UNITED STATES SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

[X]

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

For the quarterly period ended June 30, 2003

OR

[]

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

For the transition period from _______________ to _______________

Commission file number 1-5152

PacifiCorp

(Exact name of registrant as specified in its charter)

STATE OF OREGON
(State or other jurisdiction
of incorporation or organization)
93-0246090
(I.R.S. Employer Identification No.)

825 N.E. Multnomah Street, Portland, Oregon
(Address of principal executive offices)
97232
(Zip Code)

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

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding twelve months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for at least the past 90 days.

YES [X]     NO  [   ]

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 [   ]     NO  [X]

As of July 28, 2003, there were 312,176,089 shares of common stock outstanding. All shares of outstanding common stock are indirectly owned by Scottish Power plc, 1 Atlantic Quay, Glasgow, G2 8SP, Scotland.

PACIFICORP

		Page No.
PART I.	FINANCIAL INFORMATION
Item 1.	Financial Statements
	Condensed Consolidated Statements of Income and Retained Earnings	2
	Condensed Consolidated Statements of Cash Flows	3
	Condensed Consolidated Balance Sheets	4
	Notes to Condensed Consolidated Financial Statements	6
	Report of Independent Accountants	16
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	17
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	22
Item 4.	Controls and Procedures	26
PART II.	OTHER INFORMATION	26
Item 5.	Other Information	26
Item 6.	Exhibits and Reports on Form 8-K	29

SIGNATURE 30

1

PART I. FINANCIAL INFORMATION

ITEM 1.

FINANCIAL STATEMENTS

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

(Millions of dollars)	Three Months Ended June 30,
	2003			2002
Revenues	$	894.8		$	885.6
Operating expenses
Purchased electricity		266.0			316.5
Fuel		116.7			97.3
Other operations and maintenance		147.3			145.2
Depreciation and amortization		104.1			106.4
Administrative and general		69.6			76.5
Taxes, other than income taxes		23.7			22.8
Unrealized (gain) loss on derivative contracts		(1.5	)		2.2
Total		725.9			766.9
Income from operations		168.9			118.7
Interest expense and other (income) expense
Interest expense		61.1			64.0
Interest income		(4.4	)		(6.3	)
Interest capitalized		(5.6	)		(5.5	)
Minority interest and other		5.9			9.4
Total		57.0			61.6
Income from operations before income taxes and cumulative effect of accounting change		111.9			57.1
Income tax expense		48.4			19.6
Income before cumulative effect of accounting change		63.5			37.5
Cumulative effect of accounting change (less applicable income tax benefit $(0.6)/2003 and $(1.1)/2002) (Notes 5 and 3)		(0.9	)		(1.9	)
Net income		62.6			35.6
Preferred dividend requirement		(1.8	)		(1.9	)
Earnings on common stock	$	60.8		$	33.7
RETAINED EARNINGS BEGINNING OF PERIOD	$	305.9		$	173.1
Net income		62.6			35.6
Cash dividends declared
Preferred stock		(1.8	)		(1.9	)
Common stock		(40.1	)		—
RETAINED EARNINGS END OF PERIOD	$	326.6		$	206.8

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

2

PACIFICORP
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)

(Millions of dollars)	Three Months Ended June 30,
	2003			2002
Cash flows from operating activities
Net income	$	62.6		$	35.6
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) loss on derivative contracts		(1.5	)		2.2
Depreciation and amortization		104.1			106.4
Deferred income taxes and investment tax credits - net		13.8			(5.4	)
Provision for pension and benefits		18.6			7.2
Deferred net power costs		(1.8	)		(3.3	)
Changes in other regulatory assets/liabilities		28.8			24.1
Accounts receivable and prepayments		(8.3	)		12.0
Inventories		5.9			(2.9	)
Accounts payable and accrued liabilities		(78.2	)		(39.1	)
Other		6.7			(6.6	)
Net cash provided by operating activities		151.6			132.1
Cash flows from investing activities
Capital expenditures		(157.6	)		(131.0	)
Proceeds from sales of assets		0.4			4.0
Proceeds from available for sale securities		47.1			52.7
Purchases of available for sale securities		(45.2	)		(52.8	)
Other		(4.5	)		1.3
Net cash used in investing activities		(159.8	)		(125.8	)
Cash flows from financing activities
Changes in short-term debt		30.0			5.0
Dividends paid		(41.9	)		(2.0	)
Repayments of long-term debt		—			(0.1	)
Redemptions of preferred stock		(7.5	)		(7.5	)
Other		(0.4	)		0.1
Net cash used in financing activities		(19.8	)		(4.5	)
(Decrease) increase in cash and cash equivalents		(28.0	)		1.8
Cash and cash equivalents at beginning of period		152.5			157.9
Cash and cash equivalents at end of period	$	124.5		$	159.7

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

3

PACIFICORP
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)

(Millions of dollars)	June 30, 2003			March 31, 2003
ASSETS
Current assets
Cash and cash equivalents	$	124.5		$	152.5
Accounts receivable less allowance for doubtful accounts, $40.2/June 2003 and $36.3/March 2003		209.3			253.2
Unbilled revenue		146.6			109.2
Inventories at average cost
Materials and supplies		99.6			99.4
Fuel		65.7			71.8
Current derivative contract asset		123.4			107.2
Other		33.6			18.9
Total current assets		802.7			812.2
Property, plant and equipment		13,712.4			13,516.8
Accumulated depreciation and amortization		(4,915.6	)		(5,483.2	)
Total property, plant and equipment - net		8,796.8			8,033.6
Other assets
Regulatory assets		1,136.0			1,175.9
Derivative contract regulatory asset		546.4			506.9
Non-current derivative contract asset		109.3			122.3
Deferred charges and other		348.3			342.1
Total other assets		2,140.0			2,147.2
Total assets	$	11,739.5		$	10,993.0

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

4

PACIFICORP
CONDENSED CONSOLIDATED BALANCE SHEETS, continued
(Unaudited)

(Millions of dollars)	June 30, 2003			March 31, 2003
LIABILITIES, REDEEMABLE PREFERRED STOCK AND SHAREHOLDERS’ EQUITY
Current liabilities
Long-term debt currently maturing	$	136.8		$	136.7
Notes payable and commercial paper		55.0			25.0
Accounts payable		205.7			235.8
Amounts due to affiliates		49.9			39.6
Accrued employee expenses		63.0			105.9
Taxes payable		67.3			66.9
Interest payable		50.8			67.9
Current derivative contract liability		101.4			91.7
Other		160.9			159.0
Total current liabilities		890.8			928.5
Deferred credits
Income taxes		1,485.5			1,480.2
Investment tax credits		88.9			91.4
Regulatory liabilities		794.6			137.0
Non-current derivative contract liability		675.0			643.5
Other		726.2			650.1
Total deferred credits		3,770.2			3,002.2
Long-term debt, net of current maturities		3,417.7			3,417.6
Commitments and contingencies (See Note 7)
Guaranteed preferred beneficial interests in Company’s junior subordinated debentures		341.9			341.8
Preferred stock subject to mandatory redemption		59.3			66.7
Redeemable preferred stock		41.3			41.3
Common equity
Common shareholder’s capital		2,892.1			2,892.1
Retained earnings		326.6			305.9
Accumulated other comprehensive income (loss):
Unrealized gain (loss) on available for sale securities, net of tax of $0.9/June 2003 and $(1.5)/March 2003		1.0			(1.7	)
Minimum pension liability, net of tax of $(0.8)		(1.4	)		(1.4	)
Total common equity		3,218.3			3,194.9
Total liabilities, redeemable preferred stock and shareholders’ equity	$	11,739.5		$	10,993.0

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

5

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 financing. Intercompany transactions and balances have been eliminated upon consolidation.

The accompanying unaudited condensed consolidated financial statements as of June 30, 2003 and for the periods ended June 30, 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. Such statements are presented in accordance with the Securities and Exchange Commission’s (“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 last Annual Report on Form 10-K have been condensed or omitted from the interim statements. A portion of the business of the Company is of a seasonal nature and, therefore, results of operations for the periods ended June 30, 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, which is available at the SEC’s website at www.sec.gov or at the Company’s website at www.pacificorp.com.

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 with 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 Scottish Power plc (“ScottishPower”) American Depository Shares (“ADS”). 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 would have been changed to the pro forma amounts below:

	Three Months Ended June 30,
(Millions of dollars)	2003			2002
Net income as reported	$	62.6		$	35.6
Stock-based employee compensation expense		(0.4	)		(0.6	)
Pro forma net income	$	62.2		$	35.0

Unbilled revenues - The Company changed its calculation of unbilled revenues, which had the effect of increasing revenues by approximately $10.0 million and after-tax net income by approximately $5.7 million for the three months ended June 30, 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. Accounting under SFAS No. 71 is appropriate as long as (i) rates are established by or subject to approval by independent, third-party regulators, (ii) rates are designed to recover the specific enterprise’s cost of service, and (iii) in view of demand for service, it is reasonable to assume that rates are set at levels that will recover costs and can be collected from customers.

6

SFAS No. 71 provides that regulatory assets may be capitalized if it is probable that future revenue in an amount at least equal to the capitalized costs will result from the inclusion of that cost in allowable costs for ratemaking purposes. In addition, the rate action should permit recovery of the specific previously incurred costs rather than provide for expected levels of similar future costs. 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. A regulator can provide current rates intended to recover costs that are expected to be incurred in the future, with the understanding that if those costs are not incurred, future rates will be reduced by corresponding amounts. If current rates are intended to recover such costs, the Company recognizes amounts charged, pursuant to such rates, as liabilities and takes those amounts to income only when the associated costs are incurred. In applying SFAS No. 71, the Company must give consideration to changes in the level of demand or competition during the cost recovery period. In accordance with SFAS No. 71, the Company capitalizes certain costs as regulatory assets in accordance with regulatory authority whereby those costs will be expensed and recovered in future periods.

The Emerging Issues Task Force (the “EITF”) of the Financial Accounting Standards Board (the “FASB”) concluded in 1997 that SFAS No. 71 should be discontinued when detailed legislation or regulatory orders regarding competition are issued. Additionally, the EITF concluded that regulatory assets and liabilities applicable to businesses being deregulated should be written off unless their realization is provided for through future regulated cash flows. The Company continuously evaluates the appropriateness of applying SFAS No. 71 in each of its jurisdictions. At June 30, 2003, management concluded that SFAS No. 71 was appropriate for the Company. However, if deregulation activities progress, the Company may in the future be required to discontinue its application of SFAS No. 71 to all or a portion of its business. If the Company stopped applying SFAS No. 71 to its regulated operations, it would write off the related balances of its regulatory assets as an expense on its income statement. Based on the balances of the Company’s regulatory assets at June 30, 2003, if the Company had stopped applying SFAS No. 71 to its remaining regulated operations, it would have recorded an extraordinary loss, after tax, of approximately $503.4 million. While regulatory orders and market conditions may affect the Company’s cash flows, its cash flows would not be affected if it stopped applying SFAS No. 71 unless a regulatory order limited its ability to recover the cost of that regulatory asset.

Regulatory assets include the following:

(Millions of dollars)	June 30, 2003		March 31, 2003
Deferred taxes (a)	$	538.2	$	550.3
Transition Plan costs - retirement and severance (b)		52.7		55.1
Deferred net power costs (c)		118.7		137.8
Demand-side resource costs		46.2		45.7
Unamortized net loss on reacquired debt		32.9		34.3
Utah and Oregon asset writebacks (d)		25.2		27.0
Unrecovered Trojan Plant		14.4		14.9
Derivative contracts (e)		546.4		506.9
Asset retirement obligation (f)		2.8		—
SB 1149 related costs (g)		22.3		22.3
Minimum pension liability offset (h)		234.5		234.5
Various other costs		48.1		54.0
Total	$	1,682.4	$	1,682.8

(a)

Excludes $88.9 million and $91.4 million as of June 30, 2003 and March 31, 2003, respectively, of investment tax credits.

(b)

Represents the unamortized amount of retirement and severance costs relating to a transition plan that the state commissions allowed to be deferred and amortized.

(c)

Represents the deferred net power costs that vary from costs included in determining retail rates in Utah, Oregon and Idaho.

7

(d)

A Utah Public Service Commission (“UPSC”) order during the year ended March 31, 2001 allowed recovery of early retirement and pension costs, reclamation costs and Year 2000 and other information system costs that had previously been written off. A UPSC order during the year ended March 31, 2002 allowed recovery of an additional $21.0 million of mine reclamation, information system and transition costs that had previously been written-off. An Oregon Public Utility Commission (the “OPUC”) order during the year ended March 31, 2001 allowed recovery of Year 2000 information system costs.

(e)

Represents the current and noncurrent mark-to-market valuation of derivative contracts.

(f)

Represents the difference between regulatory approved removal costs and asset retirement obligation (“ARO”) removal costs.

(g)

Represents the State of Oregon Senate Bill 1149 related transition and implementation costs allowed to be recovered by a systems benefit charge allotted to associated customers effective March 1, 2002.

(h)

The Company’s retirement plans had assets with a fair value that was less than the accumulated benefit obligation under the plans primarily due to declines in the equity markets. As a result, the Company recognized a minimum pension liability in the fourth quarter of the year ended March 31, 2003. The liability adjustment was recorded as a noncash charge of $234.5 million to Regulatory assets.

Regulatory liabilities include the following:

(Millions of dollars)	June 30, 2003		March 31, 2003
Deferred taxes	$	39.4	$	39.3
Centralia gain		62.6		66.5
Merger credits		12.0		15.2
Asset retirement obligation (a)		660.9		—
Various other costs		19.7		16.0
Total	$	794.6	$	137.0

(a)

Represents removal costs recovered in rates that do not qualify as AROs 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 has reached agreements in principle with the staffs of the OPUC and the Washington Utilities and Transportation Commission (the “WUTC”) and parties to the Wyoming depreciation case on issues similar to those previously approved in Utah and Idaho with respect to 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.

NOTE 3 - Derivative Instruments

On April 1, 2001, the Company adopted SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities (“SFAS No. 133”), as amended by SFAS No. 138 and numerous interpretations of the Derivatives Implementation Group that are approved by the FASB, collectively “SFAS No. 133.” Under SFAS No. 133, derivative instruments are recorded on the Condensed Consolidated Balance Sheet as an asset or liability measured at estimated fair value, with changes in fair value recognized currently in earnings unless specific hedge accounting criteria are met. As contracts settle, their impact is recorded in the Condensed Statements of Consolidated Income.

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 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

8

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 its business and activities, measure quantitative market risk exposure and identify qualitative market risk exposure in its businesses. 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 its objective, that such instruments will be primarily used for hedging and not for speculation.

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 EITF No. 99-2, Accounting for Weather Derivatives. The unrealized loss recorded for these contracts was $6.4 million and $1.7 million for the three months ended June 30, 2003 and 2002, respectively.

The following table summarizes the SFAS No. 133 movements for the three months ended June 30, 2003:

(Millions of dollars)	Asset (Liability)			Regulatory Net Asset (Liability)			Deferred Tax Liability			Accumulated Income
Balance at March 31, 2003	$	(505.7	)		506.9			(0.5	)		0.7
Settlements		3.3			(2.3	)		(0.4	)		0.6
Changes in valuation assumptions		(68.5	)		68.5			—			—
Changes in fair value		27.2			(26.7	)		(0.2	)		0.3
Balance at June 30, 2003	$	(543.7	)	$	546.4		$	(1.1	)	$	1.6

NOTE 4 - Related Party Transactions

There are no loans or advances between PacifiCorp and ScottishPower or between PacifiCorp and 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 PacifiCorp 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.

9

(Millions of dollars)	June 30, 2003		March 31, 2003
Amounts due from affiliated entities:
ScottishPower (a)	$	0.2		0.1
PHI subsidiaries (b)		2.8		2.4
	$	3.0	$	2.5
Amounts due to affiliated entities:
ScottishPower (c)	$	3.3		2.6
PHI subsidiaries (d)		46.6		37.0
	$	49.9	$	39.6

	Three Months Ended June 30,
(Millions of dollars)	2003		2002
Revenues from affiliated entities:
PHI subsidiaries (f)	$	1.0	$	1.1
Expenses incurred from affiliated entities:
ScottishPower (c)	$	1.9	$	2.3
PHI subsidiaries (g)		4.2		0.6
	$	6.1	$	2.9
Expenses recharged to affiliated entities:
ScottishPower (a)	$	0.3	$	0.1
PHI subsidiaries (b)		2.0		1.6
	$	2.3	$	1.7
Interest expense to affiliated entities:
PHI subsidiaries (e)	$	0.1	$	—

(a)

Amounts due from affiliates are included in Other current assets on the Condensed Consolidated Balance Sheet. The Company recharges to ScottishPower payroll costs and related benefits of employees working on international assignment.

(b)

Amounts shown pertain to activities of the Company and its subsidiaries with PHI and its subsidiaries. Expenses recharged reflect costs for support services to PHI and its subsidiaries.

(c)

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

(d)

Includes current portion of net income taxes payable to PHI of $46.6 million and $37.0 million at June 30, 2003 and March 31, 2003, respectively. PHI is the tax paying entity for the consolidated group.

(e)

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

(f)

These revenues represent wheeling revenues received from PPM Energy, Inc. (“PPM”).

(g)

These expenses primarily represent operating lease payments for the West Valley facility, located in Utah, and owned by a subsidiary of PPM, which was only partially operational during the three months ended June 30, 2002.

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 1.4% and 1.9% for the three months ended June 30, 2003 and 2002, respectively.

10

NOTE 5 – Asset Retirement Obligations

In June 2001, the FASB issued SFAS No. 143. The statement requires the fair value of an ARO 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 ARO 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 loss. The Company adopted this statement as of April 1, 2003.

The Company had been recording retirement obligations relating to mining reclamation and closure costs prior to adoption of the standard. In addition, the Company has been recording accumulated removal costs as a part of 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 AROs 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 Consolidated Balance Sheet to account for the difference between asset retirement costs as currently approved in rates and costs under SFAS No. 143.

Upon adoption of SFAS No. 143 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. As a result of the regulated enviornment 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 $8.0 million and $2.7 million, respectively.

The following table describes the changes to the Company’s ARO liability for the three months ended June 30, 2003:

(Millions of dollars)
Liability recognized at adoption on April 1, 2003	$	196.4
Liabilities incurred (a)		4.9
Liabilities settled (b)		(3.4	)
Revisions in cash flow (c)		(0.2	)
Accretion expense		2.0
Asset retirement obligation at June 30, 2003	$	199.7

(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 mine.

The proforma ARO 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)
Proforma ARO liability at April 1, 2001	$	207.0
Proforma ARO 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 proforma periods listed above.

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NOTE 6 - Financing Arrangements

At June 30, 2003, the Company had $800.0 million of committed bank revolving credit agreements, including a $300.0 million facility having a three-year term that became effective June 4, 2002 and a new $500.0 million facility that became effective June 3, 2003 having a 364-day term plus a one-year term loan option. The interest on advances under these facilities is based on LIBOR plus a margin that varies based on the Company’s credit ratings. As of June 30, 2003, these facilities were fully available, and there were no borrowings outstanding.

During June 2003, the Company notified holders of its intent to redeem first mortgage bonds totaling $57.5 million aggregate principal amount plus redemption premium of $1.6 million and accrued interest. These retirements will occur in July 2003 and August 2003 and are expected to be funded initially through short-term debt or available cash. The Company continues to classify this debt as long-term based on management’s intent and the Company’s ability to support this debt on a long-term basis.

NOTE 7 - Commitments and Contingencies

The Company follows SFAS No. 5, Accounting for Contingencies (“SFAS No. 5”), 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 Department of Labor, the United States 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. The evaluation of these contingencies is performed by various specialists inside and outside of the Company.

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 might be, management currently believes that disposition of these matters will not have a materially adverse effect on the Company’s consolidated financial position or results of operations.

Enron reserves

Beginning in summer 2000, market conditions in California resulted in defaults of 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 has 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 also a party to a FERC proceeding that is investigating potential refunds for energy transactions in the California market 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 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. Requests for a rehearing and appeals of this decision are likely.

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 power suppliers. On July 3, 2003, the Company filed a petition for review of certain aspects of this order in the Ninth Circuit Court of Appeals. The Company also plans to seek rehearing of this order at the FERC.

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FERC Show-Cause Orders - In May 2002, the Company, together with other California power market participants, responded to data requests from the FERC regarding trading practices connected with the power 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. The Staff’s Final Report recommended that the FERC issue show-cause orders to numerous market participants, including the Company, requiring them to demonstrate why their behaviors did not violate the California Independent System Operators’ (the “Cal ISO”) and the California Power Exchange (the “CPX”) tariffs as part of the ongoing FERC trading practices investigation. 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 power market, as defined in the Cal ISO and CPX tariffs. In setting the cases for hearing, the Commission directed the administrative law judge (“ALJ”) 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. Responses to the show-cause orders are due to the FERC by September 2, 2003.

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 are expiring in the next few years and 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. Power generation reductions may result from the additional environmental requirements. As of June 30, 2003, the Company had incurred approximately $96.0 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.

During the three months ended June 30, 2003, the Company entered into a settlement agreement to remove the Powerdale project rather than to 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 is projected to cost $4.9 million with removal to commence in 2010. The FERC also issued final Environmental Impact Statements (“EIS”) for both the North Umpqua and Bear River hydroelectric projects in April 2003, which is the final step prior to receiving new operating licenses. The EISs are materially consistent with the negotiated settlement agreements for both projects and licenses are expected by March 31, 2004. Settlement agreements are contingent on acceptable orders being issued by the FERC and on obtaining all necessary permits. Additionally, in June 2003, the Company submitted a draft license application to interested parties for a 90-day review for the Klamath hydroelectric project and a final license application to the FERC for the Prospect Nos. 1,2 and 4 Hydroelectric Projects. The FERC is expected to complete its required analysis over the next two years.

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; and the Resource Conservation and Recovery Act of 1976 and the Clean Water Act, relating to water quality. These laws could potentially impact future operations. Contingencies identified at June 30, 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 environmental laws, new mercury maximum control technology requirements, promulgated under the existing Clean Air Act, are scheduled to be implemented during the next five years. 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 consist primarily of capital expenditures. The Company expects these costs will be included in rates and, as such, will not have a material adverse impact on the Company’s consolidated results of operations. Most recently, the Company has been cooperating with the EPA in providing information about certain of its generating plants as both seek a mutual, comprehensive solution to air quality issues as they relate to such plants generally, and is discussing many of the same technical issues with state air regulators.

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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 power canal and associated 70-MegaWatt ("MW") hydroelectric facility (“Swift No. 2”) are owned by Cowlitz County Public Utility District (“Cowlitz”). It is anticipated that Cowlitz will repair Swift No. 2 in time for a calendar-year 2005 startup. 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, by restricting both flow and generation flexibility (“shaping”). Repairs to the canal were completed and Swift No. 1 was returned to full capacity levels as of mid-July 2002 (though with limited shaping capabilities). Environmental, operations safety and fish mitigation issues remain to be resolved before full use of Swift No. 1 can resume. The Company continues to seek ways to mitigate any capacity and shaping limitations and to recover any business losses. The full impact of the Swift power canal outage and plans for repair of the Swift No. 2 facility are still being determined. The Company is seeking reimbursement from Cowlitz 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 8 - Income Taxes

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

The Company accrued federal and state income tax expense of $48.4 million and $19.6 million, representing effective tax rates of 43.3% and 34.3%, for the three months ended June 30, 2003 and 2002, respectively. The increase in the estimated effective tax rate for the three months ended June 30, 2003 as compared to the three months ended June 30, 2002 is primarily due to higher levels of pre-tax income in the current period, which diluted the benefit of certain tax credits.

The Company has established, and periodically reviews, an estimated contingent tax reserve on its consolidated balance sheet to provide for the possibility of adverse outcomes in tax proceedings. No events have occurred during the three months ended June 30, 2003 that materially impact the Company’s estimate of the contingent liability recorded as of March 31, 2003. During the three months ended June 30, 2003, the tax contingency reserve was increased by $3.4 million primarily to accrue interest on tax contingencies provided for in prior periods.

NOTE 9 - Comprehensive Income

The components of comprehensive income are as follows:

	Three Months Ended June 30,
(Millions of dollars)	2003		2002
Net income	$	62.6	$	35.6
Other comprehensive income:
Unrealized gain on available-for-sale securities, net of taxes: $2.4/2003 and $0.2/2002		2.7		0.4
Total comprehensive income	$	65.3	$	36.0

NOTE 10 - New Accounting Standards

In January 2003, the FASB issued FASB Interpretation No. 46, Consolidation of Variable-Interest Entities (“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. FIN No. 46 applies immediately to variable-interest entities created after January 31, 2003 and applies for periods beginning after June 15, 2003, to variable-interest entities acquired before February 1, 2003. The Company is currently evaluating the impact of adopting FIN No. 46 on its consolidated financial position and results of operations.

In April 2003, the FASB issued SFAS No. 149, Amendment of Statement 133 on Derivative Instruments and Hedging Activities (“SFAS No. 149”). This statement amends and clarifies financial reporting for derivative instruments, including certain derivative instruments embedded in other contracts and for hedging activities. This

14

statement is effective for contracts entered into or modified after June 30, 2003. The Company is currently evaluating the impact of adopting this statement on its consolidated financial position and results of operations.

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 is effective for financial instruments entered into or modified after May 31, 2003, and otherwise is effective at the beginning of the first interim period beginning after June 30, 2003. The Company will be reclassifying Preferred stock subject to mandatory redemption and Guaranteed preferred beneficial interest in Company’s junior subordinated debentures to short-term and long-term liabilities on its Condensed Consolidated Balance Sheet. All associated dividends will be treated as interest expense.

In May 2003, the EITF issued EITF No. 00-21, Revenue Arrangements with Multiple Deliverables (“EITF No. 00-21”). 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 Company is currently evaluating the impact of adopting this issue on its consolidated financial position and results of operations.

In June 2003, the FASB issued guidance under Issue C20 that amended SFAS No.133, Interpretation of the Meaning of Not Clearly and Closely Related in Paragraph 10(b) regarding Contracts with a Price Adjustment Feature. This statement amends and clarifies the normal purchases and normal sales exemption for financial reporting for derivative instruments, including certain derivative instruments embedded in other contracts and for hedging activities. This statement is effective on the first day of the first fiscal quarter beginning after July 10, 2003. The Company is currently evaluating the impact of applying this guidance on its consolidated financial position and results of operations.

NOTE 11 - 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.

NOTE 12 - Subsequent Events

On July 17, 2003, the Company’s Board of Directors declared a dividend on common stock of approximately $0.13 per share totaling $40.1 million and payable on August 27, 2003.

The Company called for redemption its two series of junior subordinated debentures, which will trigger the retirement of the PacifiCorp Capital I, Series A and PacifiCorp Capital II, Series B Preferred Securities totaling $352.0 million, plus accrued interest. The redemptions will occur in August 2003 and are expected to be funded initially through short-term debt. This amount will be classified as long-term debt based on management’s intent and the Company’s ability to support this debt on a long-term basis.

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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 June 30, 2003, and the related condensed consolidated statements of income and retained earnings for each of the three month periods ended June 30, 2003 and 2002 and the condensed consolidated statements of cash flows for the three month periods ended June 30, 2003 and 2002. These 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 condensed consolidated interim financial statements for them to be in conformity with accounting principles generally accepted in the United States of America.

We previously audited in accordance with auditing standards generally accepted in the United States of America, the consolidatedbalance sheet as of March 31, 2003, and the related statements of consolidated income, changes in common shareholder’s equity and cash flowsfor 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 consolidatedbalance sheet from which it has been derived.

The Company changed its method of accounting for derivative instruments as of April 1, 2001.

As discussed in Note 5 to the Condensed Consolidated Financial Statements, the Company changed its method of accounting for asset retirement obligations as of April 1, 2003.

PricewaterhouseCoopers LLP
Portland, Oregon

July 24, 2003

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ITEM 2.

MANAGEMENT’S DISCUSSION AND ANALYSIS OFFINANCIAL 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 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 2003 Annual Report on Form 10-K 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, fuel costs and other changes in operating costs, which could affect the Company’s cost recovery;

•

changing conditions in wholesale power 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 potentially serious impact on electric capacity and cost and on the Company’s ability to generate electricity;

•

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

•

the impact from the possible formation of a Regional Transmission Organization and the impact from 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;

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•

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

•

employee 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 and disruption or constraints to 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 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 outcome of general rate cases submitted for regulatory approval; 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 assumes no obligation 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’s earnings contribution on common stock for the three months ended June 30, 2003 was $60.8 million, as compared to $33.7 million for the three months ended June 30, 2002. Retail sales volumes, driven by an increase in temperatures and an increase in customers, were 4.6% higher than the prior year period. Output from the Company’s thermal facilities increased by 811,335 MegaWatt-hours (“MWh”), or 7.6%, as a result of improved operating performance, as well as increases from new plant additions. Output from the Company-owned hydroelectric facilities was lower by 194,792 MWh, or 16.4%, as a result of reduced levels of precipitation and snowpack. This trend in hydroelectric output is expected to continue for the three months ended September 30, 2003.

In the wholesale markets in which the Company operates, both electricity and gas prices were above levels experienced in the prior year period. Natural gas prices were more than $2.00 per mmbtu (million British thermal units) higher mainly as a result of low natural gas inventories, as well as natural gas supply and demand concerns. This increase, when combined with below normal hydroelectric conditions, resulted in electricity prices that were approximately $15.00 per MWh higher than prior year period levels. The Company continues to take actions to maintain a balanced net energy position.

As discussed in ITEM 5. OTHER INFORMATION, the Company has general rate cases pending in Utah, Oregon, Wyoming and California. The total of these requests will not be finalized until the Utah detailed filing is made in July 2003, but the total is expected to be approximately $240.0 million. These increases are sought to recover rising costs, including insurance premiums, pension expense and health care, along with a return on equity

18

of 11.5% in all cases. These cases should be finalized by March 2004. As with any general rate case, the outcome of these requests is uncertain.

COMPARISON OF THE THREE MONTHS ENDED JUNE 30, 2003 and 2002

REVENUES

(Millions of dollars)	Three Months Ended June 30,				Change			% Change
	2003		2002		Favorable/(Unfavorable)
Residential	$	227.2	$	205.1	$	22.1		10.8	%
Commercial		199.2		186.1		13.1		7.0
Industrial		177.4		166.9		10.5		6.3
Other retail revenues		8.7		8.3		0.4		4.8
Retail sales		612.5		566.4		46.1		8.1
Wholesale sales		253.6		293.5		(39.9	)	(13.6	)
Other revenues		28.7		25.7		3.0		11.7
Total Revenues	$	894.8	$	885.6	$	9.2		1.0
Energy sales (Millions of kWh)
Residential		3,253		2,939		314		10.7
Commercial		3,522		3,380		142		4.2
Industrial		4,676		4,609		67		1.5
Other		158		175		(17	)	(9.7	)
Retail sales		11,609		11,103		506		4.6
Wholesale sales		6,640		9,982		(3,342	)	(33.5	)
Total		18,249		21,085		(2,836	)	(13.5	)
Average residential usage (kWh)		2,463		2,266		197		8.7
Total customers - end of period (In thousands)		1,545		1,520		25		1.6

Residential revenues for the three months ended June 30, 2003 increased $22.1 million, or 10.8%, from the three months ended June 30, 2002 primarily due to increases of $19.2 million from higher average estimated customer usage, including a change in the calculation of unbilled revenues and the impact of warmer weather, and $3.6 million relating to growth in the average number of residential customers, mainly in Utah and Oregon. These increases were partially offset by a decrease of $0.7 million due to lower prices, mainly in Oregon.

Commercial revenues for the three months ended June 30, 2003 increased $13.1 million, or 7.0%, from the three months ended June 30, 2002 primarily due to increases of $6.1 million from higher average estimated customer usage, including a change in the calculation of unbilled revenues. Growth in the average number of commercial customers increased revenues $3.8 million and higher prices, mainly in Utah, increased revenues by $3.4 million.

Industrial revenues for the three months ended June 30, 2003 increased $10.5 million, or 6.3%, from the three months ended June 30, 2002 primarily due to an $8.6 million increase resulting from higher prices, mainly in Idaho, and a $1.9 million increase due to higher average estimated customer usage, including a change in the calculation of unbilled revenues.

Wholesale sales for the three months ended June 30, 2003 decreased $39.9 million, or 13.6%, from the three months ended June 30, 2002, primarily due to a reduction in volumes of 33.5%, the impact of which was $63.9 million. The majority of this reduction was in short-term and spot market sales, which were 38.4% lower than the prior year period. A similar volume reduction is reflected in the Company’s Purchased electricity expense. Offsetting this volume reduction, the Company achieved an increase of 29.9% on prices realized as compared to those in the three months ended June 30, 2002, the impact of which was $24.0 million. The primary factors contributing to higher market electricity prices in the Western United States (“U.S.”) during the three months ended June 30, 2003 were an increase in the market price of natural gas and a reduction in hydroelectric generation.

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Other revenues for the three months ended June 30, 2003 increased $3.0 million, or 11.7%, from the three months ended June 30, 2002 primarily due to $3.9 million and $2.4 million of revenue reductions in the prior year period relating to Demand side management and an alternative form of regulation process in Oregon, respectively. These favorable variances were partially offset by a $2.7 million decrease in revenue from the conclusion of the amortization of a regulatory liability.

See Part II - Item5. OTHER INFORMATION for information regarding recent developments in regulatory issues affecting the Company.

OPERATING EXPENSES

Purchased electricity expense for the three months ended June 30, 2003 decreased $50.5 million, or 16.0%, from the three months ended June 30, 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 49.1% with a resulting reduction in purchased electricity expense of $208.8 million. Partially offsetting this reduction was a 29.1% 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 Purchase electricity expense of $88.4 million. Long-term purchase volumes increased $71.8 million, or 26.3%, primarily from increases on exchange contracts. Costs relating to weather derivatives increased Purchased electricity expense by $2.7 million compared to the three months ended June 30, 2002. Wheeling expense decreased $7.3 million as a result of the lower volumes. Demand side management costs and other fees increased Purchased electricity expense by $2.3 million.

Fuel expense for the three months ended June 30, 2003 increased $19.4 million, or 19.9% from the three months ended June 30, 2002. Increased thermal generation volumes of 7.6% resulted in increased costs of $11.1 million, of which $3.5 million was due to increases in coal volumes, $1.4 million was due to increases in natural gas volumes, $3.3 million was due to the impact from the Company’s Gadsby peaking plant and $2.9 million was due to the impact of the West Valley plant, neither of which was fully operational in the prior year period. Coal prices increased slightly by $0.2 million, but were offset by a 25.5% decrease in contracted natural gas prices paid, resulting in a benefit of $1.4 million. The remaining cost increase of $9.5 million relates to the net impact of a regulatory deferral for the Trail Mountain coal mine that reduced fuel costs in the three months ended June 30, 2002.

Other operations and maintenance expense for the three months ended June 30, 2003 increased $2.1 million, or 1.4%, from the three months ended June 30, 2002 primarily due to a $5.3 million increase in employee related expenses due in part to higher pension costs and changes in the level and timing of capitalized costs. In addition, rent expense increased $3.7 million due to the West Valley plant, which was not fully operational in the prior year period. These increases were partially offset by the establishment of a $7.0 million reserve for California exposures recorded in the prior year period.

Depreciation and amortization expense for the three months ended June 30, 2003 decreased $2.3 million, or 2.2%, from the three months ended June 30, 2002 primarily due to a new depreciation study approved by regulators as discussed in ITEM 1. FINANCIAL INFORMATION – NOTE 2, which was partially offset by the effect of increased plant in service.

Administrative and general expenses for the three months ended June 30, 2003 decreased $6.9 million, or 9.0%, from the three months ended June 30, 2002. The prior year period included $5.3 million in severance accruals relating to a Company mining operation. In addition, contract services for the three months ended June 30, 2002 were $4.1 million higher due to additional consulting and outside services. Partially offsetting these decreases was a $2.7 million increase in insurance reserves.

Taxes, other than income taxes, for the three months ended June 30, 2003 increased $0.9 million, or 3.9%, from the three months ended June 30, 2002, primarily due to higher franchise tax expense.

The Unrealized gain on Statement of Financial Accounting Standards (“SFAS”) No. 133, Accounting for Derivative Instruments and Hedging Activities (“SFAS No. 133”), derivative instruments for the three months ended June 30, 2003 was $1.5 million compared to a loss of $2.2 million for the three months ended June 30, 2002 primarily due to an increase in the number of contracts being marked through the Condensed Consolidated Statements of Income and Retained Earnings.

20

INTEREST EXPENSE AND OTHER (INCOME) EXPENSE

Interest expense decreased $2.9 million, or 4.5%, primarily due to lower average debt balances.

Interest income decreased $1.9 million, or 30.2%, primarily due to lower interest income on regulatory assets.

Minority interest expense and other decreased $3.5 million, or 37.2%, partially due to a $3.4 million expense recorded in the prior year period for the reversal of a previously recorded gain in accordance with a regulatory order.

INCOME TAX EXPENSE

Income tax expense increased $28.8 million principally due to the higher pre-tax income in the current period. The estimated effective tax rate for the three months ended June 30, 2003 was 43.3% compared to a 34.3% estimated effective tax rate for the three months ended June 30, 2002. The increase in the estimated effective tax rate is primarily due to higher levels of pre-tax income in the current period, which diluted the benefit of certain 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 (“SFAS No. 143”) during the three months ended June 30, 2003. The Company recorded a $1.9 million after-tax loss from the implementation of revised Issue C15 and Issue C16 during the three months ended June 30, 2002.

LIQUIDITY AND CAPITAL RESOURCES

OPERATING ACTIVITIES

Net cash flows provided by operating activities were $151.6 million for the three months ended June 30, 2003 compared to $132.1 million for the three months ended June 30, 2002 due primarily to an increase in overall earnings and the timing of collections and payments.

INVESTING ACTIVITIES

Capital spending totaled $157.6 million for the three months ended June 30, 2003 compared to $131.0 million for the three months ended June 30, 2002. Current year capital spending is in line with the construction program outlined in the Company’s 2003 Annual Report on Form 10-K. The increase was primarily due to expenditures for network growth and system upgrades. Proceeds from sales of assets for the three months ended June 30, 2002 represented sales of utility properties.

FINANCING ACTIVITIES

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 having a three-year term that became effective June 4, 2002 and the other facility for $500.0 million having 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 LIBOR plus a margin that varies based on the Company’s credit ratings. In addition to these committed credit facilities, the Company had $91.5 million in money market accounts included in Cash and cash equivalents at June 30, 2003 available to meet its liquidity needs.

The Company redeemed $7.5 million of preferred stock during both three month periods ended June 30, 2003 and 2002.

The Company declared and paid dividends of $40.1 million on common stock, and paid dividends of $1.8 million on preferred stock during the three months ended June 30, 2003. The Company declared dividends of $1.8 million on preferred stock on May 22, 2003, which are payable on August 15, 2003. On July 17, 2003, the Company’s Board of Directors declared a dividend on common stock of approximately $0.13 per share totaling $40.1 million and payable on August 27, 2003.

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During June 2003, the Company notified holders of its intent to redeem first mortgage bonds totaling $57.5 million aggregate principal amount plus redemption premium of $1.6 million and accrued interest. These retirements will occur in July 2003 and August 2003 and are expected to be funded initially through short-term debt or available cash. The Company continues to classify this debt as long-term based on management’s intent and the Company’s ability to support this debt on a long-term basis.

The Company called for redemption of the two series of junior subordinated debentures, which will trigger the retirement of the PacifiCorp Capital I, Series A and PacifiCorp Capital II, Series B Preferred Securities totaling $352.0 million, plus accrued interest. The redemptions will occur in August 2003 and are expected to be funded initially through short-term debt. Following the retirement, this amount will be classified as long-term debt based on management’s intent and the Company’s ability to support this debt on a long-term basis.

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 adequately fund itself and expects to be able to continue to do so, further negative events by other industry participants may make it more difficult and expensive for the Company to obtain necessary financing or replace financing agreements at their maturity.

CREDIT RATINGS

The Company’s credit ratings at June 30, 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

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

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.

CAPITALIZATION

At June 30, 2003, PacifiCorp had $55.0 million of commercial paper outstanding at a weighted average interest rate of 1.3%. These borrowings and other financing arrangements are supported by revolving credit agreements and cash on hand as described above.

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 ITEM7A. 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 – FEDERAL ENERGY REGULATORY COMMISSION 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 changes in energy and air quality laws. Energy legislation passed by the U.S. House of Representatives and now pending in the Senate would make some changes in federal law that would affect the

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Company. Those changes may include measures affecting the hydroelectric relicensing process under the Federal Power Act and extension of the renewable energy production tax credit, which would likely benefit the Company’s efforts to develop, acquire and maintain a low-cost generation portfolio. Changes to the Clean Air Act, contemplated by the proposed Clear Skies Act, are being monitored closely by the Company, as they may affect control requirements for several emissions from fossil-fueled generation plants.

The laws of the states in which the Company operates affect the Company’s generation, transmission and distribution business. All but two of the legislatures monitored by the Company have concluded their regular business for the year. The legislative session in Oregon is expected to continue into August 2003, though legislators are focused almost exclusively on budget and tax bills. While the Company may be affected by changes in Oregon tax law enacted in the current legislative session, the Company cannot assess at this time what impacts, if any, may ultimately be borne by the Company and its customers. The California Legislature continues to address both fiscal and policy matters. As in Oregon, California tax law changes may be adopted, but it is not possible to predict which proposals may become law. Each chamber of the General Assembly has taken up competing bills to revise the state’s electric industry restructuring law (AB 1890). The chambers’ bills are substantially different and it is impossible to determine what, if any, legislation will ultimately be enacted. The Company is monitoring the progress of these bills.

In February 2003, the Oregon Public Power Coalition submitted a petition to Multnomah County, Oregon, calling for an election to form a government-owned and operated electric utility in the county. On June 12, 2003, the Multnomah County Commission voted to place the Public Utility District measure on the November 2003 ballot as required by state statute. If approved by the voters, the measure would result in the formation of a public utility district and could result in condemnation of the Company’s property in Multnomah County, Oregon, making that property part of a government-owned and operated utility. The Company serves 68,000 homes and businesses in the county, which represents approximately 1.9 million MWh, or $108.1 million in annual revenues. The Company is vigorously opposing this action.

Security Risk

The emergence of terrorism threats, both domestic and foreign, is a risk to the entire utility industry, including the Company. The Company’s current comprehensive security project has identified critical assets as part of a risk mitigation program for both cyber and physical security. A program has been implemented that identified critical business processes, created and implemented business continuity plans and is developing additional alternate processing locations for key business areas. The Company has identified critical physical assets and has created a plan to retrofit the sites with enhanced security controls. In conjunction with North American Electric Reliability Council’s Urgent Action Standard for cyber and physical security, the Company is conducting a gap analysis and is implementing changes to standardize security controls that are in line with the standard. The Company is also tracking the evolution of security standards that may be promulgated by the FERC.

Market Risk

Coal - The Company operates several thermal generation plants in Utah. A Company mine provides almost 50.0% 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 from 25 million tons in calendar 2002 to approximately 19.5 million tons in calendar 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 long-term coal prices. The Company will continue to evaluate its fueling options. Recovery of all costs incurred to fuel the Company’s generating plants will be requested in rate filings with the regulatory commissions.

Natural Gas - There has been recent interest and concern at the national level regarding natural gas supply relative to demand. Energy experts, including representatives from the FERC, the National Association of Regulatory Utility Commissioners and the Federal Reserve Bank of Dallas, will convene an August 2003 meeting to discuss the economic impact of a major supply deficiency extending beyond the spot market. Natural gas price and supply concerns at the national level are generally focused on natural gas demand and storage capability for the peak winter periods.

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Recently, the Company purchased, under fixed price terms, its forecasted natural gas supply needs for the Company’s gas fired electric generation through calendar year 2005. Analysis and planning for long-term acquisitions or long-term supply contracts are also underway.

Credit Risk

On July 8, 2003, PG&E National Energy Group, Inc., (“NEG”), PG&E Energy Trading Holdings Corporation (“PG&E ET”) and PG&E ET subsidiaries filed petitions for protection under Chapter 11 of the federal bankruptcy code. While PacifiCorp does not have direct exposure to any of the NEG entities that have filed for bankruptcy protection, the Company, in a joint ownership arrangement with a subsidiary of NEG, Larkspur, has a 50.0% ownership interest in the Hermiston Generating Company (“HGC”). HGC owns and operates a 452 aMW (average MegaWatt) gas fired power plant located in Hermiston, Oregon. Currently, 100.0% of the power generated by this facility is delivered to the Company. Given the current HGC ownership structure, and the fact that NEG has not included Larkspur in its bankruptcy filing, the Company does not expect any change in the current operating arrangement between itself and HGC. The Company has provided surety to replace expiring letters of credit and other credit support that are part of the facility’s financing and other arrangements.

RISK MEASUREMENT

Interest Rate Exposure

The Company’s risk to 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 discussed below for exposure to interest rate fluctuations 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 from changes in market conditions and does not purport to represent actual losses (or gains) in fair value that may be incurred by the Company.

The table below shows the potential loss in fair market value (“FMV”) of the Company’s interest-rate-sensitive positions, as of March 31, 2003 and June 30, 2003, as well as the Company’s quarterly high and low potential losses.

	Confidence Interval		Time Horizon	March 31, 2003			2004 Quarterly						June 30, 2003
(Millions of dollars)							High			Low
Interest-Rate-Sensitive Portfolio - FMV	95.0	%	1 Day	$	(18.2	)	$	(27.7	)	$	(18.2	)	$	(27.7	)

The increase in potential loss in fair market value from March 31, 2003 to June 30, 2003 was primarily due to an increase in interest rate volatility.

Commodity Price Exposure

The Company’s market risk to commodity price change is primarily related to its fuel and electricity commodities, which are subject to fluctuations due to unpredictable factors, such as weather, which impacts energy supply and demand. The Company’s energy purchase and sales activities are governed by the Company’s risk management policy and the risk levels established as part of that policy. For a complete discussion 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 utilizing 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 forward time period. The VaR model is a risk analysis tool that attempts to measure the potential change in fair value, earnings or cash flow from changes in market conditions and does not purport to represent actual losses (or gains) in fair value that may be incurred by the Company.

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As of June 30, 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 $12.8 million, as compared to $16.4 million as of June 30, 2002. The average daily VaR (five-day holding period and to a 99.0% confidence level) for the quarter ended June 30, 2003 was $15.9 million. The maximum and minimum VaR measured during the quarter ended June 30, 2003 was $ 23.2 million and $9.4 million, respectively. The Company maintained compliance with its VaR limit procedures during the quarter ended June 30, 2003. Changes in markets inconsistent with historical trends or assumptions used could cause actual results to exceed predicted limits. Market values associated with derivative commodity instruments held for purposes of economic hedging and balancing the Company’s energy commodity portfolio risk, but accounted for at fair market value, were not material as of June 30, 2003.

FAIR VALUE OF DERIVATIVES

Statement of Financial Accounting Standards (“SFAS”) No. 133, Accounting for Derivative Instruments and Hedging Activities (“SFAS No. 133”) requires all derivatives, as defined by the standard, to be marked to market value, except those which qualify for specific exemption under the standard or associated Derivatives Implementation Group guidance, such as those defined as normal purchases and normal sales. The derivatives that are marked to market value 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 June 30, 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		3.3
Changes in valuation assumptions (a)		(68.5	)
Changes in fair values (b)		27.2
Fair value of contracts outstanding at the end of the period (c)	$	(543.7	)

(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 $546.4 million in net regulatory assets, as authorized by regulatory orders received, 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 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 June 30, 2003, the net value of these instruments was a liability of $6.4 million.

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The following discloses summarized information with respect to valuation techniques and contractual maturities of the Company’s energy-related contracts qualifying as derivatives under SFAS No. 133 as of June 30, 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 based on models and other valuation methods	$	22.0	$	5.3	$	(53.1	)	$	(517.9	)	$	(543.7	)

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.

FEDERAL ENERGY REGULATORY COMMISSION ISSUES

California Refund Case

On December 12, 2002, an administrative law judge (“ALJ”) issued a Certification of Proposed Findings on California Refund Liability in which the ALJ preliminarily determined that $1.2 billion was still owed to suppliers by the California Independent System Operators’ (the “Cal ISO”) and the California Power Exchange (the “CPX”), which amount was calculated by offsetting a $1.8 billion refund against the $3.0 billion owed to suppliers. In its findings, the FERC adopted recommendations from the final report of the FERC’s staff on price manipulation in the western markets (“Staff’s Final Report”), including a new proxy for natural gas prices, which could increase the amount of refunds, if any, owed by all parties. The FERC expects that refunds will be distributed by the end of summer 2003. The Company’s level of exposure to refunds is dependent upon any final order issued by the FERC in response to the outcome of these proceedings. The Company has established a reserve of approximately $17.7 million for any refunds owed as a result of this FERC 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. Requests for a rehearing and appeals of this decision are likely.

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FERC Show-Cause Orders

In May 2002, the Company responded to data requests from the FERC regarding trading practices connected with the power 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. The Staff’s Final Report recommends that the FERC issue show-cause orders to numerous market participants, including the Company, requiring them to demonstrate why their behaviors did not violate the Cal ISO and CPX tariffs as part of the ongoing FERC trading practices investigation. 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 power market, as defined in the Cal ISO and CPX tariffs. In setting the cases for hearing, the Commission directed the ALJ 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. Responses to the show-cause orders are due to the FERC by September 2, 2003.

Federal Power Act Section 206 Case

On June 25, 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 power suppliers. On July 3, 2003, the Company filed a petition for review of certain aspects of this order in the Ninth Circuit Court of Appeals. The Company also plans to seek rehearing of this order at the FERC.

REGULATORY ACTIONS

Utah

The Company commenced a general rate case on May 15, 2003 based on the year ended March 31, 2003 and including known and measurable changes that will occur by January 1, 2004. The initial filing included a projected revenue requirement increase of $125.0 million that serves as a cap on the amount the Company can receive in the case. A subsequent detailed filing will be made in July 2003 identifying the final requested amount under this cap. If approved, the effective date of the increase would be January 1, 2004, with cash collections beginning April 1, 2004.

Oregon

Settlement discussions are in process with respect to the Company’s general rate case filed on March 18, 2003 for an annual increase of $57.9 million to take effect in January 2004.

In November 2000, the Company made a deferred accounting filing to track its excess net power costs. On July 18, 2002, the Oregon Public Utility Commission (the “OPUC”) approved the filing, finding that the Company had prudently incurred the excess net power costs. On June 17, 2003, the Industrial Customers of Northwest Utilities (the “ICNU”) and the Citizens’ Utility Board (the “CUB”) appealed to the Oregon Court of Appeals the March 26, 2003 decision of the Marion County, Oregon Circuit Court that affirmed the OPUC July 18, 2002 order.

The Company continues to pursue its October 2, 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. Oral argument was held before the appellate court on July 8, 2003.

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 authorized by the Wyoming Public Service Commission (the “WPSC”) in December 2000, for $60.3 million. 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 for rehearing of the decision on April 4, 2003. After a public deliberation on May 30, 2003, the WPSC denied the petition and directed the preparation of an order consistent with its decision. The order denying rehearing was issued on July 15, 2003. The Company is considering its legal and appellate options.

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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 ROE to 11.5% to compensate the Company for general risks relating to the western U.S. utility environment, as well as some additional risks relating to multijurisdictional operations. The Company has requested an increase of $41.8 million, or 13.1%, in base rates to take effect in March 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 prior to 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, to allow the Company to file a general rate case, which is currently restricted through December 2005. Through March 31, 2003, the deferral is expected to total $12.2 million. Hearings were held March 20-24, 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 will allow the Company to file a general rate case anytime before July 2005 that addresses the level of prices needed to cover all ongoing costs to serve Washington customers.

California

On June 19, 2003, the Company and the California Office of Rate Payer Advocates signed a settlement in principle regarding revenue requirements in the Company’s pending general rate case. If the agreement is approved, the Company would be allowed to recover approximately $2.8 million in addition to the amount collected through the interim increase approved by the California Public Utilities Commission in June 2002. A hearing was held on June 23, 2003 to address the settlement agreement and to introduce testimony and other exhibits into the record. A second stipulation was signed in early July 2003 by all parties in the case to settle customer class cost allocation and rate design issues. An additional hearing was held on July 21, 2003, to consider this second stipulation.

INTEGRATED RESOURCE PLAN

The Company’s Integrated Resource Plan (“IRP”) was filed with the relevant state commissions on January 24, 2003. The IRP is a regulatory requirement in all states in which the Company operates, with the exception of Wyoming. The IRP has been acknowledged in Utah and Idaho, and the Company filed for an exemption in California. On July 2, 2003, the OPUC staff issued final comments, recommendations and a draft order on the IRP. The WUTC has also indicated that it expects to come to a decision on acknowledgement in late August 2003.

The Company has segregated the IRP supply-side action items into a series of four separate Request for Proposals (“RFPs”). Each RFP focuses on a specific category of supply-side resources and provides for the staged procurement of resources in future years in order to achieve load/resource balance. The first of these four RFPs was issued on June 6, 2003 and responses were received on July 22, 2003. The expected total cycle time for each RFP process is approximately six months. Approval for resources procured via the first RFP effort is expected toward the end of calendar year 2003.

In addition to the four supply-side RFPs, the Company issued a separate RFP for the demand-side resources called for in the IRP. The demand-side RFP requested 100.0 MegaWatt or more of conservation to be obtained over the next 10 years and load control proposals specifically addressing peak load. The RFP was issued on June 26, 2003, with responses due on August 18, 2003.

On March 6, 2003, the Utah Public Service Commission opened a docket to consider adopting competitive bidding rules governing the acquisition of generating resources and/or specific affiliate interest rules. The parties initially focused on competitive bidding rules and are now contemplating the extent to which affiliate interest rules should be studied.

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ITEM 6.

EXHIBITS AND REPORTS ON FORM 8-K

(a)  Exhibits.

4.1	Fifteenth Supplemental Indenture to Mortgage and Deed of Trust
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

(b)  Reports on Form 8-K.

None.

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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:  July 28, 2003	By:	/s/ RICHARD D. PEACH
		Richard D. Peach Chief Financial Officer

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