PACIFICORP /OR/ - Quarter Report: 2005 December (Form 10-Q)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

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

		For the quarterly period ended December 31, 2005

		OR

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

		For the transition period from ________________ to ________________

Commission file number: 1-5152

PacifiCorp

(Exact name of registrant as specified in its charter)

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

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

503-813-5000

(Registrant’s telephone number, including area code)

None

(Former name, former address and former fiscal year, if changed since last report)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

Yes x No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act.

Large accelerated filer o Accelerated filer o Non-accelerated filer x

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

Yes o No x

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date.

Class		Outstanding at February 10, 2006

Common Stock, no par value		347,158,187 shares

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	2

Item 1.	Financial Statements	2

	Condensed Consolidated Statements of Income and Retained Earnings	2

	Condensed Consolidated Balance Sheets	3

	Condensed Consolidated Statements of Cash Flows	5

	Notes to the Condensed Consolidated Financial Statements	6

	Report of Independent Registered Public Accounting Firm	19

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

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	32

Item 4.	Controls and Procedures	36

PART II.	OTHER INFORMATION	36

	Information Regarding Recent Regulatory Developments	36

Item 1.	Legal Proceedings	38

Item 1A.	Risk Factors	38

Item 6.	Exhibits	39

Signature		40

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

PACIFICORP

CONDENSED CONSOLIDATED STATEMENTS OF INCOME AND RETAINED EARNINGS

(Unaudited)

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

(Millions of dollars)	2005			2004			2005			2004

Revenues	$	1,165.0		$	849.5		$	2,667.1		$	2,426.0

Operating expenses:
Energy costs		529.5			327.7			997.0			889.2
Operations and maintenance		243.7			234.2			740.8			689.5
Depreciation and amortization		112.4			110.1			335.6			326.7
Taxes, other than income taxes		23.2			22.3			72.4			70.5

Total		908.8			694.3			2,145.8			1,975.9

Income from operations		256.2			155.2			521.3			450.1

Interest expense and other (income) expense:
Interest expense		71.1			68.2			210.5			199.3
Interest income		(2.5	)		(2.3	)		(7.1	)		(7.6	)
Interest capitalized		(7.9	)		(3.3	)		(21.4	)		(9.2	)
Minority interest and other		(0.8	)		(4.6	)		(3.4	)		(8.4	)

Total		59.9			58.0			178.6			174.1

Income from operations before income tax expense		196.3			97.2			342.7			276.0
Income tax expense		68.5			45.9			129.1			111.9

Net income		127.8			51.3			213.6			164.1
Preferred dividend requirement		(0.6	)		(0.6	)		(1.6	)		(1.6	)

Earnings on common stock	$	127.2		$	50.7		$	212.0		$	162.5

RETAINED EARNINGS AT BEGINNING OF PERIOD	$	427.6		$	405.3		$	446.4		$	390.1
Net income		127.8			51.3			213.6			164.1
Cash dividends declared:
Preferred stock		(0.6	)		(0.6	)		(1.6	)		(1.6	)
Common stock		(54.6	)		(48.3	)		(158.2	)		(144.9	)

RETAINED EARNINGS AT END OF PERIOD	$	500.2		$	407.7		$	500.2		$	407.7

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

PACIFICORP

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

(Millions of dollars)	December 31, 2005			March 31, 2005

ASSETS
Current assets:
Cash and cash equivalents	$	163.6		$	199.3
Accounts receivable (less allowance for doubtful accounts of $10.9/December and $11.6/March)		273.0			293.0
Unbilled revenue		169.6			143.8
Amounts due from affiliates		1.9			36.5
Inventories at average costs:
Materials and supplies		125.7			114.7
Fuel		63.3			58.5
Current derivative contract asset		380.1			252.7
Other		48.7			115.8

Total current assets		1,225.9			1,214.3

Property, plant and equipment		14,825.3			14,259.0
Construction work-in-progress		625.4			593.4
Accumulated depreciation and amortization		(5,558.9	)		(5,361.8	)

Total property, plant and equipment - net		9,891.8			9,490.6

Other assets:
Regulatory assets		906.1			972.8
Derivative contract regulatory asset		—			170.0
Non-current derivative contract asset		504.8			360.3
Deferred charges and other		298.8			312.9

Total other assets		1,709.7			1,816.0

Total assets	$	12,827.4		$	12,520.9

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

PACIFICORP

CONDENSED CONSOLIDATED BALANCE SHEETS, continued

(Unaudited)

(Millions of dollars)	December 31, 2005			March 31, 2005

LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	301.0		$	350.4
Amounts due to affiliates		6.3			3.9
Accrued employee expenses		102.3			134.3
Taxes payable		28.1			39.8
Interest payable		53.0			64.8
Current derivative contract liability		210.2			136.7
Current deferred tax liability		29.0			2.0
Long-term debt and capital lease obligations, currently maturing		311.0			269.9
Preferred stock subject to mandatory redemption, currently maturing		3.7			3.7
Notes payable and commercial paper		214.6			468.8
Other		119.3			123.4

Total current liabilities		1,378.5			1,597.7

Deferred credits:
Deferred income taxes		1,601.7			1,629.0
Investment tax credits		69.6			75.6
Regulatory liabilities		814.4			806.0
Derivative contract regulatory liability		92.3			—
Non-current derivative contract liability		533.1			630.5
Pension and other post employment liabilities		432.2			422.4
Other		329.8			304.8

Total deferred credits		3,873.1			3,868.3

Long-term debt and capital lease obligations, net of current maturities		3,729.5			3,629.0
Preferred stock subject to mandatory redemption, net of current maturities		41.3			48.8

Total liabilities		9,022.4			9,143.8

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

Common equity:
Common shareholder’s capital		3,269.1			2,894.1
Retained earnings		500.2			446.4
Accumulated other comprehensive income (loss):
Unrealized gain on available-for-sale securities, net of tax of $2.1/December and $2.6/March		3.4			4.3
Minimum pension liability, net of tax of $(5.5)/December and March		(9.0	)		(9.0	)

Total common equity		3,763.7			3,335.8

Total shareholders’ equity		3,805.0			3,377.1

Total liabilities and shareholders’ equity	$	12,827.4		$	12,520.9

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

PACIFICORP

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Nine Months Ended December 31,

(Millions of dollars)	2005			2004

Cash flows from operating activities:
Net income	$	213.6		$	164.1
Adjustments to reconcile net income to net cash provided by operating activities:
Unrealized (gain) loss on derivative contracts		(33.5	)		0.7
Depreciation and amortization		335.6			326.7
Deferred income taxes and investment tax credits - net		6.2			64.1
Regulatory asset/liability establishment and amortization - net		45.6			52.1
Other		43.5			(1.8	)
Changes in:
Accounts receivable, prepayments and other current assets		38.8			(117.4	)
Inventories		(15.8	)		(4.2	)
Amounts due to/from affiliates, net		37.0			(33.5	)
Accounts payable and accrued liabilities		(114.3	)		(71.4	)
Other		16.5			(21.1	)

Net cash provided by operating activities		573.2			358.3

Cash flows from investing activities:
Capital expenditures		(716.1	)		(539.9	)
Proceeds from sales of assets		1.3			4.7
Proceeds from available-for-sale securities		91.0			38.5
Purchases of available-for-sale securities		(65.2	)		(37.9	)
Other		0.3			(5.4	)

Net cash used in investing activities		(688.7	)		(540.0	)

Cash flows from financing activities:
Changes in short-term debt		(254.2	)		159.8
Proceeds from long-term debt, net of issuance costs		296.0			395.2
Proceeds from equity contributions		375.0			—
Dividends paid		(159.8	)		(146.5	)
Repayments and redemptions of long-term debt		(169.7	)		(252.8	)
Redemptions of preferred stock		(7.5	)		(7.5	)

Net cash provided by financing activities		79.8			148.2

Change in cash and cash equivalents		(35.7	)		(33.5	)
Cash and cash equivalents at beginning of period		199.3			58.5

Cash and cash equivalents at end of period	$	163.6		$	25.0

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 Summary of Significant Accounting Policies

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

The accompanying unaudited Condensed Consolidated Financial Statements as of December 31, 2005 and for the three and nine months ended December 31, 2005 and 2004, in the opinion of management, include all normal recurring adjustments necessary for a fair statement of financial position, results of operations and cash flows for such periods. The March 31, 2005 Condensed Consolidated Balance Sheet data was derived from audited financial statements. These statements as of December 31, 2005 and for the three and nine months ended December 31, 2005 and 2004 are presented in accordance with the interim reporting requirements of the Securities and Exchange Commission (the “SEC”) and therefore do not include all of the disclosures required by accounting principles generally accepted in the United States of America. Certain information and footnote disclosures made in PacifiCorp’s Annual Report on Form 10-K for the year ended March 31, 2005 have been condensed or omitted from the interim statements. A portion of the business of PacifiCorp is of a seasonal nature and, therefore, results of operations for the three and nine months ended December 31, 2005 and 2004 are not necessarily indicative of the results for a full year. These Condensed Consolidated Financial Statements should be read in conjunction with the financial statements and related notes in PacifiCorp’s Annual Report on Form 10-K for the year ended March 31, 2005.

These interim statements have been prepared using accounting policies consistent with those applied at March 31, 2005.

Sale of PacifiCorp

On May 23, 2005, ScottishPower and PacifiCorp Holdings, Inc. (“PHI”), PacifiCorp’s direct parent company, executed a Stock Purchase Agreement (the “Stock Purchase Agreement”) providing for the sale of all PacifiCorp common stock to MidAmerican Energy Holdings Company (“MidAmerican”) for a value of approximately $9.4 billion, consisting of approximately $5.1 billion in cash plus approximately $4.3 billion in net debt and preferred stock, which will remain outstanding at PacifiCorp. MidAmerican is based in Des Moines, Iowa, and is a privately owned global provider of energy services.

The closing of the sale of PacifiCorp is subject to a number of conditions, including ScottishPower shareholder consent and regulatory notification and/or approvals from the Federal Energy Regulatory Commission (the “FERC”), the Department of Justice or the Federal Trade Commission, the Federal Communications Commission, the Nuclear Regulatory Commission and the public utility commissions in the states of Utah, Oregon, Wyoming, Washington, Idaho and California, as well as consents under existing third-party agreements. Pending satisfaction of the closing conditions, the Stock Purchase Agreement requires ScottishPower and PHI to cause PacifiCorp to operate its business in the ordinary course consistent with past business practice. The Stock Purchase Agreement also requires ScottishPower and PHI to obtain MidAmerican’s prior approval to certain actions taken by PacifiCorp beyond limits specified in the Stock Purchase Agreement, including:

•	borrowings or debt issuances;

•	capital expenditures;

•	construction or acquisition of new generation, transmission or delivery facilities or systems, other than as budgeted or necessary to fulfill regulatory commitments;

•	unbudgeted significant acquisitions or dispositions;

•	modifications to material agreements with regulators;

•	issuance or sale of any capital stock to any person, other than PHI in certain circumstances;

•	adoption or amendment of employee benefit plans or material increases to employee compensation; and

•	payment of dividends to PHI.

While the sale of PacifiCorp is pending and the Stock Purchase Agreement is in effect, ScottishPower and PHI have agreed to make common equity contributions to PacifiCorp of $125.0 million at the end of each quarter in fiscal year 2006 and $131.25 million at the end of each quarter in fiscal year 2007. If the sale is completed, MidAmerican will refund to PHI the amount of required fiscal year 2007 common equity contributions as an increase to the purchase price. As described in Note 7 – Common Shareholder’s Equity, PHI has made the equity contributions required to date by the Stock Purchase Agreement.

Pursuant to the Stock Purchase Agreement, ScottishPower has agreed to cause PacifiCorp to not pay quarterly dividends to PHI in excess of $214.8 million in the aggregate during fiscal year 2006 and $242.3 million in the aggregate during fiscal year 2007. These restrictions will terminate upon either the close of the sale of PacifiCorp or the earlier termination of the Stock Purchase Agreement.

PacifiCorp is party to pre-existing agreements with affiliates of MidAmerican for certain gas transportation and steam purchase transactions. These transactions are not significant to PacifiCorp’s Energy costs.

Pursuant to the Stock Purchase Agreement, upon the closing of PacifiCorp’s sale to MidAmerican, PacifiCorp will settle outstanding intercompany liabilities with ScottishPower subsidiaries and transfer to certain of these affiliate entities the assets and liabilities associated with the participation of affiliate employees in benefit plans sponsored by PacifiCorp.

Reclassifications

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

Stock-based Compensation

As permitted by Statement of Financial Accounting Standards (“SFAS”) No. 123, Accounting for Stock-Based Compensation (“SFAS No. 123”), PacifiCorp accounts for its stock-based compensation arrangements, primarily employee stock options, 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 PacifiCorp 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 if the ultimate number of shares to be awarded is known at the date of the grant. All options are issued in ScottishPower American Depository Shares. Had PacifiCorp determined compensation cost based on the fair value at the grant date for all stock options vesting in each period under SFAS No. 123, PacifiCorp’s net income would have been reduced to the pro forma amounts below:

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

(Millions of dollars)	2005			2004			2005			2004

Net income as reported	$	127.8		$	51.3		$	213.6		$	164.1
Add: stock-based compensation expense using the intrinsic value method, net of related tax effects		—			0.2			0.1			0.7
Less: stock-based compensation expense using the fair value method, net of related tax effects		(0.3	)		(0.5	)		(0.9	)		(1.6	)

Pro forma net income	$	127.5		$	51.0		$	212.8		$	163.2

New Accounting Standards

SFAS No. 123R and SAB No. 107

In December 2004, the FASB issued SFAS No. 123R, Share-Based Payment (“SFAS No. 123R”), a revision of the originally issued SFAS No. 123. SFAS No. 123R establishes standards for the accounting for transactions in which an entity exchanges its equity instruments for goods or services. In March 2005, the SEC issued Staff Accounting Bulletin (“SAB”) No. 107 (“SAB No. 107”), which provides additional guidance in applying the provisions of SFAS No. 123R. SFAS No. 123R requires that the cost resulting from all share-based payment transactions be recognized in the financial statements using the fair value method. The intrinsic value method of accounting established by APB No. 25 will no longer be allowed. SAB No. 107 describes the SEC Staff’s guidance in determining the assumptions that underlie the fair value estimates and discusses the interaction of SFAS No. 123R with other existing SEC guidance.

In April 2005, the effective date of SFAS No. 123R was deferred until the beginning of the fiscal year that begins after June 15, 2005; however, early adoption is encouraged. A modified prospective application is required for new awards and for awards modified, repurchased or cancelled after the required effective date. The provisions of SAB No. 107 will be applied upon adoption of SFAS No. 123R.

Certain PacifiCorp employees receive awards under various ScottishPower share-based payment plans. Application to these awards of the fair value method required by SFAS No. 123R, as compared to the application of the intrinsic value method allowed under APB No. 25, is not expected to result in a material change to recorded compensation expense upon adoption of SFAS No. 123R.

FSP SFAS No. 109-1

In December 2004, the FASB issued FASB Staff Position (“FSP”) SFAS No. 109-1, Application of FASB Statement No. 109, Accounting for Income Taxes, to the Tax Deduction on Qualified Production Activities Provided by the American Jobs Creation Act of 2004. The tax deduction addressed in FSP SFAS No. 109-1 will be treated as a “special deduction” as described in SFAS No. 109, Accounting for Income Taxes. As such, the special deduction has no effect on deferred tax assets and liabilities existing at the enactment date. Rather, the impact of this deduction will be reported in the period in which the deduction could be claimed on a separate return basis in accordance with PacifiCorp’s accounting policy. This statement became effective upon issuance. PacifiCorp currently believes the effect of this statement on its consolidated financial position and results of operations is immaterial.

FIN 47

In March 2005, the FASB issued FASB Interpretation No. 47, Accounting for Conditional Asset Retirement Obligations – an Interpretation of FASB Statement No. 143 (“FIN 47”). FIN 47 clarifies that the term “conditional asset retirement obligation” as used in SFAS No. 143 refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity. The obligation to perform the asset retirement activity is unconditional, even though uncertainty exists about the timing and/or method of settlement. FIN 47 clarifies that an entity is required to recognize a liability for the fair value of a conditional asset retirement obligation when incurred if the liability’s fair value can be reasonably estimated. FIN 47 is effective at the end of the fiscal year ending after December 15, 2005. PacifiCorp is currently evaluating the impact of adopting FIN 47 on its consolidated financial position and results of operations.

EITF No. 04-6

In March 2005, the Emerging Issues Task Force (the “EITF”) issued EITF No. 04-6, Accounting for Stripping Costs Incurred during Production in the Mining Industry (“EITF No. 04-6”). EITF No. 04-6 requires that stripping costs incurred during the production phase of a mine are variable production costs that should be included in the costs of the inventory produced (that is, extracted) during the period that the stripping costs are incurred. EITF No. 04-6 is effective for all fiscal years beginning after December 15, 2005 and is expected to be adopted by PacifiCorp on April 1, 2006. While the Company is currently evaluating what impact this guidance will have on its consolidated financial statements, its adoption is not expected to have a material impact on PacifiCorp’s consolidated financial position or results of operations.

Note 2 - Accounting for the Effects of Regulation

PacifiCorp records regulatory assets and liabilities based on management’s assessment that it is probable that a cost will be recovered (asset) or that an obligation has been incurred (liability) in accordance with the provisions of SFAS No. 71, Accounting for the Effects of Certain Types of Regulation. The final outcome, or additional regulatory actions, could change management’s assessment in future periods.

Regulatory assets include the following:

(Millions of dollars)	December 31, 2005		March 31, 2005

Deferred income taxes	$	485.1	$	499.9
Minimum pension liability		280.7		280.7
Unamortized issuance costs on retired debt		30.3		34.6
Demand-side resource costs		15.6		25.5
Transition plan - retirement and severance		17.8		24.9
Various other costs		76.6		107.2

Subtotal		906.1		972.8
Derivative contracts (a)		—		170.0

Total	$	906.1	$	1,142.8

(a)	Represents net unrealized losses related to derivative contracts included in rates at March 31, 2005. See Note 3 – Derivative Instruments for further information.

Regulatory liabilities include the following:

(Millions of dollars)	December 31, 2005		March 31, 2005

Asset retirement removal costs (a)	$	709.8	$	692.1
Bonneville Power Administration Regional Exchange Program		21.9		12.6
Deferred income taxes		41.7		44.4
Various other costs		41.0		56.9

Subtotal		814.4		806.0
Derivative contracts (b)		92.3		—

Total	$	906.7	$	806.0

(a)	Represents removal costs recovered in rates.

(b)	Represents net unrealized gains related to derivative contracts included in rates at December 31, 2005. See Note 3 – Derivative Instruments for further information.

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

Note 3 - Derivative Instruments

PacifiCorp’s derivative instruments are recorded on the Condensed Consolidated Balance Sheets as assets or liabilities measured at estimated fair value, unless they qualify for certain exemptions permitted under SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended. Changes in fair value of PacifiCorp’s recorded derivative contracts are recognized immediately in the Condensed Consolidated Statements of Income and Retained Earnings, except for contracts probable of recovery in rates based upon approval in states comprising substantially all of PacifiCorp’s retail revenues. The net change in fair value for such contracts is

deferred as either a regulatory asset or liability until realized. Unrealized gains and losses on derivative contracts held for trading purposes are presented on a net basis in Revenues. Unrealized gains and losses on derivative contracts not held for trading purposes are presented on a gross basis in Revenues for sales contracts and in Energy costs and Operations and maintenance expense for purchase contracts and financial swaps.

Unrealized gains and losses on energy sales and purchase contracts are affected by fluctuations in forward market prices for electricity and natural gas. The following table summarizes the amount of the pre-tax unrealized gains and losses included within the Condensed Consolidated Statements of Income and Retained Earnings associated with changes in the fair value of PacifiCorp’s derivative contracts.

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

(Millions of dollars)	2005			2004			2005			2004

Revenues	$	239.4		$	(55.1	)	$	(53.7	)	$	(102.7	)
Operating expenses:
Energy costs		(155.7	)		39.6			92.2			102.0
Operations and maintenance		(4.2	)		—			(5.0	)		—

Total unrealized gain (loss) on derivative contracts	$	79.5		$	(15.5	)	$	33.5		$	(0.7	)

The following table summarizes the changes in fair value of PacifiCorp’s derivative contracts executed for balancing system resources and load obligations (non-trading) and for taking advantage of arbitrage opportunities (trading) for the nine months ended December 31, 2005, as well as the portion of those amounts that has been recognized as a regulatory net asset (liability) because the contracts are receiving recovery in rates.

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

(Millions of dollars)	Trading			Non-trading

Fair value of contracts outstanding at March 31, 2005	$	0.2		$	(154.4	)	$	170.0
Contracts realized or otherwise settled during the period		(0.1	)		(72.7	)		74.0
Other changes in fair values (a)		(0.3	)		368.9			(336.3	)

Fair value of contracts outstanding at December 31, 2005	$	(0.2	)	$	141.8		$	(92.3	)

(a)	Other changes in fair values include the effects of changes in market prices, inflation rates and interest rates, including those based on models, on new and existing contracts.

(b)	Net unrealized losses (gains) related to derivative contracts included in rates are recorded as a regulatory net asset (liability).

Weather derivatives - PacifiCorp currently has a non-exchange traded streamflow weather derivative contract to reduce PacifiCorp’s exposure to variability in weather conditions that affect hydroelectric generation. Under the agreement, PacifiCorp pays an annual premium in return for the right to make or receive payments if streamflow levels are above or below certain thresholds. PacifiCorp estimates and records an asset or liability corresponding to the total expected future cash flow under the contract in accordance with EITF No. 99-2, Accounting for Weather Derivatives. The net asset recorded for this contract was zero at December 31, 2005 and $20.3 million at March 31, 2005. PacifiCorp did not recognize a net gain or net loss on this contract for the three months ended December 31, 2005 or 2004 because streamflow levels did not meet the required thresholds for these periods. PacifiCorp recognized a loss on this contract of $15.6 million for the nine months ended December 31, 2005 and a gain on this contract of $2.9 million for the nine months ended December 31, 2004.

Note 4 – Related-Party Transactions

There are no loans or advances between PacifiCorp and ScottishPower or between PacifiCorp and PHI. Loans from ScottishPower or PHI to PacifiCorp generally require state regulatory approval. There are intercompany loan agreements that allow funds to be lent from PacifiCorp Group Holdings Company (“PGHC”) to PacifiCorp, but

loans from PacifiCorp to PGHC are prohibited. There are intercompany loan agreements that allow funds to be lent between PacifiCorp and Pacific Minerals, Inc., a wholly owned subsidiary of PacifiCorp. PacifiCorp does not maintain a centralized cash or money pool. Therefore, funds of each company are not commingled with funds of any other company. Other affiliate transactions that PacifiCorp enters into are subject to certain approval and reporting requirements of the regulatory authorities.

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

(Millions of dollars)	December 31, 2005		March 31, 2005

Amounts due from affiliated entities:
SPUK (a)	$	0.1	$	0.3
PHI and its subsidiaries (b)		1.8		36.2

	$	1.9	$	36.5

Prepayments to affiliated entities:
PHI and its subsidiaries (c)	$	—	$	1.5
DIIL (d)		1.8		—

	$	1.8	$	1.5

Amounts due to affiliated entities:
SPUK (e)	$	2.3	$	3.9
PHI and its subsidiaries (f)		4.0		—

	$	6.3	$	3.9

Deposits received from affiliated entities:
PHI and its subsidiaries (g)	$	0.3	$	0.3

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

	2005		2004		2005		2004

Revenues from affiliated entities:
PHI and its subsidiaries (g)	$	3.1	$	1.1	$	5.7	$	4.7


Expenses recharged to affiliated entities:
SPUK (a)	$	1.7	$	0.9	$	5.5	$	2.1
PHI and its subsidiaries (b)		1.4		2.3		6.1		6.5

	$	3.1	$	3.2	$	11.6	$	8.6


Expenses incurred from affiliated entities:
SPUK (e)	$	4.3	$	4.0	$	12.9	$	15.5
PHI and its subsidiaries (c)		6.6		4.5		15.5		13.0
DIIL (d)		1.9		—		5.4		—

	$	12.8	$	8.5	$	33.8	$	28.5

(a)

These receivables and expenses primarily represent costs associated with retention agreements and severance benefits reimbursable by Scottish Power UK plc (“SPUK”), an indirect subsidiary of ScottishPower, and amounts allocated to SPUK by PacifiCorp for administrative services provided under ScottishPower’s affiliated interest cross-charge policy. In addition, PacifiCorp recharged to SPUK payroll costs and related benefits of PacifiCorp employees working on international assignment in the United Kingdom during each of the three and nine months ended December 31, 2005 and 2004.

(b)

Amounts shown pertain to activities of PacifiCorp with PHI and its subsidiaries. Expenses recharged reflect costs for support services to PHI and its subsidiaries. Amounts due from PHI and its subsidiaries include $33.8 million as of March 31, 2005 of taxes receivable from PHI. PHI is the tax-paying entity for PacifiCorp.

(c)

These expenses primarily relate to operating lease payments for the West Valley facility, located in Utah and owned by West Valley Leasing Company, LLC (“West Valley”). West Valley is a subsidiary of PPM Energy, Inc. (“PPM”), which is a subsidiary of PHI. Certain costs associated with the West Valley lease are prepaid on an annual basis. Lease expense for the West Valley facility for the three months ended December

31, 2005 and 2004 was $4.2 million and for the nine months ended December 31, 2005 and 2004 was $12.6 million.

(d)

PacifiCorp began participating in a captive insurance program provided by Dornoch International Insurance Limited (“DIIL”), an indirect wholly owned consolidated subsidiary of ScottishPower, in May 2005. DIIL covers all or significant portions of the property damage and liability insurance deductibles in many of PacifiCorp’s current policies, as well as overhead distribution and transmission line property damage. PacifiCorp has no equity interest in DIIL and has no obligation to contribute equity or loan funds to DIIL. Premium amounts are established to cover loss claims, administrative expenses and appropriate reserves, but otherwise DIIL is not operated to generate profits. Certain costs associated with the captive insurance program are prepaid.

(e)

These liabilities and expenses primarily represent amounts allocated to PacifiCorp by SPUK for administrative services received under the cross-charge policy. Cross-charges from SPUK to PacifiCorp amounted to $3.8 million for the three months ended December 31, 2005 and 2004, $11.9 million for the nine months ended December 31, 2005 and $12.4 for the nine months ended December 31, 2004. These costs were recorded in Operations and maintenance expense. SPUK also recharged PacifiCorp for payroll costs and related benefits of SPUK employees working on international assignments with PacifiCorp in the United States for the three and nine months ended December 31, 2005 and 2004.

(f)	The amount shown primarily represents taxes payable to PHI as of December 31, 2005. PHI is the tax-paying entity for PacifiCorp.

(g)

These revenues and the associated deposits relate to wheeling services billed to PPM. PacifiCorp provides these services to PPM pursuant to PacifiCorp’s FERC-approved open access transmission tariff, which requires PacifiCorp to make transmission services available on a non-discriminatory basis to all interested parties.

Note 5 - Financing Arrangements

Long-Term Debt

In September 2005, the SEC declared effective PacifiCorp’s shelf registration statement covering $700.0 million of future first mortgage bond and unsecured debt issuances. PacifiCorp has not yet issued any of the securities covered by this registration statement.

In June 2005, PacifiCorp issued $300.0 million of its 5.25% Series of First Mortgage Bonds due June 15, 2035. PacifiCorp used the proceeds for the reduction of short-term debt, including the short-term debt used in December 2004 to redeem its 8.625% Series of First Mortgage Bonds due December 13, 2024 totaling $20.0 million.

Other Financing Arrangements

During the nine months ended December 31, 2005, PacifiCorp entered into three new standby letters of credit, which totaled $56.7 million at December 31, 2005.

During the nine months ended December 31, 2005, PacifiCorp amended $421.3 million of its existing committed standby bond purchase and letter of credit agreements, which provide credit enhancement and liquidity support for eight series of variable-rate pollution control revenue bond obligations. Changes included an exclusion of the acquisition of PacifiCorp by MidAmerican as an event of default under the agreements.

In August 2005, PacifiCorp amended and restated its existing $800.0 million committed bank revolving credit agreement. Changes included an increase to 65.0% in the covenant not to exceed a specified debt-to-capitalization percentage, extension of the termination date to August 29, 2010 and an exclusion of the acquisition of PacifiCorp by MidAmerican as an event of default under the agreement.

Note 6 - Commitments and Contingencies

PacifiCorp follows SFAS No. 5, Accounting for Contingencies, to determine accounting and disclosure requirements for contingencies. PacifiCorp operates in a highly regulated environment. Governmental bodies such as the FERC, state regulatory commissions, the SEC, the Internal Revenue Service, the Department of Labor, the United States Environmental Protection Agency (the “EPA”) and others have authority over various aspects of PacifiCorp’s

business operations and public reporting. Reserves are established when required, in management’s judgment, and disclosures regarding litigation, assessments and creditworthiness of customers or counterparties, among others, are made when appropriate. The evaluation of these contingencies is performed by various specialists inside and outside of PacifiCorp.

Litigation

In May 2004, PacifiCorp was served with a complaint filed in the United States District Court for the District of Oregon by the Klamath Tribes of Oregon, individual Klamath Tribal members and the Klamath Claims Committee. The complaint generally alleges that PacifiCorp and its predecessors affected the Klamath Tribes’ federal treaty rights to fish for salmon in the headwaters of the Klamath River in southern Oregon by building dams that blocked the passage of salmon upstream to the headwaters beginning in 1911. In September 2004, the Klamath Tribes filed their first amended complaint adding claims of damage to their treaty rights to fish for sucker and steelhead in the headwaters of the Klamath River. The complaint seeks in excess of $1.0 billion in compensatory and punitive damages. In July 2005, the District Court dismissed the case and in September 2005 denied the Klamath Tribes’ request to reconsider the dismissal. In October 2005, the Klamath Tribes appealed the District Court’s decision to the Ninth Circuit Court of Appeals and briefing is scheduled to be completed by March 2006. PacifiCorp believes the outcome of this proceeding will not have a material impact on its consolidated financial position, results of operations or liquidity.

In October 2005, PacifiCorp was added as a defendant to a lawsuit originally filed in February 2005 in state district court in Salt Lake City, Utah by USA Power, LLC and its affiliated companies, USA Power Partners, LLC and Spring Canyon, LLC (collectively, “USA Power”), against Utah attorney Jody L. Williams and the law firm Holme, Roberts & Owen, LLP, who represent PacifiCorp on various matters from time to time. USA Power is the developer of a planned generation project in Mona, Utah called Spring Canyon, which PacifiCorp, as part of its resource procurement process, at one time considered as an alternative to the Currant Creek Power Plant. USA Power’s complaint alleges that PacifiCorp misappropriated confidential proprietary information in violation of Utah’s Uniform Trade Secrets Act and accuses PacifiCorp of breach of contract and related claims. USA Power seeks $250.0 million in damages, statutory doubling of damages for its trade secrets violation claim, punitive damages, costs and attorneys’ fees. PacifiCorp believes it has a number of defenses and intends to vigorously oppose any claim of liability for the matters alleged by USA Power. Furthermore, PacifiCorp expects that the outcome of this proceeding will not have a material impact on its consolidated financial position, results of operations or liquidity.

In October 2005, the Utah Committee of Consumer Services (the “CCS”), a state utility consumer advocate, filed a request for agency action with the Utah Public Service Commission (the “UPSC”). The request seeks an order requiring PacifiCorp to return to Utah ratepayers certain monies collected in Utah rates for taxes, which the CCS alleges were improperly retained by PacifiCorp’s parent company, PHI. The CCS has publicly announced it is seeking a refund of at least $50.0 million to Utah ratepayers. In November 2005, PacifiCorp filed a response with the UPSC seeking dismissal of the request. In December 2005 that request was denied. PacifiCorp disagrees with, and intends to vigorously oppose, the claims made by the CCS. A procedural schedule to hear the matter has not been established.

In April 2004, PacifiCorp filed a complaint with the federal district court in Wyoming challenging the Wyoming Public Service Commission (the “WPSC”) decision made in March 2003 to deny recovery of the Hunter No. 1 replacement power costs and certain deferred excess net power costs. The complaint was filed on the grounds that the decision violates federal law by denying PacifiCorp recovery in retail rates of its wholesale electricity and transmission costs incurred to serve Wyoming customers. The lawsuit seeks an injunction requiring the WPSC to pass through PacifiCorp’s wholesale electricity and transmission costs in retail rates. In November 2004, the court denied the defendants’ motion to dismiss the complaint. In January 2005, the defendants appealed the court’s ruling on the motion to dismiss and requested a stay of the underlying litigation. The defendants’ appeal on sovereign immunity grounds and a decision on the issue of whether the defendants’ notice of appeal was timely are pending at the Tenth Circuit Court of Appeals. In February 2006, PacifiCorp and certain parties intervening in its pending Wyoming general rate case reached a settlement of the terms of PacifiCorp’s general rate case request. PacifiCorp also agreed to dismiss its federal lawsuit challenging the WPSC decision, and the defendants agreed to dismiss their pending appeal, subject to final approval of the general rate case settlement.

From time to time, PacifiCorp is also a party to various other legal claims, actions, complaints and disputes, certain of which involve material amounts. PacifiCorp recorded $7.1 million in reserves as of December 31, 2005 related to various outstanding legal actions and disputes, excluding those discussed below. PacifiCorp currently believes that disposition of these matters will not have a material adverse effect on PacifiCorp’s consolidated financial position, results of operations or liquidity.

Environmental Issues

PacifiCorp is subject to numerous environmental laws, including the Federal Clean Air Act and various state air quality laws; the Endangered Species Act, particularly as it relates to certain endangered species of fish; the Comprehensive Environmental Response, Compensation and Liability Act, and similar state laws relating to environmental cleanups; the Resource Conservation and Recovery Act, and similar state laws relating to the storage and handling of hazardous materials; and the Clean Water Act, and similar state laws relating to water quality. These laws could potentially impact future operations. Contingencies identified at December 31, 2005 principally consist of air quality matters. Pending or proposed air regulations will require PacifiCorp to reduce its electricity plant emissions of sulfur dioxide, nitrogen oxides and other pollutants below current levels. These reductions will be required to address regional haze programs, mercury emissions regulations and possible re-interpretations and changes to the federal Clean Air Act. In the future, PacifiCorp expects to incur significant costs to comply with various stricter air emissions requirements. These potential costs are expected to consist primarily of capital expenditures. PacifiCorp expects these costs would be included in rates and, as such, would not have a material adverse impact on PacifiCorp’s consolidated financial position or results of operations.

Hydroelectric Relicensing

PacifiCorp’s hydroelectric portfolio consists of 51 plants with an aggregate plant net capability of 1,159.4 MW. The FERC regulates 99.0% of the installed capacity through 18 individual licenses. Several of PacifiCorp’s hydroelectric projects are in some stage of relicensing under the Federal Power Act. Hydroelectric relicensing and the related environmental compliance requirements are subject to uncertainties. PacifiCorp expects that future costs relating to these matters may be significant and consist primarily of additional relicensing costs, operations and maintenance expense and capital expenditures. Electricity generation reductions may result from the additional environmental requirements. PacifiCorp has accumulated approximately $67.3 million in costs as of December 31, 2005 for ongoing hydroelectric relicensing that are reflected in assets on the Condensed Consolidated Balance Sheet. PacifiCorp expects that these and future costs will be included in rates and, as such, will not have a material adverse impact on PacifiCorp’s consolidated financial position or results of operations.

The Bear River license issued by the FERC that was final in May 2004 included a requirement to evaluate decommissioning the 7.5 MW Cove Plant and associated project features (the “Cove Development”). In July 2005, a settlement agreement to remove the Cove Development was signed by PacifiCorp, state and federal agencies, and non-governmental agencies. Decommissioning of the Cove Development is contingent upon receiving an amended FERC license and removal order that is not materially inconsistent with the settlement agreement and other regulatory approvals. The settlement agreement was filed with the FERC in August 2005 as part of an application to amend the Bear River project license to provide for the removal of the Cove Development while continuing the operation of the other Bear River project plants. Decommissioning of the Cove Development is expected to be completed by the end of calendar 2006 for a total cost not to exceed $3.9 million, excluding inflation.

In October 2005, the new FERC license for the North Umpqua hydroelectric project became final under the terms of the North Umpqua Settlement Agreement. Prior to this date, the license had been effective, but not final, because environmental groups had challenged its legality before the FERC and in federal court. In September 2005, the Ninth Circuit Court of Appeals issued an order upholding the new license. Since the Court’s order was not appealed within the allowed time, all legal challenges of the FERC license order have been exhausted and the license is final for purposes of recording liabilities. PacifiCorp is committed, over the 35-year life of the license, to fund approximately $47.5 million for environmental mitigation and enhancement projects. As a result of the license becoming final, PacifiCorp recorded additional liabilities and intangible assets in October 2005 amounting to a present value of $11.2 million. At December 31, 2005, the liability recorded for all North Umpqua obligations amounted to a present value of $22.9 million.

FERC Issues

California Refund Case - PacifiCorp is a party to a FERC proceeding that is investigating potential refunds for energy transactions in the California Independent System Operator and the California Power Exchange markets during past periods of high energy prices. PacifiCorp has a reserve of $17.7 million for these potential refunds. PacifiCorp’s ultimate exposure to refunds is dependent upon any order issued by the FERC in this proceeding. In addition, beginning in summer 2000, California market conditions resulted in defaults of amounts due to PacifiCorp from certain counterparties resulting from transactions with the California Independent System Operator and California Power Exchange. PacifiCorp has reserved $5.0 million for these receivables.

Northwest Refund Case - In June 2003, the FERC terminated its proceeding relating to the possibility of requiring refunds for wholesale spot-market bilateral sales in the Pacific Northwest between December 2000 and June 2001. The FERC concluded that ordering refunds would not be an appropriate resolution of the matter. In November 2003, the FERC issued its final order denying rehearing. Several market participants have filed petitions in the Ninth Circuit Court of Appeals for review of the FERC’s final order. A decision from the Ninth Circuit Court of Appeals is not expected to have a significant impact on PacifiCorp’s consolidated financial position or results of operations.

Federal Power Act Section 206 Case - In June 2003, the FERC issued a final order denying PacifiCorp’s request for recovery of excessive prices charged under certain wholesale electricity purchases scheduled for delivery during summer 2002 and dismissing PacifiCorp’s complaints, under Section 206 of the Federal Power Act, against five wholesale electricity suppliers. In July 2003, PacifiCorp filed its request for rehearing of the FERC’s order, which request was granted in August 2003. The FERC issued its final order denying rehearing in November 2003. Also in November 2003, PacifiCorp filed a petition in the Ninth Circuit Court of Appeals for review of the FERC’s final order denying recovery. Court briefs from interested parties were filed by March 2005. In August 2005, the Ninth Circuit Court of Appeals dismissed PacifiCorp’s appeal. In September 2005, PacifiCorp filed a request for rehearing of the Ninth Circuit’s decision. This request was denied by the Ninth Circuit in October 2005. PacifiCorp will not pursue further review of the case; therefore, the Ninth Circuit’s dismissal is final.

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

FERC Market Power Analysis - Pursuant to the FERC’s orders granting PacifiCorp authority to sell capacity and energy at market-based rates, PacifiCorp and certain of its affiliates are required to submit a joint market power analysis every three years. Under the FERC’s current policy, applicants must demonstrate that they do not possess market power in order to charge market-based rates for sales of wholesale energy and capacity in the applicants’ control areas. An analysis demonstrating an applicant’s passage of certain threshold screens for assessing generation market power establishes a rebuttable presumption that the applicant does not possess generation market power, while failure to pass any screen creates a rebuttable presumption that the applicant has generation market power. In February 2005, PacifiCorp submitted a joint triennial market power analysis in compliance with the FERC’s requirements. The analysis indicated that PacifiCorp failed to pass one of the generation market power screens in PacifiCorp’s eastern control area and in Idaho Power Company’s control area. In May 2005, the FERC issued an order instituting a proceeding pursuant to Section 206 of the Federal Power Act to determine whether PacifiCorp may continue to charge market-based rates for sales of wholesale energy and capacity in its east control area. Under the terms of the order, PacifiCorp and its affiliated co-applicants were required to submit additional information and analysis to the FERC within 60 days to rebut the presumption that PacifiCorp has generation market power. In June and July 2005, PacifiCorp filed additional analysis in response to the FERC’s May 2005 order. In January 2006, the FERC requested PacifiCorp to amend its previous filings with additional analysis. If the FERC ultimately finds that PacifiCorp has market power, PacifiCorp will be required to implement measures to mitigate

any exercise of market power, which may result in decreased revenues and/or increased operating expenses. PacifiCorp believes the outcome of this proceeding will not have a material impact on its consolidated financial position or results of operations.

Note 7 – Common Shareholder’s Equity

On December 30, 2005, PacifiCorp issued 11,627,907 shares of its common stock to its direct parent company, PHI, in consideration of the capital contribution of $125.0 million in cash made by PHI on that date. On September 30, 2005, PacifiCorp issued 11,617,101 shares of its common stock to PHI in consideration of the capital contribution of $125.0 million in cash made by PHI on that date. On July 21, 2005, PacifiCorp issued 11,737,090 shares of its common stock to PHI in consideration of the capital contribution of $125.0 million in cash made by PHI on June 30, 2005. Proceeds from each issuance were used for the reduction of short-term debt.

Note 8 – Retirement Benefit Plans

The components of net periodic benefit cost for the three months and nine months ended December 31, 2005 and 2004 are as follows:

	Retirement Plans

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

(Millions of dollars)	2005			2004			2005			2004

Service cost	$	7.7		$	6.5		$	23.1		$	19.5
Interest cost		18.6			18.4			55.8			55.3
Expected return on plan assets (a)		(19.2	)		(19.4	)		(57.6	)		(58.2	)
Amortization of unrecognized net obligation		2.1			2.1			6.3			6.3
Amortization of unrecognized prior service cost		0.3			0.3			0.9			1.0
Amortization of unrecognized loss		5.4			2.2			16.1			6.4

Net periodic benefit cost	$	14.9		$	10.1		$	44.6		$	30.3

	Other Postretirement Benefits

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

(Millions of dollars)	2005			2004			2005			2004

Service cost	$	2.2		$	2.1		$	6.6		$	6.4
Interest cost		7.6			7.7			22.8			23.2
Expected return on plan assets (a)		(6.6	)		(6.6	)		(19.7	)		(19.8	)
Amortization of unrecognized net obligation		3.1			3.1			9.2			9.2
Amortization of unrecognized prior service cost		0.6			—			1.6			—
Amortization of unrecognized loss		0.7			0.2			2.0			0.5

Net periodic benefit cost	$	7.6		$	6.5		$	22.5		$	19.5

(a)	The market-related value of plan assets, among other factors, is used to determine expected return on plan assets and is calculated by spreading the difference between expected and actual investment returns over a five-year period beginning in the first year in which they occur.

Employer Contributions

As discussed in PacifiCorp’s Annual Report on Form 10-K for the year ended March 31, 2005, PacifiCorp expects to contribute $70.1 million to its retirement plans and $29.9 million to its other postretirement benefit plans during the year ending March 31, 2006. PacifiCorp contributed $62.8 million to its retirement plans and $0.2 million to its other postretirement benefit plans during the nine months ended December 31, 2005.

Note 9 - Income Taxes

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

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

	Nine Months Ended December 31,

	2005		2004

Federal statutory rate	35.0	%	35.0	%
State taxes, net of federal benefit	2.9		3.7
Effect of regulatory treatment of depreciation differences	3.1		2.5
Effect of regulatory treatment of other differences	(1.0	)	2.8
Tax reserves	2.0		(1.6	)
Tax credits	(2.1	)	(2.5	)
Other	(2.2	)	0.6

Effective income tax rate	37.7	%	40.5	%

PacifiCorp has established, and periodically reviews, an estimated contingent tax reserve on its Condensed Consolidated Balance Sheets to provide for the possibility of adverse outcomes in tax proceedings. The current-year accruals are primarily attributable to new issues identified for tax years ended after March 31, 2000. PacifiCorp anticipates that final settlement and payment on settled issues and other unresolved issues will not have a material adverse impact on its consolidated financial position or results of operations. A tax contingency reserve of $4.3 million released in the nine months ended December 31, 2004 was primarily attributable to an audit settlement with the Oregon Department of Revenue for tax years 1991 through 1999.

Note 10 - Comprehensive Income

The components of comprehensive income are as follows:

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

(Millions of dollars)	2005			2004		2005			2004

Net income	$	127.8		$	51.3	$	213.6		$	164.1
Other comprehensive income:
Unrealized gain (loss) on available-for-sale securities, net of tax of $(0.2) and $(0.5)/2005 and $1.2 and $0.7/2004		(0.3	)		1.9		(0.9	)		1.1

Total comprehensive income	$	127.5		$	53.2	$	212.7		$	165.2

Note 11 - Independent Registered Public Accounting Firm Review Report

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

Note 12 - Subsequent Events

On January 27, 2006, PacifiCorp’s Board of Directors declared a dividend on common stock of $0.163 per share totaling $56.6 million and payable on the earlier of March 31, 2006 or the closing date of the acquisition of PacifiCorp by MidAmerican. If the acquisition of PacifiCorp closes prior to March 31, 2006, the dividend amount will be reduced pro rata based on the closing date relative to March 31, 2006.

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of PacifiCorp:

We have reviewed the accompanying condensed consolidated balance sheet of PacifiCorp and its subsidiaries as of December 31, 2005 and the related condensed consolidated statements of income and retained earnings for each of the three month and nine month periods ended December 31, 2005 and 2004 and the condensed consolidated statements of cash flows for the nine month periods ended December 31, 2005 and 2004. These interim financial statements are the responsibility of PacifiCorp’s management.

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

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

We previously audited in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet as of March 31, 2005, and the related consolidated statements of income, changes in common shareholder’s equity and of cash flows for the year then ended (not presented herein), and in our report dated May 27, 2005 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, 2005, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived.

PricewaterhouseCoopers LLP

Portland, Oregon

February 13, 2006

ITEM 2.

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

OVERVIEW

The Management’s Discussion and Analysis should be read in conjunction with the Condensed Consolidated Financial Statements.

PacifiCorp is a regulated electricity company serving approximately 1.6 million residential, commercial and industrial customers in service territories aggregating approximately 136,000 square miles in portions of the states of Utah, Oregon, Wyoming, Washington, Idaho and California. The regulatory commissions in each state approve rates for retail electric sales within their respective states. PacifiCorp also sells electricity on the wholesale market to public and private utilities, energy marketing companies and incorporated municipalities. Wholesale activities are regulated by the Federal Energy Regulatory Commission (the “FERC”). PacifiCorp owns, or has interests in, 69 thermal, hydroelectric and wind generating plants with an aggregate nameplate rating of 8,776.3 megawatts (“MW”) and plant net capability of 8,231.4 MW. The FERC and the six state regulatory commissions also have authority over the construction and operation of PacifiCorp’s electric facilities. PacifiCorp delivers electricity through 58,360 miles of distribution lines and 15,530 miles of transmission lines.

Sale of PacifiCorp

On May 23, 2005, Scottish Power plc (“ScottishPower”) and PacifiCorp Holdings, Inc. (“PHI”), PacifiCorp’s direct parent company, executed a Stock Purchase Agreement (the “Stock Purchase Agreement”) providing for the sale of all PacifiCorp common stock to MidAmerican Energy Holdings Company (“MidAmerican”) for a value of approximately $9.4 billion, consisting of approximately $5.1 billion in cash plus approximately $4.3 billion in net debt and preferred stock, which will remain outstanding at PacifiCorp. MidAmerican is based in Des Moines, Iowa, and is a privately owned global provider of energy services. Through its energy-related business platforms - CalEnergy, CE Electric UK, Kern River Gas Transmission Company, Northern Natural Gas Company and MidAmerican Energy Company - MidAmerican provides electric and natural gas services to 5 million customers worldwide.

The closing of the sale of PacifiCorp is subject to a number of conditions, including ScottishPower shareholder consent and regulatory notification and/or approvals from the FERC, the Department of Justice or the Federal Trade Commission, the Federal Communications Commission, the Nuclear Regulatory Commission and the public utility commissions in the states of Utah, Oregon, Wyoming, Washington, Idaho and California, as well as consents under existing third-party agreements. The Energy Policy Act of 2005 enacted in August 2005 includes a provision repealing the Public Utility Holding Company Act of 1935. The repeal took effect on February 8, 2006, prior to the closing of the sale of PacifiCorp; as a result, approval of the transaction by the Securities and Exchange Commission (the “SEC”) is not required. See “Part II. Other Information – Information Regarding Recent Regulatory Developments” for more information on the Energy Policy Act of 2005. ScottishPower shareholders approved the sale on July 22, 2005. The Department of Justice and the Federal Trade Commission completed their review of MidAmerican’s acquisition of PacifiCorp in August 2005. The FERC and the Nuclear Regulatory Commission formally approved MidAmerican’s acquisition of PacifiCorp in December 2005.

Pending satisfaction of the closing conditions, which is expected to occur in calendar 2006, the Stock Purchase Agreement requires ScottishPower to cause PacifiCorp to operate its business in the ordinary course consistent with past business practice. The Stock Purchase Agreement also requires ScottishPower to obtain MidAmerican’s prior approval to certain actions taken by PacifiCorp beyond limits specified in the Stock Purchase Agreement, including:

•	borrowings or debt issuances;

•	capital expenditures;

•	construction or acquisition of new generation, transmission or delivery facilities or systems, other than as budgeted or necessary to fulfill regulatory commitments (for example, the construction of the Currant Creek and Lake Side Power Plants is permitted to proceed as planned);

•	unbudgeted significant acquisitions or dispositions;

•	modifications to material agreements with regulators;

•	issuance or sale of any capital stock to any person, other than PHI in certain circumstances;

•	adoption or amendment of employee benefit plans or material increases to employee compensation; and

•	payment of dividends to PHI.

Although PacifiCorp intends to, and the Stock Purchase Agreement requires ScottishPower to cause PacifiCorp to, operate its business in the normal course pending the sale of PacifiCorp to MidAmerican, some of the agreements and restrictions in the Stock Purchase Agreement may affect how PacifiCorp manages its affairs.

While the sale of PacifiCorp is pending and the Stock Purchase Agreement is in effect, ScottishPower and PHI have agreed to make common equity contributions to PacifiCorp of $125.0 million at the end of each quarter in fiscal year 2006 and $131.25 million at the end of each quarter in fiscal year 2007. If the sale is completed, MidAmerican will refund to PHI the amount of required fiscal year 2007 common equity contributions as an increase to the purchase price. On December 30, 2005, September 30, 2005 and June 30, 2005, PHI made quarterly common equity contributions of $125.0 million as required by the Stock Purchase Agreement.

Until completion of the sale (or termination of the Stock Purchase Agreement), a joint executive committee with an equal number of representatives from ScottishPower and MidAmerican is facilitating the transactions contemplated in the Stock Purchase Agreement (including the process of obtaining required consents and approvals), integration planning and strategic development and will develop recommendations concerning the structure and the general operation of PacifiCorp prior to the closing. If ScottishPower completes the sale of PacifiCorp, MidAmerican will cause the election of its own nominees as directors of PacifiCorp and influence the management and policies of PacifiCorp following the sale.

The Stock Purchase Agreement may be terminated prior to completion by mutual agreement of MidAmerican and ScottishPower or otherwise in specified circumstances, including (i) material breach of the representations, warranties or covenants of the parties and (ii) the sale not being completed by May 23, 2006; however, if federal or state approvals have not been obtained but all other conditions have been fulfilled or are capable of being fulfilled as of May 23, 2006, either ScottishPower or MidAmerican may elect to extend the term of the Stock Purchase Agreement until February 17, 2007.

In July 2005, MidAmerican and PacifiCorp filed applications with the public utility commissions in the six states where PacifiCorp has retail customers seeking approval of MidAmerican’s acquisition of PacifiCorp. The applications propose a number of regulatory commitments by MidAmerican and PacifiCorp upon which approval of the transaction would be conditioned, including expected financial benefits in the form of reduced corporate overhead and financing costs, certain mid- to long-term capital and other expenditures of significant amounts and a commitment not to seek utility rate increases attributable solely to the change in ownership. The capital and other expenditures proposed by MidAmerican and PacifiCorp include:

•

Approximately $812.0 million in investments (generally to be made over several years following the sale and subject to subsequent regulatory review and approval) in emissions reduction technology for PacifiCorp’s existing coal plants, which, when coupled with the use of reduced emissions technology for anticipated new coal-fueled generation, is expected to result in significant reductions in emissions rates of sulfur dioxide, nitrogen oxide and mercury and to avoid an increase in the carbon dioxide emissions rate; and

•

Approximately $519.5 million in investments (to be made over several years following the sale and subject to subsequent regulatory review and approval) in PacifiCorp’s transmission and distribution system that would enhance reliability, facilitate the receipt of renewable resources and enable further system optimization.

The commitments proposed in the state regulatory filings are subject to the commissions’ approval of the sale to MidAmerican. While certain of the identified capital expenditures might be incurred even if the transaction is not approved, PacifiCorp has not committed to make these specific expenditures regardless of the transaction’s regulatory outcome. If the sale is not approved, the amount, nature and timing of capital expenditures could differ significantly from the commitments proposed to state regulatory authorities. As described in PacifiCorp’s testimony supporting the requests for transaction approval, PacifiCorp presently expects that annual capital expenditures of at least $1.0 billion will be required for at least the next five years, including the investments described above, and

PacifiCorp expects to seek recovery of these costs in retail rates in the future. This level of spending is dependent upon the availability of funding on reasonable terms and conditions. If market conditions are not favorable it may be necessary to postpone certain planned capital expenditures or take other actions.

Hearings on each state regulatory approval were completed in January 2006, and PacifiCorp, along with MidAmerican, has participated in settlement discussions with interested parties in all six states. PacifiCorp and MidAmerican have reached settlements in each state with a number of interested parties who intervened in the approval processes generally based on the originally proposed regulatory commitments. The settlement reached with interested parties in Oregon in December 2005 added proposed credits that will reduce retail rates generally through 2010 to the extent that PacifiCorp does not achieve identified cost reductions or demonstrate mitigation of certain risks to customers. If the rate credits are adopted by all six states required to approve PacifiCorp’s sale, their maximum potential value is $142.5 million. The Oregon settlement also includes a newly proposed commitment that, following the sale and through December 31, 2008, PacifiCorp will not make any dividends to MidAmerican or its affiliates that will reduce PacifiCorp’s common equity capital below 48.25% of PacifiCorp’s total capitalization without prior commission approval. After 2008, the required minimum level of common equity declines annually to 44.0% after December 31, 2011. In January 2006, the Utah Public Service Commission (the “UPSC”) issued a written order approving PacifiCorp’s sale to MidAmerican and the Wyoming Public Service Commission (the “WPSC”) orally approved the transaction, and in February 2006 the Idaho Public Utilities Commission issued a written order approving the sale, in each case based on the settlement reached with interested parties.

Forward-Looking Statements

This report includes forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. All statements, other than statements of historical fact, made in this report are forward-looking. When used in this Management’s Discussion and Analysis of Financial Condition and Results of Operations and elsewhere in this report, the words “will,” “may,” “could,” “believes,” “estimates,” “expects,” “anticipates,” “forecasts,” “plans,” “intends,” “projected,” “potential” and variations of such words and similar expressions are intended to identify forward-looking statements. Forward-looking statements included in this report relate to, among other matters, the effect on PacifiCorp of the following: the effect of the terms of the Stock Purchase Agreement for the sale of PacifiCorp and the completion of the sale, including actions and expenditures proposed by MidAmerican and PacifiCorp in order to obtain regulatory approval, as well as the timing of the sale and such proposed actions and expenditures; recently enacted Oregon Senate Bill 408; potential adjustment of regulatory rates to cover costs; the impact of new accounting standards or accounting policy changes; the outcome of litigation or regulatory proceedings; the timing of future regulatory filings; environmental laws; federal energy policy and legislation; capital expenditure levels; results from, and the timing of, the construction or repair of generating facilities; hydroelectric relicensing and decommissioning activities; electricity outages; retirement plan contributions; outcome of tax proceedings; growth in customers and usage; levels of hydroelectric and thermal generation; sufficiency of PacifiCorp’s available funds to meet its liquidity needs and future financing; proposed amendments to PacifiCorp’s financing agreements; off-balance sheet arrangements; the effect of risk management measures, including use of financial derivatives to manage and mitigate interest rate exposure; fluctuations in forward market prices for electricity and natural gas; and the efficiency and effectiveness of PacifiCorp’s resource and fuel procurement. Forward-looking statements reflect management’s current expectations, plans or projections and are inherently uncertain. There can be no assurance the results predicted will be realized. Actual results may vary from those represented by the forecasts, and those variations may be material. The following are among the factors that could cause actual results to differ materially from the forward-looking statements:

•	The effect of the Stock Purchase Agreement for the sale of PacifiCorp, including the consummation of the sale, potential obligations arising out of approval of the sale by regulatory bodies or the termination of the Stock Purchase Agreement;

•	The outcome of general rate cases and other proceedings conducted by regulatory commissions or other governmental and legal bodies;

•	Changes in prices and availability (for both purchases and sales) of wholesale electricity, natural gas and other fuel sources and other changes in operating costs that could affect PacifiCorp’s cost recovery;

•

Changes in regulatory requirements or other legislation, including the recently enacted federal Energy Policy Act of 2005, legislation or regulatory outcomes limiting the ability of public utilities to recover income tax expense in retail rates such as Senate Bill 408, industry restructuring and deregulation initiatives;

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

•	Economic trends that could impact electricity usage;

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

•	A high degree of variance between actual and forecasted load and prices that could impact the hedging strategy and costs to balance electricity load and supply;

•	Hydroelectric conditions, as well as natural gas and coal production and price levels, which could have a significant impact on electric capacity and cost and on PacifiCorp’s ability to generate electricity;

•	Performance of PacifiCorp’s generation facilities, including the level of planned and unplanned outages;

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

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

•	The impact of new accounting pronouncements or changes in current accounting estimates and assumptions on financial position and results of operations;

•	The impact of interest rates, investment performance and increases in health care costs on pension and post-retirement expense;

•	The impact of amendments to existing financing arrangements;

•	Continued availability of funds to meet liquidity requirements;

•	The impact of any required performance under off-balance sheet arrangements;

•	Financial condition and creditworthiness of significant customers and suppliers;

•	The impact of financial derivatives used to mitigate or manage interest rate risk and volume and price risk due to weather extremes;

•	Changes in PacifiCorp’s credit ratings;

•	The impact of implementation of the proposed regional transmission entity, Grid West, or the formation of any similar organization;

•

Timely and appropriate completion of PacifiCorp’s resource procurement process; unanticipated construction delays, changes in costs, receipt of required permits and authorizations, ability to fund resource projects and other factors that could affect future generation plants and infrastructure additions; and

•	The risks discussed in PacifiCorp’s Annual Report on Form 10-K for the year ended March 31, 2005, as updated in PacifiCorp’s Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2005 and its other reports filed with the SEC.

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

Accounting Matters

Critical Accounting Estimates

The preparation of consolidated financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect results of operations and the reported amounts of assets and liabilities in the Condensed Consolidated Financial Statements. The estimates and assumptions may change as time passes and accounting guidance evolves. Management bases its estimates and assumptions on historical experience and on various other judgments that it believes are reasonable at the time of application. Changes in these estimates and assumptions could have a material impact on the Condensed

Consolidated Financial Statements. If estimates and assumptions are different than the actual amounts recorded, adjustments are made in subsequent periods to take into consideration the new information. Critical accounting policies, in addition to certain less significant accounting policies, are discussed with senior members of management and PacifiCorp’s Board of Directors, as appropriate. Those policies that management considers critical are Derivatives, Pensions and Other Postretirement Benefits, Regulation, Unbilled Revenues, Contingencies and Asset Retirement Obligations, and are described in PacifiCorp’s Annual Report on Form 10-K for the year ended March 31, 2005, under “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.” For new accounting standards, see “Part I – Item 1. Financial Statements – Note 1 – Basis of Presentation and Summary of Significant Accounting Policies,” which are incorporated by reference into this Item 2.

RESULTS OF OPERATIONS

Overview

PacifiCorp’s net income was $213.6 million for the nine months ended December 31, 2005 compared to $164.1 million during the nine months ended December 31, 2004. This increase was primarily due to higher retail revenues attributable to higher prices approved by regulators, customer growth and a net increase in customer usage, as well as increased generation output and higher net unrealized gains on wholesale sales and purchase contracts, partially offset by the impact of increased fuel prices and higher operations and maintenance expense. The increase in net unrealized gains on wholesale sales and purchase contracts was driven primarily by favorable movements in forward market prices of natural gas, partially offset by unfavorable movements in forward market prices of electricity.

Retail energy sales volumes grew by 2.0% in the nine months ended December 31, 2005 as compared to the nine months ended December 31, 2004. PacifiCorp’s number of customers has been increasing by approximately 2.0% annually over the past five fiscal years. This trend is expected to continue for the foreseeable future. Although customer usage increased during the nine months ended December 31, 2005, usage is affected by economic and weather conditions, consumer trends and energy savings programs.

PacifiCorp pursues a regulatory program in all states, with the objective of keeping customer rates closely aligned to ongoing costs. In recent years, PacifiCorp has filed general rate cases in all six states where it has retail customers and PacifiCorp expects to make additional general rate case filings in certain states over the coming year. PacifiCorp’s regulatory program also includes various other filings such as proposed power cost adjustment mechanisms. See “Part II. Other Information – Information Regarding Recent Regulatory Developments” for developments regarding state regulatory issues and pending rate case filings.

PacifiCorp relies on electricity generated by its thermal facilities to meet a substantial portion of its customer load. PacifiCorp’s maintenance and overhaul programs are utilized to facilitate reliable generation availability at its thermal facilities through planned outages, but PacifiCorp still may experience unplanned outages. During these outage periods, other owned generation or wholesale market purchases are utilized to balance system requirements. PacifiCorp’s hydroelectric facilities are utilized as lower-cost sources of electricity generation but are dependent upon precipitation, temperatures and other variables. Wholesale energy sales and purchase contracts are utilized to balance PacifiCorp’s physical excess or shortage of net electricity and are impacted by the movements in the market prices of both natural gas and electricity. While increased thermal generation output reduces the need for wholesale market purchases, its financial impact is significantly affected by market prices for coal and natural gas.

Output from PacifiCorp’s thermal plants increased by 721,613 megawatt-hours (“MWh”), or 2.0%, during the nine months ended December 31, 2005 as compared to the nine months ended December 31, 2004. Construction of the Currant Creek and Lake Side Power Plants is progressing as scheduled, and once in full commercial operation, these plants together will provide 1,067.4 MW of electricity to meet expected future energy needs.

Output from PacifiCorp-owned hydroelectric facilities during the nine months ended December 31, 2005 increased by 205,787 MWh, or 9.0%, as compared to the nine months ended December 31, 2004. This increase was primarily attributable to current-year water conditions that, although lower than normal, improved relative to the prior-year period. PacifiCorp’s hydroelectric generation was 84.2% of normal for the nine months ended December 31, 2005,

based on a 30-year average. Actual hydroelectric generation for the fiscal year ending March 31, 2006, will be impacted by precipitation, temperatures and other variables during the fourth quarter. Hydroelectric generation has been below normal for the past 6 years. PacifiCorp cannot predict if this trend will continue in future years.

PacifiCorp continues to experience increasing employee costs primarily due to rising healthcare and pension costs. Pension costs continue to increase as a result of decreases in discount rates, which result in increases in PacifiCorp’s projected benefit obligation, as well as the recognition of deferred losses from lower than expected plan asset returns. Other employee costs continue to increase due to normal annual salary and wage increases.

Wholesale energy sales and purchase contracts that meet the definition of a derivative are recorded at fair value. For derivative contracts, when forward market prices are higher than contract prices, wholesale energy sales contracts will have unrealized losses and wholesale purchase contracts will have unrealized gains. The opposite is true when forward market prices are lower than contract prices. Unrealized gains and losses will reverse in future periods when the contracts settle at contract prices. They do not result in cash collections or payments other than in obtaining or providing cash collateral required in support of certain contracts. See “Part I – Item 1. Financial Statements – Note 3 – Derivative Instruments” for a summary of unrealized losses and gains on wholesale energy sales and purchase contracts.

Three Months Ended December 31, 2005 Compared to Three Months Ended December 31, 2004

Revenues

	Three Months Ended December 31,				Favorable/(Unfavorable)

(Millions of dollars)	2005		2004		$ Change		% Change

Retail	$	697.8	$	662.3	$	35.5	5.4	%
Wholesale sales and other		467.2		187.2		280.0	149.6

Total revenues	$	1,165.0	$	849.5	$	315.5	37.1

Retail energy sales (thousands of MWh)		12,576		12,318		258	2.1
Total average retail customers (in thousands)		1,627		1,592		35	2.2

Retail revenues increased $35.5 million, or 5.4%, primarily due to:

•	$20.6 million of increases from higher prices approved by regulators;

•	$11.0 million of increases relating to growth in the number of residential and commercial customers; and

•	$5.4 million of increases due to higher average residential and industrial customer usage, net of decreases in commercial and other customer usage; partially offset by,

•	$1.6 million of decreases due to changes in price mix resulting from the levels of customer usage at different customer tariffs in the various states that PacifiCorp serves.

Wholesale sales and other revenues increased $280.0 million, or 149.6%, primarily due to:

•	$294.5 million of increases from higher unrealized gains on short- and long-term energy sales contracts recorded at fair value, primarily due to changes in forward market prices;

•	$14.0 million of increases resulting from the sale of SO₂ emission allowances; and

•	$8.2 million of increases in revenues from the settlement of amounts previously disputed with third parties; partially offset by,

•	$43.1 million of decreases related to non-physically settled system balancing transactions.

Operating Expenses

	Three Months Ended December 31,				Favorable/(Unfavorable)

(Millions of dollars)	2005		2004		$ Change			% Change

Energy costs	$	529.5	$	327.7	$	(201.8	)	(61.6	)%
Operations and maintenance		243.7		234.2		(9.5	)	(4.1	)
Depreciation and amortization		112.4		110.1		(2.3	)	(2.1	)
Taxes, other than income taxes		23.2		22.3		(0.9	)	(4.0	)

Total operating expenses	$	908.8	$	694.3	$	(214.5	)	(30.9	)

Energy costs increased $201.8 million, or 61.6%, primarily due to:

•	$195.3 million of increases from higher unrealized losses on short- and long-term energy purchase contracts recorded at fair value, primarily due to changes in forward market prices.

Operations and maintenance expense increased $9.5 million, or 4.1%, primarily due to:

•	$8.3 million of increases in employee expenses, primarily due to higher wages and pension and benefit costs.

Depreciation and amortization expense increased $2.3 million, or 2.1%, primarily due to:

•	$3.9 million of net increases in depreciation expense due to additions to plant in service; partially offset by,

•	$1.2 million of decreases in amortization expense predominantly due to certain capitalized software becoming fully amortized.

Interest and Other (Income) Expense

	Three Months Ended December 31,						Favorable/(Unfavorable)

(Millions of dollars)	2005			2004			$ Change			% Change

Interest expense	$	71.1		$	68.2		$	(2.9	)	(4.3	)%
Interest income		(2.5	)		(2.3	)		0.2		8.7
Interest capitalized		(7.9	)		(3.3	)		4.6		139.4
Minority interest and other		(0.8	)		(4.6	)		(3.8	)	(82.6	)

Total	$	59.9		$	58.0		$	(1.9	)	(3.3	)

Interest expense increased $2.9 million, or 4.3%, primarily due to:

•	Higher average debt outstanding and higher variable rates during the three months ended December 31, 2005; partially offset by,

•	Lower average fixed rates on long-term debt during the three months ended December 31, 2005.

Interest capitalized increased $4.6 million, or 139.4%, primarily due to:

•	Higher average construction work-in-progress balances that qualify for capitalized interest and higher capitalization rates during the three months ended December 31, 2005.

Minority interest and other (income) expense changed $3.8 million, primarily due to:

•	Lower gains on net investments for the three months ended December 31, 2005 compared to the three months ended December 31, 2004.

Income Tax Expense

Income tax expense increased $22.6 million, primarily due to:

•	$34.7 million of increases due to higher levels of income from operations before income tax expense for the three months ended December 31, 2005; partially offset by,

•	$12.1 million of decreases, including $8.8 million from the tax effect of regulatory treatment of differences other than depreciation differences and other decreases from individually insignificant differences.

Nine Months Ended December 31, 2005 Compared to Nine Months Ended December 31, 2004

Revenues

	Nine Months Ended December 31,				Favorable/(Unfavorable)

(Millions of dollars)	2005		2004		$ Change		% Change

Retail	$	2,095.0	$	1,988.2	$	106.8	5.4	%
Wholesale sales and other		572.1		437.8		134.3	30.7

Total revenues	$	2,667.1	$	2,426.0	$	241.1	9.9

Retail energy sales (thousands of MWh)		37,344		36,616		728	2.0
Total average retail customers (in thousands)		1,617		1,582		35	2.2

Retail revenues increased $106.8 million, or 5.4%, primarily due to:

•	$59.4 million of increases from higher prices approved by regulators;

•	$32.0 million of increases relating to growth in the number of residential and commercial customers;

•	$12.2 million of increases due to higher average residential and industrial customer usage, net of decreases in commercial and other customer usage; and

•	$3.2 million of increases due to changes in price mix, resulting from the levels of customer usage at different customer tariffs in the various states that PacifiCorp serves.

Wholesale sales and other revenues increased $134.3 million, or 30.7%, primarily due to:

•	$72.7 million of increases in wholesale electricity revenues, primarily relating to higher prices;

•	$49.0 million of increases from lower unrealized losses on short- and long-term energy sales contracts recorded at fair value due to changes in forward market prices;

•	$16.2 million of increases resulting from the sale of SO₂ emission allowances; and

•	$8.2 million of increases in revenues from the settlement of amounts previously disputed with third parties; partially offset by,

•	$31.9 million of decreases related to non-physically settled system balancing transactions.

Operating Expenses

	Nine Months Ended December 31,				Favorable/(Unfavorable)

(Millions of dollars)	2005		2004		$ Change			% Change

Energy costs	$	997.0	$	889.2	$	(107.8	)	(12.1	)%
Operations and maintenance		740.8		689.5		(51.3	)	(7.4	)
Depreciation and amortization		335.6		326.7		(8.9	)	(2.7	)
Taxes, other than income taxes		72.4		70.5		(1.9	)	(2.7	)

Total operating expenses	$	2,145.8	$	1,975.9	$	(169.9	)	(8.6	)

Energy costs increased $107.8 million, or 12.1%, primarily due to:

•	$57.8 million of increases from higher purchased electricity relating to higher volumes and prices;

•	$18.5 million of increases related to unfavorable changes in fair value on weather derivative contracts compared to the prior year;

•	$12.1 million of increases relating to higher volumes of coal consumed due mainly to an increase in thermal generation;

•	$10.1 million of increases relating to higher prices for coal consumed; and

•	$9.8 million of increases from lower unrealized gains on short- and long-term energy purchase contracts recorded at fair value.

Operations and maintenance expense increased $51.3 million, or 7.4%, primarily due to:

•	$43.5 million of increases in employee expenses, primarily due to higher wages and pension and benefit costs;

•	$7.3 million of increases in materials and supplies utilized in plant overhaul activities; and

•	$6.3 million of an increase arising from the prior year reversal of an accrual for certain tax-related employee severance liabilities.

Depreciation and amortization expense increased $8.9 million, or 2.7%, primarily due to:

•	$12.0 million of net increases in depreciation expense due to additions to plant in service; partially offset by,

•	$2.2 million of decreases in amortization expense predominantly due to certain capitalized software becoming fully amortized.

Interest and Other (Income) Expense

	Nine Months Ended December 31,						Favorable/(Unfavorable)

(Millions of dollars)	2005			2004			$ Change			% Change

Interest expense	$	210.5		$	199.3		$	(11.2	)	(5.6	)%
Interest income		(7.1	)		(7.6	)		(0.5	)	(6.6	)
Interest capitalized		(21.4	)		(9.2	)		12.2		132.6
Minority interest and other		(3.4	)		(8.4	)		(5.0	)	(59.5	)

Total	$	178.6		$	174.1		$	(4.5	)	(2.6	)

Interest expense increased $11.2 million, or 5.6%, primarily due to:

•	Higher average debt outstanding and higher variable rates during the nine months ended December 31, 2005; partially offset by,

•	Lower average fixed rates on long-term debt during the nine months ended December 31, 2005.

Interest capitalized increased $12.2 million, or 132.6%, primarily due to:

•	Higher average construction work-in-progress balances that qualify for capitalized interest and higher capitalization rates during the nine months ended December 31, 2005.

Minority interest and other (income) expense changed $5.0 million, primarily due to:

•	Lower gains on net investments for the nine months ended December 31, 2005 compared to the nine months ended December 31, 2004.

Income Tax Expense

Income tax expense increased $17.2 million, primarily due to:

•	$23.2 million of increases due to higher levels of income from operations before income tax expense for the nine months ended December 31, 2005; and

•

$11.1 million of net increases due to $6.8 million of additional tax contingency reserves in the current year as a result of new issues identified for the tax years ended after March 31, 2000, compared to $4.3 million of tax contingency reserve releases in the prior year primarily attributable to an audit settlement with the Oregon Department of Revenue for tax years 1991 through 1999; partially offset by,

•	$17.1 million of decreases, including $11.0 million from the tax effect of regulatory treatment of differences other than depreciation differences and other decreases from individually insignificant differences.

LIQUIDITY AND CAPITAL RESOURCES

Sources and Uses of Cash

PacifiCorp depends on both internal and external sources of liquidity to provide working capital and to fund capital requirements. Short-term cash requirements not met by cash provided by operating activities are generally satisfied with proceeds from short-term borrowings. Long-term cash needs are met through sales of securities, including

additional long-term debt issuances, and also by issuance of common equity to PacifiCorp’s immediate corporate parent, PHI. Issuance of longer-term securities is influenced by levels of short-term debt, cash from operations, capital expenditures, market conditions, regulatory approvals and other considerations.

Operating Activities

Net cash flows provided by operating activities increased $214.9 million to $573.2 million for the nine months ended December 31, 2005, compared to $358.3 million for the nine months ended December 31, 2004, due mainly to the impact of changing prices and volumes on wholesale sales and purchase transactions, changes in net cash collateral requirements and amounts, increasing employee-related obligations and the net impact of the timing of cash collections and payments.

Investing Activities

Capital spending totaled $716.1 million for the nine months ended December 31, 2005, compared to $539.9 million for the nine months ended December 31, 2004. Capital spending increased primarily due to construction of the Lake Side Power Plant and expenditures for the installation of emission control equipment at the Huntington Power Plant, as well as various capital projects related to transmission and distribution and other thermal and hydroelectric facilities.

Financing Activities

Short-Term Debt

PacifiCorp’s short-term debt decreased by $254.2 million during the nine months ended December 31, 2005, primarily due to proceeds from long-term debt and common stock financing during the period, partially offset by capital expenditures in excess of net cash from operations.

Revolving Credit and Other Financing Agreements

PacifiCorp’s short-term borrowings and certain other financing arrangements are supported by an $800.0 million committed bank revolving credit agreement. This facility was amended during August 2005 to extend the termination date to August 29, 2010. Other amendments include an increased maximum permitted debt-to-capitalization ratio of 65.0% and allowing for the acquisition of PacifiCorp by MidAmerican. The interest rate on advances under this facility is generally based on the London Interbank Offered Rate (LIBOR) plus a margin that varies based on PacifiCorp’s credit ratings. As of December 31, 2005, this facility was fully available and there were no borrowings outstanding. In addition to this committed credit facility, at December 31, 2005 PacifiCorp had $118.8 million in money market accounts included in Cash and cash equivalents available to meet its liquidity needs. Regulatory authorities limit PacifiCorp to $1.5 billion of short-term debt, of which $214.6 million was outstanding at December 31, 2005 at a weighted average interest rate of 4.3%.

At December 31, 2005, PacifiCorp had $517.8 million of standby letters of credit and standby bond purchase agreements available to provide credit enhancement and liquidity support for variable-rate pollution-control revenue bond obligations. These committed bank arrangements expire periodically through the year ending March 31, 2011. At December 31, 2005, PacifiCorp had amended $421.3 million of these bank arrangements to allow for the acquisition of PacifiCorp by MidAmerican and anticipates completion of similar amendments to the remaining bank arrangements by the closing date of the sale.

PacifiCorp’s revolving credit agreement contains customary covenants and default provisions. PacifiCorp monitors these covenants on a regular basis to ensure that events of default will not occur, and as of December 31, 2005, PacifiCorp was in compliance with the covenants of its revolving credit agreement. PacifiCorp’s other financing arrangements generally contain similar covenants, although the maximum permitted debt-to-capitalization ratio for some of the arrangements is 60.0%. PacifiCorp was also in compliance with these agreements at December 31, 2005. PacifiCorp anticipates seeking amendments to the covenants in these other financing agreements to conform them to the amended covenants in its revolving credit agreement.

During the nine months ended December 31, 2005, PacifiCorp entered into three new standby letters of credit totaling $56.7 million at December 31, 2005.

Long-Term Debt

During September 2005, the SEC declared effective PacifiCorp’s shelf registration statement covering $700.0 million of future first mortgage bond and unsecured debt issuances. PacifiCorp has not yet issued any of the securities covered by this registration statement.

On June 13, 2005, PacifiCorp issued $300.0 million of its 5.25% Series of First Mortgage Bonds due June 15, 2035. PacifiCorp used the proceeds for the reduction of short-term debt, including the short-term debt used in December 2004 to redeem its 8.625% Series of First Mortgage Bonds due December 13, 2024 totaling $20.0 million. For the nine months ended December 31, 2005, PacifiCorp made scheduled long-term debt repayments of $169.7 million.

Preferred Stock Redemptions

PacifiCorp redeemed $7.5 million of preferred stock subject to mandatory and optional redemption during each of the nine months ended December 31, 2005 and 2004.

Common Stock

Dividends

During the nine months ended December 31, 2005, PacifiCorp had the following dividend activity:

•	$158.2 million declared and paid on common stock;

•	$4.2 million declared on preferred stock and preferred stock subject to mandatory redemption, of which $2.6 million was recorded as interest expense; and

•	$4.4 million paid on preferred stock and preferred stock subject to mandatory redemption.

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

•	$144.9 million declared and paid on common stock;

•	$4.6 million declared on preferred stock and preferred stock subject to mandatory redemption, of which $3.0 million was recorded as interest expense; and

•	$4.8 million paid on preferred stock and preferred stock subject to mandatory redemption.

Cautionary Statement

If market conditions warrant, PacifiCorp may seek to issue long-term debt to more permanently fund its liquidity requirements or to refinance short-term or maturing long-term debt. However, management expects existing funds and cash generated from operations, together with additional equity contributions from PHI required by the Stock Purchase Agreement and availability under the committed credit facilities, to be sufficient to fund liquidity requirements for the next 12 months. Continued availability under committed credit facilities depends upon PacifiCorp’s obtaining appropriate amendments or waivers under certain of its financing agreements. If these amendments or waivers cannot be obtained or replacement facilities arranged, the sale of all of PacifiCorp’s common stock by PHI to MidAmerican would constitute an event of default under these agreements.

Future Uses of Cash

Dividends

On January 27, 2006, PacifiCorp’s Board of Directors declared a dividend on common stock of $0.163 per share, totaling $56.6 million and payable on the earlier of March 31, 2006 or the closing date of the acquisition of PacifiCorp by MidAmerican. If the acquisition of PacifiCorp closes prior to March 31, 2006, the dividend amount will be reduced pro rata based on the closing date relative to March 31, 2006. Pursuant to the Stock Purchase Agreement for the sale of PacifiCorp, ScottishPower has agreed to cause PacifiCorp to not pay quarterly dividends to PHI in excess of $214.8 million in the aggregate during fiscal year 2006 and $242.3 million in the aggregate during fiscal year 2007. These restrictions will terminate upon either the close of the sale of PacifiCorp or the earlier termination of the Stock Purchase Agreement.

Contractual Obligations and Commercial Commitments

For an in-depth discussion of PacifiCorp’s contractual obligations and commercial commitments, see “Contractual Obligations and Commercial Commitments” in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in PacifiCorp’s Annual Report on Form 10-K for the year ended March 31, 2005.

Capital Expenditure Program

Capital expenditures are expected to be approximately $2.1 billion for the two-year period ending March 31, 2007, as reported in PacifiCorp’s Annual Report on Form 10-K for the year ended March 31, 2005. However, actual expenditures over the two-year period may vary due to timing of capital projects and related expenditures, as well as changes in the scope of planned projects and implications of capital commitments related to regulatory approval of the sale of PacifiCorp to MidAmerican. PacifiCorp generally expects at least $1.0 billion per year in capital expenditures will be required for at least the next five years. This level of spending is dependent upon the availability of funding at reasonable terms and conditions. If market conditions are not favorable it may be necessary to postpone certain planned capital expenditures or take other actions.

Construction of the Currant Creek Power Plant began in March 2004. The simple-cycle phase of the project was completed and placed in service during the nine months ended December 31, 2005. The combined-cycle phase is expected to be placed in service by the end of fiscal year 2006. The total plant is expected to cost approximately $350.0 million, which will be incurred from fiscal year 2004 through fiscal year 2007. Of this total expected amount, $328.3 million had been spent, of which $164.3 million was included in Property, plant and equipment, and $164.0 million was included in Construction work-in-progress, as of December 31, 2005. Recovery of PacifiCorp’s investment in the plant will be reviewed by all states PacifiCorp serves as part of ongoing and future general rate cases.

The development of the Lake Side Power Plant began in May 2004 and its construction began in April 2005. The plant is expected to cost approximately $347.0 million, which will be incurred from fiscal year 2005 through fiscal year 2008. Of this total expected amount, $150.0 million had been spent, of which $19.0 million was included in Property, plant and equipment, and $131.0 million was included in Construction work-in-progress, as of December 31, 2005. Recovery of PacifiCorp’s investment in the plant will be reviewed by all states PacifiCorp serves as part of ongoing and future general rate cases.

Expenditures for the installation of emission control equipment at the Huntington Power Plant are expected to cost approximately $136.1 million, which will be incurred from fiscal year 2005 through fiscal year 2007. Of this total expected amount, $43.3 million had been spent and was included in Construction work-in-progress as of December 31, 2005. Recovery of PacifiCorp’s investment in these facilities will be reviewed by all states PacifiCorp serves as part of ongoing and future general rate cases.

Credit Ratings

PacifiCorp’s credit ratings at December 31, 2005, were as follows:

	Moody’s	Standard & Poor's

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

On May 25, 2005, following the announcement of the proposed sale of PacifiCorp, Standard & Poor’s Ratings Services (“Standard & Poor’s”) placed the corporate credit rating and securities ratings of PacifiCorp on credit watch with negative implications. On May 26, 2005, Moody’s Investors Service affirmed the issuer credit rating, debt and securities ratings of PacifiCorp and changed the rating outlook to developing from stable.

Recent reports by Standard & Poor’s have stated that PacifiCorp’s current credit ratings reflect the benefits of ScottishPower ownership and that if PacifiCorp were considered on a stand-alone basis, its current credit ratios would not support the existing ratings. Standard & Poor’s has also indicated that PacifiCorp’s future ratings will be influenced by a number of factors, including financial results, the extent to which Oregon Senate Bill 408 will impact PacifiCorp, the structure of the proposed acquisition by MidAmerican and other considerations.

The ratings are subject to change or withdrawal at any time by the respective credit ratings services. Each credit rating should be evaluated independently of any other rating. For a further discussion of PacifiCorp’s credit ratings and their effect on PacifiCorp’s business, see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” in PacifiCorp’s Annual Report on Form 10-K for the year ended March 31, 2005.

Off-Balance Sheet Arrangements

PacifiCorp from time to time enters into arrangements in the normal course of business to facilitate commercial transactions with third parties that involve guarantee, indemnification or similar arrangements. PacifiCorp currently has indemnification obligations for breaches of warranties or covenants in connection with the sale of certain assets. In addition, PacifiCorp evaluates potential obligations that arise out of variable interests in unconsolidated entities, determined in accordance with revised FASB Interpretation No. 46, Consolidation of Variable-Interest Entities, an interpretation of Accounting Research Bulletin No. 51. PacifiCorp believes that the likelihood that it would be required to perform or otherwise incur any significant losses associated with any of these obligations is remote. See “Item 8. Financial Statements and Supplementary Data - Note 11 – Guarantees and Other Commitments and Note 13 – Consolidation of Variable-Interest Entities” for more information on these obligations and arrangements in PacifiCorp’s Annual Report on Form 10-K for the year ended March 31, 2005.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

PacifiCorp participates in a wholesale energy market that includes public utility companies, electricity and natural gas marketers, financial institutions, industrial companies and government entities. A variety of products exist in this market, ranging from electricity and natural gas purchases and sales for physical delivery to financial instruments such as futures, swaps, options and other complex derivatives. Transactions may be conducted directly with customers and suppliers, through brokers, or with an exchange that serves as a central clearing mechanism. PacifiCorp is subject to the various risks inherent in the energy business, including credit risk, interest rate risk and commodity price risk.

Credit Risk

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

PacifiCorp seeks to mitigate credit risk (and concentrations of credit risk) by applying specific eligibility criteria to prospective counterparties. However, despite mitigation efforts, defaults by counterparties occur from time to time. PacifiCorp continues to actively monitor the creditworthiness of those counterparties with whom it transacts and uses a variety of risk mitigation techniques to limit its exposure where it believes appropriate. When PacifiCorp considers a new asset purchase, transaction or contractual arrangement, market liquidity and the ability to optimize the investment are main considerations. To mitigate exposure to the financial risks of wholesale counterparties, PacifiCorp has entered into netting and collateral arrangements that include margining and cross-product netting

agreements and obtaining third-party guarantees, letters of credit and cash deposits. Counterparties may be assessed interest fees for delayed receipts. If required, PacifiCorp exercises rights under these arrangements, including calling on the counterparty’s credit support arrangement.

The following table represents PacifiCorp’s December 31, 2005 distribution of unsecured credit exposure, net of collateral, within its electricity and natural gas portfolio of purchase and sale contracts and takes into account contractual netting rights.

Distribution of Credit Exposure	% of Total

Investment grade - Externally rated	87.5	%
Non-investment grade - Externally rated	—
Investment grade - Internally rated	0.2
Non-investment grade - Internally rated	12.3

	100.0	%

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

The “Non-investment grade – Internally rated” component of PacifiCorp’s overall credit exposure reflects the market value of a small number of contracts that support PacifiCorp’s Integrated Resource Plan and Oregon’s electric energy restructuring legislation as it relates to renewable energy projects, as well as compliance with FERC regulations requiring utilities to purchase power from qualifying facilities.

Interest Rate Risk

PacifiCorp is exposed to risk resulting from changes in interest rates as a result of its issuance of variable-rate debt and commercial paper. PacifiCorp manages its interest rate exposure by maintaining a blend of fixed-rate and variable-rate debt and by monitoring the effects of market changes in interest rates. Changing interest rates will affect interest paid on variable-rate debt and interest earned by PacifiCorp’s pension plan assets, mining reclamation trust funds and cash balances. PacifiCorp’s principal sources of variable-rate debt are commercial paper and pollution-control revenue bonds remarketed on a periodic basis. Commercial paper is periodically refinanced with fixed-rate debt when needed and when interest rates are considered favorable. PacifiCorp may also enter into financial derivative instruments, including interest rate swaps, swaptions and United States Treasury lock agreements, to manage and mitigate interest rate exposure. PacifiCorp does not anticipate using financial derivatives as the principal means of managing interest rate exposure. PacifiCorp’s weighted-average cost of debt is recoverable in rates. Increases or decreases in interest rates are reflected in PacifiCorp’s cost of debt calculation as rate cases are filed. Any adverse change to PacifiCorp’s credit rating could negatively impact PacifiCorp’s ability to borrow and the interest rates that are charged.

As of December 31, 2005, PacifiCorp had $756.3 million of variable-rate liabilities and $150.0 million of temporary cash investments. At December 31, 2005, PacifiCorp had no financial derivatives in effect relating to interest rate exposure.

Based on a sensitivity analysis as of December 31, 2005, for a one-year horizon, PacifiCorp estimated that if market interest rates average 1.0% higher (lower), interest expense, net of offsetting impacts in interest income, would increase (decrease) by $6.1 million. Comparatively, based on a sensitivity analysis as of December 31, 2004, for a one-year horizon, had interest rates averaged 1.0% higher (lower), PacifiCorp estimated that interest expense, net of offsetting impacts in interest income, would have increased (decreased) by $8.1 million. These amounts include the effect of invested cash and were determined by considering the impact of the hypothetical interest rates on the variable-rate securities outstanding as of December 31, 2005 and 2004. The decrease in interest rate sensitivity was primarily due to the increase in invested cash and decrease in outstanding variable rate commercial paper. If interest rates changed significantly, PacifiCorp might take actions to manage its exposure to the change. However, due to the uncertainty of the specific actions that might be taken and their possible effects, the sensitivity analysis assumes no changes in PacifiCorp’s financial structure.

Commodity Price Risk

PacifiCorp’s exposure to market risk due 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, electricity demand and plant performance, that affect energy supply and demand. PacifiCorp’s energy purchase and sales activities are governed by PacifiCorp’s risk management policy and the risk levels established as part of that policy.

PacifiCorp’s energy commodity price exposure arises principally from its electric supply obligation in the western United States. PacifiCorp manages this risk principally through the operation of its generation plants with a net capability of 8,231.4 MW, as well as transmission rights held both on some of its own 15,530-mile transmission system and on third-party transmission systems, and through its wholesale energy purchase and sales activities. Wholesale contracts are utilized primarily to balance PacifiCorp’s physical excess or shortage of net electricity for future time periods. Financially settled contracts are utilized to further mitigate commodity price risk. PacifiCorp may from time to time enter into other financially settled, temperature-related derivative instruments that reduce volume and price risk on days with weather extremes. In addition, a financially settled hydroelectric streamflow hedge is in place through September 2006 to reduce volume and price risks associated with PacifiCorp’s hydroelectric generation resources.

PacifiCorp measures the market risk in its electricity and natural gas portfolio daily, utilizing a historical Value-at-Risk (“VaR”) approach and other measurements of net position. PacifiCorp also monitors its portfolio exposure to market risk in comparison to established thresholds and measures its open positions subject to price risk in terms of quantity at each delivery location for each forward time period.

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

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

As of December 31, 2005, PacifiCorp’s estimated potential five-day unfavorable impact on fair value of the electricity and natural gas commodity portfolio over the next 24 months was $20.1 million, as measured by the VaR computations described above, compared to $26.3 million as of December 31, 2004. The minimum, average and maximum daily VaR (five-day holding periods) for the three and nine months ended December 31, 2005 are as follows:

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

(Millions of dollars)	2005		2005

Minimum VaR (measured)	$	17.3	$	6.7
Average VaR (calculated)		24.7		17.8
Maximum VaR (measured)		36.4		46.2

PacifiCorp maintained compliance with its VaR limit procedures during the nine months ended December 31, 2005. Changes in markets inconsistent with historical trends or assumptions used could cause actual results to exceed predicted limits.

Fair Value of Derivatives

The following table shows the changes in the fair value of energy-related contracts subject to the requirements of SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended, from March 31, 2005 to December 31, 2005, and quantifies the reasons for the changes.

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

(Millions of dollars)	Trading			Non-trading

Fair value of contracts outstanding at March 31, 2005	$	0.2		$	(154.4	)	$	170.0
Contracts realized or otherwise settled during the period		(0.1	)		(72.7	)		74.0
Other changes in fair values (a)		(0.3	)		368.9			(336.3	)

Fair value of contracts outstanding at December 31, 2005	$	(0.2	)	$	141.8		$	(92.3	)

(a)	Other changes in fair values include the effects of changes in market prices, inflation rates and interest rates, including those based on models, on new and existing contracts.

(b)	Net unrealized losses (gains) related to derivative contracts included in rates are recorded as a regulatory net asset (liability).

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

components are valued against the appropriate forward price curve. The optionality is valued using a modified Black-Scholes model or a stochastic simulation (Monte Carlo) approach. Each option component is modeled and valued separately using the appropriate forward price curve.

PacifiCorp’s valuation models and assumptions are continuously updated to reflect current market information, and evaluations and refinements of model assumptions are performed on a periodic basis.

The following table shows summarized information with respect to valuation techniques and contractual maturities of PacifiCorp’s energy-related contracts qualifying as derivatives under SFAS No. 133 as of December 31, 2005.

	Fair Value of Contracts at Period-End

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

Trading:
Values based on quoted market prices from third-party sources	$	(0.2	)	$	—	$	—	$	—		$	(0.2	)
Values based on models and other valuation methods		—			—		—		—			—

Total trading	$	(0.2	)	$	—	$	—	$	—		$	(0.2	)

Non-trading:
Values based on quoted market prices from third-party sources	$	4.0		$	23.8	$	14.3	$	2.4		$	44.5
Values based on models and other valuation methods		166.1			161.0		21.1		(250.9	)		97.3

Total non-trading	$	170.1		$	184.8	$	35.4	$	(248.5	)	$	141.8

Standardized derivative contracts that are valued using market quotations are classified as “values based on quoted market prices from third-party sources.” All remaining contracts, which include non-standard contracts and contracts for which market prices are not routinely quoted, are classified as “values based on models and other valuation methods.” Both classifications utilize market curves as appropriate for the first six years.

ITEM 4. CONTROLS AND PROCEDURES

PacifiCorp maintains disclosure controls and procedures designed to provide reasonable assurance that material information required to be disclosed by it in the reports it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that the information is accumulated and communicated to PacifiCorp’s management, including its Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure. PacifiCorp performed an evaluation, under the supervision and with the participation of its management, including its Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of PacifiCorp’s disclosure controls and procedures as of the end of the period covered by this report. Based on this evaluation, PacifiCorp’s management, including its Chief Executive Officer and Chief Financial Officer, concluded that the disclosure controls and procedures were effective as of the end of the period covered by this report.

During the three months ended December 31, 2005, there was no change in PacifiCorp’s internal control over financial reporting identified in connection with the evaluation required by paragraph (d) of Securities Exchange Act of 1934 Rules 13a-15 or 15d-15 that occurred that has materially affected, or is reasonably likely to materially affect, PacifiCorp’s internal control over financial reporting.

PART II. OTHER INFORMATION

INFORMATION REGARDING RECENT REGULATORY DEVELOPMENTS

PacifiCorp’s Annual Report on Form 10-K for the year ended March 31, 2005, contains information concerning the federal and state regulatory matters in which PacifiCorp is involved. See “Item 1. Business – Regulation.” Certain developments with respect to those matters are set forth below, in “Part I – Item 1. Financial Statements – Note 6 –

Commitments and Contingencies” and in the corresponding sections of PacifiCorp’s previous Quarterly Reports on Form 10-Q for its current fiscal year, which are incorporated by reference into this discussion. For information about regulatory filings with state public utility commissions and federal agencies related to MidAmerican’s proposed acquisition of PacifiCorp, see “Part I – Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Sale of PacifiCorp.”

State Regulatory Actions

Utah

In November 2005, PacifiCorp filed a Power Cost Adjustment Mechanism (“PCAM”) application. The PCAM provides for 90.0% recovery of actual power costs that exceed the amount in rates and a 100.0% refund of any over-collection of power costs. If approved, the PCAM will become effective after base rates are determined in PacifiCorp’s next Utah general rate case.

Oregon

In December 2005, the Oregon Public Utility Commission (the “OPUC”) granted PacifiCorp’s motion for reconsideration and rehearing of the rate order issued in PacifiCorp’s last general rate case. The OPUC’s September 2005 rate order implemented a $26.6 million downward adjustment to PacifiCorp’s revenue requirement based on the OPUC’s interpretation of Oregon Senate Bill 408, legislation intended to address differences between income taxes collected by Oregon public utilities in retail rates and actual taxes paid by the utilities or consolidated groups in which utilities are included for income tax reporting purposes. In granting PacifiCorp’s motion for reconsideration and rehearing, the OPUC will reconsider whether Oregon Senate Bill 408 applies to this rate case and, it if does, whether the tax adjustment ordered by the OPUC results in rates that are unconstitutional. A hearing and submissions of written briefs are scheduled to occur through May 2006. PacifiCorp continues to participate in the permanent rulemaking process in order to implement Oregon Senate Bill 408. PacifiCorp expects that the permanent rules will be issued during the fiscal quarter ending September 30, 2006.

In April 2006, long-term special contracts for PacifiCorp’s Klamath basin irrigation customers will expire. Under the existing contracts, customers receive power at rates equaling less than one-tenth of PacifiCorp’s average retail rates charged to other customers on general irrigation tariffs. The rates that these Klamath basin customers will pay after the expiration of their special contract were a contested issue in PacifiCorp’s last general rate proceeding. The OPUC separated the rate-standard and rate-setting issues from the general rate proceeding and required parties to file legal briefs on the appropriate rate standard to apply to these customers. In November 2005, the OPUC issued an order stating that the same “just and reasonable” standard that applies to all of PacifiCorp’s retail customers also applies to irrigation customers in the Klamath basin. A procedural schedule for the evidentiary rate-setting portion of the proceeding has been established. An order is expected in April 2006. Legislation enacted in 2005 by the Oregon Legislative Assembly and Governor Kulongoski limits increases in rates for the Klamath Basin customers to 50.0% per year. The legislation states that the full cost of providing the rate credits will be spread among other PacifiCorp customers.

Wyoming

In February 2006, the WPSC orally approved an agreement settling PacifiCorp’s pending general rate case and a separate December 2005 request by PacifiCorp to recover increased costs of net wholesale purchased power used to serve Wyoming customers. The settlement provides for a $15.0 million revenue increase effective March 1, 2006, an additional $10.0 million revenue increase effective July 1, 2006, a PCAM and an agreement by the parties to support a forecast test year in the next general rate case application.

Washington

In May 2005, PacifiCorp filed a general rate case request with the Washington Utilities and Transportation Commission (the “WUTC”) for approximately $39.2 million annually. PacifiCorp filed rebuttal testimony in December 2005 that decreased the originally filed amount by $6.6 million annually, for an updated request of $32.6 million annually. Hearings on the updated request took place in January and February 2006. If approved by the WUTC, customer rates would increase by 14.9% in April 2006.

As part of that proceeding, PacifiCorp is also requesting to recover $8.3 million in hydroelectric costs. PacifiCorp is proposing that future hydroelectric and power cost volatility be recovered through a proposed PCAM.

California

In November 2005, PacifiCorp filed a general rate case with the California Public Utilities Commission (“CPUC”) for an increase of $11.0 million annually, or an average increase of 15.6% related to increasing costs, including power costs and operating expenses, as well as significant needed capital investments.

PacifiCorp’s application also requests the implementation of an Energy Cost Adjustment Clause (“ECAC”), which would allow for annual rate adjustments for changes in the level of net power costs, and a Post Test-Year Adjustment Mechanism (“PTAM”), which would allow annual rate adjustments for changes in operating costs and plant additions. The proposed ECAC and PTAM would operate outside the context of traditional general rate cases.

PacifiCorp also serves customers in California that fall under long-term special contracts for Klamath basin irrigation customers described above. In January 2006, PacifiCorp served notice to the CPUC of its intent to reset the rates for these customers to standard irrigation rates upon expiration of the special contracts in April 2006. After a formal protest by the irrigation customers, PacifiCorp and the irrigation customers agreed upon and presented a joint proposal for a 4-year transition to standard irrigation rates to the CPUC, which is scheduled to rule on the proposal prior to the expiration of the special contracts.

ITEM 1. LEGAL PROCEEDINGS

See “Part I – Item 1. Financial Statements – Note 6 – Commitments and Contingencies” and “Part II. Other Information – Information Regarding Recent Regulatory Developments,” which are incorporated by reference into this Item 1.

ITEM 1A. RISK FACTORS

For a discussion of certain risks and other factors to be considered when evaluating PacifiCorp, please see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Risk Factors” in PacifiCorp’s Annual Report on Form 10-K for the year ended March 31, 2005 and “Part I – Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Risk Factors” in PacifiCorp’s Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2005, as well as “Part I – Item 3. Quantitative and Qualitative Disclosures About Market Risk” of this Quarterly Report.

ITEM 6. EXHIBITS

10.1*		Compromise Agreement among PacifiCorp, PacifiCorp Holdings, Inc. and Michael J. Pittman, dated October 4, 2005. (Exhibit 10.4, Quarterly Report on Form 10-Q for quarterly period ended September 30, 2005, File No. 1-5152).
10.2		Amendment to PacifiCorp Executive Severance Plan, dated effective October 31, 2005.
10.3*		Amendment No. 1 to Employment Agreement among PacifiCorp, Scottish Power plc and Judi Johansen, dated as of December 20, 2005. (Exhibit 10, Current Report on Form 8-K, filed December 23, 2005, File No. 1-5152).
12.1		Statements of Computation of Ratio of Earnings to Fixed Charges.
12.2		Statements of Computation of Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividends.
15		Letter regarding unaudited interim financial information.
31.1		Section 302 Certification of Principal Executive Officer Pursuant to Rule 13a-14(a)/15d-14(a).
31.2		Section 302 Certification of Principal Financial Officer Pursuant to Rule 13a-14(a)/15d-14(a).
32.1		Section 906 Certification of Principal Executive Officer Pursuant to 18 U.S.C. Section 1350.
32.2		Section 906 Certification of Principal Financial Officer Pursuant to 18 U.S.C. Section 1350.

______________

*Incorporated herein by reference.

SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

		PACIFICORP


Date:	February 13, 2006	By:	/s/ RICHARD D. PEACH

			Richard D. Peach Chief Financial Officer and officer duly authorized to sign this report on behalf of registrant