PACIFICORP /OR/ - Quarter Report: 2000 December (Form 10-Q)

See accompanying Notes to Condensed Consolidated Financial Statements

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See accompanying Notes to Condensed Consolidated Financial Statements

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See accompanying Notes to Condensed Consolidated Financial Statements

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See accompanying Notes to Condensed Consolidated Financial Statements

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For the nine-month period ended December 31, 2000, the Company incurred expenses of $9 million pretax and $5 million after-tax in costs associated with the Merger, which includes recording $12 million in Washington merger credits partially offset by a $3 million adjustment to a previously accrued liability. These merger credits were offsetable against merger savings and created a contingent liability at the Merger date. The August 9, 2000 Washington rate order removed the ability to offset these credits against savings, resulting in recognition of an expense in the second quarter of 2001.

The following table shows where merger costs have been recorded in the Company's financial results.

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 5.  DISCONTINUED OPERATIONS

In October 1998, the Company decided to exit its energy trading business by offering TPC Corporation ("TPC") for sale and ceasing the eastern U.S. electricity trading operations of PacifiCorp Power Marketing ("PPM"). PPM's activities in the eastern United States have been discontinued and all forward electricity trading has been closed. On April 1, 1999, Holdings sold TPC to NIPSCO Industries, Inc. for $150 million. This activity resulted in a net after-tax gain of $1 million in the first quarter of 2000.

 6.  ACCOUNTING FOR THE EFFECTS OF REGULATION

Rate Increase Granted:
On October 25, 2000, the Washington Utilities and Transportation Commission approved the Company's application for a system benefits charge to recover costs associated with funding energy efficiency programs. The Company will collect approximately $2.8 million per year through December 31, 2002.

Rate Increases Submitted for Regulatory Approval:
On December 18, 2000, the Company filed a request with the Wyoming Public Service Commission (the "WPSC") for an increase in electricity prices for its customers in Wyoming. If approved by the WPSC, the request would increase prices about 3.4% overall, or $9 million. The rate resulted from an agreement with the Wyoming Consumer Advocate Staff, in which the Company agreed to limit this request at $8 million plus the effect of any revisions to the Company's depreciation rates that were approved as part of a previous filing with the WPSC. The agreement also called for any rate increase to be effective no sooner than 12 months after the date of the order of the previous case, which was May 25, 2000.

On January 12, 2001, the Company filed a request with the Utah Public Service Commission for an increase in electricity prices for its customers in Utah. This request encompasses power costs in excess of the level assumed in Utah rates since November 1, 2000 and does not include excess costs associated with the Hunter outage. If approved, the request would increase prices by approximately 19.1% overall, or $142 million. Concurrently, the Company filed a separate emergency petition for interim relief asking that the increase become effective January 22, 2001.

Deferred Excess Power Cost Filings:
On November 1, 2000, the Company filed applications seeking deferred accounting treatment for net power costs in excess of costs included in determining retail rates in the states of Utah, Idaho, Wyoming, and Oregon. The applications sought to defer excess power costs beginning November 1, 2000.

Subsequent to the November 1, 2000 filings, the Company's Hunter power plant in Utah experienced a failure of a 430 megawatt ("MW") generation unit. Since the commencement of the outage, the cost of power purchases to replace the output of the Hunter unit has exceeded that unit's costs included in current rates.

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The Utah deferred accounting filing originally encompassed all power costs above the level assumed in Utah rates since November 1, 2000. In light of the Company's January 12, 2001 Utah rate increase request which included recovery of excess power costs not related to the Hunter outage, the Utah deferred accounting filing is expected to be amended to include only excess costs associated with the Hunter outage.

The Oregon deferred accounting filing encompasses all power costs above 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 excess power costs attributable to Oregon over an amortization period. This 3% rate increase is the maximum allowed per state statute. On January 23, 2001, the OPUC authorized deferred accounting for $23 million without an immediate rate increase and scheduled a hearing on February 20, 2001, to consider further deferrals, implementation of a companion rate increase and development of a mechanism for recovery of the deferred costs.

The Idaho deferred accounting filing encompasses all power costs above the level assumed in Idaho rates since November 1, 2000, including costs to replace lost generation resulting from the Hunter unit outage. On January 11, 2001, Idaho Public Utilities Commission (the "IPUC") staff filed comments with the IPUC in support of full deferral of excess power costs for the 12-month period from December 1, 2000 to November 30, 2001.

Approval for deferral of excess power costs was received from the WPSC on November 30, 2000. The Company is currently working with the WPSC to develop a mechanism for recovery of these deferred costs. During the third quarter 2001, $16 million of power costs was deferred, which encompasses all power costs above the level in Wyoming rates since November 30, 2000, including costs to replace lost generation resulting from the Hunter unit outage.

The Company is reviewing its options in Washington, where it agreed to a 5-year rate plan in June 2000, before purchased power costs significantly increased. The Company is looking at ways to reopen that rate plan and either defer, or obtain rate inclusion of, power costs above the level in current Washington rates.

Oregon Senate Bill 1149 ("SB 1149") Filing:
During 1999, legislation was enacted in Oregon that requires competition for industrial and large commercial customers of both the Company and Portland General Electric Company by October 1, 2001. See "Item 1. Business-Domestic Electric Op erations-Competition" in the Company's 2000 Annual Report on Form 10-K. SB 1149 authorizes the OPUC to make decisions on a variety of important issues, including the method for valuation of stranded costs/benefits.

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On October 2, 2000, the Company filed its plans to implement the requirements outlined by SB 1149 and subsequent commission rules. This includes how electricity service suppliers would be certified, customer metering and billing options, and electricity delivery issues. On November 1, 2000, the Company filed the unbundling information required under SB 1149 rules and requested a related $160 million in increased revenues. On December 1, 2000, the Company filed a resource plan to address the manner in which the Company proposes to use its generation resources under SB 1149.

Energy Curtailment:
In December 2000, the Company filed for Pilot Energy Exchange Service programs in Oregon, Washington, Utah, and Wyoming. This is 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. The customer must execute an agreement prior to being allowed to receive service under this program. The Company expects these pilot programs to be an economic alternative to paying higher market prices by reducing the system-wide demand for electricity.

Strategic Regulation Project:
On December 1, 2000, the Company filed requests with the utility commissions in Oregon, Utah, Wyoming, Washington and Idaho to change the way the Company is regulated. 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 distribution companies, a generation company 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 they deem appropriate without affecting customers in other states or treating shareholders unfairly. Approval for these proposals must be obtained from the utility commissions in Oregon, Utah, Wyoming, Washington, Idaho and California, as well as from the Federal Energy Regulatory Commission ("FERC") and the Securities and Exchange Commission ("SEC"). This process is expected to take more than a year.

 7.  CONTINGENT LIABILITIES

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.

 8.  ASSET SALES

On September 6, 2000, the Company completed the sale of its ownership of Powercor pursuant to the August 2, 2000 agreement to sell Powercor and the Company's 19.9% interest in Hazelwood, both indirectly owned subsidiaries of the Company, to Cheung Kong Infrastructure and Hongkong Electric Holdings for approximately AUS $2.4 billion, including repayment or assumption of debt of

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approximately AUS $1.3 billion. Powercor and Hazelwood represent all of the Australian electric operations segment of the Company. Of the estimated $673 million in net sales proceeds, which are subject to final selling expenses and other adjustments, $350 million was lent to a directly owned subsidiary of ScottishPower. The remaining proceeds of $323 million were used to repay debt of the Company. The Company recorded an estimated impairment of $188 million in anticipation of the loss on the sale of the Australian electric operations segment in the first quarter of 2001, which was adjusted in the second quarter of 2001 to $197 million upon the completion of the sale of its indirect ownership of Powercor. The sale of the Company's interest in Hazelwood was completed on November 17, 2000, to National Power Australia Holdings Pty Ltd, a wholly owned indirect subsidiary of International Power plc, for approximately AUS $88 million, which resulted in an additional loss of $1 million in the third quarter of 2001. The $46 million in net proceeds from the sale of Hazelwood was lent to a directly owned subsidiary of ScottishPower.

The loss on sale of Australian electric operations is as follows:

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The Company has an agreement with Nor-Cal Electric Authority ("Nor-Cal") for the sale of the Company's California electric assets for $178 million. The Company does not expect to incur a material gain or loss on this sale. On August 7, 2000, the Administrative Law Judge for the California Public Utilities Commission (the "CPUC") issued a draft decision that would dismiss the Company's application for approval of the sale to Nor-Cal. On December 21, 2000, the CPUC approved the decision to dismiss the application for approval of the sale. The Company is currently in discussion with Nor-Cal to evaluate its options with respect to this sale.

 9.  INCOME TAXES

The Company accrued federal and state income tax expense of $83 million on the loss from continuing operations for the nine months ended December 31, 2000. For the nine months ended December 31, 2000 and 1999, 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 reconciled as follows:

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10.  COMPREHENSIVE INCOME

The components of comprehensive income are as follows:

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- Normal Purchases and Sales: These forward contracts are excluded from the requirements of SFAS No. 133. The realized gains and losses on these contracts are reflected in the income statement at the contract settlement date. The wholesale contracts that generally qualify as normal purchases and sales are long term contracts that are not settled for cash.

- Cash Flow Hedge: The unrealized gains and losses related to these forward contracts will be included in accumulated other comprehensive income, a component of common stockholder's equity. Cash flow hedges are wholesale contracts in the western system where the Company has some generation available for sale and long and short-term purchase contracts to cover probable load that may have been settled for cash.

- Trading Activity: The unrealized gains and losses related to these forward contracts will be reflected in the income statement. The Company's trading activity consists of contracts not classified as normal purchases and sales or cash flow hedges.

Unrealized gains and losses from forward contracts represent the differences between the forward contract prices and the market prices at any given date until the final settlement of the contract. The realized gain or loss on the forward contract recorded at the contract settlement represents the difference between the contract price and actual cost of the commodity that was purchased or sold. When the Company adopts SFAS No. 133 on April 1, 2001, it may have a significant impact on the income statement and a significant impact on accumulated other comprehensive income. The volatility of the wholesale power market, continual changes in the types of forward contracts that the Company has, and certain issues that are still being addressed by the FASB Derivatives Implementation Group ("DIG") may impact the amounts which will be recognized under SFAS No. 133.

As a public utility, the Company will be required under SFAS No. 133 to classify certain of its sales and purchase contracts as derivatives. The Company's intent in entering into these contracts, generally, is to balance its electric load with available resources. When possible, the Company will satisfy its load requirements with electricity from its owned generating facilities. While SFAS No. 133 will require fluctuations in market prices to be reflected in the income statement and accumulated other comprehensive income, the final impact of settling these contracts may be significantly different than represented in interim financial disclosures.

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12.  SEGMENT INFORMATION

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

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year, which was primarily due to increased economic activity and colder than normal weather. The increase in demand, coupled with unexpected plant outages throughout the Western Systems Coordinating Council (the "WSCC"), low hydroelectric conditions and high natural gas prices, created volatility and drove power prices to unusually high levels. In addition, on November 24, 2000, the Company's Hunter power plant in Utah experienced a failure of a 430 MW generation unit that is currently expected to return to service during May 2001. Due to the combined effect of the conditions described above, the Company was required to purchase power at unusually high prices, which resulted in an unfavorable purchased power expense variance. Despite having significantly less excess electricity available to sell into the wholesale market compared to the third quarter of 2000, the higher market prices resulted in higher wholesale revenue. This benefit, combined with the higher retail sales generated from load growth, served to partially offset the unusually high purchased power prices.

Australian electric operations recorded a loss of $1 million in the third quarter of 2001 compared to earnings of $14 million in the 2000 quarter. On September 6, 2000, the Company completed the sale of Powercor and, on November 17, 2000, the Company completed the sale of Hazelwood. See Note 8 to the condensed consolidated financial statements.

Other operations reported a loss of $21 million in the 2001 quarter compared to a loss of $15 million in the 2000 quarter. The current period loss was primarily due to the Company's inability to use alternative fuel tax credits generated by the Company's synthetic fuel operations, partially offset by increased interest income and favorable unregulated energy trading activities. See Note 9 to the condensed consolidated financial statements. The third quarter of 2000 also included merger costs of $3  million after-tax.

Comparison of the nine-month periods ended December 31, 2000 and 1999

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(2)  Represents the discontinued operations of TPC and the eastern United States energy trading activities of PPM.

The Company recorded a loss on common stock of $103 million in the 2001 period compared to a loss of $26 million in the 2000 period. The 2001 results included a loss of $198 million from the sale of Australian electric operations. The 2001 results also included $5 million after-tax in merger costs compared to $202 million in the 2000 period. The results for the 2000 period also included a $15 million after-tax write-off of projects under construction, which were abandoned in the period.

See Note 3 to the condensed consolidated financial statements for a table showing where merger costs have been recorded in the Company's financial results.

Domestic electric earnings contribution increased by $112 million compared to the 2000 period. The 2001 results included $5 million after-tax in merger costs compared to $199 million in the 2000 period. The results for the 2000 period also included the $15 million after-tax write-off of projects under construction. Retail sales volumes increased 4% over last year, primarily due to increased economic activity and hotter than normal weather in the summer months and colder than normal weather in the third quarter. The increase in demand, coupled with unexpected plant outages throughout the WSCC, low hydroelectric conditions and high natural gas prices, drove prices to unusually high levels. In addition, the Company's Hunter power plant experienced a failure as described above. Due to the combined effect of the conditions described above, the Company was required to purchase power at unusually high prices, which resulted in an unfavorable purchased power expense variance. Despite having significantly less excess electricity available to sell into the wholesale market compared to 2000, the higher market prices resulted in higher wholesale revenue. This benefit, combined with the higher retail sales generated from load growth, served to partially offset the high purchased power prices. Additional favorable operating expense variances resulted from asset write backs, which occurred due to rate orders successfully resolving issues surrounding previously denied costs. Further, the Company recorded a loss on the May 2000 sale of the Centralia plant and mine. See Notes 6 and 8 to the condensed consolidated financial statements.

Australian electric operations recorded a loss of $187 million in the 2001 period compared to earnings of $29 million in the 2000 period. This $216 million change was primarily due to the $218 million loss recorded on the sale of Australian electric operations. See Note 8 to the condensed consolidated financial statements.

Other operations reported income of $26 million in the 2001 period compared to a loss of $1 million in the 2000 period. This increase was primarily due to a reduction in expenses relating to exiting energy development businesses and a net gain recognized upon settlement of foreign currency exchange swaps upon the sale of the Company's indirect ownership of Powercor, partially offset by the Company's inability to use alternative fuel tax credits generated by the Company's synthetic fuel operations. See Notes 8 and 9 to the condensed consolidated financial statements.

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DOMESTIC ELECTRIC OPERATIONS

The Company's operations are planned and managed to meet anticipated requirements through its portfolio of low cost generating assets and purchase contracts. Demand for power in 2001 continued to exceed expectations as a result of strong economic growth in the region and hotter than normal weather in the summer months and colder than normal weather in the third quarter. Supply in the WSCC has not kept pace with growing demand and the price of natural gas has increased. These factors, along with unanticipated generation outages in the WSCC, and lower than normal hydro generation, led to increases in the level and volatility of power prices during 2001. In addition, on November 24, 2000, the Company's Hunter power plant experienced a failure. Lower margins were realized in the three months and nine months ended December 31, 2000 as a result of purchasing power to meet demand requirements at prices in excess of tariff rates for retail sales.

The underlying economic issues of supply and demand are expected to impact power prices in the future and are reflected in forward market prices well above historical norms. The Company's ultimate profitability in future periods depends on the Company's generation and volume of load, market prices of power, availability of transmission and regulated rates paid by customers. See "Business Risk."

Comparison of the three-month periods ended December 31, 2000 and 1999

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Revenues

Total domestic electric operations revenues increased $463 million, or 54%, from the third quarter of 2000. This was primarily attributable to increases in wholesale sales of $406 million and a $39 million increase in retail revenues.

Residential revenues increased by $20 million, or 9%. Growth in the average number of residential customers of 2% added $4 million to revenues. Price increases in Oregon, Utah and Wyoming added $8 million to revenues in 2001. Volume increases of 6%, primarily due to weather, increased residential revenues by $8 million.

Commercial revenues increased by $13 million, or 7%, primarily as a result of increased economic activity in Utah and Oregon. Growth in the average number of commercial customers of 3% added $6 million to revenues and volume increases of 6% added $6 million to revenues.

Industrial revenues were up $6 million, or 4%. Price increases in Oregon, Utah and Wyoming increased revenues by $8 million. This was partially offset by decreased irrigation usage, which reduced revenues by $1 million.

Wholesale sales increased $406 million, or 143%. Sales prices for short-term firm and spot market sales averaged $105 per megawatt hour ("MWh") in 2001 compared to $31 per MWh in 2000, creating a $401 million increase in revenues. Higher long-term firm contract prices added $8 million to revenues.

Other revenues increased by $17 million, or 115%, primarily due to an increase in wheeling revenues from increased usage of the transmission system by third parties.

See Note 6 to the condensed consolidated financial statements regarding recent regulatory action relating to domestic electric operations.

Operating Expenses

Total operating expenses increased $508 million, or 69%. This increase was primarily attributable to increased purchased power expense due to increased prices on short-term firm and spot market purchased power.

Purchased power expense was $849 million, an increase of $593 million. Higher prices on short-term firm and spot market purchases increased purchased power expense by $354 million. Short-term firm and spot market purchase prices averaged $111 per MWh in the quarter versus $31 per MWh in 2000. Demand for power continued to exceed expectations as a result of strong economic growth in the region and colder than normal weather conditions. Supply in the WSCC did not keep pace with growing demand. These factors, along with unanticipated generation outages in the WSCC, led to increases in the level and volatility of power prices during the third quarter of 2001. The November 24, 2000 failure of a generation unit at the Company's Hunter power plant resulted in a net unfavorable purchased power variance of $68 million. A 26% increase in short-term firm and spot market purchases added $143 million to purchased power expense, which includes the $68 million net relating to the Hunter unit

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outage. Increased prices and volumes relating to long-term firm contracts added $44 million and $27 million, respectively, to purchased power expense. Increased usage of transmission systems owned by third parties added $24 million to expense.

Fuel costs decreased $4 million, or 3%, to $126 million, primarily due to the May 2000 sale of the Centralia generation plant, partially offset by increased generation, which resulted in higher fuel consumption.

Total operations and maintenance expense and administrative, general and other tax expense decreased by $80 million. The Company is implementing the Transition Plan and the effects of that process are included in the variances in operations and maintenance expense, as well as administrative, general and taxes, discussed below.

Other operations and maintenance expense decreased $36 million, or 23%. Expense for 2000 included $23 million of write-offs of assets under construction and $4 million of write-offs of obsolete inventory. The sale of the Centralia plant and mine drove a $3 million decrease in expense and bad debt expense decreased by $6 million.

Administrative, general and taxes - other decreased $44 million, or 45%. Decreased labor, severance and employee-related costs resulted in a $35 million favorable variance, which includes a $12 million favorable variance due to merger costs recorded in the prior year. In addition, property tax expense and contract services related to Year 2000 conversion each decreased by $3 million.

Other Income and Expense

Domestic electric operations interest expense decreased $6 million primarily due to lower debt balances. Third quarter 2000 results included $202 million of merger costs compared to none in 2001. See Note 3 to the condensed consolidated financial statements. Income tax expense increased $4 million primarily due to the increase in taxable income.

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Wholesale sales increased $703 million, or 88%. Sales prices for short-term firm and spot market sales averaged $91 per MWh in 2001 compared to $27 per MWh in 2000, creating a $979 million increase in revenues. Long-term firm contract sales added $40 million to revenues. Partially offsetting these increases was a $316 million decrease resulting from lower short-term firm and spot market energy volumes.

Other revenues increased by $37 million, or 66%, primarily due to a $20 million increase in wheeling revenues from increased usage of the transmission system by third parties and $7 million in revenues resulting from a favorable AFOR price increase in Oregon. These AFOR revenue increases were partially offset by costs mandated by regulators. In addition, increased revenues relating to accruals on long-term contracts and other adjustments added $5 million to revenues.

See Note 6 to the condensed consolidated financial statements regarding recent regulatory action relating to domestic electric operations.

Operating Expenses

Total operating expenses increased $961 million, or 47%. This increase was primarily attributable to increased purchased power expense due to increased prices on short-term firm and spot market purchased power.

Purchased power expense was $1.85 billion, an increase of $1.09 billion, or 143%. Short-term firm and spot market purchases increased purchased power expense by $953 million primarily due to increased purchase prices, including the $68 million net unfavorable effect of the Hunter unit outage. Short-term firm and spot market purchase prices averaged $92 per MWh in the 2001 period versus $28 per MWh in the 2000 period. Demand for power continued to exceed expectations as a result of strong economic growth in the region and hotter than normal weather in the summer months and colder than normal weather in the third quarter. Supply in the WSCC did not keep pace with growing demand. These factors, along with unanticipated generation outages in the WSCC and lower than normal hydro generation, led to increases in the level and volatility of power prices during the 2001 period. Increased volumes and prices relating to long-term firm contracts added $65 million and $45 million, respectively, to purchased power expense. Increased usage of transmission systems owned by third parties added $24 million to expense.

Fuel costs decreased $19 million, or 5%, to $355 million, primarily due to the May 2000 sale of the Centralia generation plant, partially offset by increased generation, which resulted in higher fuel consumption.

Depreciation expense increased by $7 million, or 2%, to $291 million primarily due to increased plant in service, partially offset by decreased software and other amortization.

Total operations and maintenance expense and administrative, general and other tax expense decreased by $87 million. The Company is implementing the Transition Plan and the effects of that process are included in the variances in operations and maintenance expense, as well as administrative, general and taxes, discussed below.

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Other operations and maintenance expense decreased $24 million, or 6%. The sale of the Centralia plant and mine drove a $9 million decrease in expense and bad debt expense decreased by $11 million. Operations and maintenance expense for 2000 included $23 million of write-offs of assets under construction and $4 million of write-offs of obsolete inventory. Offsetting these net favorable variances was increased labor expense resulting from an increasing amount of work relating to expense rather than capital projects.

Administrative, general and taxes - other decreased $63 million, or 27%. Contract services relating to Year 2000 conversion and SAP conversion decreased $8 million. Decreased labor and severance costs resulted in a $24 million favorable variance, including a $12 million favorable variance due to merger costs recorded in the prior year. Employee related expenses decreased $23 million, primarily due to the impact of favorable returns on pension plan assets on pension expense. In addition, property tax expense decreased by $6 million.

Included within Operating expenses in 2001 was a $43 million gain related to rate orders received which successfully resolved issues surrounding previously denied costs and resulted in the establishment of $43 million of regulatory assets. In addition, the Company recorded a loss of $14 million on the sale of the Centralia Power Plant and mine. See Note 8 to the condensed consolidated financial statements.

Other Income and Expense

Domestic electric operations interest expense decreased $11 million primarily due to lower debt balances. The 2000 results included $213 million of merger costs compared to $9 million in 2001. The expense in 2001 is primarily related to merger credits in the state of Washington becoming unavailable for offset. See Note 3 to the condensed consolidated financial statements. Income tax expense decreased $23 million due to nondeductible merger costs in the prior year, partially offset by higher taxable income in the current year.

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AUSTRALIAN ELECTRIC OPERATIONS

On September 6, 2000, the Company completed the sale of its indirect ownership of Powercor pursuant to the August 2, 2000 agreement to sell Powercor and the Company's 19.9% interest in Hazelwood. On November 17, 2000, the Company completed the sale of Hazelwood to National Power Australia Holdings Pty Ltd, a wholly owned indirect subsidiary of International Power plc, pursuant to the partnership's pre-emptive rights process. See Note 8 to the condensed consolidated financial statements.

Australian electric operations' financial results for the period from October 1, 2000 to the date of the Hazelwood sale are included in PacifiCorp's financial results for the quarter ended December 31, 2000. Australian electric operations' financial results for the period from January 1, 2000 to the date of the Hazelwood sale are included in PacifiCorp's financial results for the nine months ended December 31, 2000. For purposes of this discussion, these financial results are referred to as "December 31, 2000" results. See Note 2 to the condensed consolidated financial statements.

Comparison of the three-month periods ended December 31, 2000 and 1999

Comparison of the nine-month periods ended December 31, 2000 and 1999

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The following discussion excludes the effects of the lower currency exchange rates and the additional one month and seventeen days included in the nine months of 2000 as a result of the 2001 sale.

Australian electric operations' total revenues remained flat compared to the 2000 period. Operating expenses increased primarily due to a $218 million loss recorded on the sale of the Australian electric operations, reduced by decreased purchased power expense. The decrease in purchased power expense was due to lower contract prices paid for power resulting from the favorable court ruling Powercor received in a dispute with one of its suppliers. This decrease was partially offset by an increase in administrative and general expenses incurred in 2001, primarily due to costs associated with a project to transition to full retail contestability.

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OTHER OPERATIONS

Comparison of the three-month periods ended December 31, 2000 and 1999

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Holdings and other operations' 2000 results included losses associated with exiting energy development businesses of approximately $8 million, as well as merger costs of $3 million. Additionally, net interest income in 2001 increased $6 million compared to the prior year, interest expense decreased $5 million due to a decrease in debt balances, and the sale of the Company's investment in Australian electric operations resulted in a net gain on settlement of foreign currency exchange swaps and debt repayment expense of $20 million. See Note 8 to the condensed consolidated financial statements. A tax expense decrease of $15 million was related primarily to the impact of a reevaluation of tax expense liabilities from settled and ongoing tax examinations in 2000.

Earnings at a subsidiary of Holdings decreased by $7 million because 2000 included revenue relating to the initial development of a cogeneration project. A contract to share margin on power marketed by another subsidiary increased income $7 million in 2001 due to higher sales prices.

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NEW ACCOUNTING STANDARDS

For information regarding the impact of the adoption of new accounting standards, see Note 11 to the condensed consolidated financial statements. With regard to the adoption of SFAS No. 133, the Company plans to adopt this statement on April 1, 2001. As a public utility, the Company will be required under the statement to classify certain of its sales and purchase contracts as derivatives. The Company's intent in entering into these contracts, generally, is to balance its electric load with available resources. When possible, the Company will satisfy its load requirements with electricity from its owned generating facilities. While SFAS No. 133 will require fluctuations in market prices to be reflected in the income statement and accumulated other comprehensive income, the final impact of settling these contracts may be significantly different than represented in interim financial disclosures.

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FINANCIAL CONDITION -

For the nine months ended December 31, 2000:

OPERATING ACTIVITIES

Net cash flows provided by continuing operations were $515 million during the period compared to $533 million for the first nine months of 2000.

Net cash used in discontinued operations in 2000 represents cash funding of TPC operations through an intercompany note payable to Holdings.

INVESTING ACTIVITIES

Capital spending totaled $296 million in 2001 compared with $459 million in 2000. Construction expenditures decreased in 2001 primarily due to lower expenditures at domestic electric operations attributable to the sale of the Centralia plant and mine and deferral of other projects. Proceeds from asset sales in 2001 were primarily the result of the sales of Powercor, Hazelwood and the Centralia plant and mine, while proceeds from asset sales in 2000 are attributable to the sale of TPC.

CAPITALIZATION

At December 31, 2000, PacifiCorp had approximately $267 million of commercial paper and uncommitted bank borrowings outstanding at a weighted average rate of 6.4%. These borrowings are supported by a $500 million revolving committed credit agreement which expires in August 2001. The Company also relies upon this facility to provide for daily liquidity requirements related to $175 million of unenhanced pollution control revenue bonds.

In July 2000, Holdings paid off $250 million of debt in anticipation of the Powercor sale.

In November 2000, the Company paid off its junior subordinated debentures, series A and B, principal balances totaling $176 million with proceeds resulting from the Powercor sale.

DIVIDENDS

The Company has declared and paid dividends on common stock during the nine months ended December 31, 2000 of $309 million to ScottishPower, the sole common shareholder of record. On November 16, 2000, the Company declared a dividend on common stock of $80 million, which is to be paid on February 12, 2001. These dividends were paid at a rate of $.27 per share, which is consistent with the historic payout rate per share.

The Company has paid dividends of $12 million on preferred stock during the nine months ended December 31, 2000. This includes $4 million declared in February 2000, and $8 million declared during the nine months ended December 31, 2000. On November 16, 2000, the Company also declared a dividend on preferred stock of $4 million, which is scheduled to be paid to shareholders on February 12, 2001.

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BUSINESS RISK

The Company participates in a wholesale energy market that includes public utility companies, power and natural gas marketers, which may or may not be affiliated with public utility companies, government entities and other entities. The participants in this market trade not only electricity and natural gas as commodities but also derivative commodity instruments such as futures, swaps, options and other financial instruments. The pricing for this wholesale market is largely unregulated and most transactions are conducted on an "over-the-counter" basis, there being no central clearing mechanism (except in the case of specific instruments traded on the commodity exchanges).

The Company is subject to the various risks inherent in the energy business, including market risk, regulatory/political risk, credit risk and interest rate risk.

Market Risk

Market risk is, in general, the risk of fluctuations in the market price of electricity. Market price is influenced primarily by factors relating to supply and demand. Those factors include the adequacy of generating reserve margins, scheduled and unscheduled outages of generating facilities, hydroelectric availability, prices and availability of fuel sources for generation, disruptions or constraints to transmission facilities, variations in the weather, economic growth, transmission capacity and other factors. The Company has been experiencing the adverse affect of higher market prices due to inadequate generating reserve margins in the WSCC, generating facility outages in the WSCC, including the unscheduled outage of the Company's Hunter unit, lower hydro availability, higher natural gas prices and growth in demand throughout the WSCC due to weather and economic growth.

During 2001, significant price volatility, driven in part by the availability of resources and demand for energy throughout the WSCC, materially impacted the cost of meeting the Company's system load requirements. While the Company plans for resources to meet its current and expected retail and wholesale load obligations, resource availability, price volatility and load volatility may materially impact the power costs to the Company and profits from excess power sales in the future. Prices paid by the Company to provide certain load balancing resources to supply its load may continue to exceed the amounts it receives though retail rates and wholesale prices. The Company has filed applications seeking deferred accounting treatment for net power costs in excess of costs included in determining retail rates in the states of Utah, Idaho, Wyoming and Oregon. Approval of certain cost deferrals has been received in Wyoming and Oregon, and the Company is working with the commissions in these states to develop mechanisms for the recovery of these cost deferrals. If received from other state jurisdictions, approval of deferred accounting treatment will help mitigate a portion of the price risk.

Regulatory/Political Risk

The WSCC is experiencing extraordinary market conditions. Recent wholesale prices have greatly exceeded historical norms, reflecting high natural gas prices, low hydro conditions, unexpected generation outages and load growth,

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among other factors. Physical supply constraints have led to rolling blackouts in certain areas of the WSCC. None of the Company's service territory have experienced such severe constraints, although resources and demand in the region are in a near-balanced condition. The region's turbulence and the financial troubles of the California energy market are drawing attention from various state and federal regulatory and political authorities. Numerous changes to the current operating structure have been proposed to address the region's issues. To date, no changes have been implemented which materially affect the Company's operations; however, the situation may change favorably or adversely in the future.

Credit Risk

Credit risk relates to the risk of loss that might occur as a result of non-performance by counterparties of their contractual obligations to deliver electricity and make financial settlements. Credit risk may be concentrated to the extent that one or more groups of counterparties have similar economic, industry or other characteristics that would cause their ability to meet contractual obligations to be similarly affected by changes in market or other conditions. In addition, credit risk includes not only the risk that a counterparty may default due to circumstances relating directly to it, but also the risk that a counterparty may default due to circumstances which relate to other market participants which have a direct or indirect relationship with such counterparty. The Company seeks to mitigate credit risk (and concentrations thereof) by applying specific eligibility criteria to prospective counterparties. However, despite mitigation efforts, defaults by counterparties occur from time to time. To date, no such default has had a material adverse effect on the Company. The Company continues to actively monitor the credit worthiness of those counterparties with whom it executes wholesale energy trading transactions within the WSCC and uses a variety of risk mitigation techniques to limit its exposure where it believes appropriate.

Interest Rate Risk

The Company manages its debt requirements with a balance of short-term and long-term debt, with an expectation of limited issuance of new long-term debt. With increasing cash requirements resulting from maturities of long term debt, the unusually high purchased power prices and the impact of the Hunter plant outage on purchased power volumes, the Company is utilizing a growing amount of short-term debt until longer term financing is completed. In January 2001, the Company's credit outlook was changed from stable to negative by a credit ratings agency, citing the impact of high purchased power prices, the Hunter outage and the uncertainty and expected delay between the request for deferred accounting treatment for excess power costs and when approval is granted and in effect. Any adverse change to the Company's credit rating could negatively impact the Company's ability to borrow and the interest rates that the Company is charged.

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RISK MANAGEMENT

Risk is an inherent part of the Company's business and activities. The risk management process established by the Company is designed to identify, assess, monitor and manage each of the various types of risk involved in its business and activities. Central to its risk management process, the Company has established a risk management committee with overall responsibility for establishing and reviewing the Company's policies and procedures for controlling and managing its risks. The risk management committee relies on the Company's treasury and risk management departments and its operating units to carry out its risk management directives and execute various hedging and energy trading strategies. Nonetheless, adverse changes in interest rates, resource availability, regulatory and political environments and commodity prices may result in losses in earnings, cash flow and/or fair values.
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The condensed consolidated financial statements as of December 31, 2000 and March 31, 2000 and for the three-month and nine-month periods ended December 31, 2000 and 1999 have been reviewed by PricewaterhouseCoopers LLP, independent accountants, in accordance with standards established by the American Institute of Certified Public Accountants. A copy of their report is included herein.

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SIGNATURE

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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