PACIFICORP /OR/ - Quarter Report: 2003 September (Form 10-Q)

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

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

For the quarterly period ended September 30, 2003

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

For the transition period from _______________ to _______________

Commission file number 1-5152

PacifiCorp

(Exact name of registrant as specified in its charter)

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

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

825 N.E. Multnomah Street,
Suite 2000, Portland, Oregon
(Address of principal executive offices)

97232-4116
(Zip Code)

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

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

YES x NO o

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

YES o NO x

As of November 6, 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 (Unaudited)

	Condensed Consolidated Statements of Income and Retained Earnings	2

	Condensed Consolidated Statements of Cash Flows	3

	Condensed Consolidated Balance Sheets	4

	Notes to the Condensed Consolidated Financial Statements	6

	Report of Independent Accountants	18

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

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	28

Item 4.	Controls and Procedures	31

PART II.	OTHER INFORMATION

Item 5.	Other Information	32

Item 6.	Exhibits and Reports on Form 8-K	37

SIGNATURE

PART I. FINANCIAL INFORMATION

ITEM 1.

FINANCIAL STATEMENTS

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

	Three Months Ended September 30,						Six Months Ended September 30,

(Millions of dollars)	2003			2002			2003			2002

Revenues	$	958.0		$	943.9		$	1,852.8		$	1,829.5

Operating expenses
Purchased electricity		325.6			358.7			591.6			675.2
Fuel		132.2			133.2			248.9			230.5
Other operations and maintenance		155.0			129.8			305.9			280.1
Depreciation and amortization		106.1			108.5			210.2			214.9
Administrative and general		48.1			61.7			114.1			133.1
Taxes, other than income taxes		24.2			25.3			47.9			48.1
Unrealized loss (gain) on derivative contracts		4.7			(5.3	)		3.2			(3.1	)

Total		795.9			811.9			1,521.8			1,578.8
Other operating expense		12.8			—			12.8			—

Income from operations		149.3			132.0			318.2			250.7

Interest expense and other (income) expense
Interest expense		62.5			80.6			123.6			144.6
Interest income		(3.6	)		(3.1	)		(8.0	)		(9.4	)
Interest capitalized		(6.5	)		(4.4	)		(12.1	)		(9.9	)
Minority interest and other		1.4			5.7			7.3			15.1

Total		53.8			78.8			110.8			140.4

Income from operations before income taxes and cumulative effect of accounting change		95.5			53.2			207.4			110.3
Income tax expense		36.4			21.7			84.8			41.3

Income before cumulative effect of accounting change		59.1			31.5			122.6			69.0
Cumulative effect of accounting change (less applicable income tax benefit: $(0.6)/2003 and $(1.1)/2002) (See Notes 3 and 5)		—			—			(0.9	)		(1.9	)

Net income		59.1			31.5			121.7			67.1
Preferred dividend requirement		(0.5	)		(1.8	)		(2.3	)		(3.7	)

Earnings on common stock	$	58.6		$	29.7		$	119.4		$	63.4

RETAINED EARNINGS BEGINNING OF PERIOD	$	326.6		$	206.8		$	305.9		$	173.1
Net income		59.1			31.5			121.7			67.1
Cash dividends declared
Preferred stock		(0.5	)		(1.8	)		(2.3	)		(3.7	)
Common stock		(40.2	)		—			(80.3	)		—

RETAINED EARNINGS END OF PERIOD	$	345.0		$	236.5		$	345.0		$	236.5

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

PACIFICORP
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)

	Six Months Ended September 30,

(Millions of dollars)	2003			2002

Cash flows from operating activities
Net income	$	121.7		$	67.1
Adjustments to reconcile net income to net cash provided by operating activities:
Cumulative effect of accounting change, net of tax		0.9			1.9
Unrealized loss (gain) on derivative contracts		3.2			(3.1	)
Depreciation and amortization		210.2			214.9
Deferred income taxes and investment tax credits - net		24.2			(12.8	)
Provision for pension and benefits		(2.5	)		(14.3	)
Deferred net power costs		(7.2	)		(23.2	)
Changes in other regulatory assets/liabilities		71.0			71.8
Accounts receivable and prepayments		(33.5	)		5.9
Inventories		12.8			(2.8	)
Accounts payable and accrued liabilities		(76.2	)		(113.0	)
Other		11.1			7.7

Net cash provided by operating activities		335.7			200.1

Cash flows from investing activities
Capital expenditures		(309.9	)		(253.1	)
Proceeds from sales of assets		1.3			9.8
Proceeds from available for sale securities		64.7			74.6
Purchases of available for sale securities		(63.2	)		(75.1	)
Other		(5.3	)		2.7

Net cash used in investing activities		(312.4	)		(241.1	)

Cash flows from financing activities
Changes in short-term debt		65.0			76.5
Proceeds from long-term debt, net of issuance costs		397.0			—
Dividends paid		(83.8	)		(3.8	)
Repayments of long-term debt		(140.0	)		(130.4	)
Repayments of preferred securities		(352.0	)		—
Redemptions of preferred stock		(7.5	)		(7.5	)
Other		(0.4	)		—

Net cash used in financing activities		(121.7	)		(65.2	)

Decrease in cash and cash equivalents		(98.4	)		(106.1	)
Cash and cash equivalents at beginning of period		152.5			157.9

Cash and cash equivalents at end of period	$	54.1		$	51.7

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

PACIFICORP
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)

ASSETS

(Millions of dollars)	September 30, 2003			March 31, 2003

Current assets
Cash and cash equivalents	$	54.1		$	152.5
Accounts receivable (less allowance for doubtful accounts: $41.1/September and $36.3/March)		251.1			250.7
Unbilled revenue		135.0			109.2
Amounts due from affiliates		2.7			2.5
Inventories at average cost
Materials and supplies		98.3			99.4
Fuel		60.1			71.8
Current derivative contract asset		88.4			107.2
Other		25.9			18.9

Total current assets		715.6			812.2

Property, plant and equipment		13,464.7			13,184.3
Construction work in progress		366.0			332.5
Accumulated depreciation and amortization		(4,987.5	)		(5,483.2	)

Total property, plant and equipment - net		8,843.2			8,033.6

Other assets
Regulatory assets		1,128.7			1,175.9
Derivative contract regulatory asset		601.7			506.9
Noncurrent derivative contract asset		138.6			122.3
Deferred charges and other		354.1			342.1

Total other assets		2,223.1			2,147.2

Total assets	$	11,781.9		$	10,993.0

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

PACIFICORP
CONDENSED CONSOLIDATED BALANCE SHEETS, continued
(Unaudited)

LIABILITIES AND SHAREHOLDERS’ EQUITY

(Millions of dollars)	September 30, 2003			March 31, 2003

Current liabilities
Long-term debt currently maturing	$	243.5		$	136.7
Preferred stock subject to mandatory redemption, currently maturing (See Note 7)		3.8			—
Notes payable and commercial paper		90.0			25.0
Accounts payable		207.9			235.8
Amounts due to affiliates		25.5			39.6
Accrued employee expenses		108.0			137.6
Taxes payable		83.8			66.9
Interest payable		66.6			67.9
Current derivative contract liability		105.5			91.7
Other		111.9			127.3

Total current liabilities		1,046.5			928.5

Deferred credits
Income taxes		1,498.8			1,480.2
Investment tax credits		87.6			91.4
Regulatory liabilities		815.1			137.0
Noncurrent derivative contract liability		725.2			643.5
Other		703.4			650.1

Total deferred credits		3,830.1			3,002.2

Long-term debt, net of current maturities		3,570.5			3,417.6
Preferred stock subject to mandatory redemption (See Note 7)		56.2			—

Total liabilities		8,503.3			7,348.3

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

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

Shareholders’ equity
Preferred stock		41.3			41.3
Common shareholder’s capital		2,892.1			2,892.1
Retained earnings		345.0			305.9
Accumulated other comprehensive income (loss):
Unrealized gain (loss) on available for sale securities, net of tax of $0.9/September and $(1.1)/March		1.6			(1.7	)
Minimum pension liability, net of tax of $(0.8)		(1.4	)		(1.4	)

Total shareholders’ equity		3,278.6			3,236.2

Total liabilities and shareholders’ equity	$	11,781.9		$	10,993.0

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

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

NOTE 1 - Basis of Presentation and Certain Significant Accounting Policies

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

The accompanying unaudited condensed consolidated financial statements as of September 30, 2003 and for the periods ended September 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 in 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 September 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.

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

Stock-based compensation - As permitted by Statement of Financial Accounting Standards (“SFAS”) No. 123, Accounting for Stock-Based Compensation (“SFAS No. 123”), the Company has elected to account for its stock-based compensation arrangements under the intrinsic value recognition and measurement principles of Accounting Principles Board (“APB”) Opinion No. 25, Accounting for Stock Issued to Employees (“APB No. 25”), and related interpretations in accounting for employee stock options issued to Company employees. Under APB No. 25, because the exercise price of employee stock options equals the market price of the underlying stock on the date of grant, no compensation expense is recorded. All options are for Scottish Power plc (“ScottishPower”) American Depository Shares. 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 September 30,				Six Months Ended September 30,

(Millions of dollars)	2003		2002		2003		2002

Net income as reported	$	59.1	$	31.5	$	121.7	$	67.1
Stock-based employee compensation expense		0.2		0.4		0.4		1.0

Pro forma net income	$	58.9	$	31.1	$	121.3	$	66.1

Unbilled revenues - The Company changed its calculation of unbilled revenues during the three months ended June 30, 2003, which had the effect of increasing revenues by approximately $10.0 million and after-tax net income by approximately $5.7 million for the six months ended September 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. SFAS No. 71 provides that regulatory assets may be capitalized if it is probable that future revenue in an amount at least equal to the capitalized costs will result from the

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

Regulatory assets include the following:

(Millions of dollars)	September 30, 2003		March 31, 2003

Deferred taxes (a)	$	543.3	$	550.3
Minimum pension liability offset (b)		234.5		234.5
Deferred net power costs (c)		95.7		137.8
Transition Plan - retirement and severance (d)		49.4		55.1
Demand-side resource		44.0		45.7
Unamortized issuance expense on retired debt (e)		44.2		34.3
Various other		117.6		118.2

Subtotal		1,128.7		1,175.9
Derivative contracts (f)		601.7		506.9

Total	$	1,730.4	$	1,682.8

(a)

Excludes $87.6 million and $91.4 million as of September 30, 2003 and March 31, 2003, respectively, of investment tax credits.

(b)

At the date of the last actuarial evaluations, 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 increase of $234.5 million to Regulatory assets.

(c)

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

(d)

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

(e)

Represents the unamortized debt expense and redemption premiums on securities retired prior to maturity. During the three months ended September 30, 2003, the Company transferred $11.9 million to regulatory assets in relation to the redemption of First Mortgage Bonds and Preferred Securities. See Note 7.

(f)

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

Regulatory liabilities include the following:

(Millions of dollars)	September 30, 2003		March 31, 2003

Asset retirement removal costs - non SFAS No. 143 (a)	$	665.5	$	—
Centralia gain		57.7		66.5
Deferred taxes		36.9		39.3
Various other		55.0		31.2

Total	$	815.1	$	137.0

(a)

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

The Company evaluates the recovery of all regulatory assets periodically and as events occur. The evaluation includes the probability of recovery, as well as changes in the regulatory environment. Regulatory and/or legislative actions in Utah, Oregon, Wyoming, Washington, Idaho and California may require the Company to record regulatory asset write-offs and charges for impairment of long-lived assets in future periods.

DEPRECIATION RATE CHANGES

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

REGULATORY ACTIONS

Oregon

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

NOTE 3 - Derivative Instruments

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

The risk management process established by the Company is designed to identify, assess, monitor and manage each of the various types of risk involved in the Company’s business and activities; measure quantitative market risk exposure; and identify qualitative market risk exposure in its 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.

On April 1, 2001, the Company adopted SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities (“SFAS No. 133”), as amended by numerous interpretations of the Derivatives Implementation Group (the “DIG”) that are approved by the Financial Accounting Standards Board (the “FASB”). Subsequent revisions were made in SFAS No. 138, Accounting for Certain Derivative Instruments and Certain Hedging Activities, and SFAS No. 149, Amendment of Statement 133 on Derivative Instruments and Hedging Activities (“SFAS No. 149”), both of which have been adopted by the Company. Collectively, these statements are referred to as “SFAS No. 133.” Under SFAS No. 133, derivative instruments are recorded on the Condensed Consolidated Balance 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 most recent update, SFAS No. 149, was issued in April 2003. This statement amends and clarifies financial reporting for derivative instruments, including certain derivative instruments embedded in other contracts, and for hedging activities. This statement was effective for contracts entered into or modified after June 30, 2003. In applying this statement, the Company began marking to market certain transactions that were entered into after June 30, 2003 that, prior to the implementation of SFAS No. 149, would have been exempted as being normal. The implementation of SFAS No. 149 resulted in a pretax loss of $2.9 million for the three months ended September 30, 2003.

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

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

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 or traded and settlement is based on climatic or other physical variables. Therefore, on a periodic basis, the Company estimates and records a gain or loss in earnings corresponding to the total expected future cash flow from these contracts in accordance with the Emerging Issues Task Force (the “EITF”) No. 99-2, Accounting for Weather Derivatives. The unrealized loss recorded for these contracts was $1.7 million and $7.4 million for the six months ended September 30, 2003 and 2002, respectively.

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

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

Balance at March 31, 2003	$	(505.7	)	$	506.9		$	(0.5	)	$	0.7
Settlements		34.4			(34.3	)		—			0.1
Changes in valuation assumptions		(59.6	)		59.7			—			0.1
Changes in fair value		(72.8	)		69.4			1.3			(2.1	)

Balance at September 30, 2003	$	(603.7	)	$	601.7		$	0.8		$	(1.2	)

NOTE 4 – Related-Party Transactions

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

(Millions of dollars)	September 30, 2003		March 31, 2003

Amounts due from affiliated entities:
ScottishPower (a)	$	0.1	$	0.1
PHI subsidiaries (b)		2.6		2.4

	$	2.7	$	2.5

Amounts due to affiliated entities:
ScottishPower (c)	$	2.2	$	2.6
PHI subsidiaries (d)		23.3		37.0

	$	25.5	$	39.6

	Three Months Ended September 30,				Six Months Ended September 30,

(Millions of dollars)	2003		2002		2003		2002

Revenues from affiliated entities:
PHI subsidiaries (f)	$	0.8	$	1.4	$	1.8	$	2.5

Expenses incurred from affiliated entities:
ScottishPower (c)	$	1.8	$	2.6	$	3.7	$	4.9
PHI subsidiaries (g)		4.3		3.5		8.5		4.1

	$	6.1	$	6.1	$	12.2	$	9.0

Expenses recharged to affiliated entities:
ScottishPower (a)	$	0.1	$	0.2	$	0.4	$	0.3
PHI subsidiaries (b)		1.8		1.9		3.8		3.5

	$	1.9	$	2.1	$	4.2	$	3.8

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

(a)

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 $23.3 million and $37.0 million at September 30, 2003 and March 31, 2003, respectively. PHI is the tax-paying entity for the Company.

(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 billed to PPM Energy, Inc. (“PPM”), a subsidiary of PHI.

(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 six months ended September 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 1.2% and 1.9% for the six months ended September 30, 2003 and 2002, respectively.

NOTE 5 - Asset Retirement Obligations

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

The Company had been recording retirement obligations relating to reclamation, closure and removal costs before adoption of the standard. In addition, the Company records removal costs as a part of depreciation expense and accumulated depreciation in accordance with regulatory accounting requirements. As a result of adoption of the standard, the net difference between these previously recorded amounts that qualify as asset retirement obligations 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 environment in which the Company operates, it reclassified to Regulatory liabilities $653.3 million of removal costs recorded in accumulated depreciation that do not qualify as retirement obligations under SFAS No. 143. Accretion and depreciation expense in the first year of adoption are expected to be $8.1 million and $3.3 million, respectively.

The following table describes the changes to the Company’s asset retirement obligation liability for the six months ended September 30, 2003:

(Millions of dollars)
Liability recognized at adoption on April 1, 2003	$	196.4
Liabilities incurred (a)		4.9
Liabilities settled (b)		(6.7	)
Revisions in cash flow (c)		(0.2	)
Accretion expense		4.0

Asset retirement obligation at September 30, 2003	$	198.4

(a)

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

(b)

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

(c)

Results from changes in the mining plan for the Deer Creek coal mine.

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

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

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

NOTE 6 - Financing Arrangements

At September 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 $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 the London Interbank Offered Rate (LIBOR) plus a margin that varies based on the Company’s credit ratings. As of September 30, 2003, these facilities were fully available, and there were no borrowings outstanding.

NOTE 7 - Preferred Securities and Long-Term Debt

In May 2003, the FASB issued SFAS No. 150, Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity (“SFAS No. 150”). This statement affects the accounting for certain financial instruments that, under previous guidance, issuers could account for as equity. The new statement requires that those instruments be classified as liabilities. Most of this statement was effective for financial instruments entered into or modified after May 31, 2003, and otherwise was effective at the beginning of the first interim period beginning after June 30, 2003. The Company reclassified 600,000 shares, $100 stated value, of its $7.48 series Preferred stock subject to mandatory redemption to short-term and long-term liabilities on the Company’s Condensed Consolidated Balance Sheet, which were $3.8 million and $56.2 million, respectively, at September 30, 2003. Associated dividends declared for the three months ended September 30, 2003 of $1.1 million have been treated as interest expense.

The Company has mandatory redemption requirements on 37,500 shares of its $7.48 series Preferred stock on each June 15 from 2002 through 2006, with a non-cumulative option to redeem 37,500 shares on each June 15 from 2002 through 2006, in each case at $100 per share, plus accrued and unpaid dividends to the date of such redemption. All outstanding shares on June 15, 2007, are subject to mandatory redemption. Holders of Preferred stock subject to mandatory redemption are entitled to certain voting rights.

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

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

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

NOTE 8 - Commitments and Contingencies

The Company follows SFAS No. 5, Accounting for Contingencies, to determine accounting and disclosure requirements for contingencies. The Company operates in a highly regulated environment. Governmental bodies such as the Federal Energy Regulatory Commission (the “FERC”), the SEC, the Internal Revenue Service (the “IRS”), the 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. Various specialists inside and outside of the Company perform evaluations of these contingencies.

Litigation

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

California and Enron reserves

Beginning in summer 2000, market conditions in California resulted in defaults 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 previously provided reserves for its California exposures and its Enron receivable, net of the effect of applying the master netting agreement with Enron, in the aggregate amount of $14.3 million.

FERC issues

California Refund Case - The Company is a party to a FERC proceeding that is investigating potential refunds for energy transactions in the California Independent System Operator and the California Power Exchange markets during past periods of high energy prices. The Company previously established a reserve of $17.7 million for these refunds. The Company’s ultimate exposure to refunds is dependent upon any final order issued by the FERC in this proceeding.

Northwest Refund Case - On June 25, 2003, the FERC terminated its proceeding relating to the possibility of requiring refunds for wholesale spot-market bilateral sales in the Pacific Northwest between December 25, 2000 and June 20, 2001. The FERC concluded that ordering refunds would not be an appropriate resolution of the matter. On August 25, 2003, the FERC granted rehearing of its June 25, 2003 order.

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. On July 28, 2003, the Company filed its request for rehearing of the FERC’s order, which was granted on August 27, 2003.

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. 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 California Independent System Operator and the California Power Exchange tariffs. In setting the cases for hearing, the Commission directed the administrative law judge to hear evidence and render findings and conclusions quantifying the extent of any unjust enrichment that resulted and to recommend monetary or other appropriate remedies. On August 29, 2003, the Company and the FERC staff reached a resolution on the show-cause order. Under the terms of the settlement agreement, the Company denied liability and agreed to pay a nominal amount of $67,745, in exchange for complete and total resolution of the issues raised in the FERC’s show-cause order relating to the Company. The FERC must approve the settlement before it becomes binding on the parties.

The BPA Settlement

The Company is a party to lawsuits before the U.S. Court of Appeals for the Ninth Circuit Court challenging the level of the Bonneville Power Administration (the “BPA”) exchange benefits payable to residential and small farm customers of investor-owned utilities in the region. These exchange benefits are passed through directly to the Company’s residential and small-farm customers in Oregon, Washington and Idaho and do not impact the Company’s earnings. Parties to these lawsuits have reached a proposed settlement under which the Company and the other investor-owned utilities will defer, with interest, exchange benefits currently payable during the BPA’s fiscal years (October 1 to September 30) 2004-2006 to the BPA’s fiscal years 2007-2011. The Company’s share of the

total benefits to be deferred is between $68.0 million and $94.0 million, of which $11.6 million has already been deferred in the BPA’s fiscal year 2003. The Company will also permanently waive its right to $80.0 million in litigation contingency payments if the settlement becomes effective. In exchange for these deferrals and waiver, all lawsuits by the settling parties challenging the investor-owned utilities’ exchange benefits will be dismissed. In addition, the settlement modifies the formula for calculating exchange benefits in fiscal years 2007-2011 by substituting an independent forecast of market power prices in place of the BPA’s own forecast. A number of parties signed the settlement on October 23, 2003; however, the settlement remains subject to execution by the Company and the other parties to the lawsuits, as well as the approval of the OPUC. The settlement is also subject to conditions that could invalidate the settlement during the 120-day period after the date of its execution on October 23, 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. Hydroelectric facilities operating under expired licenses may operate under annual licenses granted by the FERC until new operating licenses are issued. Hydroelectric relicensing and the related environmental compliance requirements are subject to a degree of uncertainty. The Company expects that future costs relating to these matters may be significant and consist primarily of additional relicensing costs and capital expenditures. Power generation reductions may also result from additional environmental requirements. As of September 30, 2003, the Company had incurred approximately $100.4 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 six months ended September 30, 2003, the Company entered into a settlement agreement to remove the Powerdale project rather than pursue a new license, based on an analysis of the costs and benefits of relicensing versus decommissioning. Removal of the Powerdale dam and associated project features is projected to cost $4.9 million, with removal to commence in 2010.

The FERC issued final Environmental Impact Statements for both the North Umpqua and Bear River hydroelectric projects in April 2003, which is the final step before receiving new operating licenses. The Environmental Impact Statements are materially consistent with the negotiated settlement agreements for both projects. Settlement agreements are contingent on acceptable orders being issued by the FERC and on obtaining all necessary permits. New licenses are expected to be issued by the FERC by December 2003 for the North Umpqua and Bear River hydroelectric projects. 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.

On July 25, 2003, the Company received a new 50-year operating license for its 4.1 megawatt (“MW”) Big Fork hydroelectric project located on the Swan River in northwestern Montana.

As part of the general rate case settlement approved by the OPUC on August 26, 2003, the Company was allowed to begin recovery of the relicensing costs associated with the North Umpqua, Bear River and Big Fork hydroelectric projects. Oregon’s allocated share of these costs is $15.8 million of the total $56.3 million of costs on a system basis. In July 2003, the Company filed a rate case in Utah, which includes relicensing costs totaling $62.3 million for the costs associated with the North Umpqua, Bear River, Big Fork, American Fork and Powerdale hydroelectric projects. Utah’s allocated portion of these costs is $24.4 million. Recovery of these costs in Utah is contingent upon the outcome of the general rate case currently before the Utah Public Service Commission. In May 2003, the Company filed a rate case in Wyoming, which includes relicensing costs totaling $10.3 million for the costs associated with the Bear River hydroelectric project. Wyoming’s allocated share of these costs is $1.5 million. Recovery of these costs in Wyoming is contingent upon the outcome of the general rate case currently before the Wyoming Public Service Commission.

Environmental issues

The Company is subject to numerous environmental laws, including the federal Clean Air Act, as enforced by the EPA and various state agencies; the 1990 Clean Air Act Amendments; the Endangered Species Act of 1973, particularly as it relates to certain endangered species of fish; the Comprehensive Environmental Response, Compensation and Liability Act of 1980, relating to environmental cleanups; the Resource Conservation and Recovery Act of 1976; and the Clean Water Act, relating to water quality. These laws could potentially impact future operations. Contingencies identified at September 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, implementation of new mercury maximum control technology requirements, promulgated under the Clean Air Act, is scheduled 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 and future costs will be found to be prudent and recoverable in rates and, as such, will not have a material adverse impact on the Company’s consolidated results of operations. The Company is providing information about certain of its generating plants to the EPA in a cooperative effort to seek a mutual, comprehensive solution to air quality issues as they relate to such plants generally. The Company is also discussing air quality issues with state air quality regulators.

Swift power canal

On April 21, 2002, a failure occurred in the Swift power canal on the Lewis River in the state of Washington. The Cowlitz County Public Utility District owns the power canal and associated 70 megawatt (“MW”) hydroelectric facility (“Swift No. 2”). The current start-up date estimate for Swift No. 2 is March 1, 2005. The failure impacted, but did not damage, the Company-owned and -operated 240 MW Swift No. 1 hydroelectric facility (“Swift No. 1”), which is upstream of the Swift power canal. The overflow spillway was modified upstream of the Swift No. 2 failure to allow restricted operations of Swift No. 1. Environmental, operations safety and fish mitigation issues remain to be resolved before full use of Swift No. 1 can resume. The current estimate for recommencing full operations at Swift No. 1 is August 1, 2005. The Company continues to seek ways to mitigate any 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 County Public Utility District of the Company’s expenditures associated with the Swift No. 2 failure, including canal modifications and energy replacement costs. This event is not expected to have a significant impact on the Company’s consolidated financial position or results of operations.

NOTE 9 - Income Taxes

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

The Company accrued federal and state income tax expense of $84.8 million and $41.3 million, representing effective tax rates of 40.9% and 37.4%, for the six months ended September 30, 2003 and 2002, respectively. The increase in the estimated effective tax rate for the six months ended September 30, 2003 as compared to the six months ended September 30, 2002 is primarily due to the accrual of additional tax contingency reserves and higher levels of pretax 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. During the six months ended September 30, 2003, the Company provided an additional $3.4 million of tax contingency reserve primarily to accrue interest on tax contingencies provided for in prior periods.

During the three months ended September 30, 2003, the Company reached an agreement in principle with the IRS Appeals Division on certain tax issues related to the Company’s 1994 through 1998 federal income tax returns. The agreement in principle results in a tax and interest liability of $13.1 million, for which a contingency tax reserve was previously provided. The Company believes that final settlement and payment on agreed issues and other unresolved issues related to the Company’s 1994 through 1998 federal income tax returns will not have a material adverse impact on its consolidated financial position or results of operations.

NOTE 10 - Comprehensive Income

The components of comprehensive income are as follows:

	Three Months Ended September 30,					Six Months Ended September 30,

(Millions of dollars)	2003		2002			2003		2002

Net income	$	59.1	$	31.5		$	121.7	$	67.1
Other comprehensive income:
Unrealized gain (loss) on available-for-sale, securities, net of taxes: $0.4 and $1.9/2003 and $(1.9) and $(1.7)/2002		0.6		(2.4	)		3.3		(2.0	)
Reclassification of SFAS No. 133 gain in earnings: net of taxes of $14.7/2002		—		24.0			—		24.0

Total comprehensive income	$	59.7	$	53.1		$	125.0	$	89.1

NOTE 11 - 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 applied immediately to variable-interest entities created after January 31, 2003, and applied for periods beginning after June 15, 2003 to variable-interest entities acquired before February 1, 2003. In October 2003, the FASB deferred the effective date of FIN No. 46 until the end of the first interim or annual period beginning after December 15, 2003. The Company is currently evaluating the impact of adopting FIN No. 46 on its consolidated financial position and results of operations.

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

In May 2003, the EITF issued EITF No. 01-8, Determining Whether an Arrangement Contains a Lease (“EITF No. 01-8”). EITF No. 01-8 provides guidance for determining whether an arrangement contains a lease that is within the scope of SFAS No. 13, Accounting for Leases (“SFAS No. 13”). The evaluation of whether an arrangement contains a lease within the scope of SFAS No. 13 should be based on the substance of the arrangement. EITF No. 01-8 was effective for the Company on July 1, 2003. The adoption of this issue had no impact on the Company’s consolidated financial position 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 for the Company on October 1, 2003. The Company is currently evaluating the impact of applying this guidance on its consolidated financial position and results of operations.

In July 2003, the EITF issued EITF No. 03-11, Reporting Gains and Losses on Derivative Instruments that Are Subject to FASB Statement No. 133, Accounting for Derivative Instruments and Hedging Activities, and Not Held for Trading Purposes (“EITF No. 03-11”). This issue addresses whether realized gains and losses should be shown gross or net in the income statement for contracts that are not held for trading purposes but are derivatives subject to SFAS No. 133. EITF No. 03-11 is effective for all derivative instruments entered into beginning October 1, 2003. The Company currently reports such transactions on a gross basis, which is the basis supported under EITF No. 03-11; therefore, the adoption of EITF No. 03-11 will have no impact on the Company’s consolidated financial position and results of operations.

NOTE 12 - 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 13 - Subsequent Events

On October 14, 2003, the Company’s Board of Directors declared a dividend on common stock of approximately $0.13 per share totaling $40.1 million, payable on November 25, 2003.

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 September 30, 2003, and the related Condensed Consolidated Statements of Income and Retained Earnings for each of the three month and six month periods ended September 30, 2003 and 2002 and the Condensed Consolidated Statements of Cash Flows for the six month periods ended September 30, 2003 and 2002. These interim Condensed Consolidated Financial Statements are the responsibility of the Company’s management.

We conducted our review in accordance with standards established by the American Institute of Certified Public Accountants. A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with generally accepted auditing standards, the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.

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

We previously audited, in accordance with auditing standards generally accepted in the United States of America, the Consolidated Balance Sheet as of March 31, 2003, and the related Statements of Consolidated Income, Common Shareholder’s Equity and Cash Flows for the year then ended (not presented herein), and in our report dated May 7, 2003, we expressed an unqualified opinion on those Consolidated Financial Statements. In our opinion, the information set forth in the accompanying Condensed Consolidated Balance Sheet as of March 31, 2003, is fairly stated in all material respects in relation to the Consolidated Balance Sheet from which it has been derived.

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

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

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

PricewaterhouseCoopers LLP Portland, Oregon
November 5, 2003

ITEM 2.

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

OVERVIEW

CRITICAL ACCOUNTING POLICIES

The preparation of consolidated financial statements in conformity with accounting principles generally accepted in the United States of America requires Company management to make estimates and assumptions that affect results of operations and the reported amounts of assets and liabilities in the consolidated financial statements. Changes in these estimates and assumptions could have a material impact on the Company’s financial position and results of operations. Those policies that management considers critical are Regulation, Revenue Recognition, Contingencies, Asset Retirement Obligations and Pensions and are described in the Company’s 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 and 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 significant 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;

•

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;

•

disruption or failures of transmission or distribution facilities;

•

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

•

the outcome of threatened or pending litigation;

•

changes in tax rates and/or policies;

•

changes in 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 and other proceedings conducted by regulatory commissions; and

•

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

Any forward-looking statements issued by the Company should be considered in light of these factors. The Company 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 six months ended September 30, 2003 was $119.4 million, as compared to $63.4 million for the six months ended September 30, 2002. Retail sales volumes were 4.8% higher in the six months ended September 30, 2003 than the comparable prior year period, driven by higher temperatures in summer 2003 and increases in usage per customer and total customer numbers. Output from the Company’s thermal facilities increased by 1,086,000 megawatt-hours (“MWh”), or 4.8%, as a result of improved operating performance and increases from new plant additions. Output from Company-owned hydroelectric facilities was lower by 182,100 MWh, or 10.6%, as a result of unusually dry conditions.

In the six months ended September 30, 2003, western United States electricity market prices were higher than the comparable prior year period driven by a combination of higher northwest natural gas prices and a reduction in hydroelectric generation. As a result of risk management actions previously taken, including use of physical resources and hedging activities, the Company maintained its balanced energy position through the summer peak period and believes that its energy position is balanced for the remainder of fiscal year 2004.

As discussed in PART II- ITEM 5. OTHER INFORMATION, the Company has general rate cases pending in Utah, Wyoming and California. These requests total approximately $182.8 million. These increases are sought to recover system investments and rising costs, including insurance premiums, pension expense and health care, along

with a return on equity 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 SEPTEMBER 30, 2003 and 2002

REVENUES

	Three Months Ended September 30,				Change			% Change

(Millions of dollars)	2003		2002		Favorable/(Unfavorable)

Residential	$	241.5	$	225.9	$	15.6		6.9	%
Commercial		214.6		200.4		14.2		7.1
Industrial		208.6		199.4		9.2		4.6
Other retail revenues		8.8		8.3		0.5		6.0

Retail sales		673.5		634.0		39.5		6.2
Wholesale sales		246.2		260.1		(13.9	)	(5.3	)
Other revenues		38.3		49.8		(11.5	)	(23.1	)

Total Revenues	$	958.0	$	943.9	$	14.1		1.5

Energy sales (millions of kWh)
Residential		3,450		3,192		258		8.1
Commercial		3,981		3,729		252		6.8
Industrial		5,210		5,109		101		2.0
Other		183		177		6		3.4

Retail sales		12,824		12,207		617		5.1
Wholesale sales		5,618		7,516		(1,898	)	(25.3	)

Total		18,442		19,723		(1,281	)	(6.5	)

Average residential usage (kWh)		2,608		2,455		153		6.2
Total customers - end of period (in thousands)		1,552		1,526		26		1.7

Residential revenues for the three months ended September 30, 2003 increased $15.6 million, or 6.9%, from the three months ended September 30, 2002 primarily due to increases of $14.2 million from higher average estimated customer usage, including the impact of warmer weather, and $4.2 million relating to growth in the average number of residential customers. These increases were partially offset by a decrease of $2.6 million due to a change in price mix.

Commercial revenues for the three months ended September 30, 2003 increased $14.2 million, or 7.1%, from the three months ended September 30, 2002 primarily due to increases of $10.0 million from higher average estimated customer usage. Growth in the average number of commercial customers increased revenues by $4.3 million.

Industrial revenues for the three months ended September 30, 2003 increased $9.2 million, or 4.6%, from the three months ended September 30, 2002 due to a $16.1 million increase resulting from higher prices, partially offset by a $6.9 million decrease due to lower average estimated customer usage.

Wholesale sales for the three months ended September 30, 2003 decreased $13.9 million, or 5.3%, from the three months ended September 30, 2002 primarily due to a reduction in volumes of 25.3%, the impact of which was $56.6 million. The majority of this reduction was in short-term and spot market sales, which were 38.6% lower than the prior year period. A parallel volume reduction is reflected in the Company’s Purchased electricity expense. Offsetting this volume reduction, the Company achieved an increase of 26.6% on prices realized as compared to those in the three months ended September 30, 2002, the impact of which was $42.7 million. The primary factors contributing to higher market electricity prices in the western United States during the three months ended September 30, 2003 were below normal hydroelectric conditions and higher natural gas prices.

Other revenues for the three months ended September 30, 2003 decreased $11.5 million, or 23.1%, from the three months ended September 30, 2002 primarily due to a $20.7 million release of reserves on a power sales contract following a settlement of a dispute with respect to the contract in September 2002 and a decrease in wheeling revenues of $2.3 million. These decreases were partially offset by increases of $4.2 million due to a contract

settlement, $3.2 million from the joint use of poles and wires, $2.0 million from the reduction of the Oregon merger credit liability and $2.0 million relating to an alternative form of regulation process in Oregon.

See PART II - ITEM 5. OTHER INFORMATION for information regarding recent developments in regulatory issues affecting the Company.

OPERATING EXPENSES

Purchased electricity expense for the three months ended September 30, 2003 decreased $33.1 million, or 9.2%, from the three months ended September 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 30.5% with a resulting reduction in Purchased electricity expense of $70.1 million. Partially offsetting this reduction was a 19.9% increase in the average purchase price due to higher market prices resulting from the same factors mentioned above for wholesale sales, the effect of which was an increase in Purchased electricity expense of $40.2 million. Long-term purchase volumes increased Purchased electricity expense by $15.4 million, or 9.3%, primarily from increases on exchange contracts. Wheeling expense decreased $10.3 million as a result of the lower volumes. Unrealized mark-to-market gains on weather derivatives and transactions designated as trading were $0.9 million for the three months ended September 30, 2003, as compared to a $7.4 million loss in the comparable prior year period for a net reduction to Purchased electricity expense of $8.3 million.

Fuel expense for the three months ended September 30, 2003 decreased $1.0 million, or 0.8%, from the three months ended September 30, 2002. Increased thermal generation volumes of 2.2% resulted in increased costs of $2.6 million, of which $2.5 million was due to increases in coal volumes and $0.1 million was due to increases in natural gas volumes. Realized coal prices increased Fuel expense by $0.3 million, but were offset by a 16.8% decrease in realized natural gas prices paid, which resulted in a benefit of $3.8 million. The reduction in realized natural gas prices was a result of lower plant availability in the three months ended September 30, 2002, which resulted in adverse gas balancing costs as compared to the current year period. Due to previous hedging activities, the Company was not required to incur the current higher natural gas market prices.

Other operations and maintenance expense for the three months ended September 30, 2003 increased $25.2 million, or 19.4%, from the three months ended September 30, 2002 primarily due to a $6.8 million increase in employee-related expenses, due in part to higher pension costs; a $4.2 million increase in materials and contract services primarily related to overhauls; and a $4.2 million increase due to contract services related to generation site development. In addition, changes in the level and timing of capitalized costs added $2.8 million to expense, other contract services increased $2.4 million, bad debts increased $1.3 million and rent expense increased $0.8 million.

Depreciation and amortization expense for the three months ended September 30, 2003 decreased $2.4 million, or 2.2%, from the three months ended September 30, 2002 primarily due to a $5.4 million decrease as a result of new depreciation rates approved by regulators as discussed in PART I - ITEM 1. FINANCIAL STATEMENTS – NOTE 2 – Accounting for the Effects of Regulation, which was partially offset by the effect on depreciation of increased plant in-service of $2.0 million and increased software development of $1.4 million.

Administrative and general expenses for the three months ended September 30, 2003 decreased $13.6 million, or 22.0%, from the three months ended September 30, 2002 primarily due to decreases of $4.5 million in employee-related expenses, $4.0 million in amortization of regulatory assets as a result of lower average balances, $2.3 million in contract services and a $1.4 million decrease in insurance costs due to lower claims in the current year period and one-time costs recognized in the prior year period.

Taxes, other than income taxes, for the three months ended September 30, 2003 decreased $1.1 million, or 4.3%, from the three months ended September 30, 2002 primarily due to lower property tax expense.

The net Unrealized loss on derivative contracts for the three months ended September 30, 2003 was $4.7 million compared to a gain of $5.3 million for the three months ended September 30, 2002 primarily due to the application of Statement of Financial Accounting Standards (“SFAS”) No. 149, Amendment of Statement 133 on Derivative Instruments and Hedging Activities (“SFAS No. 149”) in the three months ended September 30, 2003 as compared to favorable price movements in the three months ended September 30, 2002.

Other operating expense for the three months ended September 30, 2003 was $12.8 million primarily due to a $10.8 million expense for changes in regulatory assets and liabilities.

INTEREST EXPENSE AND OTHER (INCOME) EXPENSE

Interest expense decreased $18.1 million, or 22.5%, primarily due to a decrease in interest on regulatory liabilities and lower average debt balances, partially offset by dividends on mandatorily redeemable preferred stock of $1.1 million, which were included in interest expense for the three months ended September 30, 2003 in accordance with SFAS 150, Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity (“SFAS No. 150”).

Interest capitalized increased $2.1 million, or 47.7%, due to higher qualifying construction work-in-progress balances and higher capitalization rates in the current period.

Minority interest and other expense decreased $4.3 million, or 75.4%, primarily due to a $2.5 million decrease in distributions on Preferred Securities, which were redeemed during the three months ended September 30, 2003. In addition, other expenses decreased $2.5 million primarily due to realized gains on the increased cash surrender value of life insurance policies, which was partially offset by a $0.8 million increase in accrued charitable donations.

INCOME TAX EXPENSE

Income tax expense increased $14.7 million primarily due to the higher pretax income in the current period. The estimated effective tax rate for the three months ended September 30, 2003 was 38.1% compared to 40.8% for the three months ended September 30, 2002. The decrease in the estimated effective tax rate is primarily due to higher levels of pretax income in the current period, which diluted the tax effect of the regulatory treatment of depreciation differences.

COMPARISON OF THE SIX MONTHS ENDED SEPTEMBER 30, 2003 and 2002

REVENUES

	Six Months Ended September 30,				Change			% Change

(Millions of dollars)	2003		2002		Favorable/(Unfavorable)

Residential	$	468.7	$	431.0	$	37.7		8.7	%
Commercial		413.8		386.5		27.3		7.1
Industrial		386.0		366.3		19.7		5.4
Other retail revenues		17.5		16.6		0.9		5.4

Retail sales		1,286.0		1,200.4		85.6		7.1
Wholesale sales		499.8		553.6		(53.8	)	(9.7	)
Other revenues		67.0		75.5		(8.5	)	(11.3	)

Total Revenues	$	1,852.8	$	1,829.5	$	23.3		1.3

Energy sales (millions of kWh)
Residential		6,703		6,131		572		9.3
Commercial		7,503		7,109		394		5.5
Industrial		9,886		9,718		168		1.7
Other		341		352		(11	)	(3.1	)

Retail sales		24,433		23,310		1,123		4.8
Wholesale sales		12,306		17,498		(5,192	)	(29.7	)

Total		36,739		40,808		(4,069	)	(10.0	)

Average residential usage (kWh)		5,074		4,722		352		7.5
Total customers - end of period (in thousands)		1,552		1,526		26		1.7

Residential revenues for the six months ended September 30, 2003 increased $37.7 million, or 8.7%, from the six months ended September 30, 2002 primarily due to increases of $33.4 million from higher average estimated customer usage, including a change in the calculation of unbilled revenues and the impact of warmer weather, and

$7.8 million relating to growth in the average number of residential customers. These increases were partially offset by a decrease of $3.4 million due to a change in price mix.

Commercial revenues for the six months ended September 30, 2003 increased $27.3 million, or 7.1%, from the six months ended September 30, 2002 primarily due to increases of $16.1 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 by $8.1 million, and higher prices increased revenues by $3.2 million.

Industrial revenues for the six months ended September 30, 2003 increased $19.7 million, or 5.4%, from the six months ended September 30, 2002 primarily due to a $24.6 million increase resulting from higher prices, partially offset by a $4.9 million decrease due to lower average estimated customer usage, including a change in the calculation of unbilled revenues.

Wholesale sales for the six months ended September 30, 2003 decreased $53.8 million, or 9.7%, from the six months ended September 30, 2002 primarily due to a reduction in volumes of 29.7%, the impact of which was $119.5 million. The majority of this reduction was in short-term and spot market sales, which were 38.6% lower than the prior year period. A parallel volume reduction is reflected in the Company’s Purchased electricity expense. Offsetting this volume reduction, the Company achieved an increase of 28.4% on prices realized as compared to those in the six months ended September 30, 2002, the impact of which was $65.7 million. The primary factors contributing to higher market electricity prices in the western United States during the six months ended September 30, 2003 were an increase in the market price of natural gas and a reduction in hydroelectric generation.

Other revenues for the six months ended September 30, 2003 decreased $8.5 million, or 11.3%, from the six months ended September 30, 2002 primarily due to a $20.7 million release of reserves on a power sales contract following a settlement of a dispute with respect to the contract in September 2002, a $4.6 million decrease in revenue from the conclusion of the amortization of a regulatory liability and a decrease in wheeling revenues of $2.8 million. These decreases were partially offset by increases of $4.9 million from the joint use of poles and wires, $4.5 million relating to an alternative form of regulation process in Oregon, $4.2 million from the reversal of a previously established reserve on power sales contracts, $4.1 million relating to demand-side management and $2.0 million from reduction of the Oregon merger credit liability.

OPERATING EXPENSES

Purchased electricity expense for the six months ended September 30, 2003 decreased $83.6 million, or 12.4%, from the six months ended September 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 41.3% with a resulting reduction in Purchased electricity expense of $278.8 million. Partially offsetting this reduction was a 26.1% 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 Purchased electricity expense of $130.4 million. Long-term purchase volumes increased Purchased electricity expense by $85.1 million, or 16.9%, primarily from increases on exchange contracts. Wheeling expense decreased $17.2 million as a result of lower volumes. Costs relating to unrealized losses on weather derivatives decreased Purchased electricity expense by $5.7 million as compared to the six months ended September 30, 2002. Other costs, which include demand-side management costs and fees, increased $2.6 million.

Fuel expense for the six months ended September 30, 2003 increased $18.4 million, or 8.0%, from the six months ended September 30, 2002. Increased thermal generation volumes of 4.8% resulted in increased costs of $15.6 million, of which $5.2 million was due to increases in coal volumes and $10.4 million was due to increases in natural gas volumes, primarily due to the impact from the Company’s Gadsby peaking plant and the leased West Valley plant, which came on line during the prior year period. Realized coal prices increased $1.3 million, but were offset by a 20.4% decrease in realized natural gas prices paid that resulted in a benefit of $8.0 million. The reduction in realized natural gas prices was as a result of lower plant availability in the six months ended September 30, 2002, which resulted in adverse natural gas balancing costs as compared to the current year period. Due to previous hedging activities, the Company was not required to incur the current higher natural gas market prices. The remaining cost increase of $9.5 million was attributable to the net impact of a regulatory deferral for the Trail Mountain coal mine that reduced fuel costs in the six months ended September 30, 2002.

Other operations and maintenance expense for the six months ended September 30, 2003 increased $25.8 million, or 9.2%, from the six months ended September 30, 2002 primarily due to a $10.0 million increase in employee-related

expenses due in part to higher pension costs; a $7.0 million increase due to the level and timing of capitalized costs; a $3.9 million increase in rent expense due to the West Valley plant, which came on-line during the prior year period; a $4.2 million increase in contract services related to generation site development; a $2.4 million increase in materials and contract services, primarily related to overhauls; and a $2.4 million increase in tree-trimming contract services. These increases were partially offset by lower bad debt expense of $6.2 million primarily due to the establishment of a $7.0 million reserve for California exposures in the prior year period.

Depreciation and amortization expense for the six months ended September 30, 2003 decreased $4.7 million, or 2.2%, from the six months ended September 30, 2002 primarily due to an $11.8 million decrease as a result of new depreciation rates approved by regulators as discussed in PART I - ITEM 1. FINANCIAL STATEMENTS – NOTE 2 – Accounting for the Effects of Regulation, which was partially offset by the effect on depreciation of increased plant in-service of $4.7 million and increased software development of $2.6 million.

Administrative and general expenses for the six months ended September 30, 2003 decreased $19.0 million, or 14.3%, from the six months ended September 30, 2002 primarily due to a $9.5 million decrease in insurance costs due to lower claims in the current year period and one-time costs recognized in the prior year period, a $6.7 million decrease in amortization on regulatory assets due to lower average asset balances and a $3.2 million decrease in contract services.

The net Unrealized loss on derivative contracts for the six months ended September 30, 2003 was $3.2 million compared to a gain of $3.1 million for the six months ended September 30, 2002 primarily due to losses from the implementation of SFAS No. 149 in the six months ended September 30, 2003.

Other operating expense for the six months ended September 30, 2003 was $12.8 million primarily due to a $10.8 million expense for changes in regulatory assets and liabilities.

INTEREST EXPENSE AND OTHER (INCOME) EXPENSE

Interest expense decreased $21.0 million, or 14.5%, primarily due to a decrease in interest on regulatory liabilities and lower average debt balances. In accordance with SFAS No. 150, dividends on mandatorily redeemable preferred stock of $1.1 million were included in Interest expense for the six months ended September 30, 2003.

Interest income decreased $1.4 million, or 14.9%, primarily due to the recognition of $1.1 million of interest income on a power sales contract settlement in September 2002.

Interest capitalized increased $2.2 million, or 22.2%, due to higher qualifying construction work-in-progress balances and higher capitalization rates in the current period.

Minority interest and other expense decreased $7.8 million, or 51.7%, partially due to a $2.5 million decrease in distributions on Preferred Securities, which were redeemed during the six months ended September 30, 2003. Other expense also decreased due to the reversal in the six months ended September 30, 2002 of a previously recorded gain of $3.4 million as a result of a regulatory order and $3.4 million due to realized gains on the increased cash surrender value of life insurance policies. These decreases were partially offset by a $1.7 million increase in accrued charitable donations.

INCOME TAX EXPENSE

Income tax expense increased $43.5 million principally due to the higher pretax income in the current period. The estimated effective tax rate for the six months ended September 30, 2003 was 40.9% compared to 37.4% for the six months ended September 30, 2002. The increase in the estimated effective tax rate is primarily due to the accrual of additional tax contingency reserves and higher levels of pretax 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, during the six months ended September 30, 2003. The Company recorded a

$1.9 million after-tax loss from the implementation of revised Issue C15 and Issue C16 guidance from the Derivatives Implementation Group during the six months ended September 30, 2002.

LIQUIDITY AND CAPITAL RESOURCES

OPERATING ACTIVITIES

Net cash flows provided by operating activities were $335.7 million for the six months ended September 30, 2003 as compared to $200.2 million for the six months ended September 30, 2002 due primarily to an increase in earnings, decrease in tax payments related to prior period IRS audits, reduced fuel inventory and the timing of collections and payments.

INVESTING ACTIVITIES

Capital spending totaled $309.9 million for the six months ended September 30, 2003 compared to $253.1 million for the six months ended September 30, 2002. The increase was primarily due to expenditures for plant refurbishments, network growth and system upgrades, and information technology.

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 the London Interbank Offered Rate (LIBOR) plus a margin that varies based on the Company’s credit ratings. In addition to these committed credit facilities, the Company had $30.7 million in money market accounts included in Cash and cash equivalents at September 30, 2003 available to meet its liquidity needs.

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

The Company redeemed $7.5 million of preferred stock during each of the six-month periods ended September 30, 2003 and 2002.

The Company declared and paid dividends of $80.3 million on common stock, and paid dividends of $3.5 million on preferred stock, during the six months ended September 30, 2003. On August 19, 2003, the Company declared dividends of $0.5 million on Preferred stock and $1.1 million on Mandatorily redeemable preferred stock, which are payable on November 15, 2003. The dividends declared on Mandatorily redeemable preferred stock were recorded as interest expense. On October 14, 2003, the Company’s Board of Directors declared a dividend on common stock of approximately $0.13 per share totaling $40.1 million payable on November 25, 2003.

Management expects existing funds and cash generated from operations, together with existing credit facilities, to be sufficient to fund liquidity requirements for the next 12 months. However, many participants in the electric utility industry have experienced a period of negative news and ratings downgrades. While the Company to date has been able to fund itself and expects to be able to continue to do so, further negative events 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.

CAPITAL EXPENDITURES

The following table shows the Company’s estimated capital expenditures for the years ending March 31, 2004 through 2006. The Company’s capital expenditure program has been recently revised and the estimates below reflect the outcome of the first of three Requests for Proposal to support the Company’s Integrated Resource Plan. Subject to regulatory approvals and other consents, this will result in the construction of the Currant Creek Project, a new 525 megawatt (“MW”) natural gas-fired plant located in Juab County, approximately 75 miles south of Salt Lake City, Utah, at a cost of approximately $350.0 million to be incurred generally over three years to 2006.

	Estimated

	Years Ending March 31,

Millions of dollars	2004		2005		2006

Distribution and transmission	$	336.0	$	353.6	$	378.2
Generation and mining		313.9		482.6		433.1
Other		99.4		79.5		106.7

Total	$	749.3	$	915.7	$	918.0

In addition to the new generating plant mentioned above, estimated future capital expenditures include upgrades to distribution and transmission lines and existing generation plants, connections for new customers, facilities to accommodate load growth, coal mine investments, air quality and environmental expenditures, hydroelectric relicensing costs and information technology systems. The Company expects that these and future costs will be found to be prudent and recoverable in future rates. All of these expenditures are subject to continuing review and revision by the Company, and actual costs could vary from estimates due to various factors, such as changes in business conditions, revised load-growth estimates, future legislative and regulatory developments and increasing costs in labor, equipment and materials. The estimates of capital expenditures for the years ending March 31, 2004 through 2006 are subject to the potential impact on generation and transmission capacity of future decisions arising from the further stages of the Request for Proposal process to support the Integrated Resource Plan. Additional expenditures may be significant but are likely to be spread over a number of years, and cannot be accurately estimated at this time.

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

CREDIT RATINGS

The Company’s credit ratings at September 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
Ratings outlook	Negative	Negative

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 September 30, 2003, the Company had $90.0 million of commercial paper outstanding at a weighted average interest rate of 1.2%. These borrowings and other financing arrangements are supported by revolving credit agreements and cash on hand as described above.

ITEM 3.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

BUSINESS RISK

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

Political Risk

The Company’s business operations are subject to a multitude of federal and state laws. The U.S. Congress is considering significant energy legislation that would make changes in federal law affecting the Company. This energy legislation is now the subject of a joint conference committee to reconcile the differences between the bills passed by the U.S. House of Representatives and the U.S. Senate. If a comprehensive energy bill is enacted, the bill will likely include direction for the regulation of, as well as financial incentives to invest in, transmission. The competing bills also include similar measures affecting the hydroelectric relicensing process and extension of the renewable energy production tax credit. These and other measures under consideration would likely benefit the Company’s efforts to develop, acquire and maintain a low-cost generation portfolio. As part of this legislation, the U.S. Congress may repeal the Public Utility Holding Company Act (the “PUHCA”). At present, the Company is unable to predict how the repeal of the PUHCA would affect the Company, which is a public utility and a subsidiary of a registered holding company. It is possible that new legislation may be enacted or the FERC may adopt new regulations if the PUHCA is repealed. Changes to the Clean Air Act, contemplated by the pending Clear Skies Act, may affect control requirements for several emissions from fossil-fueled generation plants.

The laws of the states in which the Company operates affect the Company’s generation, transmission and distribution business. All of the legislatures monitored by the Company have concluded their regular business for their legislative years. The Oregon legislature passed a series of tax changes designed to reduce the state’s budget deficit. The Company is not significantly affected by the changes enacted in Oregon, based on a preliminary analysis of the new law. The California legislature failed to pass either of two competing bills designed to revise the state’s electric industry restructuring law (AB 1890). The California legislature did pass, and Governor Davis signed into law, a bill exempting the Company from the state’s statutory prohibition on the disposal of utility generating assets. This prohibition had been an impediment to the Company’s plans to decommission, or otherwise dispose of, several small hydroelectric assets.

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 and impose a property tax to perform a feasibility study. On June 12, 2003, the Multnomah County Commission voted to place ballot measures 26-51 and 26-52 on the November 2003 ballot as required by state statute.

On November 4, 2003, Multnomah County voters defeated ballot measures 26-51 and 26-52 to form a government-owned and -operated electric utility. Proponents of the measures may pursue legal challenges to the outcome. State law prohibits proponents from placing a similar measure on the ballot for one year.

The Company serves 68,000 homes and businesses in Multnomah County, which represents approximately 1.9 million MWh, or $108.1 million in annual revenues.

Security Risk

Ongoing threats of terrorism, both domestic and foreign, continue to be a risk to the utility industry, including the Company. The Company has a comprehensive approach to identifying critical assets, evaluating both cyberspace and physical security and retrofitting critical sites with enhanced security controls. In conjunction with the North American Electric Reliability Council’s Urgent Action Standard for cyberspace and physical security, the Company is conducting a gap analysis and is implementing necessary changes to standardize security controls to ensure compliance with this standard. The Company continues to monitor the evolution of security standards that may be promulgated by the FERC and the North American Electric Reliability Council.

The Company implemented a program that identified critical business processes and led the Company to develop and verify key business recovery plans across the Company’s business.

Market Risk

Coal - The Company operates several thermal generation plants in Utah. A Company mine provides almost 50% of the coal used to fuel these plants. The balance of coal comes from short- and long-term purchases from third parties. Coal production in Utah is expected to decrease in calendar year 2004. This reduction can be primarily attributed to the closing of one unaffiliated mine and the shifting of production from a long-wall to a continuous mine operation at another unaffiliated mine. These reductions may have an impact on 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 - In early summer 2003, the FERC announced that it had concerns regarding the economic impact of a major natural gas supply deficiency extending beyond the spot market. While those concerns have somewhat diminished with the increasing natural gas storage levels, the FERC has broadened its focus on natural gas to include an array of policy issues currently facing the natural gas industry and the FERC’s regulation of the industry for the future. While the natural gas topics that the FERC is addressing occupy the national interest, these issues and strategy discussions do not materially impact the Company.

Since June 30, 2003, the Company purchased, under fixed-price terms, its calendar year 2006 forecasted natural gas supply needs for the Company’s current natural gas-fired electric generation plant. The Company currently supplies four natural gas-fired generating plants that, at capacity, require a maximum of 229,000 MMBtu of natural gas per day. The Company’s Integrated Resource Plan has identified the need for additional resources, due to expected load growth, that could increase this requirement to 500,000 MMBtu per day, or more. The Currant Creek Project, which resulted from the Integrated Resource Plan and subsequent Request for Proposal is a natural gas-fired plant. The fuel supply for the Currant Creek Project will be managed by the Company consistent with the corporate fuels strategy, which focuses on the management and mitigation of risks associated with supplying natural gas to fuel generation. The prospective growth of the Company’s natural gas requirements points to the need for a prudent, disciplined and well-documented approach to procurement and hedging. The Company has developed a natural gas strategy that addresses hedging the commodity risk (physical availability and price), the transportation risk and the storage risk associated with its forecasted and potentially growing natural gas requirements. The natural gas strategy, combined with the prospect for increasing natural gas requirements, is expected to increase the volume and type of the Company’s hedging activity and extend the term of its hedging activity beyond calendar year 2006.

Credit Risk

On July 8, 2003, National Energy & Gas Transmission, Inc. (“NEGT”) and Energy Trading Holdings Corporation and its subsidiaries filed petitions for protection under Chapter 11 of the federal bankruptcy code. While PacifiCorp does not have direct exposure to any of the NEGT entities that have filed for bankruptcy protection, the Company, in a joint ownership arrangement with a subsidiary of NEGT, Larkspur Power Corporation (“Larkspur”), that has a 50.0% ownership interest in the Hermiston Generating Company (“HGC”). HGC owns and operates a 452 MW natural 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 NEGT 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 for exposure to interest rate fluctuations discussed below are based on a Value-at-Risk (“VaR”) approach using a one-year horizon and a 95.0% confidence level and assuming a one-day holding period in normal market conditions. The VaR model is a risk analysis tool that attempts to measure the potential change in fair value, earnings or cash flow 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 of the Company’s interest-rate-sensitive positions, as of March 31, 2003 and September 30, 2003, as well as the Company’s quarterly high and low potential losses.

(Millions of dollars)	Confidence Interval		Time Horizon	March 31, 2003			2004 Quarterly						September 30, 2003

							High			Low

Interest-rate-sensitive portfolio - fair market value	95.0	%	1 Day	$	(18.2	)	$	(33.4	)	$	(18.2	)	$	(33.4	)

The increase in potential loss in fair market value from March 31, 2003 to September 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 that impact energy supply and demand. Risk management policy and the risk levels established as part of that policy govern the Company’s energy purchase and sales activities. For additional information about on the Company’s Risk Management and Measurement, see ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK in the Company’s 2003 Annual Report on Form 10-K.

The Company measures the market risk in its electricity and natural gas portfolio daily 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.

As of September 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 $13.1 million, as compared to $19.9 million as of September 30, 2002. The average daily VaR (five-day holding period and to a 99.0% confidence level) for the quarter ended September 30, 2003 was $12.5 million. The maximum and minimum VaR measured during the quarter ended September 30, 2003 were $14.7 million and $9.8 million, respectively. The Company maintained compliance with its VaR limit procedures during the quarter ended September 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 of the Company’s energy commodity portfolio risk, but accounted for at fair market value, were not material as of September 30, 2003.

FAIR VALUE OF DERIVATIVES

Statement of Financial Accounting Standards (“SFAS”) No. 133, Accounting for Derivative Instruments and Hedging Activities (“SFAS No. 133”), as amended by SFAS No. 138, Accounting for Certain Derivative Instruments and Certain Hedging Activities, and SFAS No. 149 (collectively SFAS No. 133) requires all derivatives, as defined by the standard, to be measured at fair value, except those that qualify for specific exemption under the standard or associated guidance, such as those defined as normal purchases and normal sales. The numerous updates

to SFAS No. 133 continue to alter the definition of a “derivative” and the exemptions. The implementation of SFAS No. 149 in the three months ended September 30, 2003 resulted in a significant increase in the number of contractual arrangements currently marked to market by the Company; however, the overall impact on the Company’s consolidated financial statements was insignificant. Although the number of contractual arrangements has increased, the derivatives that are marked to market in accordance with SFAS No. 133 include only certain of the Company’s commercial contractual arrangements, as many of these arrangements are outside the scope of SFAS No. 133.

The following table shows the changes in the fair value of energy-related contracts qualifying as derivatives under SFAS No. 133 from April 1, 2003 to September 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		34.4
Changes in valuation assumptions (a)		(59.6	)
Changes in fair values (b)		(72.8	)

Fair value of contracts outstanding at the end of the period (c)	$	(603.7	)

(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 $601.7 million in net regulatory assets, as authorized by regulatory orders received, to recover the costs with respect to these contracts.

Short-term contracts are valued based upon quoted market prices. Long-term contracts are valued by separating each contract into its component physical and financial forward, swap and option legs. Forward and swap legs are valued against the appropriate market curve. The option leg is valued using a modified Black-Scholes model or a stochastic simulation (Monte Carlo) approach. Each leg is modeled and valued separately using the appropriate forward market price curve. The forward market price curve is derived 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 September 30, 2003, the net value of these instruments was a liability of $5.2 million.

The following discloses summarized information with respect to valuation techniques and contractual maturities of the Company’s contracts qualifying as derivatives under SFAS No. 133 as of September 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	$	(17.1	)	$	(14.2	)	$	(78.6	)	$	(493.8	)	$	(603.7	)

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.

FERC ISSUES

California Refund Case

The Company is a party to a FERC proceeding that is investigating potential refunds for energy transactions in the California Independent System Operator and the California Power Exchange markets during past periods of high energy prices. The Company previously established a reserve of $17.7 million for these refunds. The Company’s ultimate level of exposure to refunds is dependent upon any final order issued by the FERC in this proceeding.

Northwest Refund Case

On June 25, 2003, the FERC terminated its proceeding relating to the possibility of requiring refunds for wholesale spot-market bilateral sales in the Pacific Northwest between December 25, 2000 and June 20, 2001. The FERC concluded that ordering refunds would not be an appropriate resolution of the matter. On August 25, 2003, the FERC granted rehearing of its June 25, 2003 order.

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. On July 28, 2003, the Company filed its request for rehearing of the FERC’s order, which was granted on August 27, 2003.

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. 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 California Independent System Operator and the California Power Exchange tariffs. In setting the cases for hearing, the Commission directed an administrative law judge to hear evidence and render findings and conclusions quantifying the extent of any unjust enrichment that resulted, and to recommend monetary or other appropriate remedies. On August 29, 2003, the Company and the FERC staff reached a resolution on the show-cause order. Under the terms of the settlement agreement, the Company denied liability and agreed to pay a nominal amount of $67,745, in exchange for complete and total resolution of the issues raised in the FERC’s show-cause order relating to the Company. The FERC must approve the settlement before it becomes binding on the parties.

REGULATORY ACTIONS

Utah

The Company commenced a general rate case on May 15, 2003 based on financial information for the year ended March 31, 2003 and including 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 was made in July 2003, requesting a revenue increase equal to the cap. The Company supplemented this filing with a filing on September 15, 2003, detailing class cost of service and rate spread and rate design proposals. The Company filed an updated revenue requirement on October 15, 2003 with the total revenue increase unchanged. The Company submitted an updated class cost of service filing on October 31, 2003. If approved, the effective date of the increase is expected to be January 1, 2004, with cash collections beginning April 1, 2004.

During summer 2003, the Company filed and received regulatory approval in Utah on three new residential demand-side management programs: a refrigerator recycling program, an air-conditioning load control program and an incentive program to install evaporative coolers or energy-efficient air-conditioners. The Company filed for a tariff rider to allow it to recover costs incurred through the implementation of all of the programs approved by the Utah Public Service Commission (the “UPSC”). The Company has been deferring the costs of approved programs since August 2001. Following the filing of testimony, tariff proposals and a series of technical conferences, interested parties have approved a stipulation detailing the introduction of a tariff rider mechanism and a self-direction program for large customers. This stipulation was heard and approved by the UPSC on September 23, 2003. By the end of November 2003, the Company will file a proposed collection rate under this newly adopted schedule. It is anticipated that the tariff rider will be introduced in customer bills after April 1, 2004.

Oregon

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

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

On October 30, 2003, the OPUC approved a settlement of the Company’s net power costs for the period September 10, 2001 through May 31, 2002 (the “Bridge Period”). An approved stipulation provided that the Company’s net power cost recovery during the Bridge Period would be based on a specified percentage of actual net power costs subject to certain adjustments, with deferred recovery or payment of any undercollection or overcollection. Following an independent audit, the parties to the original stipulation agreed that the Company undercollected Bridge Period net power costs by $300,000. The OPUC approved this $300,000 in net power costs for later collection in rates.

Wyoming

On May 7, 2002, the Company filed a request to recover replacement power costs of $30.7 million, resulting from the outage of the Company’s Hunter No. 1 generating plant, and a proposal for recovering deferred net power costs of $60.3 million. In December 2000, the Wyoming Public Service Commission (the “WPSC”) authorized the

deferral of net power costs. On March 6, 2003, the WPSC denied recovery of the Hunter No. 1 replacement power costs and the deferred net power costs. The Company filed a petition for rehearing of the decision on April 4, 2003. After a public deliberation on May 30, 2003, the WPSC denied the petition, and the order denying rehearing was issued on July 15, 2003. On August 8, 2003, the Company petitioned the Laramie County district court to review the WPSC decision. On September 22, 2003, the district court certified the case to the Wyoming Supreme Court.

On May 27, 2003, the Company filed a general rate case with the WPSC to recover rising costs (including insurance premiums, pension funding and health care costs) and requested an increase in the return on equity to 11.5% to compensate the Company for general risks relating to the western United States utility environment, as well as some additional risks relating to multijurisdictional operations. The Company has requested an annual increase of $41.8 million, or 13.1%, in base rates to take effect in March 2004. Hearings in the case are scheduled to begin on January 16, 2004 with an order expected by the end of March 2004.

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

Washington

On April 5, 2002, the Company filed a petition with the Washington Utilities and Transportation Commission (the “WUTC”) seeking authority to begin deferring net power costs in excess of those included in rates as of June 1, 2002 for later recovery in rates, either through a power cost adjustment mechanism or a limited rate adjustment. Under the rate plan approved by the WUTC in August 2000 at the conclusion of the Company’s last general rate case in Washington, there were limitations on the Company’s ability to request changes to general rates before January 2006. On October 18, 2002, the Company filed testimony and supporting documents, requesting deferral and recovery of excess net power costs estimated at the time to be $17.5 million, including carrying charges, or, alternatively, to allow the Company to file a general rate case, which was restricted through December 2005. Through March 31, 2003, the deferral was 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 does allow the Company to file a general rate case any time before July 2005 that addresses the level of prices needed to cover all ongoing costs to serve Washington customers. On August 14, 2003, the Public Counsel section of the state attorney general’s office filed a court action in Thurston County superior court requesting review of the WUTC’s decision to allow the Company to file a general rate case that would allow a change in rate base prior to January 1, 2006. A status conference in that proceeding is scheduled for November 7, 2003.

On October 13, 2003, the Company filed petitions with the WUTC for accounting orders to allow deferral and amortization of the Trail Mountain coal mine closure costs and environmental remediation costs. These filings were made in response to the stipulation approved in the last general rate proceeding in Washington requiring that items treated as regulatory assets under authorizations from other states that are proposed for inclusion in Washington at the end of the rate plan period be supported by accounting authorizations in Washington.

Idaho

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

California

On June 19, 2003, the Company and the California Public Utilities Commission’s (“CPUC”) Office of Ratepayer Advocates executed a settlement agreement addressing revenue requirements in the Company’s pending general rate case. On July 7, 2003, an all-party settlement was filed addressing revenue allocation and rate design. Hearings were held in June and July to consider the respective settlement agreements and to receive evidence and exhibits into the record. On September 9, 2003, an administrative law judge issued a draft order approving the settlement and establishing a 30-day comment period. The matter is currently scheduled for consideration at the CPUC’s November 13, 2003 business meeting. If the CPUC approves the draft order on November 13, 2003, the likely effective date would be December 1, 2003. If the draft order is approved, the Company would be allowed to recover approximately $2.8 million annually in addition to the $4.7 million collected annually through the interim increase approved by the CPUC in June 2002.

Affiliated Interest Filings

On September 30, 2003, the Company made compliance filings for a cross-charge policy agreement governing the allocation of costs incurred by the Company and by Scottish Power UK plc, a subsidiary of Scottish Power plc, on behalf of each other. Filings were submitted to Utah, Oregon, Wyoming, Washington and Idaho. The agreement establishes a process for directly assigning or allocating costs between the Company and Scottish Power UK plc for common corporate functions. These charges to the Company are estimated to be approximately $20 million annually.

PROPOSED ASSET DISPOSITION

In July 1998, the Company announced its intention to sell its California service territory, including its electric distribution assets, to Nor-Cal Electric Authority (“Nor-Cal”). In June 2002, the California county of Siskiyou filed a validation action in California superior court, challenging the authority of Nor-Cal to enter into such a transaction and alleging certain conflicts of interest between Nor-Cal and its advisors. On August 7, 2003, the Company announced that it was concluding talks with Nor-Cal and ending all efforts to sell the Company’s California service area.

INTEGRATED RESOURCE PLAN

The Company’s Integrated Resource Plan was filed with the relevant state commissions on January 24, 2003. The Integrated Resource Plan is a regulatory requirement in all states in which the Company operates, with the exception of Wyoming. The Integrated Resource Plan has been acknowledged in Utah, Oregon, Washington and Idaho, and the Company filed for an exemption in California.

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

The first of these three Requests for Proposal (RFP 2003A) was issued on June 6, 2003. RFP 2003A requested east side seasonal resources of 225 MW for the summer period (June through September) in years 2004-2007; resources of 200 MW for delivery starting by June 1, 2005; and resources of 570 MW for delivery starting by June 1, 2007. No seasonal supply resources have been procured to date although negotiations continue. The Currant Creek Project was demonstrated to be the most economical resource choice for a flexible resource capable of being available by June 2005. The Currant Creek Project is a 525 MW natural gas-fired combined-cycle combustion turbine generation project located approximately 75 miles south of Salt Lake City, Utah. The Currant Creek Project will be constructed in two phases with two 140 MW (280 MW total) simple-cycle combustion turbines being installed during calendar year 2005.Two heat-recovery steam generators and a steam generation turbine will be added in calendar year 2006 to bring the plant output to a total of 525 MW. In addition, the Company requested a resource capable of being available by June 2007. Evaluation of responses to the Company’s request for a 570 MW, or more, resource capable of being available by June 2007 continues. This may result in a long-term power purchase agreement, a facility lease or investment in an additional generation plant.

The second Request for Proposal (RFP 2003B) is expected to be issued in December 2003 and will request approximately 1,100 MW of renewable resources for the Company’s entire service territory. The third Request for Proposal (RFP2004A) is expected to be issued in early calendar year 2004 and will request additional resources to

serve the Company’s eastern service territory in Utah, Wyoming and Idaho. The expected total cycle time for each Request for Proposal process is approximately six to eight months.

In addition to the three supply-side Requests for Proposal, the Company issued a separate Request for Proposal for the demand-side resources called for in the Integrated Resource Plan. The demand-side Request for Proposal requested 100 MW or more of conservation to be obtained over the next 10 years and load control proposals specifically addressing peak load. The demand-side Request for Proposal was issued on June 26, 2003, with responses due on August 18, 2003. Analysis of initial responses has been completed and a short-list of bidders has been selected for further evaluation.

The effects of a recently updated load forecast may result in demand-side and supply-side resources being procured or constructed that are in excess of that originally published in the Integrated Resource Plan. An update to the Integrated Resource Plan has been filed with the regulatory commissions in the states the Company serves.

MULTI-STATE PROCESS

The Company is involved in a collaborative process with the six states it serves to develop mutually acceptable solutions to the issues faced by the Company and the states, as a result of the Company’s multistate operations. These issues pertain to the inconsistent allocation of some of the cost of the Company’s existing investments and the recovery of the cost of future investments. Between April 2002 and July 2003, the Company and key parties from Utah, Oregon, Wyoming, Washington and Idaho, along with a key monitoring contact from California, analyzed over 50 options to address these issues, which were narrowed to two possibilities. Both sought to clarify roles and responsibilities, including cost allocations for future generation resources and provide states with the ability to independently implement state energy policy objectives, and achieve permanent consensus on each state’s responsibility for the costs and entitlement to the benefits of the Company’s existing assets. Following the July 2003 meeting, the Company undertook extensive analytical work to develop a single proposal that would best balance the needs of the Company and requirements of the states in addressing the positions, issues and concerns raised and discussed during the course of the collaborative and individual state meetings. This work culminated in a regulatory filing on September 30, 2003 in the states of Utah, Oregon, Wyoming and Idaho. Similar filings in Washington and California will follow in coordination with rate case activity. The states are now working to set regulatory process schedules in preparation for the hearings in the near future.

ITEM 6.

EXHIBITS AND REPORTS ON FORM 8-K

(a) Exhibits.

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

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

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

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

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

Exhibit Number	File Type	File Date	File Number

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

4.2*		Third Restated Articles of Incorporation and Bylaws. See 3.1 and 3.2 above.
12.1		Statements of Computation of Ratio of Earnings to Fixed Charges
12.2		Statements of Computation of Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividends
15		Letter regarding unaudited interim financial information
31.1		Principal Executive Officer Certification Pursuant to Sarbanes-Oxley Act of 2002, Section 302
31.2		Principal Financial Officer Certification Pursuant to Sarbanes-Oxley Act of 2002, Section 302
32.1		Principal Executive Officer Certification Pursuant to Sarbanes-Oxley Act of 2002, Section 906
32.2		Principal Financial Officer Certification Pursuant to Sarbanes-Oxley Act of 2002, Section 906

Incorporated herein by reference.

(b) Reports on Form 8-K.

On Form 8-K, dated August 7, 2003, under Item 5. Other Events, the Company announced that it was concluding its talks with Nor-Cal and ending all efforts to sell the Company’s California service area to Nor-Cal.

On Form 8-K, dated August 27, 2003, under Item 5. Other Events, the Company announced that the OPUC had granted approximately $8.5 million of additional annual revenues, the removal of merger credits of approximately $12.0 million and an additional $5.0 million in revenues in the current fiscal year due to allowing implementation of the new rates five months earlier than scheduled.

On Form 8-K, dated September 8, 2003, under Item 5. Other Events, the Company announced that it had issued $200.0 million of its 4.30% First Mortgage Bonds due September 15, 2008 and $200.0 million of its 5.45% First Mortgage Bonds due September 15, 2013.

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: November 5, 2003	By:	/s/ RICHARD D. PEACH

		Richard D. Peach Chief Financial Officer