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10-K 1 p0331200210k.htm PACIFICORP 3/31/2002 10-K Nm bxcd

SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-K

(Mark One)

/X/	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended March 31, 2002
OR

/ /	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the Transition period from _________ to _________

Commission File Number 1-5152

PACIFICORP
(Exact name of registrant as specified in its charter)

State of Oregon (State or other jurisdiction of incorporation or organization)	93-0246090 (I.R.S. Employer Identification No.)
825 N.E. Multnomah, Portland, Oregon (Address of principal executive offices)	97232 (Zip Code)

Registrant's telephone number, including area code: (503) 813-5000

Securities registered pursuant to Section 12(b) of the Act:

	Title of each Class	Name of each exchange on which registered
	8 1/4% Cumulative Quarterly Income Preferred Securities, Series A, of PacifiCorp Capital I 7.70% Trust Preferred Securities, Series B, of PacifiCorp Capital II	New York Stock Exchange New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act:

Title of each Class

5% Preferred Stock (Cumulative; $100 Stated Value)
Serial Preferred Stock (Cumulative; $100 Stated Value)
No Par Serial Preferred Stock (Cumulative; $100 Stated Value)

Indicate by check mark whether the Registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. YES X NO ___

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of Registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [X]

On May 24, 2002, the aggregate market value of the shares of voting and non-voting common equity of the Registrant held by non-affiliates was $0.

As of May 24, 2002, there were 297,324,604 shares of common stock outstanding. All shares of outstanding common stock are indirectly owned by Scottish Power plc, 1 Atlantic Quay, Glasgow, G2 8SP, Scotland.

DOCUMENTS INCORPORATED BY REFERENCE

None.

TABLE OF CONTENTS

	Page No.
Definitions..................................................	ii
Corporate Organization.......................................	iv
Part I Item 1. Business........................................ Item 2. Properties...................................... Item 3. Legal Proceedings............................... Item 4. Submission of Matters to a Vote of Security Holders.......................................	1 22 24 24
Part II Item 5. Market for Registrant's Common Equity and Related Stockholder Matters................... Item 6. Selected Financial Data......................... Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations........... Item 7A. Quantitative and Qualitative Disclosures about Market Risk............................. Item 8. Financial Statements and Supplementary Data..... Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure........	24 25 25 43 49 109
Part III Item 10. Directors and Executive Officers of the Registrant.................................... Item 11. Executive Compensation.......................... Item 12. Security Ownership of Certain Beneficial Owners and Management................................ Item 13. Certain Relationships and Related Transactions..	109 112 123 125
Part IV Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K...........................	125
Signatures..................................................	128

DEFINITIONS

When the following terms are used in the text, they will have the meanings indicated:

Term	Meaning
BPA............	Bonneville Power Administration
Centralia......	Centralia Power Plant and coal mine, which was wholly-owned and operated by the Company until its sale on May 4, 2000
Company........	PacifiCorp and its subsidiaries
CPUC...........	California Public Utilities Commission
EPA............	United States Environmental Protection Agency
FERC...........	Federal Energy Regulatory Commission
FPA............	Federal Power Act
Hazelwood......	Hazelwood Power Partnership, an Australian partnership and 19.9% indirectly owned investment of Holdings until its sale in November 2000
Holdings.......	PacifiCorp Group Holdings Company, a Delaware corporation and wholly-owned subsidiary of PacifiCorp until its transfer to PHI on February 4, 2002, and its wholly-owned subsidiary, PacifiCorp International Group Holdings Company
IPUC...........	Idaho Public Utilities Commission
kWh............	Kilowatt hours
MW.............	Megawatt
MWh............	Megawatt hours
NAGP...........	NA General Partnership, a Nevada general partnership, the direct parent of PHI and an indirect subsidiary of ScottishPower
OPUC...........	Oregon Public Utilities Commission
PFS............	PacifiCorp Financial Services, Inc., an Oregon corporation and wholly-owned direct subsidiary of Holdings, and its subsidiaries
PacifiCorp.....	PacifiCorp, an Oregon corporation
Pacific Power..	Pacific Power & Light Company, the assumed business name of PacifiCorp under which it conducts a portion of its retail electric operations

Term	Meaning
PHI............	PacifiCorp Holdings, Inc., a Delaware corporation and non- operating U.S. holding company that became PacifiCorp's direct parent on December 31, 2001 and the direct parent of Holdings on February 4, 2002
PKE............	Pacific Klamath Energy, Inc., an Oregon corporation and wholly-owned subsidiary of PacifiCorp until its transfer to PHI in March 2001
PPM............	PacifiCorp Power Marketing, Inc., an Oregon corporation and wholly-owned subsidiary of PacifiCorp until its transfer to PHI in March 2001
Powercor.......	Powercor Australia Ltd., a Victoria, Australia limited liability corporation and indirect, wholly-owned subsidiary of Holdings, and its immediate parent companies, until its sale in September 2000
SB 1149........	Oregon Senate Bill 1149
ScottishPower..	Scottish Power plc, the indirect parent company of PacifiCorp
SEC............	Securities and Exchange Commission
SFAS...........	Statement of Financial Accounting Standards
UPSC...........	Utah Public Service Commission
Utah Power.....	Utah Power & Light Company, the assumed business name of PacifiCorp under which it conducts a portion of its retail electric operations
WPSC...........	Wyoming Public Service Commission
WSCC...........	Western System Coordinating Council
WUTC...........	Washington Utilities and Transportation Commission

iii

PART I

ITEM 1. BUSINESS

THE ORGANIZATION

PacifiCorp is a United States electricity company operating in six western states. The Company conducts its retail electric utility business as Pacific Power and Utah Power, and engages in power production and sales on a wholesale basis under the name PacifiCorp.

In November 1999, PacifiCorp and ScottishPower completed a merger (the "Merger") as a result of which PacifiCorp became a direct subsidiary of NAGP. At that time, PacifiCorp was the direct parent of Holdings, and Holdings was the direct parent of PPM and PKE. PPM and PKE were later transferred to PacifiCorp. In December 2000, PHI was created as another direct subsidiary of NAGP.

To facilitate an increased focus on its regulated energy businesses in the western United States, the Company has separated its non-utility operations from its regulated utility operations through corporate restructuring.

In March 2001, PacifiCorp transferred PPM and PKE to PHI. Accordingly, the results of operations and assets of PPM and PKE are not included with those of PacifiCorp commencing March 31, 2001.

On December 31, 2001, NAGP contributed all of the common stock of PacifiCorp to PHI. On February 4, 2002, PacifiCorp transferred all of the capital stock of Holdings to PHI. Accordingly, the results of operations and assets of Holdings are not included with those of PacifiCorp commencing February 4, 2002.

As a result of this corporate restructuring, PHI currently holds all of the outstanding capital stock of each of PPM, PKE and Holdings, and all of the common stock of PacifiCorp. See the Corporate Organization diagram above.

The Company's fiscal year end is March 31. The years ended March 31, 2002, 2001 and 2000 and quarterly periods within those years are referred to herein as 2002, 2001 and 2000, respectively. References to future years are to years ending March 31.

From time to time, the Company may make or issue forward-looking statements that involve a number of risks and uncertainties under the safe harbor provisions of the Private Securities Litigation Reform Act of 1995 as described in Forward Looking Statements under ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS. Any forward-looking statements made or issued by the Company should be considered in light of these factors.

The 8 1/4% Cumulative Quarterly Income Preferred Securities (Series A Preferred Securities) of PacifiCorp Capital I, and the 7.70% Trust Preferred Securities (Series B Preferred Securities) of PacifiCorp Capital II, each a wholly-owned subsidiary trust of the Company, are traded on the New York Stock Exchange. All outstanding shares of the common stock of PacifiCorp are

indirectly owned by ScottishPower, whose American Depository Shares ("ADS") are traded on the New York Stock Exchange.

DOMESTIC ELECTRIC OPERATIONS

The Company conducts its domestic retail electric utility operations as Pacific Power and Utah Power, and engages in wholesale electric transactions under the name PacifiCorp. Pacific Power and Utah Power provide electric service within their respective service territories in the states of Utah, Oregon, Wyoming, Washington, Idaho and California.

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, however, the Company experienced electricity prices that were at levels consistent with those historically allowed in cost-of-service rates charged to customers. The decline in market prices for electricity was due to low summer demand, conservation measures, the introduction of a price cap mechanism by the FERC that was 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. The Company received limited benefit from market 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 sought 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 to partially fund power purchases required for peak demand periods. 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.

The Company has outstanding commitments to purchase power to fulfill its regulatory obligations and to avoid being supply constrained. Depending on load requirements, the Company may have power in excess of its own requirements, primarily in the shoulder hour periods. The actual impact of these purchases on the Company will depend on: (i) market prices for electricity at the time the purchases occur, (ii) the amount for which excess power can be sold, (iii) load requirements at those times, and (iv) the regulatory treatment of such costs.

In an effort to mitigate the 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 defer for each state some or all of the net

power costs that vary from costs included in determining retail rates during the period from November 2000 through October 2001. During 2002, the Company deferred $167.9 million, plus carrying costs of $23.9 million, under these orders. At March 31, 2002, the Company had a balance of $305.4 million of deferred net power costs. The Company has received orders in Utah, Oregon and Idaho to allow recovery of deferred net power costs representing $259.9 million of the amount deferred as of March 31, 2002. The recovery of deferred net power costs relating to Wyoming is being considered in a general rate case filed on May 7, 2002. Management believes that the Company is entitled to full recovery of these deferred costs. However, recovery is subject to a number of factors, including intervention by third parties and the outcome of regulatory hearings. Therefore, full recovery cannot be assured. See REGULATION - Deferred Net Power Costs below for more information on the status of these regulatory proceedings.

The Company's operations are exposed to risks, including legislative and governmental regulations; volatility in the price and supply of purchased power, fuel and natural gas; uncertain recovery of purchased power costs and purchased natural gas costs; weather conditions; economic conditions; availability of generation facilities; competition; technology; and availability of funding. In addition, the energy business exposes the Company to the financial, liquidity, credit, volumetric and commodity price risks associated with wholesale sales and purchases. See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - BUSINESS RISK for further discussion.

SERVICE TERRITORY

The Company serves approximately 1.5 million retail customers in service territories aggregating about 136,000 square miles in portions of six western states: Utah, Oregon, Wyoming, Washington, Idaho, and California. The service territory's diverse regional economy range from rural, agricultural and mining areas to urbanized manufacturing and government service centers. No one segment of the economy dominates the service territory, which helps mitigate exposure to economic swings. In the eastern portion of the service territory, Wyoming and eastern Utah, the main industrial activities are mining and extracting coal, oil, natural gas, uranium, and oil shale. In the western portion of the service territory, mainly consisting of Oregon and southeastern Washington, the economy generally revolves around agriculture and manufacturing, with pulp and paper, lumber and wood products, food processing, high technology, and primary metals being the largest industrial sectors.

In October 2001, the Company and Nor-Cal Electric Authority ("Nor-Cal") reached an agreement in principle for the sale of the Company's California electric service territory. The parties have been working to complete the sale of these properties since 1999. In December 2000, the CPUC turned down a previous agreement between these parties. If a new definitive agreement is reached, it will be subject to approval by the CPUC, which is expected to take between six months and one year.

The geographic distribution of the Company's retail electric operating revenues for the year ended March 31, 2002 was as follows: Utah, 39.1%; Oregon, 32.5%; Wyoming, 12.6%; Washington, 7.9%; Idaho, 5.6%; and California, 2.3%.

CUSTOMERS

Electric utility revenues and energy sales, by class of customer, for the years ended March 31, 2002, 2001 and 2000, were as follows:

	2002		2001		2000
Operating revenue (Millions of dollars): Residential Commercial Industrial Government, municipal and other Total retail sales Wholesale sales Total energy sales Other revenues Total operating revenues	$ 901.7 747.7 705.1 34.5 2,389.0 1,684.7 4,073.7 172.9 $4,246.6	22.1% 18.4 17.3 0.8 58.6 41.4 100.0%	$ 852.1 710.5 730.1 32.5 2,325.2 2,078.1 4,403.3 131.9 $4,535.2	19.4% 16.1 16.6 0.7 52.8 47.2 100.0%	$ 798.7 667.2 694.5 30.4 2,190.8 1,029.1 3,219.9 72.3 $3,292.2	24.8% 20.7 21.6 0.9 68.0 32.0 100.0%
Megawatt-hours sold (Thousands of MWh): Residential Commercial Industrial Government, municipal and other Total retail sales Wholesale sales Total MWh sold	13,395 13,810 19,611 711 47,527 24,438 71,965	18.6% 19.2 27.2 1.0 66.0 34.0 100.0%	13,455 13,634 20,659 705 48,453 27,502 75,955	17.7% 18.0 27.2 0.9 63.8 36.2 100.0%	13,028 12,827 20,488 663 47,006 34,327 81,333	16.0% 15.8 25.2 0.8 57.8 42.2 100.0%

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

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.

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

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.

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.

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.

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.

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.

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

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.

Oregon - On June 26, 2001, the Company received approval from the OPUC for an overall price increase of 1.0%, or $7.6 million, through an annual adjustment as part of the Alternative Form of Regulation ("AFOR") process previously authorized in Oregon. The new rates took effect July 1, 2001 and will run until the Company recovers all under-earnings relating to the AFOR. The Company received approximately $5.7 million in additional revenues in 2002 relating to this increase, which is expected to terminate in June 2002.

On November 1, 2000, the Company filed the unbundling generation, transmission and distribution cost information required under SB 1149 rules. See Deregulation below for further information on SB 1149. On September 7, 2001, the OPUC granted a rate increase in the amount of $64.4 million, effective September 10, 2001. This increase added approximately $37.7 million of revenues in 2002.

On January 17, 2002, the Company requested approval to begin recovering in rates the amortization of approximately $12.9 million of SB 1149 implementation costs, which were deferred between April and December 2001. At its public meeting on March 5, 2002, the OPUC granted this request effective March 6, 2002. This approval increases annual revenues by approximately $2.6 million, or 0.3%, overall. The OPUC had already ordered recovery of the approximately $5.4 million in SB 1149 costs incurred prior to March 31, 2001. In both cases, the deferred costs will be recovered over a five-year period. The Company is now recovering approximately $3.7 million annually of the SB 1149 costs, including $0.5 million in 2002.

In Oregon, the final order in the rate case that concluded in September 2001 required the Company to file the results of a new hourly net power cost model to replace the net power cost model currently used in setting rates. The Company filed this material in a power cost rate case on December 31, 2001 and requested a $34.3 million annual rate increase. The Company also filed for a permanent power cost adjustment mechanism. The Company filed a stipulation with all parties on March 29, 2002. The stipulation would result in an increase of $18.7 million for power cost recovery, in effect for one year. The Company would also agree to withdraw its request for a permanent power cost adjustment mechanism. The Company may renew this request after January 2003. The stipulation also includes the following major components: (i) a rate 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 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.

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

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.

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,

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.

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.

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.

Millions of Dollars	Actual	Estimated
Millions of Dollars	2002	2003	2004	2005
Transmission Distribution Production Other Total	$ 35.9 207.9 168.3 82.4 $494.5	$ 61.1 187.4 190.9 113.2 $552.6	$ 30.6 154.6 130.9 74.6 $390.7	$ 25.7 159.2 136.1 68.6 $ 389.6

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

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.

EMPLOYEES

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.

ITEM 2. PROPERTIES

The Company owns, or has an interest in, 53 hydroelectric generating plants, with an aggregate nameplate rating of 1,068 MW and plant net capability of 1,119 MW. It also owns or has interests in 17 thermal-electric generating plants with an aggregate nameplate rating of 7,169 MW and plant net capability of 6,663 MW. The Company also jointly owns one wind power generating plant with an aggregate nameplate rating and plant net capability of 33 MW. The following table summarizes the Company's existing generating facilities:

	Location	Energy Source	Installation Dates	Nameplate Rating (MW)	Plant Net Capability (MW)
HYDROELECTRIC PLANTS (a) Swift (b) Merwin Yale Five North Umpqua Plants John C. Boyle Copco Nos. 1 and 2 Plants Clearwater Nos. 1 and 2 Plants Grace Prospect No. 2 Cutler Oneida Iron Gate Soda Fish Creek 33 Minor Hydroelectric Plants	Cougar, WA Ariel, WA Amboy, WA Toketee Falls, OR Keno, OR Hornbrook, CA Toketee Falls, OR Grace, ID Prospect, OR Collingston, UT Preston, ID Hornbrook, CA Soda Springs, ID Toketee Falls, OR Various	Lewis River Lewis River Lewis River N. Umpqua River Klamath River Klamath River Clearwater River Bear River Rogue River Bear River Bear River Klamath River Bear River Fish Creek Various	1958 1932-1958 1953 1949-1956 1958 1918-1925 1953 1914-1923 1928 1927 1915-1920 1962 1924 1952 1896-1990	240.0 135.0 134.0 133.5 80.0 47.0 41.0 33.0 32.0 30.0 30.0 18.0 14.0 11.0 89.3*	263.6 144.0 134.0 137.5 84.0 54.5 41.0 33.0 36.0 29.1 28.0 19.5 14.0 12.0 89.1*
Subtotal (53 Hydroelectric Plants)				1,067.8	1,119.3
THERMAL ELECTRIC PLANTS Jim Bridger Huntington Dave Johnston Naughton Hunter 1 and 2 Hunter 3 Cholla Unit 4 Wyodak Carbon Craig 1 and 2 Colstrip 3 and 4 Hayden 1 and 2 Blundell Gadsby Little Mountain Hermiston James River	Rock Springs, WY Huntington, UT Glenrock, WY Kemmerer, WY Castle Dale, UT Castle Dale, UT Joseph City, AZ Gillette, WY Castle Gate, UT Craig, CO Colstrip, MT Hayden, CO Milford, UT Salt Lake City, UT Ogden, UT Hermiston, OR Camas, WA	Coal-Fired Coal-Fired Coal-Fired Coal-Fired Coal-Fired Coal-Fired Coal-Fired Coal-Fired Coal-Fired Coal-Fired Coal-Fired Coal-Fired Geothermal Gas-Fired Gas-Fired Gas-Fired Black Liquor	1974-1979 1974-1977 1959-1972 1963-1971 1978-1980 1983 1981 1978 1954-1957 1979-1980 1984-1986 1965-1976 1984 1951-1955 1971 1996 1996	1,541.1* 996.0 816.8 707.2 727.9* 495.6 414.0* 289.7* 188.6 172.1* 155.6* 81.3* 26.1 251.6 16.0 237.0* 52.2	1,413.4* 895.0 762.0 700.0 662.5* 460.0 380.0* 268.0* 175.0 165.0* 144.0* 78.0* 23.0 235.0 14.0 236.0* 52.0
Subtotal (17 Thermal Electric Plants)				7,168.8	6,662.9
OTHER PLANTS Foote Creek Subtotal (1 Other Plant)	Arlington, WY	Wind Turbines	1998	32.6* 32.6	32.6* 32.6
Total Hydro, Thermal and Other Generating Facilities (71)				8,269.2	7,814.8

----------
*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

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:

Location	Plant Served	Recoverable Tons (in Millions)
Craig, Colorado Emery County, Utah Rock Springs, Wyoming	Craig Huntington and Hunter Jim Bridger	50(a) 68(b) 100(c)

____________

(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%.

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

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

Most of the Company's coal reserves are held pursuant to leases from the federal government through the Bureau of Land Management and from certain states and private parties. The leases generally have multi-year terms that may be renewed or extended and require payment of rentals and royalties. In addition, federal and state regulations require that comprehensive environmental protection and reclamation standards be met during the course of mining operations and upon completion of mining activities. In 2002, the Company expended $13.0 million in reclamation costs and accrued $0.5 million of estimated final mining reclamation costs. Final mine reclamation funds have been established for the Bridger Mine by the Company and Idaho Power. At March 31, 2002, these reclamation funds totaled $80.4 million, of which the Company's portion is $53.6 million, and the Company had an accrued reclamation liability for all mine reclamation of $145.6 million.

ITEM 3.  LEGAL PROCEEDINGS

The Company is a party from time to time in various legal claims, actions and complaints. Although it is impossible to predict with certainty whether or not the Company will ultimately be successful in its legal proceedings or, if not, what the impact might be, management believes that disposition of these matters will not have a material adverse effect on the Company's consolidated financial results.

ITEM 4.  SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

No information is required to be reported pursuant to this item.

PART II

ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER
MATTERS

PacifiCorp is an indirect subsidiary of ScottishPower, which owns all 297,324,604 shares of PacifiCorp's outstanding common stock. Therefore, there is no public market for PacifiCorp's common stock. Dividend information required by this item is included in QUARTERLY FINANCIAL DATA under ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.

The Company is restricted from paying dividends or making other distributions to ScottishPower without prior OPUC approval to the extent such payment or distribution would reduce the Company's common stock equity below a specified percentage of its total capitalization. The percentage of total capitalization increases over time from 35.0% after December 31, 1999 to 40.0% after

December 31, 2004. In addition, the Company must give the OPUC 30 days prior notice of any special cash dividend or any transfer involving more than five percent of PacifiCorp's retained earnings in a six-month period. The Company is also subject to maximum debt to total capitalization levels under various debt agreements.

Under the Public Utility Holding Company Act of 1935, the Company may pay dividends out of capital or unearned surplus only with SEC approval. Dividends from earned surplus are permitted without approval. The Company has received approval to pay dividends out of unearned surplus of the lesser of $900.0 million or the proceeds received from sales of non-utility assets. At March 31, 2002, $300.0 million was available for dividends out of unearned surplus.

ITEM 6.  SELECTED FINANCIAL DATA

The information required by this item is included in SELECTED FINANCIAL INFORMATION under ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.

ITEM 7.  MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
         RESULTS OF OPERATIONS

OVERVIEW

Unless otherwise stated, references below to periods in 2002, 2001 and 2000 are to periods in the years ended March 31, 2002, 2001 and 2000, respectively.

To facilitate an increased focus on its regulated energy businesses in the western United States, the Company has separated its non-utility operations from its regulated utility operations through corporate restructuring. The FERC and the state utility commissions approved the Company's applications to implement an internal corporate restructuring and, on December 31, 2001, all of the PacifiCorp common stock held by NAGP was transferred to PHI. PacifiCorp transferred all of the capital stock of Holdings to PHI in February 2002. Holdings includes the wholly owned subsidiary, PFS, a financial services business. The transfer was done to better separate the Company's regulated utility business from its non-utility operations.

As a result of this transfer, the operations of Holdings are included in the Company's Statements of Consolidated Income and Statements of Consolidated Cash Flows for the years ended March 31, 2001 and 2000, but are included for only the first ten months of the year ended March 31, 2002. Holdings' balance sheet is included in the Consolidated Balance Sheet as of March 31, 2001, but not at March 31, 2002.

In March 2001, the Company transferred its interest in PPM and PKE, two non-utility energy companies, to PHI. As a result, the operations of the transferred companies are included in the Company's Statements of Consolidated Income and Statements of Consolidated Cash Flows for the years ended March 31, 2001 and 2000, but are not included for the year ended March 31, 2002. PPM and PKE balance sheets are not included in the Consolidated Balance Sheets as of March 31, 2001 and 2002.

The Company completed the sales of its ownership of Powercor on September 6, 2000 and its 19.9% interest in Hazelwood on November 17, 2000. Powercor, an indirectly owned subsidiary of the Company, and Hazelwood represented the entire Australian Electric Operations segment of the Company. Australian Electric Operations' financial results for the period from January 1, 2000 to the respective dates of sale are included in the Company's financial results for the year ended March 31, 2001. Australian Electric Operations' financial results for the calendar year ended December 31, 1999 are included in the Company's financial results for the year ended March 31, 2000. Therefore, results for 2001 are not directly comparable to 2000 as the sale of the Australian Electric Operations was substantially completed on September 6, 2000. Australian Electric Operations' balance sheet is not included in the Consolidated Balance Sheets as of March 31, 2001 and 2002.

FORWARD-LOOKING STATEMENTS

The information in the tables and text in this document includes certain forward-looking statements that involve a number of risks and uncertainties that may influence the financial performance and earnings of the Company. When used in this MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS, the words "estimates," "expects," "anticipates," "forecasts," "plans," "intends" and variations of such words and similar expressions are intended to identify forward-looking statements that involve risks and uncertainties. There can be no assurance the results predicted will be realized. Actual results may vary from those represented by the forecasts, and those variations may be material. The following are among the factors that could cause actual results to differ materially from the forward-looking statements:

  .  utility commission practices;
  .  political developments;
  .  regional, national and international economic conditions;
  .  weather and behavioral variations affecting customer electricity usage;
  .  competition and supply in bulk power and natural gas markets;
  .  hydroelectric and natural gas production levels;
  .  changes in coal quality and prices;
  .  unscheduled generation outages;
  .  disruption or constraints to transmission facilities;
  .  outcome of hydro-facility relicensing;
  .  energy purchase and sales activities;
  .  changes in environmental, regulatory or tax legislation, including
     industry restructure and deregulation initiatives;
  .  nonperformance by counterparties;
  .  technological developments in the electricity industry;
  .  outcome of rate cases submitted for regulatory approval;
  .  workforce factors;
  .  new accounting pronouncements;
  .  terrorist activity;
  .  credit rating changes; and
  .  the cost and availability of debt and equity capital.

Any forward-looking statements issued by the Company should be considered in light of these factors. The Company assumes no obligation to update or revise any forward-looking statements to reflect actual results, changes in

assumptions or changes in other factors affecting such forward-looking statements or if the Company later becomes aware that these assumptions are not likely to be achieved.

CRITICAL ACCOUNTING POLICIES

The preparation of consolidated financial statements in conformity with Generally Accepted Accounting Principles requires management to make estimates and assumptions that affect results of operations and the reported amounts of assets and liabilities in the consolidated financial statements. Changes in these estimates and assumptions could have a material impact on the consolidated financial statements. Those policies that management considers critical are described below. Other significant accounting policies and recently issued accounting standards are discussed in Note 1 of Notes to the Consolidated Financial Statements under ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.

Regulation

The Company prepares its consolidated financial statements in accordance with SFAS No. 71. A regulated company must satisfy the following conditions in order to apply the accounting policies and practices of SFAS No. 71: an independent regulator must set rates; the regulator must set the rates to cover specific costs of delivering service; and the service territory must lack competitive pressures to reduce rates below the rates set by the regulator. SFAS No. 71 requires the Company to reflect the impact of regulatory decisions in its consolidated financial statements and requires that certain costs be deferred on the balance sheet until matching revenues can be recognized. Similarly, certain items may be deferred as regulatory liabilities and amortized to the income statement as rates to customers are reduced.

If the Company should determine in the future that it no longer meets the criteria for continued application of SFAS No. 71, the Company could be required to write-off its regulatory assets and liabilities unless regulators specify some other means of recovery or refund. The Company intends to seek recovery of all of its prudent costs, including stranded costs, in the event of deregulation. However, due to the current lack of definitive legislation, the Company cannot predict whether it will be successful.

At March 31, 2002, the Company's SFAS No. 71 regulatory assets and liabilities for all states totaled $1,626.7 million and $219.7 million, respectively. Because of potential regulatory and/or legislative actions 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 SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets" ("SFAS No. 144"), which requires the recognition of impairment on long-lived assets when book values exceed expected future cash flows. Integral parts of future cash flow estimates include estimated future prices to be received, the expected future cash cost of operations, sales and load growth forecasts and the nature of any legislative or regulatory cost recovery mechanisms.

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

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

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.

RESULTS OF OPERATIONS

Earnings (Loss) Overview of the Company

	Years Ended March 31,
(Millions of dollars)	2002	2001	2000
Earnings (loss) contribution on common stock (a) Domestic Electric Operations Australian Electric Operations Other Operations (b) Continuing operations Discontinued operations (c) Cumulative effect of accounting change (d) Total	$ 232.8 27.4 20.5 280.7 146.7 (112.8) $ 314.6	$ 110.1 (187.2) (29.0) (106.1) - - $(106.1)	$ 10.9 39.0 13.8 63.7 1.1 - $ 64.8

(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").

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.

REVENUES

Revenues
	Years Ended March 31,
(Millions of dollars)	2002	2001	2000
Domestic Electric Operations Wholesale Residential Commercial Industrial Other retail revenues Other revenues Total	$1,684.7 901.7 747.7 705.1 34.5 172.9 4,246.6	$2,078.1 852.1 710.5 730.1 32.5 131.9 4,535.2	$1,029.1 798.7 667.2 694.5 30.4 72.3 3,292.2
Australian Electric Operations Residential Commercial Industrial Other Total	- - - - -	144.6 136.0 78.2 40.5 399.3	214.6 198.4 136.0 68.6 617.6
Other Operations	12.6	122.2	77.1
Total revenues	$4,259.2	$5,056.7	$3,986.9

Energy Sales
	Years Ended March 31,
(Thousands of MWh)	2002	2001	2000
Domestic Electric Operations Wholesale Residential Commercial Industrial Other	24,438 13,395 13,810 19,611 711 71,965	27,502 13,455 13,634 20,659 705 75,955	34,327 13,028 12,827 20,488 663 81,333

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

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.

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

	Years Ended March 31,
(Millions of dollars)	2002	2001	2000
Domestic Electric Operations Purchased power Fuel Other operations and maintenance Depreciation and amortization Administrative and general Taxes, other than income taxes Unrealized gain on SFAS No. 133 derivative instruments Total Domestic Electric Operations	$2,038.8 490.9 560.6 401.3 245.6 90.7 (182.8) 3,645.1	$2,478.4 491.0 534.8 389.0 121.0 97.5 - 4,111.7	$ 957.9 512.3 554.2 379.9 200.8 99.3 - 2,704.4
Australian Electric Operations Purchased power Other operations and maintenance Depreciation and amortization Administrative and general Taxes, other than income taxes Total Australian Electric Operations	- - - - - -	157.6 65.9 36.4 54.1 0.8 314.8	260.0 104.3 57.9 68.8 1.5 492.5
Other Operations	9.0	135.8	84.9
Total Operating expenses	$3,654.1	$4,562.3	$3,281.8

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

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.

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

	Years Ended March 31,
(Millions of dollars)	2002	2001	2000
Interest expense Interest income Interest capitalized Losses from equity investments Merger costs Minority interest and other (a) Total	$227.7 (23.6) (6.9) - - (1.8) $195.4	$290.4 (31.6) (12.9) 1.4 9.3 (8.0) $248.6	$341.4 (17.1) (20.2) 2.6 195.5 (13.7) $488.5

(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.

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.

LIQUIDITY AND CAPITAL RESOURCES

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

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.

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

(Millions of dollars, except percentages)	March 31,
	2002		2001
Long-term debt Common equity Short-term debt and long-term debt currently maturing Preferred stock Preferred Securities of Trusts Total Capitalization	$3,553.8 2,891.9 321.0 115.5 341.5 $7,223.7	49.2% 40.0 4.5 1.6 4.7 100.0%	$2,906.9 3,414.4 291.7 216.5 341.2 $7,170.7	40.5% 47.6 4.1 3.0 4.8 100.0%

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%.

VARIABLE RATE LIABILITIES

(Millions of dollars)	March 31,
(Millions of dollars)	2002	2001
Domestic Electric Operations Percentage of Total Capitalization	$ 831.0 11.5%	$ 895.0 12.5%

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.

CONTRACTUAL OBLIGATIONS AND COMMERCIAL COMMITMENTS

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

Contractual Obligations (Millions of dollars)	Payments Due by Period
Contractual Obligations (Millions of dollars)	1 year	2-3 years	4-5 years	There- After	Total
Long-term debt, principal only	$ 144.6	$ 376.2	$ 523.7	$2,626.2	$3,670.7
Capital lease minimum payments	3.2	6.8	7.0	55.9	72.9
Operating leases	16.6	37.2	7.9	8.8	70.5
Power contract commitments	739.9	975.4	926.9	2,893.3	5,535.5
Total contractual cash obligations	$ 904.3	$1,395.6	$1,465.5	$5,584.2	$9,349.6

Other Commercial Commitments (Millions of dollars)	Amount of Commitment Expiration Per Period
Other Commercial Commitments (Millions of dollars)	1 year	2-3 years	4-5 years	There- After	Total Amounts Committed
Lines of credit	$ 880.0	$ -	$ -	$ -	$ 880.0
Standby letters of credit	54.8	170.6	71.5	-	296.9
Standby bond purchase agreements	96.5	124.4	-	-	220.9
Other commercial commitments	2.3	-	-	-	2.3
Total commercial commitments	$1,033.6	$ 295.0	$ 71.5	$ -	$1,400.1

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.

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.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

BUSINESS RISK

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

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

Market Risk
Market risk is, in general, the risk of both fluctuations in the market price of electricity and fuel, as well as volumetric risk caused by changes in weather, the economy, unanticipated outages and customer behavior. Market price is influenced primarily by factors relating to supply and demand. Those factors include the adequacy of generating capacity, scheduled and unscheduled outages of generating facilities, hydroelectric availability, prices and availability of fuel sources for generation, disruptions or constraints to transmission facilities, weather conditions, economic growth, transmission capacity and other factors. Early in 2001, the Company began experiencing the adverse effect of higher market prices due to inadequate generating capacity in the WSCC, generating facility outages in the WSCC, including the unscheduled outage of the Company's Hunter unit, lower hydro availability, high natural gas prices and increases in demand throughout the WSCC due in large part to economic growth.

During 2000 and 2001, significant price and volumetric volatility, driven in part by the change in availability of resources and demand for energy throughout the WSCC, as well as regulatory influences, materially impacted the cost of meeting the Company's system load requirements. While the Company plans for resources to meet its current and expected retail and wholesale load obligations, resource availability, price volatility and load volatility may materially impact the power costs to the Company and profits from excess power sales in the future. Prices paid by the Company to provide certain load balancing resources to supply its load may exceed the amounts it receives through retail rates and wholesale prices. Approval of deferred accounting treatment mitigates a portion of the price risk, assuming that recovery mechanisms are implemented as anticipated. The Company has recorded approved deferred amounts as regulatory assets. If recovery mechanisms are not implemented as anticipated, the Company would write-off these regulatory assets.

Regulatory/Political Risk
The Company is subject to the jurisdiction of federal and state regulatory authorities. These regulators determine the rates the Company may charge its retail customers. The rates authorized by the regulators may be less than the costs to the Company to provide electrical service to its customers in a given period.

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

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

Credit Risk
Credit risk relates to the risk of loss that might occur as a result of nonperformance by counterparties of their contractual obligations to make or take delivery of electricity, natural gas or other commodities and make financial settlements thereon. Credit risk may be concentrated to the extent that one or more groups of counterparties have similar economic, industry or other characteristics that would cause their ability to meet contractual obligations to be similarly affected by changes in market or other conditions. In addition, credit risk includes not only the risk that a counterparty may default due to circumstances relating directly to it, but also the risk that a counterparty may default due to circumstances which relate to other market participants which have a direct or indirect relationship with such counterparty. The Company seeks to mitigate credit risk (and concentrations thereof) by applying specific eligibility criteria to prospective counterparties. However, despite mitigation efforts, defaults by counterparties occur from time to time. To date, no such default has had a material adverse effect on the Company. The Company continues to actively monitor the credit worthiness of those counterparties with whom it executes wholesale energy and gas purchase and sales transactions within the WSCC, including those in California, and uses a variety of risk mitigation techniques to limit its exposure where it believes appropriate. The Company, like all participants in the regional market, has exposure to other participants who may have credit exposure to the utilities in California. To mitigate exposure to the financial risks of these counterparties, the Company has entered into netting, margining and guarantee arrangements. The Company calculates reserves for all of its credit exposure by grouping counterparties, based upon managerial judgment and rating, and then calculating a reserve based upon a ratings agency historical default rate.

Interest Rate Risk
The Company manages its debt requirements with a balance of short-term and long-term debt. In November 2001, the Company issued $800.0 million of long-term, fixed rate First Mortgage Bonds. The proceeds of this issuance were used, in part, to reduce short-term debt outstanding, which had grown as a result of increasing cash requirements resulting from the unusually high purchased power prices, the impact of the Hunter No. 1 plant outage on purchased power volumes, and maturities of long-term debt and mandatorily redeemable preferred stock. In November 2001, the Company's credit ratings were lowered by two credit rating agencies, citing the impact of high purchased power prices, the Hunter No. 1 outage, and the uncertainty and expected delay between incurring and recovering the deferred net power costs from customers. Any adverse change to the Company's credit rating could negatively impact the Company's ability to borrow and the interest rates that the Company is charged. The activity in the western electricity market has had a negative impact on the willingness of the financial markets to provide financing on conditions and at rates that have historically been available to the Company.

Insurance Risks

The Company faced a drastically changed insurance market in 2002 as it sought to renew primary property and liability insurance policies for the first time since the summer of 2000. The hardening of the insurance market that began in the spring of 2001 was made worse by the events of September 11th. Significant reductions in market capacity and an increase in the incidents of losses worldwide contributed to unprecedented insurance program costs, in some cases two to four times prior levels.

Those increased costs came in the form of increased premiums for coverage as well as substantial increases in self-insured retentions and exposures. Restrictions on the type of coverage available, the scope of the coverage and the limits of coverage were common. As a result of the changes in the market, the Company reevaluated each exposure to ensure that all critical coverage that could be obtained was pursued and critically evaluated. This resulted in the purchase of business interruption insurance in addition to some of the more traditional property and liability coverage elements. The loss of coverage on the transmission and distribution system assets was anticipated, as was the loss of terrorism coverage.

RISK MANAGEMENT

Risk is an inherent part of the Company's business and activities. The risk management process established by the Company is designed to identify, assess, monitor and manage each of the various types of risk involved in its business and activities. Central to its risk management process, the Company has established a risk management committee with overall responsibility for establishing and reviewing the Company's policies and procedures for controlling and managing its risks. The senior risk management committee relies on the Company's treasury and risk management departments and its operating units to carry out its risk management directives and execute various hedging and energy purchase and sales strategies.

The risk management process established by the Company is designed to measure quantitative market risk exposure and identify qualitative market risk exposure in its businesses. To assist in managing the volatility relating to these exposures, the Company enters into various derivative transactions consistent with the Company's risk management policy. That policy governs the Company's use of derivative instruments and its energy purchase and sales practices and describes the Company's credit policy and management information systems required to effectively monitor such derivative use. The Company's risk management policy provides for the use of only those instruments that have a close correlation with its portfolio of assets, liabilities or anticipated transactions. The risk management policy includes as its objective that interest rate and other derivative instruments will be used for hedging and not for speculation. The risk management policy also governs the energy purchase and sales activities and is generally designed for hedging the Company's existing energy and asset exposures.

The Company took further steps in 2002 to manage commodity price volatility and reduce exposure. These steps included adding to the generation portfolio and entering into transactions that help to shape the Company's system resource portfolio, including physical hedging products and financial temperature-related instruments that reduce resource and price risk on hot summer days. In addition, "hydroelectric" hedges were put in place for the next five years to limit volume and price risks associated with Pacific Northwest hydroelectric generation availability.

RISK MEASUREMENT

Value at Risk Analysis
The tests discussed below for exposure to interest rate fluctuations are based on a Value at Risk ("VAR") approach using a one-year horizon and a 95.0% confidence level and assuming a one-day holding period in normal market conditions. The VAR model is a risk analysis tool that attempts to measure the potential losses in fair value, earnings or cash flow from changes in market conditions and does not purport to represent actual losses in fair value that may be incurred by the Company. The VAR model also calculates the potential gain in fair market value or improvement in earnings and cash flow associated with favorable market price movements.

Sensitivity Analysis
The Company measures the market risk relating to its commodity price exposure positions by utilizing a VAR approach using a two-year horizon and a 99% confidence level and assuming a five-day holding period. The VAR model is a risk analysis tool that attempts to measure the potential losses in fair value, earnings or cash flow from changes in market conditions and does not purport to represent actual losses in fair value that may be incurred by the Company. The VAR model also calculates the potential gain in fair market value or improvement in earnings and cash flow associated with favorable market price movements.

Exposure Analysis
Interest Rate Exposure - The Company may use interest rate swaps, forwards, futures and collars to adjust the characteristics of its liability portfolio. This strategy is consistent with the Company's capital structure policy, which provides guidance on overall debt to equity and variable rate debt as a percent of capitalization levels. At March 31, 2002, the Company had none of these financial derivatives in effect relating to its interest rate exposure.

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

The table below shows the potential loss in fair market value ("FMV") of the Company's interest rate sensitive positions, for continuing operations, as of March 31, 2001 and 2002, as well as the Company's quarterly high and low potential losses.

(Millions of dollars)	Confidence Interval	Time Horizon	3/31/01	2002 Quarterly High	2002 Quarterly Low	3/31/02
Interest Rate Sensitive Portfolio - FMV	95%	1 day	$(11.6)	$(28.8)	$(11.6)	$(28.8)

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.

The following table shows the changes in the fair value of energy related contracts from April 1, 2001 to March 31, 2002 and quantifies the reasons for the changes.

(Millions of dollars)

Fair value of contracts outstanding at the beginning of the period	$ 101.6
Contracts realized or otherwise settled during the period	60.2
Changes in fair values attributable to changes in contract terms resulting in changes in valuation assumptions	171.0
Other changes in fair values	(838.7)
Fair value of contracts outstanding at the end of the period	$(505.9)

(Millions of dollars)	Fair Value of Contracts at Period-End
Source of fair value	Maturity less than 1 year	Maturity 2-3 years	Maturity 4-5 years	Maturity in excess of 5 years	Total fair value
Prices actively quoted	$ (37.5)	$ -	$ -	$ -	$ (37.5)
Prices provided by other external sources	-	-	-	-	-
Prices based on models and other valuation methods	(62.9) $(100.4)	(101.2) $(101.2)	(91.4) $(91.4)	(212.9) $(212.9)	(468.4) $(505.9)

Short-term contracts are valued based upon quoted market prices. Long-term contracts are valued by separating each contract into its component physical and financial swap and option legs. Swap legs are valued against the appropriate market curve. The option leg is valued using a modified Black-Scholes model approach. Each leg is modeled and valued separately using the appropriate forward market price curve. The forward market price curve is derived using daily market quotes from independent energy brokers. For contracts extending past 2006, the forward prices are derived using a fundamentals model (cost-to-build approach) that is updated as warranted to reflect changes in the market, at least quarterly.

A sensitivity analysis has been prepared to estimate the Company's exposure to market risk relating to commodity price exposure of its portfolio of load, plant and physical and derivative positions for electricity. Based on the Company's commodity price exposure at March 31, 2002, a near-term adverse change in commodity prices of 10.0% would have a negative impact on pretax earnings of $1.5 million in 2003 based on the Company's then-current (at March 31, 2002) commodity position over the 12 month period ending March 31, 2003.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Page

Index To Consolidated Financial Statements:
  Report of Management......................................
  Report of Independent Accountants.........................
  Statements Of Consolidated Income (Loss) For The Years
    Ended March 31, 2002, 2001 And 2000.....................
  Statements Of Consolidated Cash Flows For The Years
    Ended March 31, 2002, 2001 And 2000.....................
  Consolidated Balance Sheets As Of March 31, 2002 And
    2001....................................................
  Statements Of Consolidated Changes In Common
    Shareholder's Equity For The Years Ended March 31, 2002,
    2001 and 2000...........................................
  Notes To The Consolidated Financial Statements............

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52

53

54

56
57

REPORT OF MANAGEMENT

The management of PacifiCorp and its subsidiaries (the "Company") are responsible for preparing the accompanying consolidated financial statements and ensuring their integrity and objectivity. The statements were prepared in accordance with accounting principles generally accepted in the United States of America. The financial statements include amounts that are based on management's best estimates and judgments. Management also prepared the other information in the annual report and is responsible for its accuracy and consistency with the financial statements.

The Company's financial statements were audited by PricewaterhouseCoopers LLP ("PricewaterhouseCoopers"), independent public accountants. Management made available to PricewaterhouseCoopers all the Company's financial records and related data, as well as the minutes of directors' meetings.

Management of the Company established and maintains an internal control structure that provides reasonable assurance as to the integrity and reliability of the financial statements, the protection of assets from unauthorized use or disposition and the prevention and detection of materially fraudulent financial reporting. The Company maintains an internal auditing program that independently assesses the effectiveness of the internal control structure and recommends possible improvements. PricewaterhouseCoopers considered that internal control structure in connection with their audits. Management reviews significant recommendations by the internal auditors and PricewaterhouseCoopers, concerning the Company's internal control structure and ensures appropriate cost-effective actions are taken.

The Company's "Guide to Business Conduct" is distributed to employees throughout the Company to provide a basis for ethical standards and conduct. The guide addresses, among other things, potential conflicts of interests and compliance with laws, including those relating to financial disclosure and the confidentiality of proprietary information.

Judith A. Johansen
President and Chief Executive Officer

Geoffrey Huggins
Vice President and Principal Financial Officer

REPORT OF INDEPENDENT ACCOUNTANTS

To the Board of Directors and Shareholders of
PacifiCorp:

In our opinion, the accompanying consolidated balance sheets and the related statements of consolidated income (loss), changes in common shareholder's equity and cash flows present fairly, in all material respects, the financial position of PacifiCorp and its subsidiaries at March 31, 2002 and 2001, and the results of their operations and their cash flows for each of the three years in the period ended March 31, 2002 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company's management; our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States of America, which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

As discussed in Note 11 to the Consolidated Financial Statements, the Company changed its method of accounting for derivative instruments as of April 1, 2001.

PricewaterhouseCoopers LLP
Portland, Oregon
May 1, 2002

STATEMENTS OF CONSOLIDATED INCOME (LOSS)

(Millions of dollars)	Years Ended March 31,
(Millions of dollars)	2002	2001	2000
Revenues	$4,259.2	$5,056.7	$3,986.9
Operating expenses Purchased power Fuel Other operations and maintenance Depreciation and amortization Administrative and general Taxes, other than income taxes Unrealized gain on SFAS No. 133 - derivative instruments Total Other operating income (Gain) loss on sale of Australian Electric Operations	2,038.8 490.9 562.8 403.0 250.6 90.8 (182.8) 3,654.1 (32.4) (27.4)	2,636.0 491.0 705.2 429.0 200.8 100.3 - 4,562.3 (30.6) 184.2	1,217.8 512.3 726.0 441.3 283.0 101.4 - 3,281.8 - -
Income from operations	664.9	340.8	705.1
Interest expense and other (income) expense Interest expense Interest income Interest capitalized Losses from equity investments Merger costs Minority interest and other Total	227.7 (23.6) (6.9) - - (1.8) 195.4	290.4 (31.6) (12.9) 1.4 9.3 (8.0) 248.6	341.4 (17.1) (20.2) 2.6 195.5 (13.7) 488.5
Income from continuing operations before income taxes and cumulative effect of accounting change Income tax expense	469.5 176.1	92.2 180.4	216.6 134.0
Income (loss) from continuing operations before cumulative effect of accounting change	293.4	(88.2)	82.6
Discontinued operations (less applicable income tax expense: $36.4/2002 and $0.7/2000)	146.7	-	1.1
Income (loss) before cumulative effect of accounting change	440.1	(88.2)	83.7
Cumulative effect of accounting change (less applicable income tax benefit: $69.0/2002)	(112.8)	-	-
Net income (loss)	327.3	(88.2)	83.7
Preferred Dividend Requirement	(12.7)	(17.9)	(18.9)
Earnings (loss) on Common Stock	$ 314.6	$ (106.1)	$ 64.8

The accompanying notes are an integral part of these consolidated financial statements.

52

STATEMENTS OF CONSOLIDATED CASH FLOWS

(Millions of dollars)	Years Ended March 31,
(Millions of dollars)	2002	2001	2000
Cash flows from operating activities Net income (loss) Adjustments to reconcile net income (loss) to net cash provided by continuing operations Gain on disposal of discontinued operations Cumulative effect of accounting change Unrealized gain on SFAS No. 133 Loss (gain) on available for sale securities Depreciation and amortization Deferred income taxes and investment tax credits - net Interest capitalized - equity funds (Gain) loss on sale of subsidiary and assets Utah rate order Regulatory asset establishment - net Deferred net power costs Accrued Merger liabilities Other Accounts receivable and prepayments Inventories Accounts payable and accrued liabilities	$ 327.3 (146.7) 112.8 (182.8) 7.6 403.0 60.9 - (52.6) - (21.0) (189.9) (0.1) 14.5 165.2 7.0 (162.6)	$ (88.2) - - - (3.9) 429.0 (26.4) (4.4) 189.2 - (35.1) (137.5) (5.9) (44.8) (161.8) (9.3) 543.8	$ 83.7 (1.1) - - (3.2) 456.3 136.7 (11.2) (1.0) (40.3) - - 71.0 43.3 (40.9) 3.9 66.3
Net cash provided by continuing operations Net cash used in discontinued operations	342.6 -	644.7 -	763.5 (8.1)
Net cash provided by operating activities	342.6	644.7	755.4
Cash flows from investing activities Construction Investments in and advances to affiliated companies - net Advances to ScottishPower Proceeds from ScottishPower note receivable Proceeds from finance note repayment Proceeds from sales of assets Proceeds from sales of finance assets and principal payments Proceeds from available for sale securities Purchases of available for sale securities Other	(505.3) (130.8) (627.4) 400.0 189.9 83.2 36.0 120.9 (152.0) 17.1	(485.7) (5.3) (396.0) 40.0 - 1,010.0 48.5 119.9 (114.5) 14.9	(574.0) (2.6) - - - 169.3 47.8 125.9 (130.4) 10.3
Net cash (used in) provided by investing activities	(568.4)	231.8	(353.7)
Cash flows from financing activities Changes in short-term debt Proceeds from long-term debt, net Dividends paid Repayments of long-term debt Redemptions of preferred stock Other	(64.0) 791.1 (310.3) (59.0) (100.0) (13.5)	131.5 1,114.0 (347.7) (1,787.0) - (2.1)	(88.1) 1,812.0 (269.5) (2,099.0) (26.1) 7.0
Net cash provided by (used in) financing activities	244.3	(891.3)	(663.7)
Increase (decrease) in cash and cash equivalents	18.5	(14.8)	(262.0)
Cash and cash equivalents at beginning of period	139.4	154.2	416.2
Cash and cash equivalents at end of period	$ 157.9	$ 139.4	$ 154.2

The accompanying notes are an integral part of these consolidated financial statements.

53

CONSOLIDATED BALANCE SHEETS

ASSETS

	March 31,
(Millions of dollars)	2002	2001
Current assets Cash and cash equivalents Accounts receivable less allowance for doubtful accounts: $34.8/2002 and $27.6/2001 Inventories at average cost ScottishPower receivables Accounts and notes receivable - affiliated entities Other Total current assets	$ 157.9 376.1 153.4 0.5 3.5 17.5 708.9	$ 139.4 567.0 160.4 370.4 73.5 46.7 1,357.4
Property, plant and equipment Domestic Electric Operations Production Transmission Distribution Other Construction work in progress Total Domestic Electric Operations Other Operations Accumulated depreciation and amortization Total property, plant and equipment - net	4,861.7 2,250.7 3,773.8 1,848.3 364.4 13,098.9 - (5,129.4) 7,969.5	4,827.5 2,183.6 3,630.3 1,768.8 268.7 12,678.9 33.5 (4,789.5) 7,922.9
Other assets Regulatory assets SFAS No. 133 regulatory asset Finance note receivable Finance assets - net Deferred charges and other Total other assets	1,158.3 468.4 - - 366.2 1,992.9	1,081.8 - 189.9 278.3 303.5 1,853.5
Total assets	$10,671.3	$11,133.8

The accompanying notes are an integral part of these consolidated financial statements.

54

CONSOLIDATED BALANCE SHEETS, continued

LIABILITIES, REDEEMABLE PREFERRED STOCK AND SHAREHOLDER'S EQUITY

	March 31,
(Millions of dollars)	2002	2001
Current liabilities Long-term debt currently maturing Notes payable and commercial paper Accounts payable ScottishPower payables Accounts and notes payable - affiliated entities Taxes payable Interest payable Dividends payable SFAS No. 133 current liability Other Total current liabilities	$ 144.5 176.5 384.5 0.8 1.0 115.9 100.8 2.3 100.4 138.9 1,165.6	$ 51.2 240.5 609.9 13.6 5.1 377.5 84.1 61.9 - 157.4 1,601.2
Deferred credits Income taxes Investment tax credits Regulatory liabilities SFAS No. 133 non-current liability Other Total deferred credits	1,434.8 99.3 219.7 405.5 443.7 2,603.0	1,645.0 107.2 256.0 - 645.4 2,653.6
Long-term debt	3,553.8	2,906.9
Commitments and contingencies (See Note 16)	-	-
Guaranteed preferred beneficial interests in Company's junior subordinated debentures	341.5	341.2
Preferred stock subject to mandatory redemption	74.2	175.0
Redeemable preferred stock	41.3	41.5
Common equity Common shareholder's capital Retained earnings Accumulated other comprehensive income (loss): Unrealized gain on available for sale securities, net of tax of $0.6/2002 and $0.6/2001 Unrealized loss on derivative financial instruments, net of tax of $(14.7) Total common equity	2,742.1 173.1 0.7 (24.0) 2,891.9	3,284.9 128.6 0.9 - 3,414.4
Total liabilities, redeemable preferred stock and shareholder's equity	$10,671.3	$11,133.8

The accompanying notes are an integral part of these consolidated financial statements.

55

STATEMENTS OF CONSOLIDATED CHANGES IN COMMON SHAREHOLDER'S EQUITY

(Millions of dollars, Thousands of shares)

	Common Shareholder's Capital		Retained Earnings	Accumulated Other Comprehensive Income (Loss)	Total Comprehensive Income (Loss) For The Year
	Shares	Amount	Retained Earnings	Accumulated Other Comprehensive Income (Loss)	Total Comprehensive Income (Loss) For The Year
Balance at March 31, 1999	297,331	$3,284.3	$738.8	$(54.7)
Comprehensive income Net income Adjustment to retained earnings for subsidiary's differing fiscal year end Other comprehensive income Unrealized gain on available-for-sale securities, net of tax of $3.0 Foreign currency translation adjustment, net of tax of $14.3 Cash dividends declared Preferred stock Common stock ($0.58 per share) Stock options exercised Forfeitures Balance at March 31, 2000	- - - - - - 62 (68) 297,325	- - - - - - 1.2 (0.6) 3,284.9	83.7 (10.4) - - (17.9) (172.0) - - 622.2	- - 4.4 23.1 - - - - (27.2)	$ 83.7 (10.4) 4.4 23.1 - - - - $100.8
Comprehensive income (loss) Net loss Other comprehensive income (loss) Foreign currency translation adjustment, net of tax of $(31.0) Realization of foreign exchange loss included in net income, net of tax of $55.6 Unrealized loss on available- for-sale securities, net of tax of $(5.9) Cash dividends declared Preferred stock Common stock ($1.31 per share) Balance at March 31, 2001	- - - - - - 297,325	- - - - - - 3,284.9	(88.2) - - - (15.4) (390.0) 128.6	- (48.0) 85.7 (9.6) - - 0.9	$(88.2) (48.0) 85.7 (9.6) - - $(60.1)
Comprehensive income (loss) Net income Other comprehensive income (loss) Unrealized loss on available- for-sale securities, net of tax of $- Cumulative effect of accounting change, net of tax of $377.5 Loss on derivative financial instruments recognized in net income, net of tax of $(70.2) Unrealized loss on derivative financial instruments, net of tax of $(321.8) Cash dividends declared Preferred stock Common stock ($0.81 per share) Transfer of Holdings Balance at March 31, 2002	- - - - - - - - 297,325	- - - - - - - (542.8) $2,742.1	327.3 - - - - (9.8) (240.8) (32.2) $ 173.1	- (0.2) 617.2 (115.1) (526.1) - - - $ (23.3)	$327.3 (0.2) 617.2 (115.1) (526.1) - - - $303.1

The accompanying notes are an integral part of these consolidated financial statements.

56

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1 - Summary Of Significant Accounting Policies

Nature of operations - The Company (which includes PacifiCorp and its subsidiaries) is a United States electricity company operating in six western states. The Company conducts its retail electric utility business as Pacific Power and Utah Power and engages in power production and sales on a wholesale basis.

Basis of presentation - The consolidated financial statements of the Company include its integrated domestic electric utility operations and its wholly owned and majority-owned subsidiaries. Significant intercompany transactions and balances have been eliminated upon consolidation.

The Federal Energy Regulatory Commission ("FERC") and the state utility commissions approved the Company's applications to implement an internal corporate restructuring and on December 31, 2001, all of the PacifiCorp common stock held by NA General Partnership ("NAGP") was transferred to PacifiCorp Holdings, Inc. ("PHI"), a wholly owned subsidiary of NAGP. PacifiCorp transferred all of the capital stock of PacifiCorp Group Holdings Company ("Holdings"), a wholly owned subsidiary of PacifiCorp, to PHI in February 2002. This was a non-cash transaction that resulted in a net reduction in shareholder's equity of $575.0 million. Holdings includes the wholly owned subsidiary, PacifiCorp Financial Services, Inc. ("PFS"), a financial services business.

In March 2001, the Company transferred its interest in PacifiCorp Power Marketing ("PPM") and Pacific Klamath Energy ("PKE") to PHI, as further discussed in Note 14.

The Company completed the sales of its ownership of Powercor Australia Ltd. ("Powercor") on September 6, 2000 and its 19.9% interest in Hazelwood Power Partnership ("Hazelwood") on November 17, 2000, as further discussed in Note 14. Powercor and Hazelwood represented all of the Australian Electric Operations segment of the Company.

On November 29, 1999, the Company and ScottishPower plc ("ScottishPower") completed a merger under which the Company became an indirect subsidiary of ScottishPower (the "Merger"). As a result of the Merger, the Company became part of a public utility holding company group, and as such, the Company's operations are subject to the requirements and restrictions of the Public Utility Holding Company Act of 1935. As a result of regulatory requirements and the existence of debt instruments that are secured by the assets of the Company, the basis of assets and liabilities reported in the Company's financial statements has not been revised to reflect the acquisition of the Company by ScottishPower. The assets, liabilities and shareholder's equity continue to be presented at historical cost.

Change in fiscal year - In connection with the Merger, the Company's year-end changed from December 31 to March 31. The years ended March 31, 2002, 2001 and 2000 and quarterly periods within those years are referred to as 2002, 2001

and 2000, respectively. References to future years are to years ending March 31. Australian Electric Operation's year-end remained December 31 after the Merger. Consequently, the Company's statements of consolidated income and consolidated cash flows as of and for the year ended March 31, 2001 include Australian Electric Operation's financial statements for the period from January 1, 2000 to the respective dates of sale. In accordance with guidelines of the Securities and Exchange Commission (the "SEC"), twelve months of income and expense for Australian Electric Operations were included in the consolidated statement of income for 2000.

Use of estimates - The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements. Actual results could differ from those estimates.

Regulation - Accounting for the domestic electric utility business conforms with accounting principles generally accepted in the United States of America as applied to regulated public utilities and as prescribed by agencies and the commissions of the various locations in which the domestic electric utility business operates. The Company prepares its financial statements as they relate to Domestic Electric Operations in accordance with Statement of Financial Accounting Standards ("SFAS") No. 71, "Accounting for the Effects of Certain Types of Regulation" ("SFAS No. 71") as further discussed in Note 3.

Foreign currency - The financial statements for foreign subsidiaries, which were sold in 2001, were prepared in currencies other than the United States dollar. The income statement amounts were translated at average exchange rates for the year, while the assets and liabilities were translated at year-end exchange rates. Translation adjustments were included in Accumulated other comprehensive income (loss), a separate component of Common equity. All gains and losses resulting from foreign currency transactions are included in the determination of net income.

Cash and cash equivalents - For the purposes of these financial statements, the Company considers all liquid investments with maturities of three months or less, at the time of acquisition, to be cash equivalents.

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. The Company provided $16.0 million, $10.6 million and $22.0 million for doubtful accounts in 2002,

2001 and 2000, respectively. Write-offs of uncollectible accounts were $8.8 million, $10.8 million and $19.0 million in 2002, 2001 and 2000, respectively.

Inventory valuation - Inventories are generally valued at the lower of average cost or market, and consisted of $59.9 million and $67.7 million of fuel, and $93.5 million and $92.7 million of material and supplies, at March 31, 2002 and 2001, respectively.

Property, plant and equipment - Property, plant and equipment are stated at original cost of contracted services, direct labor and materials, interest capitalized during construction and indirect charges for engineering, supervision and similar overhead items. The cost of depreciable domestic electric utility properties retired, including the cost of removal, less salvage, is charged to accumulated depreciation. The costs of planned major maintenance activities are expensed as the costs are incurred. Other repair and maintenance costs for property, plant and equipment are also expensed as incurred.

Depreciation and amortization - At March 31, 2002, the average depreciable lives of property, plant and equipment by category for Domestic Electric Operations were: Production, 41 years; Transmission, 58 years; Distribution, 42 years and Other, 20 years.

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. Composite depreciation rates on utility plants (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.

Asset impairments - Long-lived assets to be held and used by the Company are reviewed for impairment when events or circumstances indicate costs may not be recoverable. Such reviews are performed in accordance with SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets ("SFAS No. 144") which the Company adopted February 1, 2002, effective as of April 1, 2001, as described under New accounting standards below. The impacts of regulation on cash flows are considered when determining impairment. Impairment losses on long-lived assets are recognized when book values exceed expected undiscounted future cash flows with the impairment measured on a discounted future cash flows basis.

Interest capitalized - Costs of debt and equity applicable to domestic electric utility properties are capitalized during construction. The composite capitalization rates were 3.6% for 2002, 7.3% for 2001 and 7.9% for 2000.

Derivatives - As discussed in Note 11, the Company adopted SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities," as amended by SFAS No. 138, effective April 1, 2001. The statement requires that the Company recognize all derivatives, as defined in the statement, on the balance sheet

at fair value. Derivatives, or any portion thereof, that are not an effective hedge, are adjusted to fair value through income. If a derivative qualifies as an effective hedge, changes in the fair value of the derivative are either offset against the change in fair value of the hedged asset, liability, or firm commitment recognized in earnings, or are recognized in Accumulated other comprehensive income (loss) until the hedged items are recognized in earnings.

Finance assets - As discussed in Note 14, the Company transferred all of its interests in PFS to PHI in February 2002 and therefore has no finance assets as of March 31, 2002. At March 31, 2001, Finance assets consisted of finance receivables, leveraged leases and operating leases and were not significant to the Company in terms of revenue or net income. The Company's leasing operations consisted principally of leveraged aircraft leases. Investments in finance assets were net of accumulated impairment charges and allowances for credit losses of $42.6 million at March 31, 2001. The Company provided zero, $7.2 million and $11.0 million for impairment charges and credit losses in 2002, 2001 and 2000, respectively. Write-offs for impairment charges and credit losses were $8.4 million, zero and $2.0 million in 2002, 2001 and 2000, respectively.

Deferred charges and other - Deferred charges and other are comprised primarily of funds held in trust for the final reclamation of a leased coal mining property, investments to fund environmental remediation, unamortized debt expense, long term customer loans and receivables, certain employee benefit plan assets, and net amounts for corporate owned life insurance.

The Company maintains a trust relating to final reclamation of a leased coal mining property. Amounts funded are based on estimated future reclamation costs and estimated future coal deliveries. In both 2002 and 2001, the Company reviewed funding requirements based on estimated future gains and interest earnings on trust assets and the projected future reclamation liability. The Company determined that no funding was required for both 2002 and 2001. Securities held in the reclamation trust fund are recorded at market value in accordance with SFAS No. 115, "Accounting for Certain Investments in Debt and Equity Securities," as discussed in Note 10. Trust assets include debt and equity securities classified as available for sale. Securities available for sale are carried at fair value with net unrealized gains or losses excluded from income and reported as Accumulated other comprehensive income (loss). Realized gains or losses are determined on the specific identification method.

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

Prior to 1980, Domestic Electric Operations did not provide deferred taxes on many of the timing differences between book and tax depreciation. In prior years, these benefits were flowed through to the utility customer as prescribed by the Company's various regulatory jurisdictions. Deferred income tax liabilities and Regulatory assets have been established for those flow through tax benefits, as shown in Note 13.

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

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

Stock based compensation - As permitted by SFAS No. 123, "Accounting for Stock Based Compensation," the Company has elected to follow Accounting Principles Board ("APB") Opinion No. 25, "Accounting for Stock Issued to Employees" ("APB No. 25") and related interpretations in accounting for employee stock options issued to Company employees. Under APB No. 25, because the exercise price of employee stock options equals the market price of the underlying stock on the date of grant, no compensation expense is recorded. Upon completion of the Merger, all options are issued in ScottishPower American Depository Shares ("ADS"), as discussed in Notes 2 and 17.

Revenue recognition - Readings of customers' electric usage meters are staggered throughout the month. The Company accrues estimated unbilled revenues for electric services, provided after the meter read date to the month-end, based upon the Company's total delivery.

New accounting standards - 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 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, "Accounting for the Effects of Certain Types of Regulation." 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, effective as of April 1, 2001. The adoption of SFAS No. 144 resulted in the Company not classifying Holdings as Discontinued Operations following the internal restructuring.

Reclassification - Certain amounts from prior years have been reclassified to conform with the 2002 method of presentation. These reclassifications had no effect on previously reported consolidated net income (loss).

NOTE 2 - ScottishPower Merger

On November 29, 1999, the Company and ScottishPower completed the Merger under which the Company became an indirect subsidiary of ScottishPower. The Company continues to operate under its current name, and its headquarters remain in Portland, Oregon. As a result of the Merger, the Company became part of a public utility holding company group and, as such, the Company's operations are subject to the requirements and restrictions of the Public Utility Holding Company Act of 1935 (the "PUHCA"). Under the PUHCA, the Company may pay dividends out of capital or unearned surplus only with SEC approval. Dividends from earned surplus are permitted without approval. In addition, the PUHCA places restrictions on transactions with affiliates.

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

The following table shows where Merger costs have been recorded in the Company's financial results. No Merger costs were incurred in 2002.

Merger Costs	Pretax		After-tax
	Years Ended March 31,		Years Ended March 31,
(Millions of dollars)	2001	2000	2001	2000
Included in Domestic Electric operating expenses Employee related expenses (severance, retention, etc.) Legal fees, contracted services and other expenses Total Merger costs included in operating expenses	$ - - -	$ 12.7 3.3 16.0	$ - - -	$ 7.9 2.0 9.9
Included within Merger costs - Domestic Electric Employee related expenses Merger credits Stamp tax Banking fees Legal fees, contracted services and other expenses Total included within Merger costs - Domestic Electric	- 12.0 (2.7) - - 9.3	23.7 57.2 77.8 19.4 12.4 190.5	- 7.4 (2.7) - - 4.7	22.1 35.5 77.8 19.4 12.4 167.2
Included within Merger costs - Other Operations	-	5.0	-	3.1
Total included within Merger costs	9.3	195.5	4.7	170.3
Total Merger costs	$ 9.3	$211.5	$ 4.7	$180.2

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.

	Years Ended March 31, 2002 and 2001
(Millions of dollars)	Total	Retirement Benefits	Severance and Other
Accruals recorded Payments Reclassifications to accrued pension costs Reclassifications to accrued postretirement benefit costs Balance at March 31, 2001 Payments Change in estimate Reclassifications to accrued severance costs Reclassification to regulatory asset Balance at March 31, 2002	$175.2 (12.5) (81.8) (17.6) 63.3 (11.6) (9.1) (11.8) (30.8) $ -	$ 99.4 - (81.8) (17.6) - - - - - $ -	$ 75.8 (12.5) - - 63.3 (11.6) (9.1) (11.8) (30.8) $ -

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.

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.

Regulatory assets include the following:

	March 31,
(Millions of dollars)	2002	2001
Deferred taxes (a) Transition Plan costs - retirement and severance (b) Deferred net power costs (c) Demand-side resource costs Unamortized net loss on reacquired debt Utah and Oregon asset writebacks (d) Unrecovered Trojan Plant SFAS No. 133 regulatory asset (e) SB 1149 related costs (f) Various other costs Total	$ 574.2 78.6 305.4 49.3 39.7 40.2 16.8 468.4 22.6 31.5 $1,626.7	$ 593.8 141.5 137.5 66.4 45.2 35.1 18.7 - 6.5 37.1 $1,081.8

(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.

Regulatory liabilities include the following:

	March 31,
(Millions of dollars)	2002	2001
Deferred taxes Centralia gain (a) Merger credits Utah rate refund Various other costs Total	$ 40.5 115.3 24.0 34.7 5.2 $ 219.7	$ 43.7 150.9 47.2 - 14.2 $ 256.0

(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

$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

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.

Oregon - On June 26, 2001, the Company received approval from the OPUC for an overall price increase of 1.0%, or $7.6 million, through an annual adjustment as part of the Alternative Form of Regulation ("AFOR") process previously authorized in Oregon. The new rates took effect July 1, 2001 and will run until the Company recovers all under-earnings relating to the AFOR. The Company received approximately $5.7 million in additional revenues in 2002 relating to this increase, which is expected to terminate in June 2002.

On November 1, 2000, the Company filed the unbundling generation, transmission and distribution cost information required under SB 1149 rules. See Deregulation below for further information on SB 1149. On September 7, 2001, the OPUC granted a rate increase in the amount of $64.4 million, effective September 10, 2001. This increase added approximately $37.7 million of revenues in 2002.

On January 17, 2002, the Company requested approval to begin recovering in rates the amortization of approximately $12.9 million of SB 1149 implementation costs, which were deferred between April and December 2001. At its public meeting on March 5, 2002, the OPUC granted this request effective March 6, 2002. This approval increases annual revenues by approximately $2.6 million, or 0.3%, overall. The OPUC had already ordered recovery of the approximately $5.4 million in SB 1149 costs incurred prior to March 31, 2001. In both cases, the deferred costs will be recovered over a five-year period. The Company is now recovering approximately $3.7 million annually of the SB 1149 costs, including $0.5 million in 2002.

In Oregon, the final order in the rate case that concluded in September 2001 required the Company to file the results of a new hourly net power cost model to replace the net power cost model currently used in setting rates. The Company filed this material in a power cost rate case on December 31, 2001 and requested a $34.3 million annual rate increase. The Company also filed for a permanent power cost adjustment mechanism. The Company filed a stipulation with all parties on March 29, 2002. The stipulation would result in an increase of $18.7 million for power cost recovery, in effect for one year. The Company would also agree to withdraw its request for a permanent power cost adjustment mechanism. The Company may renew this request after January 2003. The stipulation also includes the following major components: (i) a rate

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

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.

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

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.

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

	March 31,
(Millions of dollars)	2002	2001
Amounts due from affiliated companies ScottishPower Note receivable (a) Interest receivable (a) Accounts receivable (b)	$ - - 0.5 $ 0.5	$370.0 0.1 0.3 $370.4
PHI and its other subsidiaries (c) Notes receivable	$ -	$ 72.1
Accounts receivable	3.5 $ 3.5	1.4 $ 73.5
Amounts due to affiliated companies ScottishPower payables (d) PHI and its other subsidiaries (c) Accounts payable Notes payable Dividends payable ScottishPower	$ 0.8 $ - 1.0 $ 1.0 $ -	$ 13.6 $ 5.1 - $ 5.1 $ 57.8

	Years Ended March 31,
(Millions of dollars)	2002	2001	2000
Revenues from affiliated companies PHI and its other subsidiaries (e)	$ 6.0	$ -	$ -
Expenses incurred from affiliated companies ScottishPower (d)	$16.5	$ 8.8	$ 4.7
Expenses recharged to affiliated companies ScottishPower (b)	$ 5.8	$ 0.3	$ -
Interest - net from affiliated companies ScottishPower (a)
Interest income PHI and its other subsidiaries (c) Interest income Interest expense	$ 9.5 $ 6.7 (0.1) $ 6.6	$14.0 $ - - $ -	$ - $ - - $ -

(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.

(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:

(Millions of dollars)	Balance	Average Interest Rate (a)
March 31, 2002 March 31, 2001	$176.5 $240.5	2.2% 5.7%

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

At March 31, 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:

	March 31,
(Millions of dollars)	2002	2001
PacifiCorp First mortgage bonds Maturing through 2007/5.7%-9.0% Maturing 2008 through 2012/6.4%-9.2% Maturing 2013 through 2017/7.3%-8.8% Maturing 2018 through 2022/8.3%-8.5% Maturing 2023 through 2027/6.7%-8.6% Maturing 2028 through 2032/7.7% Guaranty of pollution control revenue bonds 5.6%-5.7% due 2022 through 2024 (a) Maturing 2031/6.2% Variable rate due 2014 (a)(b) Variable rate due 2025 (a)(b) Variable rate due 2006 through 2031 (b) Funds held by trustees Capitalized lease obligations, maturing 2014 through 2022/10.4%-14.8% Unamortized premium or discount Total Less current maturities Total	$1,002.0 1,078.1 91.0 30.7 432.5 300.0 71.2 12.7 40.7 175.8 438.0 (2.0) 27.6 (5.0) 3,693.3 (143.9) 3,549.4	$1,052.7 578.1 91.0 30.7 432.5 - 71.2 12.7 40.7 175.8 438.0 (2.1) 27.2 (2.8) 2,945.7 (50.3) 2,895.4
Subsidiaries 8.6% Note due 2005 6.0%-6.1% Notes due through 2003 (c) Total Less current maturities Total Total	5.0 - 5.0 (0.6) 4.4 $3,553.8	5.5 6.9 12.4 (0.9) 11.5 $2,906.9

(a)  Secured by pledged first mortgage bonds generally at the same interest rates, maturity dates and redemption provisions as the pollution control revenue bonds.

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

(c)  PFS notes extinguished in 2002 due to the synthetic fuel operations sale.

First mortgage bonds of the Company may be issued in amounts limited by Domestic Electric Operations' property, earnings and other provisions of the mortgage indenture. Approximately $11.5 billion of the eligible assets (based on original cost) of PacifiCorp are subject to the lien of the mortgage. Approximately $1.5 billion of first mortgage bonds were redeemable at the Company's option at March 31, 2002 at redemption prices dependent upon U.S. Treasury yields. Approximately $654.5 million of pollution control revenue bonds were redeemable at the Company's option at par at March 31, 2002. Subsidiary notes are redeemable at the Company's option at face amount. The remaining long-term debt was not redeemable at the Company's option 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 used the proceeds for general corporate purposes, including the repayment of commercial paper and short-term debt borrowed from Holdings. 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.

The annual maturities of long-term debt, capitalized lease obligations and redeemable preferred stock outstanding are $148.2 million, $140.4 million, $243.5 million, $289.2 million and $242.5 million in 2003 through 2007, respectively.

The Company made interest payments, net of capitalized interest, of $246.7 million, $337.5 million and $402.4 million in 2002, 2001 and 2000, respectively. This includes interest on leveraged lease debt that is netted against revenue on leveraged leases.

NOTE 8 - Guaranteed Preferred Beneficial Interests In
Company's Junior Subordinated Debentures

Wholly-owned subsidiary trusts of the Company (the "Trusts") have issued, in public offerings, redeemable preferred securities ("Preferred Securities") representing preferred undivided beneficial interests in the assets of the Trusts, with liquidation amounts of $25.0 per Preferred Security. The sole assets of the Trusts are Junior Subordinated Deferrable Interest Debentures of the Company that bear interest at the same rates as the Preferred Securities to which they relate, and certain rights under related guarantees by the Company.

Preferred Securities outstanding were as follows:

		March 31,
(Millions of dollars, Thousands of Preferred Securities)		2002	2001
8,680 5,400 Total	8.25% Cumulative Quarterly Income Preferred Securities, Series A, with Trust assets of $223.7 million (a) 7.70% Trust Preferred Securities, Series B, with Trust assets of $139.2 million (b)	$210.6 130.9 $341.5	$210.4 130.8 $341.2

(a) Amount is net of unamortized issuance costs of $6.4 million and $6.6 million at March 31, 2002 and 2001, respectively.

(b) Amount is net of unamortized issuance costs of $4.1 million and $4.2 million at March 31, 2002 and 2001, respectively.

All of the 8.25% Cumulative Quarterly Income Preferred Securities, Series A, were redeemable at the Company's option at face amount at March 31, 2002.

NOTE 9 - Common and Preferred Stock

Common Stock - The Company has one class of common stock with no par value. A total of 750,000,000 shares were authorized and 297,324,604 were issued and outstanding at March 31, 2002 and 2001.

Common Dividend Restrictions - ScottishPower is the sole indirect shareholder of the Company's common stock. The Company is restricted from paying dividends or making other distributions to ScottishPower without prior OPUC approval to the extent such payment or distribution would reduce the Company's common stock equity below a specified percentage of its total capitalization. The percentage of total capitalization increases over time from 35.0% after December 31, 1999 to 40.0% after December 31, 2004. In addition, the Company must give the OPUC 30 days prior notice of any special cash dividend or any transfer involving more than five percent of PacifiCorp's retained earnings in a six-month period. The Company is also subject to maximum debt to total capitalization levels under various debt agreements.

Under the Public Utility Holding Company Act of 1935, the Company may pay dividends out of capital or unearned surplus only with SEC approval. Dividends from earned surplus are permitted without approval. The Company has received approval to pay dividends out of unearned surplus of the lesser of $900.0 million or the proceeds received from sales of non-utility assets. At March 31, 2002, $300.0 million was available for dividends out of unearned surplus.

Preferred Stock

(Thousands of shares)

At December 31, 1998

Redemptions and repurchases

At March 31, 2001 and 2000

Redemptions and repurchases

At March 31, 2002

3,160

(995)

2,165

(1,000)

1,165

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

Preferred Stock Outstanding (Millions of dollars, Thousands of shares) Series	March 31, 2002		March 31, 2001
	Shares	Amount	Shares	Amount
Subject to Mandatory Redemption No Par Serial Preferred, $100 stated value, 16,000 Shares authorized $7.70 7.48	- 750 750	$ - 74.2 74.2	1,000 750 1,750	$100.0 75.0 175.0
Not Subject to Mandatory Redemption Serial Preferred, $100 stated value, 3,500 Shares authorized 4.52% 4.56 4.72 5.00 5.40 6.00 7.00 5% Preferred, $100 stated value, 127 Shares authorized Total	2 85 70 42 66 6 18 126 415 1,165	0.2 8.4 6.9 4.2 6.6 0.6 1.8 12.6 41.3 $115.5	2 85 70 42 66 6 18 126 415 2,165	0.2 8.5 7.0 4.2 6.6 0.6 1.8 12.6 41.5 $216.5

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

The Company had $2.3 million in preferred dividends declared but unpaid at March 31, 2002. The Company had $57.8 million and $4.1 million in common and preferred dividends, respectively, declared but unpaid at March 31, 2001.

NOTE 10 - Securities Available For Sale

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

(Millions of dollars)	Amortized Cost	Gross Unrealized Gains	Gross Unrealized Losses	Estimated Fair Value
March 31, 2002 Money market account Mutual fund account Debt securities Equity securities Total March 31, 2001 Money market account Debt securities Equity securities Total	$ 2.7 29.3 26.9 50.7 $109.6 $ 2.7 25.1 54.9 $ 82.7	$ - - 0.5 5.8 $ 6.3 $ - 0.7 7.9 $ 8.6	$ - (0.5) (0.2) (3.4) $ (4.1) $ - - (6.1) $ (6.1)	$ 2.7 28.8 27.2 53.1 $111.8 $ 2.7 25.8 56.7 $ 85.2

The quoted market price of securities at March 31, 2002, is used to estimate the securities' fair value.

The amortized cost and estimated fair value of debt securities at March 31, 2002 and 2001 by contractual maturities are shown below. Actual maturities may differ from contractual maturities because borrowers may have the right to call or prepay obligations with or without call or prepayment penalties.

	March 31,
(Millions of dollars)	2002		2001
(Millions of dollars)	Amortized Cost	Estimated Fair Value	Amortized Cost	Estimated Fair Value
Debt securities Due in one year or less Due after one year through five years Due after five years through ten years Due after ten years Money market account Mutual fund account Equity securities Total	$ - 6.0 8.7 12.2 2.7 29.3 50.7 $109.6	$ - 6.1 8.8 12.3 2.7 28.8 53.1 $111.8	$ 0.8 6.6 7.0 10.7 2.7 - 54.9 $ 82.7	$ 0.9 6.8 7.2 10.9 2.7 - 56.7 $ 85.2

Proceeds, gross gains and gross losses from realized sales of available-for-sale securities using the specific identification method were as follows for the years ended March 31, 2002, 2001 and 2000:

(Millions of dollars)	Years Ended March 31,
(Millions of dollars)	2002	2001	2000
Proceeds Gross gains Gross losses Net (losses) gains	$120.9 $ 4.5 (12.1) $ (7.6)	$119.9 $ 11.8 (7.9) $ 3.9	$125.9 $ 8.2 (5.0) $ 3.2

NOTE 11 - Derivative Instruments

On April 1, 2001, the Company adopted SFAS No. 133, as amended by SFAS No. 138 and numerous interpretations of the Derivatives Implementation Group ("DIG") that are approved by the FASB, collectively "SFAS No. 133." Under SFAS No. 133, derivative instruments are recorded on the Consolidated Balance Sheet as an asset or liability measured at estimated fair value, with changes in fair value recognized currently in earnings (in Purchased power and Fuel), unless specific hedge accounting criteria are met. As contracts settle, sales are recorded in Operating revenues, with purchases and futures recorded in Purchased power and Fuel on the Statements of Consolidated Income (Loss). A derivative financial instrument or other contract derives its value from another investment, a designated benchmark, or an underlying price.

The Company's primary business is to serve its retail customers. The Company's business is exposed to risks relating to, but not limited to, changes in certain commodity prices and counterparty performance. The Company enters into derivative instruments, including electricity, natural gas and coal forward, option and swap contracts, and weather contracts to manage its exposure to commodity price risk and thereby attempts to minimize variability in net power costs for customers. The majority of these contracts qualify for the normal purchase and normal sale exception under SFAS No. 133. The Company has policies and procedures to manage risks inherent in these activities and a Risk Management Committee to monitor compliance with the Company's risk management policies and procedures.

The Risk Management Committee has limited the types of commodity instruments the Company may trade to those related to electricity, natural gas and coal commodities and those instruments are to be used for hedging price fluctuations associated with the management of resources. Commodity instruments are not generally held by the Company for speculative trading purposes. The estimated fair value of trading instruments at March 31, 2002, was $1.1 million favorable to the Company.

The accounting treatment for the various classifications of derivative financial instruments under SFAS No. 133 is as follows:

Normal purchases and normal sales - The contracts that qualify as normal purchases and normal sales are excluded from the requirements of SFAS 133. The realized gains and losses on these contracts are reflected in the income statement at the contract settlement date.

Cash Flow Hedge - The unrealized gains and losses relating to these forward contracts are included in Accumulated other comprehensive income (loss), a component of shareholder's equity. As the forward contracts are settled, the realized gains and losses are recorded on the Statements of Consolidated Income (Loss) as a component of Operating revenues or Purchased power and the unrealized gains and losses are reversed from Accumulated other comprehensive income (loss).

Trading Activity - The unrealized gains and losses relating to these forward contracts are reflected in the Statements of Consolidated Income (Loss) as a component of Operating revenues. As the forward contracts are settled, the realized gains or losses are recorded and the unrealized gains and losses are reversed.

The Company has the following types of commodity transactions:

Coal, natural gas, and other fuel purchase contracts - The Company enters into long-term and short-term coal, natural gas, diesel, and other purchase contracts to provide adequate fuel resources to its electricity generation facilities. These contracts generally have limited optionality and require the Company to take physical delivery of the commodity. These contracts are generally determined to be normal purchases and normal sales contracts under SFAS No. 133.

Weather derivatives - To a limited degree, the Company has executed contracts to hedge changes in hydroelectric generation due to variation in precipitation, streamflow, or temperature. These contracts are not exchange traded and settlement is based on climatic or other physical variables. Therefore, on a periodic basis, the Company estimates and records a gain or loss in earnings corresponding to the total expected future cash flow from these contracts in accordance with EITF No. 99-2, "Accounting for Weather Derivatives." At March 31, 2002, amounts recorded for these contracts were $1.2 million.

Wholesale electricity purchase and sales contracts - The Company makes continuing projections of future retail and wholesale loads and future resource availability to meet these loads based on a number of criteria, including historic load and forward market and other economic information and experience. Based on these projections, the Company purchases and sells electricity on a forward yearly, quarterly, monthly, daily and hourly basis to match actual resources to actual energy requirements and sells any surplus at the best available price. This process involves hedging transactions which include the purchase and sale of firm capacity and energy under long-term contracts, forward physical or financial contracts for the purchase and sale of a specified amount of capacity or energy at a specified price over a given period of time (typically for one month, three months or one year), and forward purchases and sales of transmission service.

Upon adoption of SFAS No. 133 on April 1, 2001, all wholesale contracts were examined and it was determined that some of the forward contracts for the purchase or sale of wholesale power were considered to be derivatives based on the accounting guidance at that time. The effects of changes in fair value of certain derivative instruments entered into to hedge the Company's future retail resource requirements are subject to regulation and, therefore, are

deferred pursuant to SFAS No. 71. The Company requested and received deferred accounting orders for the effects of SFAS No. 133 as it relates to the change in fair value of long-term wholesale electricity contracts not meeting the definition of normal purchases and normal sales contracts. At the date of adopting SFAS No. 133, the Company recorded a net regulatory asset relating to the fair value of long-term wholesale contracts (which did not meet the definition of normal purchases and normal sales contracts) of $711.0 million. Short-term wholesale electricity purchase contracts not meeting the definition of normal purchases and normal sales contracts were designated as cash flow hedges to hedge the risk of changes in the cost of providing electricity to serve the Company's retail load. These hedges were fully effective. At the date of adopting SFAS No. 133, the Company recorded an unrealized after-tax gain of $617.2 million as a component of equity related to the fair value of short-term wholesale purchase contracts. Short-term wholesale electricity sales contracts not meeting the definition of normal purchases and normal sales contracts were marked to market through income, resulting in a $112.8 million after-tax loss on adoption of SFAS No. 133.

In June 2001, the DIG issued guidance which provided that certain forward power purchase or sales agreements, including capacity contracts, could be excluded from the requirements of SFAS No. 133 by expanding the normal purchases and normal sales exclusion. The Company implemented this new guidance, on a prospective basis, beginning July 1, 2001. As a result, substantially all of the Company's short-term wholesale electricity contracts were determined to meet the normal purchases and normal sales exclusion. No further market value changes were recognized for those excluded contracts and unrealized gains (losses) recorded in Other comprehensive income ("OCI") relating to the existing cash flow hedges as of July 1, 2001 are reversed prospectively when the related contracts are settled.

To mitigate exposure to credit risk, the Company has entered into master netting agreements with all of its significant trading counter parties. Unrealized gains and losses on contracts with parties under master netting agreements are presented net on the financial statements.

The following table summarizes the SFAS No. 133 adoption and activity for the year:

(millions)	Current Assets (Liability)	Regulatory Net Asset (Liability)	Deferred Tax Asset (Liability)	Income (Loss)	OCI Gain (Loss)
Adoption April 1, 2001	101.6	711.2	(308.5)	(112.8)	617.2
Settlements	60.2	(20.3)	(15.2)	139.7	(115.1)
Change in fair value	(667.7)	(222.5)	337.9	(26.2)	(526.1)
Balance March 31, 2002	(505.9)	468.4	14.2	0.7	(24.0)

contracts extending past 2006, the forward prices are derived using a fundamentals model (cost-to-build approach) that is updated as warranted to reflect changes in the market, at least quarterly.

As of March 31, 2002, the Company anticipated that approximately $38.6 million ($24.0 million after-tax) of the unrealized net losses on derivative instruments in Accumulated other comprehensive income (loss) will reverse during the subsequent twelve months as the underlying contracts are settled. A corresponding change to the SFAS No. 133 asset will be recorded with no net effect on earnings. As of March 31, 2002, contracts designated as cash flow hedges have contractual settlement dates through September 2002.

During 2001, the DIG issued guidance under Issue C16, "Applying the Normal Purchases and Normal Sales Exception to Contracts that Combine a Forward Contract and a Purchased Option Contract" ("Issue C16"). The guidance disallows normal purchases and normal sales treatment for commodity contracts (other than power contracts) that contain volumetric variability or optionality. Issue C16 is effective April 1, 2002. As a result, these contracts will be required to be marked-to-market through earnings. The Company will be reviewing its contracts to determine which contracts, if any, will no longer qualify as normal purchase and normal sales contracts.

To date, the DIG has issued more than 100 interpretations to provide "guidance" in applying SFAS No. 133. As the DIG or the FASB continues to issue interpretations, the Company may change the conclusions that it has reached and, as a result, the accounting treatment and financial statement impact could change in the future.

NOTE 12 - Fair Value of Financial Instruments

	March 31, 2002		March 31, 2001
(Millions of dollars)	Carrying Amount	Fair Value	Carrying Amount	Fair Value
Long-term debt (a) Preferred Securities Preferred stock subject to mandatory redemption	$3,670.7 341.5 74.2	$3,763.5 338.1 81.5	$2,930.9 341.2 175.0	$3,024.8 333.7 185.5

(a) Represents long-term debt and long-term debt classified as currently maturing, less capitalized lease obligations.

The carrying value of cash and cash equivalents, receivables, payables, accrued liabilities and short-term borrowings approximates fair value because of the short-term maturity of these instruments. The fair value of the finance note receivable approximates its carrying value at March 31, 2001.

The fair value of the Company's long-term debt and redeemable preferred stock has been estimated by discounting projected future cash flows, using the current rate at which similar loans would be made to borrowers with similar credit ratings and for the same maturities. Current maturities of long-term debt were included. Preferred Securities were estimated using quoted market prices at March 31, 2002 and 2001.

NOTE 13 - Income Taxes

Upon its acquisition by ScottishPower, the Company became a member of a group that files its federal and state tax returns on a consolidated basis. Tax expense is calculated on a separate return basis. Amounts payable for federal and state taxes are remitted to the Company's parent.

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 difference between taxes calculated as if the statutory federal tax rate of 35.0% was applied to income from continuing operations before income taxes and the recorded tax expense is reconciled as follows:

(Millions of dollars)	Years Ended March 31,
(Millions of dollars)	2002	2001	2000
Computed Federal Income Taxes	$164.3	$ 32.3	$ 75.8
Increase (Reduction) in Tax Resulting from: Depreciation differences Depletion Investment tax credits Merger costs Affordable housing and alternative fuel credits Loss from sales of Australian operations (a) Tax reserves Income taxed at less than statutory rate Corporate owned life insurance Nontaxable income All other Total Federal Income Tax State Income Tax, Net of Federal Income Tax Benefit	13.7 (1.5) (10.8) - - (9.9) 20.9 (4.6) (3.3) (1.4) (4.8) (1.7) 162.6 13.5	21.4 (3.0) (9.4) (0.9) - 74.3 66.2 (4.0) (3.0) (2.4) (2.8) 136.4 168.7 11.7	23.0 (4.2) (9.1) 41.7 (27.9) - 27.6 (3.1) (1.9) (2.6) 2.6 46.1 121.9 12.1
Total Income Tax Expense	$176.1	$180.4	$134.0

(a) The Company did not have enough capital gains to offset the capital losses resulting from the sale of the Australian operations in 2001. Subsequently, an election was made to reattribute a portion of the losses to the group so that a benefit could be taken.

The provision for income taxes is summarized as follows:

(Millions of dollars)	Years Ended March 31,
(Millions of dollars)	2002	2001	2000
Current Federal State Total Deferred Federal State Total Investment Tax Credits Total Income Tax Expense	$104.1 11.1 115.2 63.2 8.5 71.7 (10.8) $176.1	$190.2 16.6 206.8 (18.4) 1.4 (17.0) (9.4) $180.4	$(12.1) 9.4 (2.7) 136.5 9.3 145.8 (9.1) $134.0

The tax effects of significant items comprising the Company's net deferred tax liability were as follows:

	March 31,
(Millions of dollars)	2002	2001
Deferred Tax Liabilities Property, plant and equipment Regulatory assets Other deferred liabilities	$ 965.4 574.2 17.8 1,557.4	$1,160.5 593.8 135.7 1,890.0
Deferred Tax Assets Regulatory liabilities Book reserves not currently deductible for tax Pension accrual Safe harbor lease Other deferred assets Net Deferred Tax Liability	(40.5) (43.8) (16.4) (13.2) (8.7) (122.6) $1,434.8	(43.7) (71.2) (24.8) (10.3) (95.0) (245.0) $1,645.0

During the current year, the Company settled its litigation with the IRS for the 1989 and 1990 tax years. A liability for the full tax impact of this settlement had been previously established. The additional payment of tax and interest was fully offset by a tax payment posted with the IRS in 1999.

The Company has concluded its settlement discussions with the IRS Appeals Division for the 1991, 1992 and 1993 tax years. The tax impact for this settlement is approximately $10.3 million. The Company has established a liability for this amount and is awaiting final billing from the IRS for these years.

The examination of the Company's 1994 through 1998 tax years is expected to be completed by June 2002. The IRS has not yet issued a Revenue Agent's Report for these years. The IRS has also notified the Company that it intends to start the examination of the 1999 and 2000 tax years beginning September 2002.

The Company made net income tax payments of $83.1 million for 2002 and in 2001 and 2000 received net income tax refunds of $63.9 million and $1.8 million, respectively.

NOTE 14 - Dispositions

On December 31, 2001, NAGP contributed all of the common stock of PacifiCorp to PHI. On February 4, 2002, PacifiCorp transferred all of the capital stock of Holdings to PHI. Accordingly, the results of operations and assets of Holdings are not included with those of PacifiCorp commencing February 4, 2002.

In October 2001, PFS sold its synthetic fuel operations. PFS received proceeds from the sale of $45.0 million and will receive quarterly royalty payments from the purchaser through October 2007. The sale resulted in a gain of approximately $11.3 million, pretax.

During the first quarter of 2002, the Company sold aircraft owned by subsidiaries of PFS. PFS received proceeds of approximately $36.0 million and recorded a $9.3 million pretax gain on the sale. These assets had previously been reported under Finance Assets - Net on the balance sheet.

In connection with an internal restructuring of the Company, the Company transferred its interest in two non-utility energy companies to an affiliated entity, PHI, in March 2001. The transfer price of $72.4 million was based on an estimate of market value and was financed through a loan from Holdings. The income and cash flow impacts from the two companies are included in the 2001 results, but the assets and liabilities associated with those businesses were removed from the consolidated balance sheet upon the transfer to PHI. No gain was recognized on the transfer. The difference between the transfer price and the book value was recorded as an adjustment to equity.

In 2001, Holdings completed the sale of its ownership of Powercor and its 19.9% interest in Hazelwood for approximately AUS $2.4 billion and approximately AUS $88.0 million, respectively. Powercor and Hazelwood represented all of the Australian Electric Operations segment of the Company. The Company recorded an after-tax loss on the sale of $197.7 million. 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.

The loss on sale of Australian Electric Operations for the year ended March 31, 2002 and 2001 is as follows:

	March 31, 2002		March 31, 2001
(Millions of dollars)	Pretax	After-Tax	Pretax	After-Tax
Australian Electric Operations: Gain (loss) on sale Loss due to cumulative unfavorable changes in foreign exchange rate Total Australian Electric Operations	$27.4 - 27.4	$27.4 - 27.4	$(109.1) (108.5) (217.6)	$(109.1)(a) (108.5)(a) (217.6)
Other Operations: Loss on repayment of debt Net gain on swap settlement	- - -	- - -	(1.9) 35.3 33.4	(1.9) 21.8 19.9
Total gain (loss) on sale	$27.4	$27.4	$(184.2)	$(197.7)

(a) The Company did not have enough capital gains to offset this capital loss and does not anticipate any further tax benefit from this loss.

In October 2001, the Company and Nor-Cal Electric Authority ("Nor-Cal") reached an agreement in principle for the sale of the Company's California electric service territory. The parties have been working to complete the sale of these properties since 1999. In December 2000, the CPUC turned down a previous agreement between these parties. If a new definitive agreement is reached, it will be subject to approval by the CPUC, which is expected to take between six months and one year.

On May 4, 2000, the utility partners, including the Company, who owned the 1,340 Megawatt ("MW") coal-fired Centralia Power Plant sold the plant and the adjacent coal mine, which was wholly-owned and operated by the Company, for approximately $500.0 million. The Company operated the plant and owned a 47.5% share. The Company recorded a loss of approximately $13.9 million on the sale.

All assets subject to disposition continued to be utilized in operations of the Company. As such, no separate accounting treatment or classification has been given to such assets.

NOTE 15 - Environmental Costs, Mine Reclamation And Closure Costs

The Company's mining operations are subject to reclamation and closure requirements. Reclamation and closure costs are estimated based on engineering studies. The Company monitors these requirements and periodically revises its cost estimates to meet existing legal and regulatory requirements of the various jurisdictions in which it operates. The Company expenses current mine reclamation costs. Costs for reclamation are accrued using the units-of-production method such that estimated final mine reclamation and closure costs are fully accrued at completion of mining activities, except where the Company has decided to close a mine. When a mine is closed, the Company records the estimated cost to complete the mine closure and seeks recovery of any incremental costs through rates. The Company believes that it has adequately provided for its reclamation obligations, assuming ongoing operations of its

mines. Total estimated final reclamation costs, including the Company's and minority interest joint owners' portions, for all mines with which the Company is involved was $184.3 million at March 31, 2002. These amounts are expected to be paid over the next 40 years.

The liabilities for environmental clean-up related costs are generally recorded on an undiscounted basis. These liabilities are recorded in the balance sheet in Deferred credits - Other at March 31, 2002 and 2001 as follows:

	March 31,
(Millions of dollars)	2002	2001
Mine reclamation and closure costs (a) Environmental remediation (b) Nuclear decommissioning (c) Total	$ 145.6 40.3 8.8 $ 194.7	$ 163.1 42.3 9.1 $ 214.5

(a)  Amounts include the Company's and minority interest joint owners' portion of mine reclamation costs. Amount also includes $12.2 million and $10.7 million at March 31, 2002 and 2001, respectively, that is included in Current liabilities - Other.

(b)  Expected to be paid over 19 years. Amount also includes $1.2 million and $0.9 million at March 31, 2002 and 2001, respectively, that is included in Current liabilities - Other.

(c)  Expected to be paid over 22 years.

The Company had trust fund assets included in Deferred Charges and Other of $80.4 million and $85.1 million at March 31, 2002 and 2001, respectively, relating to mine reclamation, including minority interest joint owners' portion.

NOTE 16 - Commitments and Contingencies

Litigation - The Company and its subsidiaries are parties from time to time to various legal claims, actions and complaints, certain of which involve material amounts. Although the Company is unable to predict with certainty whether or not it will ultimately be successful in these legal proceedings or, if not, what the impact might be, management currently believes that disposition of these matters will not have a materially adverse effect on the Company's consolidated financial statements.

Environmental issues - The Company is subject to numerous environmental laws including: the Federal Clean Air Act, as enforced by the Environmental Protection Agency and various state agencies; the 1990 Clean Air Act Amendments; the Endangered Species Act, particularly as it relates to certain potentially endangered species of salmon; the Comprehensive Environmental Response, Compensation and Liability Act, relating to environmental cleanups; along with the Federal Resource Conservation and Recovery Act and the Clean Water Act relating to water quality. These laws could potentially impact future operations. For those contingencies identified at March 31, 2002,

principally the Superfund sites where the Company has been or may be designated as a potentially responsible party and Clean Air Act matters, future costs associated with the disposition of these matters are expected to be addressed in future regulatory requests and, therefore, are not expected to be material to the Company's consolidated financial statements.

Hydroelectric relicensing - The Company's hydroelectric portfolio consists of 53 plants with a total capacity of 1,119 MW. Ninety-seven percent of the installed capacity is regulated by the FERC through 20 individual licenses. Nearly all of the Company's hydroelectric projects are in some stage of relicensing under the FPA. Hydro relicensing and the related environmental compliance requirements are subject to a high degree of change in estimation. However, the Company expects that these costs will be significant and consist primarily of future capital expenditures.

California and Enron Reserves - 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. 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.

Construction and other - The Company has an ongoing construction program and, as a part of this program, substantial commitments have been made.

Leases - The Company has certain properties under leases with various expiration dates and renewal options. Rentals on lease renewals are subject to negotiation. Certain leases provide for options to purchase at fair market value. The Company is also committed to pay all taxes, expenses of operation (other than depreciation) and maintenance applicable to the leased property.

Net rent expense for the years ended March 31, 2002, 2001 and 2000, was $27.1 million, $8.7 million and $16.0 million, respectively. In 2002, the Company leased a new generating turbine that added $24.7 million to rent expense. Future minimum lease payments under noncancellable operating leases are $4.1 million, $3.7 million, $3.5 million, $3.5 million and $1.9 million for 2003 through 2007, respectively.

Future minimum lease payments under capital leases are $3.2 million, $3.4 million, $3.4 million, $3.4 million and $3.6 million for 2003 through 2007, respectively, and $55.9 million thereafter. The amount of interest in those lease payments is $45.3 million.

Future minimum lease payments on the West Valley City, Utah lease discussed in Note 3 are $12.5 million, $15.0 million, $15.0 million, $2.5 million and $- for 2003 through 2007, respectively.

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."

Jointly owned facilities - At March 31, 2002, Domestic Electric Operations' participation in jointly owned facilities was as follows:

(Millions of dollars)	Domestic Electric Operations' Share	Plant in Service	Accumulated Depreciation/ Amortization	Construction Work in Progress
Centralia Skookumchuck (a) Jim Bridger Units 1,2,3 and 4 (b) Trojan (c) Colstrip Units 3 and 4 (b) Hunter Unit 1 Hunter Unit 2 Wyodak Craig Station Units 1 and 2 Hayden Station Unit 1 Hayden Station Unit 2 Hermiston (d) Foote Creek (b) Other kilovolt lines and substations Unallocated acquisition adjustments (e) Total	47.5% 66.7 2.5 10.0 93.8 60.3 80.0 19.3 24.5 12.6 50.0 78.8 Various	$ 8.7 830.8 - 234.4 280.8 198.9 304.3 152.8 40.0 25.9 161.3 40.5 78.0 141.2 $2,497.6	$ 4.9 392.9 - 99.7 122.4 87.6 130.1 72.5 14.0 9.9 25.0 4.7 14.8 46.7 $1,025.2	$ - 6.2 - 4.6 1.3 5.2 0.4 2.2 0.2 0.1 0.1 3.3 - - $23.6

(a)  The Centralia plant was sold on May 4, 2000. The joint owners of the plant retained ownership in the Skookumchuck Dam and related facilities. For additional information on the sale, see Note 14.

(b)  Includes kilovolt lines and substations.

(c)  Plant, inventory, fuel and decommissioning costs totaling $16.8 million relating to the Trojan Plant were included in regulatory assets at March 31, 2002.

(d)  Additionally, the Company has contracted to purchase the remaining 50% of the output of the plant.

(e)  Represents the excess of the cost of the acquired interest in purchased facilities over their original net book value.

Under the joint agreements, each participating utility is responsible for financing its share of construction, operating and leasing costs. Domestic Electric Operations' portion is recorded in its applicable operations, maintenance and tax accounts, which is consistent with wholly owned plants.

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 hydroelectric facility are owned by Cowlitz County Public Utility District. Preliminary investigations suggest that the facility will be out of service for an extended period of time, possibly more than a year. This failure impacts the Company's owned and operated 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 recover other 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.

Long-term wholesale sales and purchased power contracts - Domestic Electric Operations manages its energy resource requirements by integrating long-term firm, short-term and spot market purchases with its own generating resources to economically dispatch the system (within the boundaries of FERC requirements) and meet commitments for wholesale sales and retail load growth. The long-term wholesale sales commitments include contracts with minimum sales requirements of $338.4 million, $312.5 million, $268.1 million, $229.5 million and $191.5 million for the years 2003 through 2007, respectively. As part of its energy resource portfolio, Domestic Electric Operations acquires a portion of its power through long-term purchases and/or exchange agreements which require minimum fixed payments of $347.6 million, $334.1 million, $338.3 million, $335.1 million and $345.0 million for the years 2003 through 2007, respectively. The purchase contracts include agreements with the BPA, the Hermiston Plant and a number of co-generating facilities.

Excluded from the minimum fixed annual payments above are commitments to purchase power from several hydroelectric projects under long-term arrangements with public utility districts. These purchases are made on a "cost-of-service" basis for a stated percentage of project output and for a like percentage of project annual costs (operating expenses and debt service). These costs are included in operations expense. Domestic Electric Operations is required to pay its portion of operating costs and its portion of the debt service, whether or not any power is produced. The arrangements provide for non-withdrawable power and the majority also provide for additional power, withdrawable by the districts upon one to five years' notice. For 2002, such purchases approximated 1.9% of energy requirements.

At March 31, 2002, Domestic Electric Operations' share of long-term arrangements with public utility districts was as follows:

Generating Facility	Year Contract Expires	Capacity (kW)	Percentage of Output	Annual Costs(a)
Wanapum Priest Rapids Rocky Reach Wells Total	2009 2005 2011 2018	155,444 109,602 64,297 59,617 388,960	18.9% 13.9 5.3 6.9	$ 7.0 4.0 3.1 2.0 $16.1

(a) Annual costs in millions of dollars. Includes debt service of $6.3 million. The Company's minimum debt service obligation at March 31, 2002 was $9.0 million, $9.0 million, $8.0 million, $10.0 million and $10.0 million for the years 2003 through 2007, respectively.

The Company has a 4.0% interest in the Intermountain Power Project (the "Project"), located in central Utah. The Company and the city of Los Angeles have agreed that the City will purchase capacity and energy from Company plants equal to the Company's 4.0% entitlement of the Project at a price equivalent to 4.0% of the expenses and debt service of the Project.

Short-term wholesale sales and purchased power contracts - At March 31, 2002, Domestic Electric Operations had short-term wholesale forward sales commitments that included contracts with minimum sales requirements of $153.2 million for the year 2003. At March 31, 2002, short-term forward purchase agreements require minimum fixed payments of $231.2 million for the year 2003.

Fuel contracts - Domestic Electric Operations has "take or pay" coal and natural gas contracts that require minimum fixed payments of $161.1 million, $156.3 million, $146.7 million, $131.5 million and $115.3 million for 2003 through 2007, respectively.

In May 1999, Domestic Electric Operations entered into a coal mining lease agreement for exclusive rights to mine the Mill Fork Tract in Emery County, Utah. The agreement calls for a lease bonus bid payment of $25.0 million, payable annually in March in installments of $5.0 million through 2003.

Resource management - The Company, as a public utility and a franchise supplier, has an obligation to manage resources to supply its customers. Rates charged to most customers are tariff rates authorized by regulatory agencies as discussed in Note 3.

NOTE 17 - Employment Benefit Plans

Retirement plans - The Company has pension plans covering substantially all employees. Benefits under the plan in the United States are based on the employee's years of service and average monthly pay in the 60 consecutive months of highest pay out of the last 120 months, with adjustments to reflect benefits estimated to be received from Social Security. Pension costs are funded annually by no more than the maximum amount that can be deducted for federal income tax purposes. At March 31, 2002, plan assets were primarily invested in common stocks, bonds and United States government obligations.

All permanent employees of Powercor engaged prior to October 4, 1994 were members of Division B or C of the Superannuation Fund (the "Fund") which provided defined benefits in the form of pensions (Division B) or lump sums (Division C). Both defined benefit Funds are closed to new members. Members who chose to contribute did so at rates of 3.0% or 6.0% of eligible salaries. Powercor employees engaged after October 4, 1994 were members of Division D of the Fund, which was a defined contribution fund in which members contributed up to 20.0% of eligible salaries. In 2001, Powercor made no contributions to Division B and C funds. In 2000, Powercor made contributions of $2.0 million to Division B and C funds. Powercor contributed to the Division D Fund at rates ranging from 6.0%-10.0% of eligible salaries in all years.

The net periodic pension (benefit) cost and significant assumptions are summarized as follows:

(Millions of dollars)	Years Ended March 31,
(Millions of dollars)	2002	2001	2000
Service cost Interest cost Expected return on plan assets Amortization of unrecognized net obligation Unrecognized prior service cost Unrecognized gain Net periodic pension (benefit) cost Discount rate Expected long-term rate of return on assets Rate of increase in compensation levels	$ 14.9 80.1 (99.9) 8.4 0.5 (10.3) $ (6.3) 7.5% 9.3% 4.0%	$ 19.5 82.4 (105.8) 8.4 0.5 (9.7) $ (4.7) 7.8% 9.3% 4.0%	$ 27.6 81.7 (93.9) 8.4 3.0 (0.8) $ 26.0 5.5%-7.5% 7.5%-9.3% 4.0%-4.5%

The change in the projected benefit obligation, change in plan assets and funded status are as follows:

	March 31,
(Millions of dollars)	2002	2001
Change in projected benefit obligation Projected benefit obligation - beginning of period Service cost Interest cost Foreign currency exchange rate changes Plan participant contributions Plan amendments Special termination benefits Actuarial loss Benefits paid Divestiture Projected benefit obligation - end of period	$1,129.4 14.9 80.1 - - 18.0 (a) 0.8 7.2 (129.6) (41.5)(b) $1,079.3	$1,142.4 19.5 82.4 (9.3) 0.5 (23.2)(c) 81.0 30.1 (128.4) (65.6) $1,129.4
Change in plan assets Plan assets at fair value - beginning of period Foreign currency exchange rate changes Actual return on plan assets Plan participant contributions Company contributions Benefits paid Divestiture Plan assets at fair value - end of period	$1,152.6 - (147.7) - 7.3 (129.6) (56.4)(b) $ 826.2	$1,265.8 (8.8) 55.3 0.5 33.7 (128.4) (65.5) $1,152.6
Reconciliation of accrued pension cost and total amount recognized Funded status of the plan Unrecognized net loss (gain) Unrecognized prior service cost (credit) Unrecognized net transition obligation Accrued pension cost Accrued benefit liability Intangible asset Accrued pension cost	$ (253.1) 71.1 13.1 41.2 $ (127.7) $ (169.0) 41.3 $ (127.7)	$ 23.2 (208.8) (4.4) 49.6 $ (140.4) $ (140.4) - $ (140.4)

(a) Represents an increase in the Company's projected benefit obligation as a consequence of the ad hoc cost of living benefit increase for retired employees that was approved on March 13, 2002.

(b) Represents a reduction in the Company's projected benefit obligation and assets as a consequence of the transfer of obligation to a new plan being jointly administered by the IBEW Local Union 57 and the Company. The new plan was created according to negotiated agreements between the Union and the

Company. As a result of these agreements, the nature of the Company's obligation changed from a fixed future benefit to a fixed percentage of pay commitment.

(c) Represents a reduction in the Company's projected benefit obligation as a consequence of an amended agreement with IBEW Local 57, under which employees under age 50 on July 1, 1999 receive their future service pension benefits from a new plan being jointly administered by the Union and the Company.

Employee Savings and Stock Ownership Plan - The Company has an employee savings and stock ownership plan that qualifies as a tax-deferred arrangement under the Internal Revenue Code. Participating United States employees may defer up to 20.0% of their compensation, subject to certain regulatory limitations. The Company matches 50.0% of employee contributions on amounts deferred up to 6.0% of total compensation with that portion vesting over five years. The Company makes an additional contribution of ScottishPower ADS to qualifying employees equal to a percentage of the employee's eligible earnings. These contributions are immediately vested. Company contributions to the savings plan were $16.8 million, $18.0 million and $18.7 million for the years ended March 31, 2002, 2001 and 2000, respectively, and represent amounts expensed for each period.

Other Postretirement Benefits - Domestic Electric Operations provides health care and life insurance benefits through various plans for eligible retirees on a basis substantially similar to those who are active employees. The cost of postretirement benefits is accrued over the active service period of employees. The transition obligation represents the unrecognized prior service cost and is being amortized over a period of 20 years. For those employees retired at January 1, 1994, the Company funds postretirement benefit expense on a pay-as-you-go basis and has an unfunded accrued liability of $181.6 million at March 31, 2002. For those employees retiring after January 1, 1994, the Company funds postretirement benefit expense through a combination of funding vehicles. The Company contributed nothing for the years ended March 31, 2002 and 2001 and $6.0 million for the year ended March 31, 2000. These funds are invested in common stocks, bonds and United States government obligations.

The net periodic postretirement benefit cost and significant assumptions are summarized as follows:

(Millions of dollars)	Years Ended March 31,
(Millions of dollars)	2002	2001	2000
Service cost Interest cost Expected return on plan assets Amortization of unrecognized net obligation Unrecognized gain Regulatory deferral Net periodic postretirement benefit cost	$ 5.2 28.6 (29.2) 12.2 (4.5) 1.5 $ 13.8	$ 5.2 27.7 (28.3) 12.2 (4.2) 1.5 $ 14.1	$ 6.5 24.5 (21.9) 12.2 (2.4) 1.5 $ 20.4
Discount rate Estimated long-term rate of return on assets Initial health care cost trend rate - under 65 Initial health care cost trend rate - over 65 Ultimate health care cost trend rate	7.5% 9.3% 10.5% 12.5% 5.0%	7.8% 9.3% 6.0% 6.5% 4.5%	7.5% 9.3% 6.6% 6.8% 4.5%

The change in the accumulated postretirement benefit obligation (the "APBO"), change in plan assets and funded status are as follows:

	March 31,
(Millions of dollars)	2002	2001
Change in accumulated postretirement benefit obligation Accumulated postretirement benefit obligation - beginning of period Service cost Interest cost Plan participant contributions Special termination benefits Actuarial loss (gain) Benefits paid Accumulated postretirement benefit obligation - end of period	$381.1 5.2 28.6 5.4 - 77.0 (26.9) $470.4	$347.0 5.2 27.7 4.7 16.9(a) (0.3) (20.1) $381.1
Change in plan assets Plan assets at fair value - beginning of period Actual return on plan assets Company contributions Plan participant contributions Net benefits paid Plan assets at fair value - end of period	$287.1 (18.0) 14.9 5.4 (26.9) $262.5	$303.1 (10.7) 10.1 4.7 (20.1) $287.1
Reconciliation of accrued postretirement costs and total amount recognized Funded status of the plan Unrecognized net loss (gain) Unrecognized net transition obligation Accrued postretirement benefit cost	$(207.9) 52.6 131.2 $ (24.1)	$ (94.0) (76.2) 143.5 $ (26.7)

(a) Represents the one-time charge for enhanced postretirement medical benefits for employees accepting the voluntary Workforce Transition Retirement Program offering in 2001.

The assumed health care cost trend rate gradually decreases over 5 to 8 years. The health care cost trend rate assumption has a significant effect on the amounts reported. Increasing the assumed health care cost trend rate by one percentage point would have increased the APBO as of March 31, 2002 by $26.3 million and the annual net periodic postretirement benefit costs by $1.8 million. Decreasing the assumed health care cost trend rate by one percentage point would have reduced the APBO as of March 31, 2002 by $24.3 million and the annual net periodic postretirement benefit costs by $1.7 million.

Postemployment Benefits - Domestic Electric Operations provides certain postemployment benefits to former employees and their dependants during the period following employment but before retirement. The costs of these benefits are accrued as they are incurred. Benefits include salary continuation, severance benefits, disability benefits and continuation of health care benefits for terminated and disabled employees and workers compensation benefits. Accrued costs for postemployment benefits were $5.4 million, $8.7 million and $7.4 million for the years ended March 31, 2002, 2001 and 2000, respectively.

Stock Option Incentive Plan - During 1997, the Company adopted a Stock Option Incentive Plan (the "Plan"). The exercise price of options granted under the Plan was 100.0% of the fair market value of the common stock on the day prior to the date of the grant. Stock options generally became exercisable in two or three equal installments on each of the first through third anniversaries of the grant date. The maximum exercise period under the Plan was ten years.

Upon completion of the Merger, all stock options granted prior to January 1999 became 100.0% vested. All outstanding stock options were converted into options to purchase ScottishPower ADS. Stock options to purchase ScottishPower ADS granted subsequent to the Merger vest over the same number of years as stock options granted prior to the Merger.

The table below summarizes the stock option activity under the Plan.

	Weighted Average Price	Number of Shares
PacifiCorp Stock
Outstanding Options March 31, 1999 Granted Exercised Forfeited Outstanding Options November 28, 1999 Conversion to ScottishPower ADS at 0.58 ADS per PacifiCorp share Outstanding Options	$21.35 17.19 19.31 21.21 20.80	6,080,285 871,900 (61,500) (614,276) 6,276,409 (6,276,409) -
ScottishPower ADS Outstanding Options November 29, 1999 Granted Exercised Forfeited	35.87 29.37 - 36.89	3,633,481 1,504,037 - (369,363)
Outstanding Options March 31, 2000 Granted Exercised Forfeited Outstanding Options March 31, 2001	33.73 25.06 30.05 33.90 33.49	4,768,155 114,150 (75,885) (1,079,400) 3,727,020
Granted Exercised Forfeited Outstanding Options March 31, 2002	25.68 26.94 32.74 32.01	824,750 (24,665) (560,109) 3,966,996

At March 31, 2002, options for 2,773,244 ScottishPower ADS were exercisable with a weighted average exercise price of $34.14 per share. The weighted average life of the options outstanding at March 31, 2002 was six years. At March 31, 2001, options for 2,496,389 ScottishPower ADS were exercisable with a weighted average exercise price of $35.43 per share. The weighted average life of the options outstanding at March 31, 2001 was six years.

100

As permitted by SFAS No. 123, the Company has elected to account for these options under APB No. 25. Accordingly, no compensation expense has been recognized for these options. Had the Company determined compensation cost based on the fair value at the grant date for all stock options vesting in each period under SFAS No. 123, the Company's net income would have been reduced to the pro forma amounts below:

(Millions of dollars)	Years Ended March 31,
(Millions of dollars)	2002	2001	2000
Net income (loss) as reported Pro forma	$327.3 $325.1	$(88.2) $(91.6)	$83.7 $78.9

The fair value of options granted was $3.4 million, $0.4 million and $14.0 million in 2002, 2001 and 2000, respectively. The fair value of each option grant was estimated on the date of grant using the Black-Scholes option-pricing model with the following assumptions used:

	2002	2001	2000
Dividend yield Risk-free interest rate Volatility Expected life of the options (years)	6.7% 4.8% 30.0% 5	6.4% 4.9% 23.5% 10	5.0% 5.0% 30.0% 10

NOTE 18 - Concentration Of Customers

During 2002, no single retail customer accounted for more than 1.4% of the Company's Domestic Electric Operations' retail utility revenues and the 20 largest retail customers accounted for 13.8% of total retail electric revenues. The geographical distribution of the Company's Domestic Electric Operations' retail operating revenues for the year ended March 31, 2002 was Utah, 39.1%; Oregon, 32.5%; Wyoming, 12.6%; Washington, 7.9%; Idaho, 5.6%; and California, 2.3%.

NOTE 19 - Segment Information

The Company operated in two business segments (excluding other and discontinued operations): Domestic Electric Operations and Australian Electric Operations. The Company identified the segments based on management responsibility within the United States and Australia. Domestic Electric Operations includes the regulated retail and wholesale electric operations in the six western states in which it operates. Australian Electric Operations included the deregulated electric operations in Australia. Other Operations consisted of PFS, the western energy trading activities and other energy development businesses, as well as the activities of Holdings, including financing costs. Holdings and its subsidiaries, including PFS, were transferred to PHI in February 2002 as discussed in Note 4.

101

(Millions of dollars)	Total Company	Domestic Electric Operations	Australian Electric Operations	Discontinued Operations	Other Operations & Eliminations
Year ended March 31, 2002 Net sales and revenue (all external) Depreciation and amortization Interest expense Interest income Income tax expense Income from continuing operations Gain from discontinued operations Cumulative effect of accounting change Total assets Investments in nonconsolidated affiliates Capital spending	$ 4,259.2 403.0 227.7 23.6 176.1 293.4 146.7 (112.8) 10,671.3 11.0 505.3	$ 4,246.6 401.3 233.3 5.0 138.6 245.5 - (112.8) 10,671.3 11.0 505.3	$ - - - - - 27.4 - - - - -	$ - - - - - - 146.7 - - - -	$ 12.6 1.7 (5.6) 18.6 37.5 20.5 - - - - -
Year ended March 31, 2001 Net sales and revenue (all external) Depreciation and amortization Interest expense Interest income Losses of nonconsolidated affiliates Income tax expense (Loss) income from continuing operations Total assets Investments in nonconsolidated affiliates Capital spending	$ 5,056.7 429.0 290.4 31.6 (1.4) 180.4 (88.2) 11,133.8 7.2 491.0	$ 4,535.2 389.0 252.3 9.6 - 87.6 128.0 11,050.7 7.0 376.1	$ 399.3 36.4 37.5 - (1.4) 15.3 (187.2) - - 47.7	$ - - - - - - - - - -	$ 122.2 3.6 0.6 22.0 - 77.5 (29.0) 83.1 0.2 67.2
Year ended March 31, 2000 Net sales and revenue (all external) Depreciation and amortization Interest expense Interest income Losses of nonconsolidated affiliates Income tax expense (benefit) Income from continuing operations Income from discontinued operations Total assets Investments in nonconsolidated affiliates Capital spending	$ 3,986.9 441.3 341.4 17.1 (2.6) 134.0 82.6 1.1 12,305.1 116.0 578.0	$ 3,292.2 379.9 268.1 5.0 - 125.2 29.8 - 11,243.3 6.1 510.0	$ 617.6 57.9 58.4 - (2.6) 24.1 39.0 - 1,781.0 106.9 66.0	$ - - - - - - - 1.1 - - -	$ 77.1 3.5 14.9 12.1 - (15.3) 13.8 - (719.2) 3.0 2.0

102

SELECTED FINANCIAL INFORMATION (UNAUDITED)

(Millions of dollars, except per share and employee amounts)	Years Ended March 31,			Three Months Ended March 31,			Years Ended December 31,
	2002	2001	2000		1999			1998	1997
Revenues Domestic Electric Operations Australian Electric Operations Other Operations (a) Total	$4,246.6 - 12.6 $4,259.2	$4,535.2 399.3 122.2 $5,056.7	$3,292.2 617.6 77.1 $3,986.9		$ 807.2 147.0 5.6 $ 959.8			$4,845.1 614.5 120.8 5,580.4	$3,706.9 716.2 125.8 $4,548.9
Income (Loss) from Operations Domestic Electric Operations Australian Electric Operations Other Operations (a) Total Net (Loss) Income	$ 622.5 27.4 15.0 $ 664.9 $ 327.3	$ 454.1 (133.1) 19.8 $ 340.8 $ (88.2)	$ 587.8 125.1 (7.8) $ 705.1 $ 83.7		$ 195.6 34.8 (2.9) $ 227.5 $ 91.3			$ 571.8 114.5 (5.5) $ 680.8 $ (36.1)	$ 601.3 150.5 58.9 $ 810.7 $ 663.7
Earnings Contribution (Loss) Continuing operations Domestic Electric Operations Australian Electric Operations Other Operations (a) Total Discontinued operations (b) Cumulative effect of accounting change (c) Extraordinary item (d) Total	$ 232.8 27.4 20.5 280.7 146.7 (112.8) - $ 314.6	$ 110.1 (187.2) (29.0) (106.1) - - - $ (106.1)	$ 10.9 39.0 13.8 63.7 1.1 - - $ 64.8		$ 75.4 10.4 0.7 86.5 - - - $ 86.5			$ 130.5 13.0 (52.2) 91.3 (146.7) - - $ (55.4)	$ 165.5 54.2 (9.6) 210.1 446.8 - (16.0) $ 640.9
Common dividends declared per share	$ 0.81	$ 1.31	$ 0.58		$ 0.27			$ 1.08	$ 1.08
Common dividends paid per share	1.00	1.12	0.85		0.27			1.08	1.08
	March 31,						December 31,
	2002	2001	2000					1998	1997
Capitalization Short-term debt Long-term debt Preferred Securities of Trusts Junior subordinated debentures Redeemable preferred stock Preferred stock Common equity Total Total Assets Total Employees	$ 321.0 3,553.8 341.5 - 74.2 41.3 2,891.9 $ 7,223.7 $10,671.3 6,287	$ 291.7 2,906.9 341.2 - 175.0 41.5 3,414.4 $ 7,170.7 $11,133.8 6,626	$ 295.9 4,045.7 340.9 175.8 175.0 41.5 3,879.9 $ 8,954.7 $12,305.1 8,832			$ 559.8 4,383.5 340.5 175.8 175.0 66.4 3,956.3 $ 9,657.3 $12,988.5 9,120			$ 554.6 4,237.2 340.4 175.8 175.0 66.4 4,320.9 $ 9,870.3 $13,627.0 10,087

(a) Other Operations includes the operations of PPM and PKE until their transfer in March 2001, Pacific Generation Company ("PGC"), a wholly-owned subsidiary of the Company until its sale in December 1997, and PFS, as well as the activities of Holdings, including financing costs, and elimination entries, until their transfer in February 2002.

(b) 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. The 2000 amount represents discontinued operations of TPC.

(c) Represents the effect of implementation of SFAS 133.

(d) Extraordinary item included a regulatory asset impairment pertaining to generation resources that were allocable to operations in California and Montana.

103

DOMESTIC ELECTRIC OPERATIONS (UNAUDITED)

(Millions of dollars, except as noted)	Years Ended March 31,			Three Months Ended March 31, 1999	Years Ended December 31,		2002 to 2001 Percentage Comparison	5-Year Compound Annual Growth
(Millions of dollars, except as noted)	2002	2001	2000	Three Months Ended March 31, 1999	1998	1997	2002 to 2001 Percentage Comparison
Revenues Residential Commercial Industrial Other Retail sales Wholesale sales Other Total	$ 901.7 747.7 705.1 34.5 2,389.0 1,684.7 172.9 4,246.6	$ 852.1 710.5 730.1 32.5 2,325.2 2,078.1 131.9 4,535.2	$ 798.7 667.2 694.5 30.4 2,190.8 1,029.1 72.3 3,292.2	$ 231.2 159.0 151.8 7.2 549.2 240.0 18.0 807.2	$ 806.6 653.5 705.5 30.2 2,195.8 2,583.6 65.7 4,845.1	$ 814.0 640.9 709.9 31.7 2,196.5 1,428.0 82.4 3,706.9	5.8% 5.2 (3.4) 6.2 2.7 (18.9) 31.1 (6.4)	2.1% 3.1 (0.1) 1.7 1.7 3.4 16.0 2.8
Expenses Purchased power Fuel Other operations and maintenance Administrative and general Depreciation and amortization Taxes, other than income taxes Unrealized gain on SFAS No. 133 - derivative instruments Special charges Operating expenses Other operating income Total	2,038.8 490.9 560.6 245.6 401.3 90.7 (182.8) - 3,645.1 (21.0) 3,624.1	2,478.4 491.0 534.8 121.0 389.0 97.5 - - 4,111.7 (30.6) 4,081.1	957.9 512.3 554.2 200.8 379.9 99.3 - - 2,704.4 - 2,704.4^(b)	209.7 126.5 114.0 46.9 88.6 25.9 - - 611.6 - 611.6	2,497.0 506.6 461.4 233.9 353.5 97.5 - 123.4 4,273.3 - 4,273.3	1,296.5 486.2 473.6 227.8 353.5 97.6 - 170.4 3,105.6 - 3,105.6	(17.7) - 4.8 103.0 3.2 (7.0) * - (11.3) (31.4) (11.2)	9.5 0.2 3.4 1.5 2.6 (1.5) * * 3.2 * 3.1
Income from Operations Interest expense Interest capitalized Merger costs Minority interest and other Income tax expense Income before cumulative effect of accounting change Cumulative effect of accounting change Net Income	622.5 233.3 (6.9) - 12.0 138.6 245.5 (112.8) 132.7	454.1 252.3 (12.9) 9.3 (10.2) 87.6 128.0 - 128.0	587.8 268.1 (20.2) 190.5 (5.6) 125.2 29.8 - 29.8	195.6 71.0 (3.4) - (6.0) 53.8 80.2 - 80.2	571.8 319.1 (14.5) 13.2 1.3 102.9 149.8 - 149.8	601.3 319.0 (12.2) - (5.8) 112.0 188.3 - 188.3	37.1 (7.5) (46.5) * * 58.2 91.8 * 3.7	0.7 (6.1) (10.8) * * 4.4 5.4 * (6.8)
Preferred Dividend Requirement Earnings Contribution (c)	(12.7) $ 120.0	(17.9) $ 110.1	(18.9) $ 10.9	(4.8) $ 75.4	(19.3) $ 130.5	(22.8) $ 165.5	(29.1) 9.0	(11.0) (6.2)
Total assets Capital spending	$10,671.3 $ 505.3	$11,050.7 $ 376.1	$11,243.3 $ 510.0		$12,051.8 $ 539.0	$12,740.7 $ 490.0	(3.4) 34.4	1.2 0.6

*Not a meaningful number.

(a)  Includes a $43.5 million asset write-back from receipt of a regulatory order and a $13.9 million loss on the sale of the Centralia plant and mine.

(b)  Includes Merger costs of $16.0 million.

(c)  Does not reflect elimination of interest on intercompany borrowing arrangements and includes income taxes on a separate-company basis.

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DOMESTIC ELECTRIC OPERATIONS STATISTICS (UNAUDITED)

	Years Ended March 31,			Three Months Ended March 31, 1999	Years Ended December 31,		2002 to 2001 Percentage Comparison	5-Year Compound Annual Growth
	2002	2001	2000	Three Months Ended March 31, 1999	1998	1997	2002 to 2001 Percentage Comparison	5-Year Compound Annual Growth
Energy Sales (Thousands of MWh) Residential Commercial Industrial Other Retail sales Wholesale sales Total	13,395 13,810 19,611 711 47,527 24,438 71,965	13,455 13,634 20,659 705 48,453 27,502 75,955	13,028 12,827 20,488 663 47,006 34,327 81,333	3,773 2,993 4,627 153 11,546 9,636 21,182	12,969 12,299 20,966 651 46,885 94,077 140,962	12,902 11,868 20,674 705 46,149 59,143 105,292	(0.4)% 1.3 (5.1) 0.9 (1.9) (11.1) (5.3)	0.8% 3.1 (1.1) 0.2 0.6 (16.2) (7.3)
Energy Source Coal Hydroelectric Other Purchase and exchange contracts Total	62.6% 4.9 0.2 32.3 100.0%	56.0% 4.0 4.0 36.0 100.0%	58.0% 7.0 3.0 32.0 100.0%	54.0% 8.0 3.0 35.0 100.0%	51.0% 6.0 2.0 41.0 100.0%	43.0% 5.0 2.0 50.0 100.0%	11.8 22.5 (95.0) (10.3)	7.8 (0.4) (36.9) (8.4)
Number of Retail Customers (Thousands) Residential Commercial Industrial Other Total	1,296 182 35 4 1,517	1,278 179 35 4 1,496	1,252 174 35 4 1,465	1,233 169 35 5 1,442	1,255 174 36 5 1,470	1,228 170 36 4 1,438	1.4 1.7 - - 1.4	1.1 1.4 (0.6) - 1.1
Residential Customers Average annual usage (kWh) Average annual revenue per customer Revenue per kWh	10,411 $ 701 $0.67	10,614 $ 672 $0.63	10,463 $ 641 $0.61		10,443 $ 650 $0.62	10,644 $ 672 $0.63
Miles of Line Transmission Distribution -- overhead -- underground	14,900 43,800 12,500	14,900 43,700 11,900	14,900 43,600 10,900		15,000 45,000 10,000	15,000 45,000 10,000	- 0.2 5.0	(0.1) (0.5) 4.6
System Peak Demand (MW) Net system load (a) -- summer -- winter Total firm load (b) -- summer -- winter	7,899 7,688 10,029 9,511	8,056 7,475 10,115 9,592	7,570 7,115 10,494 10,622		7,666 7,909 11,629 12,301	7,110 7,403 10,871 10,830	(5.6) (2.9) (0.9) (0.8)	1.4 (0.4) (1.6) (2.6)
System Capability (megawatts) (c) -- summer -- winter	11,015 11,050	11,327 11,270	13,457 13,184		12,632 13,427	12,343 12,618	(2.8) (2.0)	(2.2) (2.6)

(a)  Excludes off-system sales.

(b)  Includes firm off-system sales.

(c)  Generating capability, short-term and long-term firm purchases at time of firm peak.

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AUSTRALIAN ELECTRIC OPERATIONS (UNAUDITED)(a)

(Millions of dollars, except as noted)	Years Ended March 31,			Three Months Ended March 31,	Years Ended December 31,
(Millions of dollars, except as noted)	2002	2001(b)	2000(b)	1999	1998	1997
Revenue Expenses Purchased power Other operations and maintenance Administrative and general Depreciation and amortization Taxes, other than income taxes Total (Gain) loss on sale of Australian electric operations Income (loss) from Operations Interest expense Equity in losses of HazelwoodOther (income) expense - net Income tax expense Earnings (loss) Contribution	$ - - - - - - - (27.4) 27.4 - - - - $ 27.4	$ 399.3 157.6 65.9 54.1 36.4 0.8 314.8 217.6 (133.1) 37.5 1.4 (0.1) 15.3 $(187.2)	$ 617.6 260.0 104.3 68.8 57.9 1.5 492.5 - 125.1 58.4 2.6 1.0 24.1 $ 39.0	$ 147.0 59.0 25.2 12.5 15.2 0.3 112.2 - 34.8 14.4 3.7 (0.1) 6.4 $ 10.4	$ 614.5 255.0 140.1 45.7 58.2 1.0 500.0 - 114.5 57.9 5.5 30.4 7.7 $ 13.0	$ 716.2 308.5 134.0 54.9 67.1 1.2 565.7 - 150.5 63.5 2.9 (2.4) 32.3 $ 54.2
Total assets Capital spending	$ - $ -	$ - $ 47.7	$1,781.0 $ 66.0		$1,663.6 $ 75.0	$1,794.2 $ 84.0

(a) Results of operations are included until the dates of disposal, September 6, 2000 for Powercor and November 17, 2000 for Hazelwood.

(b) Australian Electric Operations' financial results for the period from January 1, 2000 to the dates of sale are included in the Company's financial results for the year ended March 31, 2001. Australian Electric Operations' financial results for the year ended December 31, 1999 are included in PacifiCorp's consolidated results for the year ended March 31, 2000. See Note 1.

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OTHER OPERATIONS (UNAUDITED)

Other Operations include the operations of PFS, PGC, the western United States energy trading activities of PPM and several start-up-phase ventures, as well as the activities of Holdings, including financing costs. PGC assets were sold on November 5, 1997 and a majority of the real estate assets of PFS were sold during May 1998. The Company transferred its interest in two non-utility energy companies to an affiliated entity, PHI, in March 2001 and transferred its interest in Holdings to PHI in February 2002.

	Years Ended March 31,			Three Months Ended March 31,	Years Ended December 31,
(Millions of dollars)	2002	2001	2000	1999	1998	1997
Earnings (loss) Contribution PFS PGC Net gain on swap settlement and debt repayment expense Holdings and other Total	$ 21.7 - - (1.2) $ 20.5	$ (30.9) - 19.9 (18.0) $ (29.0)	$ 15.5 - - (1.7)(a) $ 13.8	$ (0.4) - - 1.1 $ 0.7	$ 8.1 - - (60.3) $(52.2)	$ 30.2 10.4 - (50.2) $ (9.6)
Total Assets PFS Holdings and other Total	$ - - $ -	$ 341.2 (258.1) $ 83.1	$ 427.0 (1,146.2) $ (719.2)		$ 423.3 (1,150.2) $ (726.9)	$ 699.0 (1,606.9) $ (907.9)
Capital spending	$ -	$ 67.2	$ 2.0		$ 53.0	$ 140.0

(a) Includes $3.1 million in Merger costs for the year ended March 31, 2000.

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SUPPLEMENTAL INFORMATION

QUARTERLY FINANCIAL DATA (UNAUDITED)

	Quarters Ended
(Millions of dollars, except per share amounts)	June 30	September 30	December 31	March 31
2002 Revenues Income from operations Income (loss) from continuing operations Discontinued operations Cumulative effect of accounting change Net income (loss) Earnings (loss) on common stock Common dividends declared per share Common dividends paid per share	$1,281.6 301.7(a) 164.3 146.7 (112.8) 198.2 193.8 $ 0.27 0.46	$1,244.2 5.5 (30.2) - - (30.2) (34.6) $ 0.27 0.27	$ 884.8(b) 131.0 46.3 - - 46.3 44.4 $ - -	$ 848.6(b) 226.7 113.0 - - 113.0 111.0 $ 0.27 0.27
2001 Revenues (Loss) income from operations Net (loss) income (Loss) earnings on common stock Common dividends declared per share Common dividends paid per share	$1,029.5 (23.7)(c) (134.7) (139.3) $ 0.77 0.50	$1,431.9 139.5(d) 52.7 48.1 $ 0.27 0.27	$1,360.3 75.2 (e) (7.6)(f) (12.1) $ 0.27 0.27	$1,235.0 149.8(g) 1.4(h) (2.8) $ - 0.08

(a)  Includes $178.1 million gain on application of SFAS No. 133 and $27.4 million gain on the sale of the Australian Electric Operations.

(b)  Short term and spot market Wholesale sales averaged $34.2 per MWh in the third quarter of 2002 compared to $105.3 per MWh in 2001 and averaged $24.6 per MWh in the fourth quarter of 2002 compared to $180.8 per MWh in 2001.

(c)  The Company recorded an impairment of $188.4 million after-tax in anticipation of the loss on the sale of the Company's indirect ownership of Powercor and the Company's 19.9% interest in Hazelwood. See Note 14.

(d)  The Company established $25.0 million in regulatory assets resulting from successful resolution of previously denied costs addressed in the Utah rate order received in May 2000. The Company recorded an additional loss of $8.3 million after-tax upon the completion of the sale of its indirect ownership of Powercor. See Notes 3 and 14.

(e)  Increases in purchased power expenses exceeded the increases in revenues by $137.1 million. Purchased power expense increased as a result of the continuing increase in demand, generation outages and lower hydro generation. This increase is net of $16.0 million of accounting deferrals received from the Wyoming Commission for power cost variances.

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(f)  The Company reversed $28.0 million in alternative fuel tax credits because its tax liability was not sufficient to utilize those credits.

(g)  Increases in purchased power expense exceeded the increases in revenues by $26.8 million net of accounting deferrals of $123.0 million pretax relating to accounting orders received from the commissions in Utah, Oregon, Wyoming, and Idaho for power cost variances. See Note 3.

(h)  Includes a $66.2 million tax reserve relating to reevaluation of tax liabilities from settled and ongoing tax examinations.

A significant portion of the operations are of a seasonal nature. 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.

See Note 4 for information regarding discontinued operations.

On March 31, 2002, there was one common shareholder of record.

ITEM 9.  CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
         FINANCIAL DISCLOSURE

No information is required to be reported pursuant to this item.

PART III

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

The following is a list of directors of the Company as of March 31, 2002.

Ian M. Russell, (49). Chairman of the Board of the Company. Director since November 1999.

Mr. Russell was appointed Chief Executive of ScottishPower and Chairman of PacifiCorp in April 2001. He previously served as Deputy Chief Executive of ScottishPower since November 1998, having previously been appointed Finance Director of ScottishPower in April 1994 and serving in both capacities from November 1998 to December 1999. In his present capacity, he is responsible for UK and US operations.

Judith A. Johansen, (43). President and Chief Executive Officer of the Company. Director since December 2000.

Ms. Johansen was elected President and Chief Executive Officer on June 4, 2001 and served as Executive Vice President since December 1, 2000. She was Administrator and Chief Executive Officer of the BPA in Portland, Oregon from June 1998 to November 2000. From 1996 to May 1998, Ms. Johansen was vice president of business development with Avista Energy and from 1994 to 1996 was BPA's vice president for generation supply.

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Nolan E. Karras, (57). Director since February 1993.

Mr. Karras is President of The Karras Company, Inc., investment advisers, Roy, Utah, and has served in that capacity since 1983. He is Chief Executive Officer of Western Hay Company, Inc., and a non-executive director of Beneficial Life Insurance Company and American General Savings Bank. He also served as a Member of the Utah House of Representatives from 1981 to 1990, and as Speaker of the Utah House of Representatives from 1989 to 1990.

William D. Landels, (59). Executive Vice President of the Company. Director since November 1999.

Mr. Landels has been with ScottishPower since 1985. He was elected Executive Vice President and Director of the Company effective upon the Merger with ScottishPower in November 1999. Prior to that, he served with the ScottishPower Group in various senior management roles, including as Managing Director of Manweb, Managing Director of Energy Supply, and Managing Director of Distribution.

Andrew N. MacRitchie, (38). Executive Vice President of the Company. Director since May 2000.

Mr. MacRitchie was elected Executive Vice President in May 2000. Mr. MacRitchie has been with ScottishPower since 1986. He served as the Transition Director for the PacifiCorp Merger from December 1999 to May 2000. He served as ScottishPower's U.S. Chief of Staff on the PacifiCorp Merger from December 1998 to December 1999 and, prior to that, he served as Manager, Business and Organizational Development.

Michael J. Pittman, (49). Senior Vice President of the Company. Director since May 2000.

Mr. Pittman was elected a Senior Vice President of the Company in May 2000. He formerly served as a Vice President of the Company from May 1993. Mr. Pittman is Chair of the PacifiCorp Foundation and a Director of PacifiCorp Investment Management Inc.

Kenneth L. Vowles, (60). Director since November 1999.

Mr. Vowles joined ScottishPower in September 1990 and was appointed to the ScottishPower Board in September 1994. He is currently the international executive director of ScottishPower, the Chairman of Manweb and a non-executive director of Mining Scotland Limited. Mr. Vowles retired on March 31, 2002.

A. Richard Walje, (50). Senior Vice President of the Company. Director since July 2, 2001.

Mr. Walje was named PacifiCorp's Vice President and Chief Information Officer in May 2000 and Senior Vice President of Corporate Business Services in May 2001. Mr. Walje also served as PacifiCorp's vice president for T&D operations and customer service from 1998 to 2000. Mr. Walje also serves on the PacifiCorp Foundation Board of Directors and Junior Achievement's Board of Directors.

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Matthew R. Wright, (37). Executive Vice President of the Company. Director since July 2, 2001.

Mr. Wright was appointed Executive Vice President of Power Delivery in January 2002. Mr. Wright served as Senior Vice President of Strategy and Planning in 2001 and as Vice President of Regulation from 1999 to 2001. Prior to joining PacifiCorp, Mr. Wright served the ScottishPower group in various management positions since 1995.

The following is a list of the executive officers of the Company not named above. There are no family relationships among the executive officers of the Company. Officers of the Company are normally elected annually.

Barry G. Cunningham, (57). Senior Vice President since March 2002.

Mr. Cunningham was named PacifiCorp's Senior Vice President of Generation in March 2002. Mr. Cunningham joined PacifiCorp in 1977 and served as vice president from 1999 to 2002 and as assistant vice president from 1998 to 1999. From 1996 to 1998, Mr. Cunningham served as Vice President and General Manager of PacifiCorp Kentucky Energy Company.

Donald N. Furman, (45). Senior Vice President since July 2001.

Mr. Furman was named PacifiCorp's Senior Vice President of Regulation and Government Affairs in July 2001. Mr. Furman served as vice president of Transmission and domestic business development from 1997 to 2001 and as President of PacifiCorp Power Marketing Inc. from 1995 to 1997.

Andrew P. Haller, (50). Senior Vice President, General Counsel and Corporate Secretary since December 2000.

Mr. Haller was chief executive for the U.S. operations of Kvaerner Process prior to joining PacifiCorp. Mr. Haller began his career with Kvaerner in 1987, and held various senior counsel and management positions, including Senior Vice President of Chemicals, Polymers and Hydrocarbons-Americas. From 1998 to 1999, he served as the Associate General Counsel for the parent company, Kvaerner ASA, in its U.S. corporate headquarters.

Geoffrey O. Huggins, (39). Vice President and Principal Financial Officer of the Company since October 2001.

Mr. Huggins joined PacifiCorp in November of 2000 as Vice President of Finance. He was elected Principal Financial Officer on October 12, 2001. Prior to joining PacifiCorp, Mr. Huggins was a partner with Deloitte & Touche LLP where he worked for 12 years as a Certified Public Accountant.

Robert A. Klein, (54). Senior Vice President, since July 2001.

Mr. Klein was named Senior Vice President of Commercial and Trading in July 2001. Prior to joining the Company in December 2000 as Vice President of Mid-Office, he served as Chief Technology Officer, Senior Vice President and

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General Manager of Equitable Energy from 1998 to 2000. Mr. Klein also served as Vice President of Risk Control and Analysis for Coral Energy from 1997 to 1998 and Vice President and Chief Operating Officer of PRIMO Systems from 1994 to 1997.

Robert Moir, (52). Senior Vice President since July 2001.

Mr. Moir was named PacifiCorp's Senior Vice President of Distribution in February 2002. Mr. Moir served as vice president since May 2000. Mr. Moir has been with ScottishPower since 1967.

Bruce N. Williams, (43). Treasurer since February 2000.

Mr. Williams has been with PacifiCorp since 1985. Prior to being elected Treasurer, he served as Assistant Treasurer of the Company.

ITEM 11. EXECUTIVE COMPENSATION

BOARD REPORT ON EXECUTIVE COMPENSATION

INTRODUCTION

This Board report on executive compensation covers the period that began April 1, 2001 and ended March 31, 2002. Where historical periods are mentioned, they refer to the 12-month periods ended March 31.

The PacifiCorp Board of Directors has the responsibility to recommend compensation levels and executive compensation plans for officers of PacifiCorp, to the Remuneration Committee of the Board of ScottishPower and to administer executive compensation plans as authorized. The Remuneration Committee of the Board of ScottishPower is comprised entirely of independent, non-employee directors. Any stock based compensation must be approved by the Board of ScottishPower. The following Board report describes the components of PacifiCorp's executive compensation program and the basis upon which recommendations and determinations were made for the period from April 1, 2001 to March 31, 2002.

COMPENSATION PHILOSOPHY

PacifiCorp's philosophy is that executive compensation should be linked closely to corporate performance and increases in shareholder value. PacifiCorp's compensation program has the following objectives:

  .  Provide competitive total compensation that enables PacifiCorp to attract
     and retain key executives.

  .  Provide variable compensation opportunities that are linked to company
     and individual performance.

  .  Establish an appropriate balance between incentives focused on short-term
     objectives and those encouraging sustained earnings performance and
     increases in shareholder value.

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Qualifying compensation for deductibility under Internal Revenue Code ("IRC") Section 162(m) is one of the factors the Board considers in designing its incentive compensation arrangements. IRC Section 162(m) limits to $1,000,000 the annual deduction by a publicly held corporation of compensation paid to any executive, except with respect to certain forms of incentive compensation that qualify for exclusion. Although it is the Board's intent to design and administer compensation programs that maximize deductibility, the Board views the objectives outlined above as more important than compliance with the technical requirements necessary to exclude compensation from the deductibility limit of IRC Section 162(m). Nevertheless, the Board believes that nearly all compensation paid to the executive officers for services rendered in the year ended March 31, 2002 is fully deductible, with the exception of severance compensation paid to certain former executives.

COMPENSATION PROGRAM COMPONENTS

The Board, assisted by its outside consultant, evaluates the total compensation package of executives (excluding ScottishPower executives on international assignment) annually in relation to competitive pay levels.

In the year ended March 31, 2002, the Board focused its market-based comparisons on the relevant industry for each officer. The Board utilized the electric utility industry as its exclusive basis for market comparison for positions with a principal focus on electric operations. For positions with a corporate-wide focus, the Board used a weighting of approximately 67.0% general industry and 33.0% electric utility industry. In all cases, compensation is targeted at market median levels, with a recognition that total compensation greater than market median, in any specific time period, anticipates that Company performance exceed the median performance of peer companies.

PacifiCorp's executive compensation programs have three principal elements: base salary, annual incentive compensation and long term incentive compensation, as described below.

Base Salaries

Base salaries and target incentive amounts are reviewed for adjustment at least annually based upon competitive pay levels, individual performance and potential, and changes in duties and responsibilities. Base salary and the incentive target are set at a level such that total annual compensation for satisfactory performance would approximate the midpoint of pay levels in the comparison group used to develop competitive data. In the year ended March 31, 2002, the base salaries of executive officers were increased, based on market analysis, to reflect competitive market changes and changes in the responsibilities of some officers.

Annual Incentives

All corporate officers (except ScottishPower executives on international assignment), including those listed in the Summary Compensation Table (other than Mr. Richardson), participated in the PacifiCorp Annual Incentive Program. The performance goals for 2002 were weighted 50.0% either Company earnings

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before interest and taxes or ScottishPower Earnings per Share ("EPS") and 50.0% individual performance.

Long-Term Incentives

Historically, the PacifiCorp Board annually reviewed and approved grants of restricted stock and stock options under the Stock Incentive Plan. However, on November 29, 2001, the Stock Incentive Plan expired. Future Long-term incentives, if any, will be approved by the Remuneration Committee of the Board of ScottishPower. Restricted stock and stock option awards made under the Stock Incentive Plan on or before April 24, 2001, will continue to remain outstanding until such time as they become vested or expire.

In determining restricted stock awards granted under the Stock Incentive Plan, the Board considered criteria such as:

  .  total shareholder return relative to peer companies;
  .  financial growth over time relative to peer companies; and
  .  other factors such as achievement of long-term goals, strategies
     and plans.

The Board approved grants of stock options based upon competitive award levels. Restricted stock awards under the Stock Incentive Plan are subject to terms, conditions and restrictions as may be determined by the Board to be consistent with the plan and the best interests of the shareholders. The restrictions include stock transfer restrictions and forfeiture provisions designed to facilitate the participants' achievement of specified stock ownership goals. Participants are also required to invest their own personal resources in ScottishPower ADS or ordinary shares ("Ordinary Shares") in order to meet the vesting requirements associated with these grants. The Summary Compensation Table below shows the grants of restricted stock made to the listed executive officers under the Stock Incentive Plan in 2002, 2001 and 2000.

All stock options awarded to officers and senior management of PacifiCorp in 2002, 2001 and 2000 are non-statutory, non-discounted options with a three-year vesting requirement and a ten-year term from the date of the grant.

SCOTTISHPOWER EXECUTIVE OFFICERS ON INTERNATIONAL ASSIGNMENT

Executive officers who are international assignees from ScottishPower are maintained on their home country remuneration program. The compensation for these individuals is determined by the ScottishPower Remuneration Committee, which consists solely of independent non-executive directors.

The ScottishPower Remuneration Committee is responsible for ensuring that the remuneration arrangements for executives attract and retain executives of high quality, who have the requisite skills and are given the incentive to achieve performance which exceeds that of ScottishPower's competitors. Furthermore, the Committee's objective is to ensure that incentive schemes are in line with best practice and promote the interests of shareholders.

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The Remuneration Committee believes that to attract and retain key executives of high caliber, the remuneration package it offers must be market-competitive. The remuneration strategy is to adopt a mid-market position on all senior management remuneration packages, and to provide packages above the mid-market level only where supported by demonstrably superior personal performance.

In setting remuneration levels, the Remuneration Committee commissioned an independent evaluation of the roles of the executives, and also of the next levels of management within ScottishPower. The Committee has also continued to take independent advice from external remuneration consultants on market-level remuneration, based on comparisons with companies of similar size and complexity. In considering the comparable companies, the consultants have included a number of other utilities, but have not restricted their study solely to utilities.

After careful consideration, the Remuneration Committee is confident that the remuneration policy stated for ScottishPower is appropriate. In line with its objectives to build an international energy business, ScottishPower has recruited a number of executives with key business skills, and hence a reward structure broadly equivalent to other large UK listed companies with international operations was necessary. The major components of ScottishPower's remuneration programs are described below.

Base Salaries

The Remuneration Committee sets the base salary for each PacifiCorp executive on international assignment by reference to both individual performance through a formal appraisal system, and to external market data, based on the job evaluation principles and reflecting similar roles in other comparable companies.

Annual Performance-Related Bonus

Executives participate in ScottishPower's performance-related pay schemes. All payments under the schemes are non-pensionable and non-contractual and are subject to the approval of the Remuneration Committee.

The 2001-02 scheme for executive directors provided a bonus of a maximum of 75.0% of salary, with half of the bonus determined by ScottishPower's financial performance. The balance of the bonus was linked to each executive's achievement of key strategic objectives, both short-term and long-term. Objectives are set annually and performance against these is reviewed on a six-month basis. Mr. Richardson earned $0, $0 and $160,500 of incentive awards during the performance periods ended March 31, 2002, 2001 and 2000, respectively.

Long Term Incentive Plan

ScottishPower operates a Long Term Incentive Plan ("LTIP") for executives that links the rewards closely between management and shareholders, and focuses on long-term corporate performance.

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Under the current plan, awards to earn shares in ScottishPower are made to the participants up to a maximum value equal to 60.0% of base salary if certain performance measures are met. These measures relate to the sustained underlying financial performance of ScottishPower and customer service standards.

The number of shares that the executive will actually receive is dependent upon ScottishPower's comparative total shareholder return performance over a three-year performance period. For LTIP awards which have vested during the year, this performance is measured against that of the Financial Times Stock Exchange ("FTSE") 100 Index and an index of the Electricity and Water sectors of the FTSE All Share Index. For LTIP awards granted during the year, this performance is measured against a comparable group of international energy companies.

The arrangements provide for a percentage of each half of the award to be earned depending upon ScottishPower's ranking within the relevant comparable group as follows: 100.0% if ScottishPower ranks in the top quartile; and 40.0% if ScottishPower is at median of the comparable group. The percentage is calculated on a straight-line basis between median and upper quartile and no award is made if ScottishPower ranks below median.

For the award that vested during the year, the shares must be held for another year before they may be exercised. The plan participant may elect to receive the shares at any time between the fourth year and the seventh year after the award has been fully earned.

COMPENSATION OF THE CHIEF EXECUTIVE OFFICER

On June 4, 2001, Ms. Johansen assumed responsibilities as Chief Executive Officer and President of PacifiCorp. Ms. Johansen has a base salary of $364,000 and a maximum annual incentive award of 75.0% of base salary. She is also eligible for participation in the Company's Long Term Incentive Program, which consists of restricted ScottishPower ADS and options for ScottishPower ADS. All years referenced are 12-month periods ended March 31.

The Board report on executive compensation detailed above has been submitted by the members of the Board of Directors listed below.

Ian M. Russell, Chairman
Judith A. Johansen
William D. Landels
Andrew N. MacRitchie
Michael J. Pittman
A. Richard Walje
Matthew R. Wright

EXECUTIVE COMPENSATION

The following table sets forth information concerning compensation for services in all capacities to PacifiCorp and its subsidiaries for the years ended March 31, 2002, 2001 and 2000 of those persons who were the Chief Executive Officer of PacifiCorp during any portion of fiscal 2002, the four

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other most highly compensated executive officers of PacifiCorp who were serving as executive officers at the end of the last completed fiscal year and one other individual for whom disclosure would have otherwise been required but for the fact that this individual was no longer an executive officer as of March 31, 2002.

Summary Compensation Table

		Annual Compensation(a)		Long-Term Compensation
Name and Principal Position	Year	Salary (b)	Bonus (c)	Restricted Stock Awards(d)	Securities Underlying Options(e)	LTIP Payout (f)	ScottishPower Performance Share(g)	All Other Compensation (h)
Judith A. Johansen President and Chief Executive Officer Alan V. Richardson Former President and Chief Executive Officer Andrew P. Haller Senior Vice President, General Counsel and Corporate Secretary Michael J. Pittman Senior Vice President A. Richard Walje Senior Vice President Donald N. Furman Senior Vice President Karen Clark Former Senior Vice President and Chief Financial Officer	2002 2001 2000 2002 2001 2000 2002 2001 2000 2002 2001 2000 2002 2001 2000 2002 2001 2000 2002 2001 2000	$360,501 110,834 - 860,832 792,330 190,566 299,425 86,042 - 275,167 249,749 244,250 240,375 214,002 214,341 234,393 208,004 208,337 255,521 327,500 61,818	$ 12,902 150,000 - - - 160,500 8,392 110,000 - 150,008 - 228,853 128,854 - 281,184 113,737 20,000 163,480 163,361 150,000 100,000	$141,683 131,138 - - - - 112,768 104,375 - 53,203 - 72,881 53,203 - 72,772 43,951 - 60,116 130,117 - 142,379	57,350 57,350 - - - - 56,800 56,800 - 13,500 - 121,707 14,000 - 109,329 13,000 - 83,000 - - -	$ - - - - - - 23,644 - - - - - 12,222 13,729 11,717 - - - - - -	- - - 50,223 25,384 18,994 - - - - - - - - - - - - - - -	$ 11,707 3,169 - 531,260 368 - 10,524 2,917 - 20,449 12,813 24,173 19,606 15,724 22,438 18,459 29,640 17,464 174,194 12,941 2,365

___________

(a)  May include amounts deferred pursuant to the Compensation Reduction Plan, under which key executives and directors may defer receipt of cash compensation until retirement or a preset future date. Amounts deferred are invested in ScottishPower ADS or a cash account on which interest is paid at a rate equal to the Moody's Intermediate Corporate Bond Yield for AA rated Public Utility Bonds.

(b)  Includes amounts paid to executive officers in the form of international assignment benefits, including foreign housing allowances. These amounts were $541,332, $424,830 and $65,273 for Mr. Richardson for 2002, 2001 and 2000, respectively.

(c)  Refer to the Board Report on Executive Compensation for a description of PacifiCorp's Annual Incentive Plan. Incentive amounts are reported for the year in which they were received by the executive officers. Amounts in this column for 2002 include a retention bonus in the amount of $125,610, $104,000, and $90,000 for Messrs. Pittman, Walje, and Furman, respectively. Amounts in this column for 2001 include special bonuses and hire-on bonuses. These amounts are $150,000, $150,000, $20,000, and $110,000 for Ms. Johansen, Ms. Clark and Messrs. Furman and Haller, respectively. Amounts in this column for 2000 included a special bonus that was paid upon the closure of the Merger with ScottishPower. These amounts were $46,500 and $125,000 for Messrs. Richardson and Pittman, respectively. In 2000, Ms. Clark received a hire on bonus of $100,000.

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(d)  Awards are restricted stock grants made in January and April of 2001 and February 2000 pursuant to the Stock Incentive Plan. In general, restricted stock awards vest over a four-year period from the date of grant, subject to compliance with the stock ownership and other terms of the grant. On March 31, 2002, the aggregate value of all restricted stock holdings, based on the market value of ScottishPower ADS at March 31, 2002, without giving effect to the diminution of value attributed to the restrictions on such stock, and the aggregate number of restricted share holdings of Ms. Johansen, Ms. Clark and Messrs. Pittman, Walje, Furman and Haller were $175,359, $0, $66,319, $70,041, $53,906 and $139,571, respectively. Regular quarterly dividends are paid on the restricted stock. Participants may defer receipt of restricted stock awards to their stock accounts under the Compensation Reduction Plan.

(e)  Amounts shown for 2000 include a retention stock option award for Messrs. Pittman, Walje and Furman covering 108,207, 95,329, and 70,000 ScottishPower ADS, respectively.

(f)  Represents the restricted stock shares that vested and were distributed to the named officer.

(g)  Represents the number of ScottishPower ordinary performance shares contingently granted in 2002, 2001 and 2000 that can be earned under the terms of the ScottishPower Long Term Incentive Plan.

(h)  Amounts shown for the year ended March 31, 2002 include:

     (i)  During 2002, Mr. Richardson purchased 279 shares under the
     ScottishPower Employee Share Ownership Plan ("ESOP"). Under the
     terms of the plan, ScottishPower matches the number of shares
     bought by the individual. The value of the 279 shares bought by
     ScottishPower, for Mr. Richardson, was $1,793.

     (ii)  Includes benefits-in-kind totaling $1,086 and an additional
     payment of $528,381 according to the terms of Mr. Richardson's
     contract.

     (iii)  Company contributions to the PacifiCorp K Plus Employee Savings
     and Stock Ownership Plan for each of Ms. Johansen, Ms. Clark and
     Messrs. Pittman, Walje, Furman and Haller, were $2,199, $9,559,
     $11,057, $10,273, $9,292, and $1,191, respectively.

     (iv)  Portions of premiums on term life insurance policies that
     PacifiCorp paid for Ms. Johansen, Ms. Clark and Messrs. Pittman,
     Walje, Furman and Haller in the amounts of $508, $432, $392, $333,
     $166 and $333, respectively. These benefits are available to all
     employees.

     (v)  Severance pay for Ms. Clark in the amount of $126,450, plus a
     special retirement benefit of $21,700 and a cash equivalent of
     long-term incentive benefit of $16,053.

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     (vi)  This column also includes vehicle allowances paid to Ms. Johansen,
     Ms. Clark and Messrs. Pittman, Walje, Furman and Haller in the amount
     of $9,000, $8,362, $9,000, $9,000, $9,000 and $9,000, respectively.

Option Grants in Last Fiscal Year

		Individual Grants(a)
	Number of Securities Underlying Options Granted(b)	% of Total Options Granted to Employees in Fiscal Year	Exercise or Base Price (£ or $/Sh)	Expiration Date	Potential Realizable Value at Assumed Annual Rates of Stock Price Appreciation for Option Term
Name					5%	10%
Alan V. Richardson (c) Judith A. Johansen Michael J. Pittman A. Richard Walje Donald N. Furman Andrew P. Haller Karen Clark (d)	124,223 57,350 13,500 14,000 13,000 56,800 46,000	3.76% 6.95 1.64 1.70 1.58 6.89 5.58	£4.83 $25.70 25.70 25.70 25.70 25.70 25.70	8/20/11 4/24/11 4/24/11 4/24/11 4/24/11 4/24/11 4/24/11	£349,239 $922,254 217,095 225,136 209,055 913,409 N/A	£886,706 $2,341,571 551,198 571,613 530,783 2,319,115 N/A

___________

(a)  All options are for ScottishPower ADS, except Mr. Richardson's options, which are for ScottishPower Ordinary Shares.

(b)  All options become exercisable for one-third of the shares covered by the option on each of the first three anniversaries of the grant date, except for Mr. Richardson, whose options become exercisable after the third anniversary of the grant date. The grant date for each option shown in the table above was April 24, 2001, except Mr. Richardson, whose options were granted in August 2001.

(c)  Mr. Richardson's options are quoted as ScottishPower Ordinary Shares. One ScottishPower ADS is equal to four ScottishPower Ordinary Shares. Mr. Richardson's options can only be exercised between the 3rd and 10th anniversary of the date of the grant, and exercise is subject to the satisfaction of a performance condition, that being a pre-determined level of EPS growth over a maximum of a three-year performance period from the date of the grant.

(d)  Upon her termination, Ms. Clark forfeited all of her options granted on April 24, 2001.

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Aggregated Option Exercises in 2002 and Year End Option Values

			Number of Securities Underlying Unexercised Options at March 31 (#)(a)	Value of Unexercised In-the-Money Options at March 31
Name	Shares Acquired on Exercise (#)	Value Realized	Exercisable/ Unexercisable	Exercisable/ Unexercisable
Judith A. Johansen Alan V. Richardson Michael J. Pittman A. Richard Walje Donald N. Furman Andrew P. Haller Karen Clark (b)	- - - - - - 15,333	$ - - - - - - 20,853	0/57,350 - 0/13,500 0/14,000 0/13,000 0/56,800 0/0	$0/$0 - $0/$0 $0/$0 $0/$0 $0/$0 $0/$0

___________

(a)  All options are for ScottishPower ADS, except Mr. Richardson's options, which were for ScottishPower Ordinary Shares.

(b)  Upon her termination, Ms. Clark forfeited all of her options granted on February 16, 2000 and April 24, 2001.

Severance Arrangements

The PacifiCorp Executive Severance Plan provides severance benefits to certain executive level employees who are designated by the PacifiCorp Board, in its sole discretion, including the executive officers named in the Summary Compensation Table. To qualify for severance benefits, the executive must have terminated employment for one of the following reasons:

(1)  voluntary termination as a result of a material alteration in the executive's assignment that has a detrimental impact on the executive's employment. A "material alteration in assignment" includes any of the following:

     (a)  a material reduction in the scope of the executive's duties
     and responsibilities;

     (b)  a material reduction in the executive's authority; or

     (c)  any reduction in base pay or a reduction in annualized base
     salary and target bonus of at least 15.0%, if the change is not due
     to a general reduction unrelated to the change in assignment; or

(2)  involuntary termination (including a Company-initiated resignation) for reasons other than for cause.

In addition, the Executive Severance Plan provides enhanced severance benefits in the event of certain terminations during the 24-month period following a qualifying change-in-control transaction, including the Merger with ScottishPower. Executives designated by the PacifiCorp Board are eligible for

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change-in-control benefits resulting from either a PacifiCorp-initiated termination without "cause", or a resignation generally within two months after a "material alteration of position". During the 24-month protection period under the Severance Plan, "cause" means the executive's gross misconduct or gross negligence or conduct that indicates a reckless disregard for the consequences and has a material adverse effect on PacifiCorp or its affiliates, and "material alteration in position" means the occurrence of any of the following:

(1)  a change in reporting relationship to a lower level;

(2)  a material reduction in the scope of duties and responsibilities;

(3)  a material reduction in authority;

(4)  a "material reduction in compensation"; or

(5)  relocation of executive's work location to an office more than 100 miles from the executive's office or more than 60 miles from the executive's home.

A "material reduction in compensation" occurs when an executive's annualized base salary is reduced by any amount or the annualized base salary and target bonus opportunity combined is reduced by at least 15.0% of the combined total opportunity before the change in compensation.

If qualified for the enhanced severance benefits, an executive would receive severance pay in an amount equal to either two, two and one-half or three times the "annual cash compensation" of such executive, depending on the level set by the Board. "Annual cash compensation" is defined as annualized base salary, target annual incentive opportunity and annualized auto allowance in effect on a material alteration or termination, whichever is greater. If the payment would result in imposition of an excise tax under IRC Section 4999, PacifiCorp is required to make an additional payment to compensate the executive for the effect of such excise tax. The executive would also receive continuation of subsidized health insurance from six to 24 months depending on length of service, and a minimum of 12 months' executive-level outplacement services. Several executives have terminated and qualified to receive change-in-control benefits.

Except in the event of a change-in-control, the definition of cause is determined by PacifiCorp in its discretion and by the Board in the event of an appeal by the employee. The Executive Severance Plan does not apply to the termination of an executive for reasons of normal retirement, death or total disability or to a termination for cause or for voluntary termination other than as specified above. Other than in connection with a change-in-control, executives named in the Summary Compensation Table (excluding Mr. Richardson) are eligible for a severance payment equal to one or two times the executive's total cash compensation, three months of health insurance benefits and outplacement benefits. Total cash compensation is defined as the combination of the annualized base salary, the target annual incentive opportunity and the annualized auto allowance in effect on the earlier of a material alteration or termination. Mr. Richardson left the Company in December 2001.

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Retirement Plans

PacifiCorp and all of its subsidiaries have adopted noncontributory defined benefit retirement plans for their employees, other than employees subject to collective bargaining agreements that do not provide for coverage. Certain executive officers, including the executive officers named in the Summary Compensation Table (other than Mr. Richardson), are also eligible to participate in PacifiCorp's nonqualified supplemental executive retirement plan. The following description assumes participation in both the retirement plans and the supplemental plan. Participants receive benefits at retirement payable for life based on length of service with PacifiCorp or its subsidiaries and average pay in the 60 consecutive months of highest pay out of the last 120 months, and pay for this purpose would include salary and bonuses as reflected in the Summary Compensation Table above. Benefits are based on 50% of final average pay plus up to an additional 15.0% of final average pay depending upon whether PacifiCorp meets certain performance goals set for each fiscal year by the Board. Participants may also elect actuarially equivalent alternative forms of benefits. Retirement benefits are reduced to reflect Social Security benefits as well as certain prior employer retirement benefits. Participants are entitled to receive full benefits upon retirement after age 60 with at least 15 years of service. Participants are also entitled to receive reduced benefits upon early retirement after age 55 or after age 50 with at least 15 years of service and 5 years of participation in the supplemental plan.

The following table shows the estimated annual retirement benefit payable upon retirement at age 60 as of March 31, 2002. Amounts in the table reflect payments from the retirement plans and the supplemental plan combined.

Estimated Annual Pension At Retirement (a)

	Years of Service (b)
Annual Pay at Retirement Date	5	15	25	30
$ 200,000 400,000 600,000 800,000 1,000,000	$ 43,333 86,667 130,000 173,333 216,667	$130,000 260,000 390,000 520,000 650,000	$130,000 260,000 390,000 520,000 650,000	$130,000 260,000 390,000 520,000 650,000

_____________

(a) The benefits shown in this table assume that the individual will remain in the employ of PacifiCorp until retirement at age 60, that the plans will continue in their present form and that PacifiCorp achieves its performance goals under the supplemental plan in all years. Amounts shown do not reflect the Social Security offset.

(b) The number of credited years of service used to compute benefits under the plans for Ms. Johansen and Messrs. Pittman, Walje, Furman and Haller are 1, 23, 17, 8 and 1, respectively.

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Retention Agreements

In order to retain executives who would otherwise have had the right to resign for any reason between 12 and 14 months following the ScottishPower Merger and qualify for the enhanced change-in-control supplemental retirement benefits, the Company has entered into retention agreements with qualifying executives (Messrs. Pittman, Walje and Furman). Those retention agreements provide for the same enhanced supplemental retirement benefits if the qualifying executives satisfy the retention criteria. Qualifying executives were required to waive their rights to unilaterally resign and receive the enhanced supplemental retirement benefits but will be eligible to receive these same enhancements if they either (1) have a subsequent qualifying "involuntarily termination" or "material alteration" in position or (2) continue employment through the established retention date of December 1, 2002.

These retention agreements also require qualifying executives to waive any rights to executive severance benefits which they may have otherwise claimed due to material alterations in their positions as of the date of the retention agreement. Unless there is a subsequent "involuntarily termination" or "material alteration" in position as defined in the Severance Plan, this waiver of severance benefits applies to these executives through November 28, 2004. The executives' waiver of severance benefits was in exchange for the enhanced supplemental retirement benefits described above, retention bonuses determined individually in the Company's discretion for each executive, and special stock option awards that vest over a three-year retention period at 25% for each of the first two years and 50% in the third year.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

All common shares of the Company are indirectly owned by Scottish Power plc, 1 Atlantic Quay, Glasgow, G2 8SP, Scotland. PacifiCorp has no compensation plans under which equity securities of PacifiCorp are authorized to be issued.

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The following table sets forth certain information as of March 31, 2002 regarding the beneficial ownership of ScottishPower Ordinary Shares by (1) each of the executive officers named in the Summary Compensation Table under Item 11 above, (2) each director of PacifiCorp as detailed under Item 10 and (3) all executive officers and directors as a group. As of March 31, 2002, each of the directors and executive officers identified above and all directors and executive officers of the Company as a group owned less than 1% of the outstanding Ordinary Shares of ScottishPower.

Beneficial Owner	Number of shares as at March 31, 2002(a)(b)
Judith A. Johansen Alan V. Richardson Andrew P. Haller Michael J. Pittman A. Richard Walje Donald N. Furman Karen K. Clark (c) Ian M. Russell Nolan E. Karras William D. Landels Andrew N. MacRitchie Matthew R. Wright	50,028 28,554 37,564 116,661 46,461 65,511 16,647 86,817 48,374 38,038 10,743 6,829
All executive officers and directors as a group (18 persons)	779,502

_____________

(a)  Includes ownership of (i) shares held by family members even though beneficial ownership of such shares may be disclaimed, (ii) shares held for the account of such persons pursuant to the PacifiCorp Compensation Reduction Plan and the PacifiCorp K Plus Savings and Stock Ownership Plan, and (iii) shares granted and vested or unvested shares for which the individual has voting but not investment power under the PacifiCorp Stock Incentive Plan.

(b)  Options granted in ScottishPower ADS under the PacifiCorp Stock Incentive Plan have been converted into options in Ordinary Shares in the above table. One ADS equates to four Ordinary Shares.

(c)  Ms. Clark resigned from the Company, effective January 3, 2002. All 7,875 unvested restricted ADS shares were forfeited upon termination.

Between April 1, 2002 and May 24, 2002, there have been no further beneficial entitlements awarded to Ms. Johansen, Ms. Clark, and Messrs. Pittman, Walje, Furman, Haller, Richardson, Russell, Landels, MacRitchie, and Wright.

On May 9, 2001 and May 22, 2001, Mr. Richardson exercised 9,661 and 10,816 respectively, of his vested Ordinary Shares under the LTIP.

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ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

RELATED TRANSACTIONS

According to the terms of Andrew Haller's offer letter, PacifiCorp made a $200,000 loan to Mr. Haller on May 21, 2001, for the repayment of obligations to his former employer. The promissory note documenting such loan includes the following terms: (1) initial payment of $35,000 was due on December 1 and received on December 31, 2001; (2) $50,000 is due on June 1, 2002, $50,000 on June 1, 2003 and $65,000 on June 1, 2004; and (3) interest at an annual rate of 4.71% is charged on the outstanding balance. As of March 31, 2002, the outstanding loan balance was $165,000 plus accrued interest.

All other information required by this item is set forth in Item 11. EXECUTIVE COMPENSATION and in Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT above.

PART IV

ITEM 14.  EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K

(a) 1.  The list of all financial statements filed as a part of this report is included in ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.

    2.  Schedules:*

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*All schedules have been omitted because of the absence of the conditions under which they are required or because the required information is included elsewhere in the financial statements included under ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.

    3.  Exhibits:

Exhibit Number	Exhibit Title
2.1(a)*	Agreement and Plan of Merger, dated as of December 6, 1998, by and among Scottish Power plc, NA General Partnership, Scottish Power NA 1 Limited and Scottish Power NA 2 Limited. (Exhibit 1 to the Form 6-K, dated December 11, 1998, filed by Scottish Power plc, File No. 1-14676).
2.1(b)*	Amended and Restated Agreement and Plan of Merger, dated as of December 6, 1998, as amended as of January 29, 1999 and February 9, 1999, and amended and restated as of February 23, 1999, by and among New Scottish Power PLC, Scottish Power plc, NA General Partnership and PacifiCorp (Exhibit (2)b, Form 10-K for year ended December 31, 1998, File No. 1-5152).
3.1*	Third Restated Articles of Incorporation of the Company (Exhibit (3)b, Form 10-K for the year ended December 31, 1996, File No. 1-5152).
3.2*	Bylaws of the Company effective November 29, 1999 (Exhibit (3)b, Form 10-K for the year ended March 31, 2000, File No. 1-5152).

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Exhibit Number	Exhibit Title
4.1*	Mortgage and Deed of Trust dated as of January 9, 1989, between the Company and Morgan Guaranty Trust Company of New York (The Chase Manhattan Bank, successor), Trustee, Ex. 4-E, Form 8-B, File No. 1-5152 as supplemented and modified by fourteen Supplemental Indentures as follows:
	Exhibit Number	File Type	File Date	File Number
	(4)(b) (4)(a) 4(a) 4(a) 4(a) 4(a) 4(a) 4(a) 4(a) (4)b (4)b (4)b (4)b 99(a)	8-K 8-K 8-K 10-Q 10-Q 8-K 10-Q 10-Q 10-K 10-K 10-K 10-K 8-K	January 9, 1990 September 11, 1991 January 7, 1992 Quarter ended March 31, 1992 Quarter ended September 30, 1992 April 1, 1993 Quarter ended September 30, 1992 Quarter ended September 30, 1993 Quarter ended June 30, 1994 Quarter ended December 31, 1994 Quarter ended December 31, 1995 Quarter ended December 31, 1996 November 21, 2001	33-31861 1-5152 1-5152 1-5152 1-5152 1-5152 1-5152 1-5152 1-5152 1-5152 1-5152 1-5152 1-5152 1-5152
4.2*	Third Restated Articles of Incorporation and Bylaws. See 3.1 and 3.2 above.

In reliance upon item 601(4)(iii) of Regulation S-K, various instruments defining the rights of holders of long-term debt of the Registrant and its subsidiaries are not being filed because the total amount authorized under each such instrument does not exceed 10% of the total assets of the Registrant and its subsidiaries on a consolidated basis. The Registrant hereby agrees to furnish a copy of any such instrument to the Commission upon request.

10.1(a)*	Short-Term Surplus Firm Capacity Sale Agreement executed July 9, 1992 by the United States of America Department of Energy acting by and through the Bonneville Power Administration and Pacific Power & Light Company (Exhibit (10)n, Form 10-K for the year ended December 31, 1992, File No. 1-5152).
10.1(b)*	Restated Surplus Firm Capacity Sale Agreement executed September 27, 1994 by the United States of America Department of Energy acting by and through the Bonneville Power Administration and Pacific Power & Light Company (Exhibit (10)t, Form 10-K for the year ended December 31, 1994, File No. 1-5152).
12.1	Statements of Computation of Ratio of Earnings to Fixed Charges
12.2	Statements of Computation of Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividends
23	Consent of PricewaterhouseCoopers LLP with respect to Annual Report on Form 10-K.
24	Powers of Attorney.

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*Incorporated herein by reference.

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(b)  Reports on Form 8-K.

     The Company filed no reports on Form 8-K during the three months ended March 31, 2002.

(c)  See (a) 3. above.

(d)  See (a) 2. above.

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SIGNATURES

PURSUANT TO THE REQUIREMENTS OF SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934, THE REGISTRANT HAS DULY CAUSED THIS REPORT TO BE SIGNED ON ITS BEHALF BY THE UNDERSIGNED THEREUNTO DULY AUTHORIZED.

PacifiCorp

      /s/JUDITH A. JOHANSEN
By_________________________________
         Judith A. Johansen
          (PRESIDENT AND
      CHIEF EXECUTIVE OFFICER)

Date: May 31, 2002

PURSUANT TO THE REQUIREMENTS OF THE SECURITIES EXCHANGE ACT OF 1934, THIS REPORT HAS BEEN SIGNED BELOW BY THE FOLLOWING PERSONS ON BEHALF OF THE REGISTRANT AND IN THE CAPACITIES AND ON THE DATES INDICATED.

SIGNATURE	TITLE	DATE
*IAN M. RUSSELL ----------------------------------- Ian M. Russell	Chairman	May 31, 2002
/s/JUDITH A. JOHANSEN ----------------------------------- Judith A. Johansen	President, Chief Executive Officer and Director	May 31, 2002
/s/GEOFFREY HUGGINS ----------------------------------- Geoffrey Huggins	Vice President, Principal Financial Officer	May 31, 2002
/s/JUDITH A. JOHANSEN ----------------------------------- Judith A. Johansen NOLAN E. KARRAS ----------------------------------- Nolan E. Karras WILLIAM D. LANDELS ----------------------------------- William D. Landels	) ) ) ) ) ) ) ) Director ) ) ) ) ) ) )	May 31, 2002

128

	TITLE	DATE
ANDREW N. MacRITCHIE ----------------------------------- Andrew N. MacRitchie MICHAEL J. PITTMAN ----------------------------------- Michael J. Pittman A. RICHARD WALJE ----------------------------------- A. Richard Walje MATTHEW R. WRIGHT ----------------------------------- Matthew R. Wright BARRY G. CUNNINGHAM ----------------------------------- Barry G. Cunningham By/s/JUDITH A. JOHANSEN ----------------------------------- Judith A. Johansen, as Attorney-in-Fact	) ) ) ) ) ) ) ) ) ) ) ) ) ) ) Director ) ) ) ) ) ) ) )	May 31, 2002

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