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

For the quarterly period ended December 31, 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 _____

Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Securities Exchange Act of 1934).

     YES _____     NO   X  

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(Unaudited)

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 December 31, 2002 and for the periods ended December 31, 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 December 31, 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 consolidated results of operations, assets and liabilities of Holdings and its subsidiaries 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: (i) rates are established by or subject to approval by independent, third-party regulators; (ii) rates are designed to recover the specific enterprise's cost-of-service; and (iii) 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 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 recognizes

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amounts charged, pursuant to such rates, as liabilities and takes 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 realization 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 December 31, 2002, management concluded that SFAS No. 71 was appropriate for the Domestic Electric Operations. However, if deregulation activities 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 December 31, 2002, the Company had a balance of $191.9 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 will be established in a final order from the Wyoming Public Service Commission in the current combined rate case and deferred net power cost recovery case. This order is expected by March 31, 2003. Full recovery cannot be assured and differences between the amount allowed by the commission and the amounts capitalized at December 31, 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 December 31, 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 in 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. On December 10, 2002, the OPUC approved the voluntary stipulation and ordered the Company to file a tariff to implement the change. The tariff was approved by the OPUC with an effective date of January 22, 2003. Amounts subject to refund would include only those collections occurring after January 22, 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, they are recorded in the Condensed Consolidated Statements of Income 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, oil and coal forward, option and swap contracts and weather contracts to manage its exposure to commodity price and volume risk and to ensure supply, thereby attempting to minimize variability in net power costs for customers. The Company has policies and procedures to manage the 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 C15 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 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 $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.

On October 25, 2002, the EITF rescinded 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. Energy related contracts that meet the definition of a derivative under other FASB rules will still be marked to market, but energy-related contracts that do not meet the definition will not. This rescission applies to any contracts

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entered into after October 25, 2002 and takes effect for existing contracts in the first fiscal reporting period beginning after December 15, 2002. During the six months ended September 30, 2002, the Company entered into energy trading activities that were accounted for under EITF No. 98-10 and EITF No. 02-3. These transactions were not material. During the three months ended December 31, 2002, there were no energy trading activities.

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 are also limited to those commodities representing the Company's principal business (electricity, natural gas, coal and oil). Weather derivatives are also used to mitigate the weather risks on hydroelectric generation and electricity demand. The Company's hedging is done mainly to help balance retail and wholesale load. Short-term commodity instruments may occasionally be held by the Company for energy trading purposes.

The following table summarizes the SFAS No. 133 movements for the nine months ended December 31, 2002:

During the nine months ended December 31, 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 from the Company to ScottishPower or PHI are prohibited under the Public Utility Holding Company Act of 1935. Loans from ScottishPower or PHI to PacifiCorp generally require state regulatory and SEC approval. Affiliate transactions with the Company are subject to certain approval and reporting requirements of the regulatory authorities.

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

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(a)  Amounts due from affiliates are included in Other current assets on the Balance Sheet. The Company recharges to ScottishPower payroll costs and related benefits of employees working on international assignment to ScottishPower.

(b)  Amounts shown relate to activities of the Company and its subsidiaries with PHI and its subsidiaries. Expenses recharged reflect costs for support services to PHI and its subsidiaries.

(c)  These expenses and liabilities primarily represent payroll costs and related benefits of ScottishPower employees working on international assignment at 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 represent wheeling revenues received from PPM Energy, Inc. ("PPM"), formerly known as PacifiCorp Power Marketing, Inc., a direct subsidiary of PHI.

(f)  These expenses represent primarily 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.

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 average rate was 1.6% and 2.3% for the three months ended December 31, 2002 and 2001, respectively, and 1.8% and 3.4% for the nine months ended December 31, 2002 and 2001, respectively. There were no advances to affiliates outstanding at December 31, 2002.

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In May 2002, the Company entered into a fifteen year operating lease on an electric generation facility with West Valley Leasing Company LLC, a subsidiary of PPM, which was approved by the OPUC. The Company, at its sole option, may terminate the lease, or purchase the facility, after three years 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. All of these units were operational at the end of July 2002.

NOTE 5 - Revolving Credit Facility

The Company entered into new revolving credit agreements that became effective June 4, 2002; 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 Company's 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 December 31, 2002, these facilities were fully available and there were no borrowings outstanding.

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 its direct parent PHI, in such amounts and at such times as would be determined by the Company, subject to regulatory approval, which has been received. Issuance and sale of the Shares is subject to the receipt of cash for the Shares in an amount per share not less than the book value of the Shares at the end of the month prior to the date of the issuance. On December 19, 2002, the Company issued 14,851,485 Shares to PHI, receiving $150.0 million in cash proceeds, equal to $10.10 per share, the book value of the Shares at the end of November 2002. Proceeds will be used to repay debt and for general corporate purposes.

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 from certain contract counterparties in California. In addition, in December 2001 Enron declared bankruptcy and defaulted on certain wholesale contracts. The Company has 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.

The Company is also 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.

Guarantees - On May 4, 2000, the Company and other joint owners completed the sale to Transalta of a power plant and coal mine located in Centralia, Washington. Under the agreement relating to the plant, the joint owners agreed to indemnify Transalta if it were to incur certain losses after the closing date and arising as a result of certain breaches of covenants. Under the agreement relating to the mine, the Company provided similar indemnity. The maximum indemnification obligation under these agreements, with respect to the Company, is limited to $556.0 million, less a deductible of approximately $1.0 million. No indemnity claims have been made to date.

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In connection with the sale of the Company's Montana service territory, the Company entered into a purchase and sale agreement with Flathead Electric Cooperative ("Flathead") dated October 9, 1998. Under the agreement, the Company indemnified Flathead for losses, if any, occurring after the closing date and arising as a result of certain breaches of warranty or covenants. The indemnification has a cap of $10.0 million. One indemnity claim relating to environmental issues has been tendered, but remediation costs, if any, are not expected to be material.

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 December 31, 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 nameplate 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 uncertainties. The Company expects that future costs relating to these matters may be significant and consist primarily of additional relicensing costs and capital expenditures. Power generation reductions may result from the additional environmental requirements. Since the commencement of the current multi-year relicensing process, the Company has incurred approximately $90.0 million in costs for hydroelectric relicensing that are reflected as an asset on the Balance Sheet. The Company expects that these and future 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. At this time, it is anticipated that Cowlitz will repair Swift No. 2 in time for a calendar year 2006 startup. This failure has impacted the Company's owned and operated 240 MW Swift No. 1 hydroelectric facility ("Swift No. 1"), 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 resumed. 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 consolidated financial position or results of operations.

NOTE 8 - Income Taxes

The Company accrued income tax expense of $65.9 million and $125.6 million, representing effective tax rates of 37.7% and 41.0%, for the nine months ended December 31, 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:

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(a)  The Employee Stock Ownership Plan ("ESOP") dividend pass through represents deductions allowed for dividend payments made on qualifying employer securities held in an ESOP.

(b)  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.

(c)  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 was $10.3 million and has been paid.

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 a liability of $40.9 million. The Company has filed an administrative appeal for the unagreed issues and believes that final settlement and payment will not have a material adverse impact upon its consolidated financial position or results of operations.

The IRS started its 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 Opinion No. 17, Intangible Assets. 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 consolidated 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. 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 consolidated financial position and results of operations.

In November 2002, the FASB issued FASB Interpretation No. 45, Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Other, relating to the guarantor's accounting for, and disclosure of, the issuance of certain types of guarantees. The disclosure requirements are effective for interim periods ending after December 15, 2002 and the provisions for initial recognition and measurement are effective on a prospective basis for guarantees that are issued or modified after December 31, 2002. The Company's guarantees are disclosed in NOTE 7 - Commitments and Contingencies.

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In December 2002, the FASB issued SFAS No. 148, Accounting for Stock-Based Compensation-Transition and Disclosure, ("SFAS No. 148"), which amends SFAS No. 123, Accounting for Stock-Based Compensation, ("SFAS No. 123"). SFAS No. 148 provides alternative methods of transition for a voluntary change to the fair value based method of accounting for stock-based employee compensation. In addition, SFAS No. 148 amends the disclosure requirements of SFAS No. 123 to require more prominent and more frequent disclosures in financial statements regarding the effects of stock-based compensation. The Company will adopt the disclosure requirements of this statement on March 31, 2003. The adoption of this statement will require the Company to make additional quarterly and annual disclosures, but will have no impact on the Company's consolidated 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 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 the Australian Electric Operations sale agreement, Holdings, while a subsidiary of the Company, received further proceeds from the sale in the amount of $27.4 million.

(b)  Amounts for the nine months ended December 31, 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.

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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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To the Board of Directors and Shareholders of PacifiCorp:

We have reviewed the accompanying condensed consolidated balance sheet of PacifiCorp and its subsidiaries as of December 31, 2002, and the related condensed consolidated statements of income and retained earnings for each of the three-month and nine-month periods ended December 31, 2002 and 2001 and the condensed consolidated statements of cash flows for the nine-month periods ended December 31, 2002 and 2001. These interim 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 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

January 31, 2003

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OVERVIEW

On December 31, 2001, NA General Partnership transferred all of the common stock of PacifiCorp (the "Company") to PacifiCorp Holdings, Inc. ("PHI"). PacifiCorp 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 and its subsidiaries are included as Other Operations in the Company's Condensed Consolidated Statement of Income and Retained Earnings and Condensed Consolidated Statement of Cash Flows for the three and nine months ended December 31, 2001, but are not included for the three and nine months ended December 31, 2002.

CRITICAL ACCOUNTING POLICIES

The preparation of consolidated financial statements in conformity with accounting principles generally accepted in the United States of America ("U.S.") 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 and prices;
  .  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;
  .  war or 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.

The western U.S. wholesale energy market was relatively stable during the nine months ended December 31, 2002 as compared to the nine months ended December 31, 2001. The Company took several actions to maintain a balanced net energy position through the summer peak period and for the remainder of this fiscal year. The Company added a 120 megawatt ("MW") gas-fired peaking plant in Utah, which came on line in August 2002, and also entered into an operating lease arrangement for a 200 MW peaking plant in Utah with West Valley Leasing Company, LLC, a subsidiary of PPM Energy, Inc. ("PPM"), formerly known as PacifiCorp Power Marketing, a subsidiary of PHI. These actions, as well as the utilization of other flexible physical and financial hedging instruments, assisted the Company in maintaining a balanced energy position during the nine months ended December 31, 2002.

The Company's hydroelectric generation has decreased in the current period due to drier than historic average conditions in the Northwest region. The decrease in river flows has been primarily a result of the adverse conditions created by an El Nino weather pattern, which has caused precipitation levels to be below normal. The reduction in hydroelectric generation has forced the Company to rely on other generation and market purchases, which have caused net power cost increases. These power cost increases have been partially mitigated through existing hedging and normal balancing activities. If this current weather pattern continues, the Company's future costs will continue to be impacted; however, much of the impact is anticipated to be offset by existing hedges and balancing activities.

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. In addition, there are regulatory and legal proceedings regarding deferred net power costs in Oregon, Wyoming and Washington. 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 intervening parties. In August 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. On December 10, 2002, the OPUC approved the voluntary stipulation and ordered the Company to file a tariff to implement the change. The tariff was approved by the OPUC with an effective date of January 22, 2003. Amounts subject to refund would only include those collections occurring after January 22, 2003. In Wyoming, the Company has requested recovery of $60.3 million in deferred net power costs and $30.7 million for replacement power costs resulting from the outage of the Company's Hunter No. 1 generating plant, to be recovered through two surcharges over three years. The Company currently expects an order on this request before March 31, 2003. In Washington, the Company has requested recovery of $17.5 million of excess power costs, including carrying charges, to be recovered through regulatory liability offsets from the gain on the sale of a Centralia, Washington power plant and coal mine, Merger Credits (as discussed in ITEM 5. OTHER INFORMATION - Merger Credits) and/or surcharges. A final decision is expected in May 2003.

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(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 in the three months ended December 31, 2001; and (iii) is net of minority interest (which is reported as a component of Minority interest and other) and preferred dividend requirements.

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

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Residential revenues for the three months ended December 31, 2002 decreased $0.3 million, or 0.1%, from the three months ended December 31, 2001 due to decreases of $0.6 million from lower prices and $3.1 million from lower average customer usage due to milder weather conditions, primarily in Oregon and Utah, offset in part by an increase in those states of $3.4 million due to growth in the average number of residential customers.

Commercial revenues for the three months ended December 31, 2002 increased $7.1 million, or 3.8%, from the three months ended December 31, 2001 due to increases of $5.4 million from higher average customer usage and $4.3 million from growth in the average number of commercial customers. These increases were partially offset by a $2.6 million decrease due to lower prices.

Industrial revenues for the three months ended December 31, 2002 decreased $1.6 million, or 1.0%, from the three months ended December 31, 2001 due to decreases of $10.4 million caused by reduced average customer usage, offset by an $8.8 million increase from higher prices.

Wholesale sales for the three months ended December 31, 2002 decreased $21.8 million, or 9.2%, from the three months ended December 31, 2001. The decrease in revenues in the three months ended December 31, 2002 resulted primarily from a decline in prices received for short-term and spot market sales as compared to those in the three months ended December 31, 2001, the impact of which was $17.7 million. Although market prices in the three months ended December 31, 2002 increased as compared to the three months ended December 31, 2001 due in part to increases in natural gas prices, average prices received by the Company in the three months ended December 31, 2001 included benefits from contracts entered into earlier when prices were substantially higher. Wholesale sales volumes increased 2.4% partially offsetting retail sales weakness as the Company sold excess power in the short-term daily and hourly markets to balance loads and resources.

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Other revenues for the three months ended December 31, 2002 decreased $9.1 million, or 20.3%, from the three months ended December 31, 2001 due primarily to a $7.5 million decrease in carrying charges on deferred power costs and a $3.2 million decrease in demand side management revenues, offset in part by a $1.1 million increase in sales under a contract for renewable energy.

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

Purchased power expense for the three months ended December 31, 2002 decreased $91.3 million, or 26.0%, from the three months ended December 31, 2001. Of the decrease in purchased power costs in the three months ended December 31, 2002, $53.3 million resulted from lower prices paid for long-term, short-term and spot market purchases than prices in the three months ended December 31, 2001. Although market prices in the three months ended December 31, 2002 increased as compared to market prices in the three months ended December 31, 2001 due in part to increases in natural gas prices, average costs incurred by the Company in the three months ended December 31, 2001 included costs from contracts entered into earlier when prices were substantially higher. Wholesale purchase volumes increased 11.0% as the Company replaced thermal generation lost from outages and offset lower hydroelectric generation caused by below normal precipitation. In addition, purchased power costs decreased $41.5 million in the three months ended December 31, 2002 as compared to the three months ended December 31, 2001 due to changes in deferred power cost balances.

Fuel expense for the three months ended December 31, 2002 decreased $2.0 million, or 1.6%, from the three months ended December 31, 2001, primarily due to a $6.7 million decrease as a result of lower volumes of coal consumed and an $9.0 million decrease as a result of lower natural gas prices in the Rocky Mountain market where the Company purchases most of its natural gas. In the Rocky Mountain market, natural gas prices were generally lower than prices in the rest of the U.S. These decreases were partially offset by a $9.0 million increase due to higher volumes of gas consumption and a $4.8 million increase as a result of higher coal prices. Natural gas consumption increased due to the West Valley and gas-fired peaking units being placed in service in the summer of 2002. Coal consumption decreased due to reduced thermal generation resulting from outages, increased purchases of short-term power and reduced retail loads.

Other operations and maintenance expense for the three months ended December 31, 2002 increased $4.7 million, or 3.2%, from the three months ended December 31, 2001 primarily due to a $7.3 million increase in contract services, mainly relating to the timing of overhauls, a $4.7 million increase in employee related costs and a $3.7 million increase in rent expense in the three months ended December 31, 2002 for the West Valley operating lease as described in

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Note 4 of Notes to the Financial Statements under ITEM 1. FINANCIAL STATEMENTS. These increases were partially offset by a $3.7 million decrease resulting from the temporary lease of a generating turbine in the three months ended December 31, 2001, a decrease of $4.5 million in demand side management costs and $3.5 million in lower bad debt reserves in the three months ended December 31, 2002.

Depreciation and amortization expense for the three months ended December 31, 2002 increased $7.9 million, or 7.8%, from the three months ended December 31, 2001 primarily due to increased expenditures on Property, plant and equipment resulting in a $2.5 million increase in depreciation expense, increased amortization of regulatory assets and liabilities of $1.1 million and a $3.6 million increase in the current period due to the termination at March 31, 2002 of a two-year depreciation expense reduction ordered by state regulatory commissions.

Administrative and general expenses for the three months ended December 31, 2002 increased $5.9 million, or 9.0%, from the three months ended December 31, 2001 primarily due to a $6.8 million increase in property and liability insurance costs resulting from higher premiums, partially offset by a $0.6 million decrease relating to higher capitalized costs in the three months ended December 31, 2002, due to an overall increase in capital projects.

Taxes, other than income taxes, for the three months ended December 31, 2002 decreased $2.2 million, or 9.4%, from the three months ended December 31, 2001, primarily due to a $1.9 million decrease in franchise taxes and lower property tax expense.

The Unrealized loss on SFAS No. 133 derivative instruments for the three months ended December 31, 2002 was $0.4 million compared to an unrealized gain of $24.0 million for the three months ended December 31, 2001, primarily due to unfavorable movements on long-term contracts and because, beginning July 1, 2001, most short-term contracts were designated as normal purchases and sales, exempting them from the mark-to-market requirements of SFAS No. 133.

OTHER OPERATING INCOME

Other operating income of $21.1 million for the three months ended December 31, 2001 pertained to a regulatory settlement that resulted in the establishment of a regulatory asset.

GAIN ON SALE OF OPERATING ASSETS

The $11.3 million Gain on sale of operating assets for the three months ended December 31, 2001, pertained to the sale of PFS's synthetic fuel operations in October 2001.

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(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 in the nine months ended December 31, 2001; and (iii) is net of minority interest (which is reported as a component of Minority interest and other) and preferred dividend requirements.

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

(c)  The amount for the nine months ended December 31, 2001 represents 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 SFAS No. 133 at April 1, 2001 and the implementation of the DIG revised Issue C15 and Issue C16 at April 1, 2002.

Residential revenues for the nine months ended December 31, 2002 increased $33.5 million, or 5.3%, from the nine months ended December 31, 2001 primarily due to increases of $20.5 million from higher rates approved by state regulatory agencies, $4.3 million from higher average customer usage and $8.7 million relating to growth in the average number of residential customers, primarily in Utah.

Commercial revenues for the nine months ended December 31, 2002 increased $18.4 million, or 3.3%, from the nine months ended December 31, 2001 primarily due to increases of $12.9 million from growth in the average number of commercial customers and $6.2 million from higher rates, offset in part by $0.7 million in reduced revenue from lower average customer usage.

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Industrial revenues for the nine months ended December 31, 2002 decreased $19.6 million, or 3.6%, from the nine months ended December 31, 2001 due to a $38.0 million decrease caused by reduced average customer usage mainly as a result of a weaker economy, partially offset by an $18.4 million increase resulting from higher rates.

Wholesale sales for the nine months ended December 31, 2002 decreased $712.6 million, or 48.1%, from the nine months ended December 31, 2001. The decrease in revenues in the nine months ended December 31, 2002 resulted from the sharp decline in market prices for short-term and spot market sales as compared to those in the nine months ended December 31, 2001, the impact of which was $2.0 billion. Factors contributing to the lower market prices included new generation online in the western U.S., the continuing effect of the Federal Energy Regulatory Commission ("FERC") market mitigation (as discussed in ITEM 5. OTHER INFORMATION - WESTERN POWER MARKET ISSUES), lower natural gas prices and weaker regional retail demand due to weather and recessionary impacts. Wholesale sales volumes increased $1.3 billion, or 34.7%, offsetting retail sales weakness as the Company sold excess power in the short-term daily and hourly markets.

Other revenues for the nine months ended December 31, 2002 decreased $25.9 million, or 18.3%, from the nine months ended December 31, 2001 primarily due to a $23.5 million decrease in wheeling revenues, caused by decreased usage of the Company's transmission system by third parties, a $10.2 million decrease in demand side management revenues, a $3.4 million decrease in revenues due to the termination of Oregon's Alternative Form of Regulation and a $12.5 million decrease in carrying charges on deferred power costs. These decreases were partially offset by a $20.7 million release of reserves on a power sales contract following a settlement of a dispute with respect to the contract and a $3.4 million increase in sales under a contract for renewable power.

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

Purchased power expense for the nine months ended December 31, 2002 decreased $919.5 million, or 49.6%, from the nine months ended December 31, 2001. Of the decrease in purchased power costs in the nine months ended December 31, 2002, $2.0 billion resulted from significantly lower market prices for short-term and spot market purchases than prices in the nine months ended December 31, 2001. Lower market prices resulted from the same factors mentioned above for lower wholesale sales. Wholesale purchase volumes increased $1.0 billion, or 37.3%, as the Company took advantage of lower prices to balance its load requirements, replaced thermal generation lost from outages and offset lower hydroelectric generation caused by below normal precipitation levels. Purchased power costs also increased $114.8 million in the nine months ended December 31, 2002 compared to the nine months ended December 31, 2001 due to lower deferrals of purchased power costs.

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(a)  Minority interest and other includes payments of $21.3 million on Preferred Securities of wholly owned subsidiary trusts for each of the nine-month periods ended December 31.

Interest expense increased $44.1 million, or 26.9%, primarily due to higher average long-term debt balances and $19.0 million of interest on regulatory liabilities. These increases were 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 $13.8 million, or 68.3%, as a result of lower average notes receivable balances due to the transfer of Holdings to PHI in February 2002, partially offset by the recognition of $1.1 million of interest income on a power sales contract settlement in September 2002. The results of Holdings are no longer included in the Company's financial statements.

Interest capitalized increased $8.6 million, or 168.6%, due to higher construction work-in-progress balances and higher capitalization rates in the nine months ended December 31, 2002.

Minority interest and other increased $23.2 million, or 351.5%. Minority interest was constant year over year. Of the increase, $18.9 million pertained to Other income and expense of Holdings in the nine months ended December 31, 2001. During the nine months ended December 31, 2001, Holdings recorded $9.3 million in gains on sales of leased aircraft owned by PFS, $4.8 million in gains on various settlements and $3.7 million in gains on sales of non-utility investments. Other expense for Domestic Electric Operations increased in part due to the reversal in the nine months ended December 31, 2002 of a previously recorded gain of $3.4 million as a result of a regulatory order.

INCOME TAX EXPENSE

Income tax expense for the nine months ended December 31, 2002 decreased $59.7 million from the nine months ended December 31, 2001. The effective tax rate for the nine months ended December 31, 2002 was 37.7% compared to a 41.0% effective tax rate for the nine months ended December 31, 2001. The declines in the tax expense and the effective tax rate were primarily due to the lower taxable income in the nine months ended December 31, 2002 and the additional tax reserves established in the nine months ended December 31, 2001 for the amounts proposed as a result of the IRS audit. See Note 8 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 nine months ended December 31, 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.

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CUMULATIVE EFFECT OF ACCOUNTING CHANGE

The Company recorded a $1.9 million loss from the implementation of revised Issue C15 and Issue C16 during the nine months ended December 31, 2002 and recorded a $112.8 million loss from the implementation of SFAS No. 133 during the nine months ended December 31, 2001.

OPERATING ACTIVITIES

Net cash flows provided by operating activities were $311.9 million for the nine months ended December 31, 2002 as compared to a usage of $19.7 million for the nine months ended December 31, 2001. The increase in operating cash flow was primarily due to an increase in the Company's cash earnings during the nine months ended December 31, 2002 as compared to the nine months ended December 31, 2001, as well as the recoveries of deferred net power costs.

INVESTING ACTIVITIES

Capital spending totaled $391.1 million for the nine months ended December 31, 2002 compared to $336.5 million for the nine months ended December 31, 2001. Current period 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 nine months ended December 31, 2002 represented sales of utility properties. The nine months ended December 31, 2001 included proceeds from the sale of PFS's synthetic fuel operations; additional proceeds, received by Holdings, relating to the disposal of Australian Electric Operations; and sales of utility properties. Proceeds from a finance note repayment in the nine months ended December 31, 2001 represented the payment of a note receivable held by Holdings relating to the discontinued operations of NERCO. Certain types of investing activities for the nine months ended December 31, 2001 do not appear in the nine months ended December 31, 2002 due to the transfer of Holdings and its subsidiaries from PacifiCorp to PHI.

The Company plans to increase the level of its capital investment by an additional $102.0 million, over the three-year period ending 2005, along the Wasatch Front in Utah to expand the distribution network. That area of Utah has experienced rapid load growth, including increased peak demand during periods of prolonged hot weather. The capital investments are intended to provide the Wasatch Front region with a more stable power supply and capacity for future natural growth, heat demand and emergency situations.

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; 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 the Company's prior credit agreements. As of December 31, 2002, these facilities were fully available and there were no borrowings outstanding. 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 $40.0 million in money market accounts included in Cash and cash equivalents at December 31, 2002 available to meet its liquidity needs.

For the nine months ended December 31, 2002, the Company redeemed $7.5 million of preferred stock as compared to $100.0 million for the nine months ended December 31, 2001.

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For the nine months ended December 31, 2002, no dividends were declared on common stock. The Company declared dividends of $1.9 million, $1.8 million and $1.8 million on preferred stock on May 24, 2002, August 22, 2002 and November 20, 2002, respectively. Dividends payable on preferred stock at December 31, 2002, which are payable on February 15, 2003, totaled $1.8 million. On December 19, 2002, the Company issued 14,851,485 shares of its common stock ("Shares") to PHI at a total price of $150.0 million, or $10.10 per share.

The Company's pension costs are dependent upon several factors and assumptions, such as the discount rate, the long-tem rate of return on plan assets and the level of Company contributions. The Company's pension plan assets have been affected by the significant declines in the equity markets over the past three years. These conditions are expected to impact the funded status of the Company Retirement Plan (the "Plan") at year-end and the pension costs for fiscal year 2004.

The Plan currently has assets with a fair value that is less than the accumulated benefit obligation under the Plan primarily due to declines in the equity markets. As a result, the Company will be required to recognize a minimum pension liability in the fourth quarter of fiscal year 2003. The liability adjustment will be recorded as a non-cash charge to Other Comprehensive Income ("OCI"), and will not affect the consolidated results of operations. The charge to OCI will be reversed if, in future periods, the fair value of the trust assets exceeds the accumulated benefit obligation. The Company estimates that the charge to OCI for the year ended March 31, 2003 will be approximately $150.0 million net of tax. The Company anticipates requesting accounting orders from the regulatory commissions to classify this charge as a regulatory asset instead of a charge to OCI.

The Company's contributions to the Plan have exceeded the minimum funding requirements of the Employee Retirement Income Security Act ("ERISA"). The Company's funding policy is to contribute amounts that are not less than the minimum amounts required to be funded under ERISA. The Company has made $26.4 million in cash contributions to the Plan during the nine months ended December 31, 2002 and made $4.2 million in cash contributions to the Plan during the nine months ended December 31, 2001. The amount of the Company's funding obligation for fiscal year 2004 is expected to be approximately $33.4 million. The Company is funding the Plan at what it believes to be an adequate level. As a result of significant declines in the equity markets, the Company expects to make larger cash contributions in the near future. Such cash requirements could be material to the Company's cash flows. The Company believes it has adequate access to capital resources to support these contributions.

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. However, many participants in the electric utility industry have experienced a period of negative news and ratings downgrades. While the Company to date has been able to adequately fund itself and expects to be able to continue to do so, further negative events by other industry participants may make it more difficult and expensive for the Company to obtain necessary financing or replace financing agreements at their maturity.

CREDIT RATINGS

The Company's credit ratings at December 31, 2002 were as follows:

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For a further 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.

CAPITALIZATION

At December 31, 2002, The Company had $167.8 million of commercial paper and other short-term borrowings outstanding at a weighted average rate of 1.7%. These borrowings and other financing arrangements are supported by committed revolving credit agreements and cash on hand as described above.

On December 19, 2002, the Company issued 14,851,485 Shares to PHI, receiving $150.0 million in cash proceeds, equal to $10.10 per share, the book value of the Shares at the end of November 2002. Proceeds will be used to repay debt and for general corporate purposes.

CONTRACTUAL OBLIGATIONS AND COMMERCIAL COMMITMENTS

The tables below show the Company's contractual obligations and commercial commitments as of December 31, 2002 for each of the 12-month periods ended December 31.

(a)  There have been no significant increases to the long-term obligations during the nine months ended December 31, 2002. The long-term debt matures at various dates through fiscal 2032, and bears interest principally at fixed rates of interest. The Company uses the proceeds from debt financing for general corporate purposes, including construction, improvement or maintenance of its utility system and the repayment of commercial paper and short-term debt. Generally, the costs of these financings are included in the rates that the state regulatory commissions authorize.

(b)  Wholly owned subsidiary trusts of the Company (the "Trusts") have issued, in public offerings, redeemable preferred securities ("Preferred Securities") representing preferred undivided beneficial interests in the assets of the Trusts, with liquidation amounts of $25.00 per Preferred Security. The sole assets of the Trusts are Junior Subordinated Deferrable Interest Debentures ("Junior Debentures") of the Company that bear interest at the same

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rates as the Preferred Securities to which they relate, and certain rights under related guarantees by the Company. These Junior Debentures are unsecured and junior in terms of preference to all senior debt including unsecured senior obligations. Under certain conditions, the Company may defer interest on the Junior Debentures. Generally, the costs of these financings are included in the rates that the state regulatory commissions authorize.

(c)  The Company's power contract commitments include purchases of coal, natural gas and electricity. The Company manages its energy resource requirements by integrating long-term, short-term and spot market purchases with its own generating resources to dispatch the system economically and meet commitments for wholesale sales and retail load growth. As part of its energy resource portfolio, the Company acquires a portion of its resource requirements through long-term purchases and/or exchange agreements.

(d)  The Company entered into new revolving credit agreements that became effective June 4, 2002; 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. Provisions in the agreements are similar to the Company's 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 December 31, 2002, these facilities were fully available and there were no borrowings outstanding.

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 FERC proceedings as mentioned under ITEM 5. OTHER INFORMATION - WESTERN POWER MARKET ISSUES below.

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 for purposes of servicing its regulated customers. This decline is due to an overall negative credit 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 less of their efforts on merchant energy trading, pursuing lower risk/slower growth opportunities, strengthening their balance sheets in order to maintain or achieve an investment grade rating, or are looking to sell their energy trading divisions, or exiting the marketplace entirely.

The Company continues to experience risk relating to increases in various insurance costs and premiums, as well as available insurance coverage for certain property and liability exposures. The Company's healthcare costs continue to rise faster than inflation, but not greater than the general industry trend.

As a result of recent negative investment market conditions and the resultant returns that the pension trust has been experiencing on its pension plan assets, the Company is exposed to increased pension expenses and cash contributions. The Company will seek recovery of these increased costs through the ratemaking process. For additional information see ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS - LIQUIDITY AND CAPITAL RESOURCES - FINANCING ACTIVITIES.

FAIR VALUE OF DERIVATIVES

SFAS No. 133 requires all derivatives, as defined by the standard, to be marked to market, 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 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.

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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 December 31, 2002 and quantifies the reasons for the changes.

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ITEM 4.  CONTROLS AND PROCEDURES

(a)  The principal executive officer and principal financial officer of the Company have evaluated the effectiveness of the Company's disclosure controls and procedures pursuant to Rule 13a-14 under the Securities Exchange Act of 1934 as of a date within 90 days prior to the filing date of this report. Based on that evaluation, such officers have concluded that the Company's disclosure controls and procedures are effective to ensure that material information relating to the Company and its subsidiaries is made known to such officers in a timely manner for inclusion in the Company's periodic filings with the Securities and Exchange Commission.

(b)  There were no significant changes in the Company's internal controls or in other factors that could significantly affect these controls subsequent to the date of their most recent evaluation by the Company's principal executive officer and principal financial officer.

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ITEM 2.  CHANGES IN SECURITIES AND USE OF PROCEEDS

On December 19, 2002, the Company issued 14,851,485 Shares to PHI for $150.0 million in cash. The sale was a private placement to the Company's immediate corporate parent pursuant to Section 4(2) of the Securities Act of 1933. No underwriters were involved in the transaction, and no underwriting discounts or other commissions were paid. Proceeds will be used to repay debt and for general corporate purposes.

ITEM 5.  OTHER INFORMATION

WESTERN POWER MARKET ISSUES

On April 26, 2001, the FERC imposed a price mitigation plan limiting prices on spot market sales in California 24 hours a day, seven days a week. On June 19, 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 July 17, 2002, the FERC issued an order that became effective November 1, 2002, setting the price cap at $250.00 per megawatt-hour ("MWh") from the previous $91.87 per MWh. However, the order also created an automatic mitigation procedure designed to limit the ability of generators to cause prices to rise above the price cap level of $91.87 per MWh.

The FERC's June 19, 2001 order also required that all public utility sellers and buyers ("Party" or "Parties") in the California Independent System Operator ("Cal ISO") 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 12, 2001, the ALJ issued a recommendation to the FERC based upon the settlement conference, proposing a methodology to calculate refunds for spot sales to the Cal ISO and California Power Exchange ("CPX") between October 2, 2000 and June 20, 2001. The FERC agreed with the ALJ-proposed methodology. A proceeding before a second ALJ was held beginning August 19, 2002 to determine each Party's refund liability. On November 20, 2002, the FERC allowed all Parties to engage in 100 days of additional discovery into market manipulation. On December 12, 2002, the ALJ issued a Certification of Proposed Findings on California Refund Liability in which the ALJ preliminarily determined that $1.2 billion was still owed to suppliers by Cal ISO and CPX, which was calculated by offsetting a $1.8 billion refund from the $3.0 billion owed to suppliers. 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. In a decision issued on September 24, 2001, the ALJ recommended that the FERC should not require refunds for these sales. On December 19, 2002, the evidentiary record was reopened in this case for the purpose of allowing parties to submit additional evidence concerning potential refunds for spot market bilateral sales transactions in the Pacific Northwest for the period January 1, 2000 through June 20, 2001 and to submit proposed new and/or modified findings of fact by February 28, 2003. The Company's obligation to make refunds, if any, will be dependent upon any final order issued by the FERC in response to the outcome of these proceedings and cannot be determined at this time.

On May 2, 2002, the Company 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 complaints were signed during a period of extreme wholesale market volatility and before the FERC imposed its West-wide spot market price mitigation (price caps). The Company is seeking reformation of the contract prices to levels that constitute just and reasonable rates. Hearings on this proceeding were concluded on January 3, 2003. An initial decision from the ALJ is expected in mid-March 2003.

In May 2002, 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 data requests issued in May 2002.

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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.

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. On a jurisdictional basis, the new depreciation study proposes to decrease annual depreciation expense in Oregon and California by $4.4 million and $2.0 million, respectively and increase 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 increases in estimated costs of removal for steam generating plants and decreases in estimated 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. On January 17, 2003, the Company and the Wyoming Consumer Advocate Staff reached an agreement that would allow the Company to recover 85% of these costs. This agreement is subject to approval as part of the general rate case, which is scheduled to be decided before March 31, 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 December 31, 2002 was $30.2 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 between the Company and Scottish Power plc (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

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UPSC allowed the Company to offset $20.6 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 December 31, 2002, the Company had provided $61.0 million in Merger Credits and interest to its customers through reduced rates. The Company is still obligated to provide $34.1 million of Merger Credits to customers in Oregon and Washington, with the possibility of offsetting $21.0 million of that amount with Merger savings in future years and/or deferred power 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. This increase included an $18.7 million one-year surcharge related to higher market costs for summer purchases and also resolved a number of other outstanding issues. The Industrial Customers of Northwest Utilities (the "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. On November 20, 2002, the OPUC issued an order that established an Issues List. ICNU filed its direct testimony on January 6, 2003. The Company and the OPUC staff are scheduled to file their testimonies on February 5, 2003, with ICNU's rebuttal testimony due on March 5, 2003. The hearings are scheduled to begin on March 20, 2003.

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. Pass throughs of BPA credits do 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 have increased approximately 9.8%. On December 18, 2002, the Company revised the requested increase to $21.4 million. On January 17, 2003, the Company and the WPSC staff reached agreement on certain issues, which resulted in the Company revising its requested increase to $20.0 million which would increase rates by approximately 6.4% if approved by the WPSC. The Company's filing also included a request to recover the replacement power costs resulting from the outage of the Company's Hunter No. 1 generating plant and a proposal for recovering deferred net power costs as discussed under Deferred Net Power Cost Filings - Wyoming. Hearings in this case were held during January 2003 and the Company currently expects an order on this request by March 31, 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. Subsequently, on December 21, 2001, the Company filed a general rate case ("GRC") to increase rates to compensatory levels. 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 June 27, 2002, the CPUC approved an interim increase of $0.01 per kilowatt-hour ("kWh") for certain customers, or approximately

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$4.7 million annually, or 8.8%, overall. This rate increase is subject to refund pending the outcome of the GRC. 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 at that time. 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 December 31, 2002, the Company had deferred power costs, net of amortization, of $191.9 million, including carrying charges.

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 under an interim relief order 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 and coal mine. These offsets reduced the regulatory asset for deferred net power costs. In addition, the UPSC allowed the elimination of $20.6 million for the final two years of Merger Credits associated with the Merger of Scottish Power plc and the Company. 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. One party opposed the rate spread provisions of the stipulation and filed a petition with the Utah Supreme Court for review of the order. The case has been assigned to the Utah Court of Appeals.

Oregon - The 2000 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 then in force. 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.

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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 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 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. (See a discussion of this appeal below.) 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 ICNU appealed this decision to the Marion County, Oregon Circuit Court. On October 11, 2002, the Company moved to intervene in this action. On December 5, 2002, CUB and ICNU filed their opening brief. The Company and the OPUC filed their respective briefs on January 13, 2003.

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. As of December 31, 2002, the Company had received $7.3 million in revenues as a result of this OPUC action. 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%, challenging the approval itself based on procedural technicalities during the approval proceeding. 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 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 or otherwise disallowing recovery. 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. On December 10, 2002, the OPUC approved the voluntary stipulation and ordered the Company to file a tariff to implement the change. The tariff was approved by the OPUC with an effective date of January 22, 2003. Amounts subject to refund would only include those collections occurring after January 22, 2003.

While the 6.0% increase established 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, mentioned above, 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 November 27, 2002, the Company filed its opening brief.

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. On April 3, 2001, the Company filed an application to recover the excess power costs accrued during the period of November 30, 2000 through January 31, 2001. 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 this request. On May 7, 2002, the Company filed a request to recover the replacement of excess power costs resulting from the outage of the Company's Hunter No. 1 generating plant for $30.7 million and a proposal for recovering deferred net power costs authorized by the WPSC in December 2000 for $60.3 million. The Company currently expects an order on this request by March 31, 2003.

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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 deferral and recovery of $17.5 million of excess power costs, including carrying charges. Hearings are scheduled for March 2003, and a decision is expected in May 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 are 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.

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. The FERC is expected to release a white paper on the SMD in April 2003. The release of the final rule is expected later in calendar year 2003.

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 West. The focus is on completing the RTO West design details, thereby influencing the final SMD western market design framework. The Company, together with other RTO West principals, filed comments in November 2002 detailing where the NOPR design potentially could be disadvantageous to western markets and requested that the FERC continue to support the ongoing RTO West development in areas where the designs differ. The Company, together with other western parties, is continuing to work with the FERC to influence final language in the SMD and assess any impacts on the Company and western region.

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 some of the cost of the Company's existing investments and the recovery of the cost of future investments. The initial phase of the process began in April and continued through December of 2002. Key parties from Utah, Oregon, Wyoming, Washington and Idaho participated in all meetings. California has a key contact monitoring the process. During this phase, parties analyzed over 50 options and have narrowed the field to two options. Both options seek 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. In the second phase, the parties will work to develop and analyze the details of the remaining two proposals with the goal of agreement to a single proposal in Spring/Summer of 2003.

The MSP was initiated at the request of states in response to the Company's Structural Realignment Proposal ("SRP"). 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

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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's Integrated Resource Plan ("IRP") provides a framework and plan for the prudent future actions required to ensure that the Company continues to provide reliable and cost-effective electric service to its customers. Through the IRP process, a solution was selected from a mix of renewable, fossil fuel, market purchase and demand side management choices that balance expected costs and risks. Any new generation or other assets called for by the IRP are expected to be included in the Company's future rate base. The IRP was filed with the state commissions on January 24, 2003.

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. The validation action is ongoing, but based on the foregoing factors, consummation of the sale is uncertain.

DEREGULATION

Oregon
Industrial and large commercial customers may choose an alternative energy plan to cost-based tariffs each calendar year. For calendar year 2003, 26 customers, representing less than 3 average MW of load, elected an alternative plan.

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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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I, Judith A. Johansen, principal executive officer of PacifiCorp, certify that:

/s/ Judith A. Johansen
Judith A. Johansen
President and Chief Executive Officer, PacifiCorp
February 4, 2003

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I, Richard D. Peach, principal financial officer of PacifiCorp, certify that:

/s/ Richard D. Peach
Richard D. Peach
Chief Financial Officer, PacifiCorp
February 4, 2003

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