PACIFICORP /OR/ - 10-Q Quarterly Report

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UNITED STATES SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

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

For the quarterly period ended December 31, 2003

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, Suite 2000, Portland, Oregon (Address of principal executive offices)		97232-4116 (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 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for 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, 2004, there were 312,176,089 shares of common stock outstanding. All shares of outstanding common stock are indirectly owned by Scottish Power plc, 1 Atlantic Quay, Glasgow, G2 8SP, Scotland.

PACIFICORP

		Page No.
PART I.	FINANCIAL INFORMATION

Item 1.	Financial Statements (Unaudited)

	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 Accountants	19

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	20

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	31

Item 4.	Controls and Procedures	34

PART II.	OTHER INFORMATION

Item 5.	Other Information	34

Item 6.	Exhibits and Reports on Form 8-K	40

SIGNATURE		42

PART I. FINANCIAL INFORMATION

ITEM 1.

FINANCIAL STATEMENTS

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

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

	2003			2002			2003			2002

Revenues	$	873.6		$	853.2		$	2,726.4		$	2,682.7

Operating expenses
Purchased electricity		250.7			259.7			842.3			934.9
Fuel		115.4			120.8			364.3			351.3
Operations and maintenance		215.0			220.7			635.0			633.9
Depreciation and amortization		107.9			109.4			318.1			324.3
Taxes, other than income taxes		25.1			21.2			73.0			69.3
Unrealized (gain) loss on derivative contracts		(2.4	)		0.4			0.8			(2.7	)

Total		711.7			732.2			2,233.5			2,311.0
Other operating expense		0.4			—			13.2			—

Income from operations		161.5			121.0			479.7			371.7

Interest expense and other (income) expense
Interest expense		66.4			63.6			190.0			208.2
Interest income		(3.2	)		(4.6	)		(11.2	)		(14.0	)
Interest capitalized		(5.0	)		(3.8	)		(17.1	)		(13.7	)
Minority interest and other (income) expense		(4.7	)		1.5			2.6			16.6

Total		53.5			56.7			164.3			197.1

Income from operations before income taxes and cumulative effect of accounting change		108.0			64.3			315.4			174.6
Income tax expense		47.5			24.6			132.3			65.9

Income before cumulative effect of accounting change		60.5			39.7			183.1			108.7
Cumulative effect of accounting change (less applicable income tax benefit of $(0.6)/2003 and $(1.1)/2002) (See Notes 3 and 5)		—			—			(0.9	)		(1.9	)

Net income		60.5			39.7			182.2			106.8
Preferred dividend requirement		(0.5	)		(1.8	)		(2.8	)		(5.5	)

Earnings on common stock	$	60.0		$	37.9		$	179.4		$	101.3

RETAINED EARNINGS AT BEGINNING OF PERIOD	$	345.0		$	236.5		$	305.9		$	173.1
Net income		60.5			39.7			182.2			106.8
Cash dividends declared
Preferred stock		(0.5	)		(1.8	)		(2.8	)		(5.5	)
Common stock		(40.1	)		—			(120.4	)		—

RETAINED EARNINGS AT END OF PERIOD	$	364.9		$	274.4		$	364.9		$	274.4

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, 2003			March 31, 2003

Current assets
Cash and cash equivalents	$	85.5		$	152.5
Accounts receivable (less allowance for doubtful accounts of $39.6/December and $36.3/March)		270.4			258.3
Unbilled revenue		150.8			109.2
Amounts due from affiliates		9.7			2.5
Inventories at average cost
Materials and supplies		97.8			99.4
Fuel		57.2			71.8
Current derivative contract assets		97.4			107.2
Other		26.6			18.9

Total current assets		795.4			819.8


Property, plant and equipment		13,652.7			13,184.3
Construction work in progress		353.1			332.5
Accumulated depreciation and amortization		(5,067.6	)		(5,483.2	)

Total property, plant and equipment - net		8,938.2			8,033.6


Other assets
Regulatory assets		1,094.2			1,175.2
Derivative contract regulatory assets		526.9			506.9
Noncurrent derivative contract assets		155.8			122.3
Deferred charges and other		327.1			342.1

Total other assets		2,104.0			2,146.5

Total assets	$	11,837.6		$	10,999.9

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, 2003			March 31, 2003

Current liabilities
Long-term debt currently maturing	$	264.7		$	136.7
Preferred stock subject to mandatory redemption, currently maturing (See Note 7)		3.8			—
Notes payable and commercial paper		224.9			25.0
Accounts payable		207.3			243.4
Amounts due to affiliates		2.7			39.6
Accrued employee expenses		106.4			137.6
Taxes payable		50.8			66.9
Interest payable		55.2			67.9
Current derivative contract liabilities		95.6			91.7
Other		117.4			127.3

Total current liabilities		1,128.8			936.1

Deferred credits
Income taxes		1,535.1			1,480.0
Investment tax credits		85.5			91.4
Regulatory liabilities		808.8			137.0
Noncurrent derivative contract liabilities		684.1			643.5
Other		711.9			650.1

Total deferred credits		3,825.4			3,002.0

Long-term debt, net of current maturities		3,527.1			3,417.6
Preferred stock subject to mandatory redemption, net of current maturities (See Note 7)		56.2			—

Total liabilities		8,537.5			7,355.7

Commitments and contingencies (See Note 8)
Guaranteed preferred beneficial interests in Company’s junior subordinated debentures (See Note 7)		—			341.8

Preferred stock subject to mandatory redemption (See Note 7)		—			66.7

Shareholders’ equity
Preferred stock		41.3			41.3
Common shareholder’s capital		2,892.1			2,892.1
Retained earnings		364.9			305.9
Accumulated other comprehensive income (loss)
Unrealized gain (loss) on available-for-sale securities, net of tax of $2.2/December and $(1.1)/March		3.7			(1.7	)
Minimum pension liability, net of tax of $(1.0)		(1.9	)		(1.9	)

Total shareholders’ equity		3,300.1			3,235.7

Total liabilities and shareholders’ equity	$	11,837.6		$	10,999.9

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

PACIFICORP
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)

(Millions of dollars)	Nine Months Ended December 31,

	2003			2002

Cash flows from operating activities
Net income	$	182.2		$	106.8
Adjustments to reconcile net income to net cash provided by operating activities:
Cumulative effect of accounting change, net of tax		0.9			1.9
Unrealized gain on derivative contracts		0.8			(2.7	)
Depreciation and amortization		318.1			324.3
Deferred income taxes and investment tax credits - net		61.8			40.8
Provision for pensions and benefits		9.2			(10.0	)
Deferred net power costs		(8.7	)		(11.4	)
Changes in other regulatory assets and liabilities		89.3			110.7
Accounts receivable and prepayments		(63.0	)		(12.2	)
Inventories		16.2			(18.7	)
Accounts payable and accrued liabilities		(132.3	)		(229.7	)
Other		(8.3	)		12.1

Net cash provided by operating activities		466.2			311.9

Cash flows from investing activities
Capital expenditures		(484.8	)		(391.1	)
Proceeds from sales of assets		2.9			7.1
Proceeds from available-for-sale securities		77.8			97.7
Purchases of available-for-sale securities		(76.7	)		(98.7	)
Other		(2.7	)		4.8

Net cash used in investing activities		(483.5	)		(380.2	)

Cash flows from financing activities
Changes in short-term debt		199.9			(8.7	)
Proceeds from long-term debt, net of issuance costs		397.0			—
Proceeds from issuance of common stock to PacifiCorp Holdings, Inc.		—			150.0
Dividends paid		(124.4	)		(5.6	)
Repayments of long-term debt		(162.3	)		(137.8	)
Repayments of preferred securities		(352.0	)		(0.3	)
Redemptions of preferred stock		(7.5	)		(7.5	)
Other		(0.4	)		—

Net cash used in financing activities		(49.7	)		(9.9	)

Decrease in cash and cash equivalents		(67.0	)		(78.2	)
Cash and cash equivalents at beginning of period		152.5			157.9

Cash and cash equivalents at end of period	$	85.5		$	79.7

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 Certain Significant Accounting Policies

The Condensed Consolidated Financial Statements of PacifiCorp include its integrated electric utility operations and its wholly owned and majority-owned subsidiaries (together, the “Company”). The subsidiaries of PacifiCorp support its electric utility operations by providing coal mining facilities and services, environmental remediation and, until their securities were redeemed in August 2003, financing. Intercompany transactions and balances have been eliminated upon consolidation.

The accompanying unaudited Condensed Consolidated Financial Statements as of December 31, 2003 and for each of the three and nine month periods ended December 31, 2003 and 2002, in the opinion of management, include all adjustments, constituting only normal recurring adjustments, necessary for a fair presentation of the financial position, results of operations and cash flows for such periods. The March 31, 2003 Condensed Consolidated Balance Sheet data was derived from audited financial statements. These statements are presented in accordance with the Securities and Exchange Commission’s (the “SEC”) interim reporting requirements, which do not include all the disclosures required by accounting principles generally accepted in the United States of America. Certain information and footnote disclosures made in the Company’s Annual Report on Form 10-K for the year ended March 31, 2003 have been condensed in or omitted from the interim statements. A portion of the business of the Company is of a seasonal nature, therefore results of operations for the periods ended December 31, 2003 and 2002 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 the Company’s 2003 Annual Report on Form 10-K.

These interim statements have been prepared using accounting policies consistent with those applied at March 31, 2003, except in relation to new accounting standards. Certain amounts have been reclassified to conform to the current method of presentation. These reclassifications had no effect on previously reported consolidated net income.

Stock-based compensation - As permitted by Statement of Financial Accounting Standards (“SFAS”) No. 123, Accounting for Stock-Based Compensation (“SFAS No. 123”), the Company has elected to account for its stock-based compensation arrangements under the intrinsic value recognition and measurement principles of Accounting Principles Board (“APB”) Opinion No. 25, Accounting for Stock Issued to Employees (“APB No. 25”), and related interpretations in accounting for employee stock options issued to Company employees. Under APB No. 25, because the exercise price of employee stock options equals the market price of the underlying stock on the date of grant, no compensation expense is recorded. All options are for American Depository Shares of Scottish Power plc (“ScottishPower”), the Company’s indirect parent. Had the Company determined compensation cost based on the fair value at the grant date for all stock options vesting in each period under SFAS No. 123, the Company’s net income (net of related tax effect) would have been changed to the pro forma amounts below:

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

(Millions of dollars)	2003		2002		2003		2002

Net income as reported	$	60.5	$	39.7	$	182.2	$	106.8
Stock-based employee compensation expense		0.2		0.5		0.6		1.5

Pro forma net income	$	60.3	$	39.2	$	181.6	$	105.3

Unbilled revenues - The Company changed its calculation of unbilled revenues during the three months ended June 30, 2003, which had the effect of increasing revenues by approximately $10.0 million and after-tax net income by approximately $5.7 million for the nine months ended December 31, 2003.

Note 2 - Accounting for the Effects of Regulation

Regulated utilities have historically applied the provisions of SFAS No. 71, Accounting for the Effects of Certain Types of Regulation (“SFAS No. 71”), which is based on the premise that regulators will set rates that allow for the recovery of a utility’s costs, including cost of capital. SFAS No. 71 provides that regulatory assets may be

capitalized if it is probable that future revenue in an amount at least equal to the capitalized costs will result from the inclusion of that cost in allowable costs for ratemaking purposes. The Company records regulatory assets and liabilities based on management’s assessment that it is probable that a cost will be recovered (asset) or that an obligation has been incurred (liability). The final outcome, or additional regulatory actions, could change management’s assessment in future periods.

Regulatory assets include the following:

(Millions of dollars)	December 31, 2003		March 31, 2003

Deferred taxes	$	536.1	$	550.3
Minimum pension liability offset		233.8		233.8
Deferred net power costs (a)		78.2		137.8
Unamortized issuance expense on retired debt (b)		42.4		34.3
Demand-side resource		42.3		45.7
Transition Plan - retirement and severance		41.5		55.1
Various other		119.9		118.2

Subtotal		1,094.2		1,175.2
Derivative contracts (c)		526.9		506.9

Total	$	1,621.1	$	1,682.1

(a)

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

(b)

Represents the unamortized debt expense and redemption premiums on securities retired prior to maturity. During the nine months ended December 31, 2003, the Company transferred $11.9 million to regulatory assets in relation to the redemption of First Mortgage Bonds and Preferred Securities. See Note 7.

(c)

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

Regulatory liabilities include the following:

(Millions of dollars)	December 31, 2003		March 31, 2003

Asset retirement removal costs (a)	$	667.2	$	—
Centralia gain		51.8		66.5
Deferred taxes		37.0		39.3
Various other		52.8		31.2

Total	$	808.8	$	137.0

(a)

Represents removal costs recovered in rates that do not qualify as asset retirement obligations under SFAS No. 143, Accounting for Asset Retirement Obligations (“SFAS No. 143”). See Note 5.

The Company 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 the Company to record regulatory asset write-offs and charges for impairment of long-lived assets in future periods.

DEPRECIATION RATE CHANGES

The Company received approval through general rate cases or separate proceedings from all state commissions for changes in the Company’s rates of depreciation. Effective April 1, 2003, the resulting depreciation rate changes reduced total Company annual depreciation expense by approximately $26.0 million, which includes removal costs, and may ultimately result in lower future revenues or offset anticipated price increases.

REGULATORY ACTIONS

Utah

On December 17, 2003, the Utah Public Service Commission (the “UPSC”) approved a stipulation allowing an annual increase of $65.0 million, representing a 7.0% average price increase. The increase in customer rates is effective April 1, 2004. A stipulation on rate spread and rate design was filed with the UPSC on January 7, 2004. On January 30, 2004, the UPSC approved the stipulation, which will result in a mechanism to collect the previously ordered price increase.

Oregon

On August 26, 2003, the Oregon Public Utility Commission (the “OPUC”) approved a settlement of the Company’s general rate case filed on March 18, 2003. Under the settlement, base rates increased by $8.5 million annually on September 1, 2003, resulting in a 1.1% average price increase. The settlement also eliminated a $12.0 million offsettable merger credit for the period from January 2004 to December 2004. A nonoffsettable merger credit will be reduced from $6.0 million to $4.0 million, and the Company anticipates amortizing the credit to return the full amount to customers by December 31, 2004.

California

The California Public Utilities Commission (the “CPUC”) issued a final order on November 13, 2003 approving two stipulations in the general rate case and finalizing permanent rates. The order grants an additional annual increase of $2.8 million effective December 1, 2003. Combining this order with the interim increase authorized in June 2002 results in an overall annual price increase of $7.6 million. This represents a 13.6% average price increase.

Note 3 - Derivative Instruments

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

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

On April 1, 2001, the Company adopted SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities (“SFAS No. 133”), as amended by numerous interpretations of the Derivatives Implementation Group (the “DIG”) that are approved by the Financial Accounting Standards Board (the “FASB”). Subsequent revisions were made in SFAS No. 138, Accounting for Certain Derivative Instruments and Certain Hedging Activities, and SFAS No. 149, Amendment of Statement 133 on Derivative Instruments and Hedging Activities (“SFAS No. 149”), both of which have been adopted by the Company. Collectively, these statements are referred to as “SFAS No. 133.” Under SFAS No. 133, derivative instruments are recorded on the Condensed Consolidated Balance Sheets as assets or liabilities measured at estimated fair value, unless they qualify for the exemptions afforded by the standard.

SFAS No. 149 was issued in April 2003. This statement amends and clarifies financial reporting for derivative instruments, including certain derivative instruments embedded in other contracts, and for hedging activities. This statement was effective for contracts entered into or modified after June 30, 2003. In applying this statement, the Company began marking to market certain transactions that were entered into after June 30, 2003 that, prior to the implementation of SFAS No. 149, would have qualified for the normal purchase, normal sale exemption under SFAS No. 133.

In June 2002, the Company’s SFAS No. 133 contract assessments were updated to reflect the revised Issue C15, Normal Purchase and Normal Sales Exception for Certain Option-Type Contracts and Forward Contracts in Electricity (“Issue C15”), guidance from the DIG, effective April 1, 2002. The effects of adoption of the revised Issue C15 at April 1, 2002 resulted in a cumulative effect of accounting change adjustment of $2.1 million unfavorable (net of a tax benefit of $1.3 million) on the Company’s Condensed Consolidated Statements of Income and Retained Earnings for the nine months ended December 31, 2002.

In October 2001, the DIG issued guidance under Issue C16, Applying the Normal Purchases and Normal Sales Exception to Contracts that Combine a Forward Contract and a Purchased Option Contract (“Issue C16”). The effects of adoption of Issue C16 at April 1, 2002 resulted in a cumulative effect of accounting change adjustment of $0.2 million favorable (net of tax of $0.2 million) on the Company’s Condensed Consolidated Statements of Income and Retained Earnings for the nine months ended December 31, 2002.

Weather derivatives - To a limited degree, the Company has executed contracts to hedge changes in hydroelectric generation due to variation in streamflows. The Company has also executed contracts to hedge changes in retail electricity demand due to abnormal ambient temperatures. These contracts are not exchange-traded, and settlement is based on climatic or other physical variables. Therefore, on a periodic basis, the Company estimates and records a gain or loss in earnings corresponding to the total expected future cash flow from these contracts in accordance with the Emerging Issues Task Force (“EITF”) No. 99-2, Accounting for Weather Derivatives. The unrealized loss recorded for these contracts was $1.4 million and $6.6 million for the nine months ended December 31, 2003 and 2002, respectively. The realized gain recorded for these contracts was $5.2 million for the nine months ended December 31, 2003. For the nine months ended December 31, 2002, no realized gain or loss was recorded.

The following table summarizes the SFAS No. 133 movements for the nine months ended December 31, 2003:

(Millions of dollars)	Net Asset (Liability)			Regulatory Net Asset (Liability)			Deferred Tax Asset (Liability)			Accumulated Income (Loss)

Balance at March 31, 2003	$	(505.7	)	$	506.9		$	(0.5	)	$	0.7
Settlements		35.7			(33.9	)		(0.7	)		1.1
Changes in valuation assumptions		(45.2	)		45.4			—			0.2
Changes in fair value		(11.3	)		8.5			1.0			(1.8	)

Balance at December 31, 2003	$	(526.5	)	$	526.9		$	(0.2	)	$	0.2

Note 4 - Related-Party Transactions

There are no loans or advances between the Company and ScottishPower or between the Company and its immediate corporate parent, PacifiCorp Holdings, Inc. (“PHI”). Loans from the Company to ScottishPower or PHI are prohibited under the Public Utility Holding Company Act of 1935. Loans from ScottishPower or PHI to the Company generally require state regulatory and SEC approval. Affiliate transactions with the Company are subject to certain approval and reporting requirements of the regulatory authorities.

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

(Millions of dollars)	December 31, 2003		March 31, 2003

Amounts due from affiliated entities:
ScottishPower (a)	$	0.2	$	0.1
PHI subsidiaries (b)		9.5		2.4

	$	9.7	$	2.5

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

Amounts due to affiliated entities:
ScottishPower (d)	$	2.7	$	2.6
PHI subsidiaries (e)		—		37.0

	$	2.7	$	39.6

Deposits received from affiliated entities:
PHI subsidiaries (f)	$	1.1	$	1.4

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

	2003		2002		2003		2002

Revenues from affiliated entities:
PHI subsidiaries (f)	$	0.9	$	0.9	$	2.7	$	3.4

Expenses incurred from affiliated entities:
ScottishPower (d)	$	2.0	$	3.7	$	5.7	$	8.6
PHI subsidiaries (c)		4.3		3.7		12.8		7.8

	$	6.3	$	7.4	$	18.5	$	16.4

Expenses recharged to affiliated entities:
ScottishPower (a)	$	0.2	$	0.3	$	0.6	$	0.6
PHI subsidiaries (b)		1.9		2.1		5.7		5.6

	$	2.1	$	2.4	$	6.3	$	6.2

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

(a)

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

(b)

Amounts shown pertain to activities of the Company with PHI and its subsidiaries. Expenses recharged reflect costs for support services to PHI and its subsidiaries and include the current portion of taxes receivable from PHI of $5.6 million at December 31, 2003, which will be applied to the Company’s liability for the quarter ending March 31, 2004. PHI is the tax-paying entity for the Company.

(c)

These expenses primarily represent operating lease payments for the West Valley facility, located in Utah and owned by West Valley Leasing Company, LLC (“West Valley”), which was only operational during a part of the nine months ended December 31, 2002. West Valley is a subsidiary of PPM Energy, Inc. (“PPM”), which is a direct subsidiary of PHI. Certain costs associated with the West Valley lease are prepaid on an annual basis.

(d)

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

(e)

Amounts shown include the current portion of net income taxes payable to PHI of $37.0 million at March 31, 2003.

(f)

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

(g)

Includes interest on short-term demand loans made to the Company by PacifiCorp Group Holdings Company, a direct subsidiary of PHI, in accordance with regulatory authorizations.

Interest rates on related-party transactions approximate the lender’s short-term borrowing cost or cost of capital as required by the relevant regulatory approval or exemption. The average applicable rates were 1.2% and 1.6% for the three months ended December 31, 2003 and 2002, respectively. The average applicable rates were 1.3% and 1.8% for the nine months ended December 31, 2003 and 2002, respectively.

On September 30, 2003, the Company made compliance filings for a cross-charge policy agreement governing the allocation of costs incurred by the Company and by Scottish Power UK plc, an indirect subsidiary of Scottish Power plc, on behalf of each other. Filings were submitted to Utah, Oregon, Wyoming, Washington and Idaho. On December 12, 2003, the OPUC approved the policy. The agreement establishes a process for directly assigning or allocating costs between the Company and Scottish Power UK plc for common corporate functions. These charges to the Company, at cost, are estimated to be in the range of $20.0 million to $25.0 million annually on a net basis. These cross-charges are expected to commence in the fourth quarter of fiscal year 2004 and will be recorded as Operations and maintenance expense.

Note 5 - Asset Retirement Obligations

In June 2001, the FASB issued SFAS No. 143. The statement requires the fair value of an asset retirement obligation to be recorded as a liability in the period in which the obligation was incurred. At the same time the liability is recorded, the costs of the asset retirement obligation must be recorded as an addition to the carrying amount of the related asset. Over time, the liability is accreted to its present value, and the addition to the carrying amount of the asset is depreciated over the asset’s useful life. Upon retirement of the asset, the Company will settle the retirement obligation against the recorded balance of the liability. Any difference in the final retirement obligation cost and the liability will result in either a gain or a loss. The Company adopted this statement as of April 1, 2003.

The Company had been recording retirement obligations relating to reclamation, closure and removal costs before adoption of the standard. In addition, the Company records removal costs as a part of depreciation expense and accumulated depreciation in accordance with regulatory accounting requirements. As a result of adoption of the standard, the net difference between these previously recorded amounts that qualify as asset retirement obligations for regulatory purposes and the fair value amounts determined under SFAS No. 143 has been recognized as a noncash cumulative effect of a change in accounting principle, net of related income taxes. The Company recovers asset retirement costs through the ratemaking process and records a Regulatory asset or Regulatory liability on the Condensed Consolidated Balance Sheets to account for the difference between asset retirement costs as currently approved in rates and costs under SFAS No. 143.

Upon adoption of SFAS No. 143 on April 1, 2003, the Company recorded an asset retirement obligation liability at its net present value of $196.4 million. The Company also increased net depreciable assets by $37.6 million, removed $163.1 million of costs accrued for final removal from accumulated depreciation and reclamation liabilities, increased regulatory liabilities by $5.8 million for the difference between retirement costs approved by regulators and obligations under SFAS No. 143 and recorded a cumulative pretax effect of a change in accounting principle of $1.5 million, which is reflected in the Company’s Condensed Consolidated Statements of Income and Retained Earnings for the nine months ended December 31, 2003. As a result of the regulated environment in which the Company operates, it reclassified to Regulatory liabilities $653.3 million of removal costs recorded in accumulated depreciation that do not qualify as retirement obligations under SFAS No. 143. Accretion and depreciation expense in the first year of adoption are expected to be $8.1 million and $3.3 million, respectively.

The following table describes the changes to the Company’s asset retirement obligation liability for the nine months ended December 31, 2003:

(Millions of dollars)
Liability recognized at adoption on April 1, 2003	$	196.4
Liabilities incurred (a)		4.9
Liabilities settled (b)		(10.9	)
Revisions in cash flow (c)		(1.0	)
Accretion expense		6.1

Asset retirement obligation at December 31, 2003	$	195.5

(a)

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

(b)

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

(c)

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

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

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

Due to regulatory accounting treatment, the adoption of SFAS No. 143 would have had no impact on Income before cumulative effect of accounting change for the pro forma periods listed above.

Note 6 - Financing Arrangements

At December 31, 2003, the Company had $800.0 million of committed bank revolving credit agreements, including a $300.0 million facility, with a three-year term that became effective June 4, 2002, and a $500.0 million facility that became effective June 3, 2003, with a 364-day term plus a one-year term loan option. The interest on advances under these facilities is based on the London Interbank Offered Rate (LIBOR) plus a margin that varies based on the Company’s credit ratings. As of December 31, 2003, these facilities were fully available, and there were no borrowings outstanding.

Note 7 - Preferred Securities and Long-Term Debt

In May 2003, the FASB issued SFAS No. 150, Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity (“SFAS No. 150”). This statement affects the accounting for certain financial instruments that, under previous guidance, issuers could account for as equity. The new statement requires that those instruments be classified as liabilities. Most of this statement was effective for financial instruments entered into or modified after May 31, 2003, and otherwise was effective at the beginning of the first interim period beginning after June 30, 2003. The Company reclassified 600,000 shares, $100 stated value, of the $7.48 series Preferred stock subject to mandatory redemption to short-term and long-term liabilities on the Company’s Condensed Consolidated Balance Sheet, which were $3.8 million and $56.2 million, respectively, at December 31, 2003. Associated dividends declared for the six months ended December 31, 2003 of $2.2 million have been treated as interest expense.

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

During July and August 2003, the Company redeemed, prior to maturity, all of the 7.25% First Mortgage Bonds due August 1, 2013 totaling $40.0 million; all of the 7.37% First Mortgage Bonds due August 11, 2023 totaling $15.5 million; and all of the 7.4% First Mortgage Bonds due July 28, 2023 totaling $2.0 million. Upon redemption, $1.9 million of deferred charges were reclassified to a regulatory asset. These retirements were funded initially through short-term debt and subsequently by the long-term financing discussed below.

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

On September 8, 2003, the Company issued $200.0 million of the 4.30% First Mortgage Bonds due September 15, 2008 and $200.0 million of the 5.45% First Mortgage Bonds due September 15, 2013. These bonds contain covenants consistent with the Company’s other series of First Mortgage Bonds. The Company used the proceeds for the refinancing of short-term debt incurred to fund the redemptions discussed above.

Note 8 - Commitments and Contingencies

The Company follows SFAS No. 5, Accounting for Contingencies, to determine accounting and disclosure requirements for contingencies. The Company operates in a highly regulated environment. Governmental bodies such as the Federal Energy Regulatory Commission (the “FERC”), the SEC, the Internal Revenue Service (the “IRS”), the U. S. Department of Labor, the U. S. Environmental Protection Agency (the “EPA”) and others have authority over various aspects of the Company’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. Various specialists inside and outside of the Company perform evaluations of these contingencies.

Litigation

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

California and Enron Reserves

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

FERC Issues

California Refund Case - The Company 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. The Company previously established a reserve of $17.7 million for these refunds. The Company’s ultimate exposure to refunds is dependent upon any final order issued by the FERC in this proceeding.

Northwest Refund Case - On June 25, 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 25, 2000 and June 20, 2001. The FERC concluded that ordering refunds would not be an appropriate resolution of the matter. On August 25, 2003, the FERC granted rehearing of its June 25, 2003 order. On November 10, 2003, the FERC issued

its final order denying rehearing. Several market participants have filed petitions in the court of appeals for review of the FERC’s final order.

Federal Power Act Section 206 Case - On June 26, 2003, the FERC issued a final order denying the Company’s request for recovery of excessive prices charged under certain wholesale electricity purchases scheduled for delivery during summer 2002 and dismissing the Company’s complaints, under section 206 of the Federal Power Act, against five wholesale electricity suppliers. On July 3, 2003, the Company filed a petition in the Ninth Circuit Court of Appeals for review of certain aspects of this order. On July 28, 2003, the Company filed its request for rehearing of the FERC’s order, which was granted on August 27, 2003. The FERC issued its final order denying rehearing on November 10, 2003. On November 19, 2003, the Company filed a petition in the Ninth Circuit Court of Appeals for review of the FERC’s final order denying recovery. On November 20, 2003, Morgan Stanley Capital Group, Inc. filed a petition in the D.C. Circuit Court of Appeals for review of the FERC’s final order. On December 9, 2003, the case was transferred to the D. C. Circuit Court of Appeals for consolidation of the two appeals.

FERC Show-Cause Orders - In May 2002, the Company, 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. The Company 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. On June 25, 2003, the FERC ordered 60 companies (including the Company) to show cause why their behavior during the California energy crisis did not constitute manipulation of the wholesale electricity market, as defined in the California Independent System Operator and the California Power Exchange tariffs. In setting the cases for hearing, the FERC directed the administrative law judge to hear evidence and render findings and conclusions quantifying the extent of any unjust enrichment that resulted and to recommend monetary or other appropriate remedies. On August 29, 2003, the Company and the FERC staff reached a resolution on the show-cause order. Under the terms of the settlement agreement, the Company 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 the Company. The FERC must approve the settlement before it becomes binding on the parties.

The BPA Settlement

The Northwest Power Act provides access to the benefits of low-cost federal hydroelectricity to the residential and small-farm customers of the region’s investor-owned utilities through the Regional Exchange Program. The Bonneville Power Administration (“BPA”) administers the Regional Exchange Program in accordance with federal law. The Company passes these benefits through to its Oregon, Washington and Idaho residential and small-farm customers in the form of electricity bill credits. Pursuant to settlement of the Regional Exchange Program for the current rate period, the Company’s residential and small-farm customers are entitled to annual benefits of approximately $118.0 million for the period 2002 through 2006. Several publicly owned utilities, cooperatives and BPA direct-service industry customers have filed petitions with the Ninth Circuit Court of Appeals seeking review of BPA’s decision to settle the Regional Exchange Program with the Company and the region’s other investor-owned utilities. Certain of these parties have threatened suits in the U.S. courts to enjoin collection of certain benefits. The Company has been actively involved in negotiations to settle these outstanding lawsuits. Unfortunately, these efforts have been unsuccessful, and the Company expects that the dispute cannot be resolved through settlement. An adverse decision by the courts could reduce the level of benefits paid to the Company’s residential and small-farm customers. Since these benefits have no impact on the Company’s earnings, an adverse decision reducing the level of these benefits would not have an effect on the Company’s consolidated financial position or results of operations.

Hydroelectric Relicensing

The Company operates the majority of its hydroelectric generating portfolio under long-term licenses from the FERC. These licenses are granted by the FERC for periods of 30 to 50 years. Many of the Company’s long-term operating licenses have expired or will expire in the next few years. Hydroelectric facilities operating under expired licenses may operate under annual licenses granted by the FERC until new operating licenses are issued. Hydroelectric relicensing and the related environmental compliance requirements are subject to a degree of uncertainty. The Company expects that future costs relating to these matters may be significant and consist primarily of additional relicensing costs and capital expenditures. Electricity generation reductions may also result from additional environmental requirements. As of December 31, 2003, the Company had incurred approximately $105.7 million in costs for ongoing hydroelectric relicensing, which are included in assets on the Company’s Condensed

Consolidated Balance Sheet. The Company expects that these and future costs will be found to be prudent and recoverable in rates and, as such, will not have a material adverse impact on the Company’s consolidated results of operations.

In June 2003, the Company entered into a settlement agreement to remove the 6-megawatt (“MW”) Powerdale project rather than pursue a new license, based on an analysis of the costs and benefits of relicensing versus decommissioning. Removal of the Powerdale dam and associated project features, which is subject to FERC and other regulatory approvals, is projected to cost $6.3 million, with removal to commence in 2010.

In June 2003, the Company submitted a draft license application to interested parties for a 90-day review for the 151.0-MW Klamath hydroelectric project in southern Oregon and northern California. The Company also submitted a final license application to the FERC for the Prospect Nos. 1, 2 and 4 hydroelectric projects in Oregon, totaling 36.8-MW. The FERC is expected to complete its required analysis over the next two years.

On July 25, 2003, the Company received a new 50-year operating license for its 4.1-MW Big Fork hydroelectric project located on the Swan River in northwestern Montana. There were no challenges to this license, and it became effective upon issuance.

On November 18, 2003, the FERC issued a new 35-year operating license for the 185.5-MW North Umpqua hydroelectric project in Oregon. On December 22, 2003, the FERC issued a new 30-year operating license for the 84.5-MW Bear River hydroelectric project in Idaho. The Company and other parties are seeking clarification/rehearing on certain elements of the licenses, which appear to be inconsistent with their respective settlement agreements. In addition, organizations that were not parties to the North Umpqua settlement agreement have requested rehearing on other elements of that license advocating removal of one of the North Umpqua project’s dams. Both the Bear River and North Umpqua projects are operating under the new FERC licenses during the clarification/rehearing process. In addition to the projects’ capital and operations and maintenance expenses associated with the new licenses, the Company may be committed, over the lives of the two licenses, to fund a total of approximately $69.0 million for environmental mitigation and enhancement projects on behalf of third parties. These commitments are contingent upon final acceptance of the licenses by the Company.

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

Environmental Issues

The Company is subject to numerous environmental laws, including the federal Clean Air Act, as enforced by the EPA and various state agencies; the 1990 Clean Air Act Amendments; the Endangered Species Act of 1973, particularly as it relates to certain endangered species of fish; the Comprehensive Environmental Response, Compensation and Liability Act of 1980, relating to environmental cleanups; the Resource Conservation and Recovery Act of 1976; and the Clean Water Act, relating to water quality. These laws could impact the Company’s future operations. Contingencies identified at December 31, 2003 principally consist of Clean Air Act matters, which are the subject of discussions with the EPA and state regulatory authorities. In addition to these laws, the U. S. Congress is currently considering several proposed bills that could create enforceable limits on electricity plant emissions of sulfur dioxide, carbon dioxide, oxides of nitrogen and mercury. The EPA has proposed or intends to propose new regulations that could also impact emissions. These requirements may require additional control equipment to be installed by 2008. The Company expects that future costs relating to these matters may be significant and would consist primarily of capital expenditures. The Company further expects that these and future costs will be found to be prudent and recoverable in rates and, as such, will not have a material adverse impact on the Company’s consolidated results of operations. The Company is providing information about certain of its generating plants to the EPA in a cooperative effort to seek a mutual, comprehensive solution to air-quality issues as they relate to such plants generally. The Company is also discussing air-quality issues with state air-quality regulators.

Swift Power Canal

On April 21, 2002, a failure occurred in the Swift power canal on the Lewis River in the state of Washington. The Cowlitz County Public Utility District owns the power canal and associated 70-MW hydroelectric facility (“Swift No. 2”). The failure impacted, but did not damage, the Company-owned and -operated 240-MW Swift No. 1 hydroelectric facility (“Swift No. 1”), which is upstream of the Swift power canal. The overflow spillway was modified upstream of the Swift No. 2 failure to allow restricted operations of Swift No. 1. The Company continues to seek ways to mitigate any shaping limitations and to recover any business losses. It is currently estimated that Swift No. 2 will return to operations during the first half of calendar year 2005. Swift No. 2 reconstruction must be completed before unrestricted use of Swift No. 1 can resume. Swift No. 1 is estimated to return to full operations during the third quarter of calendar year 2005. The Company will be working cooperatively with Cowlitz Public Utility District to expedite reconstruction efforts. The full impact of the Swift power canal outage and plans for repair of the Swift No. 2 facility are currently under review. The Company is seeking reimbursement from Cowlitz County Public Utility District of the Company’s expenditures associated with the Swift No. 2 failure, including canal modifications and energy replacement costs. This event is not expected to have a significant impact on the Company’s consolidated financial position or results of operations.

Note 9 - Income Taxes

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

The Company recorded federal and state income tax expense of $132.3 million and $65.9 million, representing effective tax rates of 41.9% and 37.7%, for the nine months ended December 31, 2003 and 2002, respectively. The increase in the estimated effective tax rate for the nine months ended December 31, 2003 as compared to the nine months ended December 31, 2002 is primarily due to lower amounts of tax credits in the current period together with higher levels of pretax income as compared to the prior year period, which diluted the benefit of tax credits.

The Company 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, 2003, the Company reached an agreement in principle with the IRS on certain tax issues related to the Company’s 1994 through 1998 federal income tax returns. The agreement in principle results in a tax and interest liability of $13.1 million, for which a contingency tax reserve was previously provided.

During the nine months ended December 31, 2003, the Company reached an agreement in principle with the IRS on certain tax issues related to the Company’s 1999 and 2000 federal income tax returns and, as a result, released $3.8 million of previously provided tax contingency reserves. This was partially offset by an increase to the tax contingency reserve of $3.5 primarily to accrue interest on remaining tax contingencies provided for in prior periods. The resulting change in the tax contingency reserve during the nine months ended December 31, 2003 was a net release of $0.3 million.

The Company believes that final settlement and payment on settled issues and other unresolved issues related to the federal income tax returns through 2000 will not have a material adverse impact on its 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)	2003		2002		2003		2002


Net income	$	60.5	$	39.7	$	182.2	$	106.8
Other comprehensive income:
Unrealized gain (loss) on available-for-sale securities, net of taxes of $1.4 and $3.3/2003 and $0.9 and $(0.9)/2002		2.1		0.9		5.4		(1.1	)
Reclassification of SFAS No. 133 gain in earnings, net of taxes of $14.7/2002		—		—		—		24.0

Total comprehensive income	$	62.6	$	40.6	$	187.6	$	129.7

Note 11 - New Accounting Standards

In January 2003, the FASB issued FASB Interpretation No. 46, Consolidation of Variable-Interest Entities, an interpretation of Accounting Research Bulletin No. 51 (“FIN No. 46”), which requires existing unconsolidated variable-interest entities to be consolidated by their primary beneficiaries if the entities do not effectively disperse risks among parties involved. In October 2003, the FASB deferred the effective date of FIN No. 46, as it applied to variable-interest entities acquired before February 1, 2003 until the end of the first interim or annual period beginning after December 15, 2003. In December 2003, the FASB issued a revision of FIN No. 46 (“FIN No. 46R”) to clarify certain provisions of the standard. FIN No. 46R requires that FIN No. 46 be applied to those entities that are considered to be special-purpose entities, no later than the end of the first interim or annual period ending after December 15, 2003. The application of FIN No. 46 to special-purpose entities as of December 31, 2003 had no impact on the Company’s consolidated financial position or results of operations. FIN No. 46R is effective for all variable-interest entities no later than the end of the first interim or annual period ending after March 15, 2004. The Company is currently evaluating the impact of adopting FIN No. 46R on its consolidated financial position and results of operations.

In May 2003, the EITF issued EITF No. 00-21, Revenue Arrangements with Multiple Deliverables. This issue addresses certain aspects of the accounting by a vendor for arrangements under which it will perform multiple revenue-generating activities in different accounting periods. This issue is effective for revenue arrangements entered into in fiscal periods beginning after June 15, 2003. The adoption of this issue had no impact on the Company’s consolidated financial position or results of operations.

In May 2003, the EITF issued EITF No. 01-8, Determining Whether an Arrangement Contains a Lease (“EITF No. 01-8”). EITF No. 01-8 provides guidance for determining whether an arrangement contains a lease that is within the scope of SFAS No. 13, Accounting for Leases (“SFAS No. 13”). The evaluation of whether an arrangement contains a lease within the scope of SFAS No. 13 should be based on the substance of the arrangement. EITF No. 01-8 was effective for the Company on July 1, 2003. The adoption of this issue had no impact on the Company’s consolidated financial position or results of operations for the period ended December 31, 2003. However, future contracts or modifications to existing contracts may have a material impact on the Company’s consolidated financial position or results of operations.

In July 2003, the EITF issued EITF No. 03-11, Reporting Gains and Losses on Derivative Instruments that Are Subject to FASB Statement No. 133, Accounting for Derivative Instruments and Hedging Activities, and Not Held for Trading Purposes (“EITF No. 03-11”). This issue addresses whether realized gains and losses should be shown gross or net in the income statement for contracts that are not held for trading purposes but are derivatives subject to SFAS No. 133. EITF No. 03-11 is effective for all derivative instruments settled on or after January 1, 2004. Adoption of EITF No. 03-11 will have no impact on the Company’s consolidated net income.

In January 2004, the FASB released FASB Staff Position (“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”). The Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the “Medicare Act”) was signed into law in December 2003 and establishes a prescription drug benefit, as well as a federal subsidy to sponsors of retiree health care benefit plans that provide a prescription drug benefit that is at least actuarially equivalent to Medicare’s prescription drug coverage. Specific authoritative guidance on the accounting for the federal subsidy is pending, and that guidance, when issued, could require the sponsor to change previously reported information. Under FSP SFAS No. 106-1, a sponsor of a postretirement health care plan that provides a prescription drug benefit is permitted to defer accounting for the effects of the Medicare Act. The election to defer is a one-time election that cannot be changed, and the deferral continues to apply unless, after January 31, 2004 but prior to the issuance of additional authoritative guidance, a significant event occurs that ordinarily would call for remeasurement of a plan’s assets and obligations. The Company has until issuance of its Annual Report on Form 10-K for the year ended March 31, 2004 to elect the deferral option and is still evaluating the impacts of the Medicare Act. Accordingly, the accompanying Condensed Consolidated Financial Statements do not reflect the effects that may result from the Medicare Act.

In January 2004, the FASB issued SFAS No. 132R, Employers’ Disclosures about Pensions and Other Postretirement Benefits (“SFAS No. 132R”). The revised statement will change the required disclosures for pension and other postretirement benefit plan assets, obligations and net cost, but will not impact the Company’s consolidated financial position or results of operations. The interim-period disclosures are effective for interim periods beginning after December 15, 2003, and this statement is generally effective for fiscal years ending after December 15, 2003.

Note 12 - Subsequent Events

On January 15, 2004, the Company’s Board of Directors declared a dividend on common stock of approximately $0.13 per share, totaling $40.1 million, payable on February 26, 2004.

Note 13 - Independent Accountants’ Review Report

The Company’s Quarterly Reports on Form 10-Q are incorporated by reference into various filings under the Securities Act of 1933 (the “Act”). The Company’s independent accountants are not subject to the liability provisions of section 11 of the Act for their report on the unaudited Condensed Consolidated Financial Information, because such report is not a “report” or a “part” of a registration statement prepared or certified by independent accountants within the meaning of sections 7 and 11 of the Act.

REPORT OF INDEPENDENT ACCOUNTANTS

To the Board of Directors and Shareholders of PacifiCorp:

We have reviewed the accompanying Condensed Consolidated Balance Sheet of PacifiCorp and its subsidiaries as of December 31, 2003, and the related Condensed Consolidated Statements of Income and Retained Earnings for each of the three month and nine month periods ended December 31, 2003 and 2002 and the Condensed Consolidated Statements of Cash Flows for the nine month periods ended December 31, 2003 and 2002. These interim Condensed Consolidated Financial Statements are the responsibility of the Company’s management.

We conducted our review in accordance with standards established by the American Institute of Certified Public Accountants. 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 generally accepted auditing standards, 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 interim Condensed Consolidated 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 auditing standards generally accepted in the United States of America, the Consolidated Balance Sheet as of March 31, 2003, and the related Statements of Consolidated Income, Common Shareholders’ Equity and Cash Flows for the year then ended (not presented herein), and in our report dated May 7, 2003, 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, 2003, is fairly stated in all material respects in relation to the Consolidated Balance Sheet from which it has been derived.

As discussed in Note 3 to the Condensed Consolidated Financial Statements, the Company adopted Statement of Financial Accounting Standards (“SFAS”) No. 149, Amendment of Statement 133 on Derivative Instruments and Hedging Activities, as of July 1, 2003.

As discussed in Note 5 to the Condensed Consolidated Financial Statements, the Company adopted SFAS No. 143, Accounting for Asset Retirement Obligations, as of April 1, 2003.

As discussed in Note 7 to the Condensed Consolidated Financial Statements, the Company adopted SFAS No. 150, Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity, as of July 1, 2003.

PricewaterhouseCoopers LLP Portland, Oregon
February 5, 2004

ITEM 2.

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

OVERVIEW

CRITICAL ACCOUNTING POLICIES

The preparation of consolidated financial statements in conformity with accounting principles generally accepted in the United States of America requires Company management to make estimates and assumptions that affect results of operations and the reported amounts of assets and liabilities in the consolidated financial statements. Changes in these estimates and assumptions could have a material impact on the Company’s financial position and results of operations. Those policies that management considers critical are Regulation, Revenue Recognition, Contingencies, Asset Retirement Obligations and Pensions and are described in the Company’s Annual Report on Form 10-K for the year ended March 31, 2003 under ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.

FORWARD-LOOKING STATEMENTS

The information in the tables and text in this document includes certain forward-looking statements that involve a number of risks and uncertainties under the safe-harbor provisions of the Private Securities Litigation Reform Act of 1995 that may influence the financial performance and earnings of the Company. 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 that involve risks and uncertainties. There can be no assurance the results predicted will be realized. Actual results may vary from those represented by the forecasts, and those variations may be material. The following are among the factors that could cause actual results to differ materially from the forward-looking statements:

•

changes in prices and availability of wholesale electricity, natural gas and fuel costs and other changes in operating costs, which could affect the Company’s cost recovery;

•

changing conditions in wholesale electricity markets, such as general credit constraints and thin trading volumes, that could make it difficult for the Company to enter into purchase and sale agreements;

•

the actions of securities rating agencies, including the determination of whether or when to make changes in the Company’s credit ratings and the impact of current or lowered ratings and other financial market conditions on the ability of the Company to obtain needed financing on reasonable terms or at all;

•

nonperformance of counterparties;

•

the effects of increased competition in energy-related businesses, including new market entrants and the effects of technologies that may be developed in the future;

•

attempts by municipalities within the Company’s service territory to form public power entities and/or acquire the Company’s facilities;

•

hydroelectric conditions and natural gas and coal production levels, which could have a significant impact on electric capacity and cost and on the Company’s ability to generate electricity;

•

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

•

the impact of the possible formation of a Regional Transmission Organization, or similar organization, and the impact of the implementation of the Standard Market Design proposed by the Federal Energy Regulatory Commission (the “FERC”);

•

the impact of enhanced physical and information security requirements imposed through legislation or regulation;

•

the outcome of pending Internal Revenue Service (the “IRS”) tax audits and settlement conferences;

•

the impact of regional, national and international economic and political conditions, including acts of terrorism, war or similar events;

•

work-force factors, including strikes, work stoppages, availability of qualified employees or loss of key executives;

•

the ability to obtain adequate insurance coverage and the cost of such insurance;

•

changes in, and compliance with, environmental and endangered-species laws, regulations, decisions and policies;

•

industrial, commercial and residential growth and demographic patterns in the Company’s service territories;

•

competition and supply in electricity and natural gas markets;

•

unscheduled generation outages;

•

disruption or failures of transmission or distribution facilities;

•

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

•

the outcome of threatened or pending litigation;

•

changes in tax rates and/or policies;

•

changes in discount rates, and other actuarial assumptions, and the return on assets associated with the Company’s pension plan, which could impact future funding obligations, costs and pension plan liabilities;

•

increasing health care costs associated with employee health insurance premiums and the obligation to provide postretirement health care benefits;

•

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

•

new accounting pronouncements;

•

the failure of critical information technology systems;

•

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

•

the cost, feasibility and eventual outcome of hydroelectric facility relicensing proceedings.

Any forward-looking statements issued by the Company should be considered in light of these factors. The Company does not plan to update or revise any forward-looking statements to reflect actual results, changes in assumptions or changes in other factors affecting such forward-looking statements or if the Company later becomes aware that these assumptions are not likely to be achieved.

RESULTS OF OPERATIONS

The Company is a regulated electricity company and serves approximately 1.6 million retail customers in service territories aggregating about 136,000 square miles in portions of the states of Utah, Oregon, Wyoming, Washington, Idaho and California. The Company owns, or has interests in, 17 thermal generating plants with an aggregate nameplate rating of 7,309.8 megawatt (“MW”) and plant net capability of 6,776.9 MW, 51 hydroelectric generating plants with an aggregate nameplate rating of 1,059.5 MW and plant net capability of 1,108.1 MW, and one wind generating plant with an aggregate nameplate rating and plant net capability of 32.6 MW. The Company delivers electricity through approximately 58,000 miles of distribution lines and 15,000 miles of transmission lines.

The Company’s earnings on common stock for the three months ended December 31, 2003 were $60.0 million, as compared to $37.9 million for the three months ended December 31, 2002. Retail sales volumes were 2.1% higher in the three months ended December 31, 2003 than in the comparable prior year period, driven by increases in usage per customer, including the impact of colder temperatures in winter 2003, as compared to winter 2002, and increases in total customer numbers. Output from the Company’s thermal plants increased by 172,000 megawatt-hours (“MWh”), or 1.5%, as compared to the prior year period, as a result of improved operating performance. Output from Company-owned hydroelectric facilities increased by 261,800 MWh, or 43.9%, as a result of unusually dry

conditions in the prior year period. Although overall hydroelectric conditions have been relatively similar during the comparable three month periods, at 65.0% of normal conditions, the increase in snowpack levels from 67.0% of normal last year to 109.0% of normal this year has led to increased generation from lowering reservoir levels in preparation for the future snowpack melt. If average or better rainfall continues through the late winter period, the Company expects improved hydroelectric conditions over the remainder of this fiscal year.

The Company’s earnings on common stock for the nine months ended December 31, 2003 were $179.4 million, as compared to $101.3 million for the nine months ended December 31, 2002. Retail sales volumes were 3.9% higher in the nine months ended December 31, 2003 than in the comparable prior year period, driven by, increases in usage per customer, including the impact of higher temperatures in summer 2003, as compared to summer 2002, colder temperatures in winter 2003, as compared to winter 2002 and increases in total customer numbers. Output from the Company’s thermal plants increased by 1,258,000MWh, or 3.6%, as compared to the prior year period, as a result of improved operating performance and increases from new plant additions. Output from Company-owned hydroelectric facilities increased by 80,400 MWh, or 3.5%, as a result of unusually dry conditions in the prior year period.

For the nine months ended December 31, 2003, electricity market prices in the western U. S. where the Company operates, were higher than in the comparable prior year period, driven by a combination of higher natural gas prices in the western U. S. and below-normal regional hydroelectric generation. As a result of risk management actions previously taken, including use of physical resources and hedging activities, the Company maintained its balanced supply/demand energy position through the summer peak period and believes that its energy position is balanced for the remainder of fiscal year 2004.

In late December 2003 and early January 2004, the Company’s distribution network was impacted by severe storms in northern Utah and parts of Oregon and California. Increased costs have been incurred as a result of the storm damage to the network. It is estimated that the Company’s pre-tax earnings for the year ended March 31, 2004 will be reduced in the range of $11.0 million to $15.0 million due to storm-related costs.

Because the Utah storms left a large number of customers without electricity for an extended period of time, the Company began an internal review, and upon completion, will report findings to the Utah regulators and customers. In addition, in January 2004, the Company agreed to make voluntary, goodwill payments to Utah customers who were without electricity for more than 48 hours. It is estimated that the aggregate goodwill payments will be in the range of $2.0 million to $3.0 million.

As discussed in PART II - ITEM 5. OTHER INFORMATION, in Oregon, the Company received an annual rate increase of $8.5 million effective September 1, 2003, which represents a 1.1% average price increase. In California, the Company received an annual rate increase of $2.8 million effective December 1, 2003. Combining this order with the interim increase authorized in June 2002 results in an overall price increase of $7.6 million annually, which represents a 13.6% average price increase. In Utah, the Company received an annual rate increase of $65.0 million, effective April 1, 2004, which represents a 7.0% average price increase.

In addition, the Company has general rate cases pending in Wyoming and Washington. These requests total approximately $61.6 million of proposed annual price increases. These increases are sought to recover system investments and rising costs, including insurance, pension, health care, power, infrastructure and security costs. The Wyoming case should be finalized by March 2004, and the Washington case should be finalized by November 2004. As with any general rate case, the outcome of these requests is uncertain.

COMPARISON OF THE THREE MONTHS ENDED DECEMBER 31, 2003 and 2002

REVENUES

(Millions of dollars)	Three Months Ended December 31,				Change			% Change

	2003		2002		Favorable/(Unfavorable)

Residential	$	255.1	$	236.7	$	18.4		7.8	%
Commercial		193.3		196.4		(3.1	)	(1.6	)
Industrial		171.3		165.2		6.1		3.7
Other retail revenues		8.0		7.3		0.7		9.6

Retail sales		627.7		605.6		22.1		3.6
Wholesale sales		228.2		215.1		13.1		6.1
Other revenues		17.7		32.5		(14.8	)	(45.5	)

Total revenues	$	873.6	$	853.2	$	20.4		2.4

Energy sales (millions of kWh)
Residential		3,740		3,489		251		7.2
Commercial		3,520		3,586		(66	)	(1.8	)
Industrial		4,629		4,592		37		0.8
Other		157		134		23		17.2

Retail sales		12,046		11,801		245		2.1
Wholesale sales		5,733		6,293		(560	)	(8.9	)

Total		17,779		18,094		(315	)	(1.7	)


Average residential usage (kWh)		2,808		2,668		140		5.2
Total customers - end of period (in thousands)		1,562		1,534		28		1.8

Residential revenues for the three months ended December 31, 2003 increased $18.4 million, or 7.8%, from the three months ended December 31, 2002 primarily due to increases of $12.5 million from higher average estimated customer usage, including the impact of colder winter weather as compared to 2002, $4.4 million relating to growth in the average number of residential customers and $1.4 million resulting from a change in price mix, resulting from different customer tariffs in the various states that the Company serves.

Commercial revenues for the three months ended December 31, 2003 decreased $3.1 million, or 1.6%, from the three months ended December 31, 2002 primarily due to decreases of $8.4 million from lower average estimated customer usage. This decrease was partially offset by growth in the average number of commercial customers, which increased revenues by $4.3 million and a change in price mix, resulting from different customer tariffs in the various states that the Company serves, which increased revenue by $1.9 million.

Industrial revenues for the three months ended December 31, 2003 increased $6.1 million, or 3.7%, from the three months ended December 31, 2002 due to a $3.2 million increase from a change in price mix, resulting from different customer tariffs in the various states that the Company serves, and a $2.8 million increase from higher average estimated customer usage.

Wholesale sales for the three months ended December 31, 2003 increased $13.1 million, or 6.1%, from the three months ended December 31, 2002 primarily due to an increase of 15.7% on prices realized as compared to those in the three months ended December 31, 2002, the impact of which was $33.9 million. The primary factor contributing to higher market electricity prices in the western U. S. during the three months ended December 31, 2003 was higher natural gas prices in the western U. S. These increases were partially offset by a reduction in volumes of 8.9%, the impact of which was $20.8 million. The majority of this reduction was in long-term sales, which were 16.0% lower than in the prior year period due to expiring contracts. Short-term and spot market sales were 5.6% lower than in the prior year period.

Other revenues for the three months ended December 31, 2003 decreased $14.8 million, or 45.5%, from the three months ended December 31, 2002 primarily due to decreases of $8.5 million in wheeling revenues, $2.7 million from the joint use of poles and wires, and the effect of a $2.2 million reversal, in the prior year period, of a previously established reserve.

OPERATING EXPENSES

Purchased electricity expense for the three months ended December 31, 2003 decreased $9.1 million, or 3.5%, from the three months ended December 31, 2002. Lower volumes incurred for short-term and spot market purchases, due to a combination of increased thermal and hydroelectric generation from Company-owned facilities, reduced volumes by 17.9%, with a resulting reduction in Purchased electricity expense of $21.7 million. The impact in the prior year period of the reversal of a net power cost deferral and changes in exchange contract estimates resulted in decreases in Purchased electricity expense of $20.5 million. Partially offsetting these reductions was a 16.5% increase in the average purchase price due to higher market prices resulting from the same factors mentioned above for wholesale sales, the effect of which was an increase in Purchased electricity expense of $21.4 million. Long-term purchase volumes increased Purchased electricity expense by $3.7 million and wheeling expense increased $6.9 million as a result of a change in a contract estimate in the prior year. Costs relating to unrealized losses and gains on weather derivatives and other costs, which include demand-side management costs and fees, increased $1.1 million.

Fuel expense for the three months ended December 31, 2003 decreased $5.4 million, or 4.5%, from the three months ended December 31, 2002. Decreases in natural gas generation volumes resulted in a decrease of $7.7 million, which were partially offset by a $5.2 million increase in coal generation volumes. Realized coal prices decreased Fuel expense by $2.4 million and a decrease in realized natural gas prices paid resulted in a benefit of $0.5 million. The reduction in realized natural gas prices was due to previous hedging activities, whereby the Company was not required to incur the current higher natural gas market prices.

Operations and maintenance expense for the three months ended December 31, 2003 decreased $5.6 million, or 2.5%, from the three months ended December 31, 2002 primarily due to a $3.9 million decrease in bad-debt expense, a $2.9 million decrease in amortization of regulatory assets as a result of lower average balances and a $2.4 million decrease in insurance costs. These decreases were partially offset by a $3.4 million increase in pension costs due to a lower expectation for future asset returns, the continued phasing-in of the negative asset returns from 2000 through 2002, and a lower discount rate. Employee-related costs increased by $5.2 million during the three months ended December 31, 2003 as compared to the prior year period primarily due to an increase in headcount. However, this increase was offset by a $6.7 million decrease due to the level and timing of capitalized costs.

Depreciation and amortization expense for the three months ended December 31, 2003 decreased $1.5 million, or 1.4%, from the three months ended December 31, 2002 primarily due to a $5.8 million decrease as a result of new depreciation rates approved by regulators, effective April 1, 2003, as discussed in PART I - ITEM 1. FINANCIAL STATEMENTS - Note 2 - Accounting for the Effects of Regulation, which was partially offset by the effect on depreciation of $2.4 million resulting from increased plant in-service and $2.1 million resulting from increased capitalized software costs.

Taxes, other than income taxes, for the three months ended December 31, 2003 increased $3.9 million, or 18.4%, from the three months ended December 31, 2002 primarily due to a $2.2 million increase in property taxes resulting from higher assessed values and a $1.4 million increase in franchise taxes due to higher retail revenues.

The net Unrealized gain on derivative contracts for the three months ended December 31, 2003 was $2.4 million compared to a loss of $0.4 million for the three months ended December 31, 2002 primarily due to favorable prices on oil and gasoline derivatives as compared to the prior year.

INTEREST EXPENSE AND OTHER (INCOME) EXPENSE

Interest expense increased $2.8 million, or 4.4%, primarily due to higher average debt balances and dividends on Preferred stock subject to mandatory redemption of $1.1 million, which were included in interest expense for the three months ended December 31, 2003 in accordance with SFAS 150, Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity (“SFAS No. 150”).

Interest income decreased $1.4 million, or 30.4%, primarily due to a decrease in interest on regulatory assets.

Interest capitalized increased $1.2 million, or 31.6%, due to higher qualifying construction work-in-progress balances and higher capitalization rates in the current period.

Minority interest and other (income) expense was $4.7 million of income for the three months ended December 31, 2003, as compared to $1.5 million of expense for the three months ended December 31, 2002, primarily due to a $7.1 million decrease in distributions on Preferred securities, which were redeemed during August 2003. Other income decreased $0.9 million primarily due to a $2.0 million unfavorable change in the realized gains/losses on the sales of utility properties, which was partially offset by a $1.2 million favorable change in the realized gain on the cash surrender value of life insurance policies.

INCOME TAX EXPENSE

Income tax expense increased $22.9 million primarily due to the higher pretax income in the current period. The estimated effective tax rate for the three months ended December 31, 2003 was 44.0%, as compared to 38.3% for the three months ended December 31, 2002. The increase in the estimated effective tax rate is primarily due to lower amounts of tax credits in the current period together with higher levels of pretax income as compared to the prior year period, which diluted the benefit of tax credits.

COMPARISON OF THE NINE MONTHS ENDED DECEMBER 31, 2003 and 2002

REVENUES

(Millions of dollars)	Nine Months Ended December 31,				Change			% Change

	2003		2002		Favorable/(Unfavorable)

Residential	$	723.8	$	667.7	$	56.1		8.4	%
Commercial		607.1		582.9		24.2		4.2
Industrial		557.3		531.5		25.8		4.9
Other retail revenues		25.5		23.9		1.6		6.7

Retail sales		1,913.7		1,806.0		107.7		6.0
Wholesale sales		728.0		768.6		(40.6	)	(5.3	)
Other revenues		84.7		108.1		(23.4	)	(21.6	)

Total revenues	$	2,726.4	$	2,682.7	$	43.7		1.6

Energy sales (millions of kWh)
Residential		10,443		9,620		823		8.6
Commercial		11,023		10,695		328		3.1
Industrial		14,515		14,310		205		1.4
Other		498		486		12		2.5

Retail sales		36,479		35,111		1,368		3.9
Wholesale sales		17,994		23,790		(5,796	)	(24.4	)

Total		54,473		58,901		(4,428	)	(7.5	)

Average residential usage (kWh)		7,882		7,391		491		6.6
Total customers - end of period (in thousands)		1,562		1,534		28		1.8

Residential revenues for the nine months ended December 31, 2003 increased $56.1 million, or 8.4%, from the nine months ended December 31, 2002 primarily as a result of increases of $45.9 million from higher average estimated customer usage, including a change in the calculation of unbilled revenues and the impact of warmer summer and colder winter weather, both as compared to the prior year, and $12.2 million relating to growth in the average number of residential customers. These increases were partially offset by a decrease of $2.0 million due to a change in price mix, resulting from different customer tariffs in the various states that the Company serves.

Commercial revenues for the nine months ended December 31, 2003 increased $24.2 million, or 4.2%, from the nine months ended December 31, 2002. Growth in the average number of commercial customers increased revenues by $12.4 million, higher average estimated customer usage, including a change in the calculation of unbilled revenues,

increased revenues by $7.7 million and a change in price mix, resulting from different customer tariffs in the various states that the Company serves, increased revenues by $4.2 million.

Industrial revenues for the nine months ended December 31, 2003 increased $25.8 million, or 4.9%, from the nine months ended December 31, 2002 primarily due to a $27.8 million increase from a change in price mix, resulting from different customer tariffs in the various states that the Company serves, partially offset by a $2.2 million decrease due to lower average estimated customer usage, including a change in the calculation of unbilled revenues.

Wholesale sales for the nine months ended December 31, 2003 decreased $40.6 million, or 5.3%, from the nine months ended December 31, 2002 primarily due to a reduction in volumes of 24.4%, the impact of which was $137.9 million. The majority of this reduction was in short-term and spot market sales, which were 30.5% lower than in the prior year period. A parallel volume reduction is reflected in the Company’s Purchased electricity expense. These decreases were partially offset by an increase of 25.0% on prices realized as compared to those in the nine months ended December 31, 2002, the impact of which was $97.3 million. The primary factors contributing to higher market electricity prices in the western U. S. during the nine months ended December 31, 2003 were an increase in the market price of natural gas and a reduction in regional hydroelectric generation.

Other revenues for the nine months ended December 31, 2003 decreased $23.4 million, or 21.6%, from the nine months ended December 31, 2002 primarily due to a $20.7 million release of reserves on a power sales contract following settlement of a dispute with respect to the contract in September 2002, a decrease in wheeling revenues of $10.6 million, a $4.6 million decrease in revenue from the conclusion of the amortization of a regulatory liability and $2.0 million from the reduction of the Oregon merger credit liability. These decreases were partially offset by a $2.2 million increase from the joint use of poles and wires; and $2.2 million from the reversal, in the prior period, of a previously established reserve.

OPERATING EXPENSES

Purchased electricity expense for the nine months ended December 31, 2003 decreased $92.6 million, or 9.9%, from the nine months ended December 31, 2002. Lower volumes incurred for short-term and spot market purchases, due to a combination of increased thermal generation from Company-owned facilities and a reduction in wholesale activity, reduced volumes by 36.4%, with a resulting reduction in Purchased electricity expense of $300.5 million. Partially offsetting these reductions was a 21.3% increase in the average purchase price due to higher market prices resulting from the same factors mentioned above for wholesale sales, the effect of which was an increase in Purchased electricity expense of $196.2 million. Long-term purchase volumes increased Purchased electricity expense by $26.8 million and other costs, which include demand-side management costs and fees, increased $2.9 million. Wheeling expense decreased $10.1 million as a result of lower volumes. Costs relating to unrealized losses on weather derivatives decreased Purchased electricity expense by $5.1 million as compared to the nine months ended December 31, 2002. The reversal of a net power cost deferral in the prior period and exchange contract adjustments resulted in decreases in purchased electricity expense of $2.8 million.

Fuel expense for the nine months ended December 31, 2003 increased $13.0 million, or 3.7%, from the nine months ended December 31, 2002. Increased thermal generation volumes of 3.6% resulted in increased costs of $13.4 million due to increases in coal generation volumes and $0.2 million due to increases in natural gas generation volumes, partially due to the impact from the Company’s Gadsby peaking plant and the leased West Valley plant, which came on-line during the prior year period. Realized coal prices decreased Fuel expense by $4.0 million and a 15.1% decrease in realized natural gas prices paid resulted in a benefit of $6.0 million. The reduction in realized natural gas prices was due to previous hedging activities, whereby the Company was not required to incur the current higher natural gas market prices. The remaining cost increase of $9.5 million was attributable to the net impact of a regulatory deferral for the Trail Mountain coal mine that reduced fuel costs in the nine months ended December 31, 2002.

Operations and maintenance expense for the nine months ended December 31, 2003 increased $1.1 million, or 0.2%, from the nine months ended December 31, 2002. Pension costs increased $11.7 million due to a lower expectation for future asset returns, the continued phasing-in of the negative asset returns from 2000 through 2002, and a lower discount rate. Rent expense increased by $4.0 million due to rent on the West Valley plant, which began service during the prior year period. Employee-related costs increased by $18.4 million during the nine months ended December 31, 2003 as compared to the prior year period primarily due to an increase in headcount. However, this increase was offset by a $21.1 decrease due to the level and timing of capitalized costs. Increases in the period were partially offset by lower bad-debt expense of $10.1 million primarily due to the establishment of a $7.0 million

reserve for California exposures in the prior year period, and a $9.7 million decrease in amortization of regulatory assets due to lower average asset balances.

Depreciation and amortization expense for the nine months ended December 31, 2003 decreased $6.2 million, or 1.9%, from the nine months ended December 31, 2002 primarily due to a $17.6 million decrease as a result of new depreciation rates approved by regulators, effective April 1, 2003, as discussed in PART I - ITEM 1. FINANCIAL STATEMENTS – Note 2 – Accounting for the Effects of Regulation, which was partially offset by the effect on depreciation of $7.2 million resulting from increased plant in-service and $4.7 million resulting from increased capitalized software costs.

Taxes, other than income taxes, for the nine months ended December 31, 2003 increased $3.7 million, or 5.3%, from the nine months ended December 31, 2002 primarily due to a $2.7 million increase in franchise taxes due to higher retail revenues and the reversal of a prior year reserve. In addition, property taxes increased $0.6 million.

The net Unrealized loss on derivative contracts for the nine months ended December 31, 2003 was $0.8 million, as compared to a gain of $2.7 million for the nine months ended December 31, 2002 primarily due to losses from additional contracts included as derivatives as required by the implementation of SFAS No. 149 in the nine months ended December 31, 2003.

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

INTEREST EXPENSE AND OTHER (INCOME) EXPENSE

Interest expense decreased $18.2 million, or 8.7%, primarily due to a decrease in interest on regulatory liabilities and lower average debt balances. In accordance with SFAS No. 150, dividends on Preferred stock subject to mandatory redemption of $2.2 million were included in Interest expense for the six months ended December 31, 2003.

Interest income decreased $2.8 million, or 20.0%, primarily due to the recognition of $1.1 million of interest income on an electricity sales contract settlement in September 2002.

Interest capitalized increased $3.4 million, or 24.8%, due to higher qualifying construction work-in-progress balances and higher capitalization rates in the current period.

Minority interest and other (income) expense decreased $14.0 million, or 84.3%, for the nine months ended December 31, 2003, partially due to a $9.5 million decrease in distributions on Preferred securities, which were redeemed during August 2003. Other income increased due to a $3.8 million favorable change in the realized gains on the increased cash surrender value of life insurance policies and the reversal in the nine months ended December 31, 2002 of a previously recorded gain of $3.4 million as a result of a regulatory order. These increases were partially offset by a $2.8 million unfavorable change in the realized gains/losses on the sales of utility properties.

INCOME TAX EXPENSE

Income tax expense increased $66.4 million principally due to the higher pretax income in the current period. The estimated effective tax rate for the nine months ended December 31, 2003 was 41.9%, as compared to 37.7% for the nine months ended December 31, 2002. The increase in the estimated effective tax rate is primarily due to lower amounts of tax credits in the current period together with higher levels of pretax income as compared to the prior year period, which diluted the benefit of tax credits.

CUMULATIVE EFFECT OF ACCOUNTING CHANGE

The Company 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. The Company recorded a $1.9 million after-tax loss from the implementation of revised Issue C15 and Issue C16 guidance from the Derivatives Implementation Group during the nine months ended December 31, 2002.

LIQUIDITY AND CAPITAL RESOURCES

OPERATING ACTIVITIES

Net cash provided by operating activities was $466.2 million for the nine months ended December 31, 2003, as compared to $311.9 million for the nine months ended December 31, 2002 due primarily to an increase in Net income, decrease in tax payments related to prior period IRS audits, reduced fuel inventory and the timing of collections and payments. Net cash provided by operating activities is impacted by seasonal movements in working capital and whether or not operating costs are recovered in rates and by the timing of that recovery.

INVESTING ACTIVITIES

Capital spending totaled $484.8 million for the nine months ended December 31, 2003, as compared to $391.1 million for the nine months ended December 31, 2002. The increase was primarily due to expenditures for distribution network growth and system upgrades, plant refurbishments and hydroelectric relicensing. The Company currently estimates capital expenditures to be $708.8 million for the year ending March 31, 2004. These expenditures are contingent upon operational constraints and regulatory approvals.

FINANCING ACTIVITIES

The Company’s short-term debt has increased by $199.9 million during the nine months ended December 31, 2003 due primarily to changes in working capital, maturing long-term debt, increased capital expenditures and the resumption of paying dividends on common shares.

The Company’s short-term borrowings and certain other financing arrangements are supported by $800.0 million of revolving credit agreements, with one facility for $300.0 million, with a three-year term that became effective June 4, 2002 and the other facility for $500.0 million, with a 364-day term plus a one-year term loan option that became effective June 3, 2003. The interest on advances under these facilities is based on the London Interbank Offered Rate (LIBOR) plus a margin that varies based on the Company’s credit ratings. At December 31, 2003, these facilities were fully available and there were no borrowings outstanding. In addition to these committed credit facilities, the Company had $71.6 million in money market accounts included in Cash and cash equivalents at December 31, 2003 available to meet its liquidity needs.

During July and August 2003, the Company redeemed, prior to maturity, First Mortgage Bonds totaling $57.5 million and Preferred Securities totaling $352.0 million. These retirements were funded initially with short-term debt. On September 8, 2003, the Company issued $200.0 million of its 4.30% First Mortgage Bonds due September 15, 2008 and $200.0 million of its 5.45% First Mortgage Bonds due September 15, 2013.

The Company redeemed $7.5 million of Preferred stock subject to mandatory redemption during each of the nine-month periods ended December 31, 2003 and 2002.

The Company declared and paid dividends of $120.4 million on common stock, and paid dividends of $4.0 million on Preferred stock, during the nine months ended December 31, 2003. On November 20, 2003, the Company declared dividends of $0.5 million on Preferred stock and $1.1 million on Preferred stock subject to mandatory redemption, which are payable on February 15, 2004. The dividends declared on Preferred stock subject to mandatory redemption were recorded as interest expense. On January 15, 2004, the Company’s Board of Directors declared a dividend on common stock of approximately $0.13 per share, totaling $40.1 million, payable on February 26, 2004.

Management expects existing funds and cash generated from operations, together with existing credit facilities, to be sufficient to fund liquidity requirements for the next 12 months. However, many participants in the electric utility industry have experienced a period of negative news and ratings downgrades. While the Company to date has been able to fund itself and expects to be able to continue to do so, further negative events experienced by the industry may make it more difficult and expensive for the Company to obtain necessary financing or replace financing agreements at their maturity.

CAPITALIZATION

At December 31, 2003, the Company had $224.9 million of Notes payable and commercial paper outstanding at a weighted average interest rate of 1.2%. These borrowings and other financing arrangements are supported by revolving credit agreements and cash on hand as described above. The following table summarizes the Company’s capitalization.

(Millions of dollars, except percentages)	December 31, 2003				March 31, 2003

Short-term debt and long-term debt currently maturing	$	489.6	6.6	%	$	161.7	2.3	%
Long-term debt		3,527.1	47.8			3,417.6	47.3
Preferred securities of trust		—	—			341.8	4.7
Preferred stock		101.3	1.4			108.0	1.5
Common equity		3,258.8	44.2			3,194.4	44.2

Total capitalization	$	7,376.8	100.0	%	$	7,223.5	100.0	%

As of December 31, 2003, the Company was in compliance with all financial covenants contained in its credit facilities and other financing arrangements and was not subject to any restrictions that would limit its ability to borrow the full amount available under its existing facilities.

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

CAPITAL EXPENDITURES

The following table shows the Company’s estimated capital expenditures for the years ending March 31, 2004 through 2006. The Company’s capital expenditure program has been revised from that shown in the Company’s Annual Report on Form 10-K for the year ended March 31, 2003 and the estimates below reflect the outcome of the summer 2005 resource category component of the first of three Requests for Proposals to support the Company’s Integrated Resource Plan. Subject to regulatory approvals and other consents, this will result in the construction of the Currant Creek project, a new 525-MW natural-gas-fired plant located in Juab County, approximately 75 miles south of Salt Lake City, Utah, at a cost of approximately $350.0 million expected to be incurred over three years to 2006.

		Estimated Capital Expenditures

		Years Ending March 31,

(Millions of dollars)		2004		2005		2006

Distribution and transmission	$	336.0	$	353.6	$	378.2
Generation and mining		273.4		483.4		472.8
Other		99.4		79.5		106.7

Total	$	708.8	$	916.5	$	957.7

In addition to the new generating plant mentioned above, estimated future capital expenditures include upgrades to distribution and transmission lines and existing generation plants, connections for new customers, facilities to accommodate load growth, coal mine investments, air-quality and environmental expenditures, hydroelectric relicensing costs and information technology systems. The Company expects that these and future costs will be deemed prudent and recoverable in future rates. All of these expenditures are subject to continuing review and revision by the Company, and actual costs could vary from estimates due to various factors, such as changes in business conditions, revised load-growth estimates, future legislative and regulatory developments and increasing costs of labor, equipment and materials.

The estimates of capital expenditures for the years ending March 31, 2004 through 2006 exclude the potential impact on generation and transmission capacity of future decisions arising from further stages of the Request for Proposals process to support the Integrated Resource Plan. Additional expenditures may be significant but are likely to be spread over a number of years, and cannot be accurately estimated, or included in the table, at this time. Based on future decisions arising from the Request for Proposal process, the capital expenditure program table may be updated in future quarters.

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

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

CONTRACTUAL OBLIGATIONS

The Company’s future contractual obligations have not changed materially from the amounts disclosed in the Company’s Annual Report on Form 10-K for the year ended March 31, 2003, with the following exceptions:

•

The Company’s net commercial paper obligations have increased $199.9 million during the nine-month period ended December 31, 2003 to fund long-term debt maturities and provide for other cash needs of the Company.

•

During July and August 2003, the Company redeemed, prior to maturity, First Mortgage Bonds totaling $57.5 million and Preferred Securities totaling $352.0 million.

•

On September 8, 2003, the Company issued $200.0 million of the 4.30% First Mortgage Bonds due September 15, 2008 and $200.0 million of the 5.45% First Mortgage Bonds due September 15, 2013.

•

The Company redeemed $7.5 million of Preferred stock subject to mandatory redemption during the nine-month period ended December 31, 2003.

•

Depending on the outcome of the rehearings for the North Umpqua and Bear River hydroelectric licenses, the Company may be committed to fund a total of approximately $69.0 million over the lives of the licenses for environmental mitigation and enhancement projects on behalf of third parties. The rehearings are expected to occur by the end of calendar year 2004.

•

In December 2003, the Company obtained regulatory approval of an affiliated-interest agreement that will result in payments to Scottish Power UK plc. These charges to the Company, at cost, are estimated to be in the range of $20.0 million to $25.0 million annually on a net basis and are expected to commence in the fourth quarter of fiscal year 2004. The Company will request regulatory recovery of these amounts, but the outcome is uncertain.

CREDIT RATINGS

The Company’s credit ratings at December 31, 2003 were as follows:

	Moody’s	S & P

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

Ratings outlook	Negative	Negative

The Company’s credit ratings are unchanged from March 31, 2003. These 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 the Company’s credit ratings, see ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS in the Company’s 2003 Annual Report on Form 10-K.

ITEM 3.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

BUSINESS RISK

The Company’s business risks relating to Operating, Regulatory, Insurance and Pension continue to be as reported in the Company’s 2003 Annual Report on Form 10-K under ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK. The Company is further subject to the risks that have been or may in the future be imposed on the market from the FERC proceedings as mentioned under PART II - ITEM 5. OTHER INFORMATION – FERC ISSUES below.

Political Risk

The Company’s business operations are subject to a multitude of federal and state laws. The U.S. Congress is considering significant energy legislation that would make changes in federal law affecting the Company. This energy legislation has been stalled short of a final vote by the U.S. Senate. If the comprehensive energy bill is enacted in its current form, the law will include direction for the regulation of, as well as financial incentives to invest in, electric transmission. The law would make changes to improve the hydroelectric relicensing process and would extend and expand eligibility for the renewable-energy production tax credit. These and other measures in the bill would likely benefit the Company’s efforts to develop, acquire and maintain a low-cost generation portfolio. The legislation would also repeal the Public Utility Holding Company Act (the “PUHCA”). At present, the Company is unable to predict how the repeal of the PUHCA would affect the Company, which is a public utility and a subsidiary of a registered holding company, Scottish Power plc. The FERC may adopt new regulations if the PUHCA is repealed. Changes to the Clean Air Act, contemplated by the pending Clear Skies Act, may affect control requirements for several emissions from fossil-fueled generation plants. No action was taken on that legislation in calendar year 2003 and its enactment is not considered likely in calendar year 2004. As the Clear Skies legislation has not progressed in the U.S. Congress, the Environmental Protection Agency (the “EPA”) is considering new regulations governing power plant emissions. The Company is monitoring the EPA’s activities and will evaluate the effects of the proposed regulations, as they are made available.

The laws of the states in which the Company operates affect the Company’s generation, transmission and distribution business. State legislatures in five of the six states in which the Company has a retail presence will conduct business in calendar year 2004. The Oregon legislature may convene in special session during calendar year 2004.

Market Risk

Coal - The Company operates several thermal generation plants in Utah. A Company mine provides almost 50% of the coal used to fuel these plants. The balance of coal comes from short- and long-term purchases from third parties. Coal production in Utah is expected to decrease in calendar year 2004. This reduction can be primarily attributed to the closing of one unaffiliated mine and the shifting of production from a long-wall to a continuous mine operation at another unaffiliated mine. These reductions may have an impact on future prices the Company pays for coal to fuel its Utah generating plants. The Company will continue to evaluate its options and take actions to acquire fuel at the lowest possible price. Recovery of all costs incurred to fuel the Company’s generating plants will be requested in rate filings with the regulatory commissions.

Natural Gas - Since March 31, 2003, the Company purchased, under fixed-price terms, its calendar year 2006 forecasted natural gas supply needs for the Company’s existing natural-gas-fired electric generation plants. The Company currently supplies four natural-gas-fired generating plants that, at capacity, require a maximum of 229,000 MMBtu (million British thermal units) of natural gas per day. The Company’s Integrated Resource Plan has identified the need for additional resources, due to expected load growth, that could increase this requirement to 500,000 MMBtu, or more, per day. This includes the Currant Creek project, which is expected to start-up June 2005. Natural gas transportation capacity was purchased to meet the needs of the Currant Creek project, consistent with the Company’s fuels strategy, which focuses on the management and mitigation of risks associated with supplying natural gas to fuel generation. During January 2004, the Company purchased most of its calendar year 2006 forecasted gas supply needs for the Currant Creek project.

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

RISK MEASUREMENT

Interest Rate Exposure

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

The tests for exposure to interest rate fluctuations discussed below are based on a Value-at-Risk (“VaR”) approach using a one-year horizon and a 95.0% confidence level and assuming a one-day holding period in normal market conditions. The VaR model is a risk analysis tool that attempts to measure the potential change in fair value, earnings or cash flow due to changes in market conditions and does not purport to represent actual losses (or gains) in fair value that may be incurred by the Company. A key market condition variable in this analysis is the level of interest rate volatility. The range of possible changes in fair value, earnings or cash flow is influenced by the degree to which interest rates are expected to fluctuate. A measure of historical interest rate volatility is used to estimate the range of possible future interest rates. In general, an increase in interest rate volatility will result in a wider estimated range of potential losses and gains in fair value, earnings or cash flow.

The table below shows the potential loss in fair market value of the Company’s interest-rate-sensitive positions, as of March 31, 2003 and December 31, 2003, as well as the Company’s quarterly high and low potential losses.

(Millions of dollars)	Confidence Interval		Time Horizon	March 31, 2003			2004 Quarterly							December 31, 2003

								High			Low

Interest-rate-sensitive portfolio - fair market value	95.0	%	1 Day	$	(18.2	)	$	(36.7	)	$	(18.2	)	$	(36.7	)

The difference in potential loss in fair market value between March 31, 2003 and December 31, 2003 was primarily driven by changes in interest rate volatility. Interest rate volatility measures increased between March 31, 2003 and December 31, 2003.

Commodity Price Exposure

The Company’s market risk of 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. Risk management policy and the risk levels established as part of that policy govern the Company’s energy purchase and sales activities. For additional information about on the Company’s risk management and measurement, see ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK in the Company’s 2003 Annual Report on Form 10-K.

The Company measures the market risk in its electricity and natural gas portfolio daily by using a historical VaR approach, as well as other measurements of net position. The Company 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 future time period. The VaR model is a risk analysis tool that attempts to measure the potential change in fair value, earnings or cash flow due to changes in market conditions and does not purport to represent actual losses (or gains) in fair value that may be incurred by the Company.

As of December 31, 2003, the Company’s estimated potential five-day unfavorable impact on fair value of the electricity and natural gas commodity portfolio over the next 24 months, as measured by the VaR, was $19.5 million, as compared to $21.3 million as of December 31, 2002. The average daily VaR (five-day holding period and to a 99.0% confidence level) for the three months ended December 31, 2003 was $14.2 million. The maximum and minimum VaR measured during the three months ended December 31, 2003 were $20.5 million and $8.4 million, respectively. The Company maintained compliance with its VaR limit procedures during the three months ended December 31, 2003. Market changes inconsistent with historical trends or current assumptions could cause actual results to exceed the VaR measured.

FAIR VALUE OF DERIVATIVES

Statement of Financial Accounting Standards (“SFAS”) No. 133, Accounting for Derivative Instruments and Hedging Activities (“SFAS No. 133”), as amended by SFAS No. 138, Accounting for Certain Derivative Instruments and Certain Hedging Activities, and SFAS No. 149 (collectively SFAS No. 133) requires all derivatives, as defined by the standard, to be measured at fair value, except those that qualify for specific exemptions afforded by the standard. The implementation of SFAS No. 149 resulted in a significant increase in the number of contractual arrangements currently being marked to market by the Company; however, the overall impact on the Company’s consolidated financial statements was not significant. The derivatives that are marked to market in accordance with SFAS No. 133 include only certain of the Company’s commercial contractual arrangements, as many of these arrangements are outside the scope of SFAS No. 133.

The following table shows the changes in the fair value of energy-related contracts qualifying as derivatives under SFAS No. 133 from April 1, 2003 to December 31, 2003 and quantifies the reasons for the changes.

(Millions of dollars)

Fair value of contracts outstanding at the beginning of the period	$	(505.7	)
Contracts realized or otherwise settled during the period		35.7
Changes in valuation assumptions (a)		(45.2	)
Changes in fair values (b)		(11.3	)

Fair value of contracts outstanding at the end of the period (c)	$	(526.5	)

(a)

Reflects changes in the fair value of the mark-to-market values as a result of applying refinements in valuation modeling techniques.

(b)

Changes in fair values reflect commodity price risk, which is influenced by contract size, term, location and unique or specific contract terms.

(c)

The Company has also recorded $526.9 million in net regulatory assets, as authorized by regulatory orders received, to recover the costs with respect to these contracts.

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

The Company also partially mitigates its exposure to price and volume risk by purchasing weather hedges. These products are designed to protect the Company from the effects of weather on its hydroelectric generation and load forecast. The Company records these instruments in its financial statements at market value in accordance with Emerging Issues Task Force No. 99-2, Accounting for Weather Derivatives. At December 31, 2003, the net value of these instruments was a liability of $4.9 million.

The following table discloses summarized information with respect to valuation techniques and contractual maturities of the Company’s contracts qualifying as derivatives under SFAS No. 133 as of December 31, 2003.

	Fair Value of Contracts at Period-End

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

Prices actively quoted	$	—		$	—		$	—		$	—		$	—
Prices provided by other external sources		(1.6	)		0.2			—			—			(1.4	)
Prices based on models and other valuation methods		3.4			(23.4	)		(82.9	)		(422.2	)		(525.1	)

Total	$	1.8		$	(23.2	)	$	(82.9	)	$	(422.2	)	$	(526.5	)

ITEM 4.

CONTROLS AND PROCEDURES

(a) Management of the Company has evaluated, under the supervision and with the participation of the chief executive officer and chief financial officer, the effectiveness of the Company’s disclosure controls and procedures as of the end of the period covered by this report pursuant to Rule 13a-15(b) under the Securities Exchange Act of 1934. Based on that evaluation, the chief executive officer and chief financial officer have concluded that the Company’s disclosure controls and procedures are effective in ensuring that information required to be disclosed is recorded, processed, summarized and reported in a timely manner.

(b) There has been no change in the Company’s internal control over financial reporting that occurred during the last fiscal quarter that has materially affected, or is reasonably likely to materially affect, the Company’s internal control over financial reporting.

PART II. OTHER INFORMATION

ITEM 5.

OTHER INFORMATION

The Company’s 2003 Annual Report on Form 10-K contains information concerning the federal and state regulatory matters in which the Company is involved. See ITEM 1. BUSINESS - REGULATION. Certain developments with respect to those matters are set forth below.

FERC ISSUES

For a discussion on FERC issues, see PART I - ITEM 1. FINANCIAL STATEMENTS – Note 8 – Commitments and Contingencies.

REGULATORY ACTIONS

Utah

The Company commenced a general rate case on May 15, 2003, based on financial information for the year ended March 31, 2003 and including certain known and measurable changes that occurred by January 1, 2004. The initial filing included a projected revenue requirement increase of $125.0 million that served as a cap on the amount the Company could receive in the case. A subsequent detailed filing was made in July 2003, requesting a revenue increase equal to the cap. The Company supplemented this filing with a filing on September 15, 2003, detailing class cost-of-service and rate spread and rate design proposals. The Company filed an updated revenue requirement on October 15, 2003, with the total revenue increase unchanged. The Company submitted an updated class cost-of-service filing on October 31, 2003. Pursuant to the test period stipulation, settlement negotiations were held, concluding with a stipulation being filed with the Utah Public Service Commission (the “UPSC”) on December 10, 2003. This stipulation allowed a revenue requirement increase of $65.0 million. It was approved at a UPSC hearing held on December 17, 2003. The increase in customer rates is effective April 1, 2004. Following discussions with all parties, the Company reached agreement with the majority of parties on the rate spread and rate design components of the general rate case. As a result, a stipulation was filed with the UPSC on January 7, 2004. On January 30, 2004, the UPSC approved the stipulation, which will result in a mechanism to collect the previously ordered 7.0% average price increase and return on equity of 10.7%.

During summer 2003, the Company filed and received regulatory approval in Utah on three new residential demand-side management programs: a refrigerator recycling program, an air-conditioning load control program and an incentive program to install evaporative coolers or energy-efficient air-conditioners. The Company filed for a tariff rider to allow it to recover costs incurred through the implementation of all of the programs approved by the UPSC. The Company has been deferring the costs of approved programs since August 2001. Following the filing of testimony, tariff proposals and a series of technical conferences, interested parties have approved a stipulation detailing the introduction of a tariff rider mechanism and a self-direction program for large customers. This stipulation was heard and approved by the UPSC on September 23, 2003. The Company held discussions with regulatory parties on the setting of an initial collection rate of 3.0% for the demand-side management tariff rider. The Company filed for approval of this proposed collection rate under the newly adopted schedule on January 22, 2004. If approved, this tariff rider will be introduced in customer bills effective April 1, 2004.

Oregon

On August 26, 2003, the Oregon Public Utility Commission (the “OPUC”) approved a settlement of the Company’s general rate case filed on March 18, 2003. Under the settlement, base rates increased by $8.5 million annually on September 1, 2003, resulting in a 1.1% average price increase and an ordered return on equity of 10.5% on the regulatory capital structure. This represents an effective return on equity of 10.7% based on the filed capital structure. Also, a $12.0 million offsettable merger credit for the period from January 2004 to December 2004 was eliminated. A nonoffsettable merger credit will be reduced from $6.0 million to $4.0 million. The Company anticipates amortizing the credit to return the full amount to customers by December 31, 2004.

In November 2000, the Company made a deferred-accounting filing to track its excess net power costs. On July 18, 2002, the OPUC approved the filing, finding that the Company had prudently incurred the excess net power costs. The Industrial Customers of Northwest Utilities and the Citizens’ Utility Board appealed the OPUC order on March 26, 2003. The Marion County, Oregon circuit court affirmed the OPUC order. The Industrial Customers of Northwest Utilities and the Citizens’ Utility Board have appealed the circuit court decision to the Oregon Court of Appeals. Briefing is complete and the Court of Appeals is expected to schedule oral arguments in spring 2004.

The Company decided to discontinue pursuit of its October 1, 2001 appeals of two OPUC orders issued in conjunction with the deferred-accounting application. The orders established the baseline and a mechanism to determine the amount of excess net power costs that are eligible for deferral and eventual recovery. On July 28, 2003, the Oregon Court of Appeals issued an order affirming the OPUC orders. Based upon this order, the Company’s judgment is that further efforts to appeal the OPUC orders are unlikely to be successful.

On October 30, 2003, the OPUC approved a settlement of the Company’s net power costs for the period from September 10, 2001 through May 31, 2002 (the “Bridge Period”). An approved stipulation provided that the Company’s net power cost recovery during the Bridge Period would be based on a specified percentage of actual net

power costs, subject to certain adjustments, with deferred recovery or payment of any undercollection or overcollection. Following an independent audit, the parties to the original stipulation agreed that the Company had undercollected Bridge Period net power costs by $300,000. The OPUC approved this $300,000 in net power costs for later collection in rates.

Wyoming

On May 7, 2002, the Company filed a request to recover replacement power costs of $30.7 million, resulting from the outage of the Company’s Hunter No. 1 generating plant, and a proposal for recovering deferred net power costs of $60.3 million. In December 2000, the Wyoming Public Service Commission (the “WPSC”) authorized the deferral of net power costs. On March 6, 2003, the WPSC denied recovery of the Hunter No. 1 replacement power costs and the deferred net power costs. The Company filed a petition on April 4, 2003 for rehearing of the decision. After a public deliberation on May 30, 2003, the WPSC denied the petition, and the order denying rehearing was issued on July 15, 2003. On August 8, 2003, the Company petitioned the Laramie County district court to review the WPSC decision. On September 22, 2003, the district court certified the case to the Wyoming Supreme Court. The Company filed its opening brief with the Wyoming Supreme Court on January 6, 2004.

On May 27, 2003, the Company filed a general rate case with the WPSC to recover rising costs (including insurance premiums, pension funding and health care costs) and requested an increase in the return on equity to 11.5% to compensate the Company for general risks relating to the western United States utility environment, as well as some additional risks relating to multijurisdictional operations. The Company has requested an annual increase of $41.8 million, or 13.1%, in base rates to take effect in March 2004. On December 23, 2003, the Company filed rebuttal testimony in this proceeding, which lowered its requested annual increase to $38.6 million. Hearings in the case were completed in January 2004. During the hearings, the Company’s requested annual increase was further lowered by the WPSC to approximately $34.9 million. The Company expects an order by early March 2004, with new rates taking effect in late March 2004.

On September 26, 2003, the Company filed a request to establish a power cost adjustment mechanism (the “PCAM”). This mechanism will reduce the regulatory lag associated with recovery of net power costs, which are defined as fuel and wheeling expenses and wholesale sales and purchases. The mechanism is proposed to become effective April 1, 2004. The PCAM includes two components: (1) an annual update that recovers forecasted net power costs through a surcharge, and (2) a deferral mechanism between customers and shareholders that shares variations in adjusted actual net power costs from forecasted net power costs. Since the base net power cost rate will be established in the current general rate case, the first adjustment to the base net power cost rate under the PCAM would be April 1, 2005, when the new forecasted net power cost would go into effect. Also beginning in 2005, the Company would make a filing by July 31 of each year to set the PCAM deferral rate to recover from, or return to, customers any costs deferred during the prior deferral period. Hearings in the PCAM case are scheduled for March 15 to 16, 2004 and an order is expected in early April 2004.

Washington

On April 5, 2002, the Company filed a petition with the Washington Utilities and Transportation Commission (the “WUTC”), seeking authority to begin deferring net power costs in excess of those included in rates as of June 1, 2002 for later recovery in rates, either through a power cost adjustment mechanism or a limited rate adjustment. Under the rate plan approved by the WUTC in August 2000 at the conclusion of the Company’s last general rate case in Washington, there were limitations on the Company’s ability to request changes to general rates before January 2006. On October 18, 2002, the Company filed testimony and supporting documents, requesting deferral and recovery of excess net power costs estimated at the time to be $17.5 million, including carrying charges, or, alternatively, that the Company be allowed to file a general rate case, which would otherwise not have been allowed until December 2005. Through March 31, 2003, the deferral was expected to total $12.2 million. Hearings were held March 20 through 24, 2003, and a decision was issued on July 15, 2003. This decision did not allow for the deferral and recovery of excess power costs, but does allow the Company to file a general rate case any time before July 2005 that addresses the level of prices needed to cover all ongoing costs to serve Washington customers. On August 14, 2003, the Public Counsel section of the state attorney general’s office filed a court action in Thurston County superior court requesting review of the WUTC’s decision to allow the Company to file a general rate case that would allow a change in base rates prior to January 1, 2006. A status conference in that proceeding was held on November 7, 2003. A briefing schedule has been established, which will be followed by oral argument in May 2004.

On October 13, 2003, the Company filed petitions with the WUTC for accounting orders to allow deferral and amortization of the Trail Mountain coal mine closure costs and environmental remediation costs. In addition, the Company filed a petition requesting WUTC authorization of accounting treatment relating to pension liability, as well as confirmation by the WUTC that certain actuarially determined pension costs are recoverable in rates. These filings were made in response to the stipulation approved in the last general rate proceeding in Washington requiring that items treated as regulatory assets under authorizations from other states that are proposed for inclusion in Washington at the end of the rate plan period be supported by accounting authorizations in Washington.

On December 16, 2003, the Company filed with the WUTC for a general rate increase of $26.7 million annually, or 13.5%. The Company’s objectives are to recover higher power costs; recover increases in insurance, pension, health care, infrastructure and security costs; increase authorized return on equity to 11.25%; and receive approval for the proposed interjurisdictional cost allocation protocol. In addition, the Company is requesting that the WUTC adopt the findings of a prudence review of generating resources acquired since the last Washington general rate case. The WUTC has adopted a procedural schedule requiring testimony from the staff and other parties in June 2004 and the Company’s rebuttal testimony in July 2004. Hearings are scheduled to begin on August 30, 2004.

Idaho

On July 11, 2003, the Company filed an application for approval of a renewable-energy tariff. Under the proposed tariff, residential and nonresidential customers can purchase newly developed wind, geothermal and solar power energy in fixed increments. On August 28, 2003, the Idaho Public Utilities Commission (the “IPUC”) approved the application as filed.

On December 23, 2003 the Company filed with the IPUC to recover $4.2 million related to Idaho’s portion of income tax payments resulting from audits of prior years. The filing requests recovery over 16 months, beginning in June 2004, when a power cost recovery surcharge, which began in June 2002, expires.

California

On June 19, 2003, the Company and the California Public Utilities Commission’s (“CPUC”) Office of Ratepayer Advocates executed a settlement agreement addressing revenue requirements in the Company’s pending general rate case. Hearings were held in June and July to consider the respective settlement agreements and to receive evidence and exhibits into the record. On July 7, 2003, an all-party settlement was filed addressing revenue allocation and rate design. On September 9, 2003, an administrative law judge issued a draft order approving the settlement and establishing a 30-day comment period. The CPUC issued a final order on November 13, 2003 approving the two stipulations in the general rate case and finalizing permanent rates. The order grants an additional annual increase of $2.8 million, effective December 1, 2003. Combining this order with the interim increase authorized in June 2002 results in an overall annual price increase of $7.6 million. This represents a 13.6% annual price increase, with a return on equity of 10.9%.

Affiliated-Interest Filings

REQUEST FOR PROPOSAL

The Company has segregated the Integrated Resource Plan supply-side action items into a series of three separate Requests for Proposal, each of which focuses on a specific category of supply-side resources and provides for the staged procurement of resources in future years to achieve load/resource balance.

Currant Creek Project

The first of these three Requests for Proposal (RFP 2003A) was issued on June 6, 2003. The Currant Creek project was demonstrated to be the most economical fiscal year 2005 resource category choice to meet the Company’s future generation needs. The Currant Creek project is a 525-MW natural-gas-fired, combined-cycle combustion turbine generation project located approximately 75 miles south of Salt Lake City, Utah and will be constructed in two phases, with two 140-MW (280-MW total) simple-cycle combustion turbines being installed during summer 2005. Two heat-recovery steam generators and a steam generation turbine will be added in calendar year 2006 to bring the plant output to a total of 525-MW.

The Company is currently seeking regulatory approval from the UPSC to proceed with construction of the 525-MW Currant Creek generation project. Hearing dates are scheduled for February 18-19, 2004 and an order is expected shortly thereafter. Approval by the UPSC is required before construction can begin. The order may approve, deny, or otherwise delay the project. If a delay causes the project to miss the projected in-service date during summer 2005, the Company may need to take actions to procure firm resources to meet its service obligations. The Company would seek to minimize the effects of any delay on net power costs through its normal balancing and hedging strategies.

The Company is still in the process of reviewing the summer 2007 resource category submissions as a result of the first Request for Proposal. The summer 2007 resource category is expected to result in a resource of greater than 500-MW.

Other Requests for Proposal

The second Request for Proposal (RFP 2003B) is expected to be issued in February 2004 and will request approximately 1,100 MW of renewable resources for the Company’s entire service territory. The third Request for Proposal (RFP2004A) is expected to be issued in calendar year 2004 and will request additional resources to serve the Company’s eastern service territory in Utah, Wyoming and Idaho. The expected total cycle time for each Request for Proposal process is approximately six to eight months or more.

In addition to the three supply-side Requests for Proposal, the Company issued a separate Request for Proposal for the demand-side resources called for in the Integrated Resource Plan. The demand-side Request for Proposal was issued on June 26, 2003, with responses due on August 18, 2003. Analysis of initial responses has been completed and a shortlist of bidders has been selected for further evaluation.

MULTI-STATE PROCESS

The Company is involved in a collaborative process with the six states it serves, in an effort to develop mutually acceptable solutions to the issues faced by the Company and the states as a result of the Company’s multistate operations. These issues pertain to the inconsistent allocation of some of the cost of the Company’s existing investments and the recovery of the cost of future investments. Between April 2002 and July 2003, the Company and key parties from Utah, Oregon, Wyoming, Washington and Idaho, along with a key monitoring contact from California, analyzed over 50 options to address these issues, which were narrowed to two possibilities. Both sought to clarify roles and responsibilities, including cost allocations for future generation resources; provide states with the ability to independently implement state energy policy objectives; and achieve permanent consensus on each state’s responsibility for the costs and each state’s entitlement to the benefits of the Company’s existing assets. Following the July 2003 meeting, the Company undertook extensive analytical work to develop a single proposal that would best balance the needs of the Company and requirements of the states in addressing the positions, issues and concerns raised and discussed during the course of the collaborative and individual state meetings. This work culminated in a regulatory filing on September 30, 2003 in the states of Utah, Oregon, Wyoming and Idaho. A similar filing was made in Washington in December 2003 as part of the general rate case filing. A filing in California will follow in coordination with rate case activity. Utah and Oregon have adopted regulatory schedules that envision continued formal and informal meetings among the states and commissions through March 2004. Direct and rebuttal testimony will be filed in May and June 2004, with hearings scheduled for July 2004. The parties have proposed a similar schedule for Wyoming and await commission approval.

REGIONAL TRANSMISSION ORGANIZATION

The Company, in conjunction with nine other utilities, is seeking to form a Regional Transmission Organization (“RTO”) in response to the FERC’s Order 2000. On September 18, 2002, the FERC found that, with some modification and further development of certain details, the RTO proposal satisfies the 12 characteristics and functions in the FERC’s Order 2000. Creation of the RTO is subject to regulatory approvals from the FERC and state regulatory commissions. The RTO, if and when fully implemented, would serve as an independent transmission provider for the RTO region and have operational authority needed for bulk electricity transfers over a majority of the 60,000 miles of transmission lines owned by its members. Under the current proposal, the Company would continue to own its transmission assets.

On July 31, 2002, the FERC issued a Notice of Proposed Rulemaking, proposing a new Standard Market Design for wholesale electricity markets. The FERC subsequently issued a “Wholesale Power Market Platform” white paper on April 28, 2003, which signaled a greater willingness to defer to regional solutions and not adopt overly prescriptive rules. In its final rule, the Company expects that the FERC will allow implementation schedules to vary depending on local needs and will allow for local differences. The FERC is closely monitoring any pending legislation in the U.S. Congress and has not yet set a date for issuing the final rule.

After the Standard Market Design white paper was released, the RTO West filing utilities reengaged the Regional Representatives Group, a formal regional stakeholder process. The Regional Representatives Group developed a consensus of regional problems and opportunities and unanimously approved a proposal for going forward. The Regional Representatives Group is currently developing an implementation plan for this regional proposal, which includes timing for seating an independent Board of Trustees, obtaining the necessary regulatory approvals and the first phase of operation by an independent regional operator.

ITEM 6.

EXHIBITS AND REPORTS ON FORM 8-K

(a) Exhibits.

2.1(a)*	Agreement and Plan of Merger, dated as of December 6, 1998, by and among Scottish Power plc, NA General Partnership, Scottish Power NA 1 Limited and Scottish Power NA 2 Limited (Exhibit 1 to the Form 6-K, dated December 11, 1998, filed by Scottish Power plc, File No. 1-14676).

2.1(b)*	Amended and Restated Agreement and Plan of Merger, dated as of December 6, 1998, as amended as of January 29, 1999 and February 9, 1999, and amended and restated as of February 23, 1999, by and among New Scottish Power plc, Scottish Power plc, NA General Partnership and PacifiCorp (Exhibit (2)b, Form 10-K for year ended December 31, 1998, File No. 1-5152).

3.1*	Third Restated Articles of Incorporation of the Company (Exhibit (3)b, Form 10-K for the year ended December 31, 1996, File No. 1-5152).

3.2*	Bylaws of the Company effective November 29, 1999 (Exhibit (3)b, Form 10-K for the year ended March 31, 2000, File No. 1-5152).

4.1*	Mortgage and Deed of Trust, dated as of January 9, 1989, between the Company and Morgan Guaranty Trust Company of New York (The Chase Manhattan Bank, successor), Trustee, Ex. 4-E, Form 8-B, File No. 1-5152 as supplemented and modified by 16 Supplemental Indentures as follows:

Exhibit Number	File Type	File Date	File Number

(4)(b)			33-31861
(4)(a)	8-K	January 9, 1990	1-5152
4(a)	8-K	September 11, 1991	1-5152
4(a)	8-K	January 7, 1992	1-5152
4(a)	10-Q	Quarter ended March 31, 1992	1-5152
4(a)	10-Q	Quarter ended September 30, 1992	1-5152
4(a)	8-K	April 1, 1993	1-5152
4(a)	10-Q	Quarter ended September 30, 1992	1-5152
4(a)	10-Q	Quarter ended September 30, 1993	1-5152
(4)b	10-Q	Quarter ended June 30, 1994	1-5152
(4)b	10-K	Quarter ended December 31, 1994	1-5152
(4)b	10-K	Quarter ended December 31, 1995	1-5152
(4)b	10-K	Quarter ended December 31, 1996	1-5152
99(a)	8-K	November 21, 2001	1-5152
4.1	10-Q	Quarter ended June 30, 2003	1-5152
99	8-K	September 8, 2003	1-5152

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

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	Principal Executive Officer Certification Pursuant to Sarbanes-Oxley Act of 2002, Section 302

31.2	Principal Financial Officer Certification Pursuant to Sarbanes-Oxley Act of 2002, Section 302

32.1	Principal Executive Officer Certification Pursuant to Sarbanes-Oxley Act of 2002, Section 906

32.2	Principal Financial Officer Certification Pursuant to Sarbanes-Oxley Act of 2002, Section 906

* Incorporated herein by reference.

(b) Reports on Form 8-K.

The Company filed a Current Report on Form 8-K, dated December 17, 2003, to announce under Item 5. Other Events that the UPSC had granted approximately $65 million of additional annual revenues following an all-parties settlement to the general rate case.

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 5, 2004	By:	/s/ RICHARD D. PEACH

		Richard D. Peach Chief Financial Officer