PACIFICORP /OR/ - Quarter Report: 2001 December (Form 10-Q)

See accompanying Notes to Condensed Consolidated Financial Statements

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See accompanying Notes to Condensed Consolidated Financial Statements

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See accompanying Notes to Condensed Consolidated Financial Statements

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See accompanying Notes to Condensed Consolidated Financial Statements

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

(b)  Amounts shown are related to activity of a subsidiary of the Company with PHI and its subsidiaries. PHI is a non-operating, U.S. holding company and also an indirect wholly owned subsidiary of ScottishPower, that became the Company's parent on December 31, 2001. PHI also owns two energy companies that were owned by the Company until March 29, 2001.

(c)  These expenses and liabilities primarily represent payroll costs and related benefits of ScottishPower employees in management positions with the Company or working for the Company on its transition plan.

(d)  The Company has dividends payable to PHI. The Company expects to pay these dividends on January 31, 2002.

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

(f)  Interest income is reported as a component of "Other expense (income) - net."

The Company filed applications with the Federal Energy Regulatory Commission ("FERC") and the state utility commissions where approval is required to implement an internal corporate restructuring. The applications were approved and on December 31, 2001, all of the PacifiCorp common stock held by NA General Partnership was transferred to PHI (a wholly owned subsidiary of NA General Partnership). PacifiCorp intends to transfer all of the capital stock of Holdings to PHI in February 2002. Thereafter, the results of operations and financial position of Holdings will not be included with those of the Company.

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The intended transfer will facilitate the further separation of the Company's non-utility operations from its regulated utility operations. See Exhibit 99 to the December 31, 2001 Form 10-Q for the pro forma financial position and results of operations of the Company assuming the transfer of Holdings had occurred on the respective dates indicated in Exhibit 99.

See "Note 1 of Notes to the Consolidated Financial Statements" in the Company's Annual Report on Form 10-K for the year ended March 31, 2001 for information on interest rates on related party borrowings.

 4.  LONG-TERM DEBT

On November 21, 2001, the Company issued $500 million of its 6.90% Series of First Mortgage Bonds due November 15, 2011 and $300 million of its 7.70% Series of First Mortgage Bonds due November 15, 2031.

The Company is using the proceeds for general corporate purposes, including the repayment of short-term debt borrowed from Holdings and commercial paper.

 5.  DISCONTINUED OPERATIONS

The Company recognized $147 million of income during the first quarter of 2002 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. This note from the buyer was recorded at the date of the NERCO sale along with a corresponding deferred gain. Payments on this note were contingent upon the buyer receiving payment under a coal supply contract. The Company recognized this gain on a cost recovery basis as payments were received from the buyer. In June 2001, the Company received full payment of the remaining balance of the note and recognized the remaining balance of the deferred gain. Deferred tax expense of $36 million was recognized on the gain in June 2001.

 6.  SCOTTISHPOWER MERGER TRANSITION PLAN ACCRUALS

As part of the integration of the Company and ScottishPower, following their merger in November 1999, the Company implemented a transition plan with significant organizational and operational changes. In 2001, the Company recorded $76 million in accruals for severance and other costs relating to the transition plan. As of December 31, 2001, $20 million had been paid, and an adjustment of $9 million based upon estimates of the remaining liability had been made, leaving a remaining unpaid liability of $47 million reported under "Deferred Credits - Other" on the balance sheet. The $9 million adjustment was a reduction of the liability and the corresponding regulatory asset.

 7.  COMMITMENTS AND CONTINGENCIES

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

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At December 31, 2001, the Company had deferred power costs pursuant to orders received from Idaho, Oregon, Utah and Wyoming. While the Company is pursuing full recovery of these costs, there can be no assurance that this will be achieved. Denial of recovery will result in the write-off of deferred power costs reported under "Regulatory Assets" on the balance sheet.

 8.  ASSET SALES

During the first quarter of 2002, the Company sold aircraft owned by subsidiaries of PFS. The Company received proceeds of approximately $35 million and recorded a $9 million pretax gain on the sale. These assets had previously been reported under "Finance Assets - Net" on the balance sheet.

In October 2001, the Company sold its synthetic fuel operations. The Company received proceeds from the sale of $45 million and will receive quarterly royalty payments from the purchaser through October 2007. The receipt of any royalties is contingent upon actual future production and sales of synthetic fuel. The sale resulted in a gain of approximately $11 million, pretax. Royalty income will be recognized as it becomes receivable.

 9.  INCOME TAXES

The Company accrued federal and state income tax expense of $126 million, representing an effective tax rate of 41%, for the first nine months of 2002. For the first nine months of 2001, the Company accrued federal and state tax expense of $83 million, although incurring a loss from continuing operations before income taxes. The difference between taxes calculated as if the statutory federal tax rate of 35% was applied to income from continuing operations before income taxes and the recorded tax expense is due to the following:

(a)  When the Company recorded the sale of Australian electric operations, it did not have capital gains to offset the capital loss resulting from the sale

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and, therefore, no tax benefit was anticipated. The additional proceeds of $27 million received in June 2001 did not have associated tax expense as they reduced the capital loss previously reported.

10.  COMPREHENSIVE INCOME

The components of comprehensive income (loss) are as follows:

11.  NEW ACCOUNTING STANDARDS

Adoption of New Standard

The Company adopted Statement of Financial Accounting Standard ("SFAS") No. 133, "Accounting for Derivative Instruments and Hedging Activities," as amended by SFAS No. 138, effective April 1, 2001. See "Note 1 of Notes to the Consolidated Financial Statements" in the Company's Annual Report on Form 10-K for the year ended March 31, 2001.

The after-tax cumulative effect of the change in accounting principle on the Company's financial statements as of April 1, 2001 was as follows:

- Income Statement: $113 million of after-tax unrealized losses;
- Other Comprehensive Income, a component of shareholders' equity:
  $617 million of after-tax unrealized gains;
- SFAS No. 133 Current asset - net: $994 million;
- SFAS No. 133 Current liability - net: $752 million;
- SFAS No. 133 Non-current liability - net: $141 million;
- SFAS No. 133 Regulatory asset - net: $711 million; and
- SFAS No. 133 Deferred tax liability: $308 million.

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Deferred accounting treatment for the effects of 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. The income statement impact of SFAS No. 133 will be partially offset, on an ongoing basis, by the change in the regulatory asset or liability allowed under the deferred accounting orders. The recognition of a regulatory asset relating to SFAS No. 133 reduced the cumulative effect of an accounting change loss by $711 million (pretax).

A number of the Company's short-term forward power purchase contracts, with maturities through December 2002, have been designated as hedges against the risk of fluctuation in the cost of electricity to serve the Company's retail load. In accordance with SFAS No. 133, the market values of these contracts and changes thereto have been recorded as part of Accumulated other comprehensive income ("OCI"). At adoption of SFAS No. 133 on April 1, 2001, the market value of hedges was recorded as an unrealized after-tax gain of $617 million that was subsequently offset during 2002 by a $639 million unrealized after-tax loss. This $639 million after-tax change was comprised of an unrealized after-tax loss of $570 million representing the decrease in market values of hedges and $69 million representing a decrease as the underlying contracts were settled. A corresponding $69 million decrease to the SFAS No. 133 asset was recorded and there was no net effect on current earnings.

As of December 31, 2001, the Company anticipated that approximately $35.3 million ($21.9 million after-tax) of the unrealized net losses on derivative instruments in OCI will reverse during the next twelve months as the underlying contracts are settled. A corresponding increase to the SFAS No. 133 asset will be recorded with no net effect on current earnings.

In June 2001, the Financial Accounting Standards Board ("FASB") cleared SFAS No. 133 Implementation Issue No. C-15 ("C-15"). This new guidance allows the normal purchase normal sales ("NPNS") exemption in SFAS No. 133 to be applied to electricity option-type contracts and forward contracts when certain criteria are met. On December 19, 2001, the FASB cleared revised guidance on C-15. This revision modified the criteria to be used in determining if contracts, primarily option contracts, meet the NPNS exemption. SFAS No. 133 Implementation Issue No. K-5 states that if a contract had been accounted for as a derivative under SFAS No. 133 and it will now cease to be considered a derivative under newly issued implementation guidance, such as C-15, then the carrying value of the contract at the time C-15 becomes effective will remain the carrying value until the contract is settled. The market values of contracts that would no longer be recorded as derivatives upon implementation of C-15 would not be subject to further market value changes being recorded after June 30, 2001. The applicable amounts of these contracts would then be reversed as the transactions are settled. There is no cumulative effect of an accounting change that would need to be recorded upon implementation of C-15. The Company adopted C-15 on July 1, 2001. The C-15 revision will be adopted April 1, 2002. The Company has not yet determined the effect, if any, that the implementation of the C-15 revision will have on its consolidated financial statements.

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On September 19, 2001, the FASB cleared SFAS No. 133 Implementation Issue No. C-16 ("C-16") and revised it on December 19, 2001. C-16 states, in part, that the inclusion of an embedded purchased option that may require delivery of the related asset at an established price within a contract that meets the definition of a derivative disqualifies the entire derivative contract from being eligible to qualify for the NPNS exemption in SFAS No. 133. The effective date of the implementation of C-16 is April 1, 2002. The Company does not expect C-16 to have a material effect on its financial position or results of operations.

New Standards Issued

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 APB Opinion No. 17, "Intangible Assets." SFAS No. 142 specifically states that it does not change the accounting prescribed by SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation." The Company has no goodwill recorded on its books. Due to the regulatory treatment anticipated for the Company's intangible assets, which were all internally developed, the Company does not expect SFAS No. 142, when adopted, to have a material effect on its financial position or results of operations. This statement will be effective for the Company beginning April 1, 2002.

In June 2001, the FASB issued SFAS No. 143, "Accounting for Asset Retirement Obligations" ("SFAS No. 143"). This statement modifies financial accounting and reporting for the legal obligations and asset retirement costs associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or the normal operations of a long-lived asset. The statement will be effective for the Company beginning April 1, 2003. The Company has not yet determined the impact that implementation of this Statement will have on its consolidated financial statements.

In August 2001, the FASB issued SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets" ("SFAS No. 144"), which modifies and expands the financial accounting and reporting for the impairment or disposal of long-lived assets other than goodwill, which is specifically addressed by SFAS No. 142. The new statement supersedes SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of," but retains many of the fundamental recognition and measurement provisions of SFAS No. 121. This statement will be effective for the Company beginning April 1, 2002. Based on current information and business conditions, the Company does not expect adoption of SFAS No. 144 to have a material effect on its financial position or results of operations.

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12.  SEGMENT INFORMATION

Selected information regarding the Company's operating segments, Domestic electric operations, Australian electric operations and Other operations, are as follows:

(a)  In June 2001, upon resolution of a contingency under the provisions of the Powercor sale agreement, the Company received further proceeds from the sale that resulted in income of $27 million in 2002.

13.  INDEPENDENT ACCOUNTANTS REVIEW REPORT

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

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(1)  Net income (loss) by segment: (a) does not reflect elimination of interest on intercompany borrowing arrangements; (b) includes income taxes on a separate company basis, with any benefit or detriment of consolidation reflected in Other operations; (c) is net of minority interest (which is reported as a component of Other expense (income) - net).

The Company recorded net income of $46 million in the third quarter of 2002 compared to a net loss of $8 million in the third quarter of 2001.

Domestic electric operations net income was $33 million in the third quarter of 2002 compared to $14 million for the third quarter of 2001. This increase was primarily attributable to lower purchased power costs (net of amounts deferred for regulatory recovery) and the impact of SFAS No. 133. The impact of applying SFAS No. 133 for the quarter ended December 31, 2001 resulted in a decrease in operating expenses of $24 million pretax ($15 million after-tax). This reflected the effect in the quarter of the decrease in accrued liabilities on settled contracts and the change in market value of remaining energy contracts that qualify as derivatives, as defined by SFAS No. 133. These expense decreases were partially offset by decreases in wholesale sales revenue and increases in other operations, maintenance, administrative and general expenses.

In 2001, the Company completed the sale of Australian electric operations. As a result, no earnings were recorded in the third quarter of 2002 as compared to a net loss of $1 million in the third quarter of 2001.

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Other operations contributed net income of $13 million in the third quarter of 2002 compared to a net loss of $21 million in the third quarter of 2001. This increase was primarily due to a decrease in losses attributable to synthetic fuel producing companies and a gain from the sale of those companies in October 2001.

Comparison of the nine months ended December 31, 2001 and 2000

*Not a meaningful number.

(1)  Net income (loss) by segment: (a) does not reflect elimination of interest on intercompany borrowing arrangements; (b) includes income taxes on a separate company basis, with any benefit or detriment of consolidation reflected in Other operations; (c) is net of minority interest (which is reported as a component of Other expense (income) - net).

The Company recorded net income of $214 million in the 2002 period compared to a net loss of $90 million in the 2001 period.

Domestic electric operations net income was $135 million, an increase of $63 million compared to the 2001 period. This increase was primarily attributable to the impact of SFAS No. 133, partially offset by an increase in other operations, maintenance, administrative and general expenses. The impact of applying SFAS No. 133 for the nine months ended December 31, 2001 resulted in a reduction in operating expenses of $174 million pretax ($108 million after-tax). This reflected the effect in the nine months ended December 31, 2001 of the change in market value of energy contracts that qualify as derivatives, as defined by SFAS No. 133. Upon adoption of SFAS No. 133 on April 1, 2001, the difference between cost and market value of these energy contracts was a loss of $182 million pretax ($113 million after-tax) that was recorded in cumulative effect of accounting change and is shown in a separate line above. See "Note 11 of the Notes to Condensed Consolidated Financial Statements." The net result on the Company's earnings in the 2002 period of implementing SFAS No. 133 and recording the changes in market value of these energy contracts was a loss of $8 million pretax ($5 million after-tax).

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In 2001, the Company completed the sale of Australian electric operations. The loss of $187 million in 2001 was due primarily to the loss recorded on the sale of Australian electric operations. In June 2001, upon resolution of a contingency under the provisions of the Powercor sale agreement, the Company received further proceeds from the sale that resulted in income of $27 million in 2002. The proceeds were a reduction of the total loss on the sale and did not have associated tax consequences as the Company does not have enough capital gains to offset the capital loss from the sale.

Other operations contributed net income of $18 million in the 2002 period compared to $26 million in the 2001 period. This decrease was primarily attributable to a net gain recorded in 2001 relating to the settlement of foreign currency exchange swaps and debt repayment expense associated with the Company's investment in Australian electric operations, and was offset by a decrease in losses attributable to synthetic fuel producing companies and a gain from the sale of those companies in October 2001.

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DOMESTIC ELECTRIC OPERATIONS

Overview

During the third quarter of 2002, the Company experienced electricity prices that were at levels closer to those embedded in its tariff structure. These were the lowest prices that the Company had seen in over a year, as extreme volatility and unprecedented high price levels had characterized the western U.S. markets late in 2001 and in early 2002. Market prices for electricity declined earlier in 2002 due to low summer demand, increased plant availability (including the return of the Company's 430 megawatt Hunter No. 1 unit to service in early May 2001 after an outage that began in November 2000), conservation measures, and the introduction of a price cap mechanism by the FERC effective June 19, 2001. The Company received limited benefit from price reductions until this quarter. The Company contracted to purchase electricity in the forward market beginning in December 2000 as the forward market at that time indicated a continuation of high prices. The Company wanted to ensure that it had adequate supplies to fulfill its regulatory supply obligations and to avoid being supply constrained in a high priced and volatile market. These factors resulted in the Company continuing to pay higher prices after the market had returned to more normal levels.

As the Company purchased electricity in the forward market to meet its regulatory obligations, its objective was to manage load and resources so that any excess power in off-peak demand periods could be sold into the market to partially fund power purchases required for peak demand periods. The forward market required the Company to purchase blocks of power to meet peak demand. Those purchased blocks of power left the Company with excess power in the shoulder hour periods (early morning and late evening). As the forward prices began to drop, the value of surplus off-peak power declined. This decline in prices resulted in the Company selling power it had committed to purchase, that was in excess of its own requirements, for amounts substantially less than the Company's average purchase costs. These power purchases in excess of requirements occurred primarily in the shoulder hour periods.

The Company has outstanding commitments to purchase power to fulfill its regulatory obligation and to avoid being supply constrained. Certain of these commitments are above current market prices as a result of price movements since the Company entered into the contracts. Depending on load requirements, the Company may have power in excess of its own requirements, primarily in the shoulder hour periods. The actual impact of these purchases on the Company will depend on market prices for electricity at the time the purchases occur, the amount for which excess power can be sold, the load requirements at those times and the amounts that can be recovered through regulated rates.

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In an effort to mitigate the discrepancy between prices paid to purchase power and revenues received through regulated rates, the Company has requested and received regulatory approval from the utility commissions in the states of Utah, Idaho, Wyoming and Oregon to defer for each state some or all of the net power costs that vary from costs included in determining retail rates. During the 2002 period, the Company deferred $119 million (plus carrying costs of $20 million) under these orders. In total, the Company has a balance of $260 million of net deferred power costs. The Company has received orders to recover $23 million annually of these costs (subject to refund pending the outcome of prudence reviews) and is working with state commissions to seek recovery of the remaining amounts. The Company intends to continue to defer any power costs in excess of costs assumed in tariff rates in those jurisdictions where it has received orders to do so. See Part II, Item 5. "Other Information" for more information on the status of these regulatory proceedings.

Effective June 19, 2001, a price mitigation plan was imposed by the FERC that limits prices on spot market sales in California 24 hours a day, seven days a week until September 30, 2002. The price limits are determined based on a calculation that involves the price of natural gas in California, the heat rate of the least efficient gas fired generation plant in California and a fixed factor to account for other variable costs. When reserves in California exceed 7%, the wholesale price is limited to 85% of the price established under the Commission's formula during the most recent hour that reserves fell below 7%. Sellers have an opportunity to justify prices above the capped limit to the FERC. However, entities reselling power that was purchased are not permitted to seek prices above the capped limit.

On July 25, 2001, the FERC issued an order that extended the California price limits to all wholesale spot market sales to the entire 11-state western region. On December 19, 2001, the FERC revised the methodology used to calculate the price limits for the winter season. The mitigated price for all hours until May 1, 2002, was raised to the full amount of the last calculated price cap when reserves in California fell below 7%. The price limit will be increased further when the indices for natural gas prices used to establish the mitigated price increase by 10%. On May 1, 2002, the price limit will again be calculated using the original methodology until the price limits expire on September 30, 2002.

The FERC's June 19, 2001 order also required that "all public utility sellers and buyers in the California ISO's markets participate in settlement discussions to complete the task of settling past accounts and structuring the new arrangements for California's energy future." The FERC also stated that "it is imperative that the parties reach agreement on: (1) the additional load that is to be moved from the spot market to longer-term contracts; (2) refund (offset) issues related to past periods; and (3) creditworthiness matters." The FERC appointed an Administrative Law Judge ("ALJ") to serve as a settlement judge. The Company and many others participated in a settlement conference convened by the ALJ during late June and early July 2001. On July 11, 2001, the ALJ issued a recommendation to the FERC based upon the settlement conference. The ALJ recommendation proposed a methodology to

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calculate refund (offset) issues. The FERC agreed with the ALJ-proposed methodology. A proceeding before a second ALJ has been established to determine each party's refund liability. The Company's exposure to refunds will be dependent upon any order issued by the FERC in response to the outcome of these proceedings. The impact of refunds on counterparties in the market with whom the Company transacts purchases and sales, or any potential impact on financial markets that make funds available to companies operating in the western states, cannot be determined at this time.

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, 2002. The ALJ recommended that FERC not require refunds for these sales. The Company's exposure to refunds will be dependent upon any order issued by the FERC in response to the outcome of these proceedings.

Shortly prior to and following the imposition of the FERC's price mitigation plan, the market prices for power declined to levels closer to those embedded in the Company's tariff structure. The method of determining the maximum price level under the plan does not guarantee that market prices cannot return, periodically or for a sustained period, to the higher levels seen in the recent past. Volatility in market prices and demand, along with fluctuations in the FERC price mitigation controls, can significantly impact future results.

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Summary of Results

Domestic electric operations had operating profit before interest and taxes of $113 million, representing a $30 million increase from the prior year period. Excluding the $24 million favorable impact during the quarter of applying SFAS No. 133, Domestic electric operations' operating profit before interest and taxes was $89 million, or an increase of $6 million from the prior year period. During the third quarter of 2002, the Company experienced a drop in the previously high short-term firm and spot market purchased power prices. For a discussion of the factors affecting the market price of power, see "Overview" above and "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Overview of 2001" in the Company's Annual Report on Form 10-K for the year ended March 31, 2001. Lower market prices contributed to a decrease in wholesale sales of $453 million, from $690 million in 2001 to $237 million in 2002. However, this decrease was more than offset by a $499 million decrease in purchased power costs from $850 million in 2001 to $351 million in 2002 (net of $73 million deferred for costs that vary from costs included in current rates). Domestic Electric Operations also experienced a $12 million increase in other revenues. Domestic electric operations had a $58 million, or 33%, increase in other operations, maintenance, administrative and general expenses and taxes, other than income taxes.

Revenues

Total Domestic electric operations revenues decreased $440 million, or 33%, to $883 million in 2002. This decrease was attributable to decreases in wholesale sales of $453 million, a $1 million increase in retail revenues and a $12 million increase in other revenues.

Residential revenues increased $2 million, or 1%. Price increases in Oregon, Utah and Wyoming added $18 million to revenues in 2002. Growth in the average number of residential customers of 1% added $3 million to revenues. Volume decreases, primarily due to changes in customer usage, decreased residential revenues by $20 million.

Commercial revenues increased $6 million, or 3%. Price increases in Oregon, Utah and Wyoming added $18 million to revenues in 2002. Growth in the average number of commercial customers of 2% added $4 million to revenues. Volume decreases, primarily due to changes in customer usage, decreased commercial revenues by $18 million.

Industrial revenues decreased $7 million, or 4%. Volume decreases of 3% reduced revenues by $10 million. Partially offsetting this decrease was an increase in prices in Utah and Wyoming that raised revenues by $2 million.

Wholesale sales revenues decreased $453 million, or 66%. Sales prices for short-term firm and spot market sales averaged $34 per MWh in 2002, a decrease from the average of $105 per MWh in 2001, resulting in a $300 million decrease in revenues. A 21% decrease in short-term and spot market sales volumes drove a $104 million decrease in revenues. The impact of the expiration of long-term firm sales contracts drove a 38% decrease in long-term firm contract volumes and lowered wholesale revenues by $61 million in 2002. Partially offsetting these decreases were long-term firm contract sales that averaged $46 per MWh

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in 2002, an increase from the average of $42 per MWh in 2001, resulting in a $12 million increase in revenues.

Other revenues increased $12 million, or 38%, primarily due to an increase in deferred carrying charges on unrecovered deferred power costs and the amortization of the Centralia regulatory liability that offsets reductions in revenue resulting from refunding a gain to customers.

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

Operating Expenses

Total Domestic electric operating expenses decreased $483 million, or 39%, to $764 million in 2002. Purchased power expense decreased $499 million due to lower short-term firm and spot market prices and volumes. In the 2002 quarter, the $21 million of other operating income was due to the September 10, 2001 Utah rate order that successfully resolved the issues surrounding previously excluded costs and resulted in the establishment of a $21 million regulatory asset. Offsetting these favorable adjustments was a $58 million increase in operations, maintenance, administrative and general expenses and taxes, other than income taxes.

Purchased power expense was $351 million, a decrease of $499 million, or 59%. A 44% decrease in short-term firm and spot market purchase volumes decreased costs by $279 million, and a 7% decrease in purchase volumes relating to long-term firm contracts decreased costs by $29 million. The decreases in volume relate, in part, to reductions in long-term firm sales commitments. As long-term sales commitments ended, the power that became available was used to meet load requirements and reduced the purchases of short-term spot power to balance load. Lower prices on short-term firm and spot market purchases decreased purchased power expense by $166 million. The decrease is net of the effect of deferred accounting treatment of $73 million for power costs that vary from costs included in current rates. Short-term firm and spot market purchase prices averaged $37 per MWh in 2002, a 67% decrease from the average price of $111 per MWh in 2001. Decreased usage of transmission systems owned by third parties reduced expense by $18 million and Demand Side Management costs were lower by $12 million. The Company estimates that current customer participation in the Demand Side Management programs has resulted in a load curtailment of approximately 56,000 MWhs for the third quarter of 2002. Offsetting these decreases were higher prices on long-term firm contracts adding $5 million to purchased power expense.

Fuel expense decreased $3 million, or 2%, to $123 million primarily due to a 5% decrease in thermal generation volumes.

Other operations and maintenance expense increased $23 million, or 19%, in 2002. The Company leased a new generating turbine that added $6 million to expense in 2002. Expenses relating to electricity generation, primarily overhauls, added $10 million to expenses in 2002. A $5 million provision for bad debt reserves was recorded during the quarter. Timing of unused leave accruals, resulting from a change in union contracts, caused a $9 million increase in expenses for the current quarter. External service providers and rent added $2 million to expense. In addition, other employee related expenses

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increased $2 million. Partially offsetting these unfavorable variances was a $15 million expense decrease due to the level and timing of capital projects and related expenditures.

Depreciation and amortization expense increased $4 million, or 4%, to $102 million primarily due to increased plant in service.

Administrative and general expenses increased $33 million, or 105%, to $65 million. Amortization of deferred transition costs allowed by state regulators contributed $3 million to the increase. In 2002, the proportion of expenditures capitalized fell from the levels capitalized in the prior year, which resulted in a $12 million increase in expense. Increased use of external service providers, primarily on strategic and risk initiatives, added $6 million to expense. In addition, employee related expenses increased by $14 million in 2002.

Taxes, other than income taxes, increased $2 million, or 8%, to $23 million primarily due to increased property tax expense.

The unrealized gain on SFAS No. 133 - derivative instruments, in the 2002 quarter pertains to the decrease in accrued liabilities relating to contracts settled in the third quarter, as well as the Company's short-term sales obligations, which are marked to market, being favorably impacted by lower forward market prices that resulted from the significant changes in market fundamentals. See "Note 11 of the Notes to Condensed Consolidated Financial Statements" for information regarding SFAS No. 133.

The $21 million recorded as Other operating income in the 2002 quarter pertains to the September 10, 2001 Utah rate order that successfully resolved the issues surrounding previously excluded costs and resulted in the establishment of a $21 million regulatory asset.

Other Expense (Income) - Net

Other expense (income) - net was $6 million of net expense in the third quarter of 2002, compared to $8 million of net income in the third quarter of the prior year. Emission allowance sales were $8 million lower in 2002. In addition, capitalized interest expense was $2 million lower, insurance proceeds were $2 million lower and legal settlement costs were $2 million higher.

Interest Expense

Domestic electric operations interest expense decreased $2 million primarily due to lower interest rates in the 2002 quarter.

Income Tax Expense

Income tax expense increased $13 million principally due to the higher taxable income in the current quarter. The effective tax rate for the third quarter of 2002 was 39% compared to 36% for the third quarter of 2001. For a reconciliation of the total income tax expense to the statutory federal income tax expense, see "Note 9 of the Notes to Condensed Consolidated Financial Statements."

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Summary of Results

Domestic electric operations had operating profit before interest and taxes of $392 million, representing a $76 million increase from the prior year. Excluding the $174 million favorable impact during the 2002 period of applying SFAS No. 133, Domestic electric operations' operating profit before interest and taxes was $218 million, or a decrease of $98 million from the prior year. During the first quarter of 2002, the Company, along with other Western Systems Coordinating Council companies, experienced continued high short-term firm and spot market purchased power prices due to the imbalance of supply and demand in the region. Prices collapsed in the second and third quarters of 2002 but the Company continued to experience high purchased power prices because it contracted for electricity in the forward market at then prevailing market prices to meet its regulatory obligations and balance its expected load. As a result, prices paid for power exceeded both current market prices and retail tariff rates. For a discussion of the factors affecting the market price of power, see "Overview" above and "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Overview of 2001" in the Company's Annual Report on Form 10-K for the year ended March 31, 2001. Wholesale sales decreased to $1.48 billion in 2002, a $25 million decrease from 2001 due to the reduction in market prices. In addition, purchased power costs of $1.85 billion (net of $119 million deferred for costs that vary from costs included in current rates), increased by $7 million over 2001. Partially offsetting the increase in purchased power costs and decrease in wholesale sales was $49 million in increased revenues due to retail price increases, net of decreases in retail volumes. Domestic electric operations had a $119 million, or 21%, increase in other operations, maintenance, administrative and general expenses and taxes, other than income taxes.

Revenues

Total Domestic electric operations revenues increased $73 million, or 2%, to $3.40 billion in 2002. This increase was primarily attributable to increases in retail sales and other revenues.

Residential revenues increased $25 million, or 4%. Price increases primarily in Oregon, Utah and Wyoming added $37 million to revenues in 2002. Growth in the average number of residential customers of 2% added $9 million to revenues. Decreases in average usage of residential customers decreased residential revenues by $22 million.

Commercial revenues increased $29 million, or 5%. Price increases primarily in Oregon, Utah and Wyoming added $27 million to revenues in 2002. Growth in the average number of commercial customers was offset by decreases in usage.

Industrial revenues decreased $7 million, or 1%. A reduction of 4% in energy volumes sold resulted in $26 million in lower revenue, and decreased irrigation usage lowered revenues by $3 million. Offsetting those decreases were price increases primarily in Oregon, Utah and Wyoming that added $21 million to revenues.

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Wholesale sales revenues decreased $25 million, or 2%. The impact of the expiration of long-term firm sales contracts drove a 36% decrease in long-term firm contract volumes and lowered wholesale revenues by $162 million in 2002. A 7% decrease in short-term and spot market sales volumes drove a $59 million decrease in revenues. Partially offsetting these decreases were sales prices for short-term firm and spot market sales averaging $107 per MWh in 2002, an increase from the average of $91 per MWh in 2001, resulting in a $154 million increase in revenues. Long-term firm contract sales averaged $44 per MWh in 2002, an increase from the average of $40 per MWh in 2001, resulting in a $42 million increase in revenues.

Other revenues increased $50 million, or 54%, primarily due to an increase in wheeling revenue, the amortization of the Centralia regulatory liability that offsets reductions in revenue resulting from refunding a gain to customers and deferred carrying charges on unrecovered deferred power costs.

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

Operating Expenses

Total Domestic electric operating expenses decreased $17 million, or 1%, to $3.00 billion in 2002. This decrease was primarily attributable to a reduction in operating expenses of $174 million for the 2002 period resulting from the application of SFAS No. 133. Partially offsetting this expense decrease was increased other operations, maintenance, administrative and general expenses and taxes, other than income taxes.

Purchased power expense of $1.85 billion, an increase of $7 million, was only slightly higher than the prior year. Higher prices on short-term firm and spot market purchases increased purchased power expense by $376 million. The increase is net of the effect of deferred accounting treatment of $103 million for power costs that vary from costs included in current rates. Short-term firm and spot market purchase prices averaged $126 per MWh in the 2002 period, a 37% increase from the average price of $92 per MWh in 2001. In addition, higher prices on long-term firm contracts added $21 million to purchased power expense. Partially offsetting these increases in expense was a 22% decrease in short-term firm and spot market purchase volumes, which decreased costs by $367 million, and a 14% decrease in purchase volumes relating to long-term firm contracts, which decreased costs by $73 million. The decreases in volume pertain to reductions in long-term firm sales commitments. As long-term sales commitments ended, the power that became available was used to meet load requirements and reduced the purchases of short-term spot power to balance load. Decreased usage of transmission systems owned by third parties reduced expense by $3 million while Demand Side Management costs added $53 million to expense. The Company estimates that current customer participation in the Demand Side Management programs has resulted in a load curtailment of approximately 1,615,000 MWhs for the 2002 period.

Fuel expense increased $14 million, or 4%, to $369 million primarily due to increased thermal generation at higher cost plants.

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Other operations and maintenance expense increased $43 million, or 11%, to $427 million. In 2002, the Company leased a new generating turbine that added $25 million to expense. Timing of electricity generation plant overhauls added $13 million to expenses in 2002. A $5 million provision for reserve for doubtful accounts was recorded in 2002. Timing of unused leave accruals resulting from a change in union contracts caused a $7 million increase in expenses for the period. Other employee related expenses and tree trimming costs increased $6 million and $3 million, respectively. Partially offsetting these unfavorable variances was a $23 million expense decrease due to the level and timing of capital projects and related expenditures.

Depreciation and amortization expense increased $8 million, or 3%, to $300 million primarily due to increased plant in service.

Administrative and general expenses increased $78 million, or 75%, to $182 million. Amortization of deferred transition costs allowed by state regulators and amortization of regulatory assets re-established in 2001 under a Utah rate order contributed $14 million and $3 million, respectively, to the increase. Employee related expenses increased $18 million. In 2002, the proportion of expenditures capitalized fell from the levels capitalized in the prior year, which resulted in a $31 million increase in expense. Increased use of external service providers, primarily on strategic and risk initiatives, added $7 million to expenses. The sale of the Australian electric operations segment in the prior year resulted in an unfavorable variance due to $3 million of expenses that were billed to the segment in the prior year.

Taxes, other than income taxes, decreased $2 million, or 2%, to $67 million primarily due to lower property tax expense resulting from the favorable resolution of outstanding property tax appeals.

The unrealized gain on SFAS No. 133 - derivative instruments, in the nine months ended December 31, 2001, pertains to the Company's short-term sales obligations being favorably impacted by lower forward market prices that resulted from the significant changes in market fundamentals. See "Note 11 of the Notes to Condensed Consolidated Financial Statements" for information regarding SFAS No. 133.

The $21 million recorded as Other operating income in 2002 pertains to the September 10, 2001 Utah rate order that successfully resolved the issues surrounding previously excluded costs and resulted in the establishment of a $21 million regulatory asset.

The $30 million recorded as Other operating income in 2001 represented primarily two offsetting items. First, the Utah rate order received in May 2000 successfully resolved the issues surrounding previously excluded costs and resulted in the establishment of a $43 million regulatory asset. Second, the Company recorded a loss of $14 million on the sale of the Centralia Power Plant and mine net of refunds to customers ordered by regulatory commissions. For more information, see "Note 17 of the Notes to the Consolidated Financial Statements" in the Company's Annual Report on Form 10-K for the year ended March 31, 2001.

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Other Expense (Income) - Net

Other expense (income) - net was $4 million of net expense in 2002, a net change of $14 million from the net income of $10 million in the prior year. Emission allowance sales were $12 million lower in 2002 and interest income was $5 million lower. In addition, capitalized interest expense decreased $5 million in the current year. These unfavorable variances were partially offset by $9 million in merger costs recorded in 2001.

Interest Expense

Domestic electric operations interest expense decreased $21 million primarily due to lower interest rates.

Income Tax Expense

Income tax expense increased $34 million principally due to the higher taxable income in the current year. The effective tax rate for the 2002 period was 40% compared to a 43% effective tax rate for the 2001 period. For a reconciliation of the total income tax expense to the statutory federal income tax expense, see "Note 9 of the Notes to Condensed Consolidated Financial Statements."

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AUSTRALIAN ELECTRIC OPERATIONS

During September and November 2000, the Company completed the sales of Powercor and its 19.9% interest in Hazelwood, respectively. As a result of these sales, the Company has completely exited its Australian electric operations.

In June 2001, upon resolution of a contingency under the provisions of the Powercor sale agreement, the Company received further proceeds due from the sale that resulted in income of $27 million in 2002.

Australian electric operations' financial results for the period from October 1, 2000 to the date of sale of Hazelwood are included in the Company's financial results for the quarter ended December 31, 2000. Australian electric operations' financial results for the period from January 1, 2000 to the respective dates of sale are included in the Company's financial results for the nine months ended December 31, 2000.

Comparison of the three months ended December 31, 2001 and 2000

Comparison of the nine months ended December 31, 2001 and 2000

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OTHER OPERATIONS

See "Note 3 of the Notes to Condensed Consolidated Financial Statements" for information regarding the anticipated transfer of Holdings from the Company to PHI.

Comparison of the three months ended December 31, 2001 and 2000

(a)  These items reflect a tax rate of approximately 38%.

Other operations reported income of $13 million in 2002 compared to a loss of $21 million in 2001.

In 2002, Other operations' earnings contribution increased $34 million compared to 2001. In 2001, the Company reversed tax credits associated with its synthetic fuel operations owned by subsidiaries of PFS. This action resulted from the recognition of the Company's inability to use these tax credits. The synthetic fuel operations were sold on October 15, 2001. See "Note 8 of the Notes to Condensed Consolidated Financial Statements." Decreased interest income of $3 million in 2002 was principally due to interest earned in 2001 on affiliated notes receivable. See "Note 3 of the Notes to Condensed Consolidated Financial Statements" for additional information on related party transactions. Financing revenue included in Other - net was $4 million lower in 2002 due to collection, in June 2001, of a contingent note receivable held by Holdings. See "Discontinued Operations" below.

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(a)  These items reflect a tax rate of approximately 38%.

(b)  This item reflects a tax rate of approximately 46% due to the non-deductible nature of a portion of this amount.

(c)  This item reflects a tax rate of approximately 13% due to the tax advantaged nature of the leveraged leased assets sold.

Other operations reported income of $18 million in 2002 compared to income of $26 million in 2001.

In 2002, Other operations' earnings contribution decreased $7 million compared to 2001. As mentioned above, the Company reversed tax credits associated with its synthetic fuel operations in 2001 that resulted in losses for that period. See "Note 8 of the Notes to Condensed Consolidated Financial Statements." The sale of the Company's investment in Australian electric operations in 2001 resulted in a net gain on settlement of foreign currency exchange swaps and debt repayment expense of $20 million. Interest expense in 2002 decreased $5 million due to the repayment of debt balances during 2001. Gains on sales of leased aircraft owned by subsidiaries of PFS were $8 million in 2002. Financing revenue included in Other - net was $9 million lower in 2002 due to collection, in June 2001, of a contingent note receivable held by Holdings. See "Discontinued Operations" below. Other - net also includes $21 million of tax expense relating to re-evaluation of tax liabilities from settled and ongoing tax examinations. For a reconciliation of the total income tax expense to the statutory federal income tax expense, see "Note 9 of the Notes to Condensed Consolidated Financial Statements."

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DISCONTINUED OPERATIONS

The Company recognized $147 million of income during the first quarter of 2002 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. This note from the buyer was recorded at the date of the NERCO sale along with a corresponding deferred gain. Payments on this note were contingent upon the buyer receiving payment under a coal supply contract. The Company recognized this gain on a cost recovery basis as payments were received from the buyer. In June 2001, the Company received full payment of the remaining balance of the note and recognized the remaining balance of the deferred gain. Deferred tax expense of $36 million was recognized on the gain in June 2001.

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FINANCIAL CONDITION -

For the nine months ended December 31, 2001:

OPERATING ACTIVITIES

Net cash flows used in operating activities were $32 million during the period compared to net cash flows provided by operating activities of $515 million in the 2001 period. This $547 million decrease in operating cash flows was primarily attributable to working capital changes relating to changes in market prices for electricity.

INVESTING ACTIVITIES

Capital spending totaled $337 million in 2002 compared with $296 million in 2001. Construction expenditures increased in 2002 primarily due to higher expenditures relating to generating assets. The $83 million of proceeds from asset sales in 2002 were primarily from the sale of the Company's synthetic fuel operations and additional proceeds received relating to the disposal of Australian electric operations. Proceeds from sales of finance assets and principal payments were $42 million. Included in that amount was $34 million for aircraft sold by subsidiaries of PFS. The $190 million of proceeds from finance note repayment in 2002 represented the payment of the note receivable recorded in connection with the sale of the Company's mining and resource development business in 1993. (See "Note 5 of the Notes to Condensed Consolidated Financial Statements.") Proceeds from asset sales in 2001 primarily represented the sale of the Australian electric operations and the Centralia plant and mine.

The changes in debt due from affiliates in 2002 were the result of activities of a subsidiary of the Company with PHI and its other subsidiaries. In 2001, activities with PHI subsidiaries were eliminated in consolidation, as those subsidiaries were owned by the Company until March 29, 2001. See "Note 3 of the Notes to Condensed Consolidated Financial Statements."

FINANCING ACTIVITIES

The Company's short-term borrowings and certain other financing arrangements are supported by $880 million of revolving credit agreements established in June 2001. The current revolving credit agreements expire in June 2002. The finance charges for these facilities are based on LIBOR plus a margin.

The Company redeemed, at par, $100 million of its preferred stock pursuant to its scheduled mandatory redemption on August 15, 2001.

The Company had $218 million of declared dividends on common stock payable at December 31, 2001. The Company expects to pay these dividends on January 31, 2002. On August 6, 2001, the Company declared a dividend on common stock of $80 million. On May 21, 2001, the Company declared a dividend on common stock of $80 million.

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On November 5, 2001, the Company declared a dividend on preferred stock of $2 million, which is scheduled to be paid to shareholders on February 15, 2002. On August 6, 2001, the Company declared a dividend on preferred stock of $2 million, which was paid to shareholders on November 15, 2001. On May 21, 2001, the Company declared a dividend of $4 million on preferred stock, which was paid to shareholders on August 15, 2001.

Proceeds from long-term debt in 2002 were from the issuance of $800 million of First mortgage bonds in November 2001.

Proceeds from long-term debt in 2001 pertained to borrowings by the Company's Australian electric operations, which were sold during 2001.

CAPITALIZATION

At December 31, 2001, PacifiCorp had approximately $76 million of commercial paper outstanding at a weighted average rate of 2.1%. These borrowings and other financing arrangements are supported by revolving credit agreements.

BUSINESS RISK

In addition to the Company's market risks relating to Regulatory/Political, Credit and Interest Rates as reported in the Company's Annual Report on Form 10-K for the year ended March 31, 2001 under "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Business 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's June 19, 2001 order as discussed under "Results of Operations - Domestic Electric Operations," above.

The Company took further steps in the third quarter of 2002 to manage commodity price volatility and reduce exposure. These steps included adding to our generation portfolio and entering into transactions that help to shape the Company's system resource portfolio, including physical hedging products and financial temperature-related instruments that reduce resource and price risk on hot summer days. In addition, "hydroelectric" hedges were put in place for the next five years to limit volume and price risks associated with Pacific Northwest hydroelectric generation availability.

To further mitigate commodity price risk, the Company has requested power cost adjustment mechanisms in Oregon, Utah, Idaho and California. Under these mechanisms, if granted by the utility commissions, all or part of actual power costs, above or below the level in rates, will be shared with customers. See Part II, Item 5. "Other Information" for information regarding recent developments in regulatory issues affecting the Company.

During the third quarter of 2002, Enron Corporation announced that it and certain subsidiaries were filing for Chapter 11 bankruptcy protection. The Company is exposed to a credit risk as a result of Enron's actions both in relation to Enron itself and to its trading partners with large receivables from Enron. However, the Company believes that its exposure in this matter will not have a material adverse effect on the Company's results of operations or financial condition.

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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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