8-K/A

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 8-K/A

CURRENT REPORT

Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

June 6, 2006 (March 21, 2006)

Date of Report (Date of earliest event reported)

MidAmerican Energy Holdings Company

(Exact name of registrant as specified in its charter)

Iowa	001-14881	94-2213782
(State or other jurisdiction	(Commission	(IRS Employer
of incorporation)	File Number)	Identification No.)
666 Grand Avenue, Des Moines, Iowa	50309
(Address of principal executive offices)	(Zip Code)
Registrant’s telephone number, including area code:	(515) 242-4300
N/A
(Former name or former address, if changed since last report.)

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:

[ ]	Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)
[ ]	Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)
[ ]	Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))
[ ]	Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

Item 2.01Completion of Acquisition or Disposition of Assets.

This Current Report on Form 8-K/A amends the Current Report on Form 8-K filed by MidAmerican Energy Holdings Company on March 21, 2006, to include the financial statements and exhibits as required in connection with the transaction reported therein.

Item 9.01Financial Statements and Exhibits.

(a)	Financial Statements of Business Acquired.
	The financial statements specified in Rule 3-05(b) of Regulation S-X were included in PacifiCorp's Annual Report on Form 10-K for the fiscal year ended March 31, 2006, filed on May 30, 2006. Portions of that report containing the required financial statements are filed as Exhibit 99.1 hereto.
(b)	Pro Forma Financial Information.
	The pro forma financial information specified in Article 11 of Regulation S-X is filed as Exhibit 99.2 hereto.
(c)	Exhibits.
	The following exhibits are filed with this report.
99.1	Audited consolidated financial statements of PacifiCorp and its subsidiaries included in PacifiCorp's Annual Report on Form 10-K for the fiscal year ended March 31, 2006, filed on May 30, 2006.
99.2	MidAmerican Energy Holdings Company unaudited pro forma condensed combined consolidated statements of operations.

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SIGNATURES

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 hereunto duly authorized.

	MidAmerican Energy Holdings Company
	(Registrant)
Date:June 6, 2006
	/s/ Douglas L. Anderson
	Douglas L. Anderson
	Senior Vice President

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EXHIBIT INDEX

Exhibit No.	Description
99.1	Audited consolidated financial statements of PacifiCorp and its subsidiaries included in PacifiCorp's Annual Report on Form 10-K for the fiscal year ended March 31, 2006, filed on May 30, 2006.
99.2	MidAmerican Energy Holdings Company unaudited pro forma condensed combined consolidated statements of operations.

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EX-99.1

EXHIBIT 99.1

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of PacifiCorp:

In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of income, common shareholder’s equity and cash flows present fairly, in all material respects, the financial position of PacifiCorp and its subsidiaries at March 31, 2006 and 2005, and the results of their operations and their cash flows for each of the three years in the period ended March 31, 2006, in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

As discussed in Note 3 to the consolidated financial statements, PacifiCorp and its subsidiaries changed the manner in which they apply the normal purchases and normal sales exception to derivative contracts entered into or modified after June 30, 2003, upon their adoption of SFAS No. 149, Amendment of Statement 133 on Derivative Instruments and Hedging Activities, as of July 1, 2003.

As discussed in Note 6 to the consolidated financial statements, PacifiCorp and its subsidiaries changed the manner in which they account for asset retirement obligations upon adoption of SFAS No. 143, Accounting for Asset Retirement Obligations, as of April 1, 2003.

PricewaterhouseCoopers LLP

Portland, Oregon

May 26, 2006

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PACIFICORP AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

(Millions of dollars)	Years Ended March 31,
	2006			2005			2004
Revenues	$	3,896.7		$	3,048.8		$	3,194.5
Operating expenses:
Energy costs		1,545.1			948.0			1,156.7
Operations and maintenance		1,014.5			913.1			895.8
Depreciation and amortization		448.3			436.9			428.8
Taxes, other than income taxes		96.8			94.4			95.3
Total		3,104.7			2,392.4			2,576.6
Income from operations		792.0			656.4			617.9
Interest expense and other (income) expense:
Interest expense		279.9			267.4			256.5
Interest income		(9.5	)		(9.1	)		(13.8	)
Interest capitalized		(32.4	)		(14.8	)		(19.9	)
Minority interest and other		(6.1	)		(7.3	)		1.6
Total		231.9			236.2			224.4
Income from operations before income tax expense and cumulative effect of accounting change		560.1			420.2			393.5
Income tax expense		199.4			168.5			144.5
Income before cumulative effect of accounting change		360.7			251.7			249.0
Cumulative effect of accounting change (less applicable income tax benefit of $(0.6)/2004		—			—			(0.9	)
Net income		360.7			251.7			248.1
Preferred dividend requirement		(2.1	)		(2.1	)		(3.3	)
Earnings on common stock	$	358.6		$	249.6		$	244.8

The accompanying notes are an integral part of these consolidated financial statements.

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PACIFICORP AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Millions of dollars)	March 31,
ASSETS	2006			2005
Current assets:
Cash and cash equivalents	$	119.6		$	199.3
Accounts receivable less allowance for doubtful accounts of $11.4/2006 and $11.6/2005		266.8			293.0
Unbilled revenue		148.2			143.8
Amounts due from affiliates - ScottishPower		—			36.5
Inventories at average costs:
Materials and supplies		131.2			114.7
Fuel		80.9			58.5
Current derivative contract asset		221.7			252.7
Other		46.9			115.8
Total current assets		1,015.3			1,214.3
Property, plant and equipment:
Generation		5,686.3			5,238.7
Transmission		2,591.8			2,507.7
Distribution		4,502.8			4,308.7
Intangible plant		659.0			607.0
Other		1,662.5			1,596.9
Total operating assets		15,102.4			14,259.0
Accumulated depreciation and amortization		(5,611.5	)		(5,361.8	)
Net operating assets		9,490.9			8,897.2
Construction work-in-progress		618.3			593.4
Total property, plant and equipment, net		10,109.2			9,490.6
Other assets:
Regulatory assets		884.3			972.8
Derivative contract regulatory asset		94.7			170.0
Non-current derivative contract asset		345.3			360.3
Deferred charges and other		282.5			312.9
Total other assets		1,606.8			1,816.0
Total assets	$	12,731.3		$	12,520.9

The accompanying notes are an integral part of these consolidated financial statements.

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PACIFICORP AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS, continued

(Millions of dollars)
	March 31,
LIABILITIES AND SHAREHOLDERS’ EQUITY	2006			2005
Current liabilities:
Accounts payable	$	361.3		$	350.4
Amounts due to affiliates - MidAmerican		3.8			—
Amounts due to affiliates - ScottishPower		—			3.9
Accrued employee expenses		118.0			134.3
Taxes payable		47.0			39.8
Interest payable		63.0			64.8
Current derivative contract liability		97.9			136.7
Current deferred tax liability		16.9			2.0
Long-term debt and capital lease obligations, currently maturing		216.9			269.9
Preferred stock subject to mandatory redemption, currently maturing		3.7			3.7
Notes payable and commercial paper		184.4			468.8
Other		103.2			123.4
Total current liabilities		1,216.1			1,597.7
Deferred credits:
Deferred income taxes		1,621.2			1,629.0
Investment tax credits		67.6			75.6
Regulatory liabilities		804.7			806.0
Non-current derivative contract liability		461.2			630.5
Pension and other post employment liabilities		385.0			422.4
Other		361.4			304.8
Total deferred credits		3,701.1			3,868.3
Long-term debt and capital lease obligations, net of current maturities		3,721.0			3,629.0
Preferred stock subject to mandatory redemption, net of current maturities		41.3			48.8
Total liabilities		8,679.5			9,143.8
Commitments, contingencies and guarantees (See Notes 10 and 11)
Shareholders’ equity:
Preferred stock		41.3			41.3
Common equity:
Common shareholder’s capital		3,381.9			2,894.1
Retained earnings		630.0			446.4
Accumulated other comprehensive income (loss):
Unrealized gain on available-for-sale
securities, net of tax of $1.7/2006 and $2.6/2005		2.7			4.3
Minimum pension liability, net of tax of $(2.5)/2006 and $(5.5)/2005		(4.1	)		(9.0	)
Total common equity		4,010.5			3,335.8
Total shareholders’ equity		4,051.8			3,377.1
Total liabilities and shareholders’ equity	$	12,731.3		$	12,520.9

The accompanying notes are an integral part of these consolidated financial statements.

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PACIFICORP AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Millions of dollars)	Years Ended March 31,
	2006			2005			2004
Cash flows from operating activities:
Net income	$	360.7		$	251.7		$	248.1
Adjustments to reconcile net income to net cash provided by operating activities:
Cumulative effect of accounting change, net of tax		—			—			0.9
Unrealized gain on derivative contracts, net		(86.8	)		(8.4	)		(6.1	)
Depreciation and amortization		448.3			436.9			428.8
Deferred income taxes and investment tax credits, net		13.9			120.0			80.5
Regulatory asset/liability establishment and amortization		51.6			66.7			111.1
Other		50.0			(27.0	)		(6.5	)
Changes in:
Accounts receivable, prepayments and other current assets		71.1			(137.8	)		(1.7	)
Inventories		(38.9	)		(16.2	)		14.1
Amounts due to/from affiliates - MidAmerican, net		3.6			—			—
Amounts due to/from affiliates - ScottishPower, net		32.6			(32.8	)		(36.8	)
Accounts payable and accrued liabilities		(13.4	)		84.1			(3.3	)
Other		1.9			(26.1	)		2.8
Net cash provided by operating activities		894.6			711.1			831.9
Cash flows from investing activities:
Capital expenditures		(1,049.0	)		(851.6	)		(690.4	)
Proceeds from sales of assets		1.3			7.1			3.3
Proceeds from available-for-sale securities		123.4			49.1			95.8
Purchases of available-for-sale securities		(84.9	)		(44.7	)		(89.4	)
Other		(14.9	)		(6.6	)		(22.8	)
Net cash used in investing activities		(1,024.1	)		(846.7	)		(703.5	)
Cash flows from financing activities:
Changes in short-term debt		(284.4	)		343.9			99.9
Proceeds from long-term debt, net of issuance costs		296.0			395.2			396.7
Proceeds from issuance of common stock to PHI		484.7			—			—
Dividends paid		(177.1	)		(195.4	)		(165.1	)
Repayments and redemptions of long-term debt		(269.7	)		(259.8	)		(194.1	)
Repayment of preferred securities		—			—			(352.0	)
Redemptions of preferred stock		(7.5	)		(7.5	)		(7.5	)
Other		7.8			—			(0.3	)
Net cash provided by (used in) financing activities		49.8			276.4			(222.4	)
Change in cash and cash equivalents		(79.7	)		140.8			(94.0	)
Cash and cash equivalents at beginning of period		199.3			58.5			152.5
Cash and cash equivalents at end of period	$	119.6		$	199.3		$	58.5

The accompanying notes are an integral part of these consolidated financial statements.

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PACIFICORP AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER’S EQUITY

(Millions of dollars, thousands of shares)	Common Shareholder’s Capital				Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Total Comprehensive Income (Loss)
	Shares	Amounts
Balance at March 31, 2003	312,176	$	2,892.1		$	305.9		$	(3.6	)
Comprehensive income
Net income	—		—			248.1			—		$	248.1
Other comprehensive income (loss):
Unrealized gain on available-for-sale securities, net of tax of $3.8	—		—			—			6.2			6.2
Minimum pension liability, net of tax of $(3.8)	—		—			—			(6.1	)		(6.1	)
Cash dividends declared:
Preferred stock	—		—			(3.3	)		—
Common stock ($0.51 per share)	—		—			(160.6	)		—			—
Balance at March 31, 2004	312,176		2,892.1			390.1			(3.5	)	$	248.2
Comprehensive income
Net income	—		—			251.7			—		$	251.7
Other comprehensive loss:
Unrealized loss on available-for-sale securities, net of tax of $(0.1)	—		—			—			(0.2	)		(0.2	)
Minimum pension liability, net of tax of $(0.6)	—		—			—			(1.0	)		(1.0	)
Stock-based compensation expense	—		2.0			—			—			—
Cash dividends declared:
Preferred stock	—		—			(2.1	)		—			—
Common stock ($0.62 per share)	—		—			(193.3	)		—			—
Balance at March 31, 2005	312,176		2,894.1			446.4			(4.7	)	$	250.5
Comprehensive income
Net income	—		—			360.7			—		$	360.7
Other comprehensive income (loss):
Unrealized loss on available-for-sale securities, net of tax of $(0.9)	—		—			—			(1.6	)		(1.6	)
Minimum pension liability, net of tax of $3.0	—		—			—			4.9			4.9
Common stock issuance	44,885		484.7			—			—			—
Tax benefit from stock option exercises	—		7.5			—			—			—
Separation of employee benefit plans	—		(3.5	)		—			—			—
Other	—		(0.9	)		—			—			—
Cash dividends declared:
Preferred stock	—		—			(2.1	)		—			—
Common stock ($0.53 per share)	—		—			(175.0	)		—			—
Balance at March 31, 2006	357,061	$	3,381.9		$	630.0		$	(1.4	)	$	364.0

The accompanying notes are an integral part of these consolidated financial statements.

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PACIFICORP AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Note 1-Summary of Significant Accounting Policies

On March 21, 2006, MidAmerican Energy Holdings Company (“MEHC”) completed its purchase of all of PacifiCorp’s outstanding common stock from PacifiCorp Holdings, Inc. (“PHI”), a subsidiary of Scottish Power plc (“ScottishPower”), pursuant to the Stock Purchase Agreement among MEHC, ScottishPower and PHI dated May 23, 2005, as amended on March 21, 2006. The cash purchase price was $5.1 billion. PacifiCorp’s common stock was directly acquired by a subsidiary of MEHC, PPW Holdings LLC. As a result of this transaction, MEHC controls the significant majority of PacifiCorp’s voting securities, which includes both common and preferred stock. MEHC, a global energy company based in Des Moines, Iowa, is a majority-owned subsidiary of Berkshire Hathaway Inc.

Nature of operations - 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 also engages in electricity sales and purchases on a wholesale basis. The subsidiaries of PacifiCorp support its electric utility operations by providing coal mining and other fuel-related services, as well as environmental remediation.

As a result of a settlement agreement between MEHC, the Utah Committee of Consumer Services and Utah Industrial Energy Consumers, MEHC contributed to PacifiCorp, at no cost, MEHC’s indirect 100.0% ownership interest in Intermountain Geothermal Company, which controls 69.3% of the steam rights associated with the geothermal field serving PacifiCorp’s Blundell Geothermal Plant in Utah. Intermountain Geothermal Company therefore became a wholly owned subsidiary of PacifiCorp in March 2006, subsequent to the sale of PacifiCorp to MEHC.

Basis of presentation - The Consolidated Financial Statements of PacifiCorp include its integrated electric utility operations and its wholly owned and majority-owned subsidiaries. Intercompany transactions and balances have been eliminated upon consolidation.

Regulation-Accounting for the electric utility business conforms to accounting principles generally accepted in the United States as applied to regulated public utilities and as prescribed by agencies and the commissions of the various locations in which the electric utility business operates. PacifiCorp prepares its financial statements in accordance with Statement of Financial Accounting Standards (“SFAS”) No. 71, Accounting for the Effects of Certain Types of Regulation (“SFAS No. 71”) as further discussed in Note 2 – Accounting for the Effects of Regulation.

Use of estimates -The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses and disclosure of contingent assets and liabilities at the date of the financial statements. These estimates involve judgments with respect to numerous factors that are difficult to predict and are beyond management’s control. As a result, actual results could differ materially from these estimates.

Reclassifications- Certain reclassifications of prior years’ amounts have been made to conform to the fiscal 2006 method of presentation. These reclassifications had no effect on previously reported consolidated net income.

Cash and cash equivalents-For the purposes of these financial statements, PacifiCorp considers all liquid investments with maturities of three months or less, at the time of acquisition, to be cash equivalents.

Accounts receivable and allowance for doubtful accounts- Accounts receivable includes billed retail and wholesale services plus any accrued and unpaid interest. Credit is granted to customers, which include retail and wholesale customers, government agencies and other utilities. Management performs continuing credit evaluations of customers’ financial conditions, and although PacifiCorp does not require collateral, deposits may be required from customers in certain circumstances. Accounts receivable are considered delinquent based on regulations provided by each state, which is generally if payment is not received by the date due, typically 30 days after the invoice date. PacifiCorp charges interest on delinquent customer accounts or past due balances in the states where PacifiCorp does business based on the respective regulation of each state, and this interest varies between 1.0% to 1.7% per month.

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Management reviews accounts receivable on a monthly basis to determine if any receivable will potentially be uncollectible. The allowance for doubtful accounts includes amounts estimated through an evaluation of specific accounts, primarily for wholesale accounts receivable, and a reserve for retail accounts receivable based on historical experience. After all attempts to collect a receivable have failed or, if later, by six months from when a customer becomes inactive, the receivable is written-off against the allowance. Management believes that the allowance for doubtful accounts as of March 31, 2006 was adequate. However, actual write-offs could exceed the recorded allowance. The allowance activity was as follows:

	Years Ended March 31,
(Millions of dollars)	2006			2005			2004
Beginning balance	$	11.6		$	23.3		$	31.1
Charged to costs and expenses, net (a)		9.2			5.0			5.2
Write-offs, net (b)		(9.4	)		(16.7	)		(13.0	)
Ending balance	$	11.4		$	11.6		$	23.3

(a) Includes amounts charged to expense for adjustments to the allowance for doubtful accounts, net of recoveries of wholesale accounts receivable.

(b) Includes write-offs of retail and wholesale accounts receivable, net of recoveries of retail accounts receivable.

Inventories - Inventories are valued at the lower of average cost or market.

Property, plant and equipment - Property, plant and equipment are originally recorded at the cost of contracted services, direct labor and materials, interest capitalized during construction and indirect charges for engineering, supervision and similar overhead items. The cost of depreciable electric utility properties retired, less salvage value, is charged to accumulated depreciation. The cost of removal is charged against the regulatory liability established through depreciation rates. Annual overhaul costs for the replacement of defined retirement units are capitalized. Generally other costs of overhaul activities and other repairs and maintenance are expensed as they are incurred.

Intangible plant consists primarily of computer software costs that are originally recorded at cost. Accumulated amortization on Intangible plant was $329.8 million at March 31, 2006 and $307.6 million at March 31, 2005. Amortization expense on Intangible plant was $45.5 million for the year ended March 31, 2006 and $48.5 million for the year ended March 31, 2005. The estimated aggregate amortization on Intangible plant for the next five succeeding 12 month periods ending from March 31, 2007 to March 31, 2011 is $45.4 million, $38.9 million, $31.0 million, $24.7 million and $21.8 million. Unamortized computer software costs were $186.7 million at March 31, 2006 and $185.1 million at March 31, 2005.

Depreciation and amortization- The average depreciable lives of Property, plant and equipment currently in use by category are as follows:

Generation
Steam plant	20 – 43 years
Hydroelectric plant	14 – 85 years
Other plant	15 – 35 years
Transmission	20 – 70 years
Distribution	44 – 50 years
Intangible plant	5 – 50 years
Other	5 – 30 years

Computer software costs included in Intangible plant are initially assigned a depreciable life of 5 to 10 years.

During the year ended March 31, 2005, PacifiCorp changed the estimated average lives of certain computer software systems to reflect operational plans. This change reduced amortization expense by $12.9 million annually on existing computer software systems, with an annual impact to net income of approximately $8.0 million.

Depreciation and amortization are computed by the straight-line method either over the life prescribed by PacifiCorp’s various regulatory jurisdictions for regulated assets or over the assets’ estimated useful lives.

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Composite depreciation rates of average depreciable assets on utility Property, plant and equipment (excluding amortization of capital leases) were 3.0% for each of the years ended March 31, 2006, 2005 and 2004.

Asset impairments - Long-lived assets to be held and used by PacifiCorp are reviewed for impairment when events or circumstances indicate costs may not be recoverable. Such reviews are performed in accordance with SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets (“SFAS No. 144”). The impacts of regulation on cash flows are considered when determining impairment. Impairment losses on long-lived assets are recognized when book values exceed expected undiscounted future cash flows with the impairment measured on a discounted future cash flows basis.

Allowance for funds used during construction - The allowance for funds used during construction (the “AFUDC”) represents the cost of debt and may also include equity funds used to finance utility property additions during construction. As prescribed by regulatory authorities, the AFUDC is capitalized as a part of the cost of utility property and is recorded in the Consolidated Statements of Income as Interest capitalized. Under regulatory rate practices, PacifiCorp is generally permitted to recover the AFUDC, and a fair return thereon, through its rate base after the related utility property is placed in service.

The composite capitalization rates were 6.5% for the year ended March 31, 2006; 4.5% for the year ended March 31, 2005; and 7.9% for the year ended March 31, 2004. PacifiCorp’s AFUDC rates do not exceed the maximum allowable rates determined by regulatory authorities.

Derivatives - In accordance with SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, (“SFAS No. 133”), as amended by SFAS No. 138, Accounting for Certain Derivative Instruments and Certain Hedging Activities, and SFAS No. 149, Amendment of Statement 133 on Derivative Instruments and Hedging Activities (“SFAS No. 149”) (collectively “SFAS No. 133”), derivative instruments are measured at fair value and recognized as either assets or liabilities on the Consolidated Balance Sheets, unless they qualify for the exemptions afforded by the standard. Changes in the fair value of derivatives are recognized in earnings during the period of change. Certain long-term derivative contracts have been approved by regulatory authorities for recovery through retail rates. Accordingly, changes in fair value of these contracts are deferred as regulatory assets or liabilities pursuant to SFAS No. 71. Derivative contracts for commodities used in PacifiCorp’s normal business operation and that settle by physical delivery, among other criteria, are eligible for the normal purchases and normal sales exemption afforded by SFAS No. 133. These contracts are accounted for under accrual accounting and recorded in Revenues or Energy costs in the Consolidated Statements of Income when the contracts settle.

Marketable securities - PacifiCorp accounts for marketable securities, included in Deferred charges and otheron PacifiCorp’s Consolidated Balance Sheets, in accordance with SFAS No. 115, Accounting for Certain Investments in Debt and Equity Securities. PacifiCorp determines the appropriate classification of all marketable securities as held-to-maturity, available-for-sale or trading at the time of purchase and re-evaluates such classification as of each balance sheet date. As shown in Note 5 – Marketable Securities, at March 31, 2006 and 2005, all of PacifiCorp’s investments in marketable securities were classified as available-for-sale and were reported at fair value. PacifiCorp uses the specific identification method in computing realized gains and losses on the sale of its available-for-sale securities. Realized gains and losses are included in Other (income) expense. Unrealized gains and losses are reported as a component of Accumulated other comprehensive income (loss). Investments that are in loss positions as of the end of each reporting period are analyzed to determine whether they have experienced a decline in market value that is considered other-than-temporary. An investment will generally be written down to market value if it has a significant unrealized loss for more than nine months. If additional information is available that indicates an investment is other-than-temporarily impaired, it will be written down prior to the nine-month time period. If an investment has been impaired for more than nine months but available information indicates that the impairment is temporary, the investment will not be written down.

Amounts held in trust– PacifiCorp holds certain trusts to fund decommissioning and reclamation activities as described in Note 5 – Marketable Securities and Note 6 – Asset Retirement Obligations and Accrued Environmental Costs. Amounts are also held in trusts that serve as funding vehicles for certain of PacifiCorp’s employee benefits, including the Supplemental Executive Retirement Plan (the “SERP”) as described in Note 17 – Employee Benefits.

Asset retirement obligations and accrued removal costs - Effective April 1, 2003, PacifiCorp recognizes the fair value of legal obligations associated with the retirement or removal of long-lived assets at the time the obligations

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are incurred and can be reasonably estimated in accordance with SFAS No. 143, Accounting for Asset Retirement Obligations (“SFAS No. 143”). The initial recognition of this liability is accompanied by a corresponding increase in Property, plant and equipment. Subsequent to the initial recognition, the liability is adjusted for any revisions to the expected value of the retirement obligation (with corresponding adjustments to Property, plant and equipment) and for accretion of the liability due to the passage of time. Additional depreciation expense is recorded prospectively for any Property, plant and equipment increases. In general, depreciation and accretion expense generated by SFAS No. 143 accounting is recorded as a regulatory asset or liability because such amounts are recoverable in rates. As of March 31, 2006, PacifiCorp adopted Financial Accounting Standards Board (the “FASB”) Interpretation No. 47, Accounting for Conditional Asset Retirement Obligations – an Interpretation of FASB Statement No. 143 (“FIN 47”) as described in Note 6 – Asset Retirement Obligations and Accrued Environmental Costs.

For those asset retirement removal costs that do not meet the requirements of SFAS No. 143, PacifiCorp recovers through approved depreciation rates estimated removal costs and accumulates such amounts in Asset retirement removal costs within Regulatory liabilities as described in Note 2 – Accounting for the Effects of Regulation.

Income taxes - PacifiCorp uses the liability method of accounting for deferred income taxes. Deferred tax liabilities and assets reflect the expected future tax consequences, based on enacted tax law, of temporary differences between the tax bases of assets and liabilities and their financial reporting amounts.

Prior to the sale of PacifiCorp to MEHC on March 21, 2006, PacifiCorp was a wholly owned subsidiary of PHI. Therefore, it was included in the consolidated income tax return for PHI from April 1, 2003 through March 21, 2006. PacifiCorp currently is an indirect, majority-owned subsidiary of Berkshire Hathaway Inc. and is included in its consolidated income tax return. PacifiCorp’s provision for income taxes has been computed on the basis that it files separate consolidated income tax returns with its subsidiaries.

Historically, PacifiCorp did not recognize deferred taxes on many of the timing differences between book and tax depreciation. In prior years, these benefits were flowed through to the utility customer as prescribed by PacifiCorp’s various regulatory jurisdictions. Deferred income tax liabilities and Regulatory assets have been established for those flow-through tax benefits as shown in Note 2 – Accounting for the Effects of Regulation since PacifiCorp is allowed to recover the increased income tax expense when these differences reverse.

Investment tax credits are deferred and amortized to income over periods prescribed by PacifiCorp’s various regulatory jurisdictions.

PacifiCorp establishes accruals for certain tax contingencies when, despite the belief that its tax return positions are supported, it also believes that certain positions may be challenged and that it is probable those positions may not be fully sustained. PacifiCorp is under continuous examination by the Internal Revenue Service and other tax authorities and accounts for potential losses of tax benefits in accordance with SFAS No. 5, Accounting for Contingencies (“SFAS No. 5”). See Note 19 – Income Taxes for further information.

Stock-based compensation - As permitted by 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 currently accounted for under APB No. 25 were issued in ScottishPower American Depository Shares, as discussed in Note 18 – Stock-Based Compensation. 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:

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(Millions of dollars)	Years Ended March 31,
	2006			2005			2004
Net income as reported	$	360.7		$	251.7		$	248.1
Add: stock-based compensation included
in reported net income, net of related tax effects		0.1			3.1			—
Less: stock-based compensation expense
using the fair value method, net of related tax effects		(1.4	)		(4.3	)		(1.1	)
Pro forma net income	$	359.4		$	250.5		$	247.0

Revenue recognition - Revenue is recognized upon delivery for retail and wholesale electricity sales. Electricity sales to retail customers are determined based on meter readings taken throughout the month. PacifiCorp accrues an estimate of unbilled revenues, which are earned but not yet billed, net of estimated line losses, each month for electric service provided after the meter reading date to the end of the month. The process of calculating the Unbilled revenue estimate consists of three components: quantifying PacifiCorp’s total electricity delivered during the month, assigning Unbilled revenues to customer type and valuing the unbilled energy. Factors involved in the estimation of consumption and line losses relate to weather conditions, amount of natural light, historical trends, economic impacts and customer type. Valuation of unbilled energy is based on estimating the average price for the month for each customer type. The amount accrued for Unbilled revenues was $148.2 million at March 31, 2006 and $143.8 million at March 31, 2005.

Segment information - PacifiCorp currently has one segment, which includes the regulated retail and wholesale electric operations.

New accounting standards -

SFAS No. 123R

On April 1, 2006, PacifiCorp adopted 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. 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. The adoption of SFAS No. 123R did not have an effect on PacifiCorp’s financial position or results of operations as all requisite service has been rendered by employees and the outstanding stock awards are fully vested. For further information see Note 18 – Stock-Based Compensation.

EITF No. 04-6

On April 1, 2006, PacifiCorp adopted Emerging Issues Task Force 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. The adoption of EITF No. 04-6 did not have a material impact on PacifiCorp’s consolidated financial position or results of operations.

Note 2-Accounting for the Effects of Regulation

Regulated utilities have historically applied the provisions of SFAS No. 71, which is based on the premise that regulators will set rates that allow for the recovery of a utility’s costs, including cost of capital. Accounting under SFAS No. 71 is appropriate as long as (i) rates are established by or subject to approval by independent, third-party regulators, (ii) rates are designed to recover the specific enterprise’s cost of service, and (iii) in view of demand for service, it is reasonable to assume that rates are set at levels that will recover costs and can be collected from customers.

SFAS No. 71 provides that regulatory assets may be capitalized if it is probable that future revenue in an amount at least equal to the capitalized costs will result from their treatment as allowable costs for rate-making purposes. In addition, the rate action should permit recovery of the specific previously incurred costs rather than provide for expected levels of similar future costs. PacifiCorp records regulatory assets and liabilities based on management’s

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assessment that it is probable that a cost will be recovered (asset) or that an obligation has been incurred (liability). The final outcome, or additional regulatory actions, could change management’s assessment in future periods. A regulator can provide current rates intended to recover costs that are expected to be incurred in the future, with the understanding that if those costs are not incurred, future rates will be reduced by corresponding amounts. If current rates are intended to recover such costs, PacifiCorp recognizes amounts charged pursuant to such rates as liabilities and takes those amounts to income only when the associated costs are incurred. In applying SFAS No. 71, PacifiCorp must give consideration to changes in the level of demand or competition during the cost recovery period. In accordance with SFAS No. 71, PacifiCorp capitalizes certain costs as regulatory assets if authorized to recover the costs in future periods.

PacifiCorp continuously evaluates the appropriateness of applying SFAS No. 71 to each of its jurisdictions. At March 31, 2006, PacifiCorp had recorded specifically identified net regulatory assets of $174.3 million. In the event PacifiCorp stopped applying SFAS No. 71 at March 31, 2006, an after-tax loss of approximately $108.2 million would be recognized.

PacifiCorp is subject to the jurisdiction of public utility regulatory authorities of each of the states in which it conducts retail electric operations with respect to prices, services, accounting, issuance of securities and other matters. The jurisdictions in which PacifiCorp operates are in various stages of evaluating deregulation. At present, PacifiCorp is subject to cost-based rate-making for its business. PacifiCorp is a “licensee” and a “public utility” as those terms are used in the Federal Power Act and is, therefore, subject to regulation by the Federal Energy Regulatory Commission (the “FERC”) as to accounting policies and practices, certain prices and other matters.

Regulatory assets include the following:

(Millions of dollars)	March 31,
	2006 (a)		2005 (a)
Deferred income taxes (b)	$	480.3	$	499.9
Minimum pension liability (c)		257.7		280.7
Unamortized issuance expense on retired debt		29.0		34.6
Demand-side resource costs		13.4		25.5
Transition plan - retirement and severance		16.9		24.9
Various other costs		87.0		107.2
Subtotal		884.3		972.8
Derivative contracts (d)		94.7		170.0
Total	$	979.0	$	1,142.8

(a) PacifiCorp had regulatory assets not accruing carrying charges of $952.9 million at March 31, 2006 and $1,095.6 million at March 31, 2005.

(b) Represents accelerated income tax benefits previously passed on to ratepayers that will be included in rates concurrently with recognition of the associated income tax expense.

(c) Represents minimum pension liability offsets proportionate to the amount of pension costs that are recoverable in rates. Remaining minimum pension liability offsets are included net of tax in Accumulated other comprehensive income (loss).

(d) Represents net unrealized losses related to derivative contracts included in rates. See Note 3 – Derivative Instruments for further information.

 

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Regulatory liabilities include the following:

(Millions of dollars)	March 31,
	2006		2005
Asset retirement removal costs (a)	$	699.8	$	692.1
Deferred income taxes		43.7		44.4
Bonneville Power Administration Regional Exchange Program		23.3		12.6
Various other costs		37.9		56.9
Total	$	804.7	$	806.0

(a) Represents removal costs recovered in rates.

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 action 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. Impairment would be measured in accordance with PacifiCorp’s asset impairment policy, as discussed in Note 1 – Summary of Significant Accounting Policies.

Note 3-Derivative Instruments

In accordance with SFAS No. 133, PacifiCorp records derivative instruments on the Consolidated Balance Sheets as assets or liabilities measured at estimated fair value, unless they qualify for the exemptions afforded by the standard. PacifiCorp uses derivative instruments (primarily forward purchases and sales) to manage the commodity price risk inherent in its fuel and electricity obligations, as well as to optimize the value of power generation assets and related contracts.

In July 2003, the EITF issued EITF No. 03-11, Reporting Realized Gains and Losses on Derivative Instruments That Are Subject to FASB Statement No. 133 and Not “Held for Trading Purposes” as defined in Issue No. 02-3 (“EITF No. 03-11”), which provides guidance on whether to report realized gains or losses on physically settled derivative contracts not held for trading purposes on a gross or net basis and requires realized gains or losses on derivative contracts that do not settle physically to be reported on a net basis. The adoption of EITF No. 03-11 during the year ended March 31, 2004 resulted in PacifiCorp netting certain contracts that were previously recorded on a gross basis in Wholesale sales and other revenues and Energy costs in the Consolidated Statements of Income. The adoption of EITF No. 03-11 had no impact on PacifiCorp’s consolidated Net income and all periods presented are consistent with the requirements of EITF 03-11.

As the FASB continues to issue interpretations, PacifiCorp may change the conclusions that it has reached and, as a result, the accounting treatment and financial statement impact could change in the future.

The accounting treatment for the various classifications of derivative financial instruments is as follows:

Normal purchases and normal sales - The contracts that qualify as normal purchases and normal sales are excluded from the requirements of SFAS No. 133. The realized gains and losses on these contracts are reflected in the Consolidated Statements of Income at the contract settlement date.

Undesignated - Unrealized gains and losses on derivative contracts held for trading purposes are presented on a net basis in the Consolidated Statements of Income as Revenues. Unrealized gains and losses on derivative contracts not held for trading purposes are presented in the Consolidated Statements of Income as Revenues for sales contracts and as Energy costs and Operations and maintenance expense for purchase contracts and financial swaps.

PacifiCorp has the following types of commodity transactions:

Wholesale electricity purchase and sales contracts - PacifiCorp makes continuing projections of future retail and wholesale loads and future resource availability to meet these loads based on a number of criteria, including

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historical load and forward market and other economic information and experience. Based on these projections, PacifiCorp purchases and sells electricity on a forward yearly, quarterly, monthly, daily and hourly basis to match actual resources to actual energy requirements and sells any surplus at the prevailing market price. This process involves hedging transactions, which include the purchase and sale of firm energy under long-term contracts, forward physical contracts or financial contracts for the purchase and sale of a specified amount of energy at a specified price over a given period of time.

Natural gas and other fuel purchase contracts - PacifiCorp manages its natural gas supply requirements by entering into forward commitments for physical delivery of natural gas. PacifiCorp also manages its exposure to increases in natural gas supply costs through forward commitments for the purchase of physical natural gas at fixed prices and financial swap contracts that settle in cash based on the difference between a fixed price that PacifiCorp pays and a floating market-based price that PacifiCorp receives.

Where PacifiCorp’s derivative instruments are subject to a master netting agreement and the criteria of FIN 39, Offsetting of Amounts Related to Certain Contracts- An Interpretation of APB Opinion No. 10 and FASB Statement No. 105, are met, PacifiCorp presents its derivative assets and liabilities, as well as accompanying receivables and payables, on a net basis in the accompanying Consolidated Balance Sheets.

Unrealized gains and losses on energy sales and purchase contracts are affected by fluctuations in forward prices for electricity and natural gas. The following table summarizes the amount of the pre-tax unrealized gains and losses included within the Consolidated Statements of Income associated with changes in the fair value of PacifiCorp’s derivative contracts that are not included in rates.

(Millions of dollars)	Years Ended March 31,
	2006			2005			2004
Revenues	$	224.4		$	(330.0	)	$	(29.4	)
Operating expenses:
Energy costs		(131.1	)		338.4			35.5
Operations and maintenance		(6.5	)		—			—
Total unrealized gain on derivative contracts	$	86.8		$	8.4		$	6.1

The following table shows the changes in the fair value of energy-related contracts subject to the requirements of SFAS No. 133, as amended, from April 1, 2005 to March 31, 2006.

							Regulatory Net Asset (Liability) (b)
(Millions of dollars)	Net Asset (Liability)
	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		(0.2	)		(115.8	)		128.3
Other changes in fair values (a)		0.2			277.9			(203.6	)
Fair value of contracts outstanding at March 31, 2006	$	0.2		$	7.7		$	94.7

(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).

PacifiCorp bases its forward price curves upon market price quotations when available and bases them on internally developed and commercial models, with internal and external fundamental data inputs, when market quotations are unavailable. Market quotes are obtained from independent energy brokers, as well as direct information received from third-party offers and actual transactions executed by PacifiCorp. Price quotations for certain major electricity

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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, forward price curves must be developed. 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 (beyond the first six years) is based upon the use of a fundamentals model (cost-to-build approach) due to the limited information available. The fundamentals model is updated as warranted, at least quarterly, to reflect changes in the market such as long-term natural gas prices and expected inflation rates.

Short-term contracts, without explicit or embedded optionality, are valued based upon the relevant portion of the forward price curve. Contracts with explicit or embedded optionality are valued by separating each contract into its physical and financial forward, swap and option components. Forward and swap components are valued against the appropriate forward price curve. The optionality is valued using a modified Black-Scholes model approach or a stochastic simulation (Monte Carlo) approach. Each option component is modeled and valued separately using the appropriate forward price curve.

Standardized derivative contracts that are valued using market quotations, as described above, are classified in the table below 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.”

(Millions of dollars)	Fair Value of Contracts at Period-End
	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
Non-trading:
Values based on quoted market prices from third-party sources	$	58.7		$	49.7		$	6.0		$	1.2		$	115.6
Values based on models and other valuation methods		64.9			82.9			4.9			(260.6	)		(107.9	)
Total non-trading	$	123.6		$	132.6		$	10.9		$	(259.4	)	$	7.7
Regulatory net asset (liability)	$	(76.2	)	$	(83.4	)	$	(5.5	)	$	259.8		$	94.7

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 (liability) recorded for this contract was $(2.1) million at March 31, 2006 and $20.3 million at March 31, 2005 and was included in other current assets (liabilities) in the Consolidated Balance Sheets. PacifiCorp recognized a loss of $15.6 million for the year ended March 31, 2006; a gain of $27.9 million for the year ended March 31, 2005; and a gain of $0.4 million for the year ended March 31, 2004.

Note 4 – Related-Party Transactions

Transactions while owned by MEHC– As discussed in Note 1 – Summary of Significant Accounting Policies, PacifiCorp was acquired by MEHC on March 21, 2006. The following describes PacifiCorp’s transactions and balances with unconsolidated related parties while owned by MEHC.

PacifiCorp began participating in a captive insurance program provided by MEHC Insurance Services Ltd. (“MISL”), a wholly owned subsidiary of MEHC. MISL 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 MISL and has no obligation to contribute

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equity or loan funds to MISL. Premium amounts are established based on a combination of actuarial assessments and market rates to cover loss claims, administrative expenses and appropriate reserves. Certain costs associated with the program are prepaid and amortized over the policy coverage period expiring March 20, 2007. Prepayments to MISL were $7.2 million at March 31, 2006. Premium expenses were $0.2 million for March 21, 2006 through March 31, 2006.

As of March 31, 2006, Amounts due to affiliates - MEHC included $3.8 million of current income taxes payable to PPW Holdings LLC.

See Note 1 – Summary of Significant Accounting Policies for information related to the transfer of MEHC’s 100.0% ownership interest in Intermountain Geothermal Company to PacifiCorp.

Transactions while owned by ScottishPower - There were no loans or advances between PacifiCorp and ScottishPower or between PacifiCorp and PHI. Loans from PacifiCorp to ScottishPower or PHI were prohibited under the Public Utility Holding Company Act of 1935 (“PUHCA”), which was repealed effective February 2006. Loans from ScottishPower or PHI to PacifiCorp generally required state regulatory and SEC approval. There were intercompany loan agreements that allowed funds to be lent to PacifiCorp from PacifiCorp Group Holdings Company (“PGHC”), but loans from PacifiCorp to PGHC were prohibited. There were intercompany loan agreements that allowed 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 were not commingled with funds of any other company.

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The tables below detail PacifiCorp’s transactions and balances with unconsolidated related parties while owned by ScottishPower.

(Millions of dollars)	March 31, 2006 *		March 31, 2005
Amounts due from former affiliated entities:
SPUK (a)	$	—	$	0.3
PHI and its subsidiaries (b)		—		36.2
	$	—	$	36.5
Prepayments to former affiliated entities:
PHI and its subsidiaries (c)	$	—	$	1.5
Amounts due to former affiliated entities:
SPUK (d)	$	—	$	3.9
Deposits received from former affiliated entities:
PHI and its subsidiaries (e)	$	—	$	0.3

(Millions of dollars)	Years Ended March 31,
	2006		2005		2004
Revenues from former affiliated entities:
PHI and its subsidiaries (e)	$	7.8	$	5.9	$	4.4
Expenses recharged to former affiliated entities:
SPUK (a)	$	6.2	$	3.0	$	0.7
PHI and its subsidiaries (b)		7.3		9.4		8.0
	$	13.5	$	12.4	$	8.7
Expenses incurred from former affiliated entities:
SPUK (d)	$	18.6	$	18.3	$	7.8
PHI and its subsidiaries (c)		19.3		17.3		17.0
DIIL (f)		7.0		—		—
	$	44.9	$	35.6	$	24.8
Interest expense to former affiliated entities:
PHI and its subsidiaries (g)	$	—	$	0.1	$	0.2

* Amounts settled at close of sale to MEHC.

(a) For the years ended March 31, 2006 and 2005, receivables and expenses included amounts allocated to Scottish Power UK plc (“SPUK”), an indirect subsidiary of ScottishPower, by PacifiCorp for administrative services provided under ScottishPower’s affiliated interest cross-charge policy. For the year ended March 31, 2006, expenses also included costs associated with retention agreements and severance benefits reimbursed by SPUK. In addition, PacifiCorp recharged to SPUK payroll costs and related benefits of PacifiCorp employees working on international assignment in the United Kingdom for ScottishPower during the years ended March 31, 2006, 2005 and 2004.

(b) Amounts shown pertain to activities of PacifiCorp with its former parent PHI and its subsidiaries. Expenses recharged reflect costs for support services to PHI and its subsidiaries. Amounts due from PHI and its subsidiaries included $33.8 million as of March 31, 2005 of income taxes receivable from PHI. PHI was the tax-paying entity while PacifiCorp was owned by ScottishPower.

(c) These expenses primarily related 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. The lease is a 15 year operating lease on an electric generation facility. The facility consists of five generating units each with a nameplate rating of 43.4 MW. Certain costs associated with the West Valley lease are prepaid on an annual basis. Lease expense was $16.4 million for the year ended March 31, 2006; $17.1 million for the year ended March 31, 2005; and $17.0 million for the year ended March 31, 2004. PacifiCorp has an option to terminate the West Valley lease if written notice is provided to West Valley on or before December 1, 2006. If the option to terminate is exercised, the lease would terminate in May 2008. PacifiCorp is committed to future minimum lease payments of $10.0 million annually for each of the 12 months ending March 31, 2007 and 2008 and $1.7 million for the two months ending May 31, 2008. These minimum future lease payments reflect the reduction in monthly payments resulting from a March 2006 amendment to the lease terms.

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(d) These liabilities and expenses primarily represented amounts allocated to PacifiCorp by SPUK for administrative services received under the cross-charge policy. Cross-charges from SPUK to PacifiCorp amounted to $16.7 million for the year ended March 31, 2006 and $14.9 million for the year ended March 31, 2005. 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 assignment with PacifiCorp in the United States.

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

(f) 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 covered all or significant portions of the property damage and liability insurance deductibles in many of PacifiCorp’s policies, as well as overhead distribution and transmission line property damage. PacifiCorp had no equity interest in DIIL and had no obligation to contribute equity or loan funds to DIIL. Premium amounts were established to cover loss claims, administrative expenses and appropriate reserves, but otherwise DIIL was not operated to generate profits.

(g) Included interest on short-term demand loans made to PacifiCorp by PGHC, in accordance with regulatory authorization.

Note 5–Marketable Securities

PacifiCorp, by contract with Idaho Power, the minority owner of Bridger Coal Company (an indirect subsidiary of PacifiCorp), maintains a trust relating to final reclamation of a leased coal mining property. Amounts funded are based on estimated future reclamation costs and estimated future coal deliveries. Trust fund assets associated with Bridger Coal Company recorded at fair value included in Deferred charges and other were $101.9 million at March 31, 2006 and $92.4 million at March 31, 2005, including the Idaho Power minority-interest portion. Minority interest in Bridger Coal Company was $49.5 million at March 31, 2006 and $26.2 million at March 31, 2005. See also Note 6 – Asset Retirement Obligations and Accrued Environmental Costs.

The amortized cost and fair value of reclamation trust securities and other investments included in Deferred charges and other on PacifiCorp’s Consolidated Balance Sheets, which are classified as available-for-sale, were as follows:

(Millions of dollars)	Amortized Cost		Gross Unrealized Gains		Gross Unrealized Losses			Estimated Fair Value
March 31, 2006
Debt securities	$	25.9	$	0.2	$	(0.6	)	$	25.5
Equity securities		61.7		7.0		(0.7	)		68.0
Total	$	87.6	$	7.2	$	(1.3	)	$	93.5
March 31, 2005
Mutual fund account (a)	$	27.0	$	—	$	(1.0	)	$	26.0
Debt securities		25.6		0.4		(0.4	)		25.6
Equity securities		60.6		13.2		(1.2	)		72.6
Total	$	113.2	$	13.6	$	(2.6	)	$	124.2

(a) In October 2005, the mutual fund account was transferred to a money market account.

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The quoted market price of securities is used to estimate their fair value.

The amortized cost and estimated fair value of debt securities at March 31, 2006 and 2005 by contractual maturities and of equity securities for the same dates are shown below. Actual maturities may differ from contractual maturities because borrowers may have the right to call or prepay obligations with or without call or prepayment penalties.

	March 31,
	2006				2005
(Millions of dollars)	Amortized Cost		Estimated Fair Value		Amortized Cost		Estimated Fair Value
Debt securities
Due in one year or less	$	0.7	$	0.6	$	0.7	$	0.7
Due after one year through five years		6.5		6.4		5.6		5.6
Due after five years through ten years		9.9		9.8		9.8		9.9
Due after ten years		8.8		8.7		9.5		9.4
Mutual fund account		—		—		27.0		26.0
Equity securities		61.7		68.0		60.6		72.6
Total	$	87.6	$	93.5	$	113.2	$	124.2

Proceeds, gross gains and gross losses from realized sales of available-for-sale securities using the specific identification method were as follows for the years ended March 31, 2006, 2005 and 2004:

	Years Ended March 31,
(Millions of dollars)	2006			2005			2004
Proceeds	$	123.4		$	49.1		$	95.8
Gross gains	$	16.6		$	6.3		$	6.5
Gross losses		(2.3	)		(2.2	)		(3.4	)
Net gains		14.3			4.1			3.1
Less net gains included in Regulatory liabilities (a)		(16.6	)		(5.6	)		(3.2	)
Net losses included in Net income	$	(2.3	)	$	(1.5	)	$	(0.1	)

(a) Realized gains and losses on the Bridger Coal Company reclamation trust described above are recorded as a regulatory liability in accordance with the prescribed regulatory treatment.

Note 6 – Asset Retirement Obligations and Accrued Environmental Costs

Asset Retirement Obligations - PacifiCorp records asset retirement obligations for long-lived physical assets that qualify as legal obligations under SFAS No. 143. PacifiCorp estimates its asset retirement obligation liabilities based upon detailed engineering calculations of the amount and timing of the future cash spending for a third party to perform the required work. Spending estimates are escalated for inflation and then discounted at a credit-adjusted, risk-free rate. PacifiCorp then records an asset retirement obligation asset associated with the liability. The asset retirement obligation assets are depreciated over their expected lives and the asset retirement obligation liabilities are accreted to the projected spending date. Changes in estimates could occur due to plan revisions, changes in estimated costs and changes in timing of the performance of reclamation activities. In addition, PacifiCorp records removal costs as a part of depreciation expense in accordance with regulatory accounting requirements described in Note 2 – Accounting for the Effects of Regulation. Since asset retirement costs are recovered through the ratemaking process, PacifiCorp records a regulatory asset or regulatory liability on the Consolidated Balance Sheets to account for the difference between asset retirement costs as currently approved in rates and costs under SFAS No. 143.

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PacifiCorp does not recognize liabilities for asset retirement obligations for which the fair value cannot be reasonably estimated. PacifiCorp has asset retirement obligations associated with its transmission and distribution systems and certain coal mines. However, due to the indeterminate removal date, the fair value of the associated liabilities currently cannot be estimated and no amounts are recognized in the Consolidated Financial Statements.

In March 2005, the FASB issued FIN 47. 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 fair value of the liability can be reasonably estimated. Upon adoption of FIN 47 at March 31, 2006, PacifiCorp recorded an asset retirement obligation liability at a net present value of $22.7 million. PacifiCorp also increased net depreciable assets by $1.8 million, reclassified $13.5 million of costs accrued for retirement removals from regulatory liabilities to asset retirement obligation liabilities, increased regulatory liabilities by $0.4 million and increased regulatory assets by $7.8 million for the difference between retirement costs approved by regulators and obligations under FIN 47.

The pro forma total asset retirement obligation liability balances that would have been reported assuming FIN 47 had been adopted on April 1, 2004, rather than March 31, 2006, are as follows:

(Millions of dollars)
Pro forma asset retirement obligation liability at April 1, 2004	$	215.8
Pro forma asset retirement obligation liability at March 31, 2005	$	222.1

Due to regulatory accounting treatment, the adoption of FIN 47 would have no material impact on net income for the pro forma periods listed above and had no impact on PacifiCorp’s reported cash flows.

The following table describes the changes to PacifiCorp’s asset retirement obligation liability for the years ended March 31, 2006 and 2005:

(Millions of dollars)	March 31, 2006			March 31, 2005
Liability recognized at beginning of period	$	199.6		$	193.5
Liabilities incurred (a)		25.2			1.4
Liabilities settled (b)		(10.4	)		(13.0	)
Revisions in cash flow (c)		(11.2	)		8.9
Accretion expense		8.9			8.8
Asset retirement obligation		212.1			199.6
Less current portion (d)		7.0			17.8
Long-term asset retirement obligation at end of period (e)	$	205.1		$	181.8

(a) Relates primarily to the adoption of FIN 47 at March 31, 2006.

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

(c) Results from changes in the timing and amounts of estimated cash flows for certain plant reclamation.

(d) Amount included in Other current liabilities on the Consolidated Balance Sheets.

(e) Amount included in Deferred credits - other on the Consolidated Balance Sheets.

PacifiCorp had trust fund assets recorded at fair value included in Deferred charges and other of $103.0 million at March 31, 2006 and $93.4 million at March 31, 2005 relating to mine and plant reclamation, including the minority-interest joint-owner portions.

Accrued Environmental Costs– PacifiCorp’s policy is to accrue environmental cleanup-related costs of a non-capital nature when those costs are believed to be probable and can be reasonably estimated. The quantification of environmental exposures is based on assessments of many factors, including changing laws and regulations, advancements in environmental technologies, the quality of information available related to specific sites, the assessment stage of each site investigation, preliminary findings and the length of time involved in remediation or settlement. PacifiCorp hires external consultants from time to time to conduct studies in order to establish reserves for various site environmental remediation costs. PacifiCorp is subject to cost-sharing agreements with other potentially responsible parties based on decrees, orders and other legal agreements. In these circumstances, PacifiCorp assesses the financial capability of other potentially responsible parties and the reasonableness of PacifiCorp’s apportionment. These agreements may affect the range of potential loss. Additionally, PacifiCorp may benefit from excess insurance policies that may cover some of the cleanup costs if costs incurred exceed certain amounts.

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PacifiCorp assesses its potential obligations to perform environmental remediation on an ongoing basis. As a result of studies performed during the year ended March 31, 2006, PacifiCorp increased its reserve by $9.7 million to reflect its most likely estimate for probable liabilities. Remediation costs that are fixed and determinable have been discounted to their present value using credit-adjusted, risk-free discount rates based on the expected future annual borrowing rates of PacifiCorp. The liability recorded was $38.5 million at March 31, 2006 and $33.3 million at March 31, 2005 and is included as part of Deferred credits - other. The March 31, 2006 recorded liability included $18.1 million of discounted liabilities. Had none of the liabilities included in the $38.5 million balance recorded at March 31, 2006 been discounted, the total would have been $40.7 million. The expected payments for each of the five 12 month periods ending March 31 and thereafter are as follows: $5.4 million in 2007, $3.9 million in 2008, $2.4 million in 2009, $1.5 million in 2010, $1.2 million in 2011 and $26.3 million thereafter.

It is possible that future findings or changes in estimates could require that additional amounts be accrued. Should current circumstances change, it is possible that PacifiCorp could incur an additional undiscounted obligation of up to approximately $53.1 million relating to existing sites. However, management believes that completion or resolution of these matters will have no material adverse effect on PacifiCorp’s consolidated financial position or results of operations.

Note 7-Notes Payable and Commercial Paper

Amounts outstanding under PacifiCorp’s short-term notes payable and commercial paper arrangements were as follows:

(Millions of dollars)	Balance		Average Interest Rate
March 31, 2006	$	184.4	4.8	%
March 31, 2005		468.8	2.9

Revolving Credit Agreement

PacifiCorp amended and restated its existing $800.0 million committed bank revolving credit agreement in August 2005. 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 exclusion of the acquisition of PacifiCorp by MEHC as an event of default under the agreement. As of March 31, 2006, PacifiCorp’s revolving credit agreement was fully available and had no borrowings outstanding. The interest 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. This facility supports PacifiCorp’s commercial paper program and $38.1 million of variable rate pollution control revenue bonds.

PacifiCorp’s revolving credit agreement contains customary covenants and default provisions and PacifiCorp monitors these covenants on a regular basis. As of March 31, 2006, PacifiCorp was in compliance with the covenants of its revolving credit agreement.

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Note 8-Long-Term Debt and Capital Lease Obligations

PacifiCorp’s long-term debt and capital lease obligations were as follows:

(Millions of dollars)	March 31,
	2006					2005
	Amount			Average Interest Rate		Amount			Average Interest Rate
First mortgage bonds
4.3% to 8.8%, due through 2011	$	901.7		6.0	%	$	1,171.4		6.2	%
5.0% to 9.2%, due 2012 to 2016		1,040.4		6.5			1,040.4		6.5
8.5% to 8.6%, due 2017 to 2021		5.0		8.5			5.0		8.5
6.7% to 8.5%, due 2022 to 2026		424.0		7.4			424.0		7.4
5.3 % to 7.7%, due 2032 to 2036		800.0		6.3			500.0		7.0
Unamortized discount		(4.7	)				(4.3	)
Guaranty of pollution-control revenue bonds
Variable rates, due 2014 (a) (b)		40.7		3.1			40.7		2.3
Variable rates, due 2014 to 2026 (b)		325.2		3.2			325.2		2.3
Variable rates, due 2025 (a) (b)		175.8		3.2			175.8		2.3
3.4% to 5.7%, due 2014 to 2026 (a)		184.0		4.5			184.0		4.5
6.2%, due 2031		12.7		6.2			12.7		6.2
Unamortized discount		(0.5	)				(0.5	)
Funds held by trustees		(2.2	)				(2.1	)
Capital lease obligations
10.4% to 14.8%, due through 2035		35.8		11.7			26.6		11.9
Total		3,937.9					3,898.9
Less current maturities		(216.9	)				(269.9	)
Total	$	3,721.0				$	3,629.0

(a) Secured by pledged first mortgage bonds generally at the same interest rates, maturity dates and redemption provisions as the pollution-control revenue bonds.

(b) Interest rates fluctuate based on various rates, primarily on certificate of deposit rates, interbank borrowing rates, prime rates or other short-term market rates.

First mortgage bonds of PacifiCorp may be issued in amounts limited by PacifiCorp’s property, earnings and other provisions of the mortgage indenture. Approximately $13.8 billion of the eligible assets (based on original cost) of PacifiCorp are subject to the lien of the mortgage.

Approximately $2.3 billion of first mortgage bonds were redeemable at PacifiCorp’s option at March 31, 2006 at redemption prices dependent upon United States Treasury yields. Approximately $541.7 million of variable-rate pollution-control revenue bonds were redeemable at PacifiCorp’s option at par at March 31, 2006. Approximately $71.2 million of fixed-rate pollution-control revenue bonds were redeemable at PacifiCorp’s option at par at March 31, 2006. The remaining long-term debt was not redeemable at March 31, 2006.

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.

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In March 2005, the maturity dates were extended to December 1, 2020 for three series of variable-rate pollution-control revenue bonds totaling $38.1 million.

PacifiCorp leases equipment and real estate in various states in which it does business under long-term agreements, extending through March 2035, which are classified as capital leases. These capital leases are payable in monthly installments allocated between principal and imputed interest rates ranging from 10.4% to 14.8%.

In April 2005, PacifiCorp entered into a 30-year transportation service agreement with Questar Pipeline Company for the right to use a newly constructed pipeline facility with a majority of the output designated to provide natural gas to the Currant Creek Power Plant. This agreement qualifies as a capital lease with an initial net present value lease obligation of $12.4 million at an imputed interest rate of 11.3%.

The annual maturities of long-term debt and capital lease obligations for the 12 months ending March 31 are:

(Millions of dollars)	Long-term Debt			Capital Lease Obligations			Total
2007	$	216.3		$	4.8		$	221.1
2008		119.9			4.8			124.7
2009		412.4			4.8			417.2
2010		138.5			5.0			143.5
2011		14.6			4.9			19.5
Thereafter		3,007.8			63.8			3,071.6
		3,909.5			88.1			3,997.6
Unamortized discount		(5.2	)		—			(5.2	)
Funds held by trustee		(2.2	)		—			(2.2	)
Amounts representing interest		—			(52.3	)		(52.3	)
	$	3,902.1		$	35.8		$	3,937.9

PacifiCorp made interest payments, net of capitalized interest, of $240.3 million for the year ended March 31, 2006; $220.4 million for the year ended March 31, 2005; and $236.7 million for the year ended March 31, 2004.

At March 31, 2006, 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. In addition, PacifiCorp had approximately $40.5 million of standby letters of credit to provide credit support for certain transactions as requested by third parties. These committed bank arrangements were all fully available as of March 31, 2006 and expire periodically through the 12 months ending March 31, 2011.

PacifiCorp’s standby letters of credit and standby bond purchase agreements generally contain similar covenants to those contained in PacifiCorp’s revolving credit agreement, although the maximum permitted debt-to-capitalization ratio for one of the standby bond purchase agreements was 60.0% as of March 31, 2006 and was amended in May 2006 to now permit a maximum ratio of 65.0%. See Note 7 – Notes Payable and Commercial Paper for further information. PacifiCorp monitors these covenants on a regular basis in order to ensure that events of default will not occur and as of March 31, 2006, PacifiCorp was in compliance with the covenants of these agreements.

Note 9 – Preferred Stock Subject to Mandatory Redemption

PacifiCorp’s Preferred stock subject to mandatory redemption was as follows:

(Thousands of shares, millions of dollars)	March 31, 2006			March 31, 2005
Series	Shares	Amount		Shares	Amount
Preferred stock subject to mandatory redemption $7.48 No Par Serial Preferred, $100 stated value, 16,000 shares authorized	450	$	45.0	525	$	52.5

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PacifiCorp has mandatory redemption requirements on 37,500 shares of the $7.48 series Preferred stock on June 15, 2006, with a non-cumulative option to redeem an additional 37,500 shares on June 15, 2006, at $100.0 per share, plus accrued and unpaid dividends to the date of such redemption. All outstanding shares on June 15, 2007 are subject to mandatory redemption. Holders of Preferred stock subject to mandatory redemption are entitled to certain voting rights and may have the right to elect members to the PacifiCorp Board of Directors in the event dividends payable are in default in an amount equal to four full quarterly payments. PacifiCorp redeemed $7.5 million of Preferred stock subject to mandatory and optional redemption during each of the years ended March 31, 2006, 2005 and 2004.

PacifiCorp had $0.8 million at March 31, 2006 and $1.0 million at March 31, 2005 in dividends declared but unpaid on Preferred stock subject to mandatory redemption that were included in Interest payable.

Note 10-Commitments and Contingencies

PacifiCorp follows SFAS No. 5, 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.

From time to time, PacifiCorp is also a party to various legal claims, actions, complaints and disputes, certain of which involve material amounts. PacifiCorp has recorded $6.7 million in reserves as of March 31, 2006 related to various outstanding legal actions and disputes, excluding those discussed below. This amount represents PacifiCorp’s best estimate of probable losses related to these matters. 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 matters - 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. Environmental contingencies identified at March 31, 2006 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 results of operations. See also Note 6 – Asset Retirement Obligations and Accrued Environmental Costs.

Hydroelectric relicensing - PacifiCorp’s hydroelectric portfolio consists of 51 plants with an aggregate plant net capability of 1,159.4 MW. The FERC regulates 93.9% of the installed capacity of this portfolio 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 will consist primarily of additional relicensing costs, operations and maintenance expense, and capital expenditures. Electricity generation reductions may result from the additional environmental requirements. PacifiCorp had incurred $70.3 million in costs as of March 31, 2006 for ongoing hydroelectric relicensing, which are reflected in Construction work-in-progress on the 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.

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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 $48.4 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 March 31, 2006, the liability recorded for all North Umpqua obligations amounted to a present value of $21.8 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.

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 former affiliates had been 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. Under the terms of the order, PacifiCorp and its formerly 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, which was filed in March 2006. 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 11 – Guarantees and Other Commitments

Guarantees

PacifiCorp is generally required to obtain state regulatory commission approval prior to guaranteeing debt or obligations of other parties. In November 2002, the FASB issued Interpretation No. 45, Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others (“FIN 45”). FIN 45 requires disclosure of certain direct and indirect guarantees.

The following represent the indemnification obligations of PacifiCorp as of March 31, 2006 and 2005.

PacifiCorp has made certain commitments related to the decommissioning or reclamation of certain jointly owned facilities and mine sites. The decommissioning guarantees require PacifiCorp to pay a proportionate share of the decommissioning costs based upon percentage of ownership. The mine reclamation obligations require PacifiCorp to pay the mining entity a proportionate share of the mine’s reclamation costs based on the amount of coal purchased by PacifiCorp. In the event of default by any of the other joint participants, PacifiCorp potentially may be obligated to absorb, directly or by paying additional sums to the entity, a proportionate share of the defaulting party’s liability.

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PacifiCorp has recorded its estimated share of the decommissioning and reclamation obligations as either an asset retirement obligation, regulatory liability or other liability.

In connection with the sale of PacifiCorp’s Montana service territory, PacifiCorp entered into a purchase and sale agreement with Flathead Electric Cooperative in October 1998. Under the agreement, PacifiCorp indemnified Flathead Electric Cooperative for losses, if any, occurring after the closing date and arising as a result of certain breaches of warranty or covenants. The indemnification has a cap of $10.1 million until October 2008 and a cap of $5.1 million thereafter (less expended costs to date). Two indemnity claims relating to environmental issues have been tendered, but remediation costs for these claims, if any, are not expected to be material.

From time to time, PacifiCorp executes contracts that include indemnities typical for the underlying transactions, which are related to sales of businesses, property, plant and equipment, and service territories. These indemnities might include any of the following matters: privacy rights; governmental regulations and employment-related issues; commercial contractual relationships; financial reports; tax-related issues; securities laws; and environmental-related issues. Performance under these indemnities generally would be triggered by breach of representations and warranties in the contract. PacifiCorp regularly evaluates the probability of having to incur costs under the indemnities and appropriately accrues for expected losses that are probable and estimable. Some of these indemnities may not limit potential liability; therefore, PacifiCorp is unable to estimate a maximum potential amount of future payments that could result from claims made under these indemnities. 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.

Unconditional Purchase Obligations

(Millions of dollars)	Payments due during the 12 months ending March 31,
	2007		2008		2009		2010		2011		Thereafter		Total
Construction	$	111.4	$	33.2	$	—	$	—	$	—	$	—	$	144.6
Operating leases		15.0		15.3		2.9		2.1		2.1		8.8		46.2
Purchased electricity		756.3		426.7		284.1		290.6		258.0		2,146.7		4,162.4
Transmission		45.7		39.5		37.7		35.3		36.8		503.3		698.3
Fuel		516.8		600.5		522.5		452.7		339.8		1,931.5		4,363.8
Other		52.6		61.0		59.5		53.6		53.4		837.0		1,117.1
Total commitments	$	1,497.8	$	1,176.2	$	906.7	$	834.3	$	690.1	$	5,427.3	$	10,532.4

Construction - PacifiCorp has an ongoing construction program to meet increased electricity usage, customer growth and system reliability objectives. At March 31, 2006, PacifiCorp had estimated long-term unconditional purchase obligations for construction of the new Lake Side Power Plant.

Operating leases - PacifiCorp leases offices, certain operating facilities, land and equipment under operating leases that expire at various dates through the 12 months ended March 31, 2093. Certain leases contain renewal options for varying periods and escalation clauses for adjusting rent to reflect changes in price indices. These leases generally require PacifiCorp to pay for insurance, taxes and maintenance applicable to the leased property. Excluded from the operating lease payments above are any power purchase agreements that meet the definition of an operating lease.

Net rent expense was $28.8 million for the year ended March 31, 2006; $26.1 million for the year ended March 31, 2005; and $29.4 million for the year ended March 31, 2004.

Minimum non-cancelable sublease rent payments expected to be received through the 12 months ended March 31, 2013 total $6.8 million.

Purchased electricity - As part of its energy resource portfolio, PacifiCorp acquires a portion of its electricity through long-term purchases and/or exchange agreements. Included in the purchased electricity payments above are any power purchase agreements that meet the definition of an operating lease.

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Included in the minimum fixed annual payments for purchased electricity above are commitments to purchase electricity from several hydroelectric projects under long-term arrangements with public utility districts. These purchases are made on a “cost-of-service” basis for a stated percentage of project output and for a like percentage of project operating expenses and debt service. These costs are included in Energy costs in the Consolidated Statements of Income. PacifiCorp is required to pay its portion of operating costs and its portion of the debt service, whether or not any electricity is produced.

At March 31, 2006, PacifiCorp’s share of long-term arrangements with public utility districts was as follows:

(Millions of dollars)
Generating Facility	Year Contract Expires	Capacity (MW)	Percentage of Output		Annual Costs (a)
Wanapum	2009	194.1	18.7	%	$	6.6
Rocky Reach	2011	67.8	5.3			3.6
Priest Rapids	2045	61.0	6.5			2.0
Wells	2018	58.3	6.9			2.1
Total		381.2			$	14.3

(a) Includes debt service totaling $7.0 million.

PacifiCorp’s minimum debt service and estimated operating obligations included in purchased electricity above for the 12 months ending March 31 are as follows:

(Millions of dollars)	Minimum Debt Service		Operating Obligations
2007	$	9.3	$	8.3
2008		9.3		8.4
2009		9.3		8.6
2010		4.7		4.8
2011		4.7		4.9
Thereafter		55.5		84.3
	$	92.8	$	119.3

PacifiCorp has a 4.0% entitlement to the generation of the Intermountain Power Project, located in central Utah, through a power purchase agreement. PacifiCorp and the City of Los Angeles have agreed that the City of Los Angeles will purchase capacity and energy from PacifiCorp’s 4.0% entitlement of the Intermountain Power Project at a price equivalent to 4.0% of the expenses and debt service of the project.

Fuel - PacifiCorp has “take or pay” coal and natural gas contracts that require minimum payments.

Other - Unconditional purchase obligations, as defined by accounting standards, are those long-term commitments that are non-cancelable or cancelable only under certain conditions. PacifiCorp has such commitments related to legal or contractual asset retirement obligations, environmental obligations, hydroelectric obligations, equipment maintenance and various other service and maintenance agreements.

Resource Management

PacifiCorp, as a public utility and a franchise supplier, has an obligation to manage resources to supply its customers. Rates charged to most customers are tariff rates authorized by regulatory agencies as discussed in Note 2 – Accounting for the Effects of Regulation.

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Note 12 - Jointly Owned Facilities

At March 31, 2006, PacifiCorp’s share in jointly owned facilities was as follows:

(Millions of dollars)	PacifiCorp Share		Plant in Service		Accumulated Depreciation/ Amortization		Construction Work-in- Progress
Jim Bridger Nos. 1 - 4 (a)	66.7	%	$	922.2	$	467.6	$	18.3
Wyodak	80.0			308.8		165.9		14.8
Hunter No. 1	93.8			307.7		142.5		1.8
Colstrip Nos. 3 and 4 (a)	10.0			239.2		116.2		1.5
Hunter No. 2	60.3			212.2		99.4		8.1
Hermiston (b)	50.0			167.0		38.9		1.6
Craig Station Nos. 1 and 2	19.3			165.3		71.3		0.7
Hayden Station No. 1	24.5			41.1		18.6		1.0
Foote Creek	78.8			36.3		10.4		—
Hayden Station No. 2	12.6			26.4		12.8		0.3
Trojan (c)	2.5			—		—		—
Other transmission and distribution plants	Various			78.6		21.2		—
Unallocated acquisition adjustments (d)				157.2		75.8		—
Total			$	2,662.0	$	1,240.6	$	48.1

(a) Includes kilovolt lines and substations.

(b) Additionally, PacifiCorp has contracted to purchase the remaining 50.0% of the output of the Hermiston Plant. See Note 13 – Consolidation of Variable-Interest Entities.

(c) The Trojan Plant was closed in 1993 and PacifiCorp is allowed recovery of costs associated with the plant over the remaining life of the original license. Plant, inventory, fuel and decommissioning costs totaling $8.1 million relating to the Trojan Plant were included in regulatory assets at March 31, 2006.

(d) Represents the excess of the costs of the acquired interests in purchased facilities over their original net book values.

Under the joint ownership agreements, each participating utility is responsible for financing its share of construction, operating and leasing costs. PacifiCorp’s portion is recorded in its applicable construction work-in-progress, operations, maintenance and tax accounts, which is consistent with wholly owned plants.

Note 13 – Consolidation of Variable-Interest Entities

In December 2003, the FASB issued revised FIN 46, Consolidation of Variable-Interest Entities, an interpretation of Accounting Research Bulletin No. 51 (“FIN 46R”), which requires existing unconsolidated variable-interest entities (“VIEs”) to be consolidated by their primary beneficiaries if the entities do not effectively disperse risks among parties involved. FIN 46R was adopted as of January 1, 2004 and resulted in disclosures describing identifiable variable interests.

VIE’s Required to be Consolidated

PacifiCorp holds an undivided interest in 50.0% of the 474-MW Hermiston Plant (see Note 12 – Jointly Owned Facilities), procures 100.0% of the fuel input into the plant and subsequently receives 100.0% of the generated electricity, 50.0% of which is acquired through a long-term purchase power agreement. As a result, PacifiCorp holds a variable interest in the joint owner of the remaining 50.0% of the plant and is the primary beneficiary. However, upon adoption of FIN 46R, PacifiCorp was unable to obtain the information necessary to consolidate the entity, because the entity did not agree to supply the information due to the lack of a contractual obligation to do so. PacifiCorp continues to request from the entity the information necessary to perform the consolidation; however, no information has yet been provided by the entity. Electricity purchased from the joint owner was $35.2 million during the year ended March 31, 2006; $34.8 million during the year ended March

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31, 2005; and $33.7 million during the year ended March 31, 2004. The entity is operated by the equity owners, and PacifiCorp has no risk of loss in relation to the entity in the event of a disaster.

Significant Variable-Interests in VIE’s not Required to be Consolidated

As discussed in Note 4 – Related-Party Transactions, PacifiCorp leases the West Valley facility from a former affiliate under an operating lease that contains purchase options at specified prices. Although the purchase options are variable-interests in West Valley, PacifiCorp is not the primary beneficiary of the entity. PacifiCorp’s exposure to loss under the operating lease is negligible.

PacifiCorp is a party to certain operating and coal purchase agreements with Trapper Mining, Inc. that create a variable interest under the provisions of FIN 46R. Trapper Mining, Inc. owns and operates the Trapper Mine near Craig, Colorado, and produces 100.0% of its output for the benefit of the Craig Power Plant. PacifiCorp has a 21.4% equity interest in Trapper Mining, Inc. and also holds a 19.3% undivided interest in the Craig Power Plant as disclosed in Note 12 – Jointly Owned Facilities. Since each equity investor in Trapper Mining, Inc. also holds a similar interest in the Craig Power Plant, and since none of the joint owners have more than a 50.0% interest in the Craig Power Plant or Trapper Mining, Inc., none of the joint owners are required to consolidate Trapper Mining, Inc. Accordingly, PacifiCorp will continue to account for its interest in Trapper Mining, Inc. via the equity method under APB No. 18, The Equity Method of Accounting for Investments in Common Stock, as in prior periods.

Note 14 – Preferred Stock

PacifiCorp’s Preferred stock was as follows:

(Thousands of shares, millions of dollars, except per share amounts)	Redemption Price Per Share		March 31, 2006			March 31, 2005
Series			Shares	Amount		Shares	Amount
Preferred stock not subject to mandatory redemption Serial Preferred, $100 stated value, 3,500 shares authorized
4.52 %	$	103.5	2	$	0.2	2	$	0.2
4.56		102.3	85		8.4	85		8.4
4.72		103.5	70		6.9	70		6.9
5.00		100.0	42		4.2	42		4.2
5.40		101.0	66		6.6	66		6.6
6.00		Non- redeemable	6		0.6	6		0.6
7.00		Non -redeemable	18		1.8	18		1.8
5% Preferred, $100 stated value, 127 shares authorized		110.0	126		12.6	126		12.6
			415	$	41.3	415	$	41.3

Generally, Preferred stock is redeemable at stipulated prices plus accrued dividends, subject to certain restrictions. Upon voluntary liquidation, all Preferred stock is entitled to stated value or a specified preference amount per share plus accrued dividends. Upon involuntary liquidation, all Preferred stock is entitled to stated value plus accrued dividends. Any premium paid on redemptions of Preferred stock is capitalized, and recovery is sought through future rates. Dividends on all Preferred stock are cumulative. Holders also have the right to elect members to the PacifiCorp Board of Directors in the event dividends payable are in default in an amount equal to four full quarterly payments.

PacifiCorp had $0.5 million at both March 31, 2006 and March 31, 2005 in dividends declared but unpaid on Preferred stock. The shares and amounts outstanding for each series of Preferred stock not subject to mandatory redemption were unchanged from March 31, 2004 through March 31, 2006.

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Note 15-Common Shareholder’s Equity

Common Shareholder’s Equity - PacifiCorp has one class of common stock with no par value. A total of 750,000,000 shares were authorized and 357,060,915 shares were issued and outstanding at March 31, 2006 and 312,176,089 shares were issued and outstanding at March 31, 2005. During the year ended March 31, 2006, PacifiCorp issued 44,884,826 shares of its common stock to PHI, its former parent company, at a total price of $484.7 million. The proceeds from the sale of the shares were used to repay short-term debt.

On March 20, 2006, immediately prior to the closing of PacifiCorp’s sale to MEHC, PacifiCorp paid a dividend on common stock, at that time held by PHI, in the aggregate amount of $16.8 million. The dividend was reduced pursuant to Amendment No. 1 to the Stock Purchase Agreement among MEHC, ScottishPower and PHI executed on the date of the transaction’s closing from the $56.6 million aggregate amount originally declared by the PacifiCorp Board of Directors on January 27, 2006.

In the past, to the extent PacifiCorp did not reimburse ScottishPower for stock-based compensation awarded under ScottishPower plans, such amounts increased the value of PacifiCorp’s common shareholder’s capital.

Common Dividend Restrictions - MEHC is the sole indirect shareholder of PacifiCorp’s common stock. The state regulatory orders that authorized the acquisition of PacifiCorp by MEHC contain restrictions on PacifiCorp’s ability to pay dividends to the extent that they would reduce PacifiCorp’s common stock equity below specified percentages of defined capitalization.

As of March 31, 2006, the most restrictive of these commitments prohibits PacifiCorp from making any distribution to PPW Holdings LLC or MEHC without prior state regulatory approval to the extent that it would reduce PacifiCorp’s common stock equity below 48.25% of its total capitalization, excluding short-term debt and current maturities of long-term debt. After December 31, 2008, this minimum level of common equity declines annually to 44.0% after December 31, 2011. The terms of this commitment treat 50.0% of PacifiCorp’s preferred stock outstanding prior to the acquisition of PacifiCorp by MEHC as common equity. As of March 31, 2006, PacifiCorp’s actual common stock equity percentage, as calculated under this measure, exceeded the minimum threshold.

In addition, PacifiCorp is restricted from making any distributions to PPW Holdings LLC or MEHC if PacifiCorp’s unsecured debt rating is BBB- or lower by Standard & Poor’s Rating Services or Fitch Ratings or Baa3 or lower by Moody’s Investor Service, as indicated by two of the three rating services. As of March 31, 2006, PacifiCorp’s unsecured debt rating was BBB+ by Standard & Poor’s Rating Services and Fitch Ratings and Baa1 by Moody’s Investor Service.

PacifiCorp is also subject to maximum debt-to-total capitalization levels under various debt agreements.

Note 16-Fair Value of Financial Instruments

(Millions of dollars)	March 31, 2006				March 31, 2005
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt (a)	$	3,902.1	$	4,091.4	$	3,872.3	$	4,209.5
Preferred stock subject to mandatory redemption		45.0		46.3		52.5		56.0

(a) Includes long-term debt classified as currently maturing, less capital lease obligations.

The carrying value of cash and cash equivalents, receivables, payables, accrued liabilities and short-term borrowings approximates fair value because of the short-term maturity of these instruments.

The fair value of PacifiCorp’s long-term debt, current maturities of long-term debt and redeemable preferred stock has been estimated by discounting projected future cash flows, using the current rate at which similar loans would be made to borrowers with similar credit ratings and for the same maturities.

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Note 17-Employee Benefits

PacifiCorp sponsors defined benefit pension plans that cover the majority of its employees and also provides health care and life insurance benefits through various plans for eligible retirees. The measurement date for plan assets and obligations is December 31 of each year.

As a result of the sale of PacifiCorp to MEHC, plan participants that were employees or retirees of certain ScottishPower affiliates and a former PacifiCorp mining subsidiary ceased to participate in PacifiCorp’s plans. This separation resulted in a net $3.5 million reduction in Common shareholder’s capital.

Pension Plans

PacifiCorp’s pension plans include the PacifiCorp Retirement Plan (the “Retirement Plan”), the SERP and a joint trust plan to which PacifiCorp contributes on behalf of certain bargaining unit employees of IBEW Local 57. Benefits under the Retirement Plan are based on the employee’s years of service and average monthly pay in the 60 consecutive months of highest pay out of the last 120 months, with adjustments to reflect benefits estimated to be received from social security. Pension costs are funded annually by no more than the maximum amount that can be deducted for federal income tax purposes.

Components of the net periodic pension benefit cost (income) are summarized as follows:

(Millions of dollars)	Years Ended March 31,
	2006			2005			2004
Service cost (a)	$	32.2		$	25.9		$	25.8
Interest cost		74.4			73.8			73.9
Expected return on plan assets (b)		(76.9	)		(77.7	)		(80.7	)
Amortization of unrecognized net transition obligation		8.4			8.4			8.4
Amortization of unrecognized prior service cost		1.2			1.4			1.5
Amortization of unrecognized loss		21.5			8.5			—
Cost of termination benefits		3.0			—			—
Net periodic pension benefit cost	$	63.8		$	40.3		$	28.9

(a) Includes contributions to the PacifiCorp/IBEW Local 57 Retirement Trust Fund of $1.4 million for the year ended March 31, 2006; no contributions for the year ended March 31, 2005; and contributions of $5.6 million for the year ended March 31, 2004.

(b) 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.

The weighted-average rates assumed in the actuarial calculations used to determine the net periodic benefit costs for the pension and postretirement benefit plans were as follows:

	Years Ended March 31,
	2006		2005		2004
Discount rate	5.75	%	6.25	%	6.75	%
Expected long-term rate of return on assets	8.75		8.75		8.75
Rate of increase in compensation levels	4.00		4.00		4.00

PacifiCorp determined the long-term rate of return based on historical asset class returns and current market conditions, taking into account the diversification benefits of investing in multiple asset classes.

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The weighted-average rates assumed in the actuarial calculations used to determine benefit obligations for the pension and postretirement benefit plans were as follows:

	March 31,
	2006		2005		2004
Discount rate	5.75	%	5.75	%	6.25	%
Rate of increase in compensation levels	4.00		4.00		4.00

The change in the projected benefit obligation, change in plan assets and funded status of the pension plans are as follows:

(Millions of dollars)	March 31,
	2006			2005
Change in projected benefit obligation
Projected benefit obligation - beginning of year	$	1,338.1		$	1,229.8
Service cost		30.8			25.9
Interest cost		74.4			73.8
Plan amendments		2.9			1.0
Cost of termination benefits		3.0			—
Separation of former participants		(44.3	)		—
Actuarial loss		22.9			86.8
Benefits paid		(84.1	)		(79.1	)
Transfers		(1.5	)		(0.1	)
Projected benefit obligation - end of year	$	1,342.2		$	1,338.1
Change in plan assets
Plan assets at fair value - beginning of year	$	806.5		$	733.2
Actual return on plan assets		72.6			87.5
Separation of former participants		(32.0	)		—
Company contributions		63.8			65.0
Benefits paid		(84.1	)		(79.1	)
Transfers		(1.9	)		(0.1	)
Plan assets at fair value - end of year	$	824.9		$	806.5
Reconciliation of accrued pension cost and total amount recognized
Funded status of the plan	$	(517.3	)	$	(531.6	)
Unrecognized net loss		435.6			443.6
Unrecognized prior service cost		10.0			9.1
Unrecognized net transition obligation		7.3			15.9
Accrued postretirement benefit before final contribution		(64.4	)		(63.0	)
Contribution made after measurement date but before March 31		3.7			—
Accrued pension cost	$	(60.7	)	$	(63.0	)
Accrued benefit liability	$	(342.3	)	$	(383.2	)
Intangible asset		17.3			25.0
Accumulated other comprehensive income, pre-tax		6.6			14.5
Regulatory assets		257.7			280.7
Accrued pension cost	$	(60.7	)	$	(63.0	)

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The aggregated accumulated benefit obligation was $1,170.9 million and the fair value of assets was $828.6 million, measured as of December 31, 2005, and including contributions prior to March 31, 2006.

The Retirement Plan and the SERP currently have assets with a fair value that is less than the accumulated benefit obligation under the Retirement Plan and the SERP, primarily due to prior declines in the equity markets and historically low interest rate levels. As a result, PacifiCorp recognized minimum pension liabilities in the fourth quarters of the years ended March 31, 2006 and 2005. The minimum pension liability adjustment impacted Regulatory assets, Intangible assets and Accumulated other comprehensive income. These adjustments are reflected in the table above and did not materially affect the consolidated results of operations. PacifiCorp requested and received accounting orders from the regulatory commissions in Utah, Oregon, Wyoming and Washington to classify most of the minimum pension liability adjustment as a Regulatory asset instead of a charge to Other comprehensive income. This increase to Regulatory assets will be adjusted in future periods as the difference between the fair value of the trust assets and the accumulated benefit obligation changes. PacifiCorp has determined that costs related to SFAS No. 87, Employers’ Accounting for Pensions (“SFAS No. 87”) for the Retirement Plan are currently recoverable in rates.

Retirement Plan assets are managed and invested in accordance with all applicable requirements, including the Employee Retirement Income Security Act and the Internal Revenue Code. PacifiCorp employs an investment approach that uses a mix of equities and fixed-income investments to maximize the long-term return of plan assets at a prudent level of risk. Risk tolerance is established through careful consideration of plan liabilities, plan funded status, and corporate financial condition. The investment portfolio contains a diversified blend of equity and fixed-income investments as shown in the table below. Equity investments are diversified across United States and non-United States stocks, as well as growth and value companies, and small and large market capitalizations. Fixed-income investments are diversified across United States and non-United States bonds. Other assets, such as private equity investments, are used to enhance long-term returns while improving portfolio diversification. PacifiCorp primarily minimizes the risk of large losses through diversification but also monitors and manages other aspects of risk through quarterly investment portfolio reviews, annual liability measurements and periodic asset/liability studies.

Details of the Retirement Plan assets by investment category based on market values are as follows:

			March 31,
	Target		2006		2005
Equity securities	55.0	%	58.5	%	56.1	%
Debt securities	35.0		34.5		33.9
Private equity	10.0		7.0		10.0

Although the SERP had no qualified assets as of March 31, 2006, PacifiCorp has a Rabbi trust that holds corporate-owned life insurance and other investments to provide funding for the future cash requirements of the SERP. Because this plan is nonqualified, the assets in the Rabbi trust are not considered plan assets. The cash surrender value of all of the policies included in the Rabbi trust plus the fair market value of other Rabbi trust investments was $36.4 million at March 31, 2006 and $34.7 million at March 31, 2005, net of amounts borrowed against the cash surrender value.

Other Postretirement Benefits

The cost of other postretirement benefits, including health care and life insurance benefits for eligible retirees, is accrued over the active service period of employees. The transition obligation represents the unrecognized prior service cost and is being amortized over a period of 20 years. PacifiCorp funds other postretirement benefits through a combination of funding vehicles. PacifiCorp contributed $29.7 million for the year ended March 31, 2006; $24.9 million for the year ended March 31, 2005; and $25.3 million for the year ended March 31, 2004. The measurement date for plan assets and obligations is December 31 of each year.

For the postretirement benefit plan assets, PacifiCorp employs an investment approach that uses a mix of equities and fixed-income investments to maximize the long-term return of plan assets for a prudent level of risk. Risk tolerance is established through careful consideration of plan liabilities, plan funded status and corporate financial condition. The investment portfolio contains a diversified blend of equity and fixed-income investments. Equity investments are diversified across United States and non-United States stocks, as well as growth and value companies, and small and large market capitalizations. Fixed-income investments are diversified across United States and non-United States bonds. Other assets, such as private equity investments, are used to enhance long-term returns while improving portfolio diversification. PacifiCorp primarily minimizes the risk of large losses through diversification, but also monitors and manages other aspects of risk through quarterly investment portfolio reviews, annual liability measurements and periodic asset/liability studies.

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The assets for other postretirement benefits are composed of three different trust accounts. The 401(h) account is invested in the same manner as the pension account. Each of the two Voluntary Employees’ Beneficiaries Association Trusts has its own investment allocation strategies. Details of the Voluntary Employees’ Beneficiaries Association Trusts’ assets by investment category based on market values are as follows:

			March 31,
	Target		2006		2005
Equity securities	65.0	%	66.0	%	66.4	%
Debt securities	35.0		34.0		33.6

Components of the net periodic postretirement benefit cost are summarized as follows:

	Years Ended March 31,
(Millions of dollars)	2006			2005			2004
Service cost	$	8.8		$	8.5		$	7.4
Interest cost		30.4			31.0			34.3
Expected return on plan assets (a)		(26.3	)		(26.4	)		(26.6	)
Amortization of unrecognized net transition obligation		12.2			12.2			12.2
Amortization of unrecognized loss		2.7			0.6			0.6
Amortization of prior service cost		2.1			0.1			—
Net periodic postretirement benefit cost	$	29.9		$	26.0		$	27.9

(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.

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The change in the accumulated postretirement benefit obligation, change in plan assets and funded status of the postretirement plan is as follows:

	March 31,
(Millions of dollars)	2006			2005
Change in accumulated postretirement benefit obligation
Accumulated postretirement benefit obligation - beginning of year	$	528.3		$	555.3
Service cost		8.8			8.5
Interest cost		30.4			31.0
Plan participant contributions		8.3			7.2
Plan amendments		22.8			0.8
Separation of former participants		(8.9	)		—
Actuarial loss (gain)		34.3			(34.4	)
Benefits paid		(41.6	)		(40.1	)
Accumulated postretirement benefit obligation - end of year	$	582.4		$	528.3
Change in plan assets
Plan assets at fair value - beginning of year	$	286.6		$	261.6
Actual return on plan assets		20.4			28.6
Company contributions		22.5			29.3
Plan participant contributions		8.3			7.2
Separation of former participants		(4.1	)		—
Net benefits paid		(41.6	)		(40.1	)
Plan assets at fair value - end of year	$	292.1		$	286.6
Reconciliation of accrued postretirement costs and total amount recognized
Funded status of the plan	$	(290.3	)	$	(241.7	)
Unrecognized net transition obligation		81.1			94.6
Unrecognized prior service cost		22.1			1.4
Unrecognized loss		138.1			100.1
Accrued postretirement benefit cost, before final contribution		(49.0	)		(45.6	)
Contribution made after measurement date but before March 31		29.7			24.9
Accrued postretirement cost	$	(19.3	)	$	(20.7	)

The assumed health care cost trend rates are as follows:

	March 31,
	2006		2005		2004
Initial health care cost trend - under 65	10.0	%	7.5	%	8.5	%
Initial health care cost trend - over 65	10.0		9.5		10.5
Ultimate health care cost trend rate	5.0		5.0		5.0
Year that rate reaches ultimate - under 65	2011		2007		2007
Year that rate reaches ultimate - over 65	2011		2009		2009

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The health care cost trend rate assumption has a significant effect on the amounts reported. An annual increase or decrease in the assumed medical care cost trend rate of 1.0% would affect the accumulated postretirement benefit obligation and the service and interest cost components as follows:

(Millions of dollars)	One Percent
	Increase		Decrease
Accumulated postretirement benefit obligation	$	43.7	$	(35.5	)
Service and interest cost components		2.8		(2.4	)

Future Contributions and Benefit Payments

In April 2006, PacifiCorp contributed $72.7 million to its Retirement Plan. In addition, PacifiCorp expects to contribute another $11.0 million to its pension plans, as well as $36.6 million to its postretirement benefit plan, during the 12 months ending March 31, 2007. The benefit payments expected to be paid, which reflect expected future service and the Medicare Part D subsidy expected to be received, are as follows:

(Millions of dollars)     12 months ending March 31,	Retirement Plans		Other Postretirement Benefits		Medicare Part D Subsidy Receipts
2007	$	92.5	$	35.8	$	(3.0	)
2008		92.4		37.9		(3.4	)
2009		93.6		40.0		(3.9	)
2010		94.7		42.1		(4.3	)
2011		97.7		44.4		(4.6	)
2012 to 2016 (inclusive)		541.2		248.2		(29.9	)

Employee Savings Plan

PacifiCorp has an employee savings plan (the “Savings Plan”) that qualifies as a tax-deferred arrangement under the Internal Revenue Code. Eligible employees of adopting affiliates are those who are not temporary, casual, leased or covered by a collective bargaining agreement that does not provide for participation. Employees of any company within the PacifiCorp controlled group of companies that has not adopted the Savings Plan are not eligible. Participating United States employees may defer up to 50.0% of their compensation, subject to certain statutory limitations. Compensation includes base pay, overtime and annual incentive, but is limited to the maximum allowable under the Internal Revenue Code. Employees can select a variety of investment options. PacifiCorp matches 50.0% of employee contributions on amounts deferred up to 6.0% of total compensation, with that portion vesting over the initial five years of an employee’s qualifying service. Thereafter, PacifiCorp’s contributions vest immediately. PacifiCorp’s matching contribution is allocated based on the employee’s investment selections. PacifiCorp may also make an additional contribution equal to a percentage of the employee’s eligible earnings. This additional contribution is allocated based on the employee’s investment selections or to the money market fund if the employee has made no selections. These contributions are immediately vested. PacifiCorp’s contributions to the Savings Plan were $22.5 million for the year ended March 31, 2006; $20.2 million for the year ended March 31, 2005; and $19.3 million for the year ended March 31, 2004; and represent amounts expensed for such periods.

Severance

As a result of general workforce reductions and ScottishPower’s corporate restructuring during the year ended March 31, 2006, PacifiCorp incurred severance expense of $4.1 million under its severance and other benefit plans related to the involuntary termination of approximately 62 employees. Services provided by these employees are expected to be complete by March 31, 2007.

As a result of the MEHC acquisition, PacifiCorp has experienced organizational changes and additional workforce reductions resulting in severance expense of $12.9 million during the year ended March 31, 2006 under its severance and other benefit plans, primarily related to the involuntary termination of 29 employees. Additional severance expense is expected to be incurred in the future as additional organizational changes occur.

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Note 18 – Stock-Based Compensation

PacifiCorp Stock Incentive Plan (“PSIP”) - During 1997, PacifiCorp adopted the PSIP. The exercise price of options granted under the PSIP was equal to the market value of the common stock on the date of the grant. ScottishPower took control of the plan upon completion of its merger and all stock options were converted into options to purchase ScottishPower American Depository Shares. The PSIP expired on November 29, 2001 and all outstanding options under the plan were fully vested as of March 31, 2005.

As a result of the sale of PacifiCorp to MEHC and in accordance with the PSIP provisions regarding a change in control, all outstanding options must be exercised no later than 12 months after the date of the sale of PacifiCorp; otherwise they will be forfeited.

ScottishPower Executive Share Option Plan (“ExSOP”) - In prior years, a select group of PacifiCorp employees received grants of stock options under the ScottishPower ExSOP. Certain grants awarded in May 2001 were performance-based awards which resulted in $2.0 million of compensation expense included in Operations and maintenance expense for the year ended March 31, 2005.

As a result of the sale of PacifiCorp to MEHC on March 21, 2006, all ExSOP options held by PacifiCorp employees became fully vested in accordance with the change-in-control provisions of the ExSOP. The change-in-control provisions also provide that all outstanding options are exercisable up to the later of 12 months after the date of the sale of PacifiCorp or 42 months after the date of original option grant. Options that are not exercised within this time period will be forfeited. As of the date of the sale, PacifiCorp ceased to participate in the plan but as of March 31, 2006, there are still options outstanding and exercisable by PacifiCorp employees.

The table below summarizes the stock option activity under the PSIP and the ExSOP.

	PSIP				ExSOP
ScottishPower American Depository Shares	Number of Shares		Weighted Average Price		Number of Shares		Weighted Average Price
Outstanding options at March 31, 2003	3,403,251		$	31.67	935,054		$	23.55
Granted	—			—	780,901			24.40
Exercised	(147,496	)		25.55	(25,508	)		23.55
Forfeited	(331,706	)		34.65	(41,991	)		23.93
Outstanding options at March 31, 2004	2,924,049			31.64	1,648,456			23.94
Granted	—			—	763,843			28.72
Exercised	(750,126	)		26.10	(483,667	)		23.84
Forfeited	(40,310	)		35.36	(30,136	)		26.37
Outstanding options at March 31, 2005	2,133,613			33.52	1,898,496			25.85
Exercised	(1,325,284	)		31.32	(1,404,637	)		25.58
Forfeited	(30,578	)		35.86	(16,096	)		27.59
Transfers due to separation	(68,710	)		37.35	(164,677	)		25.56
Outstanding options at March 31, 2006	709,041			37.15	313,086			27.15

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Information with respect to options outstanding and options exercisable under the PSIP and the ExSOP as of March 31, 2006 and 2005 were as follows:

	Options Outstanding				Options Exercisable
Range of Exercise Prices	Number of Shares	Weighted Average Exercise Price		Weighted Average Remaining Life (in years)	Number of Shares	Weighted Average Exercise Price
Year ended March 31, 2006
PSIP
$25.70 - $36.64	268,205	$	31.25	1.0	268,205	$	31.25
$39.99 - $41.38	440,836		40.74	1.0	440,836		40.74
Total	709,041		37.15	1.0	709,041		37.15
ExSOP
$23.55 - $28.72	313,086	$	27.15	1.4	313,086	$	27.15
Year ended March 31, 2005
PSIP
$25.70 - $36.64	1,589,323	$	31.05	4.2	1,589,323	$	31.05
$39.99 - $43.83	544,290		40.72	3.0	544,290		40.72
Total	2,133,613		33.52	3.9	2,133,613		33.52
ExSOP
$23.55 - $28.72	1,898,496	$	25.85	8.2	182,134	$	23.97

ScottishPower Long-Term Incentive Plan-In prior years, a select group of PacifiCorp employees received grants of performance share awards under ScottishPower’s Long-Term Incentive Plan. The number of shares that actually vest is dependent upon the outcome of certain performance measures over a three-year period. The plan’s change-in-control provisions resulted in removal of the employees’ future service requirement as of the date of the acquisition but retained the three-year performance requirements. As a result, the number of shares that ultimately vest at the end of the performance period, if any, will be prorated to reflect only the portion of the three-year period which had elapsed between the date of original grant and the date of the sale of PacifiCorp to MEHC. During the year ended March 31, 2006, no stock-based compensation expense was recorded because the performance measures were not yet reached.

Deferred Share Program - In May 2004, ScottishPower implemented a deferred share program under which certain PacifiCorp employees were granted an annual stock bonus award based on a fixed dollar amount but distributable in ScottishPower American Depository Shares with the number of shares to be determined by the quoted market price of the shares at the date of issuance. Historically, compensation expense was accrued throughout the year in which the employee services were rendered and awards earned. During the year ended March 31, 2005, $3.1 million of compensation costs were accrued. However, as a result of the sale of PacifiCorp to MEHC, the program was modified during the year ended March 31, 2006 to provide for a cash payment rather than a share-based payment. The plan was discontinued as of April 1, 2006.

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Note 19-Income Taxes

The difference between the United States federal statutory tax rate and the effective income tax rate attributed to income from continuing operations is as follows:

	Years Ended March 31,
	2006		2005		2004
Federal statutory rate	35.0	%	35.0	%	35.0	%
State taxes, net of federal benefit	2.9		3.8		3.6
Effect of regulatory treatment of depreciation differences	2.5		4.1		4.5
Tax reserves	1.1		(0.9	)	(3.1	)
Tax credits	(2.6	)	(2.3	)	(2.5	)
Other	(3.3	)	0.4		(0.8	)
Effective income tax rate	35.6	%	40.1	%	36.7	%

The provision for income taxes is summarized as follows:

	Years Ended March 31,
(Millions of dollars)	2006			2005			2004
Current
Federal	$	167.3		$	58.6		$	63.0
State		18.2			(10.1	)		1.0
Total		185.5			48.5			64.0
Deferred
Federal		19.7			112.6			77.8
State		2.1			15.3			10.6
Total		21.8			127.9			88.4
Investment tax credits		(7.9	)		(7.9	)		(7.9	)
Total income tax expense	$	199.4		$	168.5		$	144.5

The tax effect of temporary differences giving rise to significant portions of PacifiCorp’s deferred tax liabilities and deferred tax assets were as follows:

(Millions of dollars)	March 31,
	2006			2005
Deferred tax liabilities:
Property, plant and equipment	$	1,531.2		$	1,512.3
Regulatory assets		623.0			667.9
Derivative contract regulatory assets		35.9			64.5
Other deferred tax liabilities		114.3			126.3
		2,304.4			2,371.0
Deferred tax assets:
Regulatory liabilities		(316.9	)		(325.2	)
Employee benefits		(170.9	)		(185.4	)
Derivative contracts		(44.0	)		(102.6	)
Other deferred tax assets		(134.5	)		(126.8	)
		(666.3	)		(740.0	)
Net deferred tax liability	$	1,638.1		$	1,631.0

PacifiCorp made net income tax payments of $140.0 million for the year ended March 31, 2006; $92.0 million for the year ended March 31, 2005; and $114.1 million for the year ended March 31, 2004. The income tax payments include payments for current federal and state income taxes, as well as amounts paid in settlement of prior years’ liabilities as a result of income tax proceedings.

39

PacifiCorp has established, and periodically reviews, an estimated contingent tax reserve on its Consolidated Balance Sheets to provide for the possibility of adverse outcomes in tax proceedings. The net federal and state contingency reserve increased $6.1 million during the year ended March 31, 2006 primarily due to new issues identified for tax years ended after March 31, 2000. The Internal Revenue Service started its examination of the 2001, 2002 and 2003 tax years in October 2004. 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.

The sale of PacifiCorp to MEHC on March 21, 2006 triggered the recognition of a deferred intercompany gain or loss for tax purposes. The recognition of the tax effects of this item is considered to have been recognized immediately prior to the closing of the sale of PacifiCorp while it was part of the PHI consolidated group. PacifiCorp is currently unable to estimate the amount of the tax effect, if any, or determine a range of the potential tax effect. Due to the uncertainty of the amount of the deferred intercompany gain or loss, no adjustments have been recorded as of March 31, 2006.

Pursuant to a formal agreement with PHI and ScottishPower, any tax liabilities generated as a result of a deferred intercompany gain would be recorded as an equity contribution to PacifiCorp. Additionally, as this transaction is deemed to be with shareholders, the net tax expense would be recorded as a reduction in Common shareholder’s capital similar to a return of capital distribution. As a result, there would be no net impact to PacifiCorp’s Common shareholder’s capital, statement of financial position or results of operations.

If a deferred intercompany loss is determined to exist, PacifiCorp would be required to recognize the tax benefit of the deferred intercompany loss as an increase in Common shareholder’s capital and establish a corresponding tax receivable or deferred tax asset, depending on whether PacifiCorp would be able to currently utilize the capital loss. In the event a deferred tax asset is created with respect to the capital loss, it will be necessary to determine whether a valuation allowance should be established against the deferred tax asset.

At March 31, 2006, PacifiCorp had no federal or state net operating loss carryforwards. At March 31, 2005, PacifiCorp had total available federal net operating loss carryforwards of approximately $2.7 million and no state net operating loss carryforwards. PacifiCorp has Oregon business energy tax credits of approximately $0.6 million at March 31, 2006 available to reduce future income tax liabilities. These credits begin to expire in 2012. PacifiCorp has Idaho investment tax credits of approximately $1.9 million at March 31, 2006 that are available to reduce future income tax liabilities. These credits begin to expire in 2017. PacifiCorp anticipates utilizing the tax credits prior to the expiration dates.

Note 20 - Concentration of Customers

During the year ended March 31, 2006, no single retail customer accounted for more than 2.0% of PacifiCorp’s retail electric revenues, and the 20 largest retail customers accounted for 13.0% of total retail electric revenues. The geographical distribution of PacifiCorp’s retail operating revenues for the year ended March 31, 2006 was: Utah, 40.9%; Oregon, 29.3%; Wyoming, 13.3%; Washington, 8.4%; Idaho, 5.7%; and California, 2.4%.

Note 21 - Subsequent Events

On May 10, 2006, the PacifiCorp Board of Directors determined to change PacifiCorp’s fiscal year-end from March 31 to December 31. PacifiCorp’s report covering the transition period beginning April 1, 2006 and ending December 31, 2006 will be filed on Form 10-K.

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SUPPLEMENTAL INFORMATION

QUARTERLY FINANCIAL DATA (UNAUDITED)

(Millions of dollars, except per share amounts)	Quarters Ended
	June 30		September 30		December 31		March 31
2006
Revenues	$	881.4	$	620.7	$	1,165.0	$	1,229.6
Income from operations		135.9		129.2		256.2		270.7
Net income		46.4		39.4		127.8		147.1
Earnings on common stock		45.9		38.9		127.2		146.6
Common dividends declared per share		16.3¢		16.3¢		16.3¢		4.8¢
Common dividends paid per share		16.3¢		16.3¢		16.3¢		4.8¢
2005
Revenues	$	747.8	$	828.7	$	849.5	$	622.8
Income from operations		129.9		165.3		155.2		206.0
Net income		50.9		61.9		51.3		87.6
Earnings on common stock		50.4		61.4		50.7		87.1
Common dividends declared per share		15.5¢		15.5¢		15.5¢		15.5¢
Common dividends paid per share		15.5¢		15.5¢		15.5¢		15.5¢

On March 31, 2006, MEHC was the only common shareholder of record.

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EX-99.2

EXHIBIT 99.2

MIDAMERICAN ENERGY HOLDINGS COMPANY

UNAUDITED PRO FORMA CONDENSED COMBINED

CONSOLIDATED STATEMENTS OF OPERATIONS

The following unaudited pro forma condensed combined consolidated statements of operations are based on the historical consolidated statements of operations of MidAmerican Energy Holdings Company (‘‘MEHC’’) and PacifiCorp after giving effect to the $5.1 billion acquisition of PacifiCorp by MEHC (the ‘‘Pro Forma Transaction’’) using the purchase method of accounting in accordance with Statement of Financial Accounting Standard No. 141, Business Combinations.

Under the purchase method of accounting, MEHC's cost to acquire PacifiCorp was preliminarily allocated to the net tangible and identifiable intangible assets acquired and liabilities assumed based upon their estimated fair values as of March 21, 2006, the closing date of the acquisition. The excess of purchase price, including outside fees and costs incurred in connection with the acquisition over the preliminary estimated fair values of the net assets acquired and liabilities assumed was classified as goodwill. PacifiCorp’s operations are regulated and are accounted for pursuant to SFAS No. 71, Accounting for the Effects of Certain Types of Regulation (“SFAS 71”). Under the rate setting and recovery provisions currently in place for these regulated operations, which provide revenue derived from cost, significant differences between the fair values of the individual tangible and intangible assets and liabilities and their carrying values were recorded with an offset to regulatory assets and liabilities. The following table summarizes the preliminary estimated fair value of assets acquired and liabilities assumed as of the acquisition date (in millions):

	Preliminary
	Fair Value
Current assets, including cash and cash equivalents of $182.5	$	1,115.3
Properties, plants and equipment, net		10,050.9
Goodwill		1,074.3
Regulatory assets		1,398.2
Other non-current assets		659.5
Current liabilities, including short-term debt of $184.4 and current portion of long-term debt of $220.6		(1,255.8	)
Regulatory liabilities		(816.3	)
Pension and postretirement obligations		(826.8	)
Subsidiary and project debt, less current portion		(3,762.3	)
Deferred income taxes		(1,681.9	)
Other non-current liabilities		(834.9	)
Net assets acquired	$	5,120.2

Given the size and timing of the acquisition, the fair values set forth above are preliminary and are subject to adjustment as additional information is obtained. When finalized, adjustments to goodwill may result. MEHC management may identify additional assets and liabilities as part of the definitive allocation process, which may adversely impact future earnings of the combined company, but are not expected to impact cash flows. Refer to Note 2 to the unaudited consolidated financial statements included in MEHC’s Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2006, for additional discussion regarding the allocation of purchase price.

The unaudited pro forma condensed combined consolidated statements of operations for the year ended December 31, 2005 and the quarter ended March 31, 2006, give effect to the Pro Forma Transaction as though it occurred on January 1, 2005. The unaudited pro forma condensed combined consolidated statements of operations include estimates of potential adjustments for events that are (a) directly attributable to the Pro Forma Transaction, (b) factually supportable, and (c) expected to have a continuing impact on MEHC's results following the Pro Forma Transaction.

The fiscal year ends of MEHC and PacifiCorp are December 31 and March 31, respectively. The historical financial information of MEHC for the year ended December 31, 2005, and the quarter ended March 31, 2006, has been derived from its audited and unaudited consolidated financial statements and notes thereto. The historical financial information of PacifiCorp for the year ended December 31, 2005, and the quarter ended March 31, 2006, has been derived from the unaudited consolidated financial statements of PacifiCorp for the nine months ended December 31, 2005 and 2004, and the audited consolidated financial statements for the years ended March 31, 2006 and 2005.

These unaudited pro forma condensed combined consolidated statements of operations should be read in conjunction with (i) the accompanying notes to the unaudited pro forma condensed combined consolidated statements of operations, (ii) the separate audited historical financial statements of MEHC and notes thereto for the year ended December 31, 2005, included in MEHC’s Annual Report on Form 10-K for the year ended December 31, 2005, (iii) the separate unaudited historical financial statements of MEHC and notes thereto for the fiscal quarter ended March 31, 2006, included in MEHC’s Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2006, (iv) the separate unaudited historical financial statements and related notes thereto of PacifiCorp for the nine-month periods ended December 31, 2005 and 2004, included in PacifiCorp’s Quarterly Report on Form 10-Q for the quarterly period ended December 31, 2005, and (v) the separate audited historical financial statements of PacifiCorp and notes thereto for the years ended March 31, 2006 and 2005, included in PacifiCorp’s Annual Report on Form 10-K for the year ended March 31, 2006.

These unaudited pro forma condensed combined consolidated statements of operations are presented for illustrative purposes only and are not necessarily indicative of what the combined company's operating results actually would have been had the acquisition been completed on the date indicated. In addition, the unaudited pro forma condensed combined consolidated statements of operations do not purport to project the future operating results of the combined company.

2

MIDAMERICAN ENERGY HOLDINGS COMPANY

UNAUDITED PRO FORMA CONDENSED COMBINED CONSOLIDATED STATEMENT OF OPERATIONS

FOR THE YEAR ENDED DECEMBER 31, 2005

(in millions)

 

				PacifiCorp Historical
	MEHC Historical			Three-months Ended 3/31/05			Nine-months Ended 12/31/05			As Adjusted			Pro Forma Adjustments				Total
Operating revenue	$	7,115.5		$	622.8		$	2,667.1		$	3,289.9		$	(2.5	)	(b)	$	10,402.9
Costs and expenses:
Cost of sales		3,284.9			58.8			997.0			1,055.8			(2.5	)	(b)		4,338.2
Operating expense and other		1,693.7			247.5			813.2			1,060.7			—				2,754.4
Depreciation and amortization		608.2			110.2			335.6			445.8			—				1,054.0
Total costs and expenses		5,586.8			416.5			2,145.8			2,562.3			(2.5	)			8,146.6
Operating income		1,528.7			206.3			521.3			727.6			—				2,256.3
Other income (expense):
Interest expense, net of amounts capitalized		(874.3	)		(62.5	)		(189.1	)		(251.6	)		(9.9	)	(c)		(1,136.1	)
														(0.3	)	(d)
Interest and dividend income		58.1			1.5			7.1			8.6			3.1		(e)		69.8
Other income (expense)		52.4			(1.1	)		3.4			2.3			9.9		(c)		64.6
Total other income (expense)		(763.8	)		(62.1	)		(178.6	)		(240.7	)		2.8				(1,001.7	)
Income from continuing operations before income tax expense, minority interest and preferred dividends of subsidiaries and equity income		764.9			144.2			342.7			486.9			2.8				1,254.6
Income tax expense		244.7			56.6			129.1			185.7			1.1		(f)		431.5
Minority interest and preferred dividends of subsidiaries		16.0			0.5			1.6			2.1			—				18.1
Income from continuing operations before equity income		504.2			87.1			212.0			299.1			1.7				805.0
Equity income		53.3			—			—			—			—				53.3
Income from continuing operations	$	557.5		$	87.1		$	212.0		$	299.1		$	1.7			$	858.3

The accompanying notes are an integral part of these unaudited pro forma financial statements.

3

MIDAMERICAN ENERGY HOLDINGS COMPANY

UNAUDITED PRO FORMA CONDENSED COMBINED CONSOLIDATED STATEMENT OF OPERATIONS

FOR THE QUARTER ENDED MARCH 31, 2006

(in millions)

 

	MEHC Historical									PacifiCorp Historical
	Three- months Ended 3/31/2006			Pro Forma Adjustments(a)			As Adjusted			Fiscal Year Ended 3/31/2006			Nine-months Ended 12/31/2005			As Adjusted			Pro Forma Adjustments				Total
Operating revenue	$	2,054.6		$	(76.5	)	$	1,978.1		$	3,896.7		$	2,667.1		$	1,229.6		$	(0.7	)	(b)	$	3,207.0
Costs and expenses:
Cost of sales		954.1			(6.5	)		947.6			1,545.1			997.0			548.1			(0.7	)	(b)		1,495.0
Operating expense and other		450.0			(34.2	)		415.8			1,111.3			813.2			298.1			—				713.9
Depreciation and amortization		188.0			(13.3	)		174.7			448.3			335.6			112.7			—				287.4
Total costs and expenses		1,592.1			(54.0	)		1,538.1			3,104.7			2,145.8			958.9			(0.7	)			2,496.3
Operating income		462.5			(22.5	)		440.0			792.0			521.3			270.7			—				710.7
Other income (expense):
Interest expense, net of amounts capitalized		(217.1	)		7.7			(209.4	)		(247.5	)		(189.1	)		(58.4	)		(6.4	)	(c)		(274.3	)
																				(0.1	)	(d)
Interest and dividend income		15.3			(0.2	)		15.1			9.5			7.1			2.4			0.8		(e)		18.3
Other income (expense)		121.7			(1.2	)		120.5			6.1			3.4			2.7			6.4		(c)		129.6
Total other income (expense)		(80.1	)		6.3			(73.8	)		(231.9	)		(178.6	)		(53.3	)		0.7				(126.4	)
Income from continuing operations before income tax expense, minority interest and preferred dividends of subsidiaries and equity income		382.4			(16.2	)		366.2			560.1			342.7			217.4			0.7				584.3
Income tax expense		131.2			(6.0	)		125.2			199.4			129.1			70.3			0.3		(f)		195.8
Minority interest and preferred dividends of subsidiaries		4.0			—			4.0			2.1			1.6			0.5			—				4.5
Income from continuing operations before equity income		247.2			(10.2	)		237.0			358.6			212.0			146.6			0.4				384.0
Equity income		1.8			—			1.8			—			—			—			—				1.8
Income from continuing operations	$	249.0		$	(10.2	)	$	238.8		$	358.6		$	212.0		$	146.6		$	0.4			$	385.8

The accompanying notes are an integral part of these unaudited pro forma financial statements.

4

MidAmerican Energy Holdings Company

Notes to Unaudited Pro Forma Condensed Combined Consolidated Statements of Operations

1. Basis of Presentation

On March 21, 2006, a wholly-owned subsidiary of MidAmerican Energy Holdings Company (“MEHC”) acquired 100% of the common stock of PacifiCorp, a regulated electric utility providing service to approximately 1.6 million customers in California, Idaho, Oregon, Utah, Washington and Wyoming from a wholly-owned subsidiary of Scottish Power plc ("ScottishPower") for a cash price of approximately $5.1 billion. The long-term debt and preferred stock of PacifiCorp, which aggregated to approximately $4.2 billion at March 21, 2006, remained outstanding following completion of the PacifiCorp acquisition. MEHC funded the acquisition of PacifiCorp with the proceeds from the sale of $5.074 billion of MEHC common stock to Berkshire Hathaway and $35.5 million of MEHC common stock to other shareholders (collectively, the ‘‘New Equity Investment’’).

The total estimated purchase price of the acquisition and the excess of the purchase price over the book values of the assets acquired and liabilities assumed, as of March 21, 2006, is as follows (in millions):

New Equity Investment	$	5,109.5
Direct transaction costs(1)		10.7
Total estimated purchase price		5,120.2
Less: Book value of PacifiCorp's assets to be acquired and liabilities to be assumed		(3,996.0	)
Post-closing receivable(2)		(49.9	)
Estimated excess of the purchase price over book value as of March 21, 2006	$	1,074.3

⁽¹⁾ The direct transaction costs consist principally of investment banker commissions and outside legal and accounting fees and expenses.

⁽²⁾ Pursuant to the terms of the Stock Purchase Agreement, as amended, ScottishPower is required to pay MEHC $4.0 million per year for 25 years after the closing date of the acquisition. A discounted asset of $49.9 million, assuming a 6.25% discount rate, was recognized in respect of the contractual receivable.

Under the purchase method of accounting, the total estimated purchase price, as shown in the table above, was allocated to PacifiCorp’s net tangible and identified intangible assets acquired and liabilities assumed based on their preliminary estimated fair values as of March 21, 2006, the closing date of the acquisition. The excess of the purchase price over the book value of the net assets acquired and liabilities assumed totaling $1.1 billion, is classified as goodwill in MEHC’s consolidated balance sheet. In accordance with Statement of Financial Accounting Standard No. 142, Goodwill and Other Intangible Assets, goodwill will not be amortized, but instead will be tested for impairment at least annually. In the event that management determines that the value of goodwill has become impaired, the combined company may incur an accounting charge for the amount of the impairment during the fiscal quarter in which the determination is made.

Statement of Financial Accounting Standard No. 141, Business Combinations (“SFAS 141”) requires that the total purchase price be allocated to PacifiCorp’s net tangible and identified intangible assets acquired and liabilities assumed based on their preliminary estimated fair values as of the acquisition date. PacifiCorp’s operations are regulated and are accounted for pursuant to SFAS No. 71, Accounting for the Effects of Certain Types of Regulation (“SFAS 71”). Under the rate setting and recovery provisions currently in place for these regulated operations, which provide revenue derived from cost, significant differences between the fair values of the individual tangible and intangible assets and liabilities and their carrying values were recorded with an offset to regulatory assets and liabilities. Given the size and timing of the acquisition, the fair values are preliminary and are subject to adjustment as additional information is obtained. When finalized, adjustments to goodwill may result. MEHC management may identify additional assets and liabilities as part of the definitive allocation process, which may adversely impact future earnings of the combined company, but are not expected to impact cash flows. Refer to Note 2 to the unaudited consolidated financial statements included in MEHC’s Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2006, for additional discussion regarding the allocation of purchase price.

5

MEHC has not identified any material pre-acquisition contingencies where the related asset, liability or impairment is probable and the amount of the asset, liability or impairment can be reasonably estimated. Prior to the end of the purchase price allocation period, if information becomes available that a pre-acquisition related loss had been incurred and the amounts can be reasonably estimated, such items will be included in the purchase price allocation.

Certain transition activities will occur as PacifiCorp is integrated into MEHC. Costs, consisting primarily of employee termination activities, will be incurred associated with such transition activities. MEHC is in the process of finalizing these plans and expects to execute these plans over the next several months. In accordance with Emerging Issues Task Force Issue No. 95-3, Recognition of Liabilities in Connection with a Purchase Business Combination (“EITF 95-3”), the finalization of certain integration plans will result in adjustments to the purchase price allocation for the acquired assets and assumed liabilities of PacifiCorp. Severance costs accrued pursuant to EITF 95-3 totaled $8.8 million at March 31, 2006. Transition costs that do not meet the criteria in EITF 95-3 are expensed in the period incurred.

2. Pro Forma Adjustments

The pro forma adjustments reflect the elimination of intercompany transactions and accounts.

The pro forma combined provision for income taxes does not necessarily reflect the amounts that would have resulted had MEHC and PacifiCorp filed consolidated income tax returns during the periods presented.

(a) Represents the pro forma adjustment to eliminate PacifiCorp’s earnings recognized by MEHC from March 21, 2006, the closing date of the acquisition, through March 31, 2006.

(b) Represents the elimination of the intercompany transactions and accounts between PacifiCorp and Intermountain Geothermal Company. Intermountain Geothermal Company, a wholly-owned subsidiary of MEHC at the time of the closing of the acquisition, provides steam under contract to PacifiCorp. In March 2006, subsequent to the acquisition of PacifiCorp, MEHC contributed the shares of Intermountain Geothermal Company to PacifiCorp.

(c) Represents the pro forma adjustment to reclassify equity allowance for funds used during construction to conform to MEHC’s historical presentation.

(d) Represents the pro forma adjustment to record interest expense on incremental short-term borrowings on transaction costs.

(e) Pursuant to the terms of the Stock Purchase Agreement, as amended, ScottishPower is required to pay MEHC $4.0 million per year for 25 years after the closing date of the acquisition. A discounted asset of $49.9 million, assuming a 6.25% discount rate, was recognized in respect of the contractual receivable. This amount represents the pro forma adjustment to record interest income on the post-closing payment receivable.

(f) Represents the pro forma tax effect of the above adjustments determined based on an estimated statutory tax rate of 40%. This estimate could change based on changes in the applicable tax rates and finalization of the combined company's tax position.

6