UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended September 30, 2013

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 October 31, 2013, 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	26
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	45
Item 4.	Controls and Procedures	45

PART II

Item 1.	Legal Proceedings	46
Item 1A.	Risk Factors	46
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	46
Item 3.	Defaults Upon Senior Securities	46
Item 4.	Mine Safety Disclosures	46
Item 5.	Other Information	46
Item 6.	Exhibits	46
Signatures		47
Exhibit Index		48

i

Definition of Abbreviations and Industry Terms

When used in Forward-Looking Statements, 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 CalEnergy Philippines and MidAmerican Renewables, LLC
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
Berkshire Hathaway	Berkshire Hathaway Inc. and its subsidiaries
Topaz	Topaz Solar Farms LLC
Topaz Project	550-megawatt solar project in California
Agua Caliente	Agua Caliente Solar, LLC
Agua Caliente Project	290-megawatt solar project in Arizona
Bishop Hill	Bishop Hill Energy II, LLC
Bishop Hill Project	81-megawatt wind-powered generating facility in Illinois
Pinyon Pines Projects	168-megawatt and 132-megawatt wind-powered generating facilities in California
Solar Star Funding	Solar Star Funding, LLC
Solar Star Projects	A combined 579-megawatt solar project in California (formerly Antelope Valley Projects)
Certain Industry Terms
AFUDC	Allowance for Funds Used During Construction
EPA	United States Environmental Protection Agency
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
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, and compliance with, laws and regulations, including reliability and safety standards, 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 facility output, accelerate facility retirements or delay facility construction or acquisition;

• the outcome of 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, new technologies and various conservation, energy efficiency and distributed generation measures and programs, 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 or generation that could impact the Company's hedging strategy and the cost of balancing its generation resources with its retail load obligations;

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

• changes in prices, availability and demand for 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 certain 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 certain contracts;

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

• increases in employee healthcare costs, including the implementation of the Affordable Care Act;

• 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 facilities and infrastructure additions;

• the availability and price of natural gas in applicable geographic regions and demand for natural gas supply;

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

iii

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

• the occurrence of any event, change or other circumstances that could give rise to the termination of the definitive agreement related to our planned acquisition of NV Energy, Inc. ("NV Energy") or the failure to consummate such acquisition, including such termination or failure due to a failure to receive the required regulatory approvals, the taking of government action (including the passage of legislation) to block such acquisition or a failure to satisfy other closing conditions contained in such definitive agreement;

• actions taken or conditions imposed by governmental or other regulatory authorities in connection with MEHC's planned acquisition of NV Energy;

• other risks or unforeseen events, including the effects of storms, floods, fires, earthquakes, explosions, landslides, litigation, wars, terrorism, embargoes and other catastrophic events, including catastrophic events triggered by a breakdown or failure of the Company's operating assets; 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 September 30, 2013, and the related consolidated statements of operations and comprehensive income for the three-month and nine-month periods endedSeptember 30,2013 and 2012, and of changes in equity and cash flows for the nine-month periods endedSeptember 30, 2013 and 2012. 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, 2012, and the related consolidated statements of operations, comprehensive income, changes in equity, and cash flows for the year then ended (not presented herein); and in our report dated March 1, 2013, 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, 2012 is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.

/s/ Deloitte & Touche LLP

Des Moines, Iowa

November 1, 2013

1

MIDAMERICAN ENERGY HOLDINGS COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (Unaudited)

(Amounts in millions)

	As of
	September 30,		December 31,
	2013		2012
ASSETS
Current assets:
Cash and cash equivalents	$	1,882	$	776
Trade receivables, net	1,339		1,380
Income taxes receivable	40		336
Inventories	774		766
Other current assets	706		612
Total current assets	4,741		3,870
Property, plant and equipment, net	39,436		37,614
Goodwill	5,251		5,120
Regulatory assets	2,675		2,840
Investments and restricted cash and investments	3,347		2,392
Other assets	710		631
Total assets	$	56,160	$	52,467

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
	September 30,			December 31,
	2013			2012
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	1,143		$	1,214
Accrued interest	324			330
Accrued property, income and other taxes	452			299
Accrued employee expenses	292			188
Short-term debt	158			887
Current portion of long-term debt	1,280			1,137
Other current liabilities	731			695
Total current liabilities	4,380			4,750
Regulatory liabilities	1,851			1,749
MEHC senior debt	4,371			4,621
Subsidiary debt	17,141			14,977
Deferred income taxes	8,391			7,903
Other long-term liabilities	2,663			2,557
Total liabilities	38,797			36,557
Commitments and contingencies (Note 11)
Equity:
MEHC shareholders' equity:
Common stock - 115 shares authorized, no par value, 75 shares issued and outstanding	—			—
Additional paid-in capital	5,390			5,423
Retained earnings	12,056			10,782
Accumulated other comprehensive loss, net	(223		)	(463		)
Total MEHC shareholders' equity	17,223			15,742
Noncontrolling interests	140			168
Total equity	17,363			15,910
Total liabilities and equity	$	56,160		$	52,467

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						Nine-Month Periods
	Ended September 30,						Ended September 30,
	2013			2012			2013			2012
Operating revenue:
Energy	$	2,778		$	2,636		$	8,048		$	7,593
Real estate	555			372			1,340			970
Total operating revenue	3,333			3,008			9,388			8,563
Operating costs and expenses:
Energy:
Cost of sales	949			884			2,753			2,576
Operating expense	686			653			2,037			1,953
Depreciation and amortization	378			367			1,143			1,072
Real estate	502			347			1,223			921
Total operating costs and expenses	2,515			2,251			7,156			6,522
Operating income	818			757			2,232			2,041
Other income (expense):
Interest expense	(309		)	(298		)	(893		)	(884		)
Capitalized interest	18			15			58			37
Allowance for equity funds	17			20			55			55
Other, net	14			18			54			39
Total other income (expense)	(260		)	(245		)	(726		)	(753		)
Income before income tax expense and equity income	558			512			1,506			1,288
Income tax expense	49			47			272			188
Equity income	28			30			68			61
Net income	537			495			1,302			1,161
Net income attributable to noncontrolling interests	12			7			28			16
Net income attributable to MEHC shareholders	$	525		$	488		$	1,274		$	1,145

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						Nine-Month Periods
	Ended September 30,						Ended September 30,
	2013			2012			2013			2012
Net income	$	537		$	495		$	1,302		$	1,161
Other comprehensive income, net of tax:
Unrecognized amounts on retirement benefits, net of tax of $(8), $(2), $11 and $1	(21		)	(5		)	36			6
Foreign currency translation adjustment	212			84			(1		)	113
Unrealized gains (losses) on available-for-sale securities, net of tax of $105, $(11), $136 and $(35)	156			(16		)	200			(51		)
Unrealized (losses) gains on cash flow hedges, net of tax of $(1), $7, $4 and $5	(2		)	11			5			8
Total other comprehensive income, net of tax	345			74			240			76
Comprehensive income	882			569			1,542			1,237
Comprehensive income attributable to noncontrolling interests	12			7			28			16
Comprehensive income attributable to MEHC shareholders	$	870		$	562		$	1,514		$	1,221

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, 2011	75	$	—	$	5,423		$	9,310	$	(641	)	$	173		$	14,265
Net income	—	—		—			1,145		—			16			1,161
Other comprehensive income	—	—		—			—		76			—			76
Distributions	—	—		—			—		—			(18		)	(18		)
Balance at September 30, 2012	75	$	—	$	5,423		$	10,455	$	(565	)	$	171		$	15,484
Balance at December 31, 2012	75	$	—	$	5,423		$	10,782	$	(463	)	$	168		$	15,910
Net income	—	—		—			1,274		—			16			1,290
Other comprehensive income	—	—		—			—		240			—			240
Distributions	—	—		—			—		—			(16		)	(16		)
Redemption of preferred securities of subsidiaries	—	—		—			—		—			(32		)	(32		)
Other equity transactions	—	—		(33		)	—		—			4			(29		)
Balance at September 30, 2013	75	$	—	$	5,390		$	12,056	$	(223	)	$	140		$	17,363

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)

	Nine-Month Periods
	Ended September 30,
	2013			2012
Cash flows from operating activities:
Net income	$	1,302		$	1,161
Adjustments to reconcile net income to net cash flows from operating activities:
Depreciation and amortization	1,166			1,086
Allowance for equity funds	(55		)	(55		)
Deferred income taxes and amortization of investment tax credits	650			655
Other, net	(25		)	(26		)
Changes in other operating assets and liabilities, net of effects from acquisitions:
Trade receivables and other assets	134			24
Derivative collateral, net	49			64
Pension and other postretirement benefit plans	(45		)	(107		)
Accrued property, income and other taxes	407			824
Accounts payable and other liabilities	100			56
Net cash flows from operating activities	3,683			3,682
Cash flows from investing activities:
Capital expenditures	(2,885		)	(2,349		)
Increase in restricted cash and investments	(464		)	(45		)
Acquisitions, net of cash acquired	(210		)	(110		)
Equity method investments	(58		)	(310		)
Purchases of available-for-sale securities	(128		)	(84		)
Proceeds from sales of available-for-sale securities	114			69
Other, net	10			12
Net cash flows from investing activities	(3,621		)	(2,817		)
Cash flows from financing activities:
Proceeds from subsidiary debt	2,496			2,199
Repayments of subsidiary debt	(437		)	(450		)
Repayments of MEHC senior and subordinated debt	—			(272		)
Net repayments of short-term debt	(919		)	(715		)
Other, net	(93		)	(58		)
Net cash flows from financing activities	1,047			704
Effect of exchange rate changes	(3		)	5
Net change in cash and cash equivalents	1,106			1,574
Cash and cash equivalents at beginning of period	776			286
Cash and cash equivalents at end of period	$	1,882		$	1,860

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 nine 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), MidAmerican Transmission, LLC (which owns a 50% interest in Electric Transmission Texas, LLC ("ETT") and Electric Transmission America, LLC), 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 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 50% interest in electric transmission businesses, a diversified portfolio of independent power projects, the second largest residential real estate brokerage firm in the United States and the second largest residential real estate brokerage franchise network in the United States. Northern Natural Gas and Kern River have been aggregated in the reportable segment called MidAmerican Energy Pipeline Group, MidAmerican Renewables, LLC and CalEnergy Philippines have been aggregated in the reportable segment called MidAmerican Renewables and MidAmerican Transmission, LLC has been included in MEHC and Other.

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 September 30, 2013 and for the three- and nine-month periods endedSeptember 30, 2013 and 2012. The results of operations for the three- and nine-month periods endedSeptember 30, 2013 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 unaudited 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, 2012 describes the most significant accounting policies used in the preparation of the unaudited Consolidated Financial Statements. There have been no significant changes in the Company's assumptions regarding significant accounting estimates and policies during the nine-month period endedSeptember 30, 2013.

(2) New Accounting Pronouncements

In February 2013, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") No. 2013-04, which amends FASB Accounting Standards Codification ("ASC") Topic 405, "Liabilities." The amendments in this guidance require an entity to measure obligations resulting from joint and several liability arrangements for which the total amount of the obligation is fixed at the reporting date as the amount the reporting entity agreed to pay plus any additional amounts the reporting entity expects to pay on behalf of its co-obligor. Additionally, the guidance requires the entity to disclose the nature and amount of the obligation, as well as other information about those obligations. This guidance is effective for interim and annual reporting periods beginning after December 15, 2013. The Company is currently evaluating the impact of adopting this guidance on its Consolidated Financial Statements.

8

In February 2013, the FASB issued ASU No. 2013-02, which amends FASB ASC Topic 220, "Comprehensive Income." The amendments in this guidance require an entity to provide information about the amounts reclassified out of accumulated other comprehensive income ("AOCI") by component. In addition, an entity is required to present, either on the face of the financial statements or in the notes, significant amounts reclassified out of AOCI by the respective line items of net income if the amount reclassified is required under GAAP to be reclassified to net income in its entirety in the same reporting period. For other amounts that are not required under GAAP to be reclassified in their entirety to net income, an entity is required to cross-reference to other disclosures required by GAAP that provide additional detail about those amounts. The Company adopted this guidance on January 1, 2013. The adoption of this guidance did not have a material impact on the Company's disclosures included within Notes to Consolidated Financial Statements.

In December 2011, the FASB issued ASU No. 2011-11, which amends FASB 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. In January 2013, the FASB issued ASU No. 2013-01, which also amends FASB ASC Topic 210 to clarify that the scope of ASU No. 2011-11 only applies to derivative instruments, repurchase agreements, reverse purchase agreements and securities borrowing and securities lending transactions that are either being offset or are subject to an enforceable master netting arrangement or similar agreement. The Company adopted the guidance on January 1, 2013. The adoption of the guidance did not have a material impact on the Company's disclosures included within Notes to Consolidated Financial Statements.

(3) Acquisitions

NV Energy, Inc.

On May 29, 2013, MEHC entered into an Agreement and Plan of Merger (the "Merger Agreement") whereby MEHC will acquire NV Energy, Inc. ("NV Energy") and NV Energy will become an indirect wholly owned subsidiary of MEHC. NV Energy is a holding company whose principal subsidiaries are Nevada Power Company ("Nevada Power") and Sierra Pacific Power Company ("Sierra") (together, the "Nevada Utilities"). The Nevada Utilities are public utilities that generate, transmit and distribute electric energy in Nevada and, in the case of Sierra, also provide natural gas service. As of December 31, 2012, NV Energy served 1.2 million electric customers and 0.2 million natural gas customers in its nearly 46,000-square-mile service territory. As of December 31, 2012, NV Energy reported $12 billion of assets and almost 6,000 megawatts ("MW") of owned generating capacity. The Merger Agreement entitles NV Energy's common shareholders to receive $23.75 in cash for each share of NV Energy common stock issued and outstanding immediately prior to the close of the acquisition. The purchase price is estimated at $5.6 billion, subject to final determination of the outstanding shares at closing. MEHC's shareholders have committed to provide sufficient capital to fund the entire purchase price of NV Energy. MEHC expects to fund the acquisition by issuing $1.0 billion of common equity to its existing shareholders, issuing $2.6 billion of junior subordinated debentures to Berkshire Hathaway and its subsidiaries, and incurring $2.0 billion of MEHC senior debt.

The acquisition has been approved by the boards of directors of both NV Energy and MEHC and the shareholders of NV Energy, but remains subject to customary closing conditions, including receipt of approvals from state and federal regulatory authorities. MEHC and NV Energy filed a joint application with the Public Utilities Commission of Nevada ("PUCN") on July 17, 2013. The PUCN has scheduled hearings relative to the joint application beginning on November 18, 2013. The PUCN has 180 days from the application filing date to issue a final order on the joint application. MEHC and NV Energy filed an application with the Federal Energy Regulatory Commission ("FERC") on July 12, 2013. On September 27, 2013, the Federal Communications Commission license transfer was approved, and on July 22, 2013, the United States Department of Justice and the Federal Trade Commission granted early termination of the mandatory waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976. The PUCN and FERC approvals are expected to be received by early 2014 and MEHC expects the acquisition to close shortly after receiving the approvals.

The Merger Agreement provides for certain termination rights for both NV Energy and MEHC. Upon termination of the Merger Agreement under certain circumstances, NV Energy may be obligated to pay MEHC a termination fee of $170 million.

HomeServices

The Company completed various acquisitions of residential real estate brokerage businesses totaling $206 million through September 2013. The purchase prices were allocated to the assets acquired and liabilities assumed in each acquisition. The assets acquired consisted of loans receivable and other working capital items, goodwill and other identifiable intangible assets. The liabilities assumed included mortgage lines of credit secured by the loans receivable acquired and other working capital items.

9

(4) Property, Plant and Equipment, Net

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

		As of
	Depreciable	September 30,			December 31,
	Life	2013			2012
Regulated assets:
Utility generation, distribution and transmission system	5-80 years	$	43,899		$	42,682
Interstate pipeline assets	3-80 years	6,388			6,354
		50,287			49,036
Accumulated depreciation and amortization		(16,128		)	(15,338		)
Regulated assets, net		34,159			33,698
Nonregulated assets:
Independent power plants	5-30 years	1,941			1,428
Other assets	3-30 years	483			432
		2,424			1,860
Accumulated depreciation and amortization		(651		)	(591		)
Nonregulated assets, net		1,773			1,269
Net operating assets		35,932			34,967
Construction work-in-progress		3,504			2,647
Property, plant and equipment, net		$	39,436		$	37,614

Construction work-in-progress includes $2.3 billion and $1.9 billion as of September 30, 2013 and December 31, 2012 related to the construction of regulated assets.

10

(5) Investments and Restricted Cash and Investments

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

	As of
	September 30,		December 31,
	2013		2012
Investments:
BYD Company Limited common stock	$	1,004	$	675
Rabbi trusts	324		313
Other	118		105
Total investments	1,446		1,093
Equity method investments:
Electric Transmission Texas, LLC	434		361
CE Generation, LLC	247		241
Bridger Coal Company	177		187
Agua Caliente Solar, LLC(1)	57		64
Other	85		71
Total equity method investments	1,000		924
Restricted cash and investments:
Solar Star and Topaz Projects	471		—
Quad Cities Station nuclear decommissioning trust funds	372		337
Other	120		154
Total restricted cash and investments	963		491
Total investments and restricted cash and investments	$	3,409	$	2,508
Reflected as:
Current assets	$	62	$	116
Noncurrent assets	3,347		2,392
Total investments and restricted cash and investments	$	3,409	$	2,508

(1) As of September 30, 2013 and December 31, 2012, the equity investment is net of investment tax credits totaling $203 million and $165 million, respectively.

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 September 30, 2013 and December 31, 2012, the fair value of MEHC's investment in BYD Company Limited common stock was $1.0 billion and $675 million, respectively, which resulted in a pre-tax unrealized gain of $772 million and $443 million as of September 30, 2013 and December 31, 2012, respectively.

Restricted Cash and Investments

As of September 30, 2013, restricted cash and investments included $460 million restricted for construction of a combined 579-megawatt solar project in California ("Solar Star Projects") (formerly the Antelope Valley Projects) and $11 million restricted for construction of a 550-megawatt solar project in California ("Topaz Project").

11

(6) Recent Financing Transactions

Long-Term Debt

In September 2013, MidAmerican Energy issued $350 million of its 2.40% First Mortgage Bonds due March 2019, $250 million of its 3.70% First Mortgage Bonds due September 2023 and $350 million of its 4.80% First Mortgage Bonds due September 2043 pursuant to its indenture dated September 9, 2013, as supplemented and amended. The net proceeds will be used for the repayment of $669 million of long-term debt maturing December 31, 2013, and for general corporate purposes.

Pursuant to MidAmerican Energy's mortgage dated September 9, 2013, the first mortgage bonds are secured by a first mortgage lien on substantially all of MidAmerican Energy’s electric generating, transmission and distribution property within the State of Iowa, subject to certain exceptions and permitted encumbrances. As of September 30, 2013, 80% of MidAmerican Energy's gross utility plant in-service was pledged. Additionally, MidAmerican Energy's senior notes outstanding are equally and ratably secured with the first mortgage bonds as required by the indentures under which the senior notes were issued.

In June 2013, Solar Star Funding, LLC issued $1.0 billion of its 5.375% Series A Senior Secured Notes. The principal of the notes amortizes beginning June 2016 with a final maturity in June 2035. The net proceeds are being used to fund the costs related to the development, construction and financing of the Solar Star Projects. Until amounts are used to fund the costs of the Solar Star Projects, unused amounts will be invested or, in certain circumstances, loaned to MEHC. As of September 30, 2013, no amounts were loaned to MEHC.

In June 2013, PacifiCorp issued $300 million of its 2.95% First Mortgage Bonds due June 2023. The net proceeds were used to fund capital expenditures and for general corporate purposes.

In April 2013, Topaz issued $250 million of its 4.875% Series B Senior Secured Notes. The principal of the notes amortizes beginning September 2015 with a final maturity in September 2039. The net proceeds are being used to fund the costs related to the development, construction and financing of the Topaz Project. Until amounts are used to fund the costs of the Topaz Project, unused amounts will be invested or, in certain circumstances, loaned to MEHC. As of September 30, 2013, no amounts were loaned to MEHC.

Credit Facilities

In July 2013, HomeServices replaced its existing $125 million unsecured facility, which had been set to expire in December 2013, with a $350 million unsecured credit facility expiring in July 2018. The replacement credit facility has a variable interest rate based on the prime lending rate or the London Interbank Offered Rate ("LIBOR"), at HomeServices' option, plus a spread that varies based on HomeServices' Total Leverage Ratio as defined in the agreement. As of September 30, 2013, HomeServices had no borrowings outstanding under its credit facility.

In July 2013, HomeServices acquired a subsidiary that maintains $275 million of mortgage lines of credit used for mortgage banking activities that expire beginning in October 2013 through June 2014. The mortgage lines of credit have variable rates based on LIBOR plus a spread, with certain minimum rates. Collateral for these credit facilities is equal to the loans funded with the facilities. As of September 30, 2013, HomeServices had $122 million outstanding under these mortgage lines of credit at a weighted average interest rate of 3.26%.

In June 2013, MEHC terminated its $479 million revolving credit facility expiring in July 2013.

In March 2013, PacifiCorp replaced its $630 million unsecured revolving credit facility, which had been set to expire in July 2013, with a $600 million unsecured revolving credit facility expiring in March 2018. The new credit facility, which supports PacifiCorp's commercial paper program, certain series of its tax-exempt bond obligations and provides for the issuance of letters of credit, has a variable interest rate based on LIBOR or a base rate, at PacifiCorp's option, plus a spread that varies based on PacifiCorp's credit ratings for its senior unsecured long-term debt securities. As of September 30, 2013, 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. As of September 30, 2013, $270 million of letters of credit were issued under this credit agreement to support variable-rate tax-exempt bond obligations. These letters of credit were previously issued under the credit facility that was replaced.

In March 2013, PacifiCorp obtained $289 million of letters of credit to support variable-rate tax-exempt bond obligations. These letters of credit expire through March 2015 and replaced certain letters of credit previously issued under one of the revolving credit facilities.

12

As of December 31, 2012, PacifiCorp had $68 million of tax-exempt bond obligations with fixed interest rates, ranging from 3.90% to 4.13%, scheduled to reset to variable or fixed interest rates in June 2013. In June 2013, $17 million of these tax-exempt bond obligations were redeemed and retired prior to their scheduled 2014 maturity date. The interest rates for the remaining $51 million, with maturity dates ranging from 2014 to 2025, were reset to variable interest rates with a weighted average interest rate of 0.24% as of September 30, 2013.

In March 2013, MidAmerican Energy replaced its $530 million unsecured revolving credit facility, which had been set to expire in July 2013, with a $600 million unsecured revolving credit facility expiring in March 2018. The new credit facility, which supports MidAmerican Energy's commercial paper program and its variable-rate tax-exempt bond obligations and provides for the issuance of letters of credit, has a variable interest rate based on LIBOR or a base rate, at MidAmerican Energy's option, plus a spread that varies based on MidAmerican Energy's credit ratings for its senior unsecured long-term debt securities. As of September 30, 2013, MidAmerican Energy had no borrowings outstanding under this credit facility.The credit facility requires that MidAmerican Energy'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.

(7) 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				Nine-Month Periods
	Ended September 30,				Ended September 30,
	2013		2012		2013		2012
Federal statutory income tax rate	35	%	35	%	35	%	35	%
Income tax credits	(17	)	(16	)	(13	)	(13	)
State income tax, net of federal income tax benefit	1		(1	)	2		—
Income tax effect of foreign income	(12	)	(12	)	(6	)	(6	)
Equity income	2		2		2		2
Effects of ratemaking	(1	)	2		(1	)	(1	)
Other, net	1		(1	)	(1	)	(2	)
Effective income tax rate	9	%	9	%	18	%	15	%

Income tax credits relate primarily to production tax credits earned by wind-powered generating facilities owned by MidAmerican Energy, PacifiCorp and Bishop Hill Energy II, LLC. Federal renewable electricity production tax credits are earned as energy from qualifying wind-powered generating facilities is produced and sold and are based on a per-kilowatt hour rate pursuant to the applicable federal income tax law. Wind-powered generating facilities are eligible for the credits for 10 years from the date the qualifying generating facilities were placed in-service.

In the third quarter of 2013, the Company recognized $54 million of deferred income tax benefits upon the enactment of a reduction in the United Kingdom corporate income tax rate from 23% to 21% effective April 1, 2014, and a further reduction to 20% effective April 1, 2015. In the third quarter of 2012, the Company recognized $38 million of deferred income tax benefits upon the enactment of a reduction in the United Kingdom corporate income tax rate from 25% to 24% effective April 1, 2012, and a further reduction to 23% effective April 1, 2013.

Berkshire Hathaway includes the Company in its United States federal income tax return. For the nine-month periods endedSeptember 30,2013 and 2012, the Company received net cash payments for income taxes from Berkshire Hathaway totaling $825 million and $1.346 billion, respectively.

13

(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						Nine-Month Periods
	Ended September 30,						Ended September 30,
	2013			2012			2013			2012
Pension:
Service cost	$	5		$	6		$	17		$	19
Interest cost	23			24			66			72
Expected return on plan assets	(31		)	(30		)	(90		)	(89		)
Net amortization	15			10			44			29
Net periodic benefit cost	$	12		$	10		$	37		$	31
Other postretirement:
Service cost	$	4		$	3		$	10		$	8
Interest cost	8			9			25			27
Expected return on plan assets	(10		)	(11		)	(32		)	(32		)
Net amortization	1			1			4			1
Net periodic benefit cost	$	3		$	2		$	7		$	4

Employer contributions to the domestic pension and other postretirement benefit plans are expected to be $72 million and $13 million, respectively, during 2013. As of September 30, 2013, $67 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						Nine-Month Periods
	Ended September 30,						Ended September 30,
	2013			2012			2013			2012
Service cost	$	5		$	5		$	16		$	15
Interest cost	21			21			63			64
Expected return on plan assets	(25		)	(26		)	(75		)	(79		)
Net amortization	14			11			41			33
Net periodic benefit cost	$	15		$	11		$	45		$	33

Employer contributions to the United Kingdom pension plan are expected to be £51 million during 2013. As of September 30, 2013, £38 million, or $59 million, of contributions had been made to the United Kingdom pension plan.

14

(9) 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 PacifiCorp and MidAmerican Energy (the "Utilities") as they have an obligation to serve retail customer load in their regulated service territories. MidAmerican Energy also provides nonregulated retail 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 10 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):

	Other						Other			Other
	Current			Other			Current			Long-term
	Assets			Assets			Liabilities			Liabilities			Total
As of September 30, 2013
Not designated as hedging contracts:
Commodity assets(1)	$	24		$	43		$	10		$	1		$	78
Commodity liabilities(1)	(12		)	(1		)	(86		)	(85		)	(184		)
Interest rate assets	—			3			—			—			3
Total	12			45			(76		)	(84		)	(103		)
Designated as hedging contracts:
Commodity assets	1			—			5			—			6
Commodity liabilities	—			—			(20		)	(12		)	(32		)
Interest rate assets	—			3			—			—			3
Interest rate liabilities	—			—			(5		)	—			(5		)
Total	1			3			(20		)	(12		)	(28		)
Total derivatives	13			48			(96		)	(96		)	(131		)
Cash collateral receivable	—			—			15			1			16
Total derivatives - net basis	$	13		$	48		$	(81	)	$	(95	)	$	(115	)

15

	Other						Other			Other
	Current			Other			Current			Long-term
	Assets			Assets			Liabilities			Liabilities			Total
As of December 31, 2012
Not designated as hedging contracts:
Commodity assets(1)	$	30		$	34		$	25		$	3		$	92
Commodity liabilities(1)	(14		)	(2		)	(177		)	(102		)	(295		)
Interest rate liabilities	—			—			—			(1		)	(1		)
Total	16			32			(152		)	(100		)	(204		)
Designated as hedging contracts:
Commodity assets	1			—			1			1			3
Commodity liabilities	(1		)	—			(22		)	(12		)	(35		)
Interest rate liabilities	—			—			(5		)	(7		)	(12		)
Total	—			—			(26		)	(18		)	(44		)
Total derivatives	16			32			(178		)	(118		)	(248		)
Cash collateral receivable	—			—			62			—			62
Total derivatives - net basis	$	16		$	32		$	(116	)	$	(118	)	$	(186	)

(1) The Company's commodity derivatives not designated as hedging contracts are generally included in regulated rates, and as of September 30, 2013 and December 31, 2012, a net regulatory asset of $144 million and $235 million, respectively, was recorded related to the net derivative liability of $106 million and $203 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						Nine-Month Periods
	Ended September 30,						Ended September 30,
	2013			2012			2013			2012
Beginning balance	$	172		$	357		$	235		$	400
Changes in fair value recognized in net regulatory assets	18			(31		)	12			42
Net gains reclassified to operating revenue	7			10			9			51
Net losses reclassified to cost of sales	(53		)	(87		)	(112		)	(244		)
Ending balance	$	144		$	249		$	144		$	249

16

Designated as Hedging Contracts

The Company uses commodity derivative contracts accounted for as cash flow hedges to hedge electricity and natural gas commodity prices for delivery to nonregulated customers, spring operational sales, natural gas storage and other transactions. The 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 commodity 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						Nine-Month Periods
	Ended September 30,						Ended September 30,
	2013			2012			2013			2012
Beginning balance	$	26		$	49		$	32		$	46
Changes in fair value recognized in OCI	1			(18		)	1			12
Net losses reclassified to cost of sales	(1		)	(4		)	(7		)	(31		)
Ending balance	$	26		$	27		$	26		$	27

Certain derivative contracts, principally interest rate locks, have settled and the fair value at the date of settlement remains in 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 nine-month periods endedSeptember 30, 2013 and 2012, hedge ineffectiveness was insignificant. As of September 30, 2013, the Company had cash flow hedges with expiration dates extending through December 2019 and $19 million of pre-tax 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 derivative contracts with fixed price terms that comprise the mark-to-market values as of (in millions):

	Unit of	September 30,		December 31,
	Measure	2013		2012
Electricity sales	Megawatt hours	(1	)	(1	)
Natural gas purchases	Decatherms	172		130
Fuel purchases	Gallons	12		16
Interest rate swaps	US$	458		470

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.

17

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 Midcontinent Independent 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 credit support provisions that in part base certain collateral requirements on credit ratings for senior unsecured debt as reported by one or more of the three recognized credit rating agencies. 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," or in some cases terminate the contract, in the event of a material adverse change in creditworthiness. These rights can vary by contract and by counterparty. As of September 30, 2013, the applicable 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 $198 million and $306 million as of September 30, 2013 and December 31, 2012, respectively, for which the Company had posted collateral of $12 million and $56 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 September 30, 2013 and December 31, 2012, the Company would have been required to post $164 million and $214 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.

(10) 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.

18

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 September 30, 2013
Assets:
Commodity derivatives	$	1		$	36		$	47		$	(29	)	$	55
Interest rate derivatives	—			6			—			—			6
Money market mutual funds(2)	1,185			—			—			—			1,185
Debt securities:
United States government obligations	125			—			—			—			125
International government obligations	—			1			—			—			1
Corporate obligations	—			34			—			—			34
Municipal obligations	—			2			—			—			2
Agency, asset and mortgage-backed obligations	—			2			—			—			2
Auction rate securities	—			—			43			—			43
Equity securities:
United States companies	204			—			—			—			204
International companies	1,007			—			—			—			1,007
Investment funds	82			—			—			—			82
	$	2,604		$	81		$	90		$	(29	)	$	2,746
Liabilities:
Commodity derivatives	$	(4	)	$	(204	)	$	(8	)	$	45		$	(171	)
Interest rate derivatives	—			(5		)	—			—			(5		)
	$	(4	)	$	(209	)	$	(8	)	$	45		$	(176	)

	Input Levels for Fair Value Measurements
	Level 1			Level 2			Level 3			Other(1)			Total
As of December 31, 2012
Assets:
Commodity derivatives	$	1		$	55		$	39		$	(47	)	$	48
Money market mutual funds(2)	589			—			—			—			589
Debt securities:
United States government obligations	104			—			—			—			104
International government obligations	—			1			—			—			1
Corporate obligations	—			32			—			—			32
Municipal obligations	—			4			—			—			4
Agency, asset and mortgage-backed obligations	—			6			—			—			6
Auction rate securities	—			—			41			—			41
Equity securities:
United States companies	187			—			—			—			187
International companies	677			—			—			—			677
Investment funds	71			—			—			—			71
	$	1,629		$	98		$	80		$	(47	)	$	1,760
Liabilities:
Commodity derivatives	$	(10	)	$	(313	)	$	(7	)	$	109		$	(221	)
Interest rate derivatives	—			(13		)	—			—			(13		)
	$	(10	)	$	(326	)	$	(7	)	$	109		$	(234	)

19

(1) Represents netting under master netting arrangements and a net cash collateral receivable of $16 million and $62 million as of September 30, 2013 and December 31, 2012, respectively.

(2) Amounts are included in cash and cash equivalents; other current assets; 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 estimated 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 brokers, exchanges, direct communication with market participants and actual transactions executed by the Company. Market price quotations are generally readily obtainable for the applicable term of the Company's outstanding derivative contracts; therefore, the Company's forward price curves reflect observable market quotes. Market price quotations for certain 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 9 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.

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					Nine-Month Periods
	Ended September 30,					Ended September 30,
				Auction					Auction
	Commodity			Rate		Commodity			Rate
	Derivatives			Securities		Derivatives			Securities
2013:
Beginning balance	$	27		$	42	$	32		$	41
Changes included in earnings	12			—		16			—
Changes in fair value recognized in other comprehensive income	—			1		(5		)	2
Changes in fair value recognized in net regulatory assets	(1		)	—		1			—
Purchases	—			—		2			—
Settlements	1			—		(7		)	—
Ending balance	$	39		$	43	$	39		$	43

20

	Three-Month Periods					Nine-Month Periods
	Ended September 30,					Ended September 30,
				Auction					Auction
	Commodity			Rate		Commodity			Rate
	Derivatives			Securities		Derivatives			Securities
2012:
Beginning balance	$	17		$	36	$	23		$	35
Changes included in earnings	(2		)	—		7			—
Changes in fair value recognized in other comprehensive income	—			2		3			4
Changes in fair value recognized in net regulatory assets	(3		)	—		—			—
Sales	—			—		—			(1		)
Settlements	—			—		(21		)	—
Ending balance	$	12		$	38	$	12		$	38

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 September 30, 2013				As of December 31, 2012
	Carrying		Fair		Carrying		Fair
	Value		Value		Value		Value
Long-term debt	$	22,792	$	25,324	$	20,735	$	24,924

(11) 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.

21

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. In May 2010, the Utah Supreme Court reversed summary judgment and remanded the case back to the Third District Court for further consideration, which led to a trial that began in April 2012. In May 2012, the jury reached a verdict in favor of the Plaintiff on its claims. The jury awarded damages to the Plaintiff for breach of contract and misappropriation of a trade secret in the amounts of $18 million for actual damages and $113 million for unjust enrichment. In May 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. In October 2012, PacifiCorp filed post-trial motions for a judgment notwithstanding the verdict and a new trial (collectively, "PacifiCorp's post-trial motions"). The trial judge stayed briefing on the Plaintiff's motions, pending resolution of PacifiCorp's post-trial motions. As a result of a hearing in December 2012, the trial judge denied PacifiCorp's post-trial motions with the exception of reducing the aggregate amount of damages to $113 million. In January 2013, the Plaintiff filed a motion for prejudgment interest. In the first quarter of 2013, PacifiCorp filed its responses to the Plaintiff's post-trial motions for exemplary damages, attorneys' fees and prejudgment interest. An initial judgment was entered in April 2013 in which the trial judge denied the Plaintiff's motions for exemplary damages and prejudgment interest and ruled that PacifiCorp must pay the Plaintiff's attorneys' fees based on applying a reasonable rate to hours worked rather than the Plaintiff's request for an amount equal to 40% of all amounts ultimately awarded. In May 2013, a final judgment was entered against PacifiCorp in the amount of $115 million, which includes the $113 million of aggregate damages previously awarded and amounts awarded for the Plaintiff's attorneys' fees. The final judgment also ordered that postjudgment interest accrue beginning as of the date of the April 2013 initial judgment. In May 2013, PacifiCorp posted a surety bond issued by a subsidiary of Berkshire Hathaway to secure its estimated obligation. Both PacifiCorp and the Plaintiff filed appeals with the Utah Supreme Court. PacifiCorp strongly disagrees with the jury's verdict and plans to vigorously pursue all appellate measures. The appeals are awaiting a briefing schedule to be set by the Utah Supreme Court. As of September 30, 2013, PacifiCorp had accrued $116 million for the final judgment and postjudgment interest, and believes the likelihood of any additional material loss is remote; however, any additional awards against PacifiCorp could also have a material effect on the consolidated financial results. Any payment of damages will be at the end of the appeals process, which could take as long as several years.

Commitments

Subsidiaries of Solar Star Funding, LLC are constructing the Solar Star Projects in California, which is expected to be placed in-service in phases through 2015. In conjunction with Solar Star Funding, LLC's $1.0 billion issuance of its 5.375% Series A Senior Secured Notes, MEHC has committed to provide Solar Star Funding, LLC and its subsidiaries with equity to fund the costs of the Solar Star Projects in an amount up to $2.75 billion less, among other things, the gross proceeds of long-term debt issuances, project revenue prior to completion and the total equity contributions made by MEHC. This commitment replaced a previous equity commitment that was in place. As of September 30, 2013, the remaining commitment is $1.75 billion. If MEHC does not maintain a minimum credit rating from two of the following three ratings agencies of at least BBB- from Standard & Poor's Ratings Services or Fitch Ratings or Baa3 from Moody's Investors Service, 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 Solar Star Projects, MEHC will have no further obligation to make any equity contribution and any unused equity contribution obligations will be canceled.

In August 2013, PacifiCorp amended an existing coal supply agreement for its coal-fueled generating facilities by exercising a five-year extension period. The amended coal supply agreement results in minimum future purchases of $95 million in 2016, $96 million in 2017 and $298 million in 2018 and thereafter.

In August 2013, the Iowa Utilities Board approved ratemaking principles for MidAmerican Energy to construct up to 1,050 megawatts (nominal ratings) of additional wind-powered generating facilities expected to be placed in-service in 2013, 2014 and 2015. MidAmerican Energy has entered into contracts totaling $1.3 billion related to these wind-powered generating facilities with minimum payments expected to be $343 million in 2013, $522 million in 2014 and $447 million in 2015.

22

In July 2013, MidAmerican Energy entered into a contract totaling $342 million to construct transmission assets related to its Multi-Value Projects approved by the Midcontinent Independent System Operator, Inc. with minimum payments of $17 million in 2013, $140 million in 2014, $149 million in 2015 and $36 million in 2016.

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.

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.

(12) Components of Accumulated Other Comprehensive Loss, Net

The following table shows the change in accumulated other comprehensive loss attributable to MEHC shareholders by each component of other comprehensive income (loss), net of applicable income taxes, for the nine-month period endedSeptember 30, 2013 (in millions):

											Accumulated
							Unrealized				Other
	Unrecognized			Foreign			Gains on		Unrealized		Comprehensive
	Amounts on			Currency			Available-		Gains on		Loss Attributable
	Retirement			Translation			For-Sale		Cash Flow		To MEHC
	Benefits			Adjustment			Securities		Hedges		Shareholders, Net
Balance, December 31, 2012	$	(575	)	$	(172	)	$	261	$	23	$	(463	)
Other comprehensive income (loss)	36			(1		)	200		5		240
Balance, September 30, 2013	$	(539	)	$	(173	)	$	461	$	28	$	(223	)

Reclassifications from AOCI to net income for the periods ended September 30, 2013 and 2012 were insignificant. For information regarding cash flow hedge reclassifications from AOCI to net income in their entirety, refer to Note 9. Additionally, refer to the "Foreign Operations" discussion in Note 8 for information about unrecognized amounts on retirement benefits reclassifications from AOCI that do not impact net income in their entirety.

(13) Other Related Party Transactions

In 2012, MidAmerican Energy signed new long-term rail transportation contracts with BNSF Railway Company ("BNSF"), an affiliate company, and Union Pacific Railroad Company ("UP") for the transportation of coal to all of the MidAmerican Energy-operated coal-fueled generating facilities. These contracts replaced a long-term contract with UP that expired December 31, 2012. For the three- and nine-month periods endedSeptember 30, 2013, $50 million and $139 million, respectively, was incurred for coal transportation services, the majority of which was related to the BNSF agreement. As of September 30, 2013, MidAmerican Energy had accounts payable to BNSF of $5 million.

23

(14) Segment Information

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						Nine-Month Periods
	Ended September 30,						Ended September 30,
	2013			2012			2013			2012
Operating revenue:
PacifiCorp	$	1,398		$	1,327		$	3,845		$	3,671
MidAmerican Funding	828			828			2,508			2,411
MidAmerican Energy Pipeline Group	194			203			685			698
Northern Powergrid Holdings	243			240			796			747
MidAmerican Renewables	116			51			246			112
HomeServices	555			372			1,340			970
MEHC and Other(1)	(1		)	(13		)	(32		)	(46		)
Total operating revenue	$	3,333		$	3,008		$	9,388		$	8,563
Depreciation and amortization:
PacifiCorp	$	173		$	164		$	518		$	488
MidAmerican Funding	98			107			309			300
MidAmerican Energy Pipeline Group	45			48			142			144
Northern Powergrid Holdings	44			44			129			127
MidAmerican Renewables	18			7			51			22
HomeServices	12			4			23			14
MEHC and Other(1)	—			(3		)	(6		)	(9		)
Total depreciation and amortization	$	390		$	371		$	1,166		$	1,086
Operating income:
PacifiCorp	$	392		$	382		$	1,005		$	917
MidAmerican Funding	130			139			279			311
MidAmerican Energy Pipeline Group	71			68			309			322
Northern Powergrid Holdings	112			118			424			406
MidAmerican Renewables	81			34			151			66
HomeServices	53			25			117			49
MEHC and Other(1)	(21		)	(9		)	(53		)	(30		)
Total operating income	818			757			2,232			2,041
Interest expense	(309		)	(298		)	(893		)	(884		)
Capitalized interest	18			15			58			37
Allowance for equity funds	17			20			55			55
Other, net	14			18			54			39
Total income before income tax expense and equity income	$	558		$	512		$	1,506		$	1,288

24

	Three-Month Periods				Nine-Month Periods
	Ended September 30,				Ended September 30,
	2013		2012		2013		2012
Interest expense:
PacifiCorp	$	98	$	98	$	293	$	294
MidAmerican Funding	42		41		124		126
MidAmerican Energy Pipeline Group	19		24		60		70
Northern Powergrid Holdings	35		36		105		103
MidAmerican Renewables	40		21		96		50
HomeServices	—		1		1		1
MEHC and Other(1)	75		77		214		240
Total interest expense	$	309	$	298	$	893	$	884

	As of
	September 30,		December 31,
	2013		2012
Total assets:
PacifiCorp	$	23,164	$	22,973
MidAmerican Funding	14,445		13,355
MidAmerican Energy Pipeline Group	4,819		4,865
Northern Powergrid Holdings	6,610		6,418
MidAmerican Renewables	3,984		3,342
HomeServices	1,358		899
MEHC and Other(1)	1,780		615
Total assets	$	56,160	$	52,467

(1) The differences between the reportable segment amounts and the consolidated amounts, described as MEHC and Other, relate to MidAmerican Transmission, LLC, other corporate entities, corporate functions and intersegment eliminations.

The following table shows the change in the carrying amount of goodwill by reportable segment for the nine-month period endedSeptember 30, 2013 (in millions):

					MidAmerican
					Energy			Northern
			MidAmerican		Pipeline			Powergrid			MidAmerican			Home-
	PacifiCorp		Funding		Group			Holdings			Renewables			Services		Other		Total
Balance, December 31, 2012	$	1,126	$	2,102	$	179		$	1,135		$	71		$	507	$	—	$	5,120
Acquisitions	—		—		—			—			—			150		4		154
Foreign currency translation	—		—		—			(3		)	—			—		—		(3		)
Other	3		—		(20		)	—			(3		)	—		—		(20		)
Balance, September 30, 2013	$	1,129	$	2,102	$	159		$	1,132		$	68		$	657	$	4	$	5,251

25

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 nine 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), MidAmerican Transmission, LLC (which owns a 50% interest in ETT and Electric Transmission America, LLC), 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 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 50% interest in electric transmission businesses, a diversified portfolio of independent power projects, the second largest residential real estate brokerage firm in the United States and the second largest residential real estate brokerage franchise network in the United States. Northern Natural Gas and Kern River have been aggregated in the reportable segment called MidAmerican Energy Pipeline Group, MidAmerican Renewables, LLC and CalEnergy Philippines have been aggregated in the reportable segment called MidAmerican Renewables and MidAmerican Transmission, LLC has been included in MEHC and Other. 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 to MidAmerican Transmission, LLC, other corporate entities, corporate functions and intersegment eliminations.

Results of Operations for the Third Quarter and First Nine Months of 2013 and 2012

Overview

Net income for the Company's reportable segments is summarized as follows (in millions):

	Third Quarter											First Nine Months
	2013			2012			Change					2013			2012			Change
Net income attributable to MEHC shareholders:
PacifiCorp	$	217		$	212		$	5		2	%	$	542		$	493		$	49		10	%
MidAmerican Funding	143			136			7			5		264			284			(20		)	(7	)
MidAmerican Energy Pipeline Group	33			31			2			6		161			159			2			1
Northern Powergrid Holdings	116			105			11			10		302			270			32			12
MidAmerican Renewables	41			20			21			*		70			26			44			*
HomeServices	30			18			12			67		69			38			31			82
MEHC and Other	(55		)	(34		)	(21		)	(62	)	(134		)	(125		)	(9		)	(7	)
Total net income attributable to MEHC shareholders	$	525		$	488		$	37		8		$	1,274		$	1,145		$	129		11

*    Not meaningful

Net income attributable to MEHC shareholders increased $37 million for the three-month period endedSeptember 30, 2013 compared to 2012 due to the following:

• PacifiCorp's net income increased as higher retail prices approved by regulators of $69 million and higher retail customer load of $7 million were partially offset by higher energy costs of $40 million, higher operating expense of $12 million, higher depreciation and amortization of $9 million and lower wholesale and other revenue of $5 million.

• MidAmerican Funding's net income increased as higher income tax benefits of $13 million from higher production tax credits and lower depreciation and amortization of $9 million were partially offset by lower regulated electric margins of $8 million and lower nonregulated electric margins of $5 million.

26

• MidAmerican Energy Pipeline Group's net income increased due to lower operating expense and lower interest expense, both primarily at Northern Natural Gas, and lower depreciation and amortization at Kern River, partially offset by lower operating revenue.

• Northern Powergrid Holdings' net income increased due to higher operating revenue from higher distribution tariff rates of $23 million and higher deferred income tax benefits of $16 million from additional reductions in the United Kingdom corporate income tax rate, partially offset by an unfavorable movement in regulatory provisions of $14 million, the write-off of hydrocarbon well exploration costs of $6 million, lower units distributed of $6 million and the impact of the stronger United States dollar of $3 million.

• MidAmerican Renewables' net income increased due to additional solar and wind-powered generating facilities placed in-service and a favorable change in the fair value of the Bishop Hill derivative contract.

• HomeServices' net income increased due to higher operating revenue of $183 million reflecting higher closed brokerage units and average home sale prices at existing businesses and higher revenue from acquired businesses, partially offset by higher commissions at both existing and acquired businesses, higher operating expense and depreciation at acquired businesses and lower earnings at its mortgage joint venture primarily due to lower refinancing activity.

• MEHC and Other net loss increased due to changes in uncertain income tax positions and higher acquisition and other costs, partially offset by lower interest expense.

Net income attributable to MEHC shareholders increased $129 million for the nine-month period endedSeptember 30, 2013 compared to 2012 due to the following:

• PacifiCorp's net income increased as higher retail prices approved by regulators of $183 million, higher retail customer load of $42 million and lower operating expense of $17 million were partially offset by lower wholesale and other revenue of $51 million, higher energy costs of $73 million and higher depreciation and amortization of $30 million.

• MidAmerican Funding's net income decreased due to higher operating expense of $34 million, lower nonregulated electric margins of $14 million and higher depreciation of $9 million, partially offset by higher income tax benefits of $15 million from higher production tax credits, higher regulated gas margins of $22 million and higher regulated electric margins of $6 million.

• MidAmerican Energy Pipeline Group's net income increased as benefits from a contract restructuring at Northern Natural Gas of $12 million and lower interest expense were partially offset by lower operating revenue and higher cost of gas sold.

• Northern Powergrid Holdings' net income increased due to higher operating revenue from higher distribution tariff rates of $58 million, higher deferred income tax benefits of $16 million from additional reductions in the United Kingdom corporate income tax rate and a net favorable movement in regulatory provisions of $14 million, partially offset by lower units distributed of $12 million, an increase in distribution operating expense of $11 million, the impact of the stronger United States dollar of $7 million, higher pension costs of $9 million, the write-off of hydrocarbon well exploration costs of $6 million and higher depreciation of $5 million.

• MidAmerican Renewables' net income increased due to additional solar and wind-powered generating facilities placed in-service and a favorable change in the fair value of the Bishop Hill derivative contract.

• HomeServices' net income increased due to higher operating revenue of $370 million reflecting higher closed brokerage units and average home sale prices at existing businesses and higher revenue from acquired businesses, partially offset by higher commissions at both existing and acquired businesses, higher operating expense and depreciation at acquired businesses and lower earnings at its mortgage joint venture primarily due to lower refinancing activity.

• MEHC and Other net loss increased due to changes in uncertain income tax positions and higher acquisition and other costs, partially offset by lower interest expense and higher equity earnings at ETT.

27

Reportable Segment Results

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

	Third Quarter											First Nine Months
	2013			2012			Change					2013			2012			Change
Operating revenue:
PacifiCorp	$	1,398		$	1,327		$	71		5	%	$	3,845		$	3,671		$	174		5	%
MidAmerican Funding	828			828			—			—		2,508			2,411			97			4
MidAmerican Energy Pipeline Group	194			203			(9		)	(4	)	685			698			(13		)	(2	)
Northern Powergrid Holdings	243			240			3			1		796			747			49			7
MidAmerican Renewables	116			51			65			*		246			112			134			*
HomeServices	555			372			183			49		1,340			970			370			38
MEHC and Other	(1		)	(13		)	12			92		(32		)	(46		)	14			30
Total operating revenue	$	3,333		$	3,008		$	325		11		$	9,388		$	8,563		$	825		10

Operating income:
PacifiCorp	$	392		$	382		$	10		3	%	$	1,005		$	917		$	88		10	%
MidAmerican Funding	130			139			(9		)	(6	)	279			311			(32		)	(10	)
MidAmerican Energy Pipeline Group	71			68			3			4		309			322			(13		)	(4	)
Northern Powergrid Holdings	112			118			(6		)	(5	)	424			406			18			4
MidAmerican Renewables	81			34			47			*		151			66			85			*
HomeServices	53			25			28			*		117			49			68			*
MEHC and Other	(21		)	(9		)	(12		)	*		(53		)	(30		)	(23		)	(77	)
Total operating income	$	818		$	757		$	61		8		$	2,232		$	2,041		$	191		9

*    Not meaningful

PacifiCorp

Operating revenue increased $71 million for the third quarter of 2013 compared to 2012 due to higher retail revenue of $76 million, partially offset by a decrease in wholesale and other revenue of $5 million. The increase in retail revenue was due to higher prices approved by regulators of $69 million and higher retail customer loads of $7 million. Customer load increased 1.4% due to the impacts of hotter weather on residential and commercial customer load and higher industrial customer usage in the eastern portion of PacifiCorp’s service territory, partially offset by lower residential and irrigation customer usage. The decrease in wholesale and other revenue was due to lower REC revenue of $14 million, partially offset by higher average wholesale prices of $9 million.

Operating income increased $10 million for the third quarter of 2013 compared to 2012 due to the higher operating revenue, partially offset by higher energy costs of $40 million, higher operating expense of $12 million and higher depreciation and amortization of $9 million due to higher plant in-service. Energy costs increased due to a higher average cost of purchased electricity, higher natural gas volumes and lower net deferrals of incurred power costs, partially offset by a lower average cost of natural gas and lower purchased electricity volumes. Operating expense increased primarily due to charges related to certain fire and other damage claims and higher property taxes.

Operating revenue increased $174 million for the first nine months of 2013 compared to 2012 due to higher retail revenue of $225 million, partially offset by a decrease in wholesale and other revenue of $51 million. The increase in retail revenue was due to higher prices approved by regulators of $183 million and higher retail customer loads of $42 million. Customer load increased 1.7% due to the impacts of hotter weather in the third quarter of 2013 and colder weather in the first quarter of 2013 on residential and commercial customer load, higher industrial customer usage primarily in the eastern portion of PacifiCorp's service territory, an increase in the average number of residential customers and higher commercial customer usage, partially offset by lower residential customer usage. The decrease in wholesale and other revenue was due to lower REC revenue of $60 million and lower wholesale volumes of $28 million, partially offset by higher average wholesale prices of $35 million.

28

Operating income increased $88 million for the first nine months of 2013 compared to 2012 due to the higher operating revenue and lower operating expense of $17 million, partially offset by higher energy costs of $73 million and higher depreciation and amortization of $30 million due primarily to higher plant in-service and accelerated depreciation rates for Oregon's share of the Carbon coal-fueled generating facility ("Carbon Facility") expected to be retired in 2015. Energy costs increased due to a higher average cost of purchased electricity, higher coal-fueled generation costs due to higher volumes and unit costs, reduced electricity swap settlement gains and lower net deferrals of incurred power costs, partially offset by a lower average cost of natural gas and lower purchased electricity volumes. Operating expense decreased due to lower charges for certain litigation, fire and other damage claims and lower maintenance expense, partially offset by higher property taxes.

MidAmerican Funding

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

	Third Quarter											First Nine Months
	2013			2012			Change					2013		2012		Change
Operating revenue:
Regulated electric	$	512		$	511		$	1		—	%	$	1,338	$	1,295	$	43		3	%
Regulated natural gas	98			87			11			13		555		441		114			26
Nonregulated and other	218			230			(12		)	(5	)	615		675		(60		)	(9	)
Total operating revenue	$	828		$	828		$	—		—		$	2,508	$	2,411	$	97		4
Operating income:
Regulated electric	$	130		$	129		$	1		1	%	$	211	$	243	$	(32	)	(13	)%
Regulated natural gas	(6		)	(3		)	(3		)	(100	)	43		28		15			54
Nonregulated and other	6			13			(7		)	(54	)	25		40		(15		)	(38	)
Total operating income	$	130		$	139		$	(9	)	(6	)	$	279	$	311	$	(32	)	(10	)

Regulated electric operating revenue increased $1 million for the third quarter of 2013 compared to 2012 due to higher retail revenue of $5 million, partially offset by lower wholesale and other revenue of $4 million. Retail revenue increased due to higher interim rates in Iowa totaling $6 million, partially offset by a 2.8% decrease in customer load. Customer load decreased due to cooler temperatures in 2013 compared to 2012, partially offset by higher non-weather related usage and customer growth. Wholesale and other revenue decreased due to lower prices.

Regulated electric operating income increased $1 million for the third quarter of 2013 compared to 2012 due to the higher operating revenue and lower depreciation of $9 million, partially offset by higher energy costs of $9 million. Energy costs increased due to higher coal transportation costs from new agreements effective in 2013, increased purchased electricity on higher volumes and unit costs, and a higher average cost of natural gas, partially offset by lower thermal generation. Depreciation and amortization decreased due to the impact of depreciation rate changes of $7 million and revenue sharing in 2012 of $6 million, partially offset by wind-powered generating facilities placed in-service in late 2012.

Regulated natural gas operating revenue increased $11 million for the third quarter of 2013 compared to 2012 due to an increase in recoveries through adjustment clauses from a higher average per-unit cost of gas sold of $8 million and higher wholesale volumes of $4 million. Regulated natural gas operating income decreased $3 million for 2013 compared to 2012 due to higher operating expense.

Nonregulated and other operating revenue decreased $12 million for the third quarter of 2013 compared to 2012 due to lower electricity volumes and prices and lower natural gas volumes, partially offset by higher natural gas prices. Nonregulated and other operating income decreased $7 million for 2013 compared to 2012 due to lower electric margins.

Regulated electric operating revenue increased $43 million for the first nine months of 2013 compared to 2012 due to higher retail revenue of $46 million, partially offset by lower wholesale and other revenue of $3 million. Retail revenue increased due to new adjustment clauses in Iowa and Illinois totaling $27 million, an increase in customer load of 0.6% and higher interim rates in Iowa totaling $6 million. Customer load increased due to customer growth and higher non-weather related usage, partially offset by the impacts of weather. Wholesale and other revenue decreased due to lower prices.

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Regulated electric operating income decreased $32 million for the first nine months of 2013 compared to 2012 as the higher operating revenue was more than offset by higher energy costs of $37 million, higher operating expense of $30 million and higher depreciation and amortization of $9 million. Energy costs increased due to higher coal transportation costs from new agreements effective in 2013, increased purchased electricity on higher volumes and unit costs and a higher average cost of natural gas, partially offset by lower thermal generation. Operating expense increased due to higher maintenance costs of $22 million primarily related to the expanded scope of work for the Louisa Generating Station outage and storm restoration costs. Depreciation and amortization increased as a result of wind-powered generating facilities placed in-service in late 2012, partially offset by the impact of revenue sharing in 2012 of $11 million.

Regulated natural gas operating revenue increased $114 million for the first nine months of 2013 compared to 2012 due an increase in recoveries through adjustment clauses from a higher average per-unit cost of gas sold of $56 million and higher volumes of $55 million. Heating degree days increased in 2013 compared to 2012 due to unseasonably warm winter and spring temperatures in 2012. Regulated natural gas operating income increased $15 million for the first nine months of 2013 compared to 2012 due to the higher volumes from the colder temperatures in 2013, partially offset by higher operating expense of $4 million.

Nonregulated and other operating revenue decreased $60 million for the first nine months of 2013 compared to 2012 due to lower electricity volumes and prices, partially offset by higher natural gas prices and volumes. Nonregulated and other operating income decreased $15 million for the first nine months of 2013 compared to 2012 due to lower electric margins.

MidAmerican Energy Pipeline Group

Operating revenue decreased $9 million for the third quarter of 2013 compared to 2012 due to contract expirations and lower storage and transportation revenue due primarily to lower spreads. Operating income increased $3 million for the third quarter of 2013 compared to 2012 as the lower operating revenue was more than offset by lower operating expense and lower depreciation and amortization expense at Kern River.

Operating revenue decreased $13 million for the first nine months of 2013 compared to 2012 due to lower operating revenue at Kern River of $16 million primarily from contract expirations and $3 million of higher operating revenue at Northern Natural Gas due to an increase in gas sales of $6 million and transportation revenue of $5 million, both on higher volumes, partially offset by lower storage revenue. Operating income decreased $13 million for the first nine months of 2013 compared to 2012 due to the lower operating revenue and higher cost of gas sold, partially offset by lower operating expense.

Northern Powergrid Holdings

Operating revenue increased $3 million for the third quarter of 2013 compared to 2012 due to higher distribution revenue of $4 million and higher contracting revenue of $4 million, partially offset by the stronger United States dollar totaling $3 million. Distribution revenue increased due to higher tariff rates of $23 million, partially offset by an unfavorable movement in regulatory provisions of $14 million and lower units distributed of $6 million. Operating income decreased $6 million for the third quarter of 2013 compared to 2012 as the higher distribution revenue was more than offset by the write-off of hydrocarbon well exploration costs of $6 million, higher pension costs of $3 million and the stronger United States dollar totaling $2 million.

Operating revenue increased $49 million for the first nine months of 2013 compared to 2012 due to higher distribution revenue of $59 million and higher contracting revenue of $10 million, partially offset by the stronger United States dollar of $15 million. Distribution revenue increased due to higher tariff rates of $58 million and a net favorable movement in regulatory provisions of $14 million, partially offset by lower units distributed of $12 million. Operating income increased $18 million for the first nine months of 2013 compared to 2012 due to the higher distribution revenue, partially offset by higher distribution operating expense of $11 million, the stronger United States dollar totaling $9 million, higher pension costs of $9 million, the write-off of hydrocarbon well exploration costs of $6 million and higher depreciation of $5 million.

MidAmerican Renewables

Operating revenue increased $65 million for the third quarter of 2013 compared to 2012 due to an increase from the Topaz Project of $33 million, which began generating revenue during the first quarter of 2013, an increase from the Pinyon Pines Projects of $21 million, which were placed in-service during the fourth quarter of 2012, and higher revenue at the Bishop Hill Project of $15 million, primarily from a favorable change in the fair value of the derivative contract. Operating income increased $47 million for 2013 compared to 2012 due to the higher operating revenue, partially offset by higher depreciation of $11 million and higher operating expense of $6 million.

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Operating revenue increased $134 million for the first nine months of 2013 compared to 2012 due to an increase from the Pinyon Pines Projects of $69 million, an increase from the Topaz Project of $51 million and higher revenue at the Bishop Hill Project of $18 million due to a favorable change in the fair value of the derivative contract and it being placed in-service during the fourth quarter of 2012. Operating income increased $85 million during the first nine months of 2013 compared to 2012 due to the higher operating revenue, partially offset by higher depreciation of $29 million and higher operating expense of $19 million.

HomeServices

Operating revenue increased $183 million for the third quarter of 2013 compared to 2012 due to an increase from existing businesses totaling $71 million, reflecting a 13% increase in closed brokerage units and a 7% increase in average home sale prices, and $112 million of revenue from acquired businesses. Operating income increased $28 million for the third quarter of 2013 compared to 2012 due to the higher operating revenue, partially offset by higher commissions at both existing and acquired businesses and higher operating expense and depreciation at acquired businesses.

Operating revenue increased $370 million for the first nine months of 2013 compared to 2012 due to an increase from existing businesses totaling $166 million, reflecting a 13% increase in closed brokerage units and an 8% increase in average home sale prices, and $204 million of revenue from acquired businesses. Operating income increased $68 million for the first nine months of 2013 compared to 2012 due to the higher operating revenue, partially offset by higher commissions at both existing and acquired businesses and higher operating expense and depreciation at acquired businesses.

MEHC and Other

Operating revenue increased $12 million for the third quarter of 2013 compared to 2012 from other corporate entities acquired in 2013. Higher operating costs due to higher acquisition and other costs resulted in an increase in the operating loss of $12 million for the third quarter of 2013 compared to 2012.

Operating revenue increased $14 million for the first nine months of 2013 compared to 2012 from other corporate entities acquired in 2013. Higher operating costs due to higher acquisition and other costs resulted in an increase in the operating loss of $23 million for the first nine months of 2013 compared to 2012.

Consolidated Other Income and Expense Items

Interest Expense

Interest expense is summarized as follows (in millions):

	Third Quarter									First Nine Months
	2013		2012		Change					2013		2012		Change
Subsidiary debt	$	233	$	220	$	13		6	%	$	672	$	640	$	32		5	%
MEHC senior debt and other	76		78		(2		)	(3	)	221		244		(23		)	(9	)
Total interest expense	$	309	$	298	$	11		4		$	893	$	884	$	9		1

Interest expense increased $11 million for the third quarter of 2013 compared to 2012 and $9 million for the first nine months of 2013 compared to 2012 due to debt issuances at PacifiCorp ($300 million in June 2013), MidAmerican Funding ($950 million in September 2013), Northern Natural Gas ($250 million in August 2012) and MidAmerican Renewables ($120 million in August 2012, $250 million in April 2013 and $1.0 billion in June 2013) and acquired debt at MidAmerican Renewables ($502 million in November 2012), partially offset by scheduled maturities and principal payments at MEHC and its subsidiaries.

Capitalized Interest

Capitalized interest increased $3 million for the third quarter of 2013 compared to 2012 and $21 million for the first nine months of 2013 compared to 2012 due to higher construction in progress balances related to the Solar Star Projects and the Topaz Project for the first nine months, partially offset by lower construction in progress balances at the Bishop Hill Project, which was placed in-service in the fourth quarter of 2012.

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Allowance For Equity Funds

Allowance for equity funds decreased $3 million for the third quarter of 2013 compared to 2012 due to lower equity AFUDC at MidAmerican Energy and PacifiCorp resulting from lower construction work-in-progress balances.

Other, Net

Other, net increased $15 million for the first nine months of 2013 compared to 2012 due to benefits from a contract restructuring at Northern Natural Gas of $12 million, higher returns from company-owned life insurance and a favorable change in the fair value of the Pinyon Pines interest rate swap.

Income Tax Expense

Income tax expense increased $2 million for the third quarter of 2013 compared to 2012 and the effective tax rates were 9% for both the third quarter of 2013 and 2012. The effective tax rates remained unchanged as higher deferred income tax benefits of $16 million from additional reductions in the United Kingdom corporate income tax rate and higher recognized production tax credits of $14 million were offset by changes in uncertain income tax positions.

Income tax expense increased $84 million for the first nine months of 2013 compared to 2012 and the effective tax rates were 18% for the first nine months of 2013 and 15% for the first nine months of 2012. The increase in the effective tax rate was due to benefits recorded in 2012 primarily related to the method change for repairs deductions and changes in uncertain income tax positions, partially offset by higher recognized production tax credits of $22 million and higher deferred income tax benefits of $16 million from additional reductions in the United Kingdom corporate income tax rate.

In the third quarter of 2013, the Company recognized $54 million of deferred income tax benefits upon the enactment of a reduction in the United Kingdom corporate income tax rate from 23% to 21% effective April 1, 2014, and a further reduction to 20% effective April 1, 2015. In the third quarter of 2012, the Company recognized $38 million of deferred income tax benefits upon the enactment of a reduction in the United Kingdom corporate income tax rate from 25% to 24% effective April 1, 2012, and a further reduction to 23% effective April 1, 2013.

Equity Income

Equity income is summarized as follows (in millions):

	Third Quarter									First Nine Months
	2013		2012		Change					2013			2012			Change
Equity income:
ETT	$	9	$	9	$	—		—	%	$	33		$	25		$	8		32	%
HomeServices Mortgage	2		6		(4		)	(67	)	10			16			(6		)	(38	)
Agua Caliente	13		12		1			8		25			21			4			19
CE Generation	2		1		1			100		(4		)	(5		)	1			20
Other	2		2		—			—		4			4			—			—
Total equity income	$	28	$	30	$	(2	)	(7	)	$	68		$	61		$	7		11

Equity income decreased $2 million for the third quarter of 2013 compared to 2012 due to lower earnings at HomeServices' mortgage joint venture primarily due to lower refinancing activity.

Equity income increased $7 million for the first nine months of 2013 compared to 2012 due to higher earnings at ETT from continued investment and additional plant placed in-service and higher earnings at Agua Caliente due to additional capacity placed in-service, partially offset by lower earnings at HomeServices' mortgage joint venture primarily due to lower refinancing activity.

Net Income Attributable To Noncontrolling Interests

Net income attributable to noncontrolling interests increased $5 million for the third quarter of 2013 compared to 2012 and $12 million for the first nine months of 2013 compared to 2012 due to HomeServices' acquisition of HSF Affiliates LLC in the fourth quarter of 2012.

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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 September 30, 2013, the Company's total net liquidity was $6.508 billion as follows (in millions):

										Northern
							MidAmerican			Powergrid
	MEHC			PacifiCorp			Funding			Holdings			Other			Total
Cash and cash equivalents	$	262		$	157		$	1,142		$	5		$	316		$	1,882
Credit facilities(1)	600			1,200			609			267			665			3,341
Less:
Short-term debt	—			—			—			(24		)	(134		)	(158		)
Tax-exempt bond support and letters of credit	(41		)	(321		)	(195		)	—			—			(557		)
Net credit facilities	559			879			414			243			531			2,626
Net liquidity before Berkshire Equity Commitment	821			$	1,036		$	1,556		$	248		$	847		4,508
Berkshire Equity Commitment(2)	2,000															2,000
Total net liquidity	$	2,821														$	6,508
Credit facilities:
Maturity date	2017			2017, 2018			2014, 2018			2017			2013-2018
Largest single bank commitment as a % of total credit facilities	8		%	7		%	7		%	39		%	17		%

(1) For further discussion regarding the Company's credit facilities, refer to Note 6 of Notes to Consolidated Financial Statements in Item 1 of this Form 10-Q. Includes uncommitted credit facilities totaling $24 million at Northern Powergrid Holdings, which was drawn as of September 30, 2013.

(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.

The above table does not include unused 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 nine-month period endedSeptember 30, 2013 was $3.683 billion, effectively unchanged from $3.682 billion for the nine-month period endedSeptember 30, 2012. Improved operating results, lower domestic pension plan contributions and other changes in working capital were substantially offset by lower income tax receipts due to lower bonus depreciation benefits, partially offset by higher investment tax credits, and higher interest payments.

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Investing Activities

Net cash flows from investing activities for the nine-month periods endedSeptember 30, 2013 and 2012 were $(3.621) billion and $(2.817) billion, respectively. The change was primarily due to higher capital expenditures, changes in restricted cash and investments related to proceeds from the issuance of long-term debt in 2013 at Solar Star Funding, LLC that is restricted for use in the construction of the Solar Star Projects and acquisitions at HomeServices, partially offset by the acquisition in 2012 of Topaz and Bishop Hill and the equity contribution in 2012 to acquire a 49% interest in Agua Caliente.

Capital Expenditures

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

	2013		2012
Capital expenditures:
PacifiCorp	$	752	$	1,037
MidAmerican Funding	599		445
MidAmerican Energy Pipeline Group	99		112
Northern Powergrid Holdings	487		310
MidAmerican Renewables	926		439
Other	22		6
Total capital expenditures	$	2,885	$	2,349

The Company's capital expenditures consisted mainly of the following for the nine-month periods endedSeptember 30:

2013:

• Transmission system investments totaling $203 million, including construction costs for PacifiCorp's 170-mile single-circuit 345-kV Sigurd-Red Butte ("Sigurd-Red Butte") transmission line expected to be placed in-service in 2015 and the 100-mile high-voltage Mona-Oquirrh ("Mona-Oquirrh") transmission line that was placed in-service in May 2013.

• Emissions control equipment on existing generating facilities totaling $169 million for installation or upgrade of sulfur dioxide scrubbers, low nitrogen oxide burners and particulate matter control systems.

• The construction of MidAmerican Energy's 1,050 MW (nominal ratings) of wind-powered generating facilities totaling $158 million, which are expected to be placed in-service in 2013, 2014 and 2015.

• The construction of PacifiCorp's Lake Side 2 645-MW combined-cycle combustion turbine natural gas-fueled generating facility ("Lake Side 2") totaling $116 million, which is expected to be placed in-service in 2014.

• Distribution, generation, mining and other infrastructure totaling $705 million at the Utilities and ongoing infrastructure needed at Northern Powergrid Holdings totaling $487 million.

• Investments at MidAmerican Renewables totaling $926 million related mainly to the Topaz Project of $499 million and the Solar Star Projects of $422 million.

2012:

• Transmission system investments totaling $262 million, including construction costs for PacifiCorp's Mona-Oquirrh transmission line.

• Emissions control equipment on existing generating facilities totaling $196 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 totaling $177 million.

• The construction of MidAmerican Energy's 407 MW of wind-powered generating facilities totaling $121 million, excluding $306 million for costs for which payments are due in December 2015.

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• Distribution, generation, mining and other infrastructure totaling $726 million at the Utilities and ongoing infrastructure needed at Northern Powergrid Holdings totaling $310 million.

• Investments at MidAmerican Renewables totaling $439 million related mainly to the Topaz Project of $313 million and the Bishop Hill Project of $125 million.

Financing Activities

Net cash flows from financing activities for the nine-month period endedSeptember 30, 2013 was $1.047 billion. Sources of cash totaled $2.496 billion related to proceeds from subsidiary debt issuances. Uses of cash consisted of $1.449 billion and consisted mainly of net repayments of short-term debt totaling $919 million and repayments of subsidiary debt totaling $437 million.

In September 2013, MidAmerican Energy issued $350 million of its 2.40% First Mortgage Bonds due March 2019, $250 million of its 3.70% First Mortgage Bonds due September 2023 and $350 million of its 4.80% First Mortgage Bonds due September 2043 pursuant to its indenture dated September 9, 2013, as supplemented and amended. The net proceeds will be used for the repayment of $669 million of long-term debt maturing December 31, 2013, and for general corporate purposes.

In June 2013, Solar Star Funding issued $1.0 billion of its 5.375% Series A Senior Secured Notes. The principal of the notes amortizes beginning June 2016 with a final maturity in June 2035. The net proceeds are being used to fund the costs related to the development, construction and financing of the Solar Star Projects. Until amounts are used to fund the costs of the Solar Star Projects, unused amounts will be invested or, in certain circumstances, loaned to MEHC. As of September 30, 2013, no amounts were loaned to MEHC.

In June 2013, PacifiCorp issued $300 million of its 2.95% First Mortgage Bonds due June 2023. The net proceeds were used to fund capital expenditures and for general corporate purposes.

In April 2013, Topaz issued $250 million of the 4.875% Series B Senior Secured Notes. The principal of the notes amortizes beginning September 2015 with a final maturity in September 2039. The net proceeds are being used to fund the costs related to the development, construction and financing of the Topaz Project. Until amounts are used to fund the costs of the Topaz Project, unused amounts will be invested or, in certain circumstances, loaned to MEHC. As of September 30, 2013, no amounts were loaned to MEHC.

Net cash flows from financing activities for the nine-month period endedSeptember 30, 2012 was $704 million. Sources of cash totaled $2.199 billion related to proceeds from subsidiary debt issuances. Uses of cash totaled $1.495 billion and consisted mainly of net repayments of short-term debt totaling $715 million, repayments of subsidiary debt totaling $450 million and the repayment of MEHC senior and subordinated debt totaling $272 million.

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 and non-recourse project finance market, among other items. 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.

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NV Energy, Inc. Acquisition

On May 29, 2013, MEHC entered into an Agreement and Plan of Merger (the "Merger Agreement") whereby MEHC will acquire NV Energy and NV Energy will become an indirect wholly owned subsidiary of MEHC. The Merger Agreement entitles NV Energy's common shareholders to receive $23.75 in cash for each share of NV Energy common stock issued and outstanding immediately prior to the close of the acquisition. The purchase price is estimated at $5.6 billion, subject to final determination of the outstanding shares at closing. MEHC's shareholders have committed to provide sufficient capital to fund the entire purchase price of NV Energy. MEHC expects to fund the acquisition by issuing $1.0 billion of common equity to its existing shareholders, issuing $2.6 billion of junior subordinated debentures to Berkshire Hathaway and its subsidiaries, and incurring $2.0 billion of MEHC senior debt.

NV Energy and its utility subsidiaries have $4.4 billion of debt subject to mandatory redemption requirements at 101% of par in the event the acquisition closes. Given the debt is currently trading at prices in excess of 101% of par, it is unlikely the debt holders would exercise their redemption rights. Additionally, NV Energy's term loan and its utility subsidiaries' revolving credit facilities have events of default that would be triggered by the closing of the acquisition. It is expected that NV Energy and its utility subsidiaries will obtain waivers of these events of default prior to closing.

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 environmental and other rules and regulations; impacts to customers' rates; 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; commodity prices; 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, for the year ended December 31, 2013 are as follows (in millions):

	2013
Forecasted capital expenditures:
PacifiCorp	$	1,081
MidAmerican Funding	1,090
MidAmerican Energy Pipeline Group	188
Northern Powergrid Holdings	675
MidAmerican Renewables	1,326
Other	36
Total	$	4,396

The Utilities anticipate costs for transmission projects will total $314 million for 2013 including the following estimated costs:

• $104 million for PacifiCorp's Sigurd-Red Butte transmission line as part of the Energy Gateway Transmission Expansion Program. The Sigurd-Red Butte project is expected to be placed in-service in 2015.

• $54 million for PacifiCorp's Mona-Oquirrh transmission line as part of the Energy Gateway Transmission Expansion Program. The project was placed in-service in May 2013.

• $41 million for other segments associated with PacifiCorp's Energy Gateway Transmission Expansion Program that are expected to be placed in-service over the next several years, depending on siting, permitting and construction schedules.

• $25 million for MidAmerican Energy's Multi-Value Projects ("MVPs") approved by the Midcontinent Independent System Operator, Inc. ("MISO") for the construction of 245 miles of 345 kV transmission line located in Iowa and Illinois. MidAmerican Energy has entered into a contract totaling $342 million related to its MVPs approved by MISO with minimum payments of $17 million in 2013, $140 million in 2014, $149 million in 2015 and $36 million in 2016.

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The Utilities anticipate costs for emissions control equipment will total $254 million for 2013, 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 a number of units at several of the Utilities coal-fueled generating facilities, including Hunter Unit 1, Jim Bridger Units 3 and 4, George Neal Energy Center Units 3 and 4 and Ottumwa Generating Station.

PacifiCorp anticipates costs for the construction of the Lake Side 2 natural gas-fueled generating facility, which is expected to be placed in-service in 2014, will total $157 million for 2013.

MidAmerican Energy anticipates costs for the construction of 1,050 MW (nominal ratings) of wind-powered generating facilities, which are expected to be placed in-service in 2013, 2014 and 2015, will total $391 million for 2013. In August 2013, the IUB approved a settlement agreement between MidAmerican Energy and the Iowa Office of Consumer Advocate for ratemaking principles related to the proposed wind-powered generating facilities. The settlement agreement establishes a cost cap of $1.9 billion, including AFUDC, for the construction of 1,050 MW (nominal ratings) of wind-powered generating facilities and provides for a fixed rate of return on equity of 11.625% over the proposed 30-year useful lives of those facilities in any future Iowa rate proceeding. The cost cap ensures that as long as total costs are below the cap, the investment will be deemed prudent in any future Iowa rate proceeding. Until such time as these generation assets are reflected in rates, and ceasing thereafter, MidAmerican Energy proposes reductions in the energy adjustment clause recoveries proposed in its current Iowa electric rate request of $3 million in 2015, $7 million in 2016 and $10 million for each calendar year thereafter, conditioned upon MidAmerican Energy having completed at least 350 MW (nominal ratings) of wind-powered generating facilities pursuant to the settlement agreement. MidAmerican Energy has entered into contracts totaling $1.3 billion related to these projects. Minimum payments are expected to be $343 million in 2013, $522 million in 2014 and $447 million in 2015.

Topaz has spent $1.059 billion for construction of the Topaz Project from inception through September 30, 2013, and expects to spend an additional $151 million for the remainder of 2013, $579 million for 2014 and $352 million for 2015. The project is expected to cost $2.44 billion, including all interest costs during construction and the initial costs to acquire the project. The project will be comprised of 22 blocks of solar panels with a nominal facilities capacity of 586 MW. As of September 30, 2013, 241 MW of the Topaz Project had been completed and is delivering energy under the power purchase agreement. Construction and commissioning are ahead of schedule and Topaz expects to place an additional 40 MW in-service in 2013, 252 MW in-service in 2014 and 53 MW in-service in 2015. As of September 30, 2013, the project was 60% constructed compared to the engineering, procurement and construction schedule of 42%, which includes 5.04 million solar panels out of an expected total of 8.39 million installed. The project is being constructed pursuant to a fixed-price, date certain, turn-key engineering, procurement and construction contract with a subsidiary of First Solar.

Subsidiaries of Solar Star Funding, LLC have spent $489 million for construction of the Solar Star Projects from inception through September 30, 2013, and expect to spend an additional $248 million for the remainder of 2013, $1.145 billion for 2014 and $713 million for 2015. The projects are expected to cost $2.75 billion, including all interest costs during construction and the initial costs to acquire the projects. The projects will be comprised of 13 blocks of solar panels with a capacity of 579 MW. As of September 30, 2013, the projects were 14% constructed compared to the engineering, procurement and construction schedule of 17%. Construction is currently behind schedule due to replacement of improperly welded panel tracking equipment. The projects are expected to be back on schedule in the first quarter of 2014. The projects were synchronized to the grid on October 1, 2013 as scheduled, and are delivering 5 MW. The projects expect to place 19 MW in-service in 2013, 335 MW in-service in 2014 and 225 MW in-service in 2015. The projects are being constructed pursuant to fixed-price, date certain, turn-key engineering, procurement and construction contracts with a subsidiary of SunPower Corporation.

Capital expenditures related to operating projects are expected to total $1.8 billion in 2013, and consist of routine expenditures for distribution, generation, mining and other infrastructure needed to serve existing and expected demand.

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Equity Investments

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. The Agua Caliente Project is expected to cost approximately $1.7 billion and will be comprised of 12 blocks of solar panels with a nominal facilities capacity of 315 MW. The Agua Caliente Project has placed 304 MW in-service as of September 30, 2013, and expects to place an additional 11 MW in-service in the last quarter of 2013. As of September 30, 2013, the Agua Caliente Project was 98% constructed compared to the engineering, procurement and construction schedule of 90%, which includes 4.79 million solar panels out of an expected total of 4.94 million installed. The project is being constructed pursuant to a fixed price, date certain, turn-key engineering, procurement and construction contract with a subsidiary of First Solar. Construction costs are expected to be funded with equity contributions from MEHC and NRG Energy, Inc. and proceeds from a $967 million secured loan maturing in 2037 from an agency of the United States government as part of the United States Department of Energy loan guarantee program. Funding requests are submitted on a monthly basis and the approved loans accrue interest at a fixed rate based on the current average yield of comparable maturity United States Treasury rates plus a spread of 0.375%.

Contractual Obligations

As of September 30, 2013, 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, 2012 other than the 2013 debt issuances and capital expenditure matters previously discussed.

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, 2012, and new regulatory matters occurring in 2013.

PacifiCorp

Utah

In March 2013, PacifiCorp filed its annual Energy Balancing Account with the UPSC requesting recovery of $17 million in deferred net power costs for the period January 1, 2012 through December 31, 2012 over a two-year period. In September 2013, PacifiCorp filed a stipulation with the UPSC providing for recovery of $15 million over a two-year period. In October 2013, the UPSC approved the stipulation with the new rates effective November 2013.

In March 2013, PacifiCorp filed with the UPSC to return $3 million to customers through the REC balancing account. In May 2013, the UPSC issued an order approving the new rates as filed effective June 2013 on an interim basis. In August 2013, the UPSC issued a final order approving the interim rates as final.

Oregon

In March 2013, PacifiCorp filed a general rate case with the OPUC requesting an annual increase of $56 million, or an average price increase of 5%. The request was reduced to $45 million, or an average price increase of 4%, as a result of the OPUC's approval of a separate tariff rider for the Mona-Oquirrh transmission line that was effective June 1, 2013. PacifiCorp's general rate case filing also included a request for a separate tariff rider for Lake Side 2. In July 2013, a multi-party stipulation was filed with the OPUC resolving all issues in the general rate case. The stipulation provides for an annual increase of $24 million, or an average price increase of 2%, which includes the impact of the revised depreciation rates. Refer to "Depreciation Rate Study" for discussion of the depreciation rate impacts. The stipulation also provides for the implementation of a separate tariff rider for Lake Side 2 when placed into service in mid-2014 with the final costs subject to a prudence determination. In addition, the stipulation specifies that January 2016 is the earliest effective date that PacifiCorp could seek an increase to customers' base rates through a general rate case. If the stipulation is approved by the OPUC, the new rates will be effective January 2014. The OPUC is expected to issue a decision no later than December 2013.

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Wyoming

In March 2013, PacifiCorp filed its annual Energy Cost Adjustment Mechanism ("ECAM") and REC and Sulfur Dioxide Revenue Adjustment Mechanism ("RRA") applications with the WPSC. The ECAM filing requested recovery of $18 million in deferred net power costs for the period January 1, 2012 to December 31, 2012 to be recovered over three years at $6 million per year pursuant to the settlement agreement in the 2012 ECAM case, which would result in a 1% increase in rates. The RRA filing requested a $15 million reduction in the RRA surcredit, or an increase in rates of 2%, to be recovered over one year. In May 2013, the WPSC approved the requested adjustments to rates on an interim basis subject to further investigation and hearing. In August 2013, PacifiCorp filed a stipulation with the WPSC in which the parties agreed to recovery of $17 million in deferred net power costs over three years and a $15 million reduction in the RRA surcredit. In September 2013, the WPSC approved the stipulation with the new rates effective November 2013.

Washington

In December 2012, PacifiCorp filed for judicial review of the WUTC's August and November 2012 orders regarding proceeds from the sales of RECs on or after January 1, 2009. In February 2013, PacifiCorp, WUTC staff and intervening parties submitted a joint filing with the WUTC proposing a tracking mechanism for REC sales revenues. In March 2013, the WUTC issued a notice stating that the February 2013 joint filing failed to comply with the WUTC's orders, primarily requiring PacifiCorp and other parties to clarify the period over which amortization of historical REC revenues (revenues from January 1, 2009 through April 2, 2011) would occur. In March 2013, PacifiCorp filed a response to the WUTC notice requesting that the WUTC not require amortization of historical REC revenues until after resolution of the pending judicial review of the WUTC's orders. WUTC staff and intervening parties submitted a joint response to the WUTC notice requesting the amortization of historical REC revenues begin on May 1, 2013 and be distributed as a one-time credit or amortized over one year. No action has been taken with regard to the parties' responses to the WUTC's notice. PacifiCorp is seeking judicial review of the WUTC's orders and in October 2013, filed its opening brief with the Washington State Court of Appeals.

In January 2013, PacifiCorp filed a general rate case with the WUTC requesting an annual increase of $43 million, or an average price increase of 14%. The requested increase includes the impacts associated with investments in PacifiCorp's facilities since the last general rate case filing, projected increases in net power costs and revised depreciation rates. In August 2013, PacifiCorp submitted rebuttal testimony reducing the requested increase to $37 million, or an average price increase of 12%. The WUTC is expected to issue a final decision by December 2013.

Idaho

In February 2013, PacifiCorp filed its annual ECAM application with the IPUC requesting recovery of $16 million of deferred net power costs, of which $9 million will be collected over a one-year period and the remainder collected over a three-year period. In March 2013, the IPUC approved the new rates, which became effective April 2013.

In June 2013, PacifiCorp filed a multi-party stipulation with the IPUC that would increase base rates $2 million effective January 2014 and approve the deferral of any removal costs incurred associated with the retirement of the Carbon Facility and any incremental depreciation expense associated with the revised depreciation rates reflected in the depreciation rate study, with timing of recovery to be determined in a future proceeding. Refer to "Depreciation Rate Study" for discussion of the depreciation rate impacts. In addition, a resource adder to provide a means for recovery of costs associated with Lake Side 2 would be included in the ECAM effective January 2015 for an estimated $5 million annually. This deferral would continue until Lake Side 2 is included in base rates. The stipulation also specifies that January 2016 is the earliest effective date that PacifiCorp could seek an increase to customers' base rates. In October 2013,the IPUC approved the stipulation.

Depreciation Rate Study

In January 2013, PacifiCorp filed applications for depreciation rate changes with the UPSC, the OPUC, the WPSC, the WUTC and the IPUC based on PacifiCorp's most recent depreciation study. In September 2013, the OPUC issued an order approving a multi-party stipulation to implement revised depreciation rates that will result in an annual increase in depreciation expense of $30 million in Oregon. To the extent depreciation rates for other than coal-fueled generating facilities agreed to in PacifiCorp's other state jurisdictions are lower than those approved in the Oregon order, PacifiCorp will be required to defer any excess revenue collected from Oregon customers until such time that customer rates are adjusted in a future proceeding. In Oregon, PacifiCorp is currently recovering costs associated with the Carbon Facility through 2015. In August and September 2013, PacifiCorp filed all-party stipulations with the UPSC, the WPSC and the IPUC that would result in an annual increase in depreciation expense of $10 million in Utah, $10 million in Wyoming and $2 million in Idaho, including deferrals related to the Carbon Facility. In September and October 2013, the UPSC and WPSC approved the stipulation.

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MidAmerican Energy

In May 2013, MidAmerican Energy filed a request with the IUB for an increase in Iowa retail electric rates. MidAmerican Energy began collecting interim rates in the third quarter of 2013 as approved by the IUB. The interim rates are being collected subject to refund pending a final decision by the IUB on MidAmerican Energy's requested rate increase. If approved, the proposed rate increase would be phased in over approximately three years and would result in equal annualized increases in revenues of $45 million, or 3.6%, above current rates, effective with the start of interim rates and again on January 1, 2015 and 2016, for a total annualized increase of $135 million when fully implemented. In addition to the request for an increase in base rates, the filing contains a request for the creation of two new adjustment clauses to be effective with the implementation of final approved rates. One clause would be for the recovery of changes in certain energy production related costs such as fuel, fuel transportation and the impacts of the production tax credit. The second clause would be for recovery of certain electric transmission charges. The filing also proposes a revenue sharing mechanism similar to that in place at MidAmerican Energy for a number of years that shares with customers revenues related to equity returns above 11.5%. A final decision by the IUB on MidAmerican Energy's request is expected by the end of the first quarter of 2014.

Since 2010, MidAmerican Energy has been investigating the possible development of a nuclear generation facility. MidAmerican Energy has completed its investigation and concluded that it is currently premature to pursue any additional site work on a nuclear facility. MidAmerican Energy submitted its assessment to the IUB in June 2013. In support of such an investigation, Iowa law provided for recovery of the cost of this effort from MidAmerican Energy's Iowa customers over three years beginning in October 2010, subject to the review of the IUB.

Kern River

In December 2009, the FERC issued an order establishing revised rates for the period of Kern River's initial long-term contracts ("Period One rates") and required that rates be established based on a levelized rate design for eligible customers that elect to take service following the expiration of their initial contracts (“Period Two rates"). The FERC set all other issues related to Period Two rates for hearing. In November 2010, the FERC issued an order that denied all requests for rehearing related to Period One rates from the FERC's December 2009 order and established that the Company is entitled to base its Period Two rates on a 100% equity capital structure.

In July 2011, the FERC issued an order requiring, among other things, that Period Two rates be based on a return on equity of 11.55% and a levelization period that coincides with a contract length of 10 or 15 years. The FERC also determined that capital expenditures associated with compressor engines and general plant replacements cannot be incorporated into Period Two rates at this time. The Company, as well as others, requested rehearing and clarification of the FERC's July 2011 order. The Company filed in compliance with the FERC's order in August 2011 and, following an order on compliance, again in September 2011. In late September 2011, the FERC issued a second order on compliance, accepting the Company's filing. In February 2013, the FERC issued an order that denied the requests for rehearing regarding its previous orders on Period Two rates. In March 2013, the Company requested clarification, or in the alternative a rehearing, on recovery of plant replacements. In October 2013, the FERC granted in part, and denied in part, Kern River's request. Clarification was granted and the FERC withdrew language from a prior order, which arguably barred Kern River's ability to seek recovery of deferred depreciation in a future rate case. Kern River's request for clarification was denied in regard to the FERC ruling now on Kern River’s recovery of deferred depreciation in a future rate case. The FERC will address the issue when the next rate case is filed.

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. 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, 2012.

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Clean Air Act Regulations

The Clean Air Act is a federal law administered by the EPA that provides a framework for protecting and improving the nation's air quality and controlling sources of air emissions. The implementation of new standards is generally outlined in State Implementation Plans ("SIPs"), which are a collection of regulations, programs and policies to be followed. SIPs vary by state and are subject to public hearings and EPA approval. Some states may adopt additional or more stringent requirements than those implemented by the EPA.

As a result of Clean Air Act requirements, the Company anticipates retirement of PacifiCorp's Carbon Facility in early 2015. In anticipation of the April 16, 2015, Mercury and Air Toxics Standards ("MATS") compliance deadline, MidAmerican Energy evaluated each of its coal-fueled generating units for compliance with the MATS emission limits. Due to the MATS compliance costs, MidAmerican Energy plans to retire four coal-fueled generating units by March 31, 2015. These units are Walter Scott, Jr. Energy Center Units 1 and 2 and George Neal Energy Center Units 1 and 2. A fifth unit, Riverside Generating Station, will be limited to natural gas combustion by March 31, 2015. The units being retired produced 2.2 million MWh of electricity, or 7% of MidAmerican Energy's owned generation production, during 2012. These planned retirements are independent of and precede the April 2016 deadline by which these five units are required to stop burning solid fuel arising from the consent decree MidAmerican Energy previously agreed to with the Sierra Club.

National Ambient Air Quality Standards

In June 2010, the EPA finalized a new national ambient air quality standard for sulfur dioxide. Under the new rule, the existing 24-hour and annual standards for sulfur dioxide, which were 140 parts per billion measured over 24 hours and 30 parts per billion measured over an entire year, were replaced with a new one-hour standard of 75 parts per billion. The new rule utilizes a three-year average to determine attainment. The rule utilizes source modeling in addition to the installation of ambient monitors where sulfur dioxide emissions impact populated areas. Attainment designations were due by June 2012; however, due to the lack of sufficient information to make the designations, the EPA extended the deadline for area designations to June 2013. The EPA issued its final designations in July 2013 and determined that a portion of Muscatine County, Iowa was in nonattainment for the one-hour sulfur dioxide standard. MidAmerican Energy's Louisa coal-fueled generating facility is located just outside of Muscatine County, south of the violating monitor. In its final designation, the EPA indicated that it was not yet prepared to conclude that the emissions from the Louisa coal-fueled generating facility contribute to the monitored violation or to other possible violations and that in a subsequent round of designations the EPA will make decisions for areas and sources outside Muscatine County. MidAmerican Energy does not believe a subsequent nonattainment designation will have a material impact on the Louisa coal-fueled generating facility.

Regional Haze

The EPA has initiated a regional haze program intended to improve visibility in designated federally protected areas ("Class I areas"). Some of PacifiCorp's coal-fueled generating facilities in Utah, Wyoming and Arizona are subject to the Clean Air Visibility Rules. In accordance with the federal requirements, states are required to submit State Implementation Plans ("SIP") that address emissions from sources subject to best available retrofit technology ("BART") requirements and demonstrate progress towards achieving natural visibility requirements in Class I areas by 2064.

The state of Utah issued a regional haze SIP requiring the installation of sulfur dioxide, nitrogen oxides and particulate matter controls on Hunter Units 1 and 2, and Huntington Units 1 and 2. In December 2012, the EPA approved the sulfur dioxide portion of the Utah regional haze SIP and disapproved the nitrogen oxides and particulate matter portions. Certain groups have appealed the EPA's approval of the sulfur dioxide portion. The state of Utah and PacifiCorp filed petitions for review of the EPA's final rule on the BART determinations in Utah's regional haze SIP in March 2013. In addition, and separate from the EPA's approval process and related litigation, the Utah Division of Air Quality is undertaking an additional BART analysis for Hunter Units 1 and 2, and Huntington Units 1 and 2, which will be provided to the EPA as a supplement to the existing Utah SIP. It is unknown whether and how this supplemental analysis will impact the EPA's decision regarding the existing SIP.

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The state of Wyoming issued two regional haze SIPs requiring the installation of sulfur dioxide, nitrogen oxides and particulate matter controls on certain PacifiCorp coal-fueled generating facilities in Wyoming. The EPA approved the sulfur dioxide SIP in December 2012, but initially proposed in June 2012 to disapprove portions of the nitrogen oxides and particulate matter SIP and instead issue a federal implementation plan ("FIP"). The EPA withdrew its initial proposed actions on the nitrogen oxides and particulate matter SIP and the proposed FIP, and in June 2013, published a re-proposed rule to disapprove portions of the SIP and instead issue a FIP. The EPA proposed to approve the installation of selective catalytic reduction equipment at Jim Bridger Unit 3 by December 31, 2015; to approve the installation of selective catalytic reduction equipment at Jim Bridger Unit 4 by December 31, 2016; to approve the installation of selective catalytic reduction equipment at Jim Bridger Unit 2 by December 31, 2021; to approve the installation of selective catalytic reduction equipment at Jim Bridger Unit 1 by December 31, 2022; and to approve the installation of selective catalytic reduction equipment and a baghouse at Naughton Unit 3 by December 31, 2014. However, the EPA accepted comments on PacifiCorp's planned conversion of Naughton Unit 3 to natural gas. Until the EPA approves the natural gas conversion, PacifiCorp remains under an obligation to comply with the SIP. The EPA also proposed to reject the SIP for the Wyodak facility, Naughton Units 1 and 2 and Dave Johnston Units 3 and 4; and to require within five years, the installation of selective non-catalytic reduction equipment at the Wyodak facility and Dave Johnston Unit 4, and selective catalytic reduction equipment at Naughton Units 1 and 2 and Dave Johnston Unit 3. The EPA also proposed to require the installation of low-nitrogen oxides burners and overfire air systems at Dave Johnston Units 1 and 2 by July 31, 2018. The EPA held three public hearings in June and July 2013, and the public comment period closed August 26, 2013. The EPA is under a consent decree entered into with environmental groups to take final action on its proposed action by November 2013. In the meantime, certain groups have appealed the EPA's approval of the sulfur dioxide SIP, and PacifiCorp has intervened in that appeal.

The state of Arizona issued a regional haze SIP requiring, among other things, the installation of sulfur dioxide, nitrogen oxides and particulate matter controls on Cholla Unit 4. The EPA approved in part, and disapproved in part, the Arizona SIP and issued a FIP for the disapproved portions. PacifiCorp filed an appeal in the United States Court of Appeals for the Ninth Circuit ("Ninth Circuit") regarding the FIP as it relates to Cholla Unit 4, and the Arizona Department of Environmental Quality and other affected Arizona utilities filed separate appeals of the FIP as it relates to their interests. The Ninth Circuit has not made any decisions in regard to these appeals. In April 2013, the EPA granted in part PacifiCorp's February 2013 petition for reconsideration relating to the compliance methodology for nitrogen oxides at Cholla Unit 4. The EPA plans to publish a notice of proposed rulemaking seeking comment on an alternative compliance methodology for nitrogen oxides at Cholla Unit 4, and PacifiCorp will have an opportunity to submit comments on that methodology.

A case is pending before the United States Court of Appeals for the Tenth Circuit ("Tenth Circuit") with regard to a similar appeal of a FIP issued by the EPA in New Mexico. A three-judge panel of the Tenth Circuit issued a ruling on an appeal of a FIP issued by the EPA rejecting portions of the Oklahoma SIP, denying the state's and utility's challenge. In September 2013, the state and utility filed petitions for review by the full court of the Tenth Circuit's decision in the Oklahoma case. Legal challenges of the EPA's final action on the Utah or Wyoming FIP would be filed in the Tenth Circuit. The United States Court of Appeals for the Eighth Circuit ("Eighth Circuit") recently issued a ruling on an appeal of a FIP issued by the EPA rejecting portions of the North Dakota SIP. The Eighth Circuit denied the state's and utilities' challenge in certain respects, but vacated and remanded a portion of the EPA's action relating to the EPA's refusal to take into consideration any existing pollution control technology in use at the source when it issued its FIP. PacifiCorp has raised similar concerns regarding the existing controls in use at the source to the EPA in the issuance of its Wyoming FIP and has filed comments relating to the Eighth Circuit decision with the EPA.

Until the EPA takes final action in each state and decisions have been made on each appeal, the Company cannot fully determine the impacts of the Regional Haze regulation on its generating facilities.

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Climate Change

GHG 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 MWh. In June 2013, the President announced a national climate change strategy and issued a presidential memorandum requiring the EPA to issue a re-proposed GHG new source performance standard for fossil-fueled generating facilities by September 2013. Rather than re-propose the April 2012 proposal, the EPA issued a new proposal. The September 2013 GHG new source performance standards released by the EPA set different standards for coal-fueled and natural gas-fueled generating facilities. The proposed standard for natural gas-fueled generating facilities considers the size of the unit and the electricity sent to the grid from the unit, establishing a standard of 1,000 to 1,100 pounds of carbon dioxide per MWh. The standard proposed for coal-fueled generating facilities is 1,100 pounds of carbon dioxide per MWh on an annual basis or 1,000 to 1,050 pounds of carbon dioxide per MWh averaged over a seven-year period, both of which would require partial carbon capture and sequestration. The proposed standards have not yet been published in the Federal Register; once they are published, a 60-day public comment period will commence prior to the EPA finalizing the standard. Any new fossil-fueled generating facilities constructed by the Company will be required to meet the final GHG new source performance standards.

In addition to requiring the EPA to re-propose standards for new fossil-fueled sources, the presidential memorandum requires the EPA to propose standards or guidelines for existing and modified fossil-fueled generating facilities by June 2014, to finalize those standards or guidelines by June 2015, and to require states to submit SIPs that comply with those standards or guidelines by June 2016. The EPA has scheduled listening sessions in its regional offices during October and November 2013 to gather pre-rulemaking input into the existing source standards or guidelines and has issued a five-page framing document to gather stakeholder feedback. Until the standards or guidelines for existing, modified or reconstructed units are proposed and finalized, the impact on the Company's existing facilities cannot be determined.

Regional and State Activities

Over the past several years, the states of California, Washington and Oregon have adopted GHG emissions performance standards for base load electricity generating resources. Under the laws in California and Oregon, the emissions performance standards provide that emissions must not exceed 1,100 pounds of carbon dioxide per MWh. Effective April 2013, Washington's amended emissions performance standards provide that GHG emissions for base load electricity generating resources must not exceed 970 pounds of carbon dioxide per MWh. These GHG emissions performance standards generally prohibit electric utilities from entering into long-term financial commitments (e.g., new ownership investments, upgrades, or new or renewed contracts with a term of five or more years) unless any base load generation supplied under long-term financial commitments comply with the GHG emissions performance standards.

GHG Litigation

In October 2009, the United States District Court for the Northern District of California ("Northern District of California") granted the defendants' motions to dismiss in the case of Native Village of Kivalina v. ExxonMobil Corporation, et al. The plaintiffs filed their complaint in February 2008, asserting claims against 24 defendants, including electric generating companies, oil companies and a coal company, for public nuisance under state and federal common law based on the defendants' GHG emissions. MEHC was a named defendant in the Kivalina case. The Northern District of California dismissed all of the plaintiffs' federal claims, holding that the court lacked subject matter jurisdiction to hear the claims under the political question doctrine, and that the plaintiffs lacked standing to bring their claims. The Northern District of California declined to hear the state law claims and the case was dismissed without prejudice to their future presentation in an appropriate state court. In November 2009, the plaintiffs appealed the case to the Ninth Circuit. In September 2012, the Ninth Circuit issued its opinion affirming the Northern District of California's dismissal of the plaintiffs' complaint. The Ninth Circuit held that the Clean Air Act displaced the plaintiffs' federal common law claims. In October 2012, the plaintiffs filed a petition for a full rehearing by the Ninth Circuit, which was denied by the Ninth Circuit in November 2012. In February 2013, the plaintiffs filed a petition with the United States Supreme Court to review the Ninth Circuit's decision. In May 2013, the United States Supreme Court denied the petition.

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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. However, commitment fees and interest rates under the credit facilities are tied to credit ratings and increase or decrease when the ratings change. A ratings downgrade could also increase the future cost of commercial paper, short- and long-term debt issuances or new credit facilities.

In accordance with industry practice, certain wholesale agreements, including derivative contracts, contain credit support provisions that in part base certain collateral requirements on credit ratings for senior unsecured debt as reported by 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," or in some cases terminate the contract, in the event of a material adverse change in creditworthiness. These rights can vary by contract and by counterparty. As of September 30, 2013, the applicable 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 September 30, 2013, the Company would have been required to post $474 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 9 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 the Topaz and Solar Star Projects, 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 and Solar Star Projects, MEHC will have no further obligation to make any equity contribution and any unused equity contribution obligations will be canceled. As of September 30, 2013, the equity commitment related to the Topaz Project was $1.3 billion and the equity commitment related to the Solar Star Projects was $1.75 billion. Refer to Note 16 of Notes to Consolidated Financial Statements in Item 8 of the Company's Annual Report on Form 10-K for the year ended December 31, 2012 and Note 11 of Notes to Consolidated Financial Statements in this Form 10-Q for a discussion of the Company's collateral requirements specific to the Company's equity commitments.

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 goodwill and long-lived assets, 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, 2012. There have been no significant changes in the Company's assumptions regarding critical accounting estimates since December 31, 2012.

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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, 2012. The Company's exposure to market risk and its management of such risk has not changed materially since December 31, 2012. Refer to Note 9 of Notes to Consolidated Financial Statements in Item 1 of this Form 10-Q for disclosure of the Company's derivative positions as of September 30, 2013.

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 September 30, 2013 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 the discussion contained herein and to Note 11 of Notes to Consolidated Financial Statements included in Part I, Item 1 of this Form 10-Q.

Litigation Related to the NV Energy Acquisition

Following the announcement of the acquisition of NV Energy by MEHC on May 29, 2013, several complaints were filed by purported shareholders of NV Energy in the Eighth Judicial District Court in Clark County, Nevada, challenging the proposed merger.

The complaints were filed on behalf of a putative class of NV Energy public shareholders, naming NV Energy, its board of directors, MEHC and Silver Merger Sub Inc. ("Merger Sub"), an indirect wholly owned subsidiary of MEHC. The complaints, as amended, generally allege that the individual defendants breached their fiduciary duties in connection with the proposed merger, and that NV Energy, Merger Sub and MEHC aided and abetted the breach of fiduciary duties by the individual defendants. The amended complaints seek, among other things, an order preliminarily and permanently enjoining the acquisition, disclosure of certain information relating to the acquisition, damages, and plaintiff's expenses.

On September 4, 2013, the parties to the lawsuits entered into a memorandum of understanding providing for the settlement of the lawsuits, subject to certain confirmatory discovery by the plaintiffs in the lawsuits and subject to the approval of the Eighth Judicial District Court in Clark County, Nevada. Pursuant to the terms of the memorandum of understanding, NV Energy made certain supplemental disclosures to its proxy statement.

Absent the court approval previously discussed, injunctive relief or an adverse determination in the shareholder class actions could result in a cash judgment or settlement and affect MEHC's ability to complete the acquisition with NV Energy. MEHC intends to vigorously defend the lawsuits.

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, 2012.

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 Wall Street Reform and Consumer Protection 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: November 1, 2013	/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

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 September 30, 2013, 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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