PACIFICORP /OR/ - Quarter Report: 2001 September (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, accounts 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 is also an indirectly owned subsidiary of ScottishPower. PHI 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 NA General Partnership, an indirect wholly owned subsidiary of ScottishPower.

(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 income - net."

The Company has filed applications with the Federal Energy Regulatory Commission ("FERC") and the state commissions where approval is required to implement an internal corporate restructuring. The applications have been approved by the FERC and all of the required states except California. The proposed restructuring would transfer all of the PacifiCorp common stock presently held by NA General Partnership to PHI (a wholly owned subsidiary of NA General Partnership).

The proposed transfer will facilitate the further separation of the Company's non-utility operations from its regulated utility operations. In connection with the proposed restructuring, the Company intends to transfer the Company's

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ownership of Holdings to PHI. See Exhibit 99 to this 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.  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 has recognized this gain on a cost recovery basis as payments have been 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.

 5.  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 September 30, 2001, $18 million had been paid, leaving a remaining unpaid liability of $58 million reported under "Deferred Credits - Other" on the balance sheet.

 6.  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. At September 30, 2001, the Company has 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.

 7.  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.

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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 December 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 $12 million, pretax. Royalty income would be recognized as it becomes receivable.

 8.  INCOME TAXES

The Company accrued federal and state income tax expense of $98 million, representing an effective tax rate of 42%, for the first half of 2002. For the first half of 2001, the Company accrued federal and state tax expense of $44 million, although incurring an operating loss before 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 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.

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

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 9.  COMPREHENSIVE INCOME

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

10.  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.

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

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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 September 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 $617 million unrealized after-tax loss. This $617 million after-tax change was comprised of an unrealized after-tax loss of $526 million representing the decrease in market values of hedges and $91 million representing a decrease as the underlying contracts were settled. A corresponding $91 million decrease to the SFAS No. 133 asset was recorded and there was no net effect on current earnings.

As of September 30, 2001, the Company anticipated that approximately $386,000 ($239,000 after-tax) of the unrealized net gains on derivative instruments in OCI will reverse during the next twelve months as the underlying contracts are settled. A corresponding decrease 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. 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.

On September 19, 2001, the FASB cleared SFAS No. 133 Implementation Issue No. C-16 ("C-16"). 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 has not yet determined the effect, if any, that implementation of C-16 will have on its consolidated financial statements.

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New Standards Issued

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. This statement will be effective for the Company beginning April 1, 2002, unless management elects earlier adoption. Management is continuing to assess the provisions of SFAS No. 144 and currently has not determined the likely impact of its adoption on the Company's consolidated financial statements.

In June 2001, the FASB issued SFAS No. 143, "Accounting for Asset Retirement Obligations." This statement modifies financial accounting and reporting for the legal obligations 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 June 2001, the FASB issued SFAS No. 142, "Goodwill and Other Intangible Assets," 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." Due to the regulatory treatment anticipated for most of the Company's goodwill and intangible assets, the Company does not expect SFAS No. 142, when adopted, to have a material effect on its financial position or results of operation. The Company is, however, in the process of determining the impact that adoption will have on its consolidated financial statements. SFAS No. 142 is effective for the Company's fiscal year beginning April 1, 2002.

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11.  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.

12.  SUBSEQUENT EVENTS

In October 2001, the Company and Nor-Cal Electric Authority ("Nor-Cal") reached an agreement in principle for the sale of the Company's California electric service area. The two parties have been working together to transfer these properties since 1999. The California Public Utilities Commission ("CPUC"), in December 2000, turned down a previous agreement between these

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parties. When a definitive agreement is reached, it will be subject to approval by the CPUC. See Part I, Item 1. "Business - Domestic Electric Operations - Proposed Asset Dispositions" in the Company's Annual Report on Form 10-K for the year ended March 31, 2001 for additional information regarding this sale.

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 (loss) income 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 income - net).

The Company recorded a loss of $30 million in the second quarter of 2002 compared to net income of $53 million in the second quarter of 2001.

Domestic electric operations net loss was $25 million compared to net income of $25 million for the second quarter of 2001. This decrease was primarily attributable to higher 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 September 30, 2001 resulted in an increase in operating expenses of $28 million pretax ($17 million after-tax). This reflects the effect in the quarter of the increase 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.

In 2001, the Company completed the sale of Australian electric operations. As a result, no earnings were recorded in the second quarter of 2002 as compared to income of $7 million in the second quarter of 2001.

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Other operations contributed a loss of $6 million in the second quarter of 2002 compared to income of $21 million in the second quarter of 2001. This decrease was primarily attributable to tax reserves recorded in 2002 and a decrease in earnings for synthetic fuel producing companies that were subsequently sold in October 2001.

Comparison of the six months ended September 30, 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 income - net).

The Company recorded net income of $168 million in the first half of 2002 compared to a loss of $82 million in the first half of 2001.

Domestic electric operations net income was $102 million, an increase of $44 million compared to the first half of 2001. This increase was primarily attributable to the impact of SFAS No. 133, partially offset by the impact of high purchased power costs (net of amounts deferred for regulatory recovery). The impact of applying SFAS No. 133 for the six months ended September 2001 resulted in a reduction in operating expenses of $150 million pretax ($93 million after-tax). This reflects the effect in the six months ended September 30, 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 10 of the Notes to Condensed Consolidated Financial Statements." The net result on the Company's earnings in the first half of 2002 of implementing SFAS No. 133 and recording the changes in market value of these energy contracts was a loss of $32 million pretax ($20 million after-tax).

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In 2001, the Company completed the sale of Australian electric operations. The loss of $186 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 income of $5 million in the first half of 2002 compared to $47 million in the first half of 2001. This decrease was primarily attributable to decreased earnings for synthetic fuel producing companies (subsequently sold in October 2001), tax reserves recorded in 2002 and 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.

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DOMESTIC ELECTRIC OPERATIONS

Overview

Over the last year, extreme volatility and unprecedented high price levels have characterized western U.S. electricity markets. For the twelve months prior to June 2001, the forward market indicated that these conditions were expected to continue throughout the summer and winter of 2001 and into next year. To ensure that the Company was able to fulfil its regulatory supply obligations and to avoid being supply constrained in a high priced and volatile market, the Company continued its policy of contracting for electricity in the forward market from December 2000 forward. 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.

In the past few months, the forward prices of energy have dropped dramatically decreasing the value of any surplus off-peak power. There were various causes of the decline, including low summer demand, increased plant availability (including the return of the Company's 430 megawatt Hunter 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. This collapse in prices has only provided limited benefit to the Company as it had committed to purchase power at higher prices in the forward market to balance its load. For a detailed discussion of how these issues have impacted the Company for the three and six months ended September 30, 2001, see the discussion of "Operating Expenses."

As a result of the lower forward prices currently prevailing, the Company's committed power purchases in excess of its requirements will result in sales for amounts expected to be substantially less than the Company's average purchase costs. These power purchases in excess of requirements are expected to occur primarily in the shoulder hour periods (early morning and late evening). The actual impact of these purchases on the Company will depend on the market prices for electricity at the time any excess power is sold and amounts that can be recovered through regulated rates.

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 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 first half of 2002, the Company deferred $175 million (plus carrying costs of $9 million) under these orders. In total, the Company has $311 million of net deferred power costs. The Company has received orders to recover $52.5 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.

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Effective June 19, 2001, a price mitigation plan was imposed by the FERC that limits prices on spot market sales in the entire 11-state western region 24 hours a day, seven days a week. The price limits will be 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. All amounts will be based on factors existing during the then most recent California Stage 1 emergency. Sellers other than marketers will have the opportunity to justify prices above the capped limit to the FERC. On July 25, 2001, the FERC issued an order that extended the price limits to wholesale sales throughout the Western United States. The Company is monitoring the impact these price mitigation controls are having on its power purchase and sales transactions. This price mitigation plan is scheduled to end 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 calculate refund amounts. 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 between December 25, 2000 and June 20, 2002 for sales in the Pacific Northwest. The ALJ recently 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 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.

On August 19, 2001, the Company filed with the FERC requesting changes in the price cap as it relates to the Pacific Northwest. The FERC is considering

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modifying the price cap for wholesale transactions in the Pacific Northwest for the upcoming winter.

Comparison of the three months ended September 30, 2001 and 2000

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Summary of Results

Domestic electric operations had operating profit before interest and taxes of $9 million, representing a $95 million decrease from the prior year period. Excluding the $28 million unfavorable impact during the quarter of applying SFAS No. 133, Domestic electric operations' operating profit before interest and taxes was $37 million, or a decrease of $67 million from the prior year period. During the second quarter of 2002, the Company experienced continued high short-term firm and spot market purchased power prices because it had contracted for electricity in the forward market at then prevailing market prices to balance its expected load for the quarter. As a result, prices paid for power exceeded both current market prices and retail tariff rates during the quarter. 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. While higher market prices contributed to increasing wholesale sales to $588 million in 2002, a $61 million increase over 2001, this increase was more than offset by purchased power costs of $768 million (net of $132 million deferred for costs that vary from costs included in current rates), representing a $104 million increase over 2001. Partially offsetting this increase in purchased power costs was $27 million in increased revenues due to retail price increases and higher wheeling revenues. Domestic electric operations had a $22 million, or 12%, increase in other operations, maintenance, administrative and general costs and taxes other than income taxes.

Revenues

Total Domestic electric operations revenues increased $88 million, or 8%, to $1.24 billion in 2002. This increase was primarily attributable to increases in wholesale sales of $61 million, an $11 million increase in retail revenues and a $16 million increase in other revenues, primarily due to wheeling revenues.

Residential revenues increased $9 million, or 4%. Growth in the average number of residential customers of 2% added $3 million to revenues. Price increases in Oregon, Utah and Wyoming added $9 million to revenues in 2002. Volume decreases, primarily due to changes in customer usage, decreased residential revenues by $3 million.

Commercial revenues increased $9 million, or 5%. Price increases in Oregon, Utah and Wyoming added $3 million to revenues in 2002. Growth in the average number of commercial customers of 2% added $5 million to revenues.

Industrial revenues decreased $8 million, or 4%. Volume decreases of 6% reduced revenues by $10 million. Partially offsetting this decrease was an increase in irrigation usage that raised revenues by $2 million.

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Wholesale sales revenues increased $61 million, or 12%. A 29% increase in short-term and spot market sales volumes drove an $82 million increase in revenues. Sales prices for short-term firm and spot market sales averaged $117 per MWh in 2002, an increase from the average of $116 per MWh in 2001, resulting in a $23 million increase in revenues. Long-term firm contract sales averaged $43 per MWh in 2002, an increase from the average of $41 per MWh in 2001, resulting in a $10 million increase in revenues. Partially offsetting these increases was the impact of the expiration of long-term firm sales contracts that drove a 35% decrease in long-term firm contract volumes and lowered wholesale revenues by $54 million in 2002.

Other revenues increased $16 million, or 49%, primarily due to an increase in wheeling revenues from increased usage of the Company's transmission system by third parties.

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

Operating Expenses

Total Domestic electric operating expenses increased $188 million, or 18%, to $1.24 billion in 2002. Purchased power expense, which represented $104 million of this increase, increased due to increased prices on forward contracts to purchase short-term firm and spot market power. Additionally, an increase in operating expenses of $26 million and $28 million for the 2002 quarter resulted from increased administrative and general costs and the unrealized losses on SFAS No. 133 - derivative instruments, respectively. In the 2001 quarter, the $25 million of other operating income was due to the Utah rate order that successfully resolved the issues surrounding previously excluded costs and resulted in the establishment of a $25 million regulatory asset.

Purchased power expense was $768 million, an increase of $104 million, or 16%. Higher prices on short-term firm and spot market purchases increased purchased power expense by $207 million. Offsetting this increase was the effect of deferred accounting treatment of $132 million for power costs that vary from costs included in current rates. Short-term firm and spot market purchase prices averaged $152 per MWh in 2002, a 43% increase from the average price of $106 per MWh in 2001. In addition, higher prices on long-term firm contracts added $20 million to purchased power expense. Increased usage of transmission systems owned by third parties added $7 million and Demand Side Management costs added $56 million to expense. The Company estimates that current customer participation in the Demand Side Management programs has resulted in a load curtailment of approximately 876,000 MWhs for the second quarter of 2002. Partially offsetting these increases in expense was a 7% decrease in short-term firm and spot market purchase volumes, which decreased costs by $38 million, and a 20% decrease in purchase volumes relating to long-term firm contracts, which decreased costs by $15 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.

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Fuel expense increased $6 million, or 5%, to $129 million primarily due to increased thermal generation at higher cost plants.

Other operations and maintenance expense was $133 million in both 2002 and 2001. In 2002, the Company leased a new generating turbine that added $11 million to expense. The level and timing of capital projects and related expenditures resulted in a $12 million decrease.

Depreciation and amortization expense increased $2 million, or 2%, to $100 million primarily due to increased plant in service.

Administrative and general expenses increased $26 million, or 80%, to $59 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 $14 million increase in expense. Increased use of external service providers, primarily on strategic and risk initiatives, added $5 million to expense. The sale of the Australian electric operations segment in the prior year resulted in an unfavorable variance due to $1 million of expenses that were billed to the segment in the prior year. In addition, property insurance premiums increased by $1 million in 2002.

Taxes other than income taxes decreased $3 million, or 15%, to $19 million primarily due to lower property tax expense resulting from the favorable resolution of outstanding property tax appeals.

The unrealized loss on SFAS No. 133 - derivative instruments, in the 2002 quarter pertains to the increase in accrued liabilities relating to contracts settled in the second quarter, as well as the Company's short-term sales obligations, which are marked to market, being unfavorably impacted by lower forward market prices that resulted from the significant changes in market fundamentals. See "Note 10 of the Notes to Condensed Consolidated Financial Statements" for information regarding SFAS No. 133.

The $25 million recorded as other operating income in the 2001 quarter pertained to a Utah rate order that successfully resolved the issues surrounding previously excluded costs and resulted in the establishment of a $25 million regulatory asset.

Other (Income) Expense - Net

Other (income) expense - net was $3 million of net income in the second quarter of 2002, a $5 million favorable variance from the second quarter of the prior year. In the second quarter of 2001, the Company recorded $9 million relating to merger costs. Partially offsetting this favorable variance was lower interest income and a decrease in emission allowance sales in 2002.

Interest Expense

Domestic electric operations interest expense decreased $9 million primarily due to lower debt balances.

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Income Tax (Benefit) Expense

Income tax expense decreased $36 million principally due to the lower taxable income in the current quarter. Domestic electric operations accrued federal and state tax benefit of $21 million for the second quarter of 2002 on an operating loss before taxes compared to tax expense of $15 million on an operating profit before taxes for the second quarter of 2001. The effective tax rate for the second quarter of 2002 was 46% compared to 38% for the second quarter of 2001. For a reconciliation of the total income tax expense to the statutory federal income tax expense, see "Note 8 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 $279 million, representing a $46 million increase from the prior year. Excluding the $150 million favorable impact during the first half of 2002 of applying SFAS No. 133, Domestic electric operations' operating profit before interest and taxes was $129 million, or a decrease of $104 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. While prices have collapsed in the second quarter of 2002, the Company continues to experience high purchase 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. While higher market prices contributed to increasing wholesale sales to $1.24 billion in 2002, a $428 million increase over 2001, this increase was more than offset by purchased power costs of $1.5 billion (net of $175 million deferred for costs that vary from costs included in current rates), representing a $506 million increase over 2001. Partially offsetting this increase in purchased power costs was $85 million in increased revenues due to retail price increases, a slight increase in residential and commercial volumes and higher wheeling revenues. Domestic electric operations had a $61 million, or 16%, increase in other operations, maintenance, administrative and general costs and taxes other than income taxes.

Revenues

Total Domestic electric operations revenues increased $513 million, or 26%, to $2.5 billion in 2002. This increase was primarily attributable to increases in wholesale sales of $428 million.

Residential revenues increased $23 million, or 6%. Growth in the average number of residential customers of 2% added $6 million to revenues. Price increases in Oregon, Utah and Wyoming added $18 million to revenues in 2002. Decreases in average usage of residential customers decreased residential revenues by $2 million.

Commercial revenues increased $23 million, or 7%. Price increases in Oregon, Utah and Wyoming added $9 million to revenues in 2002. Growth in the average number of commercial customers of 2% added $9 million to revenues and volume increases of 3% added $5 million to revenues.

Industrial revenues were comparable to the prior year. Price increases in Oregon, Utah and Wyoming added $19 million to revenues. Partially offsetting this increase was a reduction of 5% in energy volumes sold that resulted in $16 million in lower revenue, and decreased irrigation usage that lowered revenues by $3 million.

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Wholesale sales revenues increased $428 million, or 52%. Sales prices for short-term firm and spot market sales averaged $149 per MWh in 2002, an increase from the average of $80 per MWh in 2001, resulting in a $448 million increase in revenues. A 4% increase in short-term and spot market sales volumes drove a $50 million increase in revenues. Long-term firm contract sales averaged $43 per MWh in 2002, an increase from the average of $38 per MWh in 2001, resulting in a $28 million increase in revenues. Partially offsetting these increases was the impact of the expiration of long-term firm sales contracts that drove a 35% decrease in long-term firm contract volumes and lowered wholesale revenues by $98 million in 2002.

Other revenues increased $37 million, or 63%, primarily due to an increase in wheeling revenues from increased usage of the Company's transmission system by third parties.

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

Operating Expenses

Total Domestic electric operating expenses increased $467 million, or 26%, to $2.24 billion in 2002. This increase was primarily attributable to increased purchased power expense due to increased prices on short-term firm and spot market purchased power and higher prices paid for forward purchases of short-term firm and spot market power delivered during the period. Partially offsetting this expense increase was a reduction in operating expenses of $150 million for the first half of 2002 resulting from the application of SFAS No. 133.

Purchased power expense was $1.5 billion, an increase of $506 million, or 51%. Higher prices on short-term firm and spot market purchases increased purchased power expense by $509 million. The increase is net of the effect of deferred accounting treatment of $175 million for power costs that vary from costs included in current rates. Short-term firm and spot market purchase prices averaged $157 per MWh in the first half of 2002, a 96% increase from the average price of $80 per MWh in 2001. In addition, higher prices on long-term firm contracts added $42 million to purchased power expense. Increased usage of transmission systems owned by third parties added $15 million and Demand Side Management costs added $71 million to expense. The Company estimates that current customer participation in the Demand Side Management programs has resulted in a load curtailment of approximately 1,559,000 MWhs for the first half of 2002. Partially offsetting these increases in expense was a 9% decrease in short-term firm and spot market purchase volumes, which decreased costs by $89 million, and an 18% decrease in purchase volumes relating to long-term firm contracts, which decreased costs by $42 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.

Fuel expense increased $17 million, or 7%, to $246 million primarily due to increased thermal generation at higher cost plants.

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Other operations and maintenance expense increased $20 million, or 8%, to $282 million. In 2002, the Company leased a new generating turbine that added $18 million to expense. The levels and timing of capital projects and related expenditures resulted in a $9 million decrease. Other employee related expenses increased $2 million. In addition, tree trimming costs increased by $3 million in 2002.

Depreciation and amortization expense increased $5 million, or 2%, to $198 million primarily due to increased plant in service.

Administrative and general expenses increased $44 million, or 62%, to $116 million. Amortization of deferred transition costs allowed by state regulators and amortization of regulatory assets reestablished in 2001 under a Utah rate order contributed $10 million and $3 million, respectively, to the increase. Employee related expenses increased $4 million, primarily due to the effect of a favorable return on pension plan assets on pension expense in the prior year. In 2002, the proportion of expenditures capitalized fell from the levels capitalized in the prior year, which resulted in a $19 million increase in expense. Increased use of external service providers, primarily on strategic and risk initiatives, added $4 million to expenses. The sale of the Australian electric operations segment in the prior year resulted in an unfavorable variance due to $2 million of expenses that were billed to the segment in the prior year. In addition, property insurance premiums increased by $1 million in 2002.

Taxes other than income taxes decreased $3 million, or 7%, to $43 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 six months ended September 30, 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 10 of the Notes to Condensed Consolidated Financial Statements" for information regarding SFAS No. 133.

The $28 million recorded as Other operating income in the first half of 2001 represented 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 $42 million regulatory asset. Second, the Company recorded a loss of $14 million on the sale of the Centralia Power Plant and mine. 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.

Other Income - Net

Other income - net was $2 million in the first half of 2002, a net change of $1 million from the net income of $3 million in the prior year. In 2001, the Company recorded $9 million relating to merger costs. Partially offsetting this favorable variance was lower interest income and a decrease in emission allowance sales in 2002.

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Interest Expense

Domestic electric operations interest expense decreased $19 million primarily due to lower debt balances.

Income Tax Expense

Income tax expense increased $21 million principally due to the higher taxable income in the current year. The effective tax rate for the first half of 2002 was 40% compared to a 44% effective tax rate for the first half of 2001. This decline in the effective tax rate resulted primarily from higher taxes in 2001 due to differences between book and tax depreciation. For a reconciliation of the total income tax expense to the statutory federal income tax expense, see "Note 8 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 its ownership 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 April 1, 2000 to the date of sale are included in the Company's financial results for the quarter ended September 30, 2000. Australian electric operations' financial results for the period from January 1, 2000 to the date of sale are included in the Company's financial results for the six months ended September 30, 2000.

Comparison of the three months ended September 30, 2001 and 2000

Comparison of the six months ended September 30, 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 September 30, 2001 and 2000

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

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

Other operations reported losses of $6 million in 2002 compared to income of $21 million in 2001.

In 2002, Other operations' earnings contribution decreased $26 million compared to 2001. Decreased production volumes drove a $7 million reduction in revenues and tax credits in the synthetic fuel operations owned by subsidiaries of PFS until their sale on October 15, 2001. See "Note 7 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 $5 million. Increased interest income of $1 million in 2002 was principally due to interest earned on affiliated notes receivable. See "Note 3 of the Notes to Condensed Consolidated Financial Statements" for additional information on related party transactions. Interest expense in 2002 decreased $2 million due to repayment of debt balances in 2001. 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 "Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations - Discontinued Operations." Other - net also includes $13 million of tax expense relating to reevaluation 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 8 of the Notes to Condensed Consolidated Financial Statements."

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

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

(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 $5 million in 2002 compared to income of $47 million in 2001.

In 2002, Other operations' earnings contribution decreased $42 million compared to 2001. Decreased production volumes drove an $11 million reduction in revenues and tax credits in the synthetic fuel operations owned by subsidiaries of PFS until their sale on October 15, 2001. See "Note 7 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 income in 2002 increased $3 million compared to 2001 principally due to interest earned on affiliated notes receivable. See "Note 3 of the Notes to Condensed Consolidated Financial Statements" for additional information on related party transactions. 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 $5 million lower in 2002 due to collection, in June 2001, of a contingent note receivable held by Holdings. See "Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations - Discontinued Operations." Other - net also includes $21 million of tax expense relating to reevaluation 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 8 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 has recognized this gain on a cost recovery basis as payments have been 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 six months ended September 30, 2001:

OPERATING ACTIVITIES

Net cash flows used in operating activities were $100 million during the period compared to net cash flows provided by operating activities of $434 million in the 2001 period. This $534 million decrease in operating cash flows was primarily attributable to higher purchased power costs (including those amounts deferred) that were not recovered through current regulated rates, combined with lower federal taxes payable and accounts payable in 2002. This adverse cash flow for accounts payable and accrued liabilities, in 2002, was partially offset by a favorable cash inflow for accounts receivable.

INVESTING ACTIVITIES

Capital spending totaled $209 million in 2002 compared with $222 million in 2001. Construction expenditures decreased in 2002 primarily due to lower expenditures at Domestic electric operations. Proceeds from asset sales in 2002 represented additional proceeds received relating to the disposal of Australian electric operations. Proceeds from sales of finance assets and principal payments were $39 million. Included in that amount was $35 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 4 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 the ScottishPower note receivable in 2002 represents the repayment of the entire note balance. The changes in debt due from affiliates in 2002 are the result of activities of a subsidiary of the Company with PHI and its 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 to replace facilities that were set to expire in August 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.

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On November 1, 2000, the Company filed the unbundling information required under Oregon Senate Bill 1149 ("SB 1149") rules and requested a related $160 million in increased revenues. On March 8, 2001, the Company and OPUC staff signed a partial stipulation that settled the majority of issues raised by OPUC staff and reduced the Company's requested increase by $19.5 million. After four rounds of testimony, the Company amended its requested increase to approximately $103 million. On September 7, 2001, the OPUC granted final rate relief in the amount of $64.4 million, effective September 10, 2001.

Rate Increases Submitted for Regulatory Approval:
On March 16, 2001, the Company filed a request with the California Public Utilities Commission ("CPUC") for an interim increase in electricity prices for its customers in California. If approved by the CPUC, the request would increase prices about 13.77% overall, or $7.4 million. On July 16, 2001, the Office of Ratepayer Advocates and other intervenor groups filed testimony opposing the increase. On August 7, 2001, the Company filed rebuttal testimony. Hearings regarding the interim increase were held on August 22-23, 2001 and briefs were filed in September 2001. A decision from the CPUC on the interim rate increase is pending.

On January 12, 2001, the Company filed a request with the UPSC for an increase in electricity prices for its customers in Utah. This request encompassed normalized power costs that vary from the level assumed in Utah rates based on the twelve months ended September 30, 2000 test year and did not include those power cost variances associated with the Hunter outage. The request would have increased prices by approximately 19.1% overall, or $142 million. On July 12, 2001, the Company agreed to reduce its request to an increase of $118 million. Concurrent with the initial filing, the Company filed a separate emergency petition for interim relief. On February 2, 2001, the Commission granted an interim rate increase of $70 million, effective February 2, 2001. The $70 million interim rate increase was subject to refund if the final rate order did not provide for at least that level of recovery. On September 10, 2001 the UPSC granted the Company a $40.5 million revenue increase. This decision sets new revenues about 5.1% higher than previous levels. The rate increase is $29.5 million lower annually than the annual $70 million interim rate increase granted in February 2001. On November 2, 2001, the UPSC issued an order allowing the Company to continue collecting the $29.5 million of revenue, subject to a prudence review, as an offset to deferred excess power costs related to Hunter 1 replacement and other excess power costs.

Deferred Power Cost Filings:
The Oregon deferred accounting filing encompassed all power costs that vary from the level in Oregon rates since November 1, 2000, including costs to replace lost generation resulting from the Hunter outage. On January 18, 2001, the Company requested a 3%, or $23 million, rate increase effective February 1, which would provide partial recovery of post-October 31, 2000 power cost variances attributable to Oregon over an amortization period. This 3% rate increase was the maximum allowed for deferred costs under the Oregon statutes. On January 23, 2001, the OPUC authorized deferred accounting for power costs of $23 million. On February 20, 2001, the OPUC authorized the 3% 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. Two subsequent OPUC orders to establish the mechanism to

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determine the amount of power costs to defer have been appealed to the Marion County Circuit Court in separate complaints for judicial review filed on October 1, 2001. The appeals have been consolidated. The appeals could take up to 12 months.

In its September 7, 2001 order, the OPUC endorsed an agreement on deferral of net power costs after September 2001. The agreement specifies that until May 2002 the Company will defer the difference between 83% of actual net power costs and the new Oregon baseline power cost in tariffs. The agreement allows for a potential base rate reset effective January 1, 2002 based on a review of expected power cost deferrals after three months of operation under the power cost recovery mechanism. The agreement also allows the Company to apply to reset the level of ongoing power costs in the rates after May 2002 and allows the Company to propose a permanent power cost recovery mechanism.

The Company filed with the OPUC on September 21, 2001 to increase the level of recovery of excess net power costs incurred to serve Oregon customers from the current 3% level, or $22.8 million awarded in February 2001, to 6%. The OPUC was asked to make a ruling on whether the Company has met the requirements of a state statute that allows for this recovery. Previously capped at 3% of a company's gross revenues for the prior calendar year, the statute was amended last July and now allows up to 6% recovery. The filing would result in an additional $22.8 million, or 3% overall increase in customers' bills, to be effective October 23, 2001. (Since February 21, 2001, customers have been paying a surcharge at this level). The total level being recovered would thus increase to $45.6 million, or 6% overall. In its public meeting on October 22, 2001, the OPUC suspended the Company's request pending the outcome of the prudence phase of the proceeding. That phase of the proceeding is scheduled to be completed in March 2002. Upon completion of the prudence review, the Company will renew its request to increase the amortization level to 6%.

In Wyoming, following on from the November 1, 2000 filing for deferred accounting treatment of net power costs that vary from costs included in determining retail rates, the Company is proposing recovery of $47 million of deferred excess power costs, incurred through June 2001, over a 12-month period. In August 2001, the Company sought interim relief of $21 million, which was denied by the WPSC on September 21, 2001. On October 15, 2001, intervenors filed testimony recommending adjustments that would reduce the Company's calculated excess purchased power costs by $68.9 million and result in an over-recovery of $21.5 million for the November 30, 2000 through June 30, 2001 period. On October 22, 2001, the Wyoming Consumer Advocate Staff filed testimony opposing the implementation of a purchased power cost adjustment and supporting many of the adjustments recommended by the intervenors. This matter is scheduled to go to hearing in November 2001. Additional filings will be made to seek recovery of the balance of the deferred account after this hearing.

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 $104 million in replacement power costs over a 12-month period. The Hunter unit returned to service in early May 2001. Hearings are set for January 2002.

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In Utah on September 21, 2001, the Company filed for permission to defer $109 million of excess net power costs above the level adopted in the Company's last general rate case for the period May 9, 2001 through September 30, 2001.

Regional Transmission Organization ("RTO"):
The Company, in conjunction with nine other utilities, is progressing in its effort to form an RTO, ("RTO West"), in support of FERC Order 2000. The 10 members of RTO West will be Avista Corporation, BC Hydro, BPA, Idaho Power Company, Montana Power Company, Nevada Power Company, PacifiCorp, Portland General Electric Company, Puget Sound Energy, Inc. and Sierra Pacific Power Company. Creation of RTO West is subject to regulatory approvals from the FERC and the states served by these entities. RTO West plans to operate all transmission facilities needed for bulk power transfers and control the majority of the 60,000 miles of transmission lines owned by the entities. The members of RTO West continue to make progress on development of the elements of the detailed filing due to the FERC on March 1, 2002. The FERC considers RTO West to be the platform for the west with regard to its stated goal of an eventual western United States-wide RTO that would encompass all of the western states.

Demand Side Management:
In response to the volatility in western power markets, the Company continued to offer its Energy Exchange programs in Oregon, Washington, Utah, Idaho and Wyoming. These programs are an optional, supplemental service that allows participating customers an opportunity to voluntarily reduce their electricity usage in exchange for a payment at times and at prices determined by the Company. Revisions to the program now allow participation from customers as small as one megawatt.

In the fourth quarter of fiscal 2001 and the first quarter of fiscal 2002, the Company filed and received regulatory approval to implement voluntary curtailment programs for irrigation customers in Oregon, Washington, Idaho and Utah.

The Company filed for and received approval of the Customer Challenge program for residential customers in all states it serves. Incentives under the program provided a 10% credit to all Oregon, Washington, Idaho, Wyoming and Utah customers who reduced their monthly kilowatt hour ("kWh") usage by 10% from the corresponding month one year ago for the months of July through September. In addition, a 20% credit was applied to all Oregon, Washington, Idaho, Wyoming, California and Utah customers who reduced their monthly kWh usage by 20% from the corresponding month one year ago for the months of June through September.

Structural Realignment Proposal:
On June 29, 2001, the Company completed its filings of a Structural Realignment Proposal ("SRP") with the utility commissions in Oregon, Utah, Wyoming, Washington and Idaho. A similar filing is planned for California. The proposed plan would change the Company's legal and regulatory structure and

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result in the creation of six state electric companies, a generation company that also holds transmission assets and a service company, all subsidiaries of a new holding company. The proposal is designed to provide a permanent allocation of generation benefits and costs among states that will allow each to pursue the regulatory policies it deems appropriate without affecting customers in other states or treating shareholders unfairly. Approval for this proposal must be obtained from the utility commissions in Oregon, Utah, Wyoming, Washington, Idaho and California, as well as from the FERC and the Securities and Exchange Commission ("SEC"). Commission decisions regarding the conceptual proposal are targeted for the second quarter of fiscal year 2003. Additional proceedings to receive approval of specific contracts and tariffs would follow.

Deregulation:
During 1999, SB 1149 was enacted in Oregon requiring competition for industrial and large commercial customers of both the Company and Portland General Electric Company by October 1, 2001. SB 1149 authorizes the OPUC to make decisions on a variety of important issues, including the method for valuation of stranded costs/benefits. The Company continues to participate in the OPUC proceedings to establish the rules and procedures that will implement the new law. On July 1, 2001, the Oregon Legislature approved, and the governor signed into law, a set of amendments that delay implementation of SB 1149 until March 1, 2002 and require the Company to provide all customers with a cost-of-service rate option for an indefinite period. There is no provision for the OPUC to delay implementation past that date. Beginning July 1, 2003, the OPUC may waive the cost-of-service rate option for classes of customers if the OPUC finds that retail markets are functioning properly. The Company has begun collection of implementation costs that were incurred through March 31, 2001 and will commence the recovery of additional implementation costs on March 1, 2002. The Company collects interest on the balance until prudently incurred costs are fully recovered.

In February 2001, the Company made its resource plan supplemental filing under SB 1149. This filing addressed the potential rate impacts and transition charges and credits associated with implementation of the resource plan options. The supplemental filing also proposed that the preferred plan for implementing direct retail access in Oregon would involve the SRP restructuring proposals. The Commission had adopted a temporary rule extending the decision date on the resource plan from April 1, 2001 to September 1, 2001. Current rules under consideration by the Commission would extend the initial decision date on the resource plan to December 31, 2002. If those rules are adopted, the Company would file an updated resource plan by May 1, 2002.

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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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