PACIFICORP /OR/ - 10-K Annual Report

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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)

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

For the fiscal year ended March 31, 2004

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 Street, Portland, Oregon
(Address of principal executive offices)

97232
(Zip Code)

(503) 813-5000
(Registrant’s telephone number)

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 o

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

Indicate by check mark whether the Registrant is an accelerated filer (as defined in Rule 12b-2 of the Act).

Yes o No x

The aggregate market value of the shares of voting and non-voting common equity of the Registrant held by non-affiliates was $0 on September 30, 2003. As of May 25, 2004, there were 312,176,089 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

Item Number		Page No.


Definitions		ii

Corporate Organization		iii


Part I

Item 1.	Business	1

Item 2.	Properties	16

Item 3.	Legal Proceedings	19

Item 4.	Submission of Matters to a Vote of Security Holders	20


Part II

Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	20

Item 6.	Selected Financial Data	21

Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	25

Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	51

Item 8.	Financial Statements and Supplementary Data	56

Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	100

Item 9A.	Controls and Procedures	100


Part III

Item 10.	Directors and Executive Officers of the Registrant	101

Item 11.	Executive Compensation	104

Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	110

Item 13.	Certain Relationships and Related Transactions	110

Item 14.	Principal Accounting Fees and Services	111



Part IV

Item 15.	Exhibits, Financial Statement Schedules and Reports on Form 8-K	112

Signatures		114

DEFINITIONS

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

Term		Meaning
Centralia		Centralia, Washington power plant (47.5% owned) and coal mine (100.0% owned), operated by PacifiCorp until its sale on May 4, 2000
CPUC		California Public Utilities Commission
EPA		United States Environmental Protection Agency
FERC		Federal Energy Regulatory Commission
IPUC		Idaho Public Utilities Commission
kWh		Kilowatt-hour(s), one kilowatt continuously for one hour
MW		Megawatt
MWh		Megawatt-hour(s), one megawatt continuously for one hour
NA1		ScottishPower NA1 Limited, incorporated under the laws of Scotland, owns 10.0% of PHI
NA2		ScottishPower NA2 Limited, incorporated under the laws of Scotland, owns 90.0% of PHI
NAGP		NA General Partnership, a Nevada general partnership, was collectively owned by NA1 and NA2 prior to merging with PHI in December 2003
OPUC		Oregon Public Utility Commission
PacifiCorp		PacifiCorp, an Oregon corporation and direct, wholly owned subsidiary of PHI
Pacific Power		Pacific Power & Light Company, the assumed business name of PacifiCorp under which it conducts a portion of its retail electric operations
PFS		PacifiCorp Financial Services, Inc., an Oregon corporation and direct, wholly owned subsidiary of PGHC, and its subsidiaries
PGHC		PacifiCorp Group Holdings Company, a Delaware corporation and direct, wholly owned subsidiary of PHI
PHI		PacifiCorp Holdings, Inc., a Delaware corporation and non-operating United States holding company
PKE		Pacific Klamath Energy, Inc., an Oregon corporation and direct, wholly owned subsidiary of PHI
PPM		PPM Energy, Inc., formerly known as PacifiCorp Power Marketing, Inc., an Oregon corporation and direct, wholly owned subsidiary of PHI
ScottishPower		Scottish Power plc, holds all of the shares of the two subsidiaries defined above, NA1 and NA2, and is the ultimate, indirect parent company of PHI and PacifiCorp
SEC		Securities and Exchange Commission
SFAS		Statement of Financial Accounting Standards
SPUK		Scottish Power UK plc, incorporated under the laws of Scotland and an indirect, wholly owned subsidiary of Scottish Power plc
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
WUTC		Washington Utilities and Transportation Commission

iii

PART I

ITEM 1. BUSINESS

OVERVIEW

PacifiCorp is a regulated electricity company operating in portions of the states of Utah, Oregon, Wyoming, Washington, Idaho and California. As a vertically integrated electric utility, PacifiCorp owns or controls fuel sources such as coal and natural gas, and uses these fuel sources, as well as wind, geothermal and hydroelectric resources, to generate electricity at its power plants. This electricity, together with electricity purchased on the wholesale market, is then transmitted via a grid of transmission lines throughout PacifiCorp’s six-state region. The electricity is then transformed to lower voltages and delivered to end-use customers through PacifiCorp’s distribution system. The retail electric utility business is conducted using the business names Pacific Power and Utah Power. Electricity sales and purchases on a wholesale basis are conducted under the name PacifiCorp. The subsidiaries of PacifiCorp support its electric utility operations by providing coal mining facilities and services and environmental remediation. PacifiCorp’s goal is to provide safe, reliable, low-cost electricity to its customers, with fair and increasing earnings to its shareholder. Costs prudently incurred by PacifiCorp to provide service to its customers are expected to be included as allowable costs for state ratemaking purposes.

Regulation

PacifiCorp is subject to comprehensive regulation by the Securities and Exchange Commission (the “SEC”), the Federal Energy Regulatory Commission (the “FERC”) and other federal, state and local regulatory agencies. These agencies regulate many aspects of PacifiCorp’s business, including customer rates, service territories, sales of securities, asset acquisitions and sales, accounting policies and practices, wholesale sales and purchases, and the operation of its generation facilities.

Employees

PacifiCorp had 6,507 employees on March 31, 2004. Approximately 58.0% of the employees of PacifiCorp 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 PacifiCorp’s judgment, employee relations are satisfactory.

Common Stock

All outstanding shares of the common stock of PacifiCorp are indirectly owned by Scottish Power plc (“ScottishPower”), whose American Depository Shares are traded on the New York Stock Exchange, under the ticker symbol “SPI”.

Safe Harbor Statement

From time to time, PacifiCorp 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 PacifiCorp, including statements in this report on Form 10-K should be considered in light of these factors.

Location and Information Requests

The location of PacifiCorp’s principal offices is 825 N.E. Multnomah Street, Portland, Oregon. PacifiCorp’s website address is www.pacificorp.com. PacifiCorp makes available free of charge, on or through its website, its annual, quarterly and current reports, and any amendments to those reports, as soon as reasonably practicable after electronically filing such reports with the SEC. Information contained on PacifiCorp’s website is not part of this report. Reports and other information regarding PacifiCorp that are required to be filed with the SEC may also be obtained from the SEC’s website at www.sec.gov.

SERVICE TERRITORIES

PacifiCorp serves approximately 1.6 million retail customers in a service territory aggregating about 136,000 square miles in portions of six western states: Utah, Oregon, Wyoming, Washington, Idaho and California. The combined service territory’s diverse regional economy ranges from rural, agricultural and mining areas to urbanized manufacturing and government service centers. No one segment of the economy dominates the service territory, which mitigates PacifiCorp’s exposure to economic fluctuations. In the eastern portion of the service territory, mainly consisting of Utah, Wyoming and southeast Idaho, the principal industries are manufacturing, health services, recreation and mining or extraction of metals, coal, oil, natural gas, phosphates and elemental phosphorus. In the western portion of the service territory, mainly consisting of Oregon, southeastern Washington and northern California, the principal industries are agriculture and manufacturing, with pulp and paper, lumber and wood products, food processing, high technology and primary metals being the largest industrial sectors. The following map highlights PacifiCorp’s retail service territory.

The geographic distribution of PacifiCorp’s retail electric operating revenues for the year ended March 31, 2004 was as follows: Utah, 38.5%; Oregon, 31.5%; Wyoming, 12.8%; Washington, 8.4%; Idaho, 6.3%; and California, 2.5%.

PacifiCorp receives authorization from state public utility commissions to serve areas within each state. This authorization is perpetual until withdrawn by the state public utility commissions. In addition, PacifiCorp has received franchises to provide electric service to customers inside incorporated areas within the states. These franchises have terms of five to 100 years, after which they must be renewed. Governmental agencies have the right to challenge PacifiCorp’s right to serve in a specific area and can condemn PacifiCorp’s property under certain circumstances in accordance with the laws in each state. However, PacifiCorp vigorously challenges any attempts from individuals and governmental entities to undertake forced takeover of any portions of its service territory.

In February 2003, the Oregon Public Power Coalition submitted a petition to Multnomah County, Oregon, calling for an election to form a government-owned and -operated electric utility in the county and impose a property tax to perform a feasibility study. As required by state statute, the Multnomah County Commission placed these initiatives on the November 2003 ballot, but the Multnomah County voters defeated these measures.

CUSTOMERS

Electricity sales and retail customers, by class of customer, for the years ended March 31, 2004, 2003 and 2002, were as follows:

	Years Ended March 31,

Electric Operations	2004				2003				2002

(Thousands of MWh)

MWh sold
Residential	14,460		23.3	%	13,287		21.6	%	13,395		22.0	%
Commercial	14,413		23.2		14,006		22.6		13,810		22.6
Industrial	19,133		30.8		19,048		30.8		19,611		32.2
Other	673		1.1		631		1.0		711		1.2

Total retail sales	48,679		78.4		46,972		76.0		47,527		78.0
Wholesale sales	13,407		21.6		14,873		24.0		13,403		22.0

Total MWh sold	62,086		100.0	%	61,845		100.0	%	60,930		100.0	%

Number of Retail Customers (Thousands)
Residential	1,341		85.4	%	1,317		85.4	%	1,296		85.4	%
Commercial	190		12.1		186		12.1		182		12.0
Industrial	34		2.2		34		2.2		35		2.3
Other	5		0.3		5		0.3		4		0.3

Total	1,570		100.0	%	1,542		100.0	%	1,517		100.0	%

Residential Customers
Average annual usage (kWh)	10,889				10,182				10,411
Average annual revenue per customer	$ 749				$ 701				$ 701
Revenue per kWh	6.9	¢			6.9	¢			6.7	¢

During the year ended March 31, 2004, no single retail customer accounted for more than 1.7% of PacifiCorp’s retail electric revenues, and the 20 largest retail customers accounted for 13.0% of PacifiCorp’s retail electric revenues.

For the five years to March 31, 2009, PacifiCorp is estimating average growth in retail megawatt-hour (“MWh”) sales in PacifiCorp’s franchise service territories to be in the range of 1.5% to 2.6% annually, depending on factors such as economic conditions, number of customers, weather, conservation efforts and changes in prices.

Seasonality

As a result of the geographically diverse area of operations, PacifiCorp’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 air-conditioning systems are heavily used.

For residential customers, within a given year, weather conditions are the dominant cause of usage variations from normal seasonal patterns. Utah and Idaho are expected to be among the ten fastest growing states in the nation over the next few years. In addition, more residential customers are installing central air conditioning systems. These factors are contributing to faster summer peak growth.

TRANSMISSION AND DISTRIBUTION

PacifiCorp delivers electricity through 57,464 miles of distribution lines and 15,763 miles of transmission lines. To continuously improve customer service and network safety, reliability and performance, PacifiCorp is focusing on infrastructure improvement projects in targeted areas, particularly along Utah’s Wasatch Front, where there has been

rapidly growing demand for electricity due to customer growth and peak load growth. The scope of the Wasatch Front $202.0 million investment program includes transmission line upgrades, new distribution substations, upgrades to existing distribution substations and other system enhancements. As of March 31, 2004, PacifiCorp has added an additional 710 megawatts (“MW”) of system capacity through this program. As of March 31, 2004, PacifiCorp had invested approximately $122.1 million of the $202.0 million allocated to the program.

The regional electricity market in which PacifiCorp competes has changing transmission regulatory structures, which could affect the operation and ownership of transmission assets and related revenues and expenses. PacifiCorp currently owns and operates transmission facilities as part of its vertically integrated utility operations. Transmission costs are not separated from, but rather are “bundled” with, generation and distribution costs in approved retail rates. In 1996, the FERC issued new rules on transmission service to facilitate competition in the wholesale market on a nationwide basis. The rules give greater flexibility and more choices to wholesale electricity customers desiring transmission service from PacifiCorp. In December 1999, the FERC issued Order 2000 to promote voluntary coordination of electric transmission systems and more efficient use of resources through regional transmission organizations and related wholesale markets.

Regional Transmission Organization

PacifiCorp joined nine western utilities to pursue the development of a Regional Transmission Organization (“RTO”). The utilities filed an RTO proposal with the FERC in response to the FERC’s Order 2000. In September 2002, the FERC found that, with some modification and further development of certain details, the RTO proposal satisfied the 12 characteristics and functions included in the FERC’s Order 2000.

In July 2002, the FERC issued a Notice of Proposed Rule Making (“NOPR”) entitled the “Standard Market Design,” relating to open-access transmission service and standard electricity market design. After significant comments against this NOPR, the FERC issued a “Wholesale Power Market Platform” white paper in April 2003, which signaled a greater willingness to defer to regional solutions. In the summer of 2003, the RTO filing utilities reengaged the Regional Representatives Group, a formal regional stakeholder process. Over the following nine months, the Regional Representatives Group developed a consensus of regional issues and opportunities and developed a regional proposal to address them. The Regional Representatives Group is currently developing an implementation plan for this regional proposal, now named “Grid West,” which includes timing for seating an independent RTO Board of Trustees, the details of the first phase of operation by an independent entity and a plan for obtaining the necessary regulatory approvals.

Creation of the RTO is subject to regulatory approvals from the FERC and state regulatory commissions. The RTO, if and when fully implemented, would serve as an independent transmission provider for the RTO region and have operational authority needed to direct bulk electricity transfers over a majority of the 60,000 miles of transmission lines owned by its members. Under the current proposal, the RTO would have operational control, but PacifiCorp would retain ownership and ultimate physical control of its transmission facilities.

POWER AND FUEL SUPPLY

PacifiCorp owns, or has interests in, the following types of electricity generating plants:

	Plants	Nameplate Rating (MW)	Net Plant Capability (MW)

Thermal
Coal	11	6,585.8	6,107.4
Natural gas and other	5	723.8	683.0
Hydroelectric	54	1,077.3	1,164.0
Wind	1	32.6	32.6

Total	71	8,419.5	7,987.0

The following table shows the percentage of PacifiCorp’s total energy requirements supplied by its generation plants during the year ended March 31, 2004.

	Year Ended March 31, 2004

Thermal
Coal	68.4	%
Natural gas and other	4.1
Hydroelectric	5.4
Wind	0.2

Total	78.1	%

PacifiCorp obtains the remainder of its energy requirements, including any changes from expectations, through short- and long-term contracts or spot market purchases described below under “Wholesale Sales and Purchased Electricity.” The share of PacifiCorp’s energy requirements generated by its plants will vary from year to year and is determined by factors such as planned and unplanned outages, availability and price of coal and natural gas, precipitation and snowpack levels, environmental considerations and the market price of electricity.

Coal

As of March 31, 2004, PacifiCorp had an estimated 220.1 million tons of recoverable coal reserves in mines owned or leased by PacifiCorp. The coal from these reserves and from long-term contracts will be used to support PacifiCorp’s fuel strategy at its generation plants. During the year ended March 31, 2004, these mines supplied 30.4% of PacifiCorp’s total coal requirements, compared to 32.7% during the year ended March 31, 2003 and 32.5% during the year ended March 31, 2002. Coal is also acquired through other long-term and short-term contracts. PacifiCorp-owned mines are located adjacent to many of its coal-fired generating plants, thus significantly reducing overall transportation costs included in fuel expense. For further information, see Item 2. Properties.

Natural Gas

PacifiCorp supplies its natural gas-fired generation plants through contracts of varying terms. PacifiCorp currently supplies four natural gas-fired generating plants (composed of 14 generating units) that, at full capacity, require a maximum of 229,000 MMBtu (million British thermal units) of natural gas per day. As of March 31, 2004, PacifiCorp had purchased, under fixed-price terms, its forecasted natural gas supply needs for its existing natural gas-fired generation plants through calendar year 2006.

PacifiCorp’s Integrated Resource Plan has identified the need for additional generation resources, due to expected load and load shape growth, which could increase its natural gas requirement to 500,000 MMBtu per day, or more. Part of the requirement for additional generation resources will be met by the new Currant Creek plant discussed below, which is expected to begin operations in June 2005. Natural gas transportation capacity was purchased to meet the needs of the Currant Creek plant, consistent with PacifiCorp’s fuel strategy, which focuses on the management and mitigation of risks associated with supplying natural gas to fuel generation. PacifiCorp has purchased all of its calendar year 2005 and 2006 forecasted natural gas supply needs for the Currant Creek plant.

The prospective growth of PacifiCorp’s natural gas requirements points to the need for a prudent, disciplined and well-documented approach to natural gas procurement and hedging. PacifiCorp has developed a natural gas strategy that addresses the need to hedge the commodity risk (physical availability and price), the transportation risk and the storage risk associated with its forecasted and potentially growing natural gas requirements. The natural gas strategy, combined with the prospect for increasing natural gas requirements, is expected to increase the volume and types of PacifiCorp’s procurement and hedging activity and extend the term of such activities beyond calendar year 2006.

Hydroelectric

PacifiCorp’s hydroelectric portfolio consists of 54 plants with a net plant capability of 1,164.0 MW. These plants account for approximately 14.6% of PacifiCorp’s total generating capacity and provide operational benefits such as flexible generation, spinning reserves and voltage control. Hydroelectric plants are located in the following states: Utah, Oregon, Wyoming, Washington, Idaho, California and Montana.

The amount of electricity PacifiCorp is able to generate from its hydroelectric plants depends on a number of factors, primarily snowpack in the mountains upstream of its hydroelectric facilities, reservoir storage, precipitation in its watershed and resulting streamflow conditions. When these factors are favorable, PacifiCorp can generate more electricity using its hydroelectric plants. When these factors are unfavorable, PacifiCorp must increase its reliance on more expensive thermal plants and purchased electricity.

PacifiCorp operates the majority of its hydroelectric generating portfolio under long-term licenses from the FERC. These licenses are granted by the FERC for periods of 30 to 50 years. Many of PacifiCorp’s long-term operating licenses have expired or will expire in the next few years. Hydroelectric facilities operating under expired licenses may operate under annual licenses granted by the FERC until new operating licenses are issued. Hydroelectric relicensing and the related environmental compliance requirements are subject to a degree of uncertainty. PacifiCorp expects that future costs relating to these matters may be significant and consist primarily of additional relicensing costs and capital expenditures. Electricity generation reductions may also result from additional environmental requirements. As of March 31, 2004, PacifiCorp had incurred $48.9 million in costs for ongoing hydroelectric relicensing in progress, which are included as assets on PacifiCorp’s Consolidated Balance Sheet. This amount excludes costs related to the North Umpqua and Bear River licenses that were issued by the FERC during the year ended March 31, 2004. PacifiCorp expects that these and future costs will be found prudent and recoverable in rates and, as such, will not have a material adverse impact on PacifiCorp’s consolidated results of operations. See Hydroelectric Actions below.

Wind

PacifiCorp is committed to renewable power as a viable, economic and environmentally prudent means of generating electricity. Wind energy can be variable and somewhat seasonal in nature. For PacifiCorp’s wind resources, most strong winds occur in the winter months, and there is a reduction in the summer months.

PacifiCorp acquires wind power through a PacifiCorp-owned wind farm and various purchased electricity agreements. For the year ended March 31, 2004, PacifiCorp received 61,560 MWh from its owned wind farm. In this same period, 183,071 MWh were purchased from other wind sources. The purchased total is expected to increase in fiscal year 2005 as one of the vendor-owned wind farms was in commercial operation for only four months of the year ended March 31, 2004.

To encourage the use of wind energy, PacifiCorp has generation, storage and delivery agreements with Bonneville Power Administration, Eugene Water and Electric Board, Public Service Company of Colorado, and Seattle City Light. For the year ended March 31, 2004, electricity under these agreements totaled 503,196 MWh in addition to the wind energy generated or purchased for PacifiCorp’s own use.

Future Generation and Conservation

Requests for Proposals

As required by state regulators, PacifiCorp published an Integrated Resource Plan in January 2003 and updated it in October 2003. The Integrated Resource Plan provides a framework and plan for the prudent future actions required to ensure that PacifiCorp continues to provide reliable and cost-effective electric service to its customers. PacifiCorp has segregated its Integrated Resource Plan supply-side action items into a series of three separate Requests for Proposals, each of which focuses on a specific category of supply-side resources and provides for the staged procurement of resources in future years in an attempt to achieve load/resource balance.

RFP 2003A - PacifiCorp issued a Request for Proposal for its supply-side resources in June 2003. Following a review process consistent with the Integrated Resource Plan, PacifiCorp determined that its own proposal to have the Currant Creek plant built presents the lowest risk and most economical choice to meet its summer 2005 generation needs. The Currant Creek plant is a 525 MW natural gas-fired, combined-cycle combustion turbine generation plant to be located approximately 75 miles south of Salt Lake City, Utah, and will be constructed in two phases, with two 140 MW (280 MW total) simple-cycle combustion turbines being installed by summer 2005 and two heat-recovery steam generators and a steam generation turbine added in spring 2006.

In March 2004, PacifiCorp received regulatory approval from the Utah Public Service Commission (“UPSC”) via a Certificate of Convenience and Necessity to proceed with construction of the Currant Creek plant. In its written

order, the UPSC agreed that the Currant Creek plant addresses a genuine need for additional resources in the summer of 2005. The type and size of generation facility proposed to address the projected need identified in PacifiCorp’s 2003 Integrated Resource Plan were also determined to be reasonable.

In March 2004, the Utah Division of Air Quality finished its evaluation of the air quality permit application and issued a Notice of Intent to Approve the air quality permit. PacifiCorp received the final approval order in May 2004. In order to allow construction to proceed without delay, PacifiCorp and the Utah Division of Air Quality entered into an Administrative Order of Consent in March 2004. The consent order authorized PacifiCorp to proceed with initial plant construction activities before receiving the final air quality approval order. As such, construction of the plant began in March 2004. The plant is expected to cost approximately $350.0 million, spent from fiscal year 2004 through fiscal year 2007. Of this total expected amount, $44.7 million had been spent as of March 31, 2004. Recovery of PacifiCorp’s investment in the plant will be reviewed by all states as part of future rate cases.

To ensure an adequate supply to meet future energy needs, PacifiCorp announced in May 2004 that it intends to enter into an asset purchase and sale agreement with Summit Vineyard LLC of Denver, Colorado, to develop, and with Siemens Westinghouse Power Corporation, to construct, a natural gas-fired combined-cycle combustion turbine power plant near Salt Lake City, Utah. The plant, to be known as the Lake Side Power Plant and having a capacity of 534 MW, was identified as the best option submitted through PacifiCorp’s competitive RFP 2003A process, which sought to identify a summer 2007 resource. PacifiCorp plans to file with the UPSC in May 2004 for a Certificate of Convenience and Necessity, a process which could take up to six months to complete. Lake Side Power Plant is expected to cost approximately $330.0 million. Recovery of PacifiCorp’s investment in the plant will be reviewed by the states PacifiCorp serves as part of future general rate cases.

RFP 2003B - PacifiCorp issued a second Request for Proposals in February 2004 for up to 1,100 MW of economic renewable resources for PacifiCorp’s entire service territory. Several responses have been received and are currently being evaluated. A decision is expected to be made in June 2004.

RFP 2004A - PacifiCorp expects to issue a third Request for Proposals once results from RFP 2003A and RFP 2003B are reviewed and a new load/resource balance is determined. PacifiCorp anticipates that it will issue RFP 2004A in calendar year 2004, requesting additional resources to serve PacifiCorp’s growing load obligation. Based on the action item list contained in PacifiCorp’s Integrated Resource Plan, it is currently expected that PacifiCorp will procure additional resources that can be delivered in or to PacifiCorp’s service territory in Utah, southwest Wyoming and southeast Idaho.

Demand-side RFP - In addition to the three supply-side Requests for Proposals, PacifiCorp issued a separate Request for Proposals for the demand-side resources called for in its Integrated Resource Plan. The demand-side Request for Proposals was issued in June 2003 and requested an additional 100 MW or more of conservation to be obtained over the next 10 years and load control proposals specifically addressing peak load. PacifiCorp completed an analysis of initial responses and has selected certain proposals for further evaluation. PacifiCorp plans to file tariffs with the state regulatory commissions for certain proposals in summer 2004.

WHOLESALE SALES AND PURCHASED ELECTRICITY

PacifiCorp uses its portfolio of generation assets and long-term firm purchases to meet its retail load obligations. In addition, PacifiCorp purchases electricity in the wholesale markets to meet its retail load obligations, long-term wholesale obligations, and energy and capacity balancing requirements. For the year ended March 31, 2004, 21.9% of PacifiCorp’s energy requirements were supplied by purchased electricity under short- and long-term purchase arrangements, both as defined by the FERC. For the year ended March 31, 2003, 23.1% of PacifiCorp’s energy requirements were supplied by purchased electricity under short- and long-term purchase arrangements. Based on current fiscal year 2005 and fiscal year 2006 projections, PacifiCorp does not expect a significant change in the amount of supply from these arrangements.

Many of PacifiCorp’s purchased electricity contracts have fixed price components, and these provide some protection against price volatility. PacifiCorp enters into wholesale purchase and sale transactions to balance its supply when generation and retail loads are higher or lower than expected. Generation varies with the levels of outages, hydroelectric generation conditions and transmission constraints, and retail load varies with the weather,

distribution system outages and the level of economic activity. In addition, PacifiCorp purchases electricity when it is more economical than generating at its own plants and enters into wholesale sales during periods of excess capacity.

PacifiCorp’s wholesale transactions are integral to its retail business, providing for a balanced and economically hedged position and enhancing the efficient use of its generating capacity over the long-term. Historically, PacifiCorp has been able to purchase electricity from utilities in the western United States for its own requirements. PacifiCorp’s transmission system connects with market hubs in the Pacific Northwest to provide access to normally low-cost hydroelectric generation and in the southwestern United States to provide access to normally higher-cost fossil-fuel generation. The transmission system is available for common use consistent with open-access regulatory requirements. If PacifiCorp is in a surplus electricity position, PacifiCorp may sell excess electricity into the wholesale market, subject to pricing and transmission constraints.

RETAIL COMPETITION

During the year ended March 31, 2004, PacifiCorp continued to operate its retail business under state regulation. Certain of PacifiCorp’s industrial customers in Oregon have the right to choose alternative electricity suppliers, and others in PacifiCorp’s service territories are seeking choice of suppliers, options to build their own generation or co-generation plants, or the use of substitute energy sources such as natural gas. If these other customers gain the right to receive electricity from alternative suppliers, they 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 electricity also influence competition. The impact of retail competition to date has been minimal.

Any adoption of retail competition in the territories served by PacifiCorp and the unbundling of regulated electricity services could have a significant adverse financial impact on PacifiCorp due to an impairment of assets, a loss of retail customers, lower profit margins or increased costs of capital and could result in increased pressure to lower the price of electricity. PacifiCorp cannot predict if or when it will be subject to changes in legislation or regulation, nor can PacifiCorp predict the impact of these changes.

ENVIRONMENTAL MATTERS

PacifiCorp’s activities are subject to a broad range of federal, state and local laws and regulations designed to protect, restore and enhance the quality of the environment. PacifiCorp’s costs of complying with complex environmental laws and regulations, as well as internal voluntary programs and goals, are significant and will continue to be so for the foreseeable future.

In the year ended March 31, 2004, PacifiCorp spent approximately $29.2 million on environmental capital projects either required by law or necessary to meet PacifiCorp’s internal environmental goals. PacifiCorp currently estimates expenditures for environmental-related capital projects will total approximately $51.8 million in the year ending March 31, 2005, $127.5 million in the year ending March 31, 2006 and $187.1 million in the year ending March 31, 2007. PacifiCorp monitors these requirements and annually revises its cost estimates to meet existing legal and regulatory requirements of the various jurisdictions in which it operates. The increase in estimated future expenditures, in comparison to expenditures for the year ended March 31, 2004, is largely due to air quality initiatives.

Air Quality

PacifiCorp’s fossil fuel-fired electricity generation plants, as well as other facilities with significant air emissions, are subject to air quality regulation under federal, state and local laws and regulations. PacifiCorp believes it has all required permits and other approvals to operate its plants and that the plants are in material compliance with applicable requirements. PacifiCorp uses emission controls, low-sulfur coal, plant operating practices sensitive to environmental impacts and continuous emissions monitoring to enable its plants to comply with emissions limits, opacity limits, visibility and other air quality requirements.

The United States Environmental Protection Agency (the “EPA”) has initiated a regional haze program intended to improve visibility at specific federally protected areas, some of which are located near PacifiCorp plants. PacifiCorp 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 global climate change, but such emissions are not currently subject to regulation. PacifiCorp is working to help mitigate the effects of such climate changes in its region by adding renewable generation, conservation and natural gas resources as outlined in the Integrated Resource Plan. Carbon dioxide emissions risk has been anticipated in PacifiCorp’s Integrated Resource Plan through the use of a projected additional cost based on the fuel’s carbon content when evaluating the cost of new resources. PacifiCorp also supports development of trading and other market mechanisms, as well as offset strategies, where feasible, to reduce future climate change compliance costs to customers.

Several bills have been introduced in the United States Congress that would create enforceable limits on electricity plant emissions of sulfur dioxide, carbon dioxide, oxides of nitrogen and mercury. Legislation to limit emissions of carbon dioxide was defeated in October 2003. The EPA has proposed or intends to propose new regulations that could also impact emission limits. These requirements may require additional control equipment to be installed on PacifiCorp’s thermal generation plants over the next 10 to 15 years. While PacifiCorp is unable at this time to predict with certainty the overall level of expenditures relating to air quality and carbon dioxide emissions, it believes these amounts could be significant but will be spread over a number of years. PacifiCorp further expects that these and future costs will be found to be prudent and thus be included in rates.

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. PacifiCorp is not part of those actions. However, PacifiCorp has responded to certain requests for information by the EPA relating to air quality compliance issues at seven of its coal-fired generating plants in Utah and Wyoming, three of which are jointly owned facilities. In addition, PacifiCorp strives to continuously work with the EPA, state air quality agencies and others in a cooperative effort to seek a mutual, comprehensive solution to air quality issues as they relate to such plants.

Water Quality

The federal Clean Water Act and individual state clean-water regulations require a permit for the discharge of wastewater, including storm water runoff from electricity plants and coal storage areas, into surface water and groundwater. PacifiCorp believes that it has management systems in place to monitor performance, identify problems and take action to ensure compliance with permit requirements. Additionally, PacifiCorp believes that it currently has, or has initiated the process to receive, all required water quality permits.

Endangered Species

The federal Endangered Species Act of 1973 and similar state statutes protect species threatened with possible extinction. Protection of the habitat of endangered and threatened species makes it difficult and more costly to perform some of PacifiCorp’s core activities, including the siting, construction and operation of new and existing transmission and distribution facilities, as well as thermal, hydroelectric and wind generation plants. In addition, issues affecting endangered species can impact the relicensing of existing hydroelectric generating projects. This can generally raise the price PacifiCorp pays to purchase wholesale electricity from hydroelectric facilities owned by others, as well as reduce the generating output and operational flexibility, and potentially increase the costs of operation, of PacifiCorp’s own hydroelectric resources.

Environmental Cleanups

Under the Comprehensive Environmental Response, Compensation and Liability Act, the Resource Conservation and Recovery Act, and similar state statutes, entities that disposed of, or arranged for the disposal of, hazardous materials may be liable for cleanup of the contaminated property. In addition, the current or former owners or operators of affected sites may be liable. PacifiCorp has been identified as a potentially responsible party in connection with a number of cleanup sites because of its current or past ownership or operation of certain properties or because PacifiCorp sent materials deemed to be hazardous to the property in the past. PacifiCorp 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 PacifiCorp’s consolidated financial position, results of operations, cash flows, liquidity or capital expenditures. PacifiCorp expects that these and future costs will be found to be prudent and thus, included in rates.

Mine Reclamation

The federal Surface Mining and Reclamation Act of 1977 and similar state statutes establish operational, reclamation and closure standards that must be met during and upon completion of mining activities. These obligations mandate that mine property be restored consistent with specific standards and the approved reclamation plan. PacifiCorp’s mining operations are subject to these reclamation and closure requirements. Significant expenditures are being incurred for both ongoing and final reclamation. The costs associated with reclamation are subject to the regulatory process, and PacifiCorp expects to be allowed to recover these costs. For further discussion, see Item 2. Properties.

Other Environmental Laws

PacifiCorp is required to comply with numerous other federal, state and local environmental laws in addition to those discussed above. PacifiCorp believes that it is in material compliance with all applicable environmental laws.

REGULATION

PacifiCorp is subject to the jurisdiction of public utility regulatory authorities in each of the states in which it conducts retail electric operations. These authorities regulate various matters, including prices, services, accounting, issuances of securities and other matters. In addition, PacifiCorp is a “licensee” and a “public utility” as those terms are used in the Federal Power Act and is therefore subject to regulation by the FERC as to accounting policies and practices, certain prices and other matters, including the terms and conditions of transmission service. Most of PacifiCorp’s hydroelectric plants are licensed by the FERC as major projects under the Federal Power Act, and certain of these projects are licensed under the Oregon Hydroelectric Act. PacifiCorp is also subject to the requirements and restrictions of the Public Utility Holding Company Act of 1935 (the “PUHCA”).

Federal Regulatory Issues

Securities and Exchange Commission

Public Utility Holding Company Act of 1935

The PUHCA and related regulations issued by the SEC govern activities of PacifiCorp and its affiliates with respect to the issuance and acquisition of securities, acquisition and sale of utility assets, certain transactions among affiliates, engaging in business activities not directly related to the utility or energy business, and other matters.

Federal Energy Regulatory Commission Actions

In November 2003, the FERC issued new Standards of Conduct governing conduct between interstate transmission gas and electricity providers and their marketing function or their energy-related affiliates. The new rule redefines the scope of the affiliates covered by the standards and is designed to prevent transmission providers from giving their marketing functions or affiliates undue preferences. All transmission providers must be in compliance by September 2004. PacifiCorp has adopted an implementation plan and will train the appropriate personnel to ensure compliance with the new rules. Other FERC actions that affect PacifiCorp are discussed below.

California Refund Case

PacifiCorp is a party to a FERC proceeding that is investigating potential refunds for energy transactions in the California Independent System Operator and the California Power Exchange markets during past periods of high-energy prices. PacifiCorp previously established a reserve of $17.7 million for these potential refunds. PacifiCorp’s ultimate exposure to refunds is dependent upon any final order issued by the FERC in this proceeding.

Northwest Refund Case

In June 2003, the FERC terminated its proceeding relating to the possibility of requiring refunds for wholesale spot-market bilateral sales in the Pacific Northwest between December 2000 and June 2001. The FERC concluded that ordering refunds would not be an appropriate resolution of the matter. In August 2003, the FERC granted rehearing of its June 2003 order. In November 2003, the FERC issued its final order denying rehearing. Several market participants have filed petitions in the court of appeals for review of the FERC’s final order.

Federal Power Act Section 206 Case

In June 2003, the FERC issued a final order denying PacifiCorp’s request for recovery of excessive prices charged under certain wholesale electricity purchases scheduled for delivery during summer 2002 and dismissing PacifiCorp’s complaints, under section 206 of the Federal Power Act, against five wholesale electricity suppliers. In July 2003, PacifiCorp filed a petition in the Ninth Circuit Court of Appeals for review of certain aspects of this order. In July 2003, PacifiCorp filed its request for rehearing of the FERC’s order, which was granted in August 2003. The FERC issued its final order denying rehearing in November 2003. In November 2003, PacifiCorp filed a petition in the Ninth Circuit Court of Appeals for review of the FERC’s final order denying recovery. In November 2003, Morgan Stanley Capital Group, Inc., one of the five wholesale electricity suppliers, filed a petition in the D.C. Circuit Court of Appeals for review of the FERC’s final order. In December 2003, the case was transferred to the D.C. Circuit Court of Appeals for consolidation of the two appeals. In December 2003, PacifiCorp filed a motion to dismiss Morgan Stanley Capital Group, Inc.’s appeal. In April 2004, the D.C. Circuit Court of Appeals dismissed Morgan Stanley Capital Group, Inc.’s appeal, and PacifiCorp moved to transfer its appeal back to the Ninth Circuit Court of Appeals.

FERC Show-Cause Orders

In May 2002, PacifiCorp, together with other California electricity market participants, responded to data requests from the FERC regarding trading practices connected with the electricity crisis during 2000 and 2001. PacifiCorp confirmed that it did not engage in any trading practices intended to manipulate the market as described in the FERC’s data requests issued in May 2002. In June 2003, the FERC ordered 60 companies (including PacifiCorp) to show cause why their behavior during the California energy crisis did not constitute manipulation of the wholesale electricity market, as defined in the California Independent System Operator and the California Power Exchange tariffs. In setting the cases for hearing, the FERC directed the administrative law judge to hear evidence and render findings and conclusions quantifying the extent of any unjust enrichment that resulted and to recommend monetary or other appropriate remedies. In August 2003, PacifiCorp and the FERC staff reached a resolution on the show-cause order. Under the terms of the settlement agreement, PacifiCorp denied liability and agreed to pay a nominal amount of $67,745, in exchange for complete and total resolution of the issues raised in the FERC’s show-cause order relating to PacifiCorp. In March 2004, the FERC issued its final order approving the settlement and terminating the docket. In April 2004, certain market participants filed a request for rehearing of the FERC’s final order.

Hydroelectric Actions

Several of PacifiCorp’s hydroelectric plants are in some stage of the relicensing process with the FERC. PacifiCorp also requested the FERC to allow decommissioning of three hydroelectric plants. The following summarizes the status of these projects.

Relicensing

Bear River hydroelectric project – (Bear River, Idaho)

In December 2003, the FERC issued a new 30-year operating license for the 84.5 MW Bear River hydroelectric project. PacifiCorp sought clarification/rehearing on certain elements of the new license, which appeared to be inconsistent with the settlement agreement entered into by PacifiCorp and other relicensing stakeholders. In March 2004, the FERC issued an order resolving most issues raised in the rehearing request. PacifiCorp has 60 days in which to accept, reject, or appeal the new license order. In addition to the project’s capital and operations

and maintenance costs associated with the new license, upon license acceptance, PacifiCorp will be committed, over the life of the license, to fund a total of approximately $28.1 million for environmental mitigation and enhancement projects.

Big Fork hydroelectric project – (Swan River, Montana)

In July 2003, PacifiCorp received a new 50-year operating license for its 4.1 MW Big Fork hydroelectric project located on the Swan River in northwestern Montana. There were no challenges to this license, and it became effective upon issuance.

Klamath hydroelectric project – (Klamath River, Oregon and California)

In February 2004, PacifiCorp filed with the FERC a final application for a new license to operate the 151.0 MW Klamath hydroelectric project in southern Oregon and northern California. The FERC is expected to complete its required analysis over the next two years. In the meantime, PacifiCorp continues to work cooperatively with a broad range of stakeholders to identify and resolve any outstanding issues in an attempt to reach a settlement.

Lewis River hydroelectric projects – (Lewis River, Washington)

PacifiCorp filed new license applications for the 135.0 MW Merwin and 240.0 MW Swift No. 1 hydroelectric projects in April 2004. An application for a new license for the 134.0 MW Yale hydroelectric project was filed with the FERC in April 1999. However, consideration of the application has been delayed pending filing of the Merwin and Swift No. 1 applications in order to complete a comprehensive environmental analysis. PacifiCorp is working with stakeholders of the Lewis River system to negotiate a settlement.

North Umpqua hydroelectric project – (North Umpqua River, Oregon)

In November 2003, the FERC issued a new 35-year operating license for the 185.3 MW North Umpqua hydroelectric project. PacifiCorp sought clarification/rehearing on certain elements of the license, which appeared to be inconsistent with the settlement agreement entered into by PacifiCorp and other relicensing stakeholders. In addition, environmental groups also sought rehearing of the new license, specifically for removal of one of the project’s dams. In March 2004, the FERC issued an order on rehearing favorable to PacifiCorp and denied the motion of the environmental groups. PacifiCorp has 60 days in which to accept, reject or appeal the new license order. In addition to the project’s capital and operations and maintenance costs associated with the new license, upon license acceptance, PacifiCorp will be committed, over the life of the license, to fund a total of approximately $51.1 million for environmental mitigation and enhancement projects.

Prospect hydroelectric project – (Rogue River, Oregon)

In June 2003, PacifiCorp submitted a final license application to the FERC for the Prospect Nos. 1, 2 and 4 hydroelectric projects totaling 36.8 MW. The FERC is expected to complete its required analysis over the next two years.

Decommissioning

PacifiCorp has negotiated with the FERC and other interested parties to decommission the American Fork, Condit and Powerdale plants, as discussed below. These settlement agreements have been filed with the FERC and are pending further regulatory action.

American Fork hydroelectric project – (American Fork River, Utah)

In February 2003, PacifiCorp entered into a settlement agreement which resolved all conditions necessary for removal of the 1.0 MW American Fork plant. The FERC decommissioning order is expected by mid-year calendar 2004. Removal costs are estimated to be $0.8 million. The parties have agreed that project removal will begin in September 2006, subject to FERC and other regulatory approvals, with operations continuing until that time.

Condit hydroelectric project – (White Salmon River, Washington)

In September 1999, a settlement agreement to remove the 9.6 MW Condit hydroelectric project was signed by PacifiCorp, state and federal agencies, and non-governmental agencies. Removal is expected to begin in October 2006, subject to FERC and other regulatory approvals. PacifiCorp is in the process of acquiring all necessary permits, within the terms and conditions of the settlement agreement. In accordance with the settlement agreement, the total costs to decommission the project cannot exceed $20.0 million, including expected inflation.

Powerdale hydroelectric project – (Hood River, Oregon)

In June 2003, PacifiCorp entered into a settlement agreement to remove the 6.0 MW Powerdale plant rather than pursue a new license, based on an analysis of the costs and benefits of relicensing versus decommissioning. Removal of the Powerdale plant and associated project features, which is subject to FERC and other regulatory approvals, is projected to ultimately cost $6.3 million. The plant will continue to operate until its removal, which will commence in 2010.

State Regulatory Actions

PacifiCorp is currently pursuing a regulatory program in all states, with the objective of keeping rates closely aligned to ongoing costs. The following provides a state-by-state update.

Utah

In January 2004, the UPSC approved a stipulation settling PacifiCorp’s general rate case filed in May 2003. Under the stipulation, base rates in Utah increased by $65.0 million annually starting in April 2004, resulting in an average price increase of 7.0% and an authorized return on equity of 10.7%.

During summer 2003, PacifiCorp filed and received regulatory approval in Utah on three new residential demand-side management programs: a refrigerator recycling program, an air-conditioning load control program and an incentive program to install evaporative coolers or energy-efficient air-conditioners. PacifiCorp filed for a tariff rider to allow it to recover costs incurred through the implementation of all of the programs approved by the UPSC. PacifiCorp has been deferring the costs of approved programs since August 2001. In September 2003, the UPSC approved a stipulation detailing the introduction of a tariff rider mechanism and self-direction program for large customers. PacifiCorp held discussions with regulatory parties on the setting of an initial collection rate of 3.0% for the demand-side management tariff rider. PacifiCorp received formal commission approval of this proposed collection rate in March 2004. This tariff rider will be introduced in customer bills effective in April 2004 and is expected to result in collections of approximately $28.0 million annually to cover demand-side management costs.

Oregon

In November 2000, PacifiCorp made a deferred accounting filing to track its excess net power costs. In July 2002, the Oregon Public Utility Commission (the “OPUC”) approved the filing, finding that PacifiCorp had prudently incurred the excess net power costs. The order authorized recovery of $131.0 million, plus carrying charges, a rate of $45.6 million annually. The Industrial Customers of Northwest Utilities and the Citizens’ Utility Board appealed the OPUC order in March 2003. The Marion County, Oregon circuit court affirmed the OPUC order. The Industrial Customers of Northwest Utilities and the Citizens’ Utility Board have appealed the circuit court decision to the Oregon Court of Appeals. Briefing is complete and the Court of Appeals heard oral arguments in May 2004.

In October 2001, PacifiCorp appealed two OPUC orders issued in conjunction with the deferred accounting application. The orders established the baseline and a mechanism to determine the amount of excess net power costs that are eligible for deferral and eventual recovery. In July 2003, the Oregon Court of Appeals issued an order affirming the OPUC orders.

In August 2003, the OPUC approved a settlement of PacifiCorp’s general rate case filed in March 2003. Under the settlement, base rates in Oregon increased by $8.5 million annually starting in September 2003, resulting in an average price increase of 1.1% and an authorized return on equity of 10.5% on the regulatory capital structure. This represents an effective authorized return on equity of 10.7% based on the filed capital structure. In addition, a $12.0 million offsettable merger credit for the period from January 2004 to December 2004 was eliminated and a

non-offsettable merger credit was reduced from $6.0 million to $4.0 million. PacifiCorp anticipates amortizing the credit to return the full amount to customers by December 2004. The settlement also included a provision that PacifiCorp will not file a general rate case in Oregon prior to August 31, 2004.

In March 2004, PacifiCorp filed with the OPUC to recover $1.6 million of Senate Bill 1149 implementation costs. The OPUC approved the application at its April 8, 2004 public meeting and customer rates were increased by 0.1% on April 9, 2004.

Wyoming

In May 2002, PacifiCorp filed a request to recover replacement power costs of $30.7 million, resulting from the outage of PacifiCorp’s Hunter No. 1 generating plant, and a proposal for recovering deferred net power costs of $60.3 million. In December 2000, the Wyoming Public Service Commission (the “WPSC”) authorized the deferral of net power costs. In March 2003, the WPSC denied recovery of the Hunter No. 1 replacement power costs and the deferred net power costs. Following rehearing petitions and petition with the Laramie County district court in September 2003, the Laramie County district court certified the case to the Wyoming Supreme Court. PacifiCorp filed its opening brief with the Wyoming Supreme Court in January 2004 and filed its reply brief in April 2004. Also, in April 2004, PacifiCorp filed a complaint with the federal district court in Wyoming challenging the March 2003 WPSC decision.

In September 2003, PacifiCorp filed a request to establish a power cost adjustment mechanism. This mechanism was intended to protect PacifiCorp from net power cost volatility and reduce the regulatory lag associated with recovery of net power costs, which are defined as fuel and wheeling expenses and wholesale sales and purchases. Hearings in the power cost adjustment mechanism case were held in March 2004. The request to establish the power cost adjustment mechanism was denied on April 14, 2004.

In March 2004, the WPSC issued an order settling PacifiCorp’s general rate case filed in May 2003. Under this order, base rates in Wyoming increased annually by $22.9 million from March 2004, resulting in an average price increase of 7.2% and an authorized return on equity of 10.75%.

Washington

In December 2003, PacifiCorp filed with the Washington Utilities and Transportation Commission (the “WUTC”) for a general rate increase of $26.7 million annually, or 13.5%. PacifiCorp’s objectives are to recover higher power costs; recover increases in insurance, pension, health care, infrastructure and security costs; increase authorized return on equity to 11.25%; and receive approval for the proposed inter-jurisdictional cost allocation protocol (Multi-State process). In addition, PacifiCorp is requesting that the WUTC adopt the findings of a prudence review of generating resources acquired since the last Washington general rate case. The WUTC has adopted a procedural schedule requiring testimony from the staff and other parties in June 2004 and PacifiCorp’s rebuttal testimony in July 2004. Hearings are scheduled to begin in August 2004. A final order is expected in November 2004.

In October 2003, PacifiCorp filed petitions with the WUTC for accounting orders to allow deferral and amortization of the Trail Mountain coal mine closure costs and environmental remediation costs. These amounts total approximately $45.9 million and $7.4 million, respectively, on a consolidated PacifiCorp basis. In addition, PacifiCorp filed a petition requesting WUTC authorization of accounting treatment relating to the pension liability, as well as confirmation by the WUTC that certain actuarially determined pension costs are recoverable in rates. These filings were made in response to the stipulation approved in the last general rate proceeding in Washington requiring that items treated as regulatory assets under authorizations from other states that are proposed for inclusion in Washington at the end of the rate plan period be supported by accounting authorizations in Washington. These items will be considered as part of the current general rate case that was filed in December 2003 and for which an order is expected by November 2004.

In April 2002, PacifiCorp filed a petition with the WUTC, seeking authority to begin deferring net power costs in excess of those included in rates as of June 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 PacifiCorp’s last general rate case in Washington, there were limitations on PacifiCorp’s ability to request changes to general rates before January 2006. In July 2003, the WUTC issued a decision that did not allow for the deferral and recovery of excess power costs, but did allow PacifiCorp to file a general rate case any time before July 2005 that addresses the level of prices needed to cover all ongoing costs to serve Washington customers.

In August 2003, the Public Counsel section of the state attorney general’s office filed a court action in Thurston County superior court requesting review of the WUTC’s decision to allow PacifiCorp to file a general rate case that would allow a change in base rates prior to January 2006. A status conference in that proceeding was held in November 2003. PacifiCorp and the WUTC staff submitted a joint reply brief in April 2004. Oral argument was held in May 2004 and the Thurston County superior court affirmed the WUTC’s decision and denied the petition for judicial review.

Idaho

In August 2003, the Idaho Public Utilities Commission (the “IPUC”) approved the renewable energy tariff filed by PacifiCorp in July 2003. Under this tariff, residential and non-residential customers can purchase newly developed wind, geothermal and solar power energy in fixed increments.

In December 2003, PacifiCorp filed with the IPUC to recover $4.2 million related to Idaho’s portion of income tax payments resulting from Internal Revenue Service audits of prior years. The filing requests recovery over 16 months, beginning in June 2004, when a power cost recovery surcharge, which began in June 2002, expires. The IPUC staff held public input meetings concerning PacifiCorp’s application in April 2004. A stipulated agreement signed by the parties was filed with the IPUC in May 2004. PacifiCorp anticipates the IPUC will consider the stipulation at commission meetings in late May or early June 2004.

California

In November 2003, the California Public Utilities Commission approved the stipulation settling PacifiCorp’s general rate case filed in December 2001. Under this order, base rates in California increased by $2.8 million effective December 2003 in addition to the interim increase authorized in June 2002. This order combined with the interim increase results in an annual increase of $7.6 million. This represents an average price increase of 13.6%, with an authorized return on equity of 10.9%.

Affiliated Interest Filings

In September 2003, PacifiCorp made compliance filings for a cross-charge policy agreement governing the allocation of costs incurred by PacifiCorp and Scottish Power UK plc, an indirect subsidiary of Scottish Power plc, on behalf of each other. Compliance filings were submitted to Utah, Oregon, Wyoming, Washington and Idaho, with approval required from Oregon only. In December 2003, the OPUC approved the policy. The SEC has authorized the provision of services pursuant to service company agreements, which reflect the requirements of the cross-charge policy, in accordance with the PUHCA and related rules. The agreement establishes a process for directly assigning or allocating costs between PacifiCorp and Scottish Power UK plc for common corporate functions. These charges to PacifiCorp, at cost, are estimated to be in the range of $14.0 million to $17.0 million annually on a net basis. These cross-charges are expected to commence during fiscal year 2005.

Depreciation Rate Changes

PacifiCorp received approval through general rate cases or separate proceedings from all state commissions for changes in PacifiCorp’s rates of depreciation. Effective April 2003, the resulting depreciation rate changes reduced total PacifiCorp annual depreciation expense by approximately $26.0 million based on the March 31, 2002 plant balances, and have begun to partially offset price increases.

Hydroelectric Relicensing

During calendar year 2003, PacifiCorp filed general rate cases before the commissions in the states of Utah, Oregon, Wyoming and Washington, which included each state’s portion of the relicensing costs associated with the hydroelectric projects where new licenses have become effective or are close to being issued by the FERC. In Oregon and Utah, the general rate cases ended in a commission-approved settlement, and the commissions did not contest the hydroelectric relicensing costs. In Wyoming, the commission’s general rate case order did not challenge the hydroelectric relicensing costs included in the test year. In Washington, the recovery of relicensing costs is contingent upon the outcome of the general rate case, which is expected to conclude by November 2004.

Multi-State Process

PacifiCorp is involved in a collaborative process with stakeholders from the six states it serves, in an effort to develop mutually acceptable solutions to the issues faced by PacifiCorp and the states as a result of PacifiCorp’s multi-state operations. These issues pertain to the inconsistent allocation of some of the cost of PacifiCorp’s existing investments and the recovery of the cost of future investments. Between April 2002 and July 2003, PacifiCorp and key parties from Utah, Oregon, Wyoming, Washington and Idaho, along with a key monitoring contact from California, analyzed over 50 options to address these issues, which were narrowed to two possibilities. Both sought 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 each state’s entitlement to the benefits of PacifiCorp’s existing assets.

Following a July 2003 meeting, PacifiCorp undertook extensive analytical work to develop a single proposal that would best balance the needs of PacifiCorp and requirements of the states in addressing the positions, issues and concerns raised and discussed during the course of the collaborative and individual state meetings. This work culminated in a regulatory filing in September 2003 in the states of Utah, Oregon, Wyoming and Idaho. A similar filing was made in Washington in December 2003 as part of the general rate case filing. A filing in California will follow in coordination with rate case activity. Utah, Oregon and Wyoming have adopted regulatory schedules that envision continued formal and informal meetings among the states and commissions through May 2004. Direct and rebuttal testimony will be filed in May and June 2004, with hearings scheduled for July 2004. The schedule in Washington is in accordance with the general rate case procedures, with rebuttal testimony to be filed in July 2004, hearings from end of August through mid-September 2004, and with a suspension order date of mid-November 2004.

ITEM 2. PROPERTIES

PacifiCorp owns its principal properties in fee (except as indicated below), subject to defects and encumbrances that do not interfere materially with their use. Substantially all of PacifiCorp’s electric utility properties are subject to the lien of PacifiCorp’s Mortgage and Deed of Trust. See Exhibit 4.1. PacifiCorp considers all of its properties to be well maintained, in good operating condition, and suitable for their intended purposes.

Headquarters/Offices

PacifiCorp’s corporate headquarters consist of approximately 800,000 square feet of owned and leased office space located in several buildings in Portland, Oregon, and Salt Lake City, Utah. PacifiCorp’s principal headquarters are in Portland, but there are several executives and departments located in Salt Lake City. In addition to the corporate headquarters, PacifiCorp owns and leases approximately one million square feet of office space in various other locations in Utah, Oregon, Wyoming, Washington, Idaho and California.

Generation

PacifiCorp owns, or has an interest in, various hydroelectric, thermal-electric and wind electricity generating plants. A generator’s nameplate rating is its full-load capacity (in megawatts) under normal operating conditions as defined by the manufacturer. The following table summarizes PacifiCorp’s existing generating plants:

	Location	Energy Source	Unit Installation Date(s)	Nameplate Rating (MW)		Plant Net Capability (MW)

HYDROELECTRIC PLANTS (a)
Swift No. 1 (b)	Cougar, WA	Lewis River	1958	240.0		264.0
Merwin	Ariel, WA	Lewis River	1931-1958	135.0		144.0
Yale	Amboy, WA	Lewis River	1953	134.0		165.0
Five North Umpqua Plants	Toketee Falls, OR	N. Umpqua River	1950-1956	133.3		139.0
John C. Boyle	Keno, OR	Klamath River	1958	80.0		90.0
Copco Nos. 1 and 2 Plants	Hornbrook, CA	Klamath River	1918-1925	47.0		54.5
Clearwater Nos. 1 and 2 Plants	Toketee Falls, OR	Clearwater River	1953	41.0		41.0
Grace	Grace, ID	Bear River	1908-1923	33.0		33.0
Prospect No. 2	Prospect, OR	Rogue River	1928	32.0		36.0
Cutler	Collingston, UT	Bear River	1927	30.0		29.1
Oneida	Preston, ID	Bear River	1915-1920	30.0		28.0
Iron Gate	Hornbrook, CA	Klamath River	1962	18.0		20.0
Soda	Soda Springs, ID	Bear River	1924	14.0		14.0
Fish Creek	Toketee Falls, OR	Fish Creek	1952	11.0		12.0
34 Minor Hydroelectric Plants (c)	Various	Various	1895-1990	99.0	*	94.4	*

Subtotal (54 Hydroelectric Plants)				1,077.3		1,164.0

THERMAL ELECTRIC PLANTS
Jim Bridger	Rock Springs, WY	Coal-Fired	1974-1979	1,541.1	*	1,413.4	*
Huntington	Huntington, UT	Coal-Fired	1974-1977	996.0		895.0
Dave Johnston	Glenrock, WY	Coal-Fired	1959-1972	816.7		762.0
Naughton	Kemmerer, WY	Coal-Fired	1963-1971	707.2		700.0
Hunter Nos. 1 and 2	Castle Dale, UT	Coal-Fired	1978-1980	728.0	*	662.0	*
Hunter No. 3	Castle Dale, UT	Coal-Fired	1983	495.6		460.0
Cholla No. 4	Joseph City, AZ	Coal-Fired	1981	414.0	*	380.0	*
Wyodak	Gillette, WY	Coal-Fired	1978	289.6	*	268.0	*
Carbon	Castle Gate, UT	Coal-Fired	1954-1957	188.6		175.0
Craig Nos. 1 and 2	Craig, CO	Coal-Fired	1979-1980	172.1	*	165.0	*
Colstrip Nos. 3 and 4	Colstrip, MT	Coal-Fired	1984-1986	155.6	*	149.0	*
Hayden Nos. 1 and 2	Hayden, CO	Coal-Fired	1965-1976	81.3	*	78.0	*
Gadsby Steam	Salt Lake City, UT	Natural Gas-Fired	1951-1952	251.6		235.0
Gadsby Peakers	Salt Lake City, UT	Natural Gas-Fired	2002	141.0		114.0
Hermiston	Hermiston, OR	Natural Gas-Fired	1996	237.0	*	245.0	*
Little Mountain	Ogden, UT	Natural Gas-Fired	1972	16.0		14.0
Camas Co-Gen	Camas, WA	Black Liquor	1996	52.2		52.0
Blundell	Milford, UT	Geothermal	1984	26.0		23.0

Subtotal (16 Thermal Electric Plants)				7,309.6		6,790.4

OTHER PLANTS
Foote Creek	Arlington, WY	Wind Turbines	1998	32.6	*	32.6	*

Subtotal (1 Other Plant)				32.6		32.6

Total Hydro, Thermal and Other Generating Plants (71)				8,419.5		7,987.0

Jointly owned plants; amount shown represents PacifiCorp’s share only.

(a)

Hydroelectric project locations are stated by locality and river watershed.

(b)

On April 21, 2002, a failure occurred to the Swift No. 2 power canal on the Lewis River in the state of Washington. The Cowlitz County Public Utility District owns the power canal and associated 70 MW hydroelectric facility (“Swift No. 2”). The failure impacted, but did not damage, the PacifiCorp-owned and -operated 240 MW Swift No. 1 hydroelectric facility (“Swift No. 1”), which is upstream of the Swift power canal. The existing Swift No. 2 overflow spillway was modified to allow restricted operations of Swift No. 1 during the Swift No. 2 project outage. PacifiCorp continues to seek ways to mitigate any shaping limitations and recover any business losses. It is currently estimated that Swift No. 2 will return to operation during the first quarter of calendar year 2006. Swift No. 2 reconstruction must be complete before Swift No. 1 can resume more normal operation; however, it has not yet been determined how Cowlitz County Public Utility District’s proposed rehabilitation design for the Swift No. 2 project will enable the full unrestricted capability

that Swift No. 1 had prior to the failure. Swift No. 1 is estimated to return to full operations during the first quarter of calendar year 2006. PacifiCorp is working cooperatively with Cowlitz County Public Utility District to incorporate project features into the power canal rehabilitation plan to minimize future impacts to the Swift No. 1 project and to expedite reconstruction efforts. The full impact of the Swift power canal outage and plans for repair of the Swift No. 2 facility are currently under review. PacifiCorp is seeking reimbursement from Cowlitz County Public Utility District of PacifiCorp’s expenditures associated with the Swift No. 2 failure, and energy replacement costs. This event is not expected to have a significant impact on PacifiCorp’s consolidated financial position or results of operations.

(c)

PacifiCorp has negotiated settlement agreements with resource agencies and other interested parties to decommission the Condit, Powerdale and American Fork plants that have a combined net capability of 16.6 MW. These settlement agreements have been filed with the FERC and are pending further regulatory action.

In May 2002, PacifiCorp entered into a 15-year operating lease on an electric generation plant with West Valley Leasing Company, LLC (“West Valley”), a subsidiary of PPM Energy, Inc. (“PPM”). The Utah facility consists of five generation units with an aggregate nameplate rating of 217.0 MW and a net plant capability of 215.0 MW. PacifiCorp, at its sole option, may terminate the lease, or purchase the facility, after three years and after six years.

Transmission and Distribution

PacifiCorp’s generating facilities are interconnected through its own transmission lines or by contract through the transmission lines of other transmission owners. Substantially all of PacifiCorp’s generating plants and reservoirs are managed on a coordinated basis to obtain maximum load-carrying capability and efficiency. Portions of PacifiCorp’s transmission and distribution systems are located:

•

On property owned or leased by PacifiCorp;

•

Under or over streets, alleys, highways and other public places, the public domain and national forests and state lands under franchises, easements or other rights which are generally subject to termination;

•

Under or over private property as a result of easements obtained primarily from the record holder of title; or

•

Under or over Native American reservations under grant of easement by the Secretary of Interior or lease by Native American tribes.

It is possible that some of the easements, and the property over which the easements were granted, may have title defects or may be subject to mortgages or liens existing at the time the easements were acquired.

At March 31, 2004, PacifiCorp owned, or participated in, an electric transmission and distribution system consisting of:

Nominal Voltage (In kilovolts)		Miles

Transmission Lines
500		717
345		1,865
230		3,334
161		284
138		2,111
115		1,605
69		3,026
57		113
46		2,708

		15,763
Distribution Lines Less than 46		57,464

Total		73,227

At March 31, 2004, PacifiCorp owned 1,048 substations.

Mining

The following table describes PacifiCorp’s recoverable coal reserves as of March 31, 2004. All coal reserves are dedicated to nearby PacifiCorp-owned or jointly owned 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%. PacifiCorp 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 for their current economically useful lives. Blending of PacifiCorp-owned and contracted coal, together with electricity plant technologies for controlling sulfur and other emissions, are utilized to meet the applicable standards. PacifiCorp-owned plants held sufficient sulfur dioxide emission allowances to comply with EPA Title IV requirements during the compliance year. The sulfur content of the coal reserves ranges from 0.30% to 0.94%, and the British Thermal Units value per pound of the reserves ranges from 8,600 to 12,400. 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, 2004, based on PacifiCorp’s most recent engineering studies, were as follows:

Location	Plant Served	Mining Method	Recoverable Tons (in Millions)

Craig, CO	Craig	Surface	48.8	(a)
Huntington & Castle Dale, UT	Huntington and Hunter	Underground	50.6	(b)
Rock Springs, WY	Jim Bridger	Surface/Underground	120.7	(c)

(a)

These coal reserves are leased and mined by Trapper Mining, Inc., a Delaware non-stock corporation operated on a cooperative basis, in which PacifiCorp has an ownership interest of 21.4%.

(b)

These coal reserves are mined by subsidiaries of PacifiCorp.

(c)

These coal reserves are leased and mined by Bridger Coal Company, a joint venture between Pacific Minerals, Inc. (“PMI”) and a subsidiary of Idaho Power Company. PMI, a subsidiary of PacifiCorp, has a two-thirds interest in the joint venture. In December 2003, PacifiCorp acquired reserves from a third party for underground mining at the Jim Bridger mine.

Most of PacifiCorp’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 rents 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. PacifiCorp expended $13.9 million in reclamation costs during the year ended March 31, 2004 and $12.5 million during the year ended March 31, 2003. PacifiCorp and Idaho Power have previously contributed funds to a trust for the reclamation of the Bridger Mine. At March 31, 2004, these reclamation funds totaled $87.2 million, of which PacifiCorp’s portion is $58.1 million. See Note 6 in Item 8. Financial Statements and Supplementary Data.

ITEM 3. LEGAL PROCEEDINGS

In May 2004, PacifiCorp was served with a complaint filed in the United States District Court for the District of Oregon by the Klamath Tribes of Oregon and certain of the Klamath Tribes’ members. The claim generally alleges that PacifiCorp and its predecessors affected the Klamath Tribes’ federal treaty rights to fish for salmon in the headwaters of the Klamath River in southern Oregon by building dams that blocked the passage of salmon upstream to the headwaters beginning in 1911. The claim seeks in excess of $1.0 billion in damages. PacifiCorp believes it has a number of defenses and intends to vigorously defend any claim of liability for the matters alleged by the Klamath Tribes.

From time to time, PacifiCorp is a party to various other legal claims, actions and complaints. Although it is impossible to predict with certainty whether or not PacifiCorp 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 PacifiCorp’s consolidated financial results. See Item 1. Business - Regulation for information concerning pending regulatory proceedings.

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, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

PacifiCorp is an indirect subsidiary of ScottishPower, which owns all 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.

To the extent that payment or distribution would reduce PacifiCorp’s common stock equity below a specified percentage of its total capitalization, PacifiCorp is restricted from paying dividends or making other distributions without prior OPUC approval. The specified percentage of total capitalization increases over time from 35.0% after December 31, 1999 to 40.0% after December 31, 2004. As of March 31, 2004, the minimum permitted ratio was 39.0%. As of March 31, 2004, under this measure, PacifiCorp’s actual common stock equity percentage was 47.5%.

PacifiCorp is also subject to maximum debt-to-total capitalization ratios under various debt agreements. For further discussion, see “Liquidity and Capital Resources” under Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

Under the PUHCA, PacifiCorp may pay dividends out of capital or unearned surplus only with SEC approval. Dividends from earned surplus are permitted without approval. PacifiCorp has previously received approval to pay dividends out of unearned surplus of the lesser of (a) $900.0 million or (b) the proceeds received from sales of non-utility assets. At March 31, 2004, PacifiCorp had $300.0 million of such proceeds from previous sales of non-utility assets. As a consequence of a new financing order expected to be issued by the SEC in June 2004, PacifiCorp expects the unearned surplus available for distribution pursuant to SEC authorization to be reduced to approximately $220.0 million. In addition, PacifiCorp must give the OPUC 30 days’ prior notice of any special cash dividend or any transfer involving more than 5.0% of PacifiCorp’s retained earnings in a six-month period. There were no special cash dividends or transfers during the year ended March 31, 2004 that required giving prior notice to the OPUC.

ITEM 6. SELECTED FINANCIAL DATA

SELECTED FINANCIAL INFORMATION (Unaudited)

	Years Ended March 31,

(Millions of dollars, except per share and employee amounts)	2004			2003			2002			2001			2000

Revenues
Electric operations (a)	$	3,194.5		$	3,082.4		$	3,341.1		$	3,343.5		$	3,002.3
Australian Operations		—			—			—			399.3			617.6
Other Operations (b)		—			—			12.6			122.2			77.1

Total	$	3,194.5		$	3,082.4		$	3,353.7		$	3,865.0		$	3,697.0

Income (loss) from operations
Electric Operations	$	618.7		$	488.9		$	598.6		$	453.1		$	587.8
Australian Operations		—			—			27.4			(133.1	)		125.1
Other Operations (b)		—			—			15.0			19.8			(7.8	)

Total	$	618.7		$	488.9		$	641.0		$	339.8		$	705.1

Net income (loss)	$	248.1		$	140.1		$	327.3		$	(88.2	)	$	83.7

Earnings contribution (loss)
Continuing operations
Electric Operations	$	245.7		$	134.7		$	232.8		$	110.1		$	10.9
Australian Operations		—			—			27.4			(187.2	)		39.0
Other Operations (b)		—			—			20.5			(29.0	)		13.8

Total		245.7			134.7			280.7			(106.1	)		63.7
Discontinued operations (c)		—			—			146.7			—			1.1
Cumulative effect of accounting change (d)		(0.9	)		(1.9	)		(112.8	)		—			—

Total	$	244.8		$	132.8		$	314.6		$	(106.1	)	$	64.8

Common dividends declared per share	$	0.51		$	—		$	0.81		$	1.31		$	0.58
Common dividends paid per share	$	0.51		$	—		$	1.00		$	1.12		$	0.85

	At March 31,

		2004		2003		2002		2001		2000

Capitalization
Short-term debt	$	364.9	$	161.7	$	322.0	$	291.7	$	295.9
Long-term debt		3,520.2		3,417.6		3,553.8		2,906.9		4,045.7
Preferred Securities of Trusts		—		341.8		341.5		341.2		340.9
Junior subordinated debentures		—		—		—		—		175.8
Preferred stock subject to mandatory redemption		60.0		66.7		74.2		175.0		175.0
Preferred stock		41.3		41.3		41.3		41.5		41.5
Common equity		3,278.7		3,194.4		2,891.9		3,414.4		3,879.9

Total	$	7,265.1	$	7,223.5	$	7,224.7	$	7,170.7	$	8,954.7

Total assets (e)	$	11,677.1	$	11,695.8	$	10,234.9	$	10,539.7	$	11,771.5

Total employees		6,507		6,140		6,287		6,626		8,832

(a)

Certain amounts from prior years have been reclassified to conform to the year ended March 31, 2004 method of presentation, including the implementation of Emerging Issues Task Force (“EITF”) No. 03-11, Reporting Gains and Losses on Derivative Instruments that Are Subject to Financial Accounting Standards Board Statement No. 133, Accounting for Derivative Instruments and Hedging Activities, and Not Held for Trading Purposes (“EITF No. 03-11”).

(b)

Other Operations includes the operations of PPM and Pacific Klamath Energy, Inc. until their transfer to PacifiCorp Holdings, Inc. (“PHI”) in March 2001 and of PacifiCorp Financial Services, Inc. (“PFS”), as well as the activities of PacifiCorp Group Holdings Company (“PGHC”), including financing costs and elimination entries, until their transfer in February 2002 to PHI.

(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”). The amount in 2000 represents discontinued operations of formerly owned TPC Corporation.

(d)

Represents the effect of implementation of Statement of Financial Accounting Standards (“SFAS”) No. 143, Asset Retirement Obligations, in the year ended March 31, 2004, Derivatives Implementation Group (“DIG”) Revised Issue C15, Normal Purchases and Normal Sales Exception for Certain Option-Type Contracts and Forward Contracts in Electricity (“Issue C15”), and Issue C16, Applying the Normal Purchases and Normal Sales Exception to Contracts that Combine a Forward Contract and a Purchased Option Contract (“Issue C16”), in the year ended March 31, 2003 and SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities (“SFAS No. 133”), in the year ended March 31, 2002.

(e)

Certain amounts have been reclassified from assets to liabilities for all periods presented.

ELECTRIC OPERATIONS (Unaudited)

	Years Ended March 31,

(Millions of dollars)	2004			2003			2002			2001			2000

Revenues
Residential	$	994.5		$	914.7		$	901.7		$	852.1		$	798.7
Commercial		792.9			763.4			747.7			710.5			667.2
Industrial		725.6			699.2			705.1			730.1			694.5
Other		34.0			31.4			34.5			32.5			30.4

Retail sales		2,547.0			2,408.7			2,389.0			2,325.2			2,190.8
Wholesale sales (a)		528.1			545.4			980.4			1,063.5			751.9
Other (a)		119.4			128.3			(28.3	)		(45.2	)		59.6

Total		3,194.5			3,082.4			3,341.1			3,343.5			3,002.3

Expenses
Purchased electricity (a)		672.8			698.5			974.4			1,287.7			668.0
Fuel		483.9			482.2			490.9			491.0			512.3
Operations and maintenance		881.8			885.1			806.2			655.8			755.0
Depreciation and amortization		428.8			434.3			401.3			389.0			379.9
Taxes, other than income taxes		95.3			93.4			90.7			97.5			99.3

Operating expenses		2,562.6			2,593.5			2,763.5			2,921.0			2,414.5
Other operating expense (income)		13.2			—			(21.0	)		(30.6	)		—

Total		2,575.8			2,593.5			2,742.5			2,890.4			2,414.5

Income from operations		618.7			488.9			598.6			453.1			587.8
Interest expense		256.5			270.3			238.3			262.0			273.1
Interest income		(13.8	)		(21.6	)		(28.9	)		(10.7	)		(5.0	)
Interest capitalized		(19.9	)		(18.0	)		(6.9	)		(12.9	)		(20.2	)
Merger costs		—			—			—			9.3			190.5
Minority interest and other		2.4			19.0			12.0			(10.2	)		(5.6	)
Income tax expense		144.5			97.2			138.6			87.6			125.2

Income before cumulative effect of accounting change		249.0			142.0			245.5			128.0			29.8
Cumulative effect of accounting change		(0.9	)		(1.9	)		(112.8	)		—			—

Net income		248.1			140.1			132.7			128.0			29.8
Preferred dividend requirement		(3.3	)		(7.3	)		(12.7	)		(17.9	)		(18.9	)

Earnings on common stock (b)	$	244.8		$	132.8		$	120.0		$	110.1		$	10.9

Total assets (c)	$	11,677.1		$	11,695.8		$	10,234.9		$	10,456.6		$	10,709.7
Capital expenditures	$	690.4		$	550.0		$	505.3		$	376.1		$	510.0

(a)

Certain amounts from prior years have been reclassified to conform to the year ended March 31, 2004 method of presentation, including the implementation of EITF No. 03-11.

(b)

Does not reflect elimination of interest on intercompany borrowing arrangements; includes income taxes on a separate-company basis.

(c)

Certain amounts have been reclassified from assets to liabilities for all periods presented.

ELECTRIC OPERATIONS STATISTICS (Unaudited)

	Years Ended March 31,

	2004			2003			2002			2001			2000

Energy sales (Thousands of MWh)
Residential		14,460			13,287			13,395			13,455			13,028
Commercial		14,413			14,006			13,810			13,634			12,827
Industrial		19,133			19,048			19,611			20,659			20,488
Other		673			631			711			705			663

Retail sales		48,679			46,972			47,527			48,453			47,006
Wholesale sales (a)		13,407			14,873			13,403			14,998			24,686

Total		62,086			61,845			60,930			63,451			71,692

Energy source
Coal		72.5	%		71.1	%		73.0	%		71.1	%		69.0	%
Hydroelectric		5.4			5.6			5.7			5.0			7.1
Wind		0.2			0.2			0.2			0.2			0.1
Purchase and exchange contracts		21.9			23.1			21.1			23.7			23.8

Total		100.0	%		100.0	%		100.0	%		100.0	%		100.0	%

Number of retail customers (thousands)
Residential		1,341			1,317			1,296			1,278			1,252
Commercial		190			186			182			179			174
Industrial		34			34			35			35			35
Other		5			5			4			4			4

Total		1,570			1,542			1,517			1,496			1,465

Residential customers
Average annual usage (kWh)		10,889			10,182			10,411			10,614			10,463
Average annual revenue per customer	$	749		$	701		$	701		$	672		$	641
Revenue per kWh		6.9¢			6.9¢			6.7¢			6.3¢			6.1¢
Miles of line
Transmission		15,763			14,949			14,900			14,900			14,900
Distribution
— overhead		43,750			43,765			43,800			43,700			43,600
— underground		13,714			13,301			12,500			11,900			10,900
System peak demand (MW)
Net system load (b)
— summer		8,922			8,549			7,899			8,056			7,570
— winter		8,013			7,613			7,688			7,475			7,115
Total firm load (c)
— summer		10,104			9,542			10,029			10,115			10,494
— winter		8,662			8,628			9,511			9,592			10,622

(a)

Certain amounts from prior years have been modified to conform to the year ended March 31, 2004 method of presentation as a result of the implementation of EITF No. 03-11.

(b)

Excludes off-system sales.

(c)

Includes firm off-system sales.

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

OVERVIEW

The Management’s Discussion and Analysis should be read in conjunction with the Consolidated Financial Statements.

PacifiCorp is a regulated electricity company serving approximately 1.6 million residential, commercial and industrial customers in service territories aggregating approximately 136,000 square miles in portions of the states of Utah, Oregon, Wyoming, Washington, Idaho and California. The regulatory commissions in each state approve rates for retail electric sales within their respective states. PacifiCorp also sells electricity on the wholesale market to public and private utilities, energy marketing companies and to incorporated municipalities. Wholesale activities are regulated by the FERC. PacifiCorp owns, or has interests in, 71 thermal, hydroelectric and wind generating plants with an aggregate nameplate rating of 8,419.5 MW and plant net capability of 7,987.0 MW. The FERC and the six state regulatory commissions also have authority over the construction and operation of PacifiCorp’s electric facilities. PacifiCorp delivers electricity through 57,464 miles of distribution lines and 15,763 miles of transmission lines.

Strategic Priorities and Economic Factors

PacifiCorp’s vision is to excel as a regulated utility providing safe, reliable, low-cost electricity to its customers with fair and increasing earnings to its shareholder.

Return on Equity and Earnings

PacifiCorp seeks to maximize its return on equity within the limits permitted by state regulators. In addition to the factors that affect PacifiCorp’s revenues, PacifiCorp’s earnings are substantially impacted by the extent to which state regulators allow it to recover costs through rate setting. Results in any particular period may be affected by delays in recovering costs through the regulatory process.

PacifiCorp’s current challenges include obtaining full and timely recovery of increased costs of insurance, pensions and health care, and capital expenditures for investments made to support growth within its operating regions. Ongoing changes in the regulatory landscape make it difficult for PacifiCorp to predict with certainty the ability to recover these types of increased costs and the full impact that any future changes will have on its business. PacifiCorp’s investment activity and increased costs have created more regulatory activity, including more frequent general rate cases. The result of these recovery efforts, as affected by the changing regulatory landscape, could have a significant impact on PacifiCorp’s earnings.

Implications of Growing Retail Demand

PacifiCorp must continue to find sources of power supply to meet the growing retail customer demand for electricity across its service territories. Utah, in particular, has one of the fastest growth rates in the nation. In response to the growing demand in its service territories, PacifiCorp’s Integrated Resource Plan provides a process for staged procurement of new base load, peaking plant, purchase and renewable resources. As part of the plan, PacifiCorp has begun having its 525 MW Currant Creek plant constructed in Utah to meet its summer 2005 generation needs and in May 2004, announced plans to enter into an asset purchase and sale agreement for the development and construction of a 534 MW natural gas-fired combined-cycle combustion turbine power plant, to be known as the Lake Side Power Plant, near Salt Lake City, Utah. In addition, PacifiCorp intends to bolster its infrastructure with new connections and reinforcement and replacement of existing network assets.

Increases or reductions in future retail demand for electricity as a result of economic growth or downturns, among other factors, such as abnormal weather, will impact retail revenues, cash flows and investment levels. In particular, the pace of economic recovery in PacifiCorp’s service territories, especially in Oregon, which has been experiencing recessionary conditions, could impact PacifiCorp’s results and timing of investments.

Risk Management

PacifiCorp continues to maintain a strong focus on risk management and minimizing its net power costs by utilizing a range of physical and financial hedges to ensure an ongoing balance between supply and demand for electricity. Although PacifiCorp proactively manages its supply and demand balance, any unanticipated changes in future customer demand, weather conditions, commodity prices and thermal or hydroelectric generation resource availability, including unplanned outages, will affect the level of PacifiCorp’s net power costs.

Sources of Funding

PacifiCorp relies on access to short- and long-term capital markets as a source of liquidity to fund future investments to the extent not covered by cash from operations. PacifiCorp emphasizes an appropriate capital structure at competitive rates to maintain a strong financial condition. If PacifiCorp is unable to obtain access to capital at competitive rates, or maintain its capital structure at acceptable levels, it may seek internal equity infusions from its parent, PHI, to help fund future investments.

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 under the safe-harbor provisions of the Private Securities Litigation Reform Act of 1995 that may influence the financial performance and earnings of PacifiCorp. When used in this report on Form 10-K, 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 that the results predicted will be realized. Actual results may vary from those represented by the forecasts, and those variations may be material. In addition to the factors discussed under “Risk Factors”, the following are among the factors that could cause actual results to differ materially from the forward-looking statements:

•

The outcome of general rate cases and other proceedings conducted by regulatory commissions;

•

Changes in prices and availability of wholesale electricity, natural gas and fuel costs and other changes in operating costs that could affect PacifiCorp’s cost recovery;

•

Changes in regulatory requirements or other legislation, including industry restructuring and deregulation initiatives;

•

Choice of alternative suppliers by customers;

•

Industrial, commercial and residential customer growth and demographic patterns in PacifiCorp’s service territories;

•

Economic trends that could impact electricity usage;

•

Competition and supply in electricity and natural gas markets;

•

Changes in weather conditions and other natural events that could affect customer demand or electricity supply;

•

Adequacy and accuracy of load and price forecasts that could impact the hedging strategy and costs to balance electricity load and supply;

•

Hydroelectric conditions and natural gas and coal production levels that could have a significant impact on electric capacity and cost and on PacifiCorp’s ability to generate electricity;

•

The cost, feasibility and eventual outcome of hydroelectric facility relicensing proceedings;

•

Changes in, and compliance with, environmental and endangered species laws, regulations, decisions and policies that could increase operating and capital improvement costs, reduce plant output and delay plant construction;

•

The impact of the possible formation of a Regional Transmission Organization, or similar organization, and the impact of the implementation of the Standard Market Design proposed by the FERC;

•

Unanticipated construction delays or changes in costs relating to present or future generating facilities;

•

Timely and appropriate completion of the Requests for Proposals process;

•

Receipt of all permits and authorization to construct future generation plants and infrastructure additions; and

•

Attempts by municipalities within PacifiCorp’s service territory to form public power entities and/or acquire PacifiCorp’s facilities.

Any forward-looking statements issued by PacifiCorp should be considered in light of these factors. PacifiCorp does not plan 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 PacifiCorp later becomes aware that these assumptions are not likely to be achieved.

Accounting Matters

Critical Accounting Estimates

The preparation of consolidated 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 results of operations and the reported amounts of assets and liabilities in the Consolidated Financial Statements. The estimates and assumptions may change as time passes and accounting guidance evolves. Management bases its estimates and assumptions on historical experience and on other various judgments that it believes are reasonable at the time of application. Changes in these estimates and assumptions could have a material impact on the Consolidated Financial Statements. If estimates and assumptions are different than the actual amounts recorded, adjustments are made in subsequent periods to take into consideration the new information. Critical accounting policies, in addition to certain less significant accounting policies, are discussed with senior members of management and PacifiCorp’s Board of Directors, as appropriate. Those policies that management considers critical are described below.

Derivatives

On April 1, 2001, PacifiCorp adopted SFAS No. 133, as amended. PacifiCorp uses derivative instruments (primarily forward purchases and sales) to manage the commodity price risk inherent in its fuel and electricity obligations, as well as to optimize the value of power generation assets and related contracts. PacifiCorp also enters into short-term energy derivatives on a limited basis for arbitrage purposes to take advantage of opportunities arising from market inefficiencies. SFAS No. 133 applies not only to traditional financial derivative instruments, but to any contract having the accounting characteristics of a derivative.

SFAS No. 133 requires that derivative instruments be recorded on the balance sheet at fair value. The fair values of derivative instruments are determined using forward price curves. Forward price curves represent PacifiCorp’s estimates of the prices at which a buyer or seller could contract today for delivery or settlement of a commodity at future dates. PacifiCorp bases its forward price curves upon market price quotations when available and uses internally developed, modeled prices when market quotations are unavailable. In general, PacifiCorp estimates the fair value of a contract by calculating the present value of the difference between the contract and the applicable forward price curve.

Price quotations for certain major electricity trading hubs are generally readily obtainable for the first three years and, therefore, PacifiCorp’s forward price curves for those locations and periods reflect observable market quotes. However, in the later years or for locations that are not actively traded, forward price curves must be estimated in other ways. For short-term contracts at less actively traded locations, prices are modeled based on observed historical price relationships with actively traded locations. For long-term contracts extending beyond three years, the forward price curve is based upon the use of a fundamentals model (cost-to-build approach), due to the limited information available. Factors used in the fundamental model include the forward prices for the commodities used as fuel to generate electricity, the expected system heat rate (which measures the efficiency of power plants in converting fuel to electricity) in the region where the purchase or sale takes place, and a fundamental forecast of expected spot prices for a commodity in a region based on modeled supply of and demand for the commodity in the region. The assumptions in these models are critical, since any changes therein could have a significant impact on the fair value of the contract.

The Financial Accounting Standards Board (“FASB”) has discussed and, from time to time, issued implementation guidance related to SFAS No. 133. In particular, much of the interpretive guidance addresses when certain contracts for the purchase and sale of power and certain natural gas supply contracts can be excluded from the provisions of SFAS No. 133 via the normal purchases and normal sales exemption. Despite the large volume of implementation guidance, SFAS No. 133 and the supplemental guidance do not provide specific guidance on all contract issues. As a result, significant judgment must be used in applying SFAS No. 133 and its interpretations.

Pensions and Other Postretirement Benefits

PacifiCorp sponsors defined benefit pension plans that cover the majority of its employees. In addition, certain bargaining unit employees participate in a joint trust plan to which PacifiCorp contributes. PacifiCorp accounts for these plans in accordance with SFAS No. 87, Employers’ Accounting for Pensions (“SFAS No. 87”). PacifiCorp accounts for its other postretirement benefit plans in accordance with SFAS No. 106, Employers’ Accounting for Postretirement Benefits Other than Pensions (“SFAS No. 106”). The expense and benefit obligations relating to PacifiCorp’s pension and other postretirement benefit plans are based on actuarial valuations. Inherent in these valuations are key assumptions, including discount rates, expected returns on plan assets, compensation increases, PacifiCorp contributions and health care cost trend rates. These actuarial assumptions are reviewed annually and modified as appropriate. The effect of modifications is generally amortized over future periods. PacifiCorp believes that the assumptions utilized in recording obligations under the plans are reasonable based on prior experience, market conditions and the advice of plan actuaries. However, actual results may differ from such assumptions.

The PacifiCorp Retirement Plan (the “Retirement Plan”) currently has assets with a fair value that is less than the accumulated benefit obligation, primarily due to declines in the equity markets during calendar years 2000 through 2002 and lower discount rates. PacifiCorp recognized a minimum pension liability in the fourth quarter of the year ended March 31, 2003 and continues to recognize this liability at March 31, 2004. The liability adjustment did not affect the consolidated results of operations. PacifiCorp requested and received accounting orders from the regulatory commissions in Utah, Oregon and Wyoming to classify most of this charge as a Regulatory asset instead of a charge to Other comprehensive income and, in December 2003, filed in Washington for similar treatment. This increase to Regulatory assets was adjusted as of March 31, 2004 and will be adjusted in future periods as the difference between the fair value of the trust assets and the accumulated benefit obligation changes. PacifiCorp has determined that SFAS No. 87 costs for the Retirement Plan are currently recoverable in rates.

PacifiCorp’s contributions to the Retirement Plan have exceeded the minimum funding requirements of the Employee Retirement Income Security Act. PacifiCorp’s funding policy is to contribute amounts that are not less than the minimum amounts required to be funded under Employee Retirement Income Security Act. PacifiCorp made $33.4 million in cash contributions to the Retirement Plan during the year ended March 31, 2004 and made $26.4 million in cash contributions to the Retirement Plan during the year ended March 31, 2003. PacifiCorp also made a $61.6 million cash contribution to the Retirement Plan in April 2004 and does not anticipate further cash contributions to the Retirement Plan during fiscal year 2005. PacifiCorp is funding the Retirement Plan at what it believes to be an adequate level, but currently expects to make larger cash contributions in the future due to its underfunded pension obligation and Employee Retirement Income Security Act requirements. Such cash requirements could be material to PacifiCorp’s cash flows. PacifiCorp believes it has adequate access to capital resources to support these contributions.

PacifiCorp discounted its future pension and other postretirement plan obligations using a rate of 6.25% at March 31, 2004, compared to 6.75% at March 31, 2003. Thus, the discount rate used for PacifiCorp’s fiscal 2004 expense was 6.75% and the discount rate that will be used for PacifiCorp’s fiscal 2005 expense is 6.25%. PacifiCorp chooses a discount rate based upon high quality fixed-income investment yields. The pension and other postretirement benefit liability, as well as expense, increases as the discount rate is reduced.

At March 31, 2004, PacifiCorp assumed that the pension and other postretirement assets would generate a long-term rate of return of 8.75%. This rate is the same as that used at March 31, 2003. In establishing its assumption as to the expected return on assets, PacifiCorp reviews the expected asset allocation and develops return assumptions for each asset class based on historical performance and independent advisors’ forward-looking views of the financial markets. Pension and other postretirement benefit expense increases as the expected rate of return on Retirement Plan assets decreases.

Based on the above assumptions, PacifiCorp expects to record pension expense of $43.3 million for the year ending March 31, 2005, as compared to $28.9 million for the year ended March 31, 2004.

The following table reflects the sensitivities of the March 31, 2004 disclosures and the projected pension expense for the year ending March 31, 2005, associated with a change in certain actuarial assumptions by the indicated percentage:

(Millions of dollars)	Change in Assumption		Impact on Projected Benefit Obligation Increase (Decrease)			Impact on Minimum Pension Liability Increase (Decrease)			Impact on Annual Pension Cost Increase (Decrease)
Actuarial Assumption	Change in Assumption

Expected long-term return on plan assets	(0.5	)%	$	—		$	—		$	4.4
Expected long-term return on plan assets	0.5			—			—			(4.4	)
Discount rate	(0.5	)		84.9			75.3			8.9
Discount rate	0.5			(77.1	)		(68.4	)		(8.1	)

PacifiCorp expects to record other postretirement benefit expense of $31.7 million for the year ending March 31, 2005, as compared to $27.9 million for the year ended March 31, 2004. PacifiCorp has determined that SFAS No. 106 costs for other postretirement benefits are currently recoverable in rates. PacifiCorp contributed $25.3 million for the year ended March 31, 2004 and $22.6 million for the year ended March 31, 2003 to the funding vehicles for its other postretirement benefit plans. PacifiCorp expects to contribute $31.0 million to the funding vehicles for its other postretirement benefit plans for the year ending March 31, 2005 and expects future cash contributions to be comparable.

In valuing its accumulated postretirement benefit obligation, PacifiCorp must make an assumption regarding future changes in health care costs. Assumed changes impact the obligation and expense as follows:

(Millions of dollars)	Impact on Accumulated Postretirement Benefit Obligation			Impact on Annual Other Postretirement Benefit Cost
Assumed health care cost trend rates

One percentage point increase	$	31.9		$	5.0
One percentage point decrease		(27.0	)		(4.2	)

Regulation

PacifiCorp prepares its Consolidated Financial Statements in accordance with SFAS No. 71, Accounting for the Effects of Certain Types of Regulation (“SFAS No. 71”). SFAS No. 71 requires PacifiCorp 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 Statements of Consolidated Income as rates to customers are reduced. 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 those costs in allowable costs for ratemaking purposes. In addition, the rate action should permit recovery of the specific previously incurred cost rather than provide for expected levels of similar future costs.

PacifiCorp is subject to state and federal regulation. In the event of deregulation, PacifiCorp would seek recovery of its net regulatory assets, and any additional stranded costs. If unsuccessful, the unrecoverable portion of its net regulatory assets would be written-off and PacifiCorp would evaluate the remaining assets on its balance sheet for impairment in accordance with SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets. PacifiCorp is unable to predict the likelihood of deregulation and its future impacts.

At March 31, 2004, PacifiCorp had recorded specifically identified regulatory assets, net of regulatory liabilities, totaling $647.0 million. In the event PacifiCorp stopped applying SFAS No. 71 at March 31, 2004, an after-tax loss of approximately $401.5 million would be recognized.

Unbilled Revenues

Electricity sales to retail customers are determined based on meter readings taken throughout the month. PacifiCorp accrues an estimate of unbilled revenues, net of estimated line losses, each month for electric service provided after

the meter reading date to the end of the month. The unbilled revenue estimate is based on three components: PacifiCorp’s total electricity delivered during the month, assigning of unbilled revenues to customer type and valuation of the unbilled energy. Factors involved in the estimation of consumption and line losses relate to weather conditions, amount of natural light, historical trends, economic impacts and customer type. Valuation of unbilled energy is based on estimating the average price for the month for each customer type. These estimates can vary significantly from period to period depending on monthly weather patterns, customers’ space heating and cooling, production levels due to economic activity, or changing irrigation patterns due to precipitation conditions.

Differences between unbilled revenue and billed revenue would most likely occur due to inaccurate meter readings, improper assignment of customers, or inaccurate estimates of line losses. At March 31, 2004, the amount accrued for unbilled revenues was $128.3 million.

Contingencies

PacifiCorp follows SFAS No. 5, Accounting for Contingencies (“SFAS No. 5”), to determine accounting and disclosure requirements for contingencies. According to SFAS No. 5, an estimated loss from a contingency shall be charged to income if (i) it is probable that an asset has been impaired or a liability had been incurred at the date of the financial statements and (ii) the amount of the loss can be reasonably estimated. Disclosure in the notes to the financial statements is required for loss contingencies not meeting both of these conditions if there is a reasonable possibility that a loss may have been incurred. Gain contingencies are not recorded until realized.

PacifiCorp operates in a highly regulated environment. Governmental bodies such as the FERC, state regulatory commissions, SEC, Internal Revenue Service, Department of Labor, EPA and others have authority over various aspects of PacifiCorp’s business operations and public reporting. Reserves are established when required based upon management’s best judgment. Appropriate disclosures are made regarding litigation, tax matters, environmental issues, assessments and creditworthiness of customers or counterparties, among others. The evaluation of these contingencies is performed by various specialists inside and outside of PacifiCorp. Accounting for contingencies requires significant judgment by management regarding the estimated probabilities and ranges of exposure to potential loss. Management’s assessment of PacifiCorp’s exposure to contingencies could change as new developments occur or more information becomes available. The outcome of the contingencies could vary significantly and could materially impact the consolidated results of operations, cash flows and financial position of PacifiCorp. Management has used its best judgment in applying SFAS No. 5 to these matters.

New Accounting Standards

FSP SFAS No. 106-1and FSP SFAS No. 106-2

In January and May 2004, the FASB issued FASB Staff Position (“FSP”) SFAS No. 106-1 and FSP SFAS No. 106-2, Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (“FSP SFAS No. 106-1” and “FSP SFAS No. 106-2”). The Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the “Medicare Act”) was signed into law in December 2003 and establishes a prescription drug benefit, as well as a federal subsidy to sponsors of retiree health care benefit plans that provide a prescription drug benefit that is at least actuarially equivalent to Medicare’s prescription drug coverage. FSP SFAS No. 106-2 provides guidance on the accounting for the effects of the Medicare Act for employers that sponsor postretirement health care plans that provide prescription drug benefits and requires those employers to provide certain disclosures regarding the effect of the federal subsidy provided by the Medicare Act. Under FSP SFAS No. 106-1, PacifiCorp elected to defer accounting for the effects of the Medicare Act. This deferral remains in effect until the appropriate effective date of FSP SFAS No. 106-2. For entities that elected deferral and for which the impact is significant, FSP SFAS No. 106-2 is effective for the first interim or annual period beginning after June 15, 2004. For entities that will not recognize a significant impact, delayed recognition of the effects of the Medicare Act until the next regularly scheduled measurement date following the issuance of FSP SFAS No. 106-2 is allowed. PacifiCorp is still evaluating the impact of the Medicare Act. Accordingly, the accompanying Consolidated Financial Statements do not reflect the effects that may result from the Medicare Act.

RESULTS OF OPERATIONS

Overview

PacifiCorp’s earnings on common stock for the year ended March 31, 2004 were $244.8 million, as compared to $132.8 million for the year ended March 31, 2003 and $314.6 million for the year ended March 31, 2002.

Retail sales volumes, comprised of Residential, Commercial and Industrial customer classes, were 3.6% higher for the year ended March 31, 2004 than for the prior year, including approximately 0.8% as a result of weather. Each retail customer class also experienced favorable price movements, which resulted in Retail revenues that were 5.7% higher than the prior year. In the Residential class, the warmer summer and colder winter weather despite a milder March 2004, as compared to the prior year, contributed to higher average customer usage. The Commercial class also partially benefited from weather, but was primarily affected by growth in the average number of customers. Industrial revenues were higher primarily through changes in the price mix, as volumes were only marginally higher.

Wholesale sales revenues declined 3.2%, with the benefit of higher prices more than offset by a decrease in volumes. Purchased electricity expense declined by 3.7%, as a result of an increase in PacifiCorp’s own generation production and lower wholesale sales, partially offset by higher prices. As a result of improved operating performance, output from PacifiCorp’s thermal plants increased by 792,000 MWh, or 1.7%, as compared to the prior year. This increase was partially offset by a reduction in output from PacifiCorp-owned hydroelectric facilities, which decreased by 154,000 MWh, or 4.2%, as a result of unusually dry conditions in fiscal year 2004. The net increase in generation reduced reliance on more expensive purchased electricity at market or contracted prices. Also contributing to the year-over-year increase in earnings was a reduction in net interest and other expense of $24.5 million, due largely to a decrease in interest on regulatory liabilities and the refinancing of higher cost securities with lower cost long-term debt. For the year ended March 31, 2004, Operations and maintenance expenses and total Depreciation and amortization were slightly lower than the previous year.

For the year ended March 31, 2004, electricity market prices in the western United States, where PacifiCorp operates, were higher than in the comparable prior year period, driven by a combination of higher natural gas prices in the western United States and below-normal regional hydroelectric generation. As a result of risk management actions previously taken, including use of physical resources and hedging activities, PacifiCorp maintained its balanced supply/demand energy position through the summer peak period and has balanced its energy position for fiscal year 2005.

The mild, dry weather experienced in March 2004 continued into April and May 2004, which has reduced residential demand and hydroelectric generating resource availability compared to normal weather conditions. Thermal generation output has also been lower in this period.

Regulatory Actions

As discussed in Part I. Item 1. Business, in Oregon, PacifiCorp received an annual rate increase of $8.5 million effective September 2003, which represents a 1.1% average price increase. In California, PacifiCorp received an annual rate increase of $2.8 million effective December 1, 2003. Combining this order with the interim increase authorized in June 2002 results in an overall price increase of $7.6 million annually, which represents a 13.6% average price increase. In Utah, PacifiCorp received an annual rate increase of $65.0 million, effective April 2004, which represents a 7.0% average price increase. In Wyoming, PacifiCorp received an annual rate increase of $22.9 million, effective March 2004, which represents a 7.2% average price increase.

In addition, PacifiCorp has a general rate case pending in Washington for approximately $26.7 million of proposed annual price increases. This increase is sought to recover system investments and rising costs, including insurance, pension, health care, power, infrastructure and security costs. The Washington case should be finalized by November 2004. As with any general rate case, the outcome of this request is uncertain.

PacifiCorp is currently pursuing a regulatory program in all states, with the objective of keeping rates closely aligned to ongoing costs. PacifiCorp is currently considering future general rate case activity in fiscal 2005.

Winter Storms

In late December 2003 and early January 2004, PacifiCorp’s distribution network was impacted by severe storms in northern Utah and parts of Oregon and California. PacifiCorp incurred increased costs as a result of the storm damage to its network. PacifiCorp’s pre-tax earnings for the year ended March 31, 2004 were reduced by $8.3 million due to storm-related costs, including goodwill credits given to customers.

Affiliated Interest Cross-Charge Policy

PacifiCorp has a cross-charge policy agreement governing the allocation of costs incurred by PacifiCorp and Scottish Power UK plc, an indirect subsidiary of Scottish Power plc, on behalf of each other. See Item 1. Business. These charges to PacifiCorp, at cost, are estimated to be in the range of $14.0 million to $17.0 million annually on a net basis. These cross-charges commence during fiscal year 2005 and will be recorded in Operations and maintenance expense.

Year Ended March 31, 2004 Compared to Year Ended March 31, 2003

Revenues

(Millions of dollars)	Year Ended March 31,

	2004		2003		$ Change			% Change


Residential	$	994.5	$	914.7	$	79.8		8.7	%
Commercial		792.9		763.4		29.5		3.9
Industrial		725.6		699.2		26.4		3.8
Other retail revenues		34.0		31.4		2.6		8.3

Retail sales		2,547.0		2,408.7		138.3		5.7
Wholesale sales		528.1		545.4		(17.3	)	(3.2	)
Other revenues		119.4		128.3		(8.9	)	(6.9	)

Total revenues	$	3,194.5	$	3,082.4	$	112.1		3.6

Energy sales (Thousands of MWh)
Residential		14,460		13,287		1,173		8.8
Commercial		14,413		14,006		407		2.9
Industrial		19,133		19,048		85		0.4
Other		673		631		42		6.7

Retail sales		48,679		46,972		1,707		3.6
Wholesale sales		13,407		14,873		(1,466	)	(9.9	)

Total		62,086		61,845		241		0.4

Average residential usage (kWh)		10,889		10,182		707		6.9
Total customers - end of period (in thousands)		1,570		1,542		28		1.8

Residential revenues increased $79.8 million, or 8.7%, due to:

•

$64.3 million of increases from higher average estimated customer usage, including the impact of warmer summer and colder winter weather, both as compared to the prior year;

•

$16.8 million of increases relating to growth in the average number of residential customers of 1.8%; and

•

$4.8 million of increases from higher regulatory rates; partially offset by,

•

$6.1 million of decreases due to a change in price mix, resulting from the level of customer usage at different customer tariffs in the various states that PacifiCorp serves.

Commercial revenues increased $29.5 million, or 3.9%, due to:

•

$16.3 million of increases relating to growth in the average number of commercial customers;

•

$7.0 million of increases from higher average estimated customer usage;

•

$4.8 million of increases from higher regulatory rates; and

•

$1.4 million of increases due to a change in price mix, resulting from the level of customer usage at different customer tariffs in the various states that PacifiCorp serves.

Industrial revenues increased $26.4 million, or 3.8%, due to:

•

$14.9 million of increases due to a change in price mix, resulting from the level of customer usage at different customer tariffs in the various states that PacifiCorp serves;

•

$7.5 million of increases from higher regulatory rates; and

•

$4.0 million of increases from higher average estimated customer usage.

Wholesale sales decreased $17.3 million, or 3.2%, primarily due to:

•

$51.6 million of decreases in long-term and short-term volumes as a result of a combination of contract expiration and higher prior year wholesale activity; and

•

$33.2 million of decreases from unfavorable movements of unrealized gains and losses on derivatives; partially offset by,

•

$66.0 million of increases from higher realized prices on both long-term and short-term markets, due to increases in market prices and escalation on long-term contract prices; and

•

$1.5 million of increases relating to other minor sales.

Other revenues decreased $8.9 million, or 6.9%, primarily due to:

•

$20.7 million of decreases from the release of reserves in the year ended March 31, 2003 on a power sales contract following settlement of a dispute with respect to the contract;

•

$14.0 million of decreases in wheeling revenues due to discontinuation of long-term contracts, less energy usage by third-party customers and unfavorable market conditions; and

•

$4.6 million of decreases from the conclusion of the amortization of a regulatory liability; partially offset by,

•

$10.8 million of increases due to the higher value, in the year ended March 31, 2004 as compared to the year ended March 31, 2003, of net margins from sales and purchase transactions that did not physically settle;

•

$6.0 million of increases from the reduction of the Oregon merger credit liability in the year ended March 31, 2003;

•

$5.7 million of increases due to the conclusion of a temporary regulatory surcharge;

•

$4.8 million of increases due to increased joint usage of PacifiCorp’s distribution poles by third parties; and

•

$2.0 million of increases due to the release of a previously established reserve for an industrial customer in the year ended March 31, 2004.

Operating Expenses

(Millions of dollars)	Year Ended March 31,

	2004		2003		$ Change			% Change

Purchased electricity	$	672.8	$	698.5	$	25.7		3.7	%
Fuel		483.9		482.2		(1.7	)	(0.4	)
Operations and maintenance		881.8		885.1		3.3		0.4
Depreciation and amortization		428.8		434.3		5.5		1.3
Taxes, other than income taxes		95.3		93.4		(1.9	)	(2.0	)

Total operating expenses	$	2,562.6	$	2,593.5	$	30.9		1.2

Purchased electricity expense decreased $25.7 million, or 3.7%, due to:

•

$38.2 million of decreases primarily relating to unrealized gains on energy contracts;

•

$23.6 million of decreases resulting from favorable power cost deferral movements;

•

$18.7 million of decreases as a result of lower volumes of long- and short-term market purchases resulting from higher thermal plant availability and lower wholesale activities than the prior year;

•

$11.0 million of decreases from lower wheeling expenses due to expired transmission contracts that were not renewed; partially offset by,

•

$61.1 million of increases from higher realized electricity prices on both long- and short-term contracts, as a result of higher market prices; and

•

$4.7 million of other increases, primarily from higher costs of ancillary services.

Fuel expense increased $1.7 million, or 0.4%, due to:

•

$9.6 million of increases relating to higher volumes as a result of higher output from coal-fired generation plants; and

•

$7.1 million of increases as a result of an increase in the price of coal consumed; partially offset by,

•

$9.2 million of decreases from lower natural gas volumes caused by unfavorable market conditions; and

•

$5.8 million of decreases from lower realized natural gas prices.

Operations and maintenance expense decreased $3.3 million, or 0.4%, primarily due to:

•

$24.0 million of decreases from the establishment of a reserve in the prior year for the FERC issues and for potential California refunds;

•	$18.9 million of decreases due to prior year mine reclamation liability adjustments for the Glenrock mine pursuant to a mine reclamation study performed; and

•

$3.4 million of decreases in workers’ compensation expense; partially offset by,

•

$14.9 million of increases in pension costs due to the continued phasing-in of the negative asset returns from 2000 through 2002, and a lower discount rate;

•

$10.8 million of increases in employee salary expense and other direct employee expenses;

•

$9.2 million of increases in consulting and technical service fees; and

•

$8.3 million of increases related to winter storm damages, primarily uninsured losses and overtime payments.

Depreciation and amortization expense decreased $5.5 million, or 1.3%, due to:

•

$27.7 million of decreases as a result of new depreciation rates approved by regulators, effective April 1, 2003; partially offset by,

•

$13.0 million of increases in depreciation expense due to higher plant in service;

•

$6.6 million of increases in software development depreciation; and

•

$2.6 million of increases in the amortization of regulatory assets.

Taxes, other than income taxes, increased $1.9 million, or 2.0%, primarily due to:

•

$2.1 million of increases in franchise taxes.

Other Operating Expense

Other operating expense increased $13.2 million, primarily due to:

•

Changes in regulatory assets and liabilities.

Interest and Other (Income) Expense

	Year Ended March 31,

(Millions of dollars)	2004			2003			$ Change			% Change


Interest expense	$	256.5		$	270.3		$	13.8		5.1	%
Interest income		(13.8	)		(21.6	)		(7.8	)	(36.1	)
Interest capitalized		(19.9	)		(18.0	)		1.9		10.6
Minority interest and other		2.4			19.0			16.6		87.4

Total	$	225.2		$	249.7		$	24.5		9.8

Interest expense decreased $13.8 million, or 5.1%, primarily due to:

•

$15.3 million of decreases in interest expense on regulatory liabilities; partially offset by,

•

Dividends declared on Preferred stock subject to mandatory redemption of $3.4 million which were included as interest expense for the year ended March 31, 2004, in accordance with SFAS No. 150, Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity (“SFAS No. 150”), which became effective beginning after June 30, 2003.

Interest income decreased $7.8 million, or 36.1%, primarily due to:

•

$3.6 million of decreases in interest income on regulatory assets;

•

A $1.1 million decrease due to interest income recognized on an electricity sales contract settlement in September 2002; and

•

A $1.5 million decrease due to interest income on the settlement of an excise tax case in March 2002.

Interest capitalized increased $1.9 million, or 10.6%, primarily due to:

•

Higher capitalization rates and qualifying construction work-in-progress balances.

Minority interest and other expense decreased $16.6 million, or 87.4%, primarily due to:

•

A decrease in distributions on Preferred Securities, which were redeemed in August 2003.

Income Tax Expense

Income tax expense increased $47.3 million, or 48.7%, primarily due to:

•

Higher levels of income from continuing operations before income taxes and cumulative effect of accounting change for the year ended March 31, 2004 compared to the prior year; partially offset by,

•

$12.2 million of a net tax contingency reserve released during the year ended March 31, 2004 as a result of agreements in principle with the Internal Revenue Service on prior year tax examinations.

Cumulative Effect of Accounting Change

There was a:

•

$0.9 million after-tax loss from the implementation of SFAS No. 143, Accounting for Asset Retirement Obligations, (“SFAS No. 143”) in the year ended March 31, 2004; and

•

$1.9 million after-tax loss from the implementation of the DIG revised Issue C15 and Issue C16 recorded in the year ended March 31, 2003.

Year Ended March 31, 2003 Compared to Year Ended March 31, 2002

In February 2002, PacifiCorp transferred all of the capital stock of its subsidiary PGHC to PHI through a corporate restructuring. PGHC includes the wholly owned subsidiary, PFS, a financial services business. As a result of this transfer, the operations of PGHC are included in PacifiCorp’s Statements of Consolidated Income and Statements of Consolidated Cash Flows for the first 10 months of the year ended March 31, 2002, but are not included for the year ended March 31, 2003.

Revenues

(Millions of dollars)	Year Ended March 31,

	2003		2002			$ Change			% Change

Electric Operations
Residential	$	914.7	$	901.7		$	13.0		1.4	%
Commercial		763.4		747.7			15.7		2.1
Industrial		699.2		705.1			(5.9	)	(0.8	)
Other retail revenues		31.4		34.5			(3.1	)	(9.0	)

Retail sales		2,408.7		2,389.0			19.7		0.8
Wholesale sales		545.4		980.4			(435.0	)	(44.4	)
Other revenues		128.3		(28.3	)		156.6		*

Total		3,082.4		3,341.1			(258.7	)	(7.7	)
Other Operations		—		12.6			(12.6	)	(100.0	)

Total revenues	$	3,082.4	$	3,353.7		$	(271.3	)	(8.1	)

Energy sales (Thousands of MWh)
Electric Operations
Residential		13,287		13,395			(108	)	(0.8	)
Commercial		14,006		13,810			196		1.4
Industrial		19,048		19,611			(563	)	(2.9	)
Other		631		711			(80	)	(11.3	)

Retail sales		46,972		47,527			(555	)	(1.2	)
Wholesale sales		14,873		13,403			1,470		11.0

Total		61,845		60,930			915		1.5

Average residential usage (kWh)		10,182		10,411			(229	)	(2.2	)
Total customers - end of period (in thousands)		1,542		1,517			25		1.6

* Not a meaningful number.

Electric Operations

Residential revenues increased $13.0 million, or 1.4%, due to:

•

$17.8 million of increases from higher rates approved by state regulatory agencies; and

•

$12.5 million of increases relating to growth in the average number of residential customers of 1.6%; partially offset by,

•

$17.3 million of decreases from lower average customer usage due to milder weather as compared to the year ended March 31, 2002.

Commercial revenues increased $15.7 million, or 2.1%, due to:

•

$16.7 million of increases from growth in the average number of commercial customers; and

•

$6.8 million of increases from higher rates; partially offset by,

•

$7.8 million in reduced revenues from lower average customer usage due to then current economic conditions.

Industrial revenues decreased $5.9 million, or 0.8%, due to:

•

$27.0 million of decreases caused by reduced customer numbers; and lower average customer usage mainly as a result of a weaker economy; partially offset by,

•

$21.1 million of increases resulting from higher rates.

Wholesale sales decreased $435.0 million, or 44.4%, due to:

•

$1.9 billion of decreases due to a sharp decline in prices realized for short-term and spot-market sales as compared to those in the year ended March 31, 2002. Factors contributing to the lower market prices included new generation in the western United States, the continuing effect of the FERC market price mitigation and lower average natural gas prices paid as compared to average prices paid in the year ended March 31, 2002. Demand growth in the Western Electricity Coordinating Council area was lower than the 10-year average, due to slower than historical United States economic growth and weather, which was milder than the year ended March 31, 2002; and

•

$152.0 million of decreases related to lower unrealized gains on energy derivatives as compared to the year ended March 2002; partially offset by,

•

$1.6 billion of an increase due to higher volumes, as PacifiCorp increased the volume of system-balancing activities.

Other revenues increased $156.6 million, primarily due to:

•

$172.9 million of increases due to the higher value, in the year ended March 31, 2003 as compared to the year ended March 31, 2002, of net margins from sales and purchases that did not physically settle;

•

$20.7 million of an increase from the release of reserves on an electricity sales contract following a settlement of a dispute with respect to the contract; and

•

$4.6 million of increases in sales under a contract for renewable power; partially offset by,

•

$26.8 million of decreases in wheeling revenues, primarily due to lower volumes;

•

$6.1 million of decreases from the amortization of the gain from the sale of the Centralia, Washington plant and mine;

•

$6.0 million of decreases relating to recognition of Oregon merger credits; and

•

$3.6 million of decreases due to lower demand-side management revenues.

Other operations

Other operations revenue decreased $12.6 million, due to:

•

PGHC being transferred to PHI in fiscal 2003.

Operating Expenses

(Millions of dollars)	Year Ended March 31,

	2003		2002		$ Change			% Change

Electric Operations
Purchased electricity	$	698.5	$	974.4	$	275.9		28.3	%
Fuel		482.2		490.9		8.7		1.8
Operations and maintenance		885.1		806.2		(78.9	)	(9.8	)
Depreciation and amortization		434.3		401.3		(33.0	)	(8.2	)
Taxes, other than income taxes		93.4		90.7		(2.7	)	(3.0	)

Total		2,593.5		2,763.5		170.0		6.2
Other Operations		—		9.0		9.0		100.0

Total operating expenses	$	2,593.5	$	2,772.5	$	179.0		6.5

Electric Operations

Purchased electricity expense decreased $275.9 million, or 28.3%, primarily due to:

•

$1.9 billion of decreases from prices incurred for short-term and spot market purchases, which were 68.3% lower than average prices incurred for the year ended March 31, 2002. Lower market prices resulted from the same factors mentioned above for lower requirements for wholesale sales; and

•

$65.7 million of a decrease as a result of lower demand-side management expenses as compared to March 2002; partially offset by,

•

$1.5 billion of increases to purchased electricity expense from higher wholesale purchase volumes, as PacifiCorp increased the volume of system-balancing activities to balance its load requirements and to replace thermal generation lost from outages; and

•

$185.5 million of increases due to lower deferrals of purchased electricity costs as compared to March 2002.

Fuel expense decreased $8.7 million, or 1.8%, due to:

•

$20.7 million of decreases from lower natural gas volumes;

•

$16.5 million of decreases from lower natural gas prices; and

•

$9.7 million of decreases from lower coal volumes; partially offset by,

•

$21.2 million of increases from the incremental impact of PacifiCorp’s operating lease of the West Valley natural gas-fired facility; and

•

$17.0 million of increases from higher coal prices caused by higher employee benefit costs at PacifiCorp-owned mines and the costs of external coal purchases.

Operations and maintenance expense increased $78.9 million, or 9.8%, primarily due to:

•

$31.7 million of increases in property and liability insurance costs resulting from higher premiums, insurance reserves and storm damage;

•

$25.2 million of increases in employee expenses, including pensions and health care costs;

•

$24.0 million of increases from the establishment in the year ended March 31, 2003 of a reserve for the FERC issues and for potential California refunds;

•

$17.5 million of increases for mine reclamation costs;

•

$12.1 million of increases in rent expense for the West Valley operating lease;

•

$10.2 million of increases in generation materials and contract services, primarily due to the scope and timing of generating plant overhauls; and

•

$8.8 million of increases due to lower capitalized costs; partially offset by,

•

$22.1 million of decreases resulting from the temporary lease of a generating turbine in the year ended March 31, 2002;

•

$13.7 million of decreases in demand-side-management costs;

•

$11.7 million reserve for bad debts recorded in the year ended March 31, 2002;

•

$2.1 million of decreases in tree trimming expense; and

•

$2.0 million of decreases in consulting expense.

Depreciation and amortization expense increased $33.0 million, or 8.2%, primarily due to:

•

$14.4 million of increases due to the termination at March 31, 2002 of a two-year depreciation expense reduction ordered by state regulatory commissions;

•

$9.5 million of increases due to increased Property, plant and equipment balances;

•

$4.7 million of increases due to increased amortization of Regulatory assets and liabilities; and

•

$4.2 million of increased software amortization.

Taxes, other than income taxes increased $2.7 million, or 3.0%, primarily due to:

•

Settlements and adjustments that lowered property tax expense during the year ended March 31, 2002.

Other Operating Income

Other operating income decreased $32.4 million primarily due to:

•

$21.0 million of decreases relating to a regulatory settlement that resulted in the establishment of a regulatory asset recorded during the year ended March 31, 2002; and

•

$11.3 million of decreases from a gain on the sale of synthetic-fuel operations in the year ended March 31, 2002.

Gain on Sale of Operating Assets

Gain on sale of operating assets was due to:

•

$27.4 million of additional proceeds received in the year ended March 31, 2002 from the resolution of a contingency under the provisions of the sale of PacifiCorp’s Australian Operations.

Other Operations

Other operations expense decreased $9.0 million, due to:

•

PGHC being transferred to PHI in February 2002.

Interest and Other (Income) Expense

	Year Ended March 31,

(Millions of dollars)	2003			2002			$ Change			% Change

Interest expense	$	270.3		$	227.7		$	(42.6	)	(18.7	)%
Interest income		(21.6	)		(47.5	)		(25.9	)	(54.5	)
Interest capitalized		(18.0	)		(6.9	)		11.1		160.9
Minority interest and other		19.0			(1.8	)		(20.8	)	*

Total	$	249.7		$	171.5		$	(78.2	)	(45.6	)

* Not a meaningful number.

Interest expense increased $42.6 million, or 18.7%, primarily due to:

•

Higher average long-term debt balances due to PacifiCorp issuing $800.0 million of new long-term debt in November 2001; and

•

$20.9 million of increases in interest expense for regulatory liabilities; partially offset by,

•

Lower average short-term and variable-interest rates.

Interest income decreased $25.9 million, or 54.5%, primarily due to:

•

$17.2 million of a decrease in interest income on notes receivable balances and temporary cash investments due to the transfer of PGHC to PHI in February 2002; and

•

$11.1 million of a decrease in interest income on regulatory assets; partially offset by,

•

$1.5 million of interest income on the settlement of an excise tax case with the state of Washington in March 2002; and

•

The recognition of $1.1 million of interest income on an electricity sales contract settlement in September 2002.

Interest capitalized increased $11.1 million due to:

•

Higher capitalization rates, as a return on equity component was included; and

•

Higher qualifying construction work-in-progress balances.

Minority interest and other expense increased $20.8 million primarily due to:

•

$18.9 million of Other income pertaining to PGHC in the year ended March 31, 2002;

•

$9.3 million in gains on sales of leased aircraft owned by PFS recorded during the year ended March 31, 2002; and

•

The reversal in the year ended March 31, 2003 of a previously recorded gain of $3.4 million as a result of a regulatory order; partially offset by,

•

$4.8 million in gains on various settlements during the year ended March 31, 2003; and

•

$3.7 million in gains on sales of non-utility investments in the year ended March 31, 2003.

Income Tax Expense

Income tax expense decreased $78.9 million primarily due to:

•

Lower income from continuing operations before income taxes and cumulative effect of accounting change in the year ended March 31, 2003; and

•

The additional tax reserves established in the year ended March 31, 2002 for the amounts proposed as a result of the Internal Revenue Service audit adjustments for tax years 1994 through 1998.

The combined federal and state effective income tax rate of 40.6% for the year ended March 31, 2003 varied from the statutory rate primarily due to the tax effects of the regulatory treatment of depreciation, which were partially offset by income tax credits. The combined federal and state effective income tax rate was 37.5% for the year ended March 31, 2002.

Discontinued Operations

•

$146.7 million of income during the year ended March 31, 2002, as a result of collecting a contingent note receivable relating to the discontinued operations of PacifiCorp’s 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’s receiving payment under a coal supply contract. PGHC recognized this gain on a cost-recovery basis as payments were received from the buyer. In June 2001, PGHC 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.

Cumulative Effect of Accounting Change

•

A $1.9 million after-tax loss from the implementation of revised DIG Issue C15 and Issue C16 was recorded during the year ended March 31, 2003; and

•

A $112.8 million after-tax loss from the implementation of SFAS No. 133 was recorded during the year ended March 31, 2002.

LIQUIDITY AND CAPITAL RESOURCES

Sources and Uses of Cash

PacifiCorp depends on both internal and external sources of liquidity to provide working capital and to fund capital requirements. Short-term cash requirements not met by cash provided by operating activities are generally satisfied with proceeds from short-term borrowings. Long-term cash needs are met through sales of securities, including additional long-term debt issuances, and also by issuance of common equity. Issuance of longer-term securities is influenced by levels of short-term debt, cash from operations, capital expenditures, market conditions, regulatory approvals and other considerations.

Operating Activities

Net cash provided by operating activities increased $150.3 million to $831.9 million for the year ended March 31, 2004, due primarily to an increase in Net income of $108.0 million, decrease in tax payments related to prior period Internal Revenue Service audits of $66.6 million, and the timing of collections and payments. Net cash provided by operating activities is impacted by seasonal movements in working capital and whether or not operating costs are recovered in rates and by the timing of that recovery.

Net cash flows provided by operating activities increased by $339.0 million to $681.6 million for the year ended March 31, 2003, as compared to $342.6 million for the year ended March 31, 2002. During the year ended March 31, 2003, PacifiCorp received cash recoveries of $111.1 million of previously deferred net power costs and $44.0 million of additional cash revenues from general rate case increases.

Investing Activities

Capital spending totaled $690.4 million for the year ended March 31, 2004, as compared to $550.0 million for the year ended March 31, 2003 and $505.3 million for the year ended March 31, 2002. The increases are primarily due to increasing expenditures for distribution network growth and system upgrades, plant refurbishments and hydroelectric relicensing. For the year ended March 31, 2004, $44.7 million was spent for the construction of the Currant Creek project and $91.5 million was spent on distribution and transmission system upgrades along the Wasatch Front.

Proceeds from a finance note repayment of $189.9 million in the year ended March 31, 2002 represented the payment of a note receivable held by PGHC relating to the discontinued operations of NERCO. Certain types of investing activities for the year ended March 31, 2002 do not appear in the year ended March 31, 2003, due to the transfer of PGHC and its subsidiaries from PacifiCorp to PHI. In the year ended March 31, 2002, net payments made by PGHC to affiliates were $358.2 million.

Financing Activities

Short-Term Debt

PacifiCorp’s short-term debt has increased by $99.9 million during the year ended March 31, 2004 due primarily to changes in working capital, maturing long-term debt, increased capital expenditures and the resumption of paying dividends on common shares. Short-term debt decreased $152.5 during the year ended March 31, 2003 primarily

due to the issuance of Common stock and an increase in cash from operations. Short-term debt decreased $64.0 million during the year ended March 31, 2002 primarily due to the issuance of long-term debt.

Revolving Credit Agreements

PacifiCorp’s short-term borrowings and certain other financing arrangements are supported by $800.0 million of revolving credit agreements, with one facility for $300.0 million, with a three-year term that became effective June 4, 2002, and the other facility for $500.0 million, with a 364-day term plus a one-year term loan option that became effective June 3, 2003. PacifiCorp is currently seeking to replace the existing facilities on terms and conditions similar to the existing facilities. While PacifiCorp believes the facilities will be successfully replaced, no assurance can be given as to this outcome. The interest on advances under these facilities is based on the London Interbank Offered Rate (LIBOR) plus a margin that varies based on PacifiCorp’s credit ratings. As of March 31, 2004, these facilities were fully available and there were no borrowings outstanding. In addition to these committed credit facilities, PacifiCorp had $45.6 million in money market accounts included in Cash and cash equivalents at March 31, 2004 available to meet its liquidity needs. Regulatory authorities limit PacifiCorp to $1.5 billion of short-term debt, of which $124.9 million was outstanding at March 31, 2004 at a weighted average rate of 1.1%.

At March 31, 2004, PacifiCorp had $517.8 million of standby letters of credit and standby bond purchase agreements available to provide credit enhancement and liquidity support for variable-rate pollution-control revenue bond obligations. These committed bank arrangements expire periodically through the year ending March 31, 2006.

Long-Term Debt

During July and August 2003, PacifiCorp redeemed, prior to maturity, First Mortgage Bonds totaling $57.5 million and Preferred Securities totaling $352.0 million. For the year ended March 31, 2004, PacifiCorp made scheduled long-term debt repayments of $136.6 million. These retirements were funded initially with short-term debt. In September 2003, PacifiCorp issued $200.0 million of its 4.30% First Mortgage Bonds due September 15, 2008 and $200.0 million of its 5.45% First Mortgage Bonds due September 15, 2013.

PacifiCorp’s Mortgage and Deed of Trust creates a lien on most of PacifiCorp’s electric utility property.

PacifiCorp’s Mortgage allows the issuance of bonds based on:

•

A percentage of utility property additions;

•

Bond credits arising from retirement of previously outstanding bonds; and/or

•

Deposits of cash.

The amount of bonds that PacifiCorp may issue generally is also subject to a net earnings test. As of March 31, 2004, PacifiCorp estimates it would be able to issue up to $3.7 billion of new First Mortgage Bonds under the most restrictive issuance test in the Mortgage. Any issuances would be subject to market conditions and amounts may be further limited by regulatory authorizations or by covenants and tests contained in other financing agreements. PacifiCorp also has the ability to release property from the lien of the Mortgage on the basis of property additions, bond credits and/or deposits of cash.

For the year ended March 31, 2003, PacifiCorp issued no long-term debt and made scheduled long-term debt repayments of $144.6 million. For the year ended March 31, 2002, PacifiCorp issued $800.0 million of long-term debt and made scheduled long-term debt repayments of $59.0 million.

Amounts Available under Shelf Registrations

At March 31, 2004, PacifiCorp had $650.0 million available under currently effective shelf registrations. Securities that may be issued under these registrations include first mortgage bonds, unsecured debt securities and no par serial preferred stock.

Common Stock

In December 2002, PacifiCorp issued 14,851,485 shares of its common stock to PHI at a total price of $150.0 million, or $10.10 per share. PacifiCorp used the proceeds from the sale of these shares to repay debt and for general corporate purposes.

Preferred Stock Redemptions

PacifiCorp redeemed $7.5 million of Preferred stock subject to mandatory and optional redemption during each of the years ended March 31, 2004 and 2003 and redeemed $100.0 million during the year ended March 31, 2002.

Dividends

During the year ended March 31, 2004, PacifiCorp had the following dividend activity:

•

$160.6 million declared and paid on common stock;

•

$2.1 million declared and paid on Preferred stock, with $0.5 million in dividends declared but unpaid at March 31, 2004; and

•

$4.6 million declared and $4.7 million paid on Preferred stock subject to mandatory redemption, with $1.1 million in dividends declared but unpaid at March 31, 2004. The dividends declared after June 30, 2003 of $3.4 million were recorded as interest expense in accordance with SFAS No. 150, adopted on July 1, 2003.

During the year ended March 31, 2003, PacifiCorp had the following dividend activity:

•

$7.3 million declared and paid on Preferred stock, with $1.8 million in dividends declared but unpaid at March 31, 2003.

During the year ended March 31, 2002, PacifiCorp had the following dividend activity:

•

$240.8 million declared and $298.6 million paid on common stock; and

•

$9.8 million declared and $11.7 million paid on Preferred stock, with $1.9 million in dividends declared but unpaid at March 31, 2002.

Cautionary Statement

Management expects existing funds and cash generated from operations, together with existing credit facilities, to be sufficient to fund liquidity requirements for the next 12 months. If market conditions warrant during the year ending March 31, 2005, PacifiCorp may seek to issue long-term debt to more permanently fund its liquidity requirements or refinance maturing long-term debt.

Capitalization

	March 31,

(Millions of dollars, except percentages)	2004				2003

Short-term debt and long-term debt currently maturing	$	364.9	5.0	%	$	161.7	2.2	%
Long-term debt		3,520.2	48.5			3,417.6	47.3
Preferred Securities of Trusts		—	—			341.8	4.7
Preferred stock subject to mandatory redemption		60.0	0.8			66.7	0.9
Preferred stock		41.3	0.6			41.3	0.6
Common equity		3,278.7	45.1			3,194.4	44.3

Total capitalization	$	7,265.1	100.0	%	$	7,223.5	100.0	%

PacifiCorp manages its capitalization and liquidity position through policies established by senior management and the PacifiCorp Board of Directors. A key objective is retention of existing credit ratings, which is expected to help allow access to flexible borrowing arrangements at favorable costs and rates. These policies, subject to periodic

review and revision, attempt to balance the interests of all shareholders, ratepayers and creditors, and to provide a competitive cost of capital and predictable capital market access.

On a consolidated basis, PacifiCorp attempts to maintain total debt at approximately 48.0% to 54.0% of capitalization. The total debt-to-capitalization ratio was 53.5% at March 31, 2004. PacifiCorp expects to maintain, over time, its capital structure in accordance with its targets. PacifiCorp has made commitments in connection with its merger with ScottishPower (the “Merger”), not to make distributions that result in a reduction of common equity, without approval, to below 39.0% of total capitalization, excluding short-term debt and current maturities of long-term debt, increasing over time to 40.0%.

As a result of recent changes in accounting standards, it is possible that new purchase power and gas agreements or amendments to existing arrangements may be accounted for as obligations on PacifiCorp’s financial statements. The effect of this may make it more difficult for PacifiCorp to comply with financial covenants in financing arrangements that contain a debt-to-capitalization test, as well as regulatory commitments concerning minimum levels of common equity as a percentage of capitalization. This may lead PacifiCorp to seek amendments or waivers to its covenants and commitments, delay or reduce spending programs or seek additional new common equity from its immediate parent, PacifiCorp Holdings, Inc.

Variable-Rate Liabilities

	March 31,

(Millions of dollars)	2004			2003

Short-term debt	$	124.9		$	25.0
Variable-rate long-term debt		541.7			654.5

	$	666.6		$	679.5

Percentage of total capitalization		9.2	%		9.4	%

PacifiCorp’s capitalization policy targets consolidated variable-rate liabilities at between 10.0% and 25.0% of total capitalization. PacifiCorp was slightly below the target range at March 31, 2004, and anticipates that variable-rate exposure will be at the lower end of the range during the year ending March 31, 2005.

Limitations

In addition to PacifiCorp’s capital structure policies, its debt capacity is also governed by its contractual commitments. PacifiCorp’s credit agreement contains customary covenants and default provisions, including covenants to maintain a debt-to-capitalization ratio. 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. PacifiCorp monitors the covenants on a regular basis in order to ensure that events of default will not occur. As of March 31, 2004, PacifiCorp was in compliance with the covenants of its credit agreement. Based on PacifiCorp’s most restrictive agreement, management believes that PacifiCorp could have borrowed an additional $1.2 billion at March 31, 2004. Any additional borrowings would be subject to market conditions, and amounts may be further limited by regulatory authorizations or by covenants and tests contained in other financing agreements.

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 PacifiCorp Board of Directors.

FUTURE USES OF CASH

Capital Expenditure Program

The following table shows actual capital expenditures for the year ended March 31, 2004 and PacifiCorp’s estimated capital expenditures for the years ending March 31, 2005 through 2007.

	Actual		Estimated

	Years Ending March 31,

(Millions of dollars)	2004		2005		2006		2007

Distribution and Transmission	$	348.9	$	377.4	$	437.5	$	418.7
Generation and Mining		271.6		441.9		549.7		552.6
Other		69.9		67.9		82.2		109.1

Total	$	690.4	$	887.2	$	1,069.4	$	1,080.4

Actual and estimated future capital expenditures include upgrades to distribution and transmission lines and existing generation plants, connections for new customers, facilities to accommodate load growth, coal mine investments, air-quality and environmental expenditures, hydroelectric relicensing costs and information technology systems. In addition, these estimates include costs to have the Currant Creek plant constructed through fiscal year 2007 and costs to have the Lake Side Power Plant developed and constructed to meet customer resource needs in summer 2007. PacifiCorp expects that these and future costs will be deemed prudent and recoverable in future rates. All of these expenditures are subject to continuing review and revision by PacifiCorp, and actual costs could vary from estimates due to various factors, such as changes in business conditions, revised load-growth estimates, future legislative and regulatory developments and increasing costs in labor, equipment and materials.

The estimates of capital expenditures for the years ending March 31, 2005 through 2007 generally exclude the potential impact on generation and transmission capacity of future decisions arising from further stages of the Requests for Proposals process to support the Integrated Resource Plan. Additional expenditures may be significant but are spread over a number of years, and cannot be accurately estimated, or included in the table, at this time. Based on future decisions arising from the Request for Proposals process, the capital expenditure program table may be updated in future quarters.

In funding its capital expenditure program, PacifiCorp expects to obtain funds required for construction and other purposes from sources similar to those used in the past, including operating cash flows and the issuance of new long-term and short-term debt. To maintain an appropriate capital structure and access to the capital markets, PacifiCorp may also require additional equity over the next several years through its immediate corporate parent, PacifiCorp Holdings, Inc. However, the amount, type and timing of any financings, if necessary, will depend upon levels of capital expenditures, operating cash flows, returns available, market conditions and regulatory approval, and there can be no assurance that such financings will be available on favorable terms, if at all.

In recently completed rate cases, regulators in Utah, Oregon and Wyoming allowed cost recovery on new investments for growth. This includes recovery of the investment costs themselves and inclusion in regulatory rate base, as well as recovery of operations and maintenance expenses. In addition, PacifiCorp is requesting similar cost recovery and rate-base treatment of growth investments in the general rate case currently in process in Washington. PacifiCorp has not yet filed rate cases in Idaho and California that include investments for growth, but expects to do so in the future.

Contractual Obligations and Commercial Commitments

Contractual Obligations

The table below shows PacifiCorp’s contractual obligations as of March 31, 2004.

	Payments due during the years ending March 31,

(Millions of dollars)	2005		2006 - 2007		2008 - 2009		Thereafter		Total


Short-term debt, including interest	$	125.0	$	—	$	—	$	—	$	125.0
Long-term debt, including interest		452.1		906.2		853.8		3,837.3		6,049.4
Capital lease minimum payments		3.4		7.0		7.4		48.6		66.4
Preferred stock subject to mandatory redemption		3.7		7.5		48.8		—		60.0
Power purchase agreements (a)		961.6		1,470.2		845.7		3,312.7		6,590.2
Purchase obligations (b)		97.6		3.6		0.3		—		101.5
Operating leases		22.1		11.7		3.6		9.2		46.6
Asset retirement obligations (c)		13.7		29.8		25.1		288.3		356.9
Hydroelectric (d)		10.2		15.0		15.9		350.0		391.1

Total contractual cash obligations	$	1,689.4	$	2,451.0	$	1,800.6	$	7,846.1	$	13,787.1

(a)

PacifiCorp’s power contract commitments include purchases or exchanges of coal, electricity and natural gas. PacifiCorp manages its energy resource requirements by integrating short- and long-term purchases with its own generating resources to dispatch the system economically and to meet commitments for wholesale sales and retail load growth. As part of its energy resource portfolio, PacifiCorp acquires a portion of its resource requirements through long-term purchases and/or exchange agreements.

(b)

These contractual obligations include commitments for capital expenditures, including $91.9 million of minimum contractual obligations associated with the new Currant Creek plant.

(c)

Represents expected cash payments adjusted for inflation for estimated costs to perform asset retirement activities.

(d)

PacifiCorp has entered into settlement agreements with various interested parties that are incorporated into the hydroelectric licenses granted by the FERC. Hydroelectric licenses have varying expiration dates, and many expire within the next five years. The contractual commitments listed here expire with the license expiration dates. However, PacifiCorp plans to acquire new licenses that will allow for continued operation for more than 30 years and expects contractual commitments to continue or increase.

Commercial Commitments

PacifiCorp’s commercial commitments include surety bonds that provide indemnities for PacifiCorp in relation to various commitments it has to third parties for obligations in the event of default on behalf of PacifiCorp. The majority of these bonds are continuous in nature and renew annually. The estimates are based on current information and actual amounts may vary due to rate changes or changes to the general operations of PacifiCorp. PacifiCorp expects the level of its surety bonding beyond the year ended March 31, 2004 to remain at the historical average of approximately $25.0 million.

CREDIT RATINGS

PacifiCorp’s credit ratings at March 31, 2004 were as follows:

	Moody’s	S & P

Issuer/Corporate	Baa1	A-
Senior secured debt	A3	A
Senior unsecured debt	Baa1	BBB+
Preferred stock	Baa3	BBB
Commercial paper	P-2	A-2

Outlook	Negative	Negative

PacifiCorp’s credit ratings are unchanged from March 31, 2003. These security ratings are not recommendations to buy, sell or hold securities. The ratings are subject to change or withdrawal at any time by the respective credit rating agencies. Each credit rating should be evaluated independently of any other rating.

PacifiCorp 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 PacifiCorp’s 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 PacifiCorp’s commercial paper program, its principal source of short-term borrowing, and may result in the requirement that PacifiCorp post collateral under certain of PacifiCorp’s power purchase and other agreements. Certain authorizations or exemptions by regulatory commissions for the issuance of securities are valid as long as PacifiCorp maintains investment grade ratings on senior secured debt. A downgrade below that level would necessitate new regulatory applications and approvals.

In addition, a number of PacifiCorp’s agreements in the wholesale electric, wholesale natural gas and energy derivatives markets contain provisions that provide the right for either counterparty to receive cash or other security if mark-to-market 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, 2004, PacifiCorp estimates that a one level downgrade, by either Standard & Poor’s or Moody’s, of its senior unsecured debt ratings would not result in any cash or collateral requirements.

OFF-BALANCE SHEET ARRANGEMENTS

PacifiCorp from time to time enters into arrangements in the normal course of business to facilitate commercial transactions with third parties that involve guarantee, indemnification or similar arrangements. PacifiCorp currently has indemnification obligations for breaches of warranties or covenants in connection with the sale of certain assets. In addition, PacifiCorp evaluates potential obligations that arise out of variable interests in unconsolidated entities, determined in accordance with FASB Interpretation No. 46, Consolidation of Variable-Interest Entities, an interpretation of Accounting Research Bulletin No. 51. See Note 11 of the Consolidated Financial Statements for more information on these obligations and arrangements. PacifiCorp believes that the likelihood that it would be required to perform or otherwise incur any significant losses associated with any of these obligations is remote.

INFLATION

PacifiCorp is subject to rate-of-return regulation and the impact of inflation on the level of cost recovery under regulation varies by state depending upon the type of test-period convention used in the state. In PacifiCorp’s state jurisdictions, a 12-month period of historical costs is typically used as the basis for developing a “test year,” which may also include various adjustments to eliminate abnormal or onetime events, normalize cost levels, or escalate the historical costs to a future level when the new rates will actually be in effect. To the extent that the levels of costs beyond the historical 12-month period can be established either through known adjustments or through the escalation of cost levels in establishing prices, PacifiCorp can mitigate the impacts of inflationary pressures. PacifiCorp is seeking to establish a uniform use of future test periods to deal with the rising cost of service and required capital investment.

RISK FACTORS

MARKET RISK

In general, market risk is the risk of fluctuations in the market price of electricity and fuel, including natural gas and coal, and is compounded by volumetric risk caused by changes in PacifiCorp’s loads and generation due to weather, the economy, unanticipated generation or alterations due to changes in market prices as well as customer behavior. Market price is influenced primarily by factors throughout the western United States 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, and changes in technology.

While PacifiCorp 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 net power costs to PacifiCorp. At certain times of year, prices paid by PacifiCorp to obtain certain load balancing resources to satisfy its load requirements may exceed the amounts it receives through retail rates from those loads. In such circumstances, PacifiCorp would seek to recover excess power costs through regulatory mechanisms.

OPERATING RISK

PacifiCorp faces a number of ongoing operational risks. These risks are continuously managed on a prudent basis in order to ensure that PacifiCorp meets its obligation to serve its customers. Given the complex nature of PacifiCorp’s vertically integrated operations and the large, geographically dispersed nature of its operations, those risks are inherently diverse. Management believes the following operational risks are significant:

•

Generation facilities:

•

Thermal and hydroelectric performance, plant maintenance and loss of generating availability; and

•

Managing physical fuel supply, including coal and natural gas.

•

Mining operations:

•

Access to sufficient coal reserves at required quality.

•

Distribution and transmission system:

•

Management of network reliability, including maintenance;

•

Levels of network reliability in emergency conditions, including storm situations; and

•

System restrictions, management of transmission scheduling and capacity limits.

•

Wholesale energy transactions:

•

Effectiveness of energy balancing activities to serve load.

•

Information technology:

•

Maintaining critical information technology systems and reliance thereon.

•

Labor relations:

•

Availability of skilled labor;

•

Work stoppages due to union disputes;

•

Attracting and retaining key personnel; and

•

Maintaining safe working conditions.

•

Security:

•

Effectiveness of security policies and disaster recovery plans in safeguarding assets.

All of these risks are mitigated through a combination of risk management policies, procedures and prudent operational practices and processes.

NEW RESOURCE RISK

PacifiCorp is in the process of having new generating facilities constructed in Utah, which are referred to as Currant Creek and as Lake Side. Through the outcome of the Requests for Proposals process, further facilities may require construction for or by PacifiCorp. The completion of these facilities without delays or cost overruns is subject to risks, including:

•

shortages and inconsistent quality of equipment, materials and labor;

•

costs of raw materials;

•

work stoppages due to union disputes;

•

permits, approvals and other regulatory matters;

•

adverse weather conditions;

•

unforeseen engineering problems;

•

environmental and geological conditions;

•

delays or increased costs to interconnect its facilities to transmission grids; and

•

unanticipated cost increases.

If PacifiCorp is unable to have the development or construction of a facility completed, or if PacifiCorp decides to delay or cancel construction of a facility, PacifiCorp may not be able to recover its investment in that facility. In addition, construction delays and contractor performance shortfalls can result in increased costs for purchased electricity and may, in turn, adversely affect PacifiCorp’s results of operations and financial position. Furthermore, if construction projects are not completed according to specification, PacifiCorp may incur liabilities and suffer reduced plant efficiency, higher operating costs and reduced earnings.

REGULATORY RISK

PacifiCorp is subject to the jurisdiction of federal and state regulatory authorities. The FERC establishes tariffs under which PacifiCorp provides wheeling service to the wholesale market and the retail market for states allowing retail competition, establishes both cost-based and market-based tariffs under which PacifiCorp sells electricity at wholesale and has licensing authority over most of PacifiCorp’s hydroelectric generation facilities. The utility regulatory commissions in each state independently determine the rates PacifiCorp may charge its retail customers in that state. Each state’s rate setting process is based upon the state commission’s acceptance of an allocated share of total PacifiCorp costs as its responsibility. When different states adopt different methods to address this interjurisdictional cost allocation issue, some costs may not be incorporated into rates in any state. Ratemaking is done on the basis of normalized costs, so if in a specific year realized costs are higher than normal, rates will not be sufficient to cover those costs. Likewise, if in a given year costs are lower than normal or revenues are higher, PacifiCorp retains the resulting higher-than-normal profit. Each commission sets rates based on a test year of its choosing. In states that use a historical test year, rate adjustments could follow cost increases, or decreases, by up to two years. Regulatory lag results in a delay in recovery of costs, including for new investments, currently incurred but not in rates, and also imposes a time-value-of-money burden on PacifiCorp. Further, each commission decides what level of expense and investment is necessary, reasonable and prudent in providing service. If a commission decides that part of PacifiCorp’s costs do not meet this standard, such costs will be disallowed and not recovered in rates. For these reasons, the rates authorized by the regulators may be less than the costs to PacifiCorp to provide electrical service to its customers in a given period.

Several of PacifiCorp’s hydroelectric projects are in some stage of the FERC relicensing under the Federal Power Act. The relicensing process is a political and public regulatory process that involves sensitive resource issues. PacifiCorp is unable to predict with certainty 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 PacifiCorp will be willing to meet the relicensing requirements to continue operating its hydroelectric projects.

Federal, state and local authorities regulate many of PacifiCorp’s activities pursuant to laws designed to restore, protect and enhance the quality of the environment. PacifiCorp is unable to predict with certainty what material impact, if any, future changes in environmental laws and regulations may have on PacifiCorp’s consolidated financial position, results of operations, cash flows, liquidity and capital expenditure requirements.

POLITICAL RISK

PacifiCorp conducts its business in conformance with a multitude of federal and state laws. During the past year, the United States Congress has had under active consideration but has been unable to pass in final form legislation making significant changes in energy, air quality and tax policy. Comprehensive energy legislation would affect the hydroelectric relicensing process under the Federal Power Act, extend the renewable energy production tax credit, and provide incentives for environmental investments at coal plants. These changes would likely benefit PacifiCorp’s efforts to develop, acquire and maintain a low-cost generation portfolio. The United States Senate recently passed legislation that includes an extension, through 2006, of the renewable energy production tax

credit and several other energy-related tax matters. For this legislation to proceed, the United States House of Representatives must pass the same legislation. The United States House of Representatives may address this legislation in the near future. Changes to the Clean Air Act have been proposed in the form of the President’s Clear Skies Act and other such bills limiting emissions of carbon dioxide. Congressional leaders have indicated that air emissions legislation may not receive formal action until calendar year 2005 at the earliest. Clear Skies and other air quality initiatives are being monitored closely by PacifiCorp because they may impact requirements to control emissions from fossil-fueled generation plants.

The laws of the states in which PacifiCorp operates affect PacifiCorp’s generation, transmission and distribution business. At present, California is the only state in which PacifiCorp provides retail service with a legislature still meeting in general session. PacifiCorp is not aware of any new laws passed by Idaho or Washington legislatures positively or negatively affecting PacifiCorp’s operations in a significant manner. The Utah legislature passed a state sales tax exemption for renewable energy equipment, which may make development of renewable energy resources in the state more economically viable. The Wyoming legislature passed legislation setting requirements for certifying mining foremen in underground operations who have transferred from similar roles in surface mining facilities. In California, PacifiCorp is monitoring discussion of several bills to revise the state’s 1996 electric restructuring law (AB 1890).

SECURITY RISK

Terrorism threats, both domestic and foreign, are an ongoing risk to the entire utility industry, including PacifiCorp. Specific potential disruptions to operations and information technologies or destruction of facilities from terrorism are not readily determinable. PacifiCorp has identified critical assets, created an effective management structure to respond to threats and developed several security approaches to security to meet the changed environment. A project is well under way that implements a comprehensive security plan, starting with the most critical assets. This plan is meant to mitigate threats from terrorist attacks and to initiate contingency plans in case PacifiCorp’s physical facilities or information technology environment are attacked. Additionally, the FERC and the North American Electric Reliability Council are promulgating standards to which PacifiCorp will be subject. PacifiCorp has completed a self-assessment of its current security plan as part of the North American Electric Reliability Council 1200 Urgent Action standard, which is directing PacifiCorp’s efforts. PacifiCorp is also communicating with the governmental entities in the United States and the United Kingdom that are charged with counteracting and preventing terrorist activities to help it refine its security approaches.

INSURANCE RISK

PacifiCorp continues to experience risk relating to increases in various insurance costs and premiums, as well as availability of insurance coverage for certain property and liability exposures.

The insurance market has changed sharply over the past three years. Significant reductions in market capacity and an increase in the incidents of losses worldwide contributed to unprecedented insurance program cost increases. During fiscal year 2004, the worldwide insurance market experienced mixed results. For property coverage, the market has softened slightly, meaning that premium increases are slowing; however, for liability coverage, increases in costs and coverage restrictions are still being imposed due to the continuing increase in claims costs.

PacifiCorp’s insurance strategy is to minimize and stabilize insurance costs, including uninsured losses. Insurance is purchased where appropriate, while certain risks are self-insured. This balance is monitored continually and altered as insurance market conditions and other factors change.

PacifiCorp’s insurance program has been fully reviewed again during fiscal year 2004. No significant changes have been made to the range of coverages purchased, and the limits of coverage and level of deductibles are considered appropriate for the risks identified. Market developments and new insurance products are analyzed as they become available, to identify whether they would be beneficial to PacifiCorp’s insurance program. Areas such as alternative business interruption products or a captive insurance firm are both currently under consideration.

Additional security requirements continue to be imposed by insurers, such as the requirement to post letters of credit as security for insurance programs including surety bonds and workers’ compensation coverage.

PENSION RISK

As a result of the decline in the equity markets and low interest rates, PacifiCorp anticipates that pension expense and PacifiCorp cash contributions into the pension trust will continue to increase in the near term. PacifiCorp is exposed to further increases in both expense and contribution levels if the capital markets underperform PacifiCorp’s long-term return expectations. In addition, low interest rates increase both funding requirements and expense levels since PacifiCorp’s pension liability increases as the discount rate declines. To the extent that actual interest rates fall below currently assumed levels, pension expense and contribution requirements will increase.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

PacifiCorp participates in a wholesale energy market that includes: public utility companies; electricity and natural gas marketers; financial institutions; industrial companies; and government entities. A variety of products exist in this market, ranging from electricity and natural gas purchases and sales for physical delivery to financial instruments such as futures, swaps, options and other complex derivatives. Transactions may be conducted directly with customers and suppliers, through brokers, or with an exchange that serves as a central clearing mechanism.

PacifiCorp is subject to the various risks inherent in the energy business, including credit risk, interest rate risk and commodity price risk.

Risk Management

PacifiCorp has a risk management committee, which is responsible for the oversight of market and credit risk relating to the commodity transactions of PacifiCorp. The risk management committee meets monthly and consists of the chief executive officer and officers from the finance, regulation, strategy, legal, wholesale and independent risk management group areas. To limit PacifiCorp’s exposure to market risk, the risk management committee, with the approval of the PacifiCorp and ScottishPower Boards of Directors, sets policies and limits and approves commodity strategies, which are reviewed frequently to respond to changing market conditions. To limit PacifiCorp’s exposure to credit risk in these activities, the risk management committee reviews counterparty credit exposure, as well as credit policies and limits, on a monthly basis.

Risk is an inherent part of PacifiCorp’s business and activities. The risk management process established by PacifiCorp is designed to identify, assess, monitor, report, manage and mitigate each of the various types of risk involved in its business and activities and 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, PacifiCorp enters into various transactions, including derivative transactions, consistent with PacifiCorp’s risk management policy. The risk management policy governs energy and fuel transactions and is designed for hedging PacifiCorp’s existing energy and asset exposures. The policy also governs PacifiCorp’s use of derivative instruments, as well as its energy purchase and sales practices, and describes PacifiCorp’s credit policy and management information systems required to effectively monitor such derivative use. PacifiCorp’s risk management policy provides for the use of only those instruments that have a close volume or price correlation with its portfolio of assets, liabilities or anticipated transactions, thereby ensuring that such instruments will be primarily used for hedging. PacifiCorp’s portfolio of energy derivatives is substantially used for non-trading purposes.

PacifiCorp continues to take steps to manage commodity price volatility and reduce exposure. These steps may include adding to the generation portfolio and entering into transactions to help to shape PacifiCorp’s system resource portfolio, including physical hedging products and financially settled (temperature-related) derivative instruments that reduce volume and price risk on days with weather extremes. In addition, a financial hydroelectric generation hedge is in place through September 2006 to reduce volume and price risks associated with PacifiCorp’s hydroelectric generation availability.

Credit Risk

Credit risk relates to the risk of loss that might occur as a result of non-performance by counterparties of their contractual obligations to make or take delivery of electricity, natural gas or other commodities and to 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 involving other market participants that have a direct or indirect relationship with such counterparty.

PacifiCorp 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. PacifiCorp continues to actively monitor the creditworthiness of those counterparties with whom it executes wholesale energy and natural gas purchase and sales transactions within the Western Electricity Coordinating Council and uses a variety of risk mitigation techniques to limit its exposure where it believes appropriate. When PacifiCorp considers a new asset purchase, transaction or contractual arrangement, market liquidity and the ability to optimize the investment are main considerations. To mitigate exposure to the financial risks of wholesale counterparties, PacifiCorp has entered into netting and collateral agreements, including margining, guarantee, letters of credit and cash deposit arrangements. Counterparties may be assessed interest fees for delayed receipts. If required, collection rights are exercised, including calling on the counterparty’s credit support arrangement.

The table below represents PacifiCorp’s March 31, 2004 distribution of unsecured credit exposure, net of collateral, within its electricity and natural gas portfolio of purchase and sale contracts and takes into account contractual netting rights.

Distribution of Credit Exposure	% of Total

Investment grade - Externally rated	90.5	%
Non-investment grade - Externally rated	6.2
Investment grade - Internally rated	2.5
Non-investment grade - Internally rated	0.8

	100.0	%

“Externally rated” represents enterprise relationships that have published ratings from at least one major credit rating agency. “Internally rated” represents those relationships that have no rating by a major credit rating agency. For those relationships, PacifiCorp utilizes commercially appropriate rating methodologies and credit scoring models to develop a public rating equivalent.

The number of counterparties in the wholesale energy markets with whom PacifiCorp is able to prudently transact business has declined since 2001. Merchant energy companies, which over most of the past decade were an important source of liquidity in the wholesale markets, are suffering from high debt levels and low operating cash flows resulting from an overbuild of generation plants in parts of the United States. Many of these merchant energy companies have either significantly reduced or withdrawn from trading in the wholesale market. Certain major financial institutions have entered or increased their participation in the wholesale market, partially offsetting this decline; however, the wholesale market in which PacifiCorp participates consists of fewer participants and has a lower overall credit quality.

Interest Rate Risk

PacifiCorp is exposed to risk resulting from changes in interest rates as a result of its issuance of variable-rate debt and commercial paper. PacifiCorp manages its interest rate exposure by maintaining a blend of fixed- and variable-rate debt and by monitoring the effects of market changes in interest rates. Changing interest rates will affect interest paid on variable-rate debt and interest earned by PacifiCorp’s pension plan assets, mining reclamation trust funds and cash balances. PacifiCorp’s principal sources of variable-rate debt are commercial paper and pollution control revenue bonds remarketed on a periodic basis. Commercial paper is periodically refinanced with fixed-rate debt when needed and when interest rates are considered favorable. PacifiCorp may also enter into financial derivative instruments, including interest rate swaps, swaptions and United States Treasury lock agreements, to manage and mitigate interest rate exposure. PacifiCorp does not anticipate using financial derivatives as the principal means of managing interest rate exposure. PacifiCorp’s cost of debt is recoverable in rates. Increases or decreases in interest rates are reflected in PacifiCorp’s cost of debt calculation as rate cases are filed. Any adverse change to PacifiCorp’s credit rating could negatively impact PacifiCorp’s ability to borrow and the interest rates that are charged.

As of March 31, 2004, PacifiCorp had $666.6 million of variable-rate liabilities and $45.6 million of temporary cash investments. At March 31, 2004, PacifiCorp had no financial derivatives in effect relating to interest rate exposure.

In order to make the interest rate risk management disclosure more meaningful, PacifiCorp has revised the risk analysis. In prior periods a Value at Risk (“VaR”) analysis of the impact of changes in interest rates on the fair market value of liabilities was disclosed. The new analysis focuses on PacifiCorp’s exposure to changes in interest rates on interest expense.

Based on a sensitivity analysis as of March 31, 2004, PacifiCorp estimated that if market interest rates average 1.0% higher (lower) in fiscal 2005 than in fiscal 2004, interest expense, net of offsetting impacts in interest income, would increase (decrease) by $6.2 million. Comparatively, based on a sensitivity analysis as of March 31, 2003, had interest rates averaged 1.0% higher (lower) in fiscal 2004 than in fiscal 2003, PacifiCorp estimated that interest expense would have increased (decreased) by $5.5 million. These amounts include the effect of invested cash and were determined by considering the impact of the hypothetical interest rates on the variable-rate securities outstanding as of March 31, 2004 and 2003. The increase in interest rate sensitivity was primarily due to the increase in outstanding variable-rate commercial paper and decrease in invested cash. If interest rates changed significantly, PacifiCorp might take actions to manage its exposure to the change. However, due to the uncertainty of the specific actions that might be taken and their possible effects, the sensitivity analysis assumes no changes in PacifiCorp’s financial structure.

Commodity Price Risk

PacifiCorp’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 energy supply and demand. PacifiCorp’s energy purchase and sales activities are governed by PacifiCorp’s risk management policy and the risk levels established as part of that policy.

PacifiCorp’s energy commodity price exposure arises principally from its electric supply obligation in the western United States. PacifiCorp manages this risk principally through the operation of its 8,419.5 MW generation plants and 15,763-mile transmission system in the western United States and through its wholesale energy purchase and sales activities. Wholesale contracts are utilized to balance PacifiCorp’s physical excess or shortage of net electricity for future months. Financially settled contracts are utilized to further mitigate commodity price risk. PacifiCorp may from time to time enter into other financially settled (temperature-related) derivative instruments that reduce volume and price risk on days with weather extremes. In addition, a financial hydroelectric generation hedge is in place through September 2006 to reduce volume and price risks associated with PacifiCorp’s hydroelectric generation availability.

PacifiCorp measures the market risk in its electricity and natural gas portfolio daily utilizing a historical VaR approach, as well as other measurements of net position. PacifiCorp also monitors its portfolio exposure to market risk in comparison to established thresholds and measures its open positions subject to price risk in terms of volumes at each delivery location for each forward time period.

VaR computations for the electricity and natural gas commodity portfolio are based on a historical simulation technique, utilizing historical price changes over a specified period to simulate potential forward energy market price curve movements to estimate the potential unfavorable impact of such price changes on the portfolio positions scheduled to settle within the following 24 months. The quantification of market risk using VaR provides a consistent measure of risk across PacifiCorp’s continually changing portfolio. VaR represents an estimate of reasonably possible changes in fair value that would be measured on its portfolio assuming hypothetical movements in future market rates and is not necessarily indicative of actual results that may occur.

PacifiCorp’s VaR computations for its electricity and natural gas commodity portfolio utilize several key assumptions, including a 99.0% confidence level for the resultant price changes and a holding period of five days. The calculation includes short-term derivative commodity instruments held for risk mitigation and balancing purposes, the expected resource and demand obligations from PacifiCorp’s long-term contracts, the expected generation levels from PacifiCorp’s generation assets and the expected retail and wholesale load levels. The portfolio reflects flexibility contained in contracts and assets, which accommodate the normal variability in PacifiCorp’s demand obligations and generation availability. These contracts and assets are valued to reflect the variability PacifiCorp experiences as a load serving entity. Contracts or assets that contain flexible elements are often referred to as having embedded options or option characteristics. Optionality means sensitivity to market price changes. Therefore, changes in the option values affect the energy position of the portfolio with respect to market

prices and this effect is calculated daily. When measuring portfolio exposure through VaR, these position changes that result from the option sensitivity are held constant through the historical simulation to avoid understating VaR.

As of March 31, 2004, PacifiCorp’s estimated potential five-day unfavorable impact on fair value of the electricity and natural gas commodity portfolio over the next 24 months was $16.0 million, as measured by the VaR computations described above, compared to $18.0 million as of March 31, 2003. The average daily VaR (five-day holding periods) for the year ended March 31, 2004 was $14.3 million. The maximum and minimum VaR measured during the year ended March 31, 2004 was $23.3 million and $7.9 million, respectively. PacifiCorp maintained compliance with its VaR limit procedures during the year ended March 31, 2004. Changes in markets inconsistent with historical trends or assumptions used could cause actual results to exceed predicted limits.

Fair Value of Derivatives

The following table shows the changes in the fair value of energy-related contracts subject to the requirements of SFAS No. 133, as amended, from April 1, 2003 to March 31, 2004 and quantifies the reasons for the changes.

(Millions of dollars)
Fair value of contracts outstanding at April 1, 2003	$	(505.7	)
Contracts realized or otherwise settled during the period		45.3
Changes in fair values attributable to changes in valuation assumptions (a)		(45.3	)
Other changes in fair values (b)		90.9

Fair value of contracts outstanding at March 31, 2004 (c)	$	(414.8	)

(a)

Reflects changes in the fair value as a result of applying refinements in valuation modeling techniques.

(b)

Other changes in fair values result from effects of changes in prices on new and existing energy-related contracts.

(c)

PacifiCorp has also recorded $422.2 million in net regulatory assets, as authorized by regulatory orders received, with respect to these contracts.

The fair value of derivative instruments is determined using forward price curves. Forward price curves represent PacifiCorp’s estimates of the prices at which a buyer or seller could contract today for delivery or settlement of a commodity at future dates. PacifiCorp bases its forward price curves upon market price quotations when available and internally developed and commercial models with internal and external fundamental data inputs when market quotations are unavailable. In general, PacifiCorp estimates the fair value of a contract by calculating the present value of the difference between the prices in the contract and the applicable forward price curve. Price quotations for certain major electricity trading hubs are generally readily obtainable for the first three years and therefore PacifiCorp’s forward price curves for those locations and periods reflect observable market quotes. However, in the later years or for locations that are not actively traded, PacifiCorp must develop forward price curves. For short-term contracts at less actively traded locations, prices are modeled based on observed historical price relationships with actively traded locations. For long-term contracts extending beyond three years, the forward price curve is based upon the use of a fundamentals model (cost-to-build approach) due to the limited information available. Factors used in the fundamentals model include the forward prices for the commodities used as fuel to generate electricity, the expected system heat rate (which measures the efficiency of power plants in converting fuel to electricity) in the region where the purchase or sale takes place, and a fundamental forecast of expected spot prices based on modeled supply and demand in the region. The assumptions in these models are critical since any changes to the assumptions could have a significant impact on the fair value of the contract. Contracts with explicit or embedded optionality are valued by separating each contract into its physical and financial forward, swap and option components. Forward and swap components are valued against the appropriate forward price curve. The optionality is valued using a modified Black-Scholes model or a stochastic simulation (Monte Carlo) approach. Each option component is modeled and valued separately using the appropriate forward price curve.

PacifiCorp’s valuation models and assumptions are continuously updated to reflect current market information, and an evaluation and refinement of model assumptions are performed on a periodic basis.

The following table shows summarized information with respect to valuation techniques and contractual maturities of PacifiCorp’s energy-related contracts qualifying as derivatives under SFAS No. 133 as of March 31, 2004.

Standardized derivative contracts that are valued using market quotations are classified as “prices based on quoted market prices from third party sources.” All remaining contracts, which include non-standard contracts and contracts for which market prices are not routinely quoted, are classified as “prices based on models and other valuation methods.”

	Fair Value of Contracts at Period-End

(Millions of dollars)	Maturity less than 1 year			Maturity 2-3 years			Maturity 4-5 years			Maturity in excess of 5 years			Total Fair Value

Prices based on quoted market prices from third party sources	$	(8.2	)	$	(7.9	)	$	—		$	—		$	(16.1	)
Prices based on models and other valuation methods		50.2			15.9			(90.8	)		(374.0	)		(398.7	)

Total	$	42.0		$	8.0		$	(90.8	)	$	(374.0	)	$	(414.8	)

PacifiCorp has executed a contract to hedge changes in hydroelectric generation due to variation in streamflows. PacifiCorp has also executed a contract to hedge changes in retail electricity demand due to abnormal ambient temperatures. These contracts are not exchange-traded, and settlement is based on climatic or other physical variables. Therefore, on a periodic basis, PacifiCorp 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. PacifiCorp recorded liabilities of $3.4 million at March 31, 2004 and $2.6 million at March 31, 2003, for the estimated fair value of the contracts. PacifiCorp realized a $5.2 million gain, excluding premium costs, for these contracts during the year ending March 31, 2004. No gain or loss was realized during the year ended March 31, 2003 or the year ended March 31, 2002.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

		Page
Index to Consolidated Financial Statements:
Report of Independent Registered Public Accounting Firm		57
Statements of Consolidated Income for the Years Ended March 31, 2004, 2003 and 2002		58
Consolidated Balance Sheets as of March 31, 2004 and 2003		59
Statements of Consolidated Cash Flows for the Years Ended March 31, 2004, 2003 and 2002		61
Statements of Consolidated Changes in Common Shareholder’s Equity for the Years Ended March 31, 2004, 2003 and 2002		62
Notes to the Consolidated Financial Statements		63

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of PacifiCorp:

In our opinion, the accompanying consolidated balance sheets and the related statements of consolidated income, common shareholder’s equity and cash flows present fairly, in all material respects, the financial position of PacifiCorp and its subsidiaries at March 31, 2004 and 2003, and the results of their operations and their cash flows for each of the three years in the period ended March 31, 2004 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 the standards of the Public Company Accounting Oversight Board (United States). Those standards 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 3 to the consolidated financial statements, the Company changed the manner in which it applies the normal purchases and normal sales exception to derivative contracts entered into after June 30, 2003 upon its adoption of Statement of Financial Accounting Standards (“SFAS”) No. 149, Amendment of Statement 133 on Derivative Instruments and Hedging Activities, as of July 1, 2003.

As discussed in Note 3 to the consolidated financial statements, the Company changed the manner in which it accounts for realized gains and losses on physically settled derivative contracts not held for trading purposes, as of January 1, 2004.

As discussed in Note 6 to the consolidated financial statements, the Company changed the manner in which it accounts for asset retirement obligations, as of April 1, 2003.

As discussed in Note 9 to the consolidated financial statements, the Company reclassified to liabilities certain financial instruments, that under previous guidance, issuers could account for as equity, as of July 1, 2003.

PricewaterhouseCoopers LLP
Portland, Oregon
May 19, 2004

PACIFICORP AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED INCOME

(Millions of dollars)	Years Ended March 31,

	2004			2003			2002

Revenues
Residential	$	994.5		$	914.7		$	901.7
Commercial		792.9			763.4			747.7
Industrial		725.6			699.2			705.1
Other retail revenues		34.0			31.4			34.5
Wholesale sales		528.1			545.4			980.4
Other		119.4			128.3			(28.3	)
Other Operations		—			—			12.6

Total		3,194.5			3,082.4			3,353.7

Operating expenses
Purchased electricity		672.8			698.5			974.4
Fuel		483.9			482.2			490.9
Operations and maintenance		881.8			885.1			813.4
Depreciation and amortization		428.8			434.3			403.0
Taxes, other than income taxes		95.3			93.4			90.8

Total		2,562.6			2,593.5			2,772.5
Other operating expense (income)		13.2			—			(32.4	)
Gain on sale of operating assets		—			—			(27.4	)

Income from operations		618.7			488.9			641.0

Interest expense and other (income) expense
Interest expense		256.5			270.3			227.7
Interest income		(13.8	)		(21.6	)		(47.5	)
Interest capitalized		(19.9	)		(18.0	)		(6.9	)
Minority interest and other		2.4			19.0			(1.8	)

Total		225.2			249.7			171.5

Income from continuing operations before income taxes and cumulative effect of accounting change		393.5			239.2			469.5
Income tax expense		144.5			97.2			176.1

Income from continuing operations before cumulative effect of accounting change		249.0			142.0			293.4
Discontinued operations (less applicable income tax expense of $36.4/2002)		—			—			146.7

Income before cumulative effect of accounting change		249.0			142.0			440.1
Cumulative effect of accounting change (less applicable income tax benefit of $(0.6)/2004, $(1.1)/2003 and $(69.0)/2002) (Notes 3 and 6)		(0.9	)		(1.9	)		(112.8	)

Net income		248.1			140.1			327.3
Preferred dividend requirement		(3.3	)		(7.3	)		(12.7	)

Earnings on common stock	$	244.8		$	132.8		$	314.6

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

PACIFICORP AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS

(Millions of dollars)		March 31,

		2004			2003

ASSETS
Current assets
Cash and cash equivalents	$	58.5		$	152.5
Accounts receivable less allowance for doubtful accounts of $23.8/2004 and $31.1/2003		234.6			258.2
Unbilled revenue		128.3			109.2
Amounts due from affiliates		2.4			2.5
Inventories
Materials and supplies		101.0			99.4
Fuel		56.0			71.8
Current derivative contract asset		118.9			107.2
Current deferred tax asset		31.5			31.1
Other		25.2			17.5

Total current assets		756.4			849.4

Property, plant and equipment
Generation		5,135.7			4,998.9
Transmission		2,439.2			2,328.9
Distribution		4,104.7			3,921.4
Intangible plant		599.5			491.0
Other		1,533.7			1,444.1
Construction work in progress		345.4			332.5

Total		14,158.2			13,516.8
Accumulated depreciation and amortization		(5,121.7	)		(4,818.3	)

Total property, plant and equipment - net		9,036.5			8,698.5

Other assets
Regulatory assets		1,032.3			1,175.2
Derivative contract regulatory asset		422.2			506.9
Non-current derivative contract asset		110.3			122.3
Deferred charges and other		319.4			343.5

Total other assets		1,884.2			2,147.9

Total assets	$	11,677.1		$	11,695.8

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

PACIFICORP AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS, continued

(Millions of dollars)	March 31,

	2004			2003

LIABILITIES, REDEEMABLE PREFERRED STOCK AND SHAREHOLDERS’ EQUITY
Current liabilities
Long-term debt and capital lease obligations, currently maturing	$	240.0		$	136.7
Preferred stock subject to mandatory redemption, currently maturing (See Note 9)		3.7			—
Notes payable and commercial paper		124.9			25.0
Accounts payable		257.8			243.4
Accrued employee expenses		140.3			141.3
Amounts due to affiliates		2.6			39.6
Taxes payable		50.2			63.1
Interest payable		66.1			67.9
Current derivative contract liability		76.9			91.7
Other		111.8			127.3

Total current liabilities		1,074.3			936.0

Deferred credit
Income taxes		1,564.6			1,511.1
Investment tax credits		83.5			91.4
Regulatory liabilities		807.5			801.9
Non-current derivative contract liability		567.1			643.5
Other		683.6			650.1

Total deferred credits		3,706.3			3,698.0

Long-term debt and capital lease obligations, net of current maturities		3,520.2			3,417.6
Preferred stock subject to mandatory redemption, net of current maturities (See Note 9)		56.3			—

Total liabilities		8,357.1			8,051.6

Commitments, contingencies and guarantees (See Notes 10 and 11)
Guaranteed preferred beneficial interests in PacifiCorp’s junior subordinated debentures		—			341.8

Preferred stock subject to mandatory redemption (See Note 9)		—			66.7

Shareholders’ equity
Preferred stock		41.3			41.3
Common shareholder’s capital		2,892.1			2,892.1
Retained earnings		390.1			305.9
Accumulated other comprehensive income (loss)
Unrealized gain (loss) on available-for-sale securities, net of tax of $2.7/2004 and $(1.1)/2003		4.5			(1.7	)
Minimum pension liability, net of tax of $(4.9)/2004 and $(1.1)/2003		(8.0	)		(1.9	)

Total shareholders’ equity		3,320.0			3,235.7

Total liabilities, redeemable preferred stock and shareholders’ equity	$	11,677.1		$	11,695.8

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

PACIFICORP AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED CASH FLOWS

(Millions of dollars)	Years Ended March 31,

	2004			2003			2002

Cash flows from operating activities
Net income	$	248.1		$	140.1		$	327.3
Adjustments to reconcile net income to net cash provided by operating activities:
Gain on disposal of discontinued operations		—			—			(146.7	)
Cumulative effect of accounting change, net of tax		0.9			1.9			112.8
Unrealized gain on derivative contracts		(6.1	)		(3.1	)		(182.8	)
Depreciation and amortization		428.8			434.3			403.0
Deferred income taxes and investment tax credits - net		80.5			31.8			60.9
Gain on sale of subsidiary and assets		(2.2	)		(3.7	)		(52.6	)
Regulatory asset/liability establishment		(22.9	)		15.7			(210.9	)
Changes in:
Other Regulatory assets/liabilities		134.0			131.1			65.0
Accounts receivable, net; Unbilled revenue; and prepayments		(1.5	)		7.6			165.2
Inventories		14.1			(17.8	)		7.0
Amounts due affiliates		(37.0	)		32.5			(11.6	)
Accounts payable and accrued liabilities		(3.3	)		(97.1	)		(151.0	)
Other		(1.5	)		8.3			(43.0	)

Net cash provided by operating activities		831.9			681.6			342.6

Cash flows from investing activities
Capital expenditures		(690.4	)		(550.0	)		(505.3	)
Investments in and advances to affiliated companies - net		—			3.3			(130.8	)
Advances to ScottishPower		—			—			(627.4	)
Proceeds from ScottishPower note receivable		—			—			400.0
Proceeds from finance note repayment		—			—			189.9
Proceeds from sales of assets		3.3			16.3			83.2
Proceeds from sales of finance assets and principal payments		—			—			36.0
Proceeds from available-for-sale securities		95.8			132.9			120.9
Purchases of available-for-sale securities		(89.4	)		(134.3	)		(152.0	)
Other		(22.8	)		6.7			17.1

Net cash used in investing activities		(703.5	)		(525.1	)		(568.4	)

Cash flows from financing activities
Changes in Short-term debt		99.9			(152.5	)		(64.0	)
Proceeds from Long-term debt, net of issuance costs		396.7			—			791.1
Proceeds from issuance of common stock to PHI		—			150.0			—
Dividends paid		(165.1	)		(7.3	)		(310.3	)
Repayments of Long-term debt		(194.1	)		(144.6	)		(59.0	)
Redemptions of Preferred Securities		(352.0	)		—			—
Redemptions of Preferred stock		(7.5	)		(7.5	)		(100.0	)
Other		(0.3	)		—			(13.5	)

Net cash (used in) provided by financing activities		(222.4	)		(161.9	)		244.3

(Decrease) increase in Cash and cash equivalents		(94.0	)		(5.4	)		18.5
Cash and cash equivalents at beginning of year		152.5			157.9			139.4

Cash and cash equivalents at end of year	$	58.5		$	152.5		$	157.9

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

PACIFICORP AND SUBSIDIARIES
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)

	Shares	Amounts

Balance at March 31, 2001	297,325	$	3,284.9		$	128.6		$	0.9
Comprehensive income
Net income	—		—			327.3			—		$	327.3
Other comprehensive income (loss):
Unrealized loss on available-for-sale securities, net of tax of $-	—		—			—			(0.2	)		(0.2	)
Cumulative effect of accounting change, net of tax of $377.5	—		—			—			617.2			617.2
Loss on derivative financial instruments, net of tax of $(70.2)	—		—			—			(115.1	)		(115.1	)
Unrealized loss on derivative financial instruments, net of tax of $(321.8)	—		—			—			(526.1	)		(526.1	)
Cash dividends declared:
Preferred stock	—		—			(9.8	)		—			—
Common stock ($0.81 per share)	—		—			(240.8	)		—			—
Transfer of PGHC	—		(542.8	)		(32.2	)		—			—

Balance at March 31, 2002	297,325		2,742.1			173.1			(23.3	)	$	303.1

Comprehensive income
Net income	—		—			140.1			—		$	140.1
Other comprehensive income (loss):
Unrealized loss on available-for-sale securities, net of tax of $(2.1)	—		—			—			(2.4	)		(2.4	)
Minimum pension liability, net of tax of $(1.1)	—		—			—			(1.9	)		(1.9	)
Unrealized gain on derivative financial instruments, net of tax of $14.7	—		—			—			24.0			24.0
Sale of common stock to parent	14,851		150.0			—			—			—
Cash dividends declared:
Preferred stock	—		—			(7.3	)		—			—

Balance at March 31, 2003	312,176		2,892.1			305.9			(3.6	)	$	159.8

Comprehensive income
Net income	—		—			248.1			—		$	248.1
Other comprehensive income (loss):
Unrealized gain on available-for-sale securities, net of tax of $3.8	—		—			—			6.2			6.2
Minimum pension liability, net of tax of $(3.8)	—		—			—			(6.1	)		(6.1	)
Cash dividends declared:
Preferred stock	—		—			(3.3	)		—			—
Common stock ($0.52 per share)	—		—			(160.6	)		—			—

Balance at March 31, 2004	312,176	$	2,892.1		$	390.1		$	(3.5	)	$	248.2

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

PACIFICORP AND SUBSIDIARIES
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Note 1 – Summary of Significant Accounting Policies

Nature of operations - PacifiCorp (which includes PacifiCorp and its subsidiaries) is a United States electricity company operating in the states of Utah, Oregon, Wyoming, Washington, Idaho and California. PacifiCorp generates electricity and conducts its retail electric utility business as Pacific Power and Utah Power and also engages in electricity sales and purchases on a wholesale basis. The subsidiaries of PacifiCorp support its electric utility operations by providing coal mining facilities and services and environmental remediation.

Basis of presentation - The Consolidated Financial Statements of PacifiCorp include its integrated electric utility operations and its wholly-owned and majority-owned subsidiaries. Intercompany transactions and balances have been eliminated upon consolidation.

After obtaining the necessary regulatory approvals, on December 31, 2001, NA General Partnership (“NAGP”) contributed all of the common stock of PacifiCorp to PacifiCorp Holdings, Inc. (“PHI”), a direct, wholly owned subsidiary of NAGP. NAGP was a wholly owned subsidiary of Scottish Power plc (“ScottishPower”) until December 1, 2003, at which time it was merged into PHI.

On February 4, 2002, PacifiCorp transferred all of the capital stock of PacifiCorp Group Holdings Company (“PGHC”) to PHI. This was a non-cash transaction that resulted in a net reduction in shareholder’s equity of $575.0 million. PGHC included the wholly owned subsidiary PacifiCorp Financial Services, Inc. (“PFS”), a financial services business. Accordingly, the consolidated results of operations, assets and liabilities of PGHC and its subsidiaries are not included with those of PacifiCorp commencing February 4, 2002.

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, liabilities, revenues, expenses and disclosure of contingent assets and liabilities at the date of the financial statements. These estimates involve judgments with respect to numerous factors that are difficult to predict and are beyond management’s control. As a result, actual results could differ materially from these estimates.

Regulation - Accounting for the electric utility business conforms to 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 electric utility business operates. PacifiCorp prepares its financial statements 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 2.

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

Accounts receivable and allowance for doubtful accounts - Accounts receivable includes billed services plus any accrued and unpaid interest. Credit is granted to customers, which includes retail and wholesale customers, government agencies, and other utilities. Management performs continuing credit evaluations of customers’ financial condition, and although PacifiCorp does not require collateral, deposits may be required from customers in certain circumstances. Accounts receivable are considered delinquent based on regulations provided by each state, which is generally if payment is not received by the date due, or typically 30 days after the invoice date. PacifiCorp charges interest on delinquent customer accounts or past due balances in the majority of the states where PacifiCorp does business based on the respective regulation of that state, which varies between 1.0% to 1.5% per month. The recorded investment in trade receivables delinquent more than 90 days and still accruing interest and those on non-accrual status is immaterial at March 31, 2004, and March 31, 2003.

Management reviews accounts receivable on a monthly basis to determine if any receivable will potentially be uncollectible. The allowance for doubtful accounts includes amounts for the evaluation of specific accounts based upon the best available facts and circumstances that a customer may be unable to meet its financial obligation, and a reserve based on historical experience. After all attempts to collect a receivable have failed or by six months from when a customer becomes inactive, the receivable is written-off against the allowance. Management believes that

the allowance for doubtful accounts as of March 31, 2004 was adequate. However, actual write-offs could exceed the recorded allowance. The allowance activity was as follows:

	Years Ended March 31,

(Millions of dollars)	2004			2003			2002

Beginning balance	$	31.1		$	34.8		$	27.6
Charged to costs and expenses		5.7			10.6			16.0
Write-offs		(13.0	)		(14.3	)		(8.8	)

Ending balance	$	23.8		$	31.1		$	34.8

Inventories - Inventories are valued at the lower of average cost or market.

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 electric utility properties retired, less salvage, is charged to accumulated depreciation. The cost of removal is charged against the regulatory liability established through depreciation rates. Generally costs of major overhaul activities and other repairs and maintenance are expensed as they are incurred. Intangible plant consists primarily of computer software costs. The unamortized computer software costs were $194.8 million at March 31, 2004 and $201.1 million at March 31, 2003.

Depreciation and amortization - The depreciable lives of Property, plant and equipment currently in use by category are as follows:

Generation
Steam plant		20 – 43 years
Hydroelectric plant		14 – 85 years
Other plant		15 – 35 years
Transmission		20 – 70 years
Distribution		44 – 50 years
Intangible plant		5 – 50 years
Other		5 – 30 years

Computer software is amortized over an average life of eight years.

Depreciation and amortization are computed by the straight-line method either over the life prescribed by PacifiCorp’s various regulatory jurisdictions for regulated assets, or over the assets’ estimated useful lives. Composite depreciation rates of average depreciable assets on utility plants (excluding amortization of capital leases) were 3.0% for the year ended March 31, 2004; 3.2% for the year ended March 31, 2003; and 3.1% for the year ended March 31, 2002.

Asset impairments - Long-lived assets to be held and used by PacifiCorp 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 PacifiCorp adopted February 1, 2002, effective as of April 1, 2001. 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.

Allowance for funds used during construction - The Allowance for funds used during construction (the “AFUDC”) represents the cost of debt and may also include equity funds used to finance utility property additions during construction. As prescribed by regulatory authorities, the AFUDC is capitalized as a part of the cost of utility property and is recorded in the Statements of Consolidated Income as Interest capitalized. Under regulatory rate practices, PacifiCorp is generally permitted to recover the AFUDC, and a fair return thereon, through its rate base after the related utility property is placed in service.

The composite capitalization rates were 7.9% for the year ended March 31, 2004; 7.2% for the year ended March 31, 2003; and 3.6% for the year ended March 31, 2002. PacifiCorp’s AFUDC rates do not exceed the maximum allowable rates determined by regulatory authorities.

Derivatives - As discussed in Note 3, in April 2001 PacifiCorp adopted SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, (“SFAS No. 133”), as amended by numerous interpretations of the Derivatives Implementation Group (the “DIG”) that are approved by the FASB. Subsequent revisions were made in SFAS No. 138, Accounting for Certain Derivative Instruments and Certain Hedging Activities, and SFAS No. 149, Amendment of Statement 133 on Derivative Instruments and Hedging Activities (“SFAS No. 149”) (collectively “SFAS No. 133”). Under the standard, derivative instruments are measured at fair value and recognized as either assets or liabilities on the Consolidated Balance Sheets, unless they qualify for the exemptions afforded by the standard. Changes in the fair value of derivatives are recognized in earnings during the period of change. Certain of PacifiCorp’s long-term derivative contracts have been approved by regulatory authorities for recovery through retail rates. Accordingly, changes in fair value of these contracts are deferred as regulatory assets or liabilities pursuant to SFAS No. 71. Derivative contracts for commodities used in PacifiCorp’s normal business operation and which settle by physical delivery, among other criteria, are eligible for the normal purchases and normal sales exemption afforded by SFAS No. 133. These contracts are accounted for under accrual accounting and recorded in Wholesale sales or Purchased electricity in the Statements of Consolidated Income when the contract settles.

Marketable securities - PacifiCorp accounts for marketable securities, included in Deferred charges and other on PacifiCorp’s Consolidated Balance Sheets, in accordance with SFAS No. 115, Accounting for Certain Investments in Debt and Equity Securities. PacifiCorp determines the appropriate classification of all marketable securities as held-to-maturity, available-for-sale, or trading at the time of purchases, and re-evaluates such classification as of each balance sheet date. As shown in Note 5, at March 31, 2004 and 2003, all of PacifiCorp’s investments in marketable securities were classified as available-for-sale and were reported at fair value. Unrealized gains and losses are reported as a component of Accumulated other comprehensive income (loss). PacifiCorp uses the specific identification method in computing realized gains and losses on the sale of its available-for-sale securities. Realized gains and losses are included in either Other income (expense).

Asset retirement obligation and accrued removal costs - Effective April 1, 2003, PacifiCorp recognizes the fair value of legal obligations associated with the retirement or removal of long-lived assets at the time the obligations are incurred and can be reasonably estimated in accordance with SFAS No. 143, Accounting for Asset Retirement Obligation, (“SFAS No. 143”). The initial recognition of this liability is accompanied by a corresponding increase in Property, plant and equipment. Subsequent to the initial recognition, the liability is adjusted for any revisions to the expected value of the retirement obligation (with corresponding adjustments to Property, plant and equipment), and for accretion of the liability due to the passage of time. Additional depreciation expense is recorded prospectively for any Property, plant and equipment increases.

PacifiCorp does not recognize liabilities for asset retirement obligations for which the fair value cannot be reasonably estimated. PacifiCorp has asset retirement obligations associated with the transmission and distribution systems and certain coal mines. However, due to the indeterminate removal date, the fair value of the associated liability currently cannot be estimated and no amounts are recognized in the Consolidated Financial Statements.

For those asset retirement removal costs that do not meet the requirements of SFAS No. 143, PacifiCorp ratably accrues the estimated retirement and removal cost when removal of the asset is considered likely, in accordance with established regulatory practices. The accrued and incurred balance for these costs is classified as Asset retirement removal costs and represents a regulatory liability, under SFAS No. 71. See Note 2.

Income taxes - PacifiCorp 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.

PacifiCorp, as a wholly owned subsidiary of PHI, is included in a consolidated tax return. PacifiCorp’s provision for income taxes has been computed on the basis that it files separate consolidated income tax returns with its subsidiaries. Amounts payable for federal and state taxes are remitted to PacifiCorp’s parent, PHI.

Historically, PacifiCorp 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 PacifiCorp’s various regulatory jurisdictions. Deferred income tax liabilities and Regulatory assets have been established for those flow-through tax benefits, as shown in Note 20.

Investment tax credits are deferred and amortized to income over periods prescribed by PacifiCorp’s various regulatory jurisdictions.

Stock-based compensation - As permitted by SFAS No. 123, Accounting for Stock-Based Compensation (“SFAS No. 123”), PacifiCorp accounts for its stock-based compensation arrangements, primarily employee stock options, under the intrinsic value recognition and measurement principles of 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 PacifiCorp 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. All options are issued in ScottishPower American Depository Shares, as discussed in Note 19. Had PacifiCorp determined compensation cost based on the fair value at the grant date for all stock options vesting in each period under SFAS No. 123, PacifiCorp’s Net income would have been reduced to the pro forma amounts below:

	Years Ended March 31,

(Millions of dollars)	2004			2003			2002

Net income as reported	$	248.1		$	140.1		$	327.3
Stock-based employee compensation expense, net of tax		(1.1	)		(1.6	)		(2.2	)

Pro forma net income	$	247.0		$	138.5		$	325.1

The fair value of options granted was $3.4 million for the year ended March 31, 2002. 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:

	Year Ended March 31, 2002

Dividend yield		6.70	%
Risk-free interest rate		4.77
Volatility		30.00
Expected life of the options (years)		5

There were no grants during the years ended March 31, 2004 and 2003.

Revenue recognition - Electricity sales to retail customers are determined based on meter readings taken throughout the month. PacifiCorp accrues an estimate of unbilled revenues, which are earned but not yet billed, net of estimated line losses, each month for electric service provided after the meter reading date to the end of the month. The process of calculating the Unbilled revenue estimate consists of three components: quantifying PacifiCorp’s total electricity delivered during the month, assigning Unbilled revenues to customer type and valuing the unbilled energy. Factors involved in the estimation of consumption and line losses relate to weather conditions, amount of natural light, historical trends, economic impacts and customer type. Valuation of unbilled energy is based on estimating the average price for the month for each customer type. The amount accrued for Unbilled revenues was $128.3 million at March 31, 2004 and $109.2 million at March 31, 2003. Electricity sales to wholesale customers are recorded upon delivery.

New accounting standards -

SFAS No. 143

In June 2001, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 143. See Note 6 for further discussion.

FIN 46R

In January 2003, the FASB issued FASB Interpretation No. 46, Consolidation of Variable-Interest Entities, an interpretation of Accounting Research Bulletin No. 51 (“FIN 46”) and issued a revised version of the interpretation in December 2003 (“FIN 46R”). See Note 13 for further discussion.

SFAS No. 149

SFAS No. 149 was issued in April 2003. See Note 3 for further discussion.

SFAS No. 150

In May 2003, the FASB issued SFAS No. 150, Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity (“SFAS No. 150”). See Note 9 for further discussion.

EITF No. 01-8

In May 2003, the Emerging Issues Task Force (“EITF”) issued EITF No. 01-8, Determining Whether an Arrangement Contains a Lease (“EITF No. 01-8”). EITF No. 01-8 generally states that the evaluation of whether an arrangement contains a lease that is within the scope of SFAS No. 13, Accounting for Leases, should be based on the substance of the arrangement. The consensus was effective for arrangements entered into or modified after June 30, 2003. PacifiCorp has determined that certain long-term power purchase contracts from qualifying facilities meet the conditions of EITF No. 01-8; however, these contracts include no minimum lease payments and, accordingly, no asset or obligation is recorded on PacifiCorp’s Consolidated Balance Sheet. Therefore, the adoption of EITF No. 01-8 had no impact on PacifiCorp’s consolidated financial position or results of operations. PacifiCorp will continue to evaluate the impact of EITF No. 01-8 as existing contracts are modified or new contracts are executed.

EITF No. 03-11

In July 2003, the EITF issued EITF No. 03-11, Reporting Gains and Losses on Derivative Instruments that Are Subject to FASB Statement No. 133, Accounting for Derivative Instruments and Hedging Activities, and Not Held for Trading Purposes (“EITF No. 03-11”). See Note 3 for further discussion.

FSP SFAS No. 106-1 and FSP SFAS No. 106-2

In January and May 2004, the FASB released FASB Staff Position (“FSP”) SFAS No. 106-1 and FSP SFAS No. 106-2, Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (“FSP SFAS No. 106-1” and “FSP SFAS No. 106-2”). The Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the “Medicare Act”) was signed into law in December 2003 and establishes a prescription drug benefit, as well as a federal subsidy to sponsors of retiree health care benefit plans that provide a prescription drug benefit that is at least actuarially equivalent to Medicare’s prescription drug coverage. FSP SFAS No. 106-2 provides guidance on the accounting for the effects of the Medicare Act for employers that sponsor postretirement health care plans that provide prescription drug benefits and requires those employers to provide certain disclosures regarding the effect of the federal subsidy provided by the Medicare Act. Under FSP SFAS No. 106-1, PacifiCorp elected to defer accounting for the effects of the Medicare Act. This deferral remains in effect until the appropriate effective date of FSP SFAS No.106-2. For entities that elected deferral and for which the impact is significant, FSP SFAS No. 106-2 is effective for the first interim or annual period beginning after June 15, 2004. For entities that will not recognize a significant impact, delayed recognition of the effects of the Medicare Act until the next regularly scheduled measurement date following the issuance of FSP SFAS No. 106-2 is allowed. PacifiCorp is still evaluating the impact of the Medicare Act. Accordingly, the accompanying Consolidated Financial Statements do not reflect the effects that may result from the Medicare Act.

SFAS No. 132R

In January 2004, the FASB issued SFAS No. 132R, Employers’ Disclosures about Pensions and Other Postretirement Benefits (“SFAS No. 132R”). See Note 18 for further discussion.

Reclassifications - Certain reclassifications of prior years’ amounts have been made to conform to the 2004 method of presentation. These reclassifications had no effect on previously reported consolidated net income.

Note 2 – 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 (i) rates are established by or subject to approval by independent, third-party regulators, (ii) rates are designed to recover the specific enterprise’s cost of service, and (iii) 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.

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 costs rather than provide for expected levels of similar future costs. PacifiCorp records regulatory assets and liabilities based on management’s assessment that it is probable that a cost will be recovered (asset) or that an obligation has been incurred (liability). The final outcome, or additional regulatory actions, could change management’s assessment in future periods. A regulator can provide current rates intended to recover costs that are expected to be incurred in the future, with the understanding that if those costs are not incurred, future rates will be reduced by corresponding amounts. If current rates are intended to recover such costs, PacifiCorp recognizes amounts charged, pursuant to such rates, as liabilities and takes those amounts to income only when the associated costs are incurred. In applying SFAS No. 71, PacifiCorp must give consideration to changes in the level of demand or competition during the cost recovery period. In accordance with SFAS No. 71, PacifiCorp capitalizes certain costs as regulatory assets in accordance with regulatory authority whereby those costs will be expensed and recovered in future periods.

PacifiCorp continuously evaluates the appropriateness of applying SFAS No. 71 to each of its jurisdictions. At March 31, 2004, PacifiCorp had recorded specifically identified net regulatory assets of $647.0 million. In the event PacifiCorp stopped applying SFAS No. 71 at March 31, 2004, an after-tax loss of approximately $401.5 million would be recognized. While regulatory orders and market conditions may affect PacifiCorp’s cash flows, its cash flows would not be affected if it stopped applying SFAS No. 71 unless a regulatory order limited its ability to recover the cost of that regulatory asset.

PacifiCorp 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 PacifiCorp operates are in various stages of evaluating deregulation. At present, PacifiCorp is subject to cost-based ratemaking for its business. PacifiCorp is a “licensee” and a “public utility” as those terms are used in the Federal Power Act and is, therefore, subject to regulation by the Federal Energy Regulatory Commission (the “FERC”) as to accounting policies and practices, certain prices and other matters.

Regulatory assets include the following:

	March 31,

(Millions of dollars)	2004		2003

Deferred income taxes	$	519.1	$	550.3
Minimum pension liability offset		226.2		233.8
Deferred net power costs (a)		57.8		137.8
Unamortized issuance expense on retired debt (b)		40.6		34.3
Demand-side resource costs		40.1		45.7
Transition plan - retirement and severance		38.2		55.1
Various other costs		110.3		118.2

Subtotal		1,032.3		1,175.2
Derivative contracts (c)		422.2		506.9

Total	$	1,454.5	$	1,682.1

(a)

Represents the deferred net power costs in Utah, Oregon and Idaho that PacifiCorp is recovering through rates.

(b)

Represents the unamortized debt expense and redemption premiums on securities retired prior to maturity. During the year ended March 31, 2004, PacifiCorp transferred $11.9 million to regulatory assets in relation to the redemption of First Mortgage Bonds and Preferred Securities. See Notes 8 and 14.

(c)

Represents the fair market value of the current and non-current derivative contracts that are specifically recoverable through rates.

At March 31, 2004, PacifiCorp had $1.3 billion of regulatory assets not accruing carrying charges. Of this amount, $422.2 million of regulatory assets for derivative contracts were offset by like-amounts of derivative instrument contract liabilities. Additionally, $226.2 million relates to regulatory assets in respect of minimum pension liability offsets where interest cost is included as a component of rates. Finally, this amount includes a deferred income tax balance of $519.1 million representing accelerated tax benefits previously flowed-through to rate-payers, which will be included in rates concurrently with recognition of the associated tax expense.

Regulatory liabilities include the following:

	March 31,

(Millions of dollars)	2004		2003

Asset retirement removal costs (a)	$	670.6	$	664.9
Centralia gain		43.7		66.5
Deferred income taxes		36.2		39.3
Various other costs		57.0		31.2

Total	$	807.5	$	801.9

(a)

For March 31, 2004, the amount represents removal costs recovered in rates that do not qualify as asset retirement obligations under SFAS No. 143. For March 31, 2003, the amount represents removal costs recovered in rates and an amount that subsequently qualified as an asset retirement obligation upon the adoption of SFAS No. 143. These amounts were previously recorded in accumulated depreciation. See Note 6.

PacifiCorp evaluates the recovery of all regulatory assets periodically and as events occur. The evaluation includes the probability of recovery as well as changes in the regulatory environment. Regulatory and/or legislative action in Utah, Oregon, Wyoming, Washington, Idaho and California may require PacifiCorp to record regulatory asset write-offs and charges for impairment of long-lived assets in future periods. Impairment would be measured in accordance with PacifiCorp’s asset impairment policy, as discussed in Note 1.

Note 3 – Derivative Instruments

PacifiCorp’s business is to serve its retail customers. PacifiCorp’s business is exposed to risks relating to, but not limited to, changes in certain commodity prices, weather conditions and counterparty performance. PacifiCorp enters into derivative instruments, including electricity, natural gas, oil and coal forward, option and weather contracts to manage its exposure to commodity price and volume risk and to ensure supply, thereby attempting to minimize variability in net power costs for customers. PacifiCorp has policies and procedures to manage the risks inherent in these activities and a risk management committee to monitor compliance with PacifiCorp’s risk management policies and procedures.

The risk management process established by PacifiCorp is designed to identify, assess, monitor and manage each of the various types of risk involved in PacifiCorp’s business and activities; measure quantitative market risk exposure; and identify qualitative market risk exposure in its business. To assist in managing the volatility relating to these exposures, PacifiCorp enters into various transactions, including derivative transactions, consistent with PacifiCorp’s risk management policy. The risk management policy governs energy purchase and sales activities and is designed for hedging PacifiCorp’s existing energy and asset exposures, and to a limited extent permits arbitrage activities to take advantage of market inefficiencies. The policy also governs PacifiCorp’s use of derivative instruments, as well as its energy purchase and sales practices, and describes PacifiCorp’s credit policy and management information systems required to effectively monitor the use of derivatives. PacifiCorp’s risk management policy provides for the use of only those instruments that have a close volume or price correlation with its portfolio of assets, liabilities or anticipated transactions. The risk management policy includes, as a strategic objective, that such instruments will be primarily used for hedging, including commodity price risk management.

In April 2001, PacifiCorp adopted SFAS No. 133. Under SFAS No. 133, derivative instruments are recorded on the Consolidated Balance Sheets as assets or liabilities measured at estimated fair value, unless they qualify for the exemptions afforded by the standard.

In June 2002, PacifiCorp’s SFAS No. 133 contract assessments were updated to reflect the revised Issue C15, Normal Purchases and Normal Sales Exception for Certain Option-Type Contracts and Forward Contracts in Electricity (“Issue C15”), guidance from the DIG, effective April 1, 2002. The revision to Issue C15 includes criteria to be considered for designation of a contract as a “capacity contract” and disallows the use of the exception for contracts that include a pricing element that is not clearly and closely related to the price of energy. The cumulative effect from adopting revised Issue C15 at April 1, 2002 was a $2.1 million loss (net of a tax benefit of $1.3 million) on the Consolidated Statement of Income for the year ended March 31, 2003. In addition, PacifiCorp deferred $0.7 million in gains at the adoption date as a regulatory liability for contracts qualifying for deferred accounting under SFAS No. 71.

In October 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 was effective April 1, 2002. The cumulative effect of adopting Issue C16 at April 1, 2002 was a $0.2 million gain (net of tax of $0.2 million) on the Consolidated Statement of Income for the year ended March 31, 2003. For contracts qualifying for deferred accounting under SFAS No. 71, the effect of adopting Issue C16 was a $126.5 million loss. The applicable contracts pertain to the purchase and transport of natural gas. The costs of these contracts have been allowed in rates and the liability is, therefore, offset by a corresponding amount included in regulatory assets.

In June 2002, the EITF released Issue No. 02-3, Accounting for Contracts Involved in Energy Trading and Risk Management Activities (“EITF No. 02-3”). In accordance with the guidance, trading contracts that meet the definition of a derivative are accounted for at market value and unrealized and realized gains and losses from all trading contracts, including those where physical delivery is required, are recorded net for all periods presented. PacifiCorp adopted EITF No. 02-3 in March 2003. The application of EITF No. 02-3 resulted in PacifiCorp’s netting 484,138 MWh for the year ended March 31, 2004 and 599,311 MWh for the year ended March 31, 2003 of physically settled, gross purchases and sales.

In April 2003, the FASB issued SFAS No. 149, which amended and clarified financial reporting for derivative instruments, including among other things the qualifications for the normal purchases and normal sales exception, under SFAS No. 133. This statement was effective for contracts entered into or modified after June 30, 2003. Certain modifications and changes to the applicability of the normal purchases and normal sales scope exception for contracts led PacifiCorp to commence marking-to-market certain transactions that were entered into after June 30, 2003 that, prior to the implementation of SFAS No. 149, would have qualified for the normal purchases and normal sales exemption under SFAS No. 133.

In July 2003, the EITF issued EITF No. 03-11. Effective January 1, 2004, PacifiCorp adopted EITF No. 03-11, which provides guidance on whether to report realized gains or losses on physically settled derivative contracts not held for trading purposes on a gross or net basis and requires realized gains or losses on derivative contracts that do not settle physically to be reported on a net basis. The adoption of EITF No. 03-11 resulted in PacifiCorp’s netting certain contracts that were previously recorded on a gross basis, which reduced Wholesale sales and Purchased electricity by $397.7 million for the year ended March 31, 2004. The amounts reclassified for prior periods were $514.8 million for the year ended March 31, 2003 and $1,037.4 million for the year ended March 31, 2002. High electricity prices seen in the market during fiscal year 2002 caused a significant increase in the reclassification of revenues and expenses for the year ended March 31, 2002. The volume of megawatt hours associated with contracts that did not settle physically was relatively consistent from year to year. Adoption of EITF No. 03-11 had no impact on PacifiCorp’s consolidated Net income.

The accounting treatment for the various classifications of derivative financial instruments 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 No. 133. The realized gains and losses on these contracts are reflected in the Statements of Consolidated Income at the contract settlement date.

Cash flow hedge - The effective portion of the unrealized gains and losses relating to these forward contracts are included in Accumulated other comprehensive income (loss), a component of shareholders’ equity, with the ineffective portion being recorded in the Statements of Consolidated Income. Amounts are reclassified from

Accumulated other comprehensive income in the same period in which the hedged transaction affects earnings or when it becomes probable that the hedged forecasted transaction will not occur.

Undesignated - The realized and unrealized gains and losses relating to derivative contracts classified as trading and risk management activities are reflected in the Consolidated Statements of Income as Wholesale sales. For the remaining undesignated contracts that are not classified as involving trading and risk management activities, unrealized gains and losses from sale and purchase contracts, along with the gross revenues or expenses upon realization, are reported in Wholesale sales and Purchased electricity, in PacifiCorp’s Consolidated Statements of Income. In previously issued financial statements, unrealized gains and losses from sale and purchase contracts were reported net in “Unrealized gain on SFAS No. 133 derivative instruments.” All prior periods have now been reclassified to conform to the current year’s presentation.

PacifiCorp has the following types of commodity transactions:

Coal, natural gas and other fuel purchase contracts - PacifiCorp 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 and its other fuel needs. These contracts generally have limited optionality and require PacifiCorp 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 - PacifiCorp has executed a contract to hedge changes in hydroelectric generation due to variation in streamflows. PacifiCorp has also executed a contract to hedge changes in retail electricity demand due to abnormal ambient temperatures. These contracts are not exchange-traded, and settlement is based on climatic or other physical variables. Therefore, on a periodic basis, PacifiCorp 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. PacifiCorp has recorded liabilities of $3.4 million at March 31, 2004 and $2.6 million at March 31, 2003, for the estimated fair value of the contracts. PacifiCorp realized a $5.2 million gain, excluding premium costs, for these contracts during the year ending March 31, 2004. No gain or loss was realized during the year ended March 31, 2003 or the year ended March 31, 2002, excluding premium costs.

Wholesale electricity purchase and sales contracts - PacifiCorp 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, PacifiCorp 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 energy under long-term contracts, forward physical contracts or financial contracts for the purchase and sale of a specified amount of 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 electricity 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 PacifiCorp’s future retail resource requirements are subject to regulation and, therefore, are deferred pursuant to SFAS No. 71. PacifiCorp 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, PacifiCorp 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 PacifiCorp’s retail load. These hedges were fully effective. At the date of adopting SFAS No. 133, PacifiCorp 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 electricity 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. PacifiCorp implemented this new guidance, on a prospective basis, beginning July 1, 2001. As a result, substantially all of PacifiCorp’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 relating to the existing cash flow hedges as of July 1, 2001 were realized by September 30, 2002.

PacifiCorp has entered into master netting agreements with certain of its significant trading counterparties. These agreements reduced PacifiCorp’s credit exposure by approximately $5.0 million at March 31, 2004. Unrealized gains and losses on contracts with parties under master netting agreements are presented net on the Consolidated Financial Statements.

(Millions of dollars)	Net Asset (Liability)			Regulatory Net Asset (Liability)

Balance at April 1, 2003	$	(505.7	)	$	506.9
Settlements		45.3			(54.4	)
Changes in valuation assumptions (a)		(45.3	)		45.5
Other changes in fair value (b)		90.9			(75.8	)

Balance at March 31, 2004	$	(414.8	)	$	422.2

(a)

Reflects changes in the fair values as a result of applying refinements in valuation modeling techniques.

(b)

Other changes in fair values result from effects of changes in prices on new and existing energy-related contracts.

Short-term contracts, without explicit or embedded optionality, are valued based upon the relevant portion of the forward price curve. Contracts with explicit or embedded optionality are valued by separating each contract into its physical and financial forward, swap and option components. Forward and swap components are valued against the appropriate forward price curve. The optionality is valued using a modified Black-Scholes model approach or a stochastic simulation (Monte Carlo) approach. Each option component is modeled and valued separately using the appropriate forward price curve.

The forward price curve is based upon market price quotations when available and upon internally developed models when market quotations are unavailable. Market quotes are obtained from independent energy brokers, as well as direct information received from third-party offers and actual transactions executed by PacifiCorp. Market quotations for certain major electricity trading hubs are generally readily obtainable for the first three years; and therefore, PacifiCorp’s forward price curves for those locations and periods reflect observable market quotes. However, in the later years or for locations that are not actively traded, forward price curves must be developed. For short-term contracts at less actively traded locations, prices are modeled based on observed historical price relationships with actively traded locations. For long-term contracts extending beyond three years, the forward price curve is based upon the use of a fundamentals model (cost-to-build approach), due to the limited information available. The fundamentals model is updated as warranted, at least quarterly, to reflect changes in the market.

Standardized derivative contracts that are valued using market quotations, as described above, are classified in the table below as “prices based on quoted market prices from third party sources.” All remaining contracts, which include non-standard contracts and contracts for which market prices are not routinely quoted, are classified as “prices based on models and other valuation methods.”

	Fair Value of Contracts at Period-End

(Millions of dollars)	Maturity less than 1 year			Maturity 2-3 years			Maturity 4-5 years			Maturity in excess of 5 years			Total Fair Value

Prices based on quoted market prices from third party sources	$	(8.2	)	$	(7.9	)	$	—		$	—		$	(16.1	)
Prices based on models and other valuation methods		50.2			15.9			(90.8	)		(374.0	)		(398.7	)

Total	$	42.0		$	8.0		$	(90.8	)	$	(374.0	)	$	(414.8	)

As the FASB continues to issue interpretations, PacifiCorp 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 4 – Related-Party Transactions

There are no loans or advances between PacifiCorp and ScottishPower or between PacifiCorp and PHI. Loans from PacifiCorp to ScottishPower or PHI are prohibited under the Public Utility Holding Company Act of 1935 (“PUHCA”). Loans from ScottishPower or PHI to PacifiCorp generally require state regulatory and Securities and Exchange Commission (the “SEC”) approval. There are intercompany loan agreements that allow funds to be lent between PacifiCorp and Pacific Minerals, Inc., a wholly owned subsidiary of PacifiCorp, and also PGHC, subject to restrictions and limits. PacifiCorp does not maintain a centralized cash or money pool. Therefore, funds of each company are not commingled with funds of any other company. Affiliate transactions that PacifiCorp enters into are subject to certain approval and reporting requirements of the regulatory authorities.

The tables below detail PacifiCorp’s transactions and balances with unconsolidated related parties.

	March 31,

(Millions of dollars)	2004		2003

Amounts due from affiliated entities:
ScottishPower (a)	$	0.2	$	0.1
PHI subsidiaries (b)		2.2		2.4

	$	2.4	$	2.5

Prepayments to affiliated entities:
PHI subsidiaries (c)	$	1.5	$	1.5

Amounts due to affiliated entities:
ScottishPower (d)	$	2.6	$	2.6
PHI subsidiaries (e)		—		37.0

	$	2.6	$	39.6

Deposits received from affiliated entities:
PHI subsidiaries (f)	$	0.6	$	1.4

	Years Ended March 31,

(Millions of dollars)	2004		2003		2002

Revenues from affiliated entities:
PHI subsidiaries (f)	$	4.4	$	4.4	$	6.0

Expenses incurred from affiliated entities:
ScottishPower (d)	$	7.8	$	10.0	$	16.5
PHI subsidiaries (c)		17.0		13.0		—

	$	24.8	$	23.0	$	16.5

Expenses recharged to affiliated entities:
ScottishPower (a)	$	0.7	$	0.5	$	5.8
PHI subsidiaries (b)		8.0		7.1		—

	$	8.7	$	7.6	$	5.8

Interest income from affiliated entities:
ScottishPower (g)	$	—	$	—	$	9.5
PHI subsidiaries (b)		—		—		6.7

	$	—	$	—	$	16.2

Interest expense with affiliated entities:
PHI subsidiaries (h)	$	0.2	$	0.1	$	0.1

(a)

PacifiCorp recharges to ScottishPower payroll costs and related benefits of PacifiCorp employees working on international assignment in the United Kingdom.

(b)

Amounts shown pertain to activities of PacifiCorp with PHI and its subsidiaries. Expenses recharged reflect costs for support services to PHI and its subsidiaries and include the current portion of taxes receivable from PHI of $0.1 million at March 31, 2004, which will be applied to PacifiCorp’s tax liability for the quarter ending June 30, 2004. PHI is the tax-paying entity for PacifiCorp.

(c)

These expenses primarily represent operating lease payments for the West Valley facility, located in Utah and owned by West Valley Leasing Company, LLC (“West Valley”), which was operational only during part of the year ended March 31, 2003. West Valley is a subsidiary of PPM Energy, Inc. (“PPM”), which is a direct subsidiary of PHI. Certain costs associated with the West Valley lease are prepaid on an annual basis.

(d)

These expenses and liabilities primarily represent payroll costs and related benefits of ScottishPower employees working for PacifiCorp in the United States.

(e)

The amount shown is the current portion of net income taxes payable to PHI.

(f)

These revenues represent wheeling revenues billed to PPM, a subsidiary of PHI. A transmission service deposit for wheeling services was made by PPM and held by PacifiCorp.

(g)

PGHC, while a subsidiary of PacifiCorp, had a note receivable, interest receivable and related interest income from a directly owned subsidiary of ScottishPower.

(h)

Includes interest on short-term demand loans made to PacifiCorp by PGHC, a direct subsidiary of PHI, in accordance with regulatory authorization.

Interest rates on related-party transactions approximate the lender’s short-term borrowing cost or cost of capital as required by the relevant regulatory approval or exemption. The average applicable rates were 1.3% for the year ended March 31, 2004; 1.7% for the year ended March 31, 2003; and 3.0% for the year ended March 31, 2002.

In May 2002, PacifiCorp entered into a 15-year operating lease on an electric generation facility with West Valley. The facility consists of five generation units each rated at 40 megawatts (“MW”) and is located in Utah. PacifiCorp, at its sole option, has the option to terminate the lease after three years and after six years. The lease also includes an option to purchase if elected by December 1, 2006. Until the three-year option to terminate, PacifiCorp is committed to future minimum lease payments of $15.0 million for the year ending March 31, 2005 and $2.5 million for the year ending March 31, 2006.

In September 2003, PacifiCorp made compliance filings for a cross-charge policy agreement governing the allocation of costs incurred by PacifiCorp and by Scottish Power UK plc, on behalf of each other. Compliance filings were submitted to Utah, Oregon, Wyoming, Washington and Idaho, with approval required from Oregon only. In December 2003, the Oregon Public Utility Commission (the “OPUC”) approved the policy. The SEC has authorized these filings pursuant to previously issued PUHCA approvals. The agreement establishes a process for directly assigning or allocating costs between PacifiCorp and Scottish Power UK plc for common corporate functions. These services include human resources, shareholder services, corporate finance functions and various other common corporate functions. These charges to PacifiCorp, at cost, are estimated to be in the range of $14.0 million to $17.0 million annually on a net basis. These cross-charges are expected to commence during fiscal year 2005 and will be recorded as Operations and maintenance expense.

Note 5 – Marketable Securities

PacifiCorp, by contract with Idaho Power, 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 the years ended March 31, 2004, 2003 and 2002, PacifiCorp reviewed funding requirements based on estimated future gains and interest earnings on trust assets and the projected future reclamation liability. PacifiCorp, under contract, reviews funding on a periodic basis.

The amortized cost and fair value of reclamation trust securities and other investments, included in Deferred charges and other assets on PacifiCorp’s Consolidated Balance Sheets, 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, 2004
Money market account	$	3.3	$	—	$	—		$	3.3
Mutual fund account (a)		26.1		—		(0.3	)		25.8
Debt securities		22.9		0.9		—			23.8
Equity securities (a)		56.7		12.0		(1.3	)		67.4

Total	$	109.0	$	12.9	$	(1.6	)	$	120.3

March 31, 2003
Money market account	$	4.0	$	—	$	—		$	4.0
Mutual fund account		30.7		—		(0.3	)		30.4
Debt securities		21.5		1.0		—			22.5
Equity securities		47.0		1.2		(5.9	)		42.3

Total	$	103.2	$	2.2	$	(6.2	)	$	99.2

(a)

A mutual fund account with an estimated fair value of $25.8 million and an unrealized loss of $0.3 million at March 31, 2004 was in a continuous unrealized loss position for more than 12 months. In addition, equity securities with an estimated fair value of $7.0 million and an unrealized loss of $0.7 million at March 31, 2004 were in a continuous unrealized loss position for more than 12 months. These impairments are considered temporary based on the nature of the investments.

The quoted market price of securities is used to estimate their fair value.

The amortized cost and estimated fair value of debt securities at March 31, 2004 and 2003 by contractual maturities and of equity securities for the same dates 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,

	2004				2003

(Millions of dollars)	Amortized Cost		Estimated Fair Value		Amortized Cost		Estimated Fair Value

Debt securities
Due in one year or less	$	—	$	—	$	1.1	$	1.1
Due after one year through five years		4.3		4.5		3.1		3.4
Due after five years through ten years		11.1		11.6		8.9		9.4
Due after ten years		7.5		7.7		8.4		8.6
Money market account		3.3		3.3		4.0		4.0
Mutual fund account		26.1		25.8		30.7		30.4
Equity securities		56.7		67.4		47.0		42.3

Total	$	109.0	$	120.3	$	103.2	$	99.2

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, 2004, 2003 and 2002:

	Years Ended March 31,

(Millions of dollars)	2004			2003			2002

Proceeds	$	95.8		$	132.9		$	120.9

Gross gains	$	6.5		$	2.6		$	4.5
Gross losses		(3.4	)		(8.7	)		(12.1	)

Net gains (losses)	$	3.1		$	(6.1	)	$	(7.6	)

Note 6 – Asset Retirement Obligations and Accrued Environmental Costs

Asset Retirement Obligations - PacifiCorp recorded asset retirement obligations at April 1, 2003 for generation plants, ponds, landfills, and coal mines which qualified as legal obligations under SFAS No. 143. PacifiCorp estimates its asset retirement obligations’ liabilities based upon detailed engineering calculations of the amount and timing of the future cash spending for a third party to perform the required work. Spending estimates are escalated for inflation, and then discounted at the credit-adjusted risk-free rate. PacifiCorp then records an asset retirement obligations asset associated with the liability. The asset retirement obligations asset is depreciated over its expected life and the asset retirement obligations liability is accreted to the projected spending date. Changes in estimates could occur due to plan revisions, changes in estimated costs and changes in timing of the performance of reclamation activities. In addition, PacifiCorp records removal costs as a part of depreciation expense in accordance with regulatory accounting requirements. As a result of adoption of SFAS No. 143, the net difference between these previously recorded amounts that qualify as asset retirement obligations for regulatory purposes and the fair value amounts determined under SFAS No. 143 has been recognized as a non-cash cumulative effect of a change in accounting principle, net of related income taxes. PacifiCorp recovers asset retirement costs through the ratemaking process and records a Regulatory asset or Regulatory liability on the Consolidated Balance Sheet to account for the difference between asset retirement costs as currently approved in rates and costs under SFAS No. 143.

Upon adoption of SFAS No. 143, PacifiCorp recorded an asset retirement obligation liability at its net present value of $196.4 million. PacifiCorp also increased net depreciable assets by $37.6 million, removed $146.8 million of costs accrued for retirement from decommissioning liabilities and reclamation liabilities, decreased regulatory liabilities by $7.7 million and increased regulatory assets by $2.8 million for the difference between retirement costs approved by regulators and obligations under SFAS No. 143, and recorded a cumulative pretax effect of a change in accounting principle of $1.5 million, which is reflected in PacifiCorp’s Consolidated Statements of Income for the

year ended March 31, 2004. Accretion expense was $8.2 million and depreciation expense was $3.3 million for the year ended March 31, 2004. Due to the regulatory environment, neither the accretion expense nor the depreciation expense impacted the Consolidated Statements of Income.

Prior to the adoption of SFAS No. 143, costs for future reclamation of coal mines were accrued using the units-of-production method such that estimated final mine reclamation and closure cost would be fully accrued at completion of mining activity. At March 31, 2003, the amount accrued was $146.9 million. At April 1, 2003, the majority of this accrual was reversed to the asset retirement obligations provision under SFAS No. 143 and the remainder was moved to Long-term liabilities. This adjustment resulted in recording a cumulative effect of a change in accounting principle of $0.9 million (net of tax of $0.6 million).

The following table describes the changes to PacifiCorp’s asset retirement obligation liability for the year ended March 31, 2004:

(Millions of dollars)
Liability recognized at adoption on April 1, 2003	$	196.4
Liabilities incurred (a)		4.9
Liabilities settled (b)		(14.5	)
Revisions in cash flow (c)		(1.5	)
Accretion expense		8.2

Asset retirement obligation		193.5
Less amount in Current liabilities - other		13.7

Long-term asset retirement obligation at March 31, 2004 (d)	$	179.8

(a)

Represents the retirement obligation created in June 2003 when a settlement agreement to decommission the Powerdale hydroelectric plant was signed.

(b)

Relates primarily to ongoing reclamation work at the Glenrock coal mine.

(c)

Results from changes in the mining plan for the Deer Creek coal mine and changes in timing of estimated cash flows for certain mine and plant reclamation.

(d)

Amount included in Deferred credits – other.

The pro forma asset retirement obligation liability balances that would have been reported assuming SFAS No. 143 had been adopted on April 1, 2001, rather than April 1, 2003, are as follows:

(Millions of dollars)
Pro forma asset retirement obligation liability at April 1, 2001		$ 207.0
Pro forma asset retirement obligation liability at March 31, 2002		200.8

Due to regulatory accounting treatment, the adoption of SFAS No. 143 would have had no material impact on Net income before cumulative effect of accounting change for the pro forma periods listed above. The adoption of SFAS No. 143 had no impact on PacifiCorp’s reported cash flows.

PacifiCorp had trust fund assets recorded at fair value included in Deferred Charges and Other of $87.4 million at March 31, 2004 and $68.5 million at March 31, 2003, relating to mine and plant reclamation, including the minority interest joint owner portions.

Accrued Environmental Costs – PacifiCorp’s policy is to accrue environmental cleanup-related costs of a non-capital nature when those costs are believed to be probable and can be reasonably estimated. The quantification of environmental exposures is based on assessments of many factors, including changing laws and regulations, advancements in environmental technologies, the quality of information available related to specific sites, the assessment stage of each site investigation, preliminary findings and the length of time involved in remediation or settlement. PacifiCorp hires external consultants from time to time to conduct studies in order to establish reserves for various site environmental remediation costs. PacifiCorp is subject to cost-sharing agreements with other potentially responsible parties based on decrees, orders and other legal agreements. In these circumstances, PacifiCorp assesses the financial capability of other potentially responsible parties and the reasonableness of PacifiCorp’s apportionment. These agreements may affect the range of potential loss. Additionally, PacifiCorp may

benefit from excess insurance policies that may cover some of the cleanup costs if costs incurred exceed certain amounts. The undiscounted liabilities for environmental cleanup-related costs recorded as part of Deferred credits - other were $37.9 million at March 31, 2004 and $45.0 million at March 31, 2003. PacifiCorp expects to spend a considerable portion of these amounts over the next seven years. It is possible that future findings or changes in estimates could require that additional amounts be accrued. However, management believes that completion or resolution of these matters will have no material adverse effect on PacifiCorp’s consolidated financial position or results of operations.

Note 7 – Short-Term Debt and Borrowing Arrangements

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

(Millions of dollars)	Balance		Average Interest Rate

March 31, 2004	$	124.9	1.1	%
March 31, 2003	$	25.0	1.4	%

At March 31, 2004, PacifiCorp had $800.0 million of committed bank revolving credit agreements, including a $300.00 million facility having a three-year term that became effective June 4, 2002 and a $500.0 million facility that became effective June 3, 2003 having a 364-day term plus a one-year term loan option. PacifiCorp is currently seeking to replace these facilities and while PacifiCorp believes the facilities will be successfully replaced on terms and conditions similar to the existing facilities, no assurance can be given as to this outcome. The interest on advances under these facilities is based on the London Interbank Offered Rate (LIBOR) plus a margin that varies based on PacifiCorp’s credit ratings. As of March 31, 2004, these facilities were fully available and there were no borrowings outstanding.

Note 8 – Long-Term Debt and Capital Lease Obligations

PacifiCorp’s long-term debt was as follows:

	March 31,

	2004					2003

(Millions of dollars)	Amount			Average Interest Rate		Amount			Average Interest Rate

First mortgage bonds
4.3% to 9.0%, due through 2009	$	1,254.4		6.2	%	$	1,190.4		6.6	%
5.5% to 9.2%, due 2010 to 2014		977.0		6.9			817.0		7.3
8.3% to 8.7%, due 2015 to 2019		21.4		8.5			21.4		8.5
6.7% to 8.5%, due 2020 to 2024		324.0		7.7			341.5		7.7
6.7% to 8.6%, due 2025 to 2029		120.0		7.0			120.0		7.0
7.7%, due 2032		300.0		7.7			300.0		7.7
Unamortized premium (discount)		(3.7	)				(3.8	)
Guaranty of pollution control revenue bonds
Variable rates, due 2006 to 2026 (b)		325.2		1.6			438.0		1.9
Variable rate, due 2014 (a) (b)		40.7		1.1			40.7		1.2
3.4% to 5.7%, due 2015 to 2026 (a)		184.0		4.5			71.2		5.6
Variable rates, due 2025 (a) (b)		175.8		1.1			175.8		1.2
6.2%, due 2031		12.7		6.2			12.7		6.2
Unamortized premium (discount)		(0.6	)				(0.6	)
Funds held by trustees		(2.1	)				(2.1	)
Note obligations of subsidiaries
8.6%, due 2005		3.8		8.6			4.4		8.6
Capitalized lease obligations
10.4% to 14.8%, due through 2022		27.6		11.9			27.7		11.9

Total		3,760.2					3,554.3
Less current maturities		(240.0	)				(136.7	)

Total	$	3,520.2				$	3,417.6

(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.

First mortgage bonds of PacifiCorp may be issued in amounts limited by PacifiCorp’s property, earnings and other provisions of the mortgage indenture. Approximately $12.4 billion of the eligible assets (based on original cost) of PacifiCorp are subject to the lien of the mortgage. PacifiCorp has an effective shelf registration statement for up to $650.0 million of certain securities including long-term debt, of which $400.0 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.

Approximately $1.9 billion of first mortgage bonds were redeemable at PacifiCorp’s option at March 31, 2004 at redemption prices dependent upon United States Treasury yields. Approximately $541.7 million of pollution control revenue bonds were redeemable at PacifiCorp’s option at par at March 31, 2004. Subsidiary notes are redeemable at the subsidiary’s option at face amount. The remaining long-term debt was not redeemable at March 31, 2004.

During July and August 2003, PacifiCorp redeemed, prior to maturity, all of the 7.25% First Mortgage Bonds due in August 2013 totaling $40.0 million; all of the 7.37% First Mortgage Bonds due in August 2023 totaling $15.5 million; and all of the 7.40% First Mortgage Bonds due in July 2023 totaling $2.0 million. Upon redemption, $1.9 million of deferred charges were reclassified to a regulatory asset. These retirements were funded initially through short-term debt and subsequently by the long-term financing discussed below.

In September 2003, PacifiCorp issued $200.0 million of the 4.30% First Mortgage Bonds due in September 2008 and $200.0 million of the 5.45% First Mortgage Bonds due in September 2013. These bonds contain covenants consistent with PacifiCorp’s other series of First Mortgage Bonds. PacifiCorp used the proceeds for the refinancing of short-term debt incurred to fund the long-term debt redemptions discussed above as well as the preferred security redemptions discussed in Note 14.

PacifiCorp leases real estate, in various states that it does business in, under long-term agreements extending through 2022, which are classified as capital leases. These capital leases are payable in monthly installments allocated between principal and interest at discount rates ranging from 10.4% to 14.8%.

The annual maturities of long-term debt and capitalized lease obligations for the years ending March 31 are:

(Millions of dollars)	Long-term Debt			Capital Lease Obligations			Total

2005	$	239.8		$	3.4		$	243.2
2006		285.4			3.4			288.8
2007		238.8			3.6			242.4
2008		119.9			3.7			123.6
2009		412.4			3.7			416.1
Thereafter		2,442.7			48.6			2,491.3

		3,739.0			66.4			3,805.4
Unamortized premium (discount)		(4.3	)		—			(4.3	)
Funds held by trustee		(2.1	)		—			(2.1	)
Amount representing interest		—			(38.8	)		(38.8	)

	$	3,732.6		$	27.6		$	3,760.2

PacifiCorp made interest payments, net of capitalized interest, of $236.7 million for the year ended March 31, 2004; $287.9 million for the year ended March 31, 2003; and $246.7 million for the year ended March 31, 2002. This includes interest on leveraged lease debt that is netted against revenue on leveraged leases held by PFS for nine months of the year ended March 31, 2002.

PacifiCorp’s credit agreement contains customary covenants and default provisions, including covenants to maintain a debt-to-capitalization ratio. PacifiCorp monitors these covenants on a regular basis in order to ensure that events of default will not occur. As of March 31, 2004, PacifiCorp was in compliance with the covenants of its credit agreement.

Note 9 – Preferred Stock Subject to Mandatory Redemption

PacifiCorp’s Preferred stock subject to mandatory redemption was as follows:

(Millions of dollars, thousands of shares )	March 31, 2004			March 31, 2003

Series	Shares	Amount		Shares	Amount

Preferred stock subject to mandatory redemption $7.48 No Par Serial Preferred, $100 stated value, 16,000 shares authorized	600	$	60.0	675	$	66.7

PacifiCorp has mandatory redemption requirements on 37,500 shares of the $7.48 series Preferred stock on each June 15 through 2006, with a non-cumulative option to redeem an additional 37,500 shares on each June 15 through 2006, in each case at $100 per share, plus accrued and unpaid dividends to the date of such redemption. All outstanding shares on June 15, 2007 are subject to mandatory redemption. Holders of Preferred stock subject to mandatory redemption are entitled to certain voting rights.

In May 2003, the FASB issued SFAS No. 150. This statement affects the accounting for certain financial instruments that, under previous guidance, issuers could account for as equity. The new statement requires that those instruments be classified as liabilities. Most of this statement was effective for financial instruments entered into or modified after May 31, 2003, and otherwise was effective at the beginning of the first interim period beginning after June 30, 2003. PacifiCorp reclassified 600,000 shares, $100 stated value, of the $7.48 series Preferred stock subject to mandatory redemption of $3.7 million to short-term liabilities and $56.3 million to long-term liabilities on PacifiCorp’s Consolidated Balance Sheet at March 31, 2004. Associated dividends declared for the nine months ended March 31, 2004 of $3.4 million were recorded as interest expense.

PacifiCorp had $1.1 million at March 31, 2004 and $1.3 million at March 31, 2003 in dividends declared but unpaid on Preferred stock subject to mandatory redemption.

Note 10 – Commitments and Contingencies

PacifiCorp follows SFAS No. 5, Accounting for Contingencies (“SFAS No. 5”), to determine accounting and disclosure requirements for contingencies. PacifiCorp operates in a highly regulated environment. Governmental bodies such as the FERC, state regulatory commissions, the SEC, the Internal Revenue Service, the Department of Labor, the United States Environmental Protection Agency (the “EPA”) and others have authority over various aspects of PacifiCorp’s business operations and public reporting. Reserves are established when required in management’s judgment, and disclosures regarding litigation, assessments and creditworthiness of customers or counterparties, among others, are made when appropriate. The evaluation of these contingencies is performed by various specialists inside and outside of PacifiCorp.

Litigation - In May 2004, PacifiCorp was served with a complaint filed in the United States District Court for the District of Oregon by the Klamath Tribes of Oregon and certain of the Klamath Tribes’ members. The claim generally alleges that PacifiCorp and its predecessors affected the Klamath Tribes’ federal treaty rights to fish for salmon in the headwaters of the Klamath River in southern Oregon by building dams that blocked the passage of salmon upstream to the headwaters beginning in 1911. The claim seeks in excess of $1.0 billion in damages. PacifiCorp believes it has a number of defenses and intends to vigorously defend any claim of liability for the matters alleged by the Klamath Tribes.

From time to time, PacifiCorp and its subsidiaries are parties to various other legal claims, actions and complaints, certain of which involve material amounts. Although PacifiCorp is unable to predict with certainty whether it will ultimately be successful in these legal proceedings and, if not, what the impact might be, management currently believes that disposition of these matters will not have a material adverse effect on PacifiCorp’s consolidated financial position or results of operations.

Environmental issues - PacifiCorp is subject to numerous environmental laws including the Federal Clean Air Act, as enforced by the EPA and various state agencies; the 1990 Clean Air Act Amendments; the Endangered Species Act of 1973, particularly as it relates to certain endangered species of fish; the Comprehensive Environmental Response, Compensation and Liability Act of 1980, relating to environmental cleanups; and the Resource Conservation and Recovery Act of 1976 and the Clean Water Act, relating to water quality. These laws could potentially impact future operations. Contingencies identified at March 31, 2004 principally consist of Clean Air Act matters, which are the subject of discussions with the EPA and state regulatory authorities. PacifiCorp expects that future costs relating to these matters may be significant and consist primarily of capital expenditures. PacifiCorp also expects these costs will be included in rates and, as such, will not have a material adverse impact on PacifiCorp’s consolidated results of operations.

Hydroelectric relicensing - PacifiCorp’s hydroelectric portfolio consists of 54 plants with a plant net capability of 1,164.0 MW. Ninety-seven percent of the installed capacity is regulated by the FERC through 20 individual licenses. Nearly all of PacifiCorp’s hydroelectric projects are in some stage of relicensing under the Federal Power Act. Hydroelectric relicensing and the related environmental compliance requirements are subject to uncertainties. PacifiCorp expects that future costs relating to these matters may be significant and consist primarily of additional relicensing costs, operations and maintenance expense and capital expenditures. Electricity generation reductions may result from the additional environmental requirements. PacifiCorp has accumulated approximately $48.9 million in costs as of March 31, 2004 for ongoing hydroelectric relicensing that are reflected in assets on the Consolidated Balance Sheet. PacifiCorp expects that these and future costs will be included in rates and, as such, will not have a material adverse impact on PacifiCorp’s consolidated results of operations.

Swift power canal - On April 21, 2002, a failure occurred to the Swift No. 2 power canal on the Lewis River in the state of Washington. The Cowlitz County Public Utility District owns the power canal and associated 70 MW hydroelectric facility (“Swift No. 2”). The failure impacted, but did not damage, PacifiCorp-owned and -operated 240 MW Swift No. 1 hydroelectric facility (“Swift No. 1”), which is upstream of the Swift No. 2 power canal. The existing Swift No. 2 overflow spillway was modified to allow restricted operation of Swift No. 1 during the Swift No. 2 project outage. PacifiCorp continues to seek ways to mitigate any shaping limitations and to recover any business losses. It is currently estimated that Swift No. 2 will return to operation during the first quarter of calendar year 2006. Swift No. 2 reconstruction must be complete before Swift No. 1 can resume more normal operation; however, it has not yet been determined how Cowlitz County Public Utility District’s proposed rehabilitation design for the Swift No. 2 project will enable the full unrestricted capability that Swift No. 1 had prior to the failure. Swift No. 1 is estimated to return to full operation during the first quarter of calendar year 2006. PacifiCorp is working cooperatively with Cowlitz Public Utility District to incorporate project features into the power canal rehabilitation plan to minimize future impacts to Swift No. 1 project capability and to expedite reconstruction efforts. The full impact of the Swift power canal outage and plans for repair of the Swift No. 2 facility are currently under review. PacifiCorp is seeking reimbursement from Cowlitz County Public Utility District of PacifiCorp’s expenditures associated with the Swift No. 2 failure, and energy replacement costs. This event is not expected to have a significant impact on PacifiCorp’s consolidated financial position or results of operations.

California and Enron Corp. Reserves - Beginning in summer 2000, market conditions in California resulted in defaults of amounts due to PacifiCorp from certain counterparties in California. In addition, in December 2001, Enron Corp. declared bankruptcy and defaulted on certain wholesale contracts. PacifiCorp has provided reserves for its California exposures and its Enron Corp. receivable, net of the effect of applying the master netting agreement with Enron Corp., in the aggregate amount of $14.3 million.

California Refund Case - PacifiCorp is a party to a FERC proceeding that is investigating potential refunds for energy transactions in the California Independent System Operator and the California Power Exchange markets during past periods of high-energy prices. PacifiCorp previously established a reserve of $17.7 million for these potential refunds. PacifiCorp’s ultimate exposure to refunds is dependent upon any final order issued by the FERC in this proceeding.

Northwest Refund Case - In June 2003, the FERC terminated its proceeding relating to the possibility of requiring refunds for wholesale spot-market bilateral sales in the Pacific Northwest between December 2000 and June 2001. The FERC concluded that ordering refunds would not be an appropriate resolution of the matter. In August 2003, the FERC granted rehearing

of its June 2003 order. In November 2003, the FERC issued its final order denying rehearing. Several market participants have filed petitions in the court of appeals for review of the FERC’s final order. PacifiCorp cannot quantify the impact of this case, if any, on future financial statements.

Federal Power Act Section 206 Case - In June 2003, the FERC issued a final order denying PacifiCorp’s request for recovery of excessive prices charged under certain wholesale electricity purchases scheduled for delivery during summer 2002 and dismissing PacifiCorp’s complaints, under section 206 of the Federal Power Act, against five wholesale electricity suppliers. In July 2003, PacifiCorp filed a petition in the Ninth Circuit Court of Appeals for review of certain aspects of this order. In July 2003, PacifiCorp filed its request for rehearing of the FERC’s order, which was granted in August 2003. The FERC issued its final order denying rehearing in November 2003. In November 2003, PacifiCorp filed a petition in the Ninth Circuit Court of Appeals for review of the FERC’s final order denying recovery. In November 2003, Morgan Stanley Capital Group, Inc., one of the five wholesale electricity suppliers, filed a petition in the D.C. Circuit Court of Appeals for review of the FERC’s final order. In December 2003, the case was transferred to the D.C. Circuit Court of Appeals for consolidation of the two appeals. In December 2003, PacifiCorp filed a motion to dismiss Morgan Stanley Capital Group, Inc.’s appeal. In April 2004, the D.C. Circuit Court of Appeals dismissed Morgan Stanley Capital Group, Inc.’s appeal, and PacifiCorp moved to transfer its appeal back to the Ninth Circuit Court of Appeals.

FERC Show-Cause Orders - In May 2002, PacifiCorp, together with other California electricity market participants, responded to data requests from the FERC regarding trading practices connected with the electricity crisis during 2000 and 2001. PacifiCorp confirmed that it did not engage in any trading practices intended to manipulate the market as described in the FERC’s data requests issued in May 2002. In June 2003, the FERC ordered 60 companies (including PacifiCorp) to show cause why their behavior during the California energy crisis did not constitute manipulation of the wholesale electricity market, as defined in the California Independent System Operator and the California Power Exchange tariffs. In setting the cases for hearing, the FERC directed the administrative law judge to hear evidence and render findings and conclusions quantifying the extent of any unjust enrichment that resulted and to recommend monetary or other appropriate remedies. In August 2003, PacifiCorp and the FERC staff reached a resolution on the show-cause order. Under the terms of the settlement agreement, PacifiCorp denied liability and agreed to pay a nominal amount of $67,745, in exchange for complete and total resolution of the issues raised in the FERC’s show-cause order relating to PacifiCorp. In March 2004, the FERC issued its final order approving the settlement and terminating the docket. In April 2004, certain market participants filed a request for rehearing of the FERC’s final order.

The Bonneville Power Administration Settlement - The Northwest Power Act provides access to the benefits of low-cost federal hydroelectricity to the residential and small-farm customers of the region’s investor-owned utilities through the Regional Exchange Program. The Bonneville Power Administration administers the Regional Exchange Program on behalf of other utilities in accordance with federal law. PacifiCorp is passing these benefits through to its Oregon, Washington and Idaho residential and small-farm customers in the form of electricity bill credits in the amount of approximately $119.2 million for the fiscal years 2002 through 2006. Additionally, PacifiCorp is currently negotiating a settlement with the Bonneville Power Administration for credits that would benefit the fiscal years 2007 through 2011. Several publicly owned utilities, cooperatives and Bonneville Power Administration direct-service industry customers have filed lawsuits with the Ninth Circuit Court of Appeals seeking review of Bonneville Power Administration’s decision to settle the Regional Exchange Program, as well as to challenge the level of benefits previously paid to customers. PacifiCorp has been actively involved in negotiations to settle these outstanding lawsuits. Unfortunately, these efforts have been unsuccessful, and PacifiCorp expects that the disputes cannot be resolved through settlement. As a result, PacifiCorp is working with the Bonneville Power Administration to identify potential solutions. As these benefits are passed through to PacifiCorp’s customers through adjustments to customer rates, an adverse decision reducing the level of these benefits, or requiring a return of benefits, should have no effect on PacifiCorp’s consolidated financial position or results of operations.

Note 11 – Guarantees and Other Commitments

Guarantees - PacifiCorp is generally required to obtain state regulatory commission approval prior to guaranteeing debt or obligations of other parties. In November 2002, the FASB issued Interpretation No. 45, Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others (“FIN 45”). FIN 45 requires disclosure of certain direct and indirect guarantees. Also, FIN 45 requires recognition of a liability at inception for certain new or modified guarantees issued after December 31, 2002. The adoption of FIN 45 in January 2003 did not have a material impact on the Consolidated Financial Statements.

The following represent the indemnification obligations of PacifiCorp as of March 31, 2004 and 2003.

PacifiCorp has made certain commitments related to the decommissioning or reclamation of certain jointly owned facilities and mine sites. The decommissioning guarantees require PacifiCorp to pay a proportionate share of the decommissioning costs based upon percentage of ownership. The mine reclamation obligations require PacifiCorp to pay the mining entity a proportionate share of the mine’s reclamation costs based on the amount of coal purchased by PacifiCorp. In the event of default by any of the other joint participants, PacifiCorp may potentially be obligated to absorb, directly or by paying additional sums to the entity, a proportionate share of the defaulting party’s liability. PacifiCorp has recorded its estimated share of the decommissioning and reclamation obligations as either an asset retirement obligation, regulatory liability or other liability.

In connection with the sale of PacifiCorp’s Montana service territory, PacifiCorp entered into a purchase and sale agreement with Flathead Electric Cooperative dated October 9, 1998. Under the agreement, PacifiCorp indemnified Flathead Electric Cooperative for losses, if any, occurring after the closing date and arising as a result of certain breaches of warranty or covenants. The indemnification has a cap of $10.1 million until October 2008 and a cap of $5.1 million thereafter (less expended costs to date). Two indemnity claims relating to environmental issues have been tendered, but remediation costs for these claims, if any, are not expected to be material.

From time to time, PacifiCorp executes contracts that include indemnifications typical for similar transactions, which are related to sales of businesses, property, plant and equipment and service territories. These indemnifications might include any of the following matters: privacy rights; governmental regulations and employment-related issues; commercial contractual relationships; financial reports; tax-related issues; securities laws; and environmental-related issues. Performance under these indemnities would generally be triggered by breach of representations and warranties in such a contract. PacifiCorp regularly evaluates the probability of having to incur costs under the indemnities and appropriately accrues for expected losses that are probable and estimable. Some of these indemnities may not limit potential liability; therefore, PacifiCorp is unable to estimate a maximum potential amount of future payments that could result from claims made under these indemnities.

PacifiCorp believes that the likelihood that it would be required to perform or otherwise incur any significant losses associated with any of these obligations is remote.

Construction - PacifiCorp has an ongoing construction program to meet increased electricity usage and customer growth. At March 31, 2004, PacifiCorp had estimated firm commitments for fiscal 2005 construction costs of $97.4 million. Of these committed costs, $91.9 million related to minimum contractual obligations associated with a remaining estimated $300.0 million of agreements to have the new Currant Creek plant constructed. In March 2004, PacifiCorp received regulatory approval from the Utah Public Service Commission for the Currant Creek plant via a Certificate of Convenience and Necessity and is expected to begin operations in June 2005.

Operating Leases - PacifiCorp leases offices, certain operating facilities and equipment under operating leases that expire at various dates through 2044. Certain leases contain renewal options for varying periods and escalation clauses for adjusting rental to reflect changes in price indices. These leases generally require PacifiCorp to pay for insurance, taxes and maintenance applicable to the leased property.

Net rent expense was $29.4 million for the year ended March 31, 2004; $21.0 million for the year ended March 31, 2003; and $27.1 million for the year ended March 31, 2002.

Future minimum lease payments under non-cancelable operating leases for the years ending March 31 are as follows:

(Millions of dollars)

2005	$	22.1
2006		8.3
2007		3.4
2008		2.0
2009		1.6
Thereafter		9.2

	$	46.6

Minimum non-cancelable sublease rentals expected to be received through 2016 is $8.7 million.

PacifiCorp is a lessor of fiber optic cable installed as ground wire for certain transmission lines and other equipment under operating leases. The lease arrangements have initial terms of five to 30 years and some contain provisions to extend the term at the option of the lessee. Certain leases include the reimbursement for taxes. Net rental income was approximately $3.4 million for each of the years ended March 31, 2004, 2003, and 2002. Future minimum lease income under non-cancelable operating leases is $3.9 million for each of the years ending March 31, 2005 through 2009 and $66.3 million thereafter.

Long-term wholesale sales - PacifiCorp 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 the FERC requirements) and meet commitments for wholesale sales and retail load growth. The long-term wholesale sales commitments include contracts with minimum sales requirements as follows for the years ending March 31:

(Millions of dollars)

2005	$	266.7
2006		225.1
2007		188.0
2008		150.8
2009		136.4
Thereafter		966.0

	$	1,933.0

Purchased electricity contracts - As part of its energy resource portfolio, PacifiCorp acquires a portion of its electricity through long-term purchases and/or exchange agreements which require minimum fixed payments as follows, for the years ending March 31:

(Millions of dollars)

2005	$	426.8
2006		436.6
2007		400.2
2008		287.0
2009		258.3
Thereafter		2,525.5

	$	4,334.4

Excluded from the minimum fixed annual payments above are commitments to purchase electricity 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. PacifiCorp is required to pay

its portion of operating costs and its portion of the debt service, whether or not any electricity is produced. The arrangements provide for non-withdrawable electricity and the majority also provide for additional electricity, withdrawable by the districts upon one to five years’ notice. For the year ended March 31, 2004, such purchases approximated 2.3% of energy requirements.

At March 31, 2004, PacifiCorp’s share of long-term arrangements with public utility districts was as follows:

(Millions of dollars)
Generating Facility	Year Contract Expires	Capacity (kW)	Percentage of Output		Annual Costs (a)

Wanapum	2009	155,444	18.7	%	$	7.2
Priest Rapids	2005	109,602	13.9			4.5
Rocky Reach	2011	64,297	5.3			4.0
Wells	2018	59,617	6.9			2.4

Total		388,960			$	18.1

(a)

Includes debt service totaling $7.0 million. PacifiCorp’s minimum debt service obligation was $6.0 million at March 31, 2004 and for the years ending March 31, is:

(Millions of dollars)

2005	$	6.4
2006		8.1
2007		11.3
2008		11.0
2009		12.1

	$	48.9

PacifiCorp has a 4.0% interest in the Intermountain Power Project, located in central Utah. PacifiCorp and the City of Los Angeles have agreed that the City of Los Angeles will purchase capacity and energy from PacifiCorp plants equal to its 4.0% entitlement of the Intermountain Power Project at a price equivalent to 4.0% of the expenses and debt service of the Intermountain Power Project.

Short-term wholesale sales and purchased electricity contracts - At March 31, 2004, PacifiCorp had short-term wholesale forward sales commitments that included contracts with minimum sales requirements as follows, for the years ending March 31:

(Millions of dollars)

2005	$	362.7
2006		168.4
2007		45.4

	$	576.5

At March 31, 2004, PacifiCorp had short-term forward purchase agreements requiring minimum fixed payments as follows, for the years ending March 31:

(Millions of dollars)

2005	$	279.3
2006		86.0
2007		15.3

	$	380.6

Fuel contracts - PacifiCorp has “take or pay” coal and natural gas contracts that require minimum fixed payments as follows, for the years ending March 31:

(Millions of dollars)

2005	$	255.5
2006		360.2
2007		171.9
2008		163.2
2009		137.2
Thereafter		787.2

	$	1,875.2

Resource management - PacifiCorp, 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 2.

Note 12 – Jointly Owned Facilities

At March 31, 2004, PacifiCorp’s share in jointly owned facilities was as follows:

(Millions of dollars)	Company Share		Plant in Service		Accumulated Depreciation/ Amortization		Construction Work in Progress

Centralia Skookumchuck (a)	47.5	%	$	8.7	$	5.1	$	—
Colstrip Nos. 3 and 4 (b)	10.0			236.4		107.2		1.3
Craig Station Nos. 1 and 2	19.3			168.5		80.0		5.8
Foote Creek	78.8			37.0		7.4		—
Hayden Station No. 1	24.5			40.8		16.1		0.2
Hayden Station No. 2	12.6			26.2		11.1		0.1
Hermiston (c)	50.0			163.6		32.1		—
Hunter No. 1	93.8			287.9		135.3		10.1
Hunter No. 2	60.3			205.7		91.7		1.3
Jim Bridger Nos. 1 - 4 (b)	66.7			873.8		432.5		9.3
Trojan (d)	2.5			—		—		—
Wyodak	80.0			306.7		148.4		2.0
Other kilovolt lines and substations	Various			78.5		18.2		—
Unallocated acquisition adjustments (e)				141.2		56.1		—

Total			$	2,575.0	$	1,141.2	$	30.1

(a)

The Centralia, Washington plant and mine were sold on May 4, 2000. The joint owners of the plant retained ownership in the Skookumchuck Dam and related facilities.

(b)

Includes kilovolt lines and substations.

(c)

Additionally, PacifiCorp has contracted to purchase the remaining 50.0% of the output of the plant. See Note 13.

(d)

Plant, inventory, fuel and decommissioning costs totaling $11.4 million relating to the Trojan Plant were included in regulatory assets at March 31, 2004.

(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. PacifiCorp’s portion is recorded in its applicable operations, maintenance and tax accounts, which is consistent with wholly owned plants.

Note 13 – Consolidation of Variable-Interest Entities

In January 2003, the FASB issued FIN 46, which requires existing unconsolidated variable-interest entities (“VIEs”) to be consolidated by their primary beneficiaries if the entities do not effectively disperse risks among parties involved. In October 2003, the FASB deferred the effective date of FIN 46, as it applied to variable-interest entities acquired before February 1, 2003, until the end of the first interim or annual period beginning after December 15, 2003. In December 2003, the FASB issued a revision of FIN 46 (“FIN 46R”) to clarify certain provisions of the standard. FIN 46R required that FIN 46 be applied to those entities that are considered to be special-purpose entities, no later than the end of the first interim or annual period ending after December 15, 2003. The application of FIN 46 to special-purpose entities as of December 31, 2003 had no impact on PacifiCorp’s consolidated financial position or results of operations. FIN 46R was adopted as of January 1, 2004 and resulted in certain disclosures describing variable interests that were identified. However, the adoption of the interpretation did not have a material impact on PacifiCorp’s consolidated financial position or results of operations. PacifiCorp will continue to evaluate the impact of FIN 46R as implementation guidance evolves. If subsequent guidance or interpretation is different from management’s current understanding, it is possible that PacifiCorp’s identification of VIEs and primary beneficiaries could change.

In general, a VIE is a corporation, partnership, trust or any other legal structure used for business purposes whose equity investors lack the characteristics of a controlling financial interest or whose equity investment at risk is not sufficient to support the entity’s activities without additional subordinated financial support. FIN 46R requires a VIE to be consolidated by a company if that company is subject to a majority of the risk of loss from the VIE’s activities or is entitled to receive a majority of the VIE’s residual returns. The company that is required to consolidate the VIE is called the primary beneficiary. FIN 46R requires deconsolidation of a VIE if a company is not the primary beneficiary of the VIE. The interpretation also requires disclosures regarding: (i) VIEs in which a company has a significant variable-interest but is not the primary beneficiary and (ii) the inability to obtain the information necessary to determine whether an entity is a VIE, identify the primary beneficiary, or consolidate the VIE.

VIEs Required to be Consolidated

PacifiCorp holds an undivided interest in 50.0% of the 474 MW Hermiston plant (see Note 12), procures 100.0% of the fuel input into the plant and subsequently acquires 100.0% of the generated electricity. Since PacifiCorp owns only 50.0% of the plant, it is required to purchase 50.0% of the generated electricity from the joint owner (in which PacifiCorp holds no equity interest) through a long-term purchase power agreement. As a result, PacifiCorp holds a variable-interest in the joint owner of the remaining 50.0% of the plant and is the primary beneficiary. However, PacifiCorp was unable to obtain the information necessary to consolidate the entity as the entity did not agree to supply the information due to the lack of a contractual obligation to do so. Electricity purchased from the joint owner was $33.7 million during the year ended March 31, 2004; $34.0 million during the year ended March 31, 2003; and $33.1 million during the year ended March 31, 2002. The entity is operated by the equity owners and PacifiCorp has no risk of loss in relation to the entity in the event of a disaster.

PacifiCorp is a party to certain operating and coal purchase agreements with Bridger Coal Company that create a variable interest under the provisions of FIN 46R. Bridger Coal Company owns and operates the Jim Bridger mine near Point of the Rocks, Wyoming, and produces 100.0% of its output for the benefit of the Bridger Power Plant. PacifiCorp has a 66.7% equity interest in both the Bridger Power Plant and Bridger Coal Company. As PacifiCorp is subject to a majority of the risk of loss from Bridger Coal Company’s activities, and is entitled to receive a majority of Bridger Coal Company’s residual returns, PacifiCorp is considered to be the primary beneficiary and is required to consolidate Bridger Coal Company. Accordingly, PacifiCorp will continue to consolidate Bridger Coal Company as in prior periods.

Significant Variable-Interests in VIEs not Required to be Consolidated

As discussed in Note 4, PacifiCorp leases the West Valley facility from PPM under an operating lease that contains purchase options at specified prices. Although the purchase options are variable interests in West Valley, PacifiCorp is not the primary beneficiary of the entity. PacifiCorp’s exposure to loss under the operating lease is negligible.

PacifiCorp is a party to certain operating and coal purchase agreements with Trapper Mining, Inc. that create a variable interest under the provisions of FIN 46R. Trapper Mining, Inc. owns and operates the Trapper Mine near Craig, Colorado, and produces 100.0% of its output for the benefit of the Craig Power Plant. PacifiCorp has a 19.3% equity interest in Craig Power Plant and a 21.4% equity interest in Trapper Mining, Inc. Since each equity investor in Trapper Mining, Inc. also holds a similar interest in the Craig Power Plant, and since none of the joint owners have more than a 50.0% interest in the Craig Power Plant or Trapper Mining, Inc., none of the joint owners are required to consolidate Trapper Mining, Inc. As such, PacifiCorp will continue to account for its interest in Trapper Mining, Inc. via the equity method under APB No. 18, The Equity Method of Accounting for Investments in Common Stock, as in prior periods.

Note 14 – Preferred Securities

During August 2003, PacifiCorp redeemed, prior to maturity, all of its Series C and D junior subordinated debentures held by two wholly owned subsidiary trusts of PacifiCorp (the “Trusts”), resulting in the redemption by the Trusts of all 8,680,000 of the 8.25% Series A Cumulative Quarterly Income Preferred Securities totaling $217.0 million and all 5,400,000 of the 7.70% Series B Preferred Securities totaling $135.0 million. Subsequent to these redemptions, the Trusts were cancelled. Upon redemption, $10.0 million of deferred charges were reclassified to a regulatory asset. These retirements were funded initially through short-term debt and subsequently by the long-term debt financing discussed in Note 8.

PacifiCorp’s Preferred Securities at March 31, 2003 were as follows:

	March 31, 2003

(Millions of dollars, thousands of Preferred Securities)	Shares	Amount

8.25% Cumulative Quarterly Income Preferred Securities, Series A,
with Trust assets of $223.7 million (a)	8,680	$	210.8

7.70% Trust Preferred Securities, Series B, with Trust assets of $139.2 million (b)	5,400		131.0

	14,080	$	341.8

(a)

Amount is net of unamortized issuance costs of $6.2 million.

(b)

Amount is net of unamortized issuance costs of $4.0 million.

Note 15 – Preferred Stock

PacifiCorp’s Preferred stock was as follows:

(Millions of dollars, except per share amounts, thousands of shares)	Redemption Price Per Share		March 31, 2004			March 31, 2003

Series			Shares	Amount		Shares	Amount

Preferred stock not subject to mandatory redemption
Serial Preferred, $100 stated value, 3,500 shares authorized
4.52%	$	103.5	2	$	0.2	2	$	0.2
4.56		102.3	85		8.4	85		8.4
4.72		103.5	70		6.9	70		6.9
5.00		100.0	42		4.2	42		4.2
5.40		101.0	66		6.6	66		6.6
6.00		Non–redeemable	6		0.6	6		0.6
7.00		Non–redeemable	18		1.8	18		1.8
5.00% Preferred, $100 stated value, 127 shares authorized		110.0	126		12.6	126		12.6

			415	$	41.3	415	$	41.3

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.

PacifiCorp had $0.5 million at March 31, 2004 and March 31, 2003 in dividends declared but unpaid on Preferred stock.

Note 16 – Common Stock

Common Stock - PacifiCorp has one class of common stock with no par value. A total of 750,000,000 shares were authorized and 312,176,089 shares were issued and outstanding at March 31, 2004 and 2003.

On August 22, 2002, PacifiCorp’s Board of Directors approved the issuance of up to 50 million additional shares of its common stock (“Shares”) to be sold, from time to time, to its direct parent, PHI, in such amounts and at such times as would be determined by PacifiCorp, subject to regulatory approval, which has been received. Issuance and sale of the Shares is subject to the receipt of cash for the Shares in an amount per share not less than the book value of the Shares at the end of the month prior to the date of the issuance. On December 19, 2002, PacifiCorp issued 14,851,485 Shares to PHI, receiving $150.0 million in cash proceeds, equal to $10.10 per share, the book value of the Shares at the end of November 2002. Proceeds were used to repay debt and for general corporate purposes.

Common Dividend Restrictions - ScottishPower is the sole indirect shareholder of PacifiCorp’s common stock. PacifiCorp is restricted from paying dividends or making other distributions without prior OPUC approval to the extent such payment or distribution would reduce PacifiCorp’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. As of March 31, 2004, the minimum ratio was 39.0%. PacifiCorp is also subject to maximum debt-to-total capitalization levels under various debt agreements.

Note 17 – Fair Value of Financial Instruments

	March 31, 2004				March 31, 2003

(Millions of dollars)	Carrying Amount		Fair Value		Carrying Amount		Fair Value


Long-term debt (a)	$	3,732.6	$	4,181.3	$	3,526.6	$	4,000.1
Preferred Securities		—		—		341.8		353.3
Preferred stock subject to mandatory redemption		60.0		67.9		66.7		78.1
Weather derivative liability		3.4		3.4		2.6		2.6

(a)

Includes 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 PacifiCorp’s long-term debt, current maturities of 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. The fair value of Preferred Securities was estimated using quoted market prices at March 31, 2003.

The fair value of weather derivatives reflects the net present value of future premiums owed by PacifiCorp, offset by estimated settlements owed to/(by) PacifiCorp, for the remainder of the contract term. PacifiCorp estimates future settlements based upon actual hydrology conditions incurred for the current contract year and hydrology forecasts for the remaining contract term. Those hydrology forecasts generally reflect normal water conditions.

Note 18 – Retirement Benefit Plans

In January 2004, the FASB issued SFAS No. 132R. The interim-period disclosures were effective for interim periods beginning after December 15, 2003, and this statement was generally effective for fiscal years ending after December 15, 2003. Adoption of this statement changed the required disclosures for pension and other postretirement benefit plan assets, obligations and net cost in the Notes to the Consolidated Financial Statements, but did not impact PacifiCorp’s consolidated financial position or results of operations.

Retirement Plans

PacifiCorp sponsors defined benefit pension plans that cover the majority of its employees. In addition, certain bargaining unit employees participate in a joint trust plan to which PacifiCorp contributes. Benefits under the main 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, 2004, plan assets were primarily invested in common stocks, bonds and United States government obligations. The measurement date for plan assets and obligations is December 31 of each year.

Components of the net periodic pension benefit cost (income) are summarized as follows:

	Years Ended March 31,

(Millions of dollars)	2004			2003			2002


Service cost	$	25.8	(a)	$	21.6	(a)	$	14.9
Interest cost		73.9			76.8			80.1
Expected return on plan assets		(80.7	)		(92.8	)		(99.9	)
Amortization of unrecognized net obligation		8.4			8.4			8.4
Amortization of unrecognized prior service cost		1.5			2.1			0.5
Amortization of unrecognized gain		—			(4.2	)		(10.3	)


Net periodic pension benefit cost (income)	$	28.9		$	11.9		$	(6.3	)

(a)

Includes contributions of $5.6 million for the year ended March 31, 2004 and $5.0 million for the year ended March 31, 2003 to the PacifiCorp/IBEW Local 57 Retirement Trust Fund.

The weighted average rates assumed in the actuarial calculations used to determine the net periodic benefit costs for the pension and postretirement benefit plans were as follows:

	Years Ended March 31,

	2004		2003		2002

Discount rate	6.75	%	7.50	%	7.75	%
Expected long-term rate of return on assets	8.75		9.25		9.25
Rate of increase in compensation levels	4.00		4.00		4.00

The weighted average rates assumed in the actuarial calculations used to determine benefit obligations for the pension and postretirement benefit plans were as follows:

	Years Ended March 31,

	2004		2003		2002

Discount rate	6.25	%	6.75	%	7.50	%
Rate of increase in compensation levels	4.00		4.00		4.00

PacifiCorp determined the long-term rate of return based on historical asset class returns and current market conditions, taking into account the diversification benefits of investing in multiple asset classes.

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

	March 31,

(Millions of dollars)	2004			2003

Change in projected benefit obligation
Projected benefit obligation - beginning of year	$	1,151.6		$	1,079.3
Service cost		20.1			16.6
Interest cost		73.9			76.8
Special termination benefits		—			(4.1	)(a)
Actuarial loss		97.1			97.5
Benefits paid		(112.9	)		(114.5	)

Projected benefit obligation - end of year	$	1,229.8		$	1,151.6

Change in plan assets
Plan assets at fair value - beginning of year	$	681.2		$	826.2
Actual return on plan assets		128.3			(60.0	)
Company contributions		36.6			29.5
Benefits paid		(112.9	)		(114.5	)

Plan assets at fair value - end of year	$	733.2		$	681.2


Reconciliation of accrued pension cost and total amount recognized
Funded status of the plan	$	(496.6	)	$	(470.4	)
Unrecognized net loss		375.2			325.6
Unrecognized prior service cost		9.4			11.0
Unrecognized net transition obligation		24.4			32.8

Accrued pension cost	$	(87.6	)	$	(101.0	)


Accrued benefit liability	$	(360.5	)	$	(381.5	)
Intangible asset		33.8			43.8
Accumulated other comprehensive income		12.9			2.9
Regulatory assets		226.2			233.8

Accrued pension cost	$	(87.6	)	$	(101.0	)

(a)

Represents an adjustment to the obligation to provide benefits to employees who elected a special termination benefit in the year ended March 31, 2001, but revoked the election in the year ended March 31, 2003.

The aggregated accumulated benefit obligation was $1,093.7 million and the fair value of assets was $733.2 million as of March 31, 2004.

The PacifiCorp Retirement Plan and the Supplemental Executive Retirement Plan, together the “Plans,” currently have assets with a fair value that is less than the accumulated benefit obligation under the Plans primarily due to declines in the equity markets and historically low interest rate levels. As a result, PacifiCorp recognized minimum pension liabilities in the fourth quarters of the years ended March 31, 2004 and at March 31, 2003. The minimum pension liability adjustment impacted Regulatory assets, Intangible assets and Accumulated other comprehensive income. These adjustments are reflected in the table above and did not materially affect the consolidated results of operations. PacifiCorp requested and received accounting orders from the regulatory commissions in Utah, Oregon and Wyoming to classify most of this charge as a Regulatory asset instead of a charge to Other comprehensive income and has filed for similar treatment in Washington during fiscal 2004. PacifiCorp has determined that according to SFAS No. 87, Employers’ Accounting for Pensions (“SFAS No. 87”), costs for the PacifiCorp Retirement Plan are currently recoverable in rates. This increase to Regulatory assets will be adjusted in future periods as the difference between the fair value of the trust assets and the accumulated benefit obligation changes.

Pension plan assets are managed and invested in accordance with all applicable requirements, including the Employee Retirement Income Security Act and the Internal Revenue Service revenue code. PacifiCorp employs an investment approach whereby a mix of equities and fixed-income investments is used to maximize the long-term

return of plan assets for a prudent level of risk. Risk tolerance is established through careful consideration of plan liabilities, plan funded status, and corporate financial condition. The investment portfolio contains a diversified blend of equity and fixed-income investments as shown in the table below. Equity investments are diversified across United States and non-United States stocks, as well as growth, value, and small and large capitalizations. Fixed-income investments are diversified across United States and non-United States bonds. Other assets, such as private equity, are used judiciously to enhance long-term returns while improving portfolio diversification. PacifiCorp primarily minimizes the risk of large losses through diversification but also monitors and manages other aspects of risk through quarterly investment portfolio reviews, annual liability measurements and periodic asset/liability studies.

The following table shows a breakdown of the pension plan assets by investment category based on market values.

			March 31,

	Target		2004		2003

Equity securities	55.0	%	55.3	%	53.2	%
Debt securities	35.0		34.4		34.6
Private equity	10.0		10.3		12.2

In April 2004, PacifiCorp contributed $61.6 million to its Retirement Plan. In addition, PacifiCorp expects to contribute another $6.2 million to its Supplemental Executive Retirement Plan, as well as $31.7 million to its other postretirement benefit plan in fiscal 2005.

Employee Savings and Stock Ownership Plan

PacifiCorp has an employee savings and stock ownership plan that qualifies as a tax-deferred arrangement under the Internal Revenue Code. Eligible employees of adopting affiliates are those who are not temporary, casual, leased, or covered by a collective bargaining agreement that does not provide for participation. Employees of any company within the PacifiCorp controlled group of companies that has not adopted the plan are not eligible. Participating United States employees may defer up to 25.0% of their compensation, subject to certain statutory limitations. This limit was raised to 50.0% in February 2004. Compensation includes base pay, overtime and annual incentive, but is limited to the maximum allowable under the Internal Revenue Code. Employees can select a variety of investment options including ScottishPower American Depository Shares (formerly PacifiCorp shares). PacifiCorp matches 50.0% of employee contributions on amounts deferred up to 6.0% of total compensation, with that portion vesting over the initial five years of an employee’s participation in the Plan. Thereafter, PacifiCorp’s contributions vest immediately. PacifiCorp’s matching contribution is allocated based on the employee’s investment selections. PacifiCorp’s additional contribution is allocated based on the employee’s investment selections or to the money market fund if the employee has made no selections. PacifiCorp makes an additional contribution equal to a percentage of the employee’s eligible earnings. These contributions are immediately vested. PacifiCorp’s contributions to the employee savings and stock ownership plan were $19.3 million for the year ended March 31, 2004; $17.4 million for the year ended March 31, 2003; and $16.8 million for the year ended March 31, 2002, and represent amounts expensed for such periods.

Other Postretirement Benefits

PacifiCorp provides health care and life insurance benefits through various plans for eligible retirees. The cost of other 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. PacifiCorp funds other postretirement benefits through a combination of funding vehicles. PacifiCorp contributed $25.3 million and $22.6 million for the years ended March 31, 2004 and 2003 and made no contributions for the year ended March 31, 2002. The measurement date for plan assets and obligations is December 31 of each year.

For the other postretirement benefit plan assets, PacifiCorp employs an investment approach whereby a mix of equities and fixed-income investments is used to maximize the long-term return of plan assets for a prudent level of risk. Risk tolerance is established through careful consideration of plan liabilities, plan funded status and corporate financial condition. The investment portfolio contains a diversified blend of equity and fixed-income investments as shown in the table below. Equity investments are diversified across United States and non-United States stocks, as well as growth, value and small and large capitalizations. Fixed-income investments are diversified across United States and non-United States bonds. Other assets, such as private equity, are used judiciously to

enhance long-term returns while improving portfolio diversification. PacifiCorp primarily minimizes the risk of large losses through diversification, but also monitors and manages other aspects of risk through quarterly investment portfolio reviews, annual liability measurements and periodic asset/liability studies.

The table below shows a breakdown of the other postretirement benefit plan assets by investment category based on market values.

			March 31,

	Target		2004		2003

Equity securities	63.0	%	62.1	%	61.6	%
Debt securities	35.0		36.1		36.6
Private equity	2.0		1.8		1.8

Components of the net periodic postretirement benefit cost are summarized as follows:

	Years Ended March 31,

(Millions of dollars)	2004			2003			2002

Service cost	$	7.4		$	5.6		$	5.2
Interest cost		34.3			34.2			28.6
Expected return on plan assets		(26.6	)		(28.5	)		(29.2	)
Amortization of unrecognized net obligation		12.2			12.2			12.2
Amortization of unrecognized loss (gain)		0.6			—			(4.5	)
Regulatory deferral		—			1.1			1.5

Net periodic postretirement benefit cost	$	27.9		$	24.6		$	13.8

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

	March 31,

(Millions of dollars)	2004			2003

Change in accumulated postretirement benefit obligation
Accumulated postretirement benefit obligation - beginning of year	$	522.4		$	470.4
Service cost		7.4			5.6
Interest cost		34.3			34.2
Plan participant contributions		6.8			6.1
Special termination benefits		—			(0.9	) (a)
Plan amendments		0.6			—
Actuarial loss		21.5			40.8
Benefits paid		(37.7	)		(33.8	)

Accumulated postretirement benefit obligation - end of year	$	555.3		$	522.4

Change in plan assets
Plan assets at fair value - beginning of year	$	218.0		$	262.5
Actual return on plan assets		50.8			(21.4	)
Company contributions		23.7			4.6
Plan participant contributions		6.8			6.1
Net benefits paid		(37.7	)		(33.8	)

Plan assets at fair value - end of year	$	261.6		$	218.0

Reconciliation of accrued postretirement costs and total amount recognized
Funded status of the plan	$	(293.7	)	$	(304.4	)
Unrecognized net transition obligation		106.8			119.0
Unrecognized prior service cost		0.6			—
Unrecognized loss		140.1			143.4

Accrued postretirement benefit cost, before final contribution		(46.2	)		(42.0	)
Final contribution made after measurement date but before March 31		25.3			21.1

Accrued postretirement cost	$	(20.9	)	$	(20.9	)

(a)

The following assumptions were used in the actuarial calculations to develop the related other postretirement balances:

	March 31,

	2004		2003		2002

Discount rate	6.25	%	6.75	%	7.50	%
Estimated long-term rate of return on assets	8.75		8.75		9.25
Initial health care cost trend - under 65	8.5		9.5		10.5
Initial health care cost trend - over 65	10.5		11.5		12.5
Ultimate health care cost trend rate	5.0		5.0		5.0

Year that rate reaches ultimate - under 65	2007		2007		2007
Year that rate reaches ultimate - over 65	2009		2009		2009

The health care cost trend rate assumption has a significant effect on the amounts reported. An annual increase or decrease in the assumed medical care cost trend rate of one percent would affect the accumulated postretirement benefit obligation and the service and interest cost components as follows:

	One Percent

(Millions of dollars)	Increase		Decrease

Accumulated postretirement benefit obligation	$	31.9	$	(27.0	)
Service and interest cost components		2.7		(2.3	)

Note 19 – Stock Option Incentive Plan

During 1997, PacifiCorp adopted a Stock Option Incentive Plan (the “Option Plan”). The exercise price of options granted under the Option 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 Option Plan was 10 years. The Option Plan expired on November 29, 2001.

Upon completion of the merger with ScottishPower (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 American Depository Shares. Stock options to purchase ScottishPower American Depository Shares granted in connection with 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 Option Plan.

ScottishPower American Depository Shares	Number of Shares		Weighted Average Price


Outstanding options at March 31, 2001	3,727,020		$	33.49

Granted	824,750			25.68
Exercised	(24,665	)		26.94
Forfeited	(560,109	)		32.74


Outstanding options at March 31, 2002	3,966,996			32.01

Forfeited	(563,745	)		34.06


Outstanding options at March 31, 2003	3,403,251			31.67

Exercised	(147,496	)		25.55
Forfeited	(331,706	)		34.65


Outstanding options at March 31, 2004	2,924,049			31.64

Information with respect to options outstanding and options exercisable as of March 31, 2004 and 2003 was as follows:

	Options Outstanding				Options Exercisable

Range of Exercise Prices	Number of Shares	Weighted Average Exercise Price		Weighted Average Remaining Life (in years)	Number of Shares	Weighted Average Exercise Price

Year ended March 31, 2004
$25.06 - $36.64	2,367,392	$	29.51	5.5	2,156,368	$	29.88
$39.99 - $43.83	556,657	40.72		3.9	556,657	40.72

Total	2,924,049	31.64		5.2	2,713,025	32.10

Year ended March 31, 2003
$25.06 - $36.64	2,737,760	$	29.45	6.1	2,104,695	$	30.10
$39.99 - $43.83	665,491	40.81		4.3	665,491	40.81

Total	3,403,251	31.67		5.8	2,770,186	32.68

Note 20 – Income Taxes

The difference between the United States federal statutory tax rate and the effective income tax rate attributed to income from continuing operations is as follows:

	Years Ended March 31,

	2004		2003		2002

Federal statutory rate	35.0	%	35.0	%	35.0	%
State taxes, net of federal benefit	1.9		3.4		2.9
Effect of regulatory treatment of depreciation differences	4.5		6.5		2.9
Tax reserves (a)	(1.4	)	1.9		4.5
Sale of Australian Electric Operations (b)	—		—		(2.1	)
Tax credits	(2.5	)	(5.6	)	(2.3	)
Other	(0.8	)	(0.6	)	(3.4	)

Effective income tax rate	36.7	%	40.6	%	37.5	%

(a)

PacifiCorp has established, and periodically reviews, an estimated contingent tax reserve on its Consolidated Balance Sheets to provide for the possibility of adverse outcomes in tax proceedings.

During the year ended March 31, 2004, PacifiCorp reached an agreement in principle with the Internal Revenue Service on certain tax issues related to PacifiCorp’s 1994 through 1998 federal income tax returns. The agreement in principle results in a tax and interest liability of $13.1 million, for which a contingency tax reserve was previously provided.

The Internal Revenue Service started its examination of the 1999 and 2000 tax years in September 2002. During the year ended March 31, 2004, PacifiCorp reached an agreement in principle with the Internal Revenue Service on certain tax issues related to PacifiCorp’s 1999 and 2000 federal income tax returns and, as a result, released $17.8 million of previously provided tax contingency reserves. This was partially offset by an increase to the tax contingency reserve of $5.6 million primarily to accrue interest on remaining tax contingencies provided for in prior periods. The resulting change in the tax contingency reserve during the year ended March 31, 2004 was a net release of $12.2 million.

PacifiCorp believes that final settlement and payment on settled issues and other unresolved issues related to the federal income tax returns through March 31, 2000 will not have a material adverse impact on its consolidated financial position or results of operations.

(b)

In accordance with United States federal income tax law, a portion of the excess capital loss from the sale of PacifiCorp’s Australian Operations during the year ended March 31, 2001 was reattributed to another member and a benefit was taken in the federal consolidated tax return filed for the year ended March 31, 2002.

The provision for income taxes is summarized as follows:

	Years Ended March 31,

(Millions of dollars)	2004			2003			2002

Current
Federal	$	63.0		$	54.2		$	104.1
State		1.0			11.2			11.1

Total		64.0			65.4			115.2

Deferred
Federal		77.8			38.6			63.2
State		10.6			1.1			8.5

Total		88.4			39.7			71.7

Investment tax credits		(7.9	)		(7.9	)		(10.8	)

Total income tax expense	$	144.5		$	97.2		$	176.1

The tax effect of temporary differences giving rise to significant portions of PacifiCorp’s deferred tax liabilities and deferred tax assets were as follows:

	March 31,

(Millions of dollars)	2004			2003

Deferred tax liabilities
Property, plant and equipment	$	1,413.2		$	1,018.8
Regulatory assets		700.0			814.0
Derivative contract regulatory assets		160.2			192.4
Other deferred tax liabilities		76.2			53.6

		2,349.6			2,078.8

Deferred tax assets
Regulatory liabilities		(329.7	)		(79.4	)
Employee benefits		(164.8	)		(209.7	)
Derivative contracts		(173.4	)		(197.8	)
Other deferred tax assets		(148.6	)		(111.9	)

		(816.5	)		(598.8	)

Net deferred tax liability	$	1,533.1		$	1,480.0

PacifiCorp made net income tax payments of $114.1 million for the year ended March 31, 2004; $82.2 million for the year ended March 31, 2003; and $83.1 million for the year ended March 31, 2002. The income tax payments include payments for current federal and state income taxes, as well as amounts paid in settlement of prior years’ liabilities as a result of income tax proceedings.

Note 21 – Discontinued Operations

PacifiCorp recognized $146.7 million of income in the year ended March 31, 2002 as a result of PGHC 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’s receiving payment under a coal supply contract. PacifiCorp recognized this gain on a cost-recovery basis as payments were received by PGHC from the buyer. In June 2001, PGHC 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.

Note 22 – 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 PGHC to PHI. Accordingly, the results of operations and assets of PGHC are not included with those of PacifiCorp commencing February 4, 2002.

In October 2001, PFS sold its synthetic fuel operations. The sale resulted in a pretax gain of approximately $11.3 million for the year ended March 31, 2002.

During the year ended March 31, 2002, PFS sold aircraft owned by one of its subsidiaries. PFS received proceeds of approximately $36.0 million and recorded a $9.3 million pretax gain on the sale.

During the year ended March 31, 2001, PGHC completed the sale of its ownership of Powercor Australia Ltd. and its 19.9% interest in Hazelwood Power Partnership. Powercor Australia Ltd. and Hazelwood Power Partnership represented the entire Australian Operations segment of PacifiCorp. In June 2001, upon resolution of a contingency under the provisions of the Powercor Australia Ltd. sale agreement, PGHC received further proceeds due from the sale that resulted in income of $27.4 million for the year ended March 31, 2002.

Note 23 – Concentration of Customers

During the year ended March 31, 2004, no single retail customer accounted for more than 1.7% of PacifiCorp’s retail electric revenues and the 20 largest retail customers accounted for 13.0% of total retail electric revenues. The geographical distribution of PacifiCorp’s retail operating revenues for the year ended March 31, 2004 was Utah, 38.5%; Oregon, 31.5%; Wyoming, 12.8%; Washington, 8.4%; Idaho 6.3%; and California, 2.5%.

Note 24 – Segment Information

PacifiCorp previously operated in two business segments (excluding other and discontinued operations): Domestic Electric Operations and Australian Operations. The Australian Operations were sold in fall 2000. PacifiCorp currently has one segment, Electric Operations, which includes the regulated retail and wholesale electric operations in the six western states in which it operates. Australian Operations included the deregulated electric operations in Australia. Other Operations consisted of PFS and other energy development businesses, as well as the activities of PGHC, including financing costs. PGHC and its subsidiaries, including PFS, were transferred to PHI in February 2002 as discussed in Note 1.

Note 25 – Subsequent Events

On April 15, 2004, the PacifiCorp Board of Directors declared a dividend on common stock of approximately $0.155 per share for a total of approximately $48.3 million, payable on May 27, 2004.

SUPPLEMENTAL INFORMATION

QUARTERLY FINANCIAL DATA (UNAUDITED)

	Quarters Ended

(Millions of dollars, except per share amounts)	June 30			September 30		December 31		March 31

2004
Revenues (a)	$	783.9		$	845.4	$	788.4	$	776.8
Income from operations		168.9			149.3		161.5		139.0
Income from continuing operations before cumulative effect of accounting change		63.5			59.1		60.5		65.9
Cumulative effect of accounting change		(0.9	)		—		—		—
Net income		62.6			59.1		60.5		65.9
Earnings on common stock		60.8			58.6		60.0		65.4
Common dividends declared per share		12.8¢			12.8¢		12.8¢		12.8¢
Common dividends paid per share		12.8¢			12.8¢		12.8¢		12.8¢

2003
Revenues (a)	$	712.0		$	762.4	$	782.0	$	826.0
Income from operations		118.7			132.0		121.0		117.2
Income from continuing operations before cumulative effect of accounting change		37.5			31.5		39.7		33.3
Cumulative effect of accounting change		(1.9	)		—		—		—
Net income		35.6			31.5		39.7		33.3
Earnings on common stock		33.7			29.7		37.9		31.5
Common dividends declared per share		—			—		—		—
Common dividends paid per share		—			—		—		—

(a)

Certain amounts from prior periods have been reclassified to conform to the year ended March 31, 2004 method of presentation.

The following schedule provides a reconciliation from the current year quarterly schedule to the amounts presented in the most recent quarterly or annual SEC filings.

	Quarters Ended

(Millions of dollars)	June 30			September 30			December 31			March 31

2004
Revenues as previously reported	$	894.8		$	958.0		$	873.6		$	776.8
Adoption of EITF No. 03-11		(110.7	)		(104.7	)		(90.5	)		—
Reclassification of Unrealized (gain) loss on derivative contracts		(0.2	)		(7.9	)		5.3			—

Revenues as currently reported	$	783.9		$	845.4		$	788.4		$	776.8

2003
Revenues as previously reported	$	885.6		$	943.9		$	853.2		$	910.7
Adoption of EITF No. 03-11		(177.2	)		(181.5	)		(71.2	)		(84.9	)
Reclassification of Unrealized (gain) loss on derivative contracts		3.6			—			—			0.2

Revenues as currently reported	$	712.0		$	762.4		$	782.0		$	826.0

On March 31, 2004, 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.

ITEM 9A. CONTROLS AND PROCEDURES

(a) PacifiCorp maintains a system of controls and procedures designed to provide reasonable assurance as to the reliability of the financial statements and other disclosures included in this annual report. PacifiCorp performed an evaluation, under the supervision of the Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of PacifiCorp’s disclosure controls and procedures. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that as of March 31, 2004 the disclosure controls and procedures were effective, in all material respects, in timely alerting management to material information relating to PacifiCorp and its consolidated subsidiaries required to be included in its periodic reports filed pursuant to the Securities Exchange Act of 1934.

(b) There has been no change in PacifiCorp’s internal control over financial reporting that occurred during the quarter ended March 31, 2004 that has materially affected, or is reasonably likely to materially affect, PacifiCorp’s internal control over financial reporting.

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PART III

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

The following is a list of directors of PacifiCorp as of March 31, 2004.

Name and Age		Business Experience Past Five Years

Ian M. Russell (51)		Chairman of the Board of Directors. Director since November 1999.

		Mr. Russell was appointed Chief Executive of ScottishPower in April 2001 and Chairman of PacifiCorp in January 2002. Mr. Russell serves on the Board of Directors for Scottish Power plc. 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 United Kingdom and United States operations.

Judith A. Johansen (45)		President and Chief Executive Officer. Director since December 2000.

		Ms. Johansen was elected President and Chief Executive Officer in June 2001 and served as Executive Vice President since December 2000. Ms. Johansen was appointed to the Board of Directors for Scottish Power plc in October 2003. She was Administrator and Chief Executive Officer of the Bonneville Power Administration in Portland, Oregon from June 1998 to November 2000. From June 1996 to May 1998, Ms. Johansen was vice president of business development with Avista Energy.

Barry G. Cunningham (59)		Senior Vice President. Director since April 2002.

		Mr. Cunningham was named PacifiCorp’s Senior Vice President of Generation in February 2002. Mr. Cunningham joined PacifiCorp in June 1977 and served as a Vice President from May 1999 to February 2002 and as an Assistant Vice President from September 1998 to May 1999.

Andrew P. Haller (52)		Senior Vice President, General Counsel and Corporate Secretary. Director since May 2003.

		Mr. Haller joined PacifiCorp in December 2000. Prior to joining PacifiCorp, he was chief executive for the United States operations of Kvaerner Process, a position he held from 1998 to 2000. Mr. Haller began his career with Kvaerner in 1987, and held various senior counsel and management positions, including Senior Vice President and General Counsel-Americas. From 1998 to 1999, he served as the Associate General Counsel for the parent company, Kvaerner ASA, in its United States corporate headquarters.

Nolan E. Karras (59)		Director since February 1993.

		Mr. Karras is President of The Karras Company, Inc., an investment adviser, and has served in that capacity since 1983. He is Chief Executive Officer of Western Hay Company, Inc., a non-executive Director of Scottish Power plc and Beneficial Life Insurance Company and is a Registered Principal for Raymond James Financial Services.

William D. Landels (61)		Executive Vice President. Director since November 1999.

101

		Mr. Landels has been with ScottishPower since 1985. He was elected Executive Vice President and Director of PacifiCorp 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. Mr. Landels retired in April 2004.

Andrew N. MacRitchie (40)		Executive Vice President. 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 United States 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.

Richard D. Peach (40)		Chief Financial Officer. Director since May 2003.

		Mr. Peach was named PacifiCorp’s Chief Financial Officer effective January 2003. Mr. Peach had previously served as Senior Vice President of Finance since March 2002. Prior to his appointment as Chief Financial Officer, Mr. Peach served as Group Controller for ScottishPower since March 2000 and served in various management positions since 1995.

Michael J. Pittman (51)		Senior Vice President. Director since May 2000.

		Mr. Pittman was elected a Senior Vice President of Human Resources in May 2000. He formerly served as a Vice President of PacifiCorp from May 1993. Mr. Pittman is also Chairman of the PacifiCorp Foundation for Learning.

A. Richard Walje (52)		Senior Vice President. Director since July 2001.

		Mr. Walje has served as PacifiCorp’s Senior Vice President of Corporate Business Services from May 2001 and served as PacifiCorp’s Vice President and Chief Information Officer from May 2000 to July 2001. Mr. Walje also served as PacifiCorp’s Vice President for Transmission and Distribution Operations and Customer Service from 1998 to 2000. Mr. Walje serves on the PacifiCorp Foundation for Learning Board of Directors.

Matthew R. Wright (39)		Executive Vice President. Director since July 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 November 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 PacifiCorp not named above. There are no family relationships among the executive officers of PacifiCorp. Officers of PacifiCorp are normally elected annually.

Name and Age		Business Experience Past Five Years

Donald N. Furman (47)		Senior Vice President.

		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 Business Development from 1997 to 2001 and as President of PPM from 1995 to 1997.

102

Robert A. Klein (56)		Senior Vice President.

		Mr. Klein has served as PacifiCorp’s Senior Vice President of Commercial and Trading since August 2001. In March 2003, he was named ScottishPower’s Energy Risk Director. Prior to joining PacifiCorp in December 2000, Mr. Klein served as Senior Vice President and General Manager of Equitable Resources’ deregulated marketing business from 1998 to 1999 and as Vice President of Risk Management for Coral Equity from 1997 to 1998.

Robert Moir (54)		Senior Vice President.

		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. He retired in March 2004.

Stan Watters (45)		Senior Vice President.

		Mr. Watters was elected Senior Vice President of Commercial and Trading in June 2003. Mr. Watters served as Vice President of Trading and Origination from July 2001 to June 2003. Mr. Watters has been with PacifiCorp since 1982.

Bruce N. Williams (45)		Treasurer.

		Mr. Williams was named Treasurer in February 2000. Prior to being elected Treasurer, he served as Assistant Treasurer of PacifiCorp and has been with PacifiCorp since 1985.

In addition to its Guide to Business Conduct, which provides a basis for employee ethical standards and conduct for all employees, the PacifiCorp Board of Directors has approved and implemented a “Code of Ethics for Principal Officers” designed to promote the integrity of PacifiCorp’s financial reporting and legal compliance. The Code of Ethics applies to PacifiCorp’s Chief Executive Officer and its financial and accounting officers. The Guide to Business Conduct and Code of Ethics are available in the Investor Relations section of PacifiCorp’s website at www.pacificorp.com. PacifiCorp intends to make available on its website any amendment to, or waiver from, the Code of Ethics as the Code applies to PacifiCorp’s Chief Executive Officer and its financial and accounting officers.

Because PacifiCorp’s common stock is indirectly, wholly owned by ScottishPower, its Board of Directors consists almost entirely of internal executives. Accordingly, the audit committee functions of PacifiCorp are carried out by the Audit Committee of ScottishPower (the “ScottishPower Audit Committee”), which consists entirely of directors who are independent of ScottishPower, determined in accordance with New York Stock Exchange listing standards.

Neither the PacifiCorp Board of Directors nor the ScottishPower Audit Committee currently has an independent director who is an audit committee financial expert in respect of PacifiCorp. However, the ScottishPower Audit Committee does have significant financial experience and includes one member who has been determined by the ScottishPower Board of Directors to be an audit committee financial expert for ScottishPower, due in part to his understanding of generally accepted accounting principles as applied in the United Kingdom. There is limited availability of appropriately experienced individuals who are experts in both United Kingdom and United States generally accepted accounting principles and otherwise qualified as independent financial experts in accordance with the rules of the SEC. The PacifiCorp Board of Directors believes that the Scottish Power Audit Committee is able to provide appropriate levels of oversight.

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ITEM 11. EXECUTIVE COMPENSATION

BOARD OF DIRECTORS OF PACIFICORP REPORT ON EXECUTIVE COMPENSATION

Introduction

The Board of Directors of PacifiCorp submits this report on executive compensation, which outlines the compensation provided to PacifiCorp’s executive officers. The Remuneration Committee of the ScottishPower Board of Directors, assisted by its outside advisors, has the responsibility to approve compensation levels and executive compensation plans for the PacifiCorp Chief Executive Officer and to review compensation for other officers of PacifiCorp. The Remuneration Committee is composed entirely of independent, non-employee directors. With the exception of any compensation requiring review by the Remuneration Committee, the ScottishPower Chief Executive Officer, the PacifiCorp Chief Executive Officer and the ScottishPower Human Resources Director have responsibility for approving compensation levels and executive compensation plans for officers of PacifiCorp. Each of these individuals serve on the Board of Directors of PacifiCorp. The Remuneration Committee must approve any stock-based compensation to PacifiCorp executive officers. The following 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, 2003 to March 31, 2004.

Compensation Philosophy

PacifiCorp’s philosophy is that executive compensation, including that of its Chief Executive Officer, should be linked closely to corporate and operational performance, customer service and increases in shareholder value. PacifiCorp’s compensation program has the following objectives:

(i)

provide competitive total compensation that enables PacifiCorp to attract and retain key executives;

(ii)

provide variable compensation opportunities that are linked to PacifiCorp, operational area, and individual performance; and

(iii)

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

Qualifying compensation for deductibility under Internal Revenue Code Section 162(m) is one of the factors the ScottishPower Chief Executive Officer, the ScottishPower Human Resources Director and the PacifiCorp Chief Executive Officer consider in designing PacifiCorp’s incentive compensation arrangements. Internal Revenue Code Section 162(m) limits to $1.0 million 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 intent to design and administer compensation programs that maximize deductibility, the Remuneration Committee, the ScottishPower Chief Executive Officer, the ScottishPower Human Resources Director and the PacifiCorp Chief Executive Officer view the objectives outlined above as more important than compliance with the technical requirements necessary to exclude compensation from the deductibility limit of Internal Revenue Code Section 162(m). Nevertheless, the Remuneration Committee, the ScottishPower Chief Executive Officer, the ScottishPower Human Resources Director and the PacifiCorp Chief Executive Officer believe that nearly all compensation paid to the executive officers for services rendered in the year ended March 31, 2004 is fully deductible.

Compensation Program Components

During the year ended March 31, 2004, the compensation programs were focused on market-based comparisons on the relevant industry for each officer. The electric utility industry was utilized as the exclusive basis for market comparison for positions with a principal focus on electric operations. For positions with a corporate-wide focus, the weighting of approximately 67.0% general industry and 33.0% electric utility industry was used for market comparison. In all cases, compensation is targeted at market median levels, with an assumption that total compensation greater than market median, in any specific time period, anticipates that Company performance exceeds the median performance of peer companies.

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

104

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, 2004, the base salary of each executive officer was increased, based on market analysis, to reflect competitive market changes, individual performance and changes in the responsibilities of some officers.

Annual Incentive Compensation

All PacifiCorp officers, including those listed in the Summary Compensation Table, participated in PacifiCorp’s Annual Incentive Program. Performance goals were based on PacifiCorp performance, operational performance and individual performance, and may include ScottishPower performance based on the level, influence and impact of the officer.

Long-Term Incentive Compensation

Historically, the Board of Directors of PacifiCorp 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. 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 are exercised or expire.

Restricted stock awards under the Stock Incentive Plan are subject to terms, conditions and restrictions determined by the Board of Directors of PacifiCorp to be consistent with the plan and the best interests of the shareholders. 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. 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 American Depository Shares 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 the year ended March 31, 2002.

In April 2003, the Remuneration Committee approved grants of stock options and performance share awards under ScottishPower’s Executive Share Option Plan 2001 (“ExSOP”) and the Long-Term Incentive Plan (“LTIP”), respectively, for a select group of executive officers and other senior managers. ExSOP and performance share grants were awarded to PacifiCorp senior managers in May 2003. See below for LTIP awards.

All stock options awarded to officers and senior management of PacifiCorp in the years ended March 31, 2004, 2003 and 2002 are non-statutory, non-discounted options with a three-year vesting requirement and a 10-year term from the date of the grant.

The LTIP links the rewards closely between management and shareholders, and focuses on long-term corporate performance. The awards will vest only if the Remuneration Committee is satisfied that certain threshold customer service and financial performance measures are achieved. The number of shares that actually vest is dependent upon ScottishPower’s comparative Total Shareholder Return performance, over a three-year performance period.

The Board of Directors of PacifiCorp report on executive compensation detailed above has been submitted by all the members of the PacifiCorp Board of Directors as listed below:

•

Ian M. Russell, Chairman

•

Judith A. Johansen

•

Barry G. Cunningham

•

Nolan E. Karras

•

Andrew N. MacRitchie

•

Michael J. Pittman

•

A. Richard Walje

105

•

Matthew R. Wright

•

Richard D. Peach

•

Andrew P. Haller

Executive Compensation

The following table sets forth information concerning compensation for services in all capacities to PacifiCorp for the years ended March 31, 2004, 2003 and 2002 of those persons who were the Chief Executive Officer of PacifiCorp during any portion of the year ended March 31, 2004 and the next four other most highly compensated executive officers of PacifiCorp who were serving as executive officers at the end of the last completed fiscal year.

Summary Compensation Table

						Long-Term Compensation

						Restricted Stock Awards (c)		Securities Underlying Options (d)	LTIP Payout (e)		ScottishPower Performance Shares (f)	All Other Compensation (g)
Name and Principal Position		Annual Compensation (a)

	Year	Salary		Bonus (b)

Judith A. Johansen President and Chief Executive Officer	2004	$	589,394	$	337,500	$	—	61,475	$	—	12,458	$	22,883
	2003		492,444		149,767		—	61,825		—	9,199		21,170
	2002		360,501		12,902		141,683	57,350		—	—		11,707

Andrew P. Haller Senior Vice President, General Counsel and Corporate Secretary	2004		327,996		190,109		—	13,530		—	5,484		20,165
	2003		310,930		132,020		—	19,165		23,069	5,069		21,037
	2002		299,425		8,392		112,768	56,800		23,644	—		10,524


Michael J. Pittman Senior Vice President	2004		313,125		187,500		—	38,729		—	7,849		20,097
	2003		300,000		47,057		—	50,954		—	7,581		18,860
	2002		275,167		150,008		53,203	13,500		—	—		20,449

A. Richard Walje Executive Vice President	2004		299,544		127,557		—	17,751		—	7,195		20,324
	2003		275,500		95,550		—	24,840		—	6,570		19,278
	2002		240,375		128,854		53,203	14,000		12,222	—		19,606

Robert A. Klein Senior Vice President	2004		265,000		143,100		—	10,860		—	4,402		19,795
	2003		228,339		75,075		—	14,011		—	3,706		21,079
	2002		202,500		13,295		—	—		—	—		10,212

(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 American Depository Shares 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)

Amounts in this column for the year ended March 31, 2003 include a promotion bonus in the amount of $41,556 for Ms. Johansen. Amounts in this column for the year ended March 31, 2002 include a retention bonus in the amount of $125,610 for Mr. Pittman and $104,000 for Mr. Walje.

(c)

On March 31, 2004, the aggregate value of all restricted stock holdings, based on the market value of ScottishPower American Depository Shares at March 31, 2004, without giving effect to the diminution of value attributed to the restrictions on such stock, was $104,444 for Ms. Johansen, $83,129 for Mr. Haller, $26,146 for Mr. Pittman, and $26,146 for Mr. Walje. The aggregate number of restricted share holdings was 3,675 for Ms. Johansen, 2,925 for Mr. Haller, 920 for Mr. Pittman, and 920 for Mr. Walje. 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.

Amounts shown for the year ended March 31, 2004 and 2003 represent the number of American Depository Shares option shares awarded under the ScottishPower ExSOP. Amounts shown for the year ended March 31,

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2002 represent the number of American Depository Shares options awarded under the PacifiCorp Stock Incentive Plan.

(e)

Represents the dollar value of restricted stock shares awarded under the PacifiCorp Stock Incentive Plan prior to PacifiCorp’s acquisition by ScottishPower that vested and were distributed to the named officer in the form of ScottishPower American Depository Shares.

(f)

Represents the number of ScottishPower American Depository Shares contingently granted in 2004, 2003 and 2002 that can be earned under the terms of the ScottishPower LTIP.

(g)

Amounts shown for the year ended March 31, 2004 include:

(i)

Company contributions to the PacifiCorp K Plus Employee Savings and Stock Ownership Plan were $12,083 for Ms. Johansen, $10,179 for Mr. Haller, $10,156 for Mr. Pittman, $10,421 for Mr. Walje and $10,000 for Mr. Klein.

(ii)

Portions of premiums on term life insurance policies that PacifiCorp paid in the amounts of $1,800 for Ms. Johansen, $986 for Mr. Haller, $941 for Mr. Pittman, $903 for Mr. Walje and $795 for Mr. Klein. These benefits are available to all employees.

(iii)

This column also includes vehicle allowances paid to Ms. Johansen and Messrs. Haller, Pittman, Walje and Klein in the amounts of $9,000 each.

Option Grants in Last Fiscal Year

The following table sets forth information regarding options to purchase ScottishPower American Depository Shares granted to each named executive officer under the ScottishPower ExSOP. 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.

	Individual Grants

Name	Number of Securities Underlying Options Granted	% of Total Options Granted to Employees in Fiscal Year		Exercise or Base Price ($/Sh)		Expiration Date	Potential Realizable Value at Assumed Annual Rates of Stock Price Appreciation for Option Term

							5%		10%

Judith A. Johansen	61,475	7.87	%	$	24.40	May 9, 2013	$	943,336	$	2,390,598
Andrew P. Haller	13,530	1.73			24.40	May 9, 2013		207,618		526,145
Michael J. Pittman	38,729	4.96			24.40	May 9, 2013		594,298		1,506,067
A. Richard Walje	17,751	2.27			24.40	May 9, 2013		272,390		690,289
Robert A. Klein	10,860	1.39			24.40	May 9, 2013		166,647		422,316

Aggregated Option Exercises at March 31, 2004 and Year-End Option Values

The following table sets forth information regarding the aggregate options exercised during the past fiscal year and the option values at the fiscal year ended March 31, 2004, for each of the named executive officers. All options are for ScottishPower American Depository Shares and include options granted under the PacifiCorp Stock Incentive Plan and the ExSOP.

				Number of Securities Underlying Unexercised Options at March 31, 2004		Value of Unexercised In-the-Money Options at March 31, 2004

Name	Shares Acquired on Exercise	Value Realized		Exercisable	Unexercisable	Exercisable		Unexercisable

Judith A. Johansen	13,500	$	23,760	97,539	126,961	$	329,245	$	517,327
Andrew P. Haller	98,925		219,475	—	47,370		—		175,641
Michael J. Pittman	—		—	193,325	81,445		104,380		349,156
A. Richard Walje	—		—	154,922	41,738		71,257		175,637
Robert A. Klein	—		—	10,245	25,326		33,945		104,916

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Employment Agreement

On September 29, 2003, Ms. Johansen and PacifiCorp executed an employment agreement providing for a base salary of $700,000 and a maximum annual incentive award of 75.0% of base salary. Under the agreement, she is eligible for participation, as defined by the plan rules, in the LTIP, ExSOP and retirement plan referred to below, in addition to other benefit plans available for senior level executives of PacifiCorp. The employment agreement renews annually unless either party terminates the agreement. Ms. Johansen or PacifiCorp may terminate the employment agreement at any time for any reason. However, if Ms. Johansen resigns from PacifiCorp due to a material alteration in compensation or assignment or following a company-initiated relocation, or if PacifiCorp terminates Ms. Johansen without cause, then Ms. Johansen will be entitled to one year’s base salary, car allowance and bonus (as modified pursuant to the terms of the employment agreement). Additionally, as part of the regular terms and conditions, Ms. Johansen agreed to confidentiality, non-competition and non-solicitation terms.

Severance Arrangements

PacifiCorp’s Executive Severance Plan provides severance benefits to certain executive-level employees who are designated by the Board of Directors of PacifiCorp, including the executive officers named in the Summary Compensation Table (other than Ms. Johansen).

Severance benefits are payable by PacifiCorp for voluntary terminations as a result of a certain material alterations in position or compensation that have a detrimental impact on the executive’s employment or involuntary terminations (including a PacifiCorp-initiated resignation) for reasons other than cause. Severance payments generally equal one or two times the executive’s annual cash compensation, three months of health insurance benefits and outplacement services.

The Executive Severance Plan also provides enhanced severance benefits in the event of certain terminations during the 24-month period following a qualifying change-in-control transaction. Executives designated by the Board of Directors of PacifiCorp are eligible for change-in-control benefits resulting from either a PacifiCorp-initiated termination without cause or a resignation generally within two months after certain material alterations in position or 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 the executive, depending on the level set by the Board of Directors of PacifiCorp. PacifiCorp is required to make an additional payment to compensate the executive for the effect of any excise tax. The executive would also receive continuation of subsidized health insurance from six to 24 months, depending on length of service, and outplacement services.

Retirement Plans

PacifiCorp has adopted non-contributory defined benefit retirement plans for its 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, are also eligible to participate in PacifiCorp’s non-qualified 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 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 annual incentive plan payments reflected in the Summary Compensation Table above. Benefits are based on 50.0% 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 of Directors of PacifiCorp. 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 five 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, 2004. Amounts in the table reflect payments from the retirement plan and the supplemental plan combined.

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Estimated Annual Pension at Retirement (a)

		Years of Service (b)

Annual Pay at Retirement Date		5		15		25		30

$	200,000	$	43,333	$	130,000	$	130,000	$	130,000
	400,000		86,667		260,000		260,000		260,000
	600,000		130,000		390,000		390,000		390,000
	800,000		173,333		520,000		520,000		520,000
	1,000,000		216,667		650,000		650,000		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.

(b)

The number of credited years of service used to compute benefits under the plans are three for Ms. Johansen, three for Mr. Haller, 24 for Mr. Pittman, 18 for Mr. Walje, and three for Mr. Klein.

Retention Agreements

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, PacifiCorp entered into retention agreements with qualifying executives (Messrs. Pittman and Walje). Those retention agreements provided for the same enhanced supplemental retirement benefits if the qualifying executives satisfied the retention criteria. Qualifying executives were required to waive their rights to unilaterally resign and receive the enhanced supplemental retirement benefits, but they are now eligible to receive these same enhancements since they have continued 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 PacifiCorp’s discretion for each executive and special stock option awards that vest over a three-year retention period at 25.0% for each of the first two years and 50.0% in the third year.

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ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

All common shares of PacifiCorp 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.

The following table sets forth certain information as of March 31, 2004 regarding the beneficial ownership of ScottishPower Ordinary Shares by (1) each of the executive officers named in the Summary Compensation Table under Item 11. Executive Compensation above, (2) each director of PacifiCorp as detailed under Item 10. Directors and Executive Officers of the Registrant, and (3) all executive officers and directors as a group. As of March 31, 2004, each of the directors and executive officers identified above and all directors and executive officers of PacifiCorp as a group owned less than 1% of the outstanding Ordinary Shares of ScottishPower.

	Amount and Nature of Beneficial Ownership

Beneficial Owner	Direct and Indirect (a)	Options (b)	Total

Judith A. Johansen	88,960	610,416	699,376
Michael J. Pittman	112,212	893,888	1,006,100
Andrew P. Haller	53,280	110,812	164,092
A. Richard Walje	83,200	684,104	767,304
Ian M. Russell	127,440	45,000	172,440
Barry G. Cunningham	58,718	468,932	527,650
Robert A. Klein	724	82,184	82,908
Nolan E. Karras	33,601	—	33,601
William D. Landels (c)	23,601	188,764	212,365
Andrew N. MacRitchie	12,448	6,634	19,082
Richard D. Peach	5,323	6,331	11,654
Matthew R. Wright	8,331	4,615	12,946
All executive officers and directors as a group (16 persons) (d)	737,591	4,015,348	4,752,939

(a)

Includes ownership of (i) shares held by family members even though beneficial ownership of such shares may be disclaimed and (ii) shares held for the account of such persons pursuant to PacifiCorp’s Compensation Reduction Plan and PacifiCorp’s K Plus Savings and Stock Ownership Plan.

(b)

Includes Ordinary Shares that each person has the right to acquire through options that become exercisable within 60 days after March 31, 2004. Options granted in ScottishPower American Depository Shares under PacifiCorp’s Stock Incentive Plan have been converted into options in Ordinary Shares. One American Depository Share equates to four Ordinary Shares.

(c)

Includes 188,764 of Ordinary Shares subject to options that became exercisable upon Mr. Landels’ retirement in April 2004.

(d)

Includes 62,748 of Ordinary Shares subject to options that became exercisable upon Mr. Moir’s retirement in March 2004.

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. Mr. Haller has repaid $82,314.26 of the loan amount. As of March 31, 2004, the outstanding loan balance was $121,873.29, including accrued interest, payable in four additional equal payments of $32,988.56, including interest, on June 30 in each year from 2004 to 2007.

See Note 4 of Notes to the Consolidated Financial Statements for other information on related-party transactions.

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ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES

The ScottishPower Audit Committee retained PricewaterhouseCoopers LLP, independent certified public accountants, as PacifiCorp’s independent registered public accounting firm for the year ended March 31, 2004 and the year ending March 31, 2005.

Fees and Pre-Approval Policy

During the year ended March 31, 2004, the ScottishPower Audit Committee adopted a pre-approval policy for PricewaterhouseCoopers’ services and fees. This policy details the services that can be provided by the independent auditors, and requires that where the initial fee value for any services permitted in accordance with the policy exceeds £100,000 (or its United States dollar equivalent), the assignment must be reviewed and authorized by both the Chairman of the ScottishPower Audit Committee with the concurrence of the ScottishPower Finance Director. Any services authorized by the Chairman are reported to the ScottishPower Audit Committee at its next scheduled meeting, and fees paid to the independent auditors are reported regularly to the ScottishPower Audit Committee. The PacifiCorp Board of Directors has not adopted any pre-approval policy that is in addition to or different than the ScottishPower Audit Committee’s pre-approval policy.

The following table presents fees paid to PricewaterhouseCoopers for the fiscal years ended March 31, 2004 and 2003.

	Year Ended March 31,

(Millions of dollars)	2004				2003

Audit fees	$	1.4	28.6	%	$	1.4	17.3	%
Audit-related fees		0.1	2.0			0.1	1.2
Tax fees		3.3	67.4			6.3	77.8
Other fees		0.1	2.0			0.3	3.7

Total	$	4.9	100.0	%	$	8.1	100.0	%

Audit fees are for the audit and review of PacifiCorp’s financial statements in accordance with the standards of the Public Company Accounting Oversight Board (United States), including comfort letters, statutory and regulatory audits, consents and services related to SEC matters.

Audit-related fees are for assurance and related services that are related to the audit or review of PacifiCorp’s financial statements, including employee benefit plan audits, due diligence services and financial accounting and reporting consultation.

Tax fees are fees for tax compliance services and related costs.

Other fees are mainly for services rendered in connection with requests from state regulatory commissions and for regulatory matters.

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PART IV

ITEM 15. 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:*

	* 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 PacifiCorp (Exhibit (3)b, Form 10-K for the year ended December 31, 1996, File No. 1-5152).

3.2*	Bylaws of PacifiCorp effective November 29, 1999 (Exhibit (3)b, Form 10-K for the year ended March 31, 2000, File No. 1-5152).

4.1*	Mortgage and Deed of Trust dated as of January 9, 1989, between PacifiCorp 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)			33-31861
(4)(a)	8-K	January 9, 1990	1-5152
4(a)	8-K	September 11, 1991	1-5152
4(a)	8-K	January 7, 1992	1-5152
4(a)	10-Q	Quarter ended March 31, 1992	1-5152
4(a)	10-Q	Quarter ended September 30, 1992	1-5152
4(a)	8-K	April 1, 1993	1-5152
4(a)	10-Q	Quarter ended September 30, 1992	1-5152
4(a)	10-Q	Quarter ended September 30, 1993	1-5152
(4)b	10-K	Quarter ended June 30, 1994	1-5152
(4)b	10-K	Quarter ended December 31, 1994	1-5152
(4)b	10-K	Quarter ended December 31, 1995	1-5152
(4)b	10-K	Quarter ended December 31, 1996	1-5152
99(a)	8-K	November 21, 2001	1-5152
99	8-K	September 8, 2003	1-5152

4.2*	Third Restated Articles of Incorporation and Bylaws. See 3.1 and 3.2 above.

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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**	Engineering, Procurement and Construction Contract between PacifiCorp and Stone & Webster, Inc., dated as of February 10, 2004

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	Power of Attorney

31.1	Section 302 Certification Principal Executive Officer Pursuant to Rule 13a-14(a)/15d-14(a)

31.2	Section 302 Certification Principal Financial Officer Pursuant to Rule 13a-14(a)/15d-14(a)

32.1	Section 906 Certification Principal Executive Officer Pursuant to 18 U.S.C. Section 1350

32.2	Section 906 Certification Principal Financial Officer Pursuant to 18 U.S.C. Section 1350

______________

Incorporated herein by reference.

Certain portions of this exhibit have been omitted and filed separately with the SEC based on a request for confidential treatment.

(b)

Reports on Form 8-K.

On Form 8-K, dated March 4, 2004, under Item 5. Other Events, PacifiCorp announced that the Wyoming Public Service Commission (“WPSC”) granted PacifiCorp $22.9 million of additional annual revenues in the general rate case filed May 27, 2003. In addition, the WPSC order provides a return on equity of 10.75%. The new rates are effective March 3, 2004. The order will result in an average overall price increase in Wyoming of approximately 7.2%. For further information regarding this general rate case, please see Item 5. Other Information in PacifiCorp’s Form 10-Q for the quarterly period ended December 31, 2003.

(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
				By:	/s/ JUDITH A. JOHANSEN

					Judith A. Johansen (PRESIDENT AND CHIEF EXECUTIVE OFFICER)

Date: May 25, 2004

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

/s/ IAN M. RUSSELL	Chairman of the Board of Directors	May 25, 2004

Ian M. Russell

/s/ JUDITH A. JOHANSEN	President, Chief Executive Officer and Director	May 25, 2004

Judith A. Johansen

/s/ RICHARD D. PEACH	Chief Financial Officer and Director	May 25, 2004

Richard D. Peach

/s/ DAVID MENDEZ	Chief Accounting Officer	May 25, 2004

David Mendez

* NOLAN E. KARRAS	) ) )

Nolan E. Karras
	) )
/s/ ANDREW N. MacRITCHIE	) ) )

Andrew N. MacRitchie

/s/ MICHAEL J. PITTMAN	) ) ) )

Michael J. Pittman
	)
/s/ A. RICHARD WALJE	) Director ) ) ) )	May 25, 2004

A. Richard Walje
	)

114

/s/ MATTHEW R. WRIGHT		) ) ) )

Matthew R. Wright
		)
/s/ BARRY G. CUNNINGHAM		) ) ) )

Barry G. Cunningham
		)
/s/ ANDREW P. HALLER		) ) ) )

Andrew P. Haller
		)
*By: /s/ JUDITH A. JOHANSEN		) ) )

Judith A. Johansen, as Attorney-in-Fact for Nolan E. Karras

115