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, 2008

or

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

For the transition period from ______ to _______

Commission	Exact name of registrant as specified in its charter;	IRS Employer
File Number	State or other jurisdiction of incorporation or organization	Identification No.
001-14881	MIDAMERICAN ENERGY HOLDINGS COMPANY	94-2213782
	(An Iowa Corporation)
	666 Grand Avenue, Suite 500
	Des Moines, Iowa 50309-2580
	515-242-4300
N/A
(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  T  No  ¨

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

Large accelerated filer ¨ Accelerated filer ¨ Non-accelerated filer T Smaller reporting company ¨

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 31, 2008, 74,859,001 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	26
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	44
Item 4(T).	Controls and Procedures	45
PART II - OTHER INFORMATION
Item 1.	Legal Proceedings	46
Item 1A.	Risk Factors	47
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	47
Item 3.	Defaults Upon Senior Securities	47
Item 4.	Submission of Matters to a Vote of Security Holders	47
Item 5.	Other Information	47
Item 6.	Exhibits	47
Signatures		48
Exhibit Index		49

2

PART I – FINANCIAL INFORMATION

Item 1.  Financial Statements

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders

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, 2008, and the related consolidated statements of operations for the three-month and nine-month periods ended September 30, 2008 and 2007, and of shareholders’ equity and cash flows for the nine-month periods ended September 30, 2008 and 2007. 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, 2007, and the related consolidated statements of operations, shareholders’ equity, and cash flows for the year then ended (not presented herein); and in our report dated February 27, 2008, we expressed an unqualified opinion on those consolidated financial statements, which included an explanatory paragraph related to the adoption of Statement of Financial Accounting Standards No. 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans – an amendment of FASB Statements No. 87, 88, 106, and 132(R), as of December 31, 2006. In our opinion, the information set forth in the accompanying consolidated balance sheet as of December 31, 2007, 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 7, 2008

3

MIDAMERICAN ENERGY HOLDINGS COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (Unaudited)

(Amounts in millions)

	As of
	September 30,		December 31,
	2008		2007
ASSETS
Current assets:
Cash and cash equivalents	$	531	$	1,178
Trade receivables, net		1,243		1,406
Inventories		553		476
Derivative contracts		207		170
Guaranteed investment contract		-		397
Other current assets		564		525
Deferred income taxes		244		162
Total current assets		3,342		4,314
Property, plant and equipment, net		28,020		26,221
Goodwill		5,210		5,339
Regulatory assets		1,681		1,503
Derivative contracts		148		227
Deferred charges, investments and other assets		2,601		1,612
Total assets	$	41,002	$	39,216

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,
	2008			2007
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Accounts payable	$	992		$	1,063
Accrued interest		359			341
Accrued property, income and other taxes		314			230
Derivative contracts		214			266
Provision for rate refunds		204			191
Other current liabilities		714			625
Short-term debt		397			130
Current portion of long-term debt		434			1,966
Current portion of MEHC subordinated debt		234			234
Total current liabilities		3,862			5,046
Regulatory liabilities		1,639			1,629
Derivative contracts		499			499
Other long-term liabilities		1,263			1,372
MEHC senior debt		5,121			4,471
MEHC subordinated debt		1,726			891
Subsidiary debt		12,737			12,131
Deferred income taxes		3,954			3,595
Total liabilities		30,801			29,634
Minority interest		139			128
Preferred securities of subsidiaries		128			128
Commitments and contingencies (Notes 3, 5 and 10)
Shareholders’ equity:
Common stock - 115 shares authorized, no par value, 75 shares issued and outstanding		-			-
Additional paid-in capital		5,455			5,454
Retained earnings		4,694			3,782
Accumulated other comprehensive (loss) income, net		(215	)		90
Total shareholders’ equity		9,934			9,326
Total liabilities and shareholders’ equity	$	41,002		$	39,216

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,
	2008			2007			2008			2007
Operating revenue	$	3,240		$	3,067		$	9,588		$	9,294
Operating costs and expenses:
Cost of sales		1,537			1,379			4,566			4,279
Operating expense		664			705			2,058			2,112
Depreciation and amortization		268			287			838			871
Total operating costs and expenses		2,469			2,371			7,462			7,262
Operating income		771			696			2,126			2,032
Other income (expense):
Interest expense		(340	)		(336	)		(998	)		(976	)
Capitalized interest		14			13			37			43
Interest and dividend income		16			33			47			75
Other income		21			31			66			86
Other expense		(2	)		(2	)		(7	)		(6	)
Total other income (expense)		(291	)		(261	)		(855	)		(778	)
Income before income tax expense, minority interest and preferred dividends of subsidiaries and equity income		480			435			1,271			1,254
Income tax expense		149			68			378			328
Minority interest and preferred dividends of subsidiaries		5			5			14			22
Equity income		(24	)		(22	)		(33	)		(34	)
Net income	$	350		$	384		$	912		$	938

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

6

MIDAMERICAN ENERGY HOLDINGS COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY (Unaudited)

FOR THE NINE-MONTH PERIODS ENDED SEPTEMBER 30, 2008 AND 2007

(Amounts in millions)

										Accumulated
	Outstanding				Additional					Other
	Common		Common		Paid-in		Retained			Comprehensive
	Shares		Stock		Capital		Earnings			(Loss) Income, Net			Total
Balance, January 1, 2007		74	$	-	$	5,420	$	2,598		$	(7	)	$	8,011
Adoption of FASB Interpretation No. 48		-		-		-		(5	)		-			(5	)
Net income		-		-		-		938			-			938
Other comprehensive income		-		-		-		-			136			136
Other equity transactions		-		-		4		-			-			4
Balance, September 30, 2007		74	$	-	$	5,424	$	3,531		$	129		$	9,084
Balance, January 1, 2008		75	$	-	$	5,454	$	3,782		$	90		$	9,326
Net income		-		-		-		912			-			912
Other comprehensive loss		-		-		-		-			(305	)		(305	)
Other equity transactions		-		-		1		-			-			1
Balance, September 30, 2008		75	$	-	$	5,455	$	4,694		$	(215	)	$	9,934

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,
	2008			2007
Cash flows from operating activities:
Net income	$	912		$	938
Adjustments to reconcile net income to net cash flows from operations:
Gain on other items, net		(24	)		(10	)
Depreciation and amortization		838			871
Amortization of regulatory assets and liabilities		(31	)		(13	)
Provision for deferred income taxes		440			42
Other		20			(38	)
Changes in other items, net of effects from acquisition:
Trade receivables and other current assets		37			(106	)
Accounts payable and other accrued liabilities		(187	)		212
Net cash flows from operating activities		2,005			1,896
Cash flows from investing activities:
Capital expenditures		(2,678	)		(2,522	)
Acquisition, net of cash acquired		(308	)		-
Purchases of available-for-sale securities		(177	)		(1,599	)
Proceeds from sale of available-for-sale securities		179			1,537
Proceeds from maturity of guaranteed investment contract		393			-
Purchase of Constellation Energy preferred stock investment		(1,000	)		-
Proceeds from sale of assets		40			65
(Increase) decrease in restricted cash		(34	)		77
Other		16			(5	)
Net cash flows from investing activities		(3,569	)		(2,447	)
Cash flows from financing activities:
Proceeds from MEHC senior and subordinated debt		1,649			1,539
Repayments of MEHC senior and subordinated debt		(1,167	)		(167	)
Proceeds from subsidiary debt		1,498			1,400
Repayments of subsidiary debt		(997	)		(250	)
Purchases of subsidiary debt		(216	)		-
Net (payment of) proceeds from hedging instruments		(99	)		32
Net repayments of MEHC revolving credit facility		-			(152	)
Net proceeds from (repayments of) subsidiary short-term debt		274			(194	)
Other		(22	)		(27	)
Net cash flows from financing activities		920			2,181
Effect of exchange rate changes		(3	)		5
Net change in cash and cash equivalents		(647	)		1,635
Cash and cash equivalents at beginning of period		1,178			343
Cash and cash equivalents at end of period	$	531			1,978

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

MidAmerican Energy Holdings Company (“MEHC”) is a holding company which owns subsidiaries that are principally engaged in energy businesses. MEHC and its subsidiaries are referred to as the “Company.” MEHC is a consolidated subsidiary of Berkshire Hathaway Inc. (“Berkshire Hathaway”). The Company is 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 (owning a majority interest in the Casecnan project), CalEnergy Generation-Domestic (owning interests in independent power projects in the United States) and HomeServices of America, Inc. (collectively with its subsidiaries, “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 interstate natural gas pipeline companies in the United States, two electricity distribution companies in Great Britain, a diversified portfolio of independent power projects and the second largest residential real estate brokerage firm in the United States.

The unaudited Consolidated Financial Statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) for interim financial information and the United States Securities and Exchange Commission’s (“SEC”) rules and regulations for Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the disclosures required by GAAP for annual financial statements. Management believes the unaudited Consolidated Financial Statements contain all adjustments (consisting only of normal recurring adjustments) considered necessary for the fair presentation of the financial statements as of September 30, 2008, and for the three- and nine-month periods ended September 30, 2008 and 2007. Certain amounts in the prior period Consolidated Financial Statements have been reclassified to conform to the current period presentation. Such reclassifications did not impact previously reported operating income, net income or retained earnings. The results of operations for the three- and nine-month periods ended September 30, 2008 are not necessarily indicative of the results to be expected for the full year.

The unaudited Consolidated Financial Statements include the accounts of MEHC and its subsidiaries in which it holds a controlling financial interest. The Consolidated Statements of Operations include the revenues and expenses of an acquired entity from the date of acquisition. Intercompany accounts and transactions have been eliminated.

The preparation of the unaudited Consolidated Financial Statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the period. Actual results may differ from the estimates used in preparing the unaudited Consolidated Financial Statements. Note 2 of Notes to Consolidated Financial Statements included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2007 describes the most significant accounting estimates and policies used in the preparation of the Consolidated Financial Statements. There have been no significant changes in the Company’s assumptions regarding significant accounting policies during the first nine months of 2008.

(2) New Accounting Pronouncements

In March 2008, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards (“SFAS”) No. 161, “Disclosures about Derivative Instruments and Hedging Activities – an amendment of FASB Statement No. 133” (“SFAS No. 161”). SFAS No. 161 is intended to improve financial reporting about derivative instruments and hedging activities by requiring enhanced disclosures to enable investors to better understand how and why an entity uses derivative instruments and their effects on an entity’s financial position, financial performance and cash flows. SFAS No. 161 is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008, with early application encouraged. The Company is currently evaluating the impact of adopting SFAS No. 161 on its disclosures included within the notes to its Consolidated Financial Statements.

9

In December 2007, the FASB issued SFAS No. 141(R), “Business Combinations” (“SFAS No. 141(R)”). SFAS No. 141(R) applies to all transactions or other events in which an entity obtains control of one or more businesses. SFAS No. 141(R) establishes how the acquirer of a business should recognize, measure and disclose in its financial statements the identifiable assets and goodwill acquired, the liabilities assumed and any noncontrolling interest in the acquired business. SFAS No. 141(R) is applied prospectively for all business combinations with an acquisition date on or after the beginning of the first annual reporting period beginning on or after December 15, 2008, with early application prohibited. SFAS No. 141(R) will not have an impact on the Company’s historical Consolidated Financial Statements and will be applied to business combinations completed, if any, on or after January 1, 2009.

In December 2007, the FASB issued SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements – an amendment of ARB No. 51” (“SFAS No. 160”). SFAS No. 160 establishes accounting and reporting standards for the noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary. SFAS No. 160 requires entities to report noncontrolling interests as a separate component of shareholders’ equity in the consolidated financial statements. The amount of earnings attributable to the parent and to the noncontrolling interests should be clearly identified and presented on the face of the consolidated statements of operations. Additionally, SFAS No. 160 requires any changes in a parent’s ownership interest of its subsidiary, while retaining its control, to be accounted for as equity transactions. SFAS No. 160 is effective for fiscal years beginning on or after December 15, 2008 and interim periods within those fiscal years. The Company is currently evaluating the impact of adopting SFAS No. 160 on its consolidated financial position and results of operations.

In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities - including an amendment of FASB Statement No. 115” (“SFAS No. 159”). SFAS No. 159 permits entities to elect to measure many financial instruments and certain other items at fair value. Upon adoption of SFAS No. 159, an entity may elect the fair value option for eligible items that exist at the adoption date. Subsequent to the initial adoption, the election of the fair value option may only be made at initial recognition of the asset or liability or upon a remeasurement event that gives rise to new-basis accounting. The decision about whether to elect the fair value option is applied on an instrument-by-instrument basis, is irrevocable and is applied only to an entire instrument and not only to specified risks, cash flows or portions of that instrument. SFAS No. 159 does not affect any existing accounting literature that requires certain assets and liabilities to be carried at fair value nor does it eliminate disclosure requirements included in other accounting standards. The Company adopted SFAS No. 159 effective January 1, 2008, and did not elect the fair value option for any existing eligible items.

In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements” (“SFAS No. 157”). SFAS No. 157 defines fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements. SFAS No. 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. Under SFAS No. 157, fair value refers to the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants in the principal or most advantageous market. The standard clarifies that fair value should be based on the assumptions market participants would use when pricing the asset or liability. In February 2008, the FASB issued Staff Position (“FSP”) No. 157-2, “Effective Date of FASB Statement No. 157” (“FSP FAS 157-2”), which delays the effective date of SFAS No. 157 for all non-financial assets and liabilities, except those that are recognized or disclosed at fair value in the consolidated financial statements on a recurring basis, until fiscal years beginning after November 15, 2008. These non-financial items include assets and liabilities such as non-financial assets and liabilities assumed in a business combination, reporting units measured at fair value in a goodwill impairment test and asset retirement obligations initially measured at fair value. In October 2008, the FASB issued FSP No. 157-3, “Determining the Fair Value of a Financial Asset When the Market for That Asset Is Not Active” (“FSP FAS 157-3”), which clarifies the application of SFAS No. 157 in a market that is not active and provides an example to illustrate key considerations in determining the fair value of a financial asset when the market for that financial asset is not active. FSP FAS 157-3 was effective upon issuance, including prior periods for which financial statements had not been issued. The Company applied the guidance of FSP FAS 157-3 when determining the fair value of its auction rate securities. The Company adopted the provisions of SFAS No. 157 for assets and liabilities recognized at fair value on a recurring basis effective January 1, 2008. The partial adoption of SFAS No. 157 did not have a material impact on the Company’s Consolidated Financial Statements. Refer to Note 8 for additional discussion.

In September 2006, the FASB issued 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 No. 158”). SFAS No. 158 requires that an employer measure plan assets and obligations as of the end of the employer’s fiscal year, eliminating the option in SFAS No. 87 and SFAS No. 106 to measure up to three months prior to the financial statement date. The requirement to measure plan assets and benefit obligations as of the date of the employer’s fiscal year-end is not required until fiscal years ending after December 15, 2008. As of September 30, 2008, PacifiCorp had not yet adopted the measurement date provisions of the statement. Upon adoption of the measurement date provisions, PacifiCorp will be required to record a transitional adjustment to retained earnings or to a regulatory asset depending on whether the amount is considered probable of being recovered in rates.

10

(3) Acquisitions

Constellation Energy Group, Inc.

Constellation Energy Group, Inc. (“Constellation Energy”) is an energy company which includes a merchant energy business and Baltimore Gas and Electric Company, a regulated electric and gas public utility in central Maryland which transmits and distributes electricity to approximately 1.2 million customers and provides retail natural gas service to approximately 0.6 million customers. As of December 31, 2007, Constellation Energy had approximately $22 billion of assets and 8,728 megawatts (“MW”) of owned generating facilities. Constellation Energy’s merchant energy business is a competitive provider of energy solutions for a variety of customers. Constellation Energy’s merchant energy business includes a power generation and development operation that owns, operates, and maintains fossil and renewable generating facilities, and holds interests in qualifying facilities, fuel processing facilities and power projects in the United States. It also includes a nuclear generation operation that owns, operates and maintains nuclear generating facilities, a customer supply operation that primarily provides energy products and services relating to load-serving obligations to wholesale and retail customers, including distribution utilities, cooperatives, aggregators, and commercial, industrial and governmental customers and a global commodities operation that manages contractually controlled physical assets, including generation facilities, natural gas properties and international coal and freight assets, provides risk management services, trades energy and energy-related commodities and deploys risk capital by taking speculative trading positions where it identifies opportunities in certain markets.

On September 19, 2008, MEHC, Constellation Energy and MEHC Merger Sub Inc. (“Merger Sub”) signed an Agreement and Plan of Merger (the “Merger Agreement”), which provides that Merger Sub will merge with and into Constellation Energy. As a result of the merger, Constellation Energy will become a wholly-owned subsidiary of MEHC. Constellation Energy will be the surviving corporation in the merger and, following the merger, will continue to do business as “Constellation Energy Group, Inc.” In addition, following completion of the merger, the registration of Constellation Energy common stock and its reporting obligations with respect to such common stock under the Securities Exchange Act of 1934, as amended, will be terminated upon application to the SEC. Upon completion of the proposed merger, shares of Constellation Energy common stock will no longer be listed on any stock exchange or quotation system, including the New York Stock Exchange. If the merger is completed, MEHC would purchase all of the outstanding shares of Constellation Energy common stock for cash consideration of approximately $4.7 billion, or $26.50 per share. MEHC will finance the $4.7 billion merger consideration through the issuance of approximately $2.7 billion of its common stock to Berkshire Hathaway and potentially to its other existing shareholders and the issuance of $2.0 billion of 11% trust preferred securities to Berkshire Hathaway.

The merger requires the affirmative vote of holders of a majority of the outstanding shares of Constellation Energy common stock. A special meeting of Constellation Energy’s common shareholders is expected to be held in the fourth quarter of 2008 or the first quarter of 2009. The approval of the following federal, state, local and international regulatory authorities, among others, also must be obtained before the merger can be completed:

·   the Federal Energy Regulatory Commission (“FERC”);

·   the Nuclear Regulatory Commission (“NRC”);

·   the Federal Communications Commission;

·   the Hart-Scott-Rodino Antitrust Improvements Act of 1976 (“HSR Act”);

·   the state regulatory agencies in several of the states in which Constellation Energy operates electric or gas businesses, including the Maryland Public Service Commission; and

·   certain notifications and approvals under foreign competition and change in control laws, including those of the European Union.

All the necessary regulatory filings were made. The applicable HSR Act waiting period expired on October 31, 2008 with no further action or requests by the Department of Justice. There are also several merger conditions that can be waived at the option of MEHC including, among others, the requirements that all unsecured senior debt of Constellation Energy be rated investment grade or better with no less than stable outlook and that there has not been a material deterioration in the value of the business as defined in the Merger Agreement. MEHC intends to complete the merger as soon as reasonably practicable and is working to close the transaction in the second quarter of 2009.

11

The Merger Agreement may be terminated at any time prior to the effective time of the merger pursuant to the terms and conditions of the Merger Agreement if the effective time of the merger has not occurred on or before June 19, 2009 (or September 19, 2009 if all conditions other than those relating to regulatory approvals, debt ratings or required consents have been fulfilled as of June 19, 2009), unless the party seeking to terminate under this provision shall have proximately contributed to the failure of the effective time of the merger to occur on or before such applicable date. Constellation Energy has agreed to pay MEHC a termination fee of $175 million if the Merger Agreement is terminated for any reason other than by Constellation Energy because of MEHC’s or Merger Sub’s breach of any representation, warranty, covenant or other agreement made by MEHC or Merger Sub.

On September 19, 2008, MEHC and Constellation Energy entered into a stock purchase agreement pursuant to which Constellation Energy agreed to sell $1.0 billion of its Series A Preferred Stock (“Constellation Energy Series A Preferred Stock”) to MEHC. On September 22, 2008, MEHC assigned its rights and obligations under the stock purchase agreement to MEHC Investment, Inc., a wholly-owned subsidiary of MEHC. This sale was consummated on September 22, 2008. If the Merger Agreement is terminated (other than due to a breach by MEHC or Merger Sub), or upon the occurrence of other specified events, the Constellation Energy Series A Preferred Stock will, subject to the receipt of all required regulatory approvals, automatically convert into (a) 35,506,757 shares of Constellation Energy common stock (representing approximately 19.9% of the number of shares of Constellation Energy common stock that were outstanding on September 22, 2008, or approximately 16.6% on an as-converted basis), subject to certain adjustments, and (b) $1.0 billion in aggregate principal amount of senior unsecured promissory notes of Constellation Energy due December 31, 2009. The Constellation Energy Series A Preferred Stock pays dividends at 8% per annum compounded quarterly and payable quarterly in arrears. In the event that Constellation Energy has not received all regulatory approvals required for the issuance of shares of common stock upon conversion of the Constellation Energy Series A Preferred Stock, Constellation Energy will be required to make a cash payment to MEHC Investment, Inc. in lieu of the issuance of the shares that are otherwise due to MEHC Investment, Inc. in an amount equal to $26.50 multiplied by the number of shares issuable and not so issued. In such event, Constellation Energy would also still be obligated to deliver the 14% Senior Notes upon such conversion. The preferred stock is mandatorily redeemable on September 22, 2010 for an amount of cash equal to 100% of the stated value, subject to adjustments, plus accrued, but unpaid dividends.

Under the articles supplementary that designated certain preferences, conversion and other rights, and the terms of the Constellation Energy Series A Preferred Stock and the Investor Rights Agreement, dated as of September 19, 2008, by and between Constellation Energy and MEHC, the number of members of Constellation Energy’s board of directors was initially increased by one, and MEHC has the right to nominate one individual to the new directorship so long as MEHC and its affiliates beneficially own at least 33.3% of the shares of Constellation Energy Series A Preferred Stock that were originally issued to MEHC Investment Inc. If MEHC does not exercise its right to nominate one individual to the new directorship, it may appoint a board observer who has the right to attend and participate in all meetings of, and receive all material distributed to, Constellation Energy’s board of directors (subject to customary exceptions), but will not be entitled to vote at meetings of the board of directors or any committees thereof. As of the date of this filing, MEHC has not exercised its right to nominate a director or appoint a board observer.

The Constellation Energy Series A Preferred Stock generally does not have voting rights, but the consent of holders of such stock is required for specified matters in accordance with the terms of the articles supplementary. The holders of Constellation Energy Series A Preferred Stock do not have the right to vote with respect to the merger.

In November 2008, MEHC entered into an agreement which allows Constellation Energy to sell to MEHC certain generating assets at predetermined prices for up to $350 million of cash.

BYD Company Limited

In September 2008, MEHC reached a definitive agreement with BYD Company Limited (“BYD”) to purchase 225 million shares, representing approximately a 10% interest in the company, at a price of HK$8 per share or HK$1.8 billion (approximately $230 million). Established in 1995, BYD is a Hong Kong listed high-tech company with two main businesses: information technology manufacturer and auto manufacturer. BYD has seven production bases in Guangdong, Beijing, Shanghai, and Xi’an and has offices in America, Europe, Japan, South Korea, India, Taiwan, Hong Kong and other regions. BYD has over 130,000 employees. The purchase is subject to certain conditions precedent, most significantly the approval by affirmative vote of holders of two thirds of the outstanding shares of BYD. An extraordinary general meeting of the holders of BYD’s shares will be held on December 3, 2008. In the event that the conditions precedent are not fulfilled by March 26, 2009 the parties are not bound to proceed with the transaction. MEHC expects the transaction to close in January 2009.

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Chehalis Power Generating, LLC

On September 15, 2008, after having received the requisite regulatory approvals, PacifiCorp acquired from TNA Merchant Projects, Inc., an affiliate of Suez Energy North America, Inc., 100% of the equity interests of Chehalis Power Generating, LLC, an entity owning a 520-MW natural gas-fired generating plant located in Chehalis, Washington. The total cash purchase price was $308 million and the estimated fair value of the acquired entity was primarily allocated to the generating plant. Chehalis Power Generating, LLC was merged into PacifiCorp immediately following the acquisition. The results of the plant’s operations have been included in the Company’s Consolidated Financial Statements since the acquisition date.

(4) Property, Plant and Equipment, Net

Property, plant and equipment, net consist of the following (in millions):

	Depreciation	September 30,			December 31,
	Life	2008			2007
Regulated assets:
Utility generation, distribution and transmission system	5-85 years	$	31,702		$	30,369
Interstate pipeline assets	3-67 years		5,523			5,484
			37,225			35,853
Accumulated depreciation and amortization			(12,563	)		(12,280	)
Regulated assets, net			24,662			23,573
Non-regulated assets:
Independent power plants	10-30 years		680			680
Other assets	3-30 years		609			650
			1,289			1,330
Accumulated depreciation and amortization			(453	)		(427	)
Non-regulated assets, net			836			903
Net operating assets			25,498			24,476
Construction in progress			2,522			1,745
Property, plant and equipment, net		$	28,020		$	26,221

Substantially all of the construction in progress as of September 30, 2008 and December 31, 2007 relates to the construction of regulated assets.

(5) Regulatory Matters

The following are updates to regulatory matters based upon material changes that occurred subsequent to December 31, 2007.

Refund Matters

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 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 95% load factor for vintage shippers and a 3% inflation factor for operating and maintenance costs. Kern River and other parties filed their requests for rehearing of the initial order on November 20, 2006. On April 18, 2008, the FERC issued an order denying rehearing on the issues raised by Kern River and other parties to the proceeding except Kern River’s request to include master limited partnerships in the proxy group for determining the allowed rate of return on equity. The grant of rehearing on this issue is consistent with the FERC’s April 17, 2008 adoption of a policy statement that addresses the inclusion of master limited partnerships in the proxy group used to determine a pipeline’s allowed return on equity. The FERC reopened the record for a paper hearing to determine Kern River’s return on equity in accordance with the policy statement. Initial, reply and rebuttal briefs were submitted by August 1, 2008. No order has yet been issued on the paper hearing.

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On September 30, 2008, Kern River filed an Offer of Settlement and Stipulation that was supported by a majority of the long-term shippers on Kern River’s system. In accordance with the terms of the settlement, those shippers that agreed to support the settlement will be charged the lower settlement rates beginning October 1, 2008. The settlement also includes a five year moratorium on rate changes from the effective date of the settlement and establishes a hearing process to define future rates for contracts that will be effective beginning in 2011.

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. Kern River has recorded a provision for rate refunds totaling $204 million as of September 30, 2008 and $191 million as of December 31, 2007. Subsequent to September 30, 2008, Kern River has paid rate refunds of $149 million to shippers that supported the settlement. Refunds will be paid to other shippers that subsequently agree to support the settlement. Non-supporting shippers will receive their refunds within 30 days after a final order on the settlement is issued. As of October 31, 2008, the settlement was supported, or not opposed, by Kern River’s shippers representing approximately 92% of contracted entitlement.

There is no statutory schedule for an ultimate order from the FERC. If the FERC does not apply the terms of the settlement to all of Kern River’s shippers, the settlement will terminate. If the settlement is terminated, the paper hearing will proceed and eventually the case will be concluded. In that instance, there is a “keep whole” provision in the settlement that will allow Kern River to recover all refunds paid, with interest.

Oregon Senate Bill 408

In October 2007, PacifiCorp filed its tax report for 2006 under Oregon Senate Bill 408 (“SB 408”), which was enacted in September 2005. SB 408 requires that PacifiCorp and other large regulated, investor-owned utilities that provide electric or natural gas service to Oregon customers file a report annually with the Oregon Public Utility Commission (the “OPUC”) comparing income taxes collected and income taxes paid, as defined by the statute and its administrative rules. PacifiCorp’s filing indicated that for the 2006 tax year, PacifiCorp paid $33 million more in federal, state and local taxes than was collected in rates from its retail customers. PacifiCorp proposed to recover $27 million of the deficiency over a one-year period starting June 1, 2008 and to defer any excess into a balancing account for future disposition. During the review process, PacifiCorp updated its filing to address the OPUC’s staff recommendations, which increased the initial request by $2 million for a total of $35 million. In April 2008, the OPUC approved PacifiCorp’s revised request with $27 million to be recovered over a one-year period beginning June 1, 2008 and the remainder to be deferred until a later period, with interest to accrue at PacifiCorp’s authorized rate of return. In June 2008, PacifiCorp recorded a $27 million regulatory asset and associated revenues representing the amount that PacifiCorp will collect from its Oregon retail customers over the one-year period that began on June 1, 2008. Since June 1, 2008, collections of the approved amount have reduced the regulatory asset initially recognized. In May 2008, the Industrial Customers of Northwest Utilities filed a petition for judicial review in the Court of Appeals of the State of Oregon challenging the OPUC order. Briefs are anticipated to be filed in late 2008. PacifiCorp believes the outcome of the judicial review will not have a material impact on its consolidated financial results.

In October 2008, PacifiCorp filed its tax report for 2007 under SB 408. PacifiCorp’s filing indicated that for the 2007 tax year, PacifiCorp paid $4 million more in federal, state and local taxes than was collected in rates from its retail customers.

(6) Recent Debt Transactions

On October 9, 2008, MidAmerican Energy entered into a revolving credit agreement, expiring October 8, 2009, for $250 million that provides support for additional commercial paper capacity.

On September 10, 2008, PacifiCorp acquired $216 million of its insured variable-rate pollution-control revenue bond obligations due to the significant reduction in market liquidity for insured variable-rate obligations.

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In September 2008, MEHC’s unsecured revolving credit facility was effectively reduced by $15 million in connection with Lehman Brothers Bank, FSB’s bankruptcy. As of September 30, 2008, the remaining $585 million unsecured revolving credit facility supports letters of credit totaling $44 million, leaving $541 million of the unsecured revolving credit facility available.

In September 2008, PacifiCorp’s unsecured revolving credit facilities were effectively reduced by $105 million in connection with Lehman Brothers Bank, FSB’s and Lehman Commercial Paper Inc.’s bankruptcies. The remaining $1,395 million unsecured revolving credit facilities supports PacifiCorp’s commercial paper program and its unenhanced variable-rate tax-exempt bond obligations. As of September 30, 2008, PacifiCorp had borrowed $117 million under its unsecured revolving credit facilities and $38 million was reserved for support of unenhanced variable-rate tax-exempt bond obligations outstanding, leaving $1,240 million of the unsecured revolving credit facilities available.

In the second quarter of 2008, MEHC and MidAmerican Energy each extended the maturity date of their respective unsecured revolving credit facilities by one year to July 2013. PacifiCorp also extended the maturity date of its $800 million unsecured revolving credit facility to July 2013. PacifiCorp’s $700 million unsecured revolving credit facility matures in October 2012.

On July 17, 2008, PacifiCorp issued $500 million of 5.65% first mortgage bonds due July 15, 2018 and $300 million of 6.35% first mortgage bonds due July 15, 2038. The net proceeds were used for general corporate purposes.

On July 15, 2008, Northern Natural Gas issued $200 million of 5.75% senior notes due July 15, 2018. The net proceeds were used to repay at maturity its $150 million, 6.75% senior notes due September 15, 2008 and the remainder is being used for general corporate purposes.

On July 1, 2008, the Iowa Finance Authority issued $45 million of variable-rate tax-exempt bonds due July 1, 2038, the proceeds of which were loaned to MidAmerican Energy and are restricted for the payment of qualified environmental construction costs. Also on July 1, 2008, the Iowa Finance Authority issued $57 million of variable-rate tax-exempt bonds due May 1, 2023 to refinance $57 million of pollution control revenue refunding bonds issued on behalf of MidAmerican Energy in 1993. These variable-rate tax-exempt bonds are remarketed and the interest rates reset on a weekly basis. As of September 30, 2008, the weighted average interest rate for these bonds was 8.25% and as of October 31, 2008 it was 2.22%. MidAmerican Energy is contractually responsible for the timely payment of principal and interest on these variable-rate tax-exempt bonds.

On April 1, 2008, MidAmerican Energy increased its unsecured revolving credit facility from $500 million to $650 million. In September 2008, MidAmerican Energy’s unsecured revolving credit facility was effectively reduced by $5 million in connection with Lehman Brothers Bank, FSB’s bankruptcy. The remaining $645 million unsecured revolving credit facility supports its commercial paper program and its variable-rate tax-exempt bond obligations. As of September 30, 2008, MidAmerican Energy had $235 million of commercial paper and $195 million was reserved for support of variable-rate tax-exempt bond obligations outstanding, leaving $215 million of the revolving credit facility available.

On March 28, 2008, MEHC issued $650 million of 5.75% senior notes due April 1, 2018. The net proceeds were used for general corporate purposes.

On March 25, 2008, MidAmerican Energy issued $350 million of 5.3% senior notes due March 15, 2018. The proceeds were used by MidAmerican Energy to pay construction costs, including costs for its wind-powered generation projects in Iowa, to repay short-term indebtedness and for general corporate purposes.

(7) Risk Management and Hedging Activities

The Company is exposed to the impact of market fluctuations in commodity prices, principally natural gas and electricity, particularly through its ownership of PacifiCorp and MidAmerican Energy. Interest rate risk exists on variable rate debt, commercial paper and future debt issuances. The Company is also exposed to foreign currency risk from its business operations and investments in Great Britain. The Company employs established policies and procedures to manage its risks associated with these market fluctuations using various commodity and financial derivative instruments, including forward contracts, futures, options, swaps and other over-the-counter agreements. The risk management process established by each business platform is designed to identify, assess, monitor, report, manage, and mitigate each of the various types of risk involved in its business. The Company does not engage in a material amount of proprietary trading activities.

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The following table summarizes the various derivative mark-to-market positions included in the Consolidated Balance Sheet as of September 30, 2008 (in millions):

											Accumulated
									Regulatory		Other
	Derivative Net Assets (Liabilities)(1)								Net Assets		Comprehensive
	Assets		Liabilities			Net			(Liabilities)		(Income) Loss(2)
Commodity	$	355	$	(710	)	$	(355	)	$	427	$	13
Interest rate swap		-		(3	)		(3	)		-		3
	$	355	$	(713	)	$	(358	)	$	427	$	16
Current	$	207	$	(214	)	$	(7	)
Noncurrent		148		(499	)		(351	)
Total	$	355	$	(713	)	$	(358	)

(1)	Derivative assets (liabilities) include $93 million of a net asset for cash collateral.
(2)	Before income taxes.

The following table summarizes the various derivative mark-to-market positions included in the Consolidated Balance Sheet as of December 31, 2007 (in millions):

												Accumulated
									Regulatory			Other
	Derivative Net Assets (Liabilities)								Net Assets			Comprehensive
	Assets		Liabilities			Net			(Liabilities)			(Income) Loss(1)
Commodity	$	396	$	(659	)	$	(263	)	$	277		$	(15	)
Foreign currency		1		(106	)		(105	)		(1	)		106
Total	$	397	$	(765	)	$	(368	)	$	276		$	91
Current	$	170	$	(266	)	$	(96	)
Non-current		227		(499	)		(272	)
Total	$	397	$	(765	)	$	(368	)

(1) Before income taxes.

(8) Fair Value Measurements

The Company has various financial instruments that are measured at fair value in the Consolidated Financial Statements, including marketable debt and equity securities and commodity derivatives. The Company’s financial assets and liabilities are measured using inputs from the three levels of the fair value hierarchy. A financial asset or liability classification within the hierarchy is determined based on the lowest level input that is significant to the fair value measurement. The three levels are as follows:

· Level 1 – Inputs are unadjusted quoted prices in active markets for identical assets or liabilities that the Company has the ability to access at the measurement date.

· Level 2 – Inputs include quoted prices for similar assets and liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability and inputs that are derived principally from or corroborated by observable market data by correlation or other means (market corroborated inputs).

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· Level 3 – Unobservable inputs reflect the Company’s judgments about the assumptions market participants would use in pricing the asset or liability since limited market data exists. The Company develops these inputs based on the best information available, including the Company’s own data.

The following table presents the Company’s assets and liabilities recognized in the Consolidated Balance Sheet and measured at fair value on a recurring basis as of September 30, 2008 (in millions):

	Input Levels for Fair Value Measurements
Description	Level 1			Level 2			Level 3			Other(1)			Total
Assets(2):
Available-for-sale securities	$	255		$	132		$	55		$	-		$	442
Commodity derivatives		6			434			205			(290	)		355
	$	261		$	566		$	260		$	(290	)	$	797
Liabilities:
Commodity derivatives	$	(50	)	$	(468	)	$	(551	)	$	359		$	(710	)
Interest rate swap		-			(3	)		-			-			(3	)
	$	(50	)	$	(471	)	$	(551	)	$	359		$	(713	)

(1)	Primarily represents netting under master netting arrangements and cash collateral requirements.
(2)	Does not include investments in either pension or other postretirement plan assets.

The Company’s investments in debt and equity securities are classified as available-for-sale and stated at fair value. When available, the quoted market price or net asset value of an identical security in the principal market is used to record the fair value. In the absence of a quoted market price in a readily observable market, the fair value is determined using pricing models based on observable market inputs and quoted market prices of securities with similar characteristics. The fair value of the Company’s investments in auction rate securities, where there is no current liquid market, is determined using pricing models based on available observable market data and the Company’s judgment about the assumptions, including liquidity and nonperformance risks, which market participants would use when pricing the asset.

The Company uses various commodity derivative instruments, including forward contracts, futures, options, swaps and other over-the counter agreements. The fair value of commodity derivatives is determined using unadjusted quoted prices for identical instruments on the applicable exchange in which the Company transacts. When quoted prices for identical instruments are not available, the Company uses forward price curves derived from market price quotations, when available, or internally developed and commercial models, with internal and external fundamental data inputs. Market price quotations are obtained from independent energy brokers, exchanges, direct communication with market participants and actual transactions executed by the Company. Market price quotations for certain major electricity and natural gas trading hubs are generally readily obtainable for the first six years, and therefore, the Company’s forward price curves for those locations and periods reflect observable market quotes. Market price quotations for other electricity and natural gas trading points are not as readily obtainable for the first six years or the instrument is not actively traded. Given that limited market data exists for these instruments, the Company uses forward price curves derived from internal models based on perceived pricing relationships to major trading hubs that are based on significant unobservable inputs.

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The following table reconciles the beginning and ending balance of the Company’s assets and liabilities measured at fair value on a recurring basis using significant Level 3 inputs (in millions):

	Three-Month Periods						Nine-Month Periods
	Ended September 30, 2008						Ended September 30, 2008
	Available-						Available-
	For-Sale			Commodity			For-Sale			Commodity
	Securities			Derivatives			Securities			Derivatives
Beginning balance	$	61		$	(232	)	$	73		$	(311	)
Changes included in earnings(1)		-			36			-			16
Unrealized gains (losses) included in other comprehensive income		(6	)		(1	)		(18	)		-
Unrealized gains (losses) included in regulatory assets and liabilities		-			(149	)		-			(51	)
Ending balance	$	55		$	(346	)	$	55		$	(346	)

(1) Changes included in earnings are reported as operating revenues in the Consolidated Statement of Operations. Net unrealized gains included in earnings for the three- and nine-month periods related to commodity derivatives held at September 30, 2008 totaled $33 million and $21 million, respectively.

(9) Related Party Transactions

As of September 30, 2008 and December 31, 2007, Berkshire Hathaway and its affiliates held 11% mandatory redeemable preferred securities due from certain wholly-owned subsidiary trusts of MEHC of $1.65 billion and $821 million, respectively. On September 19, 2008, a wholly-owned subsidiary trust of MEHC issued $1.0 billion of 11% mandatory redeemable preferred securities to Berkshire Hathaway and its affiliates due in August 2015 and MEHC issued $1.0 billion of 11% subordinated debt to the trust. The proceeds were used to purchase a $1.0 billion investment in Constellation Energy Series A Preferred Stock (see Note 3). Interest expense on these securities totaled $22 million and $26 million for the three-month periods ended September 30, 2008 and 2007, respectively, and $67 million and $84 million for the nine-month periods ended September 30, 2008 and 2007, respectively. Accrued interest totaled $17 million as of September 30, 2008 and December 31, 2007.

For the nine-month period ended September 30, 2008, the Company received cash payments for income taxes from Berkshire Hathaway totaling $171 million. For the nine-month period ended September 30, 2007, the Company made cash payments for income taxes to Berkshire Hathaway totaling $134 million.

(10) Commitments and Contingencies

Environmental Matters

The Company is subject to federal, state, local and foreign laws and regulations regarding air and water quality, hazardous and solid waste disposal and other environmental matters that have the potential to impact the Company’s current and future operations. The Company believes it is in material compliance with current environmental requirements.

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Accrued Environmental Costs

The Company is fully or partly responsible for environmental remediation at various contaminated sites, including sites that are or were part of the Company’s operations and sites owned by third parties. The Company accrues environmental remediation expenses when the expenses are believed to be probable and can be reasonably estimated. The quantification of environmental exposures is based on many factors, including changing laws and regulations, advancements in environmental technologies, the quality of available site-specific information, site investigation results, expected remediation or settlement timelines, the Company’s proportionate responsibility, contractual indemnities and coverage provided by insurance policies. The liability recorded as of September 30, 2008 and December 31, 2007 was $38 million and is included in other current liabilities and other long-term liabilities on the Consolidated Balance Sheets. Environmental remediation liabilities that separately result from the normal operation of long-lived assets and that are associated with the retirement of those assets are separately accounted for as asset retirement obligations.

Hydroelectric Relicensing

PacifiCorp’s hydroelectric portfolio consists of 47 plants with an aggregate facility net owned capacity of 1,158 MW. The FERC regulates 98% of the net capacity of this portfolio through 16 individual licenses, which typically have terms of 30 to 50 years. In April 2008 and June 2008, the FERC issued new licenses for the Prospect and the Lewis River hydroelectric projects, respectively. The cost of implementing these new licenses is not expected to be significant. PacifiCorp’s Klamath hydroelectric project is currently undergoing relicensing with the FERC.

In February 2004, PacifiCorp filed with the FERC a final application for a new license to operate the 169-MW (nameplate rating) Klamath hydroelectric project in anticipation of the March 2006 expiration of the existing license. PacifiCorp is currently operating under an annual license issued 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 United States 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. In January 2007, the United States Departments of Interior and Commerce filed modified terms and conditions consistent with the March 2006 filings and rejected the alternatives proposed by PacifiCorp. PacifiCorp is prepared to meet and implement the federal agencies’ terms and conditions as part of the project’s relicensing. However, PacifiCorp expects to continue in settlement discussions with various parties in the Klamath Basin area who have intervened with the FERC licensing proceeding to try to achieve a mutually acceptable outcome for the project.

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. PacifiCorp filed comments on the draft statement by the close of the public comment period on December 1, 2006. Subsequently, in November 2007, the FERC issued its final environmental impact statement. The United States Fish and Wildlife Service and the National Marine Fisheries Service issued final biological opinions in December 2007 analyzing the hydroelectric project’s impact on endangered species under a new FERC license consistent with the FERC staff’s recommended alternative and modified terms and conditions issued by the United States Departments of Interior and Commerce. The United States Fish and Wildlife Service asserted that the hydroelectric project is currently not covered by previously issued biological opinions and that consultation under the Endangered Species Act is required by the issuance of annual license renewals. PacifiCorp has disputed these assertions and believes that consultation on annual FERC licenses is not required. PacifiCorp is currently working with the United States Fish and Wildlife Service to resolve any endangered species issues. PacifiCorp will need to obtain water quality certifications from Oregon and California prior to the FERC issuing a final license. PacifiCorp currently has an application pending in Oregon and resubmitted its application to California in September 2008.

Hydroelectric relicensing and the related environmental compliance requirements and litigation are subject to uncertainties. PacifiCorp expects that future costs relating to these matters will be significant and will consist primarily of additional relicensing costs, operations and maintenance expense, and capital expenditures. Electricity generation reductions may result from the additional environmental requirements. PacifiCorp had incurred $90 million and $89 million in costs as of September 30, 2008 and December 31, 2007, respectively, for ongoing hydroelectric relicensing projects. PacifiCorp had incurred $54 million and $48 million in costs as of September 30, 2008 and December 31, 2007, respectively, related to the relicensing of the Klamath hydroelectric project. These costs are included in construction in progress and reflected in property, plant and equipment, net on the Consolidated Balance Sheets. While the costs of implementing new license provisions cannot be determined until such time as a new license is issued, such costs could be material.

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Legal Matters

The Company is party in a variety of legal actions arising out of the normal course of business. Plaintiffs occasionally seek punitive or exemplary damages. The Company does not believe that such normal and routine litigation will have a material effect on its consolidated financial results. The Company is also involved in other kinds of legal actions, some of which assert or may assert claims or seek to impose fines and penalties in substantial amounts and are described below.

Constellation Energy

Beginning September 18, 2008, six shareholders of Constellation Energy have filed lawsuits in the Circuit Court for Baltimore City, Maryland challenging the proposed merger. Four of those lawsuits were brought as shareholder class actions and two were brought as shareholder derivative actions. The four shareholder class actions claim that Constellation Energy and members of its board of directors breached their fiduciary duties to shareholders in agreeing to the proposed merger. One of these four shareholder class actions also names MEHC as a defendant, alleging that it aided and abetted members of Constellation Energy’s board of directors in breaching their fiduciary duties. The two shareholder derivative actions allege that members of Constellation Energy’s board of directors breached their fiduciary duties to the Company in agreeing to the proposed merger and that MEHC aided and abetted members of the board of directors in breaching their fiduciary duties.

The shareholder class actions and shareholder derivative actions claim that the merger consideration is inadequate and does not maximize value for shareholders, that the sales process leading up to the merger was unreasonably short and procedurally flawed, and that unreasonable deal protection devices were agreed to that ward off competing bids and coerce shareholders into accepting the merger.

There are currently two shareholder class actions pending in the United States District Court of the District of Maryland arising out of the proposed transaction between Constellation Energy and MEHC. MEHC is a defendant in both complaints.

Although MEHC is unable at this time to determine the ultimate outcome of these lawsuits, injunctive relief or an adverse determination in the shareholder class actions or the shareholder derivative actions could result in a cash judgment or settlement and affect our ability to complete the proposed merger with Constellation Energy.

PacifiCorp

In February 2007, the Sierra Club and the Wyoming Outdoor Council filed a complaint against PacifiCorp in the federal district court in Cheyenne, Wyoming, alleging violations of the Wyoming state opacity standards at PacifiCorp’s Jim Bridger plant in Wyoming. Under Wyoming state requirements, which are part of the Jim Bridger plant’s Title V permit and are enforceable by private citizens under the federal Clean Air Act, a potential source of pollutants such as a coal-fired generating facility must meet minimum standards for opacity, which is a measurement of light that is obscured in the flue of a generating facility. The complaint alleges thousands of violations of six-minute compliance periods and seeks an injunction ordering the Jim Bridger plant’s compliance with opacity limits, civil penalties of $32,500 per day per violation and the plaintiffs’ costs of litigation. The court granted a motion to bifurcate the trial into separate liability and remedy phases. In March 2008, the court indefinitely postponed the date for the liability-phase trial. The remedy-phase trial has not yet been scheduled. The court also has before it a number of motions on which it has not yet ruled. PacifiCorp believes it has a number of defenses to the claims. PacifiCorp intends to vigorously oppose the lawsuit but cannot predict its outcome at this time. PacifiCorp has already committed to invest at least $812 million in pollution control equipment at its generating facilities, including the Jim Bridger plant. This commitment is expected to significantly reduce system-wide emissions, including emissions at the Jim Bridger plant.

CalEnergy Generation-Foreign

In February 2002, pursuant to the share ownership adjustment mechanism in the CE Casecnan shareholder agreement, MEHC’s indirect wholly owned subsidiary, CE Casecnan Ltd., advised the minority shareholder 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. On January 3, 2006, the Superior Court of the State of California entered a judgment in favor of LPG against CE Casecnan Ltd. Pursuant to the judgment, 15% of the distributions of CE Casecnan was deposited into escrow plus interest at 9% per annum. The judgment was appealed, and as a result of the appellate decision, CE Casecnan Ltd. determined that LPG would retain ownership of 10% of the shares of CE Casecnan, with the remaining 5% share to be transferred to CE Casecnan Ltd. subject to certain buy-up rights under the shareholder agreement, which are also being litigated. The remaining issues are fully briefed and pending before the court. The Company intends to vigorously defend and pursue the remaining claims.

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On July 1, 2005, MEHC and CE Casecnan Ltd. commenced an action against San Lorenzo Ruiz Builders and Developers Group, Inc. (“San Lorenzo”) in the District Court of Douglas County, Nebraska, seeking a declaratory judgment as to San Lorenzo’s right to repurchase 15% of the shares in CE Casecnan. 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. Currently, the action is in the discovery phase, and a one-week trial has been set to begin on May 4, 2009. The impact, if any, of this litigation on the Company cannot be determined at this time. The Company intends to vigorously defend the counterclaims.

Commercial Commitments

PacifiCorp has an ongoing construction program to meet increased electricity usage, customer growth, and system reliability and emission control objectives. During 2008, PacifiCorp has entered into multiple new purchase commitments in the amount of $441 million for wind turbines that will be delivered at varying dates through 2010. The payment schedule is as follows: $191 million in 2008, $129 million in 2009, $108 million in 2010 and $13 million in 2011. As of September 30, 2008, PacifiCorp has made $59 million of scheduled payments for these purchase commitments.

In January 2008, PacifiCorp executed an engineering, procurement and construction (“EPC”) agreement for the addition of a new sulfur dioxide scrubber on Unit 3 and the replacement of an existing scrubber on Unit 4 of the Dave Johnston plant. PacifiCorp executed an EPC agreement, effective September 2008, for a double-circuit, 345-kilovolt transmission line to be built between the Populus substation located in southern Idaho and the Terminal substation located in the Salt Lake City area, one of the first major segments of the Energy Gateway Transmission Expansion Project. PacifiCorp is committed to making total progress payments in the amount of $911 million for these two EPC agreements. Scheduled progress payments are as follows: $170 million in 2008, $601 million in 2009, $119 million in 2010, $10 million in 2011 and $11 million in 2012. As of September 30, 2008, PacifiCorp has made $60 million of scheduled payments for these EPC agreements.

PacifiCorp enters into various power purchase agreements to obtain additional energy to satisfy generation needs beyond PacifiCorp's currently available sources. In September 2008, PacifiCorp executed a power purchase agreement to purchase the entire output of the Three Buttes wind plant located in Natrona County and Converse County, Wyoming. The nameplate capacity of the proposed wind plant is expected to be 99 MW. The delivery of energy and associated renewable energy credits under this agreement is expected to commence in December 2009 for a period of 20 years. PacifiCorp will be obligated to make payments in the amount of the contractual price per MWh of actual energy delivered to PacifiCorp.

(11) Employee Benefit Plans

Domestic Operations

Beginning in August 2008, non-union employee participants of the PacifiCorp-sponsored and MidAmerican Energy-sponsored noncontributory defined benefit pension plans were offered the option to continue to receive pay credits in their current cash balance retirement plan or receive equivalent fixed 401(k) contributions to the PacifiCorp-sponsored and MidAmerican Energy-sponsored 401(k) plans. The change in election is not expected to materially impact the amounts currently recognized on the Consolidated Financial Statements. The election is effective beginning January 1, 2009.

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Combined net periodic benefit cost for domestic pension, including supplemental executive retirement plans, and other postretirement benefit plans included the following components (in millions):

	Three-Month Periods						Nine-Month Periods
	Ended September 30,						Ended September 30,
	2008			2007			2008			2007
Pension
Service cost	$	12		$	15		$	39		$	41
Interest cost		28			28			81			84
Expected return on plan assets		(29	)		(29	)		(87	)		(84	)
Net amortization		2			5			6			22
Net periodic benefit cost	$	13		$	19		$	39		$	63

Other Postretirement
Service cost	$	3		$	2		$	9		$	10
Interest cost		11			11			35			36
Expected return on plan assets		(10	)		(9	)		(32	)		(31	)
Net amortization		3			6			12			17
Net periodic benefit cost	$	7		$	10		$	24		$	32

Employer contributions to domestic pension and other postretirement plans are expected to be $77 million and $41 million, respectively, in 2008. As of September 30, 2008, $74 million and $32 million of contributions had been made to the pension and other postretirement plans, respectively.

CE Electric UK

Net periodic benefit cost for the UK pension plan included the following components (in millions):

	Three-Month Periods						Nine-Month Periods
	Ended September 30,						Ended September 30,
	2008			2007			2008			2007
Service cost	$	5		$	6		$	16		$	18
Interest cost		25			24			77			70
Expected return on plan assets		(30	)		(30	)		(93	)		(88	)
Net amortization		6			8			16			24
Net periodic benefit cost	$	6		$	8		$	16		$	24

Employer contributions to the UK pension plan are expected to be £48 million for 2008. As of September 30, 2008, £37 million, or $72 million, of contributions had been made to the UK pension plan.

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(12) Comprehensive Income and Components of Accumulated Other Comprehensive (Loss) Income, Net

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

	Three-Month Periods						Nine-Month Periods
	Ended September 30,						Ended September 30,
	2008			2007			2008			2007
Net income	$	350		$	384		$	912		$	938
Other comprehensive (loss) income:
Unrecognized amounts on retirement benefits, net of tax of $12, $8(1), $14 and $12(1)		30			(7	)		36			(1	)
Foreign currency translation adjustment		(320	)		52			(304	)		117
Fair value adjustment on cash flow hedges, net of tax of $(22), $(12), $(13) and $12		(33	)		(20	)		(19	)		18
Unrealized (losses) gains on marketable securities, net of tax of $(4), $-, $(12) and $1		(7	)		1			(18	)		2
Total other comprehensive (loss) income		(330	)		26			(305	)		136
Comprehensive income	$	20		$	410		$	607		$	1,074

(1) These amounts include a benefit of approximately $7 million due to adjustments recognized in July 2007 as a result of the United Kingdom corporate income tax rate decreasing from 30% to 28%.

Accumulated other comprehensive (loss) income, net is included in the Consolidated Balance Sheets in shareholders’ equity, and consists of the following components (in millions):

	As of
	September 30,			December 31,
	2008			2007
Unrecognized amounts on retirement benefits, net of tax of $(114) and $(128)	$	(293	)	$	(329	)
Foreign currency translation adjustment		52			356
Fair value adjustment on cash flow hedges, net of tax of $25 and $38		38			57
Unrealized (losses) gains on marketable securities, net of tax of $(8) and $4		(12	)		6
Total accumulated other comprehensive (loss) income, net	$	(215	)	$	90

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(13)   Segment Information

MEHC’s reportable segments were determined based on how the Company’s strategic units are 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. Intersegment eliminations and adjustments, including the allocation of goodwill, have been made. 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,
	2008			2007			2008			2007
Operating revenue:
PacifiCorp	$	1,245		$	1,137		$	3,395		$	3,190
MidAmerican Funding		1,107			985			3,561			3,193
Northern Natural Gas		149			118			520			460
Kern River		126			105			340			302
CE Electric UK		245			273			773			775
CalEnergy Generation-Foreign		38			39			96			169
CalEnergy Generation-Domestic		8			9			23			25
HomeServices		330			410			913			1,215
Corporate/other(1)		(8	)		(9	)		(33	)		(35	)
Total operating revenue	$	3,240		$	3,067		$	9,588		$	9,294
Depreciation and amortization:
PacifiCorp	$	123		$	124		$	364		$	367
MidAmerican Funding		61			70			210			215
Northern Natural Gas		15			14			44			43
Kern River		15			20			58			59
CE Electric UK		48			46			138			132
CalEnergy Generation-Foreign		6			9			17			44
CalEnergy Generation-Domestic		2			2			6			6
HomeServices		4			6			14			16
Corporate/other(1)		(6	)		(4	)		(13	)		(11	)
Total depreciation and amortization	$	268		$	287		$	838		$	871
Operating income:
PacifiCorp	$	268		$	269		$	717		$	699
MidAmerican Funding		159			171			438			429
Northern Natural Gas		95			32			295			203
Kern River		99			71			244			209
CE Electric UK		115			118			399			390
CalEnergy Generation-Foreign		30			24			72			100
CalEnergy Generation-Domestic		5			4			12			12
HomeServices		1			19			(10	)		46
Corporate/other(1)		(1	)		(12	)		(41	)		(56	)
Total operating income		771			696			2,126			2,032
Interest expense		(340	)		(336	)		(998	)		(976	)
Capitalized interest		14			13			37			43
Interest and dividend income		16			33			47			75
Other income		21			31			66			86
Other expense		(2	)		(2	)		(7	)		(6	)
Total income before income tax expense, minority interest and preferred dividends of subsidiaries and equity income	$	480		$	435		$	1,271		$	1,254

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	Three-Month Periods				Nine-Month Periods
	Ended September 30,				Ended September 30,
	2008		2007		2008		2007
Interest expense:
PacifiCorp	$	91	$	76	$	255	$	230
MidAmerican Funding		52		48		153		131
Northern Natural Gas		17		15		46		43
Kern River		16		19		52		56
CE Electric UK		51		61		148		178
CalEnergy Generation-Foreign		2		3		6		11
CalEnergy Generation-Domestic		4		4		13		13
HomeServices		-		-		1		1
Corporate/other(1)		107		110		324		313
Total interest expense	$	340	$	336	$	998	$	976

	As of
	September 30,		December 31,
	2008		2007
Total assets:
PacifiCorp	$	17,229	$	16,049
MidAmerican Funding		10,273		9,377
Northern Natural Gas		2,589		2,488
Kern River		1,948		1,943
CE Electric UK		5,973		6,802
CalEnergy Generation-Foreign		488		479
CalEnergy Generation-Domestic		567		544
HomeServices		729		709
Corporate/other(1)		1,206		825
Total assets	$	41,002	$	39,216

(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 investments and related interest income and (ii) intersegment eliminations.

Goodwill is allocated to each reportable segment included in total assets above. Goodwill as of December 31, 2007 and the changes for the nine-month period ended September 30, 2008 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, 2007	$	1,125	$	2,108	$	275		$	34	$	1,335		$	71	$	391	$	5,339
Foreign currency translation		-		-		-			-		(107	)		-		-		(107	)
Other(1)		2		3		(20	)		-		(7	)		-		-		(22	)
Goodwill at September 30, 2008	$	1,127	$	2,111	$	255		$	34	$	1,221		$	71	$	391	$	5,210

(1) Other goodwill adjustments relate primarily to income tax adjustments.

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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 that 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 herein. Explanations include management’s best estimate of the impact of weather, customer growth and other factors. This discussion should be read in conjunction with the Company’s historical unaudited Consolidated Financial Statements and the notes included elsewhere in Item 1 of this Form 10-Q. The Company’s actual results in the future could differ significantly from the historical results.

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 (owning a majority interest in the Casecnan project), CalEnergy Generation-Domestic (owning interests in independent power projects in the United States) and HomeServices of America, Inc. (collectively with its subsidiaries, “HomeServices”). Through these platforms, MEHC 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 interstate natural gas pipeline companies in the United States, two electricity distribution companies in Great Britain, a diversified portfolio of independent power projects and the second largest residential real estate brokerage firm in the United States.

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. Forward-looking statements can typically be identified by the use of forward-looking words, such as “may,” “could,” “project,” “believe,” “anticipate,” “expect,” “estimate,” “continue,” “intend,” “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;

· changes in governmental, legislative or regulatory requirements affecting the Company or the electric or gas utility, pipeline or power generation industries;

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

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

· changes in economic, industry or weather conditions, as well as demographic trends, that could affect customer growth and usage or supply of electricity and gas or the Company’s ability to obtain long-term contracts with customers;

· changes in the residential real estate brokerage and mortgage industries that could affect brokerage transaction levels;

· changes in prices and availability for both purchases and sales of wholesale electricity, coal, natural gas, other fuel sources and fuel transportation that could have a significant impact on generation capacity and energy costs;

· the financial condition and creditworthiness of the Company’s significant customers and suppliers;

· changes in business strategy or development plans;

· availability, terms and deployment of capital, including severe reductions in demand for investment-grade commercial paper, debt securities and other sources of debt financing and volatility in the London Interbank Offered Rate, the base interest rate for MEHC and its subsidiaries credit facilities;

26

· performance of the Company’s generation facilities, including unscheduled outages or repairs;

· risks relating to nuclear generation;

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

· the impact of increases in healthcare costs, changes in interest rates, mortality, morbidity and investment performance on pension and other postretirement benefits expense, as well as the impact of changes in legislation on funding requirements;

· changes in MEHC’s and its subsidiaries’ credit ratings;

· unanticipated construction delays, changes in costs, receipt of required permits and authorizations, ability to fund capital projects and other factors that could affect future generation plants and infrastructure additions;

· the impact of new accounting pronouncements or changes in current accounting estimates and assumptions on financial results;

· The ability to obtain governmental and shareholder approvals for the acquisition of Constellation Energy Group, Inc. (“Constellation Energy”) or to satisfy other conditions to the acquisition on the terms and expected time-frame or at all;

· the Company’s ability to successfully integrate future acquired operations into its business;

· other risks or unforeseen events, including litigation and 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 MEHC’s filings with the United States (“U.S.”) Securities and Exchange Commission (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 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.

Results of Operations

Overview

Net income for the third quarter of 2008 was $350 million, a decrease of $34 million, or 9%, and for the first nine months of 2008 was $912 million, a decrease of $26 million, or 3%, as compared to 2007. After adjusting for the $61 million deferred income tax benefit recognized in the third quarter of 2007 related to a change in the United Kingdom’s corporate income tax rate from 30% to 28%, net income increased by $27 million, or 8%, for the third quarter and $35 million, or 4%, for the first nine months of 2008. Our pipeline businesses, Northern Natural Gas and Kern River, achieved higher net income for 2008 due to favorable market conditions, an after-tax gain on the sale of non-strategic assets and a reduction in customer refund liabilities related to the current rate proceeding. CE Electric UK’s net income was higher for the first nine months of 2008 due to lower interest costs and favorable operating results, partially offset by the unfavorable impact from the foreign currency exchange rate. Net income was lower at HomeServices due to the continuing weak U.S. housing market. Also unfavorably impacting net income for the first nine months of 2008 compared to 2007 was the transfer of two geothermal projects to the Philippine government in July 2007. PacifiCorp’s and MidAmerican Funding’s net incomes were lower due to a number of factors including the impact of mild weather, higher energy costs, higher maintenance expense for emergency response and restoration related to storms and floods in 2008, interest costs and lower allowance for funds used during construction (“AFUDC”), partially offset at MidAmerican Funding by lower depreciation as a result of Iowa revenue sharing.

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 and intersegment eliminations.

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A comparison of operating revenue and operating income for the Company’s reportable segments are summarized as follows (in millions):

	Third Quarter											First Nine Months
	2008			2007			Change					2008			2007			Change
Operating revenue:
PacifiCorp	$	1,245		$	1,137		$	108		9	%	$	3,395		$	3,190		$	205		6	%
MidAmerican Funding		1,107			985			122		12			3,561			3,193			368		12
Northern Natural Gas		149			118			31		26			520			460			60		13
Kern River		126			105			21		20			340			302			38		13
CE Electric UK		245			273			(28	)	(10	)		773			775			(2	)	-
CalEnergy Generation-Foreign		38			39			(1	)	(3	)		96			169			(73	)	(43	)
CalEnergy Generation-Domestic		8			9			(1	)	(11	)		23			25			(2	)	(8	)
HomeServices		330			410			(80	)	(20	)		913			1,215			(302	)	(25	)
Corporate/other		(8	)		(9	)		1		11			(33	)		(35	)		2		6
Total operating revenue	$	3,240		$	3,067		$	173		6		$	9,588		$	9,294		$	294		3

Operating income:
PacifiCorp	$	268		$	269		$	(1	)	-	%	$	717		$	699		$	18		3	%
MidAmerican Funding		159			171			(12	)	(7	)		438			429			9		2
Northern Natural Gas		95			32			63		197			295			203			92		45
Kern River		99			71			28		39			244			209			35		17
CE Electric UK		115			118			(3	)	(3	)		399			390			9		2
CalEnergy Generation-Foreign		30			24			6		25			72			100			(28	)	(28	)
CalEnergy Generation-Domestic		5			4			1		25			12			12			-		-
HomeServices		1			19			(18	)	(95	)		(10	)		46			(56	)	(122	)
Corporate/other		(1	)		(12	)		11		92			(41	)		(56	)		15		27
Total operating income	$	771		$	696		$	75		11		$	2,126		$	2,032		$	94		5

PacifiCorp

Operating revenue increased $108 million for the third quarter and $205 million for the first nine months of 2008. Retail revenue increased $20 million for the third quarter and $143 million for the first nine months of 2008 due to higher prices approved by regulators, growth in the average number of customers and receiving approval in June 2008 to begin collecting $27 million of previously under-collected income taxes pursuant to Oregon Senate Bill 408. Partially offsetting the higher retail revenue for the third quarter of 2008 was lower average customer usage due primarily to a mild summer in Utah. Overall, sales volumes to retail customers were flat for the third quarter and increased 1.8% for the first nine months of 2008.

Wholesale and other revenue increased $42 million for the third quarter and $76 million for the first nine months of 2008 due primarily to higher average wholesale prices, partially offset by lower wholesale volumes for the first nine months, and higher contracted prices for transmission services. Operating revenue also increased $46 million for the third quarter and decreased $14 million for the first nine months of 2008 due to changes in the fair value of energy sales contracts accounted for as derivatives.

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Operating income decreased $1 million for the third quarter and increased $18 million for the first nine months of 2008. The higher revenue for 2008 was offset by higher energy costs and operating expenses. The increase in energy costs consisted of the following (in millions):

	Increase (Decrease)
	Third			First Nine
	Quarter			Months
Energy Costs:
Cost of natural gas, coal and other fuel	$	41		$	142
Purchased electricity		(1	)		26
Changes in the fair value of energy purchase contracts accounted for as derivatives		53			(1	)
Transmission and other		6			12
	$	99		$	179

The cost of fuel increased due to higher average prices for both natural gas and coal and the addition of the 548-megawatt Lake Side plant in September 2007. The average unit cost of purchased electricity also increased for the 2008 periods as compared to 2007. This average unit cost increase was offset by lower volumes purchased due in part to the addition of the Lake Side plant and other sources of owned generation. Operating expenses increased by $12 million for both periods due to increased spending on demand-side management projects, which are recovered in rates, overhauls and new wind generation operating expenses.

MidAmerican Funding

MidAmerican Funding’s operating revenue and operating income are summarized as follows (in millions):

	Third Quarter											First Nine Months
	2008			2007			Change					2008		2007		Change
Operating revenue:
Regulated electric	$	552		$	537		$	15		3	%	$	1,527	$	1,484	$	43		3	%
Regulated natural gas		192			146			46		32			1,043		854		189		22
Nonregulated and other		363			302			61		20			991		855		136		16
Total operating revenue	$	1,107		$	985		$	122		12		$	3,561	$	3,193	$	368		12
Operating income:
Regulated electric	$	148		$	157		$	(9	)	(6	)%	$	353	$	346	$	7		2	%
Regulated natural gas		(5	)		(7	)		2		29			43		35		8		23
Nonregulated and other		16			21			(5	)	(24	)		42		48		(6	)	(13	)
Total operating income	$	159		$	171		$	(12	)	(7	)	$	438	$	429	$	9		2

Regulated electric revenue increased $15 million for the third quarter and $43 million for the first nine months of 2008. Wholesale revenue increased $28 million for the third quarter and $55 million for the first nine months of 2008 due primarily to higher sales volumes resulting from increased generation available from both the addition of owned generation and the impact of lower retail sales volumes. Retail revenue decreased $13 million for the third quarter and $12 million for the first nine months of 2008 due primarily to lower sales volumes resulting from the mild temperatures experienced in the service territory in 2008, partially offset by an increase in the average number of retail customers and the sale of renewable energy credits. Total sales volumes increased 1.8% for the third quarter and 4.5% for the first nine months of 2008.

Regulated electric operating income decreased $9 million for the third quarter and increased $7 million for the first nine months of 2008. The higher revenue for 2008 was offset by higher energy costs and operating costs and expenses. Energy costs increased $22 million for the third quarter and $14 million for the first nine months of 2008 due to higher average fuel prices for coal and natural gas. The average unit cost increases were partially offset by lower volumes purchased for the first nine months of 2008 due in part to the addition of sources of owned generation. Operating costs and expenses increased $2 million for the third quarter and $22 million for the first nine months of 2008 due to higher maintenance costs associated with scheduled plant outages, increased maintenance expense for emergency response and restoration related to storms and floods in 2008 of $12 million and the additional generation placed in-service, partially offset by a decrease in depreciation as a result of lower revenue sharing in connection with the lower Iowa electric equity returns.

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Regulated natural gas revenue increased $46 million for the third quarter and $189 million for the first nine months of 2008 due primarily to a higher average per-unit cost of gas sold, which was largely passed on to customers, and higher retail sales volumes for the first half of 2008 resulting from colder temperatures. Regulated natural gas operating income increased $8 million for the first nine months of 2008 due primarily to higher retail sales volumes.

The increase in nonregulated and other revenue was due primarily to higher gas revenue of $62 million for the third quarter and $114 million for the first nine months of 2008 as a result of higher prices throughout the year and higher volumes for the first half of 2008. Nonregulated electric retail revenue increased $19 million for the first nine months of 2008 due primarily to higher average prices. Nonregulated and other operating income decreased $5 million for the third quarter and $6 million for the first nine months of 2008 due primarily to a lower gross margin on nonregulated electric retail sales as a result of increased costs of electricity and the reduction in electric retail sales volumes in the Illinois market.

Northern Natural Gas

Operating revenue increased $31 million for the third quarter and $60 million for the first nine months of 2008. Transportation revenue increased $29 million for the third quarter and $66 million for the first nine months of 2008 on stronger market conditions and higher market area reservation revenue. Additionally, storage revenue increased $10 million for the first nine months of 2008 due primarily to an expansion of its Redfield storage facilities and higher interruptible storage activity. Partially offsetting the higher transportation and storage revenue for the first nine months of 2008 were lower sales of gas for operational purposes of $15 million due primarily to lower sales volumes.

Operating income increased $63 million for the third quarter and $92 million for the first nine months of 2008 due primarily to the higher operating revenue and a pre-tax gain on the sale of certain non-strategic operating assets of $26 million in the third quarter of 2008.

Kern River

Operating revenue increased $21 million for the third quarter and $38 million for the first nine months of 2008 due to a reduction in customer refund liabilities of $13 million for the third quarter and $46 million for the first nine months of 2008 related to Kern River’s current rate proceeding. Market oriented revenues, still strong in 2008, decreased $12 million for the first nine months of 2008 as a result of market conditions.

Operating income increased $28 million for the third quarter and $35 million for the first nine months of 2008 due to the operating revenue increases.

CE Electric UK

Operating revenue decreased $28 million for the third quarter and $2 million for the first nine months of 2008. The foreign currency exchange rate had an unfavorable impact of $18 million for the third quarter and $16 million for the first nine months of 2008. Distribution revenue decreased $15 million for the third quarter and increased $7 million for the first nine months of 2008. Distribution tariffs were higher for the first quarter of 2008 as rates were increased in April 2007 to bill under-recovered amounts under the regulatory scheme. These rates were lowered in April 2008, which led to lower distribution revenue for the second and third quarters of 2008. The decrease in operating revenue was partially offset by higher revenue at CE Gas of $7 million for the third quarter and $9 million for the first nine months of 2008.

Operating income decreased $3 million for the third quarter and increased $9 million for the first nine months of 2008. For the third quarter of 2008, operating income decreased due to the lower distribution revenue of $15 million and the impact from the foreign currency exchange rate of $8 million, partially offset by the write-off of an unsuccessful exploration well in 2007 at CE Gas totaling $9 million and higher revenue at CE Gas. For the first nine months of 2008, operating income increased due primarily to the higher revenue totaling $16 million and the write-off of the unsuccessful exploration well of $9 million, partially offset by a $17 million realized gain on the sale of certain CE Gas assets in 2007 and the impact from the foreign currency exchange rate of $6 million.

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CalEnergy Generation-Foreign

Operating revenue decreased $1 million for the third quarter and $73 million for the first nine months of 2008. Operating revenue was lower by $11 million for the third quarter and $95 million for the first nine months of 2008 due to the transfer of the Malitbog and Mahanagdong projects on July 25, 2007 to the Philippine government. This decrease was partially offset by higher operating revenue of $10 million for the third quarter and $22 million for the first nine months of 2008 at the Casecnan project primarily due to higher variable energy fees as a result of increased generation from higher water flows.

Operating income increased $6 million for the third quarter and decreased $28 million for the first nine months of 2008 due primarily to higher operating revenue at the Casecnan project, partially offset by the transfer of the Malitbog and Mahanagdong projects which contributed $4 million for the third quarter and $47 million for the first nine months of 2007.

HomeServices

Operating revenue decreased $80 million for the third quarter and $302 million for the first nine months of 2008. As compared to 2007, third quarter brokerage transactions declined by 14% and the average home sales price declined by 10%, while the first nine month brokerage transactions declined by 21% and the average home sales price declined by 8% reflecting the continuing weak U.S. housing market.

Operating income decreased $18 million for the third quarter and $56 million for the first nine months of 2008 due primarily to the continuing weak U.S. housing market and a $10 million charge taken in 2008 related to office lease terminations, partially offset by lower commissions and operating expenses.

Consolidated Other Income and Expense Items

Interest Expense

Interest expense is summarized as follows (in millions):

	Third Quarter									First Nine Months
	2008		2007		Change					2008		2007		Change
Subsidiary debt	$	223	$	216	$	7		3	%	$	643	$	633	$	10		2	%
MEHC senior debt and other		88		86		2		2			267		238		29		12
MEHC subordinated debt-Berkshire Hathaway Inc.		22		26		(4	)	(15	)		67		84		(17	)	(20	)
MEHC subordinated debt-other		7		8		(1	)	(13	)		21		21		-		-
Total interest expense	$	340	$	336	$	4		1		$	998	$	976	$	22		2

Interest expense increased $4 million for the third quarter and $22 million for the first nine months of 2008 due primarily to debt issuances at domestic energy businesses and at MEHC, partially offset by debt retirements and scheduled principal repayments.

Other Income, Net

Other income, net is summarized as follows (in millions):

	Third Quarter											First Nine Months
	2008			2007			Change					2008			2007			Change
Capitalized interest	$	14		$	13		$	1		8	%	$	37		$	43		$	(6	)	(14	)%
Interest and dividend income		16			33			(17	)	(52	)		47			75			(28	)	(37	)
Other income		21			31			(10	)	(32	)		66			86			(20	)	(23	)
Other expense		(2	)		(2	)		-		-			(7	)		(6	)		(1	)	(17	)
Total other income, net	$	49		$	75		$	(26	)	(35	)	$	143		$	198		$	(55	)	(28	)

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Interest and dividend income decreased $17 million for the third quarter and $28 million for the first nine months of 2008 due primarily to the maturities of guaranteed investment contracts in December 2007 and February 2008 that were used to retire debt maturing at CE Electric UK. Additionally, average cash balances and interest rates were lower in the third quarter of 2008.

Other income decreased $10 million for the third quarter and $20 million for the first nine months of 2008 due primarily to lower equity AFUDC on lower construction activity throughout the first nine months of 2008, which also attributed to the $6 million decrease in capitalized interest.

Income Tax Expense

Income tax expense increased $81 million to $149 million for the third quarter and $50 million to $378 million for the first nine months of 2008. The effective tax rate was 31% for the third quarter of 2008 as compared to 16% for 2007 and 30% for the first nine months of 2008 as compared to 26% for 2007. The increases in income tax expense and the effective tax rates were primarily due to the recognition of $61 million of deferred income tax benefits upon the enactment in July 2007 of a reduction in the United Kingdom corporate income tax rate from 30% to 28%. Adjusting for this benefit, the effective tax rates were 30% for the third quarter and 31% for the first nine months of 2007.

Minority Interest and Preferred Dividends of Subsidiaries

Minority interest and preferred dividends of subsidiaries decreased $8 million to $14 million for the first nine months of 2008. The decrease was due primarily to additional expense in 2007 related to the minority ownership of the Casecnan project.

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Liquidity and Capital Resources

Each of MEHC’s direct and indirect subsidiaries is organized as a legal entity separate and apart from MEHC and its other subsidiaries. Pursuant to separate financing agreements, the assets of each subsidiary may be pledged or encumbered to support or otherwise provide the security for its own project or subsidiary debt. It should not be assumed that any asset of any subsidiary of MEHC’s will be available to satisfy the obligations of MEHC or any of its other subsidiaries’ obligations. However, unrestricted cash or other assets which are available for distribution may, subject to applicable law, regulatory commitments 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.

As of September 30, 2008, the Company’s total net liquidity available was $6.2 billion. The components of total net liquidity available are as follows (in millions):

										Other
							MidAmerican			Reporting
	MEHC			PacifiCorp			Funding(1)			Segments			Total(2)
Cash and cash equivalents	$	126		$	69		$	15		$	321		$	531
Available revolving credit facilities	$	585		$	1,395		$	645		$	303		$	2,928
Less:
Short-term borrowings and issuance of commercial paper		-			(117	)		(235	)		(45	)		(397	)
Pollution control revenue bond support, letters of credit and other		(44	)		(38	)		(195	)		(92	)		(369	)
Net revolving credit facilities available	$	541		$	1,240		$	215		$	166		$	2,162
Net liquidity available before Berkshire Equity Commitment	$	667		$	1,309		$	230		$	487		$	2,693
Berkshire Equity Commitment(3)		3,500												3,500
Total net liquidity available	$	4,167											$	6,193
Unsecured revolving credit facilities:
Maturity date	2013				2012-2013		2013			2010
Largest single bank commitment as a % of total(4)		17	%		15	%		23	%		29	%

(1)	The above table does not include MidAmerican Energy’s revolving credit agreement for $250 million entered into on October 9, 2008.
(2)	The above table does not include unused revolving credit facilities and letters of credit for investments that are accounted for under the equity method. As of September 30, 2008, the Company’s pro rata share of unsecured revolving credit facilities was $126 million and the Company’s pro rata share of available unsecured revolving credit facilities was $105 million.
(3)	On March 1, 2006, MEHC and Berkshire Hathaway entered into an equity commitment pursuant to which Berkshire Hathaway has agreed to purchase up to $3.5 billion of MEHC’s common equity upon any requests authorized from time to time by MEHC’s Board of Directors (the “Berkshire Equity Commitment”).
(4)	An inability of financial institutions to honor their commitments could adversely affect the Company’s short-term liquidity and ability to meet long-term commitments.

The Company’s cash and cash equivalents were $531 million as of September 30, 2008, compared to $1.18 billion as of December 31, 2007. The Company recorded separately in other current assets, restricted cash and investments as of September 30, 2008 and December 31, 2007 of $105 million and $73 million, respectively. The restricted cash and investments balance is mainly composed of current amounts deposited in restricted accounts relating to (i) the Company’s debt service reserve requirements relating to certain projects, (ii) trust funds related to mine reclamation, and (iii) unpaid dividends declared obligations. The debt service funds are restricted by their respective project debt agreements to be used only for the related project. Additionally, the Company has restricted cash and investments recorded in deferred charges, investments and other assets of $379 million and $425 million as of September 30, 2008 and December 31, 2007, respectively, that principally relate to trust funds held for nuclear decommissioning and mine reclamation costs.

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Operating Activities

Cash flows generated from operations for the nine-month periods ended September 30, 2008 and 2007 were $2.01 billion and $1.90 billion, respectively. The increase was due primarily to higher customer collections and lower income taxes paid due mainly to benefits from federal bonus depreciation, partially offset by higher fuel costs, the timing of payments, greater disbursements for interest, higher net margin deposits and the transfer in 2007 of the Malitbog and Mahanagdong projects. Subsequent to September 30, 2008, the Company paid refunds totaling $149 million related to the Kern River rate case as discussed in Note 5 to Notes to Consolidated Financial Statements included in Item 1 of this Form 10-Q.

Investing Activities

Cash flows used in investing activities for the nine-month periods ended September 30, 2008 and 2007 were $3.57 billion and $2.45 billion, respectively. In September 2008, the Company made a $1.0 billion investment in Constellation Energy’s 8% Series A preferred stock (“Constellation Energy Series A Preferred Stock”) and acquired Chehalis Power Generation, LLC for $308 million. Refer to Note 3 of Notes to Consolidated Financial Statements included in Item 1 of this Form 10-Q for further discussion regarding these transactions. In February 2008, the Company received proceeds from the maturity of a guaranteed investment contract of $393 million. Capital expenditures increased $156 million due primarily to higher capital expenditures associated with additional wind generation.

Capital expenditures by reportable segment are summarized as follows (in millions):

	First Nine Months
	2008		2007
Capital expenditures*:
PacifiCorp	$	1,111	$	1,136
MidAmerican Funding		1,104		879
Northern Natural Gas		112		180
CE Electric UK		328		295
Other reportable segments and corporate/other		23		32
Total capital expenditures	$	2,678	$	2,522

* Excludes amounts for non-cash equity AFUDC.

Capital expenditures consisted primarily of the following:

· Combined, PacifiCorp and MidAmerican Energy spent $1.08 billion during the first nine months of 2008 on wind-powered generation. By September 30, 2008, 251 MW (nameplate ratings) were placed in service. An additional 891.5 MW (nameplate ratings) are expected to be placed in service by December 31, 2008.

· Combined, PacifiCorp and MidAmerican Energy spent $198 million on emissions control equipment.

· Projects mainly for distribution, transmission, generation, mining and other infrastructure needed to serve existing and growing demand.

Financing Activities

Cash flows generated from financing activities for the first nine months of 2008 were $920 million. Sources of cash totaled $3.42 billion and consisted mainly of proceeds from the issuance of MEHC senior and subordinated debt totaling $1.65 billion and subsidiary debt totaling $1.50 billion and the net proceeds from subsidiary short-term debt totaling $274 million. Uses of cash totaled $2.50 billion and consisted mainly of $1.17 billion for repayments of MEHC senior and subordinated debt, $1.21 billion for repayments and purchases of subsidiary debt and a $99 million payment of hedging instruments related to the maturity of U.S. dollar denominated debt at CE Electric UK.

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Cash flows generated from financing activities for the first nine months of 2007 were $2.18 billion. Sources of cash totaled $2.97 billion and consisted mainly of proceeds from the issuance of MEHC senior debt totaling $1.54 billion and subsidiary debt totaling $1.40 billion. Uses of cash totaled $790 million and consisted mainly of $250 million for repayments of subsidiary debt, $194 million of net repayments of subsidiary short-term debt, $167 million for repayments of MEHC subordinated debt and $152 million of net repayments of the MEHC revolving credit facility.

Short-term Debt and Revolving Credit Facilities

MEHC had no outstanding borrowings under its unsecured revolving credit facility at either September 30, 2008 or December 31, 2007. Borrowings by MEHC’s subsidiaries under their commercial paper programs and unsecured revolving credit facilities increased $267 million during the first nine months of 2008 due mainly to a $117 million increase at PacifiCorp and a $149 million increase at MidAmerican Funding due mainly to capital expenditures, scheduled debt maturities and, in the case of PacifiCorp, temporary purchases of long-term debt, partially offset by net cash from operating activities. Continued disruptions in the credit markets may result in increased costs of commercial paper and limit the ability of PacifiCorp and MidAmerican Funding to issue commercial paper, which may lead to a higher reliance on their respective unsecured revolving credit facilities and the related financial institutions for short-term liquidity purposes.

Long-term Debt

In addition to the debt issuances and unsecured revolving credit facilities discussed herein, MEHC and its subsidiaries made scheduled repayments on and purchases of MEHC senior and subordinated debt and subsidiary debt totaling $2.38 billion during the nine-month period ended September 30, 2008.

· On September 19, 2008, a wholly-owned subsidiary trust of MEHC issued $1.0 billion of 11% mandatory redeemable preferred securities to Berkshire Hathaway and its affiliates due in August 2015 and MEHC issued $1.0 billion of 11% subordinated debt to the trust. The proceeds were used to purchase a $1.0 billion investment in Constellation Energy Series A Preferred Stock.

· On July 17, 2008, PacifiCorp issued $500 million of 5.65% first mortgage bonds due July 15, 2018 and $300 million of 6.35% first mortgage bonds due July 15, 2038. The net proceeds were used for general corporate purposes.

· On July 15, 2008, Northern Natural Gas issued $200 million of 5.75% senior notes due July 15, 2018. The net proceeds were used to repay at maturity its $150 million, 6.75% senior notes due September 15, 2008 and the remainder is being used for general corporate purposes.

· On July 1, 2008, the Iowa Finance Authority issued $45 million of variable-rate tax-exempt bonds due July 1, 2038, the proceeds of which were loaned to MidAmerican Energy and are restricted for the payment of qualified environmental construction costs. Also on July 1, 2008, the Iowa Finance Authority issued $57 million of variable-rate tax-exempt bonds due May 1, 2023 to refinance $57 million of pollution control revenue refunding bonds issued on behalf of MidAmerican Energy in 1993. These variable-rate tax-exempt bonds are remarketed and the interest rates reset on a weekly basis. As of September 30, 2008, the weighted average interest rate for these bonds was 8.25% and as of October 31, 2008 it was 2.22%. MidAmerican Energy is contractually responsible for the timely payment of principal and interest on these variable-rate tax-exempt bonds.

· On March 28, 2008, MEHC issued $650 million of 5.75% senior notes due April 1, 2018. The net proceeds were used for general corporate purposes.

· On March 25, 2008, MidAmerican Energy issued $350 million of 5.3% senior notes due March 15, 2018. The proceeds were used by MidAmerican Energy to pay construction costs, including costs for its wind-powered generation projects in Iowa, repay short-term indebtedness and for general corporate purposes.

The Company may from time to time seek to acquire its outstanding securities through cash purchases in the open market, privately negotiated transactions or otherwise. Any debt securities repurchased by the Company may be reissued or resold by the Company from time to time and will depend on prevailing market conditions, the Company’s liquidity requirements, contractual restrictions and other factors. The amounts involved may be material.

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Future Uses of Cash

The Company has available a variety of sources of liquidity and capital resources, both internal and external, including cash flows from operations, public and private debt offerings, the issuance of commercial paper, the use of unsecured revolving credit facilities, the issuance of equity and other sources. These sources are expected to provide funds required for current operations, capital expenditures, acquisitions, investments, debt retirements and other capital requirements. The availability and terms under which each subsidiary has access to external financing depends on a variety of factors, including its credit rating, investors’ judgment of risk and conditions in the overall capital market at the time of marketing, including the condition of the utility industry in general. Additionally, the Berkshire Equity Commitment can 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 MEHC’s regulated subsidiaries. Berkshire Hathaway will have up to 180 days to fund any such request in minimum increments of at least $250 million pursuant to one or more drawings authorized by MEHC’s Board of Directors. The funding of each drawing will be made by means of a cash equity contribution to us in exchange for additional shares of MEHC’s common stock. The Berkshire Equity Commitment will expire on February 28, 2011.

In the U.S., the U.K. and most other economies around the world, recent market and economic conditions have been unprecedented and challenging with more restrictive credit conditions and slow growth through the third quarter of 2008. For the first nine months of 2008, continued concerns about the systemic impact of inflation, energy costs, geopolitical issues, the availability and cost of credit, the U.S. mortgage market and a declining real estate market in the U.S. and the U.K. have contributed to increased market volatility and diminished expectations for the U.S. and U.K. economies. In the third quarter, large financial institutions such as Countrywide Financial Corporation, Washington Mutual Savings Bank, the Federal Home Loan Mortgage Association, the Federal National Mortgage Association, Wachovia Corporation, Bear Stearns Companies Inc and Merrill Lynch & Co., Inc. were unable to survive as independent institutions. Lehman Brothers Holdings Inc. was forced to file for bankruptcy. Other surviving institutions such as Citigroup Inc., Goldman Sachs Group, Inc., American International Group, Inc., Morgan Stanley and others required multibillion dollar capital infusions.The U.S. federal government enacted emergency legislation in an attempt to stabilize the economy, increased the federal deposit insurance, invested billions of dollars in financial institutions and is taking other steps to infuse liquidity into the economy. The global nature of this credit crisis led other governments to institute similar measures. These conditions, combined with volatile oil, gas and other commodity prices, declining business and consumer confidence and increased unemployment have in the weeks subsequent to the end of the quarter contributed to volatility of unprecedented levels.

As a result of these market conditions, the cost and availability of credit has been and may continue to be adversely affected by illiquid credit markets and significantly wider credit spreads. Concern about the general stability of the markets and the credit strength of counterparties has led many lenders and institutional investors to reduce, and in some cases, cease to provide funding to borrowers. Continued turbulence in the U.S. and international markets and economies may adversely affect our liquidity and financial condition, and the liquidity and financial condition of our customers. Although in some cases, certain strong investment grade regulated utilities have been able to issue debt in the capital markets, the cost of this capital has increased and, if these poor market conditions continue, it may limit the Company’s ability to access the bank and debt markets to meet liquidity and capital expenditure needs, resulting in adverse effects on the timing and amount of the Company’s capital expenditures, financial condition and results of operations.

Capital Expenditures

The Company has significant future capital requirements. Forecasted capital expenditures for fiscal 2008, which exclude non-cash equity AFUDC, are approximately $4.2 billion. Capital expenditure needs are reviewed regularly by management and may change significantly as a result of these reviews, which may consider, among other factors, changes in rules and regulations, including environmental and nuclear, changes in income tax laws, general business conditions, load projections, system reliability standards, the cost and efficiency of construction labor, equipment, and materials, and the cost and availability of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered.

Forecasted capital expenditures for fiscal 2008 include the following:

· Combined, PacifiCorp and MidAmerican Energy anticipate spending $1.7 billion on wind-powered generation facilities of which 1,142.5 MW (nameplate ratings) are expected to be placed in service in 2008. During 2008, PacifiCorp entered into multiple new purchase commitments totaling $441 million for wind turbines related to the construction of wind generation facilities that will be placed in service at various dates through 2010. The progress payments for 2008 are estimated to be $191 million, which is included in the above estimate.

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· Combined, PacifiCorp and MidAmerican Energy are projecting to spend $305 million for emissions control equipment in 2008.

· PacifiCorp expects to spend $113 million for transmission system expansion and upgrades for the year ended December 31, 2008, which includes the construction of a 135-mile, double-circuit, 345-kilovolt transmission line to be built between the Populus substation located in southern Idaho and the Terminal substation located in the Salt Lake City area, one of the first major segments of the Energy Gateway Transmission Expansion Project. This transmission line will be constructed in the Path C Transmission corridor, a primary transmission corridor in PacifiCorp’s balancing authority area. PacifiCorp expects to complete construction of this line in 2010. PacifiCorp executed the engineering, procurement and construction agreement effective September 2008 for the Populus to Terminal segment. PacifiCorp is committed to making progress payments for the construction of the Populus to Terminal segment totaling $581 million. The progress payments for 2008 are estimated to be $67 million, which is included in the estimate above.

· Projects mainly for distribution, transmission, generation, mining and other infrastructure needed to serve existing and growing demand.

In July 2008, PacifiCorp filed a petition for declaratory order with the FERC to confirm incentive rate treatment for the Energy Gateway Transmission Expansion Project. The Energy Gateway Transmission Expansion Project is an investment plan to build more than 1,900 miles of new high-voltage transmission lines primarily in Wyoming, Utah, Idaho, Oregon and the desert Southwest. The plan, with an estimated cost which could exceed $6 billion, depending on the ultimate configuration and timing of each segment, includes projects that will address customer base growth and customers’ increasing electric energy use, improve system reliability and deliver wind and other renewable generation resources to more customers throughout PacifiCorp’s six-state service area and the Western United States. Several transmission segments associated with this plan are expected to be placed in service beginning 2010 with major segments in service by 2014, depending on siting, permitting and construction timeframes. In October 2008, the FERC granted a 200 basis point (two percentage point) incentive rate adder to PacifiCorp’s base return on equity for seven of the eight project segments. The FERC did not preclude PacifiCorp from filing for incentive rate treatment for the remaining segment at a future date.

The Company is subject to federal, state, local and foreign laws and regulations with regard to air and water quality, renewable portfolio standards, hazardous and solid waste disposal and other environmental matters. The future costs (beyond existing planned capital expenditures) of complying with applicable environmental laws, regulations and rules cannot yet be reasonably estimated but are expected to be material to the Company. In particular, future mandates, including those associated with addressing the issue of global climate change, may impact the operation of the Company’s domestic generating facilities and may require PacifiCorp, MidAmerican Energy and other company-owned generation assets to reduce emissions at their facilities through the installation of additional emission control equipment or to purchase additional emission allowances or offsets in the future. The Company is not aware of any proven commercially available technology that eliminates or captures and stores carbon dioxide emissions from coal-fired and gas-fired generation facilities, and the Company is uncertain when, or if, such technology will be commercially available.

Refer to the Environmental Regulation section of Item 1 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2007 for a detailed discussion of the topic.

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Acquisitions and Joint Ventures

Constellation Energy

On September 19, 2008, MEHC, Constellation Energy and MEHC Merger Sub Inc. (“Merger Sub”) signed an Agreement and Plan of Merger (the “Merger Agreement”), under which Constellation Energy will become a wholly-owned subsidiary of MEHC. If the merger is completed, MEHC would purchase all of the outstanding shares of Constellation Energy common stock for cash consideration of approximately $4.7 billion, or $26.50 per share. MEHC will finance the $4.7 billion merger consideration through the issuance of approximately $2.7 billion of its common stock to Berkshire Hathaway and potentially to its other existing shareholders and the issuance of $2.0 billion of 11% trust preferred securities to Berkshire Hathaway. The 11% trust preferred securities will have dividend provisions and terms similar to comparable provisions in the existing 11% trust preferred securities previously issued to Berkshire Hathaway and its subsidiaries. Pursuant to the Merger Agreement and the stock purchase agreement, MEHC has invested $1.0 billion in Constellation Energy in exchange for its Constellation Energy Series A Preferred Stock. The merger is not subject to a financing condition. In November 2008, MEHC entered into an agreement which allows Constellation Energy to sell to MEHC certain generating assets at predetermined prices for up to $350 million of cash.

Refer to Note 3 of Notes to Consolidated Financial Statements included in Item 1 of this Form 10-Q for additional discussion regarding the merger with Constellation Energy, the Constellation Energy Series A Preferred Stock and certain related matters.

BYD Company Limited

In September 2008, MEHC reached a definitive agreement with BYD Company Limited (“BYD”) to purchase 225 million shares, representing approximately a 10% interest in the company, at a price of HK$8 per share or HK$1.8 billion (approximately $230 million). MEHC will finance the investment by issuing common shares to Berkshire Hathaway in the second quarter of 2009. Refer to Note 3 of Notes to Consolidated Financial Statements included in Item 1 of this Form 10-Q for additional discussion regarding the proposed transaction.

Electric Transmission Joint Ventures

In December 2007, the Public Utility Commission of Texas (“PUCT”) approved Electric Transmission Texas, LLC’s (“ETT”) initial rates, its request for a transfer of facilities and a certificate of convenience and necessity to operate as a stand alone transmission utility in the Electric Reliability Council of Texas (“ERCOT”) region. ETT was awarded a 9.96% after tax return on equity rate in those approvals. In 2008, intervenors filed a notice of appeal to the Travis County District Court. In October 2008, the court ruled that the PUCT exceeded its authority by approving ETT’s application as a stand alone transmission utility without a service area under the wrong section of the statute. ETT believes that ruling is incorrect. Moreover, ETT provided evidence in its application that ETT has complied with what the court determined was the proper section of the statute. ETT cannot predict the outcome of this proceeding or its future effect on ETT’s financial results. As of September 30, 2008, the Company’s net investment in ETT was $16 million.

Investment Trust Valuation

The Company sponsors defined benefit pension plans and postretirement benefit plans that cover the majority of its employees. The investments within the associated employee benefit plan trusts incurred market losses of approximately $529 million, or 13%, during the first nine months of 2008. The benefit plan assets and obligations of plans are measured as of December 31 each year. Reductions in plan assets as a result of investment losses may result in a change in individual plan funded status and a decrease (increase) in regulatory assets (liabilities) for our Domestic Regulated Businesses and a decrease (increase) in shareholders’ equity for MEHC and CE Electric UK. Changes in the value of plan assets will not have an impact on earnings for 2008; however, reduced benefit plan assets may result in increased benefit costs in future years and may increase the amount and accelerate the timing of required future funding contributions.

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Nuclear decommissioning trust funds have been established for the Quad Cities Nuclear Station Units 1 and 2 to satisfy MidAmerican Energy’s nuclear decommissioning obligations. These funds will not be needed until decommissioning commences. Current licenses for the Quad Cities Station provide for operation until December 14, 2032. These investments in debt and equity securities are classified as available-for-sale and are reported at fair value. Funds are invested in the trust in accordance with applicable federal and state investment guidelines and are restricted for use as reimbursement for costs of decommissioning the Quad Cities Station. The investments within the associated trusts incurred market losses of approximately $27 million, or 10%, during the first nine months of 2008. Should the trust funds continue to experience declines in market value, MidAmerican Energy may be required to take measures, such as making additional contributions to the trusts or providing financial guarantees through letters of credit or guarantees, to assure regulatory authorities that the trusts are adequately funded.

PacifiCorp has established a trust for the investment of funds for final reclamation of a leased coal mining property. These investments in debt and equity securities are classified as available-for-sale and are reported at fair value and include the minority interest joint-owner portions. Amounts funded are based on estimated future reclamation costs and estimated future coal deliveries. The investments within the associated trusts incurred market losses of approximately $12 million, or 10%, during the first nine months of 2008.

Contractual Obligations and Commercial Commitments

Subsequent to December 31, 2007, there were no material changes outside the normal course of business in the contractual obligations and commercial commitments from the information provided in Item 7 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2007, other than the 2008 debt issuances previously discussed, the acquisitions discussed in Note 3 and the commercial commitments discussed in Note 10 of Notes to Consolidated Financial Statements included in Item 1 of this Form 10-Q. Additionally, refer to the “Capital Expenditures” and “Investment Trust Valuation” discussions included in “Liquidity and Capital Resources.”

Credit Ratings

On September 18, 2008, Standard & Poor’s placed MEHC’s debt credit ratings on CreditWatch with negative implications. As of September 30, 2008, MEHC’s senior unsecured debt credit ratings were as follows: Moody’s Investor Service, “Baa1/stable;” Standard & Poor’s, “BBB+/watch negative;” and Fitch Ratings, “BBB+/stable.” Debt and preferred securities of MEHC and certain of its subsidiaries are 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 issued debt or preferred securities. 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.

MEHC and its subsidiaries have no credit rating downgrade triggers that would accelerate the maturity dates of outstanding debt and a change in ratings is not an event of default under the applicable debt instruments. The Company’s unsecured revolving credit facilities do not require the maintenance of a minimum credit rating level in order to draw upon their availability, but under certain instances must maintain sufficient covenant tests if ratings drop below a certain level. However, commitment fees and interest rates under the credit facilities are tied to credit ratings and increase or decrease when the ratings change. A ratings downgrade could also increase the future cost of commercial paper, short- and long-term debt issuances or new credit facilities.

A change in PacifiCorp’s or MidAmerican Energy’s credit rating could result in the requirement to post cash collateral, letters of credit or other similar credit support under certain agreements related to their procurement or sale of electricity, natural gas, coal, transportation and other supplies. In accordance with industry practice, PacifiCorp’s and MidAmerican Energy’s agreements may either specifically provide bilateral rights to demand cash or other security if credit exposures on a net basis exceed certain ratings-dependent threshold levels 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. As of September 30, 2008, PacifiCorp’s and MidAmerican Energy’s credit ratings from the three recognized credit rating agencies were investment grade; however, if the ratings fell one rating below investment grade, PacifiCorp’s and MidAmerican Energy’s collateral requirements would increase by approximately $340 million and $226 million, respectively. The collateral requirements could fluctuate considerably due to seasonality, market price volatility, a loss of key generating facilities or other related factors.

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Regulatory Matters

In addition to the discussion contained herein regarding updates to regulatory matters based upon material changes that occurred subsequent to December 31, 2007, refer to Note 5 of Notes to Consolidated Financial Statements included in Item 1 of this Form 10-Q for additional regulatory matter updates.

Federal Regulation

Northwest Power Act

The Northwest Power Act, through the Residential Exchange Program, provides access to the benefits of low-cost federal hydroelectricity to the residential and small-farm customers of the region’s investor-owned utilities. The program is administered by the Bonneville Power Administration (the "BPA") in accordance with federal law. Pursuant to agreements between the BPA and PacifiCorp, benefits from the BPA are passed through to PacifiCorp’s Oregon, Washington and Idaho residential and small-farm customers in the form of electricity bill credits.

Several publicly owned utilities, cooperatives and the BPA’s direct-service industry customers filed lawsuits against the BPA with the United States Court of Appeals for the Ninth Circuit (the "Ninth Circuit") seeking review of certain aspects of the BPA’s Residential Exchange Program, as well as challenging the level of benefits previously paid to investor-owned utility customers. In May 2007, the Ninth Circuit issued two decisions that resulted in the BPA suspending payments to the Pacific Northwest’s six utilities, including PacifiCorp. This resulted in increases to PacifiCorp’s residential and small-farm customers’ electric bills in Oregon, Washington and Idaho.

In February 2008, the BPA initiated a rate proceeding under the Northwest Power Act to reconsider the level of benefits for the years 2002 through 2006 consistent with the Ninth Circuit’s decisions to re-establish the level of benefits for years 2007 and 2008 and to set the level of benefits for years 2009 and beyond. Also in February 2008, the BPA offered PacifiCorp and other investor-owned utilities an interim agreement intended to resume customer benefits pending the outcome of the rate proceeding. In March 2008, the OPUC ordered PacifiCorp to not execute the interim agreement offered by the BPA because the benefits offered were subject to true-up and acceptance of the benefits before the conclusion of the rate proceeding was not in the best interest of customers. In March and May 2008, PacifiCorp and other parties submitted testimony in the BPA rate proceeding and initial legal briefing was completed in June 2008. The BPA issued its final record of decision in September 2008 establishing rates for the time period of October 2008 through September 2009. In September 2008, the OPUC approved PacifiCorp's request to execute the residential purchase and sale agreement for the payment of Residential Exchange Program benefits from the BPA. In October 2008, PacifiCorp filed revised tariff sheets in both Oregon and Washington to resume residential exchange credits for customer invoices. The OPUC and WUTC approved the tariff sheet filings in October 2008, with an effective date of November 1, 2008. Because the benefit payments from the BPA are passed through to PacifiCorp’s customers, the outcome of this matter will not have a significant effect on the Company’s consolidated financial results.

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State Regulatory Actions

PacifiCorp is currently pursuing a regulatory program in all states, with the objective of keeping rates closely aligned to ongoing costs.

Utah

In December 2007, PacifiCorp filed a general rate case with the UPSC requesting an annual increase of $161 million, or an average price increase of 11%. The increase is primarily due to increased capital spending and net power costs, both of which are driven by load growth. In March 2008, PacifiCorp filed supplemental testimony reducing the requested rate increase to $100 million. The decrease was primarily a result of a UPSC-ordered change in the test period and reductions associated with recent UPSC orders on depreciation rate changes and two deferred accounting requests. Subsequently, hearings were held on the revenue requirement portion of the case and PacifiCorp filed additional testimony. In August 2008, the UPSC issued its revenue requirement order in the case, increasing rates by $36 million, or 3%. The new rates became effective August 13, 2008. In September 2008, PacifiCorp filed a petition for reconsideration of several elements of the order. In October 2008, the UPSC issued an order on the reconsideration petition allowing PacifiCorp to recover an additional $3 million, bringing the total rate increase to $39 million. A settlement that provides for an equal percentage increase to all tariff customers was reached in the rate-design phase of the case and was approved by the UPSC.

In July 2008, PacifiCorp filed a general rate case with the UPSC requesting an annual increase of $161 million over PacifiCorp’s then-current rates, or an average price increase of 11%, prior to any consideration for the UPSC’s order in the December 2007 case described above. In September 2008, PacifiCorp filed supplemental testimony that reflected then-current revenues and other adjustments based on the August 2008 order in the 2007 general rate case. The supplemental filing reduced PacifiCorp’s request to $115 million. In October 2008, the UPSC issued an order changing the test period from the twelve months ending June 30, 2009 using end-of-period rate base to the forecast calendar year 2009 using average rate base. PacifiCorp is required to update its filing to reflect the change in test period by December 1, 2008. The UPSC issued an order resetting the beginning of the 240-day statutory time period required to process the case to the date of the September 2008 supplemental filing. Based on the new time period, the new rates, if approved, will become effective in May 2009.

Oregon

In April 2008, PacifiCorp filed its first annual renewable adjustment clause to recover the revenue requirement related to new renewable resources and associated transmission that are eligible under the Oregon Renewable Energy Act and are not reflected in general rates. PacifiCorp requested an annual increase of $39 million on an Oregon-allocated basis, or an average price increase of 4%. The OPUC is expected to issue a decision in November 2008, with rates effective January 1, 2009.

In July 2008, as part of its annual transition adjustment mechanism, PacifiCorp filed updated forecasted net power costs for 2009. PacifiCorp proposed a net power cost increase of $57 million on an Oregon-allocated basis, or an average price increase of 6%. In September 2008, PacifiCorp filed a stipulation agreement reducing the proposed net power cost increase to $34 million on an Oregon-allocated basis, or an average price increase of 2%. The forecasted net power costs will be updated again in early November 2008 for OPUC-ordered changes, changes to the forward price curve and new wholesale sales and purchases. A final update for changes in the forward price curve will be filed in November 2008. The new rates will become effective January 1, 2009.

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Wyoming

In June 2007, PacifiCorp filed a general rate case with the Wyoming Public Service Commission (the “WPSC”) requesting an annual increase of $36 million, or an average price increase of 8%. In addition, PacifiCorp requested approval of a new renewable resource recovery mechanism and a marginal cost pricing tariff to better reflect the cost of adding new generation. In January 2008, PacifiCorp reached a settlement in principle with parties to the case, subject to approval by the WPSC. The settlement provides for an annual rate increase of $23 million, or an average price increase of 5%. In addition, the parties also agreed to modify the current power cost adjustment mechanism (“PCAM”) to use forecasted power costs in the future and to terminate the PCAM by April 2011, unless a continuation is specifically applied for by PacifiCorp and approved by the WPSC. PacifiCorp’s marginal cost pricing tariff proposal will not be implemented, but will be the subject of a collaborative process to seek a new pricing proposal. Also as part of the settlement, PacifiCorp agreed to withdraw from this filing its request for a renewable resource recovery mechanism. The stipulation was approved by the WPSC in March 2008. The new rates were effective May 1, 2008.

In February 2008, PacifiCorp filed its annual PCAM application with the WPSC for costs incurred during the period December 1, 2006 through November 30, 2007. In March 2008, the WPSC approved PacifiCorp’s request on an interim basis effective April 1, 2008, resulting in a rate increase of $31 million, or an average price increase of 8%, to recover deferred power costs over a one-year period. In August 2008, PacifiCorp reached an agreement with parties to the case to adjust the rate increase to $29 million. The settlement agreement was filed with the WPSC in August 2008. In September 2008, the WPSC issued a bench order approving the stipulation agreement. The interim rates were revised to reflect the $29 million increase approved in the stipulation agreement and became effective October 15, 2008.

In July 2008, PacifiCorp filed a general rate case with the WPSC requesting an annual increase of $34 million, or an average price increase of 7%, with an effective date in May 2009. Power costs have been excluded from the filing and will be addressed separately in PacifiCorp’s annual PCAM application in February 2009.

Washington

In February 2008, PacifiCorp filed a general rate case with the WUTC for an annual increase of $35 million, or an average price increase of 15%. In August 2008, PacifiCorp filed with the WUTC an all-party settlement agreement in which the parties agreed to an overall rate increase of $20 million, or 9%. The settlement was approved by the WUTC in October 2008 with the new rates effective October 15, 2008. The increase is composed of an $18 million increase to base rates, as well as a $2 million annual surcharge for approximately three years related to recovery of higher power costs incurred in 2005 due to poor hydroelectric conditions. The total recovery of the higher power costs will be $6 million plus interest. PacifiCorp agreed to drop the current proposal for a generation cost adjustment mechanism (“GCAM”) and further committed that PacifiCorp would not propose a GCAM in the next general rate case.

Idaho

In September 2008, PacifiCorp filed a general rate case with the Idaho Public Utilities Commission (the “IPUC”) for an annual increase of $6 million, or an average price increase of 4%, with an effective date of April 18, 2009. The increase is primarily due to increased capital spending and net power costs.

In October 2008, PacifiCorp filed a request with the IPUC for approval of an annual energy cost adjustment mechanism (“ECAM”) to defer the difference between base net power costs set during a general rate case and actual net power costs incurred by PacifiCorp. If approved, annually on April 1 PacifiCorp would file an application with the IPUC to adjust the ECAM surcharge rate beginning June 1 to refund or collect the ECAM deferred balance from the end of the prior calendar year.

Environmental Matters

In addition to the discussion contained herein, refer to Note 9 of Notes to Consolidated Financial Statements included in Item 1 of this Form 10-Q and Item 1 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2007 for additional information regarding certain environmental matters affecting PacifiCorp’s and MidAmerican Energy’s operations.

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National Ambient Air Quality Standards

The EPA implements national ambient air quality standards for ozone and fine particulate matter, as well as for other criteria pollutants that set the minimum level of air quality for the United States. Areas that achieve the standards, as determined by ambient air quality monitoring, are characterized as being in attainment, while those that fail to meet the standards are designated as being nonattainment areas. Generally, sources of emissions in a nonattainment area are required to make emissions reductions. A new, more stringent standard for fine particulate matter became effective on December 18, 2006, but is under legal challenge in the United States Court of Appeals for the District of Columbia Circuit. On September 2, 2008, the EPA recommended that all of Scott and Muscatine Counties in Iowa and Rock Island County in Illinois be designated as being in nonattainment of the fine particulate standard adopted in December 2006. MidAmerican Energy’s Riverside coal-fired generating facility is located in Scott County, Iowa and its Louisa coal-fired generating facility is located in Louisa County, adjacent to Muscatine County, Iowa. The Iowa Department of Natural Resources disagrees with the EPA’s recommended nonattainment designation for all of Scott and Muscatine Counties and believes that the nonattainment boundaries should be drawn more narrowly to include only those facilities they believe have caused the monitored exceedances of the standard. The EPA plans to make its final designations regarding nonattainment by December 18, 2008. Until the final designations have been made, it cannot be determined what impact the nonattainment designation may have on the operation of MidAmerican Energy’s facilities.

Regulated Air Pollutants

In March 2005, the EPA released the final Clean Air Interstate Rule (“CAIR”), calling for reductions of sulfur dioxide (“SO2”) and nitrogen oxide (“NOx”) emissions in the Eastern United States through, at each state’s option, a market-based cap and trade system, emission reductions, or both because of contributions to downwind nonattainment of the fine particulate matter and ozone standards. The SO2 and NOx emissions reductions were planned to be accomplished in two phases, in 2009-2010 and 2015. However, on July 11, 2008, the United States Court of Appeals for the District of Columbia Circuit held that the CAIR was fatally flawed and vacated the rule, remanding it to the EPA to consider which states are included in CAIR based on their contribution to nonattainment and connect states’ emission reductions to contributions to nonattainment in addition to distributing allowances appropriately. On September 24, 2008, the EPA and others filed a petition for rehearing to the full court of the CAIR. On October 21, 2008, the United States Court of Appeals for the District of Columbia Circuit, on its own motion, ordered the parties to the appeal to file additional briefs on two issues, including whether the parties seek to have the CAIR vacated and whether the court should stay its mandate until the EPA promulgates a revised rule. Given the court’s ruling, the pending petition for rehearing, and the request for additional briefing, it is unknown when reductions in emissions of SO2 and NOx will be required or the level of any required reductions on MidAmerican Energy’s generation facilities. PacifiCorp’s generation facilities are not subject to the CAIR. Under the CAIR, a market for trading SO2 and NOx emission credits had developed. As a result of the rule being vacated, that market has been adversely affected and the value of credits has declined. While MidAmerican Energy participated in the market for SO2 credits, management does not expect these market declines to be material to the Company.

The Clean Air Mercury Rule (“CAMR”), issued in 2005, set up an emissions trading system to reduce mercury emissions. The rule was unanimously overturned on February 8, 2008 by a three-judge panel of the United States Court of Appeals for the District of Columbia Circuit. On September 17, 2008, the Utility Air Regulatory Group petitioned the United States Supreme Court for a writ of certiorari to review the United States Court of Appeals for the District of Columbia Circuit’s February 8, 2008 decision overturning the rule. The EPA filed a petition to the United States Supreme Court on October 17, 2008 seeking to overturn the lower court’s ruling.

The emissions reductions could be made more stringent by current or future regulatory and legislative proposals at the federal or state levels that would result in significant reductions of SO2, NOX and mercury, as well as carbon dioxide and other gases that may affect global climate change.

Regional Haze

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. In accordance with the federal requirements, states were required to submit state implementation plans by December 2007 to demonstrate reasonable progress toward achieving natural visibility conditions in certain Class I areas by requiring emission controls, known as best available retrofit technology (“BART”), on sources with emissions that are anticipated to cause or contribute to impairment of visibility. Iowa submitted its state implementation plan to the EPA by December 2007 and suggested that the emission reductions already made by MidAmerican Energy and additional reductions that will be made under the CAIR place the state in the position that no further reductions should be required. However, because the court has vacated the CAIR, emissions reductions could be required under the regional haze provisions at MidAmerican Energy’s BART-eligible sources. Until the outcome of the CAIR or its replacement is better known, it is not known whether emissions reductions will be required under this provision.

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Renewable Portfolio Standards

In March 2008, Utah’s governor signed Utah Senate Bill 202, “Energy Resource and Carbon Emission Reduction Initiative.” Among other things, this law provides that, beginning in the year 2025, 20% of adjusted retail electric sales of all Utah utilities be supplied by renewable energy, if it is cost-effective. Retail electric sales will be adjusted by deducting the amount of generation from sources that produce zero or reduced carbon emissions, and for sales avoided as a result of energy efficiency and demand-side management programs. Qualifying renewable energy sources can be located anywhere in the Western Electricity Coordinating Council areas, and renewable energy credits can be used. The costs of complying with the law will be a system cost and are expected to be recovered in retail rates in all states served, either through rate cases or adjustment mechanisms.

New Accounting Pronouncements

For a discussion of new accounting pronouncements affecting the Company, refer to Note 2 of Notes to Consolidated Financial Statements included in Item 1 of this Form 10-Q.

Critical Accounting Policies

Certain accounting policies require management to make estimates and judgments concerning transactions that will be settled in the future. Amounts recognized in the Consolidated Financial Statements from such estimates are necessarily based on numerous assumptions involving varying and potentially significant degrees of judgment and uncertainty. Accordingly, the amounts currently reflected in the Consolidated Financial Statements will likely increase or decrease in the future as additional information becomes available. Estimates are used for, but not limited to, the accounting for the effects of certain types of regulation, derivatives, impairment of long-lived assets and goodwill, pension and other postretirement obligations, income taxes and revenue recognition - unbilled revenue. For additional discussion of the Company’s critical accounting policies, see Item 7 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2007. The Company’s critical accounting policies have not changed materially since December 31, 2007.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

For quantitative and qualitative disclosures about market risk affecting the Company, see Item 7A of the Company’s Annual Report on Form 10-K for the year ended December 31, 2007. The Company’s exposure to market risk and its management of such risk has not changed materially since December 31, 2007. The recent unprecedented volatility in the capital and credit markets has developed rapidly and may create additional risks in the future. Refer to Note 7 of Notes to Consolidated Financial Statements included in Item 1 of this Form 10-Q for disclosure of the Company’s derivative positions as of September 30, 2008 and December 31, 2007.

Foreign Currency Risk

MEHC’s business operations and investments outside the United States increase its risk related to fluctuations in foreign currency rates primarily in relation to the British pound. Our principal reporting currency is the United States dollar, and the value of the assets and liabilities, earnings, cash flows and potential distributions from our foreign operations changes with the fluctuations of the currency in which they transact.

CE Electric UK’s functional currency is the British pound. As a result of the strengthening of the United States dollar versus the British pound since December 31, 2007, MEHC’s Consolidated Balance Sheet was negatively impacted by a $304 million cumulative translation adjustment recorded in accumulated other comprehensive (loss) income, net. The decline in the average currency exchange rate of the British pound versus the United States dollar also resulted in lower reported earnings at CE Electric UK of $6 million for the nine month period ended September 30, 2008.

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Credit Risk

As of September 30, 2008, 64% of PacifiCorp’s and 80% of MidAmerican Energy’s credit exposure, net of collateral, from wholesale operations was with counterparties having externally rated “investment grade” credit ratings, while an additional 6% of PacifiCorp’s and 17% of MidAmerican Energy’s credit exposure, net of collateral, from wholesale operations was with counterparties having financial characteristics deemed equivalent to “investment grade” by PacifiCorp and MidAmerican Energy based on internal review.

For the nine month period ended September 30, 2008, the Company has not experienced a significant increase in customers’ inability to pay, or pay on time, amounts owed to the Company. Management continues to closely monitor credit risks and has heightened collection efforts, including the evaluation of counterparty credit risk. The Company’s bad debt expense has not materially changed for the first nine months of 2008 as compared to 2007.

Interest Rate Risk

As of September 30, 2008, the Company had floating-rate obligations totaling $997 million that expose the Company to the risk of increased interest expense in the event of increases in short-term interest rates. Changes in floating interest rates have not had a material impact on the Company’s consolidated interest expense for the nine month period ended September 30, 2008.

Refer to the “Liquidity and Capital Resources” discussion in Item 2 of this Form 10-Q for a discussion regarding the current debt markets and the potential impact to the Company.

Item 4(T). Controls and Procedures

At the end of the period covered by this Quarterly Report on Form 10-Q, the Company carried out an evaluation, under the supervision and with the participation of the Company’s management, including the Chief Executive Officer (principal executive officer) and the Chief Financial Officer (principal financial officer), of 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). Based upon that evaluation, the Company’s management, including the Chief Executive Officer (principal executive officer) and the Chief Financial Officer (principal financial officer), concluded that the Company’s disclosure controls and procedures were effective to ensure that information required to be disclosed by the Company in the reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and is accumulated and communicated to management, including the Company’s Chief Executive Officer (principal executive officer) and Chief Financial Officer (principal financial officer), or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure. There has been no change in the Company’s internal control over financial reporting during the quarter ended September 30, 2008 that has materially affected, or is reasonably likely to materially affect, the Company’s internal control over financial reporting.

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PART II – OTHER INFORMATION

Item 1. Legal Proceedings

For a description of certain legal proceedings affecting the Company, refer to Item 3 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2007 and Part II, Item 1 of each of the Company’s Quarterly Reports on Form 10-Q for the quarterly periods ended March 31, 2008 and June 30, 2008. In addition to the discussion contained herein regarding material developments to legal proceedings, refer to Note 10 of Notes to Consolidated Financial Statements included in Part I, Item 1 of this Form 10-Q.

Constellation Energy

Beginning September 18, 2008, six shareholders of Constellation Energy have filed lawsuits in the Circuit Court for Baltimore City, Maryland challenging the proposed merger. Four of those lawsuits were brought as shareholder class actions and two were brought as shareholder derivative actions. The four shareholder class actions claim that Constellation Energy and members of its board of directors breached their fiduciary duties to shareholders in agreeing to the proposed merger. One of these four shareholder class actions also names MEHC as a defendant, alleging that it aided and abetted members of Constellation Energy’s board of directors in breaching their fiduciary duties. The two shareholder derivative actions allege that members of Constellation Energy’s board of directors breached their fiduciary duties to the Company in agreeing to the proposed merger and that MEHC aided and abetted members of the board of directors in breaching their fiduciary duties.

The shareholder class actions and shareholder derivative actions claim that the merger consideration is inadequate and does not maximize value for shareholders, that the sales process leading up to the merger was unreasonably short and procedurally flawed, and that unreasonable deal protection devices were agreed to that ward off competing bids and coerce shareholders into accepting the merger.

There are currently two shareholder class actions pending in the United States District Court of the District of Maryland arising out of the proposed transaction between Constellation Energy and MEHC. MEHC is a defendant in both complaints.

Although MEHC is unable at this time to determine the ultimate outcome of these lawsuits, injunctive relief or an adverse determination in the shareholder class actions or the shareholder derivative actions could result in a cash judgment or settlement and affect our ability to complete the proposed merger with Constellation Energy.

PacifiCorp

In May 2007, PacifiCorp was served with a complaint filed in the United States District Court for the Northern District of California by individual Karuk and Yurok Tribe members, a commercial fisherman, a resort owner and the Klamath Riverkeeper. The complaint alleges that reservoirs behind the hydroelectric dams that PacifiCorp operates on the Klamath River provide an environment for the growth of a blue-green algae known as microcystis aeruginosa, which can generate a toxin called microcystin and cause the plaintiffs physical, property and economic harm. In March 2008, one of the Yurok Tribe members voluntarily dismissed his claims in the case. In April 2008, the court entered a stipulation and order dismissing plaintiff Klamath Riverkeeper’s claims, with prejudice. In July 2008, commercial fisherman Michael Hudson’s claims were dismissed with prejudice, and PacifiCorp filed motions for summary judgment on all remaining plaintiffs for all remaining claims. In August 2008, plaintiff Leaf Hillman, Karuk Tribe member, voluntarily dismissed all his personal injury claims with prejudice. In September 2008, PacifiCorp filed a motion for summary judgment on all of plaintiffs’ claims for public nuisance, private nuisance and negligence. In October 2008, the parties negotiated a final settlement in the matter and a stipulation was filed with the court dismissing all plaintiffs and all remaining claims, with prejudice.

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In May 2004, PacifiCorp was served with a complaint filed in the United States District Court for the District of Oregon (the “District Court”) 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 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 and briefing was completed in March 2006. In February 2008, the Ninth Circuit affirmed the District Court’s 2005 decisions dismissing the case. In May 2008, the plaintiffs filed a petition requesting review by the U.S. Supreme Court. PacifiCorp filed a brief in opposition to the petition in June 2008. In October 2008, the U.S. Supreme Court denied plaintiffs’ petition for review.

Item 1A.  Risk Factors

There has been no material change to the Company’s risk factors from those disclosed in Item 1A of the Company’s Annual Report on Form 10-K for the year ended December 31, 2007.

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.

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SIGNATURES

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

	MIDAMERICAN ENERGY HOLDINGS COMPANY
	(Registrant)
Date: November 7, 2008	/s/ Patrick J. Goodman
	Patrick J. Goodman
	Senior Vice President and Chief Financial Officer
	(principal financial and accounting officer)

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EXHIBIT INDEX

Exhibit No.	Description
15	Awareness Letter of Independent Registered Public Accounting Firm.
31.1	Principal Executive Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2	Principal Financial Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1	Principal Executive Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2	Principal Financial Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

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