PACIFICORP /OR/ - Annual Report: 2001 (Form 10-K)

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PART I

As a result of the geographically diversified area of operations, the Company's service territory has historically had complementary seasonal load patterns. In the western sector, customer demand peaks in the winter months due to space heating requirements. In the eastern sector, customer demand peaks in the summer when irrigation and cooling systems are heavily used. Many factors affect per customer consumption of electricity. For residential customers, within a given year, weather conditions are the dominant cause of usage variations from normal seasonal patterns. However, the price of electricity is also considered a significant factor. In response to recent region-wide electricity supply shortages, the Company is actively promoting electricity conservation programs, which may cause usage variations. See "Regulation" for additional information.

During 2001, no single retail customer accounted for more than 2% of the Company's retail utility revenues and the 20 largest retail customers accounted for 15% of total retail electric revenues.

Competition

In many cases, customers have the option to switch energy sources for heating and air conditioning. In addition, certain of the Company's industrial customers are seeking choice of suppliers, options to build their own generation or cogeneration, or the use of alternative energy sources such as natural gas. When a competitive marketplace exists, customers will make their energy purchasing decision based upon many factors, including price, service and system reliability.

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During 2001, the Company continued to operate its electricity distribution and retail sales business as a regulated monopoly throughout most of its franchise service territories. However, the Company anticipates increasing competition, principally as a result of industry restructuring, deregulation and increased marketing by alternative energy suppliers.

Beginning in April 1998, California retail electric energy sales have been subject to open market competition. The Company's generation in California, which represents 1% of total nameplate rating, is currently regulated, but, under present legislation, energy supply will not be state regulated beginning April 2002. The Company has not determined what effects, if any, this will have on the financial reporting and results of its generation business. Deregulation in Oregon has been moving forward, but caution is being taken to avoid the problems that have been encountered in California. It is expected that regulators will act prudently to protect the state's utilities from potential hazards of deregulation. Four other states, Utah, Wyoming, Washington and Idaho, have been slow in deregulating their electric markets. See "Regulation." The Company supports increased customer choice under terms and conditions that are equitable to all stakeholders.

The Energy Policy Act, passed in 1992, opened wholesale competition to energy brokers, independent power producers and power marketers. In 1996, the FERC ordered all investor-owned utilities to allow others access to their transmission systems for wholesale power sales ("open access"). This access must be provided at the same price and terms the utilities would apply to their own wholesale customers. The Company is working with eight other utilities, including the federal Bonneville Power Administration ("BPA"), to form a regional transmission organization. See "Regulation - Regional Transmission Organization ("RTO")." Competition is also influenced by availability and price of alternate energy sources and the general demand for electrical power.

The Company has formulated strategies to meet these challenges. The Company is marketing power supply services to other utilities in the western United States, including dispatch assistance, daily system load monitoring, backup power, power storage and power marketing, and services to retail customers that encourage efficient use of energy. Effective January 1, 1998, the California Public Utilities Commission (the "CPUC") adopted rules regulating the nontariffed sale of energy and energy products and services by utilities and their affiliates. The rules also mandated a 10% rate reduction in tariffed electricity prices in California, which resulted in a $3.5 million annual reduction in the Company's revenues. The Company has decided to refrain from marketing nontariffed energy products and services to retail customers in California, but intends to continue limited purchases and sales in the wholesale business, selling to utilities in California and marketers elsewhere in the western United States. See "ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - BUSINESS RISK."

The Company believes that the regulatory initiatives that are underway in each of the states it services may eventually bring competition for electricity generation services. This change in the regulatory structure may significantly affect the Company's future financial position, results of operations and cash

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flows. The Company intends to seek regular price increases to the extent it underearns its allowed rate of return. This intention, consistent with the strategic direction implemented in 1998, provides a continued foundation for use of Statement of Financial Accounting Standards ("SFAS") No. 71 in its financial statements. The Company currently has outstanding rate increase requests before the state commissions in California, Oregon, Utah, and Wyoming. See "Regulation."

Power and Fuel Supply

The supply of power has not kept pace with the growing demand in the western United States and the Company is experiencing the effect of high market prices associated with this shortage. Prices paid by the Company to provide certain load balancing resources to supply its load may continue to exceed the amounts it receives through retail rates and wholesale prices.

The Company owns or has interests in generating plants with an aggregate nameplate rating of 8,280 MW and plant net capability of 7,832 MW. See "ITEM 2. PROPERTIES." With its present generating facilities, under average water conditions, the Company would expect that approximately 5% of its energy requirements for 2002 would be supplied by its hydroelectric plants and 67% by its thermal plants. The balance of 28% would be obtained under long-term purchase contracts, and interchange and other purchase arrangements. The Pacific Northwest is experiencing a period of decreased rainfall, which has resulted in less favorable hydroelectric generation. These conditions may cause the hydroelectric expectations not to be met, as the needs of fish migration and irrigation could utilize water that otherwise would be used to produce electricity. During 2001, approximately 4% and 60% of the Company's energy requirements were supplied by its hydroelectric and thermal generation plants, respectively, and the remaining 36% by purchased power. Thermal generation's contribution to energy requirements was reduced by the sale of the Centralia plant in May of 2000 and the Hunter unit outage. This outage occurred on November 24, 2000 and continued until May 2001.

The Company's generating facilities are interconnected through its own transmission lines or by contract through the lines of others. Substantially all generating facilities and reservoirs located within the western states are managed on a coordinated basis to obtain maximum load carrying capability and efficiency.

As of March 31, 2001, the Company had 229 million tons of recoverable coal reserves that are mined by the Company or its affiliates. The coal from these reserves is dedicated to Company generation plants that are near the mines. During 2001, these mines supplied approximately one half of the Company's total coal requirements. Coal is also acquired through long-term and short-term contracts.

The Company has entered into long-term and short-term natural gas contracts to supply its generation plants that use natural gas with the fuel needed for operations. See "ITEM 2. PROPERTIES" for information regarding generating plant energy sources.

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Wholesale Sales and Purchased Power

Wholesale sales of power contribute significantly to total revenues even though the Company has scaled back wholesale sales from 1998 levels. The Company's wholesale sales complement its retail business and enhance the efficient use of its generating capacity over the long term.

The Company's transmission system connects with other utilities in the Pacific Northwest having low-cost hydroelectric generation and with utilities in California and the southwestern United States having higher-cost, fossil-fuel generation. The transmission system is available for common use consistent with open access regulatory requirements. If the Company is in a surplus power position, the Company is able to sell excess generation into the wholesale market.

Historically, during the winter, the Company was able to purchase power from utilities in the southwestern United States, either for its own peak requirements or for resale to other regional utilities. During the summer, the Company was historically able to sell excess power to utilities in the southwestern United States to assist them in meeting their peak requirements.

In addition to its base of thermal and hydroelectric generation assets, the Company utilizes a mix of long-term and short-term firm power purchases and nonfirm purchases to meet its load obligations and to make sales to other utilities. Many of the Company's purchased power contracts have fixed price components, which provide some protection against the current price volatility. See Note 14 of Notes to the Consolidated Financial Statements under Item 8 for further information on long-term wholesale sales and purchased power contracts.

The Company currently purchases 925 MW of firm capacity annually from the BPA pursuant to a long-term agreement. The purchase amount declines annually to 750 MW in July 2003 and again to 575 MW in July 2004 through August 2011. The Company's annual payment under this agreement for the period ended March 31, 2001 was $65 million. The price for this capacity is a per MW charge, therefore, the costs associated with this agreement will decline as the MW purchase declines. The price is adjusted by the rate of change in the BPA's Average System Cost. The next scheduled price change will be October 1, 2001. The Company expects a slight decline in price.

Under the requirements of the Public Utility Regulatory Policies Act of 1978, the Company purchases the output of qualifying facilities constructed and operated by entities that are not public utilities. During 2001, the Company purchased an average of 109 MW from qualifying facilities, compared to an average of 112 MW in 2000. Long-term firm power purchases supplied 13% of the Company's total energy requirements in 2001. Short-term firm and nonfirm power purchases supplied 23% of the Company's total energy requirements in 2001. See Note 14 of Notes to the Consolidated Financial Statements under ITEM 8 for further discussion on the Company's commitments and contingencies.

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Proposed Asset Dispositions

In July 1998, the Company announced its intention to sell its California electric distribution assets. This action was in response to the continued decline in earnings on the assets and the changes in the legislative and regulatory environments in California. The Company had an agreement with Nor-Cal Electric Authority ("Nor-Cal") for the sale of the Company's California electric distribution assets for $178 million. On December 21, 2000, the CPUC approved an Administrative Law Judge's 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.

Projected Demand

The Company continues to experience economic growth in several portions of its service territory and retail energy sales for the Company have grown at a compound annual rate of 2.1% since 1995. This increase in demand is happening throughout the WSCC, due in large part to economic growth. Future increases in demand are dependent upon several factors, including the impact of Demand Side Management programs and higher prices. 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 power costs to the Company. The Company is pursuing price increases in jurisdictions where it does not earn an appropriate rate of return and will seek operating efficiencies as outlined in the Transition Plan. For more information, see Note 2 of Notes to the Consolidated Financial Statements under ITEM 8.

For the periods 2002 to 2005, the average annual growth in retail MWh sales in the Company's franchise service territories is estimated to be about 1.7%, excluding the potential effects of decreased demand resulting from conservation efforts and higher prices. Because of price increases throughout the region, the Company anticipates that demand growth will slow or may even reverse. During this period, the Company may lose retail energy sales to other suppliers in connection with deregulation of the electric industry. As the electric industry evolves toward deregulation, the Company expects to have opportunities to sell any excess power in wholesale markets. The Company's actual results will be determined by a variety of factors, including the outcome of deregulation in the electric industry, economic and demographic growth, and competition.

Environmental Issues

Federal, state and local authorities regulate many of the Company's activities pursuant to laws designed to restore, protect and enhance the quality of the environment. These laws have increased the cost of providing electric service. The Company is unable to predict what material impact, if any, future changes in environmental laws and regulations may have on the Company's consolidated financial position, results of operations, cash flows, liquidity, and capital expenditure requirements.

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All of the Company's mining operations are subject to reclamation and closure requirements. The Company monitors these requirements and annually revises its cost estimates to meet existing legal and regulatory requirements of the various jurisdictions in which it operates. Compliance with future requirements could result in higher expenditures for both capital improvements and operating costs.

Air Quality. The Company's fossil fuel-fired electricity generation plants are subject to regulation under federal, state and local requirements. Emission controls, low sulfur coal, environmentally conscious plant operating practices and continuous emissions monitoring are all utilized to enable coal-burning plants to comply with emission limits, opacity limits, visibility and other air quality requirements. The United States Environmental Protection Agency (the "EPA") has implemented new regulations addressing regional haze. Carbon dioxide emissions are the subject of growing world-wide discussion and action in the context of global warming, but such emissions are not currently regulated. The Company's coal-burning plants, along with all other major coal-burning plants in the United States, participated in an effort to gather additional information about mercury emissions pursuant to a request issued by the EPA. Based in part on this effort, the EPA has indicated that controls to regulate mercury emissions from coal-burning plants will be brought forward by 2003.

The Company has received Title V Air Operating Permits for all of its coal and natural gas-fired power plants. In response to a 1998 citizens group challenge of the operating permits for the Company's Naughton and Jim Bridger power plants, the EPA ordered the state of Wyoming to reissue those permits with new continuous opacity monitoring requirements in place. The plants are currently working with the state of Wyoming to determine what, if any, new requirements should be imposed.

In 1999, the EPA commenced enforcement actions alleging violations of New Source Review requirements by the owners of certain coal-fired generating plants in the eastern and mid-western United States. The Company is not part of that action. However, in December 2000, the EPA notified the Company that it is investigating similar issues at four of the Company's coal plants. The Company is cooperating with that investigation by gathering and providing requested information to the EPA.

Electromagnetic Fields. A number of studies continue to examine the possibility of adverse health effects from electromagnetic fields ("EMF"), without conclusive results. Certain states and cities have enacted regulations to limit the strength of magnetic fields at the edge of transmission line rights-of-way. Other than in California, none of the state agencies with jurisdiction over the Company's operations have adopted formal rules or programs with respect to magnetic fields or magnetic field considerations in the siting of electric facilities. The CPUC has issued an interim order requiring utilities to implement no-cost or low-cost mitigation steps in the design of new facilities. It is uncertain whether the Company's operations may be adversely affected in other ways as a result of EMF concerns.

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Endangered Species. Protection of the habitat of endangered and threatened species makes it difficult and more costly to perform some of the core activities of the Company, including the siting, construction and operation of new and existing transmission and distribution facilities, as well as generation plants. In addition, endangered species issues impact the relicensing of existing hydroelectric generating projects, generally raising the price the Company must pay to purchase wholesale power from hydroelectric facilities owned by others, reducing output and increasing the costs of operating the Company's own hydroelectric resources. These actions could also result in further restrictions on timber harvesting and reduce electricity sales to Domestic electric operations' customers in the wood products industry.

Environmental Cleanups. Under the Federal Comprehensive Environmental Response, Compensation and Liability Act and similar state statutes, entities that disposed of or arranged for the disposal of hazardous substances may be liable for cleanup of the contaminated property. In addition, the current or former owners or operators of affected sites also may be liable. The Company has been identified as a potentially responsible party in connection with a number of cleanup sites because of current or past ownership or operation of the property or because the Company sent hazardous waste or other hazardous substances to the property in the past. The Company has completed several cleanup actions and is actively participating in investigations and remedial actions at other sites. The costs associated with those actions are not expected to be material to the Company's consolidated financial position, results of operations, cash flows, liquidity, or capital expenditure requirements.

Water Quality. The Federal Clean Water Act and individual state clean water regulations require a permit for the discharge of waste water, including storm water runoff from the power plants and coal storage areas, into surface waters. Also, permits may be required in some cases for discharges into ground waters. The Company believes that it currently has all required permits and management systems in place to assure compliance with permit requirements.

Regulation

The Company is subject to the jurisdiction of public utility regulatory authorities of each of the states in which it conducts retail electric operations as to prices, services, accounting, issuance of securities and other matters. Commissioners are appointed by the individual state's governor for varying terms. The Company is a "licensee" and a "public utility" as those terms are used in the Federal Power Act (the "FPA") and is, therefore, subject to regulation by the FERC as to accounting policies and practices, certain prices and other matters. Most of the Company's hydroelectric plants are licensed as major projects under the FPA and certain of these projects are licensed under the Oregon Hydroelectric Act. As a result of the Merger, the Company is also subject to the requirements and restrictions of the Public Utility Holding Company Act of 1935.

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The Company's hydroelectric portfolio consists of 53 plants that include 87 generating units with a total capacity of approximately 1,100 MW. Ninety-seven percent of the installed capacity is regulated by the FERC through 20 individual licenses. These projects account for about 14 percent of the Company's total generating capacity and provide operational benefits such as peaking capacity, generation, spinning reserves and voltage control.

Nearly all of the Company's hydroelectric projects are in some stage of relicensing under the FPA. The relicensing process is an extremely political and public regulatory process that involves controversial resource issues. In the new licenses, the FERC is expected to impose conditions designed to address the impact of the projects on fish and other environmental concerns. In addition, under the FPA and other laws, the state and federal agencies and tribes have mandatory conditioning authorities that give them significant influence and control in the relicensing process. It is extremely difficult to determine the economic impact of these mandates, but capital expenditures and operating costs are expected to increase in future periods while generation losses may result due to environmental and fish concerns. As a result of these issues, the Company has analyzed the costs and benefits of relicensing the Condit dam and has agreed to remove the Condit dam at a cost of approximately $16 million.

During 1998, the Company filed new depreciation rates with the respective regulatory commissions in the states of Oregon, Utah and Wyoming based upon a depreciation study. New depreciation rates were filed in Washington as part of a general rate case filing and subsequently approved by the Washington Utilities and Transportation Commission (the "WUTC") in an order dated August 9, 2000. New depreciation rates were approved by the Utah Public Service Commission (the "UPSC") in an order dated January 6, 2000, the Oregon Public Utility Commission (the "OPUC") in an order dated May 31, 2000 and the Wyoming Public Service Commission (the "WPSC") in an order dated July 28, 2000. The impact of the proposed changes in depreciation is being incorporated into the current general rate cases in Utah, Oregon and Wyoming. Based on the depreciation rates that have been approved, annual depreciation expense would be increased by approximately $20 million. The increase in depreciation expense is primarily due to revisions of the estimated costs of removal for steam production and distribution plants. For the period April 1, 2000 to March 31, 2002, the Utah and Wyoming commissions have ordered a reversal of a portion of previously accrued depreciation. These reversals in total, for both states, will amount to approximately $14 million per year for two years.

Between February 10 and April 6, 2000, the Company received approval orders from all states in which the Company operates for the sale of the Company's interests in the Centralia plant and mine. FERC approved the sale on January 13, 2000 and the sale was completed on May 4, 2000.

The Company filed requests with the commissions in the states it serves to grant deferred accounting treatment for the effects of SFAS No. 133 on the financial statements of the Company. The estimated effect of adopting SFAS No. 133 on April 1, 2001 assumes that the Company will receive regulatory orders directing the deferral, as a regulatory asset or liability, of the effects of

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fair valuing long-term contracts that are included in the Company's rates. The income statement impact of SFAS No. 133 would be partially offset, on an ongoing basis, by the change in the regulatory asset or liability allowed under the deferred accounting order.

On February 7, 2001, the Company filed applications with the UPSC, the WPSC, the Idaho Public Utilities Commission (the "IPUC") and the OPUC requesting accounting orders to defer $27 million in unrecovered costs associated with its Trail Mountain coal mine. The Company ceased operations at the mine on March 7, 2001. The mine is located in Central Utah and supplied fuel to the Hunter Plant. In April 2001, the IPUC and the WPSC approved deferred accounting treatment of their portions of costs associated with the Trail Mountain coal mine closure.

On October 30, 2000, the Company and BPA executed a 10-year settlement agreement that replaced the Residential Exchange Program. This settlement will be effective October 1, 2001 and is expected to provide the Company's residential and irrigation customers in Oregon, Washington and Idaho with benefits equaling $76 million per year during the first five years of the agreement. These benefits pass through to customers and do not impact the Company's earnings.

Merger Credits:
As a result of the Merger, the Company is required to provide benefits to rate payers through fixed reductions in rates or "Merger Credits." The Company's total obligation for merger credits is $133.4 million through the period ending December 31, 2004. A portion of this amount must be provided without offset or reduction of any kind and, accordingly, the Company recorded $57.2 million as a liability and current expense in its financial statements for the year ended March 31, 2000. In the second quarter of 2001, the Company recorded $12 million as a liability and current expense in relation to the August 9, 2000 order from the WUTC, which impacted the Company's ability to offset merger credits in the future. See Note 2 of Notes to the Consolidated Financial Statements under ITEM 8. The remaining $64.2 million obligation of the Company with respect to merger credits is subject to possible offset if the Company demonstrates in a future rate case, to the satisfaction of the respective commissions, that merger-related cost reductions have occurred and are being reflected in rates. This $64.2 million obligation will be reflected in future periods.

Rate Increases Granted:
On October 25, 2000, the WUTC 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.

On September 27, 2000, the Company received an order from the OPUC authorizing increased prices in Oregon for residential customers of 2.33%, commercial and small industrial customers of 1.37%, large industrial customers of 0.4%, and public street lighting customers of 1.27%. These price increases are expected to result in annual revenues of $14 million. The order was effective on October 1, 2000.

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On August 9, 2000, the Company received an order from the WUTC that authorized the Company to increase rates by 3% on September 1, 2000, 3% on January 1, 2002 and 1% on January 1, 2003.

On June 20, 2000, the Company received approval from the OPUC for an overall price increase of 1.8%, or $13.7 million, through an annual adjustment as part of the alternative form of regulation ("AFOR") process previously authorized in Oregon. Of this amount, approximately $10 million is offset by costs mandated by regulators. The increase will cause rates for residential customers to rise by 2.9%, for large industrial users by 1.1%, and for commercial customers by 0.5%. The new rates took effect July 1, 2000 and are expected to increase annual revenues by approximately $3.7 million net of costs mandated by the OPUC. The AFOR is authorized to run through June 30, 2001. Existing rates in Oregon will continue unchanged after the AFOR's termination until new rates are authorized by the OPUC.

On May 25, 2000, the Company received an order from the WPSC authorizing an increase in prices, which is expected to result in increased annual revenues of $11 million. The Company received authorization for an additional $1 million increase effective July 19, 2000.

On May 24, 2000, the Company received an order from the UPSC authorizing increased prices in Utah for residential, irrigation, small commercial and lighting customers of 4.24% and large commercial and industrial customers of less than 1%. These price increases are expected to result in additional annual revenues of $17 million. The order was effective on May 25, 2000 and allowed recovery of early retirement and pension costs, reclamation costs, and Year 2000 and other information systems costs that had previously been written off. As a result, $17 million in regulatory assets was established in the first quarter of 2001 relating to cost recoveries which required no additional review and $25 million in regulatory assets was established in the second quarter of 2001 relating to cost recoveries which successfully passed additional review. An additional $7 million may be recovered in future periods following further review.

Rate Increases Submitted for Regulatory Approval:
On March 16, 2001, the Company filed a request with the CPUC for an 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. Hearings are scheduled for the week of August 20, 2001.

On December 18, 2000, the Company filed a request with 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 to $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.

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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 as discussed below under "Deferred Power Cost Filings." 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. On February 2, 2001, the Commission granted an interim rate increase of $70 million, effective February 2, 2001, subject to refund if the final rate order does not provide for at least this level of recovery.

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 January 24, 2001, the OPUC staff filed a settlement proposal recommending an $18.5 million rate increase. This was later revised on February 6, 2001 to reflect a $28.9 million increase. 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. On March 12, 2001, staff and intervenors filed their direct case in the docket. See "Deregulation."

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

The Utah deferred accounting filing originally encompassed all power costs that vary from 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 the power cost variances not related to the Hunter outage, the Utah deferred accounting filing was effectively amended by stipulation to include only the cost variances associated with the Hunter outage. Hunter deferred accounting was adopted by the Commission effective November 24, 2000, the date the outage began. During 2001, the Company has deferred $79 million relating to the Utah approval of the power cost variances related to Hunter.

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

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3% rate increase is 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 has 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 deadband. Outside the deadband, a portion of these costs are deferred based on stipulated ratios. The OPUC also ordered the Company to work with the commission staff and intervenors to develop a baseline around which the deadband 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.

On February 12, 2001, the IPUC approved the Company's deferred accounting filing for all power costs that vary from the level assumed in Idaho rates for the period November 1, 2000 through October 31, 2001, including costs to replace lost generation resulting from the Hunter unit outage. The Company has deferred $11 million related to this approval as of March 31, 2001.

Approval for deferral of power costs that vary from rate assumptions was received from the WPSC on November 30, 2000. The Company is currently working with the WPSC to develop a power cost adjustment mechanism for recovery of these deferred amounts. During 2001, $27 million of power costs were deferred, which encompassed all net purchased power costs that varied from 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 to either defer, or obtain rate inclusion of, power costs that vary from the level in current Washington rates.

Regional Transmission Organization ("RTO"):
The Company, in conjunction with eight other utilities, is involved in a voluntary effort to form a RTO, named RTO West, in support of FERC Order 2000. FERC Order 2000 requires all public utilities that own, operate or control interstate electric transmission to file a proposal for a RTO. The nine members of RTO West will be Avista Corporation, 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 about 30,000 miles of the 50,000 miles of transmission line owned by the entities. On October 16, October 23 and December 1, 2000, the members made filings addressing structural, operational and contractual issues associated with the RTO formation. On April 25, 2001, the FERC accepted the key components of these filings, including the governance structure, scope and configuration. FERC suggested that RTO West could serve as the basis for the ultimate formation of an RTO encompassing the entire WSCC. Because of the continuing development, the Company cannot currently quantify the impact, if any, of the RTO formation on its future operations.

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Demand Side Management:
In December 2000 and January 2001, the Company filed for Pilot Energy Exchange Service 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. The customer must execute an agreement prior to being allowed to receive service under the program. The Company expects these programs to be an economic alternative to paying higher market prices by reducing the system-wide demand for electricity. In March 2001, the Company submitted proposals to expand the programs to all customers of one MW and greater in Oregon, Washington, Utah, Idaho, and Wyoming. The exchange had achieved over 9,500 MWh of load curtailment through March 31, 2001 and is expected to grow as the customer base expands.

In March 2001, the Company also filed and received regulatory approval to implement voluntary curtailment programs for irrigation customers in Oregon and Washington. Similar filings were submitted in Idaho and Utah and are under regulatory review.

The Company filed for approval of Residential Usage Incentives in all states it serves in April 2001. If approved, the incentives would provide a 20% credit on monthly bills in June, July, August and September of 2001 for residential customers who reduce their monthly kWh usage from the corresponding month one year ago by 20%. The Company believes this program will set clear and simple targets for customers to receive benefits if they conserve energy.

Proposed Restructuring:
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 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 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 FERC and the Securities and Exchange Commission ("SEC"). This process is expected to take more than a year.

Deregulation:
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. Under the legislation, the Company is required to unbundle rates for generation, transmission, distribution, and other retail services, and offer residential customers a cost-of-service rate option, and a portfolio of rate options that includes new renewable energy resources and market-based generation. SB 1149 authorizes the OPUC to make decisions on a variety of important issues, including the method

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for valuation of stranded costs/benefits. The OPUC may provide incentives for divestiture of generation assets or the functional separation of such assets. Generation asset divestiture is not mandated and is solely at the Company's discretion. Transition charges may be included in the direct access, portfolio rate option, and cost-of-service rates. SB 1149 requires the OPUC to report to the Oregon state legislature by January 1, 2003 as to whether residential electric customers would benefit from direct access.

On October 2, 2000, the Company filed its plans to implement the requirements outlined by SB 1149 and subsequent commission rules. 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.

This resource plan presented the estimate of the value of the Company's generating facilities. This valuation was based on various assumptions, including future electricity prices and cost estimates for compliance with existing and anticipated air quality regulations impacting the Company's thermal generation, as well as the estimated costs associated with relicensing of the Company's hydroelectric facilities. The Company's preliminary analyses indicate that the after-tax present value of the air quality and hydroelectric costs over the projected useful life of the thermal plants, and the term of the licenses in the case of the hydroelectric licenses, could exceed $1 billion predominantly in increased capital expenditures. The final cost is dependent on a variety of factors, including the actual terms and applicability of existing and anticipated environmental laws and regulations, the costs associated with lost generation, developments in pollution control technologies, and the actual terms and conditions of any new hydroelectric licenses. The ultimate impact of these compliance costs on the Company will depend on the regulatory treatment of such costs, whether the Company elects to sell or abandon facilities rather than make the required capital expenditures, and numerous other factors, many of which are beyond the Company's control.

In February 2001, the Company made its resource plan supplemental filing. 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 restructuring proposals discussed above. See "Proposed Restructuring." The Commission has adopted a temporary rule extending the decision date on the resource plan from April 1, 2001 to September 1, 2001.

On January 3, 2001, the OPUC adopted public purpose rules as required by SB 1149. The rules require electric utilities and suppliers that provide electricity services to direct access consumers to collect public purpose charges equal to 3% of the total revenues for electricity services, distribution, ancillary services, metering and billing, transition charges, and other types of costs that were included in electric rates on January 23, 1999.

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19

Construction Program

The following table shows actual construction costs for 2001 and the Company's estimated construction costs for 2002 through 2004, including costs of acquiring demand-side resources. The estimates of construction costs for 2002 through 2004 are subject to continuing review and revision as appropriate by the Company.

AUSTRALIAN ELECTRIC OPERATIONS

----------
*Jointly owned plants; amount shown represents the Company's share only.

NOTE: Hydroelectric project locations are stated by locality and river
watershed.

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The Company's generating facilities are interconnected through its own transmission lines or by contract through the lines of others. Substantially all generating facilities and reservoirs located within the western states are managed on a coordinated basis to obtain maximum load carrying capability and efficiency. Portions of the Company's transmission and distribution systems are located, by franchise or permit, upon public lands, roads and streets and, by easement or license, upon the lands of other third parties.

Substantially all of the Company's electric utility property is subject to the lien of the Company's Mortgage and Deed of Trust.

The following table describes the Company's recoverable coal reserves as of March 31, 2001. All coal reserves are dedicated to nearby Company operated generating plants. Recoverability by surface mining methods typically ranges between 90% and 95%. Recoverability by underground mining techniques ranges from 50% to 70%. The Company considers that the respective coal reserves assigned to the Craig, Dave Johnston, Huntington, Hunter and Jim Bridger plants, together with coal available under both long-term and short-term contracts with external suppliers, will be sufficient to provide these plants with fuel that meets the Clean Air Act standards effective in 1999, for their current economically useful lives. The sulfur content of the coal reserves ranges from 0.43% to 0.84% and the British Thermal Units value per pound of the reserves ranges from 7,600 to 11,400. Coal reserve estimates are subject to adjustment as a result of the development of additional data, new mining technology and changes in regulation and economic factors affecting the utilization of such reserves.

____________

(1)  These coal reserves are leased and mined by Trapper Mining, Inc., a Delaware nonstock corporation operated on a cooperative basis, in which the Company has an ownership interest of approximately 20%.

(2)  These coal reserves are mined by subsidiaries of the Company and are in underground mines.

(3)  These coal reserves are leased and mined by Bridger Coal Company, a joint venture between Pacific Minerals, Inc., a subsidiary of the Company, and a subsidiary of Idaho Power Company. Pacific Minerals, Inc. has a two-thirds interest in the joint venture.

Most of the Company's coal reserves are held pursuant to leases from the federal government through the Bureau of Land Management and from certain states and private parties. The leases generally have multi-year terms that may be renewed or extended and require payment of rentals and royalties. In

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(1)  (Loss) earnings contribution on common stock by segment: (a) does not reflect elimination for 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 and (c) is net of preferred dividend requirements and minority interest (which is reported as a component of Minority interest and other).

(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 $106 million in 2001 compared to earnings of $65 million in 2000. The 2001 results included a loss of $198 million from the sale of Australian electric operations, $218 million of which represents the loss on sale recorded at Australian electric operations partially offset by a $20 million net gain recorded at Other operations on the settlement of foreign currency exchange swaps and debt repayment expense. The 2001 results also included $27 million after-tax for regulatory asset write backs and $5 million after-tax in merger costs compared to $180 million in the 2000 period. The results for the 2000 period also included a $15 million after-tax write-off of projects under construction, that were abandoned in the period. Excluding these items, earnings would have been $70 million in 2001 and $260 million in the preceding period. This variance is mainly attributable to higher purchased power costs in 2001 compared to 2000.

See Note 2 of Notes to the Consolidated Financial Statements under ITEM 8 for a table showing where merger costs have been recorded in the Company's financial results. See Note 17 of Notes to the Consolidated Financial Statements under ITEM 8 for information regarding the sale of Australian electric operations.

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In 2001, the Company, along with other utilities in the WSCC, has been challenged by the market and economic conditions of the electricity industry in the region. The economic growth of the region has spurred the increase in demand for electricity. At the same time, generation resources have been impacted by the lack of new generation facility construction, unplanned outages in generation facilities, including the November 24, 2000 outage of the Company's 430 MW Hunter unit, and by the low snow pack and rainfall resulting in low hydroelectric generation. The limited current and forecasted hydro resources are also in demand for meeting irrigation needs and for protection of migrating fish.

All these conditions have led to unprecedented high short-term firm and spot market prices. To meet certain load and contractual obligations, the Company has had to purchase power at prices that have exceeded the revenues received from retail rates and committed wholesale sales. If the supply of electricity does not improve, the demand does not decrease or customer rates do not increase sufficiently, the Company may be required to continue to purchase electricity at prices greater than amounts received in revenues.

In November 2000, the Company filed applications seeking deferred accounting treatment for future net power costs that vary from costs included in determining retail rates in the states of Utah, Idaho, Wyoming and Oregon. The Company has received approval of deferred accounting treatment from these states to cover a portion of these cost variances. This will help mitigate a portion of the adverse effect of higher market prices, assuming that recovery mechanisms are implemented as anticipated. The Company requested recovery from customers in Utah, Oregon, Wyoming and California of increasing costs and has also requested power cost adjustments in Oregon and Wyoming. These power cost adjustments provide for continued periodic adjustment of rates for costs incurred that vary from costs included in tariffed rates.

Public utilities in the western United States, including the Company, and governors in the western states, have all been promoting conservation as a method to ease the current and potential future energy shortage. Actions have been initiated to pay industrial and commercial electricity users to forgo power consumption by shutting down their operations so that power could be redistributed to other uses and residential customers. The Company has participated in such power redistribution through its voluntary Demand Side Management program. The Company is also addressing supply and demand issues through contracting power from customer-owned generation, providing consumer education about conservation, working with regulators to develop rate structures to promote conservation and providing monetary incentives to customers for reduction in usage. These actions along with increasing prices paid by customers for power may reduce the rate of electricity consumption.

Disruptions in the western electricity market have had a negative impact on the willingness of the financial markets to provide financing on conditions and at rates that have historically been available to the Company. At March 31, 2001, PacifiCorp had a $500 million committed bank revolving credit agreement that expires in August 2001. The Company relies upon this facility in part to provide committed back-up for short-term borrowing and for daily liquidity requirements for $175 million of unenhanced pollution control

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revenue bonds. The Company is currently seeking to replace the existing credit facility. While the Company believes this facility will be successfully replaced at costs marginally higher than historical rates, no assurances can be given as to this outcome. Regulatory authorities limit PacifiCorp to $1.5 billion of short-term debt, of which $241 million was outstanding at March 31, 2001 at a weighted average rate of 5.7%. See Notes 7 and 8 of Notes to the Consolidated Financial Statements under ITEM 8 for additional information.

While in 2001, the Company incurred a greater cost of purchasing power at higher prices than the benefit received from making wholesale sales in the market, the impact was mitigated by the Company's overall near balanced supply and demand portfolio. Other utilities in the WSCC have been severely impacted as a result of purchasing electricity to cover load at prices higher than could be recovered in retail rates and wholesale prices. This impact, coupled with significantly higher natural gas prices and the effects of the California power market restructuring, led to SCE and PG&E defaulting in the fourth quarter of 2001 on payments owed to various creditors. In April 2001, PG&E filed for Chapter 11 reorganization. These defaults have resulted in the subsequent defaults by the CPX, the Cal ISO and the Automated Power Exchange. The Company has limited exposure to these California entities at March 31, 2001. The exposure that the Company has to other entities that have been counterparties in energy transactions with these California entities could be significant depending on the level of purchases and sales that existed and continues with these defaulting entities. The ramifications to future operations in the WSCC from these events are uncertain.

The Company's operations are exposed to risks, including legislative and governmental regulations, the price and supply of purchased power, fuel and natural gas, recovery of purchased power costs and purchased natural gas costs, weather conditions, availability of generation facilities, competition, technology and availability of funding. In addition, the energy business exposes the Company to the financial, liquidity, credit and commodity price risks associated with wholesale sales and purchases. For additional information, see "Business Risk."

Domestic electric operations' contribution to earnings on common stock was $110 million in 2001. After adjusting earnings by $5 million for merger costs and $27 million for regulatory asset write backs, the contribution would have been $88 million. Domestic electric operations' earnings contribution in 2000 was $11 million. After adjusting 2000 earnings by $177 million for merger costs and a write-off of projects under construction of $15 million, the contribution would have been $203 million. The $115 million decrease in adjusted earnings was the result of several factors, including the unprecedented short-term firm and spot market prices, lower hydro resources, load increases and the adverse effect of the Hunter unit outage.

Australian electric operations' recorded a loss of $187 million in 2001. This $226 million decrease from the prior year was primarily due to the $218 million loss recorded at Australian electric operations on its sale in 2001.

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Other operations reported a net loss of $29 million in 2001 as compared to earnings of $14 million in 2000. A primary cause of this change was the decrease in 2001 of PFS's earnings contribution, primarily due to the Company's inability to use tax credits of $28 million and a decrease in operating income of $6 million, generated by the synthetic fuel operations owned by subsidiaries of PFS. Interest income in 2001 increased $8 million compared to the prior year as a result of an increase in investments of cash received from the sale of Australian electric operations. Interest expense decreased $8 million due to a decrease in debt balances.

The Company's combined federal and state effective income tax rate from continuing operations was 196% for 2001, 62% for 2000, and 35% for 1998. The tax rate in 2001 varied from the statutory rate primarily due to the substantially nondeductible losses on the sales of its Australian operations and reserves for tax on outstanding Internal Revenue Service examination issues. The primary cause for the variance from the statutory tax rate in 2000 was the nondeductible nature of many merger costs. For a reconciliation of effective tax rate to statutory rate, see Note 15 of Notes to the Consolidated Financial Statements under ITEM 8.

A report on Form 10-Q for the three-month transition period of January 1, 1999 through March 31, 1999 was filed with the Securities and Exchange Commission on January 13, 2000. Pages 13 through 20 thereof are incorporated herein by reference.

FORWARD-LOOKING STATEMENTS

The information in the tables and text in this document includes certain forward-looking statements that involve a number of risks and uncertainties that may influence the financial performance and earnings of the Company. When used in this "Management's Discussion and Analysis of Financial Condition and Results of Operations," the words "estimates," "expects," "anticipates," "forecasts," "plans," "intends" and variations of such words and similar expressions are intended to identify forward-looking statements that involve risks and uncertainties. There can be no assurance the results predicted will be realized. Actual results will vary from those represented by the forecasts, and those variations may be material.

The following are among the factors that could cause actual results to differ materially from the forward-looking statements: utility commission practices; political developments; regional, national and international economic conditions; weather and behavioral variations affecting customer usage; competition and supply in bulk power and natural gas markets; hydroelectric and natural gas production; coal quality and prices; unscheduled generation outages; disruption or constraints to transmission facilities; hydro-facility relicensing; energy purchase and sales activities; environmental, regulatory and tax legislation, including industry restructure and deregulation initiatives; nonperformance by counterparties; technological developments in the electricity industry; proposed asset dispositions and the cost and availability of debt and equity capital. Any forward-looking statements issued by the Company should be considered in light of these factors.

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DOMESTIC ELECTRIC OPERATIONS

OVERVIEW

The year 2001 was a period of unprecedented change in the utility and energy businesses. Market forces described above drove record increases in purchased power prices and economic growth tightened the availability of excess power. During the period, the Company, along with other WSCC companies, was required to purchase power at unprecedentedly high short-term firm and spot market prices. The increase in power prices was driven by numerous factors, including increased load demands resulting from economic growth in the region, unusually low hydroelectric conditions, and unplanned outages in generation facilities in the WSCC, along with high natural gas prices. On November 24, 2000, the Company's Hunter power plant experienced a failure of a 430 MW generation unit that returned to service during May 2001. In May 2000, the Company sold the Centralia plant and mine, which had contributed up to 637 MW of the Company's generation portfolio. While these market conditions contributed to doubling of wholesale revenues to $2.08 billion, the $1.05 billion increase in wholesale revenues was more than offset by the $1.52 billion, or 159%, increase in purchased power costs.

Domestic electric operations' contribution to earnings on common stock was $110 million in 2001 compared to $11 million in 2000. The nondeductible nature of most merger costs contributed to an effective tax rate of 81% in 2000 compared to 41% in 2001 for Domestic electric operations.

Income before income taxes was $216 million in 2001 and $155 million in 2000. Significant, nonrecurring items in 2001 include $9 million pretax in merger costs and regulatory asset write backs of $43 million pretax, which reduced operating expenses. After adjusting for these nonrecurring items, income before income taxes would have been $182 million in 2001. Significant, nonrecurring expenses in 2000 included $207 million pretax in merger costs and $23 million of write-offs of assets under construction. After adjusting for these nonrecurring items, income before income taxes would have been $385 million in 2000. This $203 million decrease in adjusted income before income taxes was primarily the result of the net unfavorable impact of a reduction in wholesale sales volume and increased purchased power costs described above, partially offset by retail and other revenue growth of $194 million and decreased other operations and maintenance and administrative, general and other tax expense.

The Company achieved $101 million, or 12%, reduction in operations and maintenance and administrative, general and other tax expense, which can be largely attributed to savings realized in implementation of the Transition Plan, the May 2000 sale of the Centralia plant and mine, and a favorable variance due to the $23 million pretax prior year write-off of assets under construction. See Notes 2, 5 and 17 of Notes to the Consolidated Financial Statements under ITEM 8.

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REVENUES

Total Domestic electric operations revenues increased $1.24 billion, or 38%, from 2000 to $4.53 billion in 2001. This was primarily attributable to increases in wholesale sales of $1.05 billion and a $134 million increase in retail revenues.

Wholesale revenues increased $1.05 billion, or 102%. Sales prices for short-term firm and spot market sales averaged $107 per MWh in 2001 compared to $27 per MWh in 2000, resulting in a price related increase of $1.56 billion. Partially offsetting this was a 27% decrease in short-term firm and spot market sales that decreased revenues by $560 million. This decrease in volume was due to the sale of the Centralia plant, the decrease in hydro availability, the outage of the Hunter unit, and the increase in load requirements, all of which impacted the amount of available power to sell on the short-term and spot market. Increased prices and volumes relating to long-term firm contracts added $36 million and $13 million, respectively, to revenues.

Residential revenues increased by $53 million, or 7%. Growth in the average number of customers of 2% added $14 million to revenues. Price increases in Oregon, Utah and Wyoming added $27 million to revenues in 2001. Volume increases of 3%, primarily due to weather, increased residential revenues by $12 million.

Industrial revenues increased $36 million, or 5%. Price increases in Oregon, Utah and Wyoming increased revenues by $31 million. Increased irrigation usage added $9 million to revenues.

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Commercial revenues increased $43 million, or 6%, primarily as a result of strong economic activity in Utah and Oregon. Growth in the average number of commercial customers of 3% added $22 million to revenues and volume increases of 6% added $20 million to revenues.

Other revenues increased by $60 million, or 82%, primarily due to an increase in wheeling revenues from increased usage of the Company's transmission system by third parties.

2000 compared to 1998 - Revenues decreased 32%, or $1.55 billion, in 2000 primarily due to decreased wholesale energy volumes. A 75% decrease in short-term firm and spot market sales volumes decreased wholesale revenues by $1.56 billion. This volume reduction was the result of a decision made in prior years to scale back wholesale sales volumes from 1998 levels. Residential revenues decreased $8 million primarily due to the effect of the 1998 Utah rate order that lowered revenues in 2000, partially offset by customer growth. Industrial revenues decreased $11 million primarily due to the effect of the Utah rate order and open access pilot programs in Oregon. Commercial revenues increased $14 million primarily due to customer growth and increased customer usage, partially offset by the effect of the Utah rate order. Other revenues increased $7 million primarily due to increased wheeling revenues.

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OPERATING EXPENSES

Operating expenses increased $1.38 billion, or 51%, to $4.08 billion in 2001. This was primarily attributable to increased purchased power expense due to significantly increased prices on short-term firm and spot market purchased power and an increase in the volume purchased resulting from increased demand. Additional factors included a decrease in the Company's system generation resulting from the outage of the Hunter unit, the decrease in hydro availability, and the sale of the Centralia plant and mine.

Purchased power expense was $2.48 billion, an increase of $1.52 billion, or 159%. Significantly higher prices on short-term firm and spot market purchases increased purchased power expense by $1.25 billion, which is net of the effect of deferred accounting treatment received from the regulatory authorities in Utah, Oregon, Wyoming, and Idaho of $139 million for power costs that vary from costs included in determining rates. Supply in the WSCC did not keep pace with increased demand due in large part to economic growth. These factors, along with unanticipated generation outages in the WSCC, including the outage at the Company's Hunter unit, and the reduction in supply from hydroelectric facilities due to unusually low precipitation, led to increases in the level and volatility of power prices in 2001. Short-term firm and spot market purchase prices averaged $103 per MWh in 2001 compared to $28 per MWh in 2000. Short-term firm and spot market purchase volumes were flat compared to the prior year. Increased prices and volumes relating to long-term firm contracts added $92 million and $105 million, respectively, to purchased power expense. Increased usage of transmission systems owned by third parties added $43 million to expense.

Fuel expense decreased $21 million, or 4%, to $491 million. This decrease is attributed to an 8% reduction in thermal generation to 48.5 million MWh, which reflects the May 2000 sale of the Centralia plant and the unplanned Hunter unit outage. Additionally, hydroelectric production decreased 37% to 3.4 million MWh due to unusually low rainfall in the region, which had the effect of increasing the average overall cost per MWh.

Total operations and maintenance expense and administrative, general and other tax expense decreased by $101 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, other than income taxes discussed below.

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Other operations and maintenance expense decreased $19 million, or 4%. The sale of the Centralia plant and mine drove a $6 million decrease in expense. Bad debt expense decreased by $8 million. Operations and maintenance expense in 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 of $19 million resulting from an increasing amount of work relating to expense rather than capital projects.

Depreciation and amortization expense increased $9 million, or 2%, to $389 million primarily due to increased depreciation rates.

Administrative, general and taxes, other than income taxes decreased $82 million, or 27%. Decreased labor and severance costs contributed $51 million to this variance, including $14 million of merger costs recorded in the prior year. Employee related expenses decreased $33 million, primarily due to the impact of favorable returns on pension plan assets on pension expense.

Included within other operating income in 2001 was a $43 million gain relating to rate orders received which provided recovery for 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 plant and mine. See Note 17 of Notes to the Consolidated Financial Statements under ITEM 8.

2000 compared to 1998 - Operating expenses decreased $1.57 billion in 2000 primarily due to lower purchased power volumes. A 77% decrease in short-term firm and spot market energy purchases decreased purchased power expense by $1.58 billion. This volume reduction was the result of a decision made in prior years to reduce wholesale sales volumes from 1998 levels. Other operations and maintenance expense increased $93 million, which included $23 million of write-offs of assets under construction. In addition, costs reclassified from administrative and general upon conversion to the SAP software operating environment increased operations and maintenance expense by $15 million in 2000 and an increasing amount of work relating to operations and maintenance rather than capital projects added $14 million. Increased materials and contracts primarily relating to steam plant overhaul costs added $11 million to operations and maintenance expenses, increased employee costs added $9 million, and increased collection activity added $8 million. Administrative, general and taxes, other than income taxes expense decreased $31 million. This decrease includes $15 million of costs reclassified to operations and maintenance expense in 2000 and a $16 million decrease in SAP and Year 2000 conversion and other consulting costs. Special charges in 1998 consisted of the costs of an early retirement and cost reduction program.

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INTEREST EXPENSE AND OTHER, INCOME TAX EXPENSE AND PREFERRED DIVIDENDS

Domestic electric operations interest expense decreased $16 million primarily due to proceeds received from asset sales and dividends received from Holdings that were used to pay down intercompany and external debt balances. The 2000 results included $191 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 2 of Notes to the Consolidated Financial Statements under ITEM 8.

Income tax expense decreased $38 million due to nondeductible merger costs in the prior year, partially offset by higher taxable income in the current year. The nondeductible nature of most merger costs contributed to an effective tax rate of 81% in 2000 compared to 41% in 2001 at Domestic electric operations. For a reconciliation of effective tax rate to statutory rate, see Note 15 of Notes to the Consolidated Financial Statements under ITEM 8.

2000 compared to 1998 - Interest expense was $51 million lower primarily due to the dividends received from Holdings that were used to pay down intercompany and external debt balances. Merger costs were $177 million higher primarily due to taxes paid for stock transfers to complete the merger and the merger credits ordered in various states. Income tax expense was $22 million higher primarily due to an increase in nondeductible merger transaction costs, partially offset by the decline in taxable income. The nondeductible nature of most merger costs contributed to an effective tax rate of 81% in 2000 compared to 41% in 1998 at Domestic electric operations. For a reconciliation of effective tax rate to statutory rate, see Note 15 of Notes to the Consolidated Financial Statements under ITEM 8.

INDUSTRY CHANGE, COMPETITION AND DEREGULATION

Industry Change - The electric power industry continues to experience change. The key driver for this change is public, regulatory and governmental support for replacing the traditional cost-of-service regulatory framework with an open market competitive framework where the customers have a choice of energy supplier. The pace at which this change will occur has slowed as regulators and legislators struggle with conversion and implementation issues. Current market prices and California's attempt to implement a form of deregulation and its consequences on the market have slowed the progress of deregulation in many areas of the western United States. However, federal laws and regulations

35

have been amended to provide for open access to transmission systems, and various states have adopted or are considering new regulations to allow open access for all energy suppliers. If portions or all of the Company's operations become deregulated, the Company's risks and opportunities would change, reflecting greater exposure to market forces and reduced or eliminated regulatory influence. Accordingly, the Company would also need to evaluate the appropriateness of applying SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation." Under deregulation, the Company may be required to discontinue its application of SFAS No. 71 to all or a portion of its business, which could result in a partial or complete write off of regulatory assets and liabilities. For additional information concerning the regulatory, competitive and environmental issues facing the Company, see "ITEM 1. BUSINESS - DOMESTIC ELECTRIC OPERATIONS - Regulation," "- Competition" and "- Environmental Issues." Also, see Note 5 of Notes to the Consolidated Financial Statements under ITEM 8 for information on accounting for the effects of regulation.

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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 its interest in 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 17 of Notes to the Consolidated Financial Statements under ITEM 8.

Australian electric operations' financial results for the period from January 1, 2000 to the dates of sale are included in the Company's financial results for the year ended March 31, 2001. Australian electric operations' financial results for the calendar year ended December 31, 1999 are included in the Company's financial results for the year ended March 31, 2000. For the purpose of this discussion, these financial results are referred to as "2001" and "2000" results, respectively.

Currency Exchange - The average currency exchange rate for converting Australian dollars to United States dollars was 0.60 in 2001 compared to 0.65 in 2000, an 8% decrease for the year. The net effect of the exchange rate fluctuation had minimal net effect on Australian electric operations' earnings contribution in 2001. The following discussion excludes the effects of the lower currency exchange rate in 2001.

Results for 2001 are not directly comparable to 2000 as the sale of the Australian electric operations was substantially completed on September 6, 2000 so the 2001 results represent eight months of operations compared with the 12 months shown for 2000 .

In 2001, Australian electric operations contributed a loss of $187 million compared to earnings of $39 million in 2000. This decrease was primarily due to the $218 million loss recorded at Australian electric operations on the sale of Powercor and the 19.9% interest in Hazelwood. See Note 17 of Notes to the Consolidated Financial Statements under ITEM 8.

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REVENUES

OPERATING EXPENSES

INTEREST EXPENSE AND OTHER AND INCOME TAXES

Overall, 2001 results (excluding the loss on the sale) are lower than in 2000 due to a shorter period of operation resulting from the sale. The following discussion is a comparison of the eight-month period of ownership in 2001 to the same eight-month period in 2000. Australian electric operations' total 2001 revenues increased $13 million compared to the 2000 period. The increase was primarily due to an increase in volume. Total operating expenses increased $220 million, primarily due to a $218 million loss recorded on the sale of the Australian electric operations. Purchased power expense decreased $17 million primarily due to the impact of a favorable court ruling in resolution of a dispute with one of Powercor's suppliers. An increase in administrative and general expenses of $15 million was primarily due to costs associated with a project to transition to full retail contestability. Interest expense for the eight-month period in 2001 was approximately $2 million higher than the expense in the 2000 period. After adjusting pretax earnings for the loss on the sale of Australian electric operations, income taxes increased by $3 million, primarily due to an increase in taxable income. See Note 15 of Notes to the Consolidated Financial Statements under ITEM 8 for a discussion of the income tax treatment on the loss from the sale.

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2000 compared to 1998

The average currency exchange rate for converting Australian dollars to United States dollars was 0.65 in 2000 compared to 0.63 in 1998, a 3% increase for the year. The net effect of the exchange rate fluctuation on net income was minimal in 2000. The following discussion reflects variances without the effects of the higher currency exchange rate in 2000.

Revenues decreased $13 million, or 2%, in 2000 primarily due to a 3% decrease in energy sales volumes. Revenues within Powercor's franchise area decreased $2 million due to price decreases for customers and $17 million due to a 378 million kWh decrease in volumes. Other revenues increased $7 million primarily due to recognition of a sales tax contract settlement payment received from the Australian Government of $4 million and refunds received with the dissolution of the Victoria Power Exchange of $2 million.

Operating expenses decreased $20 million, or 4%, in 2000. Total purchased power expense decreased $2 million. Other operations and maintenance expense decreased $39 million. The decrease in expense was related to an increase in external network revenue of $18 million relating to customers within Powercor's distribution area being supplied electricity by competitors, a decrease in external network fees of $11 million and a $9 million decrease due to reclassification to administrative and general of construction service expense. Administrative, general and taxes, other than income taxes increased $22 million. An increase of $9 million was attributable to the aforementioned reclassification from other operations and maintenance. Restructuring costs increased $4 million over 1998. A project to transition to full retail contestability increased expenses by $3 million, and salaries and incentives increased $4 million. Income taxes increased by $16 million, primarily due to an increase in taxable income.

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OTHER OPERATIONS

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

Other operations reported a loss of $29 million for 2001 compared to earnings of $14 million in 2000.

In 2001, earnings contribution decreased due to the Company's inability to use tax credits of $28 million and a decrease in operating income of $6 million, both related to the synthetic fuel operations owned by subsidiaries of PFS. The Company did not have sufficient income tax liability to utilize all of the alternative fuel credits generated by these operations. See Note 15 of Notes to the Consolidated Financial Statements under ITEM 8. 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 17 of Notes to the Consolidated Financial Statements under ITEM 8. Additionally, interest income in 2001 increased $8 million compared to the prior year as a result of an increase in investments of cash received from the sale of Australian electric operations. Interest expense decreased $8 million due to a decrease in debt balances. In 2000, results included losses associated with exiting energy development businesses of approximately $7 million, as well as merger costs of $3 million. A write down, to anticipated net realizable value, of off-lease assets that are being sold increased the loss by $5 million in 2001.

Other - net includes tax expense related to reevaluation of tax liabilities from settled and ongoing tax examinations. For a reconciliation of effective tax rate to statutory rate, see Note 15 of Notes to the Consolidated Financial Statements under ITEM 8.

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2000 compared to 1998 - Earnings contribution of Other operations in 2000 increased $66 million compared to 1998. Results for 1998 included a loss of $32 million related to the decision to shut down or sell the Company's energy development businesses. Additionally, there was a loss of $55 million associated with the Company's terminated bid for The Energy Group ("TEG") and closing associated foreign exchange positions. The loss associated with TEG was partially offset by a gain of $10 million on the sale of TEG shares. In comparison, earnings in 2000 included a decrease in interest income of $31 million, resulting from a reduction in investments due to dividend payments made by Holdings to Domestic electric operations, offset by an increase of earnings at PFS's synthetic fuel operations of $13 million.

DISCONTINUED OPERATIONS

Discontinued operations reported earnings in 2000 of $1 million compared to losses of $147 million in 1998. The 1998 results included $105 million for the loss anticipated to exit the eastern United States energy trading business and a loss of $42  million for operating losses prior to the decision to exit. On April 1, 1999, Holdings sold TPC for $150 million. Exiting these energy trading activities resulted in a net after-tax gain of $1 million in 2000. See Note 4 of Notes to the Consolidated Financial Statements under ITEM 8.

In 1998, the pretax loss associated with exiting the eastern United States energy trading business was $155 million. This loss consisted of write downs of intangible assets of $83 million and the costs to exit a portion of the business and sell another portion of the business of $72 million. The exiting costs included anticipated severance payments and operating costs to the selling date and selling expenses. The remaining values for these businesses represented the estimated market value of the fixed assets of the companies and the estimated remaining working capital at the sale date.

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LIQUIDITY AND CAPITAL RESOURCES

OPERATING ACTIVITIES

Cash flows from continuing operations decreased $118 million from 2000 to 2001. This decrease was largely due to the impact of significantly higher purchased power prices on net income, combined with regulated rates that did not reflect the costs to purchase power, which were only partially offset by cash from working capital increases. The Company has received deferred accounting treatment for a portion of net power costs that vary from costs included in determining retail rates in the states of Utah, Oregon, Idaho, and Wyoming, and is currently working with these states to develop recovery mechanisms for the deferred costs. Additionally, the Company has asked for rate increase requests before the state commissions in California, Oregon, Utah and Wyoming. For more detail on deferred power cost and rate increase filings, see "ITEM 1. DOMESTIC ELECTRIC OPERATIONS - Regulation."

INVESTING ACTIVITIES

Capital spending totaled $486 million in 2001 compared with $574 million in 2000. Construction expenditures decreased in 2001 primarily due to lower expenditures at Domestic electric operations, which can be attributed to the sale of the Centralia plant and mine and timing of capital projects. Proceeds from asset sales in 2001 were primarily the result of the sales of Powercor, the Company's interest in Hazelwood and the Centralia plant and mine, while proceeds from asset sales in 2000 were attributable to the sale of TPC.

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 its interest in 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 17 of Notes to the Consolidated Financial Statements under ITEM 8.

On May 4, 2000, the utility partners who owned the 1,340 MW coal-fired Centralia Power Plant sold the plant and the adjacent coal mine owned by the Company to TransAlta for approximately $500 million. See Note 17 of Notes to the Consolidated Financial Statements under ITEM 8.

On April 1, 1999, Holdings sold TPC for $150 million. Exiting its energy trading business in the eastern United States and its other energy development businesses resulted in a net after-tax gain of $1 million in the first quarter of 2000.

FINANCING ACTIVITIES

In November 2000, the Company retired $176 million of junior subordinated debentures with a portion of the proceeds from the Powercor sale.

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

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During 2001, the Company declared dividends on common stock of $390 million and paid dividends on common stock of $332 million to an indirect subsidiary of ScottishPower. On November 16, 2000, the Company declared a dividend on common stock of $80 million, of which $22 million was paid on February 12, 2001 and $58 million was payable at March 31, 2001. These dividends were declared at a rate that is consistent with the Company's historic pre-merger rate per share. See Note 18 of Notes to the Consolidated Financial Statements under ITEM 8.

The Company declared dividends of $15 million on preferred stock during 2001 and had $4 million in preferred dividends declared but unpaid at March 31, 2001.

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CAPITALIZATION

The Company manages its capitalization and liquidity position in a consolidated manner through policies established by senior management and the Board of Directors. These policies, subject to periodic review and revision, have resulted from a review of historical and projected practices for businesses and industries that have financial and operating characteristics similar to the Company and its principal business operations.

The Company's policies attempt to balance the interests of all shareholders, ratepayers and creditors. In addition, given the changes that are occurring within the industry and market segments in which the Company operates, these policies are intended to remain sufficiently flexible to allow the Company to respond to these developments.

On a consolidated basis, the Company attempts to maintain total debt at approximately 48% to 54% of capitalization. The total debt to capitalization ratio was 44% at March 31, 2001 as a result of paying down debt with proceeds from asset sales. The Company expects, over time, to maintain its capital structure in accordance with its targets. The Company also attempts to maintain a preferred stock ratio, including subordinated debt, at 8% to 12% of capitalization. The preferred stock ratio was 8% at March 31, 2001. The Company has made commitments in connection with the Merger not to make distributions that result in a reduction of common equity, without approval, to below 36% of total capitalization, increasing over time to 40%.

Long-term debt at March 31, 2000 included Australian electric operations debt of $841 million, which the buyer assumed as a condition of the sale.

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VARIABLE RATE LIABILITIES

The Company's capitalization policy targets consolidated variable rate liabilities at between 10% and 25% of total capitalization.

AVAILABLE CREDIT FACILITIES

At March 31, 2001, PacifiCorp had a $500 million committed bank revolving credit agreement that expires in August 2001. The Company relies upon this facility in part to provide for committed back-up for short-term borrowing and daily liquidity requirements related to $175 million of unenhanced pollution control revenue bonds. The Company is currently seeking to replace the existing credit facility. Regulatory authorities limit PacifiCorp to $1.5 billion of short-term debt, of which $241 million was outstanding at March 31, 2001 at a weighted average rate of 5.7%. See Notes 7 and 8 of Notes to the Consolidated Financial Statements for additional information under ITEM 8.

The Company believes that its existing and available capital resources and the anticipated replacement of the revolving credit facility will be sufficient to meet working capital, dividend and construction needs in 2002. While the Company believes the revolving credit facility will be successfully replaced at costs marginally higher than historical rates, no assurances can be given as to this outcome.

LIMITATIONS

In addition to the Company's capital structure policies, its debt capacity is also governed by its contractual commitments. PacifiCorp's principal debt limitation is a 60% debt to defined capitalization test contained in its principal credit agreements. Based on the Company's most restrictive agreement, management believes that PacifiCorp and its subsidiaries could have borrowed an additional $2.8 billion of debt at March 31, 2001.

Under PacifiCorp's principal credit agreements, it is an event of default if any person or group, other than ScottishPower, acquires 35% or more of PacifiCorp's common shares or if, during any period of 14 consecutive months, individuals who were directors of PacifiCorp on the first day of such period (and any new directors whose election or nomination was approved by such individuals and directors) cease to constitute a majority of the Board of Directors.

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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 capacity, scheduled and unscheduled outages of generating facilities, hydroelectric availability, prices and availability of fuel sources for generation, disruptions or constraints to transmission facilities, weather conditions, economic growth, transmission capacity and other factors. The Company has been experiencing the adverse effect of higher market prices due to inadequate generating capacity in the WSCC, generating facility outages in the WSCC, including the unscheduled outage of the Company's Hunter unit, lower hydro availability, high natural gas prices and increases in demand throughout the WSCC due in large part to economic growth.

During 2001, significant price volatility, driven in part by the change in 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 through retail rates and wholesale prices. The Company has filed applications seeking deferred accounting treatment for net power costs that vary from costs included in determining retail rates in the states of Utah, Idaho, Wyoming and Oregon. Approval of certain cost deferrals has been received in these states, and the Company is working with the commissions in these states to develop mechanisms for the recovery of these cost deferrals. Approval of deferred accounting treatment mitigates a portion of the price risk, assuming that recovery mechanisms are implemented as anticipated. The Company has recorded approved deferred amounts as regulatory assets. If recovery mechanisms are not implemented as anticipated, the Company would write off these regulatory assets. See Note 5 of Notes to the Consolidated Financial Statements under ITEM 8.

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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, among other factors. Physical supply constraints have led to rolling blackouts in certain areas of the WSCC. None of the Company's service territory has experienced such severe constraints, although resources and demand in the region are in a tightly 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 that materially affect the Company's operations; however, the situation may change favorably or adversely in the future.

The Company is subject to the jurisdiction of federal and state regulatory authorities. The rates the Company may charge its retail customers are determined by these regulators. The rates authorized by the regulators may be less than the costs to the Company to provide electrical service to its customers.

Nearly all of the Company's hydroelectric projects are in some stage of relicensing under the FPA. The relicensing process is an extremely political and public regulatory process that involves controversial resource issues. The Company is unable to predict the requirements that may be imposed during the relicensing process, the economic impact of those requirements, whether new licenses will ultimately be issued or whether the Company will be willing to meet the relicensing requirements to continue operating its hydroelectric projects. For more information on hydroelectric relicensing, see "DOMESTIC ELECTRIC OPERATIONS - Regulation" under ITEM 1.

Federal, state and local authorities regulate many of the Company's activities pursuant to laws designed to restore, protect and enhance the quality of the environment. The Company is unable to predict what material impact, if any, future changes in environmental laws and regulations may have on the Company's consolidated financial position, results of operations, cash flows, liquidity, and capital expenditure requirements. For more discussion related to environmental issues, see "DOMESTIC ELECTRIC OPERATIONS - Environmental Issues" under ITEM 1.

Credit Risk

Credit risk relates to the risk of loss that might occur as a result of nonperformance 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

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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 purchase and sales transactions within the WSCC, including those in California, and uses a variety of risk mitigation techniques to limit its exposure where it believes appropriate. At March 31, 2001, the Company had receivables of $1 million from SCE, a less than investment grade purchaser of power, $1 million from San Diego Gas and Electric Co., and no receivable directly from PG&E, a company that filed for Chapter 11 reorganization in April 2001. The Company has not taken specific reserves against these amounts. The Company, like all participants in the regional market, has exposure to other participants who may have credit exposure to the utilities in California. To mitigate exposure to the financial risks of these counterparties, the Company has entered into netting, margining and guarantee arrangements. The Company calculates reserves for all of its credit exposure by grouping counterparties, based upon managerial judgment and rating, and then calculating a reserve based upon a ratings agency historical default rate.

At March 31, 2001, the Company had no receivables related to its direct energy transactions with the CPX and a receivable of $6 million from the Cal ISO. The majority of this amount has been reserved based on the estimated amounts indirectly receivable from companies defaulting on payments to Cal ISO. Under default provisions contained in the CPX tariff, the CPX has charged back some of the defaults of CPX participants to remaining participants, including the Company, based upon the level of purchase and sales activity of each participant during the preceding three-month period. The Company has paid $2 million in charge-backs to the CPX related to SCE's default on its payments to the CPX. Subsequent to this payment, FERC ruled that charge-backs are not permissible. As a result of this FERC ruling, the Company has recorded a receivable and demanded a refund of this $2 million charge-back from the CPX.

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 and manditorily redeemable preferred stock, 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 these costs are recovered from customers or longer term financing is completed. In January and February 2001, the Company's credit outlook was lowered by two credit rating agencies, citing the impact of high purchased power prices, the Hunter outage, and the uncertainty and expected delay between incurring and recovering the deferred power costs from customers. 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. The Company is currently seeking to replace its existing credit facility. The activity in the western electricity market has had a negative impact on the willingness of the financial markets to provide financing on conditions and at rates that have

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prices for its commodity derivatives. The fair value of such positions are a summation of the fair values calculated for each commodity derivative by valuing each position and option at quoted futures prices or assumed forward prices.

EXPOSURE ANALYSIS

Interest Rate Exposure

The Company may use interest rate swaps, forwards, futures and collars to adjust the characteristics of its liability portfolio. This strategy is consistent with the Company's capital structure policy which provides guidance on overall debt to equity and variable rate debt as a percent of capitalization levels for both the consolidated organization and its principal subsidiaries.

The Company's risk to interest rate changes is primarily a noncash fair market value exposure and generally not a cash or current interest expense exposure. This is due to the size of the Company's fixed rate, long-term debt portfolio relative to variable rate debt.

The table below shows the potential loss in fair market value ("FMV") of the Company's interest rate sensitive positions, for continuing operations, as of March 31, 2000 and 2001, as well as the Company's quarterly high and low potential losses.

Commodity Price Exposure

The Company's market risk to commodity price change is primarily related to its electricity commodities which are subject to fluctuations due to unpredictable factors, such as weather, which impacts supply and demand. The Company's energy purchase and sales activities are governed by the derivative policy and the risk levels established as part of that policy.

The Company's energy commodity price exposure arises principally from its electric supply obligation in the United States. The Company manages this risk principally through the operation of its 7,832 MW generation and transmission system in the western United States and through its wholesale energy purchase and sales activities. Electricity futures contracts are utilized to hedge Domestic electric operations' excess or shortage of net electricity for future months. The changes in market value of such contracts have had a high correlation to the price changes of the hedged commodity.

Gains and losses relating to qualifying hedges of firm commitments or anticipated inventory transactions are deferred on the balance sheet and included in the basis of the underlying transactions.

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A sensitivity analysis has been prepared to estimate the Company's exposure to market risk related to commodity price exposure of its financial instrument derivative positions for electricity. Based on the Company's derivative price exposure at March 31, 2001 and 2000, a near-term adverse change in commodity prices of 10% would have no impact on 2001 pretax earnings and would negatively impact pretax earnings by $18 million in 2000. This decrease is a result of the sales of Australian electric operations and a subsidiary of Holdings in 2001.

INFLATION

Due to the capital-intensive nature of the Company's core businesses, inflation may have a significant impact on replacement of property, acquisition and development activities and final mine reclamation costs. To date, management does not believe that inflation has had a significant impact on any of the Company's other businesses.

NEW ACCOUNTING STANDARDS

The Company adopted SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities," as amended by SFAS No. 138, effective April 1, 2001. The statement requires that the Company recognize all derivatives, as defined in the statement, on the balance sheet at fair value. Derivatives, or any portion thereof, that are not an effective hedge, must be adjusted to fair value through income. If a derivative qualifies as an effective hedge, changes in the fair value of the derivative either will be offset against the change in fair value of the hedged asset, liability, or firm commitment recognized in earnings, or will be recognized in accumulated other comprehensive income until the hedged items are recognized in earnings.

Based on analysis to date, the Company expects that the most significant impact of complying with SFAS No. 133 will be the ongoing market adjustments to the income statement from wholesale purchase and sales activities that qualify for treatment as derivatives. Based on current interpretation of SFAS No. 133 and other guidance, the Company is classifying its wholesale forward contracts as follows:

- 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 shareholder's equity. Cash flow hedges are wholesale contracts for short-term purchases to cover probable load that may be settled for cash.

- Wholesale Purchases and Sales: The unrealized gains and losses related to these forward contracts will be reflected in the income statement. These contracts are the ones not classified as normal purchases and sales or cash flow hedges.

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(See accompanying Notes to the Consolidated Financial Statements)

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(See accompanying Notes to the Consolidated Financial Statements)

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(See accompanying Notes to the Consolidated Financial Statements)

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LIABILITIES, REDEEMABLE PREFERRED STOCK AND SHAREHOLDERS' EQUITY

(See accompanying Notes to the Consolidated Financial Statements)

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(See accompanying Notes to the Consolidated Financial Statements)

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(a)  Amounts include the Company's and minority interest joint owners' portion of mine reclamation costs.

(b)  At March 31, 2000, the Company had approximately $26 million accrued for its share of the Centralia mine reclamation costs. These reclamation costs were assumed by the buyer as a condition of the sale. See Note 17.

(c)  Expected to be paid over 19 years.

(d)  Expected to be paid over 22 years.

The Company had trust fund assets of $85.1 million and $100.5 million at March 31, 2001 and 2000, respectively, relating to mine reclamation, including minority interest joint owners' portion.

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INTEREST CAPITALIZED

Costs of debt and equity applicable to domestic electric utility properties are capitalized during construction. The composite capitalization rates were 7.3% for 2001, 7.9% for 2000 and 5.7% for 1998.

INCOME TAXES

The Company uses the liability method of accounting for deferred income taxes. Deferred tax liabilities and assets reflect the expected future tax consequences, based on enacted tax law, of temporary differences between the tax bases of assets and liabilities and their financial reporting amounts.

Prior to 1980, Domestic electric operations did not provide deferred taxes on many of the timing differences between book and tax depreciation. In prior years, these benefits were flowed through to the utility customer as prescribed by the Company's various regulatory jurisdictions. Deferred income tax liabilities and regulatory assets have been established for those flow through tax benefits. See Note 15.

Investment tax credits for regulated Domestic electric operations are deferred and amortized to income over periods prescribed by the Company's various regulatory jurisdictions.

Provisions for United States income taxes were made on the undistributed earnings of the Company's international businesses.

FOREIGN CURRENCY

Until sold, financial statements for foreign subsidiaries were translated into United States dollars at end of period exchange rates as to assets and liabilities and weighted average exchange rates as to revenues and expenses. The resulting translation gains or losses were accumulated in the "accumulated other comprehensive income" account, a component of common equity and comprehensive income. All gains and losses resulting from foreign currency transactions are included in the determination of net income.

DERIVATIVES

Gains and losses on hedges of existing assets and liabilities are included in the carrying amounts of those assets or liabilities and are recognized in income as part of the carrying amounts. Gains and losses relating to hedges of anticipated transactions and firm commitments are deferred on the balance sheet and recognized in income when the transaction occurs. Nonhedged derivative instruments are marked-to-market with gains or losses recognized in the determination of net income.

The derivative policy includes as its objective that interest rates and foreign exchange derivative instruments will be used for hedging and not for speculation. The derivative policy also governs the energy purchase and sales activities and is generally designed for hedging the Company's existing load and asset exposures.

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REVENUE RECOGNITION

The Company accrues estimated unbilled revenues for electric services provided after cycle billing to month-end.

COMPREHENSIVE INCOME

As permitted by SFAS No. 130, "Reporting Comprehensive Income," the Company has not included a statement of comprehensive income. Instead the Company included the amounts on the Statement of Consolidated Changes in Common Shareholders' Equity.

ENERGY TRADING

Revenues and purchased energy expense for PPM's energy trading and marketing activities are recorded upon settlement of transactions. Beginning January 1, 1999, in accordance with Emerging Issues Task Force ("EITF") 98-10, "Accounting for Contracts Involved in Energy Trading and Risk Management Activities," PPM applied mark-to-market accounting for all energy trading activities and presents the net margin in revenues. The energy trading activities were transferred to an affiliated company in 2001. See Note 17.

PREFERRED STOCK RETIRED

Amounts paid in excess of the net carrying value of preferred stock retired are amortized over five years in accordance with regulatory orders.

STOCK BASED COMPENSATION

As permitted by SFAS No. 123, "Accounting for Stock Based Compensation," the Company has elected to follow Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued to Employees" ("APB 25") and related interpretations in accounting for employee stock options issued to Company employees. Under APB 25, because the exercise price of employee stock options equals the market price of the underlying stock on the date of grant, no compensation expense is recorded. Upon completion of the Merger, PacifiCorp stock is no longer being issued for compensatory purposes. See Notes 2 and 16.

NEW ACCOUNTING STANDARDS

The Company adopted SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities," as amended by SFAS No. 138, effective April 1, 2001. The statement requires that the Company recognize all derivatives, as defined in the statement, on the balance sheet at fair value. Derivatives, or any portion thereof, that are not an effective hedge, must be adjusted to fair value through income. If a derivative qualifies as an effective hedge, changes in the fair value of the derivative either will be offset against the change in fair value of the hedged asset, liability, or firm commitment recognized in earnings, or will be recognized in accumulated other comprehensive income until the hedged items are recognized in earnings.

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Based on analysis to date, the Company expects that the most significant impact of complying with SFAS No. 133 will be the ongoing market adjustments to the income statement from wholesale purchase and sales activities that qualify for treatment as derivatives. Based on current interpretation of SFAS No. 133 and other guidance, the Company is classifying its wholesale forward contracts as follows:

- 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 shareholder's equity. Cash flow hedges are wholesale contracts for short-term purchases to cover probable load that may be settled for cash.

- Wholesale Purchases and Sales: The unrealized gains and losses related to these forward contracts will be reflected in the income statement. These contracts are the ones 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. On April 1, 2001, the Company expects to record the cumulative effects of adopting SFAS No. 133 in its financial statements by recording the following after-tax unrealized gains or losses on forward contracts as of April 1, 2001:

- Cumulative effect of a change in accounting principle:
  - Income Statement: $113 million of unrealized loss;
  - Other Comprehensive Income, a component of shareholders' equity:
    $617 million of unrealized gain;
- FAS 133 Contract asset - net: $102 million; and
- Regulatory asset - net: $711 million

The volatility of the wholesale power market, continual changes in the types of forward contracts of the Company and certain issues that are still being addressed by the Financial Accounting Standards Board (the "FASB") Derivatives Implementation Group ("DIG") may impact the amounts that have been and will be recognized under SFAS No. 133. The estimated effect of adopting SFAS No. 133 on April 1, 2001 assumes that the Company will receive regulatory orders directing 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 Company is required under SFAS No. 133 to classify certain of its sales and purchase contracts as derivatives. As a public utility, the Company's intent in entering into these contracts, generally, is to balance its electric

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load with available resources. When possible, the Company satisfies its load requirements with electricity from its owned generating facilities. While SFAS No. 133 requires 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 reports.

RECLASSIFICATION

Certain amounts from prior years have been reclassified to conform with the 2001 method of presentation. These reclassifications had no effect on previously reported consolidated net income.

NOTE 2  SCOTTISHPOWER MERGER

On November 29, 1999, the Company and ScottishPower completed the Merger under which the Company became an indirect subsidiary of ScottishPower. The Company continues to operate under its current name, and its headquarters remains in Portland, Oregon. As a result of the Merger, the Company became part of a public utility holding company group. The Company's operations are now subject to the requirements and restrictions of the Public Utility Holding Company Act of 1935.

Each share of the Company's common stock was converted tax-free into a right to receive 0.58 American Depositary Shares ("ADS") (each ADS represents four ordinary shares) or 2.32 ordinary shares of ScottishPower. Cash was paid in lieu of fractional shares.

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

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As a result of the Merger, the Company has implemented a transition plan (the "Transition Plan") with significant organizational and operational changes. The Company expects to reduce its workforce company-wide by approximately 1,600 from 1998 levels over a five-year period ending in 2005, mainly through early retirement, voluntary severance and attrition. The estimated early retirement and severance costs are being deferred and amortized over future periods, as ordered by the various utility commission accounting orders received by the Company. The Company recorded $158 million in regulatory assets and $17 million in deferred charges as a result of the accounting orders issued by state regulatory bodies for these estimated costs. As of March 31, 2001, the Company had $63 million of accrued liabilities in deferred credits - other relating to these early retirement and severance costs. Below is a summary of the accrual recorded and payments made during 2001 related to the deferred costs described above.

NOTE 3  BID FOR THE ENERGY GROUP

During 1997 and 1998, the Company sought to acquire The Energy Group PLC ("TEG"), a diversified international energy group with operations in the United Kingdom, the United States and Australia. In March 1998, another United States utility made a tender offer at a price higher than the Company's offer and on April 30, 1998, the Company announced that it would not increase its revised offer for TEG.

The Company recorded an $89 million pretax charge ($55 million after-tax) to 1998 earnings, included in "TEG costs," for bank commitment and facility fees, foreign currency option contract expense, legal expenses and other related costs incurred since the Company's original bid for TEG in June of 1997. These costs had been deferred pending the outcome of the transaction.

Additionally, in connection with the attempt to acquire TEG, a subsidiary of the Company purchased approximately 46 million shares of TEG at a price of 820 pence per share, or $625 million. The Company recorded a pretax gain on the TEG shares of $16 million ($10 million after-tax), included in "TEG costs," when they were sold on June 2, 1998.

NOTE 4  DISCONTINUED OPERATIONS

In October 1998, the Company decided to exit its energy trading business by offering for sale TPC, and ceasing PPM's electricity trading operations conducted in the eastern United States. PPM's activities in the eastern United States have been discontinued and all the related forward electricity trading

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has been closed. On April 1, 1999, Holdings sold TPC to NIPSCO Industries, Inc. for $150 million. Exiting these energy trading activities resulted in a net after-tax gain of $1 million in the first quarter of 2000.

During the year ended December 31, 1998, PPM's eastern energy trading and TPC generated revenues of $2.96 billion. The loss from those discontinued operations was $42 million, net of taxes of $24 million, and the loss on disposal was $105 million, net of income tax benefit of $50 million and $52 million of provision for operating losses during phase-out period. Net loss from discontinued operations for the year ended December 31, 1998 was $147 million.

At March 31, 2001 and 2000, Holdings had $8 million and $15 million, respectively, of liabilities in "Customer deposits and other" relating to discontinued operations.

NOTE 5  ACCOUNTING FOR THE EFFECTS OF REGULATION

Regulated utilities have historically applied the provisions of SFAS No. 71 which is based on the premise that regulators will set rates that allow for the recovery of a utility's costs, including cost of capital. Accounting under SFAS No. 71 is appropriate as long as: rates are established by or subject to approval by independent, third-party regulators; rates are designed to recover the specific enterprise's cost-of-service; and in view of demand for service, it is reasonable to assume that rates are set at levels that will recover costs and can be collected from customers. In applying SFAS No. 71, the Company must give consideration to changes in the level of demand or competition during the cost recovery period. In accordance with SFAS No. 71, Domestic electric operations capitalizes certain costs as regulatory assets in accordance with regulatory authority whereby those costs will be expensed and recovered in future periods.

The EITF of the FASB concluded in 1997 that SFAS No. 71 should be discontinued when detailed legislation or regulatory orders regarding competition are issued. Additionally, the EITF concluded that regulatory assets and liabilities applicable to businesses being deregulated should be written off unless their recovery is provided for through future regulated cash flows. The Company continuously evaluates the appropriateness of applying SFAS No. 71 to each of its jurisdictions. At March 31, 2001, management concluded that SFAS No. 71 was appropriate for its Domestic electric operations. However, if efforts to deregulate progress, the Company may in the future be required to discontinue its application of SFAS No. 71 to all or a portion of its business.

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

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Energy Regulatory Commission (the "FERC") as to accounting policies and practices, certain prices and other matters.

Regulatory assets include the following:

(a)  Excludes $107 million and $115 million as of March 31, 2001 and 2000, respectively, of investment tax credit regulatory liabilities.

(b)  Represents the unamortized amount of retirement and severance costs related to the Transition Plan that the state commissions allowed to be deferred and amortized. Recovery of the amortization is being sought in the general rate cases.

(c)  Represents the deferred net power costs that vary from costs included in determining retail rates in the states of Utah, Oregon, Idaho and Wyoming. The Company anticipates that it will get recovery of these costs.

(d)  Additional losses on debt reacquired in 2001 offset the amortization recorded during that year.

(e)  A UPSC order during 2001 allowed recovery of early retirement and pension costs, reclamation costs, and Year 2000 and other information system costs that had previously been written off.

Regulatory liabilities include the following:

(a)  Represents the gain on the sale of the Centralia plant and mine that is being returned to customers as ordered by the state commissions in connection with approving the sale. The gain amounts claimed by the jurisdictions the Company serves exceeded the actual gain on the transaction by $14 million resulting in a loss on sale that was recorded in Other operating income.

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The Company evaluates the recovery of all regulatory assets annually. The evaluation includes the probability of recovery as well as changes in the regulatory environment. Because of the potential regulatory and/or legislative action in Utah, Oregon, Wyoming, Idaho and Washington, the Company may have regulatory asset write-offs and charges for impairment of long-lived assets in future periods. Impairment would be measured in accordance with the Company's asset impairment policy. See Note 1.

DEPRECIATION RATE INCREASE

During 1998, the Company filed new depreciation rates in the states of Oregon, Utah and Wyoming based upon a depreciation study. New depreciation rates were filed in Washington as part of a general rate case filing. New depreciation rates were approved by the commissions during 2000. The impact of the proposed changes in depreciation is being incorporated into the current general rate cases in Utah, Oregon and Wyoming. Based on the depreciation rates that have been approved, annual depreciation expense would be increased by approximately $20 million. The increase in depreciation expense is primarily due to revisions of the estimated costs of removal for steam production and distribution plants. For the period April 1, 2000 to March 31, 2002, the Utah and Wyoming commissions have ordered a reversal of a portion of previously accrued depreciation. These reversals in total, for both states, will amount to approximately $14 million per year for two years.

MERGER CREDITS

As a result of the Merger, the Company is required to provide benefits to rate payers through fixed reductions in rates or "Merger Credits." The Company's total obligation for merger credits is $133.4 million through the period ending December 31, 2004. A portion of this amount must be provided without offset or reduction of any kind and, accordingly, the Company recorded $57.2 million as a liability and current expense in its financial statements for the year ended March 31, 2000. In the second quarter of 2001, the Company recorded $12 million as a liability and current expense in relation to the August 9, 2000 order from the WUTC, which impacted the Company's ability to offset merger credits in the future. See Note 2. The remaining $64.2  million obligation of the Company with respect to merger credits is subject to possible offset if the Company demonstrates in a future rate case, to the satisfaction of the respective commissions, that merger-related cost reductions have occurred and are being reflected in rates. This $64.2 million obligation will be reflected in future periods.

RATE INCREASES GRANTED

On October 25, 2000, the WUTC 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.

On September 27, 2000, the Company received an order from the OPUC authorizing increased prices in Oregon for residential customers of 2.33%, commercial and small industrial customers of 1.37%, large industrial customers of 0.4%, and

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public street lighting customers of 1.27%. These price increases are expected to result in annual revenues of $14 million. The order was effective on October 1, 2000.

On August 9, 2000, the Company received an order from the WUTC that authorized the Company to increase rates by 3% on September 1, 2000, 3% on January 1, 2002 and 1% on January 1, 2003.

On June 20, 2000, the Company received approval from the OPUC for an overall price increase of 1.8%, or $13.7 million, through an annual adjustment as part of the alternative form of regulation ("AFOR") process previously authorized in Oregon. Of this amount, approximately $10 million is offset by costs mandated by regulators. The increase will cause rates for residential customers to rise by 2.9%, for large industrial users by 1.1%, and for commercial customers by 0.5%. The new rates took effect July 1, 2000 and are expected to increase annual revenues by approximately $3.7 million net of costs mandated by the OPUC. The AFOR is authorized to run through June 30, 2001. Existing rates in Oregon will continue unchanged after the AFOR's termination until new rates are authorized by the OPUC.

On May 25, 2000, the Company received an order from the WPSC authorizing an increase in prices, which is expected to result in increased annual revenues of $11 million. The Company received authorization for an additional $1 million increase effective July 19, 2000.

On May 24, 2000, the Company received an order from the UPSC authorizing increased prices in Utah for residential, irrigation, small commercial and lighting customers of 4.24% and large commercial and industrial customers of less than 1%. These price increases are expected to result in additional annual revenues of $17 million. The order was effective on May 25, 2000 and allowed recovery of early retirement and pension costs, reclamation costs, and Year 2000 and other information systems costs that had previously been written off. As a result, $17 million in regulatory assets was established in the first quarter of 2001 relating to cost recoveries which required no additional review and $25 million in regulatory assets was established in the second quarter of 2001 relating to cost recoveries which successfully passed additional review. An additional $7 million may be recovered in future periods following further review.

DEFERRED POWER COST FILINGS

On November 1, 2000, the Company filed applications seeking deferred accounting treatment for net power costs that vary from costs included in determining retail rates in the states of Utah, Idaho, Wyoming, and Oregon. The applications sought to defer these power cost variances 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 that vary from 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 the power cost variances not related to the Hunter outage, the Utah deferred accounting filing was effectively amended by stipulation to include only the cost variances associated with the Hunter outage. Hunter deferred accounting was adopted by the Commission effective November 24, 2000, the date the outage began. During 2001, the Company has deferred $79 million relating to the Utah approval of the power cost variances related to Hunter.

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 is 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 has 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 February 12, 2001, the IPUC approved the Company's deferred accounting filing for all power costs that vary from the level assumed in Idaho rates for the period November 1, 2000 through October 31, 2001, including costs to replace lost generation resulting from the Hunter unit outage. The Company has deferred $11 million related to this approval as of March 31, 2001.

Approval for deferral of power costs that vary from rate assumptions was received from the WPSC on November 30, 2000. The Company is currently working with the WPSC to develop a power cost adjustment mechanism for recovery of these deferred amounts. During 2001, $27 million of power costs were deferred, which encompassed all net purchased power costs that varied from the level in Wyoming rates since November 30, 2000, including costs to replace lost generation resulting from the Hunter unit outage.

NOTE 6  SPECIAL CHARGES

In January 1998, the Company announced a plan to reduce its work force in the United States by approximately 600 positions, or 7% of the work force in the United States. The Company offered enhanced early retirement to approximately 1,200 employees. The actual net work force reduction from this program was 759 positions, with 981 employees accepting the offer and 222 vacated positions backfilled. The pretax cost of $113 million ($70 million after-tax) was recorded in March 1998.

In the fall of 1998, the Company initiated a cost reduction program that included involuntary employee severance and enhanced early retirement for employees who met certain age and service criteria and were displaced in conjunction with the cost reduction initiatives. Approximately 167 employees were displaced, with 35 of them eligible for the enhanced early retirement, and the Company recorded a $10 million ($6 million after-tax) expense in special charges.

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Below is a summary of the accrual recorded and payments made during 1998 relating to the work force reduction initiatives described above.

As of March 31, 2001, substantially all of the remaining obligations relating to work force reduction initiatives had been satisfied.

NOTE 7  SHORT-TERM DEBT AND BORROWING ARRANGEMENTS

PacifiCorp's short-term debt and borrowing arrangements were as follows:

(a)  Computed by dividing the total interest on principal amounts outstanding at the end of the period by the weighted daily principal amounts outstanding.

At March 31, 2001, commercial paper and bank line borrowings were supported by a $500 million revolving credit agreement, which expires in August 2001. The Company is currently seeking to replace the existing credit facility.

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NOTE 8  LONG-TERM DEBT

The Company's long-term debt was as follows:

(a)  Pollution control revenue bonds of $71 million are secured by pledged first mortgage bonds generally at the same interest rates, maturity dates and redemption provisions as the pollution control revenue bonds.

(b)  Interest rates fluctuate based on various rates, primarily on certificate of deposit rates, interbank borrowing rates, prime rates or other short-term market rates.

(c)  In November 2000, the Company redeemed its Junior subordinated debentures with a portion of the proceeds from the Powercor sale.

(d)  The March 31, 2000 balance included debt of Australian subsidiaries of $412 million and long-term debt of Holdings of $250 million. In July 2000, Holdings paid off the $250 million of debt in anticipation of the Powercor sale. The Australian debt was assumed by the buyer as a condition of the sale.

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(e)  Interest rates fluctuated based on Australian Bank Bill Acceptance Rates. A revolving loan agreement required that at least 50% of the borrowings must be hedged against variations in interest rates. Approximately $413 million was hedged at March 31, 2000 at an average rate of 7% and for an average life of 4.5 years. The Companies had the ability to support short-term borrowings and current debt being refinanced on a long-term basis through revolving lines of credit and, therefore, based upon management's intent, had classified $429 million of short-term debt as long-term debt at March 31, 2000. The Australian bank bill borrowings and commercial paper were assumed by the buyer as a condition of the sale.

First mortgage bonds of the Company may be issued in amounts limited by Domestic electric operations' property, earnings and other provisions of the mortgage indenture. Approximately $11 billion of the eligible assets (based on original cost) of PacifiCorp are subject to the lien of the mortgage. Approximately $700 million of first mortgage bonds were callable at March 31, 2001 at redemption prices dependent upon U.S. Treasury yields. Approximately $665 million of pollution control revenue bonds were callable at March 31, 2001 at redemption prices ranging from 100% to 103% based on the series and redemption dates. Subsidiary notes are callable at face amount. The remaining long-term debt was not callable at March 31, 2001.

The junior subordinated debentures were unsecured obligations of the Company and were subordinated to the Company's first mortgage bonds, pollution control revenue bonds, commercial paper, bank debt and any future senior indebtedness.

The annual maturities of long-term debt, capitalized lease obligations and redeemable preferred stock outstanding are $151 million, $155 million, $140 million, $244 million and $289 million in 2002 through 2006, respectively.

The Company made interest payments, net of capitalized interest, of $337 million, $402 million, $116 million and $444 million in 2001, 2000, the three months ended March 31, 1999, and the year 1998, respectively.

NOTE 9  GUARANTEED PREFERRED BENEFICIAL INTERESTS IN
        COMPANY'S JUNIOR SUBORDINATED DEBENTURES

Wholly-owned subsidiary trusts of the Company (the "Trusts") have issued, in public offerings, redeemable preferred securities ("Preferred Securities") representing preferred undivided beneficial interests in the assets of the Trusts, with liquidation amounts of $25 per Preferred Security. The sole assets of the Trusts are Junior Subordinated Deferrable Interest Debentures of the Company that bear interest at the same rates as the Preferred Securities to which they relate, and certain rights under related guarantees by the Company.

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Preferred Securities outstanding were as follows:

NOTE 10  COMMON AND PREFERRED STOCK

The Company has one class of common stock with no par value. A total of 750,000,000 shares were authorized and 297,324,604 were issued and outstanding at March 31, 2001 and 2000.

Common Dividend Restrictions - ScottishPower is the sole indirect shareholder of the Company's common stock. The Company is restricted from paying dividends or making other distributions to ScottishPower without prior OPUC approval to the extent such payment or distribution would reduce the Company's common stock equity below a specified percentage of its total capitalization. The percentage of total capitalization increases over time from 35% after December 31, 1999 to 40% after December 31, 2004. In addition, the Company must give the OPUC 30 days prior notice of any special cash dividend or any transfer involving more than five percent of PacifiCorp's retained earnings in a six-month period. The Company is also subject to maximum debt to total capitalization levels under various debt agreements.

Under the Public Utility Holding Company Act of 1935, the Company may pay dividends out of capital or unearned surplus only with SEC approval. Dividends from earned surplus are permitted without approval. The Company has received approval to pay dividends out of unearned surplus of the lesser of $900 million or the proceeds received from sales of nonutility assets.

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Generally, preferred stock is redeemable at stipulated prices plus accrued dividends, subject to certain restrictions. Upon voluntary or involuntary liquidation, all preferred stock is entitled to stated value or a specified preference amount per share plus accrued dividends. Any premium paid on redemptions of preferred stock is capitalized, and recovery is sought through future rates. Dividends on all preferred stock are cumulative.

Mandatory redemption requirements at stated value plus accrued dividends on No Par Serial Preferred Stock are as follows: the $7.70 series is redeemable in its entirety on August 15, 2001; and 37,500 shares of the $7.48 series are redeemable on each June 15 from 2002 through 2006, with all shares outstanding on June 15, 2007 redeemable on that date. If the Company is in default in its obligation to make any future redemptions on the $7.48 series, it may not pay cash dividends on common stock.

The Company had $58 million and $4 million in common and preferred dividends, respectively, declared but unpaid at March 31, 2001 and $4 million in preferred dividends declared but unpaid at March 31, 2000.

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NOTE 11 SECURITIES AVAILABLE FOR SALE

The amortized cost and fair value of reclamation trust securities and other investments, which are classified as available for sale, were as follows: