BERKSHIRE HATHAWAY ENERGY CO - FORM 10-Q

Attached files

file	filename
EX-32.2 - SECTION 906 CFO CERTIFICATION - BERKSHIRE HATHAWAY ENERGY CO	exh32_2.htm
EX-31.2 - SECTION 302 CFO CERTIFICATION - BERKSHIRE HATHAWAY ENERGY CO	exh31_2.htm
EX-32.1 - SECTION 906 CEO CERTIFICATION - BERKSHIRE HATHAWAY ENERGY CO	exh32_1.htm
EX-31.1 - SECTION 302 CEO CERTIFICATION - BERKSHIRE HATHAWAY ENERGY CO	exh31_1.htm
EX-10.1 - FACILITY AGREEMENT, DATED MARCH 26, 2010 - BERKSHIRE HATHAWAY ENERGY CO	exh10-1.htm
EX-15 - AWARENESS LETTER OF INDEPENDENT REIGSTERED PUBLIC ACCOUNTING FIRM - BERKSHIRE HATHAWAY ENERGY CO	exh15.htm

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 March 31, 2010

[ ] 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 has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ¨ No ¨

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

Large accelerated filer ¨

Accelerated filer ¨

Non-accelerated filer T

Smaller reporting company ¨

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

Yes ¨ No T

All of the shares of common equity of MidAmerican Energy Holdings Company are privately held by a limited group of investors. As of April 30, 2010, 74,609,001 shares of common stock were outstanding.

TABLE OF CONTENTS

PART I

Item 1.	Financial Statements	3
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	27
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	39
Item 4.	Controls and Procedures	39

PART II

Item 1.	Legal Proceedings	40
Item 1A.	Risk Factors	40
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	40
Item 3.	Defaults Upon Senior Securities	40
Item 4.	(Removed and Reserved)	40
Item 5.	Other Information	40
Item 6.	Exhibits	40
Signatures		41
Exhibit Index		42

PART I

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 March 31, 2010, and the related consolidated statements of operations, cash flows, changes in equity, and comprehensive income for the three-month periods ended March 31, 2010 and 2009. 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, 2009, and the related consolidated statements of operations, cash flows, changes in equity, and comprehensive income for the year then ended (not presented herein); and in our report dated March 1, 2010, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying consolidated balance sheet as of December 31, 2009 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

May 7, 2010

MIDAMERICAN ENERGY HOLDINGS COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (Unaudited)

(Amounts in millions)

	As of
	March 31,		December 31,
	2010		2009
ASSETS

Current assets:
Cash and cash equivalents	$	571	$	429
Trade receivables, net		1,175		1,308
Inventories		533		591
Derivative contracts		161		136
Investments and restricted cash and investments		90		83
Other current assets		514		546
Total current assets		3,044		3,093

Property, plant and equipment, net		30,711		30,936
Goodwill		5,020		5,078
Investments and restricted cash and investments		2,889		2,702
Regulatory assets		2,193		2,093
Derivative contracts		46		52
Other assets		906		730

Total assets	$	44,809	$	44,684

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

MIDAMERICAN ENERGY HOLDINGS COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (Unaudited) (continued)

(Amounts in millions)

	As of
	March 31,		December 31,
	2010		2009

LIABILITIES AND EQUITY

Current liabilities:
Accounts payable	$	828	$	918
Accrued interest		328		344
Accrued property, income and other taxes		324		277
Derivative contracts		143		123
Short-term debt		254		179
Current portion of long-term debt		535		379
Other current liabilities		763		683
Total current liabilities		3,175		2,903

Regulatory liabilities		1,625		1,603
Derivative contracts		475		458
MEHC senior debt		5,371		5,371
MEHC subordinated debt		403		402
Subsidiary debt		13,270		13,600
Deferred income taxes		5,734		5,604
Other long-term liabilities		1,773		1,900
Total liabilities		31,826		31,841

Commitments and contingencies (Note 12)

Equity:
MEHC shareholders’ equity:
Common stock - 115 shares authorized, no par value, 75 shares issued and outstanding		-		-
Additional paid-in capital		5,444		5,453
Retained earnings		6,983		6,788
Accumulated other comprehensive income, net		327		335
Total MEHC shareholders’ equity		12,754		12,576
Noncontrolling interests		229		267
Total equity		12,983		12,843

Total liabilities and equity	$	44,809	$	44,684

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

MIDAMERICAN ENERGY HOLDINGS COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)

(Amounts in millions)

	Three-Month Periods
	Ended March 31,
	2010			2009

Operating revenue:
Energy	$	2,738		$	2,796
Real estate		199			173
Total operating revenue		2,937			2,969

Operating costs and expenses:
Energy:
Cost of sales		1,162			1,164
Operating expense		615			703
Depreciation and amortization		311			296
Real estate		210			192
Total operating costs and expenses		2,298			2,355

Operating income		639			614

Other income (expense):
Interest expense		(308	)		(318	)
Capitalized interest		14			9
Interest and dividend income		6			15
Other, net		37			(44	)
Total other income (expense)		(251	)		(338	)

Income before income tax expense and equity expense (income)		388			276
Income tax expense		56			61
Equity expense (income)		3			(9	)
Net income		329			224
Net income attributable to noncontrolling interests		87			7
Net income attributable to MEHC	$	242		$	217

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

MIDAMERICAN ENERGY HOLDINGS COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)

(Amounts in millions)

	Three-Month Periods
	Ended March 31,
	2010			2009

Cash flows from operating activities:
Net income	$	329		$	224
Adjustments to reconcile net income to net cash flows from operating activities:
Depreciation and amortization		315			300
Stock-based compensation		-			123
Changes in regulatory assets and liabilities		10			18
Provision for deferred income taxes		7			147
Other, net		(8	)		15
Changes in other operating assets and liabilities:
Trade receivables and other assets		180			166
Derivative collateral, net		(67	)		(19	)
Trading securities		-			193
Contributions to pension and other postretirement benefit plans, net		(40	)		(23	)
Accounts payable and other liabilities		90			(491	)
Net cash flows from operating activities		816			653

Cash flows from investing activities:
Capital expenditures		(585	)		(812	)
Purchases of available-for-sale securities		(41	)		(125	)
Proceeds from sales of available-for-sale securities		43			109
Proceeds from Constellation Energy 14% note		-			1,000
Increase in restricted cash		(10	)		(12	)
Other, net		(24	)		(3	)
Net cash flows from investing activities		(617	)		157

Cash flows from financing activities:
Repayments of MEHC subordinated debt		(45	)		(500	)
Proceeds from subsidiary debt		-			992
Repayments of subsidiary debt		(23	)		(195	)
Net proceeds from MEHC revolving credit facility		123			39
Net repayments of subsidiary short-term debt		(42	)		(214	)
Net purchases of common stock		(56	)		(123	)
Other, net		(7	)		(16	)
Net cash flows from financing activities		(50	)		(17	)

Effect of exchange rate changes		(7	)		(1	)

Net change in cash and cash equivalents		142			792
Cash and cash equivalents at beginning of period		429			280
Cash and cash equivalents at end of period	$	571		$	1,072

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

MIDAMERICAN ENERGY HOLDINGS COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY (Unaudited)

(Amounts in millions)

	MEHC Shareholders’ Equity
												Accumulated
												Other
						Additional						Comprehensive
	Common					Paid-in			Retained			Income (Loss),			Noncontrolling			Total
	Shares			Stock		Capital			Earnings			Net			Interests			Equity

Balance, January 1, 2009		75		$	-	$	5,455		$	5,631		$	(879	)	$	270		$	10,477
Net income		-			-		-			217			-			7			224
Other comprehensive loss		-			-		-			-			(78	)		(1	)		(79	)
Stock-based compensation		-			-		123			-			-			-			123
Exercise of common stock options		1			-		25			-			-			-			25
Common stock purchases		(1	)		-		(148	)		-			-			-			(148	)
Contributions		-			-		-			-			-			8			8
Distributions		-			-		-			-			-			(15	)		(15	)
Other equity transactions		-			-		-			-			-			7			7
Balance, March 31, 2009		75		$	-	$	5,455		$	5,848		$	(957	)	$	276		$	10,622

Balance, January 1, 2010		75		$	-	$	5,453		$	6,788		$	335		$	267		$	12,843
Deconsolidation of BCC		-			-		-			-			-			(84	)		(84	)
Net income		-			-		-			242			-			87			329
Other comprehensive loss		-			-		-			-			(8	)		-			(8	)
Common stock purchases		-			-		(9	)		(47	)		-			-			(56	)
Distributions		-			-		-			-			-			(7	)		(7	)
Other equity transactions		-			-		-			-			-			(34	)		(34	)
Balance, March 31, 2010		75		$	-	$	5,444		$	6,983		$	327		$	229		$	12,983

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

MIDAMERICAN ENERGY HOLDINGS COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited)

(Amounts in millions)

	Three-Month Periods
	Ended March 31,
	2010			2009

Net income	$	329		$	224

Other comprehensive income (loss), net of tax:
Unrecognized amounts on retirement benefits, net of tax of $13 and $4		33			10
Foreign currency translation adjustment		(172	)		(48	)
Fair value adjustment on cash flow hedges, net of tax of $(12) and $(26)		(19	)		(40	)
Unrealized gains on marketable securities, net of tax of $101 and $-		150			-
Total other comprehensive income (loss), net of tax		(8	)		(78	)

Comprehensive income		321			146
Comprehensive income attributable to noncontrolling interests		87			7
Comprehensive income attributable to MEHC	$	234		$	139

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

MIDAMERICAN ENERGY HOLDINGS COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

(1)

General

MidAmerican Energy Holdings Company (“MEHC”) is a holding company that owns subsidiaries principally engaged in energy businesses (collectively with its subsidiaries, the “Company”). MEHC is a consolidated subsidiary of Berkshire Hathaway Inc. (“Berkshire Hathaway”). The balance of MEHC’s common stock is owned by Mr. Walter Scott, Jr. (along with family members and related entities), a member of MEHC’s Board of Directors, and Mr. Gregory E. Abel, a member of MEHC’s Board of Directors and MEHC’s President and Chief Executive Officer. As of March 31, 2010, Berkshire Hathaway, Mr. Scott (along with family members and related entities) and Mr. Abel owned 89.8%, 9.4% and 0.8%, respectively, of MEHC’s voting common stock.

The Company is organized and managed as eight distinct platforms: PacifiCorp, MidAmerican Funding, LLC (“MidAmerican Funding”) (which primarily consists of 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 consists of Northern Electric Distribution Limited (“Northern Electric”) and Yorkshire Electricity Distribution plc (“Yorkshire Electricity”)), CalEnergy Generation-Foreign (which owns a majority interest in the Casecnan project in the Philippines), CalEnergy Generation-Domestic (which owns 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, an electric and natural gas utility company in the Midwestern United States, two interstate natural gas pipeline companies in the United States, two electricity distribution companies in Great Britain, a diversified portfolio of independent power projects and the second largest residential real estate brokerage firm in the United States.

The unaudited Consolidated Financial Statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) for interim financial information and the United States Securities and Exchange Commission’s 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 Consolidated Financial Statements as of March 31, 2010 and for the three-month periods ended March 31, 2010 and 2009. The results of operations for the three-month period ended March 31, 2010 are not necessarily indicative of the results to be expected for the full year.

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 revenue 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, 2009 describes the most significant accounting policies used in the preparation of the Consolidated Financial Statements. There have been no significant changes in the Company’s assumptions regarding significant accounting estimates and policies during the three-month period ended March 31, 2010.

(2)	New Accounting Pronouncements

In January 2010, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2010-06 (“ASU No. 2010-06”), which amends FASB Accounting Standards Codification (“ASC”) Topic 820, “Fair Value Measurements and Disclosures.” ASU No. 2010-06 requires disclosure of (a) the amount of significant transfers into and out of Levels 1 and 2 of the fair value hierarchy and the reasons for those transfers and (b) gross presentation of purchases, sales, issuances and settlements in the Level 3 fair value measurement rollforward. This guidance clarifies that existing fair value measurement disclosures should be presented for each class of assets and liabilities. The existing disclosures about the valuation techniques and inputs used to measure fair value for both recurring and nonrecurring fair value measurements have also been clarified to ensure such disclosures are presented for the Levels 2 and 3 fair value measurements. The Company adopted this guidance as of January 1, 2010, with the exception of the disclosure requirement to present purchases, sales, issuances and settlements gross in the Level 3 fair value measurement rollforward, which is effective for fiscal years beginning after December 15, 2010, and for interim periods within those fiscal years. The adoption did not have a material impact on the Company’s disclosures included within Notes to Consolidated Financial Statements.

In June 2009, the FASB issued authoritative guidance (which was codified into ASC Topic 810, “Consolidation,” with the issuance of ASU No. 2009-17) that requires a primarily qualitative analysis to determine if an enterprise is the primary beneficiary of a variable interest entity. This analysis is based on whether the enterprise has (a) the power to direct the activities of the variable interest entity that most significantly impact the entity’s economic performance and (b) the obligation to absorb losses of the entity or the right to receive benefits from the entity that could potentially be significant to the variable interest entity. In addition, enterprises are required to more frequently reassess whether an entity is a variable interest entity and whether the enterprise is the primary beneficiary of the variable interest entity. Finally, the guidance for consolidation or deconsolidation of a variable interest entity is amended and disclosure requirements about an enterprise’s involvement with a variable interest entity are enhanced. The Company adopted this guidance as of January 1, 2010 on a prospective basis. As a result, PacifiCorp’s coal mining joint venture, Bridger Coal Company (“BCC”), was deconsolidated and is being accounted for under the equity method of accounting as the power to direct the activities that most significantly impact BCC’s economic performance are shared with the joint venture partner. The deconsolidation of BCC resulted in a decrease in assets, liabilities and noncontrolling interest equity as of January 1, 2010 of $192 million, $108 million and $84 million, respectively.

(3)	Property, Plant and Equipment, Net

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

		As of
	Depreciable	March 31,			December 31,
	Life	2010			2009

Regulated assets:
Utility generation, distribution and transmission system	5-85 years	$	35,204		$	35,616
Interstate pipeline assets	3-67 years		5,797			5,809
			41,001			41,425
Accumulated depreciation and amortization			(13,186	)		(13,336	)
Regulated assets, net			27,815			28,089

Non-regulated assets:
Independent power plants	10-30 years		677			677
Other assets	3-30 years		476			480
			1,153			1,157
Accumulated depreciation and amortization			(467	)		(462	)
Non-regulated assets, net			686			695

Net operating assets			28,501			28,784
Construction in progress			2,210			2,152
Property, plant and equipment, net		$	30,711		$	30,936

Substantially all of the construction in progress as of March 31, 2010 and December 31, 2009 relates to the construction of regulated assets.

(4)	Regulatory Matters

The following are updates to regulatory matters based upon material changes that occurred subsequent to December 31, 2009.

Rate Matters

Kern River Rate Case

In January 2009, the Federal Energy Regulatory Commission (“FERC”) issued an order rejecting an Offer of Settlement and Stipulation (“Settlement”) for the 2004 general rate case that had been filed in September 2008 and that had the support or was not opposed by a majority of Kern River’s long-term shippers, finding the Settlement would result in unjust and unreasonable rates. Kern River was ordered to file compliance rates based on an allowed return on equity of 11.55%. Pursuant to the January 2009 order, Kern River made the compliance filing in March 2009, which was revised in September 2009. A request for rehearing of the FERC’s January 2009 order, as well as comments and protests on Kern River’s March 2009 and September 2009 compliance filings, were timely filed. In December 2009, the FERC issued an order establishing Kern River’s rates for the period of Kern River’s current long-term contracts (“Period One rates”), and affirmed its prior opinion with regard to Kern River’s allowed return, while requiring that rates be levelized for shippers that elect to continue to take service following the expiration of their current contracts (“Period Two rates”). The FERC set all other issues related to Period Two rates for settlement processes, and a hearing should settlement processes fail. Kern River made a compliance filing conforming its Period One rates to the FERC’s order in January 2010 and then filed illustrative Period Two rates in February 2010 as required by the FERC’s order. Kern River filed a request for rehearing of the FERC’s December 2009 order in January 2010 and timely filed in the United States Court of Appeals for the District of Columbia Circuit a request for review of the issues resolved by the December 2009 order. Kern River sought the FERC’s authority to issue provisional refunds to its shippers subject to its right of recoupment, if necessary, based on the final rulings in the matter, and such authority was granted by the FERC in March 2010. In March 2010, the settlement discussions ordered by the FERC reached an impasse and were terminated. Formal hearings for Period Two rates are scheduled to commence in December 2010.

Oregon Senate Bill 408

Oregon Senate Bill 408 (“SB 408”) requires PacifiCorp and other large regulated, investor-owned utilities that provide electric or natural gas service to Oregon customers to file an annual report each October with the Oregon Public Utility Commission (“OPUC”) comparing income taxes collected and income taxes paid, as defined by the statute and its administrative rules. If after its review, the OPUC determines the amount of income taxes collected differs from the amount of income taxes paid by more than $100,000, the OPUC must require the public utility to establish an automatic adjustment clause to account for the difference.

The OPUC’s April 2008 order approving the recovery of $35 million, plus interest, related to PacifiCorp’s 2006 tax report is being challenged by the Industrial Customers of Northwest Utilities, which filed a petition in May 2008 with the Oregon Court of Appeals seeking judicial review of the April 2008 order. PacifiCorp believes the outcome of these proceedings will not have a material impact on its consolidated financial results. The $35 million, plus interest, was previously recorded in earnings.

In October 2009, PacifiCorp filed its 2008 tax report under SB 408. PacifiCorp’s filing for the 2008 tax year indicated that PacifiCorp paid $38 million more in income taxes than was collected in rates from its retail customers. In January 2010, PacifiCorp entered into a stipulation with OPUC staff and the Citizens’ Utility Board of Oregon, agreeing to a lower recovery totaling $2 million, including interest. In April 2010, the OPUC issued an order adopting the stipulation in its entirety.

(5)	Fair Value Measurements

The carrying amounts of the Company’s cash, certain cash equivalents, receivables, payables, accrued liabilities and short-term borrowings approximate fair value because of the short-term maturity of these instruments. The Company has various financial assets and liabilities that are measured at fair value on the Consolidated Financial Statements using inputs from the three levels of the fair value hierarchy. A financial asset or liability classification within the hierarchy is determined based on the lowest level input that is significant to the fair value measurement. The three levels are as follows:

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

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

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

The following table presents the Company’s assets and liabilities recognized on the Consolidated Balance Sheet and measured at fair value on a recurring basis as of March 31, 2010 (in millions):

	Input Levels for Fair Value Measurements
Description	Level 1			Level 2			Level 3			Other(1)			Total

Assets:
Commodity derivatives	$	4		$	473		$	40		$	(310	)	$	207
Investments in available-for-sale securities:
Money market mutual funds(2)		572			-			-			-			572
Debt securities		75			41			43			-			159
Equity securities		2,456			-			-			-			2,456
	$	3,107		$	514		$	83		$	(310	)	$	3,394

Liabilities:
Commodity derivatives	$	(10	)	$	(604	)	$	(422	)	$	422		$	(614	)
Interest rate derivative		-			(4	)		-			-			(4	)
	$	(10	)	$	(608	)	$	(422	)	$	422		$	(618	)

(1)	Primarily represents netting under master netting arrangements and a net cash collateral receivable of $112 million.

(2)	Amounts are included in cash and cash equivalents; current investments and restricted cash and investments; and noncurrent investments and restricted cash and investments on the Consolidated Balance Sheet. The fair value of these money market mutual funds approximates cost.

The following table presents the Company’s assets and liabilities recognized on the Consolidated Balance Sheet and measured at fair value on a recurring basis as of December 31, 2009 (in millions):

	Input Levels for Fair Value Measurements
Description	Level 1			Level 2			Level 3			Other(1)			Total

Assets:
Commodity derivatives	$	3		$	318		$	36		$	(169	)	$	188
Investments in available-for-sale securities:
Money market mutual funds(2)		376			-			-			-			376
Debt securities		70			79			46			-			195
Equity securities		2,230			8			-			-			2,238
	$	2,679		$	405		$	82		$	(169	)	$	2,997

Liabilities:
Commodity derivatives	$	(5	)	$	(395	)	$	(395	)	$	218		$	(577	)
Interest rate derivative		-			(4	)		-			-			(4	)
	$	(5	)	$	(399	)	$	(395	)	$	218		$	(581	)

(1)	Primarily represents netting under master netting arrangements and a net cash collateral receivable of $49 million.

(2)	Amounts are included in cash and cash equivalents; current investments and restricted cash and investments; and noncurrent investments and restricted cash and investments on the Consolidated Balance Sheet. The fair value of these money market mutual funds approximates cost.

When available, the fair value of derivative contracts is determined using unadjusted quoted prices for identical contracts on the applicable exchange in which the Company transacts. When quoted prices for identical contracts are not available, the Company uses forward price curves derived from market price quotations, when available, or internally developed and commercial models, with internal and external fundamental data inputs. Market price quotations are obtained from independent energy brokers, exchanges, direct communication with market participants and actual transactions executed by the Company. Market price quotations for certain major electricity and natural gas trading hubs are generally readily obtainable for the applicable term of the Company’s outstanding derivative contracts; therefore, the Company’s forward price curves for those locations and periods reflect observable market quotes. Market price quotations for other electricity and natural gas trading hubs are not as readily obtainable. Given that limited market data exists for these contracts, as well as for those contracts that are not actively traded, the Company uses forward price curves derived from internal models based on perceived pricing relationships to major trading hubs that are based on significant unobservable inputs. Refer to Note 6 for further discussion regarding the Company’s risk management and hedging activities.

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

The following table reconciles the beginning and ending balances of the Company’s assets and liabilities measured at fair value on a recurring basis using significant Level 3 inputs for the three-month periods ended March 31 (in millions):

	2010						2009
	Commodity			Debt			Commodity			Debt
	Derivatives			Securities			Derivatives			Securities

Beginning balance	$	(359	)	$	46		$	(369	)	$	37
Changes included in earnings(1)		9			-			18			-
Changes in fair value recognized in other comprehensive income		-			(3	)		-			1
Changes in fair value recognized in net regulatory assets		(28	)		-			(2	)		-
Purchases, sales, issuances and settlements		(4	)		-			(28	)		-
Net transfers (to) from Level 2		-			-			(21	)		-
Ending balance	$	(382	)	$	43		$	(402	)	$	38

(1)

Changes included in earnings are reported as operating revenue on the Consolidated Statements of Operations. Net unrealized gains included in earnings for the three-month periods ended March 31, 2010 and 2009, related to commodity derivatives held at March 31, 2010 and 2009, totaled $9 million and $14 million, respectively.

The Company’s long-term debt is carried at cost on the Consolidated Financial Statements. The fair value of the Company’s long-term debt has been estimated based upon quoted market prices, where available, or at the present value of future cash flows discounted at rates consistent with comparable maturities with similar credit risks. The carrying value of the Company’s variable-rate long-term debt approximates fair value because of the frequent repricing of these instruments at market rates. The following table presents the carrying value and estimated fair value of the Company’s long-term debt (in millions):

	As of March 31, 2010				As of December 31, 2009
	Carrying		Fair		Carrying		Fair
	Value		Value		Value		Value

Long-term debt	$	19,579	$	20,793	$	19,752	$	21,042

(6)	Risk Management and Hedging Activities

The Company is exposed to the impact of market fluctuations in commodity prices, interest rates and foreign currency exchange rates. The Company is principally exposed to electricity and natural gas commodity price risk through MEHC’s ownership of PacifiCorp and MidAmerican Energy (the “Utilities”) as they have an obligation to serve retail customer load in their regulated service territories. MidAmerican Energy also provides nonregulated retail natural gas and electricity services in competitive markets. The Utilities’ load and generation assets represent substantial underlying commodity positions. Exposures to commodity prices consist mainly of variations in the price of fuel required to generate electricity, wholesale electricity that is purchased and sold and natural gas supply for regulated and nonregulated retail customers. Electricity and natural gas prices are subject to wide price swings as supply and demand for these commodities are impacted by, among many other unpredictable items, changing weather, market liquidity, generating facility availability, customer usage, storage, and transmission and transportation constraints. Interest rate risk exists on variable-rate debt, commercial paper and future debt issuances. Additionally, the Company is exposed to foreign currency exchange rate risk from its business operations and investments in Great Britain. The Company does not engage in a material amount of proprietary trading activities.

Each of the Company’s business platforms has established a risk management process that is designed to identify, assess, monitor, report, manage and mitigate each of the various types of risk involved in its business. To mitigate a portion of its commodity risk, the Company uses commodity derivative contracts, including forwards, futures, options, swaps and other agreements, to effectively secure future supply or sell future production generally at fixed prices. The Company manages its interest rate risk by limiting its exposure to variable interest rates and by monitoring market changes in interest rates. The Company may from time to time enter into interest rate derivative contracts, such as interest rate swaps or locks, to mitigate the Company’s exposure to interest rate risk. The Company does not hedge all of its commodity price and interest rate risks, thereby exposing the unhedged portion to changes in market prices.

There have been no significant changes in the Company’s accounting policies related to derivatives. Refer to Note 5 for additional information on derivative contracts.

The following tables, which exclude contracts that qualify for the normal purchases or normal sales exception afforded by GAAP, summarize the fair value of the Company’s derivative contracts, on a gross basis, and reconcile those amounts to the amounts presented on a net basis on the Consolidated Balance Sheets (in millions):

	As of March 31, 2010
	Derivative Assets						Derivative Liabilities
	Current			Noncurrent			Current			Noncurrent			Total

Not Designated as Hedging Contracts(1)(2):
Commodity assets	$	335		$	69		$	24		$	64		$	492
Commodity liabilities		(94	)		(23	)		(210	)		(560	)		(887	)
Interest rate liability		-			-			-			(4	)		(4	)
Total		241			46			(186	)		(500	)		(399	)

Designated as Hedging Contracts(1):
Commodity assets		9			-			13			3			25
Commodity liabilities		-			-			(97	)		(52	)		(149	)
Total		9			-			(84	)		(49	)		(124	)

Total derivatives		250			46			(270	)		(549	)		(523	)
Cash collateral (payable) receivable		(89	)		-			127			74			112
Total derivatives - net basis	$	161		$	46		$	(143	)	$	(475	)	$	(411	)

	As of December 31, 2009
	Derivative Assets						Derivative Liabilities
	Current			Noncurrent			Current			Noncurrent			Total

Not Designated as Hedging Contracts(1)(2):
Commodity assets	$	219		$	70		$	22		$	31		$	342
Commodity liabilities		(30	)		(17	)		(171	)		(476	)		(694	)
Interest rate liability		-			-			-			(4	)		(4	)
Total		189			53			(149	)		(449	)		(356	)

Designated as Hedging Contracts(1):
Commodity assets		5			-			7			3			15
Commodity liabilities		(4	)		-			(53	)		(44	)		(101	)
Total		1			-			(46	)		(41	)		(86	)

Total derivatives		190			53			(195	)		(490	)		(442	)
Cash collateral (payable) receivable		(54	)		(1	)		72			32			49
Total derivatives - net basis	$	136		$	52		$	(123	)	$	(458	)	$	(393	)

(1)	Derivative contracts within these categories are subject to master netting arrangements and are presented on a net basis on the Consolidated Balance Sheets.

(2)	The Company’s commodity derivatives not designated as hedging contracts are generally included in regulated rates and as of March 31, 2010 and December 31, 2009, a net regulatory asset of $401 million and $353 million, respectively, was recorded related to the net derivative liability of $395 million and $352 million, respectively.

Not Designated as Hedging Contracts

For the Company’s commodity derivatives not designated as hedging contracts, the settled amount is generally included in regulated rates. Accordingly, the net unrealized gains and losses associated with interim price movements on contracts that are accounted for as derivatives and probable of inclusion in regulated rates are recorded as net regulatory assets. The following table reconciles the beginning and ending balances of the Company’s net regulatory assets and summarizes the pre-tax gains and losses on commodity derivative contracts recognized in net regulatory assets, as well as amounts reclassified to earnings for the three-month periods ended March 31 (in millions):

	2010		2009

Beginning balance	$	353	$	446
Changes in fair value recognized in net regulatory assets		15		(101	)
Gains reclassified to earnings - operating revenue		22		92
Gains (losses) reclassified to earnings - cost of sales		11		(122	)
Ending balance	$	401	$	315

For the Company’s derivatives not designated as hedging contracts and for which changes in fair value are not recorded as a net regulatory asset or liability, unrealized gains and losses are recognized on the Consolidated Statements of Operations as operating revenue for sales contracts, cost of sales and operating expense for purchase contracts and electricity and natural gas swap contracts and interest expense for the interest rate derivative. The following table summarizes the pre-tax gains (losses) included on the Consolidated Statements of Operations associated with the Company’s derivative contracts not designated as hedging contracts and not recorded as a net regulatory asset or liability for the three-month periods ended March 31 (in millions):

	2010			2009
Commodity derivatives:
Operating revenue	$	10		$	21
Cost of sales		(4	)		(14	)
Operating expense		1			(1	)
Total	$	7		$	6

Designated as Hedging Contracts

The Company uses derivative contracts accounted for as cash flow hedges to hedge electricity and natural gas commodity prices for delivery to nonregulated customers, spring operational sales, natural gas storage and other transactions. The Company’s derivative contracts designated as fair value hedges were not significant.

The following table reconciles the beginning and ending balances of the Company’s accumulated other comprehensive loss (pre-tax) and summarizes pre-tax gains and losses on derivative contracts designated and qualifying as cash flow hedges recognized in other comprehensive income (“OCI”), as well as amounts reclassified to earnings for the three-month periods ended March 31 (in millions):

	2010			2009
	Commodity			Commodity			Interest Rate
	Derivatives(1)			Derivatives			Derivative		Total(1)

Beginning balance	$	81		$	83		$	6	$	89
Losses recognized in OCI		50			88			-		88
Gains reclassified to earnings - revenue		1			-			-		-
Losses reclassified to earnings - cost of sales		(13	)		(23	)		-		(23	)
Ending balance	$	119		$	148		$	6	$	154

(1)	Certain derivative contracts, principally interest rate locks, have settled and the fair value at the date of settlement remains in accumulated other comprehensive income (loss) and is recognized in earnings when the forecasted transactions impact earnings.

Realized gains and losses on all hedges and hedge ineffectiveness are recognized in income as operating revenue, cost of sales, operating expense or interest expense depending upon the nature of the item being hedged. For the three-month periods ended March 31, 2010 and 2009, hedge ineffectiveness was insignificant. As of March 31, 2010, the Company had cash flow hedges with expiration dates extending through December 2022 and $58 million of pre-tax net unrealized losses are forecasted to be reclassified from accumulated other comprehensive income (“AOCI”) into earnings over the next twelve months as contracts settle.

Derivative Contract Volumes

The following table summarizes the net notional amounts of outstanding derivative contracts with fixed price terms that comprise the mark-to-market values as of March 31 (in millions):

	Unit of
	Measure	2010			2009
Commodity contracts:
Electricity sales	Megawatt hours		(18	)		(18	)
Natural gas purchases	Decatherms		228			263
Fuel purchases	Gallons		15			13
Interest rate derivative – variable to fixed swap	Australian dollars		59			62

Credit Risk

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

The Utilities analyze the financial condition of each significant wholesale counterparty before entering into any transactions, establish limits on the amount of unsecured credit to be extended to each counterparty and evaluate the appropriateness of unsecured credit limits on an ongoing basis. To mitigate exposure to the financial risks of wholesale counterparties, the Utilities enter into netting and collateral arrangements that may include margining and cross-product netting agreements and obtains third-party guarantees, letters of credit and cash deposits. Counterparties may be assessed interest fees for delayed payments. If required, the Utilities exercise rights under these arrangements, including calling on the counterparty’s credit support arrangement.

MidAmerican Energy also has potential indirect credit exposure to other market participants in the regional transmission organization (“RTO”) markets where it actively participates, including the Midwest Independent Transmission System Operator, Inc., PJM Interconnection, L.L.C., and the Electric Reliability Council of Texas. In the event of a default by a RTO market participant on its market-related obligations, losses are allocated among all other market participants in proportion to each participant’s share of overall market activity during the period of time the loss was incurred. Transactional activities of MidAmerican Energy and other participants in organized RTO markets are governed by credit policies specified in each respective RTO’s governing tariff or related business practices. Credit policies of RTO’s, which have been developed through extensive stakeholder participation, generally seek to minimize potential loss in the event of a market participant default without unnecessarily inhibiting access to the marketplace. MidAmerican Energy’s share of historical losses from defaults by other RTO market participants has not been material.

Collateral and Contingent Features

In accordance with industry practice, certain derivative contracts contain provisions that require MEHC’s subsidiaries, principally the Utilities, to maintain specific credit ratings from one or more of the major credit rating agencies on their unsecured debt. These derivative contracts may either specifically provide bilateral rights to demand cash or other security if credit exposures on a net basis exceed specified rating-dependent threshold levels (“credit-risk-related contingent features”) or provide the right for counterparties to demand “adequate assurance” in the event of a material adverse change in the subsidiary’s creditworthiness. These rights can vary by contract and by counterparty. As of March 31, 2010, these subsidiary’s credit ratings from the three recognized credit rating agencies were investment grade.

The aggregate fair value of the Company’s derivative contracts in liability positions with specific credit-risk-related contingent features totaled $672 million and $473 million as of March 31, 2010 and December 31, 2009, respectively, for which the Company had posted collateral of $201 million and $99 million, respectively. If all credit-risk-related contingent features for derivative contracts in liability positions had been triggered as of March 31, 2010 and December 31, 2009, the Company would have been required to post $249 million and $237 million, respectively, of additional collateral. The Company’s collateral requirements could fluctuate considerably due to market price volatility, changes in credit ratings or other factors.

(7)	Investments and Restricted Cash and Investments

Investments and restricted cash and investments consists of the following (in millions):

	As of
	March 31,			December 31,
	2010			2009
Investments:
BYD common stock	$	2,241		$	1,986
Rabbi trusts		271			268
Other		92			97
Total investments		2,604			2,351

Restricted cash and investments:
Nuclear decommissioning trust funds		274			264
Mine reclamation trust funds		-			79
Other		101			91
Total restricted cash and investments		375			434

Total investments and restricted cash and investments		2,979			2,785
Less current portion		(90	)		(83	)
Noncurrent portion	$	2,889		$	2,702

Investments and restricted cash and investments that management does not intend to use in current operations are presented as noncurrent on the Consolidated Balance Sheets. Gross unrealized and realized gains and losses of investments are not material as of March 31, 2010 and December 31, 2009 and for the three-month periods ended March 31, 2010 and 2009, except as discussed below related to the BYD Company Limited (“BYD”) and Constellation Energy Group, Inc. (“Constellation Energy”) common stock investments.

MEHC’s investment in BYD common stock is accounted for as an available-for-sale security with changes in fair value recognized in AOCI. As of March 31, 2010 and December 31, 2009, the fair value of MEHC’s investment in BYD common stock was $2.241 billion and $1.986 billion, respectively, which resulted in a pre-tax unrealized gain of $2.009 billion and $1.754 billion as of March 31, 2010 and December 31, 2009, respectively.

For the three-month period ended March 31, 2009, the Company recognized losses on Constellation Energy common stock still held as of March 31, 2009 totaling $66 million and recognized gains on Constellation Energy common stock sold during the three-month period ended March 31, 2009 totaling $10 million, each of which are included in other, net on the Consolidated Statements of Operations.

The Company’s restricted cash and investments are related to (a) the Company’s debt service reserve requirements for certain projects, (b) funds held in trust for nuclear decommissioning and coal mine reclamation and (c) unpaid dividends declared obligations. The debt service funds are restricted by their respective project debt agreements to be used only for the related project. Effective January 1, 2010, the Company deconsolidated BCC. Refer to Note 2 for further discussion.

(8)	Short-Term Debt and Revolving Credit Facilities

In March 2010, CE Electric UK replaced its expiring £100 million unsecured credit facility with a £150 million unsecured credit facility expiring in March 2013. The £150 million credit facility has substantially the same covenant terms as the expiring £100 million credit facility.

(9)	Related Party Transactions

As of March 31, 2010 and December 31, 2009, Berkshire Hathaway and its affiliates held 11% mandatory redeemable preferred securities due from certain wholly-owned subsidiary trusts of MEHC of $308 million and $353 million, respectively. Interest expense on these securities totaled $10 million and $18 million for the three-month periods ended March 31, 2010 and 2009, respectively. Accrued interest totaled $5 million and $8 million as of March 31, 2010 and December 31, 2009, respectively.

For the three-month period ended March 31, 2010, the Company received net cash payments for income taxes from Berkshire Hathaway totaling $65 million. For the three-month period ended March 31, 2009, the Company made cash payments for income taxes to Berkshire Hathaway totaling $315 million.

(10)	Employee Benefit Plans

Domestic Operations

Net periodic benefit cost for the domestic pension and other postretirement benefit plans included the following components for the three-month periods ended March 31 (in millions):

	Pension						Other Postretirement
	2010			2009			2010			2009

Service cost	$	7		$	8		$	2		$	2
Interest cost		27			26			11			11
Expected return on plan assets		(27	)		(26	)		(10	)		(9	)
Net amortization		3			1			4			5
Net periodic benefit cost	$	10		$	9		$	7		$	9

Employer contributions to the domestic pension and other postretirement benefit plans are expected to be $125 million and $33 million, respectively, during 2010. As of March 31, 2010, $42 million and $7 million of contributions had been made to the domestic pension and other postretirement benefit plans, respectively.

In March 2010, the President signed into law healthcare reform legislation that included provisions to eliminate the tax deductibility of other postretirement costs to the extent of retiree drug subsidies received from the federal government beginning after December 31, 2012. Accordingly, the Company increased deferred income tax liabilities and, consistent with the expectation that such additional income tax expense amounts are probable of inclusion in regulated rates, recorded a $53 million increase to net regulatory assets.

United Kingdom Operations

Net periodic benefit cost for the UK pension plan included the following components for the three-month periods ended March 31 (in millions):

	2010			2009

Service cost	$	4		$	3
Interest cost		22			19
Expected return on plan assets		(26	)		(24	)
Net amortization		8			4
Net periodic benefit cost	$	8		$	2

Employer contributions to the UK pension plan are expected to be £45 million during 2010. As of March 31, 2010, £11 million, or $17 million, of contributions had been made to the UK pension plan.

(11)	Income Taxes

A reconciliation of the federal statutory income tax rate to the effective income tax rate applicable to income before income tax expense is as follows for the three-month periods ended March 31:

	2010			2009

Federal statutory income tax rate		35	%		35	%
Federal and state income tax credits		(10	)		(13	)
State taxes, net of federal tax effect		3			1
CE Casecnan noncontrolling interest verdict		(5	)		-
Tax effect of foreign income		(5	)		(2	)
Effects of ratemaking		(2	)		(2	)
Other, net		(2	)		3
Effective income tax rate		14	%		22	%

(12)	Commitments and Contingencies

Legal Matters

The Company is party to 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 impact 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, penalties and other costs in substantial amounts and are described below.

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 generating facility in Wyoming. Under Wyoming state requirements, which are part of the Jim Bridger generating facility’s Title V permit and are enforceable by private citizens under the federal Clean Air Act, a potential source of pollutants such as a coal-fired generating facility must meet minimum standards for opacity, which is a measurement of light that is obscured in the flue of a generating facility. The complaint alleged thousands of violations of asserted six-minute compliance periods and sought an injunction ordering the Jim Bridger generating facility’s compliance with opacity limits, civil penalties of $32,500 per day per violation and the plaintiffs’ costs of litigation. In February 2010, PacifiCorp, the Sierra Club and the Wyoming Outdoor Council reached an agreement in principle to settle all outstanding claims in the action. The settlement was memorialized in a consent decree filed in April 2010 with the United States Environmental Protection Agency (“EPA”) and also with the court for review and approval. The EPA has 45 days to review and comment on the consent decree. After that, if approved by the court as expected, the consent decree is expected to be issued as a final court order and is not expected to have a material impact on PacifiCorp’s consolidated financial results.

CalEnergy Generation-Foreign

In February 2002, pursuant to the share ownership adjustment mechanism in the CE Casecnan Water and Energy Company, Inc. (“CE Casecnan”) shareholder agreement, MEHC’s indirect wholly owned subsidiary, CE Casecnan Ltd., advised the minority shareholder of CE Casecnan, LaPrairie Group Contractors (International) Ltd. (“LPG”) that MEHC’s indirect ownership interest in CE Casecnan had increased to 100% effective from commencement of commercial operations. In 2002, LPG filed a complaint in the Superior Court of the State of California, City and County of San Francisco (the “Superior Court”), 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 Philippine National Irrigation Administration arbitration. In January 2006, the Superior Court entered a judgment in favor of LPG against CE Casecnan Ltd regarding the calculation of the proforma financial projections. Pursuant to the judgment, 15% of the distributions of CE Casecnan were deposited into escrow plus interest at 9% per annum. The judgment was appealed, and as a result of the appellate decision, LPG retained ownership of 10% of the shares of CE Casecnan, with the remaining 5% share to be transferred to CE Casecnan Ltd. subject to certain buy-up rights under the shareholder agreement. The issues relating to the exercise of the buy-up right were decided by the Superior Court and in June 2009, LPG exercised its buy-up rights with respect to the remaining 5% ownership interest. In October 2009, the Superior Court issued a judgment declaring that after the buy up LPG was a 15% shareholder. The judgment was appealed in January 2010. Briefs will be filed in the second quarter in which CE Casecnan Ltd. will argue that LPG is only entitled to a 10% interest in the project company, and will challenge the computation of the buy-up price for the still disputed 5% interest. The appeal is expected to conclude in 2011. In April 2010, the Superior Court issued a tentative decision denying the remainder of LPG’s claims, including LPG’s claim for punitive damages.

In July 2005, MEHC and CE Casecnan Ltd. commenced an action against San Lorenzo Ruiz Builders and Developers Group, Inc. (“San Lorenzo”) in the District Court of Douglas County, Nebraska (the “District Court”), seeking a declaratory judgment as to San Lorenzo’s right to repurchase up to 15% of the shares in CE Casecnan. In January 2006, San Lorenzo filed a counterclaim against MEHC and CE Casecnan Ltd. seeking declaratory relief that it has effectively exercised its option to purchase up to 15% of the shares of CE Casecnan, that it is the rightful owner of such shares and that it is due all dividends previously paid on such shares. In March 2010, after a two-week jury trial, the judge declined to submit the claims and defenses in the case to the jury. Instead, the judge issued a written order in April 2010, which management believes is based on the findings of the Superior Court in the California litigation involving LPG discussed above. The order finds that San Lorenzo was entitled to be a 15% shareholder of CE Casecnan effective March 30, 2002 and is owed $32 million as of March 31, 2010. The Superior Court subsequently issued an order in the California litigation which management believes contradicts the April 2010 order issued by the District Court. MEHC filed motions to vacate or modify the order of the District Court or to grant a new trial based on errors in the proceeding and in light of the Superior Court order in the California litigation based on the same facts. MEHC also filed a motion asking the judge to recuse himself from further proceedings in the case due to his decision to not submit the claims and defenses to the jury and comments he made prior to his April 2010 order that he was not an expert in contract law and that the case would have been better served in a commercial court that handled exclusively contracts. A hearing on the motions is scheduled for May 10, 2010. In the event the Nebraska order is not vacated or modified or if a new trial is not granted, the ruling will be appealed.

As a result of the court’s ruling, the Company established a $48 million noncontrolling interest attributable to San Lorenzo in CE Casecnan. The noncontrolling interest established consisted of (1) 15% of CE Casecnan’s equity as of March 30, 2002 totaling $17 million; (2) an $83 million charge to net income attributable to noncontrolling interests representing 15% of CE Casecnan’s earnings since March 30, 2002; and (3) a $52 million reduction to San Lorenzo’s noncontrolling interest for 15% of CE Casecnan’s dividends paid since March 30, 2002, which is recorded in other current liabilities on the Consolidated Balance Sheet. The court’s ruling resulted in a $59 million after-tax charge to net income attributable to MEHC for the three-month period ended March 31, 2010. Depending on the ultimate outcome of the litigation, adjustments to this estimate may be necessary.

Environmental Laws and Regulations

Accrued Environmental Costs

The Company is fully or partly responsible for environmental remediation at various contaminated sites, including sites that are or were part of the Company’s operations and sites owned by third parties. The Company accrues environmental remediation expenses when the expenses are believed to be probable and can be reasonably estimated. The quantification of environmental exposures is based on many factors, including changing laws and regulations, advancements in environmental technologies, the quality of available site-specific information, site investigation results, expected remediation or settlement timelines, the Company’s proportionate responsibility, contractual indemnities and coverage provided by insurance policies. The liability recorded as of March 31, 2010 and December 31, 2009 was $21 million and is included in other current liabilities and other long-term liabilities on the Consolidated Balance Sheets. Environmental remediation liabilities that separately result from the normal operation of long-lived assets and that are legal obligations associated with the retirement of those assets are separately accounted for as asset retirement obligations.

Hydroelectric Relicensing

PacifiCorp’s hydroelectric portfolio consists of 47 generating facilities with an aggregate facility net owned capacity of 1,158 megawatts (“MW”). The FERC regulates 98% of the net capacity of this portfolio through 16 individual licenses, which typically have terms of 30 to 50 years. PacifiCorp expects to incur ongoing operating and maintenance expense and capital expenditures associated with the terms of its renewed hydroelectric licenses and settlement agreements, including natural resource enhancements. PacifiCorp’s Klamath hydroelectric system is currently operating under annual licenses. Substantially all of PacifiCorp’s remaining hydroelectric generating facilities are operating under licenses that expire between 2030 and 2058.

In February 2004, PacifiCorp filed with the FERC a final application for a new license to operate the 170-MW Klamath hydroelectric system 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 operating under annual licenses until the relicensing process is complete or the system’s four mainstem dams are removed. As part of the relicensing process, the FERC is required to perform an environmental review, and in November 2007, the FERC issued its final environmental impact statement. The United States Fish and Wildlife Service and the National Marine Fisheries Service issued final biological opinions in December 2007 analyzing the Klamath hydroelectric system’s impact on endangered species under a new FERC license consistent with the FERC staff’s recommended license alternative and terms and conditions issued by the United States Departments of the Interior and Commerce. These terms and conditions include construction of upstream and downstream fish passage facilities at the Klamath hydroelectric system’s four mainstem dams. Prior to the FERC issuing a final license, PacifiCorp is required to obtain water quality certifications from Oregon and California. PacifiCorp currently has water quality applications pending in Oregon and California.

In November 2008, PacifiCorp signed a non-binding agreement in principle (“AIP”) that laid out a framework for the disposition of PacifiCorp’s Klamath hydroelectric system relicensing process, including a path toward potential dam transfer and removal by an entity other than PacifiCorp no earlier than 2020. Subsequent to release of the AIP, negotiations between the parties continued with an expanded group of stakeholders. A final draft of the Klamath Hydroelectric Settlement Agreement (“KHSA”) was released in January 2010 for public review. The parties to the KHSA, which include PacifiCorp, the United States Department of the Interior, the United States Department of Commerce, the State of California, the State of Oregon and various other governmental and non-governmental settlement parties, signed the KHSA in February 2010. Federal legislation to endorse and enact provisions of the KHSA is expected to be introduced in the United States Congress in 2010.

Under the terms of the KHSA, the United States Departments of the Interior and Commerce will conduct scientific and engineering studies and consult with state, local and tribal governments and other stakeholders, as appropriate, to determine by March 31, 2012 whether removal of the Klamath hydroelectric system’s four mainstem dams will advance restoration of the salmonid fisheries of the Klamath Basin and is in the public interest. This determination will be made by the United States Secretary of the Interior. If it is determined that dam removal should proceed, dam removal is expected to commence no earlier than 2020.

Under the KHSA, PacifiCorp and its customers are protected from uncapped dam removal costs and liabilities. For dam removal to occur, federal legislation consistent with the KHSA must be enacted to provide, among other things, protection for PacifiCorp from all liabilities associated with dam removal activities. In addition, the KHSA limits PacifiCorp’s contribution to dam removal costs to no more than $200 million, of which up to $184 million would be collected from PacifiCorp’s Oregon customers with the remainder to be collected from PacifiCorp’s California customers. An additional $250 million for dam removal costs is expected to be raised through a California bond measure. If dam removal costs exceed $200 million and if the State of California is unable to raise the funds necessary for dam removal costs, sufficient funds would need to be obtained elsewhere in order for the KHSA and dam removal to proceed.

Actual removal of a facility would occur only after all permits for removal are obtained and the facility and associated land are transferred to a dam removal entity. Prior to potential removal of a facility, the facility will generally continue to operate as it does currently. However, PacifiCorp is responsible for implementing interim measures to provide additional resource protections, water quality improvements, habitat enhancement for aquatic species and increased funding for hatchery operations in the Klamath River Basin.

In July 2009, Oregon’s governor signed a bill authorizing PacifiCorp to collect surcharges from its Oregon customers for Oregon’s share of the customer contribution for the cost of removing the Klamath hydroelectric system’s four mainstem dams. In March 2010, PacifiCorp filed with the OPUC to begin collecting the surcharge from Oregon customers, as of that date, subject to refund based on the OPUC’s determination that the surcharges result in rates that are fair, just and reasonable. Also in March 2010, PacifiCorp filed with the California Public Utilities Commission to collect a surcharge from PacifiCorp’s California customers beginning January 1, 2011. The proceeds from the surcharges will be deposited in trust accounts to be established by each of the respective utility commissions.

As of March 31, 2010 and December 31, 2009, PacifiCorp had $69 million and $67 million, respectively, in costs related to the relicensing of the Klamath hydroelectric system included in construction in progress and reflected in property, plant and equipment, net on the Consolidated Balance Sheets.

(13)	MEHC Shareholders’ Equity

In March 2010, MEHC purchased 250,000 shares of common stock for $225 per share, or $56 million, from Mr. Scott (along with family members and related entities). In March 2009, 703,329 common stock options were exercised having an exercise price of $35.05 per share, or $25 million. Also in March 2009, MEHC purchased the shares issued from the options exercised for $148 million. As a result, the Company recognized $125 million of stock-based compensation expense, including the Company’s share of payroll taxes, for the three-month period ended March 31, 2009, which is included in operating expense on the Consolidated Statement of Operations.

(14)	Components of Accumulated Other Comprehensive Income, Net

Accumulated other comprehensive income attributable to MEHC, net consists of the following components (in millions):

	As of
	March 31,			December 31,
	2010			2009

Unrecognized amounts on retirement benefits, net of tax of $(188) and $(201)	$	(482	)	$	(515	)
Foreign currency translation adjustment		(363	)		(191	)
Fair value adjustment on cash flow hedges, net of tax of $(12) and $-		(19	)		-
Unrealized gains on marketable securities, net of tax of $794 and $693		1,191			1,041
Total accumulated other comprehensive income attributable to MEHC, net	$	327		$	335

(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
	Ended March 31,
	2010			2009

Operating revenue:
PacifiCorp	$	1,106		$	1,116
MidAmerican Funding		1,135			1,136
Northern Natural Gas		209			241
Kern River		86			97
CE Electric UK		192			193
CalEnergy Generation-Foreign		22			23
CalEnergy Generation-Domestic		8			8
HomeServices		199			173
Corporate/other(1)		(20	)		(18	)
Total operating revenue	$	2,937		$	2,969

Depreciation and amortization:
PacifiCorp	$	140		$	134
MidAmerican Funding		86			82
Northern Natural Gas		16			16
Kern River		27			24
CE Electric UK		39			36
CalEnergy Generation-Foreign		6			6
CalEnergy Generation-Domestic		2			2
HomeServices		4			4
Corporate/other(1)		(5	)		(4	)
Total depreciation and amortization	$	315		$	300

Operating income:
PacifiCorp	$	258		$	260
MidAmerican Funding		125			156
Northern Natural Gas		126			159
Kern River		49			61
CE Electric UK		90			102
CalEnergy Generation-Foreign		14			16
CalEnergy Generation-Domestic		4			4
HomeServices		(11	)		(19	)
Corporate/other(1)		(16	)		(125	)
Total operating income		639			614
Interest expense		(308	)		(318	)
Capitalized interest		14			9
Interest and dividend income		6			15
Other, net		37			(44	)
Total income before income tax expense and equity expense (income)	$	388		$	276

	Three-Month Periods
	Ended March 31,
	2010		2009
Interest expense:
PacifiCorp	$	101	$	99
MidAmerican Funding		48		51
Northern Natural Gas		15		15
Kern River		13		14
CE Electric UK		37		34
CalEnergy Generation-Foreign		1		1
CalEnergy Generation-Domestic		4		4
Corporate/other(1)		89		100
Total interest expense	$	308	$	318

	As of
	March 31,		December 31,
	2010		2009
Total assets:
PacifiCorp	$	20,184	$	20,244
MidAmerican Funding		10,752		10,732
Northern Natural Gas		2,656		2,657
Kern River		1,906		1,875
CE Electric UK		5,321		5,622
CalEnergy Generation-Foreign		407		463
CalEnergy Generation-Domestic		565		569
HomeServices		652		657
Corporate/other(1)		2,366		1,865
Total assets	$	44,809	$	44,684

(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 (a) corporate functions, including administrative costs, interest expense, corporate cash and investments and related interest income and (b) intersegment eliminations.

The following table shows the change in the carrying amount of goodwill by reportable segment for the three-month period ended March 31, 2010 (in millions):

					Northern					CE			CalEnergy
			MidAmerican		Natural			Kern		Electric			Generation-		Home-
	PacifiCorp		Funding		Gas			River		UK			Domestic		Services		Total

Balance, December 31, 2009	$	1,126	$	2,102	$	223		$	34	$	1,130		$	71	$	392	$	5,078
Foreign currency translation		-		-		-			-		(51	)		-		-		(51	)
Other		-		-		(7	)		-		-			-		-		(7	)
Balance, March 31, 2010	$	1,126	$	2,102	$	216		$	34	$	1,079		$	71	$	392	$	5,020

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 consolidated 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 Notes to Consolidated Financial Statements in Item 1 of this Form 10-Q. The Company’s actual results in the future could differ significantly from the historical results.

Forward-Looking Statements

This report contains statements that do not directly or exclusively relate to historical facts. These statements are “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934, as amended. Forward-looking statements can typically be identified by the use of forward-looking words, such as “may,” “could,” “project,” “believe,” “anticipate,” “expect,” “estimate,” “continue,” “intend,” “potential,” “plan,” “forecast” and similar terms. These statements are based upon the Company’s current intentions, assumptions, expectations and beliefs and are subject to risks, uncertainties and other important factors. Many of these factors are outside the Company’s control and could cause actual results to differ materially from those expressed or implied by the Company’s forward-looking statements. These factors include, among others:

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

changes in federal, state and local 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, among other items, increase operating and capital costs, reduce plant output 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 or the Company’s ability to obtain long-term contracts with customers and suppliers;

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

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

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

changes in business strategy or development plans;

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

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

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

risks relating to nuclear generation;

the impact of derivative contracts used to mitigate or manage volume, price and interest rate risk, including increased collateral requirements, and changes in the commodity prices, interest rates and other conditions that affect the fair value of derivative contracts;

increases in employee healthcare costs;

the impact of investment performance and changes in interest rates, legislation, healthcare cost trends, mortality and morbidity on pension and other postretirement benefits expense and funding requirements;

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

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

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

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

other risks or unforeseen events, including litigation, wars, the effects of terrorism, embargoes and other catastrophic events; and

other business or investment considerations that may be disclosed from time to time in MEHC’s filings with the United States 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 Part II, 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 for the First Quarter of 2010 and 2009

Overview

Net income attributable to MEHC for the three months ended March 31, 2010 was $242 million, an increase of $25 million, or 12%, compared to 2009. The results for 2010 included an after-tax charge of $59 million related to the CE Casecnan noncontrolling interest verdict. The results for 2009 included an after-tax stock-based compensation charge of $75 million as a result of the purchase of shares of common stock that were issued upon the exercise of stock options and a mark-to-market after-tax loss on the Constellation Energy Group, Inc. (“Constellation Energy”) common stock investment of $33 million. Excluding the impact of these items, net income attributable to MEHC decreased $24 million for 2010 compared to 2009. Net income attributable to MEHC decreased due to lower net income at MidAmerican Funding, Northern Natural Gas, Kern River, CE Electric UK and CalEnergy-Domestic, partially offset by higher net income at PacifiCorp and HomeServices and higher income tax benefits.

Net income was lower at MidAmerican Funding due to lower regulated electric wholesale margins and storm restoration costs. Net income at Northern Natural Gas and Kern River was lower as a result of lower revenue from less favorable market conditions. CE Electric UK’s net income decreased due to lower revenue from over-recovery provisions in the current regulatory period, partially offset by higher tariff rates and the impact from the foreign currency exchange rate. CalEnergy-Domestic’s net income decreased due to the timing of planned outages and the expiration of a favorable power purchase contract in the second quarter of 2009.

PacifiCorp’s net income increased due to higher prices approved by regulators, higher renewable energy credit sales, lower purchased power costs and higher allowance for funds used during construction, partially offset by lower wholesale revenue and retail usage. Net income at HomeServices increased due to higher brokerage activity in 2010.

Segment Results

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

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

	First Quarter
	2010			2009			Change
Operating revenue:
PacifiCorp	$	1,106		$	1,116		$	(10	)	(1	)%
MidAmerican Funding		1,135			1,136			(1	)	-
Northern Natural Gas		209			241			(32	)	(13	)
Kern River		86			97			(11	)	(11	)
CE Electric UK		192			193			(1	)	(1	)
CalEnergy Generation-Foreign		22			23			(1	)	(4	)
CalEnergy Generation-Domestic		8			8			-		-
HomeServices		199			173			26		15
Corporate/other		(20	)		(18	)		(2	)	(11	)
Total operating revenue	$	2,937		$	2,969		$	(32	)	(1	)

Operating income:
PacifiCorp	$	258		$	260		$	(2	)	(1	)%
MidAmerican Funding		125			156			(31	)	(20	)
Northern Natural Gas		126			159			(33	)	(21	)
Kern River		49			61			(12	)	(20	)
CE Electric UK		90			102			(12	)	(12	)
CalEnergy Generation-Foreign		14			16			(2	)	(13	)
CalEnergy Generation-Domestic		4			4			-		-
HomeServices		(11	)		(19	)		8		42
Corporate/other		(16	)		(125	)		109		87
Total operating income	$	639		$	614		$	25		4

PacifiCorp

Operating revenue decreased $10 million for 2010 compared to 2009 due to a decrease in wholesale and other revenue of $64 million, partially offset by higher retail revenue of $34 million and an increase in the sale of renewable energy credits totaling $22 million. The decrease in wholesale and other revenue was due to a 14% decrease in wholesale volumes, a 9% decrease in average wholesale prices and lower revenue attributable to PacifiCorp’s majority-owned coal mining operations as a result of adopting authoritative guidance requiring equity method accounting treatment of the operations effective January 1, 2010 (“PacifiCorp’s Coal Mining Operations”). The increase in retail revenue was due to an increase in prices approved by regulators and higher demand-side management revenue, partially offset by a 2% decrease in volumes. Retail volumes decreased as a result of lower customer usage primarily due to warmer than normal weather experienced in Oregon and Washington.

Operating income decreased $2 million for 2010 compared to 2009 due to the lower operating revenue, higher operating expenses of $13 million and higher depreciation and amortization of $6 million due to new assets placed in service during 2009, partially offset by lower energy costs totaling $27 million. Operating expenses increased due to higher demand-side management costs, partially offset by lower costs attributable to PacifiCorp’s Coal Mining Operations. Energy costs decreased due to a decrease in the average cost and volume of purchased electricity and the effects of regulatory cost recovery adjustment mechanisms of $10 million.

MidAmerican Funding

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

	First Quarter
	2010		2009		Change
Operating revenue:
Regulated electric	$	429	$	444	$	(15	)	(3	)%
Regulated natural gas		387		388		(1	)	-
Nonregulated and other		319		304		15		5
Total operating revenue	$	1,135	$	1,136	$	(1	)	-

Operating income:
Regulated electric	$	62	$	97	$	(35	)	(36	)%
Regulated natural gas		43		43		-		-
Nonregulated and other		20		16		4		25
Total operating income	$	125	$	156	$	(31	)	(20	)

Regulated electric operating revenue decreased $15 million for 2010 compared to 2009. Wholesale and other revenue decreased $23 million due to a 9% decrease in volumes resulting from lower generation, partly as a result of the expiration of a power purchase agreement, and a 5% decrease in average wholesale prices. Retail revenue increased $8 million on higher volumes of 3% primarily due to customer growth and higher customer usage, including the impacts of favorable weather.

Regulated electric operating income decreased $35 million for 2010 compared to 2009. In addition to the lower operating revenue, energy costs increased $15 million due to greater coal-fired generation and higher transmission costs, partially offset by lower purchases of electricity. Depreciation and amortization increased $3 million and operating expense increased $2 million primarily due to higher maintenance costs as a result of storm damage totaling $9 million, partially offset by lower general maintenance and health care costs.

Nonregulated and other operating revenue increased $15 million for 2010 compared to 2009 due to a 14% increase in electric retail volumes, partially offset by a 4% decrease in electric retail rates and lower gas revenue resulting from a 3% decrease in volumes. Nonregulated and other operating income increased $4 million for 2010 compared to 2009 due to higher electric retail margins.

Northern Natural Gas

Operating revenue decreased $32 million and operating income decreased $33 million for 2010 compared to 2009 due to lower transportation revenue of $27 million and lower storage revenue of $3 million. Transportation revenue decreased due to lower transportation volumes, principally in the field area, caused by less favorable economic conditions and lower natural gas price spreads.

Kern River

Operating revenue decreased $11 million for 2010 compared to 2009 due to lower natural gas price spreads and volumes totaling $7 million and lower rates as a result of the Federal Energy Regulatory Commission (“FERC”) order received in December 2009. Operating income decreased $12 million for 2010 compared to 2009 primarily due to the lower operating revenue.

CE Electric UK

Operating revenue decreased $1 million for 2010 compared to 2009. The decrease was due to lower distribution revenue totaling $16 million and lower gas production of $3 million, partially offset by the impact from the foreign currency exchange rate totaling $16 million. Distribution revenue was lower due to over-recovery provisions in the current regulatory period totaling $28 million, partially offset by higher tariff rates.

Operating income decreased $12 million for 2010 compared to 2009 primarily due to the lower distribution revenue and gas production, partially offset by the impact from the foreign currency exchange rate on operating income totaling $8 million.

CalEnergy Generation-Foreign

Operating revenue decreased $1 million and operating income decreased $2 million for 2010 compared to 2009 due to lower rainfall and related variable energy delivery fees earned in 2010 at the Casecnan project.

HomeServices

Operating revenue increased $26 million for 2010 compared to 2009 due to a 14% increase in closed brokerage units and a 5% increase in average home sale prices. Operating income increased $8 million for 2010 compared to 2009 due to a higher operating margin on higher revenue.

Corporate/other

Operating income increased $109 million due to $125 million of stock-based compensation expense in 2009 as a result of the purchase of common stock issued by MEHC upon the exercise of the last remaining stock options that had been granted to certain members of management at the time of Berkshire Hathaway Inc.’s (“Berkshire Hathaway”) acquisition of MEHC in 2000, partially offset by higher deferred compensation expense in 2010.

Consolidated Other Income and Expense Items

Interest Expense

Interest expense is summarized as follows (in millions):

	First Quarter
	2010		2009		Change

Subsidiary debt	$	210	$	210	$	-		-	%
MEHC senior debt and other		83		84		(1	)	(1	)
MEHC subordinated debt - Berkshire Hathaway		10		18		(8	)	(44	)
MEHC subordinated debt - other		5		6		(1	)	(17	)
Total interest expense	$	308	$	318	$	(10	)	(3	)

Interest expense decreased $10 million for 2010 compared to 2009 due to scheduled maturities and principal repayments and the January 2009 repayment of the remaining $500 million of 11% trust preferred securities to Berkshire Hathaway that were issued in connection with the purchase of the Constellation Energy preferred stock, partially offset by the $250 million debt issuance in July 2009 at MEHC and the impact of the foreign currency exchange rate of $3 million.

Capitalized Interest

Capitalized interest increased $5 million for 2010 compared to 2009 due to higher construction activity at PacifiCorp.

Interest and Dividend Income

Interest and dividend income decreased $9 million for 2010 compared to 2009 primarily due to income earned in 2009 related to the Constellation Energy investments.

Other, Net

Other, net increased $81 million to income of $37 million for 2010 compared to expense of $44 million for 2009 due to a $56 million loss on the Constellation Energy common stock investment in 2009, higher allowance for equity funds used during construction totaling $11 million, primarily due to higher construction activity at PacifiCorp, and higher earnings on deferred compensation investments.

Income Tax Expense

Income tax expense decreased $5 million for 2010 compared to 2009 and the effective tax rates were 14% and 22% for 2010 and 2009, respectively. The decrease in the effective tax rate was mainly due to income tax benefits from the CE Casecnan noncontrolling interest verdict, lower taxes on foreign income and other tax benefits.

Equity Expense (Income)

Equity expense (income) decreased $12 million to expense of $3 million for 2010 compared to income of $9 million for 2009 due to lower equity earnings at CE Generation, LLC primarily due to the timing of planned outages at the Imperial Valley projects and lower gas revenue as a result of the expiration of a favorable power purchase contract in the second quarter of 2009 at the Saranac project.

Net Income Attributable to Noncontrolling Interests

Net income attributable to noncontrolling interests increased $80 million for 2010 compared to 2009 due to an $83 million charge related to the CE Casecnan noncontrolling interest verdict.

Liquidity and Capital Resources

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

As of March 31, 2010, the Company’s total net liquidity available was $6.31 billion. The components of total net liquidity available are as follows (in millions):


							MidAmerican
	MEHC			PacifiCorp			Funding			Other(1)			Total(2)

Cash and cash equivalents	$	8		$	255		$	161		$	147		$	571

Available revolving credit facilities	$	585		$	1,395		$	654		$	353		$	2,987
Less:
Short-term borrowings and issuances of commercial paper		(173	)		-			-			(81	)		(254	)
Tax-exempt bond support, letters of credit and other		(41	)		(258	)		(195	)		-			(494	)
Net revolving credit facilities available	$	371		$	1,137		$	459		$	272		$	2,239

Net liquidity available before Berkshire Equity Commitment	$	379		$	1,392		$	620		$	419		$	2,810
Berkshire Equity Commitment(3)		3,500												3,500
Total net liquidity available	$	3,879											$	6,310
Unsecured revolving credit facilities:
Maturity date(4)		2013			2012-2013			2010, 2013			2010, 2013
Largest single bank commitment as a % of total(5)		17	%		15	%		23	%		22	%

(1)	In March 2010, CE Electric UK replaced its expiring £100 million unsecured credit facility with a £150 million unsecured credit facility expiring in March 2013.

(2)	The above table does not include unused revolving credit facilities and letters of credit for investments that are accounted for under the equity method.

(3)	In March 2006, MEHC and Berkshire Hathaway entered into the Berkshire Equity Commitment pursuant to which Berkshire Hathaway has agreed to purchase up to $3.5 billion of MEHC’s common equity upon any requests authorized from time to time by MEHC’s Board of Directors. The proceeds of any such equity contribution shall only be used for the purpose of (a) paying when due MEHC’s debt obligations and (b) funding the general corporate purposes and capital requirements of MEHC’s regulated subsidiaries. In March 2010, MEHC and Berkshire Hathaway amended the Berkshire Equity Commitment extending the term from February 28, 2011 to February 28, 2014 and reducing the Maximum Equity Amount, as defined in the agreement, from $3.5 billion to $2.0 billion effective March 1, 2011.

(4)	For further discussion regarding the Company’s credit facilities, refer to Note 9 of Notes to Consolidated Financial Statements in Item 8 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2009.

(5)	An inability of financial institutions to honor their commitments could adversely affect the Company’s short-term liquidity and ability to meet long-term commitments.

Operating Activities

Net cash flows from operating activities for the three-month periods ended March 31, 2010 and 2009 were $816 million and $653 million, respectively. The increase was mainly due to lower income taxes paid of $375 million primarily as a result of taxable income from the Constellation Energy transactions in 2009, partially offset by proceeds from the sale of Constellation Energy common stock in 2009 of $137 million and changes in collateral posted for derivative contracts of $48 million.

Investing Activities

Net cash flows from investing activities for the three-month periods ended March 31, 2010 and 2009 were $(617) million and $157 million, respectively. In January 2009, the Company received $1 billion, plus accrued interest, in full satisfaction of the 14% Senior Notes from Constellation Energy. Capital expenditures decreased $227 million due primarily to lower capital expenditures at PacifiCorp and MidAmerican Funding, partially offset by higher capital expenditures at Kern River related to the 2010 and Apex Expansion projects.

Capital Expenditures

Capital expenditures by reportable segment for the three-month periods ended March 31 are summarized as follows (in millions):

	2010		2009
Capital expenditures(1):
PacifiCorp	$	369	$	567
MidAmerican Funding		69		121
Northern Natural Gas		20		24
Kern River		48		8
CE Electric UK		77		90
Other		2		2
Total capital expenditures	$	585	$	812

(1)	Excludes amounts for non-cash equity allowance for funds used during construction (“AFUDC”).

The Company’s capital expenditures relate primarily to PacifiCorp and MidAmerican Energy (the “Utilities”), which consisted mainly of the following for the three-month periods ended March 31:

2010:

Transmission system investment totaling $129 million, including construction costs for the first major segment of the Energy Gateway Transmission Expansion Program, a 135-mile, double circuit, 345-kilovolt transmission line to be built between the Populus substation in southern Idaho and the Terminal substation near Salt Lake City, Utah, which is expected to be placed in service during 2010.

Emissions control equipment totaling $54 million.

Distribution, generation, mining and other infrastructure needed to serve existing and expected growing demand totaling $255 million.

2009:

The construction and development of wind-powered generating facilities totaling $201 million.

Transmission system investment totaling $107 million, including a major segment of the Energy Gateway Transmission Expansion Program at PacifiCorp.

Emissions control equipment totaling $69 million.

Distribution, generation, mining and other infrastructure needed to serve existing and expected growing demand totaling $311 million.

Additionally, capital expenditures for the three-month period ended March 31, 2010 include costs related to Kern River’s two expansion projects totaling $34 million. The 2010 Expansion project was placed in service in April 2010.

Financing Activities

Net cash flows from financing activities for the three-month period ended March 31, 2010 were $(50) million. Uses of cash totaled $173 million and consisted mainly of $56 million for net purchases of common stock, $45 million for repayments of MEHC subordinated debt, $42 million for net repayments of subsidiary short-term debt and $23 million for repayments of subsidiary debt. Sources of cash totaled $123 million and consisted of net proceeds from the MEHC revolving credit facility.

Net cash flows from financing activities for the three-month period ended March 31, 2009 were $(17) million. Uses of cash totaled $1.048 billion and consisted mainly of $500 million for repayments of MEHC subordinated debt, $214 million for net repayments of subsidiary short-term debt, $195 million for repayments of subsidiary debt and $123 million for net purchases of common stock. Sources of cash totaled $1.031 billion and consisted of proceeds from the issuance of subsidiary debt totaling $992 million and net proceeds from the MEHC revolving credit facility totaling $39 million.

Short-term Debt and Revolving Credit Facilities

MEHC had outstanding borrowings of $173 million and $50 million under its unsecured revolving credit facilities as of March 31, 2010 and December 31, 2009, respectively. Borrowings by MEHC’s subsidiaries under their commercial paper programs and unsecured revolving credit facilities decreased $48 million during the three-month period ended March 31, 2010 due primarily to lower borrowings at CE Electric UK.

Future Uses of Cash

The Company has available a variety of sources of liquidity and capital resources, both internal and external, including net cash flows from operating activities, public and private debt offerings, the issuance of commercial paper, the use of unsecured revolving credit facilities, the issuance of equity and other sources. These sources are expected to provide funds required for current operations, capital expenditures, acquisitions, investments, debt retirements and other capital requirements. The availability and terms under which each subsidiary has access to external financing depends on a variety of factors, including its credit rating, investors’ judgment of risk and conditions in the overall capital market, including the condition of the utility industry in general. Additionally, the Berkshire Equity Commitment can be used for the purpose of (a) paying when due MEHC’s debt obligations and (b) funding the general corporate purposes and capital requirements of MEHC’s regulated subsidiaries. Berkshire Hathaway will have up to 180 days to fund any such request in increments of at least $250 million pursuant to one or more drawings authorized by MEHC’s Board of Directors. The funding of any such drawing will be made by means of a cash equity contribution to MEHC in exchange for additional shares of MEHC’s common stock. In March 2010, MEHC and Berkshire Hathaway amended the Berkshire Equity Commitment extending the term from February 28, 2011 to February 28, 2014 and reducing the Maximum Equity Amount, as defined in the agreement, from $3.5 billion to $2.0 billion effective March 1, 2011.

Capital Expenditures

The Company has significant future capital requirements. Capital expenditure needs are reviewed regularly by management and may change significantly as a result of these reviews, which may consider, among other factors, changes in rules and regulations, including environmental and nuclear; changes in income tax laws; general business conditions; load projections; system reliability standards; the cost and efficiency of construction labor, equipment and materials; and the cost and availability of capital. Expenditures for compliance-related items such as pollution-control technologies, replacement generation, nuclear decommissioning, hydroelectric relicensing, hydroelectric decommissioning and associated operating costs are generally incorporated into MEHC’s energy subsidiaries’ regulated retail rates.

Forecasted capital expenditures, which exclude non-cash equity AFUDC, are approximately $2.7 billion for 2010, and include the following:

$452 million for transmission system investments at PacifiCorp, including $248 million for the Energy Gateway Transmission Expansion Program, which includes costs for completion of the first major segment of the program, the Populus to Terminal transmission line.

$363 million for environmental projects at the Utilities to install and upgrade emissions control equipment at certain coal-fired generating facilities to meet anticipated air quality and visibility targets through reductions of sulfur dioxide, nitrogen oxide and particulate matter emissions.

$146 million for construction and development of wind-powered generating facilities at PacifiCorp.

$144 million at Kern River for two expansion projects.

Remaining amounts are for ongoing investments in distribution, generation, mining and other infrastructure needed to serve existing and expected demand.

MidAmerican Energy continues to evaluate additional cost-effective wind-powered generation. In December 2009, the Iowa Utilities Board (“IUB”) issued an Order approving, subject to conditions, a settlement agreement between MidAmerican Energy and the Iowa Office of Consumer Advocate in conjunction with MidAmerican Energy’s ratemaking principles application to construct up to 1,001 megawatts (“MW”) (nominal ratings) of additional wind-powered generation in Iowa through 2012, the last 251 MW of which is subject to IUB confirmation. MidAmerican Energy has further committed that not greater than 500 MW will be placed in service during 2012. Wind-powered generation projects under this agreement are authorized to earn a 12.2% return on equity in any future Iowa rate proceeding. The Order has been appealed to the district court in Polk County, Iowa, by one of the intervenors in the proceeding. MidAmerican Energy has not entered into any material contracts for the development or construction of new wind-powered generation or the purchase of any related wind turbines.

Contractual Obligations

Subsequent to December 31, 2009, there were no material changes outside the normal course of business in contractual obligations from the information provided in Item 7 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2009. Additionally, refer to the “Capital Expenditures” discussion included in “Liquidity and Capital Resources.”

Regulatory Matters

MEHC’s regulated subsidiaries are subject to comprehensive regulation. In addition to the discussion contained herein regarding updates to regulatory matters based upon material changes that occurred subsequent to those disclosed in Item 7 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2009, refer to Note 4 of Notes to Consolidated Financial Statements in Item 1 of this Form 10-Q for additional regulatory matter updates.

PacifiCorp

Utah

In March 2009, PacifiCorp filed for an energy cost adjustment mechanism (“ECAM”) with the Utah Public Service Commission (“UPSC”). The filing recommends that the UPSC adopt the ECAM to recover the difference between base net power costs set in the next Utah general rate case and actual net power costs. The UPSC has separated the application into two phases to first address whether the mechanism is in the public interest, and then if it is found to be in the public interest, to determine the type of mechanism that should be implemented. Hearings on the public interest phase were completed in January 2010. In February 2010, the UPSC issued an order to proceed to the second phase to address design considerations in the development of an ECAM. Additionally, in February 2010, PacifiCorp filed an application with the UPSC seeking approval to defer the difference between the net power costs allowed by the UPSC’s final order in PacifiCorp’s 2009 general rate case and the actual net power costs incurred. Also in February 2010, the Utah Association of Energy Users filed a motion with the UPSC seeking approval to defer incremental renewable energy credit revenue in excess of the renewable energy credit value utilized in Utah rates established by the 2009 general rate case. If approved, the filings would establish a deferred cost balance to be considered for collection or refund through any potential mechanism established in the second phase of the ECAM proceeding.

In February 2010, PacifiCorp filed an alternative cost recovery application with the UPSC requesting recovery of $34 million associated with two major construction projects that are expected to be completed and in-service by June 2010. The mechanism provides for a ruling from the UPSC within 150 days of the application. In March 2010, PacifiCorp updated its alternative cost recovery application to reflect the cost of capital decisions from the February 2010 general rate case order, reducing the amount requested for recovery to $33 million.

Oregon

In February 2010, PacifiCorp made the initial filing for the annual transition adjustment mechanism (“TAM”) with the OPUC for an annual increase of $69 million to recover the anticipated net power costs forecasted for calendar year 2011. The rates in the TAM filing will be effective January 1, 2011 and are subject to updates throughout the proceeding.

In March 2010, PacifiCorp filed a general rate case with the Oregon Public Utility Commission (“OPUC”) requesting an annual increase of $131 million, or an average price increase of 13%. If approved by the OPUC, the rates will be effective January 1, 2011.

Wyoming

In October 2009, PacifiCorp filed a general rate case with the Wyoming Public Service Commission (“WPSC”) requesting a rate increase of $71 million with an effective date of August 1, 2010. Power costs are included in the general rate case, reflecting increased coal costs and the expiration of low cost long-term power purchase contracts. The application is based on a test period ending December 31, 2010. In March 2010, a multi-party stipulation was filed with the WPSC agreeing to an overall rate increase of $36 million, or an average price increase of 7%, to be implemented in two phases. If the stipulation is approved by the WPSC, the first phase, consisting of a $26 million increase, will be effective July 1, 2010 and the second phase, consisting of the remaining $10 million increase, will be effective February 1, 2011. The WPSC held hearings in April 2010 on the general rate case stipulation.

In January 2010, PacifiCorp filed its annual power cost adjustment mechanism (“PCAM”) application with the WPSC requesting recovery of $8 million in deferred net power costs. In March 2010, a multi-party stipulation was filed with the WPSC agreeing to reduce the requested recovery to $4 million. In April 2010, the WPSC approved a change in the PCAM surcharge rate effective April 1, 2010 to begin recovery of the $4 million on an interim basis until a final order on the PCAM stipulation is issued. In April 2010, the WPSC held hearings on the PCAM application and the multi-party stipulation.

In April 2010, PacifiCorp filed an application with the WPSC requesting approval of a new ECAM to replace the existing PCAM. The PCAM will sunset with the final deferral of power costs in November 2010.

Washington

In May 2010, PacifiCorp filed a general rate case with the Washington Utilities and Transportation Commission (“WUTC”) requesting an annual increase of $57 million, or an average price increase of 21%. If approved by the WUTC, the rates will be effective in April 2011.

Idaho

In February 2010, PacifiCorp filed an ECAM application with the Idaho Public Utilities Commission (“IPUC”) requesting recovery of $2 million in deferred net power costs. In March 2010, the IPUC issued an order approving PacifiCorp’s ECAM application effective April 1, 2010.

Northern Natural Gas

In November 2009, the FERC issued an order initiating a rate proceeding under Section 5 of the Natural Gas Act (“NGA”) for the purpose of investigating whether Northern Natural Gas’ rates are just and reasonable. The case was assigned to an administrative law judge and an initial decision by the administrative law judge must be issued in November 2010. In February 2010, Northern Natural Gas filed a cost and revenue study pursuant to the FERC’s order that demonstrated no adjustment to Northern Natural Gas’ rates were warranted. On May 5, 2010, a group of seven customers, representing approximately 39% of 2009 annual transportation and storage revenue, filed a motion to terminate the proceeding provided Northern Natural Gas would not file to make new rates effective prior to November 1, 2011. The customers requested a decision from the FERC prior to May 28, 2010. If the FERC does not grant the motion, Northern Natural Gas plans to file to increase rates pursuant to Section 4 of the NGA. Northern Natural Gas believes that the ultimate resolution of the matter will not have a material adverse effect on the Company’s consolidated financial results.

Environmental Laws and Regulations

The Company is subject to federal, state, local and foreign laws and regulations regarding air and water quality, renewable portfolio standards, climate change, hazardous and solid waste disposal, protected species and other environmental matters that have the potential to impact the Company’s current and future operations. In addition to imposing continuing compliance obligations, these laws and regulations provide authority to levy substantial penalties for noncompliance including fines, injunctive relief and other sanctions. These laws and regulations are administered by the United States Environmental Protection Agency and various other state, local and international agencies. All such laws and regulations are subject to a range of interpretation, which may ultimately be resolved by the courts. Environmental laws and regulations continue to evolve, and the Company is unable to predict the impact of the changing laws and regulations on its operations and consolidated financial results. The Company believes it is in material compliance with all applicable laws and regulations. Refer to “Future Uses of Cash” for discussion of the Company’s forecasted environmental-related capital expenditures.

There have been no material changes to environmental laws and regulations subsequent to those disclosed in Item 7 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2009. Refer to Note 12 of Notes to Consolidated Financial Statements in Item 1 of this Form 10-Q and Item 7 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2009 for additional information regarding certain environmental laws and regulations affecting the Company’s operations.

Credit Ratings

MEHC’s senior unsecured debt credit ratings are as follows: Moody’s Investors Service, “Baa1/stable;” Standard & Poor’s Rating Services, “BBB+/stable;” and Fitch Ratings, “BBB+/stable.” Debt and preferred securities of MEHC and certain of its subsidiaries are rated by the credit rating agencies. Assigned credit ratings are based on each rating agency’s assessment of the rated company’s ability to, in general, meet the obligations of its issued debt or preferred securities. The credit ratings are not a recommendation to buy, sell or hold securities, and there is no assurance that a particular credit rating will continue for any given period of time.

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

In accordance with industry practice, certain agreements, including derivative contracts, contain provisions that require certain of MEHC’s subsidiaries, principally the Utilities, to maintain specific credit ratings on their unsecured debt from one or more of the major credit ratings agencies. These agreements, including derivative contracts, may either specifically provide bilateral rights to demand cash or other security if credit exposures on a net basis exceed specified rating-dependent threshold levels (“credit-risk-related contingent features”) or provide the right for counterparties to demand “adequate assurance” in the event of a material adverse change in the subsidiary’s creditworthiness. These rights can vary by contract and by counterparty. As of March 31, 2010, these subsidiary’s credit ratings from the three recognized credit rating agencies were investment grade. If all credit-risk-related contingent features or adequate assurance provisions for these agreements, including derivative contracts, had been triggered as of March 31, 2010, the Company would have been required to post $614 million of additional collateral. The Company’s collateral requirements could fluctuate considerably due to market price volatility, changes in credit ratings or other factors. Refer to Note 6 of Notes to Consolidated Financial Statements in Item 1 of this Form 10-Q for a discussion of the Company’s collateral requirements specific to the Company’s derivative contracts.

New Accounting Pronouncements

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

Critical Accounting Estimates

Certain accounting measurements require management to make estimates and judgments concerning transactions that will be settled several years in the future. Amounts recognized on the Consolidated Financial Statements based on such estimates involve numerous assumptions subject to varying and potentially significant degrees of judgment and uncertainty. Accordingly, the amounts currently reflected on the Consolidated Financial Statements will likely change in the future as additional information becomes available. Estimates are used for, but not limited to, the accounting for the effects of certain types of regulation, derivatives, impairment of long-lived assets and goodwill, pension and other postretirement benefits, income taxes and revenue recognition - unbilled revenue. For additional discussion of the Company’s critical accounting estimates, see Item 7 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2009. There have been no significant changes in the Company’s assumptions regarding critical accounting estimates since December 31, 2009.

Item 3.

Quantitative and Qualitative Disclosures About Market Risk

For quantitative and qualitative disclosures about market risk affecting the Company, see Item 7A of the Company’s Annual Report on Form 10-K for the year ended December 31, 2009. The Company’s exposure to market risk and its management of such risk has not changed materially since December 31, 2009. Refer to Note 6 of Notes to Consolidated Financial Statements in Item 1 of this Form 10-Q for disclosure of the Company’s derivative positions as of March 31, 2010.

Item 4.

Controls and Procedures

At the end of the period covered by this Quarterly Report on Form 10-Q, the Company carried out an evaluation, under the supervision and with the participation of the Company’s management, including the Chief Executive Officer (principal executive officer) and the Chief Financial Officer (principal financial officer), of the effectiveness of the design and operation of the Company’s disclosure controls and procedures (as defined in Rule 13a-15(e) promulgated under the Securities and Exchange Act of 1934, as amended). Based upon that evaluation, the Company’s management, including the Chief Executive Officer (principal executive officer) and the Chief Financial Officer (principal financial officer), concluded that the Company’s disclosure controls and procedures were effective to ensure that information required to be disclosed by the Company in the reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and is accumulated and communicated to management, including the Company’s Chief Executive Officer (principal executive officer) and Chief Financial Officer (principal financial officer), or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure. There has been no change in the Company’s internal control over financial reporting during the quarter ended March 31, 2010 that has materially affected, or is reasonably likely to materially affect, the Company’s internal control over financial reporting.

PART II

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, 2009. Refer to Note 12 of Notes to Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q for material developments since those disclosed in Item 3 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2009.

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, 2009.

Item 2.

Unregistered Sales of Equity Securities and Use of Proceeds

Not applicable.

Item 3.

Defaults Upon Senior Securities

Not applicable.

Item 4.

(Removed and Reserved)

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.

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: May 7, 2010	/s/ Patrick J. Goodman
	Patrick J. Goodman
	Senior Vice President and Chief Financial Officer
	(principal financial and accounting officer)

EXHIBIT INDEX

Exhibit No.	Description

10.1	£150,000,000 Facility Agreement, dated March 26, 2010, among CE Electric UK Funding Company, Yorkshire Electricity Distribution plc and Northern Electric Distribution Limited, as Borrowers, and Abbey National Treasury Services plc, Lloyds TSB Bank plc and The Royal Bank of Scotland plc, as Original Lenders.

15	Awareness Letter of Independent Registered Public Accounting Firm.

31.1	Principal Executive Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2	Principal Financial Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.1	Principal Executive Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32.2	Principal Financial Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

Attached files

BERKSHIRE HATHAWAY ENERGY CO Reports

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