UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

[X] Quarterly Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the quarterly period ended September 30, 2006

or

[ ] Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the transition period from ______ to _______

Commission File No. 001-14881

MIDAMERICAN ENERGY HOLDINGS COMPANY

(Exact name of registrant as specified in its charter)

Iowa	94-2213782
(State or other jurisdiction of	(I.R.S. Employer
incorporation or organization)	Identification No.)
666 Grand Avenue, Des Moines, Iowa	50309
(Address of principal executive offices)	(Zip Code)
(515) 242-4300
(Registrant’s telephone number, including area code)
(Former name, former address and former fiscal year, if changed since last report)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ¨ No T

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

Large accelerated filer ¨ Accelerated filer ¨ Non-accelerated filer T

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

Yes ¨ No T

All of the shares of common equity of MidAmerican Energy Holdings Company are privately held by a limited group of investors. As of October 27, 2006, 74,164,001 shares of common stock were outstanding.

TABLE OF CONTENTS

PART I - FINANCIAL INFORMATION

Item 1.	Financial Statements	3
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	33
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	53
Item 4.	Controls and Procedures	56
PART II - OTHER INFORMATION
Item 1.	Legal Proceedings	57
Item 1A.	Risk Factors	58
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	58
Item 3.	Defaults Upon Senior Securities	58
Item 4.	Submission of Matters to a Vote of Security Holders	58
Item 5.	Other Information	58
Item 6.	Exhibits	58
Signatures		59
Exhibit Index		60

2

PART I - FINANCIAL INFORMATION

Item 1. Financial Statements.

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders

MidAmerican Energy Holdings Company

Des Moines, Iowa

We have reviewed the accompanying consolidated balance sheet of MidAmerican Energy Holdings Company and subsidiaries (the “Company”) as of September 30, 2006, and the related consolidated statements of operations for the three-month and nine-month periods ended September 30, 2006 and 2005, and of stockholders’ equity and cash flows for the nine-month periods ended September 30, 2006 and 2005. These interim financial statements are the responsibility of the Company’s management.

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

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

We have previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet of MidAmerican Energy Holdings Company and subsidiaries as of December 31, 2005, and the related consolidated statements of operations, stockholders’ equity, and cash flows for the year then ended (not presented herein); and in our report dated March 3, 2006, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying consolidated balance sheet as of December 31, 2005 is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.

/s/ Deloitte & Touche LLP

Des Moines, Iowa

November 3, 2006

3

MIDAMERICAN ENERGY HOLDINGS COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (Unaudited)

(Amounts in millions)

	As of
	September 30,		December 31,
	2006		2005
ASSETS
Current assets:
Cash and cash equivalents	$	432.9	$	357.9
Short-term investments		18.5		38.4
Restricted cash and short-term investments		143.4		102.9
Accounts receivable, net		1,101.5		802.6
Amounts held in trust		113.7		108.5
Inventories		374.9		128.2
Derivative contracts		221.9		54.0
Deferred income taxes		154.1		177.7
Other current assets		262.0		140.1
Total current assets		2,822.9		1,910.3
Properties, plants and equipment, net		23,324.2		11,915.4
Goodwill		5,313.2		4,156.2
Regulatory assets		1,878.5		441.1
Other investments		985.4		798.7
Derivative contracts		290.2		6.1
Deferred charges and other assets		1,411.6		1,142.9
Total assets	$	36,026.0	$	20,370.7

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

4

MIDAMERICAN ENERGY HOLDINGS COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (Unaudited) (continued)

(Amounts in millions)

	As of
	September 30,			December 31,
	2006			2005
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable	$	919.5		$	523.6
Accrued interest		340.5			198.3
Accrued property and other taxes		318.7			189.1
Amounts held in trust		113.7			108.5
Derivative contracts		204.8			61.7
Other liabilities		588.9			389.3
Short-term debt		296.3			70.1
Current portion of long-term debt		511.7			313.7
Current portion of parent company subordinated debt		234.0			234.0
Total current liabilities		3,528.1			2,088.3
Other long-term accrued liabilities		928.2			766.9
Regulatory liabilities		1,647.3			773.9
Pension and postretirement obligations		1,452.6			633.3
Derivative contracts		643.2			106.8
Parent company senior debt		4,477.9			2,776.2
Parent company subordinated debt		1,189.0			1,354.1
Subsidiary and project debt		10,898.1			6,836.6
Deferred income taxes		3,361.1			1,539.6
Total liabilities		28,125.5			16,875.7
Minority interest		104.4			21.4
Preferred securities of subsidiaries		128.7			88.4
Commitments and contingencies (Note 9)
Stockholders’ equity:
Zero-coupon convertible preferred stock - no shares authorized, issued or outstanding at September 30, 2006; 50.0 shares authorized, no par value, 41.3 shares issued and outstanding at December 31, 2005		-			-
Common stock - 115.0 shares authorized, no par value, 74.2 shares issued and outstanding at September 30, 2006; 60.0 shares authorized, no par value, 9.3 shares issued and outstanding at December 31, 2005		-			-
Additional paid-in capital		5,396.2			1,963.3
Retained earnings		2,355.9			1,719.5
Accumulated other comprehensive loss, net		(84.7	)		(297.6	)
Total stockholders' equity		7,667.4			3,385.2
Total liabilities and stockholders' equity	$	36,026.0		$	20,370.7

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

5

MIDAMERICAN ENERGY HOLDINGS COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)

(Amounts in millions)

	Three-Month Periods						Nine-Month Periods
	Ended September 30,						Ended September 30,
	2006			2005			2006			2005
Operating revenue	$	2,779.9		$	1,745.4		$	7,452.1		$	5,154.0
Costs and expenses:
Cost of sales		1,238.6			776.4			3,348.4			2,323.9
Operating expense		680.3			413.2			1,816.3			1,218.2
Depreciation and amortization		245.5			165.5			737.5			462.5
Total costs and expenses		2,164.4			1,355.1			5,902.2			4,004.6
Operating income		615.5			390.3			1,549.9			1,149.4
Other income (expense):
Interest expense		(308.7	)		(221.0	)		(838.5	)		(676.7	)
Capitalized interest		10.7			4.7			25.6			12.9
Interest and dividend income		19.2			17.3			52.8			40.7
Other income		26.5			14.8			201.1			53.8
Other expense		(1.8	)		(15.8	)		(10.4	)		(20.6	)
Total other income (expense)		(254.1	)		(200.0	)		(569.4	)		(589.9	)
Income from continuing operations before income tax expense, minority interest and preferred tax expense, minority interest and preferred		361.4			190.3			980.5			559.5
Income tax expense		107.6			55.6			320.5			187.2
Minority interest and preferred dividends of subsidiaries		6.5			4.4			20.4			11.0
Income from continuing operations before equity income		247.3			130.3			639.6			361.3
Equity income		25.0			22.9			34.7			41.0
Income from continuing operations		272.3			153.2			674.3			402.3
Income from discontinued operations, net of income tax		-			1.8			-			4.8
Net income available to common and preferred stockholders	$	272.3		$	155.0		$	674.3		$	407.1

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

6

MIDAMERICAN ENERGY HOLDINGS COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY (Unaudited)

FOR THE NINE-MONTH PERIODS ENDED SEPTEMBER 30, 2006 AND 2005

(Amounts in millions)

												Accumulated
	Outstanding					Additional						Other
	Common			Common		Paid-in			Retained			Comprehensive
	Shares			Stock		Capital			Earnings			Loss			Total
Balance, January 1, 2005		9.0		$	-	$	1,950.7		$	1,156.8		$	(136.3	)	$	2,971.2
Net income		-			-		-			407.1			-			407.1
Other comprehensive loss		-			-		-			-			(132.6	)		(132.6	)
Other equity transactions		-			-		0.6			-			-			0.6
Balance, September 30, 2005		9.0		$	-	$	1,951.3		$	1,563.9		$	(268.9	)	$	3,246.3
Balance, January 1, 2006		9.3		$	-	$	1,963.3		$	1,719.5		$	(297.6	)	$	3,385.2
Net income		-			-		-			674.3			-			674.3
Other comprehensive income		-			-		-			-			212.9			212.9
Preferred stock conversion to common
stock		41.3			-		-			-			-			-
Exercise of common stock options		0.5			-		13.1			-			-			13.1
Tax benefit from exercise of common
stock options		-			-		19.8			-			-			19.8
Common stock issuances		35.2			-		5,109.5			-			-			5,109.5
Common stock purchases		(12.1	)		-		(1,712.1	)		(37.9	)		-			(1,750.0	)
Other equity transactions		-			-		2.6			-			-			2.6
Balance, September 30, 2006		74.2		$	-	$	5,396.2		$	2,355.9		$	(84.7	)	$	7,667.4

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

7

MIDAMERICAN ENERGY HOLDINGS COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)

(Amounts in millions)

	Nine-Month Periods
	Ended September 30,
	2006			2005
Cash flows from operating activities:
Income from continuing operations	$	674.3		$	402.3
Adjustments to reconcile income from continuing operations to cash flows from continuing operations:
Distributions less income on equity investments		(18.2	)		(16.9	)
Gain on other items, net		(134.6	)		(22.7	)
Depreciation and amortization		737.5			462.5
Amortization of regulatory assets and liabilities		31.2			31.3
Amortization of deferred financing costs		12.3			14.5
Provision for deferred income taxes		219.3			136.1
Other		39.3			20.9
Changes in other items, net of effects from acquisitions:
Accounts receivable and other current assets		181.5			122.7
Accounts payable and other accrued liabilities		(90.6	)		53.3
Deferred income		(8.4	)		(5.8	)
Net cash flows from continuing operations		1,643.6			1,198.2
Net cash flows from discontinued operations		-			0.4
Net cash flows from operating activities		1,643.6			1,198.6
Cash flows from investing activities:
PacifiCorp acquisition, net of cash acquired		(4,932.4	)		-
Other acquisitions, net of cash acquired		(73.6	)		(9.5	)
Capital expenditures relating to operating projects		(1,139.6	)		(533.9	)
Construction and other development costs		(594.8	)		(272.7	)
Purchases of available-for-sale securities		(1,088.3	)		(2,421.8	)
Proceeds from sale of available-for-sale securities		1,185.1			2,514.7
Purchase of other investments		-			(556.6	)
Proceeds from sale of assets		17.4			56.0
Other		(30.5	)		12.4
Net cash flows from continuing operations		(6,656.7	)		(1,211.4	)
Net cash flows from discontinued operations		-			6.2
Net cash flows from investing activities		(6,656.7	)		(1,205.2	)
Cash flows from financing activities:
Proceeds from the issuances of common stock		5,122.6			-
Purchases of common stock		(1,750.0	)		-
Proceeds from parent company senior debt		1,699.3			-
Proceeds from subsidiary and project debt		365.4			750.6
Repayments of parent company senior and subordinated debt		(167.0	)		(381.5	)
Repayments of subsidiary and project debt		(257.3	)		(632.2	)
Net proceeds from parent company revolving credit facility		93.0			55.0
Net repayment of subsidiary short-term debt		(51.1	)		(0.5	)
Net proceeds from settlement of treasury rate lock agreements		53.0			-
Other		(23.0	)		(8.1	)
Net cash flows from financing activities		5,084.9			(216.7	)
Effect of exchange rate changes		3.2			(19.2	)
Net change in cash and cash equivalents		75.0			(242.5	)
Cash and cash equivalents at beginning of period		357.9			837.3
Cash and cash equivalents at end of period	$	432.9		$	594.8

The accompanying notes are an integral part of these financial statements

8

MIDAMERICAN ENERGY HOLDINGS COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1. General

The accompanying unaudited consolidated financial statements have been prepared in accordance with generally accepted accounting principles for interim financial information and the instructions for Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the information and footnotes required by generally accepted accounting principles for annual financial statements. In the opinion of the management of MidAmerican Energy Holdings Company (“MEHC”) and its subsidiaries (collectively, the “Company”), the unaudited consolidated financial statements contain all adjustments, including normal recurring items, considered necessary for a fair presentation of the financial position as of September 30, 2006 and the results of operations for the three-month and nine-month periods ended September 30, 2006 and 2005, and the changes in stockholders’ equity and cash flows for the nine-month periods ended September 30, 2006 and 2005. The results of operations for the three-month and nine-month periods ended September 30, 2006 are not necessarily indicative of the results to be expected for the full year.

Preparation of the consolidated financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenue and expenses during the period. Management believes the most complex and sensitive judgments, because of their significance to the consolidated financial statements, result primarily from the need to make estimates about the effects of matters that are inherently uncertain. Actual results could differ materially from management’s estimates. Management’s Discussion and Analysis and Note 2 to the consolidated financial statements included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2005, describe the most significant accounting estimates and policies used in preparation of the consolidated financial statements. There have been no significant changes in the Company’s assumptions regarding critical accounting estimates during the first nine months of 2006, except as they relate to the PacifiCorp acquisition and PacifiCorp’s derivative instruments (see Note 3).

The unaudited consolidated financial statements include the accounts of MEHC and its wholly-owned subsidiaries, except for certain trusts formed to hold trust preferred securities. Subsidiaries which are less than 100% owned but greater than 50% owned are consolidated with a minority interest. Subsidiaries that are 50% owned or less, but where the Company has the ability to exercise significant influence, are accounted for under the equity method of accounting. All inter-enterprise transactions and accounts have been eliminated. The results of operations of the Company include the Company’s proportionate share of results of operations of entities acquired from the date of each acquisition for purchase business combinations.

Berkshire Hathaway Inc. (“Berkshire Hathaway”) currently owns 88.2% (86.6% on a diluted basis) of the outstanding common stock of MEHC. The Company's operations are organized and managed as eight distinct platforms: PacifiCorp, MidAmerican Funding, LLC (“MidAmerican Funding”) (which primarily includes MidAmerican Energy Company (“MidAmerican Energy”)), Northern Natural Gas Company (“Northern Natural Gas”), Kern River Gas Transmission Company (“Kern River”), CE Electric UK Funding Company (“CE Electric UK”) (which primarily includes Northern Electric Distribution Limited (“Northern Electric”) and Yorkshire Electricity Distribution plc (“Yorkshire Electricity”)), CalEnergy Generation-Foreign, CalEnergy Generation-Domestic and HomeServices of America, Inc. (“HomeServices”). Through these platforms, the Company owns and operates an electric utility company in the Western United States, a combined electric and natural gas utility company in the Midwestern United States, two natural gas pipeline companies in the United States, two electricity distribution companies in Great Britain, a diversified portfolio of domestic and international independent power projects and the second largest residential real estate brokerage firm in the United States.

Certain amounts in the prior period consolidated financial statements and supporting note disclosures have been reclassified to conform to the current period presentation. Such reclassifications did not impact previously reported net income or retained earnings. As of December 31, 2005, the Company reclassified $1.6 billion of accumulated depreciation related to the acquisitions of Northern Natural Gas and Kern River from gross property to accumulated depreciation to conform to its current period presentation.

9

2. New Accounting Pronouncements

In September 2006, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards (“SFAS”) No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans - an amendment of FASB Statements No. 87, 88, 106, and 132(R)” (“SFAS 158”). SFAS 158 requires an employer to recognize in its statement of financial position the over- or under-funded status of a defined benefit postretirement plan measured as the difference between the fair value of plan assets and the benefit obligation. For a pension plan, the benefit obligation is the projected benefit obligation; for any other postretirement benefit plan, such as a retiree health care plan, the benefit obligation is the accumulated postretirement benefit obligation. SFAS 158 also requires entities to recognize as a component of other comprehensive income, net of tax, the actuarial gains and losses and the prior service costs and credits that arise during the period, but were not recognized as components of net periodic benefit cost of the period pursuant to SFAS No. 87, “Employers' Accounting for Pensions” (“SFAS 87”) and SFAS No. 106, “Employers’ Accounting for Postretirement Benefits Other Than Pensions” (“SFAS 106”). The Company intends to recognize as regulatory assets (liabilities) the majority of the amounts attributable to its domestic regulated operations that would otherwise be charged to other comprehensive income, net of tax, pursuant to SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation” (“SFAS 71”). SFAS 158 does not impact the calculation of net periodic benefit cost and the amounts recognized in either accumulated other comprehensive income or regulatory assets (liabilities) will be adjusted as they are subsequently recognized as components of net periodic benefit cost pursuant to the recognition and amortization provisions of SFAS 87 and SFAS 106.

The recognition and related disclosure provisions of SFAS 158 are effective for the Company’s fiscal year ending December 31, 2006, while the requirement to measure plan assets and benefit obligations as of the date of the employer’s fiscal year-end statement of financial position is not effective until fiscal years ending after December 15, 2008. The Company is currently evaluating the impact of adopting SFAS 158 on its consolidated financial position and results of operations.

In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements” (“SFAS 157”). SFAS 157 defines fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements. SFAS 157 does not impose fair value measurements on items not already accounted for at fair value; rather it applies, with certain exceptions, to other accounting pronouncements that either require or permit fair value measurements. SFAS 157 is effective for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. The Company is currently evaluating the impact of adopting SFAS 157 on its consolidated financial position and results of operations.

In July 2006, the FASB issued FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes - an interpretation of FASB Statement No. 109”(“FIN 48”). FIN 48 clarifies the accounting for uncertainty in income taxes recognized in accordance with SFAS No. 109, “Accounting for Income Taxes” (“SFAS 109”), and prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a return. Guidance is also provided on de-recognition, classification, interest and penalties, accounting in interim periods, disclosure and transition. FIN 48 is effective for fiscal years beginning after December 15, 2006. The Company is currently evaluating the impact of adopting FIN 48 on its consolidated financial position and results of operations.

In December 2004, the FASB issued SFAS No. 123R, “Share-Based Payment” (“SFAS 123R”), which replaces SFAS No. 123, “Accounting for Stock-Based Compensation,” and supersedes Accounting Principles Board Opinion No. 25, “Accounting for Stock Issued to Employees.” SFAS 123R establishes standards for the accounting for transactions in which an entity exchanges its equity instruments for goods or services, primarily focusing on the accounting for transactions in which an entity obtains employee services in share-based payment transactions. SFAS 123R requires entities to measure compensation costs for all share-based payments, including stock options, at fair value and expense such payments over the service period. As of January 1, 2006, the Company adopted SFAS 123R. Adoption of SFAS 123R did not affect the Company’s financial position, results of operations or cash flows as all of the Company’s outstanding stock options were fully vested on January 1, 2006. Modifications to outstanding stock options after January 1, 2006 may result in additional compensation expense pursuant to the provisions of SFAS 123R.

10

3. PacifiCorp Acquisition

On March 21, 2006, a wholly owned subsidiary of MEHC acquired 100% of the common stock of PacifiCorp from a wholly owned subsidiary of Scottish Power plc for a cash purchase price of $5,109.5 million, which was funded through the issuance of common stock (see Note 4). MEHC also incurred $10.6 million of direct transaction costs associated with the acquisition, which consisted principally of investment banker commissions and outside legal and accounting fees and expenses, resulting in a total purchase price of $5,120.1 million. As a result of the acquisition, MEHC controls the significant majority of PacifiCorp’s voting securities, which include both common and preferred stock. The results of PacifiCorp’s operations are included in the Company’s results beginning March 21, 2006.

PacifiCorp is a regulated electric utility serving approximately 1.7 million residential, commercial and industrial customers in service territories aggregating approximately 136,000 square miles in portions of the states of Utah, Oregon, Wyoming, Washington, Idaho and California. The regulatory commissions in each state approve rates for retail electric sales within their respective states. PacifiCorp also sells electricity on the wholesale market to public and private utilities, energy marketing companies and to incorporated municipalities. Wholesale activities are regulated by the Federal Energy Regulatory Commission (“FERC”). As of September 30, 2006, PacifiCorp owns, or has interests in, 69 thermal, hydroelectric and wind generating plants with an aggregate facility net owned capacity of 8,550.4 megawatts (“MW”).

Allocation of Purchase Price

SFAS No. 141, “Business Combinations,” requires that the total purchase price be allocated to PacifiCorp’s net tangible and identified intangible assets acquired and liabilities assumed based on their estimated fair values as of the acquisition date. PacifiCorp’s operations are regulated, which provide revenue derived from cost, and are accounted for pursuant to SFAS 71. PacifiCorp has demonstrated a past history of recovering its costs incurred through its rate making process. Given the size and timing of the acquisition, the fair values set forth below are preliminary and are subject to adjustment as additional information is obtained. Certain adjustments related to derivative contracts, severance costs and income taxes have been made through September 30, 2006, which were not significant to the overall purchase price allocation. When finalized, additional adjustments to goodwill may result. The following table summarizes the preliminary estimated fair values of the 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		1,109.8
Regulatory assets		1,354.7
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		(1,263.5	)
Regulatory liabilities		(818.2	)
Pension and postretirement obligations		(827.8	)
Subsidiary and project debt, less current portion		(3,762.3	)
Deferred income taxes		(1,651.3	)
Other non-current liabilities		(847.0	)
Net assets acquired	$	5,120.1

The Company 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. Pursuant to Emerging Issues Task Force (“EITF”) Issue No. 93-7, “Uncertainties Related to Income Taxes in a Purchase Business Combination,” the Company will adjust goodwill prospectively for the settlement of any income tax related pre-acquisition contingencies. Prior to the end of the purchase price allocation period, if information becomes available that a non-income tax related pre-acquisition related loss had been incurred and the amounts can be reasonably estimated, such items will be included in the purchase price allocation.

11

Certain transition activities are occurring as PacifiCorp has been integrated into the Company. Costs, consisting primarily of employee termination activities, have been incurred associated with such transition activities. The Company finalized these plans and expects to finish executing them over the next several months. In accordance with EITF Issue No. 95-3, “Recognition of Liabilities in Connection with a Purchase Business Combination” (“EITF 95-3”), the finalization of certain integration plans results in adjustments to the purchase price allocation for the acquired assets and assumed liabilities of PacifiCorp. Severance costs accrued pursuant to EITF 95-3 during the period from acquisition to September 30, 2006 totaled $32.7 million. Accrued severance costs were $28.8 million at September 30, 2006. Transition costs that do not meet the criteria in EITF 95-3 are expensed in the period incurred.

Properties, Plants and Equipment, Net

The fair values of properties, plants and equipment, net as of the acquisition date are as follows (in millions):

	Ranges of
	Estimated		Preliminary
	Useful Life		Fair Value
Utility generation and distribution system, net		5-85 years	$	9,314.0
Other assets, net		5-30 years		8.9
Construction in progress(1)				728.0
Total properties, plants and equipment, net			$	10,050.9

⁽¹⁾ Includes $173.5 million related to the Currant Creek Power Plant, a 523 MW combined cycle plant in Utah that went into service on March 22, 2006.

Goodwill

The excess of the purchase price paid over the estimated fair values of the identifiable assets acquired and liabilities assumed totaled $1,109.8 million and was allocated as goodwill to the PacifiCorp reportable segment. In accordance with SFAS No. 142, “Goodwill and Other Intangible Assets,” goodwill is not amortized, but rather is reviewed annually for impairment or more frequently if indicators of impairment exist. In accordance with SFAS 109, a deferred tax liability was not recorded on the goodwill since it is not tax deductible.

The recognition of goodwill from the acquisition of PacifiCorp resulted from various attributes of PacifiCorp’s operations and business in general. There is no assurance that these attributes will continue to exist to the same degree as believed at the time of the acquisition. These attributes include, but are not limited to:

·    Ability to improve operational results through the prudent deployment of capital;

·    Operations in six states providing regulatory and geographic diversity;

·    Ability to improve regulatory relationships and develop customer solutions;

·    Low-cost competitive position;

·    Generation and fuel diversification, including:

·    The operation of coal generation;

·    The operation of several coal mines contributing to low-cost supply and supply certainty;

·    Access to multiple gas suppliers; and

·    Low-cost hydroelectric generation;

·    Strong customer service reputation; and

·    Significant customer and load growth opportunities.

12

Regulatory Assets and Liabilities

The fair values of regulatory assets as of the acquisition date are as follows (in millions):

	Preliminary
	Fair Value
Pension and postretirement benefits	$	684.5
Deferred income taxes		480.3
Derivative contracts(1)		51.2
Other		138.7
Total regulatory assets	$	1,354.7

⁽¹⁾ Represents net unrealized losses related to derivative contracts that are probable of recovery in retail rates as of the acquisition date. In February 2006 in Oregon and in March 2006 in Utah, PacifiCorp filed rate cases to ensure, among other items, that PacifiCorp would achieve recovery of its future net power costs. Actual rate case settlements were achieved in both states during the third quarter of 2006. Based on management’s consideration of the rate settlements, as well as the new power costs recovery adjustment mechanisms obtained in Wyoming and California earlier in 2006, it was determined that certain contracts were probable of being recovered in retail rates as of the acquisition date. Accordingly, the Company recorded a $43.5 million reduction to its regulatory assets and a corresponding increase to goodwill related to its estimate of the unrealized gains on contracts receiving recovery.

As of the acquisition date, PacifiCorp had $1,328.6 million of regulatory assets not accruing carrying charges. 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.

The fair values of regulatory liabilities as of the acquisition date are as follows (in millions):

	Preliminary
	Fair Value
Asset retirement removal costs	$	713.3
Deferred income taxes		43.7
Other		61.2
Total regulatory liabilities	$	818.2

Derivative Instruments

In accordance with SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” (“SFAS 133”), as amended, PacifiCorp records derivative instruments as assets or liabilities measured at estimated fair value, unless they qualify for the exemptions afforded by SFAS 133. 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. Changes in the fair value of derivatives are recognized in earnings during the period of change, except for contracts designated as a cash flow hedge or that are probable of recovery or refund in retail rates. Changes in the fair value of contracts probable of recovery or refund in retail rates are deferred as regulatory assets or liabilities pursuant to SFAS 71.

Unrealized gains and losses on derivative contracts not held for trading purposes or offset as a regulatory asset or liability, are presented on a gross basis in the consolidated statements of operations as operating revenue for sales contracts and as cost of sales and operating expense for purchase contracts and financial swaps. Unrealized and realized gains and losses from all derivative contracts held for trading purposes, including those where physical delivery is required, are presented on a net basis in the consolidated statements of operations as operating revenue.

13

In order to reduce the impact of fluctuations in forward prices of electricity and natural gas on PacifiCorp’s results of operations, PacifiCorp initiated cash flow hedging in April 2006 for a portion of its derivative contracts, primarily comprised of electricity sales and natural gas purchase contracts. Changes in fair value of derivative contracts designated as cash flow hedges are recorded as other comprehensive income to the extent the hedges are effective in offsetting changes in future cash flows for forecasted electricity and natural gas purchase and sales transactions. Amounts included in accumulated other comprehensive income are reclassified to operating revenue or cost of sales when the forecasted sale or purchase transaction is recognized in earnings, or when it is probable that the forecasted transaction will not occur.

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 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.

The fair values of derivative instruments, primarily used for non-trading purposes, as of the acquisition date are as follows (in millions):

	Preliminary
	Fair Value
Maturity:
Less than 1 year	$	123.8
1-3 years		132.6
4-5 years		10.9
Excess of 5 years		(259.4	)
Total	$	7.9
Reflected as:
Current asset	$	221.7
Non-current asset		345.3
Current liability		(97.9	)
Non-current liability		(461.2	)
Total	$	7.9

14

Short-Term and Long-Term Debt

The fair values of short-term and long-term debt as of the acquisition date are as follows (in millions):

	Average
	Interest			Preliminary
	Rate			Fair Value
Short-term debt - notes payable and commercial paper		4.8	%	$	184.4
Long-term debt:
First mortgage bonds -
4.3% to 8.8%, due through 2011		6.0		$	901.7
5.0% to 9.2%, due 2012 to 2016		6.5			1,040.4
8.5% to 8.6%, due 2017 to 2021		8.5			5.0
6.7% to 8.5%, due 2022 to 2026		7.4			424.0
5.3% to 7.7%, due 2032 to 2036		6.3			800.0
Guaranty of pollution-control revenue bonds -
Variable rates, due 2014		3.1			40.7
Variable rates, due 2014 to 2026		3.2			325.2
Variable rates, due 2025		3.2			175.8
3.4% to 5.7%, due 2014 to 2026		4.5			184.0
6.2%, due 2031		6.2			12.7
Preferred stock subject to mandatory redemption		-			45.0
Other		11.7	%		28.4
					3,982.9
Less current portion					(220.6	)
Total long-term debt				$	3,762.3

The annual repayments of the long-term debt are as follows: period from acquisition to December 31, 2006 - $214.7 million; 2007 - $164.0 million; 2008 - $413.3 million; 2009 - $139.6 million; 2010 - $15.9 million; and thereafter - $3,042.8 million. Unamortized debt discounts and funds held by trustees totaled $7.4 million at March 21, 2006.

Additionally, PacifiCorp has in place an $800.0 million committed bank revolving credit agreement expiring on July 6, 2011. The credit agreement carries an interest rate that is generally based on LIBOR plus a margin that varies based on PacifiCorp’s credit ratings and requires that PacifiCorp’s ratio of consolidated debt to total capitalization not exceed 0.65 to 1. PacifiCorp is in compliance with all covenants related to its revolving credit agreement.

Pension and Postretirement Obligations

PacifiCorp sponsors defined benefit pension plans that cover the majority of its employees. In addition, certain bargaining unit employees participate in a joint trust plan to which PacifiCorp contributes. Benefits under the main plan are based on final average pay formulas. Pension costs are funded annually by no more than the maximum amount that can be deducted for federal income tax purposes.

PacifiCorp also provides health care and life insurance benefits through various plans for eligible retirees. The cost of other postretirement benefits is accrued over the active service period of employees. PacifiCorp funds other postretirement benefits through a combination of funding vehicles.

The measurement date for plan assets and obligations for the pension and postretirement benefit plans is December 31 of each year. The weighted-average discount rate and rate of increase in compensation levels assumed in the actuarial calculations used to determine benefit obligations for the pension and postretirement benefit plans were 5.75% and 4.00%, respectively, as of the most recent measurement date.

15

The projected benefit obligation, value of plan assets and funded status of the pension and postretirement benefit plans as of the acquisition date are as follows:

				Post-
	Pension			Retirement
Benefit obligation	$	(1,339.5	)	$	(581.9	)
Plan assets at fair value		824.9			292.1
Funded status	$	(514.6	)	$	(289.8	)

The pension plan 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 include contributions prior to the acquisition date. Included in the pension plan obligations are the PacifiCorp Retirement Plan (the “Retirement Plan”) and the Supplemental Executive Retirement Plan (the “SERP”), which 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 declines in the equity markets and historically low interest rate levels. Through the purchase price allocation, the resulting minimum pension liabilities were adjusted to the funded status of each plan and represent the pension and postretirement obligations as of the acquisition date. PacifiCorp continues to recover substantially all of its pension and postretirement costs in rates based on actuarial calculations utilizing pre-acquisition values.

Deferred Income Taxes

The net deferred tax liability as of the acquisition date consists of the following (in millions):

Deferred tax assets:
Regulatory liabilities	$	316.9
Employee benefits		180.1
Other		181.9
Total deferred tax assets		678.9
Deferred tax liabilities:
Property, plant and equipment		1,591.0
Regulatory assets		642.4
Other		113.7
Total deferred tax liabilities		2,347.1
Net deferred tax liability	$	1,668.2
Reflected as:
Current liability	$	16.9
Non-current liability		1,651.3
	$	1,668.2

16

Pro Forma Financial Information

The following pro forma condensed consolidated results of operations assume that the acquisition of PacifiCorp was completed as of January 1, 2006 and 2005, respectively (in millions):

	Nine-Month Periods
	Ended September 30,
	2006		2005
Operating revenue	$	8,604.4	$	7,276.9
Net income available to common and preferred stockholders	$	817.8	$	580.3

The pro forma financial information represents the historical operating results of the combined company with adjustments for purchase accounting and is not necessarily indicative of the results of operations that would have been achieved if the acquisition had taken place at the beginning of each period presented.

4. Stockholders’ Equity and Related Party Transactions

On February 9, 2006, following the effective date of the repeal of the Public Utility Holding Company Act of 1935, Berkshire Hathaway converted its 41,263,395 shares of MEHC’s no par zero-coupon convertible preferred stock into an equal number of shares of MEHC’s common stock. As a consequence, Berkshire Hathaway now consolidates the Company in its financial statements as a majority-owned subsidiary and will include the Company in its consolidated federal U.S. income tax return.

On March 1, 2006, MEHC and Berkshire Hathaway entered into an Equity Commitment Agreement (the “Berkshire Equity Commitment”) pursuant to which Berkshire Hathaway has agreed to purchase up to $3.5 billion of common equity of MEHC upon any requests authorized from time to time by the Board of Directors of MEHC. The proceeds of any such equity contribution shall only be used for the purpose of (a) paying when due MEHC’s debt obligations and (b) funding the general corporate purposes and capital requirements of the Company’s regulated subsidiaries. Berkshire Hathaway will have up to 180 days to fund any such request. The Berkshire Equity Commitment will expire on February 28, 2011, was not used for the PacifiCorp acquisition and will not be used for future acquisitions.

On March 2, 2006, MEHC amended its Articles of Incorporation to (i) increase the amount of its common stock authorized for issuance to 115.0 million shares and (ii) no longer provide for the authorization to issue any preferred stock of MEHC.

On March 6, 2006, Mr. David L. Sokol, Chairman and Chief Executive Officer of MEHC, exercised 450,000 common stock options having an exercise price of $29.01 per share. Additionally, Mr. Sokol put 344,274 shares of common stock to MEHC for a purchase price of $50.0 million.

On March 21, 2006, Berkshire Hathaway and certain other of MEHC’s existing stockholders and related companies invested $5,109.5 million, in the aggregate, in 35,237,931 shares of MEHC’s common stock in order to provide equity funding for the PacifiCorp acquisition (see Note 3). The per-share value assigned to the shares of common stock issued, which were effected pursuant to a private placement and were exempt from the registration requirements of the Securities Act of 1933, as amended, was based on an assumed fair market value as agreed to by MEHC’s stockholders.

On March 28, 2006, MEHC repurchased 11,724,138 shares of common stock from Berkshire Hathaway for an aggregate purchase price of $1,700.0 million.

At September 30, 2006 and December 31, 2005, Berkshire Hathaway and its affiliates held 11% mandatory redeemable preferred securities due from certain wholly owned subsidiary trusts of MEHC of $1,122.2 million and $1,289.2 million, respectively. Interest expense on these securities totaled $32.7 million and $39.0 million, respectively, for the three-month periods ended September 30, 2006 and 2005, and $103.3 million and $120.3 million, respectively, for the nine-month periods ended September 30, 2006 and 2005.

17

5. Properties, Plants and Equipment, Net

Properties, plants and equipment, net consist of the following (in millions):

	Ranges of		As of
	Estimated		September 30,			December 31,
	Useful Life		2006			2005
Utility generation and distribution system		5-85 years	$	26,967.4		$	10,499.1
Interstate pipeline assets		3-67 years		5,281.3			5,321.8
Independent power plants		10-30 years		1,183.8			1,384.6
Other assets		3-30 years		545.3			476.5
Total operating assets				33,977.8			17,682.0
Accumulated depreciation and amortization				(12,515.0	)		(6,614.2	)
Net operating assets				21,462.8			11,067.8
Construction in progress				1,861.4			847.6
Properties, plants and equipment, net			$	23,324.2		$	11,915.4

The utility generation and distribution system and interstate pipeline assets are the regulated assets of PacifiCorp, MidAmerican Funding, Northern Natural Gas, Kern River and CE Electric UK. At September 30, 2006 and December 31, 2005, accumulated depreciation and amortization related to the Company’s regulated assets totaled $11.7 billion and $5.7 billion, respectively. Additionally, substantially all of the construction in progress at September 30, 2006 and December 31, 2005 relates to the construction of regulated assets.

6. Recent Debt Transactions

On March 24, 2006, MEHC completed a $1,700.0 million offering of unsecured senior bonds due 2036 (the ‘‘Bonds’’). The Bonds were issued at an offering price of 99.957%, accrue interest at a rate of 6.125% per annum and mature on April 1, 2036. Accrued interest on the Bonds is payable on April 1 and October 1 of each year, commencing on October 1, 2006, until the principal amount of the Bonds is paid in full. The proceeds were used to fund MEHC’s exercise of its right to repurchase shares of its common stock previously issued to Berkshire Hathaway.

On June 15, 2006, MidAmerican Energy’s 6.375% series of notes, totaling $160.0 million, matured.

On July 6, 2006, MEHC entered into a $600.0 million credit facility pursuant to the terms and conditions of an amended and restated credit agreement. The amended and restated credit agreement remains unsecured, carries a variable interest rate based on LIBOR or a base rate, at MEHC’s option, plus a margin, and the termination date was extended to July 6, 2011. The facility continues to support letters of credit for the benefit of certain subsidiaries and affiliates. As of September 30, 2006, the outstanding balance and amount of letters of credit issued under the credit agreement totaled $144.0 million and $59.9 million, respectively. At September 30, 2006, the interest rate on the $144.0 million outstanding under the credit agreement was 5.57%.

On August 10, 2006, PacifiCorp issued $350.0 million of 6.1%, 30-year first mortgage bonds. The proceeds from this offering were used to repay a portion of PacifiCorp’s short-term debt and for general corporate purposes.

In September 2006, MEHC entered into a treasury rate lock in the notional amount of $1,550.0 million to hedge against a rise in interest rates related to the anticipated funding of its 2007 and 2008 maturities of parent company senior debt. The fair value of this hedge as of September 30, 2006 was immaterial.

On October 6, 2006, MidAmerican Energy completed the sale of $350.0 million in aggregate principal amount of its 5.8% medium-term notes due October 15, 2036. The proceeds from this offering are being used to support construction of MidAmerican Energy’s electric generation projects, to repay a portion of its short-term debt and for general corporate purposes.

18

7. Other Income and Other Expense

Other Income

Other income consists of the following (in millions):

	Three-Month Periods				Nine-Month Periods
	Ended September 30,				Ended September 30,
	2006		2005		2006		2005
Gain on Mirant bankruptcy claim	$	-	$	-	$	89.3	$	-
Gains from non-strategic assets and investments		1.2		-		46.0		19.9
Allowance for equity funds used during construction		16.5		8.2		39.0		18.9
Other		8.8		6.6		26.8		15.0
Total other income	$	26.5	$	14.8	$	201.1	$	53.8

Mirant Americas Energy Marketing (“Mirant”) Bankruptcy Claim

Mirant was one of the shippers that entered into a 15-year, 2003 Expansion Project, firm gas transportation contract (90,000 Dth per day) with Kern River (the “Mirant Agreement”) and provided a letter of credit equivalent to 12 months of reservation charges as security for its obligations thereunder. In July 2003, Mirant filed for Chapter 11 bankruptcy protection and Kern River subsequently drew on the letter of credit and held the proceeds thereof, $14.8 million, as cash collateral. Kern River claimed $210.2 million in damages due to the rejection of the Mirant Agreement. The bankruptcy court ultimately determined that Kern River was entitled to a general unsecured claim of $74.4 million in addition to the $14.8 million cash collateral. In January 2006, Mirant emerged from bankruptcy and on February 6, 2006, a stipulated judgment was entered that allowed Kern River to receive a pro rata amount of shares of new Mirant stock determined by Kern River’s allowed claim amount plus interest in relation to the unsecured creditor class of over $6 billion. In February 2006, Kern River received an initial distribution of such shares in payment of the majority of its allowed claim. Kern River sold all of the shares of new Mirant stock received from its allowed claim amount plus interest in the first quarter of 2006 and recognized a gain from those sales of $89.3 million.

Non-Strategic Assets and Investments

Included in gains from non-strategic assets and investments are gains at MidAmerican Funding from the disposition of common shares held in an electronic energy and metals trading exchange. In the second quarter of 2006, MidAmerican Funding sold a majority of these common shares and realized a pre-tax gain of $27.6 million. MidAmerican Funding donated its remaining shares to a charitable foundation and recognized a pre-tax gain and donation expense of $4.5 million as MidAmerican Funding’s equity investment in the common shares was carried at zero cost.

Other Expense

The Company’s other expense totaled $1.8 million and $15.8 million, respectively, for the three-month periods ended September 30, 2006 and 2005, and $10.4 million and $20.6 million, respectively, for the nine-month periods ended September 30, 2006 and 2005. During the third quarter of 2005, two major airline carriers filed for bankruptcy. A subsidiary of MidAmerican Funding evaluated its investments in commercial passenger aircraft leased to major domestic airlines and recognized losses totaling $14.0 million, or $8.8 million after tax, for other-than-temporary impairments of those investments in the third quarter of 2005.

19

8. Regulatory Matters

The following are updates to regulatory matters based upon changes that occurred during the nine-month period ended September 30, 2006:

PacifiCorp

Utah

In March 2006, PacifiCorp filed a general rate case with the Utah Public Service Commission (“UPSC”) related to increased investments in Utah due to growing demand for electricity. In April 2006, PacifiCorp filed a revised case reflecting the effects of PacifiCorp’s sale to MEHC, which reduced the original requested increase from $197.2 million to $194.1 million. In July 2006, a stipulation was reached with several parties and was filed with the UPSC. The stipulation calls for an annual increase of $115.0 million, or 9.95%, with $85.0 million of the increase effective December 11, 2006 and the remaining $30.0 million effective June 1, 2007. Under the terms of the stipulation, PacifiCorp has agreed not to file another rate case until after December 11, 2007. Also as part of the stipulation, PacifiCorp’s power cost adjustment mechanism (“PCAM”) application will be withdrawn. An order is expected before December 11, 2006.

Oregon

In February 2006, PacifiCorp filed a general rate case request with the Oregon Public Utility Commission (“OPUC”) for an increase of $112.0 million, or 13.2%. The request was related to investments in generation, transmission and distribution infrastructure and increases in fuel and general operating expenses, including power plant maintenance. In September 2006, the OPUC approved a settlement agreement with all parties, under which PacifiCorp will receive an annual increase for non-power cost items of $33.0 million effective January 1, 2007. Also on January 1, 2007, PacifiCorp will receive an increase for power costs using the existing transition adjustment mechanism, which will be capped at $10.0 million for January 1, 2007. After 2007, PacifiCorp’s power costs will be updated annually using the existing transition adjustment mechanism without a cap. PacifiCorp has agreed not to file a new rate case prior to September 1, 2007.

In September 2005, Oregon’s governor signed into law Senate Bill 408. This legislation is intended to address differences between taxes based on income that are collected by Oregon public utilities in retail rates and actual taxes paid by the utilities or affiliated groups in which utilities are included for income tax reporting purposes.

Oregon Senate Bill 408 requires that all regulated, investor-owned utilities that provided electric or natural gas service to an average of 50,000 or more Oregon customers in 2003 file an annual tax report with the OPUC. Among other information, the tax report must contain; (i) the amount of taxes paid by the utility, or paid by the affiliated group and “properly attributed” to the regulated operations of the utility, and (ii) the amount of taxes “authorized to be collected in rates.” If the OPUC determines that the amount of taxes “authorized to be collected” differs by more than $100,000 from the amount of taxes paid, in either direction, the OPUC shall require the public utility to implement a rate schedule with an automatic adjustment clause resulting in a surcredit or a surcharge on customer bills. The law is applicable for years beginning on or after January 1, 2006. The first tax report that can result in a rate adjustment will be filed on or before October 15, 2007 with the resulting surcredit or surcharge, if any, implemented in rates on or before June 1, 2008.

A permanent rulemaking docket was opened by the OPUC in September 2005 to establish rules for the implementation of Oregon Senate Bill 408. In September 2006, the OPUC adopted final administrative rules setting forth the method of calculating the portion of the total consolidated tax liability that is “properly attributed” to the regulated operations of the utility, as well as other items necessary for the implementation of Oregon Senate Bill 408.

The final administrative rules define the amount of federal, state, and local taxes paid by the utility, or paid by the affiliated group and “properly attributed” to the regulated operations of the utility, as the lowest of; (i) the total tax liability of the affiliated group of which the utility is a member, (ii) the standalone tax liability of the utility, or (iii) the tax liability calculated using the “apportionment method.” The “apportionment method” uses an evenly weighted three-factor formula premised on property, payroll and sales, with amounts for the regulated operations of the utility in the numerator and amounts for the affiliated group in the denominator, to generate an allocation factor that is applied against the tax liability of PacifiCorp’s respective affiliated group in order to “apportion” part of that tax liability to the regulated operations of the utility. For federal purposes, the affiliated group of which PacifiCorp is a member is Berkshire Hathaway and its subsidiaries. For state and local purposes, the affiliated group differs based upon jurisdictional filing requirements.

20

As a result of the law and the final administrative rules, the tax liability of the affiliated group of which PacifiCorp is a member and the affiliated group’s impact on the factor determined under the “apportionment method” may impact the amount of taxes paid and “properly attributed” to PacifiCorp. PacifiCorp cannot reasonably predict the financial results and the related impact of its federal affiliated group, Berkshire Hathaway and its subsidiaries, and therefore, cannot determine the impact this law may have on its consolidated financial position and results of operations.

Additionally, the calculation of  “taxes authorized to be collected in rates,” as defined by the OPUC, is based upon assumptions in the  latest rate case(s) used to set rates for the respective financial reporting period. As such, “taxes authorized to be collected in rates” does not reflect actual tax collections. The resulting difference between actual tax collections and the amount deemed collected pursuant to Oregon Senate Bill 408 may be a benefit or detriment to PacifiCorp and cannot be reasonably predicted.

The OPUC recognizes that a potential conflict between its rules and federal Internal Revenue Code regulations could deny PacifiCorp the tax benefits of accelerated depreciation. As such, the OPUC has required that no later than December 31, 2006, the affected utilities each file a request for a private letter ruling from the Internal Revenue Service on this issue, which may result in reconsideration of further changes to the rule or underlying law.

Oregon Senate Bill 408 cannot be used to decrease utility rates below a fair and reasonable level and the final administrative rules expressly provide that a utility may challenge any adjustment if it would result in rates that are not fair, just and reasonable resulting in confiscatory rates.

PacifiCorp continues to evaluate its legal and legislative options.

Wyoming

In March 2006, the Wyoming Public Service Commission (“WPSC”) approved an agreement that settled the general rate case filed by PacifiCorp in October 2005 and a separate request filed by PacifiCorp in December 2005 to recover increased costs of net wholesale purchased power used to serve Wyoming customers. The agreement provides for an annual rate increase of $15.0 million effective March 1, 2006, an additional annual rate increase of $10.0 million effective July 1, 2006, a PCAM and an agreement by the parties to support a forecast test year in the next general rate case application. In June 2006, the WPSC approved tariffs and rate schedules to implement the rate increase of $10.0 million annually, unbundling of net power costs from base rates, and establishing a PCAM effective July 2006.

Washington

In May 2005, PacifiCorp filed a general rate case request with the Washington Utilities and Transportation Commission (“WUTC”) for an increase of $39.2 million annually, which was later reduced to $30.0 million. In April 2006, the WUTC issued an order denying PacifiCorp’s request to increase retail rates. The WUTC determined that application of PacifiCorp’s cost allocation methodology failed to satisfy the statutory requirements that resources must benefit Washington ratepayers. In April 2006, PacifiCorp filed a petition for reconsideration of the order and requested an increase of not less than $11.0 million. PacifiCorp also filed a limited rate request seeking a rate increase of $7.0 million, which represents a 2.99% increase in rates. In June 2006, the WUTC suspended PacifiCorp’s limited rate request and consolidated the request with the general rate case. In July 2006, the WUTC issued an order denying PacifiCorp’s request for reconsideration and rejecting the 2.99% limited rate request filing.

In October 2006, PacifiCorp filed a general rate case with the WUTC for an annual increase of $23.2 million, or 10.2%. The WUTC set an eight-month schedule with an expected order date of June 15, 2007. As part of the filing, PacifiCorp proposed a Washington-only cost allocation methodology which is based on PacifiCorp’s western resources. The rate case included a five-year pilot on the proposed allocation methodology and a PCAM.

21

MidAmerican Funding

On April 18, 2006, the Iowa Utilities Board (“IUB”) approved a settlement agreement filed in conjunction with MidAmerican Energy’s application for up to 545 MW, based on nameplate ratings, of additional wind-powered generation capacity in Iowa. The settlement agreement extends the current revenue sharing mechanism through 2012 and extends MidAmerican Energy’s and the Iowa Office of Consumer Advocate’s commitments regarding increases or decreases in electric base rates through December 31, 2012.

Kern River

Kern River’s 2004 general rate case hearing concluded in August 2005. On March 2, 2006, Kern River received an initial decision on the case from the administrative law judge. On October 19, 2006, the FERC issued an order that modified certain aspects of the administrative law judge’s initial decision, including changing the allowed return on equity from 9.34% to 11.2% and granting Kern River an income tax allowance. The order also affirmed the rejection of certain issues included in Kern River’s filed position, including the rates for the vintage system being designed on a 95% load factor basis as the FERC determined a 100% load factor basis should be used. The FERC also rejected a 3% inflation factor for certain operating expenses and a shorter useful life for certain plant. Kern River’s compliance filing and the parties’ requests for rehearing are due November 20, 2006. Kern River is required to make refunds within 30 days after a final order is issued that is no longer subject to rehearing. An order on rehearing is not expected to be issued until the first or second quarter of 2007. Kern River was permitted to bill the requested rate increase prior to final approval by the FERC, subject to refund, beginning effective November 1, 2004. Since that time, Kern River has recorded a provision for estimated refunds pursuant to SFAS No. 5, “Accounting for Contingencies.” As a result of the October 19, 2006 FERC order, the liability for rates subject to refund increased $35.6 million to $88.3 million at September 30, 2006, and depreciation expense was reduced by $28.2 million.

9. Commitments and Contingencies

Environmental Matters

PacifiCorp and MidAmerican Energy are subject to numerous environmental laws, including the federal Clean Air Act and various state air quality laws; the Endangered Species Act; 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 have the potential for impacting the Company’s operations. Specifically, the Clean Air Act will likely continue to impact the operation of PacifiCorp’s and MidAmerican Energy’s generating facilities and will likely require PacifiCorp and MidAmerican Energy to reduce emissions from those facilities through the installation of additional or improved emission controls, the purchase of additional emission allowances, or some combination thereof.

Air Quality

PacifiCorp and MidAmerican Energy are subject to applicable provisions of the Clean Air Act and related air quality standards promulgated by the United States Environmental Protection Agency (“EPA”). The Clean Air Act provides the framework for regulation of certain air emissions and permitting and monitoring associated with those emissions. PacifiCorp and MidAmerican Energy believe they are in material compliance with current air quality requirements.

The EPA has in recent years implemented more stringent national ambient air quality standards for ozone and new standards for fine particulate matter. These standards set the minimum level of air quality that must be met throughout the United States. Areas that achieve the standards, as determined by ambient air quality monitoring, are characterized as being in attainment of the standard. Areas that fail to meet the standard are designated as being nonattainment areas. Generally, once an area has been designated as a nonattainment area, sources of emissions that contribute to the failure to achieve the ambient air quality standards are required to make emissions reductions. The EPA has concluded that the counties in Washington, Idaho, Montana, Wyoming, Colorado, Utah and Arizona, where PacifiCorp’s major emission sources are located, and the entire state of Iowa, where MidAmerican Energy’s major emission sources are located, are in attainment of the ozone and the current fine particulate matter standards.

In December 2005, the EPA proposed a revision of the ambient air quality standards for fine particles that would maintain the current annual standard and set a new, more stringent 24-hour standard for concentration of fine particulate in the ambient air. The standards were published in the Federal Register on October 17, 2006 and become final on December 18, 2006.

22

In March 2005, the EPA released the final Clean Air Mercury Rule (“CAMR”). The CAMR utilizes a market-based cap and trade mechanism to reduce mercury emissions from coal-burning power plants from the 1999 nationwide level of 48 tons to 15 tons at full implementation. The CAMR’s two-phase reduction program requires initial reductions of mercury emission in 2010 and an overall reduction in mercury emissions from coal-burning power plants of 70% by 2018. Individual states are required to implement the CAMR or alternative requirements to achieve equivalent or greater mercury emission reductions through their state implementation plans.

In March 2005, the EPA released the final Clean Air Interstate Rule (“CAIR”), calling for reductions of sulfur dioxide (“SO₂”) and nitrogen oxides (“NO_x”) emissions in the eastern United States through, at each state’s option, a market-based cap and trade system, emission reductions, or both. The state of Iowa has implemented rules that exercise the option of the market-based cap and trade system. While the state of Iowa has been determined to be in attainment of the ozone and fine particulate standards, Iowa has been found to significantly contribute to nonattainment of the fine particulate standard in Cook County, Illinois; Lake County, Indiana; Madison County, Illinois; St. Clair County, Illinois; and Marion County, Indiana. The EPA has also concluded that emissions from Iowa significantly contribute to ozone nonattainment in Kenosha and Sheboygan counties in Wisconsin and Macomb County, Michigan. Under the final CAIR, the first phase reductions of SO₂ emissions are effective on January 1, 2010, with the second phase reductions effective January 1, 2015. For NO_x, the first phase emissions reductions are effective January 1, 2009, and the second phase reductions are effective January 1, 2015. The CAIR calls for overall reductions of SO₂ and NO_x in Iowa of 68% and 67%, respectively, from 2003 levels by 2015.

The CAMR or the CAIR could, in whole or in part, be superseded or made more stringent by one of a number of multi-pollutant emission reduction proposals currently under consideration at the federal level, including pending legislative proposals that contemplate 70% to 90% reductions of SO₂, NO_x and mercury, as well as possible new federal regulation of carbon dioxide and other gases that may affect global climate change. In addition to any federal legislation that could be enacted by Congress to supersede the CAMR and the CAIR, the rules could be changed or overturned as a result of litigation. The sufficiency of the standards established by both the CAMR and the CAIR has been legally challenged in the United States District Court for the District of Columbia.

The EPA has initiated a regional haze program intended to improve visibility at specific federally protected areas. Some of PacifiCorp’s and MidAmerican Energy’s plants meet the threshold applicability criteria under the Clean Air Visibility Rules. PacifiCorp and other stakeholders are participating in the Western Regional Air Partnership to help develop the technical and policy tools needed to comply with this program, while MidAmerican Energy and other stakeholders are participating in the Central States Regional Air Partnership to help develop the technical and policy tools needed to comply with this program.

As of September 30, 2006, PacifiCorp’s environmental contingencies principally consist of air quality matters. Pending or proposed air regulations would, if enacted, require PacifiCorp to reduce its electricity plant emissions of SO₂, NO_x and other pollutants at its generating facilities below current levels. The acquisition of PacifiCorp by MEHC includes a regulatory commitment to spend approximately $812 million to reduce emissions at PacifiCorp’s generating facilities to address existing and future air quality requirements. These costs and any additional expenditures necessitated by air quality regulations are expected to be recoverable through the ratemaking process.

MidAmerican Energy has implemented a planning process that forecasts the site-specific controls and actions that may be required to meet emissions reductions as promulgated by the EPA. In accordance with an Iowa law passed in 2001, MidAmerican Energy has on file with the IUB its current multi-year plan and budget for managing SO₂, NO_x and mercury from its generating facilities in a cost-effective manner. The plan, which is required to be updated every two years, provides specific actions to be taken at each coal-fired generating facility and the related costs and timing for each action. Pursuant to an unrelated rate settlement agreement approved by the IUB on October 17, 2003, if prior to January 1, 2011, capital and operating expenditures to comply with air quality requirements cumulatively exceed $325 million, then MidAmerican Energy may seek to recover the additional expenditures from customers.

Under existing New Source Review (“NSR”) provisions of the Clean Air Act, any facility that emits regulated pollutants is required to obtain a permit from the EPA or a state regulatory agency prior to (1) beginning construction of a new major stationary source of an NSR-regulated pollutant or (2) making a physical or operational change to an existing stationary source of such pollutants that increases certain levels of emissions, unless the changes are exempt under the regulations (including routine maintenance, repair and replacement of equipment). In general, projects subject to NSR regulations are subject to pre-construction review and permitting under the Prevention of Significant Deterioration (“PSD”) provisions of the Clean Air Act. Under the PSD program, a project that emits threshold levels of regulated pollutants must undergo a Best Available Control Technology analysis and evaluate the most effective emissions controls. These controls must be installed in order to receive a permit. Violations of NSR regulations, which may be alleged by the EPA, states, and environmental groups, among others, potentially subject a utility to material expenses for fines and other sanctions and remedies including requiring installation of enhanced pollution controls and funding supplemental environmental projects.

23

The EPA has requested from several utilities information and supporting documentation regarding their capital projects for various generating plants. The requests were issued as part of an industry-wide investigation to assess compliance with the NSR and the New Source Performance Standards of the Clean Air Act. In 2001 and 2003, PacifiCorp received requests for information from the EPA relating to PacifiCorp’s capital projects at seven of its generating plants; PacifiCorp submitted information responsive to the requests, and there are currently no outstanding data requests pending from the EPA. In December 2002 and April 2003, MidAmerican Energy received requests from the EPA to provide documentation related to its capital projects from January 1, 1980, to April 2003 for a number of its generating plants. MidAmerican Energy has submitted information to the EPA in responses to these requests, and there are currently no outstanding data requests pending from the EPA. PacifiCorp and MidAmerican Energy cannot predict the outcome of these requests at this time.

In 2002 and 2003, the EPA proposed various changes to its NSR rules that clarify what constitutes routine repair, maintenance and replacement for purposes of triggering NSR requirements. These changes have been subject to legal challenge and, until such time as the legal challenges are resolved and the rules are effective, PacifiCorp and MidAmerican Energy will continue to manage projects at its generating plants in accordance with the rules in effect prior to 2002. In October 2005, the EPA proposed a rule that would change or clarify how emission increases are to be calculated for purposes of determining the applicability of the NSR permitting program for existing power plants. The EPA also proposed additional changes to the NSR rules in September 2006 that are intended to simplify the permitting process and allow facilities to undertake activities that improve the safety, reliability and efficiency of plants without triggering NSR. The EPA plans to finalize the rules by May 2007.

In February 2005, the Kyoto Protocol became effective, requiring 35 developed countries to reduce greenhouse gas emissions by approximately 5% between 2008 and 2012. While the United States did not ratify the protocol, the ratification and implementation of its requirements in other countries has resulted in increased attention to climate change in the United States. In 2005, the Senate adopted a “sense of the Senate” resolution that puts the Senate on record that Congress should enact a comprehensive and effective national program of mandatory, market-based limits and incentives on emissions of greenhouse gases that slow, stop, and reverse the growth of such emissions at a rate and in a manner that will not significantly harm the United States economy; and will encourage comparable action by other nations that are major trading partners and key contributors to global emissions. It is anticipated that the resolution may be further addressed by Congress in 2006. While debate continues at the national level over the direction of domestic climate policy, several states are developing state-specific or regional legislative initiatives to reduce greenhouse gas emissions. In December 2005, the states of Connecticut, Delaware, Maine, New Hampshire, New Jersey, New York and Vermont signed a mandatory regional pact to reduce greenhouse gas emissions that would become effective in 2009 and ultimately would require a reduction in greenhouse gas emissions of 10 percent from 1990 levels. An executive order signed by California’s governor in June 2005 would reduce greenhouse gas emissions in that state to 2000 levels by 2010, to 1990 levels by 2020 and 80 percent below 1990 levels by 2050. In August 2006, the California legislature adopted a greenhouse gas emission performance standard to all electricity generated within the state or delivered from outside the state that is no higher than the greenhouse gas emission levels of a state-of-the-art combined-cycle natural gas generation facility. California also adopted a statewide greenhouse gas emission cap to reduce greenhouse gas emissions by approximately 25% from 1990 levels by 2020. Both requirements have been signed by California’s governor and will move forward through the rulemaking and implementation process.

Litigation was filed in the federal district court for the southern district of New York seeking to require reductions of carbon dioxide emissions from generating facilities of five large electric utilities. The court dismissed the public nuisance suit, holding that such critical issues affecting the United States such as greenhouse gas emissions reductions are not the domain of the court and should be resolved by the Executive Branch and the U.S. Congress. This ruling has been appealed to the Second Circuit Court of Appeals. The outcome of climate change litigation and federal and state initiatives cannot be determined at this time; however, adoption of stringent limits on greenhouse gas emissions could significantly impact the Company’s fossil-fueled facilities and, therefore, its results of operations.

24

The EPA’s regulation of certain pollutants under the Clean Air Act, and its failure to regulate other pollutants, is being challenged by various lawsuits brought by both individual state attorney generals and environmental groups. To the extent that these actions may be successful in imposing additional and/or more stringent regulation of emissions on fossil-fueled facilities in general and PacifiCorp’s and MidAmerican Energy’s facilities in particular, such actions could significantly impact the Company’s fossil-fueled facilities and, therefore, its results of operations.

Hydroelectric Relicensing

PacifiCorp’s hydroelectric portfolio consists of 50 plants with an aggregate facility net owned capacity of 1,139.4 MW. The FERC regulates 93.9% of the installed capacity of this portfolio through 18 individual licenses. Several of PacifiCorp’s hydroelectric plants are in some stage of re-licensing with the FERC. Hydroelectric re-licensing 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 re-licensing costs, operations and maintenance expense, and capital expenditures. Electricity generation reductions may result from the additional environmental requirements. As of September 30, 2006 PacifiCorp had incurred $76.5 million in costs, for ongoing hydroelectric re-licensing, which are reflected in properties, plants and equipment, net in the accompanying 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.

In February 2004, PacifiCorp filed with the FERC a final application for a new license to operate the 161.4 MW Klamath hydroelectric project in anticipation of the March 2006 expiration of the existing license. PacifiCorp is currently operating under an annual license granted by the FERC and expects to continue to operate under annual licenses until the new operating license is issued. As part of the relicensing process, the U.S. Departments of Interior and Commerce filed proposed licensing terms and conditions with the FERC in March 2006, which proposed that PacifiCorp construct upstream and downstream fish passage facilities at the Klamath hydroelectric project’s four mainstem dams. In April 2006, PacifiCorp filed alternatives to the federal agencies’ proposal and requested an administrative hearing to challenge some of the federal agencies’ factual assumptions supporting their proposal for the construction of the fish passage facilities. A hearing was held in August 2006 before an administrative law judge. The administrative law judge issued a ruling in September 2006 generally supporting the federal agencies’ factual assumptions. The U.S. Departments of Interior and Commerce are scheduled to file a modified proposal for the licensing terms and conditions in January 2007 that takes into consideration the administrative judge’s ruling, the FERC’s draft environmental impact statement described below and other appropriate matters, including the value of the Klamath hydroelectric project and the electricity it produces. PacifiCorp is currently evaluating the impact of the ruling on the Klamath hydroelectric project relicensing process. Also, as part of the relicensing process, the FERC is required to perform an environmental review. In September 2006, the FERC issued its draft environmental impact statement on the Klamath hydroelectric project license. The draft environmental impact statement is open to public comment and the FERC is conducting public meetings and accepting written comments during November 2006. The FERC is expected to issue its final environmental impact statement by April 2007.

As of September 30, 2006, PacifiCorp has incurred costs of $40.3 million, which are reflected in properties, plants and equipment, net in the accompanying consolidated balance sheet, in the relicensing of the Klamath project. While the costs of implementing new license provisions cannot be determined until such time as a new license is issued, such costs could be significant.

Mine Reclamation

The federal Surface Mining Control and Reclamation Act of 1977 and similar state statutes establish operational, reclamation and closure standards that must be met during and upon completion of mining activities. These obligations mandate that mine property be restored consistent with specific standards and the approved reclamation plan. PacifiCorp’s mining operations are subject to these reclamation and closure requirements. Significant expenditures are being incurred for both ongoing and final reclamation. PacifiCorp’s estimated mine and plant reclamation costs for its coal mines were $140.2 million at September 30, 2006 and are the asset retirement obligation for these mines, which is reflected in other long-term accrued liabilities in the accompanying consolidated balance sheet. PacifiCorp has established trusts for the investment of funds for mine and plant reclamation. The fair value of the assets held in trusts was $104.3 million at September 30, 2006, and is reflected in other investments in the accompanying consolidated balance sheet.

25

Nuclear Decommissioning

Expected nuclear decommissioning costs for Quad Cities Station have been developed based on a site-specific decommissioning study that includes decontamination, dismantling, site restoration, dry fuel storage cost and an assumed shutdown date. Quad Cities Station nuclear decommissioning costs are included in base rates in MidAmerican Energy’s Iowa tariffs. The fair value of MidAmerican Energy’s share of estimated decommissioning costs for Quad Cities Station was $170.1 million and $163.0 million as of September 30, 2006 and December 31, 2005, respectively, and is the asset retirement obligation for Quad Cities Station, which is reflected in other long-term accrued liabilities in the accompanying consolidated balance sheets. MidAmerican Energy has established trusts for the investment of funds for decommissioning the Quad Cities Station. The fair value of the assets held in the trusts was $247.1 million and $228.1 million, respectively, as of September 30, 2006 and December 31, 2005, and is reflected in other investments in the accompanying consolidated balance sheets. MidAmerican Energy’s depreciation and amortization includes costs for Quad Cities Station decommissioning. The regulatory provision charged to expense is equal to the funding that is being collected in Iowa rates.

Accrued Environmental Costs

The Company’s policy is to accrue environmental clean-up 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. The liability recorded at September 30, 2006 and December 31, 2005 was $43.7 million and $7.5 million, respectively.

Legal Matters

In addition to the proceeding described below, the Company is currently party to various items of litigation or arbitration in the normal course of business, none of which are reasonably expected by the Company to have a material adverse effect on its financial position, results of operations or cash flows.

CalEnergy Generation-Foreign

Pursuant to the share ownership adjustment mechanism in the CE Casecnan stockholder agreement, which is based upon pro forma financial projections of the Casecnan project prepared following commencement of commercial operations, in February 2002, MEHC’s indirect wholly-owned subsidiary, CE Casecnan Ltd., advised the minority stockholder of CE Casecnan, LaPrairie Group Contractors (International) Ltd. (“LPG”), that MEHC’s indirect ownership interest in CE Casecnan had increased to 100% effective from commencement of commercial operations. On July 8, 2002, LPG filed a complaint in the Superior Court of the State of California, City and County of San Francisco against CE Casecnan Ltd. and MEHC. LPG’s complaint, as amended, seeks compensatory and punitive damages arising out of CE Casecnan Ltd.’s and MEHC’s alleged improper calculation of the proforma financial projections. On January 21, 2004, CE Casecnan Ltd., LPG and CE Casecnan entered into a status quo agreement pursuant to which the parties agreed to set aside certain distributions related to the shares subject to the LPG dispute and CE Casecnan agreed not to take any further actions with respect to such distributions without at least 15 days prior notice to LPG. Accordingly, 15% of the CE Casecnan dividend distributions declared in 2004, 2005 and 2006, totaling $27.5 million, has been set aside in a separate bank account in the name of CE Casecnan.

On August 4, 2005, the court issued a decision, ruling in favor of LPG on five of the eight disputed issues in the first phase of the litigation. On September 12, 2005, LPG filed a motion seeking the release of the funds which have been set aside pursuant to the status quo agreement referred to above. MEHC and CE Casecnan Ltd. filed an opposition to the motion on October 3, 2005, and at the hearing on October 26, 2005, the court denied LPG’s motion. On January 3, 2006, the court entered a judgment in favor of LPG against CE Casecnan Ltd. According to the judgment LPG would retain its ownership of 15% of the shares of CE Casecnan and distributions of the amounts deposited into escrow plus interest at 9% per annum. On February 28, 2006, CE Casecnan Ltd. filed an appeal of this judgment and the August 4, 2005 decision. The appeal is fully briefed and is expected to be resolved sometime in 2007. The parties are proceeding in the trial court on LPG’s remaining claim against MEHC for damages for alleged breach of fiduciary duty. This claim is expected to be resolved sometime in 2007. The impact, if any, of this litigation on the Company cannot be determined at this time.

26

In February 2003, San Lorenzo Ruiz Builders and Developers Group, Inc. (“San Lorenzo”), an original shareholder substantially all of whose shares in CE Casecnan were purchased by MEHC in 1998, threatened to initiate legal action against the Company in the Philippines in connection with certain aspects of its option to repurchase such shares. On July 1, 2005, MEHC and CE Casecnan Ltd. commenced an action against San Lorenzo in the District Court of Douglas County, Nebraska, seeking a declaratory judgment as to MEHC’s and CE Casecnan Ltd.'s rights vis-à-vis San Lorenzo in respect of such shares. San Lorenzo filed a motion to dismiss on September 19, 2005. Subsequently, San Lorenzo purported to exercise its option to repurchase such shares. On January 30, 2006, San Lorenzo filed a counterclaim against MEHC and CE Casecnan Ltd. seeking declaratory relief that it has effectively exercised its option to purchase 15% of the shares of CE Casecnan, that it is the rightful owner of such shares, and that it is due all dividends paid on such shares. On March 9, 2006, the court granted San Lorenzo’s motion to dismiss, but has since permitted MEHC and CE Casecnan Ltd. to file an amended complaint incorporating the purported exercise of the option. The complaint has been amended and the action is proceeding. The matter is currently in the early stages of discovery. The impact, if any, of San Lorenzo’s purported exercise of its option and the Nebraska litigation on the Company cannot be determined at this time. The Company intends to vigorously defend the counterclaims.

10. Comprehensive Income

The components of comprehensive income are as follows (in millions):

	Three-Month Periods						Nine-Month Periods
	Ended September 30,						Ended September 30,
	2006			2005			2006			2005
Net income	$	272.3		$	155.0		$	674.3		$	407.1
Other comprehensive income (loss):
Foreign currency translation		27.5			(26.2	)		163.8			(142.2	)
Cash flow hedges, net of tax of $18.9; $25.5; $40.5; and $(2.3), respectively		29.4			37.4			64.9			(6.1	)
Minimum pension liability, net of tax of $(1.2); $1.4; $(7.6); and $5.9, respectively		(2.9	)		3.2			(17.7	)		15.3
Marketable securities, net of tax of $2.0; $0.3; $1.3; and $0.3, respectively		3.0			0.4			1.9			0.4
Total comprehensive income	$	329.3		$	169.8		$	887.2		$	274.5

27

11. Retirement Plans

PacifiCorp

PacifiCorp sponsors noncontributory defined benefit pension plans that cover the majority of its employees. In addition, certain bargaining unit employees participate in a joint trust plan to which PacifiCorp contributes. PacifiCorp also maintains noncontributory, nonqualified defined benefit supplemental executive retirement plans for active and retired participants. PacifiCorp also provides health care and life insurance benefits through various plans for eligible retirees. Net periodic benefit cost for the three-month period ended September 30, 2006 and for the period from acquisition to September 30, 2006 for the pension, including supplemental retirement, and postretirement benefit plans included the following components for PacifiCorp (in millions):

	Three-Month Period						Period from Acquisition
	Ended September 30, 2006						to September 30, 2006
	Pension			Post-retirement			Pension			Post-retirement
Service cost	$	11.6		$	2.2		$	20.2		$	4.8
Interest cost		18.8			8.2			39.9			17.3
Expected return on plan assets		(18.1	)		(6.4	)		(38.6	)		(13.7	)
Amortization of net transition balance		0.6			3.0			1.6			6.4
Amortization of prior service cost		0.3			0.7			0.6			1.5
Amortization of prior year loss		6.5			1.4			13.9			2.9
Curtailment loss		(0.7	)		-			-			-
Net periodic benefit cost	$	19.0		$	9.1		$	37.6		$	19.2

PacifiCorp expects to contribute $80.6 million and $56.7 million, respectively, to its pension and postretirement plans during the period from acquisition to December 31, 2006. For the period from acquisition to September 30, 2006, $78.6 million and $29.3 million, respectively, of contributions have been made to the pension and postretirement plans.

MidAmerican Funding

MidAmerican Energy sponsors a noncontributory defined benefit pension plan covering substantially all employees of MEHC and its domestic energy subsidiaries, except for PacifiCorp and its subsidiaries. MidAmerican Energy also sponsors certain postretirement health care and life insurance benefits covering substantially all retired employees of MEHC and its domestic energy subsidiaries, except for PacifiCorp and its subsidiaries. Non-union employees hired after June 30, 2004 and union employees hired after June 30, 2006, under contracts covering substantially all of MidAmerican Energy’s union employees, are not eligible for postretirement benefits other than pensions. Net periodic benefit cost for the three-month and nine-month periods ended September 30 for the pension, including supplemental retirement, and postretirement benefit plans included the following components for MEHC and the aforementioned subsidiaries (in millions):

	Three-Month Periods						Nine-Month Periods
	Ended September 30,						Ended September 30,
	2006			2005			2006			2005
Pension:
Service cost	$	6.5		$	6.5		$	19.0		$	19.9
Interest cost		9.7			9.5			28.4			27.9
Expected return on plan assets		(9.8	)		(10.2	)		(28.6	)		(29.2	)
Amortization of prior service cost		0.7			0.7			1.9			2.0
Amortization of prior year loss		0.3			0.2			0.9			0.9
Net periodic benefit cost	$	7.4		$	6.7		$	21.6		$	21.5

28

	Three-Month Periods						Nine-Month Periods
	Ended September 30,						Ended September 30,
	2006			2005			2006			2005
Postretirement:
Service cost	$	2.0		$	1.8		$	5.4		$	5.2
Interest cost		3.9			3.1			10.6			10.3
Expected return on plan assets		(2.8	)		(2.7	)		(7.6	)		(7.3	)
Amortization of net transition balance		0.4			0.6			1.1			1.8
Amortization of prior service cost		-			-			(0.1	)		-
Amortization of prior year loss		0.8			0.3			2.1			1.0
Net periodic benefit cost	$	4.3		$	3.1		$	11.5		$	11.0

The Company expects to contribute $5.9 million and $15.6 million, respectively, in 2006 to its pension and postretirement plans. As of September 30, 2006, $4.4 million and $11.6 million, respectively, of contributions have been made to the pension and postretirement plans.

CE Electric UK

Certain wholly-owned subsidiaries of CE Electric UK participate in the Northern Electric group of the United Kingdom industry-wide Electricity Supply Pension Scheme (the “UK Plan”), which provides pension and other related defined benefits, based on final pensionable pay, to substantially all employees of CE Electric UK’s certain wholly-owned subsidiaries. Net periodic benefit cost for the pension plan included the following components for CE Electric UK (in millions):

	Three-Month Periods						Nine-Month Periods
	Ended September 30,						Ended September 30,
	2006			2005			2006			2005
Service cost	$	4.7		$	3.8		$	13.7		$	11.7
Interest cost		19.8			18.7			57.6			58.1
Expected return on plan assets		(25.8	)		(23.7	)		(75.1	)		(73.6	)
Amortization of prior service cost		0.5			0.5			1.4			1.5
Amortization of prior year loss		8.0			5.8			24.1			17.0
Net periodic benefit cost	$	7.2		$	5.1		$	21.7		$	14.7

Employer contributions to the UK Plan, including £23.1 million for the existing funding deficiency, are expected to be £35.0 million for 2006. As of September 30, 2006, £26.3 million, or $47.7 million, of contributions have been made to the UK Plan, including £17.3 million, or $31.5 million, in respect of the existing funding deficiency.

29

12. Segment Information

The Company has identified eight reportable segments: PacifiCorp, MidAmerican Funding, Northern Natural Gas, Kern River, CE Electric UK, CalEnergy Generation-Foreign, CalEnergy Generation-Domestic, and HomeServices. The Company’s determination of reportable segments considers the strategic units under which the Company is managed. The Company’s foreign reportable segments include CE Electric UK, whose business is principally in Great Britain, and CalEnergy Generation-Foreign, whose business is in the Philippines. The reportable segment financial information includes all necessary adjustments and eliminations needed to conform to the Company’s significant accounting policies including the allocation of goodwill. Information related to the Company’s reportable segments is shown below (in millions):

	Three-Month Periods						Nine-Month Periods
	Ended September 30,						Ended September 30,
	2006			2005			2006			2005
Operating revenue:
PacifiCorp	$	1,035.9		$	-		$	1,972.3		$	-
MidAmerican Funding		766.8			723.3			2,570.1			2,199.3
Northern Natural Gas		125.6			115.4			442.3			378.5
Kern River		64.5			82.2			230.0			240.0
CE Electric UK		242.6			209.4			668.9			663.5
CalEnergy Generation-Foreign		81.9			79.1			241.1			223.4
CalEnergy Generation-Domestic		9.2			8.3			24.7			24.9
HomeServices		461.9			538.4			1,334.8			1,454.8
Total reportable segments		2,788.4			1,756.1			7,484.2			5,184.4
Corporate/other(1)		(8.5	)		(10.7	)		(32.1	)		(30.4	)
Total operating revenue	$	2,779.9		$	1,745.4		$	7,452.1		$	5,154.0
Depreciation and amortization:
PacifiCorp	$	118.2		$	-		$	247.3		$	-
MidAmerican Funding		58.0			77.5			220.2			215.3
Northern Natural Gas		14.4			13.2			42.8			16.2
Kern River(2)		(8.2	)		15.5			38.4			46.7
CE Electric UK		35.6			31.7			100.0			101.4
CalEnergy Generation-Foreign		17.5			22.6			62.6			67.9
CalEnergy Generation-Domestic		1.9			2.2			5.9			6.6
HomeServices		10.1			4.5			25.7			13.2
Total reportable segments		247.5			167.2			742.9			467.3
Corporate/other(1)		(2.0	)		(1.7	)		(5.4	)		(4.8	)
Total depreciation and amortization	$	245.5		$	165.5		$	737.5		$	462.5

30

	Three-Month Periods						Nine-Month Periods
	Ended September 30,						Ended September 30,
	2006			2005			2006			2005
Operating income:
PacifiCorp	$	201.0		$	-		$	354.3		$	-
MidAmerican Funding		129.2			130.2			342.8			288.2
Northern Natural Gas		25.9			13.0			169.7			162.7
Kern River		59.3			52.7			151.5			149.6
CE Electric UK		136.3			113.1			367.6			353.7
CalEnergy Generation-Foreign		57.1			49.4			158.5			136.6
CalEnergy Generation-Domestic		5.3			4.3			11.7			13.8
HomeServices		19.7			47.9			54.3			106.8
Total reportable segments		633.8			410.6			1,610.4			1,211.4
Corporate/other(1)		(18.3	)		(20.3	)		(60.5	)		(62.0	)
Total operating income		615.5			390.3			1,549.9			1,149.4
Interest expense		(308.7	)		(221.0	)		(838.5	)		(676.7	)
Capitalized interest		10.7			4.7			25.6			12.9
Interest and dividend income		19.2			17.3			52.8			40.7
Other income		26.5			14.8			201.1			53.8
Other expense		(1.8	)		(15.8	)		(10.4	)		(20.6	)
Total income from continuing operations before income tax expense, minority interest and preferred dividends of subsidiaries and equity income	$	361.4		$	190.3		$	980.5		$	559.5
Interest expense:
PacifiCorp	$	72.3		$	-		$	149.7		$	-
MidAmerican Funding		36.2			33.1			114.1			100.4
Northern Natural Gas		12.5			12.9			37.5			40.1
Kern River		19.8			18.2			55.6			55.1
CE Electric UK		55.4			54.8			158.6			167.5
CalEnergy Generation-Foreign		4.8			7.4			16.1			24.0
CalEnergy Generation-Domestic		4.4			4.5			13.3			13.8
HomeServices		0.5			0.6			1.4			1.8
Total reportable segments		205.9			131.5			546.3			402.7
Corporate/other(1)		102.8			89.5			292.2			274.0
Total interest expense	$	308.7		$	221.0		$	838.5		$	676.7

31

	As of
	September 30,		December 31
	2006		2005
Total assets:
PacifiCorp	$	14,890.0	$	-
MidAmerican Funding		8,082.7		8,003.4
Northern Natural Gas		2,247.8		2,245.3
Kern River		2,063.0		2,099.6
CE Electric UK		6,504.2		5,742.7
CalEnergy Generation-Foreign		615.6		643.1
CalEnergy Generation-Domestic		562.4		555.1
HomeServices		819.1		814.3
Total reportable segments		35,784.8		20,103.5
Corporate/other(1)		241.2		267.2
Total assets	$	36,026.0	$	20,370.7

(1)

The remaining differences between the segment amounts and the consolidated amounts described as “Corporate/other” relate principally to intersegment eliminations for operating revenue and, for the other items presented, to (i) corporate functions, including administrative costs, interest expense, corporate cash and related interest income, (ii) intersegment eliminations and (iii) fair value adjustments relating to acquisitions.

(2)

The negative depreciation and amortization at Kern River for the three-month period ended September 30, 2006, is due to an adjustment to Kern River’s depreciation made after receiving an order on its rate case from the FERC (see Note 8).

Goodwill is allocated to each reportable segment included in total assets above. Goodwill as of December 31, 2005 and the changes for the nine-month period ended September 30, 2006 by reportable segment are as follows (in millions):

						Northern					CE			CalEnergy
			MidAmerican			Natural			Kern		Electric			Generation			Home-
	PacifiCorp		Funding			Gas			River		UK			Domestic			Services			Total
Goodwill at December 31, 2005	$	-	$	2,117.6		$	327.1		$	33.9	$	1,207.2		$	72.4		$	398.0		$	4,156.2
Goodwill from acquisitions		1,109.8		-			-			-		-			-			33.6			1,143.4
Reclassification of intangible assets(1)		-		-			-			-		-			-			(44.9	)		(44.9	)
Foreign currency translation		-		-			-			-		80.4			-			-			80.4
Other(2)		-		(0.2	)		(19.7	)		-		(1.2	)		(0.4	)		(0.4	)		(21.9	)
Goodwill at September 30, 2006	$	1,109.8	$	2,117.4		$	307.4		$	33.9	$	1,286.4		$	72.0		$	386.3		$	5,313.2

(1)	During the three-month period ending June 30, 2006, the Company reclassified $44.9 million of identifiable intangible assets from goodwill that principally related to trade names at HomeServices that were determined to have finite lives.
(2)	Other goodwill adjustments relate primarily to income tax adjustments.

32

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

The following is management’s discussion and analysis of certain significant factors which have affected the financial condition and results of operations of MidAmerican Energy Holdings Company (“MEHC”) and its subsidiaries (collectively, the “Company”) during the periods included in the accompanying consolidated financial statements. This discussion should be read in conjunction with the Company’s historical consolidated financial statements and the related notes thereto included elsewhere in this report. The Company’s actual results in the future could differ significantly from the historical results.

Forward-Looking Statements

This report contains statements that do not directly or exclusively relate to historical facts. These statements are “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. You can typically identify forward-looking statements by the use of forward-looking words, such as “may,” “will,” “could,” “project,” “believe,” “anticipate,” “expect,” “estimate,” “continue,” “potential,” “plan,” “forecast,” and similar terms. These statements are based upon the Company’s current intentions, assumptions, expectations and beliefs and are subject to risks, uncertainties and other important factors. Many of these factors are outside the Company’s control and could cause actual results to differ materially from those expressed or implied by the Company’s forward-looking statements. These factors include, among others:

·   general economic, political and business conditions in the jurisdictions in which the Company’s facilities are located;

·   the financial condition and creditworthiness of significant customers and suppliers;

·   governmental, statutory, legislative, regulatory or administrative initiatives, or ratemaking actions affecting the Company or the electric or gas utility, pipeline or power generation industries, including increased competition;

·   the outcome of general rate cases and other proceedings conducted before regulatory authorities or other governmental and legal bodies;

·   changes in economic, industry or weather conditions that could affect customer growth, usage of electricity or gas and operating revenue;

·   changes in prices and availability of wholesale electricity (for both purchases and sales), coal, natural gas, other fuel sources and fuel transportation;

·   changes in business strategy, development plans or customer or vendor relationships;

·   availability, terms and deployment of capital;

·   availability of qualified personnel;

·   unscheduled outages or repairs;

·   risks relating to nuclear generation;

·   the impact of derivative instruments used to mitigate or manage interest rate risk and volume and price risk and changes in the commodity prices, interest rates and other conditions that affect the value of the derivatives;

·   financial or regulatory accounting principles or policies imposed by the Public Company Accounting Oversight Board, the Financial Accounting Standards Board, the U.S. Securities and Exchange Commission (“SEC”), the Federal Energy Regulatory Commission (“FERC”), state public utility commissions, the Office of Gas and Electricity Markets in the United Kingdom and similar entities with regulatory oversight;

·   changes in, and compliance with, environmental laws, regulations, decisions and policies that could increase operating and capital improvement costs or affect plant output and/or delay plant construction;

·   the Company’s ability to successfully integrate PacifiCorp’s operations into the Company’s business;

·   other risks or unforeseen events, including wars, the effects of terrorism, embargos and other catastrophic events; and

·   other business or investment considerations that may be disclosed from time to time in filings with the SEC or in other publicly disseminated written documents.

Further details of the potential risks and uncertainties affecting the Company are described in MEHC’s filings with the SEC, including Item 1A. Risk Factors and other discussions contained in this Form 10-Q. The Company undertakes no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. The foregoing review of factors should not be construed as exclusive.

33

Executive Summary

The Company’s operations are organized and managed as eight distinct platforms: PacifiCorp, MidAmerican Funding, LLC (“MidAmerican Funding”) (which primarily includes MidAmerican Energy Company (“MidAmerican Energy”)), Northern Natural Gas Company (“Northern Natural Gas”), Kern River Gas Transmission Company (“Kern River”), CE Electric UK Funding Company (“CE Electric UK”) (which primarily includes Northern Electric Distribution Limited (“Northern Electric”) and Yorkshire Electricity Distribution plc (“Yorkshire Electricity”)), CalEnergy Generation-Foreign, CalEnergy Generation-Domestic and HomeServices of America, Inc. (“HomeServices”). These platforms are discussed in detail in the Company’s Annual Report on Form 10-K for the year ended December 31, 2005, except for PacifiCorp, which was purchased on March 21, 2006, and is discussed herein. Through these platforms, the Company owns and operates an electric utility company in the Western United States, a combined electric and natural gas utility company in the Midwestern United States, two natural gas pipeline companies in the United States, two electricity distribution companies in Great Britain, a diversified portfolio of domestic and international independent power projects and the second largest residential real estate brokerage firm in the United States.

The following significant events and changes occurred during the first nine months of 2006 and 2005, as discussed in more detail herein, which highlight some of the factors that affected, or may affect in the future, the Company’s financial condition, results of operations and liquidity:

·   In May 2005, MEHC reached a definitive agreement with Scottish Power plc (“ScottishPower”) and its subsidiary, PacifiCorp Holdings, Inc., to acquire 100% of the common stock of ScottishPower’s wholly owned indirect subsidiary PacifiCorp for $5.1 billion in cash. On March 21, 2006, MEHC issued common stock of $5.1 billion to Berkshire Hathaway Inc. (“Berkshire Hathaway”) and other existing stockholders and closed the PacifiCorp acquisition. The results of PacifiCorp are included in MEHC’s results beginning March 21, 2006.

·   On February 9, 2006, following the effective date of the repeal of the Public Utility Holding Company Act of 1935, Berkshire Hathaway converted its 41,263,395 shares of MEHC’s no par, zero-coupon convertible preferred stock into an equal number of shares of MEHC’s common stock.

·   On March 1, 2006, MEHC and Berkshire Hathaway entered into an Equity Commitment Agreement (the “Berkshire Equity Commitment”) pursuant to which Berkshire Hathaway has agreed to purchase up to $3.5 billion of common equity through February 28, 2011.

·   MidAmerican Funding’s operating income for the first nine months of 2006 increased $54.6 million, or 18.9%, from the comparable period in 2005 due primarily to improvements in MidAmerican Energy’s gross margin from regulated electric retail and wholesale sales.

·   Northern Natural Gas’ operating income for the first nine months of 2006 increased $7.0 million, or 4.3%, from the comparable period in 2005. Favorable comparative operating results in 2006 versus 2005 were largely offset by the net favorable effects, totaling $16.0 million, of two rate case settlements approved by the FERC during the first six months of 2005 and a $19.7 million gain from the sale of an idled section of pipeline in Oklahoma and Texas in the second quarter of 2005.

·   On October 19, 2006, the FERC issued an order that modified certain aspects of the administrative law judge’s initial decision received earlier in 2006. As a result of the FERC order, the liability for rates subject to refund increased $35.6 million to $88.3 million at September 30, 2006, and depreciation expense was reduced by $28.2 million.

·   HomeServices’ operating income for the first nine months of 2006 decreased $52.5 million, or 49.2%, from the comparable period in 2005 due mainly to fewer brokerage transactions closed at existing businesses as a result of the general slowdown in the U.S. housing markets, partially offset by the results of acquired companies not included in the comparable 2005 periods.

·   During the first nine months of 2006, the Company recognized after-tax gains from the disposition of available-for-sale securities totaling $73.3 million.

34

·   MidAmerican Energy is currently constructing Council Bluffs Energy Center Unit No. 4 (“CBEC Unit 4”), a 790-megawatt (“MW”) (expected accreditation) super-critical-temperature, coal-fired generating plant, of which MidAmerican Energy’s share is 479 MW, and expects to invest approximately $850 million in the project through 2007, including transmission facilities. Through September 30, 2006, MidAmerican Energy has invested $725.4 million in the project, including $121.3 million for MidAmerican Energy’s share of deferred payments allowed by the construction contract.

·   PacifiCorp is currently constructing the Lake Side Power Plant, an estimated 550-MW combined cycle plant in Utah, expected to be in service by the summer of 2007. The cost of the Lake Side Power Plant is expected to total approximately $347 million, of which $272.5 million has been incurred through September 30, 2006.

·   PacifiCorp placed 100.5 MW of wind-powered generation in operation in September 2006 and is currently constructing 140.4 MW of additional wind-powered generation that is expected to be in service by August 2007. MidAmerican Energy is currently constructing 99 MW of wind-powered generation that is expected to be in service by the end of 2006 and 123 MW of additional wind-powered generation that is expected to be in service by the end of 2007.

·   On March 24, 2006, MEHC completed a $1.7 billion offering of unsecured senior bonds due 2036 (the ‘‘Bonds’’). The Bonds were issued at an offering price of 99.957%, accrue interest at a rate of 6.125% per annum and mature on April 1, 2036.

·   On March 28, 2006, MEHC exercised its right to repurchase $1.7 billion of common stock from Berkshire Hathaway.

·   On August 10, 2006, PacifiCorp issued $350.0 million of 6.1%, 30-year first mortgage bonds. The proceeds from this offering are being used to repay a portion of PacifiCorp’s short-term debt and for general corporate purposes.

·   On October 6, 2006, MidAmerican Energy completed the sale of $350.0 million in aggregate principal amount of its 5.8% medium-term notes due October 15, 2036. The proceeds from this offering are being used to support construction of MidAmerican Energy’s electric generation projects, to repay a portion of its short-term debt and for general corporate purposes.

PacifiCorp Acquisition

On March 21, 2006, a wholly owned subsidiary of MEHC acquired 100% of the common stock of PacifiCorp from a wholly owned subsidiary of ScottishPower for a cash purchase price of $5,120.1 million, which includes direct transaction costs. The results of PacifiCorp’s operations are included in the Company’s results beginning March 21, 2006.

In February and March 2006, the state commissions in all six states where PacifiCorp has retail customers approved the sale of PacifiCorp to MEHC. The approvals were conditioned on a number of regulatory commitments, including expected financial benefits in the form of reduced corporate overhead and financing costs, certain mid- to long-term capital and other expenditures of significant amounts and a commitment not to seek utility rate increases attributable solely to the change in ownership. The capital and other expenditures proposed by MEHC and PacifiCorp include:

·   Approximately $812 million in investments (generally to be made over several years following the sale and subject to subsequent regulatory review and approval) in emissions reduction technology for PacifiCorp’s existing coal plants, which, when coupled with the use of reduced emissions technology for anticipated new coal-fueled generation, is expected to result in significant reductions in emissions rates of sulfur dioxide, nitrogen oxide and mercury and to avoid an increase in the carbon dioxide emissions rate;

·   Approximately $520 million in investments (to be made over several years following the sale and subject to subsequent regulatory review and approval) in PacifiCorp’s transmission and distribution system that would enhance reliability, facilitate the receipt of renewable resources and enable further system optimization; and

35

·   The addition of 400 MW of cost-effective renewable resources to PacifiCorp’s generation portfolio by December 31, 2007, including 100 MW of cost-effective wind resources by March 21, 2007.

The commitments approved by the state commissions also include credits that will reduce retail rates generally through 2010 to the extent that PacifiCorp does not achieve identified cost reductions or demonstrate mitigation of certain risks to customers. The maximum potential value of these rate credits to customers in all six states is $142.5 million. PacifiCorp and MEHC have made additional commitments to the state commissions that limit the dividends PacifiCorp can pay to MEHC or its affiliates. As of September 30, 2006, the most restrictive of these commitments prohibits PacifiCorp from making any distribution to MEHC or its affiliates 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. PacifiCorp’s ratio, as calculated pursuant to the requirements of the applicable commitment, was 51.9% at September 30, 2006.

PacifiCorp is a regulated electric utility company serving approximately 1.7 million residential, commercial and industrial customers in service territories aggregating approximately 136,000 square miles in portions of the states of Utah, Oregon, Wyoming, Washington, Idaho and California. The regulatory commissions in each state approve rates for retail electric sales within their respective states. PacifiCorp also sells electricity on the wholesale market to public and private utilities, energy marketing companies and to incorporated municipalities. Wholesale activities are regulated by the FERC. The FERC and the six state regulatory commissions also have authority over the construction and operation of PacifiCorp’s electric generation facilities. PacifiCorp delivers electricity through approximately 59,500 miles of distribution lines and approximately 15,600 miles of transmission lines.

PacifiCorp owns, or has interests in, the following types of electricity generating plants at September 30, 2006:

			Facility Net		Net
			Capacity		Megawatts
	Plants		Megawatts		Owned
Coal		11		9,466.0		6,103.9
Natural gas and other		6		1,411.0		1,174.0
Hydroelectric		50		1,139.4		1,139.4
Wind		2		141.9		133.1
Total		69		12,158.3		8,550.4

PacifiCorp obtains the remainder of its energy requirements, including additional energy required beyond expectations, through short- and long-term contracts or spot market purchases. The share of PacifiCorp’s energy requirements generated by its plants will vary from year to year and is determined by factors such as planned and unplanned outages, availability and price of coal and natural gas, precipitation and snowpack levels, environmental considerations and the market price of electricity.

During PacifiCorp’s fiscal year ended March 31, 2006, no single retail customer accounted for more than 2.0% of its 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 its fiscal 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%.

As a result of the geographically diverse area of operations, PacifiCorp’s service territory has historically experienced complementary seasonal load patterns. In the western portion, customer demand peaks in the winter months due to heating requirements. In the eastern portion, customer demand peaks in the summer when irrigation and air-conditioning systems are heavily used.

36

Results of Operations

Overview

Net income for the first nine months of 2006 increased $267.2 million, or 65.6%, to $674.3 million from the comparable period in 2005. Net income related to PacifiCorp, which was acquired on March 21, 2006, was $147.6 million during the period from acquisition to September 30, 2006. Also contributing to the increase in net income were favorable comparative first nine months operating results at MidAmerican Funding, Northern Natural Gas, Kern River, CE Electric UK and CalEnergy Generation-Foreign, as well as an after-tax gain of $55.3 million from the sale of Mirant common stock received as part of Kern River’s Mirant bankruptcy claim award in the first quarter of 2006 and an after-tax gain at MidAmerican Funding of $18.0 million on the disposition of common shares in an electronic energy and metals trading exchange in the second quarter of 2006.

Partially offsetting these favorable items were lower comparative first nine months operating results at HomeServices, higher parent company interest expense and lower equity earnings, as well as $9.0 million of unrealized, after-tax, losses at CalEnergy Gas (Holdings) Limited (“CE Gas”) related to its Australian gas production hedges and a $4.6 million, after-tax, adverse adjustment related to Kern River’s provision for estimated refunds made in the third quarter of 2006 after receiving an order on its pending rate case from the FERC. Additionally, Northern Natural Gas recognized an after-tax gain in the second quarter of 2005 of $12.0 million related to the sale of an idled section of pipeline in Oklahoma and Texas and the after-tax, net favorable effects in the first nine months of 2005 of $8.6 million related to the settlement of its outstanding rate cases.

Segment Results

The reportable segment financial information includes all necessary adjustments and eliminations needed to conform to the Company’s significant accounting policies. The differences between the segment amounts and the consolidated amounts, described as “Corporate/other,” relate principally to corporate functions including administrative costs, intersegment eliminations and fair value adjustments relating to acquisitions. A comparison of operating revenue and operating income for the Company’s reportable segments for the third quarter and the first nine months of 2006 and 2005 follows (in millions):

	Third Quarter						First Nine Months
	2006			2005			2006			2005
Operating revenue:
PacifiCorp	$	1,035.9		$	-		$	1,972.3		$	-
MidAmerican Funding		766.8			723.3			2,570.1			2,199.3
Northern Natural Gas		125.6			115.4			442.3			378.5
Kern River		64.5			82.2			230.0			240.0
CE Electric UK		242.6			209.4			668.9			663.5
CalEnergy Generation-Foreign		81.9			79.1			241.1			223.4
CalEnergy Generation-Domestic		9.2			8.3			24.7			24.9
HomeServices		461.9			538.4			1,334.8			1,454.8
Total reportable segments		2,788.4			1,756.1			7,484.2			5,184.4
Corporate/other		(8.5	)		(10.7	)		(32.1	)		(30.4	)
Total operating revenue	$	2,779.9		$	1,745.4		$	7,452.1		$	5,154.0
Operating income:
PacifiCorp	$	201.0		$	-		$	354.3		$	-
MidAmerican Funding		129.2			130.2			342.8			288.2
Northern Natural Gas		25.9			13.0			169.7			162.7
Kern River		59.3			52.7			151.5			149.6
CE Electric UK		136.3			113.1			367.6			353.7
CalEnergy Generation-Foreign		57.1			49.4			158.5			136.6
CalEnergy Generation-Domestic		5.3			4.3			11.7			13.8
HomeServices		19.7			47.9			54.3			106.8
Total reportable segments		633.8			410.6			1,610.4			1,211.4
Corporate/other		(18.3	)		(20.3	)		(60.5	)		(62.0	)
Total operating income	$	615.5		$	390.3		$	1,549.9		$	1,149.4

37

PacifiCorp

On March 21, 2006, MEHC acquired 100% of the common stock of PacifiCorp. Operating revenue for the period from acquisition to September 30, 2006 consisted of retail and wholesale and other revenues totaling $1,581.8 million and $390.5 million, respectively.PacifiCorp’s results included $14.1 million and $33.8 million, respectively, of after-tax, non-cash losses for the third quarter of 2006 and for the period from acquisition to September 30, 2006, on its electricity and natural gas forward purchase and sales contracts. The losses related to unfavorable mark-to-market movements in forward price curves and the impact of contracts that settled during the period. 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.

MidAmerican Funding

MidAmerican Funding’s operating revenue and operating income for the third quarter and the first nine months of 2006 and 2005 are summarized as follows (in millions):

	Third Quarter						First Nine Months
	2006			2005			2006		2005
Operating revenue:
Regulated electric	$	494.5		$	467.6		$	1,370.3	$	1,127.4
Regulated natural gas		153.4			181.2			778.3		858.7
Nonregulated		118.9			74.5			421.5		213.2
Total operating revenue	$	766.8		$	723.3		$	2,570.1	$	2,199.3
Operating income:
Regulated electric	$	126.6		$	140.0		$	308.3	$	261.4
Regulated natural gas		(6.4	)		(9.4	)		23.8		22.0
Nonregulated		9.0			(0.4	)		10.7		4.8
Total operating income	$	129.2		$	130.2		$	342.8	$	288.2

Regulated Electric Operations

The operating results of MidAmerican Energy’s regulated electric business for the third quarter and the first nine months of 2006 and 2005 are summarized as follows (in millions, except for average number of customers):

	Third Quarter				First Nine Months
	2006		2005		2006		2005
Retail	$	375.7	$	374.0	$	977.8	$	935.0
Wholesale		118.8		93.6		392.5		192.4
Total operating revenue		494.5		467.6		1,370.3		1,127.4
Cost of fuel, energy and capacity		199.3		147.6		516.8		339.8
Margin		295.2		320.0		853.5		787.6
Operating expense		118.5		110.4		348.8		335.0
Depreciation and amortization		50.1		69.6		196.4		191.2
Operating income	$	126.6	$	140.0	$	308.3	$	261.4
Sales (gigawatt-hours):
Retail		5,515		5,415		15,111		14,356
Wholesale		2,618		2,154		8,357		5,922
		8,133		7,569		23,468		20,278
Average number of customers		710,147		701,286		708,898		699,815

38

MidAmerican Energy’s regulated electric retail revenue for the third quarter and for the first nine months of 2006 increased $1.7 million, or 0.5%, to $375.7 million and $42.8 million, or 4.6%, to $977.8 million, respectively, from the comparable periods in 2005. Electric retail sales volumes increased 1.8% and a growing retail customer base, in particular the addition of a large steel manufacturer in the fourth quarter of 2005, improved electric retail revenue by $14.0 million compared to the third quarter of 2005. Transmission revenue increased $3.0 million due to an increase in the use of MidAmerican Energy’s transmission lines by other utilities. Milder average temperatures during the third quarter of 2006 compared to the same period in 2005 resulted in a $12.1 million decrease in electric retail revenue, while electricity usage factors not dependent on weather, such as the size of homes, technology changes and the use of multiple appliances, reduced electric revenue by $4.3 million compared to the third quarter of 2005. Electric retail sales volumes increased 5.3% compared to the first nine months of 2005. A growing retail customer base, in particular the addition of a large steel manufacturer in the fourth quarter of 2005, improved electric retail revenue by $38.6 million, while electricity usage factors not dependent on weather increased electric revenue by $7.7 million compared to the first nine months of 2005. Transmission revenue increased $11.2 million due to increased utilization of transmission services. Milder average temperatures during the first nine months of 2006 compared to the same period in 2005 resulted in a $17.0 million decrease in electric retail revenue.

In addition to retail sales, MidAmerican Energy sells electric energy, or wholesale sales, to other utilities, marketers and municipalities. MidAmerican Energy’s wholesale revenue for the third quarter and for the first nine months of 2006 increased $25.2 million, or 26.9%, to $118.8 million and $200.1 million, or 104.0%, to $392.5 million, respectively, from the comparable periods in 2005. The effect of higher electric energy prices increased wholesale energy revenue in the third quarter and in the first nine months of 2006 by $5.1 million and $121.0 million, respectively. Wholesale units for the third quarter and for the first nine months of 2006 increased 21.5% and 41.1%, respectively, from the comparable periods in 2005, resulting in increases in revenue of $20.1 million and $79.1 million, respectively. Improved market opportunities increased wholesale sales volumes in the third quarter and in the first nine months of 2006. Additional available MidAmerican Energy-owned, base load generation, including generation available as a result of newly added wind generation supplying retail customers, increased wholesale sales volumes in the first nine months of 2006.

Cost of fuel, energy and capacity for the third quarter and for the first nine months of 2006 increased $51.7 million, or 35.0%, to $199.3 million and $177.0 million, or 52.1%, to $516.8 million, respectively, from the comparable periods in 2005. The increase for the third quarter of 2006 from the comparable period in 2005 was due to an increase in purchased power costs due to higher wholesale sales volumes and outages at certain coal plants during the quarter. The increase for the first nine months of 2006 from the comparable period in 2005 was due to an increase in purchased power costs due to higher wholesale sales volumes and unit costs.

Regulated electric operating expense for the third quarter and for the first nine months of 2006 increased $8.1 million, or 7.3%, to $118.5 million and $13.8 million, or 4.1%, to $348.8 million, respectively, from the comparable periods in 2005. The increase for the third quarter of 2006 from the comparable period in 2005 was due to increases in efficiency program costs and electric generation plant costs of $2.8 million and $2.0 million, respectively. The increase for the first nine months of 2006 from the comparable period in 2005 was due mainly to increases of $4.4 million in efficiency program costs, $3.2 million in steam generation plant operating costs, $2.1 million in health benefit costs and $1.6 million in property taxes. The increases in energy efficiency costs are offset by corresponding increases in revenues.

Regulated electric depreciation and amortization for the third quarter and for the first nine months of 2006 decreased $19.5 million to $50.1 million and increased $5.2 million to $196.4 million, respectively, from the comparable periods in 2005. Regulated depreciation and amortization decreased in the third quarter of 2006 from the comparable period in 2005 due to a $20.5 million decrease in regulatory expense related to a revenue sharing arrangement in Iowa as a result of lower Iowa electric returns on equity primarily from a reduction in electric margins. The increase for the first nine months of 2006 from the comparable period in 2005 was mainly due to 200 MW of wind-powered generation facilities placed in service in late 2005.

Regulated Natural Gas Operations

Regulated natural gas revenue includes purchased gas adjustment clauses through which MidAmerican Energy is allowed to recover the cost of gas sold from its retail gas utility customers. Consequently, fluctuations in the cost of gas sold do not affect gross margin or operating income because revenues reflect comparable fluctuations through the purchased gas adjustment clauses. MidAmerican Energy’s average per-unit cost of gas sold for the third quarter of 2006 decreased 29.4%, resulting in a $47.5 million decrease in revenue and cost of gas sold from the comparable period in 2005. That decrease was partially offset by a 10.7% increase in sales volumes resulting in a $15.7 million increase in revenue and cost of gas sold, due to cooler temperature conditions, which increased sales for heating purposes. Compared to the first nine months of 2005, sales volumes decreased 12.0% for the first nine months of 2006, resulting in an $83.8 million decrease in revenue and cost of gas sold due to milder temperature conditions. Partially offsetting the decrease from lower sales volumes was a 0.6% increase in MidAmerican Energy’s average per-unit cost of gas sold for the first nine months of 2006, resulting in a $3.5 million increase in revenue and cost of gas sold from the comparable period in 2005.

39

Nonregulated Operations

MidAmerican Funding’s nonregulated operating revenue for the third quarter and for the first nine months of 2006 increased $44.4 million, or 59.6%, to $118.9 million and $208.3 million, or 97.7%, to $421.5 million, respectively, from the comparable periods in 2005 due primarily to a change in management’s strategy related to certain end-use natural gas contracts that resulted in prospective revenues and cost of sales being recorded on a gross, rather than net, basis. For the third quarter and for the first nine months of 2005, cost of sales totaling $64.7 million and $180.3 million, respectively, were netted in nonregulated operating revenue for such end-use gas contracts. Additionally, nonregulated operating revenue was lower in the third quarter of 2006 from the comparable period in 2005 due to lower gas volumes and lower electric and gas prices and was higher in the first nine months of 2006 from the comparable period in 2005 due to higher electric volumes. Nonregulated operating income for the third quarter and for the first nine months of 2006 increased $9.4 million to $9.0 million and $5.9 million to $10.7 million, respectively, from the comparable periods in 2005 due principally to higher realized margins and an increase in unrealized net gains on electric and natural gas financial instruments used for hedging purposes.

Northern Natural Gas

Operating revenue for the third quarter and for the first nine months of 2006 increased $10.2 million, or 8.8%, to $125.6 million and $63.8 million, or 16.9%, to $442.3 million, respectively, from the comparable periods in 2005. Transportation and storage revenues in the third quarter and in the first nine months of 2006 increased $12.4 million and $49.8 million, respectively, from the comparable periods in 2005. These increases were primarily due to higher field area demand and rates as well as new contracts and contract extensions. Also contributing to the increase in operating revenue in the first nine months of 2006 were increased sales of gas and condensate liquids, both utilized to manage physical flows on the pipeline system, that increased revenues by $14.6 million due to higher volumes and prices and the net effects of FERC approved rate settlements that reduced operating revenue for the first nine months of 2005 by $8.6 million.

Cost of sales for the first nine months of 2006 increased $13.5 million to $44.4 million from the comparable period in 2005 due primarily to higher gas and condensate liquids sales and prices. Operating expense for the first nine months of 2006 increased $16.7 million, or 9.9%, to $185.5 million from the comparable period in 2005 largely due to the $19.7 million gain recorded in the second quarter of 2005 on the sale of an idled section of pipeline in Oklahoma and Texas.

Depreciation and amortization for the first nine months of 2006 increased $26.6 million to $42.8 million from the comparable period in 2005 due primarily to the net effects of FERC approved rate settlements that reduced depreciation and amortization for the first nine months of 2005 by $25.7 million.

Kern River

Kern River’s 2004 general rate case hearing concluded in August 2005. On March 2, 2006, Kern River received an initial decision on the case from the administrative law judge. On October 19, 2006, the FERC issued an order that modified certain aspects of the administrative law judge’s initial decision, including changing the allowed return on equity from 9.34% to 11.2% and granting Kern River an income tax allowance. The order also affirmed the rejection of certain issues included in Kern River’s filed position, including the rates for the vintage system being designed on a 95% load factor basis as the FERC determined a 100% load factor basis should be used. The FERC also rejected a 3% inflation factor for certain operating expenses and a shorter useful life for certain plant. Kern River was permitted to bill the requested rate increase prior to final approval by the FERC, subject to refund, beginning effective November 1, 2004. Since that time, Kern River has recorded a provision for estimated refunds. As a result of the October 19, 2006 FERC order, the liability for rates subject to refund, including interest, increased $35.6 million to $88.3 million at September 30, 2006, and depreciation expense was reduced by $28.2 million.

40

Operating revenue for the third quarter and for the first nine months of 2006 decreased $17.7 million, or 21.5%, to $64.5 million and $10.0 million, or 4.2%, to $230.0 million, respectively, from the comparable periods in 2005. The decreases in operating revenue are due to a $33.6 million adjustment to Kern River’s provision for estimated refunds, partially offset by higher transportation revenues due mainly to higher volumes and rates resulting from more favorable market conditions.

Depreciation and amortization for the third quarter and for the first nine months of 2006 decreased $23.7 million to $(8.2) million and $8.3 million to $38.4 million, respectively, from the comparable periods in 2005 primarily due to changes in the expected depreciation rates in connection with the current rate proceeding.

CE Electric UK

Operating revenue for the third quarter of 2006 increased $33.2 million, or 15.9%, to $242.6 million from the comparable period in 2005 due primarily to a $10.5 million favorable impact from the exchange rate, $10.4 million of higher distribution revenues at Northern Electric and Yorkshire Electricity, higher gas exploration revenues of $6.8 million and higher contracting revenue of $5.4 million. Operating revenue for the first nine months of 2006 increased $5.4 million, or 0.8%, to $668.9 million from the comparable period in 2005 due primarily to $18.1 million of higher distribution revenues at Northern Electric and Yorkshire Electricity and higher contracting revenue of $6.6 million, partially offset by a $12.9 million unrealized loss at CE Gas related to its derivative condensate contracts, which are marked to market, and a $9.2 million adverse impact from the exchange rate.

Cost of sales for the third quarter and for the first nine months of 2006 increased $7.2 million, or 25.9%, to $35.2 million and $6.8 million, or 7.7%, to $94.6 million, respectively, from the comparable periods in 2005 due mainly to higher contracting costs of $5.2 million and $7.2 million, respectively.

Operating expense for the first nine months of 2006 decreased $13.8 million, or 11.4%, to $106.8 million from the comparable period in 2005 due mainly to lower costs of $6.0 million associated with the withdrawal from the metering market, $2.9 million of lower pension costs and a $1.8 million favorable impact from the exchange rate.

CalEnergy Generation-Foreign

Operating revenue for the third quarter and for the first nine months of 2006 increased $2.8 million, or 3.5%, to $81.9 million and $17.7 million, or 7.9%, to $241.1 million, respectively, from the comparable periods in 2005. The increases were due to higher revenue at the Casecnan Project of $12.9 million and $25.6 million, respectively, due mainly to higher variable energy fees as a result of significantly higher water flows, partially offset by lower revenue at the Leyte Projects of $10.1 million and $7.9 million, respectively, due primarily to the scheduled transfer on June 25, 2006 of the Upper Mahiao Project to the Philippine government.

Depreciation and amortization for the third quarter and for the first nine months of 2006 decreased $5.1 million to $17.5 million and $5.3 million to $62.6 million, respectively, from the comparable periods in 2005 due to the aforementioned transfer of the Upper Mahiao Project.

HomeServices

Operating revenue for the third quarter of 2006 decreased $76.5 million, or 14.2%, to $461.9 million and cost of sales decreased $54.8 million, or 14.8%, to $316.3 million from the comparable period in 2005. The decreases in operating revenue and cost of sales were due to a decline from existing businesses totaling $116.6 million and $82.6 million, respectively, reflecting primarily fewer brokerage transactions closed as a result of the general slowdown in the U.S. housing markets, partially offset by the results of acquired companies not included in the comparable 2005 period totaling $40.1 million and $27.8 million, respectively.

Operating revenue for the first nine months of 2006 decreased $120.0 million, or 8.2%, to $1,334.8 million and cost of sales decreased $88.0 million, or 8.8%, to $917.6 million from the comparable period in 2005. The decreases in operating revenue and cost of sales were due to a decline from existing businesses totaling $206.1 million and $147.4 million, respectively, reflecting primarily fewer brokerage transactions closed as a result of the general slowdown in the U.S. housing markets, partially offset by the results of acquired companies not included in the comparable 2005 period totaling $86.1 million and $59.4 million, respectively.

41

Operating expense for the third quarter and for the first nine months of 2006 increased $1.0 million, or 0.9%, to $115.9 million and $7.9 million, or 2.4%, to $337.2 million, respectively, from the comparable periods in 2005 mainly due to $11.0 million and $20.2 million, respectively, in operating expense related to the results of acquired companies not included in the comparable 2005 periods, partially offset by $10.0 million and $12.3 million, respectively, in lower operating expense at existing businesses due primarily to lower salaries and employee benefits and marketing and promotion expense.

Depreciation and amortization for the third quarter and for the first nine months of 2006 increased $5.6 million to $10.1 million and $12.5 million to $25.7 million, respectively, from the comparable periods in 2005 due primarily to higher amortization of acquisition intangibles.

Consolidated Other Income and Expense Items

Interest Expense

Interest expense for the third quarter and for the first nine months of 2006 and 2005 is summarized as follows (in millions):

	Third Quarter				First Nine Months
	2006		2005		2006		2005
Subsidiary debt	$	205.8	$	131.5	$	546.2	$	402.7
Parent company short-term and senior debt		63.4		43.7		168.5		133.4
Parent company subordinated debt-Berkshire		32.7		39.0		103.3		120.3
Parent company subordinated debt-other		6.8		6.8		20.5		20.3
Total interest expense	$	308.7	$	221.0	$	838.5	$	676.7

Interest expense on subsidiary debt for the third quarter and for the first nine months of 2006 increased $74.3 million to $205.8 million and $143.5 million to $546.2 million, respectively, from the comparable periods in 2005 due primarily to PacifiCorp’s interest expense which totaled $72.3 million and $149.7 million, respectively, during the third quarter of 2006 and the period from acquisition to September 30, 2006. Additionally, interest expense on subsidiary debt was higher in the third quarter and the first nine months of 2006 compared to the same periods in 2005 due to MidAmerican Energy’s 5.75% $300.0 million debt issuance in November 2005. These increases were partially offset by maturities of and scheduled principal repayments on other subsidiary and project debt. The increase for the first nine months of 2006 was also partially offset by a $10.2 million charge incurred in February 2005 to exercise the call option on the £155.0 million Variable Rate Reset Trust Securities at CE Electric UK.

Interest expense on parent company short-term and senior debt for the third quarter and for the first nine months of 2006 increased $19.7 million to $63.4 million and $35.1 million to $168.5 million, respectively, from the comparable periods in 2005 due mainly to MEHC’s 6.125% $1,700.0 million debt issuance in March 2006, partially offset by scheduled debt maturities.

Interest expense on parent company subordinated debt-Berkshire for the third quarter and for the first nine months of 2006 decreased $6.3 million to $32.7 million and $17.0 million to $103.3 million, respectively, from the comparable periods in 2005 as a result of scheduled principal repayments.

42

Other Income, Net

Other income, net for the third quarter and for the first nine months of 2006 and 2005 is summarized as follows (in millions):

	Third Quarter						First Nine Months
	2006			2005			2006			2005
Capitalized interest	$	10.7		$	4.7		$	25.6		$	12.9
Interest and dividend income		19.2			17.3			52.8			40.7
Other income		26.5			14.8			201.1			53.8
Other expense		(1.8	)		(15.8	)		(10.4	)		(20.6	)
Total other income, net	$	54.6		$	21.0		$	269.1		$	86.8

Capitalized interest for the third quarter and for the first nine months of 2006 increased $6.0 million to $10.7 million and $12.7 million to $25.6 million, respectively, from the comparable periods in 2005 due mainly to $6.3 million and $11.7 million, respectively, from PacifiCorp.

Interest and dividend income for the third quarter and for the first nine months of 2006 increased $1.9 million to $19.2 million and $12.1 million to $52.8 million, respectively, from the comparable periods in 2005. The increase in the third quarter was mainly due to $3.2 million from PacifiCorp. The increase in the first nine months was mainly due to $5.9 million from PacifiCorp and earnings on guaranteed investment contracts (£100.0 million at 4.75% and £200.0 million at 4.73%) purchased in May 2005 at CE Electric UK.

Other income for the third quarter and for the first nine months of 2006 increased $11.7 million to $26.5 million and $147.3 million to $201.1 million, respectively, from the comparable periods in 2005. Other income in the first nine months of 2006 included Kern River’s $89.3 million of gains from the sales of Mirant stock and MidAmerican Funding’s $32.1 million of gains from the disposition of common shares held in an electronic energy and metals trading exchange. Additionally, the allowance for equity funds used during construction for the third quarter and for the first nine months of 2006 increased $8.3 million and $20.1 million, respectively, from the comparable periods in 2005 due primarily to $5.8 million and $12.5 million, respectively, from PacifiCorp and $2.4 million and $7.8 million, respectively, due largely to increased levels of capital project expenditures at MidAmerican Energy.

Other expense for the third quarter and for the first nine months of 2006 decreased $14.0 million to $1.8 million and $10.2 million to $10.4 million, respectively, from the comparable periods in 2005 due primarily to losses for other-than-temporary impairments of MidAmerican Funding’s investments in commercial passenger aircraft leased to major domestic airlines of $14.0 million and $15.8 million, respectively, in the third quarter and the first nine months of 2005. Additionally, in connection with its disposition of common shares held in an electronic energy and metals trading exchange, MidAmerican Funding donated certain of these common shares to a charitable foundation and recognized a donation expense of $4.5 million, which partially offset the decrease in other expense for the first nine months of 2006 from the comparable period in 2005.

Income Tax Expense

Income tax expense for the third quarter and for the first nine months of 2006 increased $52.0 million to $107.6 million and $133.3 million to $320.5 million, respectively, from the comparable periods in 2005. The effective tax rates were 29.8% and 29.2%, respectively, for the third quarter of 2006 and 2005 and were 32.7% and 33.5%, respectively, for the first nine months of 2006 and 2005.

Minority Interest and Preferred Dividends of Subsidiaries

Minority interest and preferred dividends of subsidiaries for the third quarter and for the first nine months of 2006 increased $2.1 million to $6.5 million and $9.4 million to $20.4 million, respectively, from the comparable periods in 2005 due mainly to higher earnings at CE Casecnan.

43

Equity Income

Equity income for the third quarter and for the first nine months of 2006 increased $2.1 million to $25.0 million and decreased $6.3 million to $34.7 million, respectively, from the comparable periods in 2005. The increase in the third quarter was due to higher earnings at CE Generation, LLC resulting from increased revenue at the Power Resources Project, partially offset by lower equity income at HomeServices due to lower refinancing activity at its residential mortgage loan joint ventures. The decrease in the first nine months was due mainly to lower earnings at CE Generation, LLC resulting from more significant scheduled overhauls as well as lower equity income at HomeServices due to lower refinancing activity at its residential mortgage loan joint ventures.

Liquidity and Capital Resources

The Company has available a variety of sources of liquidity and capital resources, both internal and external, including the Berkshire Equity Commitment. These resources provide funds required for current operations, construction expenditures, debt retirement and other capital requirements. The Company may from time to time seek to retire its outstanding securities through cash purchases in the open market, privately negotiated transactions or otherwise. Such repurchases or exchanges, if any, will depend on prevailing market conditions, the Company’s liquidity requirements, contractual restrictions and other factors. The amounts involved may be material.

Each of MEHC’s direct or indirect subsidiaries is organized as a legal entity separate and apart from MEHC and its other subsidiaries. Pursuant to separate financing agreements at each subsidiary, the assets of each subsidiary may be pledged or encumbered to support or otherwise provide the security for their own project or subsidiary debt. It should not be assumed that any asset of any subsidiary of MEHC will be available to satisfy the obligations of MEHC or any of its other subsidiaries; provided, however, that unrestricted cash or other assets which are available for distribution may, subject to applicable law and the terms of financing and ring-fencing arrangements for such parties, be advanced, loaned, paid as dividends or otherwise distributed or contributed to MEHC or affiliates thereof.

The Company’s cash and cash equivalents and short-term investments, which consist primarily of auction rate securities that are used in the Company’s cash management program, were $451.4 million at September 30, 2006, compared to $396.3 million at December 31, 2005. In addition, the Company recorded separately, in restricted cash and short-term investments and in deferred charges and other assets, restricted cash and investments of $173.5 million and $136.7 million, respectively, at September 30, 2006 and December 31, 2005. The restricted cash balance is mainly composed of amounts deposited in restricted accounts relating to (i) the Company’s debt service reserve requirements relating to certain projects, (ii) customer deposits held in escrow, (iii) custody deposits, and (iv) unpaid dividends declared obligations. The debt service funds are restricted by their respective project debt agreements to be used only for the related project.

Cash Flows from Operating Activities

The Company generated cash flows from operations of $1,643.6 million for the first nine months of 2006, compared with $1,198.6 million from the comparable period in 2005. The increase was mainly due to the inclusion of $347.6 million of PacifiCorp’s operating cash flows for the period from acquisition to September 30, 2006 and the greater utilization of income tax net operating loss carryforwards.

Cash Flows from Investing Activities

Cash flows used in investing activities for the first nine months of 2006 and 2005 were $6,656.7 million and $1,205.2 million, respectively. The increase was primarily due to the 2006 acquisition of PacifiCorp, net of cash acquired, for $4,932.4 million and a $927.8 million increase in capital expenditures, construction and other development costs. These increases were partially offset by the 2005 purchase of two guaranteed investment contracts by certain indirect wholly owned subsidiaries of CE Electric UK totaling $556.6 million. Additionally, Kern River received proceeds in 2006 totaling $89.3 million from the sale of Mirant shares received in payment of the majority of its allowed bankruptcy claim and MidAmerican Funding received proceeds in 2006 totaling $27.6 million from the sale of common shares held in an electronic energy and metals trading exchange.

44

Capital Expenditures, Construction and Other Development Costs

Capital expenditures, construction and other development costs were $1,734.4 million for the first nine months of 2006 compared with $806.6 million from the comparable period in 2005. The following table summarizes the expenditures by reportable segment (in millions):

	Nine-Month Periods
	Ended September 30,
	2006		2005
Capital expenditures:
PacifiCorp	$	844.3	$	-
MidAmerican Funding		514.4		498.5
Northern Natural Gas		78.5		72.1
CE Electric UK		284.9		222.8
Other reportable segments and corporate/other		12.3		13.2
Total capital expenditures	$	1,734.4	$	806.6

Forecasted capital expenditures, construction and other development costs for fiscal 2006, which exclude the non-cash equity allowance for funds used during construction ("AFUDC"), are approximately $2.5 billion. Capital expenditure needs are reviewed regularly by management and may change significantly as a result of such reviews. The Company expects to meet these capital expenditures with cash flows from operations and the issuance of debt. Capital expenditures relating to operating projects, consisting mainly of recurring expenditures and the funding of growing load requirements, were $1,139.6 million for the first nine months of 2006. Construction and other development costs were $594.8 million for the first nine months of 2006. These costs consist mainly of expenditures for large scale generation projects at PacifiCorp and MidAmerican Energy as described below.

PacifiCorp

As required by state regulators, PacifiCorp uses Integrated Resource Plans (“IRP”) to develop a long-term view of prudent future actions required to help ensure that PacifiCorp continues to provide reliable and cost-effective electric service to its customers. The IRP process identifies the amount and timing of PacifiCorp’s expected future resource needs and an associated optimal future resource mix that accounts for planning uncertainty, risks, reliability impacts and other factors. The IRP is a coordinated effort with stakeholders in each of the six states where PacifiCorp operates. Each state commission that has IRP adequacy rules judges whether the IRP reasonably meets its standards and guidelines at the time the IRP is filed. If the IRP is found to be adequate, then it is formally “acknowledged.” The IRP can then be used as evidence by parties in rate-making or other regulatory proceedings.

In November 2005, PacifiCorp released an update to its 2004 IRP. The updated 2004 IRP identified a need for approximately 2,113 MW of additional resources by summer 2014, to be met with a combination of thermal generation (1,936 MW) and load control programs (177 MW). PacifiCorp also planned to implement energy conservation programs of 450 average MW, to continue to seek procurement of 1,400 MW of economic renewable resources and to use wholesale electricity transactions to make up for the remaining difference between retail load obligations and available resources.

In July 2006, PacifiCorp filed its 2012 draft request for proposals under its updated 2004 IRP with the UPSC and the OPUC. The draft request for proposals is for generation resources of between 840 MW and 915 MW to be available in 2012 through 2013. The scope of this draft request for proposals is focused on resources capable of delivering energy and capacity in or to PacifiCorp’s network transmission system in PacifiCorp’s eastern service territory. All transaction and resource decisions will be evaluated on a comparable least-cost and risk-balanced approach. In response to issues and concerns from stakeholders, PacifiCorp filed a revised version of the 2012 draft request for proposals in October 2006. Conditional approvals are expected from the state commissions in November 2006.

In March 2006, PacifiCorp completed construction of the Currant Creek Power Plant, a 523-MW combined cycle plant in Utah. Total project costs incurred were approximately $341 million. Presently under construction is the Lake Side Power Plant, an estimated 550-MW combined cycle plant in Utah, expected to be in service in May 2007. The cost of the Lake Side Power Plant is expected to total approximately $347 million, including approximately $13 million of non-cash equity AFUDC, of which $272.5 million, including $7.6 million of non-cash equity AFUDC, has been incurred through September 30, 2006. Both plants are 100% owned and operated by PacifiCorp.

45

In July 2006, PacifiCorp entered into an agreement to acquire a 100.5-MW wind energy generation facility that became operational in September 2006. An initial investment in an additional 140.4-MW wind energy generation facility occurred in September 2006 and construction is scheduled to be completed by August 2007.

Additionally, in conjunction with regulatory commitments made by the Company, approximately $520 million in investments are anticipated being made to PacifiCorp’s transmission and distribution system over the next several years that would enhance reliability, facilitate the receipt of renewable resources and enable further system optimization. Such investments would be subject to regulatory review and approval.

PacifiCorp’s capital requirements for the period from acquisition to December 31, 2006, which exclude the non-cash equity AFUDC, are estimated to be approximately $1,218 million, which includes $494 million for the generation development projects described above, $92 million for emissions control equipment to address current and anticipated air quality regulations and $632 million for ongoing operational projects, including connections for new customers and facilities to accommodate load growth.

MidAmerican Funding

MidAmerican Energy anticipates a continuing increase in demand for electricity from its regulated customers. To meet anticipated demand and ensure adequate electric generation in its service territory, MidAmerican Energy is currently constructing CBEC Unit 4, a 790-MW (expected accreditation) super-critical-temperature, coal-fired generating plant. MidAmerican Energy will operate the plant and hold an undivided ownership interest as a tenant in common with the other owners of the plant. MidAmerican Energy’s current ownership interest is 60.67%, equating to 479 MW of output. Municipal, cooperative and public power utilities will own the remainder, which is a typical ownership arrangement for large base-load plants in Iowa. The facility will provide service to regulated retail electricity customers. Wholesale sales may also be made from the facility to the extent the power is not immediately needed for regulated retail service. MidAmerican Energy has obtained regulatory approval to include the Iowa portion of the actual cost of the generation project in its Iowa rate base as long as the actual cost does not exceed the agreed cap that MidAmerican Energy believes to be reasonable. If the cap is exceeded, MidAmerican Energy has the right to demonstrate the prudence of the expenditures above the cap, subject to regulatory review. MidAmerican Energy expects to invest approximately $850 million in CBEC Unit 4, including transmission facilities and approximately $64 million of non-cash equity AFUDC. Through September 30, 2006, MidAmerican Energy has invested $725.4 million in the project, including $121.3 million for MidAmerican Energy’s share of deferred payments allowed by the construction contract and $40.8 million of non-cash equity AFUDC.

On December 16, 2005, MidAmerican Energy filed with the Iowa Utilities Board (“IUB”) a settlement agreement between MidAmerican Energy and the Iowa Office of Consumer Advocate regarding ratemaking principles for up to 545 MW (nameplate ratings) of wind-powered generation capacity in Iowa to be installed in 2006 and 2007. Generally speaking, accredited capacity ratings for wind-powered generation facilities are considerably less than the nameplate ratings due to the varying nature of wind. The settlement agreement was approved by the IUB on April 18, 2006.

MidAmerican Energy has been working with wind project developers and contractors to add new MidAmerican Energy-owned generation assets. In February 2006, MidAmerican Energy entered into agreements to add 99 MW (nameplate ratings) of wind-powered generation by the end of 2006. In June 2006, MidAmerican Energy entered into an additional agreement to add 123 MW (nameplate ratings) of wind-powered generation by the end of 2007.

While MidAmerican Energy continues to pursue additional wind-powered generation in the 2006-2007 timeframe, MidAmerican Energy will only add additional wind-powered generation if it views that it will be cost-effective.

MidAmerican Energy’s capital requirements for 2006, which exclude the non-cash equity AFUDC, are estimated to be approximately $752 million, which includes $352 million for the generation development projects described above, $53 million for emissions control equipment to address current and anticipated air quality regulations and $347 million for ongoing operational projects, including connections for new customers and facilities to accommodate load growth.

46

Cash Flows from Financing Activities

Cash flows generated from financing activities for the first nine months of 2006 were $5,084.9 million. Sources of cash totaled $7,333.3 million and consisted mainly of $5,122.6 million of proceeds from the issuance of common stock and $1,699.3 million of proceeds from the issuance of parent company senior debt. Uses of cash totaled $2,248.4 million and consisted mainly of $1,750.0 million for repurchases of common stock, $257.3 million for repayments of subsidiary and project debt and $167.0 million for repayment of parent company subordinated debt.

Cash flows used in financing activities for the first nine months of 2005 were $216.7 million. Sources of cash totaled $805.6 million and consisted primarily of $750.6 million of proceeds from the issuance of subsidiary and project debt. Uses of cash totaled $1,022.3 million and consisted primarily of $632.2 million for repayments of subsidiary and project debt and $381.5 million for repayments of parent company senior and subordinated debt.

Recent Debt and Stock Transactions

On March 6, 2006, Mr. David L. Sokol, Chairman and Chief Executive Officer of MEHC, exercised 450,000 common stock options having an exercise price of $29.01 per share. Additionally, Mr. Sokol put 344,274 shares of common stock to MEHC for a purchase price of $50.0 million.

On March 21, 2006, Berkshire Hathaway and certain other of MEHC’s existing stockholders and related companies invested $5,109.5 million, in the aggregate, in 35,237,931 shares of MEHC’s common stock in order to provide equity funding for the PacifiCorp acquisition. The per-share value assigned to the shares of common stock issued, which were effected pursuant to a private placement and were exempt from the registration requirements of the Securities Act of 1933, as amended, was based on an assumed fair market value as agreed to by MEHC’s stockholders.

On March 24, 2006, MEHC completed a $1,700.0 million offering of unsecured senior bonds due 2036 (the ‘‘Bonds’’). The Bonds were issued at an offering price of 99.957%, will accrue interest at a rate of 6.125% per annum and will mature on April 1, 2036. Accrued interest on the Bonds is payable on April 1 and October 1 of each year, commencing on October 1, 2006, until the principal amount of the Bonds is paid in full. The proceeds were used to fund MEHC’s exercise of its right to repurchase shares of its common stock previously issued to Berkshire Hathaway.

On March 28, 2006, MEHC repurchased 11,724,138 shares of common stock from Berkshire Hathaway for an aggregate purchase price of $1,700.0 million.

On June 15, 2006, MidAmerican Energy’s 6.375% series of notes, totaling $160.0 million, matured.

On July 6, 2006, MEHC entered into a $600.0 million credit facility pursuant to the terms and conditions of an amended and restated credit agreement. The amended and restated credit agreement remains unsecured, carries a variable interest rate based on LIBOR or a base rate, at MEHC’s option, plus a margin, and the termination date was extended to July 6, 2011. The facility continues to support letters of credit for the benefit of certain subsidiaries and affiliates. As of September 30, 2006, the outstanding balance and amount of letters of credit issued under the credit agreement totaled $144.0 million and $59.9 million, respectively. At September 30, 2006, the interest rate on the $144.0 million outstanding under the credit agreement was 5.57%.

On August 10, 2006, PacifiCorp issued $350.0 million of 6.1%, 30-year first mortgage bonds. The proceeds from this offering were used to repay a portion of PacifiCorp’s short-term debt and for general corporate purposes.

In September 2006, MEHC entered into a treasury rate lock in the notional amount of $1,550.0 million to hedge against a rise in interest rates related to the anticipated funding of its 2007 and 2008 maturities of parent company senior debt. The fair value of this hedge as of September 30, 2006 was immaterial.

On October 6, 2006, MidAmerican Energy completed the sale of $350.0 million in aggregate principal amount of its 5.8% medium-term notes due October 15, 2036. The proceeds from this offering are being used to support construction of MidAmerican Energy’s electric generation projects, to repay a portion of its short-term debt and for general corporate purposes.

47

The Energy Policy Act

On August 8, 2005, the Energy Policy Act was signed into law. That law impacts many segments of the energy industry. A tax provision extended the federal production tax credit for new renewable electricity generation projects through December 31, 2007. In part as a result of that portion of the law, PacifiCorp and MidAmerican Energy began development efforts to add additional wind-powered generation. The law also expands FERC regulatory authority in areas such as electric system reliability, electric transmission expansion and pricing, regulation of utility holding companies, and enforcement authority to issue substantial civil penalties.

Pension Protection Act of 2006

On August 17, 2006, the Pension Protection Act of 2006 (the “Pension Act”) was signed into law. The Pension Act includes a requirement for qualified pension plans to be fully funded within seven years following the January 1, 2008 effective date. The Company does not anticipate any significant changes to the amount of funding previously anticipated through 2007. The Company is reviewing the impacts of the Pension Act on funding requirements for its domestic pension plans for 2008 and beyond. As a result of the Pension Act, the Company may be required to accelerate contributions to its domestic pension plans for periods after 2007 and there may be more volatility in annual contributions in the future.

CalEnergy Generation-Foreign - Customers

The PNOC-Energy Development Corporation (“PNOC-EDC”)’s and the Philippine National Irrigation Administration’s obligations under the project agreements are substantially denominated in U.S. Dollars and are the Leyte Projects’ and the Casecnan Project’s sole source of operating revenue. Because of the dependence on a single customer, any material failure of the customer to fulfill its obligations under the project agreements and any material failure of the Republic of the Philippines to fulfill its obligation under the performance undertaking would significantly impair the ability to meet existing and future obligations, including obligations pertaining to the outstanding project debt.

The 10-year cooperation period for the Upper Mahiao Project ended on June 25, 2006, and the Upper Mahiao Project was transferred to the PNOC-EDC at no cost on an “as-is” basis. Additionally, the 10-year cooperation periods for the Mahanagdong and Malitbog Projects end in July 2007, at which time each project will also be transferred to the PNOC-EDC at no cost on an “as-is” basis. For the first nine months of 2006, the Upper Mahiao Project’s financial results represented 0.3%, 0.6% and 2.3%, respectively, and the Mahanagdong and Malitbog Projects’ combined financial results represented 1.5%, 4.8% and 4.5%, respectively, of MEHC’s total consolidated operating revenue, income from continuing operations and operating cash flows from continuing operations. Additionally, the net properties, plants and equipment and the project debt of the Mahanagdong and Malitbog Projects represented less than 1%, respectively, of MEHC’s total consolidated net properties, plants and equipment and subsidiary and project debt at September 30, 2006.

Credit Ratings Risks

Debt and preferred securities of MEHC and its subsidiaries may be rated by nationally recognized credit rating agencies. Assigned credit ratings are based on each rating agency’s assessment of the rated company’s ability to, in general, meet the obligations of its debt or preferred securities issued by the rated company. The credit ratings are not a recommendation to buy, sell or hold securities, and there is no assurance that a particular credit rating will continue for any given period of time. Other than the agreements discussed below, MEHC and its subsidiaries do not have any credit agreements that require termination or a material change in collateral requirements or payment schedule in the event of a downgrade in the credit ratings of the respective company’s securities.

48

In conjunction with their risk management activities, PacifiCorp and MidAmerican Energy must meet credit quality standards as required by counterparties. In accordance with industry practice, master agreements that govern PacifiCorp’s and MidAmerican Energy’s energy supply and marketing activities either specifically require them to maintain investment grade credit ratings or provide the right for counterparties to demand “adequate assurances” in the event of a material adverse change in PacifiCorp’s or MidAmerican Energy’s creditworthiness. If one or more of PacifiCorp’s or MidAmerican Energy’s credit ratings decline below investment grade, PacifiCorp or MidAmerican Energy may be required to post cash collateral, letters of credit or other similar credit support to facilitate ongoing wholesale energy supply and marketing activities. As of September 30, 2006, PacifiCorp’s and MidAmerican Energy’s credit ratings from the three recognized credit rating agencies were investment grade; however if the ratings fell below investment grade, PacifiCorp’s and MidAmerican Energy’s estimated potential collateral requirements would total approximately $263 million and $173 million, respectively. PacifiCorp’s and MidAmerican Energy’s potential collateral requirements could fluctuate considerably due to seasonality, market price volatility, and a loss of key generating facilities or other related factors.

Yorkshire Power Group Limited (“YPGL”), a subsidiary of CE Electric UK, has in effect certain currency rate swap agreements for its Yankee bonds with three large multi-national financial institutions. The swap agreements effectively convert the U.S. dollar fixed interest rate to a fixed rate in sterling for $281.0 million of 6.496% Yankee bonds outstanding at September 30, 2006. The agreements extend until February 25, 2008 and convert the U.S. dollar interest rate to a fixed sterling rate ranging from 7.3175% to 7.345%. The estimated fair value of these swap agreements at September 30, 2006, was $91.0 million based on quotes from the counterparties to these instruments and represents the estimated amount that the Company would expect to pay if these agreements were terminated. Certain of these counterparties have the option to terminate the swap agreements and demand payment of the fair value of the swaps if YPGL’s credit ratings from the three recognized credit rating agencies decline below investment grade. As of September 30, 2006, YPGL’s credit ratings from the three recognized credit rating agencies were investment grade; however, if the ratings fell below investment grade, payment requirements would have been $42.5 million.

Contractual Obligations and Commercial Commitments

The Company has contractual obligations and commercial commitments that may affect its financial condition. Contractual obligations to make future payments arise from parent company and subsidiary long-term debt and notes payable, operating leases and power and fuel purchase contracts. Other obligations and commitments arise from unused lines of credit and letters of credit. Material obligations and commitments as of September 30, 2006 are as follows (in millions):

	Payments Due By Period
			Remainder						2011 and
	Total		of 2006		2007-2008		2009-2010		After
Contractual Cash Obligations:
Parent company senior debt	$	4,475.0	$	-	$	1,550.0	$	-	$	2,925.0
Parent company subordinated debt		1,496.8		67.0		468.0		422.5		539.3
Subsidiary and project debt		11,314.5		271.1		1,522.1		558.4		8,962.9
Interest payments on long-term debt		14,557.3		340.1		2,103.6		1,667.3		10,446.3
Short-term debt		296.2		296.2		-		-		-
Coal, electricity and natural gas contract commitments(1)		9,846.4		447.6		2,494.3		1,736.9		5,167.6
Owned hydroelectric commitments(1)		715.9		20.0		99.4		117.7		478.8
Operating leases(1)		477.9		24.4		163.9		99.2		190.4
Deferred costs on construction contract(2)		200.0		-		200.0		-		-
Total contractual cash obligations	$	43,380.0	$	1,466.4	$	8,601.3	$	4,602.0	$	28,710.3

49

	Commitment Expiration per Period
			Remainder						2011 and
	Total		of 2006		2007-2008		2009-2010		After
Other Commercial Commitments:
Unused revolving credit facilities and lines of credit -
Parent company revolving credit facility	$	396.1	$	-	$	-	$	-	$	396.1
Subsidiary revolving credit facilities and lines of credit		1,364.6		-		27.5		312.2		1,024.9
Total unused revolving credit facilities and lines of credit	$	1,760.7	$	-	$	27.5	$	312.2	$	1,421.0
Parent company letters of credit outstanding	$	61.0	$	-	$	61.0	$	-	$	-
Pollution control revenue bond standby letters of credit	$	296.9	$	-	$	-	$	296.9	$	-
Pollution control revenue bond standby bond purchase agreements	$	220.9	$	-	$	124.4	$	-	$	96.5
Other standby letters of credit	$	96.3	$	7.0	$	24.9	$	-	$	64.4

(1)	The coal, electricity and natural gas contract commitments, owned hydroelectric commitments and operating leases are not reflected on the consolidated balance sheets.
(2)	MidAmerican Energy is allowed to defer up to $200.0 million in payments to the contractor under its contract to build CBEC Unit 4. Approximately 39.3% of this commitment is expected to be funded by the joint owners of CBEC Unit 4.

The Company has other types of commitments that are subject to change and relate primarily to the items listed below. For additional information, refer, where applicable, to Note 3, “PacifiCorp Acquisition,” and Note 9, “Commitments and Contingencies,” to the Interim Financial Statements and to the Notes to Consolidated Financial Statements included in Item 8, “Financial Statements and Supplementary Data,” included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2005.

·Debt service reserve guarantees

· Asset retirement obligations

· Nuclear decommissioning costs

· Residual guarantees on operating leases

· Pension and postretirement commitments

Regulatory Matters

In addition to the discussion contained herein regarding updates to regulatory matters based upon changes that occurred during the nine-month period ended September 30, 2006; refer to Note 8, “Regulatory Matters,” to the Interim Financial Statements for additional regulatory matter updates.

PacifiCorp

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. In February 2005, PacifiCorp submitted a joint triennial market power analysis, which indicated that PacifiCorp failed to pass one of the generation market power screens. In May 2005, the FERC issued an order instituting a proceeding pursuant to Section 206 of the Federal Power Act to determine whether PacifiCorp may continue to charge market-based rates for sales of wholesale energy and capacity. In June and July 2005, PacifiCorp and its formerly affiliated co-applicants submitted additional information and analysis to the FERC to rebut the presumption that PacifiCorp had generation market power. In January 2006, the FERC requested PacifiCorp to amend its previous filings with additional analysis, which was filed in March 2006. In June 2006, the FERC issued an order finding that PacifiCorp does not have market power and terminating the proceeding.

50

MidAmerican Funding

On July 13, 2004, the FERC issued an order requiring MidAmerican Energy to conduct a study to determine whether MidAmerican Energy or its affiliates possess generation market power. MidAmerican Energy is being required to show the absence of generation market power in order to be allowed to continue to sell wholesale electric power at market-based rates. The FERC order is intended to have MidAmerican Energy conform to what has become the FERC’s general practice for utilities given authorization to make wholesale market-based sales. Under this general practice, utilities authorized to make market-based electric sales must submit a new market power study to the FERC every three years. MidAmerican Energy filed the required study on October 29, 2004. On June 1, 2005, the FERC issued an order setting for investigation the reasonableness of MidAmerican Energy’s market-based rates within its control area. The order also terminated the previously established November 1, 2004, refund date and instead required that market-based sales made by MidAmerican Energy within its control area beginning August 7, 2005, be subject to refund until the matter is resolved. The FERC also required MidAmerican Energy to file additional information by July 1, 2005, and August 1, 2005. In its August 1, 2005 filing, MidAmerican Energy filed a proposed cost-based sales tariff (“CBST”) applicable to sales made within its control area to replace its market-based sales tariff. On March 17, 2006, the FERC issued an order (the “March 17 Order”) accepting MidAmerican Energy’s commitment not to make sales using market-based rates in its control area but rejected the proposed applicable tariff language. The FERC directed MidAmerican Energy to file revised tariff language by April 17, 2006. MidAmerican Energy made such filing together with a request for clarification, or in the alternative, rehearing (the “Request for Clarification”) of the March 17 Order. MidAmerican Energy estimates that its maximum potential refund obligation is $16 million and its minimum potential refund obligation is $50,000 for the period August 7, 2005 through September 30, 2006. The actual refund will depend upon the FERC’s ruling on the Request for Clarification and the applicability of the CBST to certain sales made within the control area for delivery outside the control area. MidAmerican Energy does not believe at this time that the ultimate outcome of this issue will have a material impact on its results of operations, financial position or cash flows.

Environmental Matters

In addition to the discussion contained herein, refer to Note 9, “Commitments and Contingencies,” to the Interim Financial Statements for additional information regarding certain environmental matters affecting PacifiCorp’s and MidAmerican Energy’s operations.

In conjunction with state regulatory approvals of the Company’s acquisition of PacifiCorp, the Company and PacifiCorp committed to invest approximately $812 million in capital spending over several years for emission control equipment to address current and future air quality initiatives implemented by the EPA or the states in which PacifiCorp operates facilities. Additional capital expenditures for emission reduction projects may be required, depending on the outcome of pending or new air quality regulations. PacifiCorp’s capital requirements for the period from acquisition to December 31, 2006, total approximately $92 million related to expenditures for such emission control capital projects.

MidAmerican Energy has implemented a planning process that forecasts the site-specific controls and actions that may be required to meet air emissions reductions as promulgated by the EPA. The plan allows MidAmerican Energy to more effectively manage its expenditures required to comply with emissions standards. On April 1, 2006, MidAmerican Energy submitted to the IUB an updated plan, as required every two years by Iowa law, which increased its estimate of required expenditures. MidAmerican Energy currently estimates that the incremental capital expenditures for emission control equipment to comply with air quality requirements will total approximately $540 million for January 1, 2006, through December 31, 2015. For 2006, MidAmerican Energy currently expects to incur approximately $53 million of such capital expenditures.

In addition to capital expenditure requirements, incremental operating costs are expected to be incurred by PacifiCorp and MidAmerican Energy in conjunction with the utilization of the emission control equipment. Estimates of environmental capital and operating requirements may change significantly at any time as a result of, among other factors, changes in related regulations, prices of products used to meet the requirements, competition in the industry for similar technology and management’s strategies for achieving compliance with the regulations.

51

New Accounting Pronouncements

For a discussion of new accounting pronouncements affecting the Company, refer to Note 2, “New Accounting Pronouncements,” to the Interim Financial Statements.

Critical Accounting Policies

The preparation of financial statements and related disclosures in conformity with accounting principles generally accepted in the United States of America requires management to make judgments, assumptions and estimates that affect the amounts reported in the consolidated financial statements and accompanying notes. Note 2 to the Company’s consolidated financial statements included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2005 describes the significant accounting policies and methods used in the preparation of the consolidated financial statements. Estimates are used for, but not limited to, the accounting for the effects of certain types of regulation, impairment of long-lived assets, contingent liabilities and the accounting for revenue. Actual results could differ from these estimates.

For additional discussion of the Company’s critical accounting policies, see Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2005. The Company’s critical accounting policies have not changed materially since December 31, 2005, except as they relate to the PacifiCorp acquisition and PacifiCorp’s derivative instruments.

PacifiCorp Acquisition

SFAS No. 141, “Business Combinations” requires that the total purchase price of acquired companies be allocated to the net tangible and identified intangible assets acquired and liabilities assumed based on their estimated fair values as of the acquisition date. Such a valuation requires management to make significant estimates and assumptions. Management makes estimates of fair value based upon assumptions believed to be reasonable. These estimates are based on historical experience and information obtained from the management of the acquired companies. These estimates are inherently uncertain and unpredictable. Assumptions may be incomplete or inaccurate, and unanticipated events and circumstances may occur which may affect the accuracy or validity of such assumptions, estimates or actual results.

PacifiCorp’s operations are regulated, which provide revenue derived from cost, and are accounted for pursuant to SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation.” PacifiCorp has demonstrated a past history of recovering its costs incurred through its rate making process. Given the size and timing of the acquisition, the fair values established to date are preliminary and are subject to adjustment as additional information is obtained. Certain adjustments related to derivative contracts, severance costs and income taxes have been made through September 30, 2006, which were not significant to the overall purchase price allocation. When finalized, additional adjustments to goodwill may result.

The Company 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. Pursuant to Emerging Issues Task Force (“EITF”) Issue No. 93-7, “Uncertainties Related to Income Taxes in a Purchase Business Combination,” the Company will adjust goodwill prospectively for the settlement of any income tax related pre-acquisition contingencies. Prior to the end of the purchase price allocation period, if information becomes available that a non-income tax related 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 the Company. Costs, consisting primarily of employee termination activities, will be incurred associated with such transition activities. The Company is in the process of finalizing these plans and expects to execute these plans over the next several months. In accordance with EITF 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. Transition costs that do not meet the criteria in EITF 95-3 are expensed in the period incurred.

52

Derivative Instruments

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. These instruments are accounted for under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” (“SFAS 133”), as amended. PacifiCorp also enters into short-term energy derivatives on a limited basis for arbitrage purposes to take advantage of opportunities arising from market inefficiencies. SFAS 133 applies not only to traditional financial derivative instruments, but to any contract having the accounting characteristics of a derivative.

SFAS 133 requires that derivative instruments be recorded on the balance sheet at fair value. The fair values of derivative instruments are determined using forward price curves. Forward price curves represent PacifiCorp’s estimates of the prices at which a buyer or seller could contract today for delivery or settlement of a commodity at future dates. PacifiCorp bases its forward price curves upon market price quotations when available and uses internally developed, modeled prices when market quotations are unavailable. In general, PacifiCorp estimates the fair value of a contract by calculating the present value of the difference between the contract and the applicable forward price curve.

Price quotations for certain major electricity trading hubs are generally readily obtainable for the first six years and, therefore, PacifiCorp’s forward price curves for those locations and periods reflect observable market quotes. However, in the later years or for locations that are not actively traded, forward price curves must be estimated in other ways. For short-term contracts at less actively traded locations, prices are modeled based on observed historical price relationships with actively traded locations. For long-term contracts extending beyond six years, the forward price curve is based upon the use of a fundamentals model (cost-to-build approach), due to the limited information available. Factors used in the fundamentals model include the forward prices for the commodities used as fuel to generate electricity, the expected system heat rate (which measures the efficiency of power plants in converting fuel to electricity) in the region where the purchase or sale takes place and a fundamentals forecast of expected spot prices for a commodity in a region based on modeled supply of and demand for the commodity in the region. The assumptions in these models are critical, since any changes in assumptions could have a significant impact on the fair value of the contract.

Despite the large volume of implementation guidance, SFAS 133 and the supplemental guidance do not provide specific guidance on all contract issues. As a result, significant judgment must be used in applying SFAS 133 and its interpretations.

Item 3. Quantitative and Qualitative Disclosures About Market Risk.

For quantitative and qualitative disclosures about market risk affecting the Company, see Item 7A, “Qualitative and Quantitative Disclosures About Market Risk,” included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2005. The Company’s exposure to market risk has not changed materially since December 31, 2005, except as it relates to the acquisition of PacifiCorp.

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

PacifiCorp is subject to the various risks inherent in the energy business, including credit risk, interest rate risk and commodity price risk. The risk management process established by PacifiCorp is designed to identify, assess, monitor, report, manage and mitigate each of the various types of risk involved in its businesses. To assist in managing the volatility relating to these exposures, PacifiCorp enters into various transactions, including derivative transactions, consistent with PacifiCorp’s risk management policy and procedures. The risk management policy governs energy transactions and is designed for hedging PacifiCorp’s existing energy and asset exposures, and to a limited extent, the policy permits arbitrage activities to take advantage of market inefficiencies. In July 2006, PacifiCorp expanded its policy to permit both arbitrage and trading activities within the limits established in the risk management policy. The policy and procedures also govern PacifiCorp’s use of derivative instruments for commodity derivative transactions, as well as its energy purchase and sales practices, and describe PacifiCorp’s credit policy and management information systems required to effectively monitor such derivative use. PacifiCorp’s risk management policy provides for the use of only those instruments that have a similar volume or price relationship to its portfolio of assets, liabilities or anticipated transactions, thereby ensuring that such instruments will be primarily used for hedging. PacifiCorp’s portfolio of energy derivatives is substantially used for non-trading purposes.

53

PacifiCorp continues to actively manage its exposure to commodity price volatility. These activities may include adding to the generation portfolio and entering into transactions that help to shape PacifiCorp’s system resource portfolio, including wholesale contracts and financially settled temperature-related derivative instruments that reduce volume and price risk due to weather extremes.

Credit Risk

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

To mitigate exposure to the financial risks of wholesale counterparties, PacifiCorp has entered into netting and collateral arrangements that include margining and cross-product netting agreements and obtaining third-party guarantees, letters of credit and cash deposits. Counterparties may be assessed interest fees for delayed receipts. If required, PacifiCorp exercises rights under these arrangements, including calling on the counterparty’s credit support arrangement. At September 30, 2006, 73.9% of PacifiCorp’s unsecured credit exposure, net of collateral, within its electricity and natural gas portfolio of purchase and sale contracts was with counterparties having “investment grade” credit ratings from at least one major credit rating agency.

Interest Rate Risk

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

As of September 30, 2006, PacifiCorp had fixed-rate long-term debt of $3,755.2 million in aggregate principal amount and having a fair value of $3,955.6 million. These instruments have fixed interest rates and therefore do not expose PacifiCorp to the risk of earnings loss due to changes in market interest rates. However, the fair value of these instruments would decrease by approximately $132 million if interest rates were to increase by 10% from their levels at September 30, 2006. In general, such a decrease in fair value would impact earnings and cash flows only if PacifiCorp were to reacquire all or a portion of these instruments prior to their maturity.

As of September 30, 2006, PacifiCorp had $621.4 million of variable-rate liabilities and $59.8 million of temporary cash investments and had no financial derivatives in effect relating to interest rate exposure. Based on a sensitivity analysis as of September 30, 2006, for a one-year horizon, PacifiCorp estimates that if market interest rates average 1.0% higher (lower), interest expense, net of offsetting impacts on interest income, would increase (decrease) by $5.6 million. This amount includes the effect of invested cash and was determined by considering the impact of the hypothetical interest rates on the variable-rate securities outstanding as of September 30, 2006. If interest rates changed significantly, PacifiCorp might take actions to manage its exposure to the change. However, due to the uncertainty of the specific actions that might be taken and their possible effects, the sensitivity analysis assumes no changes in PacifiCorp’s financial structure.

54

Commodity Price Risk

PacifiCorp’s exposure to market risk due to commodity price change is primarily related to its fuel and electricity commodities, which are subject to fluctuations due to unpredictable factors, such as weather, electricity demand and plant performance, that affect energy supply and demand. PacifiCorp’s energy purchase and sales activities are governed by PacifiCorp’s risk management policy and the risk levels established as part of that policy.

PacifiCorp’s energy commodity price exposure arises primarily from its electric supply obligation in the western United States. PacifiCorp manages this risk principally through the operation of its generation plants with a net capacity owned of 8,550.4 MW, as well as transmission rights held both on some of its own approximately 15,600-mile transmission system and on third-party transmission systems, and through its wholesale energy purchase and sales activities. Wholesale contracts are utilized primarily to balance PacifiCorp’s physical excess or shortage of net electricity for future time periods. Financially settled contracts are utilized to further mitigate commodity price risk. PacifiCorp may from time to time enter into other financially settled, temperature-related derivative instruments that reduce volume and price risk on days with weather extremes. In addition, a financially settled hydroelectric streamflow hedge was in place through September 2006 to reduce volume and price risks associated with PacifiCorp’s hydroelectric generation resources.

The fair value of derivative instruments is determined using forward price curves. Forward price curves represent PacifiCorp’s estimates of the prices at which a buyer or seller could contract today for delivery or settlement of a commodity at future dates. PacifiCorp bases its forward price curves upon market price quotations when available and internally developed and commercial models with internal and external fundamental data inputs when market quotations are unavailable. In general, PacifiCorp estimates the fair value of a contract by calculating the present value of the difference between the prices in the contract and the applicable forward price curve. Price quotations for certain major electricity trading hubs are generally readily obtainable for the first six years, and therefore PacifiCorp’s forward price curves for those locations and periods reflect observable market quotes. However, in the later years or for locations that are not actively traded, PacifiCorp must develop forward price curves. For short-term contracts at less actively traded locations, prices are modeled based on observed historical price relationships with actively traded locations. For long-term contracts extending beyond six years, the forward price curve is based upon the use of a fundamentals model (cost-to-build approach) due to the limited information available.

Factors used in the fundamentals model include the forward prices for the commodities used as fuel to generate electricity, the expected system heat rate (which measures the efficiency of electricity plants in converting fuel to electricity) in the region where the purchase or sale takes place and a fundamental forecast of expected spot prices based on modeled supply and demand in the region. The assumptions in these models are critical since any changes to the assumptions could have a significant impact on the fair value of the contract. Contracts with explicit or embedded optionality are valued by separating each contract into its physical and financial forward and option components. Forward components are valued against the appropriate forward price curve. The optionality is valued using a modified Black-Scholes model or a stochastic simulation (Monte Carlo) approach. Each option component is modeled and valued separately using the appropriate forward price curve. PacifiCorp’s valuation models and assumptions are continuously updated to reflect current market information, and evaluations and refinements of model assumptions are performed on a periodic basis.

The following table shows summarized information with respect to contractual maturities of PacifiCorp’s energy-related contracts, primarily used for non-trading purposes, qualifying as derivatives under SFAS 133 as of September 30, 2006.

Maturity:
Less than 1 year	$	54.8
1-3 years		50.7
4-5 years		6.0
Excess of 5 years		(290.8	)
Total	$	(179.3	)
Regulatory net asset	$	212.5

55

Item 4. Controls and Procedures.

An evaluation was performed under the supervision and with the participation of the Company’s management, including the chief executive officer and chief financial officer, regarding the effectiveness of the design and operation of the Company’s disclosure controls and procedures (as defined in Rule 13a-15(e) promulgated under the Securities and Exchange Act of 1934, as amended) as of September 30, 2006. Based on that evaluation, the Company’s management, including the chief executive officer and chief financial officer, concluded that the Company’s disclosure controls and procedures were effective. As a result of the acquisition of PacifiCorp in the first quarter of 2006, the Company has expanded its internal control over financial reporting to include consolidation of the PacifiCorp results of operations, as well as acquisition related accounting and disclosures. There have been no other changes during the quarter covered by this report in the Company’s internal control over financial reporting that has materially affected, or is reasonably likely to materially affect, the Company’s internal control over financial reporting.

56

PART II - OTHER INFORMATION

Item 1. Legal Proceedings.

For a description of certain legal proceedings affecting the Company, please review Item 3, “Legal Proceedings” included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2005. In addition to the discussion contained herein, refer to Note 9, “Commitments and Contingencies,” to the Interim Financial Statements for additional information regarding the Company’s legal proceedings.

PacifiCorp

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

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

MidAmerican Funding

MidAmerican Energy was one of dozens of companies named as defendants in a January 20, 2004 consolidated class action lawsuit filed in the United States District Court for the Southern District of New York. The suit alleges that the defendants have engaged in unlawful manipulation of the prices of natural gas futures and options contracts traded on the New York Mercantile Exchange during the period January 1, 2000 to December 31, 2002. On September 9, 2005, MidAmerican Energy and counsel for the plaintiffs executed a stipulation and agreement of settlement, which upon final approval by the court following notice to all class members, MidAmerican Energy will be dismissed from the lawsuit. The court approved the settlement on a preliminary basis on February 8, 2006, and signed its final judgment and order of dismissal on May 24, 2006. No appeal of the order was filed within the applicable appeal period and, accordingly, the matter is concluded. MidAmerican Energy’s obligation to the plaintiffs was an immaterial amount.

On December 28, 2004, an apparent gas explosion and fire resulted in three fatalities, one serious injury and property damage at a commercial building in Ramsey, Minnesota. According to the Minnesota Office of Pipeline Safety, an improper installation of a pipeline connection may have been a cause of the explosion and fire. A predecessor company to MidAmerican Energy provided gas service in Ramsey, Minnesota at the time of the original installation in 1980. In 1993, a predecessor of CenterPoint Energy, Inc. (“CenterPoint”) acquired all of the Minnesota gas properties owned by the MidAmerican Energy predecessor company.

57

As a result of the explosion and fire, MidAmerican Energy and CenterPoint received settlement demands which totaled $15.5 million. MidAmerican Energy’s exposure, if any, to these demands are covered under its liability insurance coverage to which a $2.0 million retention applies. In addition, counsel for CenterPoint stated that a replacement program has been initiated for the purpose of locating and replacing all mechanical couplings in the former North Central Public Service Company properties located in Minnesota. Counsel for CenterPoint has represented that the value of the replacement claim may be in the range of $35-$45 million.

Two lawsuits naming MidAmerican Energy as a defendant are currently on file related to this incident. On February 8, 2006, MidAmerican Energy was served with a Third Party Complaint filed in U.S. District Court, District of Minnesota, by CenterPoint Resources Corp. d/b/a CenterPoint Energy. The Third Party Complaint seeks contribution and indemnity on a wrongful death claim filed by the estate of one of the decedents and all sums associated with CenterPoint’s replacement program. MidAmerican Energy was served with a second Third Party Complaint filed in U.S. District Court, District of Minnesota, by CenterPoint seeking contribution and indemnity on a property damage and business interruption claim filed by Ramsey Premier Partners, LLC, and all sums associated with CenterPoint’s replacement program. MidAmerican Energy’s motion for summary judgment filed in both of these cases has been heard by the court and a decision is pending. All claims arising from this incident have been settled by CenterPoint pursuant to Confidential Orders and Agreements; however, the Third Party actions by CenterPoint Energy Resources Corp. against MidAmerican Energy remain. MEHC and MidAmerican Energy intend to vigorously defend the Company’s position in these lawsuits and believe their ultimate outcome will not have a material impact on the Company’s results of operations, financial position or cash flows.

Item 1A. Risk Factors.

There has been no material change to the Company’s risk factors from those disclosed in the Company’s Annual Report on Form 10-K for the year ended December 31, 2005, except for those related to the acquisition and businesses of PacifiCorp, which was consummated on March 21, 2006. The Company’s risk factors after consummation of the acquisition of PacifiCorp are incorporated by reference into this Item 1A by reference to Exhibit 20.1 to MEHC’s Current Report on Form 8-K dated March 17, 2006.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds.

Not applicable.

Item 3. Defaults Upon Senior Securities.

Not applicable.

Item 4. Submission of Matters to a Vote of Security Holders.

Not applicable.

Item 5. Other Information.

Not applicable.

Item 6. Exhibits.

The exhibits listed on the accompanying Exhibit Index are filed as part of this Quarterly Report.

58

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 thereunto duly authorized.

	MIDAMERICAN ENERGY HOLDINGS COMPANY
	(Registrant)
Date:  November 3, 2006	/s/ Patrick J. Goodman
	Patrick J. Goodman
	Senior Vice President and Chief Financial Officer

59

EXHIBIT INDEX

Exhibit No.	Description
31.1	Chief Executive Officer’s Certificate Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2	Chief Financial Officer’s Certificate Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1	Chief Executive Officer’s Certificate Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2	Chief Financial Officer’s Certificate Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

60