For the quarterly period ended June 30, 2002

OR

For the transition period from _______________ to _______________

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 _____

1

The accompanying notes are an integral part to these Condensed Consolidated Financial Statements

3

(Unaudited)

NOTE 1 - Financial Statements

The condensed consolidated financial statements of PacifiCorp (the "Company") include its integrated domestic electric utility operations and its wholly owned and majority-owned subsidiaries ("Domestic Electric Operations"). The subsidiaries of PacifiCorp support its electric utility operations by providing environmental remediation, financing and coal mining facilities and services. Intercompany transactions and balances have been eliminated upon consolidation.

The accompanying unaudited condensed consolidated financial statements as of June 30, 2002 and for the periods ended June 30, 2002 and 2001, in the opinion of management, include all adjustments, constituting only normal recurring adjustments, necessary for a fair presentation of financial position, results of operations and cash flows for such periods. The March 31, 2002 condensed consolidated balance sheet data was derived from audited financial statements. Such statements are presented in accordance with the Securities and Exchange Commission's ("SEC") interim reporting requirements, which do not include all the disclosures required by accounting principles generally accepted in the United States of America. Certain information and footnote disclosures made in the last Annual Report on Form 10-K have been condensed or omitted from the interim statements. A portion of the business of the Company is of a seasonal nature and, therefore, results of operations for the periods ended June 30, 2002 and 2001 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 2002 Annual Report on Form 10-K.

After obtaining the necessary regulatory approvals, on December 31, 2001 NA General Partnership ("NAGP") contributed all of the common stock of PacifiCorp to PacifiCorp Holdings, Inc. ("PHI"), a wholly owned subsidiary of NAGP. NAGP is a wholly owned subsidiary of Scottish Power plc ("ScottishPower"). On February 4, 2002, PacifiCorp transferred all of the capital stock of PacifiCorp Group Holdings Company ("Holdings"), a wholly owned subsidiary of PacifiCorp, to PHI. Holdings includes the wholly owned subsidiary, PacifiCorp Financial Services, Inc. ("PFS"), a financial services business. Accordingly, the results of operations and assets of Holdings are not included with those of PacifiCorp commencing February 4, 2002.

These interim statements have been prepared using accounting policies consistent with those applied at March 31, 2002. Certain amounts have been reclassified to conform with the current method of presentation. These reclassifications had no effect on previously reported consolidated net income.

NOTE 2 - Accounting for the Effects of Regulation

Regulated utilities have historically applied the provisions of Statement of Financial Accounting Standards ("SFAS") No. 71, Accounting for the Effects of Regulation, ("SFAS No. 71"), which is based on the premise that regulators will set rates that allow for the recovery of a utility's costs, including cost of capital. Accounting under SFAS No. 71 is appropriate as long as: rates are established by or subject to approval by independent, third-party regulators; rates are designed to recover the specific enterprise's cost-of-service; and in view of demand for service, it is reasonable to assume that rates are set at levels that will recover costs and can be collected from customers.

SFAS No. 71 provides that regulatory assets may be capitalized if it is probable that future revenue in an amount at least equal to the capitalized costs will result from the inclusion of that cost in allowable costs for ratemaking purposes. In addition, the rate action should permit recovery of the specific previously incurred and capitalized costs rather than to provide for expected levels of similar future costs. The statement makes it clear that a company does not need absolute assurance prior to capitalizing a cost, only reasonable assurance. A regulator can provide current rates intended to recover costs that are expected to be incurred in the future, with the understanding that if those costs are not incurred, future rates will be reduced by corresponding amounts. If current rates are intended to

6

recover such costs, the Company shall recognize amounts charged, pursuant to such rates, as liabilities and take those amounts to income only when the associated costs are incurred. In applying SFAS No. 71, the Company must give consideration to changes in the level of demand or competition during the cost recovery period. In accordance with SFAS No. 71, Domestic Electric Operations capitalizes certain costs as regulatory assets in accordance with regulatory authority whereby those costs will be expensed and recovered in future periods.

The Emerging Issues Task Force ("EITF") of the Financial Accounting Standards Board ("FASB") concluded in 1997 that SFAS No. 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. The Company continuously evaluates the appropriateness of applying SFAS No. 71 to each of its jurisdictions. At June 30, 2002, management concluded that SFAS No. 71 was appropriate for its Domestic Electric Operations. However, if deregulation activities continue to progress, the Company may in the future be required to discontinue its application of SFAS No. 71 to all or a portion of its business.

The Company is subject to the jurisdiction of public utility regulatory authorities of each of the states in which it conducts retail electric operations as to prices, services, accounting, issuance of securities and other matters. The jurisdictions in which the Company operates are in various stages of evaluating deregulation. At present, the Company is subject to cost based rate making for its Domestic Electric Operations business. The Company is a "licensee" and a "public utility" as those terms are used in the Federal Power Act (the "FPA") and is, therefore, subject to regulation by the Federal Energy Regulatory Commission (the "FERC") as to accounting policies and practices, certain prices and other matters.

In an effort to mitigate the temporary discrepancy between prices paid to purchase power and revenues received through regulated rates, the Company requested and received regulatory approval from the utility commissions in the states of Utah, Oregon, Wyoming and Idaho to capitalize for each state some of the net power costs that vary from costs included in determining retail rates. At June 30, 2002, the Company had a balance of $233.5 million of such capitalized costs supported by regulatory orders or stipulated agreements reached in Utah, Oregon and Idaho and an amount for deferred net power costs anticipated to be recoverable in Wyoming. The determination of the amount to be recovered in Wyoming is subject to receipt of a final commission order from the Wyoming Public Service Commission in a rate case expected to be concluded late in calendar 2002. Full recovery cannot be assured and differences between the amount allowed by the commission and the amounts capitalized at June 30, 2002 will b e recognized as either a charge or credit to income upon receiving a final commission order. The balance of deferred net power costs at June 30, 2002 has been adjusted for regulatory liability offsets as allowed by the Utah and Idaho Commission orders. On July 18, 2002, the Oregon Public Utility Commission issued an order approving a stipulation agreement allowing recovery of $136.5 million in deferred net power costs, including $5.5 million in carrying charges.

Deferred accounting treatment for the effects of SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, ("SFAS No. 133"), on the financial statements of the Company has been granted in all the states the Company serves. The regulatory orders direct the deferral, as a regulatory asset or liability, of the effects of fair valuing long-term contracts that are included in the Company's rates.

NOTE 3 - Derivative Instruments

On April 1, 2001, the Company adopted SFAS No. 133, as amended by SFAS No. 138 and numerous interpretations of the Derivatives Implementation Group (the "DIG") that are approved by the FASB, collectively "SFAS No. 133." Under SFAS No. 133, derivative instruments are recorded on the Condensed Consolidated Balance Sheet as an asset or liability measured at estimated fair value, with changes in fair value recognized currently in earnings, unless specific hedge accounting criteria are met. As contracts settle, sales are recorded in Revenues, with purchases and futures recorded in Purchased power and Fuel expense on the Condensed Consolidated Statements of Income. A derivative financial instrument or other contract derives its value from another investment, a designated benchmark, or an underlying price.

7

The Company's primary business is to serve its retail customers. The Company's business is exposed to risks relating to, but not limited to, changes in certain commodity prices and counterparty performance. The Company enters into derivative instruments, including electricity, natural gas and coal forward, option and swap contracts, and weather contracts to manage its exposure to commodity price risk and ensure supply and thereby attempts to minimize variability in net power costs for customers. The Company has policies and procedures to manage risks inherent in these activities and a Risk Management Committee to monitor compliance with the Company's risk management policies and procedures.

During the three months ended June 30, 2002, the Company's SFAS No. 133 contract assessments were updated to reflect the revised Issue C15, Normal Purchase and Normal Sales Exception for Certain Option-Type Contracts and Forward Contracts in Electricity, ("Issue C15"), guidance from the DIG, effective April 1, 2002. The revision to Issue C-15 includes criteria to be considered for designation of a contract as a "capacity contract" and disallows the use of the exception for contracts that include a pricing element that is not clearly and closely related to the price of energy. The effects of adoption of the revised Issue C15 at April 1, 2002 resulted in a cumulative effect of accounting change adjustment of $2.1 million unfavorable (net of tax of $1.3 million) on the Company's Condensed Consolidated Statements of Income and Retained Earnings. For contracts qualifying for deferred accounting under SFAS No. 71, the effect of adopting the revised C15 Issue was less than $1.0  million favorable.

In October 2001, the DIG issued guidance under Issue C16, Applying the Normal Purchases and Normal Sales Exception to Contracts that Combine a Forward Contract and a Purchased Option Contract, ("Issue C16"). The guidance disallows normal purchases and normal sales treatment for commodity contracts (other than power contracts) that contain volumetric variability or optionality. Issue C16 was effective April 1, 2002. The effects of adoption of Issue C16 at April 1, 2002 resulted in a cumulative effect of accounting change adjustment of $0.2 million favorable (net of tax of $0.2 million) on the Company's Condensed Consolidated Statements of Income and Retained Earnings. For contracts qualifying for deferred accounting under SFAS No. 71, the effect of adopting Issue C16 was a fair value of $126.5 million unfavorable to the Company at June 30, 2002 relating to contracts for the purchase and transport of gas to a gas-fired facility of the Company. The cost of this contract has already been allowed in rates and the liability is, therefore, offset by a corresponding amount included in regulatory assets.
To date, over 150 interpretations have been issued to provide "guidance" in applying SFAS No. 133. As the FASB continues to issue interpretations, the Company may change the conclusions that it has reached and, as a result, the accounting treatment and financial statement impact could change in the future.

The Risk Management Committee has limited the types of commodity instruments the Company may utilize to those relating to electricity, natural gas and coal commodities, and those instruments are used for hedging price fluctuations associated with the management of resources. The Company's hedging is done solely to help balance retail and wholesale load. Short-term commodity instruments are occasionally held by the Company for trading purposes. Earnings on trading transactions amounted to $1.5 million for the three months ended June 30, 2002. All of these transactions were settled by June 30, 2002.

The following table summarizes the SFAS No. 133 movements for the three months ended June 30, 2002:

8

As of June 30, 2002, the Company anticipated that approximately $38.6 million ($24.0 million after-tax) of the unrealized net losses on derivative instruments in Accumulated other comprehensive income (loss) will reverse during the subsequent twelve months as the underlying contracts are settled. A corresponding change to the SFAS No. 133 asset will be recorded with no net effect on earnings. As of June 30, 2002, contracts designated as cash flow hedges have contractual settlement dates through September 2002.

NOTE 4 - Related Party Transactions

There are no loans or advances between PacifiCorp and ScottishPower or between PacifiCorp and PHI. Loans to ScottishPower or PHI are prohibited under the Public Utility Holding Company Act of 1935. Loans from ScottishPower or PHI to PacifiCorp generally would require state regulatory and SEC approval.

The tables below detail the Company's transactions and balances with other unconsolidated related parties.

(a)  The Company recharges, to ScottishPower, payroll costs and related benefits of employees working for ScottishPower.

(b)  These expenses and liabilities primarily represent payroll costs and related benefits of ScottishPower employees in management positions with the Company.

(c)  These revenues primarily represent wheeling revenues received from PacifiCorp Power Marketing, Inc. ("PPM"), a subsidiary of PHI. These expenses represent operating lease payments for a generation facility owned by a subsidiary of PPM, as discussed below.

9

(d)  Holdings, while a subsidiary of the Company, had a note receivable, interest receivable and related interest income from a directly owned subsidiary of ScottishPower.

(e)  Amounts shown are related to activities of Holdings, while a subsidiary of the Company, with PHI and its subsidiaries.

Interest rates on related party transactions approximate the lender's short-term borrowing cost or cost of capital as required by the relevant regulatory approval or exemption. The applicable rate at March 31, 2002 was 1.9% and at June 30, 2002 was 2.2%.

In May 2002, the Company entered into a fifteen year operating lease on an electric generation facility with a subsidiary of PPM. This lease was approved by the Oregon Public Utilities Commission ("OPUC"). The Company, at its sole option, may terminate the lease after three and six years. The facility is located in Utah, and is being constructed by West Valley Leasing Company, a wholly owned subsidiary of PPM. The facility consists of five generation units each rated at 40 megawatt ("MW"). Scheduled lease payments are $3.0 million annually per unit. Four of these units were operational June 15, 2002 and the fifth unit was operational at the end of July 2002.

Affiliate transactions with the Company are subject to certain approval and reporting requirements of the regulatory authorities.

NOTE 5 - Revolving Credit Facility

The Company signed new revolving credit agreements that became effective June 4, 2002 with one for $500.0 million having a 364-day term plus a one-year term loan option, and the other for $300.0 million having a three-year term. Other provisions are similar to the prior credit agreements. The interest on advances under these facilities is based on LIBOR plus a margin that varies based on the Company's credit ratings. As of June 30, 2002, no borrowings were outstanding under these facilities.

NOTE 6 - Commitments and Contingencies

Litigation - From time to time, 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 financial position or results of operations.

California and Enron reserves - Beginning in the summer of 2000, market conditions in California resulted in defaults of amounts due to the Company for certain contract counterparties in California. In addition, in December 2001 Enron declared bankruptcy and defaulted on certain wholesale contracts.

The Company is a party to a FERC proceeding that is investigating potential refunds for energy transactions in the California market during past periods of high energy prices. The Company's ultimate exposure to refunds is dependent upon any order issued by the FERC in this proceeding. See ITEM 1. BUSINESS - DOMESTIC ELECTRIC OPERATIONS - WESTERN POWER MARKET ISSUES of the Company's 2002 Annual Report on Form 10-K.

The Company provided reserves for its California exposures and its Enron receivable, net of the effect of applying its master netting agreement, in the aggregate amount of $19.0 million.

10

Environmental issues - The Company is subject to numerous environmental laws including: the Federal Clean Air Act, as enforced by the Environmental Protection Agency ("EPA") and various state agencies; the 1990 Clean Air Act Amendments; the Endangered Species Act, particularly as it relates to certain potentially endangered species of salmon; the Comprehensive Environmental Response, Compensation and Liability Act, relating to environmental cleanups; along with the Federal Resource Conservation and Recovery Act and the Clean Water Act relating to water quality. These laws could potentially impact future operations. For those contingencies identified at June 30, 2002, principally the Superfund sites, where the Company has been or may be designated as a potentially responsible party and Clean Air Act matters, which are the subject of discussions with the EPA and state regulatory authorities, future costs associated with the disposition of these matters are expected to be addressed in futu re regulatory requests. The Company is currently unable to predict what impact, if any, these costs may have on the Company's consolidated financial position, results of operations, cash flows, liquidity, and capital expenditure requirements.

Hydroelectric relicensing - The Company's hydroelectric portfolio consists of 53 plants with a total capacity of 1,119 MW. Ninety-seven percent of the installed capacity is regulated by the FERC through 20 individual licenses. Nearly all of the Company's hydroelectric projects are in some stage of relicensing under the FPA. Hydro relicensing and the related environmental compliance requirements are subject to a high degree of change in estimation. Because, these matters are expected to be addressed in future regulatory requests, the Company is currently unable to predict what impact, if any, these costs may have on the Company's consolidated financial position, results of operations, cash flows, liquidity, and capital expenditure requirements. However, the Company expects that the impact will be significant and consist primarily of future capital expenditures, and power generation reductions may result from the additional environmental requirements.

Swift power canal - On April 21, 2002, a failure occurred in the Swift power canal on the Lewis River in the state of Washington. The power canal and associated 70 MW hydroelectric facility ("Swift No. 2") are owned by Cowlitz County Public Utility District ("Cowlitz"). Preliminary investigations suggest that Swift No. 2 will be out of service for more than a year. This failure can impact the Company's owned and operated 240 MW Swift No. 1 hydroelectric facility, which is upstream of the Swift power canal, by restricting both flow and generation flexibility ("shaping"). Cowlitz and the Company reached agreement on power canal repairs. Such repairs were completed and Swift No. 1 was returned to full capacity levels as of mid-July 2002 (though with limited shaping capabilities). Environmental and fish mitigation issues remain to be resolved before full use of Swift No. 1 can be ensured. The Company will continue to seek ways to mitigate any capacity and shaping limitations and also to recover any business losses. The full impact of the Swift outage and plans for repair of the Swift No. 2 facility are being determined. Final plans for the refurbishment of Cowlitz's Swift No. 2 facility are also unknown at this time. This event is not expected to have a significant impact on the Company's financial position or results of operations.

11

NOTE 7 - Income Taxes

The Company accrued federal and state income tax expense of $19.6 million and $101.1 million, representing effective tax rates of 34.3% and 38.1%, for the three months ended June 30, 2002 and 2001, respectively. The difference between taxes calculated as if the statutory federal tax rate of 35.0% was applied to Income from continuing operations before income taxes and Cumulative effect of accounting change and the recorded tax expense is due to the following:

(a)   The additional proceeds from the sale of the Australian Electric Operations of $27.4 million received in June 2001 did not have associated tax expense as they reduced the loss previously reported.

(b)  Reserves for tax on outstanding Internal Revenue Service examination issues.

The Company has concluded its settlement discussions with the IRS Appeals Division for the 1991, 1992 and 1993 tax years. The tax impact for this settlement is approximately $10.3 million. The Company has an established liability for this amount and is awaiting final billing from the IRS for these years.

The examination of the Company's 1994 through 1998 tax years was completed in July 2002. The IRS issued a Revenue Agent's Report on July 3, 2002 for these years. Further, the IRS also issued a Revenue Agent's Report on July 17, 2002 containing solely the issues agreed upon with the Company. The tax impact for the agreed upon issues is approximately $40.9 million. The Company has an established liability for this amount. The Company intends to file an administrative appeal for the unagreed issues. The Company believes that final settlement will not have a material adverse impact upon its financial position or results of operations.

The IRS has also notified the Company that it intends to start the examination of the 1999 and 2000 tax years beginning September 2002.

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NOTE 8 - Comprehensive Income

The components of comprehensive income are as follows:

NOTE 9 - New Accounting Standards

Adoption of New Standard

In June 2001, the FASB issued SFAS No. 142, Goodwill and Other Intangible Assets, ("SFAS No. 142"), which addresses financial accounting and reporting for acquired goodwill and other intangible assets and supersedes Accounting Principles Board ("APB") Opinion No. 17, Intangible Assets, ("APB No. 17"). SFAS No. 142 specifically states that it does not change the accounting prescribed by SFAS No. 71. This statement was effective for the Company beginning April 1, 2002. The Company has no goodwill recorded on its books. Due to the regulatory treatment for the Company's intangible assets, which were all internally developed, the adoption of SFAS No. 142 had no material effect on the Company's financial position or results of operations.

New Standard Issued

In June 2001, the FASB issued SFAS No. 143, Accounting for Asset Retirement Obligations, ("SFAS No. 143"). The statement requires the fair value of an asset retirement obligation to be recorded as a liability in the period in which the obligation was incurred. At the same time the liability is recorded, the costs of the asset retirement obligation will be recorded as an addition to the carrying amount of the related asset. Over time, the liability is accreted to its present value and the addition to the carrying amount of the asset is depreciated over the asset's useful life. Upon retirement of the asset, the Company will settle the retirement obligation against the recorded balance of the liability. Any difference in the final retirement obligation cost and the liability will result in either a gain or loss. The Company will adopt this statement on April 1, 2003 and is currently evaluating the impact of adopting this statement on its financial position and results of operations.

NOTE 10 - Segment Information

The Company previously operated in two business segments (excluding other and discontinued operations): Domestic Electric Operations and Australian Electric Operations. The Company identified the segments based on management responsibility within the United States and Australia. Domestic Electric Operations includes the regulated retail and wholesale electric operations in the six western states in which it operates. Australian Electric Operations included the deregulated electric operations in Australia, which were sold in the fall of 2000. Other Operations consisted of PFS, as well as the activities of Holdings, including related financing costs. Holdings and its subsidiaries, including PFS, were transferred to PHI in February 2002. Therefore, the Company has only one operating segment in fiscal 2003.

13

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

(a)  In June 2001, upon resolution of a contingency under the provisions of a portion of the Australian Electric Operations sale agreement, the Company received further proceeds from the salein the amount of $27.4 million.

(b) Amounts for the three months ended June 30, 2001 represent the collection of a contingent note receivable relating to the discontinued operations of a former mining and resource development business, NERCO, Inc., which was sold in 1993.

NOTE 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 condensed 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.

14

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 June 30, 2002, and the related condensed consolidated statements of income and retained earnings for each of the three-month periods ended June 30, 2002 and 2001 and the condensed consolidated statements of cash flows for the three-month periods ended June 30, 2002 and 2001. 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 accounting principles generally accepted in the United States of America.

We previously audited in accordance with auditing standards generally accepted in the United States of America, the consolidated balance sheet as of March 31, 2002, and the related statements of consolidated income, changes in common shareholder's equity and cash flows for the year then ended (not presented herein), and in our report dated May 1, 2002 we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying condensed consolidated balance sheet as of March 31, 2002, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived.





PricewaterhouseCoopers LLP
Portland, Oregon

August 8, 2002

15

OVERVIEW

On December 31, 2001, all of the PacifiCorp (the "Company") common stock held by NA General Partnership ("NAGP") was transferred to PacifiCorp Holdings, Inc. ("PHI"). PacifiCorp subsequently transferred all of the capital stock of PacifiCorp Group Holdings Company ("Holdings") to PHI in February 2002. Holdings includes the wholly owned subsidiary, PacifiCorp Financial Services, Inc. ("PFS"), a financial services business. This transfer was made to better separate PacifiCorp's regulated utility business from its non-utility operations. As a result, the operations of Holdings are included as Other Operations in the Company's Condensed Consolidated Statement of Income and Condensed Consolidated Statement of Cash Flows for the three months ended June 30, 2001, but are not included for the three months ended June 30, 2002.

CRITICAL ACCOUNTING POLICIES

The preparation of consolidated financial statements in conformity with Generally Accepted Accounting Principles requires management to make estimates and assumptions that affect results of operations and the reported amounts of assets and liabilities in the consolidated financial statements. Changes in these estimates and assumptions could have a material impact on the Company's financial position and results of operations. Those policies that management considers critical are Regulation, Revenue Recognition, Allowance for Doubtful Accounts, Derivatives, Depreciation, Pensions and Contingent Tax Liability and are described in the Company's Annual Report on Form 10-K under ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.

FORWARD-LOOKING STATEMENTS

The information in the tables and text in this document includes certain forward-looking statements that involve a number of risks and uncertainties that may influence the financial performance and earnings of the Company. When used in this MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS, the words "estimates," "expects," "anticipates," "forecasts," "plans," "intends" and variations of such words and similar expressions are intended to identify forward-looking statements that involve risks and uncertainties. There can be no assurance the results predicted will be realized. Actual results may vary from those represented by the forecasts, and those variations may be material. The following are among the factors that could cause actual results to differ materially from the forward-looking statements:

  .  utility commission practices;
  .  political developments;
  .  regional, national and international economic conditions;
  .  weather and behavioral variations affecting customer electricity usage;
  .  competition and supply in bulk power and natural gas markets;
  .  hydroelectric and natural gas production levels;
  .  changes in coal quality and prices;
  .  unscheduled generation outages;
  .  disruption or constraints to transmission or distribution facilities;
  .  outcome of hydroelectric facility relicensing;
  .  energy purchase and sales activities;
  .  changes in environmental, regulatory or tax legislation, including industry restructure
     and deregulation initiatives;
  .  nonperformance by counterparties;
  .  technological developments in the electricity industry;
  .  outcome of rate cases submitted for regulatory approval;
  .  workforce factors;
  .  new accounting pronouncements;
  .  terrorist activity;
  .  credit rating changes; and
  .  the cost and availability of debt and equity capital.

16

Any forward-looking statements issued by the Company should be considered in light of these factors. The Company assumes no obligation to update or revise any forward-looking statements to reflect actual results, changes in assumptions or changes in other factors affecting such forward-looking statements or if the Company later becomes aware that these assumptions are not likely to be achieved.

The western U.S. wholesale energy market was relatively stable during the three months ended June 30, 2002, with adequate capacity. The fill level of hydroelectric dams was also back to normal levels. Physical additions of peaking plant to meet summer demand, such as the 120 megawatt ("MW") Gadsby gas-fired peaking plant in Utah, scheduled to come on line in late summer, and the operating lease from a subsidiary of PacifiCorp Power Marketing, a subsidiary of PHI, of a 200 MW peaking plant in Utah, and other flexible physical hedge products, are expected to help the Company maintain a balanced net energy position through this fiscal year.

The Company has made progress toward recovering the deferred net power costs incurred during the period of extreme volatility and unprecedented high price levels beginning in the summer of 2000 and extending through the summer of 2001. These costs are being recovered through the following rate orders: (i) $147.0 million in Utah, approved on May 1, 2002 and recoverable through a $29.5 million annual surcharge for two years and regulatory liability offsets and (ii) $25.0 million in Idaho, approved on June 7, 2002 and recoverable through a $22.7 million surcharge over two years and regulatory liability offsets. On July 18, 2002, the Oregon Public Utility Commission ("OPUC") approved recovery of $136.5 million in deferred net power costs, including $5.5 million in carrying charges. In August 2002, the OPUC allowed the Company to raise the annual surcharge level to recover these costs to 6.0%, from 3.0%. In Wyoming, the Company has requested recovery of $91.0 million i n deferred net power costs to be recovered through two surcharges over three years.

The Company's earnings contribution on common stock for the three months ended June 30, 2002 was $33.7 million compared to $193.8 million for the three months ended June 30, 2001. Earnings contribution was impacted by the following items: (i) Unrealized losses and gains on SFAS No. 133 derivative instruments; (ii) changes in accounting relating to the adoption of SFAS No. 133 in 2001 and revised Issue C15 and Issue C16 in 2002; (iii) income in 2001 from the discontinued operations of a former mining and resource development business; and (iv) a gain in 2001 from the sale of Australian Electric Operations.

(a)  Earnings contribution on common stock by segment: (i) does not reflect elimination of interest on intercompany borrowing arrangements; (ii) includes income taxes on a separate company basis, with any benefit or detriment of consolidation reflected in Other Operations; and (iii) is net of preferred dividend requirements and minority interest (which is reported as a component of Minority interest and other).

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(b)  All Other Operations were transferred to PHI on February 4, 2002.

(c)  Amounts for the three months ended June 30, 2001 represent the collection of a contingent note receivable relating to the discontinued operations of a former mining and resource development business, NERCO, Inc. ("NERCO"), which was sold in 1993.

(d)  Represents the effect of implementation of Statement of Financial Accounting Standards ("SFAS") No. 133, Accounting for Derivative Instruments and Hedging Activities, ("SFAS No. 133") at April 1, 2001 and the implementation of the Derivatives Implementation Group ("DIG") revised Issue C15 and Issue C16 at April 1, 2002.

Residential revenues for the three months ended June 30, 2002 increased $16.4 million, or 8.7%, from the three months ended June 30, 2001 primarily due to increases of $9.5 million due to higher prices, mainly in Oregon, $4.3 million from higher average customer usage, and $2.4 million relating to growth in the average number of residential customers.

Commercial revenues for the three months ended June 30, 2002 increased $2.2 million, or 1.2%, from the three months ended June 30, 2001. Growth in the average number of commercial customers increased revenues $4.2 million. This increase was partially offset by a $2.5 million decrease due to lower customer usage.

Industrial revenues for the three months ended June 30, 2002 decreased $20.6 million, or 11.0%, from the three months ended June 30, 2001 primarily due to a $16.2 million decrease caused by reduced customer usage and a $4.5 million decrease resulting from lower prices.

18

Wholesale sales for the three months ended June 30, 2002 decreased $363.1 million, or 55.3%, from the three months ended June 30, 2001. The decrease in revenues in the current period resulted from the sharp decline in market prices for short-term and spot market sales from those in the prior period. Factors contributing to the lower market prices included more generation online in the western U.S., lower natural gas prices, increased hydroelectric generation and weaker demand. Megawatt-hour wholesale sales increased 95.5%. Volumes for short-term and spot market sales increased significantly as the Company took advantage of lower prices to meet its load requirement and sold excess power in the daily and hourly markets. Volumes also increased in the current period due to the prior period outage at the Hunter No. 1 generation plant.

Other revenues for the three months ended June 30, 2002 decreased $18.9 million, or 38.7%, from the three months ended June 30, 2001 primarily due to a $16.3 million decrease in wheeling revenues from decreased usage of the Company's transmission system by third parties.

See Part II, Item 5. Other Information for information regarding recent developments in regulatory issues affecting the Company.

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(a)  Minority interest and other includes payments of $7.1 million on Preferred Securities of wholly owned subsidiary trusts for each of the three month periods ended June 30.

Interest expense increased $9.0 million, or 16.4%, primarily due to higher debt balances, partially offset by lower short-term and variable interest rates. The Company issued $800.0 million of new long-term debt in November 2001.

Interest income decreased $6.2 million, or 74.7%, primarily due to the transfer of Holdings to PHI in February 2002. Holdings interest income from Scottish Power UK plc, and other affiliates is no longer included in the Company's results.

Interest capitalized increased $3.2 million, or 139.1% due to higher construction work-in-progress balances and higher capitalization rates in the current period.

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Minority interest and other increased $17.5 million, or 216.0% partially due to the reversal in the current period of a previously recorded gain of $3.4 million as a result of a regulatory order. For the three months ended June 30, 2001, the Company recorded a $9.3 million gain on the sales of leased aircraft owned by PFS and a $3.5 million gain on the sales of non-utility investments held by Holdings.

INCOME TAX EXPENSE

Income tax expense decreased $81.5 million principally due to the lower taxable income in the current period. The effective tax rate for the three months ended June 30, 2002 was 34.3% compared to a 38.1% effective tax rate for the three months ended June 30, 2001. See Note 7 of the NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS under ITEM 1. FINANCIAL STATEMENTS.

DISCONTINUED OPERATIONS

The Company recognized $146.7 million of income during the three months ended June 30, 2001 as a result of collecting a contingent note receivable relating to the discontinued operations of its former mining and resource development business, NERCO, which was sold in 1993. Deferred tax expense of $36.4 million was recognized on the gain in June 2001.

OPERATING ACTIVITIES

Net cash flows provided by operating activities were $132.1 million for the three months ended June 30, 2002 compared to $61.4 million for the three months ended June 30, 2001. This increase in operating cash flows was primarily attributable to higher purchased power prices included in the prior period net income that were not being recovered through regulated rates.

INVESTING ACTIVITIES

Capital spending totaled $131.0 million for the three months ended June 30, 2002 compared to $106.6 million for the three months ended June 30, 2001. Current year capital spending is in line with the construction program outlined in the Company's 2002 Annual Report on Form 10-K. The increase was primarily due to expenditures for new generation, network growth, system upgrades and other capital projects. Proceeds from sales of assets for the three months ended June 30, 2002 represented sales of utility properties and for the three months ended June 30, 2001 represented additional proceeds relating to the disposal of Australian Electric Operations. Proceeds from finance note repayment in the prior period represented the payment of a note receivable held by Holdings relating to the discontinued operations of a former mining and resource development business, NERCO, which was sold in 1993. Certain investing activities for the three months ended June 30, 2001 do not appear in th e three months ended June 30, 2002 due to the transfer of Holdings and its subsidiaries from PacifiCorp to PHI.

FINANCING ACTIVITIES

The Company does not utilize "off-balance sheet" financing arrangements other than operating leases, which are accounted for in accordance with SFAS No. 13, Accounting for Leases.

The Company's short-term borrowings and certain other financing arrangements are supported by $800.0 million of revolving credit agreements that became effective June 4, 2002 with one facility for $500.0 million having a 364-day term plus a one-year term loan option, and the other facility for $300.0 million having a three-year term. Other provisions are similar to prior credit agreements. The interest on advances under these facilities is based on LIBOR plus a margin that varies based on the Company's credit ratings. In addition to these committed credit facilities, the Company had $129.0 million in money market accounts included in Cash and cash equivalents at June 30, 2002 available to meet its liquidity needs.

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The Company declared dividends of $1.9 million on preferred stock on May 24, 2002, which are payable on August 15, 2002.

Management expects existing funds and cash generated from operations, together with existing credit facilities, to be sufficient to fund liquidity requirements for the next 12 months.

CAPITALIZATION

At June 30, 2002, PacifiCorp had $181.5 million of commercial paper outstanding at a weighted average rate of 2.1%. These borrowings and other financing arrangements are supported by revolving credit agreements and cash on hand as described above.

For a discussion of the Company's credit ratings, see ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS in the Company's 2002 Annual Report on Form 10-K.

CONTRACTUAL OBLIGATIONS AND COMMERCIAL COMMITMENTS

The tables below show the Company's contractual obligations and commercial commitments as of June 30, 2002 for each of the 12-month periods ended June 30.

(a) A portion of the operating lease obligations are expected to be offset by sublease revenue. At June 30, 2002, expected sublease revenues were $0.7 million for year one, $0.7 million for years two and three, $0.5 million for years four and five and $1.4 million thereafter.

The amounts above do not include capital commitments.

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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

BUSINESS RISK

The Company's business risks relating to Market, Regulatory/Political, Credit, Interest Rate and Insurance continue to be as reported in the Company's Annual Report on Form 10-K for the year ended March 31, 2002 under ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK. The Company is further subject to the risks that have been or may in the future be imposed on the market from the Federal Energy Regulatory Commission (the "FERC") proceedings as mentioned under ITEM 5. OTHER INFORMATION - WESTERN POWER MARKET ISSUES below.

During the quarter, the Company responded to data requests from the FERC regarding trading practices connected with the California power crisis of 2000 and 2001. The Company confirmed that it did not engage in any trading practices intended to manipulate the market as described in the FERC's request.

There has been a decrease in the number of counterparties in the wholesale energy markets with whom the Company has been able to transact business. This is due to an overall negative ratings trend in the energy industry and the concern that these counterparties may face a liquidity crisis and be unable to meet their obligations. In addition, some counterparties are focusing their efforts on trading around their assets, pursuing lower risk/slower growth opportunities, strengthening their balance sheets in order to maintain an investment grade rating, exiting the marketplace entirely, or are looking to sell their energy trading divisions.

The Company continues to experience risk relating to increases in various insurance premiums and available insurance coverage for certain property and liability exposures.

FAIR VALUE OF DERIVATIVES

SFAS No. 133 requires all derivatives, as defined by the standard, to be marked to market value, except those which qualify for specific exemption under the standard or associated DIG guidance, such as those defined as normal purchases and normal sales. The derivatives that are marked to market value in accordance with SFAS No. 133 include only certain of the Company's commercial contractual arrangements as many of these arrangements are outside the scope of SFAS No. 133.

The following table shows the changes in the fair value of energy related contracts qualifying as derivatives under SFAS No. 133 from April 1, 2002 to June 30, 2002 and quantifies the reasons for the changes.

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The following discloses summarized information with respect to valuation techniques and contractual maturities of the Company's energy-related contracts qualifying as derivatives under SFAS No. 133 as of June 30, 2002.

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ITEM 5.  OTHER INFORMATION

WESTERN POWER MARKET ISSUES

Effective June 19, 2001, FERC imposed a price mitigation plan that limits prices on spot market sales in California 24 hours a day, seven days a week until September 30, 2002. Sellers have an opportunity to justify to FERC prices above the capped limit. However, entities reselling power that was purchased are not permitted to seek prices above the capped limit.

On July 25, 2001, the FERC issued an order that extended the California price limits to all wholesale spot market sales in the entire 11-state western region. On December 19, 2001, the FERC revised the methodology used to calculate price limits for the winter season. The mitigated price for all hours until May 1, 2002, was raised to the full amount of the last calculated price cap when reserves in California fell below 70.0%. The price limit will be increased further when the indices for natural gas prices used to establish the mitigated price increase by 10.0%. On May 1, 2002, the price limit calculations reverted to using the original methodology. Effective July 12, 2002, the FERC reset the price limit to $91.87 per MWh as a hard price cap through September 30, 2002. On July 17, 2002, the FERC ordered that the price cap would be raised to $250.00 per MWh effective October 1, 2002.

The FERC's June 19, 2001 order also required that "all public utility sellers and buyers in the Cal ISO's markets participate in settlement discussions to complete the task of settling past accounts and structuring the new arrangements for California's energy future." The FERC appointed an Administrative Law Judge ("ALJ") to serve as a settlement judge. On July 11, 2001, the ALJ issued a recommendation to the FERC based upon the settlement conference, proposing a methodology to calculate refund issues. The FERC agreed with the ALJ-proposed methodology. A proceeding before a second ALJ has been established to determine each party's refund liability. This phase of the proceeding is scheduled for hearing in August 2002. The Company's exposure to refunds is dependent upon any order issued by the FERC in response to the outcome of these proceedings.

The FERC has also established a second proceeding to consider the possibility of requiring refunds for wholesale sales in the Pacific Northwest between December 25, 2000 and June 20, 2001. The ALJ recommended that FERC not require refunds for these sales. The FERC has not yet issued a decision in the Pacific Northwest refund proceeding. The Company's exposure to refunds will be dependent upon any order issued by the FERC in response to the outcome of these proceedings and cannot be determined at this time.

On May 2, 2002, PacifiCorp filed a series of complaints with the FERC against five wholesale power suppliers for charging excessive prices for wholesale electricity purchases scheduled for delivery during the summer of 2002. The contracts covered in the complaint were signed during a period of extreme wholesale market volatility and before the FERC imposed its West-wide spot market price mitigation (price caps). PacifiCorp is seeking reformation of the contract prices to levels that constitute just and reasonable rates.

During the quarter, the Company responded to data requests from the FERC regarding trading practices connected with the California power crisis of 2000 and 2001. The Company confirmed that it did not engage in any trading practices intended to manipulate the market as described in the FERC's request.

REGULATION

The regulatory issues detailed in the paragraphs below represent only those issues that have changed since the Company filed its Annual Report on Form 10-K for the year ended March 31, 2002. See ITEM 1. BUSINESS - DOMESTIC ELECTRIC OPERATIONS - REGULATION of that report for more detailed information on all regulatory issues currently affecting the Company.

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Trail Mountain Mine Closure Costs
On February 7, 2001, the Company filed applications with the UPSC, the OPUC, the Wyoming Public Service Commission ("WPSC") and the Idaho Public Utilities Commission ("IPUC") requesting accounting orders to defer $27.1 million in unrecovered costs associated with its Trail Mountain coal mine. The Company ceased operations at the mine on March 7, 2001. The mine is located in Central Utah and supplied fuel to the Hunter Plant. In April 2001, the WPSC and the IPUC approved deferred accounting treatment of their state's share of the $27.1 million of non-recovered Trail Mountain Mine investment costs. Additional closure-related costs in the amount of $18.7 million were subsequently identified, and the total amount subject to possible deferral increased to approximately $45.8 million. The Company filed in Utah and Oregon to include the additional costs in its deferral application and received approval to defer the full $45.8 million for accounting purposes. In addition, the parti es in Oregon signed a stipulation calling for a permanent $1.1 million annual rate reduction in Oregon due to the removal of the Trail Mountain assets from rate base. The stipulation also provides for a $2.6 million annual surcharge for five years to recover Oregon's share of mine closure costs. This stipulation was approved by the OPUC on May 20, 2002. On April 4, 2002, the UPSC approved deferral of Utah's share of the $45.8 million with a five-year amortization beginning April 1, 2001.

In April 2002, the Company established a regulatory asset for the full closure costs of the Trail Mountain mine with a five-year amortization period beginning April 1, 2001. The resulting regulatory asset at June 30, 2002 was $34.8 million, net of amortization. The reestablishment of the regulatory asset increased accumulated depreciation to reverse the effects of the retirement of the mine and decreased coal inventory costs for the closure-related costs.

Concluded Regulatory Actions
Oregon - On May 20, 2002, the OPUC approved a one-year $15.4 million overall rate increase effective June 1, 2002 for the Company's Oregon customers to cover increases in power costs. The Industrial Customers of Northwest Utilities has requested reconsideration of a portion of this order and has also challenged the order in the Marion County, Oregon, Circuit Court . The amount at issue in the reconsideration request in Oregon is $1.2 million annually.

Idaho - On January 7, 2002, the Company filed a request with the IPUC to recover $38.0 million of deferred net power costs through a temporary 24-month surcharge on customer bills and to implement a new credit to pass through Residential Exchange Program benefits from two Bonneville Power Administration settlement agreements. The credit would not affect Company earnings. In addition, the Company requested an adjustment of individual rate classes to more closely reflect the actual cost-of-service and proposed a rate mitigation policy to ensure that no customer class would receive a rate increase during the period in which the proposed surcharge is in effect. Parties to the proceeding agreed to a stipulation that would allow recovery of $25.0 million of the deferred net power costs. This recovery would be achieved through a $22.7 million power cost surcharge over two years plus termination of future merger credits in the amount of $2.3 million. The IPUC approved the stipu lation on June 7, 2002. On June 28, 2002, the Company filed a petition asking the IPUC to reconsider the portion of its June 7, 2002 order requiring that the Company implement a one-time refund of $1.1 million related to procedural issues in the form of a $20 per customer credit. Two individuals also filed petitions for reconsideration of several aspects of the IPUC's order approving the stipulation. On July 24, 2002, the IPUC granted the Company's petition for reconsideration, with hearings set for September 10, 2002, and denied the petitions from the two other parties.

Rate Increases Submitted for Regulatory Approval
Wyoming - On May 7, 2002, the Company filed a general rate case seeking a permanent $30.7 million increase in electricity rates for its Wyoming customers. If approved by the WPSC, customer rates would increase approximately 9.8%. The Company's filing also incorporated a request for all deferred net power costs, including those for which recovery was being sought in a prior withdrawn proceeding, totaling $91.0 million.

California - On March 16, 2001, the Company filed an interim rate relief request with the CPUC as Phase I in an effort to seek an increase in electricity rates for its customers in California. On June 27, 2002, the CPUC approved an interim increase of $0.01 per kilowatt hour ("kWh") for certain customers, or approximately $4.7 million annually, or 8.8%, overall. This rate increase is subject to refund pending the outcome of the General Rate Case

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("GRC"). In addition, the Company filed Phase II of a GRC to increase rates to compensatory levels on December 21, 2001. If approved by the CPUC, customer rates would increase 29.4% overall or $16.0 million annually, with an authorized return on equity of 11.5%. The annual amount requested would incorporate the Phase I interim amount. On December 26, 2001, the Office of Ratepayer Advocates ("ORA") filed a motion to dismiss or defer the Company's GRC request. The Company responded to ORA's motion on January 9, 2002. Following the expiration of the protest period, on February 25, 2002, the Company filed a motion for a pre-hearing conference to identify parties of record, establish a procedural schedule and address other issues.

Deferred Net Power Cost Filings
On November 1, 2000, the Company filed applications in Utah, Oregon, Wyoming and Idaho seeking deferred accounting treatment for net power costs materially in excess of the power costs assumed in setting existing retail rates. The applications sought to defer these power cost variances beginning November 1, 2000. As discussed below, the Company received authorization to defer some power costs in excess of those included in retail rates in all the states where requests were made. At June 30, 2002, the Company had a regulatory asset, net of amortization, of $233.5 million, including carrying charges, for total deferred net power costs.

Utah - In Utah, pursuant to the UPSC's approval of deferred accounting treatment for replacement power costs resulting from the Hunter No. 1 outage, the Company filed on August 23, 2001 seeking permission to recover $103.5 million in replacement power costs over a 12-month period. On November 2, 2001, the UPSC allowed the Company to apply over-collections from an earlier general rate case toward Hunter No. 1 replacement power costs on an interim basis, subject to refund. The amount of the interim relief was approximately $29.5 million annually.

Also in Utah, on September 21, 2001, the Company filed for permission to defer $109.0 million of net power costs above the level adopted in the UPSC's rate order of September 10, 2001. These costs were incurred during the period May 9, 2001 through September 30, 2001. A hearing relating to the deferral was held on December 7, 2001.

On May 1, 2002, the UPSC issued an order approving a stipulation agreement regarding recovery of the deferred and non-deferred net power costs referred to above. The order allowed the Company to continue collecting the $29.5 million annual surcharge until March 31, 2004 and to apply the $34.7 million of revenue already collected subject to refund against deferred net power costs. The order also allowed the Company to offset deferred net power costs against a regulatory liability of $27.0 million relating to the gain from the 2001 sale of the Centralia, Washington power plant. These offsets reduced the regulatory asset for deferred net power costs. In addition, the UPSC allowed the elimination of $20.0 million for the final two years of merger credits associated with the merger of ScottishPower and PacifiCorp. Monthly revenues will increase approximately $1.0 million until December 31, 2003 due to the termination of merger credits. The Company has recorded additional deferre d net power costs of $17.9 million, has withdrawn its request to defer $109.0 million of deferred net power costs and has committed not to file a general rate case with a rate effective date prior to January 1, 2004, with certain exceptions. This order should allow the Company to recover a total of $147.0 million of deferred net power costs in Utah by March 31, 2004. A party that opposed the stipulation has filed a petition with the Utah Supreme Court for review of the order approving the stipulation.

Oregon - The Oregon deferred accounting filing encompassed all power costs that vary from the level in Oregon rates during the period from November 1, 2000 through September 9, 2001, including costs to replace lost generation resulting from the Hunter No. 1 outage. On January 18, 2001, the Company requested a 3.0%, or $22.8 million, annual rate increase effective February 1, 2001, to provide partial recovery of post-October 31, 2000 power cost variances attributable to Oregon over an amortization period. This 3.0% rate increase was the maximum allowed on an annual basis for the recovery of deferred costs under the Oregon statutes. On January 23, 2001, the OPUC authorized deferred accounting for power costs of $22.8 million. On February 20, 2001, the OPUC authorized the 3.0% rate increase effective February 21, 2001, subject to refund, pending the outcome of a separate phase of the proceeding to examine the prudence of these expenditures. At June 30, 2002, the Company had received $29.1 million in revenues as a result of this OPUC action.

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The Company filed with the OPUC on September 21, 2001 to increase the level of recovery of deferred net power costs incurred to serve Oregon customers from the current 3.0% amortization level, or $22.8 million awarded in February 2001, to 6.0%, the maximum allowed on an annual basis for recovery of deferred costs under a recent change in Oregon law. On October 22, 2001, the OPUC suspended the Company's request pending the outcome of the prudence phase of the proceeding.

In December 2001, the Company and the OPUC staff reached a stipulation in the prudence phase of its deferred net power cost proceeding. The stipulation provided that the Company would be permitted to recover 85.0% of the deferred net power costs in Oregon, or about $136.5 million, including $5.5 million of carrying charges. The stipulation allowed the Company to seek increased recovery in the event the Company's appeal of the Commission's order limiting deferrals is successful. On July 18, 2002, the OPUC issued an order approving the stipulation and ending the prudence phase of the proceeding. On August 6, 2002, the OPUC allowed the Company to increase the amortization level from 3.0% to 6.0%. The new rates are effective August 8, 2002.

While the 6.0% increase establishes the maximum annual rate to be recovered, the Company continued to pursue the total amount to be recovered through its October 1, 2001 appeals, to the Marion County, Oregon, Circuit Court , of two OPUC orders. These orders established the mechanism to determine the amount of power costs to defer. The appeals were consolidated. On June 5, 2002, the Marion County, Oregon, Circuit Court upheld the OPUC decision. The Company continues to pursue the appeals process.

On September 7, 2001, the OPUC endorsed an agreement on deferral of net power costs after September 2001. From September 10, 2001 until May 31, 2002, the Company deferred the difference between 83.0% of actual net power costs and the new Oregon baseline power cost in tariffs. This mechanism was terminated on May 31, 2002 concurrent with the effective date of the settlement approved on May 20, 2002.

Wyoming - In Wyoming, on November 1, 2000, the Company filed for deferred accounting treatment of net power costs that vary from costs included in determining retail rates. The Company proposed to recover $47.0 million of deferred net power costs, incurred through June 2001, over a 12-month period. On November 20, 2001, following an order by the WPSC dismissing the majority of the Company's case based on a procedural issue, the Company requested authority to withdraw its deferred net power cost recovery filing without prejudice. On November 26, 2001, the WPSC granted the Company's motion. On May 7, 2002, the Company filed a Wyoming general rate case that includes a consolidation of all deferred net power costs, including those for which recovery was being sought in the withdrawn proceeding, totaling $91.0 million.

Washington - On April 5, 2002, the Company filed a petition with the WUTC seeking authority to begin deferring net power costs in excess of those included in rates as of June 1, 2002 for later recovery in rates, either through a power cost adjustment mechanism or a limited rate adjustment. Under the rate plan approved by the WUTC in August 2000 at the conclusion of the Company's last general rate case in Washington, there are limitations on the Company's ability to raise general rates prior to 2006. On May 10, 2002, the other parties to the rate plan filed a motion with the WUTC seeking to reopen the Company's 2000 general rate case and consolidate it with the Company's request for deferred accounting. In an order issued on July 12, 2002, the WUTC granted the motion to consolidate, and scheduled a preliminary conference in the proceeding for August 2002.

Regional Transmission Organization ("RTO")
The Company, in conjunction with nine other utilities, is seeking to form an RTO ("RTO West"), in response to FERC Order 2000. The 10 members of RTO West would be Avista Corporation, British Columbia Hydro Power Authority, BPA, Idaho Power Company, Northwestern Energy L.L.C. (formerly 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 the FERC and some of the states served by these entities who may also assert jurisdiction over certain matters relating to the formation of RTO West. RTO West plans to operate all transmission facilities needed for bulk power transfers and control the majority of the 60,000 miles of transmission lines owned by the entities. On March 29, 2002, the members of RTO West filed a request with the FERC for a declaratory judgment that their proposal to establish RTO West as a regional

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transmission organization satisfies the characteristics and functions of FERC Order 2000. The FERC is expected to
rule on the filing in September 2002.

On July 31, 2002, the FERC issued its Notice of Proposed Rulemaking ("NOPR"), proposing a new Standard Market Design for wholesale electricity markets and requesting comments from market participants by mid-October 2002. The Company is in the process of evaluating the NOPR and assessing its impacts on the Company.

Integrated Resource Planning
The Company is developing an Integrated Resource Plan ("IRP") to create a clear plan and strategy to help ensure that the Company fulfills its obligations to serve customers while delivering the most economic solutions for both the customer and the shareholder. The IRP is intended to reduce commodity risk and help the Company achieve its allowed regulated rate of return. The IRP is expected to be filed with state commissions by December 2002. On July 23, 2002 the OPUC opened a rulemaking to consider changes to its IRP planning process.

PROPOSED ASSET DISPOSITION

In July 1998, the Company announced its intention to sell its California service territory, including its electric distribution assets. The Company and Nor-Cal Electric Authority ("Nor-Cal")have engaged in detailed negotiations with a view towards executing a definitive sale agreement. Various factors have impeded consummation of the sale transaction. Most recently, in June 2002, the California county of Siskiyou filed a validation action in California Superior Court, challenging the authority of Nor-Cal to enter into such a transaction as proposed, and alleging certain conflicts of interest among Nor-Cal and its advisors. Based on the foregoing factors, consummation of the sale is uncertain.

ITEM 6.  EXHIBITS AND REPORTS ON FORM 8-K

(a)  Exhibits.

(b)  Reports on Form 8-K.

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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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