NOTE 1 - Financial Statements

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

The accompanying unaudited condensed consolidated financial statements as of September 30, 2002 and for the periods ended September 30, 2002 and 2001, in the opinion of management, reflect all adjustments, which include only normal recurring adjustments, necessary for a fair presentation of financial position, results of operations and cash flows for such periods. The March 31, 2002 condensed consolidated balance sheet data was derived from audited financial statements. Such statements are presented in accordance with the Securities and Exchange Commission's ("SEC") interim reporting requirements, which do not include all the disclosures required by accounting principles generally accepted in the United States of America. Certain information and footnote disclosures made in the last Annual Report on Form 10-K have been condensed or omitted from the interim statements. A portion of the business of the Company is of a seasonal nature and, therefore, results of operations for the periods ended September 30, 2002 and 2001 are not necessarily indicative of the expected results for any other interim period or the year ending March 31, 2003. These condensed consolidated financial statements should be read in conjunction with the financial statements and related notes in the Company's 2002 Annual Report on Form 10-K.

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

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

NOTE 2 - Accounting for the Effects of Regulation

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

SFAS No. 71 provides that regulatory assets may be capitalized if it is probable that future revenue in an amount at least equal to the capitalized costs will result from the inclusion of that cost in allowable costs for ratemaking purposes. In addition, the rate action should permit recovery of the specific previously incurred and capitalized costs rather than to provide for expected levels of similar future costs. The Company records regulatory assets and liabilities based on management's assessment that it is probable that a cost will be recovered (asset) or that an obligation has been incurred (liability). The final outcome, or additional regulatory actions, could change

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management's assessment in future periods. A regulator can provide current rates intended to recover costs that are expected to be incurred in the future, with the understanding that if those costs are not incurred, future rates will be reduced by corresponding amounts. If current rates are intended to recover such costs, the Company shall recognize amounts charged, pursuant to such rates, as liabilities and take those amounts to income only when the associated costs are incurred. In applying SFAS No. 71, the Company must give consideration to changes in the level of demand or competition during the cost recovery period. In accordance with SFAS No. 71, Domestic Electric Operations capitalizes certain costs as regulatory assets in accordance with regulatory authority whereby those costs will be expensed and recovered in future periods.

The Emerging Issues Task Force ("EITF") of the Financial Accounting Standards Board ("FASB") concluded in 1997 that SFAS No. 71 should be discontinued when detailed legislation or regulatory orders regarding competition are issued. Additionally, the EITF concluded that regulatory assets and liabilities applicable to businesses being deregulated should be written-off unless their recovery is provided for through future regulated cash flows. The Company continuously evaluates the appropriateness of applying SFAS No. 71 to each of its jurisdictions. At September 30, 2002, management concluded that SFAS No. 71 was appropriate for the Domestic Electric Operations. However, if deregulation activities continue to progress, the Company may in the future be required to discontinue its application of SFAS No. 71 to all or a portion of its business.

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

In an effort to mitigate the temporary discrepancy between prices paid to purchase power and revenues received through regulated rates, the Company requested and received regulatory approval from the utility commissions in the states of Utah, Oregon, Wyoming and Idaho to capitalize for each state some of the net power costs that vary from costs included in determining retail rates. At September 30, 2002, the Company had a balance of $227.1 million of such capitalized costs supported by regulatory orders or stipulated agreements reached in Utah, Oregon and Idaho and an amount for deferred net power costs anticipated to be recoverable in Wyoming. The determination of the amount to be recovered in Wyoming is subject to receipt of a final commission order from the Wyoming Public Service Commission ("WPSC") in a rate case expected to be concluded by March 2003. Full recovery cannot be assured and differences between the amount allowed by the commission and the amounts capitalized at September 30, 2002 will be recognized as either a charge or credit to income upon receiving a final commission order. The balance of deferred net power costs at September 30, 2002 has been adjusted for regulatory liability offsets as allowed by the Utah and Idaho Commission orders. On July 18, 2002, the Oregon Public Utility Commission ("OPUC") issued an order approving a stipulation agreement allowing recovery of $136.5 million for certain deferred net power costs, including $5.5 million in carrying charges. This order is the subject of a court appeal by the intervening parties. On August 6, 2002, the OPUC allowed the Company to increase the amortization level for these deferred costs, from 3.0% to 6.0%. In October 2002, the Company entered into a voluntary stipulation with one of the intervening parties, supported by the OPUC staff, to allow collections from Oregon customers for these costs to be refunded if, as a result of the foregoing court appeal, an order or ruling is issued declaring all or any portion of these deferred costs imprudent. Amounts subject to refund would include only those collections occurring after the OPUC approves this stipulation, which management expects will occur before March 31, 2003.

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

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NOTE 3 - Derivative Instruments

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

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

In June 2002, the Company's SFAS No. 133 contract assessments were updated to reflect the revised Issue C15, Normal Purchase and Normal Sales Exception for Certain Option-Type Contracts and Forward Contracts in Electricity, ("Issue C15"), guidance from the DIG, effective April 1, 2002. The revision to Issue C-15 includes criteria to be considered for designation of a contract as a "capacity contract" and disallows the use of the exception for contracts that include a pricing element that is not clearly and closely related to the price of energy. The effects of adoption of the revised Issue C15 at April 1, 2002 resulted in a cumulative effect of accounting change adjustment of $2.1 million unfavorable (net of a tax benefit of $1.3 million) on the Company's Condensed Consolidated Statements of Income (Loss) and Retained Earnings. For contracts qualifying for deferred accounting under SFAS No. 71, the effect of adopting the revised C15 Issue was $0.7 million favorable.

In October 2001, the DIG issued guidance under Issue C16, Applying the Normal Purchases and Normal Sales Exception to Contracts that Combine a Forward Contract and a Purchased Option Contract, ("Issue C16"). The guidance disallows normal purchases and normal sales treatment for commodity contracts (other than power contracts) that contain volumetric variability or optionality. Issue C16 was effective April 1, 2002. The effects of adoption of Issue C16 at April 1, 2002 resulted in a cumulative effect of accounting change adjustment of $0.2 million favorable (net of tax of $0.2 million) on the Company's Condensed Consolidated Statements of Income (Loss) and Retained Earnings. For contracts qualifying for deferred accounting under SFAS No. 71, the effect of adopting Issue C16 was a fair value of $126.5 million unfavorable to the Company. The applicable contracts pertain to the purchase and transport of natural gas. The costs of these contracts have been allowed in rates and the liability is, therefore, offset by a corresponding amount included in regulatory assets.

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

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

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are also limited to those commodities representing the Company's principal business (electricity, natural gas and coal). The Company's hedging is done solely to help balance retail and wholesale load. Short-term commodity instruments are occasionally held by the Company for trading purposes. Transactions classified as energy trading activities are accounted for under EITF No. 98-10 and contributed $1.6 million for the six months ended September 30, 2002. All of these transactions were settled by September 30, 2002.

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

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

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

NOTE 4 - Related Party Transactions

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

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

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

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

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

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

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

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

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

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

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

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

NOTE 5 - Revolving Credit Facility

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

NOTE 6 - Common Stock

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

NOTE 7 - Commitments and Contingencies

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

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

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

WESTERN POWER MARKET ISSUES

of the Company's 2002 Annual Report on Form 10-K.

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

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Environmental issues - The Company is subject to numerous environmental laws including: the Federal Clean Air Act, as enforced by the Environmental Protection Agency ("EPA") and various state agencies; the 1990 Clean Air Act Amendments; the Endangered Species Act, particularly as it relates to certain potentially endangered species of fish; the Comprehensive Environmental Response, Compensation and Liability Act, relating to environmental cleanups; along with the Federal Resource Conservation and Recovery Act and the Clean Water Act relating to water quality. These laws could potentially impact future operations. Contingencies identified at September 30, 2002 principally consist of Clean Air Act matters, which are the subject of discussions with the EPA and state regulatory authorities. The Company expects that future costs relating to these matters may be significant and consist primarily of capital expenditures. The Company expects these costs will be included in rates, and as such, will not have a material adverse impact on the Company's consolidated results of operations.

Hydroelectric relicensing - The Company's hydroelectric portfolio consists of 53 plants with a total capacity of 1,119 MW. Ninety-seven percent of the installed capacity is regulated by the FERC through 20 individual licenses. Nearly all of the Company's hydroelectric projects are in some stage of relicensing under the FPA. Hydro relicensing and the related environmental compliance requirements are subject to a high degree of change in estimation. The Company expects that future costs relating to these matters may be significant and consist primarily of capital expenditures, and that power generation reductions may result from the additional environmental requirements. The Company expects these costs will be included in rates, and as such, will not have a material adverse impact on the Company's consolidated results of operations.

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

NOTE 8 - Income Taxes

The Company accrued federal and state income tax expense of $41.3 million and $98.1 million, representing effective tax rates of 37.4% and 42.2%, for the six months ended September 30, 2002 and 2001, respectively. The difference between taxes calculated as if the statutory federal tax rate of 35.0% was applied to Income from

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continuing operations before income taxes and cumulative effect of accounting change and the recorded tax expense is due to the following:

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

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

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

The examination of the Company's 1994 through 1998 tax years was completed in July 2002. The IRS issued a Revenue Agent's Report on July 3, 2002 for these years. Further, the IRS also issued a Revenue Agent's Report on July 17, 2002 containing solely the issues agreed upon with the Company. The tax impact for the agreed upon issues is an expense of approximately $40.9 million. The Company has an established liability for this amount. The Company has filed an administrative appeal for the unagreed issues. The Company believes that final settlement will not have a material adverse impact upon its financial position or results of operations. The IRS started the examination of the 1999 and 2000 tax years in September 2002.

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NOTE 9 - Comprehensive Income

The components of comprehensive income are as follows:

NOTE 10 - New Accounting Standards

Adoption of New Standard

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

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

New Standard Issued

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

NOTE 11 - Segment Information

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

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

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

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

NOTE 12 - Independent Accountants Review Report

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

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