Berkshire Hathaway Energy 10-Q 2012 Q2 Quarterly report

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 June 30, 2012

or

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

For the transition period from ______ to _______

Commission File Number	Exact name of registrant as specified in its charter; State or other jurisdiction of incorporation or organization	IRS Employer 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  x  No  o

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  x  No  o

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 o Accelerated filer o Non-accelerated filer x Smaller reporting company o

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

Yes  o  No  x

All of the shares of common equity of MidAmerican Energy Holdings Company are privately held by a limited group of investors. As of July 31, 2012, 74,609,001 shares of common stock were outstanding.

TABLE OF CONTENTS

PART I

Item 1.	Financial Statements	1
Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	25
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	41
Item 4.	Controls and Procedures	41

PART II

Item 1.	Legal Proceedings	42
Item 1A.	Risk Factors	42
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	42
Item 3.	Defaults Upon Senior Securities	42
Item 4.	Mine Safety Disclosures	42
Item 5.	Other Information	42
Item 6.	Exhibits	42
Signatures		43
Exhibit Index		44

i

Definition of Abbreviations and Industry Terms

When used in Part I, Items 2 through 4, and Part II, Items 1 through 6, the following terms have the definitions indicated.

MidAmerican Energy Holdings Company and Related Entities
MEHC	MidAmerican Energy Holdings Company
Company	MidAmerican Energy Holdings Company and its subsidiaries
PacifiCorp	PacifiCorp and its subsidiaries
MidAmerican Funding	MidAmerican Funding, LLC
MidAmerican Energy	MidAmerican Energy Company
Northern Natural Gas	Northern Natural Gas Company
Kern River	Kern River Gas Transmission Company
Northern Powergrid Holdings	Northern Powergrid Holdings Company
MidAmerican Energy Pipeline Group	Consists of Northern Natural Gas and Kern River
MidAmerican Renewables	Consists of MidAmerican Renewables, LLC and CalEnergy Philippines
CE Casecnan	CE Casecnan Water and Energy Company, Inc.
HomeServices	HomeServices of America, Inc. and its subsidiaries
ETT	Electric Transmission Texas, LLC
Utilities	PacifiCorp and MidAmerican Energy Company
Domestic Regulated Businesses	PacifiCorp, MidAmerican Energy Company, Northern Natural Gas Company and Kern River Gas Transmission Company
Berkshire Hathaway	Berkshire Hathaway Inc. and its subsidiaries
Topaz	Topaz Solar Farms LLC
Topaz Project	Topaz Solar Farms LLC's 550-megawatt solar project
Agua Caliente	Agua Caliente Solar, LLC
Agua Caliente Project	Agua Caliente Solar, LLC's 290-megawatt solar project
Bishop Hill	Bishop Hill Energy II, LLC
Bishop Hill Project	Bishop Hill Energy II, LLC's 81-MW wind-powered generating project
Certain Industry Terms
AFUDC	Allowance for Funds Used During Construction
Dodd-Frank Reform Act	Dodd-Frank Wall Street Reform and Consumer Protection Act
EPA	United States Environmental Protection Agency
ERCOT	Electric Reliability Council of Texas
FERC	Federal Energy Regulatory Commission
GHG	Greenhouse Gases
IPUC	Idaho Public Utilities Commission
IUB	Iowa Utilities Board
kV	Kilovolt
MW	Megawatts
OPUC	Oregon Public Utility Commission
REC	Renewable Energy Credit
RPS	Renewable Portfolio Standards
RTO	Regional Transmission Organization
UPSC	Utah Public Service Commission
WPSC	Wyoming Public Service Commission
WUTC	Washington Utilities and Transportation Commission

ii

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 "will," "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 control of the Company and could cause actual results to differ materially from those expressed or implied by such forward-looking statements. These factors include, among others:

• general economic, political and business conditions, as well as changes in laws and regulations affecting the Company's operations or related industries;

• changes in, and compliance with, environmental laws, regulations, decisions and policies that could, among other items, increase operating and capital costs, reduce generating facility output, accelerate generating facility retirements or delay generating facility construction or acquisition;

• the outcome of general rate cases and other proceedings conducted by regulatory commissions or other governmental and legal bodies and the Company's ability to recover costs in rates in a timely manner;

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

• a high degree of variance between actual and forecasted load that could impact the Company's hedging strategy and the cost of balancing its generation resources and wholesale activities with its retail load obligations;

• performance and availability of the Company's generating facilities, including the impacts of outages and repairs, transmission constraints, weather and operating conditions;

• 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 generating 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;

• 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 commodity prices, interest rates and other conditions that affect the fair value of derivative contracts;

• the impact of inflation on costs and the Company's ability to recover such costs in regulated rates;

• 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 and regulations that could affect brokerage and mortgage 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 availability and price of natural gas in applicable geographic regions;

• the impact of new accounting guidance or changes in current accounting estimates and assumptions on the Company's consolidated financial results;

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

iii

• other risks or unforeseen events, including the effects of storms, floods, fires, litigation, wars, 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 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 United States Securities and Exchange Commission, 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 factors should not be construed as exclusive.

iv

PART I

Item 1. Financial Statements

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of

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 June 30, 2012, and the related consolidated statements of operations and comprehensive income for the three-month and six-month periods endedJune 30, 2012 and 2011, and of changes in equity and cash flows for the six-month periods endedJune 30, 2012 and 2011. 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, 2011, 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 February 27, 2012, 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, 2011 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

August 3, 2012

1

MIDAMERICAN ENERGY HOLDINGS COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (Unaudited)

(Amounts in millions)

	As of
	June 30,		December 31,
	2012		2011
ASSETS
Current assets:
Cash and cash equivalents	$	880	$	286
Trade receivables, net	1,188		1,270
Income taxes receivable	—		456
Inventories	726		690
Other current assets	644		581
Total current assets	3,438		3,283
Property, plant and equipment, net	35,340		34,167
Goodwill	5,016		4,996
Investments and restricted cash and investments	2,348		1,948
Regulatory assets	2,826		2,835
Other assets	532		489
Total assets	$	49,500	$	47,718

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

2

MIDAMERICAN ENERGY HOLDINGS COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (Unaudited) (continued)

(Amounts in millions)

	As of
	June 30,			December 31,
	2012			2011
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	1,007		$	989
Accrued employee expenses	246			155
Accrued interest	349			326
Accrued property, income and other taxes	531			340
Derivative contracts	150			160
Short-term debt	76			865
Current portion of long-term debt	1,224			1,198
Other current liabilities	579			514
Total current liabilities	4,162			4,547
Regulatory liabilities	1,699			1,663
MEHC senior debt	4,621			4,621
Subsidiary debt	14,500			13,253
Deferred income taxes	7,383			7,076
Other long-term liabilities	2,215			2,293
Total liabilities	34,580			33,453
Commitments and contingencies (Note 10)
Equity:
MEHC shareholders' equity:
Common stock - 115 shares authorized, no par value, 75 shares issued and outstanding	—			—
Additional paid-in capital	5,423			5,423
Retained earnings	9,967			9,310
Accumulated other comprehensive loss, net	(639		)	(641		)
Total MEHC shareholders' equity	14,751			14,092
Noncontrolling interests	169			173
Total equity	14,920			14,265
Total liabilities and equity	$	49,500		$	47,718

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

3

MIDAMERICAN ENERGY HOLDINGS COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)

(Amounts in millions)

	Three-Month Periods						Six-Month Periods
	Ended June 30,						Ended June 30,
	2012			2011			2012			2011
Operating revenue:
Energy	$	2,319		$	2,356		$	4,957		$	5,011
Real estate	389			290			598			479
Total operating revenue	2,708			2,646			5,555			5,490
Operating costs and expenses:
Energy:
Cost of sales	750			840			1,692			1,812
Operating expense	674			626			1,300			1,261
Depreciation and amortization	357			332			705			664
Real estate	359			271			574			472
Total operating costs and expenses	2,140			2,069			4,271			4,209
Operating income	568			577			1,284			1,281
Other income (expense):
Interest expense	(296		)	(303		)	(586		)	(606		)
Capitalized interest	13			9			22			18
Interest and dividend income	2			6			5			9
Other, net	18			20			51			46
Total other income (expense)	(263		)	(268		)	(508		)	(533		)
Income before income tax expense and equity income	305			309			776			748
Income tax expense	37			76			141			187
Equity income	19			7			31			14
Net income	287			240			666			575
Net income attributable to noncontrolling interests	5			4			9			8
Net income attributable to MEHC	$	282		$	236		$	657		$	567

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

4

MIDAMERICAN ENERGY HOLDINGS COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited)

(Amounts in millions)

	Three-Month Periods						Six-Month Periods
	Ended June 30,						Ended June 30,
	2012			2011			2012			2011
Net income	$	287		$	240		$	666		$	575
Other comprehensive (loss) income, net of tax:
Unrecognized amounts on retirement benefits, net of tax of $5, $2, $3 and $-	16			5			11			—
Foreign currency translation adjustment	(56		)	2			29			78
Unrealized losses on available-for-sale securities, net of tax of $(83), $(53), $(24) and $(180)	(124		)	(82		)	(35		)	(271		)
Unrealized gains (losses) on cash flow hedges, net of tax of $9, $7, $(2) and $8	12			11			(3		)	12
Total other comprehensive (loss) income, net of tax	(152		)	(64		)	2			(181		)
Comprehensive income	135			176			668			394
Comprehensive income attributable to noncontrolling interests	5			4			9			8
Comprehensive income attributable to MEHC	$	130		$	172		$	659		$	386

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

5

MIDAMERICAN ENERGY HOLDINGS COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY (Unaudited)

 (Amounts in millions)

	MEHC Shareholders' Equity
									Accumulated
				Additional					Other
	Common			Paid-in			Retained		Comprehensive			Noncontrolling			Total
	Shares	Stock		Capital			Earnings		Loss, Net			Interests			Equity
Balance at December 31, 2010	75	$	—	$	5,427		$	7,979	$	(174	)	$	176		$	13,408
Net income	—	—		—			567		—			8			575
Other comprehensive loss	—	—		—			—		(181		)	—			(181		)
Distributions	—	—		—			—		—			(13		)	(13		)
Other equity transactions	—	—		(4		)	—		—			2			(2		)
Balance at June 30, 2011	75	$	—	$	5,423		$	8,546	$	(355	)	$	173		$	13,787
Balance at December 31, 2011	75	$	—	$	5,423		$	9,310	$	(641	)	$	173		$	14,265
Net income	—	—		—			657		—			9			666
Other comprehensive income	—	—		—			—		2			—			2
Distributions	—	—		—			—		—			(13		)	(13		)
Balance at June 30, 2012	75	$	—	$	5,423		$	9,967	$	(639	)	$	169		$	14,920

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

6

MIDAMERICAN ENERGY HOLDINGS COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)

(Amounts in millions)

	Six-Month Periods
	Ended June 30,
	2012			2011
Cash flows from operating activities:
Net income	$	666		$	575
Adjustments to reconcile net income to net cash flows from operating activities:
Depreciation and amortization	715			670
Changes in regulatory assets and liabilities	1			(8		)
Deferred income taxes and amortization of investment tax credits	426			276
Other, net	(32		)	(27		)
Changes in other operating assets and liabilities, net of effects from acquisitions:
Trade receivables and other assets	117			163
Derivative collateral, net	13			13
Contributions to pension and other postretirement benefit plans, net	(95		)	(85		)
Accrued property, income and other taxes	641			287
Accounts payable and other liabilities	50			(25		)
Net cash flows from operating activities	2,502			1,839
Cash flows from investing activities:
Capital expenditures	(1,512		)	(1,176		)
Acquisitions, net of cash acquired	(106		)	—
Purchases of available-for-sale securities	(66		)	(88		)
Proceeds from sales of available-for-sale securities	57			87
Equity method investments	(264		)	(38		)
Increase in restricted cash and investments	(315		)	(5		)
Other, net	9			7
Net cash flows from investing activities	(2,197		)	(1,213		)
Cash flows from financing activities:
Proceeds from subsidiary debt	1,599			790
Repayments of subsidiary debt	(426		)	(502		)
Repayment of MEHC subordinated debt	(22		)	(22		)
Net repayments of short-term debt	(817		)	(320		)
Other, net	(45		)	(20		)
Net cash flows from financing activities	289			(74		)
Effect of exchange rate changes	—			(1		)
Net change in cash and cash equivalents	594			551
Cash and cash equivalents at beginning of period	286			470
Cash and cash equivalents at end of period	$	880		$	1,021

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

7

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 Company's operations are 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"), Northern Powergrid Holdings Company ("Northern Powergrid Holdings") (which primarily consists of Northern Powergrid (Northeast) Limited and Northern Powergrid (Yorkshire) plc), CalEnergy Philippines (which owns a majority interest in the Casecnan project in the Philippines), MidAmerican Renewables, LLC (which owns interests in independent power projects in the United States), and HomeServices of America, Inc. (collectively with its subsidiaries, "HomeServices"). Through these platforms, the Company owns and operates an electric utility company in the Western United States, 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. Northern Natural Gas and Kern River have been aggregated in the reportable segment called MidAmerican Energy Pipeline Group, and CalEnergy Philippines and MidAmerican Renewables, LLC have been aggregated in the reportable segment called MidAmerican Renewables.

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 June 30, 2012 and for the three- and six-month periods endedJune 30, 2012 and 2011. The results of operations for the three- and six-month periods endedJune 30, 2012 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 Consolidated 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, 2011 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 six-month period endedJune 30, 2012.

(2) New Accounting Pronouncements

In December 2011, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") No. 2011-11, which amends FASB Accounting Standards Codification ("ASC") Topic 210, "Balance Sheet." The amendments in this guidance require an entity to provide quantitative disclosures about offsetting financial instruments and derivative instruments. Additionally, this guidance requires qualitative and quantitative disclosures about master netting agreements or similar agreements when the financial instruments and derivative instruments are not offset. This guidance is effective for fiscal years beginning on or after January 1, 2013, and for interim periods within those fiscal years. The Company is currently evaluating the impact of adopting this guidance on its disclosures included within Notes to Consolidated Financial Statements.

8

In June 2011, the FASB issued ASU No. 2011-05, which amends FASB ASC Topic 220, "Comprehensive Income." ASU No. 2011-05 provides an entity with the option to present the total of comprehensive income, the components of net income and the components of other comprehensive income either in a single continuous statement of comprehensive income or in two separate but consecutive statements. Regardless of the option chosen, this guidance also requires presentation of items on the face of the financial statements that are reclassified from other comprehensive income to net income. This guidance does not change the items that must be reported in other comprehensive income, when an item of other comprehensive income must be reclassified to net income or how tax effects of each item of other comprehensive income are presented. This guidance is effective for interim and annual reporting periods beginning after December 15, 2011. In December 2011, the FASB issued ASU No. 2011-12, which also amends FASB ASC Topic 220 to defer indefinitely the ASU No. 2011-05 requirement to present items on the face of the financial statements that are reclassified from other comprehensive income to net income. ASU No. 2011-12 is also effective for interim and annual reporting periods beginning after December 15, 2011. The Company adopted this guidance on January 1, 2012 and elected the two separate but consecutive statements option.

In May 2011, the FASB issued ASU No. 2011-04, which amends FASB ASC Topic 820, "Fair Value Measurements and Disclosures." The amendments in this guidance are not intended to result in a change in current accounting. ASU No. 2011-04 requires additional disclosures relating to fair value measurements categorized within Level 3 of the fair value hierarchy, including quantitative information about unobservable inputs, the valuation process used by the entity and the sensitivity of unobservable input measurements. Additionally, entities are required to disclose the level of the fair value hierarchy for assets and liabilities that are not measured at fair value in the balance sheet, but for which disclosure of the fair value is required. This guidance is effective for interim and annual reporting periods beginning after December 15, 2011. The Company adopted ASU No. 2011-04 on January 1, 2012. The adoption of this guidance did not have a material impact on the Company's disclosures included within Notes to Consolidated Financial Statements.

(3) Property, Plant and Equipment, Net

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

		As of
	Depreciable	June 30,			December 31,
	Life	2012			2011
Regulated assets:
Utility generation, distribution and transmission system	5-80 years	$	41,083		$	40,180
Interstate pipeline assets	3-80 years	6,278			6,245
		47,361			46,425
Accumulated depreciation and amortization		(14,844		)	(14,390		)
Regulated assets, net		32,517			32,035
Nonregulated assets:
Independent power plants	5-30 years	677			677
Other assets	3-30 years	438			429
		1,115			1,106
Accumulated depreciation and amortization		(557		)	(533		)
Nonregulated assets, net		558			573
Net operating assets		33,075			32,608
Construction work-in-progress		2,265			1,559
Property, plant and equipment, net		$	35,340		$	34,167

Construction work-in-progress includes $1.8 billion and $1.6 billion as of June 30, 2012 and December 31, 2011, respectively, related to the construction of regulated assets.

9

The Company completed various acquisitions totaling $106 million during the six-month period endedJune 30, 2012. The purchase price for each acquisition was allocated to the assets acquired, which relate primarily to development and construction costs for the Topaz solar project ("Topaz Project") and the Bishop Hill II wind-powered generation project. There were no material liabilities assumed.

(4) Fair Value Measurements

The carrying value of the Company's cash, certain cash equivalents, receivables, payables, accrued liabilities and short-term borrowings approximates 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 Sheets and measured at fair value on a recurring basis (in millions):

	Input Levels for Fair Value Measurements
	Level 1			Level 2			Level 3			Other(1)			Total
As of June 30, 2012
Assets:
Commodity derivatives	$	1		$	126		$	28		$	(116	)	$	39
Money market mutual funds(2)	1,045			—			—			—			1,045
Debt securities:
United States government obligations	95			—			—			—			95
International government obligations	—			1			—			—			1
Corporate obligations	—			30			—			—			30
Municipal obligations	—			8			—			—			8
Agency, asset and mortgage-backed obligations	—			7			—			—			7
Auction rate securities	—			—			36			—			36
Equity securities:
United States companies	180			—			—			—			180
International companies	426			—			—			—			426
Investment funds	67			—			—			—			67
	$	1,814		$	172		$	64		$	(116	)	$	1,934
Liabilities - commodity derivatives	$	(22	)	$	(528	)	$	(11	)	$	249		$	(312	)

10

	Input Levels for Fair Value Measurements
	Level 1			Level 2			Level 3			Other(1)			Total
As of December 31, 2011
Assets:
Commodity derivatives	$	1		$	166		$	27		$	(147	)	$	47
Money market mutual funds(2)	164			—			—			—			164
Debt securities:
United States government obligations	89			—			—			—			89
International government obligations	—			1			—			—			1
Corporate obligations	—			30			—			—			30
Municipal obligations	—			12			—			—			12
Agency, asset and mortgage-backed obligations	—			7			—			—			7
Auction rate securities	—			—			35			—			35
Equity securities:
United States companies	166			—			—			—			166
International companies	489			—			—			—			489
Investment funds	64			—			—			—			64
	$	973		$	216		$	62		$	(147	)	$	1,104
Liabilities - commodity derivatives	$	(37	)	$	(598	)	$	(4	)	$	303		$	(336	)

(1) Represents netting under master netting arrangements and a net cash collateral receivable of $133 million and $156 million as of June 30, 2012 and December 31, 2011, respectively.

(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 Sheets. The fair value of these money market mutual funds approximates cost.

Derivative contracts are recorded on the Consolidated Balance Sheets as either assets or liabilities and are stated at fair value unless they are designated as normal purchases or normal sales and qualify for the exception afforded by GAAP. When available, the fair value of derivative contracts is estimated using unadjusted quoted prices for identical contracts in the market in which the Company transacts. When quoted prices for identical contracts are not available, the Company uses forward price curves. Forward price curves represent the Company's estimates of the prices at which a buyer or seller could contract today for delivery or settlement at future dates. The Company bases its forward price curves upon 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 due to the length of the contract. 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 unobservable inputs. The estimated fair value of these derivative contracts is a function of underlying forward commodity prices, interest rates, currency rates, related volatility, counterparty creditworthiness and duration of contracts. Refer to Note 5 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 available-for-sale 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.

11

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 (in millions):

	Three-Month Periods					Six-Month Periods
	Ended June 30,					Ended June 30,
				Auction					Auction
	Commodity			Rate		Commodity			Rate
	Derivatives			Securities		Derivatives			Securities
2012
Beginning balance	$	25		$	36	$	23		$	35
Changes included in earnings(1)	(1		)	—		9			—
Changes in fair value recognized in other comprehensive income	6			—		3			2
Changes in fair value recognized in net regulatory assets	(6		)	—		3			—
Sales	—			—		—			(1		)
Settlements	(7		)	—		(21		)	—
Ending balance	$	17		$	36	$	17		$	36

2011
Beginning balance	$	(341	)	$	39		$	(331	)	$	50
Changes included in earnings(1)	2			—			4			—
Changes in fair value recognized in other comprehensive income	—			—			—			2
Changes in fair value recognized in net regulatory assets	96			—			83			—
Sales	—			(2		)	—			(15		)
Settlements	10			—			11			—
Ending balance	$	(233	)	$	37		$	(233	)	$	37

(1) Changes included in earnings are reported as operating revenue on the Consolidated Statements of Operations. For commodity derivatives held as of June 30, 2012 and 2011, net unrealized (losses) gains included in earnings for the three-month periods endedJune 30, 2012 and 2011 totaled $(2) million and $2 million, respectively, and for the six-month periods endedJune 30, 2012 and 2011, totaled $5 million and $1 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 is a Level 2 fair value measurement and 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 June 30, 2012				As of December 31, 2011
	Carrying		Fair		Carrying		Fair
	Value		Value		Value		Value
Long-term debt	$	20,345	$	24,189	$	19,072	$	23,327

12

(5) 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, natural gas, coal and fuel oil commodity price risk primarily through MEHC's ownership of the Utilities as they have an obligation to serve retail customer load in their regulated service territories. MidAmerican Energy also provides nonregulated retail electricity and natural gas services in competitive markets. The Utilities' load and generating facilities 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 retail customers. Commodity prices are subject to wide price swings as supply and demand are impacted by, among many other unpredictable items, weather, market liquidity, generating facility availability, customer usage, storage, and transmission and transportation constraints. Interest rate risk exists on variable-rate debt 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 price risk, the Company uses commodity derivative contracts, which may include 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 primarily through the issuance of fixed-rate long-term debt and by monitoring market changes in interest rates. Additionally, 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, interest rate and foreign currency exchange 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 4 for additional information on derivative contracts.

The following table, which reflects master netting arrangements and excludes contracts that have been designated as normal under the normal purchases or normal sales exception afforded by GAAP, summarizes the fair value of the Company's derivative contracts, on a gross basis, and reconciles those amounts to the amounts presented on a net basis on the Consolidated Balance Sheets (in millions):

							Derivative
	Other						Contracts -			Other
	Current			Other			Current			Long-term
	Assets			Assets			Liabilities			Liabilities			Total
As of June 30, 2012
Not designated as hedging contracts(1):
Commodity assets	$	64		$	6		$	61		$	13		$	144
Commodity liabilities	(35		)	(2		)	(275		)	(189		)	(501		)
Total	29			4			(214		)	(176		)	(357		)
Designated as hedging contracts:
Commodity assets	5			2			2			2			11
Commodity liabilities	(1		)	—			(34		)	(25		)	(60		)
Total	4			2			(32		)	(23		)	(49		)
Total derivatives	33			6			(246		)	(199		)	(406		)
Cash collateral (payable) receivable	—			—			96			37			133
Total derivatives - net basis	$	33		$	6		$	(150	)	$	(162	)	$	(273	)

13

							Derivative
	Other						Contracts -			Other
	Current			Other			Current			Long-term
	Assets			Assets			Liabilities			Liabilities			Total
As of December 31, 2011
Not designated as hedging contracts(1):
Commodity assets	$	93		$	14		$	73		$	13		$	193
Commodity liabilities	(47		)	(5		)	(324		)	(216		)	(592		)
Total	46			9			(251		)	(203		)	(399		)
Designated as hedging contracts:
Commodity assets	—			—			1			—			1
Commodity liabilities	(6		)	—			(24		)	(17		)	(47		)
Total	(6		)	—			(23		)	(17		)	(46		)
Total derivatives	40			9			(274		)	(220		)	(445		)
Cash collateral (payable) receivable	(2		)	—			114			44			156
Total derivatives - net basis	$	38		$	9		$	(160	)	$	(176	)	$	(289	)

(1) The Company's commodity derivatives not designated as hedging contracts are generally included in regulated rates, and as of June 30, 2012 and December 31, 2011, a net regulatory asset of $357 million and $400 million, respectively, was recorded related to the net derivative liability of $357 million and $399 million, respectively.

Not Designated as Hedging Contracts

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 (in millions):

	Three-Month Periods						Six-Month Periods
	Ended June 30,						Ended June 30,
	2012			2011			2012			2011
Beginning balance	$	415		$	543		$	400		$	564
Changes in fair value recognized in net regulatory assets	3			(40		)	73			(62		)
Net gains reclassified to operating revenue	12			—			41			8
Net losses reclassified to cost of sales	(73		)	(5		)	(157		)	(12		)
Ending balance	$	357		$	498		$	357		$	498

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.

14

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 (in millions):

	Three-Month Periods						Six-Month Periods
	Ended June 30,						Ended June 30,
	2012			2011			2012			2011
Beginning balance(1)	$	71		$	34		$	46		$	37
Changes in fair value recognized in OCI	(8		)	(16		)	30			(14		)
Net gains reclassified to operating revenue	—			1			—			1
Net losses reclassified to cost of sales	(14		)	(4		)	(27		)	(9		)
Ending balance(1)	$	49		$	15		$	49		$	15

(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 ("AOCI") and is recognized in earnings when the forecasted transactions impact earnings.

Realized gains and losses on 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- and six-month periods endedJune 30, 2012 and 2011, hedge ineffectiveness was insignificant. As of June 30, 2012, the Company had cash flow hedges with expiration dates extending through May 2032 and $33 million of pre-tax net unrealized losses are forecasted to be reclassified from AOCI into earnings over the next twelve months as contracts settle.

Derivative Contract Volumes

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

	Unit of	June 30,	December 31,
	Measure	2012	2011
Electricity purchases	Megawatt hours	4	6
Natural gas purchases	Decatherms	143	183
Fuel purchases	Gallons	9	19

Credit Risk

The Utilities extend unsecured credit to other utilities, energy marketing companies, financial institutions and other market participants in conjunction with their 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 obtain third-party guarantees, letters of credit and cash deposits. Counterparties may be assessed fees for delayed payments. If required, the Utilities exercise rights under these arrangements, including calling on the counterparty's credit support arrangement.

15

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. and the PJM Interconnection, L.L.C. 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, diversifying MidAmerican Energy's exposure to credit losses from individual participants. 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 wholesale 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 June 30, 2012, these subsidiaries' 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 $507 million and $571 million as of June 30, 2012 and December 31, 2011, respectively, for which the Company had posted collateral of $111 million and $125 million, respectively, in the form of cash deposits and letters of credit. If all credit-risk-related contingent features for derivative contracts in liability positions had been triggered as of June 30, 2012 and December 31, 2011, the Company would have been required to post $310 million and $332 million, respectively, of additional collateral. The Company's collateral requirements could fluctuate considerably due to market price volatility, changes in credit ratings, changes in legislation or regulation, or other factors.

16

(6) Investments and Restricted Cash and Investments

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

	As of
	June 30,			December 31,
	2012			2011
Investments:
BYD common stock	$	424		$	488
Rabbi trusts	303			290
Other	100			99
Total investments	827			877
Equity method investments:
CE Generation, LLC	248			255
Electric Transmission Texas, LLC	285			221
Bridger Coal Company	204			204
Agua Caliente Solar, LLC	75			—
Other	61			52
Total equity method investments	873			732
Restricted cash and investments:
Nuclear decommissioning trust funds	325			308
Other	398			82
Total restricted cash and investments	723			390
Total investments and restricted cash and investments	2,423			1,999
Less current portion	(75		)	(51		)
Noncurrent portion	$	2,348		$	1,948

Investments

MEHC's investment in BYD Company Limited common stock is accounted for as an available-for-sale security with changes in fair value recognized in AOCI. As of June 30, 2012 and December 31, 2011, the fair value of MEHC's investment in BYD Company Limited common stock was $424 million and $488 million, respectively, which resulted in a pre-tax unrealized gain of $192 million and $256 million as of June 30, 2012 and December 31, 2011, respectively.

Equity Method Investments

In January 2012, MEHC, through an indirect wholly-owned subsidiary, acquired from NRG Energy, Inc. a 49% equity interest in Agua Caliente Solar, LLC ("Agua Caliente"), the developer and owner of a solar project in Arizona.

Restricted Cash and Investments

As of June 30, 2012 and December 31, 2011, other restricted cash and investments includes $315 million and $- million, respectively, restricted for construction of the Topaz Project.

17

(7) Recent Financing Transactions

Long-Term Debt

In January 2012, PacifiCorp issued $350 million of its 2.95% First Mortgage Bonds due February 2022 and $300 million of its 4.10% First Mortgage Bonds due February 2042. The net proceeds were used to repay short-term debt, fund capital expenditures and for general corporate purposes. In March 2012, PacifiCorp issued an additional $100 million of its 2.95% First Mortgage Bonds due February 2022. The net proceeds were used to redeem $84 million of tax-exempt bond obligations prior to scheduled maturity with a weighted average interest rate of 5.7%, repay short-term debt and for general corporate purposes.

In February 2012, Topaz Solar Farms, LLC ("Topaz") issued $850 million of the 5.75% Series A Senior Secured Notes. The principal of the notes amortize beginning September 2015 with a final maturity in September 2039. The net proceeds will be used to fund the costs and expenses related to the development, construction and financing of the Topaz Project. Any unused amounts will be invested or, in certain circumstances, loaned to MEHC. As of June 30, 2012, $321 million was loaned to MEHC.

In June 2012, MidAmerican Energy redeemed $275 million of its 5.125% senior notes due January 2013 at a redemption price determined in accordance with the terms of the indenture.

In July 2012, Northern Powergrid (Yorkshire) plc issued £150 million of its 4.375% Bonds due July 2032. The net proceeds will be used for general corporate purposes.

In conjunction with the construction of wind-powered generating facilities in 2012, MidAmerican Energy has accrued as construction work-in-progress amounts it is not contractually obligated to pay until December 2015. The amounts ultimately payable are discounted at 1.43% and recognized upon delivery of the equipment as long-term debt. The discount is being amortized as interest expense over the period until payment is due using the effective interest method. As of June 30, 2012, $89 million of such debt, net of associated discount, was outstanding.

Credit Facilities

In June 2012, MEHC entered into a $600 million senior unsecured credit facility expiring in June 2017. The credit facility includes rate options for which rates vary based on the borrowing option and MEHC's credit ratings for its senior unsecured long-term debt securities. This facility is for general corporate purposes and also supports letters of credit for the benefit of certain subsidiaries and affiliates. As of June 30, 2012, MEHC had no borrowings outstanding under this credit facility.The credit facility requires that MEHC's ratio of consolidated debt, including current maturities, to total capitalization not exceed 0.70 to 1.0 as of the last day of each quarter.

In June 2012, PacifiCorp replaced its existing $635 million unsecured credit facility expiring in October 2012 with a $600 million unsecured credit facility expiring in June 2017. The replacement credit facility includes rate options for which rates vary based on the borrowing option and PacifiCorp's credit ratings for its senior unsecured long-term debt securities. This facility is for general corporate purposes including supporting PacifiCorp's commercial paper program and provides for the issuance of letters of credit. As of June 30, 2012, PacifiCorp had no borrowings outstanding under this credit facility.The credit facility requires that PacifiCorp's ratio of consolidated debt, including current maturities, to total capitalization not exceed 0.65 to 1.0 as of the last day of each quarter.

In connection with its offering, Topaz entered into a letter of credit and reimbursement facility in an aggregate principal amount of $345 million. Letters of credit issued under the letter of credit facility will be used to (a) provide security under the power purchase agreement and large generator interconnection agreements, (b) fund the debt service reserve requirement and the operation and maintenance debt service reserve requirement, (c) provide security for remediation and mitigation liabilities, and (d) provide security in respect of conditional use permit sales tax obligations. As of June 30, 2012, Topaz had $42 million of letters of credit issued under this facility.

Pursuant to an equity funding and contribution agreement, MEHC has committed to provide Agua Caliente with funding for (a) base equity contributions of up to an aggregative amount of $303 million for the construction of the Agua Caliente Project, and (b) transmission upgrade costs. In January 2012, MEHC entered into a $303 million letter of credit facility related to its funding commitments. The equity funding and contribution agreement and the letter of credit commitment decreases as equity is contributed to the Agua Caliente Project. As of June 30, 2012, the balance of the commitment was $207 million.

18

(8) Employee Benefit Plans

Domestic Operations

Net periodic benefit cost for the domestic pension and other postretirement benefit plans included the following components (in millions):

	Three-Month Periods						Six-Month Periods
	Ended June 30,						Ended June 30,
	2012			2011			2012			2011
Pension:
Service cost	$	7		$	8		$	13		$	14
Interest cost	24			27			48			52
Expected return on plan assets	(30		)	(32		)	(59		)	(59		)
Net amortization	9			4			19			9
Net periodic benefit cost	$	10		$	7		$	21		$	16
Other postretirement:
Service cost	$	2		$	3		$	5		$	5
Interest cost	9			10			18			21
Expected return on plan assets	(10		)	(11		)	(21		)	(21		)
Net amortization	(1		)	5			—			8
Net periodic benefit cost	$	—		$	7		$	2		$	13

Employer contributions to the domestic pension and other postretirement benefit plans are expected to be $114 million and $9 million, respectively, during 2012. As of June 30, 2012, $97 million and $4 million of contributions had been made to the domestic pension and other postretirement benefit plans, respectively.

Foreign Operations

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

	Three-Month Periods						Six-Month Periods
	Ended June 30,						Ended June 30,
	2012			2011			2012			2011
Service cost	$	5		$	5		$	10		$	10
Interest cost	22			23			43			46
Expected return on plan assets	(27		)	(29		)	(53		)	(58		)
Net amortization	8			9			22			18
Net periodic benefit cost	$	8		$	8		$	22		$	16

Employer contributions to the United Kingdom pension plan are expected to be £50 million during 2012. As of June 30, 2012, £25 million, or $39 million, of contributions had been made to the United Kingdom pension plan.

19

(9) 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:

	Three-Month Periods				Six-Month Periods
	Ended June 30,				Ended June 30,
	2012		2011		2012		2011
Federal statutory income tax rate	35	%	35	%	35	%	35	%
Federal and state income tax credits	(14	)	(10	)	(12	)	(10	)
State income tax, net of federal income tax benefit	2		1		2		1
Income tax effect of foreign income	(3	)	(2	)	(3	)	(2	)
Income tax method change	(6	)	—		(2	)	—
Effects of ratemaking	(3	)	(1	)	(3	)	(1	)
Other, net	1		2		1		2
Effective income tax rate	12	%	25	%	18	%	25	%

Federal and state income tax credits primarily relate to production tax credits at the Utilities. The Utilities' wind-powered generating facilities are eligible for federal renewable electricity production tax credits for 10 years from the date the facilities were placed in service.

MidAmerican Energy changed the method by which it determines current income tax deductions for repair costs related to its regulated utility electric transmission and distribution assets based on new guidance published by the Internal Revenue Service. Application of this guidance results in current deductibility for those costs, which are capitalized for book purposes. MidAmerican Energy retroactively applied the method change, deducted amounts related to prior years' costs on its 2011 tax return and recognized the change in the second quarter of 2012. State utility rate regulation in Iowa requires that the tax effect of certain temporary differences be flowed through immediately to customers. Therefore, amounts that would otherwise have been recognized in income tax expense have been included as changes in regulatory assets. Accordingly, MidAmerican Energy's earnings for the three- and six-month periods ended June 30, 2012, reflect $18 million of income tax benefits recognized in connection with this method change for income tax years prior to 2012.

Berkshire Hathaway includes the Company in its United States federal income tax return. As of June 30, 2012, the Company had income taxes payable to Berkshire Hathaway of $168 million and as of December 31, 2011, the Company had income taxes receivable from Berkshire Hathaway of $456 million.

(10) 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.

20

USA Power

In October 2005, prior to MEHC's ownership of PacifiCorp, PacifiCorp was added as a defendant to a lawsuit originally filed in February 2005 in the Third District Court of Salt Lake County, Utah ("Third District Court") by USA Power, LLC, USA Power Partners, LLC and Spring Canyon Energy, LLC (collectively, the "Plaintiff"). The Plaintiff's complaint alleged that PacifiCorp misappropriated confidential proprietary information in violation of Utah's Uniform Trade Secrets Act and accused PacifiCorp of breach of contract and related claims in regard to the Plaintiff's 2002 and 2003 proposals to build a natural gas-fueled generating facility in Juab County, Utah. In October 2007, the Third District Court granted PacifiCorp's motion for summary judgment on all counts and dismissed the Plaintiff's claims in their entirety. In February 2008, the Plaintiff filed a petition requesting consideration by the Utah Supreme Court on two of its five claims. In May 2010, the Utah Supreme Court remanded the case back to the Third District Court for further consideration, which led to a trial that began in April 2012. On May 21, 2012, the jury reached a verdict in favor of the Plaintiff on both claims. The jury awarded the Plaintiff breach of contract damages of $18 million and unjust enrichment damages of $113 million against PacifiCorp; however, a final judgment has not been rendered on the verdict. On May 24, 2012, the Plaintiff filed a motion seeking exemplary damages. Under the Utah Uniform Trade Secrets law, the judge may award exemplary damages in an additional amount not to exceed twice the original award. The Plaintiff also filed a motion to seek recovery of attorneys' fees in an amount equal to 40% of all amounts ultimately awarded in the case. PacifiCorp plans on filing post-trial motions for a judgment notwithstanding the verdict and a new trial (collectively, "PacifiCorp's post-trial motions"). The trial judge set a schedule to file PacifiCorp's post-trial motions in the fall of 2012 and stayed briefing on the Plaintiff's motions, pending resolution of PacifiCorp's post-trial motions. PacifiCorp strongly disagrees with the verdict and will aggressively pursue available options in an effort to vacate or reduce the verdict, including, if necessary, appellate measures. If the judge grants either of PacifiCorp's post-trial motions, then the Plaintiff's motions for exemplary damages and attorneys' fees will be moot. If the judge does not grant either of PacifiCorp's post-trial motions, then the judge will set a schedule for PacifiCorp to respond to the Plaintiff's motions for exemplary damages and attorneys' fees. In the event the judge does not grant either of PacifiCorp's post-trial motions, PacifiCorp expects a decision on the Plaintiff's motions for exemplary damages and attorneys' fees in 2013. PacifiCorp believes there is meritorious basis for such post-trial motions and appeal. PacifiCorp has accrued its estimated liability as of June 30, 2012, and believes the ultimate outcome of the case will not be material to PacifiCorp's consolidated financial results; however this matter could have a material effect on PacifiCorp's consolidated financial results in the event of an unfavorable outcome. Any payment of damages will be at the end of the appeal process, which could take several years.

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, emissions performance standards, climate change, coal combustion byproduct disposal, hazardous and solid waste disposal, protected species and other environmental matters that have the potential to impact the Company's current and future operations. The Company believes it is in material compliance with all applicable laws and regulations.

Hydroelectric Relicensing

PacifiCorp's Klamath hydroelectric system is currently operating under annual licenses with the Federal Energy Regulatory Commission ("FERC"). In February 2010, 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 Klamath Hydroelectric Settlement Agreement ("KHSA"). Among other things, the KHSA provides that the United States Department of the Interior conduct scientific and engineering studies to assess whether removal of the Klamath hydroelectric system's mainstem dams is in the public interest and will advance restoration of the Klamath Basin's salmonid fisheries. 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. If Congress does not enact legislation, then PacifiCorp will resume relicensing at the FERC. In November 2011, bills were introduced in both chambers of the United States Congress that, if passed, would enact the KHSA and a companion agreement that seeks to resolve other water-related conflicts and restore habitat in the Klamath basin.

21

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 or other appropriate State of California financing mechanism. If dam removal costs exceed $200 million and if the State of California is unable to raise the additional funds necessary for dam removal costs, sufficient funds would need to be provided by an entity other than PacifiCorp in order for the KHSA and dam removal to proceed.

PacifiCorp has begun collection of surcharges from Oregon customers for their share of dam removal costs, as approved by the Oregon Public Utility Commission ("OPUC"), and is depositing the proceeds in a trust account maintained by the OPUC. PacifiCorp has begun collection of surcharges from California customers for their share of dam removal costs, as approved by the California Public Utilities Commission ("CPUC"), and is depositing the proceeds into trust accounts maintained by the CPUC. PacifiCorp is authorized to collect the surcharges through 2019.

As of June 30, 2012, PacifiCorp's property, plant and equipment, net included $121 million of costs associated with the Klamath hydroelectric system's mainstem dams and the associated relicensing and settlement costs. PacifiCorp has received approvals from the OPUC, the CPUC and the Wyoming Public Service Commission to depreciate the Klamath hydroelectric system's mainstem dams and the associated relicensing and settlement costs through the expected dam removal date. The depreciation rate changes were effective January 1, 2011 and will allow for full depreciation of the assets by December 2019 for those jurisdictions. PacifiCorp filed for consistent ratemaking treatment in the last Idaho general rate case, which was settled in January 2012 without a decision on this matter. PacifiCorp expects to seek similar approval in Washington. As part of the July 2011 Utah general rate case settlement that was approved by the Utah Public Service Commission in August 2011, PacifiCorp and the other parties to the settlement agreed to defer a decision regarding the acceleration of the depreciation rates for the Klamath hydroelectric system's mainstem dams to a future rate proceeding, at which time Utah's $36 million share of associated relicensing and settlement costs would be addressed. In the 2012 Utah general rate case, PacifiCorp has requested approval for Utah's share of accelerated depreciation of the Klamath hydroelectric system's mainstem dams and associated relicensing and settlement costs. This proceeding is currently in process.

Guarantees

The Company has entered into guarantees as part of the normal course of business and the sale of certain assets. These guarantees are not expected to have a material impact on the Company's consolidated financial results.

(11) Components of Accumulated Other Comprehensive Loss, Net

The following table shows the change in accumulated other comprehensive loss attributable to MEHC by each component of other comprehensive income, net of applicable income taxes, for the six-month period endedJune 30, 2012 (in millions):

							Unrealized						Accumulated
	Unrecognized			Foreign			Gains on			Unrealized			Other
	Amounts on			Currency			Available-			Gains on			Comprehensive
	Retirement			Translation			For-Sale			Cash Flow			Loss Attributable
	Benefits			Adjustment			Securities			Hedges			To MEHC, Net
Balance, December 31, 2011	$	(491	)	$	(307	)	$	142		$	15		$	(641	)
Other comprehensive income (loss)	11			29			(35		)	(3		)	2
Balance, June 30, 2012	$	(480	)	$	(278	)	$	107		$	12		$	(639	)

22

(12) Segment Information

MEHC's reportable segments were determined based on how the Company's strategic units are managed. Northern Natural Gas and Kern River have been aggregated in the reportable segment called MidAmerican Energy Pipeline Group, and CalEnergy Philippines and MidAmerican Renewables, LLC have been aggregated in the reportable segment called MidAmerican Renewables. Prior year amounts have been changed to conform to the current presentation. The Company's reportable segments with foreign operations include Northern Powergrid Holdings, whose business is principally in Great Britain, and MidAmerican Renewables, whose business includes operations 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						Six-Month Periods
	Ended June 30,						Ended June 30,
	2012			2011			2012			2011
Operating revenue:
PacifiCorp	$	1,153		$	1,091		$	2,344		$	2,210
MidAmerican Funding	709			805			1,583			1,784
MidAmerican Energy Pipeline Group	193			202			495			495
Northern Powergrid Holdings	244			238			507			490
MidAmerican Renewables	30			30			61			62
HomeServices	389			290			598			479
MEHC and Other(1)	(10		)	(10		)	(33		)	(30		)
Total operating revenue	$	2,708		$	2,646		$	5,555		$	5,490
Depreciation and amortization:
PacifiCorp	$	163		$	156		$	324		$	311
MidAmerican Funding	100			84			193			169
MidAmerican Energy Pipeline Group	48			47			96			93
Northern Powergrid Holdings	42			42			83			83
MidAmerican Renewables	8			7			15			15
HomeServices	7			3			10			6
MEHC and Other(1)	(4		)	(4		)	(6		)	(7		)
Total depreciation and amortization	$	364		$	335		$	715		$	670
Operating income:
PacifiCorp	$	254		$	267		$	535		$	538
MidAmerican Funding	81			85			172			198
MidAmerican Energy Pipeline Group	71			64			254			241
Northern Powergrid Holdings	131			136			288			295
MidAmerican Renewables	15			17			32			33
HomeServices	30			19			24			7
MEHC and Other(1)	(14		)	(11		)	(21		)	(31		)
Total operating income	568			577			1,284			1,281
Interest expense	(296		)	(303		)	(586		)	(606		)
Capitalized interest	13			9			22			18
Interest and dividend income	2			6			5			9
Other, net	18			20			51			46
Total income before income tax expense and equity income	$	305		$	309		$	776		$	748

23

	Three-Month Periods				Six-Month Periods
	Ended June 30,				Ended June 30,
	2012		2011		2012		2011
Interest expense:
PacifiCorp	$	97	$	103	$	196	$	203
MidAmerican Funding	42		45		85		93
MidAmerican Energy Pipeline Group	23		26		46		53
Northern Powergrid Holdings	34		39		67		78
MidAmerican Renewables	20		5		29		10
MEHC and Other(1)	80		85		163		169
Total interest expense	$	296	$	303	$	586	$	606

	As of
	June 30,		December 31,
	2012		2011
Total assets:
PacifiCorp	$	22,691	$	22,364
MidAmerican Funding	12,634		12,430
MidAmerican Energy Pipeline Group	4,829		4,854
Northern Powergrid Holdings	5,883		5,690
MidAmerican Renewables	2,029		890
HomeServices	766		649
MEHC and Other(1)	668		841
Total assets	$	49,500	$	47,718

(1) The remaining differences between the segment amounts and the consolidated amounts described as "MEHC and 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 six-month period endedJune 30, 2012 (in millions):

					MidAmerican
					Energy			Northern
			MidAmerican		Pipeline			Powergrid		MidAmerican		Home-
	PacifiCorp		Funding		Group			Holdings		Renewables		Services		Total
Balance, December 31, 2011	$	1,126	$	2,102	$	205		$	1,097	$	71	$	395	$	4,996
Foreign currency translation	—		—		—			9		—		—		9
Other	—		—		(13		)	—		—		24		11
Balance, June 30, 2012	$	1,126	$	2,102	$	192		$	1,106	$	71	$	419	$	5,016

24

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 the Company during the periods included herein. Explanations include management's best estimate of the impacts 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.

The Company's operations are organized and managed as eight distinct platforms: PacifiCorp, MidAmerican Funding (which primarily consists of MidAmerican Energy), Northern Natural Gas, Kern River, Northern Powergrid Holdings (which primarily consists of Northern Powergrid (Northeast) Limited and Northern Powergrid (Yorkshire) plc), CalEnergy Philippines (which owns a majority interest in the Casecnan project in the Philippines), MidAmerican Renewables, LLC (which owns interests in independent power projects in the United States), and HomeServices. Through these platforms, the Company 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. Northern Natural Gas and Kern River have been aggregated in the reportable segment called MidAmerican Energy Pipeline Group, and CalEnergy Philippines and MidAmerican Renewables, LLC have been aggregated in the reportable segment called MidAmerican Renewables. 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 reportable segment amounts and the consolidated amounts, described as "MEHC and Other," relate principally to corporate functions, including administrative costs and intersegment eliminations.

Results of Operations for the Second Quarter and First Six Months of 2012 and 2011

Overview

Net income attributable to MEHC for the three-month period ended June 30, 2012, was $282 million, an increase of $46 million, or 19%, compared to 2011. PacifiCorp's net income was $131 million for 2012, an increase of $2 million, or 2%, compared to 2011 as higher retail prices approved by regulators and higher retail customer load were substantially offset by higher energy costs, higher operating expense, lower average wholesale prices and higher depreciation and amortization. Net income at MidAmerican Funding was $77 million for 2012, an increase of $33 million, or 75%, compared to 2011 due to income tax benefits from the effects of ratemaking primarily related to repair deductions and higher production tax credits from additional wind-powered generation placed in service in late 2011. Additionally, higher regulated electric margins were partially offset by higher depreciation and amortization. Net income at MidAmerican Energy Pipeline Group was $31 million for 2012, an increase of $4 million, or 15%, compared to 2011 due to higher operating revenue related to the Kern River Apex Expansion project being placed in service in October 2011. Northern Powergrid Holdings' net income was $72 million for 2012, and was flat compared to 2011 as higher distribution rates and lower interest expense were offset by a favorable movement in regulatory provisions in 2011 and higher operating expense. MidAmerican Renewables' net income was $1 million for 2012, a decrease of $9 million, or 90%, compared to 2011 primarily due to higher interest expense related to the Topaz project financing, partially offset by higher equity earnings due to the acquisition of a 49% interest in Agua Caliente in January 2012. HomeServices' net income for 2012 was $21 million, an increase of $8 million, or 62%, compared to 2011 due to higher revenue and margins from higher closed units, partially offset by higher operating expenses and higher depreciation and amortization. MEHC and Other net loss of $51 million improved $8 million for 2012 compared to 2011 due to the cessation of purchase price pension amortization in 2011 and lower interest expense, partially offset by higher compensation expense.

25

Net income attributable to MEHC for the six-month period ended June 30, 2012, was $657 million, an increase of $90 million, or 16%, compared to 2011. PacifiCorp's net income was $281 million for 2012, an increase of $25 million, or 10%, compared to 2011 as higher retail prices approved by regulators, higher wholesale and other revenue, lower interest expense, higher equity AFUDC and a lower effective income tax rate were partially offset by higher energy costs, higher operating expense and higher depreciation and amortization. Net income at MidAmerican Funding was $148 million for 2012, an increase of $35 million, or 31%, compared to 2011 due to income tax benefits from the effects of ratemaking and higher production tax credits from additional wind-powered generation placed in service in late 2011, lower interest expense and higher regulated electric margins, partially offset by higher depreciation and amortization and lower regulated natural gas margins. Net income at MidAmerican Energy Pipeline Group was $128 million for 2012, an increase of $7 million, or 6%, compared to 2011 due to higher operating revenue, net of higher depreciation and lower equity AFUDC, related to the Kern River Apex Expansion project being placed in service in October 2011, and lower interest expense. Northern Powergrid Holdings' net income was $165 million for 2012, an increase of $5 million, or 3%, compared to 2011 due to higher distribution rates and lower interest expense, partially offset by a favorable movement in regulatory provisions in 2011 and higher operating expense. MidAmerican Renewables' net income was $6 million for 2012, a decrease of $15 million compared to 2011 primarily due to higher interest expense related to the Topaz project financing and lower equity earnings at CE Generation, partially offset by higher equity earnings due to the acquisition of a 49% interest in Agua Caliente in January 2012. HomeServices' net income for 2012 was $20 million, an increase of $13 million, compared to 2011 due to higher revenue and margins from higher closed units, partially offset by higher operating expenses and higher depreciation and amortization. MEHC and Other net loss of $91 million improved $20 million for 2012 compared to 2011 due to the cessation of purchase price pension amortization in 2011, higher equity income at ETT and lower interest expense, partially offset by higher compensation expense.

Reportable Segment Results

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

	Second Quarter											First Six Months
	2012			2011			Change					2012			2011			Change
Operating revenue:
PacifiCorp	$	1,153		$	1,091		$	62		6	%	$	2,344		$	2,210		$	134		6	%
MidAmerican Funding	709			805			(96		)	(12	)	1,583			1,784			(201		)	(11	)
MidAmerican Energy Pipeline Group	193			202			(9		)	(4	)	495			495			—			—
Northern Powergrid Holdings	244			238			6			3		507			490			17			3
MidAmerican Renewables	30			30			—			—		61			62			(1		)	(2	)
HomeServices	389			290			99			34		598			479			119			25
MEHC and Other	(10		)	(10		)	—			—		(33		)	(30		)	(3		)	(10	)
Total operating revenue	$	2,708		$	2,646		$	62		2		$	5,555		$	5,490		$	65		1

Operating income:
PacifiCorp	$	254		$	267		$	(13	)	(5	)%	$	535		$	538		$	(3	)	(1	)%
MidAmerican Funding	81			85			(4		)	(5	)	172			198			(26		)	(13	)
MidAmerican Energy Pipeline Group	71			64			7			11		254			241			13			5
Northern Powergrid Holdings	131			136			(5		)	(4	)	288			295			(7		)	(2	)
MidAmerican Renewables	15			17			(2		)	(12	)	32			33			(1		)	(3	)
HomeServices	30			19			11			58		24			7			17			*
MEHC and Other	(14		)	(11		)	(3		)	(27	)	(21		)	(31		)	10			32
Total operating income	$	568		$	577		$	(9	)	(2	)	$	1,284		$	1,281		$	3		—

*    Not meaningful

26

PacifiCorp

Operating revenue increased $62 million for the second quarter of 2012 compared to 2011 due to higher retail revenue of $76 million, partially offset by lower wholesale and other revenue of $14 million. The increase in retail revenue was due to higher prices approved by regulators of $49 million, higher residential and commercial customer load in Utah due to the impacts of hot weather and higher irrigation load in Idaho and Utah, partially offset by lower residential customer load in Oregon due to mild weather and lower industrial customer load in Oregon and Wyoming. The decrease in wholesale and other revenue was due to lower average market prices of $19 million and lower volumes of $4 million, partially offset by higher renewable energy credit revenue of $5 million.

Operating income decreased $13 million for the second quarter of 2012 compared to 2011 as the increase in operating revenue was more than offset by higher energy costs of $33 million, higher operating expense of $33 million and higher depreciation and amortization of $7 million due to higher plant in service. Energy costs increased due to higher purchased power volumes of $28 million, reduced electricity swap settlement gains of $27 million and higher natural gas-fueled generation, partially offset by lower purchased power prices. Energy supplied increased 2% for the second quarter of 2012 compared to 2011. Higher purchased power volumes of 16% resulting from lower average market prices and a 38% increase in natural gas-fueled generation due to higher availability and improved spark spreads were partially offset by lower hydroelectric and wind-powered generation. Operating expense increased due to charges in 2012 related to litigation, damage claims, the impairment of environmental costs at a coal-fueled generating facility and higher property taxes due to higher plant in service.

Operating revenue increased $134 million for the first six months of 2012 compared to 2011 due to higher retail revenue of $124 million and higher wholesale and other revenue of $10 million. The increase in retail revenue was due to higher prices approved by regulators of $109 million, higher retail customer load substantially due to the impacts of hot weather in Utah and higher irrigation load in Idaho, partially offset by lower residential customer load in Oregon and lower industrial customer load in Oregon and Wyoming primarily due to certain large customers electing to self-generate. The increase in wholesale and other revenue was due to higher volumes of $29 million and renewable energy credit revenue of $21 million, partially offset by lower average market prices of $42 million.

Operating income decreased $3 million for the first six months of 2012 compared to 2011 as the increase in operating revenue was more than offset by higher energy costs of $95 million, higher operating expense of $28 million and higher depreciation and amortization of $13 million due to higher plant in service. Energy costs increased due to reduced electricity swap settlement gains of $78 million, higher thermal generation, the impact of energy cost adjustment mechanisms of $15 million and higher purchased power volumes of $7 million, partially offset by lower purchased power prices of $51 million. Energy supplied increased 4% for the first six months of 2012 compared to 2011. Higher natural gas-fueled generation of 37% due to higher availability and improved spark spreads, higher coal generation and higher purchased power volumes were partially offset by lower hydroelectric and wind-powered generation. Operating expense increased due to charges in 2012 related to litigation, damage claims, the impairment of environmental costs at a coal-fueled generating facility and higher property taxes due to higher plant in service.

MidAmerican Funding

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

	Second Quarter									First Six Months
	2012		2011		Change					2012		2011		Change
Operating revenue:
Regulated electric	$	404	$	412	$	(8	)	(2	)%	$	784	$	789	$	(5	)	(1	)%
Regulated natural gas	91		130		(39		)	(30	)	354		463		(109		)	(24	)
Nonregulated and other	214		263		(49		)	(19	)	445		532		(87		)	(16	)
Total operating revenue	$	709	$	805	$	(96	)	(12	)	$	1,583	$	1,784	$	(201	)	(11	)
Operating income:
Regulated electric	$	66	$	65	$	1		2	%	$	114	$	115	$	(1	)	(1	)%
Regulated natural gas	1		4		(3		)	(75	)	31		49		(18		)	(37	)
Nonregulated and other	14		16		(2		)	(13	)	27		34		(7		)	(21	)
Total operating income	$	81	$	85	$	(4	)	(5	)	$	172	$	198	$	(26	)	(13	)

27

Regulated electric operating revenue decreased $8 million for the second quarter of 2012 compared to 2011 due to lower wholesale and other revenue of $24 million, partially offset by higher retail revenue of $16 million. Wholesale and other revenue decreased due to lower volumes and prices. Volumes decreased 24% as certain coal units could not be economically dispatched as average market prices decreased 7% compared to 2011. Retail revenue increased due to the new adjustment clauses in Iowa and Illinois totaling $11 million and a 2% increase in customer load as a result of abnormally hot weather in 2012.

Regulated electric operating income increased $1 million for the second quarter of 2012 compared to 2011 as lower revenue and higher depreciation and amortization of $15 million, due to 594 MW of additional wind-powered generation placed in service in 2011 and the effects of revenue sharing, were offset by lower energy costs. Energy costs decreased due to lower purchased power prices and volumes, the additional wind-powered generation and lower coal generation.

Regulated natural gas operating revenue decreased $39 million for the second quarter of 2012 compared to 2011 due to a lower average per-unit cost of gas sold of 42% and lower volumes sold of 4% from unseasonably warm weather. Regulated natural gas operating income decreased by $3 million from the second quarter of 2012 compared to 2011 due to lower volume-related gas margins.

Nonregulated and other operating revenue decreased $49 million for the second quarter of 2012 compared to 2011 due to lower electricity prices and volumes and lower natural gas prices. Nonregulated and other operating income decreased $2 million for the second quarter of 2012 compared to 2011 due to lower electric margins.

Regulated electric operating revenue decreased $5 million for the first six months of 2012 compared to 2011 due to lower wholesale and other revenue of $13 million, partially offset by higher retail revenue of $8 million. Wholesale and other revenue decreased due to lower average market prices of 13%. Retail revenue increased due to the new adjustment clauses in Iowa and Illinois totaling $13 million, partially offset by a 1% decrease in customer load.

Regulated operating income decreased $1 million for the first six months of 2012 compared to 2011 as lower revenue and higher depreciation and amortization of $24 million, due to 594 MW of additional wind-powered generation placed in service in 2011 and the effects of revenue sharing, were offset by lower energy costs. Energy costs decreased due to lower purchased power prices and volumes, the additional wind-powered generation and lower coal generation.

Regulated natural gas operating revenue decreased $109 million for the first six months of 2012 compared to 2011 due to a lower average per-unit cost of gas sold of 23% and lower volumes of 7% from unseasonably warm weather. Regulated natural gas operating income decreased by $18 million for the first six months of 2012 compared to 2011 due to lower volume-related gas margins.

Nonregulated and other operating revenue decreased $87 million for the first six months of 2012 compared to 2011 due to lower electricity and natural gas prices and volumes. Nonregulated and other operating income decreased $7 million for the first six months of 2012 compared to 2011 due to lower electric margins.

MidAmerican Energy Pipeline Group

Operating revenue decreased $9 million for the second quarter of 2012 compared to 2011 due to lower sales of gas and condensate liquids totaling $15 million on lower volumes, partially offset by higher revenue from increased capacity from the Kern River Apex Expansion project being placed in service in October 2011 and higher storage revenue rates at Northern Natural Gas. Operating income increased $7 million for the second quarter of 2012 compared to 2011 due to the higher revenue from the Kern River Apex Expansion project and higher storage revenue rates.

Operating revenue was flat for the first six months of 2012 compared to 2011 as higher revenue from the Kern River Apex Expansion project and better natural gas price spreads were offset by lower sales of gas and condensate liquids on lower volumes and contract expirations at Kern River. Operating income increased $13 million for the first six months of 2012 compared to 2011 due to the higher revenue from the Kern River Apex Expansion project and better natural gas price spreads and lower operating expense at Northern Natural Gas, partially offset by the lower revenue from contract expirations and higher depreciation related to the Kern River Apex Expansion project.

28

Northern Powergrid Holdings

Operating revenue increased $6 million for the second quarter of 2012 compared to 2011 due to higher distribution revenue of $11 million, partially offset by the stronger United States dollar totaling $7 million. Distribution revenue increased due to higher tariff rates of $18 million and higher units distributed, partially offset by a favorable movement in regulatory provisions in 2011of $11 million. Operating income decreased $5 million for the second quarter of 2012 compared to 2011 as the higher distribution revenue was more than offset by higher pension expense of $9 million and higher distribution operating expense of $5 million.

Operating revenue increased $17 million for the first six months of 2012 compared to 2011 due to higher distribution revenue of $29 million, partially offset by the stronger United States dollar totaling $12 million. Distribution revenue increased due to higher tariff rates of $48 million, partially offset by a favorable movement in regulatory provisions in 2011 of $22 million. Operating income decreased $7 million for the first six months of 2012 compared to 2011 as the higher distribution revenue was more than offset by higher pension expense of $22 million, higher distribution operating expense of $10 million and the stronger United States dollar.

HomeServices

Operating revenue increased $99 million for the second quarter of 2012 compared to 2011 due to an increase from existing businesses totaling $58 million reflecting a 19% increase in closed brokerage units and $41 million from the results of acquired companies. Operating income increased $11 million for the second quarter of 2012 compared to 2011 due to the higher operating revenue, net of commissions, partially offset by higher operating expense at both existing and acquired businesses and higher depreciation and amortization at acquired businesses.

Operating revenue increased $119 million for the first six months of 2012 compared to 2011 due to an increase from existing businesses totaling $78 million reflecting a 17% increase in closed brokerage units and $41 million from the results of acquired companies. Operating income increased $17 million for the first six months of 2012 compared to 2011 due to the higher operating revenue, net of commissions, partially offset by higher operating expense at both existing and acquired businesses and higher depreciation and amortization at acquired businesses.

MEHC and Other

Operating loss increased $3 million for the second quarter of 2012 compared to 2011 due to higher compensation expense, partially offset by the cessation of purchase price pension amortization in 2011.

Operating loss improved by $10 million for the first six months of 2012 compared to 2011 due to the cessation of purchase price amortization in 2011, partially offset by higher compensation expense.

Consolidated Other Income and Expense Items

Interest Expense

Interest expense is summarized as follows (in millions):

	Second Quarter									First Six Months
	2012		2011		Change					2012		2011		Change
Subsidiary debt	$	214	$	212	$	2		1	%	$	420	$	425	$	(5	)	(1	)%
MEHC senior debt and other	82		83		(1		)	(1	)	166		165		1			1
MEHC subordinated debt - Berkshire Hathaway	—		4		(4		)	(100	)	—		9		(9		)	(100	)
MEHC subordinated debt - other	—		4		(4		)	(100	)	—		7		(7		)	(100	)
Total interest expense	$	296	$	303	$	(7	)	(2	)	$	586	$	606	$	(20	)	(3	)

Interest expense decreased $7 million for the second quarter of 2012 compared to 2011 and $20 million for the first six months of 2012 compared to 2011 due to scheduled maturities and early principal repayments in 2011, partially offset by the debt issuances at PacifiCorp ($400 million in May 2011, $650 million in January 2012 and $100 million in March 2012), Northern Natural Gas ($200 million in April 2011) and MidAmerican Renewables ($850 million in February 2012).

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Capitalized Interest

Capitalized interest increased $4 million for both the second quarter of 2012 compared to 2011 and the first six months of 2012 compared to 2011 due to higher construction in progress balances at Topaz and PacifiCorp, partially offset by lower construction in progress balances at MidAmerican Energy Pipeline Group due to the Kern River Apex Expansion project being placed in service in October 2011.

Interest and Dividend Income

Interest and dividend income decreased $4 million for both the second quarter of 2012 compared to 2011 and the first six months of 2012 compared to 2011 due to interest refunds associated with Oregon Senate Bill 408 in 2011.

Other, Net

Other, net decreased $2 million for the second quarter of 2012 compared to 2011 due to lower Rabbi Trust earnings and lower equity AFUDC at MidAmerican Energy Pipeline Group due to the Kern River Apex Expansion project being placed in service in October 2011, partially offset by higher equity AFUDC at PacifiCorp.

Other, net increased $5 million for the first six months of 2012 compared to 2011 due to higher equity AFUDC at PacifiCorp and higher Rabbi Trust earnings, partially offset by lower equity AFUDC at MidAmerican Energy Pipeline Group due to the Kern River Apex Expansion project being placed in service in October 2011.

Income Tax Expense

Income tax expense decreased $39 million for the second quarter of 2012 compared to 2011 and the effective tax rates were 12% for the second quarter of 2012 and 25% for the second quarter of 2011. The decrease in the effective tax rate was due to the effects of ratemaking primarily related to the method change for repair deductions and higher income tax benefits related to additional production tax credits at MidAmerican Energy due to wind-powered generation placed in service in late 2011.

Income tax expense decreased $46 million for the first six months of 2012 compared to 2011 and the effective tax rates were 18% for the first six months of 2012 and 25% for the first six months of 2011. The decrease in the effective tax rate was due to higher income tax benefits related to additional production tax credits at MidAmerican Energy due to wind-powered generation placed in service in late 2011, the method change for repairs deductions and the effects of ratemaking.

Equity Income

Equity income increased $12 million for the second quarter of 2012 compared to 2011 and $17 million for the first six months of 2012 compared to 2011 due to the acquisition of a 49% interest in Agua Caliente in January 2012, higher earnings at ETT due to continued investment and higher earnings at HomeServices' mortgage joint venture due to higher refinancing activity, partially offset by lower earnings at CE Generation.

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Liquidity and Capital Resources

Each of MEHC's direct and indirect subsidiaries is organized as a legal entity separate and apart from MEHC and its other subsidiaries. It should not be assumed that the assets of any subsidiary will be available to satisfy MEHC's obligations or the obligations of its other subsidiaries. However, unrestricted cash or other assets that are available for distribution may, subject to applicable law, regulatory commitments and the terms of financing and ring-fencing arrangements for such parties, be advanced, loaned, paid as dividends or otherwise distributed or contributed to MEHC or affiliates thereof. The long-term debt of subsidiaries may include provisions that allow MEHC's subsidiaries to redeem it in whole or in part at any time. These provisions generally include make-whole premiums. Refer to Note 17 of Notes to Consolidated Financial Statements in Item 8 of the Company's Annual Report on Form 10-K for further discussion regarding the limitation of distributions from MEHC's subsidiaries.

As of June 30, 2012, the Company's total net liquidity was $5.432 billion and the components are as follows (in millions):

										Northern
							MidAmerican			Powergrid
	MEHC			PacifiCorp			Funding			Holdings			Other			Total
Cash and cash equivalents	$	305		$	107		$	272		$	7		$	189		$	880
Credit facilities(1)	1,152			1,320			654			236			95			3,457
Less:
Short-term debt	—			—			—			(44		)	(32		)	(76		)
Tax-exempt bond support and letters of credit	(32		)	(602		)	(195		)	—			—			(829		)
Net credit facilities	1,120			718			459			192			63			2,552
Net liquidity before Berkshire Equity Commitment	1,425			$	825		$	731		$	199		$	252		3,432
Berkshire Equity Commitment(2)	2,000															2,000
Total net liquidity	$	3,425														$	5,432
Credit facilities:
Maturity date	2013, 2017			2013, 2017			2013			2013			2012, 2013
Largest single bank commitment as a % of total credit facilities(3)	12		%	13		%	23		%	33		%	53		%

(1) For further discussion regarding the Company's credit facilities, refer to Note 7 of Notes to Consolidated Financial Statements in Item 1 of this Form 10-Q.

(2) MEHC has an Equity Commitment Agreement with Berkshire Hathaway (the "Berkshire Equity Commitment") pursuant to which Berkshire Hathaway has agreed to purchase up to $2.0 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. The Berkshire Equity Commitment expires on February 28, 2014.

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

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

Operating Activities

Net cash flows from operating activities for the six-month periods endedJune 30, 2012 and 2011 were $2.502 billion and $1.839 billion, respectively. The increase was primarily due to higher income tax receipts of $561 million from bonus depreciation and investment tax credits related to renewable projects, improved operating results, lower interest payments and other changes in working capital.

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Investing Activities

Net cash flows from investing activities for the six-month periods endedJune 30, 2012 and 2011 were $(2.197) billion and $(1.213) billion, respectively. The change was primarily due to an increase in restricted cash and investments related to proceeds from the issuance of $850 million of long-term debt at Topaz that is restricted for use in the construction of the Topaz Project; the acquisitions of Topaz and Bishop Hill and a 49% interest in Agua Caliente; and higher capital expenditures at MidAmerican Renewables, Northern Powergrid Holdings and the Utilities.

Capital Expenditures

Capital expenditures, which exclude amounts for non-cash equity AFUDC and other non-cash items, by reportable segment for the six-month periods endedJune 30 are summarized as follows (in millions):

	2012		2011
Capital expenditures:
PacifiCorp	$	721	$	712
MidAmerican Funding	259		219
MidAmerican Energy Pipeline Group	65		101
Northern Powergrid Holdings	181		138
MidAmerican Renewables	282		—
Other	4		6
Total capital expenditures	$	1,512	$	1,176

The Company's capital expenditures relate primarily to the Utilities and consisted mainly of the following for the six-month periods endedJune 30:

2012:

• Transmission system investments totaling $187 million, including construction costs for PacifiCorp's 100-mile high-voltage transmission line being built between the Mona substation in central Utah and the Oquirrh substation in the Salt Lake Valley. A 65-mile segment of the Mona-Oquirrh transmission project will be a single-circuit 500-kV transmission line, while the remaining 35-mile segment will be a double-circuit 345-kV transmission line. The transmission line is expected to be placed in service in 2013.

• Emissions control equipment on existing generating facilities totaling $124 million for installation or upgrade of sulfur dioxide scrubbers, low nitrogen oxide burners and particulate matter control systems.

• The development and construction of PacifiCorp's Lake Side 2 637-MW combined-cycle combustion turbine natural gas-fueled generating facility ("Lake Side 2") totaling $123 million, which is expected to be placed in service in 2014.

• The construction of MidAmerican Energy's 407 MW of wind-powered generating facilities totaling $71 million, excluding $89 million of costs for which payments are due in December 2015. The wind-powered facilities are expected to be placed in service in 2012.

• Distribution, generation, mining and other infrastructure needed to serve existing and expected demand totaling $475 million.

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2011:

• Emissions control equipment on existing generating facilities totaling $149 million for installation or upgrade of sulfur dioxide scrubbers, low nitrogen oxide burners and particulate matter control systems, including costs for projects that were placed in service in April 2011.

• Transmission system investments totaling $100 million, including permitting and right of way costs for PacifiCorp's Mona-Oquirrh transmission project.

• The construction of MidAmerican Energy's 593 MW of wind-powered generating facilities totaling $89 million, excluding $94 million of costs for which payments are due in December 2013. The wind-powered facilities were placed in service in December 2011.

• The development and construction of Lake Side 2 totaling $75 million.

• Distribution, generation, mining and other infrastructure needed to serve existing and expected demand totaling $518 million.

Additionally, capital expenditures for the six-month period endedJune 30, 2012 include costs related to MidAmerican Renewables totaling $282 million related to the Topaz and Bishop Hill Projects. The remaining amounts are for ongoing investments in distribution and other infrastructure needed at the other platforms to serve existing and expected demand.

Financing Activities

Net cash flows from financing activities for the six-month period endedJune 30, 2012 was $289 million. Sources of cash totaled $1.599 billion related to proceeds from subsidiary debt. Uses of cash totaled $1.310 billion and consisted mainly of net repayments of short-term debt totaling $817 million, repayments of subsidiary debt totaling $426 million and repayment of MEHC subordinated debt totaling $22 million. For the six-month period endedJune 30, 2012, subsidiary debt issuances included the following:

• In January 2012, PacifiCorp issued $350 million of its 2.95% First Mortgage Bonds due February 1, 2022 and $300 million of its 4.10% First Mortgage Bonds due February 1, 2042. The net proceeds were used to repay short-term debt, fund capital expenditures and for general corporate purposes. In March 2012, PacifiCorp issued an additional $100 million of its 2.95% First Mortgage Bonds due February 1, 2022. The net proceeds were used to redeem $84 million of tax-exempt bond obligations prior to scheduled maturity with a weighted average interest rate of 5.7%, to repay short-term debt and for general corporate purposes.

• In February 2012, Topaz issued $850 million of the 5.75% Series A Senior Secured Notes. The principal of the notes amortize beginning September 2015 with a final maturity in September 2039. The net proceeds will be used to fund the costs and expenses related to the development, construction and financing of the Topaz Project. Any unused amounts will be invested or, in certain circumstances, loaned to MEHC. As of June 30, 2012, $321 million was loaned to MEHC.

In conjunction with the construction of wind-powered generating facilities in 2012, MidAmerican Energy has accrued as construction work-in-progress amounts it is not contractually obligated to pay until December 2015. The amounts ultimately payable are discounted at 1.43% and recognized upon delivery of the equipment as long-term debt. The discount is being amortized as interest expense over the period until payment is due using the effective interest method. As of June 30, 2012, $89 million of such debt, net of associated discount, was outstanding.

Additionally, in July 2012, Northern Powergrid (Yorkshire) plc issued £150 million of its 4.375% Bonds due July 2032. The net proceeds will be used for general corporate purposes.

Net cash flows from financing activities for the six-month period endedJune 30, 2011 was $(74) million. Sources of cash totaled $790 million related to proceeds from subsidiary debt. Uses of cash totaled $864 million and consisted mainly of repayments of subsidiary debt totaling $502 million, net repayments of short-term debt totaling $320 million and repayment of MEHC subordinated debt totaling $22 million.

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Future Uses of Cash

The Company has available a variety of sources of liquidity and capital resources, both internal and external, including 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 ratings, investors' judgment of risk and conditions in the overall capital market, including the condition of the utility industry in general. Additionally, MEHC has the Berkshire Equity Commitment pursuant to which Berkshire Hathaway has agreed to purchase up to $2.0 billion of MEHC's common equity upon any requests authorized from time to time by MEHC's Board of Directors. The Berkshire Equity Commitment expires on February 28, 2014 and may 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. 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.

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; outcomes of regulatory proceedings; 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. Prudently incurred 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 amounts for non-cash equity AFUDC and other non-cash items, are approximately $3.8 billion for 2012 and consist mainly of large scale projects at the Utilities and MidAmerican Renewables, including the following:

• $835 million for the Topaz Project, which is a 550-MW solar project in California that will be completed in 22 blocks through 2015, with an aggregate tested capacity of 586 MW. The Topaz Project expects to place 45 MW in service in 2012.

• $217 million for 407 MW of wind-powered generation at MidAmerican Energy that it expects to place in service in 2012, excluding approximately $400 million of payments deferred until December 2015.

• $385 million for transmission system investments, including $282 million for the Energy Gateway Transmission Expansion Program, which includes construction costs for the Mona-Oquirrh transmission line.

• $277 million for emissions control equipment at the Utilities, which includes equipment to meet air quality and visibility targets, including the reduction of sulfur dioxide, nitrogen oxides and particulate matter emissions. This estimate includes the installation of new or the replacement of existing emissions control equipment at several of the Utilities' coal-fueled generating facilities.

• $230 million for development and construction of Lake Side 2, which is expected to be placed in service in 2014.

• $149 million for the construction of the Bishop Hill Project, an 81-MW wind-powered generating facility in Illinois that is expected to be placed in service in 2012. In March 2012, MEHC, through a wholly-owned subsidiary, acquired Bishop Hill from Invenergy Wind LLC, which included the Bishop Hill Project.

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

Equity Investments

ETT, a company owned equally by indirect subsidiaries of American Electric Power Company, Inc. and MEHC, owns and operates electric transmission assets in the ERCOT. In order to fund ETT's ongoing transmission investment, MEHC expects to make equity contributions to ETT during 2012 of $107 million.

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Agua Caliente, a company owned 51% by NRG Energy, Inc. and 49% by an indirect subsidiary of MEHC, is constructing the 290-MW Agua Caliente Project in Arizona that will be completed in 12 blocks through 2014. Pursuant to an equity funding and contribution agreement, MEHC has committed to provide Agua Caliente with funding for (a) base equity contributions of up to an aggregate amount of $303 million for the construction of the Agua Caliente Project and (b) transmission upgrade costs. MEHC expects to make equity contributions to Agua Caliente during 2012 of $266 million.

Contractual Obligations

As of June 30, 2012, there have been 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, 2011 other than the 2012 debt issuances previously discussed and MidAmerican Energy's redemption of $275 million of its 5.125% senior notes due January 2013. Additionally, refer to the "Capital Expenditures" discussion included in "Liquidity and Capital Resources."

In April 2012, MidAmerican Energy entered into a multi-year coal transportation agreement with BNSF Railway Company, an affiliate of the Company, for long-haul delivery of coal to MidAmerican Energy's generating facilities that are not “captive” to a single railroad. The new contract will provide delivery for the majority of the coal anticipated to be delivered to MidAmerican Energy-operated coal-fueled generating facilities beginning January 1, 2013. While prices for this rail service are significantly higher than those contained in MidAmerican Energy's legacy long-haul rail contract, which expires December 31, 2012, the BNSF Railway Company proposal was the lowest cost and best overall bid. Negotiations continue on arrangements for delivery of coal to MidAmerican Energy's other coal-fueled generating facilities.

Regulatory Matters

MEHC's regulated subsidiaries and certain affiliates are subject to comprehensive regulation. The discussion below contains material developments to those matters disclosed in Item 7 of the Company's Annual Report on Form 10-K for the year ended December 31, 2011.

PacifiCorp

Utah

In February 2012, PacifiCorp filed a general rate case with the UPSC requesting a rate increase of $172 million, or an average price increase of 10%. In July 2012, PacifiCorp filed rebuttal testimony that reduced the requested increase to $156 million, or an average price increase of 9%. Once approved, the new rates will be effective in October 2012.

In March 2012, PacifiCorp filed its first annual energy balancing account with the UPSC requesting: (a) $9 million for recovery of 70% of the net power costs in excess of amounts included in base rates for the period October 1, 2011 through December 31, 2011 and (b) collection of $20 million of excess net power costs representing the first annual installment of the $60 million of excess net power costs approved for recovery in the September 2011 general rate case settlement. Collection of the $20 million installment began in June 2012. The effective date for collection of the $9 million is pending an order from the UPSC.

In March 2012, PacifiCorp filed with the UPSC to return $4 million to customers through the REC balancing account. The new rates became effective in June 2012 on an interim basis until a final order is issued by the UPSC.

Oregon

In February 2012, PacifiCorp made its initial filing for the annual Transition Adjustment Mechanism with the OPUC for an annual increase of $10 million, or an average price increase of 1%, to recover the anticipated net power costs forecasted for calendar year 2013. In July 2012, PacifiCorp filed updated net power costs reducing the requested increase to $3 million, or an average price increase of less than 1%.

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In March 2012, PacifiCorp filed a general rate case with the OPUC requesting an annual increase of $41 million, or an average price increase of 3%. As part of the general rate case filing, PacifiCorp indicated that it anticipates that the 172-MW Carbon coal-fueled generating facility ("Carbon Facility") will be retired in early 2015. Refer to "Environmental Laws and Regulations" for a further discussion regarding the Carbon Facility. In July 2012, a multiparty partial stipulation was filed with the OPUC resolving most components of the general rate case, including PacifiCorp's requests to include in rates the accelerated depreciation and decommissioning costs for the early retirement of the Carbon Facility. The stipulation provides for an annual increase of $24 million, or an average price increase of 2%. If the stipulation is approved by the OPUC, the new rates will be effective January 1, 2013. The issues that were not settled in the stipulation include the prudence of PacifiCorp's investments in environmental controls at its thermal generating facilities, PacifiCorp's request for a power cost adjustment mechanism and PacifiCorp's proposal to add the Mona to Oquirrh transmission line to its rate base through a separate tariff rider when the line goes into service in 2013. Resolution of these issues is pending.

Wyoming

In December 2011, PacifiCorp filed a general rate case with the WPSC requesting an annual increase of $63 million, or an average price increase of 10%.

In March 2012, PacifiCorp made its first annual Wyoming energy cost adjustment mechanism ("ECAM") filing with the WPSC. The filing requested recovery of $29 million, or an average price increase of 5%, for deferred net power costs for the period December 1, 2010 to December 31, 2011. The new rates became effective in May 2012 on an interim basis and were revised in July 2012 in anticipation of the general rate case stipulation described below.

In July 2012, the WPSC approved a stipulation that consolidated and resolved the December 2011 general rate case and the March 2012 ECAM filing. The stipulation resulted in a $50 million general rate increase that will be effective in two stages. The first increase of $32 million, or an average price increase of 5%, will be effective in October 2012 and the second increase of $18 million, or an average price increase of 3%, will be effective in October 2013. The stipulation also resulted in a reduction of the ECAM surcharge rate increase from $29 million to $27 million and the increase will be collected over three years, resulting in an average price increase of 1% per year. In addition, PacifiCorp agreed not to file another general rate case in Wyoming prior to March 2014 with the new rates to be effective no earlier than January 2015. PacifiCorp will continue to file its required annual ECAM filings.

In March 2012, PacifiCorp filed its first annual Wyoming REC and Sulfur Dioxide Revenue Adjustment Mechanism ("RRA") application with the WPSC. The RRA tracks the difference between PacifiCorp's actual revenues from the sale of RECs and sulfur dioxide allowances and the amounts credited to customers in current rates. The filing requests to reduce the current surcredit by $1 million to $15 million. The surcredit became effective in May 2012 on an interim basis until a final order is issued by the WPSC.

In September 2011, PacifiCorp filed with the WPSC an application for a certificate of public convenience and necessity ("CPCN") for pollution control facilities at Naughton Unit No. 3 in Wyoming. In April 2012, PacifiCorp filed testimony modifying its original CPCN application to reflect its current plan to convert the Naughton Unit No. 3 to a natural gas-fueled unit as a result of PacifiCorp's current estimation that conversion is the least cost alternative for meeting air quality and visibility requirements and is in the best interest of customers. In May 2012, PacifiCorp filed a motion to withdraw the CPCN application, which was approved by the WPSC.

Washington

In May 2010, PacifiCorp filed a general rate case with the WUTC requesting an annual increase of $57 million, or an average price increase of 21%. In November 2010, the requested annual increase was reduced to $49 million, or an average price increase of 18%. In March 2011, the WUTC issued a final order and clarification letter approving an annual increase of $33 million, or an average price increase of 12%, reduced in the first year by a customer bill credit of $5 million, or 2%, related to the sale of RECs expected during the twelve-month period ended March 31, 2012, as well as requiring PacifiCorp to submit additional information to the WUTC regarding the sales of RECs. The new rates were effective in April 2011. Although both PacifiCorp and the WUTC staff filed petitions for reconsideration of various items on the final order, the WUTC denied the petitions for reconsideration. In May 2011, PacifiCorp submitted to the WUTC the additional information required by the March 2011 order regarding PacifiCorp's proceeds from sales of RECs for the period January 1, 2009 forward and a detailed proposal for a tracking mechanism for proceeds of RECs. Intervening parties and WUTC staff proposed that PacifiCorp refund to customers the amount of REC sales in excess of the amount included in base rates since January 1, 2009. Initial and reply briefs from all parties were filed in November 2011. Oral arguments were held before the WUTC in January 2012.

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In July 2011, PacifiCorp filed a general rate case with the WUTC requesting an annual increase of $13 million, or an average price increase of 4%, with an effective date no later than June 1, 2012. In February 2012, the parties to the proceeding filed a settlement agreement with the WUTC reflecting an annual increase of $5 million, or an average price increase of 2%. In March 2012, the WUTC approved the settlement agreement with an effective date of June 2012.

Idaho

In February 2012, PacifiCorp filed an ECAM application with the IPUC requesting recovery of $18 million in deferred net power costs with a $3 million increase to the current ECAM surcharge rate. In March 2012, the IPUC approved the new rates with an effective date of April 2012. In April 2012, Monsanto Company filed a motion for reconsideration of the IPUC order. As a result, the IPUC ordered a workshop to discuss certain aspects of PacifiCorp's ECAM application. In June 2012, the parties filed final comments with the IPUC supporting an increase to the current ECAM surcharge rate that will result in recovery of $18 million in deferred net power costs. In July 2012, the IPUC issued a final order approving the agreement reached by the parties.

MidAmerican Energy

On February 21, 2012, MidAmerican Energy filed an application with the IUB for an interim and final increase in Iowa retail electric rates in the form of two adjustment clauses to be added to customers' bills. The requested adjustment clauses and a modification to current revenue sharing provisions are consistent with a November 2011 settlement agreement between MidAmerican Energy and the Iowa Office of Consumer Advocate ("OCA"), in which the parties agree to support the proposed changes. The adjustment clauses would recover anticipated increases in retail coal and coal transportation costs and environmental control expenditures subject to an aggregate maximum of $39 million, or 3.4%, for 2012 and an additional $37 million for an aggregate maximum of $76 million for 2013, or a 3.2% increase from 2012. The requested modification to the existing revenue sharing provisions provides for MidAmerican Energy to share with its customers 20% of revenue associated with Iowa electric returns on equity between 10% and 10.5%, 50% of revenue associated with Iowa electric returns on equity between 10.5% and 11.75%, 75% of revenue associated with Iowa electric returns on equity between 11.75% and 13.0% and 83.3% of revenue associated with Iowa electric returns on equity above 13.0%. Such shared amounts would reduce MidAmerican Energy's investment in the Walter Scott, Jr. Energy Center Unit 4. Pursuant to the settlement agreement, MidAmerican Energy is not precluded from seeking interim rate relief in 2013. MidAmerican Energy implemented the adjustment clauses on an interim basis in March 2012 and expects resolution of the related rate proceeding in the fourth quarter of 2012. On July 27, 2012, MidAmerican Energy, the OCA and a group of large industrial customers jointly filed a settlement agreement with the IUB that resolves all issues surrounding the Iowa proceeding. The settlement agreement requests IUB approval of the establishment of a single adjustment clause to increase MidAmerican Energy's revenue by $39 million in 2012 and $76 million in 2013 and does not track specific costs, modification of revenue sharing provisions as filed, and suspension of the procedural schedule for the case. Subsequently, the only two additional parties in the case filed pleadings with the IUB stating they had no objection to the settlement agreement.

Environmental Laws and Regulations

The Company is subject to federal, state, local and foreign laws and regulations regarding air and water quality, RPS, emissions performance standards, climate change, coal combustion byproduct disposal, 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 regulators with the authority to levy substantial penalties for noncompliance including fines, injunctive relief and other sanctions. These laws and regulations are administered by the EPA 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 "Liquidity and Capital Resources" for discussion of the Company's forecasted environmental-related capital expenditures. The discussion below contains material developments to those matters disclosed in Item 7 of the Company's Annual Report on Form 10-K for the year ended December 31, 2011.

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Clean Air Standards

National Ambient Air Quality Standards

In June 2012, the EPA released a proposal to strengthen the fine particulate matter National Ambient Air Quality Standards, reducing the standard from 15 micrograms per cubic meter to a range of 12 to 13 micrograms per cubic meter while taking comment on a standard of 11 micrograms per cubic meter. The EPA is also proposing a new, separate fine particulate matter standard of either 28 or 30 deciviews or measure of haze, aimed at improving visibility. The public comment period closes August 31, 2012. The EPA is required to finalize the proposal by December 14, 2012. Until the standards are final and attainment designations made, the Company cannot determine the potential impacts of the standards; however, any impacts are not anticipated to be significant.

Mercury and Air Toxics Standards

The Clean Air Mercury Rule ("CAMR"), issued by the EPA in March 2005, was the United States' first attempt to regulate mercury emissions from coal-fueled generating facilities through the use of a market-based cap-and-trade system. The CAMR, which mandated emissions reductions of approximately 70% by 2018, was overturned by the United States Court of Appeals for the District of Columbia Circuit ("D.C. Circuit") in February 2008. In March 2011, the EPA proposed a new rule that would require coal-fueled generating facilities to reduce mercury emissions and other hazardous air pollutants through the establishment of "Maximum Achievable Control Technology" standards rather than a cap-and-trade system. The final rule, Mercury and Air Toxics Standards ("MATS"), was published in the Federal Register on February 16, 2012, with an effective date of April 16, 2012, and requires that new and existing coal-fueled facilities achieve emission standards for mercury, acid gases and other non-mercury hazardous air pollutants. Existing sources are required to comply with the new standards by April 16, 2015. Individual sources may be granted up to one additional year, at the discretion of the Title V permitting authority, to complete installation of controls or for transmission system reliability reasons. While the final MATS continues to be reviewed by the Company, the Company believes that its emissions reduction projects completed to date or currently permitted or planned for installation, including scrubbers, baghouses and electrostatic precipitators are consistent with the EPA's MATS and will support the Company's ability to comply with the final rule's standards for acid gases and non-mercury metallic hazardous air pollutants. The Company will be required to take additional actions to reduce mercury emissions through the installation of controls or use of sorbent injection at certain of its coal-fueled generating facilities and otherwise comply with the final rule's standards. The Company is evaluating whether or not to close certain units. As a result of recent testing and evaluation, PacifiCorp currently anticipates that retiring the Carbon Facility in early 2015 will be the least-cost alternative to comply with the MATS and other environmental regulations. PacifiCorp continues to assess compliance alternatives and potential transmission system impacts that could otherwise impact PacifiCorp's ultimate decision with respect to the Carbon Facility, including timing of retirement and decommissioning. Incremental costs to install and maintain emissions control equipment at the Company's coal-fueled generating facilities and any requirement to shut down what have traditionally been low cost coal-fueled generating facilities will likely increase the cost of providing service to customers. In addition, numerous lawsuits are pending against the MATS in the D.C. Circuit, which may have an impact on the Company's compliance obligations and the timing of those obligations.

Regional Haze

In May 2012, the EPA published in the Federal Register a proposal to partially approve and partially disapprove the Utah regional haze state implementation plan ("SIP"). The EPA's partial approval of the sulfur dioxide portion of the SIP is based on a sulfur dioxide milestone and backstop trading program to reduce emissions. The partial disapproval is based on the EPA's assertion that the Utah Department of Environmental Quality failed to conduct the appropriate five-factor best available retrofit technology analysis for nitrogen oxides and particulate matter. The EPA did not propose to issue a Federal Implementation Plan ("FIP"), but acknowledged the state's ongoing efforts to conduct the required analysis. The public comment period closed on the EPA's proposed action in July 2012.

In May 2012, the EPA published in the Federal Register a proposal to approve the Wyoming regional haze SIP for sulfur dioxide. The Wyoming SIP utilizes the same trading program utilized by Utah. The EPA's public comment period closed in July 2012. In addition, the EPA published in the Federal Register a proposal to partially approve and partially disapprove the Wyoming regional haze SIP for nitrogen oxides and particulate matter and issue a FIP for those portions proposed to be disapproved. The EPA action proposed to accelerate the installation of selective catalytic reduction equipment at PacifiCorp's Jim Bridger Units 1 and 2 to 2017 from 2021 and 2022, but agreed to accept comment on maintaining the original schedule as the state proposed. In addition, the EPA proposed to reject the SIP for the Wyodak facility and Dave Johnston Unit 3 and require the installation of selective non-catalytic reduction equipment within five years, as well as requiring the installation of low-nitrogen oxides burners and overfire air systems at Dave Johnston Units 1 and 2. The EPA held public hearings on its proposed disapproval on June 26 and 28, 2012, and the written comment period closes August 3, 2012. Until the EPA takes final action on the SIP or FIP and the appropriate appeal period passes, the Company cannot fully determine the impacts of the EPA's proposal.

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In July 2012, the EPA published in the Federal Register a proposal to partially approve and partially disapprove the Arizona regional haze SIP addressing, among others, the Cholla generating facility. PacifiCorp owns 100% of Cholla Unit 4. The Arizona SIP provided for low-nitrogen oxides burners, while the proposed FIP would require installation of selective catalytic reduction equipment within five years after final action. The EPA is taking public comments on its proposed action until September 18, 2012.

Climate Change

GHG New Source Performance Standards

Under the Clean Air Act, the EPA may establish emissions standards that reflect the degree of emissions reductions achievable through the best technology that has been demonstrated, taking into consideration the cost of achieving those reductions and any non-air quality health and environmental impact and energy requirements. The EPA entered into a settlement agreement with a number of parties, including certain state governments and environmental groups, in December 2010 to promulgate emissions standards covering GHG. In April 2012, the EPA proposed new source performance standards for new fossil-fueled generating facilities that would limit emissions of carbon dioxide to 1,000 pounds per megawatt hour. The proposal exempts simple cycle combustion turbines from meeting the GHG standards. The public comment period closed in June 2012. The EPA indicated in the proposal that it does not have sufficient information to establish GHG new source performance standards for modified or reconstructed units and has not established a schedule for when these units, or other existing sources, will be regulated. Any new fossil-fueled generating facilities constructed by the Company will be required to meet the final GHG new source performance standards, which, if finalized as proposed, will preclude the construction of any coal-fueled generating facilities that do not have carbon capture and sequestration. Until any standards for existing, modified or reconstructed units are proposed and finalized, the impact on the Company's existing facilities cannot be determined.

GHG Litigation

In October 2009, a three-judge panel in the United States Court of Appeals for the Fifth Circuit ("Fifth Circuit") issued its opinion in the case of Ned Comer, et al. v. Murphy Oil USA, et al., ("Comer I") a putative class action lawsuit against insurance, oil, coal and chemical companies, based on claims that the defendants' GHG emissions contributed to global warming that in turn caused a rise in sea levels and added to the ferocity of Hurricane Katrina, which combined to damage the plaintiff's private property, as well as public property. In 2007, the United States District Court for the Southern District of Mississippi ("Southern District of Mississippi") dismissed the case based on the lack of standing and further held that the claims were barred by the political question doctrine. In March 2010, the full court of the Fifth Circuit agreed to rehear the case; however, in May 2010, the Fifth Circuit dismissed the appeal for failure to have a quorum, resulting in the Southern District of Mississippi's decision, holding that property owners did not have standing to sue for climate change and that climate change was a political question for the United States Congress, standing as good law. The plaintiffs filed a petition asking the United States Supreme Court to direct the Fifth Circuit to reinstate the appeal and return it to the original panel. In January 2011, the United States Supreme Court denied the request, resulting in the original dismissal of the case to stand. However, in May 2011, the Comer case was refiled ("Comer II") in the Southern District of Mississippi. In response to the defendants' motions to dismiss in Comer II, the Southern District of Mississippi, in March 2012, granted the motions, dismissing the suit with prejudice. Plaintiffs filed an appeal with the Fifth Circuit in April 2012. The Company was not a party in Comer I and is not a party in Comer II.

Collateral and Contingent Features

Debt of MEHC and debt and preferred securities of certain of its subsidiaries are rated by 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.

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In accordance with industry practice, certain wholesale 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 three recognized credit rating agencies. These agreements 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 June 30, 2012, 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 had been triggered as of June 30, 2012, the Company would have been required to post $644 million of additional collateral. The Company's collateral requirements could fluctuate considerably due to market price volatility, changes in credit ratings, changes in legislation or regulation, or other factors. Refer to Note 5 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.

In accordance with MEHC's equity commitment agreement related to Topaz, if MEHC does not maintain at least an investment grade credit rating from at least two of the three credit ratings agencies, MEHC's obligations under the equity commitment agreement would be supported by cash collateral or a letter of credit issued by a financial institution that meets certain minimum criteria specified in the financing documents. Upon reaching the final commercial operation date of the Topaz Project, MEHC will have no further obligation to make any equity contribution and any unused equity contribution obligations will be canceled.

In July 2010, the President signed into law the Dodd-Frank Reform Act. The Dodd-Frank Reform Act reshapes financial regulation in the United States by creating new regulators, regulating new markets and firms, and providing new enforcement powers to regulators. Virtually all major areas of the Dodd-Frank Reform Act are subject to extensive rulemaking proceedings being conducted both jointly and independently by multiple regulatory agencies, some of which have been completed and others that are expected to be finalized in late 2012.

The Company is a party to derivative contracts, including over-the-counter derivative contracts. The Dodd-Frank Reform Act provides for extensive new regulation of over-the-counter derivative contracts and certain market participants, including imposition of mandatory clearing, exchange trading, capital, margin, reporting, recordkeeping, and business conduct requirements primarily for "swap dealers" and "major swap participants." The Dodd-Frank Reform Act provides certain exemptions from these requirements for commercial end-users when using derivatives to hedge or mitigate commercial risk of their businesses. Although the Company generally does not enter into over-the-counter derivative contracts for purposes unrelated to hedging of commercial risk and does not believe it will be considered a swap dealer or major swap participant, the outcome of remaining rulemaking proceedings cannot be predicted and, therefore, the impact of the Dodd-Frank Reform Act on the Company's consolidated financial results cannot be determined at this time.

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 and 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, 2011. There have been no significant changes in the Company's assumptions regarding critical accounting estimates since December 31, 2011.

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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, 2011. The Company's exposure to market risk and its management of such risk has not changed materially since December 31, 2011. Refer to Note 5 of Notes to Consolidated Financial Statements in Item 1 of this Form 10-Q for disclosure of the Company's derivative positions as of June 30, 2012.

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 United States Securities and Exchange Commission'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 June 30, 2012 that has materially affected, or is reasonably likely to materially affect, the Company's internal control over financial reporting.

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PART II

Item 1. Legal Proceedings

For a description of certain legal proceedings affecting the Company, refer to Note 10 of Notes to Consolidated Financial Statements included in Part I, Item 1 of this Form 10-Q.

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, 2011.

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

Not applicable.

Item 3. Defaults Upon Senior Securities

Not applicable.

Item 4. Mine Safety Disclosures

Information regarding the Company's mine safety violations and other legal matters disclosed in accordance with Section 1503(a) of the Dodd-Frank Reform Act is included in Exhibit 95 to this Form 10-Q.

Item 5. Other Information

Not applicable.

Item 6. Exhibits

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

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SIGNATURES

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

	MIDAMERICAN ENERGY HOLDINGS COMPANY
	(Registrant)
Date: August 3, 2012	/s/ Patrick J. Goodman
	Patrick J. Goodman
	Executive Vice President and Chief Financial Officer
	(principal financial and accounting officer)

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EXHIBIT INDEX

Exhibit No. Description

4.1 Trust Deed, dated as of July 5, 2012, among Northern Powergrid (Yorkshire) plc and HSBC Corporate Trustee Company (UK) Limited, relating to £150,000,000 in principal amount of the 4.375% Bonds due 2032.

10.1 $600,000,000 Credit Agreement, dated as of June 28, 2012, among MidAmerican Energy Holdings Company, as Borrower, the Banks, Financial Institutions and Other Institutional Lenders, as Initial Lenders, Union Bank, N.A, as Administrative Agent and Swingline Lender, and the LC Issuing Banks.

10.2 $600,000,000 Credit Agreement, dated as of June 28, 2012, among PacifiCorp, as Borrower, the Banks, Financial Institutions and Other Institutional Lenders, as Initial Lenders, JPMorgan Chase Bank, N.A., as Administrative Agent and Swingline Lender, and the LC Issuing Banks (incorporated by reference to Exhibit 10.1 to the PacifiCorp Quarterly Report on Form 10-Q for the quarter ended June 30, 2012).

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.

95 Mine Safety Disclosures Required by the Dodd-Frank Wall Street Reform and Consumer Protection Act.

101 The following financial information from MidAmerican Energy Holdings Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 2012, is formatted in XBRL (eXtensible Business Reporting Language) and included herein: (i) the Consolidated Balance Sheets, (ii) the Consolidated Statements of Operations, (iii) the Consolidated Statements of Comprehensive Income, (iv) the Consolidated Statements of Changes in Equity, (v) the Consolidated Statements of Cash Flows, and (vi) the Notes to Consolidated Financial Statements, tagged in summary and detail.

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