PACIFICORP /OR/ - Annual Report: 2005 (Form 10-K)

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)

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

For the fiscal year ended March 31, 2005

o	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, 2004. As of May 19, 2005, 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	17
	Item 3.		Legal Proceedings	21
	Item 4.		Submission of Matters to a Vote of Security Holders	22
Part II
		Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	22
		Item 6.	Selected Financial Data	23
		Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	27
		Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	56
		Item 8.	Financial Statements and Supplementary Data	62
		Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	106
		Item 9A.	Controls and Procedures	106
		Item 9B.	Other Information	106
Part III
		Item 10.	Directors and Executive Officers of the Registrant	107
		Item 11.	Executive Compensation	110
		Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	118
		Item 13.	Certain Relationships and Related Transactions	118
		Item 14.	Principal Accounting Fees and Services	119
Part IV
		Item 15.	Exhibits, Financial Statement Schedules	120
Signatures				122

DEFINITIONS

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

Term		Meaning

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
MidAmerican		MidAmerican Energy Holdings Company, an lowa corporation
MW		Megawatt
MWh		Megawatt-hour(s), one megawatt continuously for one hour
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, 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
Wheeling		The transmission of electricity by an entity that neither owns nor directly uses the electricity transmitted
WPSC		Wyoming Public Service Commission
WUTC		Washington Utilities and Transportation Commission

iii

PART I

ITEM 1.

BUSINESS

OVERVIEW

PacifiCorp is a regulated electricity company serving retail customers in portions of the states of Utah, Oregon, Wyoming, Washington, Idaho and California. As a vertically integrated electric utility, PacifiCorp owns or has contracts for fuel sources such as coal and natural gas and uses these fuel sources, as well as wind, geothermal and water 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 customers through PacifiCorp’s distribution system. PacifiCorp sells electricity primarily in the retail market, with sales to residential, commercial and industrial customers. It conducts its retail electric utility business under the names Pacific Power and Utah Power. PacifiCorp also sells electricity in the wholesale market in connection with excess electricity generation or hedging activities. Wholesale electricity sales and purchases are conducted under the name PacifiCorp. 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. PacifiCorp expects that costs prudently incurred to provide service to its customers will be included as allowable costs for state ratemaking purposes.

Ownership by ScottishPower; Agreement to Sell PacifiCorp

Currently, 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.”

On May 23, 2005, ScottishPower and PacifiCorp Holdings, Inc. (“PHI”), its wholly owned subsidiary directly holding PacifiCorp’s common stock, executed a Stock Purchase Agreement (the “Stock Purchase Agreement”) providing for the sale of all PacifiCorp common stock held by PHI to MidAmerican Energy Holdings Company (“MidAmerican”) for a value of approximately $9.4 billion, consisting of approximately $5.1 billion in cash plus approximately $4.3 billion in net debt and preferred stock, which will remain outstanding at PacifiCorp. MidAmerican is based in Des Moines, Iowa, and is a privately owned global provider of energy services. The acquisition is subject to customary closing conditions, including the approval of the transaction by the shareholders of ScottishPower and the receipt of required state and federal regulatory approvals. The transaction is expected to be completed in calendar 2006. The Stock Purchase Agreement also requires ScottishPower to obtain MidAmerican’s prior approval to certain actions taken by PacifiCorp, including incurring indebtedness and making capital expenditures, beyond agreed limits. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Overview – Sale of PacifiCorp” for a more detailed description.

The summary of the terms of the Stock Purchase Agreement contained in this Annual Report is modified in its entirety by reference to the terms of such agreement, which is included as an exhibit hereto.

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 of electricity, and the operation of its electric generation and transmission facilities.

Consistent with state regulations, PacifiCorp uses an Integrated Resource Plan to provide a framework and plan for prudent future actions required to help ensure that PacifiCorp continues to provide reliable and cost-effective electric service to its customers.

Employees

PacifiCorp had 6,654 employees on March 31, 2005. Approximately 57.3% 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.

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 “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Forward-Looking Statements.” 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 97232. 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 service territories 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 natural resources. 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 forest products, food processing, high technology and primary metals being the largest industrial sectors. The following map highlights PacifiCorp’s retail service territory, plant locations and PacifiCorp’s primary transmission lines. PacifiCorp’s generating facilities are interconnected through PacifiCorp’s own transmission lines or by contract through the transmission lines owned by others. See “Item 2. Properties” for additional information on PacifiCorp’s plants.

The geographic distribution of PacifiCorp’s retail electric operating revenues for the years ended March 31, 2005 and 2004 was as follows:

	Years Ended March 31,

	2005		2004

Utah	40.6	%	38.5	%
Oregon	29.3		31.5
Wyoming	13.6		12.8
Washington	8.0		8.4
Idaho	6.1		6.3
California	2.4		2.5

	100.0	%	100.0	%

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 years or more, some being granted indefinitely. PacifiCorp must renew franchises that expire. 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. See “Item 7. Risk Factors – PacifiCorp is subject to federal and state legislation, regulations and political risks that may adversely affect its business.”

CUSTOMERS

Electricity sold to retail customers and the number of retail customers, by class of customer, for the years ended March 31, 2005, 2004 and 2003, were as follows:

	Years Ended March 31,

	2005					2004					2003

(Thousands of MWh)

MWh sold
Residential		14,117		28.9	%		14,460		29.7	%		13,287		28.3	%
Commercial		14,642		29.9			14,413		29.6			14,006		29.8
Industrial		19,454		39.8			19,133		39.3			19,048		40.6
Other		706		1.4			673		1.4			631		1.3

Total MWh sold		48,919		100.0	%		48,679		100.0	%		46,972		100.0	%

Number of Retail Customers (Thousands)
Residential		1,373		85.5	%		1,341		85.4	%		1,317		85.4	%
Commercial		194		12.1			190		12.1			186		12.1
Industrial		34		2.1			34		2.2			34		2.2
Other		4		0.3			5		0.3			5		0.3

Total		1,605		100.0	%		1,570		100.0	%		1,542		100.0	%


Residential Customers
Average annual usage (kWh)		10,411					10,889					10,182
Average annual revenue per customer	$	741				$	749				$	701
Revenue per kWh		7.1	¢				6.9	¢				6.9	¢

For the five years to March 31, 2010, PacifiCorp is estimating average growth in retail megawatt-hour (“MWh”) sales in PacifiCorp’s franchise service territories to be in the range of 2.2% to 3.3% 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. Strong Utah residential growth over the last several years and increasing installations of central air conditioning systems are contributing to faster summer peak growth.

RETAIL COMPETITION

During the year ended March 31, 2005, PacifiCorp continued to operate its retail business under state regulation, which generally prohibits retail competition. However, certain of PacifiCorp’s commercial and industrial customers in Oregon have the right to choose alternative electricity suppliers. As a result of Direct Access mandated by Oregon’s Senate Bill 1149, a group of customers having a total average load of approximately 18 megawatts (“MW”) have chosen service from suppliers other than PacifiCorp. A group of customers having a total average load of approximately 2 MW have taken service from PacifiCorp at the Daily Market Pricing Option. This service provides a market-based pricing option by linking the energy charge on a customer’s bill to a representative market price index. PacifiCorp does not expect the Direct Access program and the Daily Market Pricing Option to have a material effect on earnings for the year ending March 31, 2006.

In addition to Oregon’s Direct Access program, others in PacifiCorp’s service territories are seeking to have a choice of suppliers, exploring options to build their own generation or co-generation plants, or considering the use of alternative energy sources such as natural gas. If these 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. The use of alternative energy sources is typically based on availability, price and the general demand for electricity.

Any adoption of retail competition by the legislatures in the states served by PacifiCorp, in addition to the Direct Access program, and/or 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. Although PacifiCorp believes it will continue as a regulated entity and does not expect significant retail competition in the near future, it cannot predict if or to what extent it will be subject to changes in legislation or regulation allowing retail competitors, nor can PacifiCorp predict the impact of these changes. See “Item 7. Risk Factors – PacifiCorp is subject to federal and state legislation, regulations and political risks that may adversely affect its business.”

POWER AND FUEL SUPPLY

Generating Plants

PacifiCorp uses its portfolio of electricity generating plants and wholesale purchases to meet its retail load obligations. PacifiCorp owns, or has interests in, the following types of electricity generating plants:

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

Coal	11	6,585.9	6,104.4
Natural gas and geothermal	5	723.9	689.0
Hydroelectric	51	1,083.6	1,155.4
Wind	1	32.6	32.6

Total	68	8,426.0	7,981.4

In addition, PacifiCorp operates a 200.0 MW net plant capability natural gas-fired facility in Utah pursuant to an operating lease with West Valley Leasing Company, LLC (“West Valley”) and is in the process of having two natural gas-fired facilities constructed in Utah, the Currant Creek and Lake Side Power Plants, with a total estimated capability of 1,059.0 MW. See “Item 2. Properties” for further discussion.

The following table shows the percentage of PacifiCorp’s total energy requirements supplied by its generation plants during the years ended March 31, 2005 and 2004.

	Years Ended March 31,

	2005		2004

Coal	69.4	%	68.4	%
Natural gas and geothermal	4.3		4.1
Hydroelectric	4.7		5.4
Wind	0.2		0.2

Total	78.6	%	78.1	%

PacifiCorp obtains the remainder of its energy requirements, including additional energy required beyond 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.

PacifiCorp’s various Integrated Resource Plans have identified the need for additional electric generation resources due to expected load growth. Part of the additional generation resources of 525.0 MW will be met by the new natural gas-fired Currant Creek Power Plant at a cost of approximately $350.0, which is expected to begin its first phase of operations in June 2005. In May 2004, PacifiCorp entered into an 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 electricity plant in Vineyard, Utah. The plant, to be known as the Lake Side Power Plant and to have a summer rated capacity of 534.0 MW, was identified as the best option submitted through PacifiCorp’s competitive Request for Proposal process for a resource to be available by summer 2007. The Utah Public Service Commission (“UPSC”) has granted all the authorizations required from it to construct and to operate the Lake Side Power Plant, and PacifiCorp is scheduled to begin operating the plant in May 2007. The Lake Side Power Plant is expected to cost approximately $347.0 million. Recovery of PacifiCorp’s investment in the plant will be reviewed by the states PacifiCorp serves as part of future general rate cases.

Coal

As of March 31, 2005, PacifiCorp had an estimated 259.1 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, 2005, these mines supplied 28.6% of PacifiCorp’s total coal requirements, compared to 30.4% during the year ended March 31, 2004, and 32.7% during the year ended March 31, 2003. The remaining coal requirements are acquired through other long-term and short-term contracts. PacifiCorp-owned mines are located adjacent to many of its coal-fired generating plants, which significantly reduces overall transportation costs included in fuel expense. For further information, see “Item 2. Properties.”

In an effort to lower costs and access better quality coal, the Jim Bridger Mine is in the process of converting from a surface operation to a primarily underground operation, while currently continuing production at its surface operations. Underground mine development and limited coal production began in fiscal 2005 and sustained operation is expected to begin by fiscal 2007. This conversion is expected to result in a reduction of the cost of mining coal over the life of the Jim Bridger Mine.

Natural Gas

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.

The additional electric generation resources that PacifiCorp will require in accordance with its Integrated Resource Plans, including the Currant Creek and Lake Side Power Plants, could increase its maximum natural gas requirement to 500,000 MMBtu per day or more. PacifiCorp has entered into transportation contracts to facilitate movement of natural gas to the Currant Creek and Lake Side Power Plants. These contracts reflect PacifiCorp’s fuel strategy that focuses on the management and mitigation of risks associated with supplying natural gas to fuel generation.

The prospective growth of PacifiCorp’s natural gas requirements requires 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.

PacifiCorp manages its natural gas supply requirements by entering into forward commitments for physical delivery of natural gas. PacifiCorp also manages its exposure to increases in natural gas supply costs through forward commitments for the purchase of physical natural gas at fixed prices and financial swap contracts that settle in cash based on the difference between a fixed price that PacifiCorp pays and a floating market-based price that PacifiCorp receives. As of March 31, 2005, PacifiCorp had hedged 100.0% of its physical and financial exposure for the remainder of calendar 2005 and has hedged 100.0% of its physical and financial exposure for calendar 2006. For calendar 2007, PacifiCorp currently has hedged 77.0% of its physical exposure and 83.0% of its financial exposure. This hedging includes the additional supply requirements arising from the Currant Creek and Lake Side Power Plants.

Hydroelectric

PacifiCorp’s hydroelectric portfolio consists of 51 plants with a net plant capability of 1,155.4 MW. These plants account for approximately 14.5% of PacifiCorp’s total generating capacity, helping satisfy a significant portion of PacifiCorp’s capability reserve margin requirements and providing operational benefits such as flexible generation 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, including snowpack in the mountains upstream of its hydroelectric facilities, reservoir storage, precipitation in its watersheds, plant availability and restrictions imposed by oversight bodies due to competing water management objectives. 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. Several 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, 2005, PacifiCorp had incurred $60.0 million in costs for ongoing hydroelectric relicensing in progress, which are included in Construction work-in-progress on PacifiCorp’s Consolidated Balance Sheet. See “Relicensing and Decommissioning” both discussed below.

Wind and Other Renewable Resources

PacifiCorp is committed to renewable power as a viable, economic and environmentally prudent means of generating electricity. The benefits of renewable energy include low to no emissions and no fossil fuel requirements. Resources such as wind and solar are intermittent, so complementary thermal or hydroelectric resources are important to integrating renewable resources into the electric system.

PacifiCorp acquires wind and other renewable power through one PacifiCorp-owned wind farm in Wyoming and various purchased electricity agreements with wind farms in Oregon and Wyoming, as well as with renewable facilities classified as “qualifying facilities” under the Public Utility Regulatory Policies Act. PacifiCorp also owns a geothermal plant in Utah.

For the year ended March 31, 2005, PacifiCorp received 286,888 MWh from its owned wind farm and geothermal plant. In this same period, 250,951 MWh were purchased from other wind sources, not including qualifying facilities.

PacifiCorp has also released a Request for Proposal for renewable energy sources. See “Future Generation and Conservation - Requests for Proposals - RFP 2003B” below for more information about the request. During the year ended March 31, 2005, PacifiCorp proceeded with analysis and negotiations with potential counterparties, with the goal of entering into purchased electricity agreements that ensure low-cost and reliable power for customers.

To encourage the use of wind energy, PacifiCorp has generation, storage and delivery agreements with Bonneville Power Administration (the “BPA”), Eugene Water and Electric Board, Public Service Company of Colorado and Seattle City Light. For the year ended March 31, 2005, electricity under these agreements totaled 498,437 MWh in addition to the wind energy generated or purchased for PacifiCorp’s own use.

Future Generation and Conservation

Integrated Resource Plans

As required by state regulators, PacifiCorp uses Integrated Resource Plans to provide a framework and plan for prudent future actions required to help ensure that PacifiCorp continues to provide reliable and cost-effective electric service to its customers. The Integrated Resource Plan process identifies PacifiCorp’s anticipated future resource mix in a coordinated process with the stakeholders in each of the six states where PacifiCorp operates.

PacifiCorp published its 2003 Integrated Resource Plan in January 2003 and updated it in October 2003. PacifiCorp has segregated its 2003 Integrated Resource Plan supply-side action items into a series of 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 and resource balance. The outstanding Requests for Proposals are discussed below.

PacifiCorp filed its 2004 Integrated Resource Plan with the relevant state commissions in January 2005. Dockets have been established in Utah, Oregon, Idaho and Washington to determine acknowledgment of the plan. Projected growth rates and contract expirations indicate a need for approximately 2,800 MW of additional resources by 2015. These estimates are subject to ongoing review and revision.

As part of the 2004 Integrated Resource Plan process, PacifiCorp has identified an electricity generation resource deficit and plans to meet the resource deficit through a combination of thermal generation (2,629 MW) and load control programs (177 MW). PacifiCorp also plans to implement energy conservation programs (450 average MW) and will continue to seek procurement of 1,400 MW of economic renewable resources that were first identified in the 2003 Integrated Resource Plan. PacifiCorp intends to utilize wholesale electricity transactions to balance the remaining difference between retail load obligations and available resources and to optimize physical assets and minimize cost.

In addition to new generation resources, future load growth could require substantial transmission investments to deliver power to customers. The actual investment requirement will depend on the location and other characteristics of the new generation resources. See “Transmission and Distribution” discussion below.

Requests for Proposals

RFP 2003B - PacifiCorp’s 2003 Integrated Resource Plan identified 1,400 MW of renewable resources as part of a least-cost portfolio of resources to meet PacifiCorp’s growing demand over a 10-year period. PacifiCorp issued a Renewable Request for Proposals in February 2004 for up to 1,100 MW of economic renewable resources for PacifiCorp’s system, which would become available in phases through calendar 2010. In May 2005, PacifiCorp entered into a 64.5 MW power purchase agreement, to take effect prior to January 2006, for the output of a wind farm located in southeastern Idaho. PacifiCorp is continuing to negotiate with other counterparties.

RFP 2009 (formerly RFP 2004A) - PacifiCorp expects to issue a third Request for Proposals following a review of the results from RFP 2003A and RFP 2003B and a new load and resource balance determination. PacifiCorp anticipates that it will issue RFP 2009 in calendar 2005 to request additional resources to serve PacifiCorp’s growing load obligation. Utah Senate Bill 26, which became law in February 2005, provides PacifiCorp a process to obtain pre-approval of related assets and/or power purchase agreements. Based on PacifiCorp’s 2003 Integrated Resource Plan, PacifiCorp expects that it 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 2003 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. Two conservation programs and one load control program were selected. Tariffs for each program have been filed with the UPSC.

WHOLESALE SALES AND PURCHASED ELECTRICITY

In addition to its portfolio of generating plants, 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, 2005, 21.4% 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, 2004, 21.9% of PacifiCorp’s energy requirements were supplied by purchased electricity under short- and long-term purchase arrangements.

Many of PacifiCorp’s purchased electricity contracts have fixed-price components, which 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, consumer trends and the level of economic activity. In addition, PacifiCorp purchases electricity in the wholesale markets when it is more economical than generating it at its own plants. PacifiCorp may also sell into the wholesale market excess electricity arising from imbalances between generation and retail load obligations, subject to pricing and transmission constraints.

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. These purchases are conducted through PacifiCorp’s transmission system, which 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.

TRANSMISSION AND DISTRIBUTION

PacifiCorp delivers electricity through approximately 58,360 miles of distribution lines and approximately 15,530 miles of transmission lines. Due to PacifiCorp’s continuing commitment to improve customer service and network safety and to enhance system reliability and performance, PacifiCorp has focused 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. For the year ended March 31, 2005, PacifiCorp’s capital spending along the Wasatch Front was $124.5 million, which included load growth, transmission and distribution upgrades and replacements. Part of this spending was attributed to a multi-year program aimed at improving service capability and reliability. As of March 31, 2005, PacifiCorp had invested approximately $172.7 million of the $202.0 million allocated to this program. As of March 31, 2005, PacifiCorp had added an additional 1,420 MW of system capacity through this program.

The regional electricity market in which PacifiCorp operates 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. It also provides wheeling, or transmission, services to third parties utilizing these facilities. 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.

Grid West and Regional Transmission Projects

PacifiCorp, in conjunction with other western utilities (referred to as the filing utilities), is seeking to develop an independent regional transmission entity that would manage certain operational functions of the transmission grid and plan for necessary expansion. A non-profit corporation has been established known as Grid West (previously known as RTO West), and in December 2004, the filing utilities, in collaboration with regional stakeholders, adopted new bylaws for Grid West’s interim board, on which PacifiCorp has a representative.

During the remainder of calendar 2005, the activities for Grid West are expected to include the continued development of the regional proposal for Grid West, initiating the process for parties to become members of the new Grid West organization and starting the search for candidates to be elected as independent members of a new five-person developmental board of trustees.

Assuming continued regional support, the filing utilities also plan to begin working with the proposed Grid West independent board of trustees to develop transmission agreements and a Grid West tariff in calendar 2006.

In January 2003, the filing utilities also entered into a Memorandum of Understanding with the other two potential western Regional Transmission Organizations, namely WestConnect and the California Independent System Operator, and anticipate continued work through either this agreement or a redefined forum to address transmission and related inter-regional market issues throughout the western interconnection.

In addition to the Grid West activities, PacifiCorp is involved in three other regional transmission expansion planning efforts. These planning efforts include technical studies that focus on evaluating the economic and operational implications of transmission expansion and resource alternatives to meet growing consumer demands in the western United States. A broad range of stakeholders is also involved in these public processes to identify the most critical electric transmission and generation project needs. The sub-regional planning processes provide a framework for regional collaboration to improve the western interconnection with technically, financially and environmentally viable transmission projects. These regional planning activities and Grid West activities are compatible, and PacifiCorp actively supports and participates in both.

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, 2005, PacifiCorp spent approximately $24.6 million on environmental capital projects either required by law or necessary to meet PacifiCorp’s internal environmental goals. Subject to applicable restrictions in the Stock Purchase Agreement, PacifiCorp currently estimates expenditures for environmental-related capital projects will total approximately $110.0 million in the year ending March 31, 2006, $148.2 million in the year ending March 31, 2007 and $138.4 million in the year ending March 31, 2008. 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, 2005, 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 this program. 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 by adding renewable generation, conservation and natural gas resources as outlined in its Integrated Resource Plans. When evaluating proposed new resources in PacifiCorp’s Integrated Resource Plans, PacifiCorp includes a projected additional cost for carbon dioxide emissions from the proposed resources. PacifiCorp also supports development of U.S. or global carbon dioxide and other greenhouse gas emissions 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 or modify enforceable limits on electricity plant emissions of sulfur dioxide, carbon dioxide, oxides of nitrogen and mercury. 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 that they will be spread over a number of years.

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 dispose of, or arrange 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. See “Item 8. Financial Statements and Supplementary Data - Note 6” for further discussion.

Mine Reclamation

The federal Surface Mining Control 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. For further discussion, see “Item 2. Properties” and “Item 8. Financial Statements and Supplementary Data - Note 6.”

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 customer rates, services, accounting policies and practices, allocation of costs by state, 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, including ScottishPower, 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

The FERC has issued Standards of Conduct governing conduct between interstate transmission gas and electricity providers and their marketing function or their energy-related affiliates. The standards are designed to prevent transmission providers from giving their marketing functions or affiliates undue preferences. PacifiCorp has trained 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 has 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. In addition, beginning in summer 2000, California market conditions resulted in defaults of amounts due to PacifiCorp from certain counterparties resulting from transactions with the California Independent System Operator and California Power Exchange. PacifiCorp has reserved $5.0 million for these receivables.

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 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. Court briefs from interested parties were filed between January 14, 2005 and April 15, 2005. A decision from the court of appeals is not expected to have a significant impact on PacifiCorp’s consolidated financial position or results of operations.

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 its request for rehearing of the FERC’s order, which request was granted in August 2003. The FERC issued its final order denying rehearing in November 2003. Also, in November 2003, PacifiCorp filed a petition in the Ninth Circuit Court of Appeals for review of the FERC’s final order denying recovery. Court briefs from interested parties were filed by March 2005. Oral argument has been scheduled for July 2005.

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 requests for rehearing of the FERC’s final order. A decision from the FERC on the rehearing requests is pending.

FERC Market Power Analysis

Pursuant to the FERC’s orders granting PacifiCorp authority to sell capacity and energy at market-based rates, PacifiCorp and certain of its affiliates are required to submit a joint market power analysis every three years. Under the FERC’s current policy, applicants must demonstrate that they do not possess market power in order to charge market-based rates for sales of wholesale energy and capacity. An analysis demonstrating an applicant’s passage of certain threshold screens for assessing generation market power establishes a rebuttable presumption that the applicant does not possess generation market power, while failure to pass any screen creates a rebuttable presumption that the applicant has generation market power. In February 2005, PacifiCorp submitted a joint triennial market power analysis in compliance with the FERC’s requirements. The analysis indicated that PacifiCorp failed to pass one of the generation market power screens in PacifiCorp’s eastern control area and in Idaho Power Company’s control area. On May 9, 2005, the FERC issued an order instituting a proceeding pursuant to section 206 of the Federal Power Act to determine whether PacifiCorp may continue to charge market-based rates for sales of wholesale energy and capacity. Under the terms of the order, PacifiCorp and its affiliated co-applicants are required to submit additional information and analysis to the FERC within 60 days to rebut the presumption that PacifiCorp has generation market power. PacifiCorp is in the process of responding to the FERC’s May 9, 2005 order. If the FERC ultimately finds that PacifiCorp has market power, PacifiCorp will be required to implement measures to mitigate any exercise of market power.

The Bonneville Power Administration Residential Exchange Program

The Northwest Power Act, through the Residential Exchange Program, provides access to the benefits of low-cost federal hydroelectricity to the residential and small-farm customers of the region’s investor-owned utilities. The BPA administers the Residential Exchange Program in accordance with federal law. Pursuant to a set of agreements between the BPA and PacifiCorp, PacifiCorp receives benefits from the BPA and passes such benefits through to its Oregon, Washington and Idaho residential and small-farm customers in the form of electricity bill credits through September 2006. In May 2004, PacifiCorp, the BPA and other parties executed an additional agreement that provides for a guaranteed range of benefits to customers for BPA’s fiscal years 2007 through 2011.

Several publicly owned utilities, cooperatives and the BPA direct-service industry customers have filed lawsuits with the Ninth Circuit Court of Appeals seeking review of certain aspects of the BPA’s Residential Exchange Program, as well as challenging the level of benefits previously paid to investor-owned utility customers. This litigation could possibly affect the amount of benefits paid by the BPA to PacifiCorp and, accordingly, the amount passed on to PacifiCorp’s customers. However, since these benefits are passed through to PacifiCorp’s customers through adjustments to customer rates, which must be approved by state utility commissions, the outcome of this litigation is not expected to have a significant effect on PacifiCorp’s consolidated financial position or results of operations.

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, Utah and Idaho)

In December 2003, the FERC issued a new 30-year operating license for the 84.5 MW Bear River hydroelectric project. The license became final and PacifiCorp accepted the new license on May 25, 2004. The FERC included in the Bear River license a requirement to evaluate decommissioning the 7.5 MW Cove plant and associated project features. As part of this evaluation, PacifiCorp has been working with stakeholders to determine the actions that would be required to decommission this plant. In addition to the project’s capital and operations and maintenance costs associated with the new license, PacifiCorp is committed, over the life of the license, to fund approximately $25.9 million for environmental mitigation and enhancement projects. The present value of the portion of these obligations for which PacifiCorp is currently committed, net of costs incurred to date of $0.1 million, was $12.5 million at March 31, 2005.

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 161.4 MW Klamath hydroelectric project. The FERC is scheduled to complete its required analysis by December 2006. PacifiCorp continues to participate in the mediated settlement discussions with state and federal agencies, Native American tribes and other stakeholders in an effort to reach a comprehensive agreement on project relicensing.

Lewis River hydroelectric projects – (Lewis River, Washington)

PacifiCorp filed new license applications for the 136.0 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 Yale application was delayed pending filing of the Merwin and Swift No. 1 applications so that the FERC could complete a comprehensive environmental analysis.

On November 30, 2004, PacifiCorp executed a comprehensive settlement agreement with 25 other parties including state and federal agencies, Native American tribes, conservation groups, and local government and citizen groups to resolve, among the parties, issues related to the pending applications for new licenses for PacifiCorp’s Merwin, Swift No. 1 and Yale hydroelectric projects. As part of this settlement agreement, PacifiCorp has agreed to implement certain protection, mitigation and enhancement measures prior to and during a proposed 50-year license period. However, these commitments are contingent on ultimately receiving a license from the FERC that is consistent with the settlement agreement and other required permits. The FERC is scheduled to complete its process and required analysis in order to be ready for a decision in March 2006.

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

In November 2003, the FERC issued a new 35-year operating license for the 188.5 MW North Umpqua hydroelectric project. Both PacifiCorp and environmental groups sought rehearing of the license, and in March 2004 the FERC issued an order on rehearing favorable to PacifiCorp and denying the motion of the environmental groups. In May 2004, the environmental groups appealed the FERC order in the Ninth Circuit Court of Appeals, where the case is currently pending. The new FERC license is currently effective, but not final, and certain implementation measures may be delayed pending the outcome of the appeal. In addition to the project’s capital and operations and maintenance costs associated with the new license, when the license becomes final PacifiCorp will be committed, over the life of the license, to fund approximately $48.9 million for environmental mitigation and enhancement projects. The present value of the portion of these obligations for which PacifiCorp is currently committed, net of costs incurred to date of $0.3 million, was $13.1 million at March 31, 2005. Additional liabilities amounting to $21.2 million, undiscounted, will be recognized when the license becomes final.

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, which total 36.8 MW. The FERC is expected to complete its required analysis and issue a new license before the end of fiscal 2006.

Decommissioning

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

The FERC issued a surrender order for American Fork on August 4, 2004, which calls for project removal to be completed by December 2007. Removal costs for this 1.0 MW project are estimated to be approximately $1.2 million, including process and permitting costs (adjusted for inflation). The parties have agreed that project removal will begin in September 2006, subject to the FERC and other regulatory approvals.

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. Under the original settlement agreement, removal was expected to begin in October 2006, for a total cost to decommission not to exceed $17.2 million, excluding inflation. In early February 2005, the parties agreed to modify the settlement agreement so that removal will not begin until October 2008 for a total cost to decommission not to exceed $20.5 million, excluding inflation. The settlement agreement is contingent upon receiving an amended FERC license and removal order that is not materially inconsistent with the amended settlement agreement and other regulatory approvals. PacifiCorp is in the process of acquiring all necessary permits, within the terms and conditions of the amended settlement agreement.

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 the FERC and other regulatory approvals, is projected to cost $5.9 million (adjusted for inflation). The plant will continue to operate until its removal, which is scheduled to 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 discussion provides a state-by-state update, but does not address the possible effect of the proposed sale of ScottishPower’s indirect interest in PacifiCorp to MidAmerican. In each state, the sale of PacifiCorp will require regulatory notification and/or approval. Although PacifiCorp intends to pursue general rate increase requests as currently planned, management is unable to predict the impact, if any, of the proposed sale and the process of obtaining such approvals, on the pending matters described below.

Utah

On August 4, 2004, PacifiCorp filed a general rate case request with the UPSC for approximately $111.0 million annually related to operating cost increases and recovery of investments that support Utah’s growing demand and need for enhanced network reliability. In October 2004, the UPSC approved the use of a forward-looking test year in this general rate case, based on projected results for the year ending March 31, 2006. PacifiCorp filed rebuttal testimony in January 2005 reducing the revenue requirement request from $111.0 million to $96.3 million. The main reasons for the change were to reflect increased revenues from updated customer contracts and to update specific items in the filing. In February 2005, the UPSC approved a stipulation settling the general rate case. Under the stipulation, PacifiCorp was awarded an increase in prices of $51.0 million annually, resulting in an average price increase of 4.7% and an allowed return on equity of 10.5%. The stipulation also included an effective date of March 1, 2005, which was a month earlier than the April 1, 2005 date required by Utah statute, resulting in a onetime benefit of $4.3 million of additional revenues.

Senate Bill 26 was signed into law in February 2005. This bill establishes rules and a mandatory process for the solicitation and evaluation of bids to procure significant energy resources. It also provides PacifiCorp with the opportunity to obtain advance approval from the UPSC of a resource decision and an assurance of the recovery of costs associated with the resource. Senate Bill 26 also establishes a voluntary process for utilities to obtain advance approval of certain other resource commitments and investment decisions.

In May 2004, PacifiCorp delivered a comprehensive report on the 2003 Utah winter storm inquiry to the UPSC. The December 2003 storm was one of the worst in Utah’s recorded history. The report identified 28 areas of improvement related to problems encountered during the storm and PacifiCorp has established a program for implementation of the improvements outlined in the report to improve system operations and service to PacifiCorp customers. In April 2004, four Utah customers filed a petition with the UPSC on behalf of themselves and other similarly situated customers seeking monetary compensation from PacifiCorp as a result of the December 2003 storm. The UPSC denied the customers’ petition for “class status” and all of their requests, other than the right of the individual customers to participate in the existing regulatory winter storm inquiry. In December 2004, a group of customers again filed a petition with the UPSC based on substantially the same claims in an attempt to have the UPSC consider their claims. PacifiCorp is seeking to have the claims dismissed or limited.

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, at a rate of $45.6 million annually. The Industrial Customers of Northwest Utilities and the Citizens’ Utility Board appealed the OPUC order. The Marion County, Oregon circuit court affirmed the OPUC order. The Industrial Customers of Northwest Utilities and the Citizens’ Utility Board appealed the circuit court decision to the Oregon Court of Appeals. The Court of Appeals heard oral arguments in May 2004. On October 27, 2004, the Oregon Court of Appeals affirmed the circuit court decision. The deadline for further appeals has passed. As of March 31, 2005, approximately $13.7 million remained to be collected by the authorized surcharge. PacifiCorp expects this to be collected by the end of September 2005.

In November 2004, PacifiCorp filed a general rate case with the OPUC related to increases in operating costs, including fuel, purchased power, and pension and health care costs. PacifiCorp is seeking an increase of $102.0 million annually, or 12.5%. If approved by the OPUC, the increase would take effect in September 2005. Settlement conferences were held in April 2005 and hearings are scheduled to occur in July 2005.

PacifiCorp filed an application in February 2005 for deferral of higher power costs in calendar 2005 due to continuing poor hydroelectric conditions. PacifiCorp seeks deferral of these costs to track and preserve them for later incorporation in rates. On May 25, 2005, this deferral application was suspended to allow the parties to focus on the power cost adjustment mechanism filed by PacifiCorp in April 2005. The power cost deferral may be reopened at the option of the parties at a later time. If approved, the proposed power cost adjustment mechanism will address Oregon’s share of PacifiCorp’s total net power cost volatility resulting from such factors as hydroelectric, natural gas and load variability. The proposed power cost adjustment mechanism is designed to be a longer-term, ongoing mechanism that passes through to customers a portion of excess net power costs or returns to customers a portion of over-collected net power costs, keeping rates more closely aligned with PacifiCorp’s actual costs. Any approved power cost adjustment mechanism could result in the creation of related regulatory assets and liabilities.

Wyoming

In March 2003, the Wyoming Public Service Commission (the “WPSC”) denied recovery of the Hunter No. 1 replacement power costs and the deferred excess net power costs. On appeal, the Laramie County District Court certified the case to the Wyoming Supreme Court. PacifiCorp filed its reply brief in April 2004. Oral arguments before the Wyoming Supreme Court took place in June 2004. On December 13, 2004, the Wyoming Supreme Court issued its decision affirming the order of the WPSC to deny recovery of replacement power and deferred excess net power costs.

Also, in April 2004, PacifiCorp filed a complaint with the federal district court in Wyoming challenging the WPSC’s March 2003 decision on the grounds that the decision violates federal law by denying PacifiCorp recovery in retail rates of its wholesale electricity and transmission costs incurred to serve Wyoming customers. The lawsuit seeks an injunction requiring the WPSC to pass through PacifiCorp’s wholesale electricity and transmission costs in retail rates. In May 2004, the defendants filed a motion to dismiss the complaint. In January 2005, the defendants appealed the court’s ruling on the motion to dismiss and requested a stay of the underlying litigation. The defendants’ appeal on sovereign immunity grounds is pending at the Tenth Circuit Court of Appeals. The defendants’ opening brief was filed on April 4, 2005. In April 2005, the Tenth Circuit Court of Appeals issued an order staying the briefing schedule pending resolution of a jurisdictional issue. On May 17, 2005, the parties filed jurisdictional briefs on the issue of whether the defendants’ notice of appeal was timely.

In June 2004, the WPSC concluded hearings on the joint application of Powder River Energy Corporation and Kennecott Energy Company for a certificate of public convenience and necessity to serve the Antelope Coal Mine in Converse County, Wyoming. The Antelope Coal Mine is in PacifiCorp’s service territory and PacifiCorp has been serving this mine for 20 years. The joint application proposed a dual certificate arrangement that would allow Kennecott Energy Company to choose its electric service provider. PacifiCorp argued that it should be the sole service provider. The WPSC deliberated this issue in September 2004 and directed parties to enter into further discussions over a six- to eight-week period to determine whether a solution could be proposed that keeps the authorized service territory of PacifiCorp and Powder River Energy Corporation intact. On October 28, 2004, the WPSC approved a stipulation that was filed by PacifiCorp, Powder River Energy Corporation and Kennecott Energy Company. The terms of the stipulation include a continued recognition of PacifiCorp’s authorized territory in Converse County through a regulatory recovery fee payment that Kennecott Energy Company will make to PacifiCorp. The regulatory recovery fee protects other Wyoming customers from any impacts due to the loss of the mine load. Powder River Energy Corporation will be the sole energy provider to the mine.

In July 2004, PacifiCorp applied to the WPSC for a stand-alone pass-on of $11.9 million in increased net wholesale purchased electricity costs. Following discussions with various parties, PacifiCorp filed a joint stipulation reducing this request to $9.3 million annually, or 2.7%. This stipulation was heard by the WPSC on September 14, 2004, and approved effective September 15, 2004. The expedited treatment of this application was recognized in the stipulation with an agreement that PacifiCorp will not file a general rate application until at least September 30, 2005. Further, the parties agreed to hold discussions on the development of a commodity cost recovery mechanism and alternative forms of regulation. Meetings have taken place with the parties to evaluate inputs into a commodity cost recovery mechanism and an alternative form of regulation.

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%. In addition, PacifiCorp requested that the WUTC adopt the findings of a prudence review of generating resources acquired since the last Washington general rate case. In August 2004, PacifiCorp entered into a settlement agreement with the WUTC staff and the Natural Resources Defense Council that recommended a $15.5 million annual increase, or 7.8%. On October 27, 2004, the WUTC issued an order adopting the multi-party settlement agreement with limited conditions, resulting in a total rate increase of $15.1 million, or 7.5%, effective November 16, 2004. On November 10, 2004, the WUTC issued a supplemental order with revised calculations. As a result, the WUTC authorized an annual increase of $15.5 million, or 7.8%, effective November 16, 2004.

PacifiCorp filed an application in March 2005 for the deferral of higher power costs in 2005 due to poor hydroelectric conditions. PacifiCorp seeks deferral of these costs to track and preserve them for later incorporation in rates, to be considered as part of PacifiCorp’s Washington general rate case proceeding described in the following paragraph. PacifiCorp requested that the deferral continue through the conclusion of that general rate proceeding. As part of that proceeding, PacifiCorp expects to address the rate treatment of the current low hydroelectric trend and power cost volatility through a proposed power cost adjustment mechanism. It is anticipated that deferral of hydroelectric impacts can be discontinued at the conclusion of that proceeding and replaced with a power cost adjustment mechanism that would address hydroelectric variability thereafter.

On May 5, 2005, PacifiCorp filed a general rate case request with the WUTC for approximately $39.2 million related to increases in operating costs, including fuel, purchased power, pension and other employee benefit costs, as well as investment in new generation, the implementation of a power cost adjustment mechanism and ratification of the Multi-State Process protocol discussed below that has been adopted by four other states served by PacifiCorp. PacifiCorp is seeking an allowed rate of return on equity of 11.125%, in line with recent requests in other states. If approved by the WUTC, customer rates would increase by 17.9% in April 2006.

Idaho

In December 2003, PacifiCorp filed with the Idaho Public Utility Commission (the “IPUC”) to recover Idaho’s portion of income tax payments resulting from Internal Revenue Service audits of prior years. In April 2004, the IPUC staff held public input meetings concerning PacifiCorp’s application. A stipulated agreement signed by the parties was filed with the IPUC in May 2004 and was approved by the IPUC in June 2004. This allowed recovery of $4.2 million over 16 months beginning in June 2004 when a power cost recovery surcharge, which began in June 2002, expired.

On January 14, 2005, PacifiCorp filed a general rate case with the IPUC related to continuing investment to serve Idaho load, increases in employee-related costs and general inflation impacts. PacifiCorp seeks an increase of $15.1 million annually, or 12.5%. If approved by the IPUC, new rates would take effect September 16, 2005. On that date, unrelated surcharges currently in effect will expire, so the net effect to customers of this increase would be $11.4 million annually, or 9.2% overall.

On January 28, 2005, the IPUC approved PacifiCorp’s application to reduce the BPA credit effective January 31, 2005. The change will result in an 8.0% reduction in the credit given to residential customers and a 20.5% reduction in the credit given to small-farm customers. Changes in the level of the BPA credit affect the net electricity costs to customers but do not impact PacifiCorp’s results of operations or earnings.

Affiliated Interest Filings

Commencing on April 1, 2004, PacifiCorp and Scottish Power UK plc (“SPUK”), an indirect subsidiary of ScottishPower, implemented a cross-charge policy governing the allocation of costs incurred by PacifiCorp and SPUK, on behalf of each other. This policy, approved by the SEC in its administration of the PUHCA, permits PacifiCorp to receive certain administrative services, priced at cost, from SPUK. These include shareholder, investor relations, management and human resource services. PacifiCorp also provides administrative services to SPUK and other ScottishPower affiliates under the cross-charge policy. Cross-charges from SPUK to PacifiCorp amounted to $14.9 million for the year ended March 31, 2005, and were recorded in Operations and maintenance expense.

On May 16, 2005, the SEC approved PacifiCorp’s participation in a captive insurance program recently established by ScottishPower for its group companies. The captive insurance company, Dornoch International Insurance Limited (“DIIL”), is an indirect wholly owned consolidated subsidiary of ScottishPower. DIIL covers all or significant portions of the property damage and liability insurance deductibles in many of PacifiCorp’s current policies, as well as activities that commercial insurance industry carriers will no longer cover, such as overhead distribution and transmission line property damage. PacifiCorp has no equity interest in DIIL and has no obligation to contribute equity or loan funds to DIIL. Premium amounts are established to cover loss claims, administrative expenses and appropriate reserves, but otherwise DIIL is not operated to generate profits.

Multi-State Process

The Multi-State Process commenced in April 2002 and was a collaborative process with stakeholders from five of the six states PacifiCorp serves. The project’s focus was to design, develop and implement a cost allocation methodology that would achieve a more permanent consensus on each state’s responsibility for the costs and benefits of PacifiCorp’s existing assets, enabling PacifiCorp to recover the cost of future investments and providing states with the ability to independently implement state energy policy objectives.

A number of collaborative meetings and conferences occurred during 2002 and 2003, which concluded in the development of a cost allocation methodology proposal, referred to as the “Protocol.” The Protocol was filed with each of the state commissions in Utah, Oregon, Wyoming and Idaho in September 2003 and in Washington as part of a general rate case in December 2003. Following discussions with all parties, the proposal was further refined and re-submitted to each of the state commissions as the “Revised Protocol.”

During June 2004 through November 2004, settlement discussions occurred in each of the states, agreements were reached with parties and hearings or oral arguments took place. Final ratification of the Revised Protocol was achieved in March 2005, and each of the state commissions in Utah, Oregon, Wyoming and Idaho issued orders approving and accepting the use of the Revised Protocol cost allocation methodology for future rate setting in each of those states. In accordance with this agreement, ongoing rate case filings in Oregon and Idaho have been based on the Revised Protocol and the recent Utah settlement was based on the Revised Protocol. In Washington, the WUTC issued its formal order approving and adopting the Washington general rate case settlement in October 2004, accepting the Revised Protocol for reporting purposes and establishing a process for ongoing discussions for a permanent allocation methodology during fiscal 2006. The Revised Protocol will be filed in the state of California with the next general rate case.

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 “Item 15. Exhibits, Financial Statement Schedules - 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 900,000 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 1.2 million square feet of office and warehouse 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	136.0		144.0
Yale	Amboy, WA	Lewis River	1953	134.0		165.0
Five North Umpqua Plants	Toketee Falls, OR	N. Umpqua River	1950-1956	136.5		138.5
John C. Boyle	Keno, OR	Klamath River	1958	90.4		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
31 Minor Hydroelectric Plants (c)	Various	Various	1895-1990	90.7	*	86.3	*

Subtotal (51 Hydroelectric Plants)				1,083.6		1,155.4

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	816.8		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		172.0
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
Hermiston	Hermiston, OR	Natural Gas-Fired	1996	237.0	*	245.0	*
Gadsby Peakers	Salt Lake City, UT	Natural Gas-Fired	2002	141.0		120.0
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	26.1		23.0

Subtotal (16 Thermal Electric Plants)				7,309.8		6,793.4

WIND PLANT
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 (68)				8,426.0		7,981.4

*	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 located on the Lewis River in the state of Washington and owned by the Cowlitz County Public Utility District. The failure impacted, but did not damage, the PacifiCorp-owned and -operated 240.0 MW Swift No. 1 hydroelectric facility, which is upstream of the Swift No. 2 power canal. In June 2004, PacifiCorp and Cowlitz County Public Utility District amended the existing power purchase agreement addressing, among other things, the general nature of the canal rebuild configuration and providing the mechanism for settling all claims between the parties related to the canal failure. Cowlitz County Public Utility District has initiated the reconstruction of the Swift No. 2 project facility with contracts currently in place for rehabilitation of the turbine generators, switchyard and reconstruction of the Swift No. 2 power canal. Based on the current schedule, the first Swift No. 2 turbine generator unit is expected to be on-line in the fourth quarter of fiscal 2006 and the second unit is expected to follow shortly thereafter.

(c)

PacifiCorp has negotiated settlement agreements with resource agencies and other interested parties to decommission the American Fork, Condit and Powerdale plants, which have a combined net capability of 16.6 MW. These settlement agreements have been filed with the FERC and are pending further regulatory action. See “Item 1. Business – Regulation – Hydroelectric Actions” for further details.

In May 2002, PacifiCorp entered into a 15-year operating lease for an electric generation facility with 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 200.0 MW. PacifiCorp, at its sole option, may terminate the lease, or purchase the facility, if written notice is provided to West Valley on or before December 1, 2006.

New Generation Resources

As part of its 2003 Integrated Resource Plan, PacifiCorp is in the process of having two new natural gas-fired combined-cycle combustion turbine power plants constructed. The Currant Creek Power Plant in Mona, Utah, is estimated to begin a simple-cycle operation with 280.0 MW of capacity in June 2005. Full combined-cycle operation is estimated to be substantially complete and begin operation March 2006, at which time the full capacity of the Currant Creek Power Plant is estimated to be 525.0 MW. The Lake Side Power Plant in Vineyard, Utah, is estimated to begin a combined cycle operation May 2007, adding an estimated 534.0 MW of capacity. These two plants, with full commercial operation, will add a total of 1,059.0 MW of capacity to PacifiCorp’s generating portfolio.

Transmission and Distribution

PacifiCorp’s generating facilities are interconnected through PacifiCorp’s 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 that 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, 2005, PacifiCorp owned, or participated in, an electric transmission and distribution system consisting of:

Nominal Voltage (In kilovolts)		Miles

Transmission Lines
500		720
345		1,900
230		3,310
161		280
138		2,050
115		1,540
69		2,970
57		110
46		2,650

		15,530
Distribution Lines
Less than 46		58,360

Total		73,890

At March 31, 2005, PacifiCorp owned 948 substations.

Mining

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 available 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 substantially 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 the 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, 2005, based on PacifiCorp’s most recent engineering studies, were as follows:

Location	Plant Served	Mining Method	Recoverable Tons (in Millions)

Craig, CO	Craig	Surface	48.4	(a)
Huntington & Castle Dale, UT	Huntington and Hunter	Underground	67.6	(b)
Rock Springs, WY	Jim Bridger	Surface/Underground	143.1	(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 Bridger mine. On January 19, 2005, Bridger Coal Company’s federal coal lease bid was accepted by the Bureau of Land Management. The coal lease was purchased for $7.0 million and includes 32.0 million of estimated recoverable tons of coal that are adjacent to the Bridger mine. The Bridger mine is in the process of conversion from surface operation to primarily underground operation, while currently continuing production at its surface operations.

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 $11.9 million in reclamation costs during the year ended March 31, 2005, and $13.9 million during the year ended March 31, 2004. PacifiCorp and Idaho Power have previously contributed funds to a trust for the reclamation of the Bridger Mine. At March 31, 2005, these reclamation funds totaled $92.5 million, of which PacifiCorp’s portion is $61.7 million. See “Item 8. Financial Statements and Supplementary Data - Note 6.”

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, individual Klamath Tribal members and the Klamath Claims Committee. The complaint 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. In September 2004, the Klamath Tribes filed their first amended complaint adding claims of damage to their treaty rights to fish for sucker and steelhead in the headwaters of the Klamath River. The complaint seeks in excess of $1.0 billion in compensatory and punitive damages. In February 2005, PacifiCorp filed a motion for summary judgment seeking dismissal of the Klamath Tribes’ claims as untimely under the applicable statute of limitations. In April 2005, the magistrate judge issued an opinion recommending that PacifiCorp’s motion for summary judgment be granted and the case be dismissed as untimely. In May 2005, the Klamath Tribes filed objections to the recommendation and PacifiCorp filed its response to the Klamath Tribes’ objections. Any final order will be subject to appeal.

From time to time, PacifiCorp is also a party to various other legal claims, actions and complaints, certain of which seek significant amounts. Although PacifiCorp is unable to predict with certainty whether it will ultimately be successful in these legal proceedings or, if not, what the impact might be, management currently believes that disposition of these matters will not have a material adverse effect on PacifiCorp’s consolidated financial position or results of operations. See “Item 1. Business - Regulation” for information concerning pending regulatory and related 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 “Item 8. Financial Statements and Supplementary Data - Quarterly Financial Data.”

On May 23, 2005, ScottishPower and PHI executed a Stock Purchase Agreement providing for the sale of all PacifiCorp common stock held by PHI to Mid American. Pursuant to the Stock Purchase Agreement, ScottishPower has agreed to cause PacifiCorp to not pay dividends to PHI in excess of $53.7 million per quarter during fiscal 2006 and $60.575 million per quarter during fiscal 2007. These restrictions will terminate upon either the close of the sale of PacifiCorp or the earlier termination of the Stock Purchase Agreement.

PacifiCorp is restricted from making any distributions without prior state regulatory approval to the extent that it would reduce PacifiCorp’s common stock equity below 40.0% of its total capitalization, excluding short-term debt and current maturities of long-term debt. As of March 31, 2005, under this measure, PacifiCorp’s actual common stock equity percentage was 47.3%.

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

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, 2005, PacifiCorp’s unearned surplus available for distribution pursuant to SEC authorization was 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, 2005, that required giving prior notice to the OPUC.

ITEM 6.

SELECTED FINANCIAL DATA (Unaudited)

	Years Ended March 31,

(Millions of dollars, except per share and employee amounts)	2005		2004			2003			2002			2001


Revenues:
Electric Operations	$	3,048.8	$	3,194.5		$	3,082.4		$	3,341.1		$	3,343.5
Australian Operations		—		—			—			—			399.3
Other Operations (a)		—		—			—			12.6			122.2

Total	$	3,048.8	$	3,194.5		$	3,082.4		$	3,353.7		$	3,865.0

Income (loss) from operations:
Electric Operations (b)	$	656.4	$	617.9		$	488.9		$	598.6		$	453.1
Australian Operations		—		—			—			27.4			(133.1	)
Other Operations (a)		—		—			—			15.0			19.8

Total	$	656.4	$	617.9		$	488.9		$	641.0		$	339.8

Net income (loss)	$	251.7	$	248.1		$	140.1		$	327.3		$	(88.2	)


Earnings on common stock:
Continuing operations
Electric Operations	$	249.6	$	245.7		$	134.7		$	232.8		$	110.1
Australian Operations		—		—			—			27.4			(187.2	)
Other Operations (a)		—		—			—			20.5			(29.0	)

Total		249.6		245.7			134.7			280.7			(106.1	)
Discontinued operations (c)		—		—			—			146.7			—
Cumulative effect of accounting change (d)		—		(0.9	)		(1.9	)		(112.8	)		—

Total earnings on common stock	$	249.6	$	244.8		$	132.8		$	314.6		$	(106.1	)


Common dividends declared per share	$	0.62	$	0.51		$	—		$	0.81		$	1.31

Common dividends paid per share	$	0.62	$	0.51		$	—		$	1.00		$	1.12

	At March 31,

	2005		2004		2003		2002		2001


Capitalization:
Short-term debt	$	468.8	$	124.9	$	25.0	$	177.5	$	240.5
Long-term debt, including current maturities		3,898.9		3,760.2		3,554.3		3,698.3		2,958.1
Preferred Securities of Trusts		—		—		341.8		341.5		341.2
Preferred stock subject to mandatory redemption		52.5		60.0		66.7		74.2		175.0
Preferred stock		41.3		41.3		41.3		41.3		41.5
Common equity		3,335.8		3,278.7		3,194.4		2,891.9		3,414.4

Total Capitalization	$	7,797.3	$	7,265.1	$	7,223.5	$	7,224.7	$	7,170.7

Total assets	$	12,520.9	$	11,677.1	$	11,695.8	$	10,234.9	$	10,539.7

Total employees		6,654		6,507		6,140		6,287		6,626

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

(b)

Prior year amounts have been reclassified to conform to current year method of presentation. The year ended March 31, 2002, includes an unrealized gain of $182.8 million related to the effects of Statement of Financial Accounting Standards (“SFAS”) No. 133, Accounting for Derivative Instruments and Hedging Activities (“SFAS No. 133”). Upon receiving regulatory approval, PacifiCorp has subsequently recorded the effects of unrealized gains/losses on certain long-term contracts as regulatory assets and liabilities.

(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.

(d)	The year ended March 31, 2004 reflects the effect of implementation of SFAS No. 143, Asset Retirement Obligations(“SFAS No. 143”) .

The year ended March 31, 2003 reflects the effect of the implementation of the Derivatives Implementation Group (the “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”).

The year ended March 31, 2002, reflects the effect of the implementation of SFAS No. 133.

ELECTRIC OPERATIONS (Unaudited)

	Years Ended March 31, *

(Millions of dollars)	2005			2004			2003			2002			2001

Revenues:
Residential	$	1,004.6		$	994.5		$	914.7		$	901.7		$	852.1
Commercial		833.1			792.9			763.4			747.7			710.5
Industrial		774.8			725.6			699.2			705.1			730.1
Other retail		36.3			34.0			31.4			34.5			32.5

Retail sales		2,648.8			2,547.0			2,408.7			2,389.0			2,325.2
Wholesale sales and other		400.0			647.5			673.7			952.1			1,018.3

Total		3,048.8			3,194.5			3,082.4			3,341.1			3,343.5

Expenses:
Purchased electricity		448.0			672.8			698.5			974.4			1,287.7
Fuel		500.0			483.9			482.2			490.9			491.0
Operations and maintenance		913.1			895.8			885.1			785.2			625.2
Depreciation and amortization		436.9			428.8			434.3			401.3			389.0
Taxes, other than income taxes		94.4			95.3			93.4			90.7			97.5

Total		2,392.4			2,576.6			2,593.5			2,742.5			2,890.4

Income from operations		656.4			617.9			488.9			598.6			453.1
Interest expense		267.4			256.5			270.3			238.3			262.0
Interest income		(9.1	)		(13.8	)		(21.6	)		(28.9	)		(10.7	)
Interest capitalized		(14.8	)		(19.9	)		(18.0	)		(6.9	)		(12.9	)
Merger costs		—			—			—			—			9.3
Minority interest and other		(7.3	)		1.6			19.0			12.0			(10.2	)
Income tax expense		168.5			144.5			97.2			138.6			87.6

Income before cumulative effect of accounting change		251.7			249.0			142.0			245.5			128.0
Cumulative effect of accounting change		—			(0.9	)		(1.9	)		(112.8	)		—

Net income		251.7			248.1			140.1			132.7			128.0
Preferred dividend requirement		(2.1	)		(3.3	)		(7.3	)		(12.7	)		(17.9	)

Earnings on common stock (a)	$	249.6		$	244.8		$	132.8		$	120.0		$	110.1

Total assets	$	12,520.9		$	11,677.1		$	11,695.8		$	10,234.9		$	10,456.6

Capital expenditures	$	851.6		$	690.4		$	550.0		$	505.3		$	376.1

(a)

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

Certain prior year amounts have been reclassified to conform to the current year method of presentation.

ELECTRIC OPERATIONS STATISTICS (Unaudited)

	Years Ended March 31,

	2005			2004			2003			2002			2001

Energy sales (Thousands of MWh):
Residential		14,117			14,460			13,287			13,395			13,455
Commercial		14,642			14,413			14,006			13,810			13,634
Industrial		19,454			19,133			19,048			19,611			20,659
Other		706			673			631			711			705

Retail sales		48,919			48,679			46,972			47,527			48,453

Energy source:
Coal and natural gas		73.7			72.5			71.1			73.0			71.1	%
Hydroelectric		4.7			5.4			5.6			5.7			5.0
Wind		0.2			0.2			0.2			0.2			0.2
Purchase and exchange contracts		21.4			21.9			23.1			21.1			23.7

Total		100.0	%		100.0	%		100.0	%		100.0	%		100.0	%

Number of retail customers (thousands):
Residential		1,373			1,341			1,317			1,296			1,278
Commercial		194			190			186			182			179
Industrial		34			34			34			35			35
Other		4			5			5			4			4

Total		1,605			1,570			1,542			1,517			1,496

Residential customers:
Average annual usage (kWh)		10,411			10,889			10,182			10,411			10,614
Average annual revenue per customer	$	741		$	749		$	701		$	701		$	672
Revenue per kWh		7.1	¢		6.9	¢		6.9	¢		6.7	¢		6.3	¢
Miles of line:
Transmission		15,530			15,180			14,950			14,900			14,900
Distribution
— overhead		43,850			43,750			43,770			43,800			43,700
— underground		14,510			13,710			13,301			12,500			11,900
System peak demand (MW):
Net system load (a)
— summer		8,628			8,922			8,549			7,899			8,056
— winter		7,965			8,013			7,613			7,688			7,475
Total firm load (b)
— summer		9,527			10,104			9,542			10,029			10,115
— winter		8,819			8,662			8,628			9,511			9,592

(a)

Excludes loads outside PacifiCorp’s control area.

(b)

Includes loads outside PacifiCorp’s control area that are associated with long-term sales commitments.

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, 68 thermal, hydroelectric and wind generating plants, with an aggregate nameplate rating of 8,426.0 MW and plant net capability of 7,981.4 MW. The FERC and the six state regulatory commissions also have authority over the construction and operation of PacifiCorp’s electric generation facilities. PacifiCorp delivers electricity through approximately 58,360 miles of distribution lines and approximately 15,530 miles of transmission lines.

Sale of PacifiCorp

On May 23, 2005, ScottishPower and PHI executed a Stock Purchase Agreement providing for the sale of all PacifiCorp common stock held by PHI to MidAmerican for a value of approximately $9.4 billion, consisting of approximately $5.1 billion in cash plus approximately $4.3 billion in net debt and preferred stock, which will remain outstanding at PacifiCorp. MidAmerican is based in Des Moines, Iowa, and is a privately owned global provider of energy services. Through its energy-related business platforms - CalEnergy, CE Electric UK, Kern River Gas Transmission Company, Northern Natural Gas Company and MidAmerican Energy Company - MidAmerican provides electric and natural gas service to 5 million customers worldwide.

The closing of the sale of PacifiCorp is subject to a number of conditions, including ScottishPower shareholder consent and regulatory notification and/or approvals from the SEC, the FERC, the Department of Justice or the Federal Trade Commission, the Nuclear Regulatory Commission and the public utility commissions in the states of Utah, Oregon, Wyoming, Washington, Idaho and California, as well as approvals under existing third-party agreements. Pending satisfaction of the closing conditions, which is expected to occur in calendar 2006, the Stock Purchase Agreement requires ScottishPower to cause PacifiCorp to operate its business in the ordinary course consistent with past business practice. The Stock Purchase Agreement also requires ScottishPower to obtain MidAmerican’s prior approval to certain actions taken by PacifiCorp beyond limits specified in the Stock Purchase Agreement, including:

•	borrowings or debt issuances;

•	capital expenditures;

•	construction or acquisition of new generation, transmission or delivery facilities or systems, other than as currently planned or necessary to fulfill regulatory commitments (for example, the construction of the Currant Creek and Lake Side Power Plants is permitted to proceed as planned);

•	unbudgeted significant acquisitions or dispositions;

•	modifications to material agreements with regulators;

•	issuance or sale of any capital stock to any person, other than PHI in certain circumstances;

•	adoption or amendment of employee benefit plans or material increases to employee compensation; and

•	payment of dividends to PHI.

Although PacifiCorp intends to, and the Stock Purchase Agreement requires ScottishPower to cause PacifiCorp to, operate its business in the normal course pending the sale of PacifiCorp to MidAmerican, some of the agreements and restrictions in the Stock Purchase Agreement may affect how PacifiCorp manages its affairs. Although PacifiCorp also intends to pursue general rate increase requests as currently planned, management is unable to predict the impact, if any, of the proposed sale and the process of obtaining state regulatory approvals on the pending general rate increase requests and any future regulatory filings.

While the sale of PacifiCorp is pending and the Stock Purchase Agreement is in effect, PHI has agreed to make common equity contributions to PacifiCorp of $125.0 million at the end of each quarter in fiscal 2006 and $131.25 million at the end of each quarter in fiscal 2007. If the sale is completed, MidAmerican will refund to PHI the amount of required fiscal 2007 common equity contributions as an increase to the purchase price.

Prior to completion of the sale (or termination of the Stock Purchase Agreement), a joint executive committee with an equal number of representatives from ScottishPower and MidAmerican will facilitate the transactions contemplated in the Stock Purchase Agreement, integration planning and strategic development and will develop recommendations concerning the structure and the general operation of PacifiCorp prior to the closing. If ScottishPower completes the sale of PacifiCorp, MidAmerican will cause the election of its own directors and influence the management and policies of PacifiCorp following the sale.

Strategic Priorities and Economic Factors

PacifiCorp’s goal 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 other factors that affect PacifiCorp’s revenues, PacifiCorp’s earnings are substantially impacted by the extent to which state regulators allow it to reflect costs through rate setting. Results in any particular period may also 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, net power costs 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 extent of recovery of 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. PacifiCorp has also filed power cost adjustment mechanisms in Oregon and Washington and may make filings for such mechanisms in other states. Power cost adjustment mechanisms are designed to keep regulatory rates more closely aligned with actual net power costs. 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, particularly in Utah. In response to the growing demand in its service territories, PacifiCorp’s Integrated Resource Plans provide a process that achieves stakeholder support for procurement of new base load, peaking plant, purchase and renewable resources through a combination of market transactions, competitive solicitations and demand-side management initiatives. In accordance with the 2003 Integrated Resource Plan, PacifiCorp’s Currant Creek Power Plant near Mona, Utah is expected to begin simple-cycle operation with 280.0 MW of capacity in June 2005. Full combined-cycle operation is expected to be substantially complete and begin operation in March 2006, at which time the full capacity of the Currant Creek Power Plant will be an estimated 525.0 MW. Also, consistent with the 2003 Integrated Resource Plan, the Lake Side Power Plant in Vineyard, Utah is expected to begin combined-cycle operation in May 2007, adding an estimated 534.0 MW of capacity. These two plants, when in full commercial operation, will add a total of 1,059.0 MW of capacity to PacifiCorp’s generation portfolio.

In addition, PacifiCorp intends to improve the performance of its infrastructure with reinforcement and replacement of existing network assets.

Increases or reductions in future retail demand for electricity as a result of economic growth or downturns or abnormal weather, among other factors, will impact retail revenues, cash flows and investment levels.

Risk Management

PacifiCorp continues to maintain a strong focus on risk management and controlling its fuel and electricity 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 fuel and electricity costs. See “Item 7A. Quantitative and Qualitative Disclosures About Market Risk.”

Sources of Funding

PacifiCorp has recently relied primarily upon access to short- and long-term debt capital markets as a source of liquidity to fund future investments to the extent not covered by cash from operations. PacifiCorp targets a capital structure that is intended to provide a competitive cost of capital and predictable capital market access. While the sale of PacifiCorp is pending and the Stock Purchase Agreement is in effect, PHI has agreed to make common equity contributions to PacifiCorp of $125.0 million at the end of each quarter in fiscal 2006 and $131.25 million at the end of each quarter in fiscal 2007 until completion of the sale or termination of the Stock Purchase Agreement. In addition, if market conditions are favorable during the year ending March 31, 2006, PacifiCorp will seek to issue long-term debt to more permanently fund its liquidity requirements or refinance maturing long-term debt. See “Liquidity and Capital Resources - Financing Activities - Cautionary Statement” below.

Forward-Looking Statements

This report includes forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. All statements, other than statements of historical fact, made in this report are forward-looking. When used in this Management’s Discussion and Analysis of Financial Condition and Results of Operations and elsewhere in this report, the words “will,” “may,” “could,” “estimates,” “expects,” “anticipates,” “forecasts,” “plans,” “intends” and variations of such words and similar expressions are intended to identify forward-looking statements. Forward-looking statements included in this report relate to, among other matters, the effect on PacifiCorp of the following: the effect of the terms of the Stock Purchase Agreement for the sale of PacifiCorp and the completion of the sale; potential adjustment of regulatory rates to cover costs; growth of retail customers and demand; the impact of new accounting standards or accounting policy changes; the outcome of litigation or regulatory proceedings; environmental laws; capital expenditure levels; results from the construction or repair of generating facilities; hydroelectric relicensing; electricity outages; retirement plan contributions; outcome of tax proceedings; sufficiency of PacifiCorp’s available funds to meet its liquidity needs and future financing; off-balance sheet arrangements; the effect of risk management measures, including use of financial derivatives to manage and mitigate interest rate exposure; and the efficiency and effectiveness of PacifiCorp’s resource and fuel procurement. Forward-looking statements reflect management’s current expectations, plans or projections and are inherently uncertain. There can be no assurance the results predicted will be realized. Actual results may vary from those represented by the forecasts, and those variations may be material. The following are among the factors, in addition to those set forth below under “Risk Factors,” that could cause actual results to differ materially from the forward-looking statements:

•	The effect of the Stock Purchase Agreement for the sale of PacifiCorp, including the consummation of the sale or the termination of the Stock Purchase Agreement;
•	The outcome of general rate cases and other proceedings conducted by regulatory commissions;

•	Changes in prices and availability (for both purchases and sales) of wholesale electricity, natural gas and other fuel sources 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;

•	Changes in expected industrial, commercial and residential customer usage in PacifiCorp’s service territories;

•	Economic trends that could impact electricity usage;

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

•	A high degree of variance between actual and forecasted load and prices that could impact the hedging strategy and costs to balance electricity load and supply;

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

•	Performance of PacifiCorp’s generation facilities, including the level of planned and unplanned outages;

•	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/or delay plant construction;

•	The impact of new accounting pronouncements on results of operations;

•	The impact of interest rates and investment performance on pension and post-retirement expense;

•	The impact of the newly formed Regional Transmission Entity, or the formation of any similar organization; and

•

Timely and appropriate completion of PacifiCorp’s resource procurement process, unanticipated construction delays, changes in costs, receipt of required permits and authorizations, ability to fund resource projects and other factors that could affect future generation plants and infrastructure additions.

Any forward-looking statements issued by PacifiCorp should be considered in light of these factors. PacifiCorp does not intend 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 and Related Policies

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 estimates, in addition to certain less significant accounting estimates, are discussed with senior members of management and PacifiCorp’s Board of Directors, as appropriate, and are disclosed to the ScottishPower Audit Committee. Those estimates 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 six 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 six 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 fundamentals 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 in assumptions could have a significant impact on the fair value of the contract.

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, 2005. The liability adjustment did not affect the consolidated results of operations. PacifiCorp requested and received accounting orders from the regulatory commissions in Utah, Oregon, Wyoming and Washington to classify most of this charge as a Regulatory asset instead of a charge to Other comprehensive income. This increase to Regulatory assets was adjusted as of March 31, 2005 and 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 costs related to SFAS No. 87 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 (“ERISA”). PacifiCorp made $61.6 million in cash contributions to the Retirement Plan during the year ended March 31, 2005, and made $33.4 million in cash contributions to the Retirement Plan during the year ended March 31, 2004. PacifiCorp also made a $60.0 million cash contribution to the Retirement Plan in April 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 ERISA 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 5.75% at March 31, 2005, compared to 6.25% at March 31, 2004. Thus, the discount rate used for PacifiCorp’s fiscal 2005 expense was 6.25% and the discount rate that will be used for PacifiCorp’s fiscal 2006 expense is 5.75%. PacifiCorp chooses a discount rate based upon high quality fixed-income investment yields. The pension and other postretirement benefit liabilities, as well as expenses, increase as the discount rate is reduced.

At March 31, 2005 and 2004, PacifiCorp assumed that the pension and other postretirement assets would generate a long-term rate of return of 8.75%. 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 expenses increase as the expected rate of return on Retirement Plan assets decreases.

Based on the above assumptions, PacifiCorp expects to record pension expense of $62.4 million for the year ending March 31, 2006, as compared to $40.3 million for the year ended March 31, 2005.

The following table reflects the sensitivities of the March 31, 2005 disclosures and the projected pension expense for the year ending March 31, 2006, associated with a change in certain actuarial assumptions by the indicated percentage:

(Millions of dollars)					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	)			88.6			76.9			8.8
Discount rate		0.5				(81.1	)		(70.3	)		(8.2	)

PacifiCorp expects to record other postretirement benefit expense of $29.9 million for the year ending March 31, 2006, as compared to $26.0 million for the year ended March 31, 2005. PacifiCorp has determined that costs related to SFAS No. 106 for other postretirement benefits are currently recoverable in rates. PacifiCorp contributed $24.9 million for the year ended March 31, 2005, and $25.3 million for the year ended March 31, 2004, to the funding vehicles for its other postretirement benefit plans. PacifiCorp expects to contribute $29.9 million to the funding vehicles for its other postretirement benefit plans for the year ending March 31, 2006, 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) Assumed health care cost trend rates	Impact on Accumulated Postretirement Benefit Obligation Increase (Decrease)			Impact on Annual Other Postretirement Benefit Cost Increase (Decrease)

One percentage point increase	$	31.6		$	4.7
One percentage point decrease		(27.2	)		(4.1	)

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 are amortized to the Statements of Consolidated Income as rates to customers are reduced or costs previously recovered in rates are actually incurred. 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, 2005, PacifiCorp had recorded specifically identified regulatory assets, net of regulatory liabilities, totaling $336.8 million. In the event PacifiCorp stopped applying SFAS No. 71 at March 31, 2005, an after-tax loss of approximately $208.9 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, assignment 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, 2005, the amount accrued for unbilled revenues was $143.8 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 has 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, the SEC, Internal Revenue Service, Department of Labor, the 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.

Asset Retirement Obligations

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. 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.

At March 31, 2005, PacifiCorp had recorded an asset retirement obligation liability of $199.6 million. Amounts recorded under SFAS No. 143 are subject to various assumptions and determinations, such as determining whether a legal obligation exists to remove assets and estimating the fair value of the costs of removal, the timing of final removal, inflation rates and the credit-adjusted risk-free interest rates to be used for discounting future liabilities. Changes that may arise over time with regard to these assumptions will change the amounts recorded in conjunction with the asset retirement obligations.

Depreciation and accretion expense generated by SFAS No. 143 accounting is recorded as a regulatory asset or liability since such amounts are recoverable in rates.

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 liabilities currently cannot be estimated and no amounts are recognized in the Consolidated Financial Statements.

PacifiCorp is currently in the process of evaluating the impact of the Financial Accounting Standards Board (the “FASB”) Interpretation No. 47, Accounting for Conditional Asset Retirement Obligations – an Interpretation of FASB Statement No. 143 (“FIN 47”) as discussed below. See also “Item 8. Financial Statements and Supplementary Data - Note 1.”

New Accounting Standards

FSP SFAS No. 106-2

In May 2004, the FASB released FASB Staff Position (“FSP”) SFAS No. 106-2, Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (“FSP SFAS No. 106-2”). FSP SFAS No. 106-2 provides guidance on the accounting for the effects of the Medicare Prescription Drug Improvement and Modernization Act of 2003 (the “Medicare Act”). The Medicare Act introduced a prescription drug benefit under Medicare, as well as a federal subsidy to sponsors of retiree health care plans that include prescription drug benefits. Employers that sponsor postretirement health care plans that offer prescription drug benefits must determine if their prescription drug benefits are actuarially equivalent to the drug benefit provided under Medicare Part D as of the date of enactment of the Medicare Act to be entitled to receive the subsidy. Employers are required to disclose the effect of the federal subsidy afforded by the Medicare Act if its prescription drug benefits are determined to be actuarially equivalent to the Medicare Part D benefit. FSP SFAS No. 106-2 was effective for the first interim or annual period beginning after June 15, 2004. PacifiCorp elected to adopt FSP SFAS No. 106-2 early upon its release with retroactive application to PacifiCorp’s Welfare Benefits Plan December 31, 2003 measurement date. Because that measurement date is used only to determine net periodic postretirement benefit cost for the period beginning April 1, 2004, there was no impact on previously reported information. The effects of the Medicare Act decreased PacifiCorp’s accumulated postretirement benefit obligation by $42.6 million. This decrease is treated as an actuarial experience gain. This actuarial experience gain reduces the unrecognized net loss resulting from differences in prior periods between actuarial assumptions and actual experience. The actuarial experience gain will be amortized to expense through a decrease in the amortization of the unrecognized net loss. The effects of the Medicare Act decreased net periodic postretirement benefit cost for the year ended March 31, 2005, when compared to the expense calculated before the adoption of FSP SFAS No. 106-2, as follows:

(Millions of dollars)	Year Ended March 31, 2005

Decrease in:
Interest cost	$	2.7
Service cost		0.1
Amortization of unrecognized loss		2.9

Decrease in Net periodic postretirement benefit cost	$	5.7

On January 21, 2005, the Centers for Medicare and Medicaid Services released final regulations for implementing the Medicare Act. These regulations provide guidance for making a determination of whether the benefits under a plan will meet the definition of actuarial equivalence. As this was subsequent to PacifiCorp’s measurement date, these regulations had no impact on the year ended March 31, 2005. PacifiCorp expects these regulations to result in an additional decrease in the accumulated postretirement benefit obligation of approximately $18.0 million and an additional decrease in the net periodic postretirement benefit cost of approximately $3.3 million during the year ending March 31, 2006.

EITF No. 03-1 and FSP EITF No. 03-1-1

In June 2004, the Emerging Issues Task Force (“EITF”) issued EITF No. 03-1, The Meaning of Other-Than-Temporary Impairment and Its Application to Certain Investments (“EITF No. 03-1”). Application guidance in EITF No. 03-1 should be used to determine when an investment is considered impaired, whether that impairment is other than temporary, and the measurement of such impairment. The guidance also includes accounting considerations subsequent to the recognition of an other-than-temporary impairment and requires certain disclosures in annual financial statements about unrealized losses that have not been recognized as other-than-temporary impairments.

In September 2004, the FASB issued FSP EITF No. 03-1-1, Effective Date of Paragraphs 10-20 of EITF No. 03-1, The Meaning of Other-Than-Temporary Impairment and Its Application to Certain Investments (“FSP EITF No. 03-1-1”). FSP EITF No. 03-1-1 delayed the previously required effective date of July 1, 2004, for PacifiCorp regarding the measurement and recognition guidance contained in the applicable paragraphs. The delay of the effective date is likely to be superceded with the final issuance of an FSP on other-than-temporary impairment of investments. The adoption of the measurement and recognition guidance of EITF No. 03-1, if implemented in its present form, is not anticipated to have a material impact on PacifiCorp’s consolidated financial position or results of operations.

SFAS No. 151

In November 2004, the FASB issued SFAS No. 151, Inventory Costs (“SFAS No. 151”), which amends Accounting Research Bulletin No. 43, Chapter 4, Inventory Pricing. SFAS No. 151 requires that abnormal amounts of idle facility expense, freight, handling costs and wasted material (spoilage) be included as current-period charges, eliminating the option for capitalization. This statement is effective for inventory costs that PacifiCorp incurs on or after April 1, 2006. PacifiCorp does not typically incur abnormal costs related to inventory balances; therefore, the adoption of this statement is not anticipated to have a material impact on PacifiCorp’s consolidated financial position or results of operations.

SFAS No. 153

In December 2004, the FASB issued SFAS No. 153, Exchanges of Non-monetary Assets (“SFAS No. 153”), which amends Accounting Principles Board (“APB”) Opinion No. 29, Accounting for Non-monetary Transactions (“APB No. 29”). SFAS No. 153 eliminates the exception from fair value measurement for non-monetary exchanges of similar productive assets in APB No. 29 and replaces it with an exception for exchanges that do not have commercial substance. This statement specifies that a non-monetary exchange has commercial substance if the future cash flows of the entity are expected to change significantly as a result of the exchange. The provisions in this statement will apply to PacifiCorp for any exchanges of non-monetary assets that occur on or after April 1, 2006. The adoption of this statement is not expected to have a material impact on PacifiCorp’s consolidated financial position or results of operations.

SFAS No. 123R and SAB No. 107

In December 2004, the FASB issued SFAS No. 123R, Share-Based Payment (“SFAS No. 123R”), a revision of the originally issued SFAS No. 123, Accounting for Stock-Based Compensation. SFAS No. 123R establishes standards for the accounting for transactions in which an entity exchanges its equity instruments for goods or services. In March 2005, the SEC issued Staff Accounting Bulletin (“SAB”) No. 107 (“SAB No. 107”), which provides additional guidance in applying the provisions of SFAS No. 123R. SFAS No. 123R requires that the cost resulting from all share-based payment transactions be recognized in the financial statements using the fair value method. The intrinsic value method of accounting established by APB No. 25, Accounting for Stock-Based Compensation (“APB No. 25”), will no longer be allowed. SAB No. 107 describes the SEC Staff’s guidance in determining the assumptions that underlie the fair value estimates and discusses the interaction of SFAS No. 123R with other existing SEC guidance.

In April 2005, the effective date of SFAS No. 123R was deferred until the beginning of the fiscal year that begins after June 15, 2005; however, early adoption is encouraged. A modified prospective application is required for new awards and to awards modified, repurchased or cancelled after the required effective date. The provisions of SAB No. 107 will be applied upon adoption of SFAS No. 123R.

The PacifiCorp Stock Incentive Plan (the “PSIP”) expired November 29, 2001; therefore, no awards under the PSIP are expected to be newly issued, modified, repurchased or cancelled as of the effective date. As of the effective date, all requisite service under the PSIP will have been previously rendered; therefore, no compensation expense is expected to result from the adoption of SFAS No. 123R in relation to the PSIP.

Certain PacifiCorp employees receive awards under various ScottishPower share-based payment plans. Application to these awards of the fair value method required by SFAS No. 123R, as compared to the application of the intrinsic value method allowed under APB No. 25, is not expected to result in a material change to recorded compensation expense upon adoption of SFAS No. 123R.

FSP SFAS No. 109-1

In December 2004, the FASB issued FSP SFAS No. 109-1, Application of FASB Statement No. 109, Accounting for Income Taxes, to the Tax Deduction on Qualified Production Activities Provided by the American Jobs Creation Act of 2004 (“FSP SFAS No. 109-1”). This tax deduction will be treated as a “special deduction” as described in SFAS No. 109, Accounting for Income Taxes (“SFAS No. 109”). As such, the special deduction has no effect on deferred tax assets and liabilities existing at the enactment date. Rather, the impact of this deduction will be reported in the period in which the deduction could be claimed on a separate return basis in accordance with PacifiCorp’s accounting policy. This statement became effective upon issuance. The impact of the deduction to PacifiCorp will depend on the application of forthcoming guidance from the Internal Revenue Service to PacifiCorp’s future qualifying electric generation activities and cannot be estimated at this time.

FIN 47

In March 2005, the FASB issued FIN 47, which clarifies that the term “conditional asset retirement obligation,” as used in SFAS No. 143, refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity. The obligation to perform the asset retirement activity is unconditional even though uncertainty exists about the timing and/or method of settlement. FIN 47 clarifies that an entity is required to recognize a liability for the fair value of a conditional asset retirement obligation when incurred if the liability’s fair value can be reasonably estimated. FIN 47 is effective at the end of the fiscal year ending after December 15, 2005. PacifiCorp is currently evaluating the impact of adopting FIN 47 on its consolidated financial position and results of operations.

RESULTS OF OPERATIONS

Overview

PacifiCorp’s earnings on common stock for the year ended March 31, 2005, were $249.6 million, as compared to $244.8 million for the year ended March 31, 2004, and $132.8 million for the year ended March 31, 2003. Significant factors affecting results for the year ended March 31, 2005, included increased regulatory rates to retail customers, partly offset by higher net wholesale electricity costs due to substitution of higher priced market transactions for reduced hydroelectric and thermal production, and increased Operations and maintenance expense.

PacifiCorp’s total revenues for the year ended March 31, 2005, decreased by $145.7 million, or 4.6%, compared to the prior year.

Retail revenues increased by $101.8 million, or 4.0%, primarily as a result of higher regulatory rates and customer growth. These benefits were partially offset by a reduction in usage per customer, in part due to milder weather in fiscal 2005. Retail energy sales volumes for the year ended March 31, 2005, increased by 240,000 MW, or 0.5%.

Wholesale sales and other revenue declined by $247.5 million, or 38.2%, primarily due to unrealized losses on wholesale sales contracts and an increase in the level of wholesale sales contracts that did not physically settle being recorded on a net basis. These decreases were partially offset by higher levels of physically settled wholesale sales activity and higher net realized prices on short- and long-term electricity sale contracts.

Purchased electricity expense for the year ended March 31, 2005, declined by $224.8 million, or 33.4%, primarily due to unrealized gains on purchased power contracts and an increase in the level of purchased power contracts that did not physically settle being recorded on a net basis. These decreases were partially offset by higher levels of physically settled power purchases, due primarily to lower hydroelectric and thermal production, and higher net realized electricity prices on short- and long-term power purchase contracts.

Output from PacifiCorp-owned hydroelectric facilities for the year ended March 31, 2005, decreased by 473,064 MWh, or 13.4%, as compared to the prior year, primarily as a result of unusually dry conditions. Hydroelectric output for both the years ended March 31, 2005 and 2004, was lower than the level of hydroelectric generation expected under normal conditions.

Output from PacifiCorp’s thermal plants for the year ended March 31, 2005, decreased by 416,776 MWh, or 0.9%, as compared to the prior year, due to slightly higher levels of planned and unplanned outages.

Revenues from wholesale sales contracts that do not physically settle are recorded net of the cost of the energy sold. Revenues from physically settled contracts are recorded on a gross basis, and the cost of energy sold pursuant to physically settled contracts is recorded as purchased electricity expense.

Significant Regulatory Outcomes

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%. In February 2005, the UPSC approved a stipulation settling PacifiCorp’s general rate case filed in August 2004. Under the stipulation, base rates in Utah increased by an additional $51.0 million annually starting in March 2005, resulting in an average price increase of 4.7% and an authorized return on equity of 10.5%.

In September 2004, the WPSC approved a stipulation for a stand-alone pass-on of increased net wholesale purchased electricity costs. This stipulation was effective September 15, 2004, and resulted in an overall price increase of $9.3 million annually, or 2.7%.

In October 2004, the WUTC issued an order adopting a multi-party settlement agreement with limited conditions. A subsequent supplemental order was issued in November 2004, resulting in a total rate increase of $15.5 million annually, or 7.8%, effective November 16, 2004.

PacifiCorp pursues a regulatory program in all states, with the objective of keeping rates closely aligned to ongoing costs. See “Item 1. Business – Regulation” for more detail on the state regulatory issues and pending rate case filings.

Affiliated Interest Cross-Charge Policy

Commencing on April 1, 2004, PacifiCorp and SPUK, an indirect subsidiary of ScottishPower, implemented a cross-charge policy governing the allocation of costs incurred by PacifiCorp and SPUK, on behalf of each other. This policy, approved by the SEC in its administration of the PUHCA, permits PacifiCorp to receive certain administrative services, priced at cost, from SPUK. These include shareholder, investor relations, management and human resource services. PacifiCorp also provides administrative services to SPUK and other ScottishPower affiliates under the cross-charge policy. Cross-charges from SPUK to PacifiCorp amounted to $14.9 million for the year ended March 31, 2005, and were recorded in Operations and maintenance expense.

Year Ended March 31, 2005 Compared to Year Ended March 31, 2004

Revenues

(Millions of dollars)	Year Ended March 31,				Favorable/(Unfavorable)

	2005		2004		$ Change			% Change

Residential	$	1,004.6	$	994.5	$	10.1		1.0	%
Commercial		833.1		792.9		40.2		5.1
Industrial		774.8		725.6		49.2		6.8
Other retail		36.3		34.0		2.3		6.8

Retail sales		2,648.8		2,547.0		101.8		4.0
Wholesale sales and other		400.0		647.5		(247.5	)	(38.2	)

Total revenues	$	3,048.8	$	3,194.5	$	(145.7	)	(4.6	)

Energy sales (Thousands of MWh)
Residential		14,117		14,460		(343	)	(2.4	)
Commercial		14,642		14,413		229		1.6
Industrial		19,454		19,133		321		1.7
Other		706		673		33		4.9

Total		48,919		48,679		240		0.5

Average residential usage (kWh)		10,411		10,889		(478	)	(4.4	)
Total customers - end of period (in thousands)		1,605		1,570		35		2.2

Residential revenues increased $10.1 million, or 1.0%, primarily due to:

•	$36.5 million of increases from higher regulatory rates; and

•	$20.7 million of increases relating to growth in the average number of residential customers; partially offset by,

•	$45.7 million of decreases from lower average estimated customer usage, including $32.1 million due to the impact of milder weather, compared to the prior year; and

•	$1.4 million of decreases due to a change in price mix, which resulted from the levels of customer usage at different customer tariffs in the various states that PacifiCorp serves.

Commercial revenues increased $40.2 million, or 5.1%, primarily due to:

•	$34.7 million of increases from higher regulatory rates;

•	$18.5 million of increases relating to growth in the average number of commercial customers; and

•	$5.9 million of increase in average estimated customer usage, excluding the effects of weather, partially offset by,

•	$11.5 million of decrease due to the impact of milder weather compared to the prior year; and

•	$7.6 million of decreases due to a change in price mix, which resulted from the levels of customer usage at different customer tariffs in the various states that PacifiCorp serves.

Industrial revenues increased $49.2 million, or 6.8%, primarily due to:

•	$37.7 million of increases from higher regulatory rates;

•	$9.8 million of increases relating to growth in the average number of industrial customers; and

•	$1.7 million of increases due to a change in price mix, which resulted from the levels of customer usage at different customer tariffs in the various states that PacifiCorp serves.

Wholesale sales and other revenues decreased $247.5 million, or 38.2%, primarily due to:

•	$300.6 million of decreases from unrealized losses from short and long-term energy sales contracts recorded at fair value, primarily due to adverse movements in market prices;

•	$252.0 million of decreases due to contracts that did not physically settle being recorded on a net basis;

•	$56.9 million of decreases in energy volumes delivered pursuant to long-term contracts as a result of contract expirations; partially offset by,

•	$198.9 million of increases in energy volumes delivered pursuant to short-term contracts, primarily due to increased system balancing activity from variations in retail load and generation levels;

•	$107.8 million of increases due to higher electricity prices on realized short- and long-term wholesale sales transactions;

•	$47.2 million of increases due to higher revenues related to regulatory asset recovery, including $27.9 million due to a new tariff in Utah; and

•	$2.8 million of increases due to higher wheeling revenue.

Operating Expenses

(Millions of dollars)	Year Ended March 31,				Favorable/(Unfavorable)

	2005		2004		$ Change			% Change

Purchased electricity	$	448.0	$	672.8	$	224.8		33.4	%
Fuel		500.0		483.9		(16.1	)	(3.3	)
Operations and maintenance		913.1		895.8		(17.3	)	(1.9	)
Depreciation and amortization		436.9		428.8		(8.1	)	(1.9	)
Taxes, other than income taxes		94.4		95.3		0.9		0.9

Total operating expenses	$	2,392.4	$	2,576.6	$	184.2		7.1

Purchased electricity expense decreased $224.8 million, or 33.4%, primarily due to:

•	$302.9 million of decreases from unrealized gains from short- and long-term energy purchase contracts recorded at fair value, primarily due to favorable movements in market prices;

•	$252.0 million of decreases due to contracts that did not physically settle being recorded on a net basis; and

•	$27.5 million of decreases from increased gains in the current year on weather derivative contracts; partially offset by,

•	$191.3 million of increases related to higher volumes of short- and long-term purchases resulting from lower hydroelectric and thermal generation, and increased retail load; and

•	$159.1 million of increases due to the effects of higher electricity prices on realized short- and long-term energy purchase contracts.

Fuel expense increased $16.1 million, or 3.3%, primarily due to:

•	$30.0 million of increases as a result of an increase in the price of coal consumed; partially offset by,

•	$9.9 million of decreases relating to lower supply volumes due mainly to a reduction in thermal plant generation; and

•	$4.0 million of decreases as a result of a decrease in the price of natural gas consumed.

Operations and maintenance expense increased $17.3 million, or 1.9%, primarily due to:

•	$44.3 million of increases in employee salary expense and other direct employee expenses, primarily due to an increase in headcount and higher benefit and pension costs;

•	$14.9 million of increases from services rendered by SPUK and charged to PacifiCorp pursuant to the affiliated interest cross-charge policy, which became effective April 1, 2004; and

•	$12.1 million of net increases due to changes in regulatory assets and liabilities, including $27.0 million of increased Utah demand-side management amortization; partially offset by,

•	$26.9 million of decreases in third-party contract and service fees, including a reduction in the use of contractors for certain activities, including information technology, planned outages and field operations;

•	$6.3 million of a decrease arising from the reversal of an accrual for certain tax-related employee severance liabilities that were resolved in fiscal 2004;

•	$5.5 million of a decrease due to the recognition of claims in the prior year due to the bankruptcy of an insurance carrier;

•	$5.5 million of decreases in insurance costs;

•	$3.5 million of decreases in rent expense;

•	$2.1 million of decreases in the level of write-offs of cancelled capital projects; and

•	$1.7 million of decreases due to contract settlements in the prior year.

Depreciation and amortization expense increased $8.1 million, or 1.9%, primarily due to:

•	$15.8 million of increases in depreciation and amortization expense due to an increase in plant in service; and

•	$4.6 million of increases in amortization expense due to higher capitalized software balances; partially offset by,

•	$12.9 million of decreases in capitalized software amortization following a change in the estimated useful lives of certain computer software systems.

Interest and Other (Income) Expense

	Year Ended March 31,						Favorable/(Unfavorable)

(Millions of dollars)	2005			2004			$ Change			% Change

Interest expense	$	267.4		$	256.5		$	(10.9	)	(4.2	)%
Interest income		(9.1	)		(13.8	)		(4.7	)	(34.1	)
Interest capitalized		(14.8	)		(19.9	)		(5.1	)	(25.6	)
Minority interest and other		(7.3	)		1.6			8.9		556.3

Total	$	236.2		$	224.4		$	(11.8	)	(5.3	)

Interest expense increased $10.9 million, or 4.2%, primarily due to:

•	$8.9 million of increases resulting from an increase in average amount of debt outstanding, due in part to the refinancing of $352.0 million of Preferred securities redeemed in August 2003 with long-term debt, partially offset by a decrease in average interest rates.

Interest income decreased $4.7 million, or 34.1%, primarily due to:

•	Decreases in interest income on regulatory assets.

Interest capitalized decreased $5.1 million, or 25.6%, primarily due to:

•	Lower average capitalization rates applied to higher qualifying construction work-in-progress balances during the year ended March 31, 2005.

Minority interest and other expense changed $8.9 million, primarily due to:

•	$11.7 million of a decrease in expense relating to distributions on Preferred securities, which were redeemed in August 2003;

•	$2.3 million of a decrease in charitable donations; partially offset by,

•	$4.3 million of an increase in income relating to proceeds from company-owned life insurance.

Income Tax Expense

Income tax expense increased $24.0 million, or 16.6%, primarily due to:

•

$14.2 million of increases in the change in the federal tax contingency reserve due to $8.5 million of additional accruals in the current year related to new activities/development of tax examinations, compared to $5.7 million of contingency reserve releases in the prior year due to the resolution of certain tax examinations;

•	$9.5 million of increases due to higher levels of income from continuing operations before income taxes and cumulative effect of accounting change for the year ended March 31, 2005; and

•	$5.4 million of increases due to permanent book and tax differences of Internal Revenue Service settlements; partially offset by,

•	$3.9 million of decreases from the tax effect of regulatory treatment of book and tax differences; and

•	$3.7 million of decreases in state income tax effect.

Cumulative Effect of Accounting Change

•	PacifiCorp recorded a $0.9 million after-tax loss from the implementation of SFAS No. 143 during the year ended March 31, 2004.

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

Revenues

(Millions of dollars)	Year Ended March 31,				Favorable/(Unfavorable)

	2004		2003		$ Change			% Change

Electric Operations
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		34.0		31.4		2.6		8.3

Retail sales		2,547.0		2,408.7		138.3		5.7
Wholesale sales and other		647.5		673.7		(26.2	)	(3.9	)

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


Energy sales (Thousands of MWh)
Electric Operations
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

Total		48,679		46,972		1,707		3.6

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%, primarily 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; 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, which resulted from the levels of customer usage at different customer tariffs in the various states that PacifiCorp serves.

Commercial revenues increased $29.5 million, or 3.9%, primarily 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, which resulted from the levels of customer usage at different customer tariffs in the various states that PacifiCorp serves.

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

•	$14.9 million of increases due to a change in price mix, which resulted from the levels 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 and other revenues decreased $26.2 million, or 3.9%, primarily due to:

•	$148.0 million of decreases in long-term and short-term energy volumes delivered as a result of a combination of contract expiration and higher prior year wholesale activity;

•	$33.2 million of decreases from unfavorable movements of unrealized gains and losses on derivatives;

•	$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,

•	$117.1 million of increases due to contracts that did not physically settle being recorded on a net basis;

•	$55.7 million of increases from higher realized prices on both long- and short-term wholesale sales transactions, due to increases in market prices and escalation on long-term contract prices;

•	$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 revenues from third parties jointly using PacifiCorp’s distribution poles; 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,				Favorable/(Unfavorable)

	2004		2003		$ Change			% Change

Electric Operations
Purchased electricity	$	672.8	$	698.5	$	25.7		3.7	%
Fuel		483.9		482.2		(1.7	)	(0.4	)
Operations and maintenance		895.8		885.1		(10.7	)	(1.2	)
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	$	2,576.6	$	2,593.5	$	16.9		0.7

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

•	$124.2 million of decreases due to lower energy purchase volumes resulting from higher thermal plant generation and lower wholesale activity than in the prior year;

•	$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; and

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

•	$117.1 million of increases due to contracts that did not physically settle being recorded on a net basis;

•	$49.5 million of increases from higher realized electricity prices on both long- and short-term energy purchase 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%, primarily 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 increased $10.7 million, or 1.2%, primarily due to:

•	$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;

•	$13.2 million of increases primarily due to changes in regulatory assets and liabilities;

•	$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; partially offset by,

•	$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.

Depreciation and amortization expense decreased $5.5 million, or 1.3%, primarily 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 and amortization 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.

Interest and Other (Income) Expense

	Year Ended March 31,						Favorable/(Unfavorable)

(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		1.6			19.0			17.4		91.6

Total	$	224.4		$	249.7		$	25.3		10.1

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 that were included as interest expense for the year ended March 31, 2004, in accordance with 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 $1.5 million decrease due to interest income on the settlement of an excise tax case in March 2002; and

•	A $1.1 million decrease due to interest income recognized on an electricity sales contract settlement in September 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 changed $17.4 million, or 91.6%, 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 and state tax authorities on prior year tax examinations.

Cumulative Effect of Accounting Change

•	PacifiCorp recorded a $0.9 million after-tax loss from the implementation of SFAS No. 143 in the year ended March 31, 2004.

•	PacifiCorp recorded a $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.

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 stock to PHI. 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 flows provided by operating activities decreased $120.8 million to $711.1 million for the year ended March 31, 2005, compared to $831.9 million for the year ended March 31, 2004, primarily due to the activities described below:

•

The change in Accounts receivable, prepayments and other current assets decreased $136.1 million during the year ended March 31, 2005 compared, to the year ended March 31, 2004, primarily due to:

•

$67.8 million increase in the change in net power costs receivable due to increased system balancing activities and higher electricity prices;

•

$52.2 million increase in the change in margin deposits due to the effects of market prices on forward natural gas and electricity purchase and sales contracts; and

•

$18.9 million increase in the change in accounts receivable primarily due to increases in revenues from retail customers.

•

The change in Inventories decreased $30.3 million during the year ended March 31, 2005, compared to the year ended March 31, 2004, primarily due to:

•

$19.1 million decrease in the change in inventories due to the decrease in the levels of fuel inventory during the year ended March 31, 2004, that were maintained through March 31, 2005; and

•

$11.1 million decrease in the change in inventories due to the increase in the baseline restocking levels of materials and supplies during the year ended March 31, 2005.

•

The change in Accounts payable and accrued liabilities increased $87.4 million during the year ended March 31, 2005, compared to the year ended March 31, 2004, primarily due to an increase in the change in net power costs payable of $60.0 million due to higher volumes of purchased electricity as a result of lower hydroelectric and thermal generation and increased retail load, as well as higher costs in March 2005 compared to March 2004.

•

Other changes in cash flows from operating activities during the year ended March 31, 2005, compared to the year ended March 31, 2004, included a $23.2 million increase in the level of funding for pension and other post-retirement benefits.

Net cash provided by operating activities increased $150.3 million to $831.9 million for the year ended March 31, 2004, compared to $681.6 million for the year ended March 31, 2003, due primarily to a $108.0 million increase in Net income, a $66.6 million decrease in tax payments related to prior period Internal Revenue Service audits, and the timing of collections and payments. Net cash provided by operating activities is impacted by seasonal movements in working capital, by whether or not operating costs are recovered in rates and by the timing of such recovery.

Investing Activities

Net cash used in investing activities increased $143.2 million to $846.7 million for the year ended March 31, 2005, primarily due to higher capital expenditures during the year ended March 31, 2005, as compared to the prior year. Capital expenditures totaled $851.6 million for the year ended March 31, 2005, compared to $690.4 million for the year ended March 31, 2004. The increase was primarily due to $158.9 million of increased expenditures on the construction of the Currant Creek Power Plant and $49.6 million towards the construction of the Lake Side Power Plant, partially offset by lower expenditures on the distribution and transmission upgrades along the Wasatch Front, as well as reductions in other capital expenditures. Expenditures for the Currant Creek and Lake Side Power Plants continue to be capitalized as construction work-in-progress until the completed components of the plants are placed into service.

Net cash used in investing activities increased $178.4 million to $703.5 million for the year ended March 31, 2004, primarily due to higher capital expenditures during the year ended March 31, 2004, as compared to the prior year. Capital expenditures totaled $690.4 million for the year ended March 31, 2004, as compared to $550.0 million for the year ended March 31, 2003. The increase was primarily due to increasing expenditures for distribution network growth and system upgrades (primarily along the Wasatch Front), plant refurbishments, power plant construction and hydroelectric relicensing. For the year ended March 31, 2004, $44.7 million was spent for the construction of the Currant Creek Power Plant and $91.5 million was spent on distribution and transmission system upgrades along the Wasatch Front.

Financing Activities

Because certain of the transactions contemplated by the Stock Purchase Agreement for the sale of PacifiCorp would, if the sale is consummated, constitute an event of default under certain of PacifiCorp’s financing agreements, PacifiCorp will need to obtain waivers or amendments to those agreements, or replace them with other facilities, prior to consummation of the sale. The following discussion does not reflect any such amendments or replacement facilities.

Short-Term Debt

PacifiCorp’s short-term debt increased by $343.9 million during the year ended March 31, 2005, to $468.8 million, primarily due to capital expenditures in excess of cash from operations and pre-funding of maturing long-term debt, partially offset by the proceeds from the long-term debt financing during the period, which were used to reduce short-term debt. Regulatory authorities limit PacifiCorp to $1.5 billion of short-term debt, of which $468.8 million was outstanding at March 31, 2005, at a weighted average interest rate of 2.9%.

Short-term debt increased by $99.9 million during the year ended March 31, 2004, primarily due 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 million during the year ended March 31, 2003, primarily due to the issuance of Common stock and an increase in cash from operations.

Revolving Credit Agreement

PacifiCorp’s short-term borrowings and certain other financing arrangements are supported by an $800.0 million committed bank revolving credit agreement with a three-year term that became effective May 28, 2004. The interest on advances under this facility is based on the London Interbank Offered Rate (LIBOR) plus a margin that varies based on PacifiCorp’s credit ratings. As of March 31, 2005, this facility was fully available and there were no borrowings outstanding. In addition to this committed credit facility, at March 31, 2005, PacifiCorp had $182.2 million in money market accounts included in Cash and cash equivalents available to meet its liquidity needs.

PacifiCorp’s revolving credit agreement contains customary covenants and default provisions, including a covenant not to exceed a specified debt-to-capitalization ratio of 60.0%. PacifiCorp monitors these covenants on a regular basis to ensure that events of default will not occur. As of March 31, 2005, PacifiCorp was in compliance with the covenants of its revolving credit agreement, which also apply to its letters of credit. See “Future Uses of Cash - Contractual Obligations and Commercial Commitments - Commercial Commitments” below for information regarding PacifiCorp’s letters of credit.

Long-Term Debt

During March 2005, the maturity dates for three series of variable-rate pollution-control revenue bonds totaling $38.1 million were extended to December 1, 2020.

For the year ended March 31, 2005, PacifiCorp made scheduled long-term debt repayments of $239.8 million. Additionally, during December 2004, PacifiCorp redeemed, prior to maturity, all of the 8.625% First Mortgage Bonds due in December 2024 and totaling $20.0 million. This retirement was initially funded through short-term debt with the expectation that it will be funded through long-term financing in the next 12 months, subject to regulatory authorization.

On August 24, 2004, PacifiCorp issued $200.0 million of its 4.95% Series of First Mortgage Bonds due August 15, 2014, and $200.0 million of its 5.90% Series of First Mortgage Bonds due August 15, 2034. PacifiCorp used the proceeds for general corporate purposes, including the reduction of short-term debt.

For the year ended March 31, 2004, PacifiCorp made scheduled long-term debt repayments of $136.6 million. Additionally, during July and August 2003, PacifiCorp redeemed, prior to maturity, First Mortgage Bonds totaling $57.5 million and Preferred Securities totaling $352.0 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.

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

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, 2005, PacifiCorp estimated it would be able to issue up to $3.2 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. See also “Limitations” below.

Amounts Available Under Shelf Registrations and State Authorizations

At March 31, 2005, PacifiCorp had $250.0 million available under a currently effective shelf registration. Securities that may be issued under this registration include first mortgage bonds, unsecured debt securities and no par serial preferred stock. PacifiCorp plans to file a shelf registration statement with the SEC during fiscal year 2006 covering $750.0 million of first mortgage bonds and unsecured debt.

During April 2005, PacifiCorp filed proposed amendments to existing state regulatory orders requesting an increase in the number of common shares that PacifiCorp may issue to PHI from approximately 35 million to 50 million shares. The IPUC and the WUTC have issued orders approving the amendments, and the OPUC is expected to consider the proposed amendments at its May 31, 2005 meeting.

During May 2005, PacifiCorp received authority to issue up to an additional $1.0 billion of long-term debt from the OPUC and the IPUC and up to $400.0 million of PacifiCorp’s first mortgage bonds from the WUTC. Prior issuances have fully utilized previous state commission authorizations.

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, 2005, 2004 and 2003.

Dividends

During the year ended March 31, 2005, PacifiCorp had the following dividend activity:

•	$193.3 million declared and paid on common stock; and

•	$6.1 million declared, which includes $4.0 million of interest expense, and $6.2 million paid on Preferred stock and Preferred stock subject to mandatory redemption.

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

•	$160.6 million declared and paid on common stock; and

•	$6.7 million declared and $6.8 million paid on Preferred stock and Preferred stock subject to mandatory redemption. 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 $7.3 million paid on Preferred stock and Preferred stock subject to mandatory redemption.

Capitalization

	March 31,

(Millions of dollars)	2005				2004

Short-term debt	$	468.8	6.0	%	$	124.9	1.7	%
Long-term debt, including current maturities		3,898.9	50.0			3,760.2	51.8
Preferred stock subject to mandatory redemption		52.5	0.7			60.0	0.8
Preferred stock		41.3	0.5			41.3	0.6
Common equity		3,335.8	42.8			3,278.7	45.1

Total capitalization	$	7,797.3	100.0	%	$	7,265.1	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 56.0% at March 31, 2005, and 53.5% at March 31, 2004. PacifiCorp seeks to maintain, over time, its capital structure in accordance with its targets. PacifiCorp currently anticipates that additional common equity contributions from its parent, PHI, will be necessary to achieve its target capitalization over the next 12 months. See “Cautionary Statement” below.

As a result of recent changes in accounting standards, such as FIN 46R, Consolidation of Variable-Interest Entities, an interpretation of Accounting Research Bulletin No. 51, and EITF No. 01-08, Determining Whether an Arrangement Is a Lease, it is possible that new purchase power and gas agreements, transmission arrangements or amendments to existing arrangements may be accounted for as capital lease obligations or debt on PacifiCorp’s financial statements. While PacifiCorp has successfully amended covenants in financing arrangements that may be impacted by these changes, it may be more difficult for PacifiCorp to comply with its capitalization targets or regulatory commitments concerning minimum levels of common equity as a percentage of capitalization. This may lead PacifiCorp to seek amendments or waivers from regulators, delay or reduce spending programs, seek additional new common equity contributions from its immediate parent, PHI, or take other actions.

Variable-Rate Liabilities

	March 31,

(Millions of dollars)	2005			2004

Short-term debt	$	468.8		$	124.9
Variable-rate long-term debt		541.7			541.7

	$	1,010.5		$	666.6

Percentage of total capitalization		13.0	%		9.2	%

PacifiCorp’s capitalization policy targets consolidated variable-rate liabilities at between 10.0% and 25.0% of total capitalization. PacifiCorp was at the lower end of the target range at March 31, 2005, and anticipates that variable-rate exposure will continue to be at the lower end of the range during the year ending March 31, 2006.

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 credit agreement. PacifiCorp monitors the covenants on a regular basis in order to ensure that events of default will not occur. As of March 31, 2005, PacifiCorp was in compliance with the covenants of its credit agreement. Based on PacifiCorp’s most restrictive covenant under the credit agreement, management believes that PacifiCorp could have borrowed an additional $0.8 billion at March 31, 2005. 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.

Pursuant to the Stock Purchase Agreement with MidAmerican for the sale of PacifiCorp, ScottishPower has agreed to limit PacifiCorp’s ability to borrow money or incur debt beyond agreed limits without prior MidAmerican approval.

Cautionary Statement

Management expects that it will be necessary to supplement cash generated from operations, the additional equity contributions from PHI required by the Stock Purchase Agreement with MidAmerican and availability under committed credit facilities with new issuances of long-term debt to fund liquidity needs during the next 12 months. However, if market conditions are not favorable for the issuance of long-term debt, it may be necessary for PacifiCorp to postpone certain planned capital expenditures, or take other actions, to the extent those expenditures are not fully covered by cash from operations, additional PHI equity and availability under committed credit facilities. In addition, if PacifiCorp cannot obtain appropriate amendments or waivers under certain of its financing agreements or arrange replacement facilities, the sale of all of its common stock by PHI to MidAmerican would constitute an event of default under these agreements.

FUTURE USES OF CASH

Dividends

On April 21, 2005, the PacifiCorp Board of Directors declared a dividend on common stock of $0.163 per share for a total of approximately $50.8 million and was paid on May 27, 2005. PacifiCorp presently anticipates that it will declare quarterly dividends on common stock at this rate per share during fiscal year 2006, subject to results of operations, financial condition and other considerations. Pursuant to the Stock Purchase Agreement for the sale of PacifiCorp, ScottishPower has agreed to cause PacifiCorp to not pay dividends to PHI in excess of $53.7 million per quarter during fiscal 2006 and $60.575 million per quarter during fiscal 2007. These restrictions will terminate upon either the close of the sale of PacifiCorp or the earlier termination of the Stock Purchase Agreement.

Capital Expenditure Program

The following table shows actual capital expenditures for the year ended March 31, 2005, and PacifiCorp’s estimated capital expenditures for the years ending March 31, 2006 and 2007. Except for major construction projects specifically exempted by the Stock Purchase Agreement, any capital expenditures for the year ending March 31, 2007, will require the prior approval of MidAmerican.

(Millions of dollars)	Actual		Estimated

	Year Ended March 31, 2005		Years Ending March 31,

				2006		2007

Distribution and Transmission	$	324.2	$	369.5	$	436.8
Generation and Mining		482.6		634.7		497.9
Other		44.8		78.2		124.5

Total	$	851.6	$	1,082.4	$	1,059.2

Actual and estimated future capital expenditures include upgrades to distribution and transmission lines, upgrades of generating plant equipment, 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 the remaining costs to have the Currant Creek Power Plant constructed into fiscal 2007 and the 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, 2006 and 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 Plans. 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 estimate of capital expenditures 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. While the sale of PacifiCorp is pending and the Stock Purchase Agreement is in effect, PHI has agreed to make common equity contributions to PacifiCorp of $125.0 million at the end of each quarter in fiscal 2006 and $131.25 million at the end of each quarter in fiscal 2007. However, the amount, type and timing of any additional 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.

Contractual Obligations and Commercial Commitments

Contractual Obligations

The table below shows PacifiCorp’s contractual obligations as of March 31, 2005.

	Payments due during the years ending March 31,

(Millions of dollars)	2006		2007 - 2008		2009 - 2010		Thereafter		Total

Long-term debt, including interest
Fixed-rate obligations	$	480.0	$	715.6	$	867.4	$	3,691.4	$	5,754.4
Variable-rate obligations (a)		12.5		25.0		25.0		663.1		725.6
Short-term debt, including interest		470.0		—		—		—		470.0
Preferred stock subject to mandatory redemption		3.7		48.8		—		—		52.5
Capital leases, including interest		3.3		7.0		7.3		43.1		60.7
Operating leases		21.3		38.0		7.4		9.4		76.1
Asset retirement obligations (b)		17.8		28.7		23.8		319.5		389.8
Power purchase agreements (c)
Electricity commodity contracts		528.2		378.3		53.8		86.4		1,046.7
Electricity capacity contracts		143.2		291.4		294.7		1,254.7		1,984.0
Electricity mixed contracts		22.9		42.8		41.2		236.1		343.0
Transmission		64.2		104.0		92.8		551.2		812.2
Fuel purchase agreements (c)
Natural gas supply and transporation		130.8		317.9		57.6		255.6		761.9
Coal supply and transportation		187.8		359.5		296.3		493.1		1,336.7
Purchase obligations (d)		259.6		83.6		1.8		3.1		348.1
Owned hydroelectric commitments (e)		25.2		34.5		25.2		352.9		437.8
Other long-term liabilities (f)		5.0		8.1		2.4		8.5		24.0

Total contractual cash obligations	$	2,375.5	$	2,483.2	$	1,796.7	$	7,968.1	$	14,623.5

(a)

Consists of principal and interest for pollution-control revenue bond obligations with interest rates scheduled to reset within the next 12 months. Future variable interest rates are set at March 31, 2005 rates. See “Item 7A. Interest Rate Risk” for additional discussion related to variable-rate liabilities.

(b)	Represents expected cash payments adjusted for inflation for estimated costs to perform legally required asset retirement activities.

(c)	Commodity contracts are agreements for the delivery of energy. Capacity contracts are agreements that provide rights to the energy output of a specified facility. Forecasted or other applicable estimated rates were used to determine total dollar value of the commitments for purposes of the table.

(d)	Includes minimum commitments for maintenance, outsourcing of certain services, contracts for software, telephone, data and consulting or advisory services. Also includes contractual obligations for engineering, procurement and construction costs on the Currant Creek and Lake Side Power Plants.

The purchase obligation amounts include only the minimum amount of items for which PacifiCorp is contractually obligated to purchase pursuant to contracts PacifiCorp cannot unilaterally terminate, and do not include the entire amounts that PacifiCorp may purchase in the future. For this reason, the amounts presented in the table will not provide a reliable indicator of PacifiCorp’s expected future cash outflows on a stand-alone basis. For purposes of identifying and accumulating purchase obligations, PacifiCorp has included all contracts meeting the definition of a purchase obligation (e.g., legally binding and specifying all significant terms, including fixed or minimum amount or quantity to be purchased and the approximate timing of the transaction). For those contracts involving a fixed or minimum quantity but variable pricing, PacifiCorp has estimated the contractual obligation based on its best estimate of pricing that will be in effect at the time the obligation is incurred.

(e)

PacifiCorp has entered into settlement agreements with various interested parties to resolve issues necessary to obtain new hydroelectric licenses from the FERC. These settlement agreements generally include clauses that allow for termination of certain of PacifiCorp’s obligations if the FERC license order is not consistent with the settlement agreement. The table only includes contractual obligations made in settlement agreements that are not contingent upon the FERC license being consistent with the settlement agreement and obligations that are required by the FERC licenses. Hydroelectric licenses have varying expiration dates, and several expire within the next five years. The contractual obligations included in the table 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 obligations to continue or increase.

(f)

Includes environmental commitments recorded on the balance sheet, which are contractually or legally binding. Excludes regulatory liabilities and employee benefit plan obligations that are not legally or contractually fixed as to timing and amount. Deferred income taxes are also excluded since cash payments are based primarily on taxable income for each discrete fiscal year.

Commercial Commitments

In September 2004, PacifiCorp entered into a new $296.9 million letter of credit facility with a maturity date of September 14, 2007. This facility provides credit enhancement and liquidity support for seven series of variable-rate pollution-control revenue bond obligations. In connection with the commencement of this new facility, corresponding amounts of previously existing letters of credit were cancelled.

At March 31, 2005, PacifiCorp had $517.8 million of standby letters of credit and standby bond purchase agreements, including the new letter of credit facility, available to provide credit enhancement and liquidity support for variable-rate pollution-control revenue bond obligations. In addition, PacifiCorp had approximately $29.0 million of standby letters of credit to provide credit support for certain transactions as requested by third parties. These committed bank arrangements were all fully available as of March 31, 2005 and expire periodically through the year ending March 31, 2010.

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. Based on current contractual commitments, PacifiCorp’s level of surety bonding beyond the year ended March 31, 2005, is estimated to be approximately $25.2 million. This estimate is based on current information and actual amounts may vary due to rate changes or changes to the general operations of PacifiCorp.

CREDIT RATINGS

PacifiCorp’s credit ratings as of May 27, 2005, are as follows:

	Moody’s	Standard & Poor’s

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	Developing	Stable

On May 25, 2005, Standard & Poor’s Ratings Services placed the corporate credit rating and securities ratings of PacifiCorp on credit watch with negative implications. On May 26, 2005, Moody’s Investors Service affirmed the debt ratings of PacifiCorp and changed the rating outlook to developing from stable.

On March 3, 2005, Moody’s Investors Service revised its outlook on PacifiCorp to stable from negative. On August 18, 2004, Standard & Poor’s Ratings Services revised its outlook on PacifiCorp to stable from negative. At the same time, Standard & Poor’s lowered the senior secured debt rating on PacifiCorp to A- from A. 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 agreement. However, interest rates on loans under the credit agreement 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 credit exposures on a net basis exceed certain negotiated threshold levels. Generally, these threshold levels are based on long-term senior unsecured or corporate ratings. As such, a ratings downgrade could require PacifiCorp to provide additional funds to a counterparty if threshold amounts were exceeded. At March 31, 2005, PacifiCorp estimates that a one level downgrade, by either Moody’s or Standard & Poor’s, of its senior unsecured debt ratings would result in $5.0 million of additional 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 the FASB Interpretation No. 46, Consolidation of Variable-Interest Entities, an interpretation of Accounting Research Bulletin No. 51. See “Item 8. Financial Statements and Supplementary Data - Note 13” 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. Forecasted test periods may be used in some jurisdictions and may include, but are not limited to, projected rate base levels and expenses, which are adjusted for both inflation and known and measurable changes. They may also include projected revenue and power cost changes related to load growth. PacifiCorp is seeking to establish future test periods to deal with the rising cost of service and required capital investment.

RISK FACTORS

The following are certain risks and other factors to be considered when evaluating PacifiCorp. See “Item 7A. Quantitative and Qualitative Disclosures About Market Risk” for a discussion of additional important risks and other factors.

The proposed sale of PacifiCorp could cause regulators, customers, suppliers and other parties with whom PacifiCorp does business to delay or defer decisions, or change existing arrangements, affecting PacifiCorp’s business.

The proposed sale of PacifiCorp will be completed only if stated conditions are met, including approval of the sale by ScottishPower’s shareholders and various federal and state regulatory approvals. Accordingly, there may be uncertainty regarding the completion of the transaction. This uncertainty may cause customers, suppliers and other parties with whom PacifiCorp does business to delay or defer decisions concerning PacifiCorp, which could negatively affect PacifiCorp’s businesses. Such parties may also seek to change existing agreements or arrangements with PacifiCorp as a result of the sale, or may choose not to continue to do business with PacifiCorp. Any such delay or deferral of decisions or changes in existing agreements or arrangements could have a material adverse effect on PacifiCorp’s business regardless of whether the sale is completed. Furthermore, the process of obtaining state regulatory approvals could delay the consideration of the pending general rate case filings and any future regulatory filings. While PacifiCorp intends to pursue general rate increase requests as currently planned, delay of requested rate increases could defer or limit PacifiCorp’s ability to fully recover its operational expenses and the costs of necessary investments.

PacifiCorp is subject to market risk, counterparty performance risk and other risks associated with wholesale energy markets.

In general, market risk is the risk of adverse fluctuations in the market price of wholesale electricity and fuel, including natural gas and coal, which is compounded by volumetric changes affecting the availability of and/or demand for electricity and fuel. PacifiCorp purchases electricity and fuel in the open market or pursuant to short-term or variable-priced contracts as part of its normal operating business. If market prices rise, especially in a time when PacifiCorp requires larger than expected volumes that must be purchased at market or short-term prices, PacifiCorp may have significantly greater expense than anticipated. In addition, PacifiCorp may not be able to timely recover all, if any, of those increased expenses through ratemaking, due to retroactive ratemaking prohibitions, unless deferred accounting has been previously authorized. Likewise, if electricity market prices drop in a period when PacifiCorp is a net seller of electricity in the wholesale market, PacifiCorp will earn less revenue, possibly to the extent of not recovering the cost of generating the electricity. Wholesale electricity prices are 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 generation levels, prices and availability of fuel sources for generation, disruptions or constraints to transmission

facilities, weather conditions, economic growth and changes in technology. Volumetric changes are caused by unanticipated changes in generation availability and/or changes in PacifiCorp’s loads due to the weather, the economy and customer behavior. Although PacifiCorp plans for resources to meet its current and expected retail and wholesale load obligations, PacifiCorp’s net power costs may be adversely impacted by market risk.

PacifiCorp is also exposed to risk related to performance of contractual obligations by its wholesale suppliers and customers. PacifiCorp relies on suppliers to deliver natural gas, coal and electricity, in accordance with short- and long-term contracts. Failure or delay by suppliers to provide natural gas, coal or electricity pursuant to existing contracts could disrupt PacifiCorp’s ability to deliver electricity and require PacifiCorp to incur additional expenses to meet the needs of PacifiCorp’s customers. In addition, as these contractual agreements end, PacifiCorp may not be able to continue to purchase natural gas, coal or electricity on terms equivalent to the terms of current contractual agreements. PacifiCorp relies on wholesale customers to take delivery of the energy they have committed to purchase and paying for the energy on a timely basis. Failure of customers to take delivery may require PacifiCorp to find other customers to take the energy at lower prices than the original customers committed to pay. 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. If the strategy used to hedge the exposure to these risks is ineffective, PacifiCorp could incur significant losses.

PacifiCorp is subject to various operational and event risks.

PacifiCorp faces a number of ongoing operational and event risks, particularly risks arising from the complexity and geographically dispersed nature of its operations. In addition to those highlighted elsewhere in these risk factors, management believes the following operational and event risks are significant:

•	Risks relating to PacifiCorp’s generation facilities:

•

Unscheduled outages at PacifiCorp’s thermal and hydroelectric plants could lead to loss of generating availability; and

•

Shortages in PacifiCorp’s physical fuel supply, including sufficient amounts of natural gas and of coal at a quality required for full generation at PacifiCorp’s coal-fired facilities, could also adversely affect PacifiCorp’s generation output and cost.

•	Risks relating to PacifiCorp’s distribution and transmission system:

•

PacifiCorp’s distribution and transmission system could be adversely affected by catastrophic events such as fires, floods, severe weather, terrorist activities and other emergency conditions that can affect PacifiCorp’s network reliability; and

•

System restrictions, transmission scheduling and capacity limits could also negatively impact the reliability and operation of PacifiCorp’s transmission system.

•	Risks relating to PacifiCorp’s wholesale energy transactions:

•

Any rapid increase in load requirements, particularly if coupled with transmission constraints, could adversely impact PacifiCorp’s ability to meet the energy needs of its customers; and

•

Any rapid decrease in load requirements could result in excess energy that may need to be sold at depressed market prices.

•	Risks relating to PacifiCorp’s information technology:

•

PacifiCorp’s critical information technology systems may suffer unanticipated failures, which could have a material adverse impact on PacifiCorp’s business operations.

•	Risks relating to PacifiCorp’s labor relations:

•

Work stoppages due to labor disputes or PacifiCorp’s inability to attract and retain key personnel and keep available skilled labor, upon which PacifiCorp’s operations rely, could have a material adverse effect on PacifiCorp’s results of operations.

•	Risks relating to PacifiCorp’s security:

•

The failure of PacifiCorp’s security policies and disaster recovery plans to adequately safeguard PacifiCorp’s assets could have a material adverse effect on PacifiCorp’s business operations and, consequently, its results of operations and financial condition.

PacifiCorp attempts to manage these risks through a combination of risk management policies, procedures and prudent operational practices and processes.

Construction of new generating facilities may not be successful and may be adversely affected by numerous factors beyond PacifiCorp’s control.

PacifiCorp is in the process of having new generating facilities constructed in Utah, the Currant Creek and Lake Side Power Plants. As demand and resource availability forecasts change, additional facilities may need to be constructed for or by PacifiCorp. The completion of these facilities without delays or cost overruns is subject to risks, including:

•	the effect of the Stock Purchase Agreement for the sale of PacifiCorp on future resource procurement decisions;

•	changes in regulations or in their interpretation or implementation;

•	shortages and inconsistent quality of equipment, materials and labor;

•	transportation delays for major equipment;

•	work stoppages or delays due to labor disputes, safety violations or accidents;

•	substandard performance or delays by independent contractors;

•	the denial or delay in obtaining permits or approvals or the outcome of other regulatory matters;

•	adverse weather conditions;

•	unforeseen engineering problems;

•	adverse environmental and geological conditions;

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

•	increased costs of raw materials; and

•	other unanticipated cost increases.

In addition, if PacifiCorp is unable to complete the development or construction of a facility, or if PacifiCorp decides to delay or cancel the construction of a facility, PacifiCorp may not be able to recover its investment in that facility. Construction delays and contractor performance shortfalls also 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.

PacifiCorp’s operating results can be adversely affected by weather conditions.

As a result of the geographically diverse area of PacifiCorp’s operations, its service territory has historically experienced complementary seasonal load patterns, weather conditions can significantly affect operating results. For residential customers, within a given year, weather conditions are the dominant cause of usage variations from normal seasonal patterns. For example, in periods of unusually hot summer weather, residential customers tend to use significantly greater amounts of electricity to run air conditioners, which may substantially increase summer peak loads. Changes in weather conditions and other natural events could impact customer behavior and PacifiCorp’s loads. Additionally, a portion of PacifiCorp’s supply of electricity comes from hydroelectric projects that are dependent upon rainfall and snowpack. During or following periods of low rainfall or snowpack, PacifiCorp may obtain substantially less electricity from hydroelectric projects and must purchase greater amounts of electricity from the wholesale market or from other sources at market prices. This could lead to increased costs to PacifiCorp. Accordingly, PacifiCorp’s operating results could be adversely affected by variations in weather conditions.

PacifiCorp’s recovery of costs is subject to regulatory review, and its inability to recover costs may adversely affect its operating income.

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. The FERC also 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. In addition, 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 for purposes of setting that state’s retail rates. 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 established according to that commission’s policies. Certain states use a future test year or allow for escalation of historical costs. In states that use a historical test year, rate adjustments could lag cost increases, or decreases, by up to two years. This regulatory lag causes PacifiCorp to incur costs, including new investments, for which recovery through rates is delayed. In addition, 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, those costs will be disallowed and not recovered in rates. For these reasons, the rates authorized by the regulators may be less than the costs incurred by 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 cannot 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 cannot 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.

PacifiCorp is subject to federal and state legislation, regulations and political risks that may adversely affect its business.

PacifiCorp conducts its business in conformance with a multitude of federal and state laws. During the past several years, the United States Congress has had, and continues to have, under active consideration, significant changes in energy and air quality policy. For example, comprehensive energy legislation could possibly change the hydroelectric relicensing process under the Federal Power Act, repeal the PUHCA and encourage investment in renewable and lower-emission coal generation. In late calendar 2004, an extension of the renewable energy production tax credit was enacted so that projects placed in service before January 1, 2006, are eligible for the production tax credit. The President has proposed a further extension of the credit, for two years, and Congress is expected to act on that proposal in whole or in part during calendar 2005. Changes to the Clean Air Act have been proposed in the form of the President’s Clear Skies Act. Other bills seek to limit emissions of carbon dioxide, as well as to impose further stringent limits on already regulated emissions such as sulfur dioxide and oxides of nitrogen. The Senate Environment and Public Works Committee has been deadlocked on the Clear Skies Act and other proposals, and statutory changes to the Clean Air Act may not be enacted this calendar year. The Clear Skies Act and other air quality initiatives could require additional control of emissions from PacifiCorp’s fossil-fueled generation plants, which would increase PacifiCorp’s costs or lower electricity generation output.

Part of the President’s budget for federal fiscal 2006 is a proposal to change over time the basis for setting certain wholesale electricity rates of the federal Power Marketing Administration from cost to market. This change, if adopted, likely would reduce the size of the residential and small-farm exchange benefit and consequently increase electricity bills for many PacifiCorp customers in Oregon, Washington and Idaho. PacifiCorp is currently required to pass the value of the exchange benefit directly on to participating customers, so any reduction in the benefit proportionately increases the rates PacifiCorp charges these customers. PacifiCorp customers in all six states may experience an increase in costs as a result. The actual impacts of this change, if enacted, on consumers and PacifiCorp are difficult to predict because they would depend on future market prices as well as on how any change is implemented. Given the level of opposition to this plan from members of Congress from the Pacific Northwest states, PacifiCorp currently believes it is unlikely that the Congress will adopt the legislation necessary to effect the proposed change in pricing of Power Marketing Administration’s electricity.

Legislation reauthorizing a series of federal surface transportation programs recently passed the House of Representatives and is now pending before the Senate. The bill exempts utility service vehicles from hours of service rules. Utilities have been under a temporary enforcement moratorium. Application of significant new limits on hours of service would hamper the ability of utilities to address service problems on a timely basis and could result in higher operational costs.

Generally, PacifiCorp provides electric service to retail consumers on an exclusive basis in service territory defined by state and local laws and franchise agreements. From time to time, local disputes arise over territory boundaries, particularly with respect to serving new customers. PacifiCorp faces a small number of local service controversies. In Washington, PacifiCorp and Columbia Rural Electric Association have service disagreements over a small number of new as well as existing customers in areas where there is not an exclusive local franchise. Efforts to resolve these disagreements through negotiations did not reach a successful conclusion, and state legislation establishing a formal dispute resolution process stalled in the House of Representatives. In Oregon, some customers in Klamath County have expressed an interest in forming a People’s Utility District, which under Oregon law requires an affirmative vote of the people in the affected area to proceed. The Oregon Legislature may consider changes to state statutes governing the formation of a People’s Utility District during its 2005 general session. PacifiCorp cannot predict whether the Legislature will act on such legislation or what impact any statutory changes may have on the likelihood of the formation of a People’s Utility District.

The Oregon legislature is considering a proposal to prohibit electric and gas utilities operating in Oregon from filing state income tax returns on a consolidated basis with their parent and affiliate companies. Although enactment of proposed or similar legislation would not affect the level of PacifiCorp’s income tax expense, if PacifiCorp is required to file its Oregon income tax return on a stand-alone basis, PacifiCorp could potentially pay greater Oregon state income taxes than otherwise payable by its parent company, PHI, which files its tax returns on a consolidated basis.

Threats or acts of terrorism could negatively impact PacifiCorp’s business.

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 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. Although PacifiCorp has taken steps to mitigate threats from terrorism, any terrorist attack could have a material adverse effect on PacifiCorp’s business operations and, consequently, its results of operations and financial position.

Declines in the availability, or increases in the cost, of PacifiCorp’s insurance policies and increases in self-insurance levels could result in material liabilities and costs, which could have a material adverse effect on PacifiCorp’s results of operations or financial position.

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 modified as insurance market conditions and other factors change.

PacifiCorp’s insurance program was reviewed during fiscal 2005. No significant changes have been made to the range of coverages purchased from commercial insurers, and PacifiCorp believes the limits of coverage and level of deductibles are 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.

The energy insurance market has continued to show mixed trends in pricing over the past year. For property insurance, there has been a general decrease in premiums, although the extent of decreases has shown signs of leveling off. Other classes of insurance are still experiencing upward pressure on premiums. PacifiCorp has worked closely with its insurance advisors and insurers to maintain efficiencies and long-term stability in premium costs. 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.

Poor investment performance of pension plan holdings and other factors impacting pension plan costs could unfavorably impact PacifiCorp’s liquidity and results of operations.

As a result of the continuing recognition of losses from the decline in the equity markets from 2000 to 2002, 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 expense levels since PacifiCorp’s pension liability increases as the discount rate declines. Increased expenses or cash funding obligations could have a material impact on PacifiCorp’s liquidity by reducing its cash flows and negatively affecting its results of operations.

PacifiCorp has a substantial amount of debt, which could adversely affect its ability to obtain future financing and limit its expenditures.

As of March 31, 2005, PacifiCorp had approximately $4.3 billion in total debt securities outstanding. PacifiCorp’s principal financing agreements contain restrictive covenants that limit PacifiCorp’s ability to borrow funds. PacifiCorp expects that it will be necessary to supplement cash generated from operations, additional equity from PHI as required by the Stock Purchase Agreement with MidAmerican, and availability under committed credit facilities with new issuances of long-term debt. However, if market conditions are not favorable for the issuance of long-term debt, it may be necessary for PacifiCorp to postpone planned capital expenditures, or take other actions, to the extent those expenditures are not fully covered by cash from operations, or additional PHI equity, and not available under committed credit facilities. In addition, the sale of all of PacifiCorp’s common stock by PHI to MidAmerican would constitute an event of default under certain of PacifiCorp’s financing agreements. If PacifiCorp is unable to obtain waivers of such default or amendments to those agreements or arrange replacement facilities and the sale is completed, the lenders may accelerate PacifiCorp’s outstanding indebtedness and exercise their other rights under these agreements.

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 risk management committees that are responsible for the oversight of market and credit risk relating to the commodity transactions of PacifiCorp. To limit PacifiCorp’s exposure to market risk, the risk forum 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 credit committee regularly reviews counterparty credit exposure, as well as credit policies and limits.

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 and procedures. The risk management policy governs energy transactions and is designed for hedging PacifiCorp’s existing energy and asset exposures, and to a limited extent, the policy permits arbitrage activities to take advantage of market inefficiencies. The policy and procedures also govern PacifiCorp’s use of derivative instruments for commodity derivative transactions, as well as its energy purchase and sales practices, and describe 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 similar volume or price relationship to 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 actively manage commodity price volatility and reduce exposure. These activities may include adding to the generation portfolio and entering into transactions that help to shape PacifiCorp’s system resource portfolio, including wholesale contracts and financially settled temperature-related derivative instruments that reduce volume and price risk due to weather extremes.

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 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, 2005 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	83.2	%
Non-investment grade - Externally rated	0.5
Investment grade - Internally rated	4.5
Non-investment grade - Internally rated	11.8

	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 internally developed, commercially appropriate rating methodologies and credit scoring models to develop a public rating equivalent.

The “Non-investment grade – Internally rated” component of PacifiCorp’s overall credit exposure increased during the year ended March 31, 2005, due to a rise in forward electricity prices at certain points of delivery, which increased the market value of the contracts with a small number of non-investment grade counterparties. These contracts support PacifiCorp’s Integrated Resource Plan and compliance with a FERC regulatory order requiring PacifiCorp to purchase power from qualifying facilities.

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, 2005, PacifiCorp had $1,010.5 million of variable-rate liabilities and $182.2 million of temporary cash investments. At March 31, 2005, PacifiCorp had no financial derivatives in effect relating to interest rate exposure.

Based on a sensitivity analysis as of March 31, 2005, for a one-year horizon, PacifiCorp estimates that if market interest rates average 1.0% higher (lower) in fiscal 2006 than in fiscal 2005, interest expense, net of offsetting impacts on interest income, would increase (decrease) by $8.3 million. Comparatively, based on a sensitivity analysis as of March 31, 2004, for a one-year horizon, had interest rates averaged 1.0% higher (lower) in fiscal 2005 than in fiscal 2004, PacifiCorp estimated that interest expense, net of offsetting impacts in interest income, would have increased (decreased) by $6.2 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, 2005 and 2004. The increase in interest rate sensitivity is primarily due to the increase in outstanding variable-rate commercial paper, partially offset by the increase in invested cash. If interest rates change 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, electricity demand and plant performance, that affect 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 generation plants, with a net capability of 7,981.4 MW, as well as transmission rights held both on some of its own 15,530-mile transmission system and on third-party transmission systems, 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 time periods. 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 financially settled hydroelectric streamflow hedge is in place through September 2006 to reduce volume and price risks associated with PacifiCorp’s hydroelectric generation resources.

PacifiCorp measures the market risk in its electricity and natural gas portfolio daily utilizing a historical Value at Risk (“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 quantity 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 (holding) 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 possible changes at a given level of confidence 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 business 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. These options provide for energy volume changes that are sensitive 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, 2005, 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 $15.5 million, as measured by the VaR computations described above, compared to $16.0 million as of March 31, 2004. The minimum, average and maximum daily VaR (five-day holding periods) for the years ended March 31, 2005 and 2004 are as follows:

	Years Ended March 31,

(Millions of dollars)	2005		2004

Maximum VaR (measured)	$	26.3	$	23.3
Average VaR (calculated)		16.6		14.3
Minimum VaR (measured)		10.6		7.9

PacifiCorp maintained compliance with its VaR limit procedures during the year ended March 31, 2005. Changes in markets inconsistent with historical trends or assumptions used could cause actual results to exceed estimates.

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, 2004, to March 31, 2005, and quantifies the reasons for the changes.

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

	Trading			Non-trading

Fair value of contracts outstanding at March 31, 2004	$	(0.5	)	$	(414.3	)	$	422.2
Contracts realized or otherwise settled during the period		0.3			(39.2	)		42.6
Changes in fair values attributable to changes in valuation techniques and assumptions (a)		—			(27.2	)		27.2
Other changes in fair values (b)		0.4			326.3			(322.0	)

Fair value of contracts outstanding at March 31, 2005	$	0.2		$	(154.4	)	$	170.0

(a)

Effective September 30, 2004, PacifiCorp changed to a U.S. London Interbank Offered Rate (LIBOR) from the U.S. Treasury rate for discounting the portfolio. This change had the effect of increasing the fair value of non-trading contracts by $25.5 million, offset by a decrease in regulatory net assets by the same amount.

Effective March 31, 2005, PacifiCorp adjusted its estimate of the period covered by market quotes from three years to six years due to the increased availability of verifiable market quotations. This change had the effect of decreasing the fair value of non-trading contracts by $52.7 million, offset by an increase in regulatory net assets by the same amount.

(b)	Other changes in fair values include the effects of changes in market prices, inflation rates and interest rates, including those based on models, on new and existing contracts for the year ended March 31, 2005.

(c)	Contracts that have received commission approval for regulatory recovery are included as a Regulatory Net Asset (Liability).

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. As noted above, price quotations for certain major electricity trading hubs are generally readily obtainable for the first six 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 six years, the forward price curve (beyond the first six years) 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 electricity 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 and option components. Forward 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 evaluations and refinements 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, 2005.

	Fair Value of Contracts at Period-End

(Millions of dollars)	Maturity Less Than 1 Year			Maturity 1-3 Years			Maturity 4-5 Years			Maturity in Excess of 5 Years			Total Fair Value

Trading:
Values based on quoted market prices from third-party sources	$	0.2		$	—		$	—		$	—		$	0.2
Values based on models and other valuation methods		—			—			—			—			—

Total trading	$	0.2		$	—		$	—		$	—		$	0.2

Non-trading:
Values based on quoted market prices from third-party sources	$	(213.0	)	$	(262.5	)	$	(38.9	)	$	(16.8	)	$	(531.2	)
Values based on models and other valuation methods		328.8			379.3			(7.3	)		(324.0	)		376.8

Total non-trading	$	115.8		$	116.8		$	(46.2	)	$	(340.8	)	$	(154.4	)

Standardized derivative contracts that are valued using market quotations are classified as “values 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 “values based on models and other valuation methods.” Both classifications utilize market curves as appropriate for the first six years.

PacifiCorp has executed a contract to hedge changes in hydroelectric generation due to variation in streamflows. This contract is 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 this contract in accordance with EITF No. 99-2, Accounting for Weather Derivatives. The net asset (liability) recorded for this contract was $20.3 million at March 31, 2005, and $(5.3) million at March 31, 2004. PacifiCorp recognized a gain of $27.9 million for the year ending March 31, 2005, a gain of $0.4 million for the year ended March 31, 2004, and no gain or loss for the year ended March 31, 2003. The gain increased during the year ended March 31, 2005, due to the unusually dry weather conditions experienced during the current year.

ITEM 8.

FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

		Page

Index to Consolidated Financial Statements:
Report of Independent Registered Public Accounting Firm		63
Statements of Consolidated Income for the Years Ended March 31, 2005, 2004 and 2003		64
Consolidated Balance Sheets as of March 31, 2005 and 2004		65
Statements of Consolidated Cash Flows for the Years Ended March 31, 2005, 2004 and 2003		67
Statements of Consolidated Changes in Common Shareholder’s Equity for the Years Ended March 31, 2005, 2004 and 2003		68
Notes to the Consolidated Financial Statements		69

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 consolidated statements of 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, 2005 and 2004, and the results of their operations and their cash flows for each of the three years in the period ended March 31, 2005, 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, PacifiCorp changed the manner in which it applies the normal purchases and normal sales exception to derivative contracts entered into or modified after June 30, 2003, upon its adoption of SFAS No. 149, Amendment of Statement 133 on Derivative Instruments and Hedging Activities, as of July 1, 2003.

As discussed in Note 6 to the consolidated financial statements, PacifiCorp 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, PacifiCorp 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 27, 2005

PACIFICORP AND SUBSIDIARIES

STATEMENTS OF CONSOLIDATED INCOME

(Millions of dollars)	Years Ended March 31,

	2005			2004			2003

Revenues:
Residential	$	1,004.6		$	994.5		$	914.7
Commercial		833.1			792.9			763.4
Industrial		774.8			725.6			699.2
Other retail		36.3			34.0			31.4
Wholesale sales and other		400.0			647.5			673.7

Total		3,048.8			3,194.5			3,082.4

Operating expenses:
Purchased electricity		448.0			672.8			698.5
Fuel		500.0			483.9			482.2
Operations and maintenance		913.1			895.8			885.1
Depreciation and amortization		436.9			428.8			434.3
Taxes, other than income taxes		94.4			95.3			93.4

Total		2,392.4			2,576.6			2,593.5

Income from operations		656.4			617.9			488.9

Interest expense and other (income) expense:
Interest expense		267.4			256.5			270.3
Interest income		(9.1	)		(13.8	)		(21.6	)
Interest capitalized		(14.8	)		(19.9	)		(18.0	)
Minority interest and other		(7.3	)		1.6			19.0

Total		236.2			224.4			249.7

Income from operations before income tax expense and cumulative effect of accounting change		420.2			393.5			239.2
Income tax expense		168.5			144.5			97.2

Income before cumulative effect of accounting change		251.7			249.0			142.0
Cumulative effect of accounting change (less applicable income tax benefit of $(0.6)/2004 and $(1.1)/2003		—			(0.9	)		(1.9	)

Net income		251.7			248.1			140.1
Preferred dividend requirement		(2.1	)		(3.3	)		(7.3	)

Earnings on common stock	$	249.6		$	244.8		$	132.8

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

PACIFICORP AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Millions of dollars)

	March 31,

	2005			2004

ASSETS

Current assets:
Cash and cash equivalents	$	199.3		$	58.5
Accounts receivable less allowance for doubtful accounts of $11.6/2005 and $23.3/2004		293.0			235.1
Unbilled revenue		143.8			127.8
Amounts due from affiliates		36.5			2.4
Inventories at average costs:
Materials and supplies		114.7			101.0
Fuel		58.5			56.0
Current derivative contract asset		252.7			118.9
Current deferred tax asset		—			31.5
Other		115.8			25.2

Total current assets		1,214.3			756.4


Property, plant and equipment:
Generation		5,238.7			5,135.7
Transmission		2,507.7			2,439.2
Distribution		4,308.7			4,104.7
Intangible plant		607.0			599.5
Other		1,596.9			1,533.7
Construction work-in-progress		593.4			345.4

Total		14,852.4			14,158.2
Accumulated depreciation and amortization		(5,361.8	)		(5,121.7	)

Total property, plant and equipment - net		9,490.6			9,036.5


Other assets:
Regulatory assets		972.8			1,032.3
Derivative contract regulatory asset		170.0			422.2
Non-current derivative contract asset		360.3			110.3
Deferred charges and other		312.9			319.4

Total other assets		1,816.0			1,884.2

Total assets	$	12,520.9		$	11,677.1

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

PACIFICORP AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS, continued

(Millions of dollars)

	March 31,

	2005			2004

LIABILITIES AND SHAREHOLDERS’ EQUITY

Current liabilities:
Accounts payable	$	350.4		$	262.6
Amounts due to affiliates		3.9			2.6
Accrued employee expenses		134.3			131.5
Taxes payable		39.8			54.2
Interest payable		64.8			66.1
Current derivative contract liability		136.7			76.9
Current deferred tax liability		2.0			—
Long-term debt and capital lease obligations, currently maturing		269.9			240.0
Preferred stock subject to mandatory redemption, currently maturing		3.7			3.7
Notes payable and commercial paper		468.8			124.9
Other		123.4			111.8

Total current liabilities		1,597.7			1,074.3


Deferred credits:
Deferred income taxes		1,629.0			1,564.6
Investment tax credits		75.6			83.5
Regulatory liabilities		806.0			807.5
Non-current derivative contract liability		630.5			567.1
Pension liability		422.4			398.9
Other		304.8			284.7

Total deferred credits		3,868.3			3,706.3


Long-term debt and capital lease obligations, net of current maturities		3,629.0			3,520.2
Preferred stock subject to mandatory redemption, net of current maturities		48.8			56.3

Total liabilities		9,143.8			8,357.1

Commitments, contingencies and guarantees (See Notes 10 and 11)

Shareholders’ equity:
Preferred stock		41.3			41.3

Common equity:
Common shareholder’s capital		2,894.1			2,892.1
Retained earnings		446.4			390.1
Accumulated other comprehensive income (loss):
Unrealized gain on available-for-sale securities, net of tax of $2.6/2005 and $2.7/2004		4.3			4.5
Minimum pension liability, net of tax of $(5.5)/2005 and $(4.9)/2004		(9.0	)		(8.0	)

Total common equity		3,335.8			3,278.7

Total shareholders’ equity		3,377.1			3,320.0

Total liabilities and shareholders’ equity	$	12,520.9		$	11,677.1

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,

	2005			2004			2003

Cash flows from operating activities:
Net income	$	251.7		$	248.1		$	140.1
Adjustments to reconcile net income to net cash provided by operating activities:
Cumulative effect of accounting change, net of tax		—			0.9			1.9
Unrealized gain on derivative contracts		(8.4	)		(6.1	)		(3.1	)
Depreciation and amortization		436.9			428.8			434.3
Deferred income taxes and investment tax credits - net		120.0			80.5			31.8
Regulatory asset/liability establishment and amortization		66.7			111.1			146.8
Other		(27.0	)		(6.5	)		3.4
Changes in:
Accounts receivable, prepayments and other current assets		(137.8	)		(1.7	)		7.6
Inventories		(16.2	)		14.1			(17.8	)
Amounts due to/from affiliates, net		(32.8	)		(36.8	)		32.5
Accounts payable and accrued liabilities		84.1			(3.3	)		(97.1	)
Other		(26.1	)		2.8			1.2

Net cash provided by operating activities		711.1			831.9			681.6

Cash flows from investing activities:
Capital expenditures		(851.6	)		(690.4	)		(550.0	)
Proceeds from sales of assets		7.1			3.3			16.3
Proceeds from available-for-sale securities		49.1			95.8			132.9
Purchases of available-for-sale securities		(44.7	)		(89.4	)		(134.3	)
Other		(6.6	)		(22.8	)		10.0

Net cash used in investing activities		(846.7	)		(703.5	)		(525.1	)


Cash flows from financing activities:
Changes in short-term debt		343.9			99.9			(152.5	)
Proceeds from long-term debt, net of issuance costs		395.2			396.7			—
Proceeds from issuance of common stock to PHI		—			—			150.0
Dividends paid		(195.4	)		(165.1	)		(7.3	)
Repayments and redemptions of long-term debt		(259.8	)		(194.1	)		(144.6	)
Repayment of preferred securities		—			(352.0	)		—
Redemptions of preferred stock		(7.5	)		(7.5	)		(7.5	)
Other		—			(0.3	)		—

Net cash provided by (used in) financing activities		276.4			(222.4	)		(161.9	)

Change in cash and cash equivalents		140.8			(94.0	)		(5.4	)
Cash and cash equivalents at beginning of period		58.5			152.5			157.9

Cash and cash equivalents at end of period	$	199.3		$	58.5		$	152.5

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
	Common Shareholder’s Capital			Retained			Accumulated Other Comprehensive			Total Comprehensive
	Shares		Amounts	Earnings			Income (Loss)			Income (Loss)

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

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 PHI	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 ($0.51 per share)	—		—		(160.6	)		—			—

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


Comprehensive income
Net income	—		—		251.7			—		$	251.7
Other comprehensive loss:
Unrealized loss on available-for-sale securities, net of tax of $(0.1)	—		—		—			(0.2	)		(0.2	)
Minimum pension liability, net of tax of $(0.6)	—		—		—			(1.0	)		(1.0	)
Stock-based compensation expense	—		2.0		—			—			—
Cash dividends declared:
Preferred stock	—		—		(2.1	)		—			—
Common stock ($0.62 per share)	—		—		(193.3	)		—			—

Balance at March 31, 2005	312,176	$	2,894.1	$	446.4		$	(4.7	)	$	250.5

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 serving retail customers in portions of 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 services.

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.

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.

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.

Reclassifications - Certain reclassifications of prior years’ amounts have been made to conform to the 2005 method of presentation. These reclassifications had no effect on previously reported consolidated net income.

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 include retail and wholesale customers, government agencies and other utilities. Management performs continuing credit evaluations of customers’ financial conditions, 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, typically 30 days after the invoice date. PacifiCorp charges interest on delinquent customer accounts or past due balances in the states where PacifiCorp does business based on the respective regulation of that state, and this interest varies between 1.0% to 1.5% per month.

Management reviews accounts receivable on a monthly basis to determine if any receivable will potentially be uncollectible. The allowance for doubtful accounts includes amounts estimated through an evaluation of specific accounts, based upon the best available facts and circumstances, of customers that may be unable to meet their financial obligations, 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, 2005, was adequate. However, actual write-offs could exceed the recorded allowance. The allowance activity was as follows:

	Years Ended March 31,

(Millions of dollars)	2005			2004			2003

Beginning balance	$	23.3		$	31.1		$	34.8
Charged to costs and expenses		5.0			5.2			10.6
Write-offs, net		(16.7	)		(13.0	)		(14.3	)

Ending balance	$	11.6		$	23.3		$	31.1

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. Annual overhead costs for the replacement of defined retirement units are capitalized. Generally other costs of overhaul activities and other repairs and maintenance are expensed as they are incurred.

Intangible plant consists primarily of computer software costs. Accumulated amortization on Intangible plant was $307.6 million and $310.0 million at March 31, 2005 and 2004. Amortization expense on Intangible plant was $48.5 million and $54.7 million for the years ended March 31, 2005 and 2004. The estimated aggregate amortization on Intangible plant for the next five succeeding fiscal years from fiscal 2006 to fiscal 2010 is $44.3 million, $39.2 million, $32.6 million, $25.1 million and $18.8 million. Unamortized computer software costs were $185.1 million at March 31, 2005, and $194.8 million at March 31, 2004.

Depreciation and amortization - The average 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 costs included in Intangible plant are initially assigned a depreciable life of 5 to 10 years.

During the year ended March 31, 2005, PacifiCorp changed the estimated average lives of certain computer software systems to reflect operational plans. This change reduced amortization expense by $12.9 million annually on existing computer software systems, with an annual impact to net income of approximately $8.0 million.

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, 2005, 3.0% for the year ended March 31, 2004, and 3.2% for the year ended March 31, 2003.

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”). 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 4.5% for the year ended March 31, 2005, 7.9% for the year ended March 31, 2004, and 7.2% for the year ended March 31, 2003. PacifiCorp’s AFUDC rates do not exceed the maximum allowable rates determined by regulatory authorities.

Derivatives - In accordance with SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, (“SFAS No. 133”), as amended by 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”), 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 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 that 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 and other revenues or Purchased electricity in the Statements of Consolidated Income when the contracts settle.

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 purchase and re-evaluates such classification as of each balance sheet date. As shown in Note 5, at March 31, 2005 and 2004, all of PacifiCorp’s investments in marketable securities were classified as available-for-sale and were reported at fair value. 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 Other (income) expense. Unrealized gains and losses are reported as a component of Accumulated other comprehensive income (loss). Investments that are in loss positions as of the end of each reporting period are analyzed to determine whether they have experienced a decline in market value that is considered other-than-temporary. An investment will generally be written down to market value if it has a significant unrealized loss for more than nine months. If additional information is available that indicates an investment is other-than-temporarily impaired, it will be written down prior to the nine-month time period. In the alternative, if an investment has been impaired for more than nine months but available information indicates that the impairment is temporary, the investment will not be written down.

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 Obligations (“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. In general, depreciation and accretion expense generated by SFAS No. 143 accounting is recorded as a regulatory asset or liability because such amounts are recoverable in rates.

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 dates, the fair value of the associated liabilities 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 recovers through approved depreciation rates estimated removal costs and accumulates such amounts in Asset retirement removal costs within Regulatory liabilities as described in 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 PacifiCorp Holdings, Inc. (“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 PHI.

Historically, PacifiCorp did not recognize 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 19.

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 if the ultimate number of shares to be awarded is known at the date of the grant. All options are issued in Scottish Power plc (“ScottishPower”) American Depository Shares, as discussed in Note 18. 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)	2005			2004			2003


Net income as reported	$	251.7		$	248.1		$	140.1
Add: stock-based compensation using the intrinsic value method, net of related tax effects		3.1			—			—
Less: stock-based compensation expense using the fair value method, net of related tax effects		(4.3	)		(1.1	)		(1.6	)

Pro forma net income	$	250.5		$	247.0		$	138.5

The $3.1 million of stock-based compensation expense presented net of tax under the intrinsic value method in the above table represents estimated expense associated with the Executive Share Option Plan 2001 (the “ExSOP”), the deferred share program and the Long-Term Incentive Plan described in Note 18.

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 $143.8 million at March 31, 2005 and $127.8 million at March 31, 2004. Electricity sales to wholesale customers are recorded upon delivery.

Segment information - PacifiCorp currently has one segment, which includes the regulated retail and wholesale electric operations.

New accounting standards -

FSP SFAS No. 106-2

In May 2004, the Financial Accounting Standards Board (the “FASB”) released FASB Staff Position (“FSP”) SFAS No. 106-2, Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (“FSP SFAS No. 106-2”). FSP SFAS No. 106-2 provides guidance on the accounting for the effects of the Medicare Prescription Drug Improvement and Modernization Act of 2003 (the “Medicare Act”). The Medicare Act introduced a prescription drug benefit under Medicare, as well as a federal subsidy to sponsors of retiree health care plans that include prescription drug benefits. Employers that sponsor postretirement health care plans that offer prescription drug benefits must determine if their prescription drug benefits are actuarially equivalent to the drug benefit provided under Medicare Part D as of the date of enactment of the Medicare Act to be entitled to receive the subsidy. Employers are required to disclose the effect of the federal subsidy afforded by the Medicare Act if its prescription drug benefits are determined to be actuarially equivalent to the Medicare Part D benefit. FSP SFAS No. 106-2 was effective for the first interim or annual period beginning after June 15, 2004. PacifiCorp elected to adopt FSP SFAS No. 106-2 early upon its release with retroactive application to PacifiCorp’s Welfare Benefits Plan December 31, 2003 measurement date. Because that measurement date is used only to determine net periodic postretirement benefit cost for the period beginning April 1, 2004, there was no impact on previously reported information. The effects of the Medicare Act decreased PacifiCorp’s accumulated postretirement benefit obligation by $42.6 million. This decrease is treated as an actuarial experience gain. This actuarial experience gain reduces the unrecognized net loss resulting from differences in prior periods between actuarial assumptions and actual experience. The actuarial experience gain will be amortized to expense through a decrease in the amortization of the unrecognized net loss. The effects of the Medicare Act decreased net periodic postretirement benefit cost for the year ended March 31, 2005, when compared to the expense calculated before the adoption of FSP SFAS No. 106-2, as follows:

(Millions of dollars)	Year Ended March 31, 2005

Decrease in:
Interest cost	$	2.7
Service cost		0.1
Amortization of unrecognized loss		2.9

Decrease in Net periodic postretirement benefit cost	$	5.7

EITF No. 03-1 and FSP EITF No. 03-1-1

In September 2004, the FASB issued FSP EITF No. 03-1-1, Effective Date of Paragraphs 10-20 of EITF No. 03-1, The Meaning of Other-Than-Temporary Impairment and Its Application to Certain Investments (“FSP EITF No. 03-1-1”). FSP EITF No. 03-1-1 delayed the previously required effective date of July 1, 2004, for PacifiCorp regarding the measurement and recognition guidance contained in the applicable paragraphs. The delay of the effective date is likely to be superceded with the final issuance of an FSP on other-than-temporary impairment of investments. The adoption of the measurement and recognition guidance of EITF No. 03-1, if implemented in its present form, is not anticipated to have a material impact on PacifiCorp’s consolidated financial position or results of operations.

SFAS No. 151

In November 2004, the FASB issued SFAS No. 151, Inventory Costs (“SFAS No. 151”), which amends Accounting Research Bulletin No. 43, Chapter 4, Inventory Pricing. SFAS No. 151 requires that abnormal amounts of idle facility expense, freight, handling costs and wasted material (spoilage) be included as current-period charges, eliminating the option for capitalization. This statement is effective for inventory costs that PacifiCorp incurs on or after April 1, 2006. PacifiCorp does not typically incur abnormal costs related to inventory balances; therefore, the adoption of this statement is not anticipated to have a material impact on PacifiCorp’s consolidated financial position or results of operations.

SFAS No. 153

In December 2004, the FASB issued SFAS No. 153, Exchanges of Non-monetary Assets (“SFAS No. 153”), which amends APB Opinion No. 29, Accounting for Non-monetary Transactions (“APB No. 29”). SFAS No. 153 eliminates the exception from fair value measurement for non-monetary exchanges of similar productive assets in APB No. 29 and replaces it with an exception for exchanges that do not have commercial substance. This statement specifies that a non-monetary exchange has commercial substance if the future cash flows of the entity are expected to change significantly as a result of the exchange. The provisions in this statement will apply to PacifiCorp for any exchanges of non-monetary assets that occur on or after April 1, 2006. The adoption of this statement is not expected to have a material impact on PacifiCorp’s consolidated financial position or results of operations.

SFAS No. 123R and SAB No. 107

In December 2004, the FASB issued SFAS No. 123R, Share-Based Payment (“SFAS No. 123R”), a revision of the originally issued SFAS No. 123. SFAS No. 123R establishes standards for the accounting for transactions in which an entity exchanges its equity instruments for goods or services. In March 2005, the Securities and Exchange Commission (“SEC”) issued Staff Accounting Bulletin (“SAB”) No. 107 (“SAB No. 107”), which provides additional guidance in applying the provisions of SFAS No. 123R. SFAS No. 123R requires that the cost resulting from all share-based payment transactions be recognized in the financial statements using the fair value method. The intrinsic value method of accounting established by APB No. 25 will no longer be allowed. SAB No. 107 describes the SEC Staff’s guidance in determining the assumptions that underlie the fair value estimates and discusses the interaction of SFAS No. 123R with other existing SEC guidance.

FSP SFAS No. 109-1

In December 2004, the FASB issued FSP SFAS No. 109-1, Application of FASB Statement No. 109, Accounting for Income Taxes, to the Tax Deduction on Qualified Production Activities Provided by the American Jobs Creation Act of 2004. This tax deduction will be treated as a “special deduction” as described in SFAS No. 109, Accounting for Income Taxes. As such, the special deduction has no effect on deferred tax assets and liabilities existing at the enactment date. Rather, the impact of this deduction will be reported in the period in which the deduction could be claimed on a separate return basis in accordance with PacifiCorp’s accounting policy. This statement became effective upon issuance. The impact of the deduction to PacifiCorp will depend on the application of forthcoming guidance from the Internal Revenue Service to PacifiCorp’s future qualifying electric generation activities and cannot be estimated at this time.

FIN 47

In March 2005, the FASB issued FASB Interpretation No. 47, Accounting for Conditional Asset Retirement Obligations – an Interpretation of FASB Statement No. 143 (“FIN 47”). FIN 47 clarifies that the term “conditional asset retirement obligation” as used in SFAS No. 143 refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity. The obligation to perform the asset retirement activity is unconditional even though uncertainty exists about the timing and/or method of settlement. FIN 47 clarifies that an entity is required to recognize a liability for the fair value of a conditional asset retirement obligation when incurred if the liability’s fair value can be reasonably estimated. FIN 47 is effective at the end of the fiscal year ending after December 15, 2005. PacifiCorp is currently evaluating the impact of adopting FIN 47 on its consolidated financial position and results of operations.

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, 2005, PacifiCorp had recorded specifically identified net regulatory assets of $336.8 million. In the event PacifiCorp stopped applying SFAS No. 71 at March 31, 2005, an after-tax loss of approximately $208.9 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 a specific 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 with respect 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)	2005		2004

Deferred income taxes	$	499.9	$	519.1
Minimum pension liability		280.7		226.2
Unamortized issuance expense on retired debt		34.6		40.6
Demand-side resource costs		25.5		40.1
Transition plan - retirement and severance		24.9		38.2
Various other costs		107.2		168.1

Subtotal		972.8		1,032.3
Derivative contracts (a)		170.0		422.2

Total	$	1,142.8	$	1,454.5

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

At March 31, 2005, PacifiCorp had $1,095.6 million of regulatory assets not accruing carrying charges. Of this amount, $170.0 million of regulatory assets for derivative contracts were offset by like amounts of derivative instrument contract liabilities. Additionally, $280.7 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 $499.9 million, representing accelerated tax benefits previously flowed through to ratepayers, which will be included in rates concurrently with recognition of the associated tax expense.

Regulatory liabilities include the following:

	March 31,

(Millions of dollars)	2005		2004

Asset retirement removal costs (a)	$	689.3	$	670.6
Gain on sale of Centralia plant		15.8		43.7
Deferred income taxes		44.4		36.2
Various other costs		56.5		57.0

Total	$	806.0	$	807.5

(a)	Represents removal costs recovered in rates that do not qualify as asset retirement obligations under SFAS No. 143.

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, report, manage and mitigate each of the various types of risk involved in its business and activities, to measure quantitative market risk exposure and to 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 transactions and is designed for hedging PacifiCorp’s existing energy and asset exposures, and to a limited extent the policy permits arbitrage activities to take advantage of market inefficiencies. The policy also governs PacifiCorp’s use of derivative instruments for commodity derivative transactions, 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 similar volume or price relationship to 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.

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 Derivatives Implementation Group (“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 Derivative contract 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.

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 Accounting for Derivative Instruments and Hedging Activities, and Not Held for Trading Purposes (“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 during the year ended March 31, 2004, resulted in PacifiCorp netting certain contracts that were previously recorded on a gross basis in Wholesale sales and other revenues and Purchased electricity expense. The adoption of EITF No. 03-11 had no impact on PacifiCorp’s consolidated Net income and all periods presented are consistent with the requirements of EITF 03-11.

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.

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.

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 and other revenues. 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 other revenues and Purchased electricity expense in the Consolidated Statements of Income.

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 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. This contract is 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 this contract in accordance with EITF No. 99-2, Accounting for Weather Derivatives. The net asset (liability) recorded for this contract was $20.3 million at March 31, 2005, and $(5.3) million at March 31, 2004. PacifiCorp recognized a gain of $27.9 million for the year ended March 31, 2005, a gain of $0.4 million for the year ended March 31, 2004, and no gain or loss for the year ended March 31, 2003. The gain increased during the year ended March 31, 2005, due to the unusually dry weather conditions experienced during the current year.

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 historical 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 prevailing market 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.

PacifiCorp has entered into master netting agreements with significant trading counterparties. These agreements, which provide the right to offset unrealized gains and losses with the same counterparty across more than one commodity and/or allow for settlement of purchase and sale transactions with the same counterparty by a single payment, reduced PacifiCorp’s credit exposure by approximately $95.3 million at March 31, 2005, and approximately $47.1 million at March 31, 2004. Amounts that qualify for offset or payment netting under master netting agreements are presented net on the Consolidated Financial Statements.

	Net Asset (Liability)						Regulatory Net Asset

(Millions of dollars)	Trading			Non-trading			(Liability) (c)


Fair value of contracts outstanding at March 31, 2004	$	(0.5	)	$	(414.3	)	$	422.2
Contracts realized or otherwise settled during the period		0.3			(39.2	)		42.6
Changes in fair values attributable to changes in valuation techniques and assumptions (a)		—			(27.2	)		27.2
Other changes in fair values (b)		0.4			326.3			(322.0	)

Fair value of contracts outstanding at March 31, 2005	$	0.2		$	(154.4	)	$	170.0

(a)

(b)	Other changes in fair values include the effects of changes in market prices, inflation rates and interest rates, including those based on models, on new and existing contracts for the year ended March 31, 2005.

(c)	Contracts that have received commission approval for regulatory recovery are included as a Regulatory Net Asset (Liability).

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.

PacifiCorp bases its forward price curves upon market price quotations when available and bases them on internally developed and commercial models, with internal and external fundamental data inputs, 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. As noted above, price quotations for certain major electricity trading hubs are generally readily obtainable for the first six 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 six years, the forward price curve (beyond the first six years) 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 such as long-term natural gas prices and expected inflation rates.

Standardized derivative contracts that are valued using market quotations, as described above, are classified in the table below as “values 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 “values based on models and other valuation methods.”

	Fair Value of Contracts at Period-End


(Millions of dollars)	Maturity Less Than 1 Year			Maturity 1-3 Years			Maturity 4-5 Years			Maturity in Excess of 5 Years			Total Fair Value

Trading:
Values based on quoted market prices from third-party sources	$	0.2		$	—		$	—		$	—		$	0.2
Values based on models and other valuation methods		—			—			—			—			—

Total trading	$	0.2		$	—		$	—		$	—		$	0.2

Non-trading:
Values based on quoted market prices from third-party sources	$	(213.0	)	$	(262.5	)	$	(38.9	)	$	(16.8	)	$	(531.2	)
Values based on models and other valuation methods		328.8			379.3			(7.3	)		(324.0	)		376.8

Total non-trading	$	115.8		$	116.8		$	(46.2	)	$	(340.8	)	$	(154.4	)

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 SEC approval. There are intercompany loan agreements that allow funds to be lent to PacifiCorp from PacifiCorp Group Holdings Company (“PGHC”), but loans from PacifiCorp to PGHC are prohibited. There are intercompany loan agreements that allow funds to be lent between PacifiCorp and Pacific Minerals, Inc., a wholly owned subsidiary of PacifiCorp. PacifiCorp does not maintain a centralized cash or money pool. Therefore, funds of each company are not commingled with funds of any other company. Other 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.

(Millions of dollars)			March 31,

			2005		2004

Amounts due from affiliated entities:
SPUK (a)			$	0.3	$	0.2
PHI and its subsidiaries (b)				36.2		2.2

			$	36.5	$	2.4

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

Amounts due to affiliated entities:
SPUK (d)			$	3.9	$	2.6

Deposits received from affiliated entities:
PHI and its subsidiaries (e)			$	0.3	$	0.6

(Millions of dollars)
	Years Ended March 31,

	2005		2004		2003

Revenues from affiliated entities:
PHI and its subsidiaries (e)	$	5.9	$	4.4	$	4.4

Expenses incurred from affiliated entities:
SPUK (d)	$	18.3	$	7.8	$	10.0
PHI and its subsidiaries (c)		17.3		17.0		13.0

	$	35.6	$	24.8	$	23.0

Expenses recharged to affiliated entities:
SPUK (a)	$	3.0	$	0.7	$	0.5
PHI and its subsidiaries (b)		9.4		8.0		7.1

	$	12.4	$	8.7	$	7.6

Interest expense to affiliated entities:
PHI and its subsidiaries (f)	$	0.1	$	0.2	$	0.1

(a)

For the year ended March 31, 2005, expenses and liabilities primarily represent amounts allocated to Scottish Power UK (“SPUK”) by PacifiCorp for services provided under the cross-charge policy described below. PacifiCorp also recharged to SPUK payroll costs and related benefits of PacifiCorp employees working on international assignment in the United Kingdom during the years ended March 31, 2005, 2004 and 2003.

(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 portion of taxes currently receivable from PHI of $33.8 million at March 31, 2005, and $0.1 million at March 31, 2004, which are applied to PacifiCorp’s tax liability in the first quarter of the following fiscal year. PHI is the tax-paying entity for PacifiCorp.

(c)

These expenses primarily relate to 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)

For the year ended March 31, 2005, expenses and liabilities primarily represent amounts allocated to PacifiCorp for services received under the cross-charge policy described below. SPUK also recharged PacifiCorp for payroll costs and related benefits of SPUK employees working on international assignment in the United States for the years ended March 31, 2005, 2004 and 2003.

(e)

These revenues and the associated deposit relate to wheeling services billed to PPM. PacifiCorp provides these services to PPM pursuant to PacifiCorp’s FERC-approved open access transmission tariff, which requires PacifiCorp to make transmission services available on a non-discriminatory basis to all interested parties.

(f)	Includes interest on short-term demand loans made to PacifiCorp by PGHC, in accordance with regulatory authorization.

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. The lease terms granted PacifiCorp two independent early termination options that provide PacifiCorp the right to terminate the lease and, at PacifiCorp’s further option, to purchase the facility for predetermined amounts. On May 28, 2004, PacifiCorp exercised its first option to terminate the West Valley lease. PacifiCorp subsequently exercised its right to rescind the termination on September 28, 2004, after determining, through a public request for proposals process, that the resource could not be replaced on a more economic basis and without increasing risks to system reliability. PacifiCorp has a second option to terminate the West Valley lease if written notice is provided to West Valley on or before December 1, 2006. Until the second option to terminate, PacifiCorp is committed to future minimum lease payments of $15.0 million annually for the years ending March 31, 2006 through 2008, and $2.5 million for the year ending March 31, 2009.

Commencing on April 1, 2004, PacifiCorp and SPUK implemented a cross-charge policy governing the allocation of costs incurred by PacifiCorp and SPUK, on behalf of each other. This policy, approved by the SEC in its administration of the PUHCA, permits PacifiCorp to receive certain administrative services, priced at cost, from SPUK. These include shareholder services, investor relations, management and human resource services. PacifiCorp also provides administrative services to SPUK and other ScottishPower affiliates under the cross-charge policy. Cross-charges from SPUK to PacifiCorp amounted to $14.9 million for the year ended March 31, 2005, and were recorded in 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, 2005, 2004 and 2003, 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:

Available-for-sale securities

(Millions of dollars)		Amortized Cost		Gross Unrealized Gains		Gross Unrealized Losses			Estimated Fair Value

March 31, 2005
Money market account	$	2.7	$	—	$	—		$	2.7
Mutual fund account		27.0		—		(1.0	)		26.0
Debt securities		25.6		0.4		(0.4	)		25.6
Equity securities		60.6		13.2		(1.2	)		72.6

Total	$	115.9	$	13.6	$	(2.6	)	$	126.9

March 31, 2004
Money market account	$	3.3	$	—	$	—		$	3.3
Mutual fund account		26.1		—		(0.3	)		25.8
Debt securities		22.9		0.9		—			23.8
Equity securities		56.7		12.0		(1.3	)		67.4

Total	$	109.0	$	12.9	$	(1.6	)	$	120.3

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, 2005 and 2004, 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,

	2005				2004

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

Debt securities
Due in one year or less	$	0.7	$	0.7	$	—	$	—
Due after one year through five years		5.6		5.6		4.3		4.5
Due after five years through ten years		9.8		9.9		11.1		11.6
Due after ten years		9.5		9.4		7.5		7.7
Money market account		2.7		2.7		3.3		3.3
Mutual fund account		27.0		26.0		26.1		25.8
Equity securities		60.6		72.6		56.7		67.4

Total	$	115.9	$	126.9	$	109.0	$	120.3

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, 2005, 2004 and 2003:

	Years Ended March 31,

(Millions of dollars)	2005			2004			2003

Proceeds	$	49.1		$	95.8		$	132.9

Gross gains	$	6.3		$	6.5		$	2.6
Gross losses		(2.2	)		(3.4	)		(8.7	)

Net gains (losses)	$	4.1		$	3.1		$	(6.1	)

Note 6 – Asset Retirement Obligations and Accrued Environmental Costs

Asset Retirement Obligations - PacifiCorp records asset retirement obligations for long-lived physical assets that qualify as legal obligations under SFAS No. 143. PacifiCorp estimates its asset retirement obligation 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 a credit-adjusted, risk-free rate. PacifiCorp then records an asset retirement obligation 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 described in Note 2. Since asset retirement costs are recovered through the ratemaking process, PacifiCorp records a Regulatory asset or Regulatory liability on the Consolidated Balance Sheets 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 at April 1, 2003, 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.

The following table describes the changes to PacifiCorp’s asset retirement obligation liability for the years ended March 31, 2005 and 2004:

(Millions of dollars)	March 31, 2005			March 31, 2004

Liability recognized at beginning of period	$	193.5		$	196.4
Liabilities incurred		1.4			4.9
Liabilities settled (a)		(13.0	)		(14.5	)
Revisions in cash flow (b)		8.9			(1.5	)
Accretion expense		8.8			8.2

Asset retirement obligation		199.6			193.5
Less amount in Current liabilities - other		17.8			13.7

Long-term asset retirement obligation at end of period (c)	$	181.8		$	179.8

(a)	Relates primarily to ongoing reclamation work at the Glenrock coal mine.
(b)	Results from changes in the timing and amounts of estimated cash flows for certain plant reclamation.
(c)	Amount included in Deferred credits – other.

PacifiCorp had trust fund assets recorded at fair value included in Deferred charges and other of $92.4 million at March 31, 2005, and $87.4 million at March 31, 2004, 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.

PacifiCorp assesses its potential obligations to perform environmental remediation on an ongoing basis. As a result of studies performed during the year ended March 31, 2005, PacifiCorp adjusted its reserve by $2.0 million to reflect its most likely estimate for probable liabilities. Remediation costs that are fixed and determinable have been discounted to their present value using credit-adjusted, risk-free discount rates based on the expected future annual borrowing rates of PacifiCorp. The liability recorded was $33.3 million at March 31, 2005, and $37.9 million at March 31, 2004, and is included as part of Deferred credits - other. The March 31, 2005 recorded liability included $23.2 million of discounted liabilities. Had none of the liabilities included in the $33.3 million balance recorded at March 31, 2005 been discounted, the total would have been $35.6 million. The expected payments for each of the five succeeding fiscal years and thereafter are as follows: $6.8 in 2006, $4.3 in 2007, $4.3 in 2008, $1.4 in 2009, $1.2 in 2010 and $15.3 thereafter.

PacifiCorp expects to spend a considerable portion of the environmental reserves over the next six years. It is possible that future findings or changes in estimates could require that additional amounts be accrued. Should current circumstances change, it is possible that PacifiCorp could incur an additional undiscounted obligation of up to approximately $77.3 million relating to existing sites. 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 - Notes Payable and Commercial Paper

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

(Millions of dollars)	Balance		Average Interest Rate

March 31, 2005	$	468.8	2.9	%
March 31, 2004	$	124.9	1.1	%

In addition to the above, at March 31, 2005, PacifiCorp had an $800.0 million committed bank revolving credit agreement, which was fully available and which had no borrowings outstanding. This facility, which has a three-year term, became effective in May 2004 and was used to replace an expiring $500.0 million facility and a $300.0 million facility that was terminated by PacifiCorp prior to its maturity. The interest on advances under this facility is based on the London Interbank Offered Rate (LIBOR) plus a margin that varies based on PacifiCorp’s credit ratings.

Note 8 - Long-Term Debt and Capital Lease Obligations

PacifiCorp’s long-term debt and capital lease obligations were as follows:

	March 31,

	2005					2004

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

First mortgage bonds
4.3% to 8.8%, due through 2010	$	1,156.8		6.1	%	$	1,392.9		6.3	%
5.0% to 9.2%, due 2011 to 2015		1,047.8		6.5			847.8		6.9
8.3% to 8.6%, due 2016 to 2020		12.2		8.5			12.1		8.5
6.7% to 8.6%, due 2021 to 2025		324.0		7.7			344.0		7.7
6.7% due 2026		100.0		6.7			100.0		6.7
5.9 % to 7.7%, due 2031 to 2035		500.0		7.0			300.0		7.7
Unamortized premium (discount)		(4.3	)				(3.7	)
Guaranty of pollution-control revenue bonds
Variable rates, due 2006 to 2007 (a)		—		—			38.1		2.9
Variable rates, due 2014 to 2026 (a)		325.2		2.2			287.1		1.5
Variable rate, due 2014 (a) (b)		40.7		2.3			40.7		1.1
3.4% to 5.7%, due 2015 to 2026 (b)		184.0		4.5			184.0		4.5
Variable rates, due 2025 (a) (b)		175.8		2.3			175.8		1.1
6.2%, due 2031		12.7		6.2			12.7		6.2
Unamortized premium (discount)		(0.5	)				(0.6	)
Funds held by trustees		(2.1	)				(2.1	)
Note obligations of subsidiaries
8.6%, due 2005		—		—			3.8		8.6
Capitalized lease obligations
10.4% to 14.8%, due through 2022		26.6		11.9			27.6		11.9

Total		3,898.9					3,760.2
Less current maturities		(269.9	)				(240.0	)

Total	$	3,629.0				$	3,520.2

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

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

First mortgage bonds of PacifiCorp may be issued in amounts limited by PacifiCorp’s property, earnings and other provisions of the mortgage indenture. Approximately $13.1 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 with the SEC for up to $250.0 million of certain securities including long-term debt.

Approximately $2.1 billion of first mortgage bonds were redeemable at PacifiCorp’s option at March 31, 2005, at redemption prices dependent upon United States Treasury yields. Approximately $541.7 million of variable-rate pollution-control revenue bonds were redeemable at PacifiCorp’s option at par at March 31, 2005. Approximately $71.2 million of fixed-rate pollution-control revenue bonds were redeemable at PacifiCorp’s option at 101.0% of par at March 31, 2005. The remaining long-term debt was not redeemable at March 31, 2005.

During March 2005, the maturity dates were extended to December 1, 2020, for three series of variable-rate pollution-control revenue bonds totaling $38.1 million.

During December 2004, PacifiCorp redeemed, prior to maturity, all of the 8.625% First Mortgage Bonds due in December 2024, which totaled $20.0 million. Upon redemption, $1.3 million of deferred charges were reclassified to a regulatory asset. This retirement was initially funded through short-term debt with the expectation that it will be funded through long-term financing in the next 12 months, subject to regulatory authorization.

PacifiCorp leases real estate in various states in which it does business under long-term agreements, extending through fiscal 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

2006	$	269.7		$	3.3		$	273.0
2007		216.1			3.5			219.6
2008		119.8			3.5			123.3
2009		412.0			3.5			415.5
2010		138.3			3.8			142.1
Thereafter		2,723.3			43.1			2,766.4

		3,879.2			60.7			3,939.9
Unamortized premium (discount)		(4.8	)		—			(4.8	)
Funds held by trustee		(2.1	)		—			(2.1	)
Amounts representing interest		—			(34.1	)		(34.1	)

	$	3,872.3		$	26.6		$	3,898.9

PacifiCorp made interest payments, net of capitalized interest, of $220.4 million for the year ended March 31, 2005; $236.7 million for the year ended March 31, 2004; and $287.9 million for the year ended March 31, 2003.

At March 31, 2005, 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. In addition, PacifiCorp had approximately $29.0 million of standby letters of credit to provide credit support for certain transactions as requested by third-parties. These committed bank arrangements were all fully available as of March 31, 2005 and expire periodically through the year ending March 31, 2010.

Note 9 – Preferred Stock Subject to Mandatory Redemption

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

(Thousands of shares, millions of dollars)	March 31, 2005			March 31, 2004

Series	Shares	Amount		Shares	Amount

Preferred stock subject to mandatory redemption $7.48 No Par Serial Preferred, $100 stated value, 16,000 shares authorized	525	$	52.5	600	$	60.0

PacifiCorp has mandatory redemption requirements on 37,500 shares of the $7.48 series Preferred stock on each June 15th through 2006, with a non-cumulative option to redeem an additional 37,500 shares on each June 15th 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. PacifiCorp redeemed $7.5 million of Preferred stock subject to mandatory and optional redemption during each of the years ended March 31, 2005, 2004 and 2003.

In May 2003, the FASB issued SFAS No. 150, Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity. 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 $1.0 million at March 31, 2005, and $1.1 million at March 31, 2004, 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, individual Klamath Tribal members and the Klamath Claims Committee. The complaint 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. In September 2004, the Klamath Tribes filed their first amended complaint adding claims of damage to their treaty rights to fish for sucker and

steelhead in the headwaters of the Klamath River. The complaint seeks in excess of $1.0 billion in compensatory and punitive damages. In February 2005, PacifiCorp filed a motion for summary judgment seeking dismissal of the Klamath Tribes’ claims as untimely under the applicable statute of limitations. In April 2005, the magistrate judge issued an opinion recommending that PacifiCorp’s motion for summary judgment be granted and the case be dismissed as untimely. In May 2005, the Klamath Tribes filed objections to the recommendation and PacifiCorp filed its response to the Klamath Tribes’ objections. Any final order will be subject to appeal. PacifiCorp believes the outcome of this proceeding will not have a material impact on its consolidated financial position, results of operations or liquidity.

From time to time, PacifiCorp is also a party to various other legal actions, complaints and disputes, certain of which involve material amounts. PacifiCorp has recorded $12.6 million in reserves related to various outstanding legal actions and disputes, excluding those discussed below. This amount represents PacifiCorp’s best estimate of probable losses related to these matters. PacifiCorp currently believes that disposition of these matters will not have a material adverse effect on PacifiCorp’s consolidated financial position, results of operations or liquidity.

Environmental issues - PacifiCorp is subject to numerous environmental laws, including the federal Clean Air Act and various state air quality laws; the Endangered Species Act, particularly as it relates to certain endangered species of fish; the Comprehensive Environmental Response, Compensation and Liability Act, and similar state laws relating to environmental cleanups; the Resource Conservation and Recovery Act and similar state laws relating to the storage and handling of hazardous materials; and the Clean Water Act, and similar state laws relating to water quality. These laws could potentially impact future operations. Contingencies identified at March 31, 2005, principally consist of air quality matters. Pending or proposed air regulations will require PacifiCorp to reduce its electricity plant emissions of sulfur dioxide, nitrogen oxides and other pollutants below current levels. These reductions will be required to address regional haze programs, mercury emissions regulations and possible re-interpretations and changes to the federal Clean Air Act. Also, similar to many other coal-burning utilities, PacifiCorp has received information requests from the EPA related to PacifiCorp’s compliance with the New Source Review provisions of the Clean Air Act, which has resulted in some discussions with the EPA and state regulatory authorities. In the future, PacifiCorp may incur significant costs to comply with various stricter air emissions requirements. These potential costs are expected to consist primarily of capital expenditures. PacifiCorp expects these costs would be included in rates and, as such, would not have a material adverse impact on PacifiCorp’s consolidated results of operations. See also Note 6.

Hydroelectric relicensing - PacifiCorp’s hydroelectric portfolio consists of 51 plants with an aggregate plant net capability of 1,155.4 MW. The FERC regulates 99.0% of the installed capacity through 18 individual licenses. Several 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 $60.0 million in costs as of March 31, 2005, 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.

In May 2004, PacifiCorp accepted the new license for the Bear River hydroelectric project. PacifiCorp is committed, over the 30-year life of the license, to fund approximately $25.9 million for environmental mitigation and enhancement projects. The present value of the portion of these obligations for which PacifiCorp is currently committed, net of costs incurred to date of $0.1 million, was $12.5 million at March 31, 2005.

The new FERC license for the North Umpqua hydroelectric project is effective but not final. When the license for this project becomes final, PacifiCorp will be committed, over the 35-year life of the license, to fund approximately $48.9 million for environmental mitigation and enhancement projects. The present value of the portion of these obligations for which PacifiCorp is currently committed, net of costs incurred to date of $0.3 million, was $13.1 million at March 31, 2005. Additional liabilities amounting to $21.2 million, undiscounted, will be recognized when the license becomes final.

Enron Corp. Reserves - In December 2001, Enron Corp. declared bankruptcy and defaulted on certain wholesale contracts. PacifiCorp had fully reserved for its $8.0 million Enron Corp. receivable. PacifiCorp sold its bankruptcy claim to a third party during the fourth quarter of fiscal 2005 for proceeds of $1.7 million.

FERC Issues

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 has 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. In addition, beginning in summer 2000, California market conditions resulted in defaults of amounts due to PacifiCorp from certain counterparties resulting from transactions with the California Independent System Operator and California Power Exchange. PacifiCorp has reserved $5.0 million for these receivables.

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 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. Court briefs from interested parties were filed between January 14, 2005 and April 15, 2005. A decision from the court of appeals is not expected to have a significant impact on PacifiCorp’s consolidated financial position or results of operations.

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 its request for rehearing of the FERC’s order, which request was granted in August 2003. The FERC issued its final order denying rehearing in November 2003. Also in November 2003, PacifiCorp filed a petition in the Ninth Circuit Court of Appeals for review of the FERC’s final order denying recovery. Court briefs from interested parties were filed by March 2005. Oral argument has been scheduled for July 2005.

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 requests for rehearing of the FERC’s final order. A decision from the FERC on the rehearing requests is pending.

FERC Market Power Analysis - Pursuant to the FERC’s orders granting PacifiCorp authority to sell capacity and energy at market-based rates, PacifiCorp and certain of its affiliates are required to submit a joint market power analysis every three years. Under the FERC’s current policy, applicants must demonstrate that they do not possess market power in order to charge market-based rates for sales of wholesale energy and capacity. An analysis demonstrating an applicant’s passage of certain threshold screens for assessing generation market power establishes a rebuttable presumption that the applicant does not possess generation market power, while failure to pass any screen creates a rebuttable presumption that the applicant has generation market power. In February 2005, PacifiCorp submitted a joint triennial market power analysis in compliance with the FERC’s requirements. The analysis indicated that PacifiCorp failed to pass one of the generation market power screens in PacifiCorp’s eastern control area and in Idaho Power Company’s control area. On May 9, 2005, the FERC issued an order instituting a proceeding pursuant to section 206 of the Federal Power Act to determine whether PacifiCorp may continue to charge market-based rates for sales of wholesale energy and capacity. Under the terms of the order, PacifiCorp and its affiliated co-applicants are required to submit additional information and analysis to the FERC within 60 days to rebut the presumption that PacifiCorp has generation market power. PacifiCorp is in the process of responding to the FERC’s May 9, 2005 order. If the FERC ultimately finds that PacifiCorp has market power, PacifiCorp will be required to implement measures to mitigate any exercise of market power.

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, 2005 and 2004.

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.

Unconditional Purchase Obligations

	Payments due during the years ending March 31,

(Millions of dollars)	2006		2007		2008		2009		2010		Thereafter		Total

Construction	$	248.2	$	56.6	$	23.0	$	—	$	—	$	—	$	327.8
Operating leases		21.3		19.7		18.3		5.3		2.1		9.4		76.1
Purchased electricity		694.3		452.4		260.1		192.3		197.4		1,577.2		3,373.7
Transmission		64.2		54.7		49.3		47.5		45.3		551.2		812.2
Fuel		318.6		337.8		339.6		183.2		170.7		748.7		2,098.6
Other		59.4		42.2		33.1		27.5		25.7		684.0		871.9

Total commitments	$	1,406.0	$	963.4	$	723.4	$	455.8	$	441.2	$	3,570.5	$	7,560.3

Construction - PacifiCorp has an ongoing construction program to meet increased electricity usage and customer growth. At March 31, 2005, PacifiCorp had estimated long-term unconditional purchase obligations for construction of the new Currant Creek and Lake Side Power Plants.

Operating leases - PacifiCorp leases offices, certain operating facilities, land and equipment under operating leases that expire at various dates through fiscal 2093. 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 $26.1 million for the year ended March 31, 2005; $29.4 million for the year ended March 31, 2004; and $21.0 million for the year ended March 31, 2003.

Minimum non-cancelable sublease rentals expected to be received through fiscal 2013 total $4.2 million.

Purchased electricity - As part of its energy resource portfolio, PacifiCorp acquires a portion of its electricity through long-term purchases and/or exchange agreements.

Included in the minimum fixed annual payments for purchased electricity 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 operating expenses and debt service. These costs are included in Purchased electricity. PacifiCorp is required to pay its portion of operating costs and its portion of the debt service, whether or not any electricity is produced.

At March 31, 2005, 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	194,106	18.7	%	$	5.7
Priest Rapids	2005	132,844	13.9			4.2
Rocky Reach	2011	68,211	5.3			3.4
Wells	2018	57,960	6.6			2.1

Total		453,121			$	15.4

(a) Includes debt service totaling $7.9 million.

PacifiCorp’s minimum debt service and estimated operating obligations included in purchased electricity above for the years ending March 31, are as follows:

(Millions of dollars)	Minimum Debt Service		Operating Obligations

2006	$	8.8	$	8.8
2007		9.4		6.9
2008		9.8		7.2
2009		11.0		7.3
2010		8.0		5.6
Thereafter		17.2		13.4

	$	64.2	$	49.2

PacifiCorp has a 4.0% entitlement to the generation of the Intermountain Power Project, located in central Utah through a power purchase agreement. PacifiCorp and the City of Los Angeles have agreed that the City of Los Angeles will purchase capacity and energy from PacifiCorp’s 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.

Fuel - PacifiCorp has “take or pay” coal and natural gas contracts that require minimum payments.

Other - Unconditional purchase obligations, as defined by accounting standards, are those long-term commitments that are non-cancelable or cancelable only under certain conditions. PacifiCorp has such commitments related to legal or contractual asset retirement obligations, environmental obligations, hydroelectric obligations, equipment maintenance and various other service and maintenance agreements.

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, 2005, PacifiCorp’s share in jointly owned facilities was as follows:

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

Colstrip Nos. 3 and 4 a (a)	10.0	%	$	238.9	$	112.0	$	0.5
Craig Station Nos. 1 and 2	19.3			163.7		67.0		0.8
Foote Creek	78.8			37.0		9.0		—
Hayden Station No. 1	24.5			41.0		17.4		0.1
Hayden Station No. 2	12.6			26.3		12.0		0.1
Hermiston (b)	50.0			163.4		37.1		5.1
Hunter No. 1	93.8			296.5		139.9		9.1
Hunter No. 2	60.3			207.4		96.3		2.6
Jim Bridger Nos. 1 - 4 (a)	66.7			892.3		450.6		22.2
Trojan (c)	2.5			—		—		—
Wyodak	80.0			307.6		156.6		5.3
Other transmission and distribution plants	Various			78.5		19.8		0.1
Unallocated acquisition adjustments (d)				157.2		75.8		—

Total			$	2,609.8	$	1,193.5	$	45.9

(a)	Includes kilovolt lines and substations.

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

(c)	Plant, inventory, fuel and decommissioning costs totaling $9.8 million relating to the Trojan Plant were included in regulatory assets at March 31, 2005.

(d)	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 December 2003, the FASB issued revised FIN 46, Consolidation of Variable-Interest Entities, an interpretation of Accounting Research Bulletin No. 51 (“FIN 46R”), 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. FIN 46R was adopted as of January 1, 2004, and resulted in certain disclosures describing variable interests that were identified. The adoption of FIN 46R did not have a material impact on PacifiCorp’s consolidated financial position or results of operations. PacifiCorp continues 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.

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 (proportionate to the joint owner’s share of the plant). 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, upon adoption of FIN 46R, PacifiCorp was unable to obtain the information necessary to consolidate the entity, because the entity did not agree to supply the information due to the lack of a contractual obligation to do so. PacifiCorp continues to request from the entity the information necessary to perform the consolidation; however, no information has yet been provided by the entity. Electricity purchased from the joint owner was $34.8 million during the year ended March 31, 2005, $33.7 million during the year ended March 31, 2004, and $34.0 million during the year ended March 31, 2003. 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.

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 21.4% equity interest in Trapper Mining, Inc. and also holds a 19.3% undivided interest in the Craig Power Plant as disclosed in Note 12. 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 Stock

PacifiCorp’s Preferred stock was as follows:

(Thousands of shares, millions of dollars, except per share amounts)	Redemption Price Per Share		March 31, 2005				March 31, 2004

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 liquidation, all Preferred stock is entitled to stated value or a specified preference amount per share plus accrued dividends. Upon involuntary liquidation, all Preferred stock is entitled to stated value 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, 2005, and at March 31, 2004, in dividends declared but unpaid on Preferred stock. The shares and amounts outstanding for each series of Preferred stock not subject to mandatory redemption were unchanged from March 31, 2003, through March 31, 2005.

Note 15 - Common Shareholder’s Equity

Common Shareholder’s Equity - 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, 2005 and 2004. To the extent PacifiCorp does not reimburse ScottishPower for stock-based compensation awarded under ScottishPower plans, such amounts increase the value of PacifiCorp’s common shareholder’s capital.

Common Dividend Restrictions - ScottishPower is the sole indirect shareholder of PacifiCorp's common stock. PacifiCorp is restricted from making any distributions without prior state regulatory approval to the extent that it would reduce PacifiCorp’s common stock equity below 40.0% of its total capitalization, excluding short-term debt and current maturities of long-term debt. As of March 31, 2005, under this measure, PacifiCorp’s actual common stock equity percentage was 47.3%. PacifiCorp is also subject to maximum debt-to-total capitalization levels under various debt agreements.

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, 2005, PacifiCorp’s unearned surplus available for distribution pursuant to SEC authorization was approximately $220.0 million. In addition, PacifiCorp must give the Oregon Public Utility Commission 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.

Note 16 - Fair Value of Financial Instruments

	March 31, 2005				March 31, 2004

(Millions of dollars)	Carrying Amount		Fair Value		Carrying Amount			Fair Value

Long-term debt (a)	$	3,872.3	$	4,209.5	$	3,732.6		$	4,181.3
Preferred stock subject to mandatory redemption		52.5		56.0		60.0			67.9
Weather derivative asset (liability)		20.3		20.3		(5.3	)		(5.3	)

(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 derivative instruments subject to SFAS No. 133 are disclosed in Note 3.

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 weather derivatives reflects the net present value of future premiums owed by PacifiCorp, offset by estimated settlements owed to (or 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 17 - Retirement Benefit Plans

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, 2005, 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)	2005			2004			2003

Service cost	$	25.9		$	25.8	(a)	$	21.6	(a)
Interest cost		73.8			73.9			76.8
Expected return on plan assets		(77.7	)		(80.7	)		(92.8	)
Amortization of unrecognized net obligation		8.4			8.4			8.4
Amortization of unrecognized prior service cost		1.4			1.5			2.1
Amortization of unrecognized loss (gain)		8.5			—			(4.2	)

Net periodic pension benefit cost	$	40.3		$	28.9		$	11.9

(a)	Includes no contributions for the year ended March 31, 2005, contributions of $5.6 million for the year ended March 31, 2004, and contributions of $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,

	2005			2004			2003

Discount rate		6.25	%		6.75	%		7.50	%
Expected long-term rate of return on assets		8.75			8.75			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:

	March 31,

	2005			2004			2003

Discount rate		5. 75	%		6.25	%		6.75	%
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 are as follows:

	March 31,

(Millions of dollars)	2005			2004

Change in projected benefit obligation
Projected benefit obligation - beginning of year	$	1,229.8		$	1,151.6
Service cost		25.9			20.1
Interest cost		73.8			73.9
Plan amendments		1.0			—
Actuarial loss		86.8			97.1
Benefits paid		(79.2	)		(112.9	)

Projected benefit obligation - end of year	$	1,338.1		$	1,229.8

Change in plan assets
Plan assets at fair value - beginning of year	$	733.2		$	681.2
Actual return on plan assets		87.5			128.3
Company contributions		65.0			36.6
Benefits paid		(79.2	)		(112.9	)

Plan assets at fair value - end of year	$	806.5		$	733.2

Reconciliation of accrued pension cost and total amount recognized
Funded status of the plan	$	(531.6	)	$	(496.6	)
Unrecognized net loss		443.6			375.2
Unrecognized prior service cost		9.1			9.4
Unrecognized net transition obligation		15.9			24.4

Accrued pension cost	$	(63.0	)	$	(87.6	)

Accrued benefit liability	$	(383.2	)	$	(360.5	)
Intangible asset		25.0			33.8
Accumulated other comprehensive income		14.5			12.9
Regulatory assets		280.7			226.2

Accrued pension cost	$	(63.0	)	$	(87.6	)

The aggregated accumulated benefit obligation was $1,189.7 million and the fair value of assets was $806.5 million as of March 31, 2005.

The PacifiCorp Retirement Plan (the “Retirement Plan”) and the Supplemental Executive Retirement Plan (the “SERP”) currently have assets with a fair value that is less than the accumulated benefit obligation under the Retirement Plan and the SERP, 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, 2005, and at March 31, 2004. 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, Wyoming and Washington to classify most of this charge as a Regulatory asset instead of a charge to Other comprehensive income. PacifiCorp has determined that according to SFAS No. 87, Employers’ Accounting for Pensions (“SFAS No. 87”), costs for the 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.

Retirement 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 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		2005		2004

Equity securities	55.0	%	56.1	%	55.3	%
Debt securities	35.0		33.9		34.4
Private equity	10.0		10.0		10.3

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 $24.9 million for the year ended March 31, 2005, $25.3 million for the year ended March 31, 2004, and $22.6 million for the year ended March 31, 2003. 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. 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 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 assets for other postretirement benefits are composed of three different trust accounts. The 401(h) account is invested in the same manner as the pension account. Each of the two Voluntary Employees’ Beneficiaries Association Trusts has its own investment allocation strategies.

Components of the net periodic postretirement benefit cost are summarized as follows:

	Years Ended March 31,

(Millions of dollars)	2005			2004			2003

Service cost	$	8.5		$	7.4		$	5.6
Interest cost		31.0			34.3			34.2
Expected return on plan assets		(26.4	)		(26.6	)		(28.5	)
Amortization of unrecognized net obligation		12.2			12.2			12.2
Amortization of unrecognized loss		0.6			0.6			—
Amortization of prior service cost		0.1			—			—
Regulatory deferral		—			—			1.1

Net periodic postretirement benefit cost	$	26.0		$	27.9		$	24.6

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

	March 31,

(Millions of dollars)	2005			2004

Change in accumulated postretirement benefit obligation
Accumulated postretirement benefit obligation - beginning of year	$	555.3		$	522.4
Service cost		8.5			7.4
Interest cost		31.0			34.3
Plan participant contributions		7.2			6.8
Plan amendments		0.8			0.6
Actuarial (gain) loss		(34.4	)		21.5
Benefits paid		(40.1	)		(37.7	)

Accumulated postretirement benefit obligation - end of year	$	528.3		$	555.3


Change in plan assets
Plan assets at fair value - beginning of year	$	261.6		$	218.0
Actual return on plan assets		28.6			50.8
Company contributions		29.3			23.7
Plan participant contributions		7.2			6.8
Net benefits paid		(40.1	)		(37.7	)

Plan assets at fair value - end of year	$	286.6		$	261.6


Reconciliation of accrued postretirement costs and total amount recognized
Funded status of the plan	$	(241.7	)	$	(293.7	)
Unrecognized net transition obligation		94.6			106.8
Unrecognized prior service cost		1.4			0.6
Unrecognized loss		100.1			140.1

Accrued postretirement benefit cost, before final contribution		(45.6	)		(46.2	)
Final contribution made after measurement date but before March 31		24.9			25.3

Accrued postretirement cost	$	(20.7	)	$	(20.9	)

The assumed health care cost trend rates are as follows:

	March 31,

	2005		2004		2003

Initial health care cost trend - under 65	7.5	%	8.5	%	9.5	%
Initial health care cost trend - over 65	9.5		10.5		11.5
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	$	31.6	$	(27.2	)
Service and interest cost components		2.7		(2.3	)

In April 2005, PacifiCorp contributed $60.0 million to its Retirement Plan. In addition, PacifiCorp expects to contribute another $10.1 million to its pension plans, as well as $29.9 million to its other postretirement benefit plans in fiscal 2006. The benefit payments expected to be paid, which reflect expected future service and the Medicare Part D subsidy expected to be received, are as follows:

(Millions of dollars) Fiscal years ending March 31,	Retirement Plans		Other Postretirement Benefits		Medicare Part D Subsidy Receipts

2006	$	90.7	$	34.5	$	—
2007		90.3		35.3		(2.6	)
2008		90.1		35.9		(2.8	)
2009		91.2		36.2		(3.1	)
2010		93.9		36.8		(3.4	)
2011 to 2015 (inclusive)		518.7		200.1		(21.6	)

Employee Savings and Stock Ownership Plan

PacifiCorp has an Employee Savings and Stock Ownership Plan (the “Savings 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 Savings Plan are not eligible. Participating United States employees may defer up to 50.0% of their compensation, subject to certain statutory limitations. 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 qualifying service. Thereafter, PacifiCorp’s contributions vest immediately. PacifiCorp’s matching contribution is allocated based on the employee’s investment selections. PacifiCorp makes an additional contribution equal to a percentage of the employee’s eligible earnings. This additional contribution is allocated based on the employee’s investment selections or to the money market fund if the employee has made no selections. These contributions are immediately vested. PacifiCorp’s contributions to the Savings Plan were $20.2 million for the year ended March 31, 2005; $19.3 million for the year ended March 31, 2004; and $17.4 million for the year ended March 31, 2003; and represent amounts expensed for such periods.

Note 18 – Stock-Based Compensation

PacifiCorp Stock Incentive Plan - During 1997, PacifiCorp adopted the PSIP. The exercise price of options granted under the PSIP was equal to the market value of the common stock on 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 PSIP was 10 years. The PSIP expired on November 29, 2001.

100

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 PSIP.

ScottishPower American Depository Shares	Number of Shares		Weighted Average Price

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

Exercised	(750,126	)		26.10
Forfeited	(40,310	)		35.36

Outstanding options at March 31, 2005	2,133,613			33.52

Information with respect to options outstanding and options exercisable under the PSIP as of March 31, 2005 and 2004, 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, 2005
$25.70 - $36.64	1,589,323	$	31.05	4.2	1,589,323	$	31.05
$39.99 - $43.83	544,290		40.72	3.0	544,290		40.72

Total	2,133,613		33.52	3.9	2,133,613		33.52


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

Executive Share Option Plan - During April 2004, ScottishPower approved grants of stock options under the ExSOP for a select group of PacifiCorp employees. The options vest over three years and expire 10 years from the date of grant. In May 2001, ScottishPower granted enhanced awards under the ExSOP that were contingent on meeting certain performance conditions and that vested at the end of three years. On March 31, 2005, the performance conditions were met. As a result, $2.0 million of compensation expense was included in Operations and maintenance expense for the year ended March 31, 2005. No further awards will be granted under the ExSOP.

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The table below summarized the stock option activity under the ExSOP.

ScottishPower American Depository Shares	Number of Shares		Weighted Average Price


Outstanding options at March 31, 2002	—		$	—

Granted	979,204			23.55
Forfeited	(44,150	)		23.55

Outstanding options at March 31, 2003	935,054			23.55

Granted	780,901			24.40
Exercised	(25,508	)		23.55
Forfeited	(41,991	)		23.93

Outstanding options at March 31, 2004	1,648,456			23.94

Granted	763,843			28.72
Exercised	(483,667	)		23.84
Forfeited	(30,136	)		26.37

Outstanding options at March 31, 2005	1,898,496			25.85

Information with respect to options outstanding and options exercisable under the ExSOP as of March 31, 2005 and 2004, 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, 2005
$23.55 - $28.72	1,898,496	$	25.85	8.2	182,134	$	23.97
Year ended March 31, 2004
$23.55 - $24.40	1,648,456		23.94	8.6	195,118		23.55

Long-Term Incentive Plan - During April 2004, ScottishPower approved grants of performance share awards under its Long-Term Incentive Plan for a select group of PacifiCorp employees. The number of shares that actually vest is dependent upon the outcome of certain performance measures over a three-year period. During the year ended March 31, 2005, $0.8 million of compensation expense was included in Operations and maintenance expense.

Deferred Share Program - In May 2004, ScottishPower implemented a deferred share program under which certain PacifiCorp employees are granted an annual stock bonus award based on a fixed dollar amount but distributable in ScottishPower American Depository Shares with the number of shares to be determined by the quoted market price of the shares at the date of issuance. Compensation expense is accrued throughout the fiscal year in which the employee services are rendered and awards earned. During the year ended March 31, 2005, $3.1 million of compensation costs were accrued.

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Note 19 - 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,

	2005		2004		2003

Federal statutory rate	35.0	%	35.0	%	35.0	%
State taxes, net of federal benefit (a)	0.9		1.9		3.4
Effect of regulatory treatment of depreciation differences	4.1		4.5		6.5
Tax reserves (b)	2.0		(1.4	)	1.9
Tax credits	(2.3	)	(2.5	)	(5.6	)
Other	0.4		(0.8	)	(0.6	)

Effective income tax rate	40.1	%	36.7	%	40.6	%

(a)	State taxes, net of federal benefit, include changes in state tax contingency reserve.

(b)	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.

The provision for income taxes is summarized as follows:

	Years Ended March 31,

(Millions of dollars)	2005			2004			2003


Current
Federal	$	58.6		$	63.0		$	54.2
State		(10.1	)		1.0			11.2

Total		48.5			64.0			65.4

Deferred
Federal		112.6			77.8			38.6
State		15.3			10.6			1.1

Total		127.9			88.4			39.7

Investment tax credits		(7.9	)		(7.9	)		(7.9	)

Total income tax expense	$	168.5		$	144.5		$	97.2

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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)	2005			2004

Deferred tax liabilities
Property, plant and equipment	$	1,512.3		$	1,413.2
Regulatory assets		667.9			700.0
Derivative contract regulatory assets		64.5			160.2
Other deferred tax liabilities		105.5			76.2

		2,350.2			2,349.6

Deferred tax assets
Regulatory liabilities		(325.2	)		(329.7	)
Employee benefits		(185.4	)		(164.8	)
Derivative contracts		(102.6	)		(173.4	)
Other deferred tax assets		(106.0	)		(148.6	)

		(719.2	)		(816.5	)

Net deferred tax liability	$	1,631.0		$	1,533.1

PacifiCorp made net income tax payments of $92.0 million for the year ended March 31, 2005, $114.1 million for the year ended March 31, 2004, and $82.2 million for the year ended March 31, 2003. 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.

During the year ended March 31, 2005, PacifiCorp favorably settled outstanding income tax issues with the State of Oregon related to PacifiCorp’s 1991 through 1998 Oregon income tax returns. The settlement resulted in a release of previously accrued tax liability of $8.5 million. The net state tax contingency release for the year ended March 31, 2005, is $12.1 million. The net federal tax contingency reserves increase for the year ended March 31, 2005, is $8.5 million, primarily to accrue interest on remaining tax contingencies provided for in prior periods.

The Internal Revenue Service has completed its examination of PacifiCorp’s federal tax return filings for the 1999 and 2000 tax years. PacifiCorp has settled with the Internal Revenue Service on certain tax issues related to these returns. Settlement and payment on agreed-upon issues and other unresolved issues related to federal income tax returns through March 31, 2000, did not have a material adverse impact on PacifiCorp’s consolidated financial position or results of operations.

The Internal Revenue Service started its examination of the 2001, 2002 and 2003 tax years in October 2004. No material Notices of Proposed Adjustments have been issued. PacifiCorp anticipates that final settlement and payment on settled issues and other unresolved issues related to the federal income tax returns through March 31, 2003, will not have a material adverse impact on its consolidated financial position or results of operations.

PacifiCorp calculates its deferred tax assets and liabilities under SFAS No. 109, which requires recording deferred tax balances, at the currently enacted tax rate, for all temporary differences between the book and tax bases of assets and liabilities, including temporary differences for which no deferred taxes had been previously provided because of use of flow-through tax accounting for ratemaking purposes. Because of prior and expected future ratemaking treatment for temporary differences for which flow-through tax accounting has been utilized, PacifiCorp has also established a regulatory asset for income taxes recoverable through future rates related to those differences. At March 31, 2005, the balance of this asset was $499.9 million. In addition, PacifiCorp has established regulatory liabilities in the amount of $44.4 million for non-recoverable income taxes.

At March 31, 2005 and 2004, PacifiCorp had total available federal net operating loss carryforwards of approximately $2.7 million and no state net operating loss carryforwards, for both years. These loss carryforwards expire between 2022 and 2026. PacifiCorp has Oregon business energy tax credits of approximately $1.9 million at March 31, 2005, available to reduce future income tax liabilities. These credits begin to expire in 2010. PacifiCorp anticipates utilizing the operating loss and tax credits prior to the expiration dates.

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Note 20 - Concentration of Customers

During the year ended March 31, 2005, no single retail customer accounted for more than 2.0% 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, 2005, was Utah, 40.6%; Oregon, 29.3%; Wyoming, 13.6%; Washington, 8.0%; Idaho, 6.1%; and California, 2.4%.

Note 21 - Subsequent Events

On April 21, 2005, the PacifiCorp Board of Directors declared a dividend on common stock of $0.163 per share for a total of approximately $50.8 million, payable on May 27, 2005.

The closing of the sale of PacifiCorp is subject to a number of conditions, including ScottishPower shareholder consent and regulatory approvals from the SEC, the FERC, the Department of Justice or the Federal Trade Commission, the Nuclear Regulatory Commission and the public utility commissions in the states of Utah, Oregon, Wyoming, Washington, Idaho and California, as well as approvals under existing third-party agreements. Pending satisfaction of the closing conditions, the Stock Purchase Agreement requires ScottishPower to cause PacifiCorp to operate its business in the ordinary course consistent with past business practice. The Stock Purchase Agreement also requires ScottishPower to obtain MidAmerican’s prior approval to certain actions taken by PacifiCorp beyond limits specified in the Stock Purchase Agreement, including:

•	borrowings or debt issuances;

•	capital expenditures;

•	construction or acquisition of new generation, transmission or delivery facilities or systems, other than as currently planned or necessary to fulfill regulatory commitments;

•	unbudgeted significant acquisitions or dispositions;

•	modifications to material agreements with regulators;

•	issuance or sale of any capital stock to any person, other than PHI in certain circumstances;

•	adoption or amendment of employee benefit plans or material increases to employee compensation; and

•	payment of dividends to PHI.

Pursuant to the Stock Purchase Agreement for the sale of PacifiCorp, ScottishPower has agreed to cause PacifiCorp to not pay dividends to PHI in excess of $53.7 million per quarter during fiscal 2006 and $60.575 million per quarter during fiscal 2007. These restrictions will terminate upon either the close of the sale of PacifiCorp or the earlier termination of the Stock Purchase Agreement.

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SUPPLEMENTAL INFORMATION

QUARTERLY FINANCIAL DATA (UNAUDITED)

	Quarters Ended

(Millions of dollars, except per share amounts)	June 30			September 30			December 31			March 31

2005
Revenues	$	747.8		$	828.7		$	849.5		$	622.8
Income from operations		129.9			165.3			155.2			206.0
Income from continuing operations before cumulative effect of accounting change		50.9			61.9			51.3			87.6
Cumulative effect of accounting change		—			—			—			—
Net income		50.9			61.9			51.3			87.6
Earnings on common stock		50.4			61.4			50.7			87.1
Common dividends declared per share		15.5	¢		15.5	¢		15.5	¢		15.5	¢
Common dividends paid per share		15.5	¢		15.5	¢		15.5	¢		15.5	¢
2004
Revenues	$	783.9		$	845.4		$	788.4		$	776.8
Income from operations		168.9			148.9			161.3			138.8
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	¢

On March 31, 2005, PHI was the only 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

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, 2005, 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.

ITEM 9B.

OTHER INFORMATION

On May 22, the ScottishPower Remuneration Committee, in light of the expected timetable for obtaining regulatory approvals of PacifiCorp’s sale to MidAmerican, approved a cash retention award for PacifiCorp’s Chief Executive Officer, Judith Johansen, equal to one times base salary, which is contingent on the closing of PacifiCorp’s sale to MidAmerican and also on Ms. Johansen’s continued employment and her satisfactory performance of duties in the period through the sale’s closing. Ms. Johansen will receive 80.0% of the retention award upon the closing of the sale and the remaining 20.0% of the award 365 days from the date of the closing, provided there have been no breach of warranty claims against ScottishPower or PHI under the Stock Purchase Agreement.

On May 23, 2005, PacifiCorp’s Compensation Committee approved a $6.0 million pool to be used for retention incentives during the period prior to completion of the sale of PacifiCorp to MidAmerican. PacifiCorp’s Chief Executive Officer will select participants, expected to be PacifiCorp senior management and other employees determined to be critical to PacifiCorp prior to completion of the sale, and determine the amounts and terms of retention awards, subject to Compensation Committee approval. Each participant will be required to sign a confidentiality and retention agreement.

On May 23, 2005, the PacifiCorp Board of Directors amended PacifiCorp’s bylaws to provide that Sections 60.801 to 60.816 of the Oregon Business Corporation Act, known as the “Oregon Control Share Act,” do not apply to acquisitions of PacifiCorp’s voting shares (as defined in the Oregon Control Share Act).

On May 26, 2005, PacifiCorp’s Compensation Committee modified participation in PacifiCorp’s Executive Severance Plan to provide that certain members of PacifiCorp senior management, including executive officers Andrew Haller, Andrew MacRitchie, Richard Peach, Stan Watters and Matthew Wright, will be eligible for one times annual compensation general severance benefits and two times annual compensation change-of-control severance benefits. In addition, the Compensation Committee modified Michael Pittman’s change-of-control severance benefits to equal two times annual compensation, which payment would be in lieu of any severance payment to which Mr. Pittman might otherwise be entitled under his employment agreement in such circumstances.

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PART III

ITEM 10.

DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

The following is a list of directors of PacifiCorp.

Name and Age		Business Experience Past Five Years

Ian M. Russell (52)		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 all ScottishPower operations.

Judith A. Johansen (46)		President and Chief Executive Officer. Director since December 2000. Ms. Johansen was elected President and Chief Executive Officer in June 2001 and prior to that 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 (60)		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 (53)		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 assumed in 1999. 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 (60)		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.

107

Andrew N. MacRitchie (41)		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 merger of PacifiCorp with ScottishPower from December 1999 to May 2000. He served as ScottishPower’s United States Chief of Staff on the merger from December 1998 to December 1999, and, prior to that, he served as Manager, Business and Organizational Development.

Richard D. Peach (41)		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 also served as Group Controller for ScottishPower from March 2000 to December 2002, Head of Customer Services, Energy Supply for ScottishPower from April 1999 to March 2000 and in various other management positions with ScottishPower since 1995.

Michael J. Pittman (52)		Senior Vice President and ScottishPower Group Human Resources Director. Director since May 2000. Mr. Pittman was elected Senior Vice President of Human Resources in May 2000. Since October 2002, Mr. Pittman has also served as Group Director of Human Resources of ScottishPower. He formerly served as a Vice President of PacifiCorp since May 1993. Mr. Pittman is also Chairman of the PacifiCorp Foundation for Learning.

A. Richard Walje (53)		Executive Vice President. Director since July 2001. Mr. Walje has served as PacifiCorp’s Executive Vice President since April 2004 and as Chief Information Officer since May 2000. Previously he served as PacifiCorp’s Senior Vice President of Corporate Business Services from May 2001 to April 2004 and 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 (40)		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 from November 2000 to January 2002 and as Vice President of Regulation from 1999 to 2000. 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.

108

Name and Age

Business Experience Past Five Years

Donald N. Furman (48)

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.

Robert A. Klein (57)		Group Energy Risk Director, ScottishPower. In March 2003, Mr. Klein was named ScottishPower’s Group Energy Risk Director, Previously, Mr. Klein served as PacifiCorp’s Senior Vice President of Commercial and Trading since August 2001. 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.

Stan Watters (46)		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 and, prior to that, as Managing Director of Wholesale Energy Services since 1998. Mr. Watters has been with PacifiCorp since 1982.

Bruce N. Williams (46)		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 for Principal Officers applies to PacifiCorp’s Chief Executive Officer and its financial and accounting officers. The Guide to Business Conduct and Code of Ethics for Principal Officers are available in the “About Us - Company Overview” 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 for Principal Officers as the Code applies to PacifiCorp’s Chief Executive Officer and its financial and accounting officers.

PacifiCorp also maintains a Business Conduct Hotline that permits employees or third parties to report unethical behavior anonymously and confidentially to either an external reporting service, which provides both a toll-free phone number and secure website, or to PacifiCorp’s Office of General Counsel via an anonymous phone line.

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 non-executive directors of ScottishPower who are deemed “independent” in accordance with New York Stock Exchange listing standards.

Neither the PacifiCorp Board of Directors nor the ScottishPower Audit Committee currently has an independent, non-executive 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 ScottishPower Audit Committee is able to provide appropriate oversight.

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ITEM 11.

EXECUTIVE COMPENSATION

PACIFICORP BOARD OF DIRECTORS REPORT ON EXECUTIVE COMPENSATION

Introduction

The PacifiCorp Board of Directors 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 the ScottishPower Human Resources Director, who also serves as a PacifiCorp executive officer, and to review compensation for other executive officers and senior management of PacifiCorp. The Remuneration Committee is composed entirely of independent, non-executive directors. With the exception of any compensation requiring review by the Remuneration Committee, the Compensation Committee of the PacifiCorp Board of Directors, consisting of the ScottishPower Chief Executive Officer, the PacifiCorp Chief Executive Officer and the ScottishPower Human Resources Director, has responsibility for approving compensation levels and executive compensation plans for executive officers of PacifiCorp. The Remuneration Committee must approve any stock-based compensation to PacifiCorp executive officers, all of which is in the form of ScottishPower equity. The following describes the components of PacifiCorp’s executive compensation program and the basis upon which recommendations and determinations were made for the year ended March 31, 2005.

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 executive 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 PacifiCorp Compensation Committee considers in designing PacifiCorp’s incentive compensation arrangements for executive officers. 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 officer, 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 and the Compensation Committee 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 and the Compensation Committee believe that nearly all compensation paid to the executive officers for services rendered in the year ended March 31, 2005, is fully deductible.

Compensation Program Components

During the year ended March 31, 2005, the compensation programs were focused on market-based comparisons on the relevant industry for each executive 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 general industry and electric utility industry were 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 PacifiCorp and industry performance exceeds the median performance of peer companies.

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

Base Salaries

Base salaries and target incentive amounts are reviewed for adjustment at least annually based upon competitive pay levels, individual performance and potential, and changes in duties and responsibilities. Base salary and the incentive target are set at a level such that total annual compensation for satisfactory performance would approximate the midpoint of pay levels in the comparison group used to develop competitive data. In the year ended March 31, 2005, 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 executive officers, including those listed in the Summary Compensation Table, participated in PacifiCorp’s Annual Incentive Plan (the “AIP”). 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 PacifiCorp Board of Directors annually reviewed and approved grants of restricted stock and stock options under the PSIP until the PSIP was assumed by ScottishPower in connection with its acquisition of PacifiCorp in 1999. On November 29, 2001, the PSIP expired. Restricted stock and stock option awards made under the PSIP on or before April 24, 2001, relate to ScottishPower American Depository Shares or Ordinary Shares (“Ordinary Shares”) and will continue to remain outstanding until such time as they vest, are exercised or expire.

Restricted stock awards under the PSIP are subject to terms, conditions and restrictions consistent with the PSIP 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 in order to meet the vesting requirements associated with these grants.

In April 2004, the Remuneration Committee approved grants of stock options and performance share awards under ScottishPower’s Executive Share Option Plan 2001 (the “ExSOP”) and the Long-Term Incentive Plan (the “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 2004. See below for the LTIP awards. The May 2004 grants were the last stock options awarded under the ExSOP. Stock options granted under the ExSOP on or before May 27, 2004, will continue to remain outstanding until such time as they are exercised or expire.

All stock options awarded to executive officers and senior management of PacifiCorp in the years ended March 31, 2005, 2004 and 2003 are non-statutory, non-discounted options with a three-year vesting requirement and a 10-year term from the date of the grant. The stock options awarded during the year ended March 31, 2003, included two separate grants. The first was a standard grant of options, each of which has a three-year vesting schedule starting on the first anniversary of the grant date, and the second was a onetime enhanced grant of options, each of which vests three years after the grant date based on performance.

In May 2004, the Remuneration Committee approved a new program to replace the ExSOP, called the Deferred Share Program, which is part of the AIP for executive officers and senior management. Eligible employees will receive an increase to their AIP maximum target incentive payment, with the increase paid in ScottishPower American Depository Shares. The Deferred Share Program is effective beginning with the year ended March 31, 2006.

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The LTIP provides for awards of performance shares that link the rewards closely between management and shareholders and focus 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 depends upon ScottishPower’s comparative Total Shareholder Return performance over a three-year performance period. Vested shares are released to participants only after the conclusion of the performance period.

The PacifiCorp Board of Directors 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

•	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, 2005, 2004, and 2003 of the Chief Executive Officer of PacifiCorp 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

Name and Principal Position	Year	Annual Compensation (a)				All Other Compensation (d)		Long-Term Compensation

								Restricted Stock Awards (e)		Securities Underlying Options	LTIP Payout (f)		ScottishPower Performance Shares (g)

		Salary		Bonus (c)


Judith A. Johansen	2005	$	743,750	$	437,500	$	23,311	$	—	52,228	$	—	19,916
President and Chief	2004		589,394		337,500		22,883		—	61,475		—	12,458
Executive Officer	2003		492,444		149,767		21,170		—	61,825		—	9,199

Michael J. Pittman	2005		323,750		189,000		20,329		—	33,948		—	6,904
Senior Vice President	2004		313,125		187,500		20,097		—	38,729		—	7,849
	2003		300,000		47,057		18,860		—	50,954		—	7,581

Andrew P. Haller	2005		334,480		167,137		20,515		—	11,667		—	4,746
Senior Vice President,	2004		327,996		190,109		20,165		—	13,530		—	5,484
General Counsel and Corporate Secretary	2003		310,930		132,020		21,037		—	19,165		23,069	5,069

A. Richard Walje	2005		317,307		158,108		20,270		—	16,613		—	6,757
Executive Vice President	2004		299,544		127,557		83,173		—	17,751		—	7,195
	2003		277,604		95,550		19,278		—	24,840		—	6,570

Matthew R. Wright (b)	2005		292,481		141,945		151,425		—	15,331		—	6,236
Executive Vice President	2004		253,612		127,527		62,766		—	10,502		—	6,301
	2003		249,997		56,048		67,456		—	11,704		—	4,681

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(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)	Salary includes foreign housing benefits paid to Mr. Wright. These amounts were $39,380 for the year ended March 31, 2004, and $53,961 for the year ended March 31, 2003.

(c)	Amounts in this column for the year ended March 31, 2003, include a promotion bonus in the amount of $41,556 for Ms. Johansen.

(d)	Amounts shown for the year ended March 31, 2005, include:

(i)

Company contributions to the PacifiCorp Employee Savings and Stock Ownership Plan (the “Savings Plan”) of $12,073 for Ms. Johansen, $10,354 for Mr. Pittman, $10,508 for Mr. Haller, $10,315 for Mr. Walje and $12,197 for Mr. Wright.

(ii)

Portions of premiums on term life insurance policies that PacifiCorp paid in the amounts of $2,238 for Ms. Johansen, $975 for Mr. Pittman, $1,007 for Mr. Haller, $955 for Mr. Walje and $880 for Mr. Wright. These benefits are available to all employees.

(iii)

Annual vehicle allowances paid to Ms. Johansen and Messrs. Pittman, Haller, Walje and Wright in the amounts of $9,000 each. The amount of annual vehicle allowance for Mr. Wright was $10,350 for the year ended March 31, 2004, and $10,800 for the year ended March 31, 2003.

(iv)

Relocation benefits paid to Mr. Walje of $62,849 for the year ended March 31, 2004.

(v)

Additional international assignment payments to Mr. Wright of $27,739 for the year ended March 31, 2005, $45,299 for the year ended March 31, 2004, and $56,656 for the year ended March 31, 2003, for cost of living and foreign service premium. Also includes international assignee localization payments to Mr. Wright of $101,609 for the year ended March 31, 2005.

(e)

On March 31, 2005, the aggregate value of all restricted stock holdings, based on the market value of ScottishPower American Depository Shares at March 31, 2005, without giving effect to the diminution of value attributed to the restrictions on such stock, was $38,220 for Ms. Johansen, $14,352 for Mr. Pittman, $30,420 for Mr. Haller and $14,352 for Mr. Walje. The aggregate number of restricted share holdings was 1,225 for Ms. Johansen, 460 for Mr. Pittman, 975 for Mr. Haller and 460 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.

(f)	Represents the dollar value of restricted stock shares awarded under the PSIP prior to PacifiCorp’s acquisition by ScottishPower that vested and were distributed to the named officer in the form of ScottishPower American Depository Shares.

(g)	Represents the number of ScottishPower American Depository Shares contingently granted in 2005, 2004 and 2003 that can be earned under the terms of the LTIP.

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Option Grants in Last Fiscal Year

The following table sets forth information regarding options to purchase ScottishPower American Depository Shares granted during the year ended March 31, 2005, to each named executive officer under the 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.

Name	Individual Grants

	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	52,228	6.84	%	$	28.72	5/26/2014	$	943,334	$	2,390,595
Michael J. Pittman	33,948	4.44			28.72	5/26/2014		613,164		1,553,877
Andrew P. Haller	11,667	1.53			28.72	5/26/2014		210,728		534,025
A. Richard Walje	16,613	2.17			28.72	5/26/2014		300,062		760,415
Matthew R. Wright	15,331	2.01			28.72	5/26/2014		276,906		701,735

Aggregated Option Exercises at March 31, 2005, 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 end of the fiscal year ended March 31, 2005, for each of the named executive officers. All options are for ScottishPower American Depository Shares and include options granted under the PSIP and the ExSOP.

Name	Shares Acquired on Exercise	Value Realized		Number of Securities Underlying Unexercised Options at March 31, 2005		Value of Unexercised In-the-Money Options at March 31, 2005

				Exercisable	Unexercisable	Exercisable		Unexercisable

Judith A. Johansen	152,603	$	711,077	—	124,125	$	—	$	644,701
Michael J. Pittman	65,385		286,932	158,088	85,245		8		454,666
Andrew P. Haller	27,703		95,713	—	31,334		—		171,720
A. Richard Walje	44,957		207,618	126,069	42,247		—		227,241
Matthew R. Wright (a)	—		—	3,329	37,536		—		65,636

(a)	Certain of Mr. Wright’s options are for ScottishPower Ordinary Shares, but are presented as American Depository Shares.

Long-Term Incentive Plan Awards in the Last Fiscal Year

The following table sets forth information regarding awards made in the year ended March 31, 2005, to each named executive officer under the LTIP. Each LTIP award entitles the executive officer to acquire, at no cost, the number of ScottishPower American Depository Shares listed in the table, less any withholding for applicable taxes. An award will only vest if the Remuneration Committee is satisfied that certain performance measures related to the sustained underlying financial performance of the ScottishPower group and improvements in customer service standards are achieved over a period of three years commencing with the fiscal year preceding the date an award is made. The number of shares that vest depend upon ScottishPower’s comparative Total Shareholder Return performance over the three-year performance period. Total Shareholder Return performance is measured against a peer group of major international energy companies. No shares vest unless ScottishPower’s Total Shareholder Return performance is at

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least equal to the median performance of the peer group, at which point 40% of the initial award vests. If ScottishPower’s performance is equal to or exceeds the top quartile, 100% of the shares vest. The number of shares that vest for performance between these two points is determined on a straightline basis. Participants may acquire the vested shares at any time after the third anniversary of grant.

Name	Number of Shares, Units or Other Rights	Performance or Other Period Until Maturation or Payout	Estimated Future Payouts Under Non-Stock Price-Based Plans

			Exercise or Threshold Shares	Target Shares (a)	Maximum Shares

Judith A. Johansen	19,916	3 years	—	7,966	19,916
Michael J. Pittman	6,904	3 years	—	2,762	6,904
Andrew P. Haller	4,746	3 years	—	1,898	4,746
A. Richard Walje	6,757	3 years	—	2,703	6,757
Matthew R. Wright	6,236	3 years	—	2,494	6,236

(a)	Amount to vest if threshold measures and median Total Shareholder Return performance are achieved.

Employment Agreements

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 in the LTIP, the ExSOP and the Retirement Plan referred to below, in addition to other benefit plans available for senior-level executives of PacifiCorp. The employment agreement continues until March 31, 2021, unless terminated by either party. 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, Ms. Johansen agreed to standard confidentiality, non-competition and non-solicitation terms.

On December 9, 2004, Mr. Pittman and PacifiCorp executed an employment agreement providing for a base salary of $325,000 and a maximum annual incentive award of 100.0% of base salary (unless otherwise modified by the Remuneration Committee). Under the agreement, he is eligible for participation in the LTIP, the ExSOP and the Retirement Plan, in addition to other benefit plans available for senior level executives of PacifiCorp. The employment agreement continues until Mr. Pittman reaches the age of 65, unless terminated by either party. Mr. Pittman or PacifiCorp may terminate the employment agreement at any time for any reason. However, if Mr. Pittman resigns from PacifiCorp due to a material alteration in compensation or assignment or following a company-initiated relocation, or if PacifiCorp terminates Mr. Pittman without cause, then Mr. Pittman will be entitled to one year’s base salary, car allowance and bonus (as modified pursuant to the terms of the employment agreement). Additionally, Mr. Pittman agreed to standard 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 PacifiCorp Board of Directors, 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.

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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 PacifiCorp Board of Directors 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 PacifiCorp Board of Directors. 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 “SERP”). The following description assumes participation in both the Retirement Plan and the SERP. 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 AIP payments reflected in the Summary Compensation Table above. Benefits are based on 50.0% of final average pay plus 1.0% of final average pay for each year that PacifiCorp meets certain performance goals set for each fiscal year by the PacifiCorp Board of Directors. The maximum benefit is 65.0% of final average pay. 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 SERP.

The following table shows the estimated annual retirement benefit payable upon retirement at age 60 as of March 31, 2005. Amounts in the table reflect payments from the Retirement Plan and the SERP combined, prior to any offset of projected social security benefits and benefits paid from any prior employer plan.

Estimated Annual Pension at Retirement (a)

Final Average Pay at Retirement Date		Years of Service (b)

		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 Retirement Plan and the SERP will continue in their present form and that PacifiCorp achieves its performance goals under the SERP in all years.

(b)	The number of credited years of service used to compute aggregate benefits under the Retirement Plan and the SERP are four for Ms. Johansen, four for Mr. Haller, 25 for Mr. Pittman, 19 for Mr. Walje and 17 for Mr. Wright.

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Retention Agreements

To retain executives who would otherwise have had the right to resign for any reason between 12 and 14 months following the merger with ScottishPower 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 required 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 was a subsequent “involuntarily termination” or “material alteration” in position as defined in the Severance Plan, this waiver of severance benefits applied 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 vested over a three-year retention period at 25.0% for each of the first two years and 50.0% in the third year.

As noted above, the retention agreements for Messrs. Pittman and Walje expired on November 28, 2004. The executives have satisfied the requirements of, and have received the remuneration and benefits payable under, those agreements.

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ITEM 12.

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

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, 2005, regarding the beneficial ownership of 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 of PacifiCorp as a group. As of March 31, 2005, 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.

	Amount and Nature of Beneficial Ownership

Beneficial Owner	Direct and Indirect (a)	Options (b)	Total


Ian M. Russell	133,570	498,678	632,248
Judith A. Johansen	103,332	480,868	584,200
Michael J. Pittman	115,238	984,704	1,099,942
Andrew P. Haller	64,887	128,296	193,183
A. Richard Walje	102,719	673,120	775,839
Barry G. Cunningham	45,020	472,036	517,056
Nolan E. Karras	42,446	—	42,446
Andrew N. MacRitchie	14,949	99,468	114,417
Richard D. Peach	14,582	75,237	89,819
Matthew R. Wright	7,445	80,574	88,019

All executive officers and directors as a group (14 persons)	748,656	4,444,765	5,193,421

(a)	Includes beneficial 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 the Savings Plan.

(b)

Includes Ordinary Shares that each person has the right to acquire through options that become exercisable within 60 days after March 31, 2005. Options granted in ScottishPower American Depository Shares under the PSIP and ExSOP have been converted into options in Ordinary Shares. One American Depository Share equates to four Ordinary Shares.

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 $121,253.09 of the loan amount. As of March 31, 2005, the outstanding loan balance was $81,548.92, including accrued interest, payable in two additional annual payments of $32,988.56 each and one of $19,741.67, including interest at the annual rate of 4.74%, on June 30 in each year from 2005 to 2007.

See “Item 8. Financial Statements and Supplementary Data - Note 4” 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, 2005, and the year ending March 31, 2006.

Fees and Pre-Approval Policy

During the year ended March 31, 2004, the 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 billed by PricewaterhouseCoopers for the fiscal years ended March 31, 2005 and 2004.

(Millions of dollars)	Year Ended March 31,

	2005				2004

Audit fees	$	1.4	30.4	%	$	1.4	28.6	%
Audit-related fees		1.1	23.9			0.1	2.0
Tax fees		2.0	43.5			3.3	67.4
Other fees		0.1	2.2			0.1	2.0

Total	$	4.6	100.0	%	$	4.9	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

(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, as amended May 23, 2005.
4.1*		Mortgage and Deed of Trust dated as of January 9, 1989, between PacifiCorp and JP Morgan Chase Bank (formerly known as The Chase Manhattan Bank), Trustee, Ex. 4-E, Form 8-B, File No. 1-5152, as supplemented and modified by 17 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, 1993	1-5152
(4)b	10-Q	Quarter ended June 30, 1994	1-5152
(4)b	10-K	Year ended December 31, 1994	1-5152
(4)b	10-K	Year ended December 31, 1995	1-5152
(4)b	10-K	Year ended December 31, 1996	1-5152
4(b)	10-K	Year ended December 31, 1998	1-5152
99(a)	8-K	November 21, 2001	1-5152
4.1	10-Q	Quarter ended June 30, 2003	1-5152
99	8-K	September 8, 2003	1-5152
4	8-K	August 24, 2004	1-5152

120

4.2*

Third Restated Articles of Incorporation and Bylaws. See 3.1 and 3.2 above.

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

10.1		Summary of Key Terms of Compensation Arrangements with PacifiCorp Named Executive Officers.

10.2*		Summary of PacifiCorp Annual Incentive Plan for Executive Officers (Exhibit 10.2, Current Report on Form 8-K, filed May 6, 2005, File No. 1-5152).

10.3		Judith Johansen Employment Agreement.

10.4		Michael Pittman Employment Agreement.

10.5		Compensation Reduction Plan.

10.6*		Executive Severance Plan (Exhibit 10.3, Current Report on Form 8-K, filed May 6, 2005, File No. 1-5152).

10.7		Supplemental Executive Retirement Plan.

10.8		Michael Pittman Retention Agreement.

10.9		A. Richard Walje Retention Agreement.

10.10*		Richard Peach Retention Agreement (Exhibit 10.4, Current Report on Form 8-K, filed May 6, 2005, File No. 1-5152).

10.11		Andrew Haller Promissory Note.

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.

31.1		Section 302 Certification of Principal Executive Officer Pursuant to Rule 13a-14(a)/15d-14(a).

31.2		Section 302 Certification of Principal Financial Officer Pursuant to Rule 13a-14(a)/15d-14(a).

32.1		Section 906 Certification of Principal Executive Officer Pursuant to 18 U.S.C. Section 1350.

32.2		Section 906 Certification of Principal Financial Officer Pursuant to 18 U.S.C. Section 1350.

99.1*		Stock Purchase Agreement among Scottish Power plc, PacifiCorp Holdings, Inc. and MidAmerican Energy Holdings Company (Exhibit 99.1, Current Report on Form 8-K, filed May 24, 2005, by MidAmerican Energy Holdings Company, File No. 001-14881).

______________

*Incorporated herein by reference.

(c)	See (a) 3. above.

(d)	See (a) 2. above.

121

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 27, 2005

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 27, 2005

Ian M. Russell

/s/ JUDITH A. JOHANSEN	President, Chief Executive Officer and Director	May 27, 2005

Judith A. Johansen

/s/ RICHARD D. PEACH	Chief Financial Officer and Director	May 27, 2005

Richard D. Peach

/s/ DAVID MENDEZ	Chief Accounting Officer	May 27, 2005

David Mendez

/s/ NOLAN E. KARRAS	) ) )

Nolan E. Karras
	)
/s/ ANDREW N. MacRITCHIE	) ) )

Andrew N. MacRitchie

122


/s/ MICHAEL J. PITTMAN	) ) )

Michael J. Pittman
	)
/s/ A. RICHARD WALJE	) Director ) )	May 27, 2005

A. Richard Walje
	)
s/ MATTHEW R. WRIGHT	) ) )

Matthew R. Wright
	)
/s/ BARRY G. CUNNINGHAM	) ) )

Barry G. Cunningham
	)
/s/ ANDREW P. HALLER	) ) )

Andrew P. Haller

123