PACIFICORP /OR/ - Quarter Report: 2004 December (Form 10-Q)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

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

For the quarterly period ended December 31, 2004

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

For the transition period from _______________ to _______________

Commission file number 1-5152

PacifiCorp

(Exact name of registrant as specified in its charter)

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

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

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

97232
(Zip Code)

503-813-5000

(Registrant’s telephone number)

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 February 4, 2005, there were 312,176,089 shares of common stock outstanding. All shares of outstanding common stock are indirectly owned by Scottish Power plc, 1 Atlantic Quay, Glasgow, G2 8SP, Scotland.

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	18

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	19

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	32

Item 4.	Controls and Procedures	36

PART II.	OTHER INFORMATION	36

	Information Regarding Recent Regulatory Developments	36

Item 1.	Legal Proceedings	42

Item 6.	Exhibits	42

Signature		43

PART I. FINANCIAL INFORMATION

ITEM 1.

FINANCIAL STATEMENTS

PACIFICORP

CONDENSED CONSOLIDATED STATEMENTS OF INCOME AND RETAINED EARNINGS

(Unaudited)

	Three Months Ended December 31,						Nine Months Ended December 31,

(Millions of dollars)	2004			2003			2004			2003

Revenues:
Residential	$	271.6		$	255.1		$	730.3		$	723.8
Commercial		202.9			193.3			632.5			607.1
Industrial		179.1			171.3			598.2			557.3
Other retail revenues		8.7			8.0			27.2			25.5
Wholesale sales and other		187.2			161.3			437.8			504.6

Total		849.5			789.0			2,426.0			2,418.3

Operating expenses:
Purchased electricity		195.2			163.7			514.2			535.0
Fuel		132.5			115.4			375.0			364.3
Operations and maintenance		234.2			215.2			693.7			635.6
Depreciation and amortization		110.1			107.9			326.7			318.1
Taxes, other than income taxes		22.3			25.1			70.5			73.0

Total		694.3			627.3			1,980.1			1,926.0
Other operating expense (income)		—			0.4			(4.2	)		13.2

Income from operations		155.2			161.3			450.1			479.1

Interest expense and other expense (income):
Interest expense		68.2			66.4			199.3			190.0
Interest income		(2.3	)		(3.2	)		(7.6	)		(11.2	)
Interest capitalized		(3.3	)		(5.0	)		(9.2	)		(17.1	)
Minority interest and other		(4.6	)		(4.9	)		(8.4	)		2.0

Total		58.0			53.3			174.1			163.7

Income from operations before income tax expense and cumulative effect of accounting change		97.2			108.0			276.0			315.4
Income tax expense		45.9			47.5			111.9			132.3

Income before cumulative effect of accounting change		51.3			60.5			164.1			183.1
Cumulative effect of accounting change (less applicable income tax benefit of $(0.6)/2003)		—			—			—			(0.9	)

Net income		51.3			60.5			164.1			182.2
Preferred dividend requirement		(0.6	)		(0.5	)		(1.6	)		(2.8	)

Earnings on common stock	$	50.7		$	60.0		$	162.5		$	179.4

RETAINED EARNINGS AT BEGINNING OF PERIOD	$	405.3		$	345.0		$	390.1		$	305.9
Net income		51.3			60.5			164.1			182.2
Cash dividends declared:
Preferred stock		(0.6	)		(0.5	)		(1.6	)		(2.8	)
Common stock		(48.3	)		(40.1	)		(144.9	)		(120.4	)

RETAINED EARNINGS AT END OF PERIOD	$	407.7		$	364.9		$	407.7		$	364.9

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

PACIFICORP
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)

ASSETS
(Millions of dollars)	December 31, 2004			March 31, 2004

Current assets:
Cash and cash equivalents	$	25.0		$	58.5
Accounts receivable (less allowance for doubtful accounts of $18.9/December and $23.8/March)		292.9			234.6
Unbilled revenue		158.2			128.3
Amounts due from affiliates		36.2			2.4
Inventories at average cost:
Materials and supplies		111.1			101.0
Fuel		50.1			56.0
Current derivative contract asset		120.4			118.9
Current deferred tax asset		23.8			31.5
Other		51.6			25.2

Total current assets		869.3			756.4

Property, plant and equipment		14,125.2			13,812.8
Construction work in progress		456.8			345.4
Accumulated depreciation and amortization		(5,295.5	)		(5,121.7	)

Total property, plant and equipment - net		9,286.5			9,036.5

Other assets:
Regulatory assets		948.6			1,032.3
Derivative contract regulatory asset		277.9			422.2
Non-current derivative contract asset		247.0			110.3
Deferred charges and other		328.1			319.4

Total other assets		1,801.6			1,884.2

Total assets	$	11,957.4		$	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)	December 31, 2004			March 31, 2004

Current liabilities:
Accounts payable	$	245.8		$	257.8
Amounts due to affiliates		8.4			2.6
Accrued employee expenses		104.2			140.3
Taxes payable		25.3			50.2
Interest payable		54.7			66.1
Current derivative contract liability		86.2			76.9
Long-term debt and capital lease obligation, currently maturing		192.5			240.0
Preferred stock subject to mandatory redemption, currently maturing		3.7			3.7
Notes payable and commercial paper		284.7			124.9
Other		121.2			111.8

Total current liabilities		1,126.7			1,074.3


Deferred credits:
Income taxes		1,599.3			1,564.6
Investment tax credits		77.5			83.5
Regulatory liabilities		815.7			807.5
Non-current derivative contract liability		552.5			567.1
Other		685.0			683.6

Total deferred credits		3,730.0			3,706.3

Long-term debt and capital lease obligation, net of current maturities		3,713.2			3,520.2
Preferred stock subject to mandatory redemption		48.8			56.3

Total liabilities		8,618.7			8,357.1

Commitments and contingencies (See Note 7)
Shareholders’ equity:
Preferred stock		41.3			41.3

Common equity:
Common shareholder’s capital		2,892.1			2,892.1
Retained earnings		407.7			390.1
Accumulated other comprehensive income (loss):
Unrealized gain on available-for-sale securities, net of tax of $3.4/December and $2.7/March		5.6			4.5
Minimum pension liability, net of tax of $(4.9)		(8.0	)		(8.0	)

Total common equity		3,297.4			3,278.7

Total shareholders’ equity		3,338.7			3,320.0

Total liabilities and shareholders’ equity	$	11,957.4		$	11,677.1

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

PACIFICORP
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)

	Nine Months Ended December 31,

(Millions of dollars)	2004			2003

Cash flows from operating activities:
Net income	$	164.1		$	182.2
Adjustments to reconcile net income to net cash provided by operating activities:
Cumulative effect of accounting change, net of tax		—			0.9
Unrealized loss on derivative contracts		0.7			0.8
Depreciation and amortization		326.7			318.1
Deferred income taxes and investment tax credits, net		64.1			61.8
Provision for pension and benefits		(16.4	)		9.2
Deferred net power costs		(1.9	)		(8.7	)
Changes in:
Other regulatory assets/liabilities		52.1			89.3
Accounts receivable and prepayments		(117.4	)		(61.5	)
Inventories		(4.2	)		16.2
Amounts due to/from affiliates, net		(33.5	)		(44.7	)
Accounts payable and accrued liabilities		(71.4	)		(89.1	)
Other		(4.6	)		(8.3	)

Net cash provided by operating activities		358.3			466.2


Cash flows from investing activities:
Capital expenditures		(539.9	)		(484.8	)
Proceeds from sales of assets		4.7			2.9
Proceeds from available-for-sale securities		38.5			77.8
Purchases of available-for-sale securities		(37.9	)		(76.7	)
Other		(5.4	)		(2.7	)

Net cash used in investing activities		(540.0	)		(483.5	)

Cash flows from financing activities:
Changes in short-term debt		159.8			199.9
Proceeds from long-term debt, net of issuance costs		395.2			397.0
Dividends paid		(146.5	)		(124.4	)
Repayments and redemptions of long-term debt		(252.8	)		(162.3	)
Repayments of preferred securities		—			(352.0	)
Redemptions of preferred stock		(7.5	)		(7.5	)
Other		—			(0.4	)

Net cash provided by (used in) financing activities		148.2			(49.7	)

Change in cash and cash equivalents		(33.5	)		(67.0	)
Cash and cash equivalents at beginning of period		58.5			152.5

Cash and cash equivalents at end of period	$	25.0		$	85.5

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 December 31, 2004 and for the nine months ended December 31, 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 December 31, 2004 and for the nine months ended December 31, 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 nine months ended December 31, 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 nine months ended December 31, 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 (“APB”) Opinion No. 25, Accounting for Stock Issued to Employees (“APB No. 25”), 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 (“SFAS No. 123”), PacifiCorp’s net income would have been changed to the following pro forma amounts:

	Three Months Ended December 31,					Nine Months Ended December 31,

(Millions of dollars)	2004		2003			2004			2003

Net income as reported	$	51.3	$	60.5		$	164.1		$	182.2
Stock-based employee compensation expense, net of tax		—		(0.2	)		(0.1	)		(0.6	)

Pro forma net income	$	51.3	$	60.3		$	164.0		$	181.6

See New Accounting Standards for discussion of Revised SFAS No. 123.

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 was effective for the first interim or annual period beginning after June 15, 2004. When FSP SFAS No. 106-2 became effective, it superceded FSP SFAS No. 106-1. PacifiCorp elected to adopt FSP SFAS No. 106-2 early upon its release with retroactive application to PacifiCorp’s Welfare Benefits Plan December 31, 2003 measurement date. Because that measurement date is used only to determine net periodic postretirement benefit cost for the period beginning April 1, 2004, there was no impact on previously reported information. The effects of the Medicare Act decreased PacifiCorp’s accumulated postretirement benefit obligation by $42.6 million. This decrease is treated as an actuarial experience gain. This actuarial experience gain reduces the unrecognized net loss resulting from differences in prior periods between actuarial assumptions and actual experience. The actuarial experience gain will be amortized to expense through a decrease in the amortization of the unrecognized net loss. The effects of the Medicare Act decreased net periodic postretirement benefit cost for the three months and nine months ended December 31, 2004, when compared to the expense calculated before the adoption of FSP SFAS No. 106-2, as follows:

(Millions of dollars)	Three Months Ended December 31, 2004		Nine Months Ended December 31, 2004


Effect on:
Interest cost	$	0.7	$	2.0
Service cost		0.1		0.1
Amortization of unrecognized loss		0.7		2.2

Net periodic postretirement benefit cost	$	1.5	$	4.3

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

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

In September 2004, the FASB issued FSP EITF No. 03-1-1, Effective Date of Paragraphs 10-20 of EITF No. 03-1, The Meaning of Other-Than-Temporary Impairment and Its Application to Certain Investments (“FSP EITF No. 03-1-1”). FSP EITF No. 03-1-1 delayed the previously required effective date of July 1, 2004 for PacifiCorp regarding the measurement and recognition guidance contained in the applicable paragraphs. The delay of the effective date is likely to be superceded with the final issuance of an FSP on other-than-temporary impairment of investments. The

adoption of the measurement and recognition guidance of EITF No. 03-1, if implemented in its present form, is not anticipated to have a material impact on PacifiCorp’s consolidated financial position or results of operations.

SFAS No. 151

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

SFAS No. 153

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

SFAS No. 123R

In December 2004, the FASB issued SFAS No. 123R, Share-Based Payment (“SFAS No. 123R”), a revision of the originally issued SFAS No. 123. SFAS No. 123R establishes standards for the accounting for transactions in which an entity exchanges its equity instruments for goods or services. This statement requires that the cost resulting from all share-based payment transactions be recognized in the financial statements using the fair value method. The intrinsic value method of accounting established by APB No. 25 will no longer be allowed.

This statement is effective as of the beginning of the first interim reporting period that begins after June 15, 2005. A modified prospective application is required for new awards and to awards modified, repurchased or cancelled after the required effective date. The PacifiCorp Stock Incentive Plan expired November 29, 2001; therefore, no new awards are expected to be issued, modified, repurchased or cancelled as of the effective date. As of the effective date, all requisite service under the PacifiCorp Stock Incentive Plan will have been previously rendered, and no compensation expense is expected to result from the adoption of this statement.

FSP SFAS No. 109-1

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

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)	December 31, 2004		March 31, 2004

Deferred income taxes	$	501.0	$	519.1
Minimum pension liability offset		226.2		226.2
Unamortized issuance expense on retired debt		36.4		40.6
Transition Plan - retirement and severance		28.3		38.2
Demand-side resource		28.0		40.1
Deferred net power costs (a)		26.0		57.8
Various other costs		102.7		110.3

Subtotal		948.6		1,032.3
Derivative contracts (b)		277.9		422.2

Total	$	1,226.5	$	1,454.5

(a)

Represents deferred net power costs in Oregon at December 31, 2004 and in Utah, Oregon and Idaho at March 31, 2004 that PacifiCorp is recovering through rates.

(b)

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)	December 31, 2004		March 31, 2004

Asset retirement removal costs (a)	$	685.6	$	670.6
Regulatory credits		60.6		85.9
Deferred income taxes		45.4		36.2
Various other costs		24.1		14.8

Total	$	815.7	$	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.

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, as amended. Changes in fair value of PacifiCorp’s recorded derivative contracts are recognized immediately in the income statement, 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. 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 nine months ended December 31, 2004.

	Net Asset (Liability)						Regulatory Net Asset (Liability) (b)

(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		0.3			(11.9	)		(13.8	)
Other changes in fair values (a)		0.4			154.7			(130.5	)

Fair value of contracts outstanding at December 31, 2004	$	0.2		$	(271.5	)	$	277.9

(a)

Effective September 30, 2004, PacifiCorp changed to a U.S. London Interbank Offered Rate (LIBOR) rate from the U.S. Treasury rate for discounting the portfolio. This change had the effect of increasing the fair value of non-trading contracts by $25.5 million, offset by a decrease in regulatory net assets by the same amount. Other changes in fair values include the effects of this change, along with the effects of changes in market prices, inflation rates and interest rates, including those based on models, on new and existing contracts for the nine months ended December 31, 2004.

(b)

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

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 net liability recorded for these contracts was $1.7 million at December 31, 2004 and $5.3 million at March 31, 2004. PacifiCorp did not recognize a net gain or net loss on the weather derivative for the three months ended December 31, 2004 or December 31, 2003. PacifiCorp recognized a gain of $2.9 million for the nine months ended December 31, 2004 and a gain of $0.4 million for the nine months ended December 31, 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 governing the allocation of costs incurred by PacifiCorp and SPUK, on behalf of each other. These cross-charges commenced during the nine months ended December 31, 2004 and were recorded in Operations and maintenance expense. These cross-charges amounted to $3.8 million for the three months ended December 31, 2004 and $12.4 million for the nine months ended December 31, 2004.

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 and an indirect subsidiary of ScottishPower. The facility consists of five generation units, each rated at 40 megawatts (“MW”), and is located in Utah. The lease terms granted PacifiCorp two independent early termination options that provide PacifiCorp the right to terminate the lease and, at PacifiCorp’s further option, to purchase the facility for predetermined amounts. On May 28, 2004, PacifiCorp exercised its first option to terminate the West Valley lease. PacifiCorp subsequently exercised its right to rescind the termination on September 28, 2004 after determining, through a public process, that the resource could not be replaced on a more economic

basis and without increasing risks to system reliability. PacifiCorp has a second option to terminate the West Valley lease if written notice is provided to West Valley on or before December 1, 2006. PacifiCorp is committed to future minimum lease payments of $15.0 million annually for years ending March 31, 2005 through 2008 and $2.5 million for the year ending March 31, 2009.

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

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

Amounts due from affiliated entities:
ScottishPower (a)	$	0.4	$	0.2
PHI subsidiaries (b)		35.8		2.2

	$	36.2	$	2.4


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


Amounts due to affiliated entities:
ScottishPower (d)	$	8.4	$	2.6


Deposits received from affiliated entities:
PHI subsidiaries (e)	$	1.1	$	0.6

	Three Months Ended December 31,				Nine Months Ended December 31,

(Millions of dollars)	2004		2003		2004		2003

Revenues from affiliated entities:
PHI subsidiaries (e)	$	1.1	$	0.9	$	4.7	$	2.7


Expenses incurred from affiliated entities:
ScottishPower (d)	$	4.0	$	2.0	$	15.5	$	5.7
PHI subsidiaries (c)		4.5		4.3		13.0		12.8

	$	8.5	$	6.3	$	28.5	$	18.5

Expenses recharged to affiliated entities:
ScottishPower (a)	$	0.9	$	0.2	$	2.1	$	0.6
PHI subsidiaries (f)		2.3		1.9		6.5		5.7

	$	3.2	$	2.1	$	8.6	$	6.3


Interest expense to affiliated entities:
PHI subsidiaries	$	—	$	—	$	—	$	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. Also included is the portion of taxes currently receivable from PHI of $31.7 million at December 31, 2004 and $0.1 million at March 31, 2004.

(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)

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

(f)

Expenses recharged reflect costs for support services to PHI and its subsidiaries.

Note 5 – Financing Arrangements

At December 31, 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.

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

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 to ensure that events of default will not occur. As of December 31, 2004, PacifiCorp was in compliance with the covenants of its credit agreements.

Note 6 – Long-Term Debt

On August 24, 2004, PacifiCorp issued $200.0 million of its 4.95% Series of First Mortgage Bonds due August 15, 2014 and $200.0 million of its 5.90% Series of First Mortgage Bonds due August 15, 2034. PacifiCorp used the proceeds for general corporate purposes, including the reduction of short-term debt. These bonds contain covenants consistent with PacifiCorp’s other series of First Mortgage Bonds.

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

Note 7 – 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, individual Klamath Tribal members and the Klamath Claims Committee. 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. In July 2004, PacifiCorp filed its answer to the complaint. In September 2004, the case was transferred to the Medford Division of the District of Oregon. Also in September 2004, the Klamath Tribes filed their first amended complaint adding claims of damage to their treaty rights to fish for sucker and steelhead in the headwaters of the Klamath River. The claim seeks in excess of $1.0 billion in compensatory and punitive damages. In October 2004, PacifiCorp filed its answer to the first amended complaint generally denying liability and asserting affirmative defenses for the matters alleged by the Klamath Tribes. A scheduling conference was held in October 2004, which established a procedural schedule for the case. In February 2005, PacifiCorp anticipates filing a motion for summary judgment seeking dismissal of the Klamath Tribes' claims as untimely under the applicable statute of limitations.

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 and various state air quality laws; the Endangered Species Act, particularly as it relates to certain endangered species of fish; the Comprehensive Environmental Response, Compensation and Liability Act, and similar state laws relating to environmental cleanups; the Resource Conservation and Recovery Act and similar state laws relating to the storage and handling of hazardous materials; and the Clean Water Act, and similar state laws relating to water quality. These laws could potentially impact future operations. Contingencies identified at December 31, 2004, principally consist of air quality matters. Pending or proposed air regulations will require PacifiCorp to reduce its electricity plant emissions of sulfur dioxide, nitrogen oxides and other pollutants below current levels. These reductions will be required to address regional haze programs, mercury emissions regulations and possible re-interpretations and changes to the federal Clean Air Act. Also, similar to many other coal burning utilities, PacifiCorp has received information requests from the EPA related to PacifiCorp’s compliance with the New Source Review provisions of the Clean Air Act, which has resulted in some discussions with the EPA and state regulatory authorities. 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.

PacifiCorp completed a study during the three months ended September 30, 2004 on sites for which it may be obligated to perform environmental remediation. As a result, during the three months ended September 30, 2004 PacifiCorp adjusted its reserve by $1.5 million to reflect its most likely estimate for probable liabilities. In the three months ended December 31, 2004, PacifiCorp recognized an additional $3.4 million for new probable environmental liabilities. Remediation costs that are fixed and determinable have been discounted to their present value. The liability was $37.9 million at December 31, 2004 and March 31, 2004. The undiscounted liability totaled $40.4 million as of December 31, 2004 and PacifiCorp used a credit-adjusted, risk-free discount rate to calculate the present value of the obligation. Should current circumstances change, it is possible that PacifiCorp could incur an additional undiscounted obligation of up to approximately $37.0 million relating to existing sites.

Hydroelectric Relicensing

PacifiCorp’s hydroelectric portfolio consists of 53 plants with a plant net capability of 1,163.5 MW. Ninety-seven percent of the installed capacity is regulated by the FERC through 18 individual licenses. Several of PacifiCorp’s hydroelectric projects are in some stage of relicensing under the Federal Power Act. Hydroelectric relicensing and the related environmental compliance requirements are subject to uncertainties. PacifiCorp expects that future costs relating to these matters may be significant and consist primarily of additional relicensing costs, operations and maintenance expense, and capital expenditures. Electricity generation reductions may result from the additional environmental requirements. PacifiCorp has accumulated approximately $57.3 million in costs as of December 31, 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 $26.5 million for environmental mitigation and enhancement projects. A $12.2 million liability, representing the present value of these obligations, was recorded in May 2004.

The new FERC license for the North Umpqua hydroelectric project, is effective, but not final. When the license for this project becomes final, PacifiCorp will be committed, over the life of the license, to fund approximately $48.9 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 in June 2004. Additional liabilities will be recognized when the license becomes final.

In February 2004, PacifiCorp filed with the FERC a final application for a new license to operate the 151.0 MW Klamath hydroelectric project in southern Oregon and northern California. The FERC is scheduled to complete its required analysis by April 2006. In the meantime, PacifiCorp continues to work cooperatively with a broad range of stakeholders to identify and resolve any outstanding issues in an attempt to reach a settlement. In October 2004, PacifiCorp convened a mediated settlement negotiation group consisting of itself, state and federal agencies, Native American tribes, and other stakeholders, in an effort to reach a comprehensive agreement on project relicensing.

On November 30, 2004, PacifiCorp executed a comprehensive settlement agreement with 25 other parties including state and federal agencies, Native American tribes, conservation groups, and local government and citizen groups to resolve, among the parties, issues related to the pending applications for new licenses for PacifiCorp’s 135.0 MW Merwin, 240.0 MW Swift No. 1 and 134.0 MW Yale hydroelectric projects on the Lewis River in southwest Washington. As part of this settlement agreement, PacifiCorp has agreed to implement certain protection, mitigation and enhancement measures prior to and during a proposed 50-year license period. However, these commitments are contingent on ultimately receiving a license from the FERC that is consistent with the settlement agreement and other required permits. The FERC is scheduled to complete its process and required analysis in order to be ready for a decision in March 2006.

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 240.0 MW Swift No. 1 hydroelectric facility, which is upstream of the Swift No. 2 power canal. In June 2004, PacifiCorp and Cowlitz County Public Utility District amended the existing power purchase agreement addressing, among other things, the general nature of the canal rebuild configuration and providing the mechanism for settling all claims between the parties related to the canal failure. Cowlitz County Public Utility District has initiated the reconstruction of the Swift No. 2 project facility with contracts currently in place for rehabilitation of the turbine generators, switchyard and reconstruction of the Swift No. 2 power canal. Based on the current schedule, the first Swift No. 2 turbine generator unit is expected to be on line in the fourth quarter of fiscal year 2006 and the second unit is expected to follow shortly thereafter.

Enron Corp. Reserves

In December 2001, Enron Corp. declared bankruptcy and defaulted on certain wholesale contracts. PacifiCorp has fully reserved for its $8.0 million Enron Corp. receivable. On January 28, 2005, PacifiCorp entered into an agreement to sell its bankruptcy claim to a third party. Closing of the sale is anticipated in the fourth quarter of fiscal 2005.

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 fully reserved for these receivables in the amount of $5.0 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. Court briefs from interested parties are due to be filed between January 14, 2005 and April 15, 2005. A decision from the court of appeals is not expected to have a significant impact on PacifiCorp’s consolidated financial position or results of operations.

Federal Power Act Section 206 Case - In June 2003, the FERC issued a final order denying PacifiCorp’s request for recovery of excessive prices charged under certain wholesale electricity purchases scheduled for delivery during summer 2002 and dismissing PacifiCorp’s complaints, under Section 206 of the Federal Power Act, against five wholesale electricity suppliers. In July 2003, PacifiCorp filed its request for rehearing of the FERC’s order, which request was granted in August 2003. The FERC issued its final order denying rehearing in November 2003. In November 2003, PacifiCorp filed a petition in the Ninth Circuit Court of Appeals for review of the FERC’s final order denying recovery. Court briefs from interested parties are due to be filed by March 1, 2005.

FERC Show-Cause Orders - In May 2002, PacifiCorp, together with other California electricity market participants, responded to data requests from the FERC regarding trading practices connected with the electricity crisis during 2000 and 2001. PacifiCorp confirmed that it did not engage in any trading practices intended to manipulate the market as described in the FERC’s data requests issued in May 2002. In June 2003, the FERC ordered 60 companies (including PacifiCorp) to show cause why their behavior during the California energy crisis did not constitute manipulation of the wholesale electricity market, as defined in the California Independent System Operator and the California Power Exchange tariffs. In 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 Regional 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, the BPA and other parties executed an additional agreement that provides for a guaranteed range of benefits to customers for fiscal years 2007 through 2011.

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

Note 8 – Retirement Benefit Plans

The components of net periodic benefit cost for the three months and nine months ended December 31 are as follows:

	Retirement Plans

	Three Months Ended December 31,						Nine Months Ended December 31,

(Millions of dollars)	2004			2003			2004			2003


Service cost	$	6.5		$	4.9		$	19.5		$	14.9
Interest cost		18.4			18.4			55.3			55.4
Expected return on plan assets		(19.4	)		(20.2	)		(58.2	)		(60.6	)
Amortization of unrecognized net obligation		2.1			2.1			6.3			6.3
Amortization of unrecognized prior service cost		0.3			0.4			1.0			1.2
Amortization of unrecognized loss		2.2			—			6.4			—

Net periodic benefit cost	$	10.1		$	5.6		$	30.3		$	17.2

	Other Postretirement Benefits

	Three Months Ended December 31,						Nine Months Ended December 31,

(Millions of dollars)	2004			2003			2004			2003

Service cost (a)	$	2.1		$	1.9		$	6.4		$	5.7
Interest cost (a)		7.7			8.6			23.2			25.8
Expected return on plan assets		(6.6	)		(6.7	)		(19.8	)		(20.0	)
Amortization of unrecognized net obligation		3.1			3.1			9.2			9.2
Amortization of unrecognized prior service cost		—			—			—			—
Amortization of unrecognized loss (a)		0.2			0.1			0.5			0.4

Net periodic benefit cost	$	6.5		$	7.0		$	19.5		$	21.1

(a) Results for the three months and nine months ended December 31, 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 December 31, 2004, PacifiCorp has made contributions of $64.1 million to its retirement plans and $0.9 million to its other postretirement benefit plan. PacifiCorp currently anticipates contributing an additional $2.7 million to its retirement plans and $25.1 million to its other postretirement benefit plan during the year ending March 31, 2005, for a total of $66.8 million to its retirement plans and $26.0 million to its other postretirement benefit plan.

Note 9 – 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 $111.9 million for the nine months ended December 31, 2004, $132.3 million for the nine months ended December 31, 2003, $45.9 million for the three months ended December 31, 2004 and $47.5 million for the three months ended December 31, 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:

	Nine Months Ended December 31,

	2004		2003

Federal statutory rate	35.0	%	35.0	%
State taxes, net of federal benefit	3.7		3.4
Effect of regulatory treatment of depreciation differences	3.6		4.9
Effect of regulatory treatment of other differences	2.8		—
Tax reserves	(1.6	)	(0.1	)
Tax credits	(2.5	)	(2.3	)
Other	(0.5	)	1.0

Effective income tax rate	40.5	%	41.9	%

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 nine months ended December 31, 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 $4.2 million primarily to accrue interest on remaining tax contingencies provided for in prior periods.

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

Note 10 – Comprehensive Income

The components of comprehensive income are as follows:

	Three Months Ended December 31,				Nine Months Ended December 31,

(Millions of dollars)	2004		2003		2004		2003


Net income	$	51.3	$	60.5	$	164.1	$	182.2
Other comprehensive income:
Unrealized gain on available-for-sale securities, net of taxes of: $1.2 and $0.7/2004 and $1.4 and $3.3/2003		1.9		2.1		1.1		5.4

Total comprehensive income	$	53.2	$	62.6	$	165.2	$	187.6

Note 11 – 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 “Securities Act”). PacifiCorp’s independent registered public accountants are not subject to the liability provisions of Section 11 of the Securities 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 Securities Act.

Note 12 – Subsequent Events

On January 20, 2005, PacifiCorp’s Board of Directors declared a dividend on common stock of $0.155 per share totaling $48.3 million and payable on February 28, 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 sheets of PacifiCorp and its subsidiaries as of December 31, 2004 and the related condensed consolidated statements of income and retained earnings for each of the three month and nine month periods ended December 31, 2004 and 2003 and the condensed consolidated statements of cash flows for the nine month periods ended December 31, 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

February 10, 2005

ITEM 2.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

OVERVIEW

This 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, 70 thermal, hydroelectric and wind generating plants with an aggregate nameplate rating of 8,419.0 megawatts (“MW”) and plant net capability of 7,994.5 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; the impact of new accounting standards; the outcome of litigation or regulatory proceedings; environmental laws; capital expenditure levels; construction or repair of generating facilities; hydroelectric relicensing; electricity outages; changes under PacifiCorp’s related-party cross-charge policy agreement; retirement plan contributions; the impact of certain accounting policy changes on PacifiCorp’s net income; outcome of tax proceedings; 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 PacifiCorp’s ability to generate electricity and generation costs;

•

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

•

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

•

The impact of new accounting pronouncements on results of operations;

•

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

•

Timely and appropriate completion of the Request 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.

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, and disclosed to the Scottish Power plc (“ScottishPower”) Audit Committee. 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 was effective for the first interim or annual period beginning after June 15, 2004. When FSP SFAS No. 106-2 became effective, it superceded FSP SFAS No. 106-1. PacifiCorp elected to adopt FSP SFAS No. 106-2 early upon its release with retroactive application to PacifiCorp’s Welfare Benefits Plan December 31, 2003 measurement date. Because that measurement date is used only to determine net periodic postretirement benefit cost for the period beginning April 1, 2004, there was no impact on previously reported information. The effects of the Medicare Act

decreased PacifiCorp’s accumulated postretirement benefit obligation by $42.6 million. This decrease is treated as an actuarial experience gain. This actuarial experience gain reduces the unrecognized net loss resulting from differences in prior periods between actuarial assumptions and actual experience. The actuarial experience gain will be amortized to expense through a decrease in the amortization of the unrecognized net loss. The effects of the Medicare Act decreased net periodic postretirement benefit cost for the three months and nine months ended December 31, 2004, when compared to the expense calculated before the adoption of FSP SFAS No. 106-2, as follows:

(Millions of dollars)	Three Months Ended December 31, 2004		Nine Months Ended December 31, 2004

Effect on:
Interest cost	$	0.7	$	2.0
Service cost		0.1		0.1
Amortization of unrecognized loss		0.7		2.2

Net periodic postretirement benefit cost	$	1.5	$	4.3

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

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

SFAS No. 151

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

SFAS No. 153

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

SFAS No. 123R

In December 2004, the FASB issued SFAS No. 123R, Share-Based Payment (“SFAS No. 123R”), a revision of the originally issued SFAS No. 123, Accounting for Stock-Based Compensation. SFAS No. 123R establishes standards for the accounting for transactions in which an entity exchanges its equity instruments for goods or services. This statement requires that the cost resulting from all share-based payment transactions be recognized in the financial statements using the fair value method. The intrinsic value method of accounting established by APB No. 25, Accounting for Stock-Based Compensation, will no longer be allowed.

This statement is effective as of the beginning of the first interim reporting period that begins after June 15, 2005. A modified prospective application is required for new awards and to awards modified, repurchased or cancelled after the required effective date. The PacifiCorp Stock Incentive Plan expired November 29, 2001; therefore, no new awards are expected to be issued, modified, repurchased or cancelled as of the effective date. As of the effective date, all requisite service under the PacifiCorp Stock Incentive Plan would have been previously rendered, and no compensation expense is expected to result from the adoption of this statement.

FSP SFAS No. 109-1

RESULTS OF OPERATIONS

Overview

PacifiCorp’s earnings on common stock for the nine months ended December 31, 2004 was $162.5 million, as compared to $179.4 million for the nine months ended December 31, 2003. Significant factors affecting results for the nine months ended December 31, 2004 included increased regulatory rates more than offset by higher net wholesale electricity costs due to substitution of higher priced market transactions for reduced thermal and hydroelectric production, and increased Operations and maintenance expense.

PacifiCorp’s total revenues for the nine months ended December 31, 2004 increased by $7.7 million as compared to the same period in the prior year. Retail revenues increased by $74.5 million, or 3.9%, primarily as a result of higher regulatory rates and customer growth. These benefits were partially offset by a reduction in usage per customer, in part due to milder weather. Wholesale sales and other declined by $66.8 million, or 13.2%, primarily due to the impact of market price movements on unrealized energy sales contracts.

Output from PacifiCorp’s thermal plants for the nine months ended December 31, 2004 decreased by 317,925 megawatt-hours (“MWh”), or 0.9%, as compared to the prior year, due to higher levels of planned and unplanned outages. Thermal output for the three months ended December 31, 2004 was improved compared to the previous six months ended September 30, 2004 and was also improved compared to the three months ended December 31, 2003 by 626,513 MWh, or 5.3%.

Output from PacifiCorp-owned hydroelectric facilities for the nine months ended December 31, 2004 decreased by 116,636 MWh, or 4.9%, as compared to the same period in the prior year, primarily as a result of unusually dry conditions. Hydroelectric output for the three months ended December 31, 2004 decreased by 41,158 MWh, or 4.8%, as compared to the prior year, primarily due to the dry conditions.

Purchased electricity expense for the nine months ended December 31, 2004 declined by $20.8 million, or 3.9%, primarily due to unrealized gains on energy purchase contracts. These decreases were partially offset by higher volumes on short- and long-term purchase contracts due to lower thermal and hydroelectric generation availability and higher retail load, as well as higher net realized electricity prices on short- and long-term contracts.

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%.

In September 2004, the Wyoming Public Service Commission (the “WPSC”) approved a stipulation for a stand-alone pass-on of increased net wholesale purchased electricity costs. This stipulation was effective September 15, 2004 and resulted in an overall price increase of $9.25 million annually, or 2.68%.

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

PacifiCorp pursues a regulatory program in all states, with the objective of keeping rates closely aligned to ongoing costs. See Part II. Other Information for more detail on the state regulatory issues.

New Coal Reserves

On January 19, 2005, Bridger Coal Company’s federal coal lease bid was accepted by the Bureau of Land Management. The coal lease includes 32.0 million of estimated recoverable tons of coal and was purchased for $7.0 million. The coal is adjacent to one of Bridger’s majority owned mines in southern Wyoming. PacifiCorp owns two-thirds of the Bridger Coal Company and this acquisition increased PacifiCorp’s recoverable tons of coal at Bridger Mine to 138.4 million.

Affiliated Interest Cross-Charge Policy

Commencing on April 1, 2004, PacifiCorp and Scottish Power UK plc (“SPUK”), an indirect subsidiary of ScottishPower, implemented a cross-charge policy governing the allocation of costs incurred by PacifiCorp and SPUK, on behalf of each other. These cross-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 amounted to $3.8 million for the three months ended December 31, 2004 and $12.4 million for the nine months ended December 31, 2004 and were recorded in Operations and maintenance expense.

Three Months Ended December 31, 2004 Compared to Three Months Ended December 31, 2003

Revenues

	Three Months Ended December 31,				$ Change			% Change

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

Residential	$	271.6	$	255.1	$	16.5		6.5	%
Commercial		202.9		193.3		9.6		5.0
Industrial		179.1		171.3		7.8		4.6
Other retail revenues		8.7		8.0		0.7		8.7

Retail sales		662.3		627.7		34.6		5.5
Wholesale sales and other		187.2		161.3		25.9		16.1

Total revenues	$	849.5	$	789.0	$	60.5		7.7

Energy sales (millions of kWh):
Residential		3,890		3,740		150		4.0
Commercial		3,655		3,520		135		3.8
Industrial		4,597		4,629		(32	)	(0.7	)
Other		176		157		19		12.1

Retail sales		12,318		12,046		272		2.3

Average residential usage (kWh)		2,858		2,808		50		1.8
Total customers - end of period (in thousands)		1,595		1,562		33		2.1

Residential revenues increased $16.5 million, or 6.5%, due to:

•

$8.9 million of increases from higher regulatory rates;

•

$5.6 million of increases relating to growth in the average number of residential customers; and

•

$5.1 million of increases from higher average estimated customer usage; partially offset by,

•

$3.1 million of decreases due to a change in price mix, resulting from the level of customer usage at different customer tariffs in the various states that PacifiCorp serves.

Commercial revenues increased $9.6 million, or 5.0%, due to:

•

$8.5 million of increases from higher regulatory rates;

•

$4.4 million of increases from higher average estimated customer usage; and

•

$4.3 million of increases relating to growth in the average number of commercial customers; partially offset by,

•

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

Industrial revenues increased $7.8 million, or 4.6%, primarily due to:

•

$10.3 million of increases from higher regulatory rates; partially offset by,

•

$2.0 million of decreases from lower average estimated customer usage; and

•

$0.4 million of decreases due to a change in price mix, resulting from the level of customer usage at different customer tariffs in the various states that PacifiCorp serves.

Wholesale sales and other increased $25.9 million, or 16.1%, primarily due to:

•

$53.6 million of increases in volumes on short-term contracts primarily due to higher thermal generation;

•

$31.2 million of increases due to effects of electricity market prices on realized short- and long-term contracts;

•

$13.3 million of increases due to higher revenues related to other demand-side management, including $7.0 million due to a new tariff in Utah;

•

$5.4 million of increases in wheeling revenue; and

•

$2.6 million of increases in revenues from joint use of poles; partially offset by,

•

$61.0 million of decreases from unrealized losses from short- and long-term energy sales contracts recorded at fair value primarily due to movements in market prices;

•

$17.2 million of decreases due to contracts that did not physically settle being recorded on a net basis; and

•

$6.9 million of decreases in volumes on long-term contracts as a result of contract expirations.

Operating Expenses

	Three Months Ended December 31,				$ Change			% Change

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

Purchased electricity	$	195.2	$	163.7	$	(31.5	)	(19.2	)%
Fuel		132.5		115.4		(17.1	)	(14.8	)
Operations and maintenance		234.2		215.2		(19.0	)	(8.8	)
Depreciation and amortization		110.1		107.9		(2.2	)	(2.0	)
Taxes, other than income taxes		22.3		25.1		2.8		11.2

Total operating expenses	$	694.3	$	627.3	$	(67.0	)	(10.7	)

Purchased electricity expense increased $31.5 million, or 19.2%, primarily due to:

•

$50.4 million of increases due to the effects of electricity market prices on realized short- and long-term contracts; and

•

$40.5 million of increases as a result of higher volumes of short- and long-term purchases primarily due to higher retail demand; partially offset by,

•

$43.1 million of decreases from unrealized gains from short- and long-term energy purchase contracts recorded at fair value primarily due to movements in market prices; and

•

$17.2 million of decreases due to contracts that did not physically settle being recorded on a net basis.

Fuel expense increased $17.1 million, or 14.8%, due to:

•

$11.5 million of increases as a result of a net increase in the price of coal and natural gas consumed; and

•

$5.6 million of increases relating to higher supply volumes due mainly to an increase in thermal plant availability.

Operations and maintenance expense increased $19.0 million, or 8.8%, primarily due to:

•

$9.2 million of increases in employee salary expense and other direct employee expenses primarily due to an increase in headcount and higher benefit and pension costs;

•

$8.1 million of increases in demand-side management costs;

•

$4.1 million of increases in materials and supplies;

•

$3.8 million of increases from the affiliated interest cross-charge policy, which became effective April 1, 2004; and

•

$1.8 million of increases in write-offs of cancelled capital projects; partially offset by,

•

$8.2 million of decreases in consulting and technical service fees.

Depreciation and amortization expense increased $2.2 million, or 2.0%, primarily due to:

•

$3.2 million of increases in depreciation expense due to higher plant in service;

•

$1.1 million of increases in amortization expense due to higher capitalized software balances; and

•

$1.0 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.

Taxes, other than income taxes decreased $2.8 million, or 11.2%, primarily due to:

•

$2.5 million of decreases in property taxes, primarily due to favorable assessment levels and lower tax rates.

Interest and Other (Income) Expense

	Three Months Ended December 31,						$ Change			% Change

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

Interest expense	$	68.2		$	66.4		$	(1.8	)	(2.7	)%
Interest income		(2.3	)		(3.2	)		(0.9	)	(28.1	)
Interest capitalized		(3.3	)		(5.0	)		(1.7	)	(34.0	)
Minority interest and other		(4.6	)		(4.9	)		(0.3	)	(6.1	)

Total	$	58.0		$	53.3		$	(4.7	)	(8.8	)

Interest expense increased $1.8 million, or 2.7%, primarily due to:

•

An increase in the average amount of debt outstanding, partially offset by a decrease in average interest rates.

Interest income decreased $0.9 million, or 28.1%, primarily due to:

•

A decrease in interest income on regulatory assets.

Interest capitalized decreased $1.7 million, or 34.0%, primarily due to:

•

Lower average capitalization rates, partially offset by,

•

Higher qualifying construction work-in-progress balances during the three months ended December 31, 2004.

Income Tax Expense

Income tax expense decreased $1.6 million, primarily due to:

•

$7.3 million of decreases in the difference in estimated annualized effective tax rate;

•

$4.1 million of decreases due to lower levels of income from continuing operations before income taxes and cumulative effect of accounting change for the three months ended December 31, 2004; and

•

$3.1 million of decreases in the tax effect of regulatory treatment of depreciation differences; partially offset by,

•

$8.4 million of increases in the tax effect of Washington regulatory treatment of book and tax differences other than depreciation differences; and

•

$4.5 million of increases in the change in tax contingency reserve.

Nine Months Ended December 31, 2004 Compared to Nine Months Ended December 31, 2003

Revenues

	Nine Months Ended December 31,				$ Change			% Change

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

Residential	$	730.3	$	723.8	$	6.5		0.9	%
Commercial		632.5		607.1		25.4		4.2
Industrial		598.2		557.3		40.9		7.3
Other retail revenues		27.2		25.5		1.7		6.7

Retail sales		1,988.2		1,913.7		74.5		3.9
Wholesale sales and other		437.8		504.6		(66.8	)	(13.2	)

Total revenues	$	2,426.0	$	2,418.3	$	7.7		0.3

Energy sales (millions of kWh):
Residential		10,171		10,443		(272	)	(2.6	)
Commercial		11,076		11,023		53		0.5
Industrial		14,846		14,515		331		2.3
Other		523		498		25		5.0

Retail sales		36,616		36,479		137		0.4

Average residential usage (kWh)		7,523		7,882		(359	)	(4.6	)
Total customers - end of period (in thousands)		1,595		1,562		33		2.1

Residential revenues increased $6.5 million, or 0.9%, due to:

•

$25.8 million of increases from higher regulatory rates;

•

$14.5 million of increases relating to growth in the average number of residential customers; and

•

$1.6 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,

•

$35.4 million of decreases from lower average estimated customer usage, including $18.3 million due to the impact of milder weather, as compared to the prior year.

Commercial revenues increased $25.4 million, or 4.2%, due to:

•

$24.3 million of increases from higher regulatory rates; and

•

$14.1 million of increases relating to growth in the average number of commercial customers; partially offset by,

•

$11.3 million of decreases from lower average estimated customer usage, including $10.3 million due to the impact of milder weather, as compared to the prior year; and

•

$1.7 million of decreases due to a change in price mix, resulting from the level of customer usage at different customer tariffs in the various states that PacifiCorp serves.

Industrial revenues increased $40.9 million, or 7.3%, due to:

•

$27.6 million of increases from higher regulatory rates;

•

$8.8 million of increases from higher average estimated customer usage;

•

$3.9 million of increases due to a change in price mix, resulting from the level of customer usage at different customer tariffs in the various states that PacifiCorp serves; and

•

$0.6 million of increases relating to growth in the average number of industrial customers.

Wholesale sales and other decreased $66.8 million, or 13.2%, primarily due to:

•

$179.4 million of decreases due to contracts that did not physically settle being recorded on a net basis;

•

$101.2 million of decreases from unrealized losses from short- and long-term energy sales contracts recorded at fair value primarily due to movements in market prices;

•

$52.2 million of decreases in volumes on long-term contracts as a result of contract expirations; and

•

$3.9 million of decreases in revenues from joint use of poles; partially offset by,

•

$154.1 million of increases in volumes on short-term contracts primarily due to increased system balancing activity from variations in retail load and generation levels;

•

$72.6 million of increases due to the effects of electricity prices on realized short- and long-term transactions.

•

$32.1 million of increases due to higher revenues related to other demand-side management, including $21.1 million due to a new tariff in Utah;

•

$3.7 million of increases due to higher wheeling revenue; and

•

$3.7 million of increases due to amortization of certain regulatory liabilities.

Operating Expenses

	Nine Months Ended December 31,				$ Change			% Change

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

Purchased electricity	$	514.2	$	535.0	$	20.8		3.9	%
Fuel		375.0		364.3		(10.7	)	(2.9	)
Operations and maintenance		693.7		635.6		(58.1	)	(9.1	)
Depreciation and amortization		326.7		318.1		(8.6	)	(2.7	)
Taxes, other than income taxes		70.5		73.0		2.5		3.4

Total operating expenses	$	1,980.1	$	1,926.0	$	(54.1	)	(2.8	)

Purchased electricity expense decreased $20.8 million, or 3.9%, primarily due to:

•

$179.4 million of decreases due to contracts that did not physically settle being recorded on a net basis; and

•

$100.6 million of decreases from unrealized gains from short- and long-term energy purchase contracts recorded at fair value primarily due to movements in market prices; partially offset by,

•

$137.8 million of increases related to higher volumes of short- and long-term purchases resulting from lower thermal and hydroelectric generating availability, and increased retail load;

•

$117.2 million of increases due to the effects of higher electricity prices on realized short- and long-term contracts; and

•

$4.4 million of increases related to a gain in the prior year period due to a settlement of a regulatory matter that had been recorded as a regulatory liability.

Fuel expense increased $10.7 million, or 2.9%, due to:

•

$17.2 million of increases as a result of a net increase in the price of coal and natural gas consumed; partially offset by,

•

$6.5 million of decreases relating to lower supply volumes due mainly to a reduction in thermal plant availability.

Operations and maintenance expense increased $58.1 million, or 9.1%, primarily due to:

•

$37.7 million of increases in employee salary expense and other direct employee expenses primarily due to an increase in headcount and higher benefit and pension costs;

•

$24.5 million of increases in demand-side management costs;

•

$12.4 million of increases from the affiliated interest cross-charge policy, which became effective April 1, 2004; and

•

$3.3 million of increases in third-party contract and service fees, including tree-trimming, maintenance, legal and compliance; partially offset by,

•

$11.5 million of a decrease due to the recognition of claims in the prior year due to the bankruptcy of an insurance carrier;

•

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

•

$2.0 million of decreases due to contract settlements in the prior year; and

•

$0.9 million of decreases in write-offs of cancelled capital projects.

Depreciation and amortization expense increased $8.6 million, or 2.7%, primarily due to:

•

$10.6 million of increases in depreciation expense due to higher plant in service;

•

$4.8 million of increases in amortization expense due to higher capitalized software balances; and

•

$2.7 million of increases in the amortization of regulatory assets; partially offset by,

•

$9.6 million of decreases in capitalized software amortization following a change in the estimated useful lives of certain computer software systems.

Taxes, other than income taxes decreased $2.5 million, or 3.4%, primarily due to:

•

$1.0 million of decreases in property tax, primarily due to favorable assessment levels and lower tax rates;

•

$0.7 million of decreases in sales and use taxes; and

•

$0.6 million of decreases in state public utility taxes due to lower retail revenues in Washington.

Other Operating (Income) Expense

Other operating expense of $13.2 million for the nine months ended December 31, 2003 was primarily due to a $10.8 million expense for changes in regulatory assets and liabilities.

Other operating income of $4.2 million for the nine months ended December 31, 2004, represents a regulatory asset write-back for income taxes recoverable in the state of Idaho.

Interest and Other (Income) Expense

	Nine Months Ended December 31,						$ Change			% Change

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

Interest expense	$	199.3		$	190.0		$	(9.3	)	(4.9)	%
Interest income		(7.6	)		(11.2	)		(3.6	)	(32.1	)
Interest capitalized		(9.2	)		(17.1	)		(7.9	)	(46.2	)
Minority interest and other		(8.4	)		2.0			10.4		520.0

Total	$	174.1		$	163.7		$	(10.4	)	(6.4	)

Interest expense increased $9.3 million, or 4.9%, primarily due to:

•

$6.3 million of increases resulting from an increase in average amount of debt outstanding, due in part to the refinancing of $352.0 million of Preferred securities redeemed in August 2003 with long-term debt, partially offset by a decrease in average interest rates;

•

$0.8 million of increases due to dividends declared on Preferred stock subject to mandatory redemption in accordance with SFAS No. 150, Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity, which became effective July 1, 2003;

•

$0.8 million of increases in amortization expense for regulatory assets; and

•

$0.4 million of increases in interest on customer deposits.

Interest income decreased $3.6 million, or 32.1%, primarily due to:

•

$3.3 million of decreases in interest income on regulatory assets.

Interest capitalized decreased $7.9 million, or 46.2%, primarily due to:

•

Lower average capitalization rates during the nine months ended December 31, 2004.

Minority interest and other (income) expense changed $10.4 million, primarily due to:

•

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

•

$1.9 million of a decrease in income relating to proceeds from company-owned life insurance.

Income Tax Expense

Income tax expense decreased $20.4 million, primarily due to:

•

$14.8 million of decreases due to lower levels of income from continuing operations before income taxes and cumulative effect of accounting change for the nine months ended December 31, 2004;

•

$8.5 million of decreases in the tax contingency reserve resulting from the favorable settlement of PacifiCorp’s 1991 through 1998 Oregon state income tax returns;

•

$6.1 million of decreases in the tax effect of regulatory treatment of depreciation differences; and

•

$4.0 million of decreases in the difference in estimated annualized effective tax rate; partially offset by,

•

$8.4 million of increases in the tax effect of Washington regulatory treatment of book and tax differences other than depreciation differences; and

•

$4.6 million of increases in the change in the tax contingency reserve.

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, during the nine months ended December 31, 2003.

LIQUIDITY AND CAPITAL RESOURCES

Sources and Uses of Cash

PacifiCorp depends on both internal and external sources of liquidity to provide working capital and to fund capital requirements. Short-term cash requirements not met by cash provided by operating activities are generally satisfied with proceeds from short-term borrowings. Long-term cash needs are met through sales of securities, including additional long-term debt issuances, and also by issuance of common 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 $358.3 million for the nine months ended December 31, 2004, compared to $466.2 million for the nine months ended December 31, 2003, primarily due to lower net income of $18.1 million, higher pension funding of $27.6 million in the current period, reduced recoveries of deferred net power costs of $29.7 million and an increase in the change in working capital of $43.7 million. The increase in the change in working capital was due to a $55.9 million increase in the change in accounts receivable and prepaid account balances and a $20.4 million increase in the change in inventory balances, offset by a $32.6 million decrease in the change in accounts payable, accrued liabilities and other current account balances.

Investing Activities

Capital spending totaled $539.9 million for the nine months ended December 31, 2004, compared to $484.8 million for the nine months ended December 31, 2003. The increase was primarily due to $132.1 million of increased expenditures on the construction of the Currant Creek plant and $9.3 million for the construction of the Lake Side plant, partially offset by $31.9 million in lower expenditures on the distribution and transmission upgrades along the Wasatch Front and reductions in other capital expenditures. Expenditures for the Currant Creek and Lake Side plants will remain in construction work-in-progress until the plants are placed into service.

Financing Activities

Short-Term Debt

PacifiCorp’s short-term debt increased by $159.8 million during the nine months ended December 31, 2004, primarily due to capital expenditures in excess of cash from operations, partially offset by the proceeds from the long-term debt financing during the period, which were used to reduce short-term debt.

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, that 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 December 31, 2004, this facility was fully available and there were no borrowings outstanding. In addition to this committed credit facility, PacifiCorp had $14.1 million in money market accounts included in Cash and cash equivalents at December 31, 2004, available to meet its liquidity needs. Regulatory authorities limit PacifiCorp to $1.5 billion of short-term debt, of which $284.7 million was outstanding at December 31, 2004, at a weighted average rate of 2.4%.

At December 31, 2004, PacifiCorp had $517.8 million of standby letters of credit and standby bond purchase agreements available to provide credit enhancement and liquidity support for variable-rate pollution control revenue bond obligations. These committed bank arrangements expire periodically through the year ending March 31, 2008. Subsequent to December 31, 2004, approximately $96.5 million of these committed bank arrangements were extended through January 21, 2010.

Long-Term Debt

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

Dividends

During the nine months ended December 31, 2004, PacifiCorp had the following dividend activity:

•

$144.9 million declared and paid on common stock; and

•

$4.6 million declared and $4.8 million paid on Preferred stock and Preferred stock subject to mandatory redemption.

During the nine months ended December 31, 2003, PacifiCorp had the following dividend activity:

•

$120.4 million declared and paid on common stock; and

•

$5.0 million declared and $5.2 million paid on Preferred stock and 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 nine months ended December 31, 2004 and 2003.

Cautionary Statement

Management anticipates that it may be necessary to supplement cash generated from operations and availability under committed credit facilities with new issuances of long-term debt or additional equity from PHI to fund liquidity requirements during the next 12 months. PacifiCorp presently anticipates a combination of sufficient access to new long-term debt and additional equity contributions from PHI to fund liquidity requirements. However, if market conditions are not favorable, or equity contributions from PHI are not available, it may be necessary for PacifiCorp to postpone certain planned capital expenditures, or take other actions, to the extent those expenditures are not fully covered by cash from operations and availability under committed credit facilities.

Future Uses of Cash

Dividends

On January 20, 2005, PacifiCorp’s Board of Directors declared a dividend on common stock of $0.155 per share, totaling $48.3 million and payable on February 28, 2005.

Contractual Obligations and Commercial Commitments

PacifiCorp enters into contracts that require cash payment at specified periods, based on specified minimum quantities and prices. For an in-depth discussion of PacifiCorp’s contractual obligations and commercial commitments, see “Contractual Obligations and Commercial Commitments” in “Management’s Discussion and Analysis of Results of Operations and Financial Condition” in PacifiCorp’s Annual Report on Form 10-K for the year ended March 31, 2004.

Capital Expenditure Program

Capital expenditures are expected to be approximately $3.0 billion for the three-year period ending March 31, 2007, as reported in PacifiCorp’s Annual Report on Form 10-K for the year ended March 31, 2004. However, actual expenditures over the three-year period may vary due to timing of capital projects and related expenditures, as well as changes in the scope of planned projects.

Construction of the Currant Creek 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, $191.3 million had been spent, and was included in construction work-in-progress, as of December 31, 2004. Recovery of PacifiCorp’s investment in the plant will be reviewed by all states PacifiCorp serves as part of future general rate cases.

The development of the Lake Side plant began in May 2004 and its construction will begin in July 2005. The plant is expected to cost approximately $347.0 million, spent from fiscal year 2005 through fiscal year 2008. Of this total expected amount, $9.3 million had been spent, and was included in construction work-in-progress as of December 31, 2004. Recovery of PacifiCorp’s investment in the plant will be reviewed by all states PacifiCorp serves as part of future general rate cases.

Other Matters

American Jobs Creation Act of 2004

On October 22, 2004, the President signed the American Jobs Creation Act of 2004 (the “Jobs Act”). The Jobs Act provides a deduction for income from qualified domestic production activities, which will be phased in from 2005 through 2010. Under the Jobs Act, qualified production activities include PacifiCorp’s electric generation activities.

Under the guidance in FSP SFAS No. 109-1, the deduction will be treated as a “special deduction” as described in SFAS No. 109. As such, the special deduction has no effect on deferred tax assets and liabilities existing at the enactment date. Rather, the impact of this deduction will be reported in the period in which the deduction could be claimed on a separate-return basis in accordance with PacifiCorp’s accounting policy.

The impact of the deduction upon PacifiCorp will depend on the application of forthcoming guidance from the Internal Revenue Service to PacifiCorp’s future qualifying electric generation activities and cannot be estimated at this time.

Credit Ratings

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

	Moody’s	S & P

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

Outlook	Negative	Stable

On August 18, 2004, Standard & Poor’s Rating Services revised its outlook on PacifiCorp to stable from negative. At the same time, Standard & Poor’s lowered the senior secured debt rating on PacifiCorp to A- from A. These security ratings are not recommendations to buy, sell or hold securities. The ratings are subject to change or withdrawal at any time by the respective credit rating agencies. Each credit rating should be evaluated independently of any other rating.

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, guarantees, 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 December 31, 2004 distribution of unsecured credit exposure, net of collateral, within its electricity and natural gas portfolio of purchase and sale contracts and takes into account contractual netting rights.

Distribution of Credit Exposure	% of Total

Investment grade - Externally rated	87.1	%
Non-investment grade - Externally rated	2.2
Investment grade - Internally rated	2.5
Non-investment grade - Internally rated	8.2

	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.

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 December 31, 2004, PacifiCorp had $826.7 million of variable-rate liabilities and $14.1 million of temporary cash investments. At December 31, 2004, PacifiCorp had no financial derivatives in effect relating to interest rate exposure.

Based on a sensitivity analysis as of December 31, 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 December 31, 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 $6.9 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 December 31, 2004 and 2003. The increase in interest rate sensitivity was primarily due to the increase in outstanding variable-rate commercial paper and the 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 7,994.5 MW, as well as its transmission rights held both on some of its own 15,763-mile transmission system and on third-party transmission systems and through its wholesale energy purchase and sales activities. Wholesale contracts are utilized to balance PacifiCorp’s physical excess or shortage of net electricity for future time periods. Financially settled contracts are utilized to further mitigate commodity price risk. PacifiCorp may from time to time enter into other financially settled (temperature-related) derivative instruments that reduce volume and price risk on

days with weather extremes. In addition, a financially settled hydroelectric 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 (holding) period to simulate potential forward energy market price curve movements to estimate the potential unfavorable impact of such price changes on the portfolio positions scheduled to settle within the following 24 months. The quantification of market risk using VaR provides a consistent measure of risk across PacifiCorp’s continually changing portfolio. VaR represents an estimate of 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. These options provide for energy volume changes that are sensitive to market price changes. Therefore, changes in the option values affect the energy position of the portfolio with respect to market prices, and this effect is calculated daily. When measuring portfolio exposure through VaR, these position changes that result from the option sensitivity are held constant through the historical simulation to avoid understating VaR.

As of December 31, 2004, PacifiCorp’s estimated potential five-day unfavorable impact on fair value of the electricity and natural gas commodity portfolio over the next 24 months was $26.3 million, as measured by the VaR computations described above, compared to $19.5 million as of December 31, 2003. The minimum, average and maximum daily VaR (five-day holding periods) for the three and nine months ended December 31, 2004 are as follows:

(Millions of dollars)	Three Months Ended December 31, 2004		Nine Months Ended December 31, 2004

Minimum VaR (measured)	$	13.6	$	11.3
Average VaR (calculated)		16.4		16.2
Maximum VaR (measured)		26.3		26.3

The increase in VaR as of December 31, 2004 as compared to the average VaR during the three and nine months ended December 31, 2003 was due to the inclusion in the portfolio position of an updated retail load forecast at December 30, 2004 that had the effect of lengthening PacifiCorp’s net energy position (i.e., the updated load forecast showed lower expected loads during the 24-month VaR measurement period), thereby causing an increase in VaR. PacifiCorp maintained compliance with its VaR limit procedures during the three months and nine months ended December 31, 2004. Changes in markets inconsistent with historical trends or assumptions used could cause actual results to exceed predicted limits.

Fair Value of Derivatives

The following table shows the changes in the fair value of energy-related contracts qualifying as derivatives under SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities (“SFAS No. 133”), as amended, from April 1, 2004, to December 31, 2004, segregated between derivative contracts held for trading and non-trading purposes, and quantifies the reasons for the changes.

							Regulatory Net Asset (Liability) (b)
	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		0.3			(11.9	)		(13.8	)
Other changes in fair values (a)		0.4			154.7			(130.5	)

Fair value of contracts outstanding at December 31, 2004	$	0.2		$	(271.5	)	$	277.9

(a)

(b)

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

The fair value of derivative instruments is determined using forward price curves. Forward price curves represent PacifiCorp’s estimates of the prices at which a buyer or seller could contract today for delivery or settlement of a commodity at future dates. PacifiCorp bases its forward price curves 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 less or 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 electricity plants in converting fuel to electricity) in the region where the purchase or sale takes place, and a fundamental forecast of expected spot prices based on modeled supply and demand in the region. The assumptions in these models are critical since any changes to the assumptions could have a significant impact on the fair value of the contract. Contracts with explicit or embedded optionality are valued by separating each contract into its physical and financial forward and option components. Forward components are valued against the appropriate forward price curve. The optionality is valued using a modified Black-Scholes model or a stochastic simulation (Monte Carlo) approach. Each option component is modeled and valued separately using the appropriate forward price curve.

PacifiCorp’s valuation models and assumptions are continuously updated to reflect current market information, and 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 December 31, 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	$	0.2		$	—		$	—		$	—		$	0.2
Prices based on models and other valuation methods		—			—			—			—			—


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


Non-trading:
Prices based on quoted market prices from third-party sources	$	(20.8	)	$	(21.0	)	$	2.1		$	2.2		$	(37.5	)
Prices based on models and other valuation methods		54.8			57.3			(59.2	)		(286.9	)		(234.0	)


Total non-trading	$	34.0		$	36.3		$	(57.1	)	$	(284.7	)	$	(271.5	)

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 December 31, 2004, the disclosure controls and procedures were effective, in all material respects, in timely alerting management to material information relating to PacifiCorp and its consolidated subsidiaries required to be included in its periodic reports filed pursuant to the Securities Exchange Act of 1934.

There has been no change in PacifiCorp’s internal control over financial reporting that occurred during the three months ended December 31, 2004, that has materially affected, or is reasonably likely to materially affect, PacifiCorp’s internal control over financial reporting.

PART II. OTHER INFORMATION

INFORMATION REGARDING RECENT REGULATORY DEVELOPMENTS

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 in PacifiCorp’s Annual Report on Form 10-K for the year ended March 31, 2004. Certain developments with respect to those matters are set forth below.

Federal Regulatory Issues

FERC Issues

For a discussion of FERC issues, see Part I – Item 1. Financial Statements – Note 7 – 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. 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 $26.5 million for environmental mitigation and enhancement projects. A $12.2 million liability, representing the present value of these obligations, was recorded in May 2004.

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

In February 2004, PacifiCorp filed with the FERC a final application for a new license to operate the 151.0 MW Klamath hydroelectric project. The FERC is scheduled to complete its required analysis by April 2006. In the meantime, PacifiCorp continues to work cooperatively with a broad range of stakeholders to identify and resolve any outstanding issues in an attempt to reach a settlement. In October 2004, PacifiCorp convened a mediated settlement negotiation group consisting of itself, state and federal agencies, Native American tribes, and other stakeholders, in an effort to reach a comprehensive agreement on project relicensing.

Lewis River hydroelectric projects – (Lewis River, Washington)

PacifiCorp filed new license applications for the 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 so that the FERC could complete a comprehensive environmental analysis.

On November 30, 2004, PacifiCorp executed a comprehensive settlement agreement with 25 other parties including state and federal agencies, Native American tribes, conservation groups, and local government and citizen groups to resolve, among the parties, issues related to the pending applications for new licenses for PacifiCorp’s 135.0 MW Merwin, 240.0 MW Swift No. 1 and 134.0 MW Yale hydroelectric projects. As part of this settlement agreement, PacifiCorp has agreed to implement certain protection, mitigation and enhancement measures prior to and during a proposed 50-year license period. However, these commitments are contingent on ultimately receiving a license from the FERC that is consistent with the settlement agreement, and other required permits. The FERC is scheduled to complete its process and required analysis in order to be ready for a decision in March 2006.

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

In November 2003, the FERC issued a new 35-year operating license for the 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. In May 2004, the environmental groups appealed the FERC order in the Ninth Circuit Court of Appeals, where the case is currently pending. The new FERC license is currently effective, but not final, and certain implementation measures may be delayed pending the outcome of the appeal. In addition to the project’s capital and operations and maintenance costs associated with the new license, when the license becomes final PacifiCorp will be committed, over the life of the license, to fund approximately $48.9 million for environmental mitigation and enhancement projects. A $13.0 million liability, representing the present value of certain obligations specified in the license, was recorded in June 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 and issue a new license by the end of fiscal year 2005.

Decommissioning

PacifiCorp has negotiated with stakeholders to decommission the American Fork, Condit and Powerdale projects. These settlement agreements have been filed with the FERC.

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

The FERC issued a surrender order for American Fork on August 4, 2004, which calls for project removal to be completed by December 2007. Removal costs for this 1.0 MW project are estimated to be approximately $1.1 million, including process and permitting costs. The parties have agreed that project removal will begin in September 2006, subject to FERC and other regulatory approvals, with operations continuing until that time.

Condit hydroelectric project – (White Salmon River, Washington)

In September 1999, a settlement agreement to remove the 9.6 MW Condit hydroelectric project was signed by PacifiCorp, state and federal agencies, and non-governmental organizations, which called for removal to begin in October 2006 for a total cost to decommission not to exceed $17.2 million, excluding inflation. In early February 2005, the parties agreed to modify the settlement agreement so that removal will not begin until October 2008 for a total cost to decommission not to exceed $20.5 million, excluding inflation. The settlement agreement is contingent upon receiving a consistent FERC order and other regulatory approvals. PacifiCorp is in the process of acquiring all necessary permits, within the terms and conditions of the settlement agreement.

State Regulatory Issues

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

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%. In October 2004, the UPSC approved the use of a forward-looking test year in this general rate case, which will be fiscal year 2006. Intervenor testimony was filed on December 3, 2004 and PacifiCorp rebuttal testimony was filed on January 14, 2005. The impact of the rebuttal case was to reduce PacifiCorp’s revenue requirement request from $111.0 million to $96.3 million. The main reasons for this change were to reflect increased revenues from updated customer contracts and to update specific items in the filing. The overall general rate case is expected to be concluded by April 2005. Settlement discussions are ongoing with all parties.

Pending before the Utah Legislature is Senate Bill 26 (“SB 26”), a bill to establish rules and a mandatory process for the solicitation and evaluation of bids to procure significant energy resources. SB 26, if enacted, would also provide PacifiCorp with the opportunity to obtain advance approval from the UPSC of a resource decision and an assurance of the recovery of costs associated with the resource. SB 26 also establishes a voluntary process for utilities to obtain advance approval of certain other resource commitments and investment decisions. The proposed legislation has received support from a wide range of stakeholders and has passed the Senate without dissent and awaits action in the House.

Oregon

In November 2000, PacifiCorp made a deferred accounting filing to track its excess net power costs. In July 2002, the Oregon Public Utility Commission (the “OPUC”) approved the filing, finding that PacifiCorp had prudently incurred the excess net power costs. The order authorized recovery of $131.0 million, plus carrying charges, a rate of $45.6 million annually. The Industrial Customers of Northwest Utilities and the Citizens’ Utility Board appealed the OPUC order. The Marion County, Oregon circuit court affirmed the OPUC order. The Industrial Customers of Northwest Utilities and the Citizens’ Utility Board appealed the circuit court decision to the Oregon Court of Appeals. The Court of Appeals heard oral arguments in May 2004. On October 27, 2004, the Oregon Court of Appeals affirmed the circuit court decision. The deadline for further appeals has passed. As of December 31, 2004, approximately $26.0 million remained to be collected by the authorized surcharge.

On November 12, 2004, PacifiCorp filed a general rate case with the OPUC related to increases in operating costs, including fuel, purchased power, and pension and health care costs. PacifiCorp is seeking an increase of $102.0 million annually, or 12.5%. If approved by the OPUC, the increase would take effect in September 2005. A pre-hearing conference was held on December 7, 2004 and scheduling hearings will be in July 2005.

As a result of Direct Access mandated by Oregon’s Senate Bill 1149, customers having a total load of approximately 20 average MW have chosen service from a supplier other than PacifiCorp. Customers having a total load of approximately 1 average MW have taken service from PacifiCorp at the Daily Market Pricing Option. These changes will not have a material effect on earnings.

Wyoming

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

Also, in April 2004, PacifiCorp filed a complaint with the federal district court in Wyoming challenging the WPSC’s March 2003 decision on the grounds that the decision violates federal law by denying PacifiCorp recovery in retail rates of its wholesale electricity and transmission costs incurred to serve Wyoming customers. The lawsuit seeks an injunction requiring the WPSC to pass through PacifiCorp’s wholesale electricity and transmission costs in retail rates. In May 2004, the WPSC filed a motion to dismiss the complaint. Oral arguments on the motion to dismiss took place in September 2004. The motion to dismiss was denied on November 5, 2004. On January 11, 2005, the defendants appealed the court’s ruling on the motions to dismiss and requested a stay of the underlying litigation. On January 31, 2005, PacifiCorp filed its brief in opposition to defendants’ interlocutory appeal of the court’s ruling.

In July 2004, PacifiCorp applied to the WPSC for a stand-alone pass-on of increased net wholesale purchased electricity costs. Following discussions with various parties, PacifiCorp filed a joint stipulation reducing this request to $9.25 million, or 2.68%. This stipulation was heard by the WPSC on September 14, 2004 and approved effective September 15, 2004. The expedited treatment of this application was recognized in the stipulation with an agreement that PacifiCorp will not file a general rate application until at least September 30, 2005. Further, the parties agreed to hold discussions on the development of a commodity cost recovery mechanism and alternative forms of regulation (“AFOR”). Meetings have taken place with the parties to evaluate inputs into a commodity cost recovery mechanism and an AFOR. PacifiCorp continues to study the stated interests of the parties in these regulatory mechanisms and how they might affect the risk of doing business in Wyoming.

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

In December 2003, OCI, a subsidiary of OCI Chemical Corporation and producer of soda ash in southwestern Wyoming, filed a complaint with the WPSC seeking a determination by the WPSC that PacifiCorp’s service is unsafe, inadequate and unreliable and that PacifiCorp be barred from imposing standard electric service rates on OCI. In addition, OCI filed a lawsuit against PacifiCorp in federal court seeking damages of approximately $6.5 million. On December 13, 2004, PacifiCorp made its designation of expert witnesses in federal court, and on December 20, 2004, PacifiCorp filed its testimony with the WPSC. On February 8, 2005, OCI filed a motion to dismiss the case before the WPSC. The WPSC has placed the motion to dismiss on its public agenda on February 10, 2005. The federal trial begins April 25, 2005.

Washington

In December 2003, PacifiCorp filed with the WUTC for a general rate increase of $26.7 million annually, or 13.5%. In addition, PacifiCorp requested that the WUTC adopt the findings of a prudence review of generating resources acquired since the last Washington general rate case. In August 2004, PacifiCorp entered into a Settlement Agreement with the WUTC Staff and the Natural Resources Defense Council that recommended a $15.5 million annual increase, or 7.8%. On October 27, 2004, the WUTC issued an order adopting the multi-party Settlement Agreement with limited conditions resulting in a total rate increase of $15.1 million, or 7.5%, effective

November 16, 2004. On November 10, 2004, the WUTC issued a supplemental order with revised calculations. As a result, the WUTC authorized an annual increase of $15.5 million, or 7.8%, effective November 16, 2004.

Idaho

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

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

On January 28, 2005, the IPUC approved PacifiCorp’s application to reduce the Bonneville Power Administration (the “BPA”) credit effective January 31, 2005. The reduction in the credit is necessary because PacifiCorp paid out $6.8 million more in credits to residential and small-farm customers than it received from the BPA. The change will result in an 8.0% reduction in the credit given to residential customers and a 20.5% reduction in the credit given to small-farm customers. Changes in the level of the BPA credit affect the net electricity costs to customers but do not impact PacifiCorp’s results of operations or earnings.

Multi-State Process

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

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

During June 2004 through November 2004, settlement discussions occurred in each of the states; agreements were reached with parties; and hearings or oral arguments took place. The final step in the regulatory process is the issuance of state orders detailing each state commission’s acceptance and implementation of the Revised Protocol. In October 2004, the WPSC issued an oral bench order approving the Wyoming settlement and the WUTC issued its formal order approving and adopting the Washington general rate case settlement and establishing a process for ongoing discussions for a permanent allocation methodology. In December 2004, the UPSC issued its order approving the Utah settlement, and in January 2005, the OPUC issued its order approving the Oregon settlement. PacifiCorp awaits receipt of the order from the IPUC, which is anticipated in February 2005. PacifiCorp is engaged in implementing the Revised Protocol for setting state revenue requirements in accordance with the orders it has received. The Revised Protocol has not yet been filed in the state of California.

Requests for Proposals

As required by state regulators, PacifiCorp published its 2003 Integrated Resource Plan in January 2003 and updated it in October 2003, 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 of these projects.

RFP 2003A - 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 electricity plant near Orem, Utah. The plant, to be known as the Lake Side Power Plant and to have a summer rated capacity of 534 MW, was identified as the best option submitted through PacifiCorp’s competitive RFP 2003A process of a resource to be made available by summer 2007. In May 2004, PacifiCorp filed with the UPSC for a Certificate of Convenience and Necessity. Hearings were held in October 2004 and the UPSC granted a Certificate of Public Convenience and Necessity in November 2004. On October 22, 2004, PacifiCorp entered into a long-term agreement with Siemens Westinghouse Power Corporation for certain maintenance items on the Lake Side Power Plant and issued a limited notice to proceed with construction preparation. The air quality permit for the Lake Side Power Plant was issued on January 6, 2005. The Interconnection Agreement between Lake Side Power Plant and PacifiCorp has been drafted and is anticipated to be signed by the end of February 2005. The Notice to Proceed between Summit Vineyard LLC and Siemens Westinghouse Power Corporation is expected to be issued by the end of February 2005. PacifiCorp is negotiating the construction of the gas lateral and the Transportation Service Agreement. The Lake Side Power Plant is expected to cost approximately $347.0 million. Recovery of PacifiCorp’s investment in the plant will be reviewed by the states PacifiCorp serves as part of future general rate cases.

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. Negotiations are currently underway for two separate projects, which have indicated their on-line date to be prior to calendar 2006.

Integrated Resource Plan

PacifiCorp filed its 2005 Integrated Resource Plan with the relevant state commissions on January 20, 2005. The 2005 Integrated Resource Plan provides a framework and plan for the prudent future actions required to ensure that PacifiCorp continues to provide reliable and cost-effective electric service to its customers. Projected growth rates and contract expirations indicate a need for approximately 2,800 MW of additional resources by 2015. These estimates are subject to ongoing review and could be revised. The Integrated Resource Plan process identifies PacifiCorp’s anticipated future resource mix in a coordinated process with the stakeholders in each of the six states where PacifiCorp operates.

As part of the Integrated Resource Plan process, PacifiCorp is expecting to meet the resource deficit through a combination of the following sources: thermal generation (approximately 2,629 MW) and load control programs (177 MW). PacifiCorp also plans to implement energy conservation programs (approximately 450 average MW) and will continue to procure 1,400 MW of economic renewable resources that were first identified in the 2003 Integrated Resource Plan. Shaped electric purchase agreements are used in an effort to optimize physical assets and reduce cost. Before PacifiCorp commits to build assets, electricity purchase agreements are reviewed and compared for economic benefit and their associated risk.

Regional Transmission Entity

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

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

Going forward, PacifiCorp will focus on working with the interim board of Grid West and the region’s stakeholders on the design details, and on influencing the acceptance of Grid West as a workable and beneficial market design framework. Assuming continued regional support, the filing utilities also plan to begin working with the proposed Grid West independent board of trustees to develop transmission agreements and develop a Grid West tariff in calendar 2006. In addition, the filing utilities have entered into a Memorandum of Understanding with the other two

potential western Regional Transmission Organizations, namely WestConnect and the California Independent System Operator, and anticipates continued work on inter-regional issues through this agreement or a redefined forum to address transmission and related market issues throughout the western interconnection.

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 6. EXHIBITS

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

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:	February 10, 2005	By:	/s/ RICHARD D. PEACH

			Richard D. Peach Chief Financial Officer