that included producers, industrial users, consumer groups, marketers and export groups. The one-year settlement establishes the Alberta System’s fixed revenue requirement for 2003. This settlement is currently before the EUB for approval together with the Alberta System 2003 Tariff Settlement which includes proposed modifications to rate design and an application for a new service. These settlements are expected to form the basis of the Alberta System tolls for 2003. TransCanada had originally applied to the EUB for approval of two new services but, after consulting with its customers, has withdrawn the application for one of the proposed services.
Power
In February 2003, TransCanada completed the acquisition of a 31.6 per cent interest in Bruce for $376 million plus closing adjustments. TransCanada also loaned a one-third share ($75 million) of a $225 million accelerated deferred rent payment to Ontario Power Generation. Bruce is a tenant under a lease on the Bruce nuclear power facility in Ontario. The lease expires in 2018 with an option to extend the lease by up to 25 years.
TransCanada’s newest power facility, the Bear Creek plant, commenced commercial operations in first quarter 2003. This 80 megawatt cogeneration facility near Grande Prairie, Alberta will sell, under a 25 year agreement, the majority of its power to Weyerhaeuser at its Grande Prairie Pulp Mill as well as Weyerhaeuser’s other Alberta facilities.
Corporate
In first quarter 2003, TransCanada’s Board of Directors unanimously recommended common shareholders vote in favour of a proposal to create a new holding company, TransCanada Corporation (Holdco), to become the parent of TransCanada PipeLines Limited.
The proposal will be voted on April 25, 2003 at TransCanada’s Annual and Special Meeting of Shareholders. The company will announce the results of the vote after the Meeting. The financial statements of Holdco will be prepared using the continuity of interests method. Accordingly, the financial statements of Holdco on the effective date, on a consolidated basis, will in all material respects be the same as those of TransCanada immediately prior to the arrangement, except as to the accounting treatment of the company’s preferred securities and preferred shares. For further information on this, refer to TransCanada’s 2003 Management Proxy Circular.
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.