PACIFICORP /OR/ - Annual Report: 2002 (Form 10-K)

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As a result of the geographically diverse area of operations, the Company's service territory has historically experienced complementary seasonal load patterns. In the western portion, customer demand peaks in the winter months due to heating requirements. In the eastern portion, 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 prior region-wide electricity supply shortages, the Company is actively promoting electricity conservation programs, which may cause usage variations. See REGULATION - Demand Side Management below for additional information.

During 2002, no single retail customer accounted for more than 1.4% of the Company's retail utility revenues and the 20 largest retail customers accounted for 13.8% of total retail electric revenues.

COMPETITION

During 2002, the Company continued to operate its electricity distribution and retail sales business as a regulated monopoly throughout most of its franchise service territories. Certain of the Company's industrial customers are seeking choice of suppliers, options to build their own generation or co-generation, 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

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reliability. Availability and price of alternative energy sources and the general demand for electrical power also influence competition. Load can also be strongly influenced by conservation and Demand Side Management activities.

In the longer term, the Company believes that customer demand for choice in each state may eventually lead to retail competition in some form. This change in the regulatory structure may significantly affect the Company's future financial position, results of operations and cash flows. See REGULATION - Deregulation.

POWER AND FUEL SUPPLY

From mid-1999 through mid-2001, the supply of power did not keep pace with the growing demand in the western United States and the Company experienced the effect of high market prices associated with this shortage. Certain forward contracts entered into during the period of high prices will continue to have a negative impact on the Company's cost of power until those contracts expire by the end of the second quarter of 2003. The Company expects a negative impact based on current forward price curves. The Company is working with regulators to ensure, to the extent possible, that prices paid by the Company to provide certain load balancing resources do not exceed the amounts it receives through retail rates and wholesale prices. See REGULATION below.

The Company owns, or has interests in, 71 generating plants with an aggregate nameplate rating of 8,269 MW and plant net capability of 7,815 MW, as shown under ITEM 2. PROPERTIES. With its present generating facilities, under average water conditions, the Company would expect that approximately 6.0% of its energy requirements for 2003 would be supplied by its hydroelectric plants, 66.0% by its thermal plants, 13.0% would be obtained under existing long-term purchase contracts, and the remaining 15.0% through short-term purchase arrangements. During 2002, its hydroelectric and thermal generation plants supplied approximately 4.9% and 62.6%, respectively, of the Company's energy requirements. The remaining 32.5% was supplied primarily by purchased power. The contribution of the Company's thermal generation to energy requirements was reduced by the Hunter No. 1 outage, which occurred on November 24, 2000 and continued until early May 2001. Generation was further impaired in late 2001 and early 2002 due to a lack of precipitation and the resulting loss of hydrogeneration.

During 2002, the Company leased gas turbine peaking generators with 95 MW capacity to provide electric generation to meet load requirements in Utah. The Company is in the process of replacing these leased gas turbine peakers at its Gadsby Plant, in Salt Lake City, Utah, with 120 MW Company-owned gas-fired turbines. An Order of Consent has been obtained from the Utah Department of Air Quality, which permits construction to proceed. Requisite building permits have been obtained from Salt Lake City. The turbines are expected to go online in late summer 2002.

The Company has signed a 20-year agreement to purchase the entire output of the Rock River I wind power project located in Arlington, Wyoming, which is projected to produce 50 MW of power. This project continues the Company's commitment to develop additional megawatts generated by renewable resources.

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In September 2001, the Company issued a Request for Proposals for electric supply that can be delivered into the Company's Utah Power electric service territory. To date, this process has resulted in a lease with PPM for new peaking resources in the Utah Power service territory and several contracts for peak power to be delivered into that territory. The lease with PPM is subject to regulatory approvals and involves a 200 MW natural gas-fired power plant in West Valley City, Utah under development by PPM. The plant is located within an area experiencing growth and where delivery to customers can be accomplished more easily during high usage hours. Certain units of the plant should be operational beginning in the summer of 2002.

On October 30, 2000, the Company and BPA executed a 10-year settlement agreement that replaced the BPA Residential Exchange Program. This settlement was effective October 1, 2001 and is expected to provide the Company's residential and irrigation customers in Oregon, Washington and Idaho with benefits equaling $115.0 million in the first year and $119.0 million per year for years two through five. These benefits pass through to customers and do not impact the Company's earnings.

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, 2002, the Company had approximately 218 million tons of recoverable coal reserves that are mined by the Company. The coal from these reserves is dedicated to Company generation plants that are near the mines. During 2002, these mines supplied approximately 32.5% of the Company's total coal requirements, compared to approximately 50.0% in 2001. The decline is due to the closure of the Trail Mountain Mine in 2001. Coal is also acquired through long-term and short-term contracts. The Company supplies its generation plants with the natural gas needed for operations through long-term and short-term contracts.

WHOLESALE SALES AND PURCHASED POWER

The Company's wholesale sales complement its retail business, form a critical part of its balancing and hedging strategy and enhance the efficient use of its generating capacity over the long term.

Historically, during the winter, the Company has been able to purchase power from utilities in the southwestern United States, principally for its own peak requirements. The Company's transmission system connects with market hubs in the Pacific Northwest having access to low-cost hydroelectric generation and also with market hubs in California and the southwestern United States with access to 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 power into the wholesale market.

In addition to its base of thermal and hydroelectric generation assets, the Company utilizes a mix of long-term, short-term and spot market purchases to

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meet its load obligations, wholesale obligations and its balancing requirements. Many of the Company's purchased power contracts have fixed price components, which provide some protection against price volatility.

The Company currently purchases 925 MW of firm capacity annually from the BPA pursuant to a long-term agreement. The purchase amount declines 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, 2002 was $60.4 million. As the price for this capacity is a per MW charge, the costs associated with this agreement will decline as the MW purchased decline. The price is adjusted by the rate of change in the BPA's Average System Cost. The Company anticipates a slight decline in price in 2003. The next scheduled price change will occur in October 2006.

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 2002, the Company purchased an average of 104 MW from qualifying facilities, compared to an average of 109 MW in 2001.

Long-term power purchases supplied 11.8% of the Company's total energy requirements in 2002. Short-term and spot market power purchases supplied 20.5% of the Company's total energy requirements in 2002.

See Note 16 of Notes to the Consolidated Financial Statements under ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA for further discussion of the Company's commitments and contingencies.

WESTERN POWER MARKET ISSUES

In early 2001, California's two largest utilities, Southern California Edison ("SCE") and Pacific Gas & Electric Company ("PG&E"), defaulted on payment obligations owed to various energy sellers, including the California Power Exchange ("CPX"), California Independent System Operator ("Cal ISO"), and Automated Power Exchange. PG&E and CPX filed voluntary petitions under Chapter 11 of the United States Bankruptcy Code for protection from creditors. SCE remains outside of bankruptcy. On December 2, 2001, Enron Corporation ("Enron") and certain of its affiliates filed for protection under Chapter 11 of the United States Bankruptcy Code. As of March 31, 2002, the Company had net outstanding receivables, after considering master netting agreements, from Cal ISO, CPX and Enron totaling approximately $14.0 million. The Company has recorded reserves for this entire amount.

Effective June 19, 2001, FERC imposed a price mitigation plan that limits prices on spot market sales in California 24 hours a day, seven days a week until September 30, 2002. The price limits are determined based on a calculation that involves the price of natural gas in California, the heat rate of the least efficient load serving gas-fired generation plant in California and a fixed factor to account for other variable costs. Sellers have an opportunity to justify to FERC prices above the capped limit. However, entities reselling power that was purchased are not permitted to seek prices above the capped limit.

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On July 25, 2001, the FERC issued an order that extended the California price limits to all wholesale spot market sales in the entire 11-state western region. On December 19, 2001, the FERC revised the methodology used to calculate price limits for the winter season. The mitigated price for all hours until May 1, 2002, was raised to the full amount of the last calculated price cap when reserves in California fell below 70.0%. The price limit will be increased further when the indices for natural gas prices used to establish the mitigated price increase by 10.0%. On May 1, 2002, the price limit calculations reverted to using the original methodology until the price limits expire on September 30, 2002.

The FERC's June 19, 2001 order also required that "all public utility sellers and buyers in the Cal ISO's markets participate in settlement discussions to complete the task of settling past accounts and structuring the new arrangements for California's energy future." The FERC also stated that "it is imperative that the parties reach agreement on: (1) the additional load that is to be moved from the spot market to longer-term contracts; (2) refund (offset) issues related to past periods; and (3) creditworthiness matters." The FERC appointed an Administrative Law Judge ("ALJ") to serve as a settlement judge. The Company and many others participated in a settlement conference convened by the ALJ during late June and early July 2001. On July 11, 2001, the ALJ issued a recommendation to the FERC based upon the settlement conference, proposing a methodology to calculate refund (offset) issues. The FERC agreed with the ALJ-proposed methodology. A proceeding before a second ALJ has been established to determine each party's refund liability. The schedule for this proceeding has been postponed and is not expected to be continued until the second half of calendar 2002. The Company's exposure to refunds, while not expected to be significant, is dependent upon any order issued by the FERC in response to the outcome of these proceedings. The impact of refunds on counterparties in the market with whom the Company transacts purchases and sales, or any potential impact on financial markets that make funds available to companies operating in the western states, cannot be determined at this time.

The FERC has also established a second proceeding to consider the possibility of requiring refunds for wholesale sales in the Pacific Northwest between December 25, 2000 and June 20, 2001. The ALJ recommended that FERC not require refunds for these sales. The FERC has not yet issued a decision in the Pacific Northwest refund proceeding. The Company's exposure to refunds will be dependent upon any order issued by the FERC in response to the outcome of these proceedings. The Company believes its exposure to refunds resulting from these proceedings will not have a material impact on results of operations or financial position.

On May 2, 2002, PacifiCorp filed a series of complaints with the FERC against five wholesale power suppliers for charging excessive prices for wholesale electricity purchases scheduled for delivery during the summer of 2002. The contracts covered in the complaint were signed during a period of extreme wholesale market volatility and before the FERC imposed its West-wide spot market price mitigation (price caps). PacifiCorp is seeking reformation of the contract prices to levels that constitute just and reasonable rates.

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PROJECTED DEMAND

The Company continues to experience economic growth in several portions of its service territory, but at a slower pace than in previous years. Retail energy sales for the Company have grown at a compound annual rate of 1.0% since 1996; however, for 2002, MWh sales decreased about 2.0%. Future increases in demand are dependent upon several factors, including the impact of Demand Side Management programs, price movements and weather and economic conditions. Resource availability, price volatility and load volatility may materially impact power costs to the Company.

For the periods 2003 to 2006, the average annual growth in retail MWh sales in the Company's franchise service territories is estimated to be about 2.4%, excluding the potential effects of decreased demand resulting from conservation efforts and higher prices. If price increases occur in the region, the Company believes that demand growth may slow. 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 protect, restore 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.

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 operating costs.

Air Quality
The Company's fossil fuel-fired electricity generation plants are subject to air quality regulation under federal and state requirements. The Company believes it has all required permits and other approvals to operate its plants and that the plants are in compliance with applicable requirements. The Company uses emission controls, low sulfur coal, environmentally conscious plant operating practices and continuous emissions monitoring to enable its plants to comply with emission limits, opacity limits, visibility and other air quality requirements. The EPA has implemented regulations addressing regional haze, and the Company is working with the Western Regional Air Partnership to help develop the technical and policy tools needed to comply with those regulations. Carbon dioxide emissions are the subject of growing discussion and action in the context of climate change, but such emissions are not currently regulated. The EPA has indicated that controls to regulate mercury emissions from coal-burning plants will be brought forward by 2003.

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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 those actions. 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. In addition, certain legislators have proposed programs to require significant reductions in emissions from coal burning power plants over the next 15 years. The Company is actively participating in the legislative and other activities associated with these proposals.

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 hydro, thermal and wind 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 requirements could also result in further restrictions on timber harvesting and reduce electricity sales to the Company's 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, except that additional permits are required with respect to the relicensing of the Company's hydroelectric projects as described below under REGULATION.

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Electromagnetic Fields
A number of studies continue to examine the possibility of adverse health effects from electromagnetic fields, without conclusive results. Certain states and cities have enacted regulations to limit the strength of electromagnetic 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 electromagnetic fields or electromagnetic 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 electromagnetic field concerns.

REGULATION

The Company is subject to the jurisdiction of public utility regulatory authorities in each of the states in which it conducts retail electric operations. That jurisdiction covers prices, services, accounting, issuances of securities and other matters. Commissioners are appointed by the respective states' governors for varying terms. The Company is a "licensee" and a "public utility" as those terms are used in 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. The Company is also subject to the requirements and restrictions of the Public Utility Holding Company Act of 1935.

The Company's hydroelectric portfolio consists of 53 plants with a total capacity of approximately 1,100 MW. The FERC regulates 97.0% of the installed capacity through 20 individual licenses. These projects account for about 13.0% 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 a public regulatory process that involves controversial political 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 Native American Tribal Councils have mandatory conditioning authorities that give them significant influence and control in the relicensing process. Under the FPA, a 401 Clean Water Act ("CWA") certification is required for any new license. FERC must accept the 401 CWA certification as mandatory prescriptions and does not have the discretion to modify the certification. It is difficult to determine the economic impact of these mandates, but capital expenditures and operating costs are expected to increase in future periods while power 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 $17.0 million.

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Depreciation Rate Increase
During 1998, the Company filed applications with the respective regulatory commissions in the states of Utah, Oregon, Wyoming and Washington to increase rates of depreciation based on a new depreciation study. All applications were approved in 2000. The increase in rates of depreciation 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 ordered a reversal of a portion of previously accrued depreciation. These reversals in total, for both states, amounted to approximately $14.0 million per year for 2001 and 2002. The Company is required to file new depreciation studies in October 2002 based on plant balances as of March 31, 2002.

Trail Mountain Mine Closure Costs
On February 7, 2001, the Company filed applications with the UPSC, the OPUC, the WPSC and the IPUC requesting accounting orders to defer $27.1 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 WPSC and the IPUC approved deferred accounting treatment of their state's share of the $27.1 million of non-recovered Trail Mountain Mine investment costs. Additional closure-related costs in the amount of $18.7 million were subsequently identified, and the total amount subject to possible deferral increased to approximately $45.8 million. The Company filed in Utah and Oregon to include the additional costs in its deferral application and received approval to defer the full $45.8 million for accounting purposes. In addition, the parties in Oregon signed a stipulation calling for a permanent $1.1 million annual rate reduction in Oregon due to the removal of the Trail Mountain assets from rate base. The stipulation also provides for a $2.6 million annual surcharge for five years to recover Oregon's share of mine closure costs. This stipulation requires OPUC approval. On April 4, 2002, the UPSC approved deferral of Utah's share of the $45.8 million with a five-year amortization beginning April 1, 2001.

In April 2002, the Company established a regulatory asset for the full closure costs of the Trail Mountain mine with a five-year amortization period beginning April 2001. The resulting regulatory asset at April 30, 2002 was $36.4 million, net of amortization. The reestablishment of the regulatory asset increased accumulated depreciation to reverse the effects of the retirement of the mine and decreased coal inventory costs for the closure-related costs. Recovery of the Trail Mountain amortization in Oregon was approved on May 20, 2002. The Company recently filed for recovery in Wyoming as part of its general rate case and will seek recovery in the remaining states.

Merger Credits
As a result of the Merger, the Company was required to provide benefits to ratepayers through fixed reductions in rates, or "Merger Credits." The Company's total obligation for Merger Credits was $133.4 million through the period ending December 31, 2004. The Company recorded $12.0 million and $57.2 million as liabilities and current expenses in its financial statements for the years ended March 31, 2001 and 2000, respectively, as those amounts were not subject to potential offsets. In May 2002, the UPSC allowed the

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Company to offset $21.0 million of future Merger Credits against deferred net power costs and eliminated the obligation for future Merger Credits in Utah. The IPUC is also considering a stipulation agreement that will allow the Company to offset future Merger Credits against deferred net power costs in the amount of $2.3 million. These actions will increase monthly revenues by approximately $1.0 million until December 31, 2003. Through March 31, 2002, the Company had provided $48.8 million in Merger Credits and interest to its customers through reduced rates. If the IPUC approves the outstanding stipulation, future Merger Credits of $44.3 million will still be due to customers in Oregon and Washington with the possibility of offsetting $21.0 million of that amount.

Regulatory Established Returns
The regulatory commissions in the various states where the Company conducts its business approve an appropriate level of cost recovery for debt, preferred equity, and common equity, which results in an allowed return on rate base ("ROR") for the Company's regulated utility business, which includes an allowed return on equity ("ROE") representing a return on shareholder investment. The Utah, Oregon, and Wyoming commissions have approved ROR's in recent general rate cases of 8.9%, 8.6%, and 8.9%, respectively, and ROE's of 11.0%, 10.8%, and 11.0%, respectively. Commissions in Washington, Idaho and California have not had recent hearings requiring a specific finding of fact on allowed ROR or ROE. However, these commissions monitor the Company's achieved ROR for appropriateness considering current market conditions.

Concluded Regulatory Actions
Utah - On January 12, 2001, the Company filed a request with the UPSC for an increase in electricity rates for its customers in Utah. This request encompassed normalized power costs based on a test year of the twelve months ended September 30, 2000 and did not include those power cost variances associated with the Hunter No. 1 outage. The request would have increased prices by approximately 19.1% overall, or $142.0 million. On July 12, 2001, the Company agreed to reduce its request to an increase of $118.0 million. Concurrent with the initial filing, the Company filed a separate emergency petition for interim relief. On February 2, 2001, the UPSC granted an interim rate increase of $70.0 million, effective February 2, 2001. The $70.0 million interim rate increase was subject to refund if the final rate order did not provide for at least that level of recovery. On September 10, 2001, in its final order, the UPSC granted the Company a $40.5 million revenue increase. This decision set new revenues about 5.1% higher than previous levels and allowed the Company to receive an additional $40.5 million in revenues during 2002. The rate increase was $29.5 million lower annually than the $70.0 million interim rate increase granted in February 2001. On November 2, 2001, the UPSC issued an order allowing the Company to retain temporarily the excess of the $70.0 million interim rate increase over the ordered $40.5 million revenue increase. The UPSC also allowed the Company to continue collecting the $29.5 million of revenue, subject to refund, as an offset to replacement power costs relating to the Hunter No. 1 outage. At March 31, 2002, the Company had collected $34.7 million of revenues subject to refund that were recorded as a regulatory liability. On May 1, 2002, the UPSC issued an order allowing the Company to apply the $34.7 million of previously collected revenues against the regulatory assets for deferred net power costs.

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revenues of $8.9 million, effective August 1, 2001. Approximately $5.9 million in additional revenues were received in 2002.

Rate Increases Submitted for Regulatory Approval
California - On March 16, 2001, the Company filed an interim rate relief request with the CPUC as Phase I in an effort to seek an increase in electricity rates for its customers in California. If approved by the CPUC, Phase I would increase rates about 13.8% overall, or $7.4 million. In addition, the Company has moved forward with its Phase II filing of a General Rate Case ("GRC") to increase rates to compensatory levels. The GRC request submitted on December 21, 2001, if approved by the CPUC, would raise customer rates 29.4% overall or $16.0 million annually, with an authorized return on equity of 11.5%. The annual amount requested would incorporate the Phase I interim amount. On December 26, 2001, the Office of Ratepayer Advocates ("ORA") filed a motion to dismiss or defer the Company's GRC request. The Company responded to ORA's motion on January 9, 2002. Following the expiration of the protest period, on February 25, 2002 the Company filed a motion for a pre-hearing conference to identify parties of record, establish a procedural schedule and address other issues.

Deferred Net Power Costs
On November 1, 2000, the Company filed applications in Utah, Oregon, Wyoming and Idaho seeking deferred accounting treatment for net power costs materially in excess of the power costs assumed in setting existing retail rates. The applications sought to defer these power cost variances beginning November 1, 2000. As discussed below, the Company received authorization to defer some power costs in excess of those included in retail rates in all the states where requests were made. At March 31, 2002, the Company had a regulatory asset of $305.4 million, including carrying costs, for total deferred power costs.

Utah - In Utah, pursuant to the UPSC's approval of deferred accounting treatment for replacement power costs resulting from the Hunter No. 1 outage, the Company filed on August 23, 2001 seeking permission to recover $103.5 million in replacement power costs over a 12-month period. On November 2, 2001, the UPSC allowed the Company to apply over-collections from the general rate case toward Hunter No. 1 replacement power costs on an interim basis, subject to refund. The amount of the interim relief was approximately $29.5 million annually. As of March 31, 2002, $34.7 million had been collected toward Hunter No. 1 replacement costs.

Also in Utah, on September 21, 2001, the Company filed for permission to defer $109.0 million of excess net power costs above the level adopted in the Company's rate order of September 10, 2001. These costs were incurred during the period May 9, 2001 through September 30, 2001. A hearing relating to the deferral was held on December 7, 2001. On November 13, 2001, the Company also filed an application with the UPSC to recover, through a surcharge, the excess net purchased power costs incurred during the period May 9, 2001 through September 30, 2001. These filings are alternative approaches to recovery of effectively the same $109.0 million of costs that are not yet deferred. They are alternatives to each other and are not additive.

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On May 1, 2002, the UPSC issued an order approving a stipulation agreement regarding recovery of deferred and non-deferred net power costs in Utah. The order allows the Company to continue collecting a $29.5 million annual surcharge until March 31, 2004 and to apply $34.7 million of revenue already collected subject to refund against deferred net power costs. The order allows the Company to offset deferred net power costs against a regulatory liability of $27.0 million for amounts to be returned to customers relating to the gain from the 2001 sale of the Centralia, Washington power plant. The Company will also realize $21.0 million by elimination of future Merger Credits. These regulatory liability offsets will reduce the regulatory asset for deferred net power costs. Monthly revenues will increase approximately $1.0 million until December 31, 2003 due to the termination of Merger Credit revenue reductions. The Company will record additional deferred net power costs of $37.9 million, withdraw its request to defer $109.0 million of excess net power costs and commit not to file a general rate case that would take effect prior to January 1, 2004, with certain exceptions. These actions should allow the Company to recover a total of $147.0 million of deferred and non-deferred net power costs in Utah.

Oregon - The Oregon deferred accounting filing encompassed all power costs that vary from the level in Oregon rates during the period from November 1, 2000 through September 9, 2001, including costs to replace lost generation resulting from the Hunter No. 1 outage. On January 18, 2001, the Company requested a 3.0%, or $23.0 million, annual rate increase effective February 1, 2001, to provide partial recovery of post-October 31, 2000 power cost variances attributable to Oregon over an amortization period. This 3.0% rate increase was the maximum allowed on an annual basis for the recovery of deferred costs under the Oregon statutes. On January 23, 2001, the OPUC authorized deferred accounting for power costs of $23.0 million. On February 20, 2001, the OPUC authorized the 3.0% rate increase effective February 21, 2001, subject to refund, pending the outcome of a separate phase of the proceeding to examine the prudence of these expenditures. The Company received $21.6 million in revenues as a result of this OPUC action. The OPUC has approved the Company's request to continue amortization at the 3.0% rate pending resolution of the prudence review, which is expected to be completed in June 2002.

The Company has appealed two OPUC orders, which establish the mechanism to determine the amount of power costs to defer, to the Marion County, Oregon, Circuit Court in separate complaints filed on October 1, 2001. The appeals have been consolidated. Oral arguments were held on May 9, 2002 and a ruling is expected in June 2002.

The Company filed with the OPUC on September 21, 2001 to increase the level of recovery of excess net power costs incurred to serve Oregon customers from the current 3.0% amortization level, or $23.0 million awarded in February 2001, to 6.0%. On October 22, 2001, the OPUC suspended the Company's request pending the outcome of the prudence phase of the proceeding. Upon completion of the prudence review, the Company will renew its request to increase the amortization level to 6.0%.

In December 2001, the Company and the OPUC staff reached a stipulation in the prudence phase of its deferred net power cost. The stipulation provides that

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the Company would be permitted to recover 85.0% of the deferred net power costs in Oregon, or about $131.0 million plus carrying charges. The stipulation allows the Company to seek a higher level of recovery in the event the Company's appeal of the Commission's order limiting deferrals is successful. On May 20, 2002, the OPUC approved a one-year $15.4 million overall rate increase effective June 1, 2002 for the Company's Oregon customers to cover increases in power costs.

On September 7, 2001, the OPUC endorsed an agreement on deferral of net power costs after September 2001. The agreement specifies that until May 2002, the Company will defer the difference between 83.0% of actual net power costs and the new Oregon baseline power cost in tariffs. In December 2001, the parties to the original stipulation agreed to extend this mechanism until June 2002.

Wyoming - In Wyoming, on November 1, 2000, the Company filed for deferred accounting treatment of net power costs that vary from costs included in determining retail rates. The Company proposed to recover $47.0 million of deferred net power costs, incurred through June 2001, over a 12-month period. On November 20, 2001, following an order by the WPSC dismissing the majority of the Company's case based on a procedural issue, the Company requested authority to withdraw its excess power cost recovery filing without prejudice. On November 26, 2001, the WPSC granted the Company's motion. On May 7, 2002, the Company filed a Wyoming general rate case that includes a consolidation of all excess net power costs, including those for which recovery was being sought in the withdrawn proceeding, totaling $91.0 million.

Idaho - On January 7, 2002, the Company filed a request with the IPUC to recover $38 million of deferred net power costs through a temporary 24-month surcharge on customer bills and to implement a new credit to pass through Residential Exchange Program benefits from the two BPA settlement agreements described above. The credit would not affect Company earnings. In addition, the Company requested an adjustment of individual rate classes to more closely reflect the actual cost-of-service and proposed a rate mitigation policy to ensure that no customer class would receive a rate increase during the period in which the proposed surcharge is in effect. Parties to the proceeding agreed to a stipulation that would allow recovery of $25.0 million of the deferred net power costs. This recovery would be achieved through a $22.7 million power cost surcharge plus termination of future Merger Credits in the amount of $2.3 million. The IPUC conducted hearings beginning on May 7, 2002 to consider the stipulation.

Washington - On April 5, 2000, the Company filed a petition with the WUTC seeking authority to begin deferring excess net power costs as of June 1, 2002 for later recovery in rates, either through a power cost adjustment mechanism or a limited rate adjustment. Under the rate plan approved by the WUTC in August 2000 at the conclusion of the Company's last general rate case in Washington, there are limitations on the Company's ability to raise general rates prior to 2006. On May 10, 2002, the other parties to the rate plan filed a motion with the WUTC seeking to reopen the Company's 2000 general rate case and consolidate it with the Company's request for deferred accounting. A ruling on this motion by the WUTC is expected in early June 2002.

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Regional Transmission Organization ("RTO")
The Company, in conjunction with nine other utilities, is seeking to form an RTO ("RTO West"), in support of FERC Order 2000. The 10 members of RTO West would be Avista Corporation, British Columbia Hydro Power Authority, BPA, Idaho Power Company, Northwestern Energy L.L.C. (formerly Montana Power Company), Nevada Power Company, PacifiCorp, Portland General Electric Company, Puget Sound Energy, Inc. and Sierra Pacific Power Company. Creation of RTO West is subject to regulatory approvals from the FERC and the states served by these entities. RTO West plans to operate all transmission facilities needed for bulk power transfers and control the majority of the 60,000 miles of transmission lines owned by the entities. On March 29, 2002, the members of RTO West filed a request with the FERC for a declaratory judgment that their proposal to establish RTO West as a regional transmission organization satisfies the characteristics and functions of FERC Order 2000. The FERC is expected to rule on the filing by August 2002.

Demand Side Management
The Company continues to offer its Energy Exchange program in Utah, Oregon, Wyoming, Washington and Idaho. This program consists of optional, supplemental services that give participating customers an opportunity to reduce their electricity usage in exchange for a payment at times and at prices determined by the Company. The program is designed to help address high-price and volatile wholesale power market circumstances when they occur. Customers with usage as low as one megawatt may participate in the program.

In response to the extraordinarily high prices for wholesale market power during the summer of 2001, the Company implemented load control measures in the form of voluntary Irrigation Curtailment programs in Idaho, Oregon, Washington, and Utah. Under the terms of these programs irrigators were offered payment in return for curtailment of irrigation pumping operations during the 2001 irrigation season. The Utah and Idaho Irrigation Curtailment programs put in place in the 2001 calendar year ended during the third quarter of the 2001 calendar year. Those put in place in Oregon and Washington ended during the fourth quarter of the 2001 calendar year.

The Company completed its Customer Energy Challenge program for residential customers on September 30, 2001. The program was in place in all states the Company serves. Incentives under the program provided a 10.0% credit to all Utah, Oregon, Wyoming, Washington and Idaho customers who reduced their monthly kWh usage by 10.0% from the corresponding month one year prior for the months of July through September. In addition, a 20.0% credit was applied to all Utah, Oregon, Wyoming, Washington, Idaho and California customers who reduced their monthly kWh usage by 20.0% from the corresponding month one year prior for the months of June through September. Evaluation reports of the program were filed with state commissions in each state in early December 2001.

Multi-State Process ("MSP")
The Company has initiated a collaborative process with the six states it serves to investigate the challenges faced by the Company as a multi-state utility. This MSP is a process by which solutions, including the Company's Structural Realignment Proposal ("SRP"), will be developed and reviewed by interested parties from across the Company's service territory. Through MSP,

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the participants are working to clarify roles and responsibilities, including cost allocations for future generation resources, provide states with the ability to independently implement state energy policy objectives, and achieve permanent consensus on each state's responsibility for the costs and entitlement to the benefits of the Company's existing assets.

The SRP plan proposed by the Company 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, which are all intended to be subsidiaries of the holding company. Individual state proceedings and schedules for SRP will be "on hold" so long as reasonable progress is made through the MSP. Any proposal that results from the MSP must be subsequently approved by the utility commissions in Utah, Oregon, Wyoming, Washington, Idaho and California. Approval from the FERC may also be required.

Deregulation
Industry restructuring to open the electric wholesale market to competition was initially promoted by federal legislation by passage of the Energy Policy Act of 1992 ("Energy Act"). The Energy Act gave FERC authority to require electric utilities to provide infrastructure and transmit electricity to or for wholesale purchasers and sellers. The Energy Act also created a new class of independent power plant owners that are able to sell generation only in wholesale markets. Deregulation in the states where the Company operates has varied significantly as discussed below.

Utah - The 2001 Utah legislature repealed a 2000 Utah bill that could have significantly changed the structure of utility regulatory agencies in Utah. The 2000 bill would have become effective July 1, 2001.

The Utah legislature also passed a bill extending the life of a legislative task force created in 1997 to study restructuring issues. The bill authorizes this task force to prepare legislation to implement an electrical restructuring plan for presentation and consideration in the 2002 legislative session, unless it is not in Utah's best interest to do so. No deregulation plan was proposed in the 2002 legislative session.

Oregon - During 1999, SB 1149 was enacted in Oregon requiring competition for industrial and large commercial customers of both the Company and Portland General Electric Company. Under the legislation, the Company is required to unbundle rates for generation, transmission, distribution and other retail services, and to offer residential customers a cost-of-service rate option and a portfolio of rate options that include new renewable energy resources and market-based generation. SB 1149 authorizes the OPUC to make decisions on certain matters, in particular the method for valuation of stranded costs/benefits. The Company continues to participate in the OPUC proceedings to establish the rules and procedures related to SB 1149. Implementation of SB 1149 began March 1, 2002, when the Company provided all customers with a cost-of-service rate option for an indefinite period and allowed industrial and large commercial customers a choice of energy provider. As a result of adopting SB 1149, 13 customers elected an alternate choice to cost-based standard offer tariffs.

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To date, adoption of SB 1149 has not had a significant financial impact on the Company's results. The Company has evaluated the implementation of SB 1149 against the criteria for continuing application of SFAS No. 71 "Accounting for the Effects of Regulation" ("SFAS No. 71") and has determined that its operations in Oregon continue to qualify for accounting under that pronouncement. The Company will evaluate the propriety of continuing to apply SFAS No. 71. Beginning July 1, 2003, the OPUC may waive the cost of service rate option for classes of customers if the OPUC finds that retail markets are functioning properly. The Company is now recovering approximately $18.0 million of SB 1149 implementation costs over a five-year period.

Washington - In 2001, the WUTC allowed six large industrial customers of Puget Sound Energy to buy electricity from any source, including other utilities, power marketers and each other. The WUTC has not adopted any similar action for the Company and its customers. To date, no deregulation plan has been proposed by the WUTC or Washington legislature.

Wyoming - In 1997 and 1998, the Wyoming legislature and WPSC initiated discussions regarding electric industry restructuring. No action has been taken as a result of those discussions.

Idaho - In 1999, the Idaho Legislative Council on Electric Utility Restructuring issued a report recommending a slow approach to electric retail competition in Idaho. The legislature established a restructuring study committee, but no deregulation plan has been proposed.

California - In 1998, California became one of the first states in the country to implement electric industry restructuring with the goal of establishing a competitive market for electric generation. The framework for electric industry restructuring was established in Assembly Bill 1890 ("AB 1890"), passed by the California Legislature and signed by the Governor in 1996. Beginning March 31, 1998, Californians were given the choice to purchase electricity from generation providers other than the traditional utilities ("direct access"). For those customers who did not choose direct access, investor-owned utilities were to continue to purchase electric power on their behalf. Investor-owned utilities continue to provide distribution services to substantially all customers within their service territories, including those customers who choose direct access. However, the CPUC suspended the ability of customers to choose suppliers on a prospective basis in the fall of 2001.

As required by AB 1890, electric rates for all customers were frozen at the level in effect on June 10, 1996, and, beginning January 1, 1998, rates for residential and small commercial customers were reduced by 10% from 1996 levels.

The Company has no generation facilities in California and therefore AB 1890 has impacted the Company only to the extent of the 10.0% retail rate reduction for its California retail customers.

In July 1998, the Company announced its intention to sell its California service territory, including its electric distribution assets. Since then, the Company has been working with the CPUC and potential buyers to complete the sale.

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CONSTRUCTION PROGRAM

The following table shows actual construction costs for 2002 and PacifiCorp's estimated construction costs for 2003 through 2005, including costs of acquiring demand-side resources. The estimates of construction costs for 2003 through 2005 exclude the potential impact of future decisions regarding expansion of physical generation capacity and hydro relicensing issues, and are subject to continuing review and revision as appropriate by the Company.

AUSTRALIAN ELECTRIC OPERATIONS

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

Other Operations consisted of Holdings and its principal subsidiary, PFS. These operations were transferred to PHI on February 4, 2002 and are no longer a part of the Company's operations.

The Company had approximately 6,300 employees on March 31, 2002.

The Company developed and commenced a Transition Plan (the "Transition Plan") in May 2000 to implement significant organizational and operational changes. As part of this Transition Plan, 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. As of March 31, 2002, the Company had reduced its workforce by approximately 1,560 from 1998 levels, including approximately 750 in Transition Plan reductions. For more information, see Note 2 of Notes to the Consolidated Financial Statements under ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.

Approximately 60% of the employees of PacifiCorp and its mining affiliates are covered by union contracts, principally with the International Brotherhood of Electrical Workers, the Utility Workers Union of America, International Brotherhood of Boilermakers and the United Mine Workers of America.

In the Company's judgment, employee relations are satisfactory.

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

(a)  Hydroelectric project locations are stated by locality and river
watershed.

(b)  On April 21, 2002, a failure occurred in the Swift power canal on the Lewis River in the state of Washington. The power canal and associated 70 MW

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hydroelectric facility are owned by Cowlitz County Public Utility District. Preliminary investigations suggest that the facility will be out of service an extended period of time, possibly for more than a year. This failure impacts the Company's 240 MW Swift No. 1 hydroelectric facility by restricting both flow and generation flexibility ("shaping"). Test operations of Swift No. 1 indicate generation output will be temporarily reduced to two-thirds capacity due to physical and environmental constraints surrounding the canal failure. Swift No. 1 is currently generating at the two-thirds capacity level with limited shaping capabilities. The Company will continue to seek ways to mitigate the reduced capacity and to recover related business losses. The impact of the Swift outage and plans for repair are being determined. A prompt return to full flow appears possible. This event is not expected to have a significant impact on the Company's financial position or results of operations.

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, 2002. All coal reserves are dedicated to nearby Company operated generating plants. Recoverability by surface mining methods typically ranges from 90.0% to 95.0%. Recoverability by underground mining techniques ranges from 50.0% to 70.0%. The Company believes that the respective coal reserves assigned to the Craig, 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. Recoverable coal reserves at March 31, 2002 were as follows:

____________

(a)  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 21.4%.

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SFAS No. 71 provides that regulatory assets may be capitalized if it is probable that future revenue in an amount at least equal to the capitalized costs will result from the inclusion of that cost in allowable costs for ratemaking purposes. In addition, the rate action should permit recovery of the specific previously incurred cost rather than to provide for expected levels of similar future costs. The statement makes it clear that a company does not need absolute assurance prior to capitalizing a cost, only reasonable assurance.

In an effort to mitigate the temporary discrepancy between prices paid to purchase power and revenues received through regulated rates, the Company requested and received regulatory approval from the utility commissions in the states of Utah, Oregon, Wyoming and Idaho to capitalize for each state some or all of the net power costs that vary from costs included in determining retail rates. At March 31, 2002, the Company had a balance of $305.4 million of such capitalized costs supported by stipulated agreements reached in Utah, Oregon, and Idaho and an estimate of the probable outcome of the Wyoming rate case expected to be settled late in calendar 2002. The determination of the amount to be recovered is subject to final commission orders from each of these states. Differences between the amount allowed by the commissions and the amounts capitalized at March 31, 2002 will be recognized as either a charge or credit to income upon receiving final commission orders.

Revenue Recognition

Electricity sales to retail customers are determined based on meter readings that are staggered throughout the month. The Company accrues an estimate of unbilled revenues each month for electric service provided after the meter reading date to the end of the month. This estimate is based on the Company's total of electricity delivered during the month and sales based on meter readings. Each month the prior month's estimated unbilled revenue accrual is reversed and the actual amount billed is recorded. At March 31, 2002, the amount accrued for unbilled revenues was $127.0 million.

Allowance for Doubtful Accounts

The Company's estimate for its allowance for doubtful accounts relating to trade receivables is based on two methods. The amounts calculated from each of these methods are combined to determine the total amount reserved. First, the Company evaluates specific accounts where it has information that the customer may have an inability to meet its financial obligations. In these cases, the Company uses its judgment, based on the best available facts and circumstances, and records a specific reserve for that customer against amounts due to reduce the receivable to the amount that is expected to be collected. These specific reserves are reevaluated and adjusted as additional information is received that impacts the amount reserved. Second, a general reserve is established for all customers based on a range of percentages applied to aging categories. These percentages are based on historical collection and write-off experience.

During 2001 and 2002, market conditions in California resulted in defaults of amounts due from California participants. In addition, Enron declared bankruptcy and defaulted on certain wholesale contracts, as discussed under

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WESTERN POWER MARKET ISSUES in ITEM 1. BUSINESS - DOMESTIC ELECTRIC OPERATIONS. The Company provided full reserves for the California receivables and reserved the entire Enron receivable, net of the effect of applying its master netting agreement, in the aggregate amount of $14.0 million. To the extent the Company receives payment of any of these amounts, future results will reflect those payments as income.

Derivatives

At March 31, 2002, the Company reported net liabilities of $505.9 million relating to contracts valued at market. Offsetting amounts of $468.4 million and $38.6 million were also reported to reflect the impact of applying SFAS No. 71 and hedge accounting, respectively, for these contracts. The Company's future financial results could be impacted by changes in market conditions to the extent that changes in contract values are not offset by regulatory or hedge accounting.

Depreciation

Depreciation and amortization are generally computed by the straight-line method in one of the following two manners: either as prescribed by the Company's various regulatory jurisdictions for Domestic Electric Operations' regulated assets, or over the assets' estimated useful lives. Provisions for depreciation (excluding amortization of capital leases) in the Domestic Electric and Australian Electric Operations were 3.1%, 3.1% and 3.2% of average depreciable assets in 2002, 2001 and 2000, respectively.

For the Company's regulated business, independent consultants are engaged every five years to conduct a depreciation study to determine the asset lives and salvage values used in depreciation rates. A new depreciation study is due to be completed in October 2002. Once completed, the study is presented to the various state regulatory commissions for approval before any new depreciation rates can be put in place in the rate-making process. At this time, the Company cannot predict what, if any, financial impact the new study may have on consolidated results of operations and financial position.

Pensions

The Company has defined benefit pension plans that cover substantially all employees and the Company also provides certain post-retirement benefits. Changes in interest rates, market values of stocks and changes in the assumptions of discount rates, expected return on plan assets and health care cost trend rate as used in the calculations by the Company's actuaries would impact the benefit obligations, fair value of plan assets and the Company's pension expense.

Contingent Tax Liability

The Company's annual tax returns are examined by the Internal Revenue Service and state agencies. Based upon known transactions and adjustments identified in these examinations, the Company provides for contingent liabilities in accordance with SFAS No. 5, "Accounting for Contingencies," to reflect the tax and interest charges anticipated to be due upon final settlement. The

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contingent liability is determined by applying the effective federal and state tax rates to events occurring during the period and management's assessment of the likely outcome given the relative merits of the respective positions of the government and the Company on the examination issues. Related interest charges are also provided using the rates furnished by the government for the appropriate financial reporting period. Reductions to the contingent tax liability are made for actual payments of tax and interest upon final settlement of examinations. Adjustments to the balance may result if negotiations or other events occur that provide evidence to the Company that the likely outcome of the settlement will differ from previous estimates. Assessment of the likely outcome of the examinations is based upon management's historical and current experience.

Earnings (Loss) Overview of the Company

(a)  Earnings (loss) contribution on common stock by segment: (i) does not reflect elimination for interest on intercompany borrowing arrangements; (ii) includes income taxes on a separate company basis, with any benefit or detriment of consolidation reflected in Other Operations and (iii) is net of preferred dividend requirements and minority interest (which is reported as a component of Minority interest and other).

(b) All Other Operations were transferred to PHI on February 4, 2002.

(c)  Amounts in 2002 represent the collection of a contingent note receivable relating to the discontinued operations of a former mining and resource development business, NERCO, Inc. ("NERCO"), which was sold in 1993. Amounts in 2000 represent the discontinued operations of TPC Corporation ("TPC"), a wholly owned subsidiary of Holdings until its sale in April 1999.

(d) Represents the effect of implementation of SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities" ("SFAS No. 133").

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The Company recorded earnings on common stock of $314.6 million in 2002 compared to a loss on common stock of $106.1 million in 2001 and earnings of $64.8 million in 2000. The 2002 results include a $146.7 million gain on discontinued operations and a $112.8 million loss due to the cumulative effect of an accounting change. The 2001 results included a loss of $197.7 million, after tax, from the sale of Australian Electric Operations. The 2001 results also included $27.0 million after-tax for regulatory asset write-backs and $5.0 million after-tax in Merger costs compared to $180.0 million after-tax in the 2000 period. The results for the 2000 period also included a $15.0 million after-tax write-off of projects under construction, which were abandoned in the period.

Extreme volatility and unprecedented high price levels characterized the western U.S. wholesale energy markets beginning in early 2001. During the latter half of 2002, the Company experienced electricity prices that were at levels consistent with those historically allowed in cost-of-service rates charged to customers. Market prices for electricity declined in early 2002 due to low summer demand, conservation measures, the introduction of a price cap mechanism by the FERC, effective June 19, 2001, and increased plant availability, including the return of the Company's 430 MW Hunter No. 1 unit to service in early May 2001 after an outage that occurred on November 24, 2000. However, the Company received limited benefit from electricity price reductions until the third quarter of 2002. The Company had contracted to purchase electricity in the forward market beginning in December 2000 as the forward market at that time indicated a continuation of high prices. The Company wanted to ensure that it had adequate supplies to fulfill its regulatory supply obligations and to avoid being supply constrained in a high priced and volatile market. These factors resulted in the Company continuing to pay higher prices after the market had returned to historic levels.

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

The Company'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 ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.

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Domestic Electric Operations
The Company was involved in significant regulatory proceedings during 2002 in an effort to achieve its allowed rate of return and to recover deferred power costs. As a result of those proceedings, the Company received $146.6 million of additional revenues. Of these receipts, $34.7 million were booked as regulatory liabilities rather than revenues, because they were collected subject to refund. On May 1, 2002, the Company received an order from the UPSC that allowed these revenues to be recorded in 2003 and removed the potential of their being refunded. Revenue increases by state in 2002 were $40.5 million for Utah, $65.5 million for Oregon and $5.9 million for Wyoming.

Wholesale revenues for 2002 decreased $393.4 million, or 18.9%, from 2001. Lower short-term and spot market sales prices contributed $601.0 million to the decrease and lower long-term sales volumes contributed $201.6 million. These decreases were partially offset by $373.1 million from higher volumes of short-term and spot market sales and $35.6 million in higher long-term sales prices. In 2001, Wholesale revenues increased $1,049.0 million, or 101.9%, from 2000. Higher short-term and spot market sales prices resulted in an increase in revenues of $1,559.9 million. Also contributing to this increase were $36.5 million from higher long-term prices and $12.7 million from higher

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long-term volumes. Partially offsetting this increase was $560.1 million from lower short-term and spot market sales volumes due to the sale of the Centralia plant, the decrease in hydro availability, the outage of the Hunter No. 1 unit and the increase in the Company's system load requirements.

Residential revenues for 2002 increased $49.6 million, or 5.8%, from 2001 due to $53.6 million in price increases, mainly in Utah and Oregon, and $12.0 million relating to growth in the average number of residential customers of 1.5%. These increases were partially offset by lower volumes of $11.1 million due to weather impacts and $4.8 million due to decreases in average customer usage. In 2001, Residential revenues increased $53.4 million, or 6.7%, from 2000. Growth in the average number of customers added $14.3 million, price increases added $27.4 million and volume increases, primarily due to weather, added $11.8 million.

Commercial revenues for 2002 increased $37.2 million, or 5.2%, from 2001 primarily due to $32.7 million in price increases. Growth in the average number of commercial customers of 2.3% increased revenues $17.7 million and higher volumes due to weather resulted in a $7.9 million increase. These increases were partially offset by $21.2 million due to lower customer usage. In 2001, Commercial revenues increased $43.3 million, or 6.5%, from 2000, primarily as a result of strong economic activity in Utah and Oregon. Growth in the average number of commercial customers added $22.2 million, volume increases added $19.6 million, and higher prices added $1.5 million.

Industrial revenues for 2002 decreased $25.0 million, or 3.4%, from 2001 due to $40.8 million from a reduction in energy volumes due to reduced customer usage. This decrease was partially offset by a $15.8 million increase resulting from higher prices. In 2001, Industrial revenues increased $35.6 million, or 5.1%, from 2000. Price increases added $30.7 million and higher irrigation usage added $8.5 million. Lower volumes due to customer usage resulted in a $3.6 million reduction in revenues in 2001.

Other revenues for 2002 increased $41.0 million, or 31.1%, from 2001 due to $23.8 million from the amortization of the Centralia gain liability that offset revenue reductions in other revenue categories, a $22.9 million increase in deferred carrying charges on unrecovered deferred power costs, $12.1 million in wheeling revenues from increased usage of the Company's transmission system by third parties, and $8.3 million from lower reserves. These increases were partially offset by a $14.9 million decrease in revenues due to lower load growth than anticipated by the AFOR in Oregon and a $12.4 million decrease due to Demand Side Management activities. In 2001, Other revenues increased by $59.6 million, or 82.4%, from 2000, primarily due to a $43.6 million increase in wheeling revenues from increased usage of the Company's transmission system by third parties.

Australian Electric Operations
Australian Electric Operations revenues were lower in 2001 compared to 2000 due to a shorter period of operation resulting from the sales of these operations in 2001 as discussed in Note 14 of Notes to the Consolidated Financial Statements under ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.

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Other Operations
Revenues from Other Operations for 2002 decreased $109.6 million, or 89.7%, from 2001 primarily due to a $64.0 million decrease as a result of the sale of the synthetic fuel operations, a decrease of $23.8 million due to the transfer of PPM and PKE to PHI, and a $20.0 million decrease in interest income due to the collection of a contingent note receivable held by Holdings. See DISCONTINUED OPERATIONS below. In 2001, revenues from Other Operations increased $45.1 million, or 58.5%, primarily due to a $26.4 million increase due to increased sales of synthetic fuel and a $16.5 million increase in energy trading revenues at a former subsidiary.

OPERATING EXPENSES

Domestic Electric Operations
Purchased power expense for 2002 decreased $439.6 million, or 17.7%, from 2001 primarily due to lower short-term and spot market purchase volumes of 15.6%, which decreased costs $295.1 million, lower long-term purchase volumes of 11.5%, which decreased costs $104.7 million, and lower short-term, spot market and long-term purchase prices of $70.8 million. While long-term prices per MWh dropped 11.2%, short-term prices only dropped 1.4%. These decreases were partially offset by a $46.2 million increase in Demand Side Management costs. In 2001, Purchased power expense was $2,478.4 million, an increase of $1,520.5 million, or 158.7%, over 2000 due to significantly higher prices on long-term, short-term and spot market purchases, increases in long-term volumes and increased usage of transmission systems owned by third parties. In 2001, 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 No. 1 unit, and the reduction in supply from hydroelectric facilities due to unusually low

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precipitation, led to increases in the level and volatility of power prices in 2001. Short-term and spot market purchase volumes were flat in 2001, compared to the prior year.

Fuel expense decreased $0.1 million in 2002. In 2001, Fuel expense decreased $21.3 million, or 4.2%, to $491.0 million from 2000. This decrease was attributable to a reduction in thermal generation due to the May 2000 sale of the Centralia plant and the unplanned Hunter No. 1 unit outage. Additionally, hydroelectric production decreased due to unusually low rainfall in the region, which increased the average overall cost per MWh.

Other operations and maintenance expense for 2002 increased $25.8 million, or 4.8%, from 2001 primarily due to $24.7 million for the lease of a new generating turbine, $20.4 million in increased power supply costs, increases in employee related expenses of $5.9 million and tree trimming costs of $1.4 million. These increases were partially offset by decreases due to the level and timing of capital projects and related expenditures of $31.6 million. In 2001, Other operations and maintenance expense decreased $19.4 million, or 3.5% from 2000, primarily due to the sale of the Centralia plant and mine and a decrease in bad debt expense.

Depreciation and amortization expenses for 2002 increased $12.3 million, or 3.2%, from 2001 primarily due to increased Property, plant and equipment that resulted in an $8.4 million increase and increased software amortization of $3.4 million. In 2001, Depreciation and amortization expenses increased $9.1 million, or 2.4%, to $389.0 million, primarily due to increased depreciation rates.

Administrative and general expenses for 2002 increased $124.6 million, or 103.0%, from 2001. Employee related expenses increased by $44.0 million. Administrative and general expenses for 2002 included $16.9 million for the amortization of deferred transition costs allowed by state regulators. The level and timing of expenditures capitalized in 2002 fell from 2001 levels and resulted in a $38.3 million increase in expense. Additional consulting and outside services added $9.7 million to expense, asset reserves added $5.4 million, lower chargebacks to Powercor added $2.8 million and increased insurance premiums added $2.9 million. In 2001, Administrative and general expenses decreased $79.8 million, or 39.7%. Decreased labor and severance costs and decreased employee related expenses, primarily due to the impact of favorable returns on pension plan assets on pension expense, contributed to this decrease.

Taxes, other than income taxes, decreased $6.8 million, or 7.0%, from 2001 primarily due to lower property tax expense resulting from the favorable resolution of outstanding property tax appeals and lower franchises taxes. In 2001, Taxes, other than income taxes decreased $1.8 million, or 1.8%, from 2000.

The Unrealized gain on SFAS No. 133 derivative instruments pertains to the Company's short-term sales obligations being favorably impacted by lower forward market prices that resulted from the significant changes in market fundamentals. See Note 11 of the Notes to Consolidated Financial Statements under Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.

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Australian Electric Operations
Total Operating expenses for Australian Electric Operations decreased $177.7 million in 2001 due mainly to a shorter period of operations resulting from the sale.

Other Operations
Operating expenses for 2002 for Other Operations decreased $126.8 million, or 93.4%, primarily due to the sale of the synthetic fuel operations that resulted in a $98.4 million decrease and $21.3 million due to the transfer of Holdings to PHI. In 2001, Operating expenses from Other Operations increased $50.9 million, or 60.0%, primarily due to a $36.2 million increase resulting from increased production of synthetic fuel, $10.3 million relating to business development costs and $3.5 million relating to increased operating costs at a former subsidiary.

OTHER OPERATING INCOME

Other operating income for 2002 increased $1.8 million. In 2002, the Company recorded $21.0 million relating to a rate order received that successfully resolved issues surrounding previously excluded costs and resulted in the establishment of a regulatory asset. The Company also recorded an $11.3 million gain on the sale of the synthetic fuel operations. Included within Other operating income in 2001 was income of $43.5 million relating to rate orders received which provided recovery for previously denied costs and resulted in the establishment of regulatory assets. In addition, the Company recorded a loss on the sale of the Centralia plant and mine of $13.9 million in 2001.

(GAIN) LOSS ON SALE OF AUSTRALIAN ELECTRIC OPERATIONS

In June 2001, upon resolution of a contingency under the provisions of the Powercor sale agreement, the Company received further proceeds due from the sale that resulted in income of $27.4 million in 2002. In 2001, the Company recorded a $184.2 million loss on the sale of the Australian Electric Operations.

INTEREST EXPENSE AND OTHER (INCOME) EXPENSE

(a)  Minority interest and other includes payments of $28.3 million on Preferred Securities of wholly owned subsidiary trusts for each of the three years ended March 31.

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Interest expense for 2002 decreased $62.7 million, or 21.6%, primarily due to the sale of the Australian operations and lower interest rates. Interest expense decreased $51.0 million in 2001, primarily due to the sale of the Australian Electric Operations and the reduction in external debt with the proceeds received from asset sales.

INCOME TAX EXPENSE

Income tax expense for 2002 decreased $4.3 million, or 2.4%, from 2001 primarily due to reduced taxable income. In 2001, Income tax expense increased $46.4 million due to higher taxable income in 2001, partially offset by the effect of nondeductible Merger costs in 2000.

The Company's combined federal and state effective income tax rate from continuing operations was 37.5% for 2002, 195.7% for 2001 and 61.9% for 2000. The tax rate in 2002 was approximately the same as the statutory rate. The tax rate in 2001 varied from the statutory rate primarily due to the substantially non-deductible losses on the sales of the 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 13 of Notes to the Consolidated Financial Statements under ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.

DISCONTINUED OPERATIONS

The Company recognized $146.7 million of income during 2002 as a result of collecting a contingent note receivable relating to the discontinued operations of its former mining and resource development business, NERCO, which was sold in 1993. This note from the buyer was recorded at the date of the NERCO sale along with a corresponding deferred gain. Payments on this note were contingent upon the buyer receiving payment under a coal supply contract. The Company recognized this gain on a cost recovery basis as payments were received from the buyer. In June 2001, the Company received full payment of the remaining balance of the note and recognized the remaining balance of the deferred gain. Deferred tax expense of $36.4 million was recognized on the gain in June 2001.

OPERATING ACTIVITIES

Cash flows from continuing operations decreased $302.1 million from 2001 to 2002. 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, Wyoming and Idaho, has received rate recovery in Utah and Oregon and is currently working with Wyoming and Idaho to develop recovery mechanisms for their deferred costs. Additionally, the Company has asked for rate increase requests

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before the state commissions in Oregon, Wyoming and California. For more detail on deferred net power cost and rate increase filings, see ITEM 1. BUSINESS - DOMESTIC ELECTRIC OPERATIONS - REGULATION. The $706.4 million change in Accounts payable and accrued liabilities primarily reflects the higher prices paid for electricity late in 2001 and larger income tax accruals in 2001.

INVESTING ACTIVITIES

Capital spending totaled $505.3 million in 2002 compared with $491.0 million in 2001. Construction expenditures increased in 2002 due to the 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.

FINANCING ACTIVITIES

The Company does not utilize "off-balance sheet" financing arrangements other than operating leases, which are accounted for in accordance with SFAS No. 13 "Accounting for Leases."

The Company's short-term borrowings and certain other financing arrangements are supported by $880.0 million of revolving credit agreements established in June 2001. The finance charges for these facilities are based on LIBOR plus a margin. The current revolving credit agreements expire in June 2002, but contain a one-year term loan option. The Company has signed new revolving credit agreements that become effective June 4, 2002 with one for $500.0 million having a 364-day term plus a one-year term option, and the other for $300.0 million having a three-year term. Other provisions are similar to the prior credit agreements. The Company had $110.6 million in money market accounts included in Cash and temporary cash investments at March 31, 2002.

On November 21, 2001, the Company issued $500.0 million of its 6.9% Series of First Mortgage Bonds due November 15, 2011 and $300.0 million of its 7.7% Series of First Mortgage Bonds due November 15, 2031. The Company has an effective shelf registration statement for up to $1.1 billion of long-term debt, of which $800.0 million has been authorized to be issued by the applicable regulatory commissions, subject to certain conditions. Any such issuance would be subject to market conditions.

On August 15, 2001, the Company redeemed, at par, $100.0 million of its preferred stock pursuant to its scheduled mandatory redemption.

During 2002, the Company declared dividends on common stock of $240.8 million and paid dividends on common stock of $298.6 million to an indirect subsidiary of ScottishPower. During 2001, the Company declared dividends on common stock of $390.0 million and paid dividends on common stock of $332.0 million to an indirect subsidiary of ScottishPower. These dividends were declared at a rate that is consistent with the Company's historic pre-Merger rate per share. See Note 9 of Notes to the Consolidated Financial Statements under ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.

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The Company declared dividends of $9.8 million and paid dividends of $11.7 million on preferred stock during 2002 and had $2.3 million in preferred dividends declared but unpaid at March 31, 2002.

CAPITALIZATION

The decline in common equity during 2002 was largely attributable to the transfer of Holdings, which had previously been included in consolidated capitalization. Long-term debt increased due to the $800.0 million First Mortgage Bond issuance during 2002. Proceeds were used for general corporate purposes and to repay short-term debt, including approximately $550.0 million temporarily advanced from Holdings. These intercompany advances were previously eliminated in PacifiCorp's consolidated results.

The Company manages its capitalization and liquidity position 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.

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 changes.

On a consolidated basis, the Company attempts to maintain total debt at approximately 48.0% to 54.0% of capitalization. The total debt to capitalization ratio was 53.6% at March 31, 2002. The Company expects, over time, to maintain its capital structure in accordance with its targets. 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 36.0% of total capitalization, excluding short-term debt and current maturities of long-term debt, increasing over time to 40.0%.

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VARIABLE RATE LIABILITIES

The Company's capitalization policy targets consolidated variable rate liabilities at between 10.0% and 25.0% of total capitalization.

AVAILABLE CREDIT FACILITIES

At March 31, 2002, PacifiCorp had $880.0 million of committed bank revolving credit agreements that expire in June 2002. These facilities contain a one-year term loan option. The Company relies upon these facilities in part to provide for committed back-up for short-term borrowing and daily liquidity requirements for $150.9 million of unenhanced pollution control revenue bonds. The Company has signed new $800.0 million credit agreements that become effective June 4, 2002. Regulatory authorities limit PacifiCorp to $1.5 billion of short-term debt, of which $176.5 million was outstanding at March 31, 2002 at a weighted average rate of 2.2%. For additional information, see Notes 6 and 7 of Notes to the Consolidated Financial Statements under ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.

The Company believes that its existing and available capital resources and the new revolving credit agreements will be sufficient to meet working capital, dividend and construction needs in 2003.

CREDIT RATINGS

The Company has no rating downgrade triggers that would accelerate the maturity dates of its debt. A change in ratings is not an event of default, nor is the maintenance of a specific minimum level of credit rating a condition to drawing upon the credit agreements. However, interest rates on loans under the credit agreements and commitment fees are tied to credit ratings and would increase or decrease when ratings are changed. A ratings downgrade may reduce the accessibility and increase the cost of the Company's commercial paper program, its principal source of short-term borrowing, and may result in the requirement that the Company post collateral under certain of the Company's power purchase and other agreements.

In addition, a number of the Company's agreements in the wholesale electric, wholesale gas and energy derivatives markets contain provisions that provide for either counterparty the right to receive cash or other security if mark to market ("MtM") exposures on a net basis exceed certain negotiated threshold levels. Generally, these threshold levels change based on long-term unsecured ratings. As such, a ratings downgrade could require PacifiCorp to provide additional funds to a counterparty if threshold amounts were exceeded. At March 31, 2002, PacifiCorp estimates that a one level downgrade, by either Standard & Poor's or Moody's, of its senior unsecured debt ratings would result in current MtM exposures exceeding the threshold levels, in those agreements that have such rating triggers, by approximately $7.2 million.

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CONTRACTUAL OBLIGATIONS AND COMMERCIAL COMMITMENTS

The tables below show the Company's contractual obligations and commercial commitments as of March 31, 2002.

The amounts above do not include capital commitments. Refer to ITEM 1. BUSINESS - DOMESTIC ELECTRIC OPERATIONS - CONSTRUCTION PROGRAM for projected capital spending.

LIMITATIONS

In addition to the Company's capital structure policies, its debt capacity is also governed by its contractual commitments. PacifiCorp's principal debt limitations are a 60.0% debt to defined capitalization test and an interest coverage covenant contained in its principal credit agreements. Based on the Company's most restrictive agreement, management believes that PacifiCorp could have borrowed an additional $1.2 billion of debt at March 31, 2002.

Under PacifiCorp's principal credit agreements, it is an event of default if any person or group, other than ScottishPower, acquires 35.0% 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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INFLATION

Due to the capital-intensive nature of the Company's business, 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 the Company's business.

NEW ACCOUNTING STANDARDS

The Company adopted SFAS No. 133, as amended by SFAS No. 138, effective April 1, 2001. For further discussion regarding the effects of this implementation and for information on other newly issued statements, see Notes 11 and 1, respectively, of Notes to the Consolidated Financial Statements under ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.

In June 2001, the Financial Accounting Standards Board ("FASB") issued SFAS No. 142, "Goodwill and Other Intangible Assets" ("SFAS No. 142"), which addresses financial accounting and reporting for acquired goodwill and other intangible assets and supersedes Accounting Principles Board ("APB") Opinion No. 17, "Intangible Assets" ("APB No. 17"). SFAS No. 142 specifically states that it does not change the accounting prescribed by SFAS No. 71. The Company has no goodwill recorded on its books. Due to the regulatory treatment for the Company's intangible assets, which were all internally developed, the adoption of SFAS No. 142 will have no material effect on the financial position or results of operations. This statement is effective for the Company beginning April 1, 2002.

In June 2001, the FASB issued SFAS No. 143, "Accounting for Asset Retirement Obligations" ("SFAS No. 143"). The statement requires the fair value of an asset retirement obligation to be recorded as a liability in the period in which the obligation was incurred. At the same time the liability is recorded, the costs of the asset retirement obligation will be recorded as an addition to the carrying amount of the related asset. Over time, the liability is accreted to its present value and the addition to the carrying amount of the asset is depreciated over the asset's useful life. Upon retirement of the asset, the Company will settle the retirement obligation against the recorded balance of the liability. Any difference in the final retirement obligation cost and the liability will result in either a gain or loss. The Company will adopt this statement on April 1, 2003. The Company is currently evaluating the impact of adopting this statement on its financial position and results of operations.

In August 2001, the FASB issued SFAS No. 144, which modifies and expands the financial accounting and reporting for the impairment or disposal of long-lived assets other than goodwill, which is specifically addressed by SFAS No. 142. The new statement supersedes SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of" ("SFAS No. 121"), but retains many of the fundamental recognition and measurement provisions of SFAS No. 121. The Company adopted SFAS No. 144 in February 2002 retroactive to April 1, 2001. The adoption of SFAS No. 144 resulted in the Company not classifying Holdings as Discontinued Operations following the internal restructuring.

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This increase in potential loss is primarily due to an increase in interest rate volatility and an increase in the duration of the portfolio during the period.

Commodity Price Exposure - The Company's market risk to commodity price change is primarily related to its fuel and 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 risk management 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 8,269 MW generation and transmission system in the western United States and through its wholesale energy purchase and sales activities. Physically settled contracts are utilized to hedge the Company's excess or shortage of net electricity for future months. The Company has also entered into several financially settled weather hedges to mitigate the risks of hot weather induced high loads or low streamflow induced loss of hydrogeneration.

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

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LIABILITIES, REDEEMABLE PREFERRED STOCK AND SHAREHOLDER'S EQUITY

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. At March 31, 2002, the Company had reduced its workforce by approximately 750 due to the Transition Plan. 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 $158.6 million in Regulatory assets and $16.6 million in Deferred charges as a result of the accounting orders issued by state regulatory bodies for these estimated costs. Below is a summary of the accruals recorded and payments made during 2002 and 2001 with respect to the deferred costs described above.

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During the year, management determined to modify the manner in which the remaining workforce reductions would be achieved over the Transition Plan period, resulting in a reduction in the estimated remaining severance costs of $9.1 million. As a result, management determined it was no longer appropriate to account for the remaining liability under Emerging Issues Task Force ("EITF") No. 94-3 "Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity (Including Certain Costs Incurred in a Restructuring)." Therefore, the remaining liability of $30.8 million has been reclassified on the balance sheet to offset the related Transition Plan regulatory assets referred to above. There is no income statement impact from the change in estimate or reclassification of the Transition Plan liability.

NOTE 3 - 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.

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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, 2002, 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 FERC as to accounting policies and practices, certain prices and other matters.

SFAS No. 71 provides that regulatory assets may be capitalized if it is probable that future revenue in an amount at least equal to the capitalized costs will result from the inclusion of that cost in allowable costs for ratemaking purposes. In addition, the rate action should permit recovery of the specific previously incurred cost rather than to provide for expected levels of similar future costs. The statement makes it clear that a company does not need absolute assurance prior to capitalizing a cost, only reasonable assurance.

In an effort to mitigate the temporary discrepancy between prices paid to purchase power and revenues received through regulated rates, the Company requested and received regulatory approval from the utility commissions in the states of Utah, Oregon, Wyoming and Idaho to capitalize for each state some or all of the net power costs that vary from costs included in determining retail rates. At March 31, 2002, the Company had a balance of $305.4 million of such capitalized costs supported by stipulated agreements reached in Utah, Oregon, and Idaho and an estimate of the probable outcome of the Wyoming rate case expected to be settled late in calendar 2002. The determination of the amount to be recovered is subject to final commission orders from each of these states. Differences between the amount allowed by the commissions and the amounts capitalized at March 31, 2002 will be recognized as either a charge or credit to income upon receiving final commission orders.

Deferred accounting treatment for the effects of SFAS No. 133 on the financial statements of the Company has been granted in all the states the Company serves. The regulatory orders direct the deferral, as a regulatory asset or liability, of the effects of fair valuing long-term contracts that are included in the Company's rates.

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Regulatory assets include the following:

(a)  Excludes $99.3 million and $107.2 million as of March 31, 2002 and 2001, respectively, of investment tax credits.

(b)  Represents the unamortized amount of retirement and severance costs relating to the Transition Plan that the state commissions allowed to be deferred and amortized. The 2002 amount reflects the reclassification of $30.8 million of severance accruals for the Transition Plan.

(c)  Represents the deferred net power costs that vary from costs included in determining retail rates in the states of Utah, Oregon, Wyoming and Idaho.

(d)  A Utah Public Service Commission ("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. A UPSC order during 2002 allowed recovery of an additional $21.0 million of mine reclamation, information system and transition costs that had previously been written-off.

(e)  Represents the current and non-current mark-to-market derivative adjustments on long-term purchased power contracts per FAS 133.

(f)  Represents the State of Oregon Senate Bill 1149 ("SB 1149") related transition and implementation costs allowed to be recovered by a systems benefit charge allotted to associated customers effective March 1, 2002.

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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 $13.9 million resulting in a loss on sale that was recorded in Other operating income in 2001. The Company is no longer required to return a portion of the gain relating to Utah customers as discussed in Deferred Net Power Costs below.

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, Washington and Idaho, 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, as discussed in Note 1.

Depreciation Rate Increase
During 1998, the Company filed applications with the respective regulatory commissions in the states of Utah, Oregon, Wyoming and Washington to increase rates of depreciation based on a new depreciation study. All applications were approved in 2000. The increase in rates of depreciation 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 ordered a reversal of a portion of previously accrued depreciation. These reversals in total, for both states, amounted to approximately $14.0 million per year for 2001 and 2002. The Company is required to file new depreciation studies in October 2002 based on plant balances as of March 31, 2002.

Trail Mountain Mine Closure Costs
On February 7, 2001, the Company filed applications with the UPSC, the Oregon Public Utilities Commission ("OPUC"), the Wyoming Public Service Commission ("WPSC") and the Idaho Public Utilities Commission ("IPUC") requesting accounting orders to defer $27.1 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 WPSC and the IPUC approved deferred accounting treatment of their state's share of the $27.1 million of non-recovered Trail Mountain Mine investment costs. Additional closure-related costs in the amount of $18.7 million were subsequently identified, and the total amount subject to possible deferral increased to approximately

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$45.8 million. The Company filed in Utah and Oregon to include the additional costs in its deferral application and received approval to defer the full $45.8 million for accounting purposes. In addition, the parties in Oregon signed a stipulation calling for a permanent $1.1 million annual rate reduction in Oregon due to the removal of the Trail Mountain assets from rate base. The stipulation also provides for a $2.6 million annual surcharge for five years to recover Oregon's share of mine closure costs. This stipulation requires OPUC approval. On April 4, 2002, the UPSC approved deferral of Utah's share of the $45.8 million with a five-year amortization beginning April 1, 2001.

In April 2002, the Company established a regulatory asset for the full closure costs of the Trail Mountain mine with a five-year amortization period beginning April 2001. The resulting regulatory asset at April 30, 2002 was $36.4 million, net of amortization. The reestablishment of the regulatory asset increased accumulated depreciation to reverse the effects of the retirement of the mine and decreased coal inventory costs for the closure-related costs. Recovery of the Trail Mountain amortization in Oregon was approved on May 20, 2002. The Company recently filed for recovery in Wyoming as part of its general rate case and will seek recovery in the remaining states.

Merger Credits
As a result of the Merger, the Company was required to provide benefits to ratepayers through fixed reductions in rates, or "Merger Credits." The Company's total obligation for Merger Credits was $133.4 million through the period ending December 31, 2004. The Company recorded $12.0 million and $57.2 million as liabilities and current expenses in its financial statements for the years ended March 31, 2001 and 2000, respectively, as those amounts were not subject to potential offsets. In May 2002, the UPSC allowed the Company to offset $21.0 million of future Merger Credits against deferred net power costs and eliminated the obligation for future Merger Credits in Utah. The IPUC is also considering a stipulation agreement that will allow the Company to offset future Merger Credits against deferred net power costs in the amount of $2.3 million. These actions will increase monthly revenues by approximately $1.0 million until December 31, 2003. Through March 31, 2002, the Company had provided $48.8 million in Merger Credits and interest to its customers through reduced rates. If the IPUC approves the outstanding stipulation, future Merger Credits of $44.3 million will still be due to customers in Oregon and Washington with the possibility of offsetting $21.0 million of that amount.

Concluded Regulatory Actions
Utah - On January 12, 2001, the Company filed a request with the UPSC for an increase in electricity rates for its customers in Utah. This request encompassed normalized power costs based on a test year of the twelve months ended September 30, 2000 and did not include those power cost variances associated with the Hunter No. 1 outage. The request would have increased prices by approximately 19.1% overall, or $142.0 million. On July 12, 2001, the Company agreed to reduce its request to an increase of $118.0 million. Concurrent with the initial filing, the Company filed a separate emergency petition for interim relief. On February 2, 2001, the UPSC granted an interim rate increase of $70.0 million, effective February 2, 2001. The $70.0 million interim rate increase was subject to refund if the final rate order did not

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increase of $2.6 million for five years to reflect the recovery of additional Trail Mountain mine closure costs; (ii) offsetting reductions totaling $2.5 million in base rates ($0.7 million cut from net power costs, $0.7 million rate reduction due to the sale of the Company's Hermiston service territory and $1.1 million from the Trail Mountain closure); (iii) a rate decrease of $3.4 million in effect for one year reflecting the refund to customers of 95% of the gain relating to the Hermiston service territory sale; (iv) an additional decrease in base power costs of $1.2 million, which would be added back to power costs if the West Valley City, Utah affiliated interest application is approved (i.e., the Company could increase base rates by $1.2 million). An order approving the stipulation agreement was issued on May 20, 2002, increasing rates for one year by $15.4 million.

Wyoming - On July 9, 2001, the Company received an order from the WPSC approving the all-party stipulation that settled all issues in the Wyoming rate case filed on December 18, 2000. This order resulted in increased annual revenues of $8.9 million, effective August 1, 2001. Approximately $5.9 million in additional revenues were received in 2002.

Rate Increases Submitted for Regulatory Approval
California - On March 16, 2001, the Company filed an interim rate relief request with the California Public Utilities Commission ("CPUC") as Phase I in an effort to seek an increase in electricity rates for its customers in California. If approved by the CPUC, Phase I would increase rates about 13.8% overall, or $7.4 million. In addition, the Company has moved forward with its Phase II filing of a General Rate Case ("GRC") to increase rates to compensatory levels. The GRC request submitted on December 21, 2001, if approved by the CPUC, would raise customer rates 29.4% overall or $16.0 million annually, with an authorized return on equity of 11.5%. The annual amount requested would incorporate the Phase I interim amount. On December 26, 2001, the Office of Ratepayer Advocates ("ORA") filed a motion to dismiss or defer the Company's GRC request. The Company responded to ORA's motion on January 9, 2002. Following the expiration of the protest period, on February 25, 2002 the Company filed a motion for a pre-hearing conference to identify parties of record, establish a procedural schedule and address other issues.

Deferred Net Power Costs
On November 1, 2000, the Company filed applications in Utah, Oregon, Wyoming and Idaho seeking deferred accounting treatment for net power costs materially in excess of the power costs assumed in setting existing retail rates. The applications sought to defer these power cost variances beginning November 1, 2000. As discussed below, the Company received authorization to defer some power costs in excess of those included in retail rates in all the states where requests were made. At March 31, 2002, the Company had a regulatory asset of $305.4 million, including carrying costs, for total deferred power costs.

Utah - In Utah, pursuant to the UPSC's approval of deferred accounting treatment for replacement power costs resulting from the Hunter No. 1 outage, the Company filed on August 23, 2001 seeking permission to recover $103.5 million in replacement power costs over a 12-month period. On

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November 2, 2001, the UPSC allowed the Company to apply over-collections from the general rate case toward Hunter No. 1 replacement power costs on an interim basis, subject to refund. The amount of the interim relief was approximately $29.5 million annually. As of March 31, 2002, $34.7 million had been collected toward Hunter No. 1 replacement costs.

Also in Utah, on September 21, 2001, the Company filed for permission to defer $109.0 million of excess net power costs above the level adopted in the Company's rate order of September 10, 2001. These costs were incurred during the period May 9, 2001 through September 30, 2001. A hearing relating to the deferral was held on December 7, 2001. On November 13, 2001, the Company also filed an application with the UPSC to recover, through a surcharge, the excess net purchased power costs incurred during the period May 9, 2001 through September 30, 2001. These filings are alternative approaches to recovery of effectively the same $109.0 million of costs that are not yet deferred. They are alternatives to each other and are not additive.

On May 1, 2002, the UPSC issued an order approving a stipulation agreement regarding recovery of deferred and non-deferred net power costs in Utah. The order allows the Company to continue collecting a $29.5 million annual surcharge until March 31, 2004 and to apply $34.7 million of revenue already collected subject to refund against deferred net power costs. The order allows the Company to offset deferred net power costs against a regulatory liability of $27.0 million for amounts to be returned to customers relating to the gain from the 2001 sale of the Centralia, Washington power plant. The Company will also realize $21.0 million by elimination of future Merger Credits. These regulatory liability offsets will reduce the regulatory asset for deferred net power costs. Monthly revenues will increase approximately $1.0 million until December 31, 2003 due to the termination of Merger Credit revenue reductions. The Company will record additional deferred net power costs of $37.9 million, withdraw its request to defer $109.0 million of excess net power costs and commit not to file a general rate case that would take effect prior to January 1, 2004, with certain exceptions. These actions should allow the Company to recover a total of $147.0 million of deferred and non-deferred net power costs in Utah.

Oregon - The Oregon deferred accounting filing encompassed all power costs that vary from the level in Oregon rates during the period from November 1, 2000 through September 9, 2001, including costs to replace lost generation resulting from the Hunter No. 1 outage. On January 18, 2001, the Company requested a 3.0%, or $23.0 million, annual rate increase effective February 1, 2001, to provide partial recovery of post-October 31, 2000 power cost variances attributable to Oregon over an amortization period. This 3.0% rate increase was the maximum allowed on an annual basis for the recovery of deferred costs under the Oregon statutes. On January 23, 2001, the OPUC authorized deferred accounting for power costs of $23.0 million. On February 20, 2001, the OPUC authorized the 3.0% rate increase effective February 21, 2001, subject to refund, pending the outcome of a separate phase of the proceeding to examine the prudence of these expenditures. The Company received $21.6 million in revenues as a result of this OPUC action. The OPUC has approved the Company's request to continue amortization at the 3.0% rate pending resolution of the prudence review, which is expected to be completed in June 2002.

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The Company has appealed two OPUC orders, which establish the mechanism to determine the amount of power costs to defer, to the Marion County, Oregon, Circuit Court in separate complaints filed on October 1, 2001. The appeals have been consolidated. Oral arguments were held on May 9, 2002 and a ruling is expected in June 2002.

The Company filed with the OPUC on September 21, 2001 to increase the level of recovery of excess net power costs incurred to serve Oregon customers from the current 3.0% amortization level, or $23.0 million awarded in February 2001, to 6.0%. On October 22, 2001, the OPUC suspended the Company's request pending the outcome of the prudence phase of the proceeding. Upon completion of the prudence review, the Company will renew its request to increase the amortization level to 6.0%.

In December 2001, the Company and the OPUC staff reached a stipulation in the prudence phase of its deferred net power cost. The stipulation provides that proceeding, the Company would be permitted to recover 85.0% of the deferred net power costs in Oregon, or about $131.0 million plus carrying charges. The stipulation allows the Company to seek a higher level of recovery in the event the Company's appeal of the Commission's order limiting deferrals is successful. On May 20, 2002, the OPUC approved a one-year $15.4 million overall rate increase effective June 1, 2002 for the Company's Oregon customers to cover increases in power costs.

On September 7, 2001, the OPUC endorsed an agreement on deferral of net power costs after September 2001. The agreement specifies that until May 2002, the Company will defer the difference between 83.0% of actual net power costs and the new Oregon baseline power cost in tariffs. In December 2001, the parties to the original stipulation agreed to extend this mechanism until June 2002.

Wyoming - In Wyoming, on November 1, 2000, the Company filed for deferred accounting treatment of net power costs that vary from costs included in determining retail rates. The Company proposed to recover $47.0 million of deferred net power costs, incurred through June 2001, over a 12-month period. On November 20, 2001, following an order by the WPSC dismissing the majority of the Company's case based on a procedural issue, the Company requested authority to withdraw its excess power cost recovery filing without prejudice. On November 26, 2001, the WPSC granted the Company's motion. On May 7, 2002, the Company filed a Wyoming general rate case that includes a consolidation of all excess net power costs, including those for which recovery was being sought in the withdrawn proceeding, totaling $91.0 million.

Idaho - On January 7, 2002, the Company filed a request with the IPUC to recover $38 million of deferred net power costs through a temporary 24-month surcharge on customer bills and to implement a new credit to pass through Residential Exchange Program benefits from the two Bonneville Power Administration ("BPA") settlement agreements described above. The credit would not affect Company earnings. In addition, the Company requested an adjustment of individual rate classes to more closely reflect the actual cost-of-service and proposed a rate mitigation policy to ensure that no customer class would receive a rate increase during the period in which the proposed surcharge is in effect. Parties to the proceeding agreed to a stipulation that would allow

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recovery of $25.0 million of the deferred net power costs. This recovery would be achieved through a $22.7 million power cost surcharge plus the termination of future Merger Credits in the amount of $2.3 million. The IPUC conducted hearings beginning on May 7, 2002 to consider the stipulation.

Washington - On April 5, 2000, the Company filed a petition with the Washington Utilities and Transportation Commission ("WUTC") seeking authority to begin deferring excess net power costs as of June 1, 2002 for later recovery in rates, either through a power cost adjustment mechanism or a limited rate adjustment. Under the rate plan approved by the WUTC in August 2000 at the conclusion of the Company's last general rate case in Washington, there are limitations on the Company's ability to raise general rates prior to 2006. On May 10, 2002, the other parties to the rate plan filed a motion with the WUTC seeking to reopen the Company's 2000 general rate case and consolidate it with the Company's request for deferred accounting. A ruling on this motion by the WUTC is expected in early June 2002.

NOTE 4 - Discontinued Operations

The Company recognized $146.7 million of income during the first quarter of 2002 as a result of collecting a contingent note receivable relating to the discontinued operations of its former mining and resource development business, NERCO, Inc. ("NERCO"), which was sold in 1993. This note from the buyer was recorded at the date of the NERCO sale along with a corresponding deferred gain. Payments on this note were contingent upon the buyer receiving payment under a coal supply contract. The Company recognized this gain on a cost recovery basis as payments were received from the buyer. In June 2001, the Company received $189.9 million, which was full payment of the remaining balance of the note and recognized the remaining balance of the deferred gain. Deferred tax expense of $36.4 million was recognized on the gain in June 2001.

In October 1998, the Company decided to exit its energy trading business by offering for sale TPC Corporation ("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 has been closed. On April 1, 1999, Holdings sold TPC to NIPSCO Industries, Inc. for $150.3 million. Exiting these energy-trading activities resulted in a net after-tax gain of $1.1 million in the first quarter of 2000.

At March 31, 2001, Holdings had $8.0 million of current liabilities in Other relating to discontinued operations.

NOTE 5 - Related Party Transactions

There are no loans or advances between PacifiCorp and ScottishPower or PHI. Any such transactions would require state regulatory and SEC approval.

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The tables below detail the Company's related party transactions and balances.

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

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

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(c)  Amounts shown are related to activity of Holdings, while a subsidiary of the Company, with PHI and its subsidiaries. PHI is a non-operating, U.S. holding company that was incorporated in December 2000. PHI is also an indirect wholly owned subsidiary of ScottishPower and became the Company's parent as of December 31, 2001. PHI also owns two energy companies that were owned by the Company until March 29, 2001.

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

(e)  These revenues primarily represent wheeling revenues received from PPM.

Interest rates on related party borrowings approximate lender's cost of capital and are reset at 30-day intervals. The applicable rate at March 31, 2002 was 1.9% and at March 31, 2001 ranged from 5.08% to 5.23%. As noted in the above table, amounts due from affiliated companies in the prior year included the $370.0 million note due to Holdings from ScottishPower. As noted in Note 1, PacifiCorp transferred ownership of Holdings to PHI in February 2002. As Holdings is no longer a subsidiary of PacifiCorp, the ScottishPower note is no longer included in its results. As this note made up the majority of last year's affiliated company receivable balance, it was the main factor affecting average interest rates on related party borrowings. Along with the elimination of that receivable, declining interest rates in the current year contributed to the lower interest rate as of March 31, 2002.

In May 2002, PacifiCorp entered into a fifteen year operating lease on a power generation facility with PPM. PacifiCorp, at its sole option, may terminate the lease after three and six years. The facility is located in Utah, and is being constructed by West Valley Leasing Company, a wholly owned subsidiary of PPM. The facility will ultimately consist of five generation units each rated at 40 MW. Scheduled lease payments are $3.0 million annually per unit. Two of these units were operational May 1, 2002; two additional units are expected to be operational no later than June 1, 2002; and the fifth unit is expected to be operational no later than August 1, 2002.

NOTE 6 - Short-Term Debt And Borrowing Arrangements

The Company'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.

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At March 31, 2002, commercial paper and bank line borrowings were supported by $880.0 million of revolving credit agreements, which expire in June 2002. The facilities contain a one-year term loan option. The Company has signed new $800.0 million credit agreements that become effective June 4, 2002.

NOTE 7 - Long-Term Debt

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