PACIFICORP /OR/ - Quarter Report: 2002 September (Form 10-Q)

NOTE 1 - Financial Statements

The condensed consolidated financial statements of PacifiCorp (the "Company") include its integrated domestic electric utility operations ("Domestic Electric Operations") and its wholly owned and majority-owned subsidiaries. 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 September 30, 2002 and for the periods ended September 30, 2002 and 2001, in the opinion of management, reflect all adjustments, which include 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 September 30, 2002 and 2001 are not necessarily indicative of the expected results for any other interim period or the year ending March 31, 2003. 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 direct, 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") to PHI. Holdings includes the wholly owned subsidiary, PacifiCorp Financial Services, Inc. ("PFS"), a financial services business. Accordingly, the results of operations, assets and liabilities 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 (loss).

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 Company records regulatory assets and liabilities based on management's assessment that it is probable that a cost will be recovered (asset) or that an obligation has been incurred (liability). The final outcome, or additional regulatory actions, could change

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management's assessment in future periods. 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 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 September 30, 2002, management concluded that SFAS No. 71 was appropriate for the 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 in 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 September 30, 2002, the Company had a balance of $227.1 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 ("WPSC") in a rate case expected to be concluded by March 2003. Full recovery cannot be assured and differences between the amount allowed by the commission and the amounts capitalized at September 30, 2002 will be recognized as either a charge or credit to income upon receiving a final commission order. The balance of deferred net power costs at September 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 ("OPUC") issued an order approving a stipulation agreement allowing recovery of $136.5 million for certain deferred net power costs, including $5.5 million in carrying charges. This order is the subject of a court appeal by the intervening parties. On August 6, 2002, the OPUC allowed the Company to increase the amortization level for these deferred costs, from 3.0% to 6.0%. In October 2002, the Company entered into a voluntary stipulation with one of the intervening parties, supported by the OPUC staff, to allow collections from Oregon customers for these costs to be refunded if, as a result of the foregoing court appeal, an order or ruling is issued declaring all or any portion of these deferred costs imprudent. Amounts subject to refund would include only those collections occurring after the OPUC approves this stipulation, which management expects will occur before March 31, 2003.

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.

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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 recorded in Purchased power and Fuel expense on the Condensed Consolidated Statements of Income (Loss) and Retained Earnings. A derivative financial instrument or other contract derives its value from another investment, a designated benchmark, or an underlying price.

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 and volume 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.

In June 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 a tax benefit of $1.3 million) on the Company's Condensed Consolidated Statements of Income (Loss) and Retained Earnings. For contracts qualifying for deferred accounting under SFAS No. 71, the effect of adopting the revised C15 Issue was $0.7 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 (Loss) 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. The applicable contracts pertain to the purchase and transport of natural gas. The costs of these contracts have been allowed in rates and the liability is, therefore, offset by a corresponding amount included in regulatory assets.

In June 2002, the EITF reached a partial consensus on Issue No. 02-3, Accounting for Contracts Involved in Energy Trading and Risk Management Activities, ("EITF No. 02-3"). The partial consensus requires that all mark-to-market gains and losses arising from energy trading contracts (whether realized or unrealized) accounted for under EITF Issue No. 98-10, Accounting for Contracts Involved in Energy Trading and Risk Management Activities, ("EITF No. 98-10") be presented on a net basis in the income statement and that the gross transaction volume be disclosed for those energy trading contracts that are physically settled. The net presentation requirement is effective beginning in the first interim period ending after July 15, 2002 and the disclosure requirements are effective for financial statements issued for fiscal years ending after July 15, 2002. Reclassification of all historical periods is required. The impact upon adoption was immaterial.

Through the Company's risk management policies and procedures, as implemented by the Risk Management Committee, the types of instruments the Company may utilize are specifically limited to those instruments that are generally used for hedging volume and price fluctuations associated with the management of resources. Instruments

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are also limited to those commodities representing the Company's principal business (electricity, natural gas and coal). 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. Transactions classified as energy trading activities are accounted for under EITF No. 98-10 and contributed $1.6 million for the six months ended September 30, 2002. All of these transactions were settled by September 30, 2002.

On October 25, 2002, the EITF agreed to rescind EITF No. 98-10. The EITF retained its June 2002 consensus requiring that revenue from energy trading be reported on a net basis by specifying that this still applies to contracts that are defined as derivatives under SFAS No. 133, even if the power, gas or other commodity is physically delivered. Contracts that meet the definition of a derivative under other FASB rules would still have to be marked to fair value, but most energy-related contracts, such as tolling, capacity, storage, and transportation agreements, would not. This rescission applies to any contracts entered into after October 25, 2002 and would take effect for existing contracts in the first fiscal reporting period beginning after December 15, 2002.

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

During the six months ended September 30, 2002, approximately $38.7 million ($24.0 million after-tax) of unrealized net losses on derivative instruments in Accumulated other comprehensive income (loss) reversed as the underlying contracts were settled. A corresponding change to the SFAS No. 133 asset was recorded with no net effect on earnings.

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.

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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)  Amounts shown relate to activities of the Company and its subsidiaries, with PHI and its subsidiaries.

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

(d)  Short-term demand loans to PacifiCorp, in accordance with regulatory authorizations, are included in Notes payable and commercial paper.

(e)  These revenues primarily represent wheeling revenues received from PacifiCorp Power Marketing, Inc. ("PPM"), a subsidiary of PHI.

(f)  These expenses represent operating lease payments for a generation facility owned by a subsidiary of PPM, as discussed below.

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

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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 September 30, 2002 was 2.2%.

In May 2002, the Company entered into a fifteen year operating lease on an electric generation facility with West Valley Leasing Company, a subsidiary of PPM. This lease was approved by the OPUC. The Company, at its sole option, may terminate the lease after three and after six years. The facility consists of five generation units each rated at 40 megawatts ("MW") and is located in Utah. Scheduled lease payments are $3.0 million annually per unit. Four of these units were operational June 15, 2002 and the fifth unit became 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 September 30, 2002, there were no borrowings outstanding under these facilities.

NOTE 6 - Common Stock

On August 22, 2002, the Board of Directors of the Company approved the issuance of up to 50 million additional shares of its common stock ("Shares") to be sold, from time to time, to PHI, in such amounts and at such times as shall be determined by the Company, but initially not expected to exceed $300.0 million. Issuance and sale of the Shares is subject to the receipt of cash for the Shares in an amount per share not less than book value at the end of the month prior to the date of the issuance. The Company has received all necessary regulatory approvals. As of September 30, 2002, no Shares had been issued.

NOTE 7 - 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.

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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 fish; 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. Contingencies identified at September 30, 2002 principally consist of Clean Air Act matters, which are the subject of discussions with the EPA and state regulatory authorities. The Company expects that future costs relating to these matters may be significant and consist primarily of capital expenditures. The Company expects these costs will be included in rates, and as such, will not have a material adverse impact on the Company's consolidated results of operations.

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. The Company expects that future costs relating to these matters may be significant and consist primarily of capital expenditures, and that power generation reductions may result from the additional environmental requirements. The Company expects these costs will be included in rates, and as such, will not have a material adverse impact on the Company's consolidated results of operations.

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"). Investigations suggest that Swift No. 2 will be out of service for an extended period of time, possibly more than two years. This failure has impacted 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, operations safety 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. This event is not expected to have a significant impact on the Company's financial position or results of operations.

NOTE 8 - Income Taxes

The Company accrued federal and state income tax expense of $41.3 million and $98.1 million, representing effective tax rates of 37.4% and 42.2%, for the six months ended September 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

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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.

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 an expense of approximately $40.9 million. The Company has an established liability for this amount. The Company has filed 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 started the examination of the 1999 and 2000 tax years in September 2002.

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NOTE 9 - Comprehensive Income

The components of comprehensive income are as follows:

NOTE 10 - 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, the adoption of SFAS No. 142 had no material effect on the Company's financial position or results of operations.

In addition, the Company adopted EITF No. 02-3, revised Issue C15 and Issue C16 as discussed in Note 3.

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 is incurred. At the same time the liability is recorded, the costs of the asset retirement obligation must 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 the recognition of 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 11 - Segment Information

The Company previously operated in two business segments (excluding other and discontinued operations): Domestic Electric Operations and Australian Electric Operations. The Australian Electric Operations were sold in the fall of 2000. The Company currently has one segment, Domestic Electric Operations, which includes the

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regulated retail and wholesale electric operations in the six western states in which the Company operates. Other Operations consisted of PFS, as well as the activities of Holdings, which were transferred to PHI in February 2002.
Selected information regarding the Company's operating segments 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 sale in the amount of $27.4 million.

(b)  Amounts for the six months ended September 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 12 - 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.

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On December 31, 2001, NA General Partnership ("NAGP") transferred all of the common stock of PacifiCorp (the "Company") 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 (Loss) and Retained Earnings and Condensed Consolidated Statement of Cash Flows for the three and six months ended September 30, 2001, but are not included for the three and six months ended September 30, 2002.

CRITICAL ACCOUNTING POLICIES

The preparation of consolidated financial statements in conformity with accounting principles generally accepted in the United States of America 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:

  .  federal and state 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;
 .  outcome of litigation;
  .  workforce factors;
  .  cost and availability of insurance;
  .  pension and healthcare costs;
  .  outcome of IRS tax settlements;

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  .  new accounting pronouncements;
  .  terrorist activity;
  .  credit rating changes; and
  .  the cost and availability of debt and equity capital.

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.

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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 September 30, 2002 and quantifies the reasons for the changes.

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Depreciation Filings
During 1998, the Company filed applications with the respective regulatory commissions in the states of Utah, Oregon, Wyoming and Washington to increase rates of depreciation based on a new depreciation study. All applications were approved in 2000. The increase in rates of depreciation is primarily due to revisions of the estimated costs of removal for steam production and distribution plants. For the period April 1, 2000 to March 31, 2002, the state commissions ordered a reversal of a portion of previously accrued depreciation. These reversals in total, for all states, amounted to approximately $14.0 million per year for 2001 and 2002. On October 1, 2002, the Company filed applications with the respective regulatory commissions in the states of Utah, Oregon, Wyoming, Washington and Idaho to change the rates of depreciation based on a new depreciation study. The new study reflects depreciable plant balances at March 31, 2002 and results in a proposed decrease of $0.7 million annually in depreciation expense. On a jurisdictional basis, the new depreciation study proposes to decrease annual depreciation expense in Oregon by $4.4 million and increases annual depreciation expense in Utah, Wyoming, Washington and Idaho by $3.7 million, $1.6 million, $0.3 million and $0.6 million, respectively. The changes in depreciation rates are primarily due to revisions of estimated costs of removal for steam generating plants and estimated service lives and costs of removal for distribution facilities.

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 parties 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. On May 7, 2002, the Company filed a general rate case in Wyoming, which seeks to recover Wyoming's share of the $45.8 million to be recovered based on a five-year amortization period beginning April 1, 2001. This general rate case is scheduled to be decided before March 2003.

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 September 30, 2002 was $32.5 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.

Merger Credits
As a result of the Merger, the Company was required to provide benefits to ratepayers through fixed reductions in rates, or "Merger Credits." The Company's total obligation for Merger Credits was $133.4 million through the period ending December 31, 2004. The Company recorded $12.0 million and $57.2 million as liabilities and current expenses in its financial statements for the years ended March 31, 2001 and 2000, respectively, as those amounts were not subject to potential offsets. In May 2002, the UPSC allowed the Company to offset $21.0 million of future Merger Credits against deferred net power costs and eliminated the obligation for future Merger Credits in Utah. On June 7, 2002, the IPUC approved a stipulation agreement that allowed the Company to offset future Merger Credits against deferred net power costs in the amount of $2.3 million. These actions will increase monthly revenues by approximately $1.0 million until December 31, 2003. Through September 30, 2002, the Company had provided $58.1 million in Merger Credits and interest to its customers through reduced rates. The Company is still obligated to provide $38.0 million of Merger Credits to customers in Oregon and Washington, with the possibility of offsetting $21.0 million of that amount against merger savings in future years or deferred power costs.

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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. This increase included an $18.7 million one-year surcharge related to above market costs for summer purchases. The Industrial Customers of Northwest Utilities ("ICNU") requested limited reconsideration of the portion of this order related to the lease of the West Valley, Utah generating units, amounting to $1.2 million annually. On August 8, 2002, the OPUC ordered this reconsideration. The OPUC will soon produce a final list of issues for the reconsideration and a schedule of proceedings.

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 ("BPA") 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 stipulation 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 $20.00 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. Hearings on the reconsideration were held on September 10, 2002. On October 25, 2002,the IPUC ordered the one-time refund of $1.1 million to be reduced to $10,000.

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. The Company currently expects an order on this request by March 2003.

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 ("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 (the "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. In September 2002, the Company and the ORA began setting up a discovery process that will be used during the initial stages of this proceeding. The discovery process began in mid-October 2002.

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 September 30, 2002, the Company had a regulatory asset, net of amortization, of $227.1 million, including carrying charges, for total deferred net power costs.

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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 deferred 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 September 30, 2002, the Company had received $39.9 million in collections as a result of this OPUC action.

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 September 16, 2002, the Citizens' Utility Board (the "CUB") and the Industrial Customers of Northwest Utilities (the "ICNU") appealed this decision to the Marion County, Oregon Circuit Court. On October 11, 2002, the Company moved to intervene in this complaint.

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On August 6, 2002, the OPUC allowed the Company to increase the amortization level from 3.0% to 6.0%. The new rates were effective August 8, 2002. On August 19, 2002, the CUB and the ICNU filed a complaint with the OPUC, requesting that the OPUC require the Company to discontinue amortization of the additional 3.0%, as it had not been authorized. On October 10, 2002, the Company filed a stipulation and tariff to allow the OPUC to reopen consideration of the increase in amortization of the deferred power costs from 3.0% to 6.0%. Subject to regulatory approval, the Company and CUB have reached a stipulation agreement, supported by the OPUC staff, that the amortization level will remain at 6.0% and that the amounts amortized after the OPUC implements the tariff will be subject to refund. The refund will occur if, an order or ruling is issued declaring all or a portion of these deferred costs imprudent. On October 14, 2002, the ICNU filed a response to the Company's motion to implement the stipulation and proposed tariff. Their response asked that the motion be denied as being procedurally improper.

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. On October 9, 2002, the Company appealed this decision to the Oregon Court of Appeals.

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. The Company currently expects an order on this request by March 2003.

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. On October 18, 2002, the Company filed testimony and supporting documents, requesting recovery of $17.5 million of excess power costs, including carrying charges. A final decision is expected by March 2003.

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 at this time 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 approval from the FERC. Some of the states served by these utilities may also assert jurisdiction over certain matters relating to the formation of RTO West. RTO West, when fully implemented, will 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.

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On July 31, 2002, the FERC issued its Notice of Proposed Rulemaking ("NOPR"), proposing a new Standard Market Design ("SMD") for wholesale electricity markets and requesting comments from market participants. Comments are due in mid-November 2002 or mid-January 2003, depending on the subject.

On September 18, 2002, the FERC voted that, with some modification and further development of certain details, the RTO West proposal not only satisfies the 12 characteristics and functions of FERC Order 2000, but also provides a basic framework for a standard market design for the region. Going forward, the focus of the RTO project will be on completing the RTO West design details, thereby influencing the final SMD Western market design framework. The entities plan to submit a proposed RTO West tariff in early 2003. In addition, the representatives are working to approve and file a Memorandum of Understanding regarding interconnection operations (seams) with the other two potential Western RTO's, WestConnect and the California Independent Grid Operator.

Multi-State Process ("MSP")
The Company continues its active engagement in a collaborative process with the six states it serves to develop mutually acceptable solutions to the problems faced by the Company and the states resulting from the Company's multi-state operations. These problems pertain to the allocation of the cost of the Company's existing investment and the recovery of the cost of future investments. This MSP is a process by which solutions, including the Company's Structural Realignment Proposal ("SRP"), are being developed and reviewed by interested parties from across the Company's service territory. Through MSP, the participants are working to clarify roles and responsibilities, including cost allocations for future generation resources, provide states with the ability to independently implement state energy policy objectives, and achieve permanent consensus on each state's responsibility for the costs and entitlement to the benefits of the Company's existing assets.

The SRP plan proposed by the Company would change the Company's legal and regulatory structure and result in the creation of six state electric distribution companies, a generation company that also holds transmission assets, and a service company, which are all intended to be subsidiaries of the holding company. Individual state proceedings and schedules for SRP are "on hold" so long as reasonable progress is made through the MSP. Any proposal that results from the MSP, is subject to approval by the utility commissions in Utah, Oregon, Wyoming, Washington, Idaho and California. Approval from the FERC may also be required.

Integrated Resource Plan

The Company is developing an Integrated Resource Plan ("IRP") to provide a framework and plan for the prudent future actions required to ensure that the Company continues to provide reliable and low-cost electric service to its customers. The IRP selects the optimal solution from a mix of renewable, fossil fuel, market purchase and demand side management choices. Any new generation or other asset called for by the IRP is expected to be included in the Company's future rate base. The IRP is expected to be filed with state commissions by December 2002. On August 6, 2002, the OPUC opened a rulemaking to consider changes to its IRP planning process.

PROPOSED ASSET DISPOSITION

California Service Territory
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.

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ITEM 6.  EXHIBITS AND REPORTS ON FORM 8-K

(a)  Exhibits.