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, 2007

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, or a non-accelerated filer. See the definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):

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

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

Yes  ¨  No  T

All of the shares of common equity of MidAmerican Energy Holdings Company are privately held by a limited group of investors. As of October 31, 2007, 74,489,001 shares of common stock were outstanding.

TABLE OF CONTENTS

Item 1.	Financial Statements	3
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	23
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	36
Item 4.	Controls and Procedures	36
PART II – OTHER INFORMATION
Item 1.	Legal Proceedings	37
Item 1A.	Risk Factors	37
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	37
Item 3.	Defaults Upon Senior Securities	37
Item 4.	Submission of Matters to a Vote of Security Holders	37
Item 5.	Other Information	37
Item 6.	Exhibits	37
Signatures		38
Exhibit Index		39

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, 2007, and the related consolidated statements of operations for the three-month and nine-month periods ended September 30, 2007 and 2006, and of shareholders’ equity and cash flows for the nine-month periods ended September 30, 2007 and 2006. 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, 2006, 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, 2007, 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). In our opinion, the information set forth in the accompanying consolidated balance sheet as of December 31, 2006, 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 2, 2007

3

MIDAMERICAN ENERGY HOLDINGS COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (Unaudited)

(Amounts in millions)

	As of
	September 30,		December 31,
	2007		2006
ASSETS
Current assets:
Cash and cash equivalents	$	1,978	$	343
Accounts receivable, net		1,339		1,280
Inventories		459		407
Derivative contracts		172		236
Guaranteed investment contracts		614		196
Other current assets		687		677
Total current assets		5,249		3,139
Property, plant and equipment, net		25,544		24,039
Goodwill		5,387		5,345
Regulatory assets		1,721		1,827
Derivative contracts		188		248
Deferred charges, investments and other assets		1,497		1,849
Total assets	$	39,586	$	36,447

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,
	2007		2006
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Accounts payable	$	850	$	1,049
Accrued interest		383		306
Accrued property and other taxes		238		231
Derivative contracts		385		271
Other current liabilities		867		713
Short-term debt		206		552
Current portion of long-term debt		2,767		1,103
Current portion of MEHC subordinated debt		234		234
Total current liabilities		5,930		4,459
Other long-term accrued liabilities		1,628		1,716
Regulatory liabilities		1,614		1,839
Derivative contracts		463		618
MEHC senior debt		4,470		3,929
MEHC subordinated debt		958		1,123
Subsidiary and project debt		11,646		11,061
Deferred income taxes		3,546		3,449
Total liabilities		30,255		28,194
Minority interest		119		114
Preferred securities of subsidiaries		128		128
Commitments and contingencies (Note 12)
Shareholders’ equity:
Common stock - 115 shares authorized, no par value, 74 shares issued and  outstanding		-		-
Additional paid-in capital		5,424		5,420
Retained earnings		3,531		2,598
Accumulated other comprehensive income (loss), net		129		(7	)
Total shareholders' equity		9,084		8,011
Total liabilities and shareholders' equity	$	39,586	$	36,447

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,
	2007			2006			2007			2006
Operating revenue	$	3,067		$	2,780		$	9,294		$	7,452
Costs and expenses:
Cost of sales		1,379			1,238			4,279			3,348
Operating expense		705			681			2,112			1,817
Depreciation and amortization		287			245			871			737
Total costs and expenses		2,371			2,164			7,262			5,902
Operating income		696			616			2,032			1,550
Other income (expense):
Interest expense		(336	)		(309	)		(976	)		(839	)
Capitalized interest		13			11			43			26
Interest and dividend income		33			19			75			53
Other income		31			26			86			201
Other expense		(2	)		(2	)		(6	)		(11	)
Total other income (expense)		(261	)		(255	)		(778	)		(570	)
Income before income tax expense, minority interest     and preferred dividends of subsidiaries and equity     income		435			361			1,254			980
Income tax expense		(68	)		(108	)		(328	)		(321	)
Minority interest and preferred dividends of subsidiaries		(5	)		(6	)		(22	)		(20	)
Equity income		22			25			34			35
Net income	$	384		$	272		$	938		$	674

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, 2007 AND 2006

(Amounts in millions)

												Accumulated
	Outstanding					Additional						Other
	Common			Common		Paid-in			Retained			Comprehensive
	Shares			Stock		Capital			Earnings			Income (Loss), Net			Total
Balance, January 1, 2006		9		$	-	$	1,963		$	1,720		$	(298	)	$	3,385
Net income		-			-		-			674			-			674
Other comprehensive income		-			-		-			-			213			213
Preferred stock conversion to common stock		41			-		-			-			-			-
Exercise of common stock options		1			-		13			-			-			13
Tax benefit from exercise of common stock options		-			-		19			-			-			19
Common stock issuances		35			-		5,110			-			-			5,110
Common stock purchases		(12	)		-		(1,712	)		(38	)		-			(1,750	)
Other equity transactions		-			-		3			-			-			3
Balance, September 30, 2006		74		$	-	$	5,396		$	2,356		$	(85	)	$	7,667
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

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,
	2007			2006
Cash flows from operating activities:
Net Income	$	938		$	674
Adjustments to reconcile net income to cash flows from operations:
Gain on other items, net		(10	)		(135	)
Depreciation and amortization		871			737
Amortization of regulatory assets and liabilities		(13	)		31
Provision for deferred income taxes		42			219
Other		(83	)		35
Changes in other items, net of effects from acquisitions:
Accounts receivable and other current assets		(106	)		182
Accounts payable and other accrued liabilities		257			(99	)
Net cash flows from operating activities		1,896			1,644
Cash flows from investing activities:
PacifiCorp acquisition, net of cash acquired		-			(4,932	)
Other acquisitions, net of cash acquired		-			(74	)
Capital expenditures relating to operating projects		(1,220	)		(1,140	)
Construction and other development costs		(1,302	)		(595	)
Purchases of available-for-sale securities		(1,260	)		(1,088	)
Proceeds from sale of available-for-sale securities		1,219			1,185
Proceeds from sale of assets		65			17
Decrease (increase) in restricted cash and investments		56			(44	)
Other		(5	)		14
Net cash flows from investing activities		(2,447	)		(6,657	)
Cash flows from financing activities:
Proceeds from the issuances of common stock		-			5,123
Purchases of common stock		-			(1,750	)
Proceeds from MEHC senior debt		1,539			1,699
Repayments of MEHC subordinated debt		(167	)		(167	)
Proceeds from subsidiary and project debt		1,400			365
Repayments of subsidiary and project debt		(250	)		(257	)
Net (repayment of) proceeds from MEHC revolving credit facility		(152	)		93
Net repayments of subsidiary short-term debt		(194	)		(51	)
Net proceeds from settlement of treasury rate lock agreements		32			53
Other		(27	)		(23	)
Net cash flows from financing activities		2,181			5,085
Effect of exchange rate changes		5			3
Net change in cash and cash equivalents		1,635			75
Cash and cash equivalents at beginning of period		343			358
Cash and cash equivalents at end of period	$	1,978		$	433

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 owning subsidiaries (together with MEHC, the “Company”) that are principally engaged in energy businesses. 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 (the subsidiaries owning a majority interest in the Casecnan Project), CalEnergy Generation-Domestic (the subsidiaries 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 domestic and international independent power projects and the second largest residential real estate brokerage firm in the United States.

The accompanying 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 U.S. Securities and Exchange Commission’s 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, 2007, and for the three- and nine-month periods ended September 30, 2007 and 2006. 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, 2007 are not necessarily indicative of the results to be expected for the full year.

The accompanying unaudited Consolidated Financial Statements include the accounts of MEHC and its subsidiaries in which it holds a controlling financial interest. The unaudited 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, 2006, 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 2007, except as described in Note 2.

 (2)   New Accounting Pronouncements

In July 2006, the Financial Accounting Standards Board (“FASB”) issued FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes - an interpretation of FASB Statement No. 109” (“FIN 48”). The Company adopted the provisions of FIN 48 effective January 1, 2007. Under FIN 48, tax benefits are recognized only for tax positions that are more likely than not to be sustained upon examination by tax authorities. The amount recognized is measured as the largest amount of benefit that is greater than 50% likely to be realized upon ultimate settlement. Unrecognized tax benefits are tax benefits claimed in the Company’s tax returns that do not meet these recognition and measurement standards.

9

As of January 1, 2007, the Company had $117 million of unrecognized tax benefits. Of this amount, the Company recognized a net increase in the liability for unrecognized tax benefits of $22 million as a cumulative effect of adopting FIN 48, which was offset by reductions in beginning retained earnings of $5 million, deferred income tax liabilities of $31 million and goodwill of $15 million, respectively, and an increase in regulatory assets of $1 million in the Consolidated Balance Sheet. The remaining $95 million had been previously accrued under Statement of Financial Accounting Standards (“SFAS”) No. 5, “Accounting for Contingencies,” or SFAS No. 109, “Accounting for Income Taxes.” Unrecognized tax benefits are included in other long-term accrued liabilities in the Consolidated Balance Sheet.

Included in the $117 million is $98 million of net unrecognized tax benefits that, if recognized, would have an impact on the effective tax rate. The remaining unrecognized tax benefits relate to tax positions for which ultimate deductibility is highly certain but for which there is uncertainty as to the timing of such deductibility and tax positions related to acquired companies. Recognition of these tax benefits, other than applicable interest and penalties, would not affect the Company’s effective tax rate. The Company recognizes interest and penalties accrued related to unrecognized tax benefits in income tax expense. As of January 1, 2007, the Company had $3 million accrued for the payment of interest and penalties, which is included in unrecognized tax benefits.

MEHC’s parent company files income tax returns in the U.S. federal jurisdiction, and various state and foreign jurisdictions. The U.S. Internal Revenue Service has closed examination of the Company’s income tax returns through 2003. In addition, open tax years related to a number of state and foreign jurisdictions remain subject to examination. During the nine-month period ended September 30, 2007, there were no material changes to the liability for uncertain tax positions.

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 should 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. SFAS No. 159 is effective for fiscal years beginning after November 15, 2007. The Company does not anticipate electing the fair value option for any existing eligible items. However, the Company will continue to evaluate items on a case-by-case basis for consideration of the fair value option.

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. SFAS No. 157 is effective for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. The Company is currently evaluating the impact of adopting SFAS No. 157 on its consolidated financial position and results of operations.

 (3)    PacifiCorp Acquisition

 General

In May 2005, MEHC reached a definitive agreement with Scottish Power plc (“ScottishPower”) and its subsidiary, PacifiCorp Holdings, Inc., to acquire 100% of the common stock of ScottishPower’s wholly-owned indirect subsidiary, PacifiCorp. On March 21, 2006, a wholly owned subsidiary of MEHC acquired 100% of the common stock of PacifiCorp from a wholly owned subsidiary of ScottishPower for a cash purchase price of $5.11 billion, which was funded through the issuance of common stock. MEHC also incurred $10 million of direct transaction costs associated with the acquisition, which consisted principally of investment banker commissions and outside legal and accounting fees, resulting in a total purchase price of $5.12 billion. As a result of the acquisition, MEHC controls substantially all of PacifiCorp’s voting securities, which include both common and preferred stock. The results of PacifiCorp’s operations are included in the Company’s results beginning March 21, 2006 (the “acquisition date”).

10

Allocation of Purchase Price

SFAS No. 141, “Business Combinations,” requires that the total purchase price be allocated to PacifiCorp’s net tangible and identified intangible assets acquired and liabilities assumed based on their estimated fair values at the acquisition date. PacifiCorp’s operations are regulated, which provide revenue derived from cost, and are accounted for pursuant to SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation.” PacifiCorp has demonstrated a past history of recovering its costs incurred through its rate making process. Certain adjustments, which were not significant, related to derivative contracts, severance costs and income taxes were made to the purchase price allocation. The following table summarizes the adjusted fair values of the assets acquired and liabilities assumed as of the acquisition date (in millions):

	Fair Value
Current assets, including cash and cash equivalents of $183	$	1,115
Property, plant and equipment, net		10,047
Goodwill		1,140
Regulatory assets		1,307
Other non-current assets		665
Total assets		14,274
Current liabilities, including short-term debt of $184 and current portion of long-term debt of $221		(1,283	)
Regulatory liabilities		(818	)
Pension and postretirement obligations		(830	)
Subsidiary and project debt, less current portion		(3,762	)
Deferred income taxes		(1,606	)
Other non-current liabilities		(855	)
Total liabilities		(9,154	)
Net assets acquired	$	5,120

Certain transition activities, pursuant to established plans, were undertaken as PacifiCorp was integrated into the Company. Costs, relating primarily to employee termination activities, have been incurred associated with such transition activities, which were completed as of March 31, 2007. The finalization of certain integration plans resulted in adjustments to the purchase price allocation for the acquired assets and assumed liabilities of PacifiCorp. Qualifying severance costs accrued during the three-month period ended March 31, 2007, and the period from the acquisition date to September 30, 2006, totaled $7 million and $33 million, respectively. Accrued severance costs were $34 million and $31 million as of March 31, 2007 and December 31, 2006, respectively.

Pro Forma Financial Information

The following pro forma condensed consolidated results of operations assume that the acquisition of PacifiCorp was completed as of January 1, 2006, and provide information for the nine-month period ended September 30, 2006 (in millions):

Operating revenue	$	8,604
Net income	$	818

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

11

(4) Property, Plant and Equipment, Net

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

		As of
	Depreciation	September 30,			December 31,
	Life	2007			2006
Regulated assets:
Utility generation and distribution system	5-85 years	$	29,679		$	27,687
Interstate pipeline assets	3-67 years		5,375			5,329
			35,054			33,016
Accumulated depreciation and amortization			(12,229	)		(11,872	)
Regulated assets, net			22,825			21,144
Non-regulated assets:
Independent power plants	10-30 years		680			1,184
Other assets	3-30 years		646			586
			1,326			1,770
Accumulated depreciation and amortization			(417	)		(844	)
Non-regulated assets, net			909			926
Net operating assets			23,734			22,070
Construction in progress			1,810			1,969
Property, plant and equipment, net		$	25,544		$	24,039

Substantially all of the construction in progress as of September 30, 2007 and December 31, 2006 relates to the construction of regulated assets.

(5) Jointly Owned Utility Plant

Walter Scott, Jr. Energy Center Unit No. 4 (“WSEC Unit 4”), formerly Council Bluffs Energy Center Unit No. 4, a 790-megawatt (“MW”) (accredited capacity) supercritical, coal-fired generating plant, began commercial operation on June 1, 2007. MidAmerican Energy operates the plant and holds an undivided ownership interest of 59.66%, or approximately 471 MW, as a tenant in common with the other owners of the plant. MidAmerican Energy accounts for, and provided financing for, its proportional share of the plant. In conjunction with WSEC Unit 4 being placed in service, $710 million was transferred from construction in progress to utility generation and distribution system.

12

(6) Regulatory Matters

The following are updates to regulatory matters based upon material changes that occurred subsequent to December 31, 2006.

Rate Matters

Iowa Electric Revenue Sharing

The Iowa Utilities Board (“IUB”) has approved a series of settlement agreements between MidAmerican Energy, the Iowa Office of Consumer Advocate (“OCA”) and other intervenors, under which MidAmerican Energy has agreed not to seek a general increase in electric base rates to become effective prior to January 1, 2014, unless its Iowa jurisdictional electric return on equity for any year covered by the applicable agreement falls below 10%, computed as prescribed in each respective agreement. Prior to filing for a general increase in electric rates, MidAmerican Energy is required to conduct 30 days of good faith negotiations with the signatories to the settlement agreements to attempt to avoid a general increase in such rates. As a party to the settlement agreements, the OCA has agreed not to request or support any decrease in MidAmerican Energy’s Iowa electric base rates to become effective prior to January 1, 2014. The settlement agreements specifically allow the IUB to approve or order electric rate design or cost of service rate changes that could result in changes to rates for specific customers as long as such changes do not result in an overall increase in revenues for MidAmerican Energy.

The settlement agreements also each provide that revenues associated with Iowa retail electric returns on equity within specified ranges will be shared with customers and that the portion assigned to customers will be recorded as a regulatory liability. The following table summarizes the ranges of Iowa electric returns on equity subject to revenue sharing under each settlement agreement, the percent of revenues within those ranges to be assigned to customers, and the method by which the liability to customers will be settled.

		Range of
		Iowa Electric	Customers’
		Return on	Share of	Method to be Used to
Date Approved	Years	Equity Subject	Revenues	Settle Liability to
by the IUB	Covered	to Sharing	Within Range	Customers
December 21, 2001	2001 - 2005	12% - 14%	50%	Credits against the cost of new generation plant in Iowa
		Above 14%	83.33%
October 17, 2003	2006 - 2010	11.75% - 13%	40%	Credits against the cost of new generation plant in Iowa
		13% - 14%	50%
		Above 14%	83.3%

January 31, 2005	2011	Same as 2006 - 2010	Credits to customer bills in 2012
April 18, 2006	2012	Same as 2006 - 2010	Credits to customer bills in 2013
July 27, 2007	2013	Same as 2006 - 2010 (1)	Credits against the cost of wind-powered generation projects covered by this agreement

(1) If a rate case is filed pursuant to the 10% threshold, as discussed above, the revenue sharing arrangement for 2013 is changed such that the amount to be shared with customers will be 83.3% of revenues associated with Iowa operating income in excess of electric returns on equity allowed by the IUB as a result of the rate case.

13

The regulatory liabilities created by the settlement agreements have been and are currently recorded as a regulatory charge in depreciation and amortization expense when the liability is accrued. As a result of the credits applied to generating plant balances when the related plant is placed in service, depreciation expense is reduced over the life of the plant. On June 1, 2007, WSEC Unit 4 was placed in service. Accordingly, $264 million, the January 1, 2007 balance of the revenue sharing liability, plus the related interest accrued in 2007, was applied against the cost of WSEC Unit 4 in utility generation and distribution system.

Refund Matters

PacifiCorp

On June 21, 2007, the Federal Energy Regulatory Commission (“FERC”) approved PacifiCorp’s settlement and release of claims agreement (“Settlement”) with Pacific Gas and Electric Company, Southern California Edison Company, San Diego Gas & Electric Company, the People of the State of California, ex rel. Edmund G. Brown Jr., Attorney General, the California Electricity Oversight Board, and the California Public Utilities Commission (collectively, the “California Parties”), certain of which purchased energy in the California Independent System Operator (“ISO”) and the California Power Exchange (“PX”) markets during past periods of high energy prices in 2000 and 2001. The Settlement, which was executed by PacifiCorp on April 11, 2007, settles claims brought by the California Parties against PacifiCorp for refunds and remedies in numerous related proceedings (together, the “FERC Proceedings”), as well as certain potential civil claims, arising from events and transactions in Western United States energy markets during the period January 1, 2000 through June 20, 2001 (the “Refund Period”). Under the Settlement, PacifiCorp made cash payments to escrows controlled by the California Parties in the amount of $16 million in April 2007, and upon FERC approval of the agreement in June 2007, PacifiCorp allowed the PX to release an additional $12 million to such escrows, which represented PacifiCorp’s estimated unpaid receivable from the transactions in the PX and ISO markets during the Refund Period, plus interest. The monies held in escrow are for distribution to buyers from the ISO and PX markets that purchased power during the Refund Period. The agreement provides for the release of claims by the California Parties (as well as additional parties that join in the Settlement) against PacifiCorp for refunds, disgorgement of profits, or other monetary or non-monetary remedies in the FERC Proceedings, and provides a mutual release of claims for civil damages and equitable relief.

(7) Recent Debt Transactions

On October 23, 2007, PacifiCorp entered into a new unsecured revolving credit facility with total bank commitments of $700 million. The facility will support PacifiCorp’s commercial paper program and terminates on October 23, 2012. Terms and conditions, including borrowing rates, are substantially similar to PacifiCorp’s existing revolving credit facility.

On October 3, 2007, PacifiCorp issued $600 million of 6.25% First Mortgage Bonds due October 15, 2037. The proceeds will be used by PacifiCorp to repay its short-term debt and for general corporate purposes.

On August 28, 2007, MEHC issued $1.0 billion of 6.50% Senior Bonds due September 15, 2037. The proceeds will be used by MEHC to repay at maturity its 3.50% senior notes due in May 2008 in an aggregate principal amount of $450 million and its 7.52% senior notes due in September 2008 in an aggregate principal amount of $550 million. Pending repayment of this indebtedness, the proceeds are being used to repay short-term indebtedness, with the balance invested in short-term securities or used for general corporate purposes.

On June 29, 2007, MidAmerican Energy issued $400 million of 5.65% Senior Notes due July 15, 2012, and $250 million of 5.95% Senior Notes due July 15, 2017. The proceeds are being used by MidAmerican Energy to pay construction costs of its interest in WSEC Unit 4 and its wind projects in Iowa, to repay short-term indebtedness and for general corporate purposes.

On May 11, 2007, MEHC issued $550 million of 5.95% Senior Bonds due May 15, 2037. The proceeds were used by MEHC to repay at maturity its 4.625% senior notes due in October 2007 in an aggregate principal amount of $200 million and its 7.63% senior notes due in October 2007 in an aggregate principal amount of $350 million.

On March 14, 2007, PacifiCorp issued $600 million of 5.75% First Mortgage Bonds due April 1, 2037. The proceeds were used by PacifiCorp to repay its short-term debt and for general corporate purposes.

On February 12, 2007, Northern Natural Gas issued $150 million of 5.8% Senior Bonds due February 15, 2037. The proceeds were used by Northern Natural Gas to fund capital expenditures and for general corporate purposes.

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 (8)   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. MEHC is also exposed to foreign currency risk from its business operations and investments in Great Britain and the Philippines. 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, swaps and options. 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.

The following table summarizes the various derivative mark-to-market positions included in the Consolidated Balance Sheet as of September 30, 2007 (in millions):

												Accumulated
									Regulatory			Other
	Derivative Net Assets (Liabilities)								Net Assets			Comprehensive
	Assets		Liabilities			Net			(Liabilities)			(Income) Loss (1)
Commodity	$	355	$	(671	)	$	(316	)	$	320		$	(4	)
Foreign currency		5		(177	)		(172	)		(4	)		177
Total	$	360	$	(848	)	$	(488	)	$	316		$	173
Current	$	172	$	(385	)	$	(213	)
Non-current		188		(463	)		(275	)
Total	$	360	$	(848	)	$	(488	)

 ⁽¹⁾    Before income taxes.

The following table summarizes the various derivative mark-to-market positions included in the Consolidated Balance Sheet as of December 31, 2006 (in millions):

												Accumulated
									Regulatory			Other
	Derivative Net Assets (Liabilities)								Net Assets			Comprehensive
	Assets		Liabilities			Net			(Liabilities)			(Income) Loss (1)
Commodity	$	467	$	(740	)	$	(273	)	$	247		$	6
Interest rate		13		-			13			-			(13	)
Foreign currency		4		(149	)		(145	)		(3	)		149
Total	$	484	$	(889	)	$	(405	)	$	244		$	142
Current	$	236	$	(271	)	$	(35	)
Non-current		248		(618	)		(370	)
Total	$	484	$	(889	)	$	(405	)

 ⁽¹⁾    Before income taxes.

 (9)  Income Taxes

In July 2007, the Company recognized $61 million of deferred income tax benefits upon the enactment of the reduction in the United Kingdom corporate income tax rate from 30% to 28% to be effective April 1, 2008.

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 (10)   Other Income

Other income consists of the following (in millions):

	Three-Month Periods				Nine-Month Periods
	Ended September 30,				Ended September 30,
	2007		2006		2007		2006
Gain on Mirant bankruptcy claim	$	3	$	-	$	3	$	89
Gains on sales of non-strategic assets and investments		-		1		1		46
Allowance for equity funds used during construction		21		16		61		39
Other		7		9		21		27
Total other income	$	31	$	26	$	86	$	201

Gain on Mirant Americas Energy Marketing (“Mirant”) Bankruptcy Claim

Mirant was one of the shippers that entered into a 15-year, 2003 Expansion Project, firm gas transportation contract (90,000 decatherms per day) with Kern River (the “Mirant Agreement”) and provided a letter of credit equivalent to 12 months of reservation charges as security for its obligations thereunder. In July 2003, Mirant filed for Chapter 11 bankruptcy protection. Kern River claimed $210 million in damages due to the rejection of the Mirant Agreement. The bankruptcy court ultimately determined that Kern River was entitled to a general unsecured claim of $74 million in addition to $15 million of cash collateral. In January 2006, Mirant emerged from bankruptcy. In February 2006, Kern River received an initial distribution of such shares in payment of the majority of its allowed claim. Kern River sold all of the shares of new Mirant stock received from its allowed claim amount plus interest in the first quarter of 2006 and recognized a gain from those sales of $89 million.

(11) Related Party Transactions

As of September 30, 2007 and December 31, 2006, Berkshire Hathaway and its affiliates held 11% mandatory redeemable preferred securities due from certain wholly owned subsidiary trusts of MEHC of $888 million and $1.06 billion, respectively. Interest expense on these securities totaled $26 million and $32 million for the three-month periods ended September 30, 2007 and 2006, respectively, and $84 million and $103 million for the nine-month periods ended September 30, 2007 and 2006, respectively. Accrued interest totaled $19 million and $21 million as of September 30, 2007 and December 31, 2006, respectively.

For the nine-month periods ended September 30, 2007 and 2006, the Company made cash payments for income taxes to Berkshire Hathaway totaling $134 million and $11 million, respectively.

 (12)   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 expense is 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, 2007 and December 31, 2006 was $32 million and $50 million, respectively, and is included in other liabilities and other long-term accrued liabilities on the accompanying 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 48 plants with an aggregate facility net owned capacity of 1,158 MW. The FERC regulates 98% of the net capacity of this portfolio through 18 individual licenses. Several of PacifiCorp’s hydroelectric projects are in some stage of relicensing with the FERC. Hydroelectric relicensing and the related environmental compliance requirements and litigation are subject to uncertainties. PacifiCorp expects that future costs relating to these matters may be significant and will consist primarily of additional relicensing costs, operations and maintenance expense, and capital expenditures. Electricity generation reductions may result from the additional environmental requirements. PacifiCorp had incurred $86 million and $79 million in costs as of September 30, 2007 and December 31, 2006, respectively, for ongoing hydroelectric relicensing, which are included in construction in progress and reflected in property, plant and equipment, net in the accompanying Consolidated Balance Sheets.

In February 2004, PacifiCorp filed with the FERC a final application for a new license to operate the 169-MW nameplate-rated 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. In January 2007, as part of the relicensing process, the United States Departments of Interior and Commerce filed modified terms and conditions consistent with the March 2006 filings, which proposed that PacifiCorp construct upstream and downstream fish passage facilities at the Klamath hydroelectric project’s four mainstem dams. 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. The FERC did not issue its final environmental impact statement in summer 2007 as scheduled, and it has provided no new issuance date. Other federal agencies are also working to complete their endangered species analyses by December 1, 2007. PacifiCorp will need to obtain water quality certifications from Oregon and California prior to the FERC issuing a final license. PacifiCorp currently has applications pending before each state.

In the relicensing of the Klamath hydroelectric project, PacifiCorp had incurred $46 million and $42 million in costs as of September 30, 2007 and December 31, 2006, respectively, which are included in construction in progress and reflected in property, plant and equipment, net in the accompanying 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.

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.

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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 of opacity, which is a measurement of light in the flue of a generating facility. The complaint alleges thousands of violations of asserted 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. A five-day trial on the liability phase is scheduled to begin on April 21, 2008. The remedy-phase trial has not yet been set. 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

Pursuant to the share ownership adjustment mechanism in the CE Casecnan Water and Energy Company, Inc. (“CE Casecnan”) shareholder agreement, which is based upon proforma financial projections of the Casecnan project prepared following commencement of commercial operations, in February 2002, MEHC’s indirect wholly owned subsidiary, CE Casecnan Ltd., advised the minority 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. LPG’s complaint, as amended, seeks compensatory and punitive damages arising out of CE Casecnan Ltd.’s and MEHC’s alleged improper calculation of the proforma financial projections and alleged improper settlement of the National Irrigation Administration arbitration. On January 21, 2004, CE Casecnan Ltd., LPG and CE Casecnan entered into a status quo agreement pursuant to which the parties agreed to set aside certain distributions related to the shares subject to the LPG dispute and CE Casecnan agreed not to take any further actions with respect to such distributions without at least 15 days prior notice to LPG. Accordingly, 15% of the CE Casecnan dividend declarations from 2004 to 2006 was set aside in a separate bank account in the name of CE Casecnan.

On January 3, 2006, the court 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. On February 21, 2007, the appellate court issued a decision, and as a result of the decision, CE Casecnan Ltd. determined that LPG would retain ownership of 10% of the shares of CE Casecnan, with the remaining 5% ownership being transferred to CE Casecnan Ltd. subject to certain buy-up rights under the shareholder agreement. Pursuant to the appellate court decision, on May 7, 2007, CE Casecnan released $22 million of dividends and $4 million of accrued interest from the dividend set aside account representing the 10% share to LPG while the remaining 5% share is still held in escrow. The parties have submitted briefs on the final calculation of the internal rate of return and whether LPG is entitled to buy-up its interest to 15% and, if so, the buy-up price. The parties have agreed to stipulate that the final calculation of the internal rate of return is 24.06%. At a hearing on October 10, 2007, the court determined that LPG was ready, willing and able to exercise its buy-up rights in 2002. Additional hearings were held on October 23 and 24, 2007, regarding the issue of the buy-up price calculation and a written decision is expected soon. LPG waived its request for a jury trial for the breach of fiduciary duty claim and the parties have entered into a stipulation which provides for a trial of such claim by the court based on the existing record of the case. The trial date has been set for March 12, 2008. The Company intends to vigorously defend and pursue the remaining claims.

In February 2003, San Lorenzo Ruiz Builders and Developers Group, Inc. (“San Lorenzo”), an original shareholder substantially all of whose shares in CE Casecnan were purchased by MEHC in 1998, threatened to initiate legal action against the Company in the Philippines in connection with certain aspects of its option to repurchase such shares. The Company believes that San Lorenzo has no valid basis for any claim and, if named as a defendant in any action that may be commenced by San Lorenzo, the Company will vigorously defend such action. On July 1, 2005, MEHC and CE Casecnan Ltd. commenced an action against San Lorenzo in the District Court of Douglas County, Nebraska, seeking a declaratory judgment as to MEHC’s and CE Casecnan Ltd.’s rights vis-à-vis San Lorenzo in respect of such shares. San Lorenzo filed a motion to dismiss on September 19, 2005. Subsequently, San Lorenzo purported to exercise its option to repurchase such shares. On January 30, 2006, San Lorenzo filed a counterclaim against MEHC and CE Casecnan Ltd. seeking declaratory relief that it has effectively exercised its option to purchase 15% of the shares of CE Casecnan, that it is the rightful owner of such shares and that it is due all dividends paid on such shares. On March 9, 2006, the court granted San Lorenzo’s motion to dismiss, but has since permitted MEHC and CE Casecnan Ltd. to file an amended complaint incorporating the purported exercise of the option. The complaint has been amended and the action is proceeding. The impact, if any, of San Lorenzo’s purported exercise of its option and the Nebraska litigation on the Company cannot be determined at this time. The Company intends to vigorously defend the counterclaims.

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(13) Employee Benefit Plans

Domestic Operations

In December 2006, PacifiCorp’s non-bargaining employees were notified that PacifiCorp would switch from a traditional final average pay formula for its retirement plan to a cash balance formula effective June 1, 2007. As a result of the change, benefits under the traditional final average pay formula were frozen as of May 31, 2007, and PacifiCorp’s pension liability and regulatory assets each decreased by $111 million.

The components of the combined net periodic benefit cost for the Company’s domestic pension and other postretirement benefit plans were as follows (in millions):

	Three-Month Periods						Nine-Month Periods
	Ended September 30,						Ended September 30,
	2007			2006			2007			2006
Pension
Service cost	$	15		$	18		$	41		$	39
Interest cost		28			28			84			68
Expected return on plan assets		(29	)		(28	)		(84	)		(67	)
Net amortization		5			9			22			19
Net periodic benefit cost	$	19		$	27		$	63		$	59

Other Postretirement
Service cost	$	2		$	4		$	10		$	10
Interest cost		11			12			36			28
Expected return on plan assets		(9	)		(9	)		(31	)		(21	)
Net amortization		6			7			17			14
Net periodic benefit cost	$	10		$	14		$	32		$	31

Employer contributions to the pension and other postretirement plans are expected to be $94 million and $46 million, respectively, in 2007. As of September 30, 2007, $90 million and $33 million of contributions had been made to the pension and other postretirement plans, respectively.

CE Electric UK

The components of the net periodic benefit cost for the Company’s UK pension plan were as follows (in millions):

	Three-Month Periods						Nine-Month Periods
	Ended September 30,						Ended September 30,
	2007			2006			2007			2006
Service cost	$	6		$	5		$	18		$	14
Interest cost		24			20			70			58
Expected return on plan assets		(30	)		(26	)		(88	)		(75	)
Net amortization		8			9			24			25
Net periodic benefit cost	$	8		$	8		$	24		$	22

Employer contributions to the UK pension plan are expected to be £35 million for 2007. As of September 30, 2007, £27 million, or $53 million, of contributions had been made to the UK pension plan.

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

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

	Three-Month Periods						Nine-Month Periods
	Ended September 30,						Ended September 30,
	2007			2006			2007			2006
Net income	$	384		$	272		$	938		$	674
Other comprehensive income:
Unrecognized amounts on retirement benefits, net of tax of $8(1); $-; $12(1); and $-		(7	)		-			(1	)		-
Minimum pension liability adjustment, net of tax of $-; $(2); $-; and $(8)		-			(3	)		-			(18	)
Foreign currency translation adjustment		52			28			117			164
Fair value adjustment on cash flow hedges, net of tax of $(12); $19; $12; and $41		(20	)		29			18			65
Unrealized gains on marketable securities, net of tax of $-; $2; $1; and $1		1			3			2			2
Total other comprehensive income		26			57			136			213
Comprehensive income	$	410		$	329		$	1,074		$	887

⁽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 income (loss), net is included in the accompanying Consolidated Balance Sheets in the common shareholders’ equity section, and consists of the following components, net of tax, as follows (in millions):

	As of
	September 30,			December 31,
	2007			2006
Unrecognized amounts on retirement benefits, net of tax of $(148) and $(160)	$	(368	)	$	(367	)
Foreign currency translation adjustment		443			326
Fair value adjustment on cash flow hedges, net of tax of $33 and $21		47			29
Unrealized gains on marketable securities, net of tax of $4 and $3		7			5
Total accumulated other comprehensive income (loss), net	$	129		$	(7	)

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 (15)    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,
	2007			2006			2007			2006
Operating revenue:
PacifiCorp	$	1,137		$	1,036		$	3,190		$	1,972
MidAmerican Funding		985			767			3,193			2,570
Northern Natural Gas		118			125			460			442
Kern River		105			64			302			230
CE Electric UK		273			243			775			669
CalEnergy Generation-Foreign		39			82			169			241
CalEnergy Generation-Domestic		9			9			25			25
HomeServices		410			462			1,215			1,335
Corporate/other(1)		(9	)		(8	)		(35	)		(32	)
Total operating revenue	$	3,067		$	2,780		$	9,294		$	7,452
Depreciation and amortization:
PacifiCorp	$	124		$	118		$	367		$	247
MidAmerican Funding		70			59			215			220
Northern Natural Gas		14			15			43			43
Kern River(2)		20			(9	)		59			38
CE Electric UK		46			36			132			100
CalEnergy Generation-Foreign		9			18			44			63
CalEnergy Generation-Domestic		2			2			6			6
HomeServices		6			10			16			26
Corporate/other(1)		(4	)		(4	)		(11	)		(6	)
Total depreciation and amortization	$	287		$	245		$	871		$	737
Operating income:
PacifiCorp	$	269		$	201		$	699		$	354
MidAmerican Funding		171			130			429			343
Northern Natural Gas		32			26			203			170
Kern River		71			59			209			151
CE Electric UK		118			137			390			368
CalEnergy Generation-Foreign		24			57			100			158
CalEnergy Generation-Domestic		4			6			12			12
HomeServices		19			19			46			54
Corporate/other(1)		(12	)		(19	)		(56	)		(60	)
Total operating income		696			616			2,032			1,550
Interest expense		(336	)		(309	)		(976	)		(839	)
Capitalized interest		13			11			43			26
Interest and dividend income		33			19			75			53
Other income		31			26			86			201
Other expense		(2	)		(2	)		(6	)		(11	)
Total income before income tax expense, minority interest and preferred dividends of subsidiaries and equity income	$	435		$	361		$	1,254		$	980

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	Three-Month Periods				Nine-Month Periods
	Ended September 30,				Ended September 30,
	2007		2006		2007		2006
Interest expense:
PacifiCorp	$	76	$	73	$	230	$	150
MidAmerican Funding		48		37		131		114
Northern Natural Gas		15		13		43		38
Kern River		19		20		56		56
CE Electric UK		61		56		178		159
CalEnergy Generation-Foreign		3		5		11		16
CalEnergy Generation-Domestic		4		4		13		13
HomeServices		-		-		1		1
Corporate/other (1)		110		101		313		292
Total interest expense	$	336	$	309	$	976	$	839

	As of
	September 30,		December 31,
	2007		2006
Total assets:
PacifiCorp	$	15,802	$	14,970
MidAmerican Funding		9,105		8,651
Northern Natural Gas		2,416		2,277
Kern River		1,996		2,057
CE Electric UK		7,094		6,561
CalEnergy Generation-Foreign		477		559
CalEnergy Generation-Domestic		566		545
HomeServices		776		795
Corporate/other (1)		1,354		32
Total assets	$	39,586	$	36,447

(1)

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

(2)

The negative depreciation and amortization at Kern River for the three-month period ended September 30, 2006, is due to a $28 million adjustment to Kern River’s depreciation made after receiving an order on its rate case from the FERC.

Goodwill is allocated to each reportable segment included in total assets above. Goodwill as of December 31, 2006, and the changes for the nine-month period ended September 30, 2007 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, 2006	$	1,118		$	2,108		$	301		$	34	$	1,328		$	71	$	385		$	5,345
Acquisitions (1)		22			-			-			-		-			-		9			31
Adoption of FIN 48		(10	)		(4	)		-			-		(1	)		-		-			(15	)
Foreign currency translation		-			-			-			-		47			-		-			47
Other (2)		(2	)		6			(19	)		-		(3	)		-		(3	)		(21	)
Goodwill at September 30, 2007	$	1,128		$	2,110		$	282		$	34	$	1,371		$	71	$	391		$	5,387

(1)	The $22 million adjustment to PacifiCorp’s goodwill was due to the completion of the purchase price allocation in the first quarter of 2007.
(2)	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 thereto included elsewhere in Item 1. 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 (the subsidiaries owning a majority interest in the Casecnan project), CalEnergy Generation-Domestic (the subsidiaries 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 natural gas interstate pipeline companies in the United States, two electricity distribution companies in Great Britain, a diversified portfolio of domestic and international independent power projects and the second largest residential real estate brokerage firm in the United States.

Forward-Looking Statements

This report contains statements that do not directly or exclusively relate to historical facts. These statements are “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. You can typically identify forward-looking statements by the use of forward-looking words, such as “may,” “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/or 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;

·    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 significant impact on 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;

·    performance of generation facilities, including unscheduled outages or repairs;

·    risks relating to nuclear generation;

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

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

·    other business or investment considerations that may be disclosed from time to time in filings with the U.S. Securities and Exchange Commission (“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 first nine months of 2007 was $938 million, an increase of $264 million, or 39%, from the comparable period in 2006. PacifiCorp, which was acquired on March 21, 2006, contributed an additional $204 million of net income in 2007 compared to 2006. Also contributing to the increase in net income were favorable operating results at the Company’s other domestic energy businesses, largely as a result of improved margins from favorable market conditions and additional generation assets being placed in service, a $61 million deferred income tax benefit recognized as a result of the reduction in the United Kingdom corporate income tax rate from 30% to 28% and the favorable impact from the foreign exchange rate. Net income decreased due to lower earnings at the Company’s foreign energy businesses including the planned turnover to the Philippine government of the Upper Mahiao project in June 2006 and the Malitbog and Mahanagdong projects in July 2007 and $73 million of after tax gains on sales of securities in 2006.

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Segment Results

The reportable segment financial information includes all necessary adjustments and eliminations needed to conform to the Company’s significant accounting policies. The differences between the segment amounts and the consolidated amounts, described as “Corporate/other,” relate principally to corporate functions including administrative costs, intersegment eliminations and fair value adjustments relating to certain acquisitions.

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

	Third Quarter											First Nine Months
	2007			2006			Change					2007			2006			Change
Operating revenue:
PacifiCorp	$	1,137		$	1,036		$	101		10	%	$	3,190		$	1,972		$	1,218		62	%
MidAmerican Funding		985			767			218		28			3,193			2,570			623		24
Northern Natural Gas		118			125			(7	)	(6	)		460			442			18		4
Kern River		105			64			41		64			302			230			72		31
CE Electric UK		273			243			30		12			775			669			106		16
CalEnergy Generation-Foreign		39			82			(43	)	(52	)		169			241			(72	)	(30	)
CalEnergy Generation-Domestic		9			9			-		-			25			25			-		-
HomeServices		410			462			(52	)	(11	)		1,215			1,335			(120	)	(9	)
Corporate/other		(9	)		(8	)		(1	)	(13	)		(35	)		(32	)		(3	)	(9	)
Total operating revenue	$	3,067		$	2,780		$	287		10		$	9,294		$	7,452		$	1,842		25
Operating income:
PacifiCorp	$	269		$	201		$	68		34	%	$	699		$	354		$	345		97	%
MidAmerican Funding		171			130			41		32			429			343			86		25
Northern Natural Gas		32			26			6		23			203			170			33		19
Kern River		71			59			12		20			209			151			58		38
CE Electric UK		118			137			(19	)	(14	)		390			368			22		6
CalEnergy Generation-Foreign		24			57			(33	)	(58	)		100			158			(58	)	(37	)
CalEnergy Generation-Domestic		4			6			(2	)	(33	)		12			12			-		-
HomeServices		19			19			-		-			46			54			(8	)	(15	)
Corporate/other		(12	)		(19	)		7		37			(56	)		(60	)		4		7
Total operating income	$	696		$	616		$	80		13		$	2,032		$	1,550		$	482		31

PacifiCorp

MEHC acquired PacifiCorp on March 21, 2006. Operating revenue for the first nine months of 2007 consisted of $2.46 billion of retail revenue and $735 million of wholesale revenue.

Operating revenue increased $101 million, or 10%, for the third quarter of 2007 due to a $100 million increase in retail revenue earned on higher prices approved by regulators and higher average customer usage and growth and a $15 million increase in wholesale revenue resulting from higher average wholesale prices.

Operating income increased $68 million, or 34%, for the third quarter of 2007 due primarily to the aforementioned higher retail and wholesale revenues and a $29 million increase in net unrealized gains on energy sales and purchase contracts accounted for as derivatives, partially offset by higher fuel and purchased power costs totaling $81 million. Fuel costs increased as a result of higher volumes due to increased generation at existing plants, the addition of the Lake Side plant in September 2007 and higher average unit fuel costs.

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MidAmerican Funding

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

	Third Quarter											First Nine Months
	2007			2006			Change					2007		2006		Change
Operating revenue:
Regulated electric	$	537		$	494		$	43		9	%	$	1,484	$	1,370	$	114	8	%
Regulated natural gas		146			153			(7	)	(5	)		854		778		76	10
Nonregulated		302			120			182		152			855		422		433	103
Total operating revenue	$	985		$	767		$	218		28		$	3,193	$	2,570	$	623	24
Operating income:
Regulated electric	$	157		$	126		$	31		25	%	$	346	$	308	$	38	12	%
Regulated natural gas		(7	)		(6	)		(1	)	(17	)		35		24		11	46
Nonregulated		21			10			11		110			48		11		37	336
Total operating income	$	171		$	130		$	41		32		$	429	$	343	$	86	25

Regulated electric revenue increased $43 million for the third quarter of 2007 and $114 million for the first nine months due to increases in wholesale revenue of $28 million and $75 million, respectively, and retail revenue of $15 million and $39 million, respectively. Wholesale revenue increased due to higher sales volumes. Retail revenue increased due to warmer temperatures in 2007 and an increase in the average number of retail customers. Regulated natural gas revenue increased $76 million for the first nine months of 2007 due to higher sales volumes resulting from colder temperatures and a higher average per-unit cost of gas sold. Nonregulated revenue increased $182 million for the third quarter of 2007 and $433 million for the first nine months due to increases in electric retail sales volumes and prices driven by improved market opportunities, partially offset by decreases in gas sales volumes and prices.

Regulated electric operating income increased $31 million for the third quarter of 2007 and $38 million for the first nine months, as a result of higher gross margins totaling $58 million and $74 million, respectively, due to higher volumes, which includes warmer temperatures in 2007, and lower average unit fuel costs, partially offset by higher operating expenses of $16 million and $41 million, respectively, due primarily to maintenance costs incurred for restoration of facilities damaged by storms and new generation assets placed in service during 2007. Depreciation and amortization expense increased $11 million for the third quarter of 2007 due mainly to new generation assets placed in service during 2007 and decreased $5 million for the first nine months due to a $16 million decrease in regulatory expense related to a revenue sharing arrangement in Iowa as a result of lower Iowa electric equity returns, partially offset by higher depreciation as a result of new generation assets placed in service during 2007. Regulated natural gas operating income increased $11 million for the first nine months of 2007 due to higher gross margins driven by higher sales volumes. Nonregulated operating income increased $11 million for the third quarter of 2007 and $37 million for the first nine months as a result of higher electric retail sales volumes and prices.

Northern Natural Gas

Operating revenue increased $18 million, or 4%, for the first nine months of 2007 due to higher transportation and storage revenues of $35 million due to higher rates and volumes resulting from favorable market conditions, partially offset by lower sales of gas and condensate liquids, which are both utilized in the operation and balancing of the pipeline system, of $18 million due primarily to lower sales volumes.

Operating income increased $33 million, or 19%, for the first nine months of 2007 due primarily to the aforementioned increase in transportation and storage revenues, partially offset by $4 million of higher operating expenses as a result of an asset impairment charge in 2007.

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Kern River

Operating revenue increased $41 million, or 64%, for the third quarter of 2007 and $72 million, or 31%, for the first nine months. Kern River earned higher market oriented revenues of $11 million for the third quarter of 2007 and $48 million for the first nine months as a result of more favorable market conditions in 2007. Additionally, Kern River received a Federal Energy Regulatory Commission order in 2006 that resulted in a $34 million reduction to operating revenue for rate case estimated refunds.

Operating income increased $12 million, or 20%, for the third quarter of 2007 and $58 million, or 38%, for the first nine months due primarily to the aforementioned increase in market oriented revenues. The $34 million decrease in revenues related to the FERC order received in 2006 was largely offset by a related $28 million adjustment that also lowered depreciation and amortization expense. Also contributing to the increase in operating income for the first nine months of 2007 were $8 million of lower depreciation and amortization expense due mainly to changes in the expected depreciation rates in connection with the current rate proceeding and lower sales and use tax expense due to a $6 million refund received in the first quarter of 2007.

CE Electric UK

Operating revenue increased $30 million, or 12%, for the third quarter of 2007 due primarily to a $19million favorable impact from the exchange rate, higher distribution revenue of $6 million at Northern Electric and Yorkshire Electricity, due primarily to tariff increases, and higher contracting revenue of $6 million. Operating revenue increased $106 million, or 16%, for the first nine months of 2007 due primarily to a $62 million favorable impact from the exchange rate, higher revenues of $31 million at CE Gas, primarily from higher gas production, and higher distribution revenue of $8 million at Northern Electric and Yorkshire Electricity due primarily to tariff increases.

Operating income decreased $19 million, or 14%, for the third quarter of 2007 due primarily to higher costs and expenses totaling $34 million, partially offset by the favorable impact from the exchange rate of $11 million and higher distribution margins of $9 million at Northern Electric and Yorkshire Electricity. Costs and expenses were higher for the third quarter of 2007 due primarily to higher distribution costs of $12 million due mainly to higher maintenance costs, higher depreciation and amortization expense of $8 million and the write-off of an unsuccessful exploration well at CE Gas totaling $9 million. Operating income increased $22 million, or 6%, for the first nine months of 2007 due primarily to the favorable impact from the exchange rate of $33 million, higher revenues at CE Gas, primarily from higher gas production margins of $25 million, and higher distribution margins of $16 million at Northern Electric and Yorkshire Electricity, partially offset by higher costs and expenses totaling $47 million. Costs and expenses were higher in 2007 due to higher depreciation and amortization of $23 million primarily associated with distribution assets, higher distribution costs of $23 million due mainly to higher maintenance and restoration costs and the write-off of an unsuccessful exploration well at CE Gas, partially offset by a $17 million realized gain on the sale of certain CE Gas assets in the first quarter of 2007.

CalEnergy Generation-Foreign

Operating revenue decreased $43 million, or 52%, for the third quarter of 2007 and $72 million, or 30%, for the first nine months as the Malitbog and Mahanagdong projects were transferred on July 25, 2007, and the Upper Mahiao project was transferred on June 25, 2006, to the Philippine government. These transfers reduced operating revenue by $30 million for the third quarter and $51 million for the first nine months. Additionally, operating revenue at the Casecnan project was lower by $13 million for the third quarter of 2007 and $21 million for the first nine months as a result of lower water flows and related energy production.

Operating income decreased $33 million, or 58%, for the third quarter of 2007 and $58 million, or 37%, for the first nine months due primarily to the aforementioned lower operating revenue and $9 million of costs incurred in the second quarter of 2007 in preparation for the July 2007 transfer of the Malitbog and Mahanagdong projects to the Philippine government, partially offset by lower depreciation and amortization expense of $9 million for the third quarter of 2007 and $20 million for the first nine months of 2007 as a result of the aforementioned transfers of the Upper Mahiao, Malitbog and Mahanagdong projects.

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HomeServices

Operating revenue decreased $52 million, or 11%, for the third quarter of 2007 and $120 million, or 9%, for the first nine months due primarily to fewer brokerage transactions as a result of the general slowdown in the U.S. housing market.

Operating income decreased $8 million, or 15%, for the first nine months of 2007 due mainly to the aforementioned decrease in brokerage transactions, mostly offset by lower commissions, operating expenses and depreciation and amortization expense.

Consolidated Other Income and Expense Items

Interest Expense

Interest expense is summarized as follows (in millions):

	Third Quarter									First Nine Months
	2007		2006		Change					2007		2006		Change
Subsidiary debt	$	226	$	208	$	18		9	%	$	663	$	547	$	116		21	%
MEHC senior debt and other		76		62		14		23			208		168		40		24
MEHC subordinated debt-Berkshire Hathaway Inc.		26		32		(6	)	(19	)		84		103		(19	)	(18	)
MEHC subordinated debt-other		8		7		1		14			21		21		-		-
Total interest expense	$	336	$	309	$	27		9		$	976	$	839	$	137		16

Interest expense increased $27 million for the third quarter of 2007 and $137 million for the first nine months due primarily to debt issuances at domestic energy businesses and at MEHC, as well as the higher exchange rate, partially offset by debt retirements and scheduled principal repayments. Also contributing to the increase for the first nine months of 2007 is higher interest expense of $80 million resulting from the acquisition of PacifiCorp.

Other Income, Net

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

	Third Quarter										First Nine Months
	2007			2006			Change				2007			2006			Change
Capitalized interest	$	13		$	11		$	2	18	%	$	43		$	26		$	17		65	%
Interest and dividend income		33			19			14	74			75			53			22		42
Other income		31			26			5	19			86			201			(115	)	(57	)
Other expense		(2	)		(2	)		-	-			(6	)		(11	)		5		45
Total other income, net	$	75		$	54		$	21	39		$	198		$	269		$	(71	)	(26	)

Capitalized interest increased $17 million for the first nine months of 2007 due primarily to increased levels of capital project expenditures as well as $12 million resulting from the acquisition of PacifiCorp.

Interest and dividend income increased $14 million for the third quarter of 2007 and $22 million for the first nine months due primarily to more favorable cash positions at MEHC and certain subsidiaries primarily as a result of 2007 debt issuances. The increase for the first nine months of 2007 is also due to higher interest and dividend income of $6 million resulting from the acquisition of PacifiCorp.

Other income decreased $115 million for the first nine months of 2007. Other income for 2006 included Kern River’s $89 million of gains from the sale of Mirant stock, $32 million of gains at MidAmerican Funding from the disposition of common shares held in an electronic energy and metals trading exchange and MidAmerican Funding’s gain of $8 million from the sale of a non-strategic investment. The equity allowance for funds used during construction (“AFUDC”) increased $22 million due to increased levels of capital project expenditures as well as $15 million resulting from the acquisition of PacifiCorp.

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Income Tax Expense

Income tax expense decreased $40 million to $68 million for the third quarter of 2007 and increased $7 million to $328 million for the first nine months. The effective tax rates were 16% and 30% for the third quarter of 2007 and 2006, respectively, and 26% and 33% for the first nine months of 2007 and 2006, respectively. The decrease in income tax expense for the third quarter of 2007 was 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%, partially offset by higher pretax earnings. The increase in income tax expense for the first nine months of 2007 was primarily due to higher pretax earnings, partially offset by the impact of the United Kingdom corporate income tax rate change. The decreases in the effective tax rates for the third quarter and for the first nine months of 2007 are due mainly to the impact of the United Kingdom corporate income tax rate change, additional production tax credits associated with wind generation facilities, higher non-taxable equity AFUDC and the effects of rate-making.

Liquidity and Capital Resources

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

Each of MEHC’s direct or indirect subsidiaries is organized as a legal entity separate and apart from MEHC and its other subsidiaries. Pursuant to separate financing agreements, 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.

The Company’s cash and cash equivalents and short-term investments combined were $2.02 billion as of September 30, 2007, compared to $358 million as of December 31, 2006. In addition, the Company recorded separately, in other current assets and in deferred charges, investments and other assets, restricted cash and investments as of September 30, 2007 and December 31, 2006 of $502 million and $531 million, respectively. The restricted cash balance is mainly composed of amounts deposited in restricted accounts relating to (i) the Company’s nuclear decommissioning and mine reclamation obligations, (ii) the Company’s debt service reserve requirements relating to certain projects, (iii) customer deposits held in escrow, (iv) custody deposits, and (v) unpaid dividends declared obligations. The debt service funds are restricted by their respective project debt agreements to be used only for the related project.

Cash Flows from Operating Activities

The Company generated cash flows from operations of $1.90 billion for the first nine months of 2007, compared with $1.64 billion from the comparable period in 2006. The increase was mainly due to the acquisition of PacifiCorp on March 21, 2006, which contributed $301 million to the increase in operating cash flows, partially offset by lower cash flows from operations as a result of the transfer of the Malitbog and Mahanagdong projects to the Philippine government in 2007 and higher cash payments for income taxes in 2007 as compared to 2006.

Cash Flows from Investing Activities

Cash flows used in investing activities for the first nine months of 2007 and 2006 were $2.45 billion and $6.66 billion, respectively. In 2006, MEHC acquired PacifiCorp for $4.93 billion, net of cash acquired. Capital expenditures, construction and other development costs increased $787 million and net purchases and sales of available-for-sale securities resulted in higher cash outflows for the first nine months of 2007 of $138 million due primarily to Kern River’s receipt of $89 million in proceeds from the sale of Mirant stock in 2006 and MidAmerican Funding’s receipt of $28 million in proceeds from the sale of common shares held in an electronic energy and metals trading exchange in 2006.

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Capital Expenditures, Construction and Other Development Costs

The following table summarizes the capital expenditures, construction and other development costs by reportable segment (in millions):

	First Nine Months
	2007		2006
Capital expenditures:
PacifiCorp	$	1,136	$	844
MidAmerican Funding		879		514
Northern Natural Gas		180		78
CE Electric UK		295		285
Other reportable segments and corporate/other		32		14
Total capital expenditures	$	2,522	$	1,735

Forecasted capital expenditures, construction and other development costs for fiscal 2007, which exclude the non-cash equity AFUDC, are approximately $3.7 billion and consist of $1.9 billion for operating projects consisting mainly of distribution network expenditures and the funding of growing demand requirements, $1.5 billion for generation development projects and $0.3 billion for emission control equipment. Capital expenditure needs are reviewed regularly by management and may change significantly as a result of such reviews. Also, estimates may change significantly at any time as a result of, among other factors, changes in related regulations, prices of products used to meet the requirements, competition in the industry for similar technology and management’s strategies for achieving compliance with the regulations. The Company expects to meet these capital expenditures with cash flows from operations and the issuance of debt. Capital expenditures relating to operating projects, consisting mainly of distribution network expenditures and the funding of growing load requirements, were $1.22 billion and $1.14 billion for the first nine months of 2007 and 2006, respectively. Construction and other development costs were $1.30 billion and $595 million for the first nine months of 2007 and 2006, respectively. These costs consist mainly of expenditures for large scale generation projects at PacifiCorp and MidAmerican Energy as described below.

PacifiCorp and MidAmerican Energy anticipate a continuing increase in demand for electricity from their regulated customers. To meet existing and anticipated demand and ensure adequate electric generation in their service territory, PacifiCorp and MidAmerican Energy have been and are each continuing to construct major generation projects.

PacifiCorp

The Lake Side plant, a 534-megawatt (“MW”) combined cycle plant in Utah, was placed into service in September 2007. The cost of the Lake Side plant is expected to total approximately $347 million, including non-cash equity AFUDC, of which $339 million, including $17 million of non-cash equity AFUDC, has been incurred through September 30, 2007. The Lake Side plant is 100% owned and operated by PacifiCorp.

The capital expenditures estimate for generation development projects for the year ending December 31, 2007, includes the 140-MW Marengo I wind plant that was placed into service in August 2007. The estimate also includes construction costs for the development of additional wind generation projects that are expected to increase PacifiCorp’s renewable generation portfolio by 362 MW. These wind generation projects are expected to be placed into service through December 31, 2008. PacifiCorp continues to pursue additional cost-effective wind-powered generation.

In May 2007, PacifiCorp announced plans to build in excess of 1,200 miles of new transmission lines originating in Wyoming and connecting into Utah, Idaho, Oregon and the desert Southwest. The estimated $4 billion investment plan includes projects that will address 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 region. These transmission lines are expected to be placed into service beginning 2010 through 2014.

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MidAmerican Funding

MidAmerican Energy has constructed Walter Scott, Jr. Energy Center Unit No. 4 (“WSEC Unit 4”), formerly Council Bluffs Energy Center Unit No. 4, a 790-MW (accredited capacity) supercritical, coal-fired generating plant, which began commercial operation on June 1, 2007. MidAmerican Energy operates the plant and holds an undivided ownership interest of 59.66%, or approximately 471 MW, as a tenant in common with the other owners of the plant. Prior to construction, MidAmerican Energy obtained approval from the Iowa Utilities Board (“IUB”) to include the Iowa portion of the actual cost of WSEC Unit 4 in its Iowa rate base as long as the actual cost did not exceed the agreed cap that MidAmerican Energy deemed reasonable. As of September 30, 2007, MidAmerican Energy had invested $835 million in the plant, including $63 million of non-cash equity AFUDC. It is presently expected that the actual final cost of WSEC Unit 4 will be within the agreed cap. If the cap is ultimately exceeded, MidAmerican Energy has the right to demonstrate the prudence of the expenditures above the cap, subject to regulatory review. In conjunction with WSEC Unit 4 being placed in service, $710 million was transferred from construction in progress to utility generation and distribution system.

On April 18, 2006, the IUB approved a settlement agreement regarding ratemaking principles for additional wind-powered generation capacity to be installed in Iowa in 2006 and 2007. On July 27, 2007, the IUB approved a settlement agreement in conjunction with MidAmerican Energy’s ratemaking principles application for up to 540 MW (nameplate ratings) of additional wind-powered generation capacity in Iowa to be placed in service on or before December 31, 2013. With the exception of 123 MW (nameplate ratings) of capacity MidAmerican Energy has under construction, all new wind-powered generation capacity up to the 540 MW will be subject to the 2007 settlement agreement. Including the 123 MW previously mentioned, MidAmerican Energy has 213 MW (nameplate ratings) of wind-powered generation under construction that is expected to be in service by December 31, 2007. Another 75 MW (nameplate ratings) of wind-powered generation is under construction and expected to be in service in mid-2008. Generally speaking, accredited capacity ratings for wind-powered generation facilities are considerably less than the nameplate ratings due to the varying nature of wind. Refer to Note 6 of Notes to Consolidated Financial Statements included in Item 1 for a more in-depth discussion of the settlement agreement.

Cash Flows from Financing Activities

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 and project debt totaling $1.4 billion. Uses of cash totaled $790 million and consisted mainly of $250 million for repayments of subsidiary and project debt, $194 million of net repayments of subsidiary short-term debt, $167 million of repayments of MEHC subordinated debt and $152 million of net repayments of the MEHC revolving credit facility.

Cash flows generated from financing activities for the first nine months of 2006 were $5.09 billion. Sources of cash totaled $7.33 billion and consisted primarily of $5.12 billion of proceeds from the issuance of common stock, $1.7 billion of proceeds from the issuance of MEHC senior debt, $365 million of proceeds from the issuance of subsidiary and project debt and $93 million of net proceeds from the MEHC revolving credit facility. Uses of cash totaled $2.25 billion and consisted primarily of $1.75 billion for purchases of common stock, $257 million of repayments of subsidiary and project debt, $167 million of repayments of MEHC subordinated debt and $51 million of net repayments of the MEHC revolving credit facility.

Credit Ratings

As of September 30, 2007, MEHC’s senior unsecured debt credit ratings were as follows: Moody’s Investor Service, “Baa1/stable”; Standard and Poor’s, “BBB+/stable”; and Fitch Ratings, “BBB+/stable.”

Debt and preferred securities of MEHC and its subsidiaries may be rated by nationally recognized credit rating agencies. Assigned credit ratings are based on each rating agency’s assessment of the rated company’s ability to, in general, meet the obligations of its 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. Other than the agreements discussed below, MEHC and its subsidiaries do not have any credit agreements that require termination or a material change in collateral requirements or payment schedule in the event of a downgrade in the credit ratings of the respective company’s securities.

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In conjunction with their risk management activities, PacifiCorp and MidAmerican Energy must meet credit quality standards as required by counterparties. In accordance with industry practice, master agreements that govern PacifiCorp’s and MidAmerican Energy’s energy supply and marketing activities either specifically require each company to maintain investment grade credit ratings or provide the right for counterparties to demand “adequate assurances” in the event of a material adverse change in PacifiCorp’s or MidAmerican Energy’s creditworthiness. If one or more of PacifiCorp’s or MidAmerican Energy’s credit ratings decline below investment grade, PacifiCorp or MidAmerican Energy may be required to post cash collateral, letters of credit or other similar credit support to facilitate ongoing wholesale energy supply and marketing activities. As of September 30, 2007, PacifiCorp’s and MidAmerican Energy’s credit ratings from the three recognized credit rating agencies were investment grade; however if the ratings fell below investment grade, PacifiCorp’s and MidAmerican Energy’s estimated potential collateral requirements would total approximately $282 million and $173 million, respectively. PacifiCorp’s and MidAmerican Energy’s potential collateral requirements could fluctuate considerably due to seasonality, market price volatility, and a loss of key generating facilities or other related factors.

Yorkshire Power Group Limited (“YPGL”), a subsidiary of CE Electric UK, has certain currency rate swap agreements for its Yankee bonds with three large multi-national financial institutions. The swap agreements effectively convert the U.S. dollar fixed interest rate to a fixed rate in sterling for $281 million of 6.496% Yankee bonds outstanding as of September 30, 2007. The agreements extend until February 25, 2008 and convert the U.S. dollar interest rate to a fixed sterling rate ranging from 7.3175% to 7.3450%. The estimated fair value of these swap agreements as of September 30, 2007 was a liability of $121 million based on quotes from the counterparties to these instruments and represents the estimated amount that the Company would expect to pay if these agreements were terminated. Certain of these counterparties have the option to terminate the swap agreements and demand payment of the fair value of the swaps if YPGL’s credit ratings from the three recognized credit rating agencies decline below investment grade. As of September 30, 2007, YPGL’s credit ratings from the three recognized credit rating agencies were investment grade; however, if the ratings fell below investment grade, payment requirements would have been $56 million.

Contractual Obligations and Commercial Commitments

Subsequent to December 31, 2006, 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, 2006, other than the items that follow.

On October 23, 2007, PacifiCorp entered into a new unsecured revolving credit facility with total bank commitments of $700 million. The facility will support PacifiCorp’s commercial paper program and terminates on October 23, 2012. Terms and conditions, including borrowing rates, are substantially similar to PacifiCorp’s existing revolving credit facility.

On October 3, 2007, PacifiCorp issued $600 million of 6.25% First Mortgage Bonds due October 15, 2037. The proceeds will be used by PacifiCorp to repay its short-term debt and for other general corporate purposes.

On August 28, 2007, MEHC issued $1.0 billion of 6.50% Senior Bonds due September 15, 2037. The proceeds will be used by MEHC to repay at maturity its 3.50% senior notes due in May 2008 in the aggregate principal amount of $450 million and its 7.52% senior notes due in September 2008 in the aggregate principal amount of $550 million. Pending repayment of its indebtedness, the proceeds are being used to repay short-term indebtedness, with the balance invested in short-term securities or used for general corporate purposes.

On June 29, 2007, MidAmerican Energy issued $400 million of 5.65% Senior Notes due July 15, 2012, and $250 million of 5.95% Senior Notes due July 15, 2017. The proceeds are being used by MidAmerican Energy to pay construction costs of its interest in WSEC Unit 4 and its wind projects in Iowa, repay short-term indebtedness and for general corporate purposes.

On May 11, 2007, MEHC issued $550 million of 5.95% Senior Bonds due May 15, 2037. The proceeds were used by MEHC to repay at maturity its 4.625% senior notes due in October 2007 in an aggregate principal amount of $200 million and its 7.63% senior notes due in October 2007 in an aggregate principal amount of $350 million.

On March 14, 2007, PacifiCorp issued $600 million of 5.75% First Mortgage Bonds due April 1, 2037. The proceeds were used by PacifiCorp to repay its short-term debt and for general corporate purposes.

On February 12, 2007, Northern Natural Gas issued $150 million of 5.8% Senior Bonds due February 15, 2037. The proceeds were used by Northern Natural Gas to fund capital expenditures and for general corporate purposes.

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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, 2006, refer to Note 6 of Notes to Consolidated Financial Statements included in Item 1 for additional regulatory matter updates.

Oregon

In July 2007, as part of PacifiCorp’s annual compliance filing with the Oregon Public Utility Commission (“OPUC”) to update forecasted net power costs, PacifiCorp requested an increase of approximately $30 million, or an average price increase of 3%, to take effect January 1, 2008. The annual filing, called the transition adjustment mechanism (“TAM”), will be adjusted for new contracts through October 2007 and for other changes to forecasted net power costs, such as coal and natural gas prices, through November 2007. The OPUC issued an order on October 17, 2007, which is expected to reduce the requested increase by approximately $9 million. The final net power cost increase under the TAM will be determined in November 2007, after PacifiCorp’s annual filing is updated for the changes to forecasted net power costs.

In August 2007, PacifiCorp filed a renewable cost adjustment clause that will allow for timely recovery of the costs to implement Oregon’s Renewable Portfolio Standard (“RPS”) between rate cases. The RPS requires the OPUC to approve an automatic adjustment clause for timely recovery of these costs by January 1, 2008.

In October 2007, PacifiCorp filed its first tax report under Oregon Senate Bill 408 (“SB 408”), which was enacted in September 2005. The filing indicates that in 2006, PacifiCorp paid $33 million more in federal, state and local taxes than was reflected in rates to its retail customers. SB 408 requires that PacifiCorp and other large regulated, investor-owned utilities that provide electric or natural gas service to Oregon customers file an annual tax report with the OPUC. The filing will be subject to a 180-day procedural schedule with rates potentially effective June 2008.

Wyoming

In June 2007, PacifiCorp filed a general rate case with the Wyoming Public Service Commission requesting an increase of $36 million annually, or an average price increase of 8%. In addition, PacifiCorp requested approval of a new renewable resource mechanism and a marginal cost pricing tariff to better reflect the cost of adding new generation. PacifiCorp expects the new rates to become effective by May 2008.

Washington

In October 2006, PacifiCorp filed a general rate case with the Washington Utilities and Transportation Commission (“WUTC”) for an annual increase of $23 million, or 10%. As part of the filing, PacifiCorp proposed a Washington-only cost-allocation methodology, which is based on PacifiCorp’s western resources. The rate case included a five-year pilot period on the proposed allocation methodology and a power cost adjustment mechanism (“PCAM”). On June 21, 2007, the WUTC issued an order approving a rate increase of $14 million, or an average price increase of 6%, effective June 27, 2007, and accepted PacifiCorp’s proposed allocation methodology for a five-year pilot period. The WUTC found that PacifiCorp demonstrated the need for a PCAM, but it did not approve the design of the proposal in this case. The order authorized PacifiCorp to file a revised PCAM proposal, with or without a request to file power cost-only rate cases, outside the context of a general rate case within 12 months of the order.

Idaho

In June 2007, PacifiCorp filed a general rate case with the Idaho Public Utilities Commission for an annual increase of $18 million, or an average price increase of 10%, with a request for an effective date of January 1, 2008. A hearing on the general rate case has been scheduled for November 6, 2007.

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The Bonneville Power Administration Residential Exchange Program

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. In October 2000, PacifiCorp entered into a settlement agreement with the BPA that provided Residential Exchange Program benefits to PacifiCorp’s customers from October 2001 through September 2006. In May 2001, PacifiCorp entered into a load reduction agreement with the BPA which eliminated the BPA’s obligation to deliver power to PacifiCorp from October 2001 through September 2006 in exchange for cash payments. This agreement also contained a “reduction of risk discount” provision which provided that the BPA would reduce the cash payments to PacifiCorp if by December 1, 2001, PacifiCorp and other utilities were able to negotiate and enter into settlement agreements with the publicly owned utilities and other of the BPA’s preference customers dismissing certain lawsuits. If these parties did not reach settlement by the specified date, the clause would expire and the BPA would make cash payments to PacifiCorp based on the original rate for the October 2002 through September 2006 period. Settlement was not reached and the clause expired, obligating the BPA to make the full cash payment to PacifiCorp. In May 2004, PacifiCorp, the BPA and other parties executed an additional agreement which modified both the October 2000 and May 2001 agreements that provides for a guaranteed range of benefits to customers from October 2006 through September 2011.

Several publicly owned utilities, cooperatives and the BPA’s direct-service industry customers filed lawsuits against the BPA with the United States Ninth Circuit Court of Appeals (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. The first decision sets aside the October 2000 Residential Exchange Program settlement agreement as being inconsistent with the BPA’s settlement authority. The second decision holds, among other things, that the BPA acted contrary to law when it allocated to its preference customers, which includes public utilities, cooperatives and federal agencies, part of the costs of the October 2000 settlement the BPA reached with its investor-owned utility customers. As a result of the ruling, in May 2007, the BPA notified the Pacific Northwest’s six utilities, including PacifiCorp, that it was immediately suspending payments. This has resulted in increases to PacifiCorp’s residential and small farm customers’ electric bills in Oregon, Washington and Idaho. Because the benefit payments from the BPA are passed through to PacifiCorp’s customers, the outcome of this matter is not expected to have a significant effect on the Company’s consolidated financial results. In October 2007, the Ninth Circuit issued one published decision and three unpublished decisions. The published decision remanded the May 2004 agreements modifying the October 2000 and May 2001 agreements to the BPA for further action consistent with the Ninth Circuit’s May 2007 decisions. The other three unpublished decisions dismiss cases in which the publicly owned utilities sought review of the BPA’s decision to implement the reduction of risk discount provision and make the full cash payment to PacifiCorp.

Environmental Matters

In addition to the discussion contained herein, refer to Note 12 of Notes to Consolidated Financial Statements included in Item 1 of this report and Item 1 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2006 for additional information regarding certain environmental matters affecting PacifiCorp’s and MidAmerican Energy’s operations.

Renewable Portfolio Standards

The RPS requirements described below could significantly impact the Company’s financial results. Resources that meet the qualifying electricity requirements under the RPS vary from state-to-state. Each state’s RPS requires some form of compliance reporting and the Company can be subject to penalties in the event of non-compliance.

In November 2006, Washington voters approved a ballot initiative establishing a RPS requirement for qualifying electric utilities, including PacifiCorp. The requirements are 3% of retail sales in 2012 through 2015, 9% of retail sales in 2016 through 2019 and 15% of retail sales in 2020. The WUTC has undertaken a rulemaking proceeding to implement the initiative. The Company expects to be able to recover its costs of complying with the RPS, either through rate cases or an adjustment mechanism.

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In June 2007, the Oregon Renewable Energy Act (the “Act”) was adopted, providing a comprehensive renewable energy policy for Oregon. Subject to certain exemptions and cost limitations established in the Act, PacifiCorp and other qualifying electric utilities must meet minimum qualifying electricity requirements for electricity sold to retail customers of at least 5% in 2011 through 2014, 15% in 2015 through 2019, 20% in 2020 through 2024, and 25% in 2025 and subsequent years. The Act requires the OPUC to establish an automatic adjustment clause or other timely mechanism to allow an electric utility to recover prudently incurred costs of its investments in renewable energy facilities and associated transmission costs. The OPUC and the Oregon Department of Energy have undertaken rulemaking proceedings to implement the initiative. The Company expects to be able to recover its costs of complying with the RPS through the automatic adjustment mechanism.

California law requires electric utilities to increase their procurement of renewable resources by at least 1% of their annual retail electricity sales per year so that 20% of their annual electricity sales are procured from renewable resources by no later than December 31, 2010. However, PacifiCorp and other small multi-jurisdictional utilities (“SMJU”) are currently awaiting further guidance from the California Public Utilities Commission (“CPUC”) on the treatment of SMJUs in the California RPS program. PacifiCorp has filed comments requesting SMJU rules for flexible compliance with annual targets. PacifiCorp expects rules governing the treatment of SMJUs and any specific flexible compliance mechanisms to be released by CPUC staff for public review in 2007. Absent further direction from the CPUC on treatment of SMJUs, the Company cannot predict the impact of the California RPS on its financial results.

Climate Change

As a result of increased attention to climate change in the United States, numerous bills have been introduced in the current session of the United States Congress that would reduce greenhouse gas emissions in the United States. Congressional leadership has made climate change legislation a priority, and many congressional observers expect to see the passage of climate change legislation within the next several years. In addition, nongovernmental organizations have become more active in initiating citizen suits under existing environmental and other laws. In April 2007, a United States Supreme Court decision concluded that the Environmental Protection Agency (“EPA”) has the authority under the Clean Air Act to regulate emissions of greenhouse gases from motor vehicles. In addition, pending cases that address the potential public nuisance from greenhouse gas emissions from electricity generators and the EPA’s failure to regulate greenhouse gas emissions from new and existing coal-fired plants are expected to become active. Furthermore, while debate continues at the national level over the direction of domestic climate policy, several states have developed state-specific laws or regional legislative initiatives to reduce greenhouse gas emissions, including Oregon, Washington, California and several Northeastern states, and individual state actions to regulate greenhouse gas emissions are likely to increase. The impact of any pending judicial proceedings and any pending or enacted federal and state climate change legislation and regulation cannot be determined at this time; however, adoption of stringent limits on greenhouse gas emissions could significantly impact the Company’s current and future fossil-fueled facilities, and, therefore, its financial results.

In February 2007, the governors of California, Arizona, New Mexico, Oregon and Washington signed the Western Regional Climate Action Initiative (the “Western Climate Initiative”) that directed their respective states to develop a regional target for reducing greenhouse gases by August 2007. Utah joined the Western Climate Initiative in May 2007. The states in the Western Climate Initiative recently announced a target of reducing greenhouse gas emissions by 15% below 2005 levels by 2020, with Utah establishing its reduction goal by August 2008. By August 2008, they are expected to devise a market-based program, such as a load-based cap-and-trade program for the electricity sector, to reach the regional target. The Western Climate Initiative participants also have agreed to participate in a multi-state registry to track and manage greenhouse gas emissions in the region.

The Washington and Oregon governors enacted legislation in May 2007 and August 2007, respectively, establishing economy-wide goals for the reduction of greenhouse gas emissions in their respective states. Washington’s goals seek to, (i) by 2020, reduce emissions to 1990 levels; (ii) by 2035, reduce emissions to 25% below 1990 levels; and (iii) by 2050, reduce emissions to 50% below 1990 levels, or 70% below Washington’s forecasted emissions in 2050. Oregon’s goals seek to, (i) by 2010, cease the growth of Oregon greenhouse gas emissions; (ii) by 2020, reduce greenhouse gas levels to 10% below 1990 levels; and (iii) by 2050, reduce greenhouse gas levels to at least 75% below 1990 levels. Each state’s legislation also calls for state government developed policy recommendations in the future to assist in the monitoring and achievement of these goals. The impact of the enacted legislation on the Company cannot be determined at this time.

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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.

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 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 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 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, 2006. The Company’s critical accounting policies have not changed materially since December 31, 2006, other than the adoption of Financial Accounting Standards Board Interpretation No. 48, “Accounting for Uncertainty in Income Taxes – an interpretation of FASB Statement No. 109.”

Item 3. Quantitative and Qualitative Disclosures About Market Risk.

Refer to Note 8 of Notes to Consolidated Financial Statements included in Item 1 for disclosure of the Company’s derivative positions as of September 30, 2007 and December 31, 2006. 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, 2006. The Company’s exposure to market risk has not changed materially since December 31, 2006.

Item 4. Controls and Procedures.

An evaluation was performed under the supervision and with the participation of the Company’s management, including the chief executive officer and chief financial officer, regarding the effectiveness of the design and operation of the Company’s disclosure controls and procedures (as defined in Rule 13a-15(e) promulgated under the Securities and Exchange Act of 1934, as amended) as of September 30, 2007. Based on that evaluation, the Company’s management, including the chief executive officer and chief financial officer, concluded that the Company’s disclosure controls and procedures were effective. There have been no changes during the quarter covered by this report in the Company’s internal control over financial reporting that has materially affected, or is reasonably likely to materially affect, the Company’s internal control over financial reporting.

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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, 2006. Material developments to these proceedings during the nine-month period ended September 30, 2007, are included in Note 12 of Notes to Consolidated Financial Statements included in Item 1.

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, 2006.

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

Not applicable.

Item 3. Defaults Upon Senior Securities.

Not applicable.

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

Not applicable.

Item 5. Other Information.

Not applicable.

Item 6. Exhibits.

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

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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 2, 2007	/s/ Patrick J. Goodman
	Patrick J. Goodman
	Senior Vice President and Chief Financial Officer

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EXHIBIT INDEX

Exhibit No.	Description
4.1	$700,000,000 Credit Agreement dated as of October 23, 2007 among PacifiCorp, The Banks Party thereto, The Royal Bank of Scotland plc, as Syndication Agent, and Union Bank of California, N.A., as Administrative Agent (incorporated by reference to Exhibit 99 to the PacifiCorp Quarterly Report on Form 10-Q for the quarter ended September 30, 2007).
31.1	Chief Executive Officer’s Certificate Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2	Chief Financial Officer’s Certificate Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1	Chief Executive Officer’s Certificate Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2	Chief Financial Officer’s Certificate Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

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