PACIFICORP /OR/ - 10-Q Quarterly Report

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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

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

For the quarterly period ended June 30, 2004

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

For the transition period from _______________ to _______________

Commission file number 1-5152

PacifiCorp

(Exact name of registrant as specified in its charter)

STATE OF OREGON
(State or other jurisdiction
of incorporation or organization)

93-0246090
(I.R.S. Employer Identification No.)

825 N.E. Multnomah Street, Portland, Oregon
(Address of principal executive offices)

97232
(Zip Code)

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

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 twelve 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 at least the past 90 days.

Yes x No o

Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Securities Exchange Act of 1934).

Yes o No x

As of August 6, 2004, there were 312,176,089 shares of common stock outstanding. All shares of outstanding common stock are indirectly owned by Scottish Power plc, 1 Atlantic Quay, Glasgow, G2 8SP, Scotland.

PACIFICORP

		Page No.
PART I.	FINANCIAL INFORMATION

Item 1.	Financial Statements

	Condensed Consolidated Statements of Income and Retained Earnings	2

	Condensed Consolidated Balance Sheets	3

	Condensed Consolidated Statements of Cash Flows	5

	Notes to the Condensed Consolidated Financial Statements	6

	Report of Independent Registered Public Accounting Firm	16

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	17

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	25

Item 4.	Controls and Procedures	29

PART II.	OTHER INFORMATION

Item 1.	Legal Proceedings	29

Item 5.	Other Information	30

Item 6.	Exhibits and Reports on Form 8-K	33

Signature		34

PART I. FINANCIAL INFORMATION

ITEM 1.

FINANCIAL STATEMENTS

PACIFICORP
CONDENSED CONSOLIDATED STATEMENTS OF INCOME AND RETAINED EARNINGS
(Unaudited)

	Three Months Ended June 30,

(Millions of dollars)	2004			2003

Revenues:
Residential	$	211.8		$	227.2
Commercial		211.0			199.2
Industrial		202.1			177.4
Other retail revenues		9.1			8.7
Wholesale sales		81.2			139.9
Other		32.6			31.5

Total		747.8			783.9

Operating expenses:
Purchased electricity		139.9			153.6
Fuel		114.4			116.7
Operations and maintenance		236.3			216.9
Depreciation and amortization		107.6			104.1
Taxes, other than income taxes		23.9			23.7

Total		622.1			615.0
Other operating income		(4.2	)		—

Income from operations		129.9			168.9

Interest expense and other (income) expense:
Interest expense		65.5			61.1
Interest income		(2.8	)		(4.4	)
Interest capitalized		(3.7	)		(5.6	)
Minority interest and other		(2.0	)		5.9

Total		57.0			57.0

Income from operations before income tax expense and cumulative effect of accounting change		72.9			111.9
Income tax expense		22.0			48.4

Income before cumulative effect of accounting change		50.9			63.5
Cumulative effect of accounting change (less applicable income tax benefit of $(0.6)/2003)		—			(0.9	)

Net income		50.9			62.6
Preferred dividend requirement		(0.5	)		(1.8	)

Earnings on common stock	$	50.4		$	60.8

RETAINED EARNINGS AT BEGINNING OF PERIOD	$	390.1		$	305.9
Net income		50.9			62.6
Cash dividends declared:
Preferred stock		(0.5	)		(1.8	)
Common stock		(48.3	)		(40.1	)

RETAINED EARNINGS AT END OF PERIOD	$	392.2		$	326.6

The accompanying notes are an integral part of these Condensed Consolidated Financial Statements.

PACIFICORP
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)

ASSETS

(Millions of dollars)	June 30, 2004			March 31, 2004

Current assets:
Cash and cash equivalents	$	72.4		$	58.5
Accounts receivable (less allowance for doubtful accounts of $23.8/June and March 2004)		232.1			234.6
Unbilled revenue		161.5			128.3
Amounts due from affiliates		10.5			2.4
Inventories at average cost:
Materials and supplies		101.7			101.0
Fuel		55.7			56.0
Current derivative contract asset		115.8			118.9
Current deferred tax asset		37.3			31.5
Other		53.3			25.2

Total current assets		840.3			756.4

Property, plant and equipment		14,006.0			13,812.8
Construction work in progress		319.8			345.4
Accumulated depreciation and amortization		(5,191.0	)		(5,121.7	)

Total property, plant and equipment - net		9,134.8			9,036.5

Other assets:
Regulatory assets		1,002.7			1,032.3
Derivative contract regulatory asset		356.2			422.2
Non-current derivative contract asset		138.0			110.3
Deferred charges and other		321.1			319.4

Total other assets		1,818.0			1,884.2

Total assets	$	11,793.1		$	11,677.1

The accompanying notes are an integral part of these Condensed Consolidated Financial Statements.

PACIFICORP
CONDENSED CONSOLIDATED BALANCE SHEETS, continued
(Unaudited)

LIABILITIES AND SHAREHOLDERS’ EQUITY

(Millions of dollars)	June 30, 2004			March 31, 2004

Current liabilities:
Accounts payable	$	233.8		$	257.8
Amounts due to affiliates		21.9			2.6
Accrued employee expenses		98.2			140.3
Taxes payable		51.1			50.2
Interest payable		54.1			66.1
Current derivative contract liability		89.7			76.9
Long-term debt and capital lease obligation, currently maturing		399.3			240.0
Preferred stock subject to mandatory redemption, currently maturing		3.7			3.7
Notes payable and commercial paper		330.8			124.9
Other		127.9			111.8

Total current liabilities		1,410.5			1,074.3

Deferred credits:
Income taxes		1,574.7			1,564.6
Investment tax credits		81.5			83.5
Regulatory liabilities		806.4			807.5
Non-current derivative contract liability		517.9			567.1
Other		670.8			683.6

Total deferred credits		3,651.3			3,706.3

Long-term debt and capital lease obligation, net of current maturities		3,361.0			3,520.2
Preferred stock subject to mandatory redemption, net of current maturities		48.8			56.3

Total liabilities		8,471.6			8,357.1

Commitments and contingencies (See Note 6)
Shareholders’ equity:
Preferred stock		41.3			41.3

Common equity:
Common shareholder’s capital		2,892.1			2,892.1
Retained earnings		392.2			390.1
Accumulated other comprehensive income (loss):
Unrealized gain on available-for-sale securities, net of tax of $2.3/June 2004 and $2.7/March 2004		3.9			4.5
Minimum pension liability, net of tax of $(4.9)/June and March 2004		(8.0	)		(8.0	)

Total common equity		3,280.2			3,278.7

Total shareholders’ equity		3,321.5			3,320.0

Total liabilities and shareholders’ equity	$	11,793.1		$	11,677.1

The accompanying notes are an integral part of these Condensed Consolidated Financial Statements.

PACIFICORP
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)

	Three Months Ended June 30,

(Millions of dollars)	2004			2003

Cash flows from operating activities:
Net income	$	50.9		$	62.6
Adjustments to reconcile net income to net cash provided by operating activities:
Cumulative effect of accounting change, net of tax		—			0.9
Unrealized loss (gain) on derivative contracts		4.8			(1.5	)
Depreciation and amortization		107.6			104.1
Deferred income taxes and investment tax credits - net		8.8			13.8
Provision for pension and benefits		(46.7	)		18.6
Deferred net power costs		(0.7	)		(1.8	)
Changes in:
Regulatory assets/liabilities		19.1			28.8
Accounts receivable and prepayments		(52.7	)		(0.3	)
Inventories		(0.3	)		5.9
Amounts due to/from affiliates		4.9			9.2
Accounts payable and accrued liabilities		(61.3	)		(95.4	)
Other		(3.5	)		6.7

Net cash provided by operating activities		30.9			151.6

Cash flows from investing activities:
Capital expenditures		(166.9	)		(157.6	)
Proceeds from available-for-sale securities		6.6			47.1
Purchases of available-for-sale securities		(8.3	)		(45.2	)
Other		2.0			(4.1	)

Net cash used in investing activities		(166.6	)		(159.8	)

Cash flows from financing activities:
Changes in short-term debt		205.9			30.0
Dividends paid		(48.8	)		(41.9	)
Redemptions of preferred stock		(7.5	)		(7.5	)
Other		—			(0.4	)

Net cash provided by (used in) financing activities		149.6			(19.8	)

Change in cash and cash equivalents		13.9			(28.0	)
Cash and cash equivalents at beginning of period		58.5			152.5

Cash and cash equivalents at end of period	$	72.4		$	124.5

The accompanying notes are an integral part of these Condensed Consolidated Financial Statements.

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

Note 1 - Basis of Presentation and Summary of Significant Accounting Policies

PacifiCorp (which includes PacifiCorp and its subsidiaries) is a United States electricity company operating in the states of Utah, Oregon, Wyoming, Washington, Idaho and California. PacifiCorp generates electricity and conducts its retail electric utility business as Pacific Power and Utah Power and also engages in electricity sales and purchases on a wholesale basis. The Condensed Consolidated Financial Statements of PacifiCorp include its integrated electric utility operations and its wholly owned and majority-owned subsidiaries. The subsidiaries of PacifiCorp support its electric utility operations by providing coal mining facilities and services and environmental remediation. Intercompany transactions and balances have been eliminated upon consolidation. PacifiCorp is an indirect subsidiary of Scottish Power plc (“ScottishPower”).

The accompanying unaudited Condensed Consolidated Financial Statements as of June 30, 2004 and for the three months ended June 30, 2004 and 2003, in the opinion of management, include all adjustments, constituting only normal recurring adjustments, necessary for a fair presentation of financial position, results of operations and cash flows for such periods. The March 31, 2004 Condensed Consolidated Balance Sheet data was derived from audited financial statements. These statements as of June 30, 2004 and for the three months ended June 30, 2004 and 2003, are presented in accordance with the interim reporting requirements of the Securities and Exchange Commission (“SEC”), which do not include all of the disclosures required by accounting principles generally accepted in the United States of America. Certain information and footnote disclosures made in PacifiCorp’s Annual Report on Form 10-K for the year ended March 31, 2004, have been condensed or omitted from the interim statements. A portion of the business of PacifiCorp is of a seasonal nature and, therefore, results of operations for the three months ended June 30, 2004 and 2003 are not necessarily indicative of the results for a full year. These Condensed Consolidated Financial Statements should be read in conjunction with the financial statements and related notes in PacifiCorp’s Annual Report on Form 10-K for the year ended March 31, 2004.

These interim statements have been prepared using accounting policies consistent with those applied at March 31, 2004, except in relation to new accounting standards.

During the three months ended June 30, 2004, PacifiCorp changed the estimated average lives of certain computer software systems to reflect operational plans. This change will reduce amortization expense by approximately $12.9 million annually on existing computer software systems, with an annual impact to net income of approximately $8.0 million.

Reclassifications

Certain amounts have been reclassified to conform to the current method of presentation. These reclassifications had no effect on previously reported consolidated net income or shareholders’ equity.

Stock-based Compensation

PacifiCorp has elected to account for its stock-based compensation arrangements under the intrinsic value recognition and measurement principles prescribed by Accounting Principles Board Opinion No. 25, Accounting for Stock Issued to Employees, whereby the options are granted with an exercise price that equals the market price of the underlying stock on the date of grant and therefore no compensation expense is recorded. All options are for ScottishPower American Depository Shares. Had PacifiCorp determined compensation cost based on the fair value recognition principles of Statement of Financial Accounting Standards (“SFAS”) No. 123, Accounting for Stock-Based Compensation, PacifiCorp’s net income would have been changed to the following pro forma amounts:

	Three Months Ended June 30,

(Millions of dollars)	2004			2003

Net income as reported	$	50.9		$	62.6
Stock-based employee compensation expense		(0.1	)		(0.4	)

Pro forma net income	$	50.8		$	62.2

New Accounting Standards

FSP SFAS No. 106-2

In May 2004, the Financial Accounting Standards Board (“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 Act for employers that sponsor postretirement health care plans that offer prescription drug benefits and requires those employers to disclose the effect of the federal subsidy afforded by the Medicare Act. For entities that elected deferral under FSP SFAS No. 106-1, Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (“FSP SFAS No. 106-1”), and for which the impact is significant, FSP SFAS No. 106-2 is effective for the first interim or annual period beginning after June 15, 2004. When FSP SFAS No. 106-2 becomes effective, or upon earlier adoption if elected, it supercedes FSP SFAS No. 106-1. Early adoption is encouraged. PacifiCorp has elected to adopt FSP SFAS No. 106-2 early. 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 effect of the Medicare Act decreased net periodic postretirement benefit cost for the three months ended June 30, 2004, when compared to the expense calculated prior to the adoption of FSP SFAS No. 106-2, as follows:

(Millions of dollars)
Effect on:
Interest cost	$	(0.7	)
Amortization of unrecognized loss		(0.7	)

Net periodic postretirement benefit cost	$	(1.4	)

EITF No. 03-1

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. While the disclosure requirements of EITF No. 03-1 were effective for annual financial statements for years ending after December 15, 2003, the recognition and measurement guidance of EITF No. 03-1 should be applied to other-than-temporary impairment evaluations in reporting periods beginning after June 15, 2004. The adoption of the recognition and measurement guidance of EITF No. 03-1 is not anticipated to have a material impact on PacifiCorp’s consolidated financial position or results of operations.

Note 2 - Accounting for the Effects of Regulation

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) in accordance with the provisions of SFAS No. 71, Accounting for the Effects of Certain Types of Regulation. The final outcome, or additional regulatory actions, could change management’s assessment in future periods.

Regulatory assets include the following:

(Millions of dollars)	June 30, 2004		March 31, 2004

Deferred taxes	$	512.3	$	519.1
Minimum pension liability offset		226.2		226.2
Deferred net power costs (a)		46.0		57.8
Unamortized issuance expense on retired debt (b)		38.8		40.6
Demand-side resource costs		34.9		40.1
Transition Plan costs - retirement and severance		35.0		38.2
Other regulatory assets		109.5		110.3

Subtotal		1,002.7		1,032.3
Derivative contracts (c)		356.2		422.2

Total	$	1,358.9	$	1,454.5

(a)

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

(b)

Represents the unamortized debt expense and redemption premiums on securities retired prior to maturity.

(c)

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

Regulatory liabilities include the following:

(Millions of dollars)	June 30, 2004		March 31, 2004

Accrued removal costs (a)	$	675.9	$	670.6
Centralia gain		38.0		43.7
Deferred income taxes		35.4		36.2
Other regulatory liabilities		57.1		57.0

Total	$	806.4	$	807.5

(a)

Represents removal costs recovered in rates that do not qualify as asset retirement obligations under SFAS No. 143, Accounting for Asset Retirement Obligations (“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 actions 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.

Note 3 - Derivative Instruments

PacifiCorp’s derivative instruments are recorded on the Condensed Consolidated Balance Sheets as assets or liabilities measured at estimated fair value, unless they qualify for certain exemptions permitted under SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities (“SFAS No. 133”), as amended. Changes in fair value of PacifiCorp’s recorded derivative contracts are recognized immediately to earnings, except for contracts that have received regulatory approval for recovery in retail rates. Such changes in fair value are deferred as regulatory assets or liabilities until realized. Unrealized and realized gains and losses from all derivative contracts held for “trading” purposes, including those where physical delivery is required, are recorded net. PacifiCorp netted trading contracts totaling 444,696 megawatt-hours (“MWh”) for the three months ended June 30, 2004 and 344,578 MWh for the three months ended June 30, 2003. Realized gains and losses from derivative contracts not held for trading purposes are recorded gross unless the contracts do not result in physical delivery.

The following table summarizes the changes in fair value of PacifiCorp’s derivative contracts executed for balancing system resources and load obligations (non-trading), and for taking advantage of arbitrage opportunities (trading) for the three months ended June 30, 2004:

							Regulatory Net Asset (Liability)
	Net Asset (Liability)

(Millions of dollars)	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		0.8			(9.8	)		9.8
Other changes in fair values (a)		1.1			68.9			(75.8	)

Fair value of contracts outstanding at June 30, 2004	$	1.4		$	(355.2	)	$	356.2

(a)

Other changes in fair values result from new transactions and the effects of changes in prices, including those based on models on new and existing contracts.

Weather derivatives - PacifiCorp estimates and records an asset or liability corresponding to the total expected future cash flow from its non-exchange traded weather derivatives in accordance with EITF No. 99-2, Accounting for Weather Derivatives. The recorded liability for these contracts was $10.2 million at June 30, 2004 and $5.3 million at March 31, 2004. PacifiCorp recognized a gain on these contracts of $3.9 million for the three months ended June 30, 2004 and a loss of $4.3 million for the three months ended June 30, 2003.

Note 4 – Related-Party Transactions

There are no loans or advances between PacifiCorp and ScottishPower or between PacifiCorp and PacifiCorp Holdings, Inc. (“PHI”), PacifiCorp’s direct parent. Loans from PacifiCorp to ScottishPower or PHI are prohibited under the Public Utility Holding Company Act of 1935. 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 from PacifiCorp Group Holdings Company (“PGHC”) to PacifiCorp, 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.

Commencing on April 1, 2004, PacifiCorp and Scottish Power UK plc (“SPUK”), an indirect subsidiary of ScottishPower, implemented a cross-charge policy agreement governing the allocation of costs incurred by PacifiCorp and SPUK, on behalf of each other. These charges to PacifiCorp, at cost, are estimated to be in the range of $14.0 million to $17.0 million annually on a net basis. These cross-charges commenced during the three months ended June 30, 2004 and were recorded in Operations and maintenance expense. For the three months ended June 30, 2004, these charges amounted to $3.6 million.

In May 2002, PacifiCorp entered into a 15-year operating lease for an electric generation facility with West Valley Leasing Company, LLC (“West Valley”). West Valley is a subsidiary of PPM Energy, Inc. (“PPM”), which is a direct subsidiary of PHI. The facility consists of five generation units, each rated at 40 megawatts (“MW”), and is located in Utah. PacifiCorp holds two independent early termination options that provide PacifiCorp the right to terminate the lease early 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 has the right, by notice given on or before September 30, 2004, to rescind the termination. In this period between exercise of the first termination option and the deadline for its rescission, PacifiCorp is seeking proposals for a replacement of this 200 MW leased resource pursuant to a request for proposals. In the event that the resource cannot be replaced on a more economic basis, PacifiCorp may rescind the termination notice prior to September 30, 2004 and continue the lease. If the termination notice is rescinded, 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.

The following tables detail PacifiCorp’s transactions and balances with unconsolidated related parties:

(Millions of dollars)	June 30, 2004		March 31, 2004

Amounts due from affiliated entities:
ScottishPower (a)	$	0.6	$	0.2
PHI subsidiaries (b)		9.9		2.2

	$	10.5	$	2.4

Prepayments to affiliated entities:
PHI subsidiaries (c)	$	1.0	$	1.5

Amounts due to affiliated entities
ScottishPower (d)	$	9.2	$	2.6
PHI subsidiaries (e)		12.7		—

	$	21.9	$	2.6

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


	Three Months Ended June 30,

(Millions of dollars)	2004		2003

Revenues from affiliated entities:
PHI subsidiaries (f)	$	2.2	$	1.0

Expenses incurred from affiliated entities:
ScottishPower (d)	$	6.6	$	1.9
PHI subsidiaries (c)		4.2		4.2

	$	10.8	$	6.1

Expenses recharged to affiliated entities:
ScottishPower (a)	$	0.6	$	0.3
PHI subsidiaries (b)		2.1		2.0

	$	2.7	$	2.3

Interest expense to affiliated entities:
PHI subsidiaries (g)	$	—	$	0.1

(a)

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

(b)

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

(c)

These expenses primarily relate to operating lease payments for the West Valley facility. Certain costs associated with the West Valley lease are prepaid on an annual basis.

(d)

These expenses and liabilities primarily represent allocated costs under the affiliated interest cross-charge policy with SPUK, effective April 1, 2004 and payroll costs and related benefits of SPUK employees working for PacifiCorp in the United States.

(e)

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

(f)

These revenues and the associated deposit relate to wheeling services billed to PPM, a subsidiary of PHI.

(g)

Includes interest on short-term demand loans made to PacifiCorp by PGHC, a direct subsidiary of PHI, in accordance with regulatory authorization. Interest rates on related-party transactions approximate the lender’s short-term borrowing cost or cost of capital as required by the relevant regulatory approval or exemption. The average applicable rate was 1.4% for the three months ended June 30, 2003. There were no loans outstanding between PacifiCorp and PGHC during the three months ended June 30, 2004.

Note 5 - Financing Arrangements

At June 30, 2004, 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 May 28, 2004 and was used to replace an expiring $500.0 million facility, as well as a $300.0 million facility that was terminated by PacifiCorp prior to its maturity. The interest on advances under this new facility is based on the London Interbank Offered Rate (LIBOR) plus a margin that varies based on PacifiCorp’s credit rating.

PacifiCorp’s credit agreements contain customary covenants and default provisions, including covenants not to exceed a specified debt-to-capitalization ratio. PacifiCorp monitors these covenants on a regular basis in order to ensure that events of default will not occur. As of June 30, 2004, PacifiCorp was in compliance with the covenants of its credit agreements.

Note 6 - Commitments and Contingencies

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

Litigation

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

From time to time, PacifiCorp is also a party to various other legal claims, actions and complaints, certain of which involve material amounts. Although PacifiCorp is unable to predict with certainty whether it will ultimately be successful in these legal proceedings 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.

Environmental Issues

PacifiCorp is subject to numerous environmental laws, including the Federal Clean Air Act, as enforced by the EPA and various state agencies; the 1990 Clean Air Act Amendments; the Endangered Species Act of 1973, particularly as it relates to certain endangered species of fish; the Comprehensive Environmental Response, Compensation and Liability Act of 1980, relating to environmental cleanups; and the Resource Conservation and Recovery Act of 1976 and the Clean Water Act, relating to water quality. These laws could potentially impact future operations. Contingencies identified at June 30, 2004, principally consist of Clean Air Act matters. Pending or proposed air regulations will require PacifiCorp to reduce its power 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 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. PacifiCorp in the future may incur significant costs to comply with various tighter 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.

Hydroelectric Relicensing

PacifiCorp’s hydroelectric portfolio consists of 54 plants with a plant net capability of 1,164.0 MW. Ninety-seven percent of the installed capacity is regulated by the FERC through 20 individual licenses. 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 $52.0 million in costs as of June 30, 2004, for ongoing hydroelectric relicensing that are reflected in assets on the Condensed Consolidated Balance Sheet. In May 2004, PacifiCorp accepted the new license for the Bear River hydroelectric project. PacifiCorp is committed, over the life of the license, to fund approximately $28.1 million for environmental mitigation and enhancement projects. A $12.2 million liability, representing the present value of these obligations, was recorded during the three months ended June 30, 2004. For the North Umpqua hydroelectric project, the new FERC license is effective, but not final. When the license for this project becomes final, PacifiCorp will be committed, over the life of the license, to fund approximately $51.1 million for environmental mitigation and enhancement projects. A $13.0 million liability, representing the present value of certain obligations specified in the license, was recorded during the three months ended June 30, 2004. Additional liabilities will be recognized when the license becomes final. PacifiCorp expects that these and future costs will be included in rates and, as such, will not have a material adverse impact on PacifiCorp’s consolidated results of operations.

Swift Power Canal

On April 21, 2002, a failure occurred to the Swift No. 2 power canal 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 MW Swift No. 1 hydroelectric facility, which is upstream of the Swift No. 2 power canal. The full impact of the Swift power canal outage on the operations and capacity of Swift No. 1 hydroelectric facility, and plans for repair of the Swift No. 2 power canal, are currently under review. 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. These developments are not expected to have a significant impact on PacifiCorp’s consolidated financial position or results of operations.

Enron Corp. Reserves

In December 2001, Enron Corp. declared bankruptcy and defaulted on certain wholesale contracts. PacifiCorp has provided reserves for its Enron Corp. receivable, net of the effect of applying the master netting agreement with Enron Corp., in the amount of $8.0 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 previously established a reserve of $17.7 million for these potential refunds. PacifiCorp’s ultimate exposure to refunds is dependent upon any order issued by the FERC in this proceeding. 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 provided reserves for these receivables in the amount of $6.3 million.

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. 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 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. Following a series of procedural motions, as of April 2004 PacifiCorp’s appeal is pending in the Ninth Circuit Court of Appeals.

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

The Bonneville Power Administration 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 Bonneville Power Administration (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 in the aggregate annual amount of approximately $119.2 million for fiscal years 2002 through 2006. On May 28, 2004, PacifiCorp and the BPA executed an additional agreement that provides for a guaranteed range of benefits for fiscal years 2007 thriugh 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 overall BPA 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 benefit 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.

Note 7 – Retirement Benefit Plans

The components of net periodic benefit cost for the three months ended June 30 are as follows:

	Retirement Plans						Other Postretirement Benefits

(Millions of dollars)	2004			2003			2004			2003

Service cost (a)	$	6.5		$	5.2		$	2.1		$	1.9
Interest cost (a)		18.4			18.5			7.7			8.6
Expected return on plan assets		(19.4	)		(20.2	)		(6.6	)		(6.6	)
Amortization of unrecognized net obligation		2.1			2.1			3.1			3.1
Amortization of unrecognized prior service cost		0.4			0.4			—			—
Amortization of unrecognized loss (a)		2.1			—			0.2			0.1

Net periodic benefit cost	$	10.1		$	6.0		$	6.5		$	7.1

(a) Results for the three months ended June 30, 2004 for Other postretirement benefits reflect the impact of the new Medicare provisions described in Note 1.

Employer Contributions

PacifiCorp previously disclosed in its financial statements for the year ended March 31, 2004, that it expected to contribute $67.8 million to its retirement plans and $31.7 million to its other postretirement benefit plan during the year ending March 31, 2005. As of June 30, 2004, PacifiCorp has made contributions of $62.4 million to its retirement plans and $0.3 million to its other postretirement benefit plan. PacifiCorp currently anticipates contributing an additional $5.4 million to its retirement plans and $25.7 million to its other postretirement benefit

plan during the year ending March 31, 2005, for a total of $67.8 million to its retirement plans and $26.0 million to its other postretirement benefit plan.

Note 8 - Income Taxes

PacifiCorp uses an estimated annual effective tax rate for computing the provision for income taxes on an interim basis.

PacifiCorp accrued federal and state income tax expense of $22.0 million for the three months ended June 30, 2004 and $48.4 million for the three months ended June 30, 2003.

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

	Three Months Ended June 30,

	2004		2003

Federal statutory rate	35.0	%	35.0	%
Effect of regulatory treatment of depreciation differences	3.4		5.2
State taxes, net of federal benefit	3.2		3.3
Tax reserves	(8.4	)	3.0
Tax credits	(3.1	)	(2.3	)
Other	0.1		(0.9	)

Effective income tax rate	30.2	%	43.3	%

PacifiCorp has established, and periodically reviews, an estimated contingent tax reserve on its Condensed Consolidated Balance Sheets to provide for the possibility of adverse outcomes in tax proceedings. During the three months ended June 30, 2004, 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. This release was partially offset by an increase to the tax contingency reserve of $2.3 million primarily to accrue interest on remaining tax contingencies provided for in prior periods. The resulting change in the tax contingency reserve during the three months ended June 30, 2004, was a net reduction of $6.2 million.

The Internal Revenue Service is currently examining PacifiCorp’s federal tax return filings for the 1999 and 2000 tax years. PacifiCorp has reached an agreement in principle with the Internal Revenue Service on certain tax issues related to these returns. PacifiCorp believes that final settlement and payment on agreed upon issues and other unresolved issues related to federal income tax returns through March 31, 2000 will not have a material adverse impact on its consolidated financial position or results of operations.

Note 9 - Comprehensive Income

The components of comprehensive income are as follows:

	Three Months Ended June 30,

(Millions of dollars)	2004			2003

Net income	$	50.9		$	62.6
Other comprehensive income:
Unrealized (loss) gain on available-for-sale securities, net of taxes: $(0.4)/2004 and $2.4/2003		(0.6	)		2.7

Total comprehensive income	$	50.3		$	65.3

Note 10 - Independent Registered Public Accounting Firm Review Report

PacifiCorp’s Quarterly Reports on Form 10-Q are incorporated by reference into various filings under the Securities Act of 1933 (the “Act”). PacifiCorp’s independent registered public accountants are not subject to the liability provisions of Section 11 of the Act for their report on the unaudited condensed consolidated financial information because such report is not a “report” or a “part” of a registration statement prepared or certified by an independent registered public accounting firm within the meaning of Sections 7 and 11 of the Act.

Note 11 - Subsequent Events

On July 15, 2004, PacifiCorp’s Board of Directors declared a dividend on common stock of $0.155 per share totaling $48.3 million and payable on August 26, 2004.

On August 4, 2004, PacifiCorp filed a general rate case request with the Utah Public Service Commission 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. The filing, which includes a request for a forward-looking test year, represents a 9.6% increase in rates and a requested return on equity of 11.125%. The case is expected to be resolved by April 2005.

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of PacifiCorp:

We have reviewed the accompanying condensed consolidated balance sheet of PacifiCorp and its subsidiaries as of June 30, 2004 and the related condensed consolidated statements of income and retained earnings for each of the three month periods ended June 30, 2004 and 2003 and the condensed consolidated statements of cash flows for the three month periods ended June 30, 2004 and 2003. These interim financial statements are the responsibility of PacifiCorp’s management.

We conducted our review in accordance with standards of the Public Company Accounting Oversight Board (United States). A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with the standards of the Public Company Accounting Oversight Board, the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.

Based on our review, we are not aware of any material modifications that should be made to the accompanying condensed consolidated interim financial statements for them to be in conformity with accounting principles generally accepted in the United States of America.

We previously audited in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet as of March 31, 2004, and the related statements of consolidated income, changes in common shareholder’s equity and of cash flows for the year then ended (not presented herein), and in our report dated May 19, 2004 we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying condensed consolidated balance sheet as of March 31, 2004, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived.


PricewaterhouseCoopers LLP Portland, Oregon
August 12, 2004

ITEM 2.

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 Condensed 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 incorporated municipalities. Wholesale activities are regulated by the Federal Energy Regulatory Commission (“FERC”). PacifiCorp owns, or has interests in, 71 thermal, hydroelectric and wind generating plants with an aggregate nameplate rating of 8,419.5 megawatts (“MW”) and plant net capability of 7,987.0 MW. The FERC and the six state regulatory commissions also have authority over the construction and operation of PacifiCorp’s electric facilities. PacifiCorp delivers electricity through 57,464 miles of distribution lines and 15,763 miles of transmission lines.

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 “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: potential adjustment of regulatory rates to cover costs; new accounting standards; the outcome of litigation; environmental laws; hydroelectric relicensing; power outages; changes in PacifiCorp’s retirement plan contributions; outcome of tax proceedings; supply and demand for energy in fiscal 2005; sufficiency of PacifiCorp’s available funds to meet its liquidity needs; off-balance sheet arrangements; the effect of risk management measures, including use of financial derivatives to manage and mitigate interest rate exposure; and increases or decreases in market interest rates. 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 that could cause actual results to differ materially from the forward-looking statements:

•

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

•

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

•

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

•

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

•

Economic trends that could impact electricity usage;

•

Competition and supply in electricity and natural gas markets;

•

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

•

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

•

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

•

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

•

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

•

Timely and appropriate completion of the Requests for Proposals process; unanticipated construction delays, changes in costs, receipt of required permits and authorizations, and other factors that could affect future generation plants and infrastructure additions; and

•

The risks discussed in PacifiCorp’s Annual Report on Form 10-K for the year ended March 31, 2004 and its other reports filed with the Securities and Exchange Commission (“SEC”)

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

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 results of operations and the reported amounts of assets and liabilities in the Condensed 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 Condensed Consolidated Financial Statements. If estimates and assumptions are different than the actual amounts recorded, adjustments are made in subsequent periods to take into consideration the new information. Critical accounting policies, in addition to certain less significant accounting policies, are discussed with senior members of management and PacifiCorp’s Board of Directors, as appropriate. Those policies that management considers critical are Derivatives, Pensions and Other Postretirement Benefits, Regulation, Unbilled Revenues and Contingencies and are described in PacifiCorp’s Annual Report on Form 10-K for the year ended March 31, 2004, under Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

New Accounting Standards

FSP SFAS No. 106-2

In May 2004, the Financial Accounting Standards Board (“FASB”) released FASB Staff Position (“FSP”) Statement of Financial Accounting Standards (“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 Act for employers that sponsor postretirement health care plans that offer prescription drug benefits and requires those employers to disclose the effect of the federal subsidy afforded by the Medicare Act. For entities that elected deferral under FSP SFAS No. 106-1, Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (“FSP SFAS No. 106-1”), and for which the impact is significant, FSP SFAS No. 106-2 is effective for the first interim or annual period beginning after June 15, 2004. When FSP SFAS No. 106-2 becomes effective, or upon earlier adoption if elected, it supercedes FSP SFAS No. 106-1. Early adoption is encouraged. PacifiCorp has elected to adopt FSP SFAS No. 106-2 early. The effect 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 three months ended June 30, 2004, when compared to the expense calculated prior to the adoption of FSP SFAS No. 106-2, as follows:

(Millions of dollars)
Effect on:
Interest cost	$	(0.7	)
Amortization of unrecognized loss		(0.7	)

Net periodic postretirement benefit cost	$	(1.4	)

EITF No. 03-1

RESULTS OF OPERATIONS

Overview

PacifiCorp’s earnings on common stock for the three months ended June 30, 2004, was $50.4 million, as compared to $60.8 million for the three months ended June 30, 2003. Significant factors affecting results for the three months ended June 30, 2004, included reduced profitability due to lower hydroelectric and thermal generation availability, reduced residential usage due to mild weather in spring 2004, and an increase in Operations and maintenance expense. Operating results improved in June 2004 as compared to the previous two months through a return to more normal weather conditions and thermal generation plants operating at higher levels.

PacifiCorp’s total revenues for the three months ended June 30, 2004, declined by $36.1 million as compared to the prior year period. Wholesale sales declined by $58.7 million, or 42.0%, primarily due to a significant decrease in volumes on both long- and short-term sales contracts and higher unrealized losses on energy sales contracts. The volume decreases were partially offset by higher electricity market prices, driven by a combination of higher natural gas prices in the western United States and below-normal regional hydroelectric generation. Retail revenues increased by $21.5 million, or 3.5%, primarily due to a $36.5 million increase in Commercial and Industrial revenues, partially offset by a $15.4 million decline in Residential revenues. Commercial and Industrial revenues benefited from improved pricing, primarily as a result of higher regulatory rates. The Residential customer class also experienced customer growth and improved pricing; however, this benefit was more than offset by a reduction in usage per customer, primarily due to the milder weather.

Purchased electricity expense declined by 8.9% primarily due to unrealized gains on energy purchase contracts as well as lower volumes on long-term purchase contracts. These decreases were partially offset by higher realized electricity prices, as a result of higher market prices, and an increase in short-term purchases due to lower thermal and hydroelectric availability. Output from PacifiCorp’s thermal plants decreased by 684,269 megawatt-hours (“MWh”), or 6.0%, as compared to the prior year. This decrease resulted from a higher level of planned and unplanned outages, mainly in April and May as compared with the prior year period. Output from PacifiCorp-owned hydroelectric facilities was reduced by 122,352 MWh, or 12.3%, as compared to the prior year period. This decrease in hydroelectric generation resulted from unusually dry conditions in the three months ended June 30, 2004.

Regulatory Actions

In January 2004, the Utah Public Service Commission (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%.

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. The filing, which includes a request for a forward-looking test year, represents a 9.6% increase in rates and a requested return on equity of 11.125%. The case is expected to be resolved by April 2005.

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

Affiliated Interest Cross-Charge Policy

Commencing on April 1, 2004, PacifiCorp and Scottish Power UK plc (“SPUK”), an indirect subsidiary of Scottish Power plc, implemented a cross-charge policy governing the allocation of costs incurred by PacifiCorp and SPUK, on behalf of each other. These charges to PacifiCorp, at cost, are estimated to be in the range of $14.0 million to $17.0 million annually on a net basis. These cross-charges commenced during the three months ended June 30, 2004 and charges amounting to $3.6 million were recorded in Operations and maintenance expense.

Winter Storms Report

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 25 areas of improvement related to problems encountered during the storm. The areas of improvement were grouped into three categories:

•

Initiatives to prevent or mitigate technology problems that impacted the outage management system;

•

Initiatives to address the number of downed secondary and service wires caused by fallen trees; and

•

Recommendations to improve the effectiveness of PacifiCorp’s emergency operating plans.

PacifiCorp has established a program for implementation of the recommendations, outlined in the final 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. In July 2004, the UPSC denied the customers’ petition for “class status” but allowed the individual customers to participate in the existing regulatory winter storm inquiry. The customers subsequently filed a motion for reconsideration with the UPSC, which is pending.

Three Months Ended June 30, 2004 Compared to Three Months Ended June 30, 2003

Revenues

(Millions of dollars)	Three Months Ended June 30,				$ Change			% Change

	2004		2003		Favorable/(Unfavorable)

Residential	$	211.8	$	227.2	$	(15.4	)	(6.8	)%
Commercial		211.0		199.2		11.8		5.9
Industrial		202.1		177.4		24.7		13.9
Other retail revenues		9.1		8.7		0.4		4.6

Retail sales		634.0		612.5		21.5		3.5
Wholesale sales		81.2		139.9		(58.7	)	(42.0	)
Other revenues		32.6		31.5		1.1		3.5

Total revenues	$	747.8	$	783.9	$	(36.1	)	(4.6	)

Energy sales (Thousands of MWh)						MWh Change

Residential		2,921		3,253		(332	)	(10.2	)
Commercial		3,572		3,522		50		1.4
Industrial		5,025		4,676		349		7.5
Other		176		158		18		11.4

Retail sales		11,694		11,609		85		0.7
Wholesale sales		2,844		3,570		(726	)	(20.3	)

Total		14,538		15,179		(641	)	(4.2	)

Average residential usage (kWh)		2,173		2,463		(290	)	(11.8	)
Total customers - end of period (in thousands)		1,573		1,545		28		1.8

Residential revenues decreased $15.4 million, or 6.8%, due to:

•

$28.5 million of decreases from lower average estimated customer usage, primarily due to the impact of milder weather, as compared to the prior year; partially offset by,

•

$6.9 million of increases from higher regulatory rates;

•

$3.8 million of increases relating to growth in the average number of residential customers; and

•

$2.4 million of increases due to a change in price mix, resulting from the level of customer usage at different customer tariffs in the various states that PacifiCorp serves.

Commercial revenues increased $11.8 million, or 5.9%, due to:

•

$7.2 million of increases from higher regulatory rates;

•

$4.7 million of increases relating to growth in the average number of commercial customers; and

•

$3.0 million of increases due to a change in price mix, resulting from the level of customer usage at different customer tariffs in the various states that PacifiCorp serves; partially offset by,

•

$3.1 million of decreases from lower average estimated customer usage.

Industrial revenues increased $24.7 million, or 13.9%, primarily due to:

•

$12.5 million of increases from higher average estimated customer usage;

•

$8.0 million of increases from higher regulatory rates; and

•

$4.0 million of increases due to a change in price mix, resulting from the level of customer usage at different customer tariffs in the various states that PacifiCorp serves.

Wholesale sales decreased $58.7 million, or 42.0%, primarily due to:

•

$33.1 million of decreases from unrealized losses from short-term energy sales contracts recorded at fair value during the three months ended June 30, 2004 as a result of the adoption of SFAS No. 149, Amendment of Statement 133 on Derivative Instruments and Hedging Activities (“SFAS No. 149) on July 1, 2003;

•

$19.3 million of decreases in volumes due to expirations of long-term contracts; and

•

$13.8 million of decreases in volumes resulting from lower hydroelectric generation and lower thermal generating availability; partially offset by,

	•	$7.4 million of increases from higher realized prices due to increases in market prices for long- and short-term transactions.

Operating Expenses

	Three Months Ended June 30,				$ Change			% Change

(Millions of dollars)	2004		2003		Favorable/(Unfavorable)

Purchased electricity	$	139.9	$	153.6	$	13.7		8.9	%
Fuel		114.4		116.7		2.3		2.0
Operations and maintenance		236.3		216.9		(19.4	)	(8.9	)
Depreciation and amortization		107.6		104.1		(3.5	)	(3.4	)
Taxes, other than income taxes		23.9		23.7		(0.2	)	(0.8	)

Total operating expenses	$	622.1	$	615.0	$	(7.1	)	(1.2	)

Purchased electricity expense decreased $13.7 million, or 8.9%, primarily due to:

•

$24.0 million of decreases from unrealized gains from short-term energy purchase contracts recorded at fair value in the three months ended June 30, 2004, as a result of the adoption of SFAS No. 149 on July 1, 2003;

•

$14.1 million of decreases as a result of lower volumes from existing long-term purchase contracts; and

•

$8.2 million of decreases related to favorable changes in fair value on weather hedges compared to the prior year; partially offset by,

•

$19.5 million of increases from higher realized electricity prices on both long- and short-term contracts, as a result of higher market prices;

•

$11.7 million of increases as a result of higher volumes of short-term market purchases resulting from lower thermal plant availability and decreased hydroelectric output; and

•

$1.0 million of increases from higher wheeling expenses resulting from increased volume and increased prices.

Fuel expense decreased $2.3 million, or 2.0%, due to:

•

$11.2 million of decreases relating to lower supply volumes due mainly to a reduction in thermal plant availability; partially offset by,

•

$8.9 million of increases as a result of an increase in the price of coal and natural gas consumed.

Operations and maintenance expense increased $19.4 million, or 8.9%, primarily due to:

•

$7.5 million of increases in employee salary expense and other direct employee expenses;

•

$6.5 million of increases due to higher demand-side management expenses;

•

$4.9 million of increases in consulting and technical service fees;

•

$3.6 million from the affiliated interest cross-charge policy, which became effective April 1, 2004;

•

$3.0 million of increases in contract services related to overhauls; and

•

$2.0 million of increases in liability insurance; partially offset by,

•

$6.1 million of decreases due to the level and timing of capital projects;

•

$1.2 million of decreases in regulatory asset amortization; and

•

$1.0 million of decreases in rent expense.

Depreciation and amortization expense increased $3.5 million, or 3.4%, due to:

•

$3.7 million of increases in depreciation expense due to higher plant in service;

•

$2.1 million of increases in amortization expense due to higher capitalized software balances; and

•

$0.9 million of increases in the amortization of regulatory assets; partially offset by,

•

$3.2 million of decreases in capitalized software amortization following a change in the estimated useful lives of certain computer software systems.

Other Operating Income

Other operating income of $4.2 million for the three months ended June 30, 2004, represents a regulatory asset write-back for income taxes recoverable in the state of Idaho.

Interest and Other (Income) Expense

	Three Months Ended June 30,						$ Change			% Change

(Millions of dollars)	2004			2003			Favorable/(Unfavorable)

Interest expense	$	65.5		$	61.1		$	(4.4	)	(7.2	)%
Interest income		(2.8	)		(4.4	)		(1.6	)	(36.4	)
Interest capitalized		(3.7	)		(5.6	)		(1.9	)	(33.9	)
Minority interest and other (income) expense		(2.0	)		5.9			7.9		133.9

Total	$	57.0		$	57.0		$	—		—

Interest expense increased $4.4 million, or 7.2%, primarily due to:

•

An increase in average amount of debt outstanding, partially offset by a decrease in average interest rates. The increase in average debt outstanding was primarily due to the refinancing of $352.0 million of Preferred securities redeemed in August 2003 with long-term debt. Interest expense of $4.3 million was recorded for the three months ended June 30, 2004, relating to this refinancing debt, while $7.1 million of distributions on the Preferred securities was recorded as Minority interest and other for the three months ended June 30, 2003;

•

Dividends declared on Preferred stock subject to mandatory redemption of $1.0 million were included as interest expense for the three months ended June 30, 2004, in accordance with SFAS No. 150, Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity, which became effective July 1, 2003; and

•

$0.6 million of increases in interest expense on regulatory liabilities.

Interest income decreased $1.6 million, or 36.4%, primarily due to:

•

$1.1 million of decreases in interest income on regulatory assets.

Interest capitalized decreased $1.9 million, or 33.9%, primarily due to:

•

Lower capitalization rates during the three months ended June 30, 2004, due to the impact of higher short-term debt levels on the capitalization rate.

Minority interest and other (income) expense decreased $7.9 million, primarily due to:

•

A decrease of $7.1 million in distributions on Preferred Securities, which were redeemed in August 2003.

Income Tax Expense

Income tax expense decreased $26.4 million primarily due to:

•

Lower levels of income from continuing operations before income taxes and cumulative effect of accounting change for the three months ended June 30, 2004; and

•

$8.5 million of a decrease in the tax contingency reserve resulting from the favorable settlement of PacifiCorp’s 1991 through 1998 Oregon state income tax returns; partially offset by,

•

$2.3 million of an increase to the tax contingency reserve primarily to accrue interest on remaining tax contingencies provided for in prior periods.

Cumulative Effect of Accounting Change

PacifiCorp recorded a $0.9 million after-tax loss from the implementation of SFAS No. 143, Accounting for Asset Retirement Obligations (“SFAS No. 143”), during the three months ended June 30, 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 equity to PacifiCorp’s immediate corporate parent, PacifiCorp Holdings, Inc. (“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 were $30.9 million for the three months ended June 30, 2004, compared to $151.6 million for the three months ended June 30, 2003, primarily due to lower net income of $11.7 million, higher pension funding of $62.7 million in the current period and changes in working capital of $28.8 million.

Investing Activities

Capital spending totaled $166.9 million for the three months ended June 30, 2004, compared to $157.6 million for the three months ended June 30, 2003. The increase was primarily due to expenditures on new generating facilities, in particular the Currant Creek plant.

Financing Activities

Short-Term Debt

PacifiCorp’s short-term debt has increased by $205.9 million during the three months ended June 30, 2004, primarily due to reduced cash from operations and increased capital expenditures.

Revolving Credit and Other Financing Agreements

PacifiCorp’s short-term borrowings and certain other financing arrangements are supported by an $800.0 million facility, with a three-year term that became effective May 28, 2004, and which was used to replace an expiring $500.0 million facility, as well as 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. As of June 30, 2004, this facility was fully available and there were no borrowings outstanding. In addition to this committed credit facility, PacifiCorp had $59.4 million in money market accounts included in Cash and cash equivalents at June 30, 2004, available to meet its liquidity needs. Regulatory authorities limit PacifiCorp to $1.5 billion of short-term debt, of which $330.8 million was outstanding at June 30, 2004, at a weighted average rate of 1.3%.

At June 30, 2004, PacifiCorp had $517.8 million of standby letters of credit and standby bond purchase agreements available to provide credit enhancement and liquidity support for variable-rate pollution-control revenue bond obligations. These committed bank arrangements expire periodically through the year ending March 31, 2006.

Dividends

During the three months ended June 30, 2004, PacifiCorp had the following dividend activity:

•

$48.3 million declared and paid on common stock;

•

$0.5 million declared and paid on Preferred stock; and

•

$1.0 million declared and $1.2 million paid on Preferred stock subject to mandatory redemption.

During the three months ended June 30, 2003, PacifiCorp had the following dividend activity:

•

$40.1 million declared and paid on common stock;

•

$0.5 million declared and paid on Preferred stock; and

•

$1.3 million declared and paid on Preferred stock subject to mandatory redemption.

Preferred Stock Redemptions

PacifiCorp redeemed $7.5 million of Preferred stock subject to mandatory and optional redemption during each of the three months ended June 30, 2004 and 2003.

Cautionary Statement

Management expects existing funds and cash generated from operations, together with existing credit facilities, to be sufficient to fund liquidity requirements for the next 12 months. If market conditions warrant, PacifiCorp may seek to issue long-term debt, or require additional equity through PHI, to more permanently fund its liquidity requirements or refinance short-term or maturing long-term debt.

Future Uses of Cash

Dividends

On July 15, 2004, PacifiCorp’s Board of Directors declared a dividend on common stock of $0.155 per share, totaling $48.3 million and payable on August 26, 2004.

Credit Ratings

PacifiCorp’s credit ratings at June 30, 2004, were as follows:

	Moody’s	S & P

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

Outlook	Negative	Negative

PacifiCorp’s credit ratings are unchanged from March 31, 2004. 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.

For a further discussion of PacifiCorp’s credit ratings, see Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations in PacifiCorp’s Annual Report on Form 10-K for the year ended March 31, 2004.

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 revised FASB Interpretation No. 46, Consolidation of Variable-Interest Entities, an interpretation of Accounting Research Bulletin No. 51. 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. For further information, see Note 11 of Notes to the Consolidated Financial Statements in PacifiCorp’s Annual Report on Form 10-K for the year ended March 31, 2004.

ITEM 3. 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.

Credit Risk

Credit risk relates to the risk of loss that might occur as a result of non-performance by counterparties of their contractual obligations to make or take delivery of electricity, natural gas or other commodities and to make financial settlements thereon. Credit risk may be concentrated to the extent that one or more groups of counterparties have similar economic, industry or other characteristics that would cause their ability to meet contractual obligations to be similarly affected by changes in market or other conditions. In addition, credit risk includes not only the risk that a counterparty may default due to circumstances relating directly to it, but also the risk that a counterparty may default due to circumstances involving other market participants that have a direct or indirect relationship with such counterparty.

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

The following table represents PacifiCorp’s June 30, 2004, distribution of unsecured credit exposure, net of collateral, within its electricity and natural gas portfolio of purchase and sale contracts and takes into account contractual netting rights.

Distribution of Credit Exposure	% of Total

Investment grade - Externally rated	95.4	%
Non-investment grade - Externally rated	2.5
Investment grade - Internally rated	1.7
Non-investment grade - Internally rated	0.4

	100.0	%

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

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

Interest Rate Risk

PacifiCorp is exposed to risk resulting from changes in interest rates as a result of its issuance of variable-rate debt and commercial paper. PacifiCorp manages its interest rate exposure by maintaining a blend of fixed-rate and variable-rate debt and by monitoring the effects of market changes in interest rates. 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. 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 June 30, 2004, PacifiCorp had $872.7 million of variable-rate liabilities and $59.4 million of temporary cash investments. At June 30, 2004, PacifiCorp had no financial derivatives in effect relating to interest rate exposure.

Based on a sensitivity analysis as of June 30, 2004, for a one-year horizon, PacifiCorp estimated that if market interest rates average 1.0% higher (lower), interest expense, net of offsetting impacts in interest income, would increase (decrease) by $8.1 million. Comparatively, based on a sensitivity analysis as of June 30, 2003, for a one-year horizon, had interest rates averaged 1.0% higher (lower), PacifiCorp estimated that interest expense, net of offsetting impacts in interest income, would have increased (decreased) by $4.9 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 June 30, 2004 and 2003. The increase in interest rate sensitivity was primarily due to the increase in outstanding variable-rate

commercial paper and decrease in invested cash. If interest rates changed significantly, PacifiCorp might take actions to manage its exposure to the change. However, due to the uncertainty of the specific actions that might be taken and their possible effects, the sensitivity analysis assumes no changes in PacifiCorp’s financial structure.

Commodity Price Risk

PacifiCorp’s market risk to commodity price change is primarily related to its fuel and electricity commodities, which are subject to fluctuations due to unpredictable factors, such as weather, that impact 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 7,987.0 MW and 15,763-mile transmission system in the western United States and through its wholesale energy purchase and sales activities. Wholesale contracts are utilized to balance PacifiCorp’s physical excess or shortage of net electricity for future months. Financially settled contracts are utilized to further mitigate commodity price risk. PacifiCorp may from time to time enter into other financially settled (temperature-related) derivative instruments that reduce volume and price risk on days with weather extremes. In addition, a financial hydroelectric generation hedge is in place through September 2006 to reduce volume and price risks associated with PacifiCorp’s hydroelectric generation.

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 volumes at each delivery location for each forward time period.

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

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

As of June 30, 2004, PacifiCorp’s estimated potential five-day unfavorable impact on fair value of the electricity and natural gas commodity portfolio over the next 24 months was $13.5 million, as measured by the VaR computations described above, compared to $12.8 million as of June 30, 2003. The average daily VaR (five-day holding periods) for the three months ended June 30, 2004, was $17.0 million. During the three months ended June 30, 2004, the maximum VaR measured was $22.1 million and the minimum VaR measured was $11.9 million. PacifiCorp maintained compliance with its VaR limit procedures during the three months ended June 30, 2004. Changes in markets inconsistent with historical trends or assumptions used could cause actual results to exceed predicted limits.

Fair Value of Derivatives

The following table shows the changes in the fair value of energy-related contracts qualifying as derivatives under SFAS No. 133 from April 1, 2004, to June 30, 2004, segregated between derivative contracts held for trading and non-trading purposes, and quantifies the reasons for the changes.

	Net Asset (Liability)						Regulatory Net Asset (Liability)

(Millions of dollars)	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		0.8			(9.8	)		9.8
Other changes in fair values (a)		1.1			68.9			(75.8	)

Fair value of contracts outstanding at June 30, 2004	$	1.4		$	(355.2	)	$	356.2

(a)

Other changes in fair values result from new transactions and the effects of changes in prices, including those based on models on new and existing contracts.

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

The following table shows summarized information with respect to valuation techniques and contractual maturities of PacifiCorp’s energy-related contracts qualifying as derivatives under SFAS No. 133 as of June 30, 2004.

	Fair Value of Contracts at Period-End

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

Trading:
Prices based on quoted market prices from third-party sources	$	1.4		$	—		$	—		$	—		$	1.4
Prices based on models and other valuation methods		—			—			—			—			—

Total trading	$	1.4		$	—		$	—		$	—		$	1.4

Non-trading:
Prices based on quoted market prices from third-party sources	$	(25.2	)	$	(10.0	)	$	—		$	—		$	(35.2	)
Prices based on models and other valuation methods		49.9			42.6			(92.2	)		(320.3	)		(320.0	)

Total non-trading	$	24.7		$	32.6		$	(92.2	)	$	(320.3	)	$	(355.2	)

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

ITEM 4.

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 quarterly report. PacifiCorp performed an evaluation, under the supervision and with the participation 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 June 30, 2004, the disclosure controls and procedures were effective, in all material respects, in timely alerting management to material information relating to PacifiCorp and its consolidated subsidiaries required to be included in its periodic reports filed pursuant to the Securities Exchange Act of 1934.

There has been no change in PacifiCorp’s internal control over financial reporting that occurred during the quarter ended June 30, 2004, that has materially affected, or is reasonably likely to materially affect, PacifiCorp’s internal control over financial reporting.

PART II. OTHER INFORMATION

ITEM 1.

LEGAL PROCEEDINGS

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.

ITEM 5.

OTHER INFORMATION

REGULATION

PacifiCorp’s Annual Report on Form 10-K for the year ended March 31, 2004, contains information concerning the federal and state regulatory matters in which PacifiCorp is involved. See Item 1. Business - Regulation. Certain developments with respect to those matters are set forth below.

Federal Regulatory Issues

FERC Issues

For a discussion on FERC issues, see Part I – Item 1. Financial Statements – Note 6 – Commitments and Contingencies.

Hydroelectric Actions

Several of PacifiCorp’s hydroelectric plants are in some stage of the relicensing or decommissioning process with the FERC, as discussed under Item 1. Business in PacifiCorp’s Annual Report on Form 10-K for the year ended March 31, 2004. The following provides an update on any changes.

Relicensing

Bear River hydroelectric project – (Bear River, Idaho)

In December 2003, the FERC issued a new 30-year operating license for the 84.5 MW Bear River hydroelectric project. PacifiCorp sought clarification/rehearing on certain elements of the new license, and in March 2004, the FERC issued an order resolving most issues raised in the rehearing request. The license became final and PacifiCorp accepted the new license on May 25, 2004. 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 $28.1 million for environmental mitigation and enhancement projects. A $12.2 million liability, representing the present value of these obligations, was recorded during the three months ended June 30, 2004.

Lewis River hydroelectric projects – (Lewis River, Washington)

PacifiCorp filed new license applications for the 135.0 MW Merwin and 240.0 MW Swift No. 1 hydroelectric projects in April 2004. An application for a new license for the 134.0 MW Yale hydroelectric project was filed with the FERC in April 1999. However, consideration of the Yale application was delayed pending filing of the Merwin and Swift No. 1 applications in order to complete a comprehensive environmental analysis. The FERC is expected to complete its required analysis over the next two years. PacifiCorp continues to work with stakeholders of the Lewis River system to negotiate a comprehensive settlement.

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

In November 2003, the FERC issued a new 35-year operating license for the 185.3 MW North Umpqua hydroelectric project. 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. On May 26, 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 $51.1 million for environmental mitigation and enhancement projects. A $13.0 million liability, representing the present value of certain obligations specified in the license, was recorded during the three months ended June 30, 2004. Additional liabilities 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 over the next year.

State Regulatory Actions

PacifiCorp pursues a regulatory program in all states that it serves, with the objective of keeping rates closely aligned to ongoing costs, as discussed under Item 1. Business in PacifiCorp’s Annual Report on Form 10-K for the year ended March 31, 2004. The following provides a state-by-state update on any changes.

Utah

Wyoming

In March 2003, the Wyoming Public Service Commission (the “WPSC”) denied recovery of the Hunter No. 1 replacement power costs and the deferred net power costs. Following rehearing petitions and petition with the Laramie County District Court in September 2003, the Laramie County District Court certified the case to the Wyoming Supreme Court in January 2004. PacifiCorp filed its reply brief in April 2004. Oral arguments before the Wyoming Supreme Court took place in June 2004.

Also, in April 2004, PacifiCorp filed a complaint with the federal district court in Wyoming challenging the March 2003 WPSC decision on the grounds that the WPSC’s decision and interpretation of state law are unconstitutional. Further, the lawsuit claims that the WPSC interfered with interstate commerce and FERC jurisdiction over wholesale transactions. The lawsuit seeks an injunction requiring the WPSC to comply with whatever decision the court makes in this matter, including the recovery of any monetary award.

In July 2004, PacifiCorp applied to the WPSC for a stand-alone pass-on of increased net wholesale purchased power costs. If approved, a bill surcharge rider would be implemented to collect additional net wholesale power costs. The application requests an overall annual revenue increase of $11.8 million, or 3.4%. PacifiCorp requested an order by September 2004. Filing for, or approval of, this application does not preclude PacifiCorp from filing a general rate case later in fiscal 2005.

In June 2004, the WPSC concluded six days of 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 is expected to deliberate the evidence and render a decision in August or September 2004.

Idaho

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

Multi-State Process

PacifiCorp is involved in a collaborative process with stakeholders from the six states it serves, in an effort to develop mutually acceptable solutions to the issues faced by PacifiCorp and the states as a result of PacifiCorp’s multi-state operations. These issues pertain to the inconsistent allocation of some of the cost of PacifiCorp’s existing investments and the recovery of the cost of future investments. Between April 2002 and July 2003, PacifiCorp and

key parties from Utah, Oregon, Wyoming, Washington and Idaho, along with a key monitoring contact from California, analyzed over 50 options to address these issues, and these options were narrowed to two possibilities. Both sought to clarify roles and responsibilities, including cost allocations for future generation resources; provide states with the ability to independently implement state energy policy objectives; and achieve permanent consensus on each state’s responsibility for the costs and each state’s entitlement to the benefits of PacifiCorp’s existing assets.

Following a July 2003 meeting, PacifiCorp undertook extensive analytical work to develop a single proposal that would best balance the needs of PacifiCorp and requirements of the states. The proposal describes the allocation of costs to each state that PacifiCorp serves and was filed in September 2003 in the states of Utah, Oregon, Wyoming and Idaho. A similar filing was made in Washington in December 2003 as part of the general rate case filing. A filing in California is anticipated to occur in coordination with rate case activity in that state.

Discussions with all parties resulted in a revised proposal being filed in Utah and Oregon in May 2004. Following further discussions and settlement meetings with parties in Utah, a settlement was reached between PacifiCorp and eight Utah parties to provide the revised proposal with stipulated conditions. This revised proposal was filed in June 2004. In July 2004, parties filed testimony in support of the revised proposal and stipulation. No party filed testimony in opposition. The UPSC conducted a one-day hearing, and PacifiCorp now awaits an order from the UPSC. In Oregon, a settlement was reached between PacifiCorp and three Oregon parties to support the revised proposal with stipulated conditions. This revised proposal was filed in July 2004. One party in Oregon opposes the revised proposal. Hearings will be held in August 2004.

Additional filings containing the revised proposal were filed in Wyoming, Idaho and Washington. The schedule in Wyoming envisions settlement discussions in August 2004 and hearings in October 2004. The schedule in Washington is in accordance with the general rate case procedures, with hearings during August and September 2004 and an order in November 2004. The schedule in Idaho is to be determined, but anticipated to be no longer than the existing schedules in the other states.

Requests for Proposals

As required by state regulators, PacifiCorp published an Integrated Resource Plan in January 2003 and updated it in October 2003, as discussed in PacifiCorp’s Annual Report on Form 10-K for the year ended March 31, 2004 under Item 1. Business. The following provides an update of these projects.

RFP 2003A - In March 2004, the Utah Division of Air Quality finished its evaluation of the air quality permit application for the Currant Creek plant and issued a Notice of Intent to Approve the air quality permit. PacifiCorp received the final approval order in May 2004. In order to allow construction of the Currant Creek plant to proceed without delay, PacifiCorp and the Utah Division of Air Quality entered into an Administrative Order on Consent in March 2004. The consent order authorized PacifiCorp to proceed with a specified list of construction activities before receiving the final air quality approval order. As such, construction of the plant began in March 2004. The plant is expected to cost approximately $350.0 million, spent from fiscal year 2004 through fiscal year 2007. Of this total expected amount, $85.2 million had been spent as of June 30, 2004. Recovery of PacifiCorp’s investment in the plant will be reviewed by all states PacifiCorp serves as part of future general rate cases.

To ensure an adequate supply to meet future energy needs, on May 27, 2004 PacifiCorp entered into an asset purchase and sale agreement with Summit Vineyard LLC of Denver, Colorado, to develop and, with Siemens Westinghouse Power Corporation, to construct, a natural gas-fired combined-cycle combustion turbine power plant near Orem, Utah. The plant, to be known as the Lake Side Power Plant and to have a capacity of 534 MW, was identified as the best option submitted through PacifiCorp’s competitive RFP 2003A process, which sought to identify a summer 2007 resource. PacifiCorp filed with the UPSC for a Certificate of Convenience and Necessity, a process which could take up to six months to complete. Hearings are currently scheduled to take place in fall 2004. The Lake Side Power Plant is expected to cost approximately $330.0 million. Recovery of PacifiCorp’s investment in the plant will be reviewed by the states PacifiCorp serves as part of future general rate cases.

RFP 2003B - PacifiCorp issued a Renewable Request for Proposals in February 2004 for up to 1,100 MW of economic renewable resources for PacifiCorp’s system. Several responses have been received and are currently being evaluated. It is anticipated that a short-list of responses will be selected during August 2004, with negotiations commencing soon thereafter.

ITEM 6.

EXHIBITS AND REPORTS ON FORM 8-K

(a) Exhibits.

	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
	15	Letter regarding unaudited interim financial information
	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

(b) Reports on Form 8-K.

	None.

SIGNATURE

Pursuant to the requirements 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
Date: August 12, 2004	By:	/s/ RICHARD D. PEACH

		Richard D. Peach Chief Financial Officer