PACIFICORP /OR/ - Quarter Report: 1999 December (Form 10-Q)

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

/X/  QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
     EXCHANGE ACT OF 1934

For the quarterly period ended December 31, 1999

OR

/ /  TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
     EXCHANGE ACT OF 1934

For the transition period from _______________ to _______________

Commission file number 1-5152

PACIFICORP
(Exact name of registrant as specified in its charter)

        STATE OF OREGON                                       93-0246090
 (State or other jurisdiction                             (I.R.S. Employer
of incorporation or organization)                         Identification No.)


825 N.E. Multnomah
Suite 2000
Portland, Oregon                                                     97232
(Address of principal executive offices)                          (Zip code)

503-813-5000
(Registrant's telephone number)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding twelve months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for at least the past 90 days.

     YES  X      NO _____

PACIFICORP

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PART I. FINANCIAL INFORMATION
  Item 1. Financial Statements

PACIFICORP
CONDENSED CONSOLIDATED STATEMENTS OF INCOME AND RETAINED EARNINGS
(Millions of Dollars, except per share amounts)
(Unaudited)

See accompanying Notes to Condensed Consolidated Financial Statements

2

PACIFICORP
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Millions of Dollars)
(Unaudited)

See accompanying Notes to Condensed Consolidated Financial Statements

3

PACIFICORP
CONDENSED CONSOLIDATED BALANCE SHEETS
(Millions of Dollars)
(Unaudited)

ASSETS

See accompanying Notes to Condensed Consolidated Financial Statements

4

PACIFICORP
CONDENSED CONSOLIDATED BALANCE SHEETS
(Millions of Dollars)
(Unaudited)

LIABILITIES AND SHAREHOLDERS' EQUITY

See accompanying Notes to Condensed Consolidated Financial Statements

5

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

December 31, 1999

 1.  FINANCIAL STATEMENTS

The accompanying unaudited condensed consolidated financial statements as of December 31, 1999 and March 31, 1999 and for the periods ended December 31, 1999 and 1998, in the opinion of management, include all adjustments, constituting only normal recording of accruals, necessary for a fair presentation of financial position, results of operations and cash flows for such periods. A significant part of the business of PacifiCorp (the "Company") is of a seasonal nature; therefore, results of operations for the periods ended December 31, 1999 and 1998 are not necessarily indicative of the results for a full year. These condensed consolidated financial statements should be read in conjunction with the financial statements and related notes in the Company's 1998 Annual Report on Form 10-K/A Amendment No. 1.

On November 29, 1999, the Company and Scottish Power PLC ("ScottishPower") completed their proposed merger under which the Company became an indirect subsidiary of ScottishPower. The Company will continue to operate under its current name, and its headquarters will remain in Portland, Oregon. As a result of the merger with ScottishPower, the Company became part of a public utility holding company group. The Company's operations are now subject to the requirements and restrictions of the Public Utility Holding Company Act of 1935.

Each share of the Company's stock was converted tax-free into a right to receive 0.58 American Depositary Shares (each ADS represents four ordinary shares) or 2.32 ordinary shares of ScottishPower. Cash was paid in lieu of fractional shares.

The condensed consolidated financial statements of the Company include the integrated domestic electric utility operations of Pacific Power and Utah Power and its wholly owned and majority owned subsidiaries. Major subsidiaries, all of which are wholly owned, are: PacifiCorp Group Holdings Company ("Holdings"), which holds directly or through its wholly owned subsidiary, PacifiCorp International Group Holdings Company, all of the Company's nonintegrated electric utility investments, including Powercor Australia Limited ("Powercor"), an Australian electricity distributor, and PacifiCorp Financial Services, Inc. ("PFS"), a financial services business. Together these businesses are referred to herein as the Companies. Significant intercompany transactions and balances have been eliminated. As a result of regulatory requirements and the existence of debt instruments that are secured by the assets of the Company, the basis of assets and liabilities reported in the Company's financial statements have not been revised to reflect the acquisition of the Company by ScottishPower. The basis of assets, liabilities and shareholder's equity continue to be presented at historical cost.

During January 2000, the Company decided to seek a buyer for Powercor. As of December 31, 1999, the Company estimates that there will be no material gain or loss realized on the disposition of the Powercor business.

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During October 1998, the Company decided to exit its energy trading business, which consisted of TPC Corporation ("TPC") and PacifiCorp Power Marketing, Inc. ("PPM"). On April 1, 1999, the Company sold TPC. See Note 3. During May 1998, the Company sold a majority of the real estate assets held by PFS. The Company also decided in October 1998 to exit the majority of its other energy development businesses and has recorded them at estimated net realizable value less selling costs.

Investments in and advances to affiliated companies represent investments in unconsolidated affiliated companies carried on the equity basis, which approximates the Company's equity in their underlying net book value.

Certain amounts have been reclassified to conform with the fiscal 2000 method of presentation. These reclassifications had no effect on previously reported consolidated net income.

 2.  CHANGE IN FISCAL YEAR

Effective November 30, 1999, the Company changed its fiscal year end from December 31 to March 31, which is the fiscal year end for ScottishPower. A report for the three-month transition period from January 1, 1999 through March 31, 1999 was filed with the Securities and Exchange Commission on January 13, 2000. As a result of this change, the first quarter refers to the period April through June, the second quarter refers to July through September, the third quarter refers to October through December and the fourth quarter refers to January through March. The year ending March 31, 2000 and quarterly periods within that year are referred to as 2000 periods.

 3.  DISCONTINUED OPERATIONS

In October 1998, the Company decided to exit its energy trading business by offering TPC for sale and ceasing the operations of PPM, which conducted electricity trading in the eastern United States. 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 an after-tax gain of $1 million in the first quarter of fiscal 2000.

The net assets, operating results and cash flows of the energy trading operations have been classified as discontinued operations for all periods presented in the consolidated financial statements and notes.

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Summarized operating results for the energy trading operations were as follows:

As mentioned previously, net assets of the discontinued operations were sold April 1, 1999. Net assets of the discontinued operations and assets held for sale as of March 31, 1999 consisted of the following:

Holdings had $20 million and $45 million as of December 31, 1999 and March 31, 1999, respectively, of liabilities in "Customer deposits and other" relating to the sale or exit of the discontinued operations.

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 4.  ACCOUNTING FOR THE EFFECTS OF REGULATION

Domestic Electric Operations prepares its financial statements in accordance with Statement of Financial Accounting Standards ("SFAS") 71, "Accounting for the Effects of Certain Types of Regulations." Under this statement, the Company may defer certain costs as regulatory assets and certain obligations as regulatory liabilities. Regulatory assets and liabilities represent probable future revenues that will be recovered from, or refunded to, customers through the ratemaking process.

The Emerging Issues Task Force of the Financial Accounting Standards Board (the "EITF") concluded in 1997 that SFAS 71 should be discontinued when detailed legislation or regulatory orders regarding competition are issued. Additionally, the EITF concluded that regulatory assets and liabilities applicable to businesses being deregulated should be written off unless their recovery is provided for through future regulated cash flows. Recoverability of regulatory assets is assessed at each reporting period.

On March 4, 1999, the Utah Public Service Commission (the "UPSC") ordered the Company to reduce customer prices by 12%, or $85 million annually effective March 1, 1999, and to make a one-time refund of $40 million to customers. Approximately $38 million of the refund relating to 1997 and 1998 was recorded in December 1998. The remaining $2 million was recorded in the fourth quarter of fiscal 1999. The ordered rate reduction is the culmination of a general rate case in Utah that began in 1997.

On September 20, 1999, the Company filed for a rate increase before the UPSC. The Company is asking for an increase of $67 million, or 9.9%, based on a test year ended December 31, 1998. The Company's effective date for this proposed tariff increase is expected to be in May 2000.

In July 1998, the Company announced its intent to sell its California electric distribution assets. This action was in response to the continued decline in earnings on the assets and the changes in the legislative and regulatory environments in California. On July 15, 1999, the Company signed a definitive agreement with Nor-Cal Electric Authority for the sale of the assets to Nor-Cal for $178 million. The Company does not expect to incur a material gain or loss on this sale. On August 16, 1999, the Company filed an application with the California Public Utility Commission (the "CPUC") for approval of the sale. On November 15, 1999, the Company filed an application for approval with the Federal Energy Regulatory Commission ("FERC"). The sale is expected to close during the first half of calendar 2000.

On April 30, 1999, the Company filed for changes in the prices it charges Oregon customers. The filing was required as part of a calendar 1998 Oregon Public Utility Commission (the "OPUC") order which uses set formulas to moderate the impact of cost fluctuations on customer prices, while assuring high-quality service. The filing also contained a request to increase the revenues collected under its system benefits charge. The changes were approved by the OPUC in June 1999, and became effective July 1, 1999. This resulted in a price increase of approximately 1.3%, or $9 million annually, in Oregon.

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On November 5, 1999, the Company filed for a rate increase before the OPUC. This rate increase contains two phases. In the first phase, the Company is asking for an increase of $61.8 million, or 8.5%. The Company's effective date for this phase of the proposed tariff increase is expected to be in the fall of 2000. In the second phase, the Company is asking for an increase of up to $26.4 million, or 3.4%, to be effective at the end of the term of the current Alternative Form of Regulation on July 1, 2001.

During 1999, legislation was enacted in Oregon that requires competition for industrial and large commercial customers of both the Company and Portland General Electric by October 1, 2001. Residential customers will receive a portfolio of commodity service options. The law exempts publicly-owned utilities and Idaho Power's Oregon service territory. The law authorizes the OPUC to make decisions on a variety of important issues, including the method for valuation of stranded costs/benefits, consumer protections, marketer certification, environmental issues, and competitive services. The legislation also calls for the functional separation of certain assets and the establishment of a code-of-conduct for electric companies and their affiliates to protect consumers against anti-competitive practices. The legislation also directs the investor-owned utilities to collect a 3% public benefit tax from regulated customers. The Company will be participating in the OPUC proceedings over the next two years to establish the rules and procedures that will implement the new law. The Company will continue to evaluate the finance and accounting impacts, including the continued propriety of applying SFAS 71, as the OPUC proceedings progress. The impacts, if any, are uncertain.

On April 30, 1999, the Company filed documents with the Idaho Public Utilities Commission (the "IPUC") to implement the next step in the gradual retirement of a federal energy credit. The proposed reduction in the credit would increase electric prices for Utah Power residential and irrigation customers in southeastern Idaho. The filing, once approved by the IPUC, would reduce the credits from the federal Bonneville Power Administration (the "BPA") and increase residential prices 3.35%, or $1 million, and irrigation prices 4%, or $1 million. These price increases are not expected to have a material impact on earnings.

Congress created the federal credit in 1980 to share the benefits of federally owned hydroelectric plants with customers of investor-owned utilities in the Columbia River drainage area. When Congress recommended in 1995 that the current exchange method be phased out by June 2001, the Company worked out a settlement with BPA in 1997 to implement the order of Congress. Without the settlement, prices would have increased more than 30% in two years. The settlement provided credits of $48 million over five years for the Company's customers, $6 million more than without the settlement. The additional money is being used to lessen the impact of price increases as the BPA exchange credit is phased out.

On July 26, 1999, the Company filed for a rate increase before the Wyoming Public Service Commission (the "WPSC"). The Company is asking for an increase of $12 million, or 4.9%, based on a test year ended December 31, 1998. The effective date for this proposed tariff increase is expected to be in the spring of 2000.

10

On November 23, 1999, the Company filed for a rate increase before the WUTC. This rate increase contains two phases. In the first phase, the Company is asking for an increase of $14.6 million, or 8.10%. Including the systems benefit charge, this increase is $17.4 million, or 9.64%. In the second phase, the Company is requesting an increase of $11.2 million, or 5.73%. Including the systems benefit charge, which will be used to fund conservation and new renewable development projects, this increase is $11.2 million, or 5.65%. The effective date for phase one of this proposed tariff increase is expected to be in the fall of 2000 and phase two would become effective one year following phase one.

On August 6, 1999, the Company filed applications with the OPUC, the Washington Utilities and Transportation Commission (the "WUTC"), the UPSC, the WPSC and the IPUC seeking orders approving the sale of the Company's interests in the Centralia plant and mine. A similar application was filed with the CPUC on August 27, 1999. The Company's applications also seek Commission orders adopting the proposed treatment of the gain from the sale. FERC approved the sale on January 13, 2000.

 5.  MERGER CREDITS AND CUSTOMER SERVICE STANDARDS

On October 5, 1999, the WPSC announced it had decided to approve the merger, and the WPSC issued an order on November 22, 1999. The Company agreed to make a filing guaranteeing a minimum of $4 million per year in cost savings that will be reflected in future rate cases.

On October 6, 1999, the OPUC issued an order approving the merger. As part of this approval, the OPUC ordered the Company to provide a merger credit to Oregon customers of $12 million per year for three years beginning in calendar 2001 and $15 million in calendar 2004. In calendar 2003 and 2004, $9 million and $12 million, respectively, of the credit can be partially or wholly eliminated to the extent that cost savings are reflected in prices.

On October 14, 1999, the WUTC approved the merger and ordered the Company to provide Washington retail customers a merger credit of $3 million per year for four years beginning in calendar 2001. The credit can be wholly or partially eliminated in all years to the extent that cost savings are reflected in prices

On November 15, 1999, the IPUC approved the merger and ordered the Company to provide a $1.6 million per year merger credit to retail tariff customers for four years beginning on January 1, 2000. The credit can be wholly or partially eliminated in years three and four to the extent that cost savings are reflected in prices.

On November 24, 1999, the UPSC approved the merger with ScottishPower. As part of the approval, the UPSC ordered the Company to provide a merger credit for retail tariff customers of $12 million per year for four years beginning in calendar 2000. The credit can be wholly or partially eliminated in years three and four to the extent that cost savings are reflected in prices.

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The Company's total obligation for merger credits described above is $133.4 million over the period ending December 31, 2004. Of this amount, $57.2 million must be provided without offset or reduction of any kind and, accordingly, the Company has recorded $57.2 million as a liability and current expense in its financial statements for the period ended December 31, 1999. The remaining $76.2 million obligation of the Company with respect to merger credits is subject to possible offset if the Company demonstrates in a future rate case, to the satisfaction of the respective commissions, that merger-related cost reductions have occurred and are being reflected in rates. This $76.2 million obligation will be reflected in future periods.

As a result of the merger, the Company has initiated comprehensive customer service standards backed by payments to customers for not meeting those standards. The standards set time limits for Company performance on customer power restoration, new connections, billing problem resolution, appointments with customers, and notification of planned power interruptions. Customers will generally receive an initial credit of $50 for each incident of nonperformance, with additional credits available depending on the amount of time it ultimately takes to comply with the standards. The Company has also initiated performance standards which are intended to improve the reliability of the system and improve response times at our customer service centers and with the various regulatory commissions. The financial impact of these service standards is estimated to be immaterial.

 6.  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.

 7.  INCOME TAXES

The Company's combined federal and state effective income tax rate from continuing operations was 116% for the nine months ended December 31, 1999 and 37% for the nine months ended December 31, 1998. 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:

12

 8.  COMPREHENSIVE INCOME

The components of comprehensive income are as follows:

13

 9.  NEW ACCOUNTING STANDARDS

In June 1999, the Financial Accounting Standards Board issued SFAS 137, "Accounting for Derivative Instruments and Hedging Activities - Deferral of the Effective Date of FASB Statement No. 133 - an amendment of FASB Statement No. 133." This statement delays the effective date of SFAS 133 for one year, to fiscal years beginning after June 15, 2000. This statement allows the Company to delay its implementation of SFAS 133.

 10.  SEGMENT INFORMATION

Selected information regarding the Company's operating segments, Domestic Electric Operations, Australian Electric Operations, Other Operations and Discontinued Operations, are as follows:

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11.  INDEPENDENT ACCOUNTANTS REVIEW REPORT

The Company's Quarterly Reports on Form 10-Q are incorporated by reference into various filings under the Securities Act of 1933 (the "Act"). The Company's independent accountants are not subject to the liability provisions of Section 11 of the Act for their report on the unaudited consolidated financial information because such report is not a "report" or a "part" of a registration statement prepared or certified by independent accountants within the meaning of Sections 7 and 11 of the Act.

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  Item 2.

MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

SUMMARY RESULTS OF OPERATIONS

This report includes forward-looking statements that involve a number of risks and uncertainties that may influence the financial performance and earnings of the Company and its subsidiaries, including the factors identified in the Company's 1998 Annual Report on Form 10-K/A Amendment No. 1. Such forward-looking statements should be considered in light of those factors.

Unless otherwise stated, references below to periods in 2000 are to periods in the fiscal year ending March 31, 2000, while references to periods in 1999 are to periods in the fiscal year ended March 31, 1999.

Comparison of the three-month periods ended December 31, 1999 and 1998

*Not a meaningful number.

(1)  Earnings contribution (loss) on common stock by segment: (a) does not reflect elimination for interest on intercompany borrowing arrangements; (b) includes income taxes on a separate company basis, with any benefit or detriment of consolidation reflected in Other Operations; (c) is net of preferred dividend requirements and minority interest.

(2)  Represents the discontinued operations of TPC and PPM.

16

The Company recorded losses on common stock of $150 million in the third quarter of 2000 compared to earnings of $21 million in the third quarter of 1999. Third quarter of 2000 results included $190 million after-tax in ScottishPower merger costs compared to $13 million in the 1999 period. The third quarter of 2000 reflected a $15 million after-tax reduction in prices due to the Utah rate order received in March 1999, while the 1999 period included a retroactive refund to Utah customers totaling $23 million after-tax. The third quarter of 2000 also included a $15 million after-tax write-off of projects under construction, which were abandoned in the period. The third quarter of 1999 also included a $17 million after-tax loss relating to the write down of the Company's investment in the Hazelwood Power Station ("Hazelwood").

The following table shows where ScottishPower merger costs have been recorded in the Company's financial results.

17

Domestic electric operations recorded a loss of $150 million in the third quarter of 2000 as compared to income of $22 million in the third quarter of 1999. Third quarter 2000 results included $187 million after-tax in ScottishPower merger costs compared to $13 million in the 1999 period. The third quarter of 2000 reflected a $15 million after-tax reduction in prices due to the Utah rate order received in March 1999, and a $15 million after-tax write-off of projects under construction. The 1999 period included the retroactive refund totaling $23 million after-tax.

Australian electric operations recorded income of $14 million in the third quarter of 2000 compared to a loss of $14 million in the 1999 period. This increase was primarily due to the receipt of a court ruling in Powercor's favor relating to a contract dispute. In addition, the third quarter of 1999 included a $17 million after-tax loss relating to the write down of the investment in Hazelwood.

Other operations reported a loss of $15 million in the 2000 quarter compared to a loss of $1 million in the 1999 period. This decrease was primarily due to an increase in income tax expense resulting from reevaluation of tax liabilities from settled and ongoing tax examinations and a decrease in interest income.

Comparison of the nine-month periods ended December 31, 1999 and 1998

*Not a meaningful number.

18

The Company recorded losses on common stock of $26 million in the 2000 period compared to a loss of $36 million in the 1999 period. The 2000 results included $202 million after-tax in ScottishPower merger costs compared to $13 million in the 1999 period. The results for the 2000 period also included a $15 million after-tax write-off of projects under construction, which were abandoned in the period. The results for the 1999 period included a $32 million after-tax loss associated with the Company's decision to shut down or sell its other energy development businesses, a $23 million after-tax charge associated with the Utah rate order refund to Utah customers, and a $17 million after-tax loss relating to the write down of Hazelwood. In addition, the results for the 1999 period included a $146 million loss associated with the energy trading activities that the Company decided to discontinue in October 1998.

The following table shows where ScottishPower merger costs have been recorded in the Company's financial results.

19

Domestic electric operations recorded a loss of $54 million in the 2000 period compared to earnings of $125 million in the 1999 period. The 2000 results included $199 million after-tax in ScottishPower merger costs compared to $13 million in the 1999 period. The 2000 results also reflected a $44 million after-tax reduction in prices due to the Utah rate order received in March 1999, while the 1999 period reflected a retroactive refund totaling $23 million after-tax. In addition, the 2000 period included decreased interest expense of $24 million due to funds received by domestic electric operations as intercompany dividends from Holdings of $500 million and $660 million in October 1998 and January 1999, respectively.

Australian electric operations recorded income of $29 million in the 2000 period compared to a loss of $1 million in the 1999 period. This increase was primarily due to the receipt of a court ruling in Powercor's favor relating to a contract dispute. In addition, the 1999 period included a $17 million after-tax loss relating to the write down of the investment in Hazelwood.

Other operations reported a loss of $1 million in the 2000 period compared to a loss of $13 million in the 1999 period. This increase was primarily due to the 1999 period including an after-tax loss of $32 million relating to the decision to exit the energy development businesses, $14 million in after-tax losses relating to the operation of those businesses prior to the Company's decision to exit, and $2 million after-tax associated with the Company's terminated bid for The Energy Group ("TEG"), partially offset by a $10 million after-tax gain on the sale of TEG shares. In addition, income tax expense increased approximately $21 million in the 2000 period primarily due to reevaluation of tax liabilities from settled and ongoing tax examination s.

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RESULTS OF OPERATIONS

Domestic Electric Operations

Comparison of the three-month periods ended December 31, 1999 and 1998

*Not a meaningful number.

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Revenues

Total domestic electric operations revenues decreased $118 million, or 12%, from the third quarter of 1999. This decrease was primarily attributable to a $141 million decrease in wholesale revenues. The sale of the Company's Montana service area in November 1998 decreased revenues $3 million, while the Utah rate order reduced revenues by $24 million. These decreases were partially offset by customer growth, which added $9 million in the 2000 period, and the one-time rate order refund that reduced revenues in the third quarter of 1999 by $39 million.

Residential revenues were up $7 million, or 3%. Excluding the impact of the Montana sale, residential revenues were up $8 million, energy volumes were down 1% and customer growth was 2%. Growth in the average number of residential customers added $4 million to revenues. Volume decreases, primarily due to weather, decreased revenues by $6 million while price increases in Oregon added $2 million to revenues. The Utah rate order decreased residential revenues by $10 million in the 2000 period. This decrease was offset by the one-time Utah rate order refund that reduced revenues by $16 million in the 1999 period.

Commercial revenues were up $13 million, or 8%. Excluding the impact of the Montana sale, commercial revenues were up $14 million and energy volumes were up 5%. Increased commercial customers added $5 million and volume increases added $4 million to revenues. The Utah rate order decreased commercial revenues by $9 million in the 2000 period. This decrease was offset by the one-time Utah rate order refund that reduced revenues by $13 million in the 1999 period.

Industrial revenues increased $5 million, or 3%. Excluding the impact of the Montana sale, industrial revenues were up $6 million while energy volumes and average customers both decreased 2%. The Company has participated in open access pilot programs in Oregon, which ended in calendar 1998, that reduced revenues $4 million. Under these programs, customers were allowed to choose service by another utility, with no franchise rights to that customer, for a specific time period. Increased irrigation usage added $2 million to industrial revenues. The Utah rate order decreased industrial revenues by $5 million in the 2000 period. This decrease was offset by the one-time Utah rate order refund that reduced revenues in the 1999 period by $10 million and other changes in the average price for electricity, which added $5 million in the 2000 period.

Wholesale sales decreased $141 million, or 33%. The decrease in revenues was driven by a 39% decline in energy volumes. Lower short-term and spot market wholesale energy volumes decreased revenues by $187 million. Related energy prices averaged $31 per MWh in the quarter, a 17% increase over the prior year. The higher prices for these sales added $44 million to revenues in the quarter. This decline in energy volumes is consistent with the Company's decision to scale back short-term wholesale sales.

See Note 4 regarding regulation of domestic electric operations' utility properties.

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Operating Expenses

Total operating expenses decreased $102 million, or 12%. This decrease was primarily attributable to decreased purchased power expense due to the decline in wholesale sales, partially offset by an increase in other operations and maintenance.

Purchased power expense was $256 million, a decrease of $140 million. The lower expense was primarily due to a 6.1 million MWh decrease in short-term firm and spot market energy purchases which decreased purchased power expense $189 million. Short-term firm and spot market purchase prices averaged $31 per MWh in the quarter versus $26 per MWh in the 1999 period, a 19% increase. The increase in purchase prices increased costs $55 million. A decrease in long-term contracts reduced expense by $3 million.

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Other Income and Expense

Domestic electric operations interest expense was down $8 million as a result of lower debt balances. The lower debt balances were primarily due to a dividend received from Holdings in January 1999 that was used to pay down intercompany debt owed to Holdings and some external debt. ScottishPower merger costs were up $188 million primarily due to $103 million in taxes paid for stock transfers to complete the merger and $57 million relating to the merger credits ordered in various states. Responsibility to pay the taxes was accepted by the Company as a cost of the merger transaction. Income tax expense decreased $25 million due to a decrease in taxable income, partially offset by the effect of an increase in nondeductible merger costs.

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*Not a meaningful number.

Revenues

Total domestic electric operations revenues decreased $1,279 million, or 34%, from the 1999 period. This decrease was primarily attributable to a $1,281 million decrease in wholesale revenues. The sale of the Company's Montana service area in November 1998 decreased revenues $21 million, while the Utah rate order reduced revenues by $71 million. These decreases were partially offset by customer growth, which added $25 million in the 2000 period, an increase in the average price for electricity, which added $22 million in the 2000 period, and the one-time rate order refund that reduced revenues in the 1999 period by $39 million.

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Residential revenues were down $4 million. Excluding the impact of the Montana sale, residential revenues were up $4 million, energy volumes were up 3% and customer growth was 2%. Growth in the average number of residential customers added $11 million to revenues and price increases in Oregon added $4 million to revenues. The Utah rate order reduced residential revenues by $30 million in the 2000 period. This decrease was partially offset by the one-time Utah rate order refund that reduced revenues in the 1999 period by $16 million and other changes in the average price for electricity, which added $4 million in the 2000 period.

Commercial revenues were up $11 million, or 2%. Excluding the impact of the Montana sale, commercial revenues were up $18 million, energy volumes were up 7% and customer growth was 3%. Increased commercial customers added $14 million to revenues and volume increases added $14 million to revenues. The Utah rate order reduced commercial revenues by $27 million in the 2000 period. This decrease was partially offset by the one-time Utah rate order that reduced revenues in the 1999 period by $13  million and other changes in the average price for electricity, which added $5 million in the 2000 period.

Industrial revenues decreased $10 million, or 2%. Excluding the impact of the Montana sale, industrial revenues were down $4 million, energy volumes were down 1% and average customers declined 4%. Decreased energy volumes due to the cyclical nature of industrial customer usage drove an $8 million decrease in revenues. The Company has participated in open access pilot programs in Oregon, which ended in calendar 1998, that reduced revenues $10 million. Increased irrigation usage added $5 million to industrial revenues. The Utah rate order reduced industrial revenues by $14 million. This decrease was partially offset by the one-time Utah rate order refund that reduced revenues in the 1999 period by $10 million and other changes in the average price for electricity, which added $13 million in the 2000 period.

Wholesale sales decreased $1,281 million, or 61%. The decrease in revenues was driven by a 63% decline in energy volumes. Lower short-term and spot market wholesale energy volumes decreased revenues by $1,271 million. This decline in energy volumes is consistent with the Company's decision to scale back short-term wholesale sales. A decrease in long-term firm contracts reduced revenues by $12 million.

See Note 4 regarding regulation of domestic electric operations' utility properties.

Operating Expenses

Total operating expenses decreased $1,234 million, or 37%. This decrease was primarily attributable to decreased purchased power expense due to the decline in wholesale sales.

Purchased power expense decreased $1,280 million, to $758 million. The lower expense was primarily due to a 46.6 million MWh decrease in short-term firm and spot market energy purchases which decreased purchased power expense $1,414 million. Short-term firm and spot market purchase prices averaged $29 per MWh in 2000 versus $28 per MWh in 1999. The increase in purchase prices increased costs $138 million. A decrease in long-term contracts reduced expense by $3 million.

26

Fuel expense was down $2 million, or 1%, to $353 million in the 2000 period. Thermal generation was up 1% to 38.8 million MWh. The average cost per MWh decreased to $9.08 from $9.43 in the prior year due to improved operating efficiencies at Company operated mines. Hydroelectric generation increased 5% compared to the 1999 period due to favorable water conditions.

Other operations and maintenance expense increased $63 million, or 18%, to $410 million. Write-offs of assets under construction were $23 million in the 2000 period. In the third quarter of 2000, the Company completed an analysis of construction projects and determined to abandon a number of these projects which were early stage construction projects. Increased tree trimming added $4 million to expenses, increased materials and contracts primarily relating to overhaul costs added $8 million, increased employee costs added $7 million and write-offs of obsolete inventory added $4 million. In addition, operations and maintenance was up $15 million due to costs reclassified from administrative and general upon conversion to SAP in January 1999.

Administrative and general expenses and taxes - other decreased $20 million, or 8%, to $234 million. This decrease was primarily due to $15 million reclassified to operations and maintenance upon conversion to SAP in January 1999. In addition, Year 2000 costs decreased $3 million. Increased employee costs relating to the merger were offset by decreased labor and other employee-related expenses.

Depreciation and amortization expense increased $16 million, or 5%, to $304 million primarily due to increased plant in service and increased depreciation on the recent installation of the new SAP software.

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Other Income and Expense

Domestic electric operations interest expense was down $38 million as a result of lower debt balances. The lower debt balances were primarily due to the dividends received from Holdings that were used to pay down intercompany debt owed to Holdings and some external debt. ScottishPower merger costs were up $200 million primarily due to the taxes paid and the ordered merger credits. Other income was up $10 million primarily due to an increase in timber sales and a decrease in new products expense. Income tax expense was $77 million, a decrease of $18 million due to the effect of a decrease in pretax income, partially offset by an increase in nondeductible merger transaction costs.

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Australian Electric Operations

ScottishPower has announced that it plans to sell the Company's Australian Electric Operations and has contracted with an investment banking firm to find a purchaser.

Comparison of the three-month periods ended December 31, 1999 and 1998

*Not a meaningful number.

Currency Exchange Rates

The currency exchange rate for converting Australian dollars to U. S. dollars was 0.64 in the 2000 period as compared to 0.62 in the 1999 period, a 3% increase. The effect of this change in exchange rates increased revenues by $5 million and costs by $4 million in the third quarter of 2000.

The following discussion excludes the effects of the higher currency exchange rates in fiscal 2000.

Revenue

Australia's electricity revenues and energy volumes sold remained flat compared to the third quarter of 1999.

Operating Expenses

Operating expenses decreased $15 million due to increased network revenue, decreased network fees and a decrease in purchased power expense. The decrease in purchased power expense was due to the favorable court ruling Powercor received from the dispute it was having with one of its suppliers, as described below. These decreases were partially offset by an increase in contract fees and increased administrative and general expenses due to increased costs to restructure.

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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 at a rate higher than it paid in calendar 1998. On November 17, 1999, the Supreme Court of Victoria upheld the validity of these contracts 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 judgements against it.

Other Income and Expense

Other expense decreased $26 million primarily due to the third quarter of 1999 including a pretax loss of $28 million relating to the write down of the Company's investment in Hazelwood to its estimated net realizable value less selling costs.

Income tax expense increased due to the effect of an increase in taxable income.

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*Not a meaningful number.

Currency Exchange Rates

The currency exchange rate for converting Australian dollars to U.S. dollars was 0.65 in the 2000 period as compared to 0.62 in the 1999 period. The effect of this change in exchange rates increased revenues by $24 million and costs by $22 million.

The following discussion does not include the effects of the higher currency exchange rate in fiscal 2000.

Revenue

Australia's electricity retail revenues decreased $12 million, or 3%. This decrease was driven by a decline in energy volumes sold of 252 million kWh, or 3%.

Other revenues increased $6 million primarily due to the recognition of a sales tax contract settlement payment received from the Australian government.

Operating Expenses

Operating expenses decreased $17 million, or 4%, primarily due to decreased network fees, increased network revenues and decreased purchased power expense due to the favorable court ruling Powercor received on a contract dispute. These decreases were partially offset by an increase in contract fees and increased administrative and general expenses due to costs to restructure.

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Other Income and Expense

Other expense decreased $30 million primarily due to a pretax loss of $28 million in the 1999 period relating to the write down of the Company's investment in Hazelwood and $5 million of costs for the removal of certain energy efficiency devices in connection with a product recall.

Income tax expense increased due to the effect of an increase in taxable income.

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Other Operations

Comparison of the three-month periods ended December 31, 1999 and 1998

*Not a meaningful number.

Other operations reported a loss of $15 million in the quarter compared to a loss of $1 million in the same period a year ago.

PFS's earnings contribution increased $2 million compared to the third quarter of 1999 due to increased tax credits received on the sales of synthetic coal fuel.

Income tax expense at Holdings increased approximately $12 million primarily due to reevaluation of tax liabilities from settled and ongoing tax examinations. In addition, interest income decreased $5 million as a result of cash dividends of $500 million paid in October 1998 and $660 million paid in January 1999 by Holdings to domestic electric operations. This cash had been invested by Holdings in interest bearing instruments prior to the dividends.

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Comparison of the nine-month periods ended December 31, 1999 and 1998

*Not a meaningful number.

Other operations reported a loss of $1 million in the 2000 period compared to a loss of $13 million in the same period a year ago. The increase in earnings was primarily due to the 1999 period including a $52 million pretax ($32 million after-tax) loss relating to the decision to shut down or sell its other energy development businesses in October 1998 and a loss of $2 million relating to the closing of foreign currency options associated with the terminated bid for TEG, partially offset by a $16 million pretax ($10 million after-tax) gain on the sale of TEG shares.

PFS's income increased $8 million primarily due to increased tax credits received on the sales of synthetic coal.

Earnings at PKE increased $9 million due to the cogeneration project under development in Klamath Falls, Oregon.

Income tax expense at Holdings increased approximately $21 million primarily due to reevaluation of tax liabilities from settled and ongoing tax examinations. In addition, interest income decreased $21 million as the result of cash dividends paid by Holdings to domestic electric operations. This cash had been invested by Holdings in interest bearing instruments prior to the dividends.

Other energy development businesses had operating losses of $14 million in fiscal year 1999. The Company shut down or sold some of these businesses in calendar 1999.

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FINANCIAL CONDITION -

For the nine months ended December 31, 1999:

OPERATING ACTIVITIES

Net cash flows provided by continuing operations were $533 million during the period compared to $453 million in the first nine months of fiscal 1999. The $80 million increase in operating cash flows was primarily attributable to decreased working capital requirements.

Net cash used in discontinued operations in fiscal 1999 represents cash funding of TPC operations through an intercompany note payable with Holdings.

INVESTING ACTIVITIES

Capital spending totaled $461 million in fiscal 2000 compared with $528 million in fiscal 1999. Construction expenditures decreased $70 million in fiscal 2000 primarily because the fiscal 1999 period included the construction of synthetic coal fuel plants.

In connection with the attempt to acquire TEG, a subsidiary of the Company acquired 46 million of TEG stock. In June 1998, the subsidiary sold the stock and received proceeds of $642 million.

During May 1998, PFS received approximately $80 million in net cash proceeds for the sale of its real estate properties.

On May 10, 1999, the utility partners who own the 1,340 MW coal-fired Centralia Power Plant announced their intention to sell the plant and the adjacent coal mine owned by the Company to TransAlta for $554 million. The sale is subject to regulatory approval and is expected to close during the first half of calendar 2000. The Company operates the plant and owns a 47.5% share. The Company expects to realize a gain on the sale, but the amount will not be determined until the regulatory approval process has been completed.

In July 1998, the Company announced its intent to sell its California electric distribution assets. This action was in response to the continued decline in earnings on the assets and the changes in the legislative and regulatory environments in California. On July 15, 1999, the Company signed a definitive agreement with Nor-Cal Electric Authority for the sale of the assets to Nor-Cal for $178 million. The Company does not expect to incur a loss on this sale. On August 16, 1999, the Company filed an application with the CPUC for approval of the sale. On November 15, 1999, the Company filed an application for approval with the FERC. The sale is expected to close during the first half of calendar 2000.

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CAPITALIZATION

At December 31, 1999, PacifiCorp had approximately $139 million of commercial paper and uncommitted bank borrowings outstanding at a weighted average rate of 6.3%. These borrowings are supported by $800 million of revolving credit agreements. At December 31, 1999, the consolidated subsidiaries had access to $723 million of short-term funds through committed bank revolving credit agreements, and had $432 million outstanding under bank revolving credit facilities. At December 31, 1999, the Company and its subsidiaries had $432 million of short-term debt classified as long-term debt as they have the intent and ability to support short-term borrowings through the various revolving credit facilities on a long-term basis.

DIVIDENDS

Following approval of the merger but before the merger was consummated, the Company declared a pre-completion dividend. This dividend was based upon the daily equivalent of the Company's historic $1.08 annual dividend per share for the days elapsed from November 15, 1999, the date of the payment of the last dividend, to and including November 28, 1999, the day before the merger's consummation. This dividend amounted to approximately $11.5 million and was paid on December 27, 1999.

INTEREST RATE EXPOSURE

The Company's market risk to interest rate change is primarily related to long-term debt with fixed interest rates. The Company uses interest rate swaps, forwards, futures and collars to adjust the characteristics of its liability portfolio. This strategy is consistent with the Company's capital structure policy that provides guidance on overall debt to equity and variable rate debt as a percent of capitalization levels for both the consolidated organization and its principal subsidiaries. Based on the Company's overall interest rate exposure, the estimated potential one-day loss in fair value as a result of near-term change in interest rates, within a 95% confidence level using historical interest rate movements based on the VAR model, was $21  million at December 31, 1999.

COMMODITY PRICE EXPOSURE

The Company's market risk to commodity price change is primarily related to its electricity commodities, which are subject to fluctuations due to unpredictable factors, such as weather, which impacts supply and demand. Based on the Company's derivative price exposure at December 31, 1999, a near-term adverse change in commodity prices of 10% would negatively impact pretax earnings by approximately $24 million.

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YEAR 2000

Since the transition to the year 2000, the Company has experienced a few minor Year 2000 related problems with its business systems that were identified and corrected. Within the electric operations of the Company no Year 2000 problems have been identified. No customers appear to have been affected by Year 2000 problems.

Due to the nature of Year 2000 issue, it is still too early to determine whether additional problems will occur. While the Company does not anticipate any major Year 2000 problems to occur, it is continuing to monitor systems for any latent Year 2000 issues.

The Company has incurred $27.5 million in costs relating to the Year 2000 project through December 31, 1999. The majority of these costs have been incurred to repair software problems. The total cost of the Year 2000 project is estimated at up to $30 million, which will be principally funded from operating cash flows. This estimate does not include the cost of system replacements that were Year 2000 ready, but not installed primarily to resolve Year 2000 problems. Year 2000 information technology ("IT") remediation costs amount to approximately 5% of IT's budget. The Company did not delay any IT projects that were critical to its operations as a result of Year 2000 remediation work. No independent verification of risk and cost estimates has been undertaken to date.

The expected costs and other impacts of the Year 2000 issues are based on management's best estimates, which were derived utilizing numerous assumptions concerning future events, including the availability of certain resources, the successful implementation of third-party modification plans and other factors. There can be no assurance that these estimates will be achieved, or that there will not be a delay in the final few elements of, or increased costs associated with, the Company's implementation of its Year 2000 project.
_____________________________________________________________________________

The condensed consolidated financial statements as of December 31, 1999 and for the three-and nine-month period ended December 31, 1999 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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REPORT OF INDEPENDENT ACCOUNTANTS

To the board of directors and shareholders of PacifiCorp:

We have reviewed the accompanying condensed consolidated balance sheet of PacifiCorp and its subsidiaries as of December 31, 1999, and the related condensed consolidated statements of income and retained earnings for each of the three- and nine-month periods ended December 31, 1999 and the condensed consolidated statement of cash flows for the nine-month period ended December 31, 1999. These financial statements are the responsibility of the Company's management.

We conducted our review in accordance with standards established by the American Institute of Certified Public Accountants. A review of interim financial information consists principally of applying analytical procedures to financial data and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with generally accepted auditing standards, the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.

Based on our review, we are not aware of any material modifications that should be made to the accompanying condensed consolidated interim financial statements for them to be in conformity with generally accepted accounting principles.





PricewaterhouseCoopers LLP
Portland, Oregon

February 14, 2000

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PART II.  OTHER INFORMATION

Item 1.   Legal proceedings

A trial date has been set for the first two weeks in May relating to the Sierra Club v. Tri-State Generation and Transmission Association, Inc., Public Service Company of Colorado, Inc., Salt River Project Agricultural Improvement and Power District, PacifiCorp and Platte River Power Authority case (see "Item 3. Legal Proceedings" at page 21 of the Company's Annual Report on Form 10-K/A Amendment No. 1 for the year ended December 31, 1998).

Item 6.   Exhibits and Reports on Form 8-K

    (a)   Exhibits.

          Exhibit 15: Letter re unaudited interim financial information.

          Exhibit 27: Financial Data Schedule for the quarter ended
          December 31, 1999 (filed electronically only).

    (b)   Reports on Form 8-K.

          None

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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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