PACIFICORP /OR/ - Quarter Report: 2001 June (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)  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 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 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

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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.

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 the quarter by a $718 million unrealized after-tax loss. This $718 million after-tax change was comprised of an unrealized after-tax loss of $526 million representing the decrease in market values of hedges and $192 million representing a decrease as the underlying contracts were settled. A corresponding $192 million decrease to the SFAS No. 133 deferred asset was recorded and there was no net effect on current earnings.

As of June 30, 2001, the Company anticipated that approximately $120 million, $74.5 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 decrease to the SFAS No. 133 liability would 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 will allow the normal purchase normal sales ("NPNS") exception 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 regarded 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 is in the process of evaluating all existing contracts that will be exempt from SFAS No. 133 upon implementation of C-15.

New Standard Issued

In June 2001, the FASB voted to issue SFAS No. 143, "Accounting for Asset Retirement Obligations." 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 financial statements.

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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.  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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*Not a meaningful number.

(1)  Earnings (loss) contribution on common stock 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 preferred dividend requirements and minority interest (which is reported as a component of Other income - net).

The Company recorded earnings on common stock of $194 million in the first quarter of 2002 compared to a loss of $139 million in the first quarter of 2001.

Domestic electric operations earnings contribution was $122 million, an increase of $94 million compared to the first quarter of 2001. The impact of applying SFAS No. 133 for the quarter ended June 2001 resulted in a reduction in operating expenses of $178 million pretax ($111 million after-tax). (This reflects the effect in the quarter of the change in market value of derivatives. Upon adoption of SFAS No. 133 on April 1, 2001, the difference between cost and market value of derivatives was a loss of $182 million pretax

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($113 million after-tax) that was recorded in cumulative effect of accounting change as 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 2002 quarter of implementing SFAS No. 133 and recording the changes in market value of derivatives was a loss of $4 million pretax ($2 million after-tax).

The $178 million operating expense reduction resulting from the changes in market value of derivatives was offset by the Company continuing to experience high purchased power costs. The purchased power prices reflected the imbalance of supply and demand.

In 2001, the Company completed the sale of Australian electric operations. The loss of $193 million in 2001 was due primarily to an impairment loss recorded on the anticipated 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 $11 million in the 2002 quarter compared to $26 million in the 2001 quarter. This decrease was primarily attributable to a benefit recorded in 2001 relating to the foreign currency swaps associated with the Company's investment in Australian electric operations.

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DOMESTIC ELECTRIC OPERATIONS

Overview

Generally, during the first quarter of fiscal 2002, the western United States continued to experience short-term firm and spot market power prices that were higher than historic prices. Efforts have been made to stabilize the western power market, including a wholesale price mitigation plan imposed by the Federal Energy Regulatory Commission ("FERC") in 11 western states, conservation efforts, construction of new generating facilities, and increased generating capacity from existing plants. The Company's 430 megawatt ("MW") Hunter unit, which went out of service on November 24, 2000, returned to service in early May 2001. While these factors have had some impact on the western power market, the Company, in balancing its load requirements, continued to purchase power at prices higher than it can currently recover through regulated rates.

In an effort to mitigate the discrepancy between prices paid and revenues received, 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 quarter of 2002, the Company deferred $43 million (plus carrying costs of $2 million) under these orders. In total, the Company has $178 million of deferred power costs (including carrying costs of $3 million and net of amortization of $8 million). The Company has received an order to recover $23 million and is working with state commissions to seek recovery of the remaining amounts.

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 California Independent Systems Operator ("the California ISO") will determine these price limits 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. 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 ultimate impact these price mitigation controls will have on the supply and demand balance in the region, and hence the impact on market prices cannot be determined at this time.

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

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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 Company's exposure to refunds will be dependent upon any order issued by the FERC in response to the ALJ's recommendations. 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.

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.

Due to the higher cost of peak-time power, an objective of the Company is to manage load and resources such that excess power in off-peak demand periods can be sold into the market to fund power purchases required for peak demand periods. Recently, in light of transmission constraints and energy shortage risks, the Company took measures to mitigate the risk of power shortages during the summer months. This included entering into contracts to purchase power for the summer months to ensure adequate resources to meet load requirements and provide some reserves to offset the risk of any generation outages. In June 2001, because of changes in market fundamentals, including the implementation of FERC mandated price mitigation controls, the forward prices of energy have dropped dramatically and the relative value of off-peak power has dropped significantly when compared to on-peak power.

With the current lower forward prices, any committed power purchases that the Company does not need would result in sales into the short-term spot market for amounts substantially less than the Company's cost. Additionally, the spread of on-peak to off-peak power prices has increased, thereby eroding the relative value of the Company's off-peak excess power resources. However, volatility in market prices and demand, along with fluctuations in the FERC price mitigation controls, can significantly impact future results. The Company intends 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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Summary of Results

Domestic electric operations had operating profit before interest and taxes of $270 million, representing a $140 million increase from the prior year. Excluding the $178 million favorable impact during the quarter of applying SFAS No. 133, Domestic electric operations' operating profit before interest and taxes was $91 million, or a decrease of $38 million from the prior year. During the 2002 quarter, the Company, along with other Western Systems Coordinating Council ("WSCC") companies, experienced continued high short-term firm and spot market purchased power prices due to the imbalance of supply and demand in the region. For a discussion of the factors affecting the market price of power, see "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 these

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higher market prices contributed to increasing wholesale sales to $657 million in 2002, a $367 million increase over 2001, this was more than offset by purchased power costs for wholesale and retail sales of $735 million, representing a $402 million increase over 2001. Partially offsetting this increase in purchased power costs was $58 million in increased revenues due to retail price increases, a slight increase in retail volumes and higher wheeling revenues. Domestic electric operations had a $49 million, or 18%, increase in other operations, maintenance, administrative and general costs. The increase primarily resulted from $11 million of increased fuel expense, $11 million related to increased amounts of work in 2002 related to expense rather than capital projects, $8 million of lease costs in 2002 related to a new generating turbine, $3 million related to the effect on pension expense in 2001 of a favorable return on pension plan assets and $7 million of amortization expense in 2002 not present in the 2001 quarter. The amortization expense related to deferred transition costs established in the first quarter of 2001 and amortized in subsequent quarters.

Revenues

Total Domestic electric operations revenues increased $425 million, or 50%, to $1.27 billion in 2002. This increase was primarily attributable to increases in wholesale sales of $367 million, a $37 million increase in retail revenues and a $22 million increase in other revenues, primarily due to wheeling revenues.

Residential revenues increased $14 million, or 8%. Growth in the average number of residential customers of 2% added $3 million to revenues. Price increases in Oregon, Utah and Wyoming added $10 million to revenues in 2002. Volume increases of 2%, primarily due to weather, increased residential revenues by $2 million.

Commercial revenues increased $14 million, or 8%. Price increases in Oregon and Utah added $7 million to revenues in 2002. Growth in the average number of commercial customers of 2% added $5 million to revenues and volume increases of 4% added $2 million to revenues.

Industrial revenues increased $8 million, or 4%. Price increases in Oregon, Utah and Wyoming added $19 million. Partially offsetting this increase was a reduction of 4%, or $6 million, relating to lower energy volumes and decreased irrigation usage that lowered revenues by $5 million.

Wholesale sales revenues increased $367 million, or 126%. Sales prices for short-term firm and spot market sales averaged $189 per megawatt hour ("MWh") in 2002, an increase from the average of $48 per MWh in 2001, resulting in a $423 million increase in revenues. Long-term firm contract sales averaged $43 per MWh in 2002, an increase from the average of $36 per MWh in 2001, resulting in a $19 million increase in revenues. Partially offsetting these increases was a $31 million decrease resulting from lower short-term firm and spot market volumes. In addition, decreased long-term firm contract volumes lowered wholesale revenues by $45 million in 2002. Total sales volumes declined 1.6 million MWhs from 2001 levels. The termination of long-term firm sales contracts was the primary cause of 1.1 million MWhs of the total

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decrease. This available power, no longer committed for contracts, was used to cover increased load demand that had previously been served through short-term market purchases.

Other revenues increased by $22 million, or 79%, 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 $278 million, or 38%, to $1.0 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. Partially offsetting this adverse variance was a reduction in operating expenses of $178 million for the 2002 quarter resulting from the implementation of SFAS No. 133.

Purchased power expense was $735 million, an increase of $402 million, or 120%. Higher prices on short-term firm and spot market purchases increased purchased power expense by $436 million. The increase is net of the effect of deferred accounting treatment of $43 million for power costs that vary from costs included in determining rates. Short-term firm and spot market purchase prices averaged $165 per MWh in 2002, an increase from the average of $50 per MWh in 2001. In addition, higher prices on long-term firm contracts added $8 million to purchased power expense. Increased usage of transmission systems owned by third parties added $8 million and Demand Side Management costs added $22 million to expense. The Company estimates that current customer participation in the Demand Side Management programs has resulted in a load curtailment of approximately 683,000 MWhs for the first quarter of 2002. Partially offsetting these increases in expense was an 11% decrease in short-term firm and spot market purchase volumes, which decreased costs by $52 million, and a 15% decrease in purchase volumes relating to long-term firm contracts, which decreased costs by $22 million. The decreases in volume relate 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.

Total other operations and maintenance expense increased $31 million, or 13%, to $266 million. In 2002, fuel expense increased $11 million primarily due to increased thermal generation at higher cost plants. In 2002, the Company leased a new generating turbine that contributed $8 million in expense. Labor expenses increased by $6 million resulting principally from an increased amount of work relating to expense rather than capital projects. In addition, tree trimming costs increased by $2 million, in 2002.

Depreciation expense increased by $2 million, or 2%, to $99 million primarily due to increased plant in service.

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Administrative and general expenses increased $18 million, or 47%, to $57 million. Amortization of deferred transition costs allowed by state regulators and amortization of regulatory assets reestablished in 2001 under a Utah rate order contributed $7 million and $3 million, respectively, to the increase. Employee related expenses increased $3 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 further increase of $5 million in expense.

The unrealized gain on SFAS No. 133 - derivative instruments, in the 2002 quarter relates to the Company's short-term sales obligations being favorably impacted by lower forward 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 $3 million recorded as Other operating income in the 2001 quarter 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 $17 million regulatory asset. Second, the Company recorded a one-time 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 Expense (Income) - Net

Other expense (income) - net was $1 million of net expense in the first quarter of 2002, a net change of $6 million from the net income of $5 million in the prior year. This decrease in income was primarily due to lower interest income in 2002 and a favorable adjustment to the cash surrender value of life insurance policies in 2001.

Interest Expense

Domestic electric operations interest expense decreased $10 million primarily due to lower debt balances.

Income Tax Expense

Income tax expense increased $57 million principally due to the higher taxable income in the current year. The effective tax rate for the first quarter of 2002 was 41% compared to a 49% effective tax rate for the first quarter of 2001. This decline in the effective tax rate resulted primarily from higher taxes in 2001 related to differences between book and tax depreciation on the Centralia plant that was sold in May 2000. 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 2001, 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 quarter ended March 31, 2000 are included in PacifiCorp's financial results for the quarter ended June 30, 2000. For the purpose of this discussion, these financial results are referred to as "June 30, 2000" results.

Comparison of the three-month periods ended June 30, 2001 and 2000

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OTHER OPERATIONS

Comparison of the three-month periods ended June 30, 2001 and 2000

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

(b)  This item reflects a tax rate of approximately 46% as foreign currency exchange rate adjustments resulted in an increased tax liability.

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

*Not a meaningful number.

Other operations reported income of $11 million in 2002 compared to income of $26 million in 2001.

In 2002, Other operations' earnings contribution decreased $15 million compared to 2001. This decrease was primarily attributable to the $15 million gain relating to foreign currency swaps recorded in 2001 associated with the Company's investment in Australian electric operations. An additional decrease resulted from a reduction in revenues and tax credits of $6 million as a result of decreased production volumes in the synthetic fuel operations owned by subsidiaries of PFS. Interest income in 2002 increased $2 million compared to 2001 principally due to interest earned on notes receivable from directly owned subsidiaries of ScottishPower. Interest expense in 2002 was negligible 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.

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

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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 three months ended June 30, 2001:

OPERATING ACTIVITIES

Net cash flows provided by operating activities were $58 million during the period compared to $228 million in the first quarter of 2001. This $170 million decrease in operating cash flows was primarily attributable to higher purchased power prices included in net income that were not currently recovered through 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 $107 million in 2002 compared with $116 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 $43 million. Included in that amount was $35 million for aircraft sold by subsidiaries of PFS. Proceeds, of $190 million, from the 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 Centralia plant and mine.

The changes in debt due from affiliates in 2002 are the result of the Company's activities with PHI and its subsidiaries. In 2001, activities with PHI subsidiaries were eliminated in consolidation, as those subsidiaries were owned by the Company.

FINANCING ACTIVITIES

The Company's borrowings and 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.

On May 21, 2001, the Company declared a dividend on common stock of $80 million payable to ScottishPower, the sole common shareholder of record. The Company had $138 million of declared dividends on common stock payable at June 30, 2001.

On May 21, 2001, the Company also declared dividends of $4 million on preferred stock, which was unpaid at June 30, 2001. This dividend is scheduled to be paid on August 15, 2001.

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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 will be held the week of August 20, 2001.

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. If approved, 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 is subject to refund if the final rate order does not provide for at least that level of recovery. The amended request is pending approval by the UPSC, with a decision anticipated in September 2001.

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 moderated its requested increase to approximately $103 million. OPUC Staff is presently recommending a decrease of approximately $20 million. Hearings were held on May 29-31, 2001 and June 7, 2001 and a presentation was made before the Commission on July 5, 2001. The Company anticipates an order on the revenue requirement phase of this proceeding in August 2001. The Company filed testimony on a Power Cost Adjustment as part of this docket on June 15, 2001 and a hearing on this issue is scheduled for September 2001.

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. The Company had deferred the $23 million as of March 31, 2001. On February 20, 2001, the OPUC authorized the 3% rate increase effective February 21, 2001. On May 11, 2001, the OPUC ordered a continuation of the deferral of a portion of net power costs varying from the level in Oregon rates. Costs subject to deferral are those that exceed a stipulated

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range for net power costs. Outside this range, a portion of these costs are deferred based on ratios to be established. The Company, OPUC Staff and intervenors filed briefs on June 11, 2001 on the level of the baseline around which the range mechanism will operate. Power costs for Oregon operations that vary from amounts in rates are being recognized in the Company's income statement pending resolution of this new deferral mechanism. In July 2001, the Oregon Legislature raised the 3% maximum annual recovery to 6%. The Company will be required to file a new application with the OPUC to increase the annual recovery from 3% to 6%.

In Wyoming, pursuant to its 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 a purchased power cost adjustment. Through this mechanism, the Company is proposing to recover $46 million of deferred excess power costs over a 12-month period. This matter is scheduled to go to hearing in November 2001.

In Utah, pursuant to its November 24, 2000 filing for deferred accounting treatment of replacement power costs resulting from the Hunter No. 1 outage, the Company intends to make a filing within the next 60 days to address the recovery of these deferred costs. While the Company believes recovery is probable, denial of recovery would result in the write-off of part or all of the deferred power costs.

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 December 1, 2001. The FERC considers RTO West to be the platform for the west with regard to its stated goal of an eventual west-wide RTO that would encompass all of the western states.

Demand Side Management:
In response to the volatility in western power markets, the Company received regulatory approval to expand 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 MW.

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.

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The Company filed for and received approval of the Customer Challenge program for residential customers in all states it serves. Incentives under the program provide a 10% credit to all Oregon, Washington, Idaho, Wyoming and Utah customers who reduce 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 will be applied to all Oregon, Washington, Idaho, Wyoming, California and Utah customers who reduce their monthly kWh usage by 20% from the corresponding month one year ago for the months of June through September. The Company believes this program sets clear and simple targets for customers to receive benefits if they conserve energy. The ultimate benefit or cost of this program will depend on customers achieving the targets.

Proposed Restructuring:
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 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"). The regulatory approval process is expected to conclude during the first quarter of fiscal year 2003.

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 will 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 will be unable to commence the recovery of implementation costs until March 1, 2002, but will be able to collect 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

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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. The Company would file an updated resource plan by May 1, 2002.

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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