PACIFICORP /OR/ - Quarter Report: 2000 September (Form 10-Q)

See accompanying Notes to Condensed Consolidated Financial Statements

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See accompanying Notes to Condensed Consolidated Financial Statements

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See accompanying Notes to Condensed Consolidated Financial Statements

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liability. These merger credits were offsetable against merger savings and created a contingent liability at the merger date. The Washington rate order removed the ability to offset these credits against savings. The Company incurred expense of $4 million pretax and after-tax during the quarter ended September 30, 1999 and $12 million pretax and after-tax during the six-month period ended September 30, 1999 in costs associated with the ScottishPower merger.

 4.  RELATED PARTY TRANSACTIONS

The Company had $8 million and $5 million as of September 30, 2000 and March 31, 2000, respectively, of accrued liabilities payable to ScottishPower. These liabilities represent costs incurred by ScottishPower employees employed as Company management and ScottishPower employees temporarily working for the Company on its transition plan. In addition, at September 30, 2000, the Company had a $350 million note receivable and $2 million in related accrued interest receivable from ScottishPower.

 5.  DISCONTINUED OPERATIONS

In October 1998, the Company decided to exit its energy trading business by offering TPC Corporation ("TPC") for sale and ceasing the eastern U.S. electricity trading operations of PacifiCorp Power Marketing ("PPM"). PPM's activities in the eastern United States have been discontinued and all forward electricity trading has been closed. On April 1, 1999, Holdings sold TPC to NIPSCO Industries, Inc. for $150 million. This activity resulted in a net after-tax gain of $1 million in the first quarter of 2000.

 6.  ACCOUNTING FOR THE EFFECTS OF REGULATION

On November 1, 2000, the Company filed applications seeking deferred accounting treatment for net power costs in excess of costs included in determining retail rates in the states of Utah, Idaho, Wyoming and Oregon. The applications seek to defer excess power costs beginning November 1, 2000. These deferred accounting requests seek to accumulate charges for recovery in future periods. The Company will initiate discussions with the staffs of the commission in each state where an application was filed to develop a mechanism, by the end of March 2001, for the recovery of the deferred amount and a proposal for the timing of such recovery.

On May 24, 2000, the Company received an order from the Utah Public Service Commission (the "UPSC") authorizing increased prices in Utah for residential, irrigation, small commercial and lighting customers of 4.24% and large commercial and industrial customers of less than 1%. The price increase is expected to result in additional annual revenues of $17 million. The order was effective on May 25, 2000 and allowed recovery of early retirement and pension costs, reclamation costs, and Year 2000 and other information systems costs that had been previously written off. As a result, $17 million in regulatory assets was established in the first quarter of 2001 relating to cost recoveries which required no additional review and $25 million in regulatory assets was established in the second quarter of 2001 relating to cost recoveries which successfully passed additional review. An additional $7 million is expected to be recovered in future periods following further review.

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On September 27, 2000, the Company received an order from the Oregon Public Utility Commission (the "OPUC") authorizing increased prices in Oregon for residential customers of 2.33%, commercial and small industrial customers of 1.37%, large industrial customers of 0.4%, and public street lighting customers of 1.27%. The price increase is expected to result in annual revenues of $14 million. The order was effective on October 1, 2000.

On June 20, 2000, the Company received approval from the OPUC for an overall price increase of 1.8%, or $13.7 million, through an annual adjustment as part of the alternative form of regulation process previously authorized in Oregon ("AFOR"). Of this amount, approximately $10 million is offset by costs mandated by regulators. The increase will cause rates for residential customers to rise by 2.9%, for large industrial users by 1.1%, and for commercial customers by 0.5%. The new rates took effect July 1, 2000 and are expected to increase annual revenues by approximately $3.7 million net of costs mandated by the OPUC.

During 1999, legislation was enacted in Oregon that requires competition for industrial and large commercial customers of both the Company and Portland General Electric Company by October 1, 2001. See "Item 1. Business-Domestic Electric Op erations-Competition" in the Company's Annual Report on Form 10-K for the fiscal year ended March 31, 2000. The law ("SB 1149") authorizes the OPUC to make decisions on a variety of important issues, including the method for valuation of stranded costs/benefits.

On October 2, 2000, the Company filed its plans to implement the requirements outlined by SB 1149 and subsequent commission rules. This includes how electricity service suppliers would be certified, customer metering and billing options, and electricity delivery issues. On November 1, 2000, the Company filed the unbundling information required under SB 1149 rules and requested a related $160 million in increased revenues. On December 1, 2000, the Company plans to file a resource plan to address the manner in which the Company proposes to use its generation resources under SB 1149.

In connection with the SB 1149 process, the Company expects to submit an estimate of the value of its generating facilities. This valuation will be based on various assumptions, including future electricity prices and cost estimates for compliance with existing and anticipated air quality regulations impacting the Company's thermal generation, as well as the estimated costs associated with relicensing of the Company's hydroelectric facilities. The Company's preliminary analyses indicate that the after-tax present value of the air quality and hydroelectric costs over the projected useful life of the thermal plants, and the term of the licenses in the case of the hydroelectric licenses, could exceed $1 billion predominantly in increased capital expenditures. The final outcome is dependent on a variety of factors, including the actual terms and applicability of existing and anticipated environmental laws and regulations, the costs associated with lost generation, developments in pollution control technologies, and the actual terms and conditions of any new hydroelectric licenses. The ultimate impact of these compliance costs on the Company will depend on the regulatory treatment of such costs, whether the Company elects to sell or abandon facilities rather than make the required capital expenditures, and numerous other factors, many of which are beyond the Company's control.

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On May 25, 2000, the Company received an order from the Wyoming Public Service Commission ("WPSC") authorizing an increase in prices resulting in increased annual revenues of $11 million. The WPSC did not allow recovery of approximately $1 million of the requested $12 million increase allocated to partial requirements industrial customers, finding that the cost of service study was not sufficient to support the increase to this class. The Company refiled for this $1 million increase and received WPSC approval effective July 19, 2000.

On August 9, 2000, the Company received an order from the Washington Utilities and Transportation Commission (the "WUTC") which authorized the Company to increase rates by 3% on September 1, 2000, 3% on January 1, 2002 and 1% on January 1, 2003. In the second quarter of 2001, the Company recorded $12 million in ScottishPower merger costs relating to Washington merger credits. See Note 3 to the condensed consolidated financial statements.

On October 25, 2000, the WUTC approved the Company's application for a system benefits charge to recover costs associated with funding energy efficiency programs. The Company will collect approximately $2.8 million per year through December 31, 2002.

On June 5, 2000, the Idaho Public Utilities Commission approved implementation of the third step in the planned phase-out of Bonneville Power Administration ("BPA") residential and irrigation exchange credits, which expire in 2001. See the Company's 2000 Annual Report on Form 10-K for more information.

The Company, in conjunction with eight other utilities, is involved in a voluntary effort to form a Regional Transmission Organization ("RTO"), named RTO West, in support of Federal Energy Regulatory Commission ("FERC") Order 2000. The nine members of RTO West will be Avista Corporation, BPA, Idaho Power Company, Montana Power Company, Nevada Power Company, PacifiCorp, Portland General Electric Company, Puget Sound Energy, Inc. and Sierra Pacific Power Company. Creation of RTO West is subject to regulatory approvals from FERC and the states served by these entities. RTO West plans to operate all transmission facilities needed for bulk power transfers and control about 30,000 miles of the 50,000 miles of transmission line owned by the entities. On October 16 and October 23, 2000, the members made filings addressing the structural and operational issues associated with the RTO formation.

 7.  CONTINGENT LIABILITIES

The Company and its subsidiaries are parties to various legal claims, actions and complaints, certain of which involve material amounts. Although the Company is unable to predict with certainty whether or not it will ultimately be successful in these legal proceedings or, if not, what the impact might be, management currently believes that disposition of these matters will not have a materially adverse effect on the Company's consolidated financial statements.

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 8.  ASSET SALES

On September 6, 2000, the Company completed the sale of its ownership of Powercor pursuant to the August 2, 2000 agreement to sell Powercor and the Company's 19.9% interest in Hazelwood, both indirectly owned subsidiaries of the Company, to Cheung Kong Infrastructure and Hongkong Electric Holdings for approximately AUS $2.4 billion, including repayment or assumption of debt of approximately AUS $1.3 billion. Powercor and Hazelwood represent all of the Australian electric operations segment of the Company. Of the estimated $673 million in net sales proceeds, which are subject to final selling expenses and other adjustments, $350 million was lent to a directly owned subsidiary of ScottishPower. The remaining proceeds of $323 million are expected to be used to repay debt of the Company. The sale of the Company's interest in Hazelwood is subject to certain additional conditions, including the rights of the other partners in Hazelwood to purchase the Company's interest. The Hazelwood sale is expected to conclude later in 2001. The Company recorded an estimated impairment of $188 million in anticipation of the loss on the sale of the Australian electric operations segment in the first quarter of 2001, which was adjusted in the second quarter of 2001 to $197 million upon the completion of the sale of its indirect ownership of Powercor. This estimate is subject to further adjustment upon completion of the sale of the Company's interest in Hazelwood.

The loss on sale of Australian electric operations is as follows:

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amortized by regulatory jurisdiction over periods of up to 20 years. After reflecting the amount to be returned to customers, the Company recorded a one-time loss of $14 million associated with this sale. For more information on the sale, see the Company's 2000 Annual Report on Form 10-K.

The Company has an agreement with Nor-Cal Electric Authority for the sale of the Company's California electric assets for $178 million. The Company does not expect to incur a material gain or loss on this sale. On August 7, 2000, the Administrative Law Judge (the "ALJ") for the California Public Utilities Commission (the "CPUC") issued a draft decision that would dismiss the Company's application for approval of the sale to Nor-Cal. In addressing the ALJ's draft decision, the CPUC could approve, reject, or modify the decision. This draft decision is currently scheduled to be addressed by the CPUC on November 21, 2000.

 9.  INCOME TAXES

The Company accrued federal and state income tax expense of $43.7 million on the loss from continuing operations for the six months ended September 30, 2000. For the six months ended September 30, 2000 and 1999, the difference between taxes calculated as if the statutory federal tax rate of 35% was applied to income from continuing operations before income taxes and the recorded tax expense is reconciled as follows:

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After removing the impacts of the loss on the sale of Australian electric operations, merger costs and the alternative fuel credits on the pretax loss and the effective tax rate, the Company's combined federal and state effective income tax rate from continuing operations would have been 40% for the six months ended September 30, 2000 and 38% for the six months ended September 30, 1999.

10.  COMPREHENSIVE INCOME

The components of comprehensive income are as follows:

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12.  SEGMENT INFORMATION

Selected information regarding the Company's operating segments, Domestic electric operations, Australian electric operations, and Other operations, are as follows:

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to the second quarter of 2000, the higher market prices resulted in higher wholesale revenue. This benefit, combined with the higher retail sales generated from load growth, served to partially offset the high purchased power prices. Additional favorable operating expense variances resulting from asset write backs occurred due to the May 2000 Utah rate order, which successfully resolved issues surrounding previously denied costs. See Note 6 to the condensed consolidated financial statements.

Australian electric operations recorded earnings of $7 million in the second quarter of 2001 compared to earnings of $5 million in the 2000 quarter. On September 6, 2000, the Company completed the sale of Powercor. See Note 8 to the condensed consolidated financial statements.

Other operations reported income of $21 million in the 2001 quarter compared to $11 million in the 2000 quarter. This increase was primarily due to a reduction in expenses relating to exiting energy development businesses, and a net gain recognized upon settlement of foreign currency exchange swaps upon the sale of Powercor. See Note 8 to the condensed consolidated financial statements.

Comparison of the six-month periods ended September 30, 2000 and 1999

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Domestic electric earnings contribution decreased by $47 million compared to the first half of 2000. Retail sales volumes increased 4% over last year, primarily due to increased economic activity and hotter than normal weather. The increase in demand, coupled with unexpected plant outages throughout the WSCC, drove prices to unusually high levels. The Company was required to purchase power at these high prices, which resulted in an unfavorable purchased power expense variance. Despite having significantly less excess electricity available to sell into the wholesale market compared to the first half of 2000, the higher market prices resulted in higher wholesale revenue. This benefit, combined with the higher retail sales generated from load growth, served to partially offset the high purchased power prices. Additional favorable operating expense variances resulting from asset write backs occurred due to the May 2000 Utah rate order which successfully resolved issues surrounding previously denied costs. Further, the Company recorded a loss on the May 2000 sale of the Centralia plant and mine. See Notes 6 and 8 to the condensed consolidated financial statements.

Australian electric operations recorded a loss of $186 million in the first half of 2001 compared to earnings of $14 million in the first half of 2000. This decrease was primarily due to the $217 million loss recorded on the September 6, 2000 sale of the indirect ownership of Powercor. The estimated impairment loss on the sale of Australian electric operations was originally recognized in the first quarter of 2001. See Note 8 to the condensed consolidated financial statements.

Other operations reported income of $47 million in the first half of 2001 compared to $14 million in the first half of 2000. This increase was primarily due to a reduction in expenses relating to exiting energy development businesses, and a net gain recognized upon settlement of foreign currency exchange swaps upon the sale of the Company's indirect ownership of Powercor. See Note 8 to the condensed consolidated financial statements.

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DOMESTIC ELECTRIC OPERATIONS

The Company's operations are planned and managed to meet anticipated requirements through its portfolio of low cost generating assets and purchase contracts. Demand for power in 2001 continued to exceed expectations as a result of strong economic growth in the region and hotter than normal weather conditions. Supply in the WSCC has not kept pace with growing demand and the price of natural gas has increased. These factors, along with unanticipated generation outages in the WSCC, including at some of the Company's facilities, led to increases in the level and volatility of power prices during 2001. Lower margins were realized in the three months and six months ended September 30, 2000 as a result of purchasing power to meet demand requirements at prices in excess of tariff rates for retail sales.

Comparison of the three-month periods ended September 30, 2000 and 1999

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Residential revenues increased by $17 million, or 9%. Growth in the average number of residential customers of 2% added $4 million to revenues. Price increases in Oregon, Utah and Wyoming added $6 million to revenues in 2001. Volume increases of 6% increased residential revenues by $7 million.

Commercial revenues increased by $9 million, or 5%, primarily as a result of increased economic activity in Utah and Oregon. Growth in the average number of commercial customers of 3% added $6 million to revenues and volume increases of 7% added $5 million to revenues.

Industrial revenues were up $8 million, or 4%. Weather conditions in the region caused increased irrigation usage, adding $4 million to revenues. Price increases in Oregon, Utah and Wyoming increased revenues by $3 million.

Wholesale sales increased $251 million, or 91%. Sales prices for short-term firm and spot market sales prices averaged $116 per megawatt hour ("MWh") in 2001 compared to $32 per MWh in 2000, creating a $423 million increase in revenues. Higher long-term firm contract volumes added $21 million to revenues. Partially offsetting these increases was a $198 million decrease resulting from 34% lower short-term firm and spot market energy volumes.

Other revenues increased by $11 million, or 52%, primarily due to an increase in wheeling revenues.

See Note 6 to the condensed consolidated financial statements regarding recent regulatory action relating to domestic electric operations.

Operating Expenses

Total operating expenses increased $359 million, or 52%. This increase was primarily attributable to increased purchased power expense due to increased prices on short-term purchased power.

Purchased power expense was $664 million, an increase of $389 million, or 141%. Higher prices on short-term firm and spot market purchases increased purchased power expense by $334 million. Short-term firm and spot market purchase prices averaged $106 per MWh in the quarter versus $36 per MWh in 2000. Demand for power continued to exceed expectations as a result of strong economic growth in the region and hotter than normal weather conditions. Supply in the WSCC did not keep pace with growing demand. These factors, along with unanticipated generation outages in the WSCC, led to increases in the level and volatility of power prices during the second quarter of 2001. An 8% increase in short-term firm and spot market purchases added $28 million to purchased power expense. Increased volumes relating to long-term firm contracts added $24 million to purchased power expense.

Fuel costs decreased $7 million, or 6%, to $118 million, primarily due to the May 2000 sale of the Centralia generation plant, partially offset by increased generation, which resulted in higher fuel consumption.

Other operations and maintenance expense increased $12 million, or 10%. An increasing amount of work relating to expense rather than capital projects resulted in $14 million of additional expense. Increased tree trimming added

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$2 million. These unfavorable variances were partially offset by a $4 million decrease in bad debt expense.

Administrative, general and taxes - other decreased $14 million, or 20%. Decreased labor and severance costs resulted in a $6 million favorable variance. Pension costs were $4 million lower in 2001 due to favorable returns on plan assets. In addition, property tax expense decreased by $3 million and rent expense decreased by $1 million.

Included within Operating expenses in 2001 were amounts recorded which related to issues surrounding previously denied costs addressed in the Utah rate order received in May 2000, which were successfully resolved in the quarter and resulted in the establishment of an additional $25 million in regulatory assets. See Note 6 to the condensed consolidated financial statements.

Other Income and Expense

Domestic electric operations interest expense decreased $3 million primarily due to lower debt balances. Second quarter 2000 results included $4 million of ScottishPower merger costs compared to $9 million in 2001. The expense in 2001 is primarily related to merger credits in the state of Washington becoming unavailable for offset. See Note 3 to the condensed consolidated financial statements. Income tax expense decreased $28 million primarily due to the decrease in taxable income.

Comparison of the six-month periods ended September 30, 2000 and 1999

Revenues

Total domestic electric operations revenues increased $374 million, or 23%, from the first half of 2000. This was primarily attributable to increases in wholesale sales of $297 million and an increase of $57 million in retail revenues.

Residential revenues increased by $18 million, or 5%. Growth in the average number of residential customers of 2% added $7 million to revenues. Price increases in Oregon, Utah and Wyoming added $8 million to revenues in 2001. Volume increases of 3% increased residential revenues by $3 million.

Commercial revenues increased by $20 million, or 6%, primarily as a result of increased economic activity in Utah and Oregon. Growth in the average number of commercial customers of 3% added $12 million to revenues and volume increases of 7% added $10 million to revenues.

Industrial revenues increased by $19 million, or 5%. Energy volumes were up 3%, which added $4 million to revenues. Price increases in Oregon, Utah and Wyoming added $4 million to revenues. Weather conditions in the region caused increased irrigation usage, adding $11 million to revenues.

Wholesale sales increased $297 million, or 57%. Sales prices for short-term firm and spot market sales averaged $80 per MWh in 2001 compared to $25 per MWh in 2000, creating a $576 million increase in revenues. Higher long-term firm contract volumes added $26 million to revenues. Partially offsetting these increases was a $303 million decrease resulting from lower short-term firm and spot market energy volumes.

Other revenues increased by $19 million, or 48%, primarily due to an $11 million increase in wheeling revenues and $7 million in revenues resulting from a favorable AFOR price increase in Oregon. These revenue increases were partially offset by costs mandated by regulators.

See Note 6 to the condensed consolidated financial statements regarding recent regulatory action relating to domestic electric operations.

Operating Expenses

Total operating expenses increased $453 million, or 34%. This increase was primarily attributable to increased purchased power expense due to increased prices on short-term purchased power.

Purchased power expense was $998 million, an increase of $496 million, or 99%. Higher prices on short-term firm and spot market purchases increased purchased power expense by $479 million. Short-term firm and spot market purchase prices averaged $80 per MWh in the first half of 2001 versus $27 per MWh in 2000. Demand for power continued to exceed expectations as a result of strong economic growth in the region and hotter than normal weather conditions. Supply in the WSCC did not keep pace with growing demand. These factors, along with unanticipated generation outages in the WSCC, led to increases in the level and volatility of power prices during the first half of 2001. Partially

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offsetting the higher prices was a 13% decrease in short-term firm and spot market purchases which decreased costs by $20 million. Increased volumes relating to long-term firm contracts added $32 million to purchased power expense.

Fuel costs decreased $9 million, or 4%, to $220 million, primarily due to the May 2000 sale of the Centralia generation plant, partially offset by increased generation, which resulted in higher fuel consumption.

Other operations and maintenance expense increased $10 million, or 4%. Power supply expenses decreased by $6 million as a result of the sale of the Centralia plant and mine and bad debt expense decreased by $5 million. Increased tree trimming added $3 million. Offsetting these net favorable variances was increased labor expense resulting from an increasing amount of work relating to expense rather than capital projects.

Administrative, general and taxes - other decreased $18 million, or 14%. Contract services relating to Year 2000 conversion and SAP conversion decreased $5 million. Decreased labor and severance costs resulted in a $5 million favorable variance. Employee related expenses decreased $2 million, primarily due to the impact of favorable returns on pension plan assets on pension expense. In addition, both property tax expense and rent expense decreased by $2 million.

Included within Operating expenses in 2001 was a $42 million gain related to the Utah rate order received in May 2000 which successfully resolved issues surrounding previously denied costs and resulted in the establishment of a $42 million regulatory asset. In addition, the Company recorded a one-time loss of $14 million on the sale of the Centralia Power Plant and mine. See Notes 6 and 8 to the condensed consolidated financial statements.

Other Income and Expense

Domestic electric operations interest expense decreased $5 million primarily due to lower debt balances. The first half of 2000 results included $12 million of ScottishPower merger costs compared to $9 million in 2001. The expense in 2001 is primarily related to merger credits in the state of Washington becoming unavailable for offset. See Note 3 to the condensed consolidated financial statements. Income tax expense decreased $27 million due to the decrease in taxable income, partially offset by the income tax impact of disposal of the Centralia plant and mine assets.

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AUSTRALIAN ELECTRIC OPERATIONS

On September 6, 2000, the Company completed the sale of its indirect ownership of Powercor pursuant to the August 2, 2000 agreement to sell Powercor and the Company's 19.9% interest in Hazelwood. The Hazelwood sale is expected to occur later this year. See Note 8 to the condensed consolidated financial statements.

Australian electric operations' financial results for the period from April 1, 2000 to the date of sale are included in PacifiCorp's financial results for the quarter ended September 30, 2000. Australian electric operations' financial results for the period from January 1, 2000 to the date of sale are included in PacifiCorp's financial results for the six months ended September 30, 2000. For purposes of this discussion, these financial results are referred to as "September 30, 2000" results. See Note 2 to the condensed consolidated financial statements.

Comparison of the three-month periods ended September 30, 2000 and 1999

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offset by an increase in administrative and general expenses incurred in 2001, primarily due to costs associated with a project to transition to full retail contestability.

The power supplier in the dispute noted above did not meet its contractual obligation to deliver power to Powercor at the agreed upon rate, which forced Powercor to purchase power on the open market in 2000 at a rate higher than it paid in 2001. On November 17, 1999, the Supreme Court of Victoria upheld the validity of the contracts with the supplier and, on December 14, 1999, ordered specific performance on the remaining contracts and payment of $29 million for failure to perform in the past. On December 21, 1999, the power supplier filed a notice of appeal seeking to overturn all of the judgments against it. This dispute was settled during the second quarter of 2001 and the appeal was discontinued.

Comparison of the six-month periods ended September 30, 2000 and 1999

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OTHER OPERATIONS

Comparison of the three-month periods ended September 30, 2000 and 1999

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Holdings and other operations' 2000 results included losses associated with exiting energy development businesses of approximately $8 million. Additionally, net interest income in 2001 increased $4 million compared to the prior year, and the sale of the Company's investment in Australian electric operations resulted in a net gain on settlement of foreign currency exchange swaps and debt repayment expense of $20 million. See Note 8 to the condensed consolidated financial statements.

Earnings at Pacific Klamath Energy Inc. decreased by $5 million because 2000 included revenue relating to the initial development of a cogeneration project in Klamath Falls, Oregon.

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FINANCIAL CONDITION -

For the six months ended September 30, 2000:

OPERATING ACTIVITIES

Net cash flows provided by continuing operations were $434 million during the period compared to $412 million for the first half of 2000.

Net cash used in discontinued operations in 2000 represents cash funding of TPC operations through an intercompany note payable to Holdings.

INVESTING ACTIVITIES

Capital spending totaled $222 million in 2001 compared with $300 million in 2000. Construction expenditures decreased in 2001 primarily due to lower expenditures at domestic electric operations attributable to the timing of projects. Proceeds from asset sales in 2001 were primarily the result of the sales of Powercor and the Centralia plant and mine, while proceeds from asset sales in 2000 are attributable to the sale of TPC.

CAPITALIZATION

At September 30, 2000, PacifiCorp had approximately $47 million of commercial paper and uncommitted bank borrowings outstanding at a weighted average rate of 6.8%. These borrowings are supported by a $500 million revolving credit agreement.

In July 2000, Holdings paid off $250 million of debt in anticipation of the Powercor sale.

DIVIDENDS

On May 15, 2000, the Company declared a dividend on common stock of $149 million payable to ScottishPower, the sole common shareholder of record. The dividend was paid June 14, 2000. On June 22, 2000, the Company declared a dividend on common stock of $80 million which was paid to ScottishPower on August 15, 2000. On September 21, 2000, the Company declared a dividend on common stock of $80 million, which is scheduled to be paid to ScottishPower on November 13, 2000.

On May 15, 2000, the Company declared a dividend on preferred stock of $4 million, which was paid to shareholders on August 15, 2000. On August 17, 2000, the Company declared a dividend on preferred stock of $4 million, which is scheduled to be paid to shareholders on November 15, 2000.
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The condensed consolidated financial statements as of September 30, 2000 and March 31, 2000 and for the three- and six-month periods ended September 30, 2000 have been reviewed by PricewaterhouseCoopers LLP, independent accountants, in accordance with standards established by the American Institute of Certified Public Accountants. A copy of their report is included herein.

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SIGNATURE

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

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