BERKSHIRE HATHAWAY ENERGY CO - FORM 10-Q

Attached files

file	filename
EX-32.1 - SECTION 906 CEO CERTIFICATION - BERKSHIRE HATHAWAY ENERGY CO	exh32_1.htm
EX-31.2 - SECTION 302 CFO CERTIFICATION - BERKSHIRE HATHAWAY ENERGY CO	exh31_2.htm
EX-31.1 - SECTION 302 CEO CERTIFICATION - BERKSHIRE HATHAWAY ENERGY CO	exh31_1.htm
EX-32.2 - SECTION 906 CFO CERTIFICATION - BERKSHIRE HATHAWAY ENERGY CO	exh32_2.htm
EX-15 - AWARENESS LETTER OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM - BERKSHIRE HATHAWAY ENERGY CO	exh15.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended September 30, 2009

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

For the transition period from ______ to _______

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

001-14881	MIDAMERICAN ENERGY HOLDINGS COMPANY	94-2213782
	(An Iowa Corporation)
	666 Grand Avenue, Suite 500
	Des Moines, Iowa 50309-2580
	515-242-4300

N/A
(Former name, former address and former fiscal year, if changed since last report)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes T No ¨

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

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

Large accelerated filer ¨

Accelerated filer ¨

Non-accelerated filer T

Smaller reporting company ¨

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

Yes ¨ No T

All of the shares of common equity of MidAmerican Energy Holdings Company are privately held by a limited group of investors. As of October 31, 2009, 74,859,001 shares of common stock were outstanding.

TABLE OF CONTENTS

PART I - FINANCIAL INFORMATION

Item 1.	Financial Statements	3

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	29

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	44

Item 4(T).	Controls and Procedures	44

PART II - OTHER INFORMATION

Item 1.	Legal Proceedings	45

Item 1A	Risk Factors	45

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	45

Item 3.	Defaults Upon Senior Securities	45

Item 4.	Submission of Matters to a Vote of Security Holders	45

Item 5.	Other Information	45

Item 6.	Exhibits	45

Signatures		46

Exhibit Index		47

PART I

Item 1.

Financial Statements

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders

MidAmerican Energy Holdings Company

Des Moines, Iowa

We have reviewed the accompanying consolidated balance sheet of MidAmerican Energy Holdings Company and subsidiaries (the “Company”) as of September 30, 2009, and the related consolidated statements of operations for the three-month and nine-month periods ended September 30, 2009 and 2008, and of cash flows and changes in equity for the nine-month periods ended September 30, 2009 and 2008. 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, 2008, and the related consolidated statements of operations, shareholders’ equity, and cash flows for the year then ended prior to retrospective adjustment for the adoption of new accounting guidance related to noncontrolling interest in a subsidiary, included in Accounting Standards Codification Topic 810 (not presented herein); and in our report dated February 27, 2009, we expressed an unqualified opinion on those consolidated financial statements. We also audited the adjustments described in Note 2 that were applied to retrospectively adjust the December 31, 2008 consolidated balance sheet of MidAmerican Energy Holdings Company and subsidiaries (not presented herein). In our opinion, such adjustments are appropriate and have been properly applied to the previously issued consolidated balance sheet in deriving the accompanying retrospectively adjusted consolidated balance sheet as of December 31, 2008.

/s/ Deloitte & Touche LLP

Des Moines, Iowa

November 6, 2009

MIDAMERICAN ENERGY HOLDINGS COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (Unaudited)

(Amounts in millions)

	As of
	September 30,		December 31,
	2009		2008
ASSETS

Current assets:
Cash and cash equivalents	$	744	$	280
Trade receivables, net		1,078		1,310
Inventories		581		566
Derivative contracts		141		227
Investments		10		1,505
Other current assets		575		529
Total current assets		3,129		4,417

Property, plant and equipment, net		30,432		28,454
Goodwill		5,076		5,023
Regulatory assets		2,044		2,156
Derivative contracts		58		97
Investments and other assets		3,251		1,294

Total assets	$	43,990	$	41,441

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

MIDAMERICAN ENERGY HOLDINGS COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (Unaudited) (continued)

(Amounts in millions)

	As of
	September 30,		December 31,
	2009		2008

LIABILITIES AND EQUITY

Current liabilities:
Accounts payable	$	821	$	1,240
Accrued interest		345		340
Accrued property, income and other taxes		302		561
Derivative contracts		132		183
Short-term debt		120		836
Current portion of long-term debt		128		421
Current portion of MEHC subordinated debt		234		734
Other current liabilities		683		578
Total current liabilities		2,765		4,893

Regulatory liabilities		1,558		1,506
Derivative contracts		401		546
MEHC senior debt		5,371		5,121
MEHC subordinated debt		423		587
Subsidiary debt		13,709		12,533
Deferred income taxes		5,420		3,949
Other long-term liabilities		1,815		1,829
Total liabilities		31,462		30,964

Commitments and contingencies (Note 12)

Equity:
MEHC shareholders’ equity:
Common stock - 115 shares authorized, no par value, 75 shares issued and outstanding		-		-
Additional paid-in capital		5,453		5,455
Retained earnings		6,495		5,631
Accumulated other comprehensive income (loss), net		303		(879	)
Total MEHC shareholders’ equity		12,251		10,207
Noncontrolling interests		277		270
Total equity		12,528		10,477

Total liabilities and equity	$	43,990	$	41,441

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

MIDAMERICAN ENERGY HOLDINGS COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)

(Amounts in millions)

	Three-Month Periods						Nine-Month Periods
	Ended September 30,						Ended September 30,
	2009			2008			2009			2008

Operating revenue:
Energy	$	2,429		$	2,910		$	7,448		$	8,675
Real estate		312			330			764			913
Total operating revenue		2,741			3,240			8,212			9,588

Operating costs and expenses:
Energy:
Cost of sales		875			1,315			2,818			3,949
Operating expense		598			561			1,908			1,766
Depreciation and amortization		313			264			916			824
Real estate		294			329			748			923
Total operating costs and expenses		2,080			2,469			6,390			7,462

Operating income		661			771			1,822			2,126

Other income (expense):
Interest expense		(316	)		(340	)		(957	)		(998	)
Capitalized interest		12			14			30			37
Interest and dividend income		8			16			36			47
Other, net		41			19			119			59
Total other income (expense)		(255	)		(291	)		(772	)		(855	)

Income before income tax expense and equity income		406			480			1,050			1,271
Income tax expense		39			149			211			378
Equity income		(21	)		(24	)		(49	)		(33	)
Net income		388			355			888			926
Net income attributable to noncontrolling interests		12			5			24			14
Net income attributable to MEHC	$	376		$	350		$	864		$	912

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

MIDAMERICAN ENERGY HOLDINGS COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)

(Amounts in millions)

	Nine-Month Periods
	Ended September 30,
	2009			2008

Cash flows from operating activities:
Net income	$	888		$	926
Adjustments to reconcile net income to net cash flows from operating activities:
Gain on other items, net		(4	)		(24	)
Depreciation and amortization		929			838
Stock-based compensation		123			-
Changes in regulatory assets and liabilities		28			(31	)
Provision for deferred income taxes		700			440
Other, net		(39	)		(17	)
Changes in other operating assets and liabilities, net of effects from acquisition:
Trade receivables and other assets		293			91
Derivative collateral, net		93			(100	)
Trading securities		499			-
Contributions to pension and other postretirement benefit plans, net		(74	)		(94	)
Accounts payable and other liabilities		(453	)		(24	)
Net cash flows from operating activities		2,983			2,005

Cash flows from investing activities:
Capital expenditures		(2,592	)		(2,678	)
Acquisition, net of cash acquired		-			(308	)
Purchases of available-for-sale securities		(483	)		(177	)
Proceeds from sales of available-for-sale securities		242			179
Proceeds from investments		1,000			393
Purchase of Constellation Energy 8% preferred stock		-			(1,000	)
Other, net		(13	)		22
Net cash flows from investing activities		(1,846	)		(3,569	)

Cash flows from financing activities:
Proceeds from MEHC senior and subordinated debt		250			1,649
Repayments of MEHC senior and subordinated debt		(667	)		(1,167	)
Proceeds from subsidiary debt		992			1,498
Repayments of subsidiary debt		(383	)		(997	)
Purchases of subsidiary debt		-			(216	)
Net repayments of MEHC revolving credit facility		(216	)		-
Net (repayments of) proceeds from subsidiary short-term debt		(506	)		274
Net payment of hedging instruments		-			(99	)
Net purchases of common stock		(123	)		-
Other, net		(23	)		(22	)
Net cash flows from financing activities		(676	)		920

Effect of exchange rate changes		3			(3	)

Net change in cash and cash equivalents		464			(647	)
Cash and cash equivalents at beginning of period		280			1,178
Cash and cash equivalents at end of period	$	744		$	531

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

MIDAMERICAN ENERGY HOLDINGS COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY (Unaudited)

(Amounts in millions)

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

Balance, January 1, 2008		75		$	-	$	5,454		$	3,782	$	90		$	256		$	9,582
Net income		-			-		-			912		-			14			926
Other comprehensive loss		-			-		-			-		(305	)		-			(305	)
Contributions		-			-		-			-		-			33			33
Distributions		-			-		-			-		-			(37	)		(37	)
Other equity transactions		-			-		1			-		-			1			2
Balance, September 30, 2008		75		$	-	$	5,455		$	4,694	$	(215	)	$	267		$	10,201

Balance, January 1, 2009		75		$	-	$	5,455		$	5,631	$	(879	)	$	270		$	10,477
Net income		-			-		-			864		-			24			888
Other comprehensive income		-			-		-			-		1,182			-			1,182
Stock-based compensation		-			-		123			-		-			-			123
Exercise of common stock options		1			-		25			-		-			-			25
Common stock purchases		(1	)		-		(148	)		-		-			-			(148	)
Contributions		-			-		-			-		-			23			23
Distributions		-			-		-			-		-			(53	)		(53	)
Other equity transactions		-			-		(2	)		-		-			13			11
Balance, September 30, 2009		75		$	-	$	5,453		$	6,495	$	303		$	277		$	12,528

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

MIDAMERICAN ENERGY HOLDINGS COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

(1)

General

MidAmerican Energy Holdings Company (“MEHC”) is a holding company that owns subsidiaries principally engaged in energy businesses (collectively with its subsidiaries, the “Company”). MEHC is a consolidated subsidiary of Berkshire Hathaway Inc. (“Berkshire Hathaway”). The balance of MEHC’s common stock is owned by Mr. Walter Scott, Jr. (along with family members and related entities), a member of MEHC’s Board of Directors, and Mr. Gregory E. Abel, a member of MEHC’s Board of Directors and MEHC’s President and Chief Executive Officer. As of September 30, 2009, Berkshire Hathaway, Mr. Scott (along with family members and related entities) and Mr. Abel owned 89.5%, 9.7% and 0.8%, respectively, of MEHC’s voting common stock.

The Company’s operations are organized and managed as eight distinct platforms: PacifiCorp, MidAmerican Funding, LLC (“MidAmerican Funding”) (which primarily consists of MidAmerican Energy Company (“MidAmerican Energy”)), Northern Natural Gas Company (“Northern Natural Gas”), Kern River Gas Transmission Company (“Kern River”), CE Electric UK Funding Company (“CE Electric UK”) (which primarily consists of Northern Electric Distribution Limited (“Northern Electric”) and Yorkshire Electricity Distribution plc (“Yorkshire Electricity”)), CalEnergy Generation-Foreign (which owns a majority interest in the Casecnan project in the Philippines), CalEnergy Generation-Domestic (which owns interests in independent power projects in the United States) and HomeServices of America, Inc. (collectively with its subsidiaries, “HomeServices”). Through these platforms, MEHC owns and operates an electric utility company in the Western United States, an electric and natural gas utility company in the Midwestern United States, two interstate natural gas pipeline companies in the United States, two electricity distribution companies in Great Britain, a diversified portfolio of independent power projects and the second largest residential real estate brokerage firm in the United States.

The unaudited Consolidated Financial Statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) for interim financial information and the United States Securities and Exchange Commission’s rules and regulations for Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the disclosures required by GAAP for annual financial statements. Management believes the unaudited Consolidated Financial Statements contain all adjustments (consisting only of normal recurring adjustments) considered necessary for the fair presentation of the Consolidated Financial Statements as of September 30, 2009 and for the three- and nine-month periods ended September 30, 2009 and 2008. Certain amounts in the prior period Consolidated Financial Statements have been reclassified to conform to the current period presentation. Such reclassifications did not impact previously reported operating income, net income attributable to MEHC or retained earnings. The results of operations for the three- and nine-month periods ended September 30, 2009 are not necessarily indicative of the results to be expected for the full year. The Company has evaluated subsequent events through November 6, 2009, which is the date the unaudited Consolidated Financial Statements were issued.

The preparation of the unaudited Consolidated Financial Statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses during the period. Actual results may differ from the estimates used in preparing the unaudited Consolidated Financial Statements. Note 2 of Notes to Consolidated Financial Statements included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2008 describes the most significant accounting policies used in the preparation of the Consolidated Financial Statements. There have been no significant changes in the Company’s assumptions regarding significant accounting estimates and policies during the nine-month period ended September 30, 2009.

(2)	New Accounting Pronouncements

In September 2009, the Financial Accounting Standards Board (the “FASB”) issued Accounting Standards Update (“ASU”) No. 2009-12 (“ASU No. 2009-12”), which amends FASB Accounting Standards Codification (“ASC”) Topic 820, “Fair Value Measurements and Disclosures” (“ASC Topic 820”). ASU No. 2009-12 allows, as a practical expedient, for the net asset value provided by the investee entity to be an applicable fair value measurement, if the net asset value was calculated within the provisions of ASC Topic 946, “Financial Services – Investment Companies.” Investments within the scope of this update are investments valued at net asset value that do not have a readily determinable fair value and have all the following attributes: (i) the investment company’s primary business activity involves investing its assets, usually in the securities of other entities not under common management, for current income, appreciation, or both; (ii) ownership in the investment company is represented by units of investments, such as shares of stock or partnership interests, to which proportionate shares of net assets can be attributed; (iii) the funds of the investment company’s owners are pooled to avail owners of professional investment management and (iv) the investment company is the primary reporting entity. Classification within the fair value hierarchy of a fair value measurement of an investment that is measured at net asset value requires judgment, which includes consideration of the entity’s ability to redeem its investment at net asset value at the measurement date. If the entity does not have the ability to redeem the investment at net asset value at the measurement date, the length of time until the investment can be redeemed shall be considered. This guidance also requires disclosures, by major category of investments, about the attributes of the investments. This guidance is effective for the first reporting period, including interim periods, ending after December 15, 2009. The Company is currently evaluating the impact of adopting this guidance on its consolidated financial results and disclosures included within Notes to Consolidated Financial Statements.

In August 2009, the FASB issued ASU No. 2009-05, which amends ASC Topic 820. ASU No. 2009-05 clarifies how to measure the fair value of a liability for which a quoted price in an active market for the identical liability is not available. In such a circumstance, an entity is required to measure fair value using one or more of the following valuation techniques: (i) quoted price of the identical liability when traded as an asset, (ii) quoted prices for similar liabilities or similar liabilities when traded as assets or (iii) another valuation technique that is consistent with fair value principles, such as an income approach or a market approach. This guidance also clarifies that both a quoted price in an active market for the identical liability at the measurement date and the quoted price for the identical liability when traded as an asset in an active market when no adjustments to the quoted price of the asset are required are Level 1 fair value measurements. When estimating the fair value of a liability, an entity is not required to include a separate input or adjustment relating to the existence of a restriction that prevents the transfer of the liability. This guidance is effective for the first reporting period, including interim periods, beginning after its August 2009 issuance. The Company is currently evaluating the impact of adopting this guidance on its disclosures included within Notes to Consolidated Financial Statements.

In June 2009, the FASB issued authoritative guidance that requires a primarily qualitative analysis to determine if an enterprise is the primary beneficiary of a variable interest entity. This analysis is based on whether the enterprise has (i) the power to direct the activities of the variable interest entity that most significantly impact the entity’s economic performance and (ii) the obligation to absorb losses of the entity or the right to receive benefits from the entity that could potentially be significant to the variable interest entity. In addition, enterprises are required to more frequently reassess whether an entity is a variable interest entity and whether the enterprise is the primary beneficiary of the variable interest entity. Finally, the guidance for consolidation or deconsolidation of a variable interest entity is amended and disclosure requirements about an enterprise’s involvement with a variable interest entity are enhanced. This guidance is effective as of the beginning of the first annual reporting period that begins after November 15, 2009, for interim periods within that first annual reporting period and for interim and annual reporting periods thereafter, with early application prohibited. The Company is currently evaluating the impact of adopting this guidance on its consolidated financial results and disclosures included within Notes to Consolidated Financial Statements.

In April 2009, the FASB issued authoritative guidance (included in ASC Topic 825, “Financial Instruments”) that requires publicly traded companies to include the annual fair value disclosures required for all financial instruments, as defined by GAAP, in interim financial statements. The Company adopted this guidance on April 1, 2009 and included the required disclosures within Notes to Consolidated Financial Statements.

In April 2009, the FASB issued authoritative guidance (included in ASC Topic 320, “Investments – Debt and Equity Securities”) that amends current other-than-temporary impairment guidance for debt securities to require a new other-than-temporary impairment model that shifts the focus from an entity’s intent to hold the debt security until recovery to its intent, or expected requirement, to sell the debt security. In addition, this guidance expands the already required annual disclosures about other-than-temporary impairment for debt and equity securities, requires companies to include these expanded disclosures in interim financial statements and addresses whether an other-than-temporary impairment should be recognized in earnings, other comprehensive income or some combination thereof. The Company adopted this guidance on April 1, 2009. The adoption did not have a material impact on the Company’s consolidated financial results and disclosures included within Notes to Consolidated Financial Statements.

In April 2009, the FASB issued authoritative guidance (included in ASC Topic 820) that clarifies the determination of fair value when a market is not active and if a transaction is not orderly. In addition, this guidance amends previous GAAP to require disclosures in interim and annual periods of the inputs and valuation techniques used to measure fair value and a discussion of changes in valuation techniques and related inputs, if any, during the period and defines “major categories” consistent with those described in previously existing GAAP. The Company adopted this guidance on April 1, 2009. The adoption did not have a material impact on the Company’s consolidated financial results and disclosures included within Notes to Consolidated Financial Statements.

In December 2008, the FASB issued authoritative guidance (included in ASC Topic 715, “Compensation – Retirement Benefits”) that requires enhanced disclosures about plan assets of defined benefit pension and other postretirement benefit plans to enable investors to better understand how investment allocation decisions are made and the major categories of plan assets. In addition, this guidance requires disclosure of the inputs and valuation techniques used to measure fair value and the effect of fair value measurements using significant unobservable inputs on changes in plan assets and establishes disclosure requirements for significant concentrations of risk within plan assets. This guidance is effective for fiscal years ending after December 15, 2009, with early application permitted. The Company is currently evaluating the impact of adopting this guidance on its disclosures included within Notes to Consolidated Financial Statements.

In March 2008, the FASB issued authoritative guidance (included in ASC Topic 815, “Derivatives and Hedging”) that requires enhanced disclosures about derivative instruments and hedging activities to enable investors to better understand how and why an entity uses derivative instruments and their effects on an entity’s financial results. The Company adopted this guidance on January 1, 2009 and included the required disclosures within Notes to Consolidated Financial Statements.

In December 2007, the FASB issued authoritative guidance (included in ASC Topic 810, “Consolidation”) that establishes accounting and reporting standards for the noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary. The Company adopted this guidance on January 1, 2009. As a result, the Company has presented noncontrolling interests as a separate component of equity on the Consolidated Balance Sheets. Previously, these amounts were reported as minority interest and preferred securities of subsidiaries within the mezzanine section on the Consolidated Balance Sheets. Also, the Company has presented net income attributable to noncontrolling interests separately on the Consolidated Statements of Operations. Previously, these amounts were reported as minority interest and preferred dividends of subsidiaries on the Consolidated Statements of Operations.

(3)	Property, Plant and Equipment, Net

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

		As of
	Depreciable	September 30,			December 31,
	Life	2009			2008

Regulated assets:
Utility generation, distribution and transmission system	5-85 years	$	35,084		$	32,795
Interstate pipeline assets	3-67 years		5,710			5,649
			40,794			38,444
Accumulated depreciation and amortization			(13,155	)		(12,456	)
Regulated assets, net			27,639			25,988

Non-regulated assets:
Independent power plants	10-30 years		677			681
Other assets	3-30 years		607			547
			1,284			1,228
Accumulated depreciation and amortization			(494	)		(430	)
Non-regulated assets, net			790			798

Net operating assets			28,429			26,786
Construction in progress			2,003			1,668
Property, plant and equipment, net		$	30,432		$	28,454

Substantially all of the construction in progress as of September 30, 2009 and December 31, 2008 relates to the construction of regulated assets.

(4)	Regulatory Matters

The following are updates to regulatory matters based upon material changes that occurred subsequent to December 31, 2008.

Rate Matters

Kern River Rate Case

In March 2006, Kern River received an initial decision from the presiding administrative law judge in Kern River’s 2004 general rate case filed in April 2004. In October 2006, the Federal Energy Regulatory Commission (“FERC”) issued an order that modified certain aspects of the administrative law judge’s initial decision, including changing the allowed return on equity from 9.34% to 11.2% and granting Kern River an income tax allowance. In April 2008, the FERC issued an order, consistent with its policy statement, granting Kern River’s request for rehearing to include master limited partnerships in the proxy group for determining the allowed rate of return on equity.

In September 2008, Kern River filed an Offer of Settlement and Stipulation (“Settlement”) that was supported or not opposed by a majority of the long-term shippers on Kern River’s system. In January 2009, the FERC issued an order rejecting the Settlement. The FERC found the Settlement would result in unjust and unreasonable rates and ordered Kern River to file compliance rates based on an allowed return on equity of 11.55%. Certain shippers filed timely requests for rehearing of the January 2009 order. Pursuant to the January 2009 order, Kern River made the compliance filing in March 2009, which was revised in September 2009. Comments and protests on Kern River’s March 2009 and September 2009 compliance filings have been submitted and a decision from the FERC is expected in late 2009 or early 2010.

Oregon Senate Bill 408 (“SB 408”)

SB 408 requires PacifiCorp and other large regulated, investor-owned utilities that provide electric or natural gas service to Oregon customers to file an annual report each October with the Oregon Public Utility Commission (the “OPUC”) comparing income taxes collected and income taxes paid, as defined by the statute and its administrative rules. PacifiCorp’s amended filing for the 2006 tax year indicated that PacifiCorp paid $35 million more in income taxes than was collected in rates from its retail customers. In April 2008, the OPUC approved the recovery of $27 million of this deficiency over a one-year period beginning June 1, 2008 with the remainder deferred until a later period, with interest to accrue at PacifiCorp’s authorized rate of return. In April 2009, the OPUC approved recovery of the remaining balance, including interest, and also approved recovery of the under collected income tax balance, including interest, associated with PacifiCorp’s 2007 tax report. In April 2009, PacifiCorp recorded a $20 million regulatory asset representing the balance to be collected from its Oregon retail customers for its 2006 and 2007 tax reports. The amounts are being collected over a one-year period beginning June1, 2009.

The OPUC’s April 2008 order on PacifiCorp’s 2006 tax report is being challenged by the Industrial Customers of Northwest Utilities (“ICNU”), which filed a petition in May 2008 with the Court of Appeals of the State of Oregon (the “Court of Appeals”) seeking judicial review of the April 2008 order. In March 2009, a notice of withdrawal of the April 2008 order was filed with the Court of Appeals by the OPUC. In May 2009, the OPUC issued an order on reconsideration, which supplemented and affirmed its April 2008 order. In June 2009, ICNU continued its challenge of the April 2008 order by filing an amended petition for judicial review with the Court of Appeals to include the May 2009 order. PacifiCorp believes the outcome of these proceedings will not have a material impact on its consolidated financial results.

In October 2009, PacifiCorp filed its tax report for 2008 under SB 408. PacifiCorp’s filing for the 2008 tax year indicated that PacifiCorp paid $38 million more in income taxes than was collected in rates from its retail customers. PacifiCorp has not recorded a regulatory asset related to the 2008 tax report.

(5)	Fair Value Measurements

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

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

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

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

The following table presents the Company’s assets and liabilities recognized in the Consolidated Balance Sheet and measured at fair value on a recurring basis as of September 30, 2009 (in millions):

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

Assets(2):
Commodity derivatives	$	7		$	440		$	36		$	(284	)	$	199
Investments in available-for-sale securities:
Money market mutual funds(3)		603			-			-			-			603
Debt securities		68			81			40			-			189
Equity securities		2,084			8			-			-			2,092
	$	2,762		$	529		$	76		$	(284	)	$	3,083

Liabilities:
Commodity derivatives	$	(7	)	$	(456	)	$	(369	)	$	303		$	(529	)
Interest rate derivative		-			(4	)		-			-			(4	)
	$	(7	)	$	(460	)	$	(369	)	$	303		$	(533	)

(1)	Primarily represents a net cash collateral receivable of $19 million and netting under master netting arrangements.

(2)	Does not include investments in either pension or other postretirement benefit plan assets.

(3)	Amounts are included in cash and cash equivalents, other current assets and investments and other assets on the Consolidated Balance Sheet. The fair value of these money market mutual funds approximates cost.

The following table presents the Company’s assets and liabilities recognized in the Consolidated Balance Sheet and measured at fair value on a recurring basis as of December 31, 2008 (in millions):

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

Assets(2):
Commodity derivatives	$	2		$	549		$	136		$	(363	)	$	324
Investments in available-for-sale securities:
Money market mutual funds(3)		202			-			-			-			202
Debt securities		45			117			37			-			199
Equity securities		171			6			-			-			177
Investments in trading securities - Equity		499			-			-			-			499
	$	919		$	672		$	173		$	(363	)	$	1,401

Liabilities:
Commodity derivatives	$	(55	)	$	(632	)	$	(505	)	$	469		$	(723	)
Interest rate derivative		-			(6	)		-			-			(6	)
	$	(55	)	$	(638	)	$	(505	)	$	469		$	(729	)

(1)	Primarily represents a net cash collateral receivable of $129 million and netting under master netting arrangements.

(2)	Does not include investments in either pension or other postretirement benefit plan assets.

(3)	Amounts are included in cash and cash equivalents, other current assets and investments and other assets on the Consolidated Balance Sheet. The fair value of these money market mutual funds approximates cost.

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

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

The following table reconciles the beginning and ending balances of the Company’s assets and liabilities measured at fair value on a recurring basis using significant Level 3 inputs for the three-month periods ended September 30 (in millions):

	2009					2008
	Commodity			Debt		Commodity			Debt
	Derivatives			Securities		Derivatives			Securities

Beginning balance	$	(360	)	$	38	$	(232	)	$	61
Changes included in earnings(1)		(3	)		-		38			-
Changes in fair value recognized in other comprehensive income		(1	)		2		-			(6	)
Changes in fair value recognized in net regulatory assets		(2	)		-		(200	)		-
Purchases, sales, issuances and settlements		33			-		48			-
Ending balance	$	(333	)	$	40	$	(346	)	$	55

(1)

Changes included in earnings are reported as operating revenue in the Consolidated Statements of Operations. Net unrealized gains (losses) included in earnings for the three-month periods ended September 30, 2009 and 2008, related to commodity derivatives held at September 30, 2009 and 2008, totaled $(3) million and $32 million, respectively.

The following table reconciles the beginning and ending balances of the Company’s assets and liabilities measured at fair value on a recurring basis using significant Level 3 inputs for the nine-month periods ended September 30 (in millions):

	2009					2008
	Commodity			Debt		Commodity			Debt
	Derivatives			Securities		Derivatives			Securities

Beginning balance	$	(369	)	$	37	$	(311	)	$	73
Changes included in earnings(1)		16			-		16			-
Changes in fair value recognized in other comprehensive income		-			3		1			(18	)
Changes in fair value recognized in net regulatory assets		32			-		(66	)		-
Purchases, sales, issuances and settlements		11			-		14			-
Net transfers into or out of Level 3		(23	)		-		-			-
Ending balance	$	(333	)	$	40	$	(346	)	$	55

(1)

Changes included in earnings are reported as operating revenue in the Consolidated Statements of Operations. Net unrealized gains (losses) included in earnings for the nine-month periods ended September 30, 2009 and 2008, related to commodity derivatives held at September 30, 2009 and 2008, totaled $12 million and $11 million, respectively.

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

	As of September 30, 2009				As of December 31, 2008
	Carrying				Carrying
	Amount		Fair Value		Amount		Fair Value

Long-term debt	$	19,865	$	21,660	$	19,396	$	19,396

(6)	Risk Management and Hedging Activities

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

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

There have been no significant changes in the Company’s significant accounting policies related to derivatives. Refer to Notes 2 and 5 for additional information on derivative contracts.

The following table, which excludes contracts that qualify for the normal purchases or normal sales exemption 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 Sheet as of September 30, 2009 (in millions):

	Balance Sheet Locations
	Derivative Assets						Derivative Liabilities
	Current			Noncurrent			Current			Noncurrent			Total

Not Designated as Hedging Contracts(1)(2):
Commodity assets	$	334		$	105		$	23		$	3		$	465
Commodity liabilities		(91	)		(39	)		(187	)		(386	)		(703	)
Total		243			66			(164	)		(383	)		(238	)

Designated as Hedging Contracts(1):
Commodity assets		4			-			13			1			18
Commodity liabilities		(5	)		-			(76	)		(48	)		(129	)
Interest rate liability		-			-			-			(4	)		(4	)
Total		(1	)		-			(63	)		(51	)		(115	)

Total derivatives		242			66			(227	)		(434	)		(353	)
Cash collateral receivable (payable)		(101	)		(8	)		95			33			19
Total derivatives - net basis	$	141		$	58		$	(132	)	$	(401	)	$	(334	)

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

(2)	The majority of the Company’s commodity derivatives not designated as hedging contracts are recoverable from customers in regulated rates and as of September 30, 2009, a net regulatory asset of $245 million was recorded related to the net derivative liabilities of $238 million.

Not Designated as Hedging Contracts

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

	Three-Month			Nine-Month
	Period Ended			Period Ended
	September 30, 2009			September 30, 2009

Beginning balance	$	247		$	446
Changes in fair value recognized in net regulatory assets		15			(182	)
Gains reclassified to earnings - operating revenue		74			243
Losses reclassified to earnings - cost of sales		(91	)		(262	)
Ending balance	$	245		$	245

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

	Three-Month			Nine-Month
	Period Ended			Period Ended
	September 30, 2009			September 30, 2009
Commodity derivatives:
Operating revenue	$	(2	)	$	22
Cost of sales		6			(5	)
Operating expense		(1	)		-
Total	$	3		$	17

Designated as Hedging Contracts

The Company uses derivative contracts accounted for as cash flow hedges to hedge electricity and natural gas commodity prices for delivery to nonregulated customers, spring operational sales, natural gas storage and other transactions. The Company’s derivative contracts designated as fair value hedges were not significant as of September 30, 2009.

The following table reconciles the beginning and ending balances of the Company’s accumulated other comprehensive loss (pre-tax) and summarizes pre-tax gains and losses on derivative contracts designated and qualifying as cash flow hedges recognized in other comprehensive income (“OCI”), as well as amounts reclassified to earnings during the three-month period ended September 30, 2009 (in millions):

	Commodity			Interest Rate
	Derivatives			Derivative		Total(1)

Beginning balance	$	104		$	4	$	108
Losses recognized in OCI		34			-		34
Losses reclassified to earnings – revenue		(1	)		-		(1	)
Losses reclassified to earnings - cost of sales		(30	)		-		(30	)
Ending balance	$	107		$	4	$	111

(1)	Certain derivative contracts, principally interest rate locks, have settled and the fair value at the date of settlement remains in accumulated other comprehensive income (loss) and is amortized to earnings over the remaining life of the respective long-term debt.

The following table reconciles the beginning and ending balances of the Company’s accumulated other comprehensive loss (pre-tax) and summarizes pre-tax gains and losses on derivative contracts designated and qualifying as cash flow hedges recognized in OCI, as well as amounts reclassified to earnings during the nine-month period ended September 30, 2009 (in millions):

	Commodity			Interest Rate
	Derivatives			Derivative			Total(1)

Beginning balance	$	83		$	6		$	89
Losses (gains) recognized in OCI		109			(2	)		107
Losses reclassified to earnings – revenue		(2	)		-			(2	)
Losses reclassified to earnings - cost of sales		(83	)		-			(83	)
Ending balance	$	107		$	4		$	111

(1)	Certain derivative contracts, principally interest rate locks, have settled and the fair value at the date of settlement remains in accumulated other comprehensive income (loss) and is amortized to earnings over the remaining life of the respective long-term debt.

Realized gains and losses on all hedges and hedge ineffectiveness are recognized in income as operating revenue or cost of sales and operating expense depending upon the nature of the item being hedged. For the three- and nine-month periods ended September 30, 2009 and 2008, hedge ineffectiveness was insignificant. As of September 30, 2009, the Company had cash flow hedges with expiration dates extending through December 2022 and $51 million of pre-tax net unrealized losses are forecasted to be reclassified from accumulated other comprehensive loss 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 (in millions):

	Unit of	As of
	Measure	September 30, 2009
Commodity contracts:
Electricity sales	Megawatt hours		(20	)
Natural gas purchases	Decatherms		262
Fuel purchases	Gallons		4
Interest rate derivative – variable to fixed swap	Australian dollars		59

Credit Risk

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

PacifiCorp and MidAmerican Energy 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, PacifiCorp and MidAmerican Energy enter into netting and collateral arrangements that may include margining and cross-product netting agreements and obtaining third-party guarantees, letters of credit and cash deposits. Counterparties may be assessed interest fees for delayed payments. If required, PacifiCorp and MidAmerican Energy exercise rights under these arrangements, including calling on the counterparty’s credit support arrangement. Based on the Company’s policies and risk exposures related to credit, it does not anticipate a material adverse effect on its consolidated financial results as a result of counterparty nonperformance.

Collateral and Contingent Features

In accordance with industry practice, certain derivative contracts contain provisions that require MEHC’s subsidiaries, principally PacifiCorp and MidAmerican Energy, to maintain specific credit ratings from one or more of the major credit rating agencies on their unsecured debt. These derivative contracts may either specifically provide bilateral rights to demand cash or other security if credit exposures on a net basis exceed specified rating-dependent threshold levels (“credit-risk-related contingent features”) or provide the right for counterparties to demand “adequate assurance” in the event of a material adverse change in the subsidiary’s creditworthiness. These rights can vary by contract and by counterparty. As of September 30, 2009, these subsidiary’s credit ratings from the three recognized credit rating agencies were investment grade.

The aggregate fair value of the Company’s derivative contracts in liability positions with specific credit-risk-related contingent features totaled $544 million as of September 30, 2009, for which the Company had posted collateral of $128 million. If all credit-risk-related contingent features for derivative contracts in liability positions had been triggered as of September 30, 2009, the Company would have been required to post $230 million of additional collateral. The Company’s collateral requirements could fluctuate considerably due to market price volatility, changes in credit ratings or other factors.

(7)	Investments

In January 2009, the Company received $1 billion, plus accrued interest, in full satisfaction of the 14% Senior Notes from Constellation Energy Group, Inc. (“Constellation Energy”). During the first six months of 2009, the Company sold 19.9 million shares of Constellation Energy common stock for $536 million, or an average price of $26.93 per share, and recognized gains totaling $37 million, which are included in other, net on the Consolidated Statements of Operations.

In September 2008, MEHC reached a definitive agreement with BYD Company Limited (“BYD”) to purchase 225 million shares, representing approximately a 10% interest in BYD, at a price of Hong Kong (“HK”) $8 per share or HK$1.8 billion (approximately $232 million). Established in 1995, BYD is a Hong Kong listed company with two main businesses: technology, including rechargeable batteries, chargers and cell phone design and assembly, and automobiles. BYD has seven production bases in Guangdong, Beijing, Shanghai and Xi’an and has offices in the United States, Europe, Japan, South Korea, India, Taiwan, Hong Kong and other regions. BYD has over 130,000 employees. The purchase was approved by an affirmative vote of the holders of two-thirds of the outstanding shares of BYD at an extraordinary general meeting held on December 3, 2008. The investment was made on July 30, 2009. MEHC’s investment in BYD is accounted for as an available-for-sale security with changes in fair value recognized in accumulated other comprehensive income. The fair value of $1.854 billion as of September 30, 2009 compared to the acquisition cost of $232 million resulted in a pre-tax unrealized gain of $1.622 billion as of September 30, 2009.

(8)	Recent Debt Transactions

In July 2009, MEHC issued $250 million of its 3.15% Senior Notes due July 15, 2012. The net proceeds are being used for general corporate purposes.

In January 2009, PacifiCorp issued $350 million of its 5.5% First Mortgage Bonds due January 15, 2019 and $650 million of its 6.0% First Mortgage Bonds due January 15, 2039. The net proceeds were used to repay short-term debt and are being used to fund capital expenditures and for general corporate purposes.

(9)	Related Party Transactions

As of September 30, 2009 and December 31, 2008, Berkshire Hathaway and its affiliates held 11% mandatory redeemable preferred securities due from certain wholly-owned subsidiary trusts of MEHC of $420 million and $1.09 billion, respectively. Interest expense on these securities totaled $13 million and $22 million for the three-month periods ended September 30, 2009 and 2008, respectively, and $47 million and $67 million for the nine-month periods ended September 30, 2009 and 2008, respectively. Accrued interest totaled $9 million and $27 million as of September 30, 2009 and December 31, 2008, respectively. In January 2009, MEHC repaid the remaining $500 million to affiliates of Berkshire Hathaway in full satisfaction of the aggregate amount owed pursuant to the $1 billion of 11% mandatory redeemable trust preferred securities issued by MidAmerican Capital Trust IV to affiliates of Berkshire Hathaway in September 2008.

For the nine-month periods ended September 30, 2009 and 2008, the Company received net cash payments for income taxes from Berkshire Hathaway totaling $178 million and $171 million, respectively.

(10)	Employee Benefit Plans

Domestic Operations

Combined net periodic benefit cost for 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,
	2009			2008			2009			2008
Pension:
Service cost	$	9		$	12		$	26		$	39
Interest cost		29			28			85			81
Expected return on plan assets		(29	)		(29	)		(85	)		(87	)
Net amortization		1			2			1			6
Net periodic benefit cost	$	10		$	13		$	27		$	39

Other Postretirement:
Service cost	$	2		$	3		$	6		$	9
Interest cost		12			11			33			35
Expected return on plan assets		(11	)		(10	)		(30	)		(32	)
Net amortization		3			3			9			12
Net periodic benefit cost	$	6		$	7		$	18		$	24

Employer contributions to domestic pension and other postretirement benefit plans are expected to be $62 million and $33 million, respectively, during 2009. As of September 30, 2009, $58 million and $25 million of contributions had been made to domestic pension and other postretirement benefit plans, respectively.

United Kingdom Operations

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

	Three-Month Periods						Nine-Month Periods
	Ended September 30,						Ended September 30,
	2009			2008			2009			2008

Service cost	$	3		$	5		$	9		$	16
Interest cost		22			25			62			77
Expected return on plan assets		(27	)		(30	)		(77	)		(93	)
Net amortization		4			6			11			16
Net periodic benefit cost	$	2		$	6		$	5		$	16

Employer contributions to the UK pension plan are expected to be £44 million during 2009. As of September 30, 2009, £33 million, or $51 million, of contributions had been made to the UK pension plan.

(11)	Income Taxes

Income tax expense decreased $110 million for the third quarter and $167 million for the first nine months of 2009 compared to 2008. The effective tax rates were 10% and 31% for the third quarter of 2009 and 2008, respectively, and 20% and 30% for the first nine months of 2009 and 2008, respectively. The decrease in income tax expense was mainly due to $55 million of income tax benefits recognized in the third quarter of 2009 for the repairs deductions discussed below, lower pre-tax income, favorable settlement of certain tax contingencies and additional production tax credits. Additionally, noncurrent net deferred tax liabilities were $5.42 billion as of September 30, 2009 and $3.949 billion as of December 31, 2008. The higher noncurrent net deferred tax liabilities were due to unrealized gains on the BYD investment, increased tax depreciation related to the addition of wind-powered generating facilities placed in-service during 2008 and 2009, bonus depreciation taken on 2009 qualified capital expenditures, and the repairs deduction discussed below.

PacifiCorp and MidAmerican Energy changed the method by which they determine current income tax deductions for repairs on certain of their regulated utility assets (the “repairs deduction”), which results in current deductibility for certain costs that are capitalized for book purposes. The repairs deduction was computed for tax years 1998 and forward and was deducted on the 2008 income tax returns. Iowa, MidAmerican Funding’s largest jurisdiction for rate regulated operations, requires immediate income recognition of such temporary differences. For the three- and nine-month periods ended September 30, 2009, the Company’s earnings reflect $55 million of net tax benefits recognized from these deductions.

(12)	Commitments and Contingencies

Legal Matters

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

PacifiCorp

In February 2007, the Sierra Club and the Wyoming Outdoor Council filed a complaint against PacifiCorp in the federal district court in Cheyenne, Wyoming, alleging violations of the Wyoming state opacity standards at PacifiCorp’s Jim Bridger plant in Wyoming. Under Wyoming state requirements, which are part of the Jim Bridger plant’s Title V permit and are enforceable by private citizens under the federal Clean Air Act, a potential source of pollutants such as a coal-fired generating facility must meet minimum standards for opacity, which is a measurement of light that is obscured in the flue of a generating facility. The complaint alleges thousands of violations of asserted six-minute compliance periods and seeks an injunction ordering the Jim Bridger plant’s compliance with opacity limits, civil penalties of $32,500 per day per violation and the plaintiffs’ costs of litigation. The court granted a motion to bifurcate the trial into separate liability and remedy phases. In August 2009, the court ruled on a number of summary judgment motions by which it determined that the plaintiffs have sufficient legal standing to proceed with their complaint and that all other issues raised in the summary judgment motions will be resolved at trial. The court also set a scheduling conference for December 2009. PacifiCorp believes it has a number of defenses to the claims. PacifiCorp intends to vigorously oppose the lawsuit but cannot predict its outcome at this time. PacifiCorp has already committed to invest at least $812 million in pollution control equipment at its generating facilities, including the Jim Bridger plant. This commitment is expected to significantly reduce system-wide emissions, including emissions at the Jim Bridger plant.

CalEnergy Generation-Foreign

In February 2002, pursuant to the share ownership adjustment mechanism in the CE Casecnan shareholder agreement, MEHC’s indirect wholly owned subsidiary, CE Casecnan Ltd., advised the minority shareholder of CE Casecnan, LaPrairie Group Contractors (International) Ltd. (“LPG”) that MEHC’s indirect ownership interest in CE Casecnan had increased to 100% effective from commencement of commercial operations. In July 2002, LPG filed a complaint in the Superior Court of the State of California, City and County of San Francisco against CE Casecnan Ltd. and MEHC. LPG’s complaint, as amended, seeks compensatory and punitive damages arising out of CE Casecnan Ltd.’s and MEHC’s alleged improper calculation of the proforma financial projections and alleged improper settlement of the Philippine National Irrigation Administration arbitration. In January 2006, the Superior Court of the State of California entered a judgment in favor of LPG against CE Casecnan Ltd. Pursuant to the judgment, 15% of the distributions of CE Casecnan were deposited into escrow plus interest at 9% per annum. The judgment was appealed, and as a result of the appellate decision, CE Casecnan Ltd. determined that LPG would retain ownership of 10% of the shares of CE Casecnan, with the remaining 5% share to be transferred to CE Casecnan Ltd. subject to certain buy-up rights under the shareholder agreement. The issues relating to the exercise of the buy-up right have been decided by the court and in June 2009, LPG exercised its buy-up rights with respect to the remaining 5% ownership interest. In October 2009, the court issued a Final Judgment declaring that LPG was a 15% shareholder, which Final Judgment remains subject to appeal. The Company intends to vigorously defend and pursue the remaining claims.

In July 2005, MEHC and CE Casecnan Ltd. commenced an action against San Lorenzo Ruiz Builders and Developers Group, Inc. (“San Lorenzo”) in the District Court of Douglas County, Nebraska, seeking a declaratory judgment as to San Lorenzo’s right to repurchase 15% of the shares in CE Casecnan. In January 2006, San Lorenzo filed a counterclaim against MEHC and CE Casecnan Ltd. seeking declaratory relief that it has effectively exercised its option to purchase 15% of the shares of CE Casecnan, that it is the rightful owner of such shares and that it is due all dividends paid on such shares. Currently, the action is in the discovery phase and a trial has been set to begin in March 2010. The impact, if any, of this litigation on the Company cannot be determined at this time. The Company intends to vigorously defend the counterclaims.

Environmental Matters

The Company is subject to federal, state, local and foreign laws and regulations regarding air and water quality, hazardous and solid waste disposal, 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 current environmental requirements.

Accrued Environmental Costs

The Company is fully or partly responsible for environmental remediation at various contaminated sites, including sites that are or were part of the Company’s operations and sites owned by third parties. The Company accrues environmental remediation expenses when the expenses are believed to be probable and can be reasonably estimated. The quantification of environmental exposures is based on many factors, including changing laws and regulations, advancements in environmental technologies, the quality of available site-specific information, site investigation results, expected remediation or settlement timelines, the Company’s proportionate responsibility, contractual indemnities and coverage provided by insurance policies. The liability recorded as of September 30, 2009 and December 31, 2008 was $20 million and $33 million, respectively, and is included in other current liabilities and other long-term liabilities on the Consolidated Balance Sheets. Environmental remediation liabilities that separately result from the normal operation of long-lived assets and that are legal obligations associated with the retirement of those assets are separately accounted for as asset retirement obligations.

Climate Change

In June 2009, the United States House of Representatives passed the American Clean Energy and Security Act of 2009 (“Waxman-Markey bill”), introduced by Representatives Henry Waxman and Edward Markey. In addition to a federal renewable portfolio standard, which would require utilities to obtain a portion of their energy from certain qualifying renewable sources, and energy efficiency measures, the bill requires a reduction in greenhouse gas emissions beginning in 2012, with emission reduction targets of 3% below 2005 levels by 2012; 17% below 2005 levels by 2020; 42% below 2005 levels by 2030; and 83% below 2005 levels by 2050 under a “cap and trade” program. In September 2009, a similar bill was introduced in the United States Senate by Senators Barbara Boxer and John Kerry, which would require a reduction in greenhouse gas emissions beginning in 2012 with emission reduction targets consistent with the Waxman-Markey bill, with the exception of the 2020 target, which requires 20% reductions below 2005 levels. If the Waxman-Markey bill or some other federal comprehensive climate change bill were to pass both Houses of Congress and be signed into law by the President, the impact on the Company’s financial performance could be material and would depend on a number of factors, including the required timing and level of greenhouse gas reductions, the price and availability of offsets and allowances used for compliance and the ability of the Company to receive revenue from customers for increased costs. The new law would likely result in increased operating costs and expenses, additional capital expenditures and retirements of existing assets, and may negatively impact demand for electricity. The Company expects its regulated subsidiaries will be allowed to recover the costs to comply with climate change requirements.

Hydroelectric Relicensing

PacifiCorp’s hydroelectric portfolio consists of 47 generating facilities with an aggregate facility net owned capacity of 1,158 megawatts (“MW”). The FERC regulates 98% of the net capacity of this portfolio through 16 individual licenses, which typically have terms of 30 to 50 years. PacifiCorp is currently actively engaged in the relicensing process with the FERC for its Klamath hydroelectric system.

In February 2004, PacifiCorp filed with the FERC a final application for a new license to operate the 169-MW Klamath hydroelectric system in anticipation of the March 2006 expiration of the existing license. PacifiCorp is currently operating under an annual license issued by the FERC and expects to continue operating under annual licenses until the relicensing process is complete. As part of the relicensing process, the FERC is required to perform an environmental review, and in November 2007, the FERC issued its final environmental impact statement. The United States Fish and Wildlife Service and the National Marine Fisheries Service issued final biological opinions in December 2007 analyzing the Klamath hydroelectric system’s impact on endangered species under a new FERC license consistent with the FERC staff’s recommended license alternative and terms and conditions issued by the United States Departments of the Interior and Commerce. These terms and conditions include construction of upstream and downstream fish passage facilities at the Klamath hydroelectric system’s four mainstem dams. PacifiCorp will need to obtain water quality certifications from Oregon and California prior to the FERC issuing a final license. PacifiCorp currently has water quality applications pending in Oregon and California.

In November 2008, PacifiCorp signed a non-binding agreement in principle (the “AIP”) that laid out a framework for the disposition of PacifiCorp’s Klamath hydroelectric system relicensing process, including a path toward dam transfer and removal by an entity other than PacifiCorp no earlier than 2020. Parties to the AIP are PacifiCorp, the United States Department of the Interior, the State of Oregon and the State of California. Any transfer of facilities and subsequent removal are contingent on PacifiCorp reaching a comprehensive final settlement with the AIP signatories and other stakeholders. As provided in the AIP, PacifiCorp’s support for a definitive settlement will depend on a variety of factors, including the protection for PacifiCorp and its customers from uncapped dam removal costs and liabilities.

The AIP includes provisions to:

·	Perform studies and implement certain measures designed to benefit aquatic species and their habitat in the Klamath Basin;

·	Support and implement legislation in Oregon authorizing a customer surcharge intended to cover potential dam removal; and

·	Require parties to support proposed federal legislation introduced to facilitate a final agreement.

Assuming a final agreement is reached, the United States government will conduct scientific and engineering studies and consult with state, local and tribal governments and other stakeholders, as appropriate, to determine by March 31, 2012 whether the benefits of dam removal will justify the costs.

In addition to signing the AIP, PacifiCorp provided both the United States Fish and Wildlife Service and the National Marine Fisheries Service an interim conservation plan aimed at providing additional protections for endangered species in the Klamath Basin. PacifiCorp is collaborating with both agencies to implement the plan.

PacifiCorp has participated in ongoing negotiations since the AIP was signed in November 2008 to arrive at a draft of the final settlement agreement. The Klamath settlement parties voted to release in September 2009 a public review draft of the final settlement agreement, which is consistent with the AIP framework. The parties will review the draft of the final settlement agreement, and expect to sign a final settlement agreement by the end of 2009.

In July 2009, Oregon’s governor signed a bill authorizing PacifiCorp to collect surcharges from its Oregon customers for Oregon’s share of the customer contribution identified in the AIP for the cost of removing the Klamath River dams. According to the AIP, the total amount to be collected from PacifiCorp’s customers is capped at $200 million. Of this amount, up to $180 million would be collected from PacifiCorp’s Oregon customers with the remainder to be collected from PacifiCorp’s California customers.

Hydroelectric relicensing and the related environmental compliance requirements and litigation are subject to uncertainties. PacifiCorp expects that future costs relating to these matters will be significant and will consist primarily of additional relicensing costs, as well as ongoing operations and maintenance expense and capital expenditures required by its hydroelectric licenses. Electricity generation reductions may result from the additional environmental requirements. PacifiCorp had incurred $65 million and $57 million in costs, included in construction in progress and reflected in property, plant and equipment, net on the Consolidated Balance Sheets, as of September 30, 2009 and December 31, 2008, respectively, for ongoing hydroelectric relicensing. While the costs of implementing new license provisions cannot be determined until such time as a new license is issued, such costs could be material.

FERC Investigation

During 2007, the Western Electricity Coordinating Council (the “WECC”) audited PacifiCorp’s compliance with several of the reliability standards developed by the North American Electric Reliability Corporation (the “NERC”). In April 2008, PacifiCorp received notice of a preliminary non-public investigation from the FERC and the NERC to determine whether an outage that occurred in PacifiCorp’s transmission system in February 2008 involved any violations of reliability standards. In November 2008, PacifiCorp received preliminary findings from the FERC staff regarding its non-public investigation into the February 2008 outage. Also in November 2008, in conjunction with the reliability standards review, the FERC assumed control of certain aspects of the WECC’s 2007 audit. PacifiCorp has engaged in discussions with FERC staff regarding findings related to the WECC audit and the non-public investigation. However, PacifiCorp cannot predict the impact of the audit or the non-public investigation on its consolidated financial results at this time.

(13)	MEHC Shareholders’ Equity

In March 2009, 703,329 common stock options were exercised having an exercise price of $35.05 per share, or $25 million. Also in March 2009, MEHC purchased the shares issued from the options exercised for $148 million. As a result, the Company recognized $125 million of stock-based compensation expense, including the Company’s share of payroll taxes, for the nine-month period ended September 30, 2009, which is included in operating expense on the Consolidated Statement of Operations.

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

Comprehensive income attributable to MEHC consists of the following components (in millions):

	Three-Month Periods Ended September 30,						Nine-Month Periods Ended September 30,
	2009			2008			2009			2008

Net income attributable to MEHC	$	376		$	350		$	864		$	912
Other comprehensive income (loss) attributable to MEHC:
Unrecognized amounts on retirement benefits, net of tax of $6, $12, $(8) and $14		13			30			(24	)		36
Foreign currency translation adjustment		(73	)		(320	)		231			(304	)
Fair value adjustment on cash flow hedges, net of tax of $3, $(22), $(5) and $(13)		7			(33	)		(6	)		(19	)
Unrealized gains (losses) on marketable securities, net of tax of $651, $(4), $653 and $(12)		978			(7	)		981			(18	)
Total other comprehensive income (loss) attributable to MEHC		925			(330	)		1,182			(305	)

Comprehensive income attributable to MEHC	$	1,301		$	20		$	2,046		$	607

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

	As of
	September 30,			December 31,
	2009			2008

Unrecognized amounts on retirement benefits, net of tax of $(164) and $(156)	$	(425	)	$	(401	)
Foreign currency translation adjustment		(215	)		(446	)
Fair value adjustment on cash flow hedges, net of tax of $(8) and $(3)		(13	)		(7	)
Unrealized gains (losses) on marketable securities, net of tax of $637 and $(16)		956			(25	)
Total accumulated other comprehensive income (loss) attributable to MEHC, net	$	303		$	(879	)

(15)	Segment Information

MEHC’s reportable segments were determined based on how the Company’s strategic units are managed. The Company’s foreign reportable segments include CE Electric UK, whose business is principally in Great Britain, and CalEnergy Generation-Foreign, whose business is in the Philippines. Intersegment transactions, including the allocation of goodwill, have been eliminated or adjusted, as appropriate. 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,
	2009			2008			2009			2008

Operating revenue:
PacifiCorp	$	1,146		$	1,245		$	3,278		$	3,395
MidAmerican Funding		812			1,107			2,711			3,561
Northern Natural Gas		116			149			477			520
Kern River		90			126			283			340
CE Electric UK		214			245			604			773
CalEnergy Generation-Foreign		51			38			107			96
CalEnergy Generation-Domestic		9			8			24			23
HomeServices		312			330			764			913
Corporate/other(1)		(9	)		(8	)		(36	)		(33	)
Total operating revenue	$	2,741		$	3,240		$	8,212		$	9,588

Depreciation and amortization:
PacifiCorp	$	139		$	123		$	414		$	364
MidAmerican Funding		85			61			251			210
Northern Natural Gas		16			15			47			44
Kern River		24			15			72			58
CE Electric UK		44			48			121			138
CalEnergy Generation-Foreign		6			6			17			17
CalEnergy Generation-Domestic		2			2			6			6
HomeServices		5			4			13			14
Corporate/other(1)		(3	)		(6	)		(12	)		(13	)
Total depreciation and amortization	$	318		$	268		$	929		$	838

Operating income:
PacifiCorp	$	299		$	268		$	796		$	717
MidAmerican Funding		123			159			363			438
Northern Natural Gas		37			95			238			295
Kern River		54			99			174			244
CE Electric UK		109			115			306			399
CalEnergy Generation-Foreign		42			30			82			72
CalEnergy Generation-Domestic		4			5			12			12
HomeServices		18			1			16			(10	)
Corporate/other(1)		(25	)		(1	)		(165	)		(41	)
Total operating income		661			771			1,822			2,126
Interest expense		(316	)		(340	)		(957	)		(998	)
Capitalized interest		12			14			30			37
Interest and dividend income		8			16			36			47
Other, net		41			19			119			59
Total income before income tax expense and equity income	$	406		$	480		$	1,050		$	1,271

	Three-Month Periods				Nine-Month Periods
	Ended September 30,				Ended September 30,
	2009		2008		2009		2008
Interest expense:
PacifiCorp	$	102	$	91	$	310	$	255
MidAmerican Funding		48		52		148		153
Northern Natural Gas		15		17		45		46
Kern River		14		16		42		52
CE Electric UK		39		51		109		148
CalEnergy Generation-Foreign		1		2		3		6
CalEnergy Generation-Domestic		4		4		12		13
HomeServices		-		-		-		1
Corporate/other(1)		93		107		288		324
Total interest expense	$	316	$	340	$	957	$	998

	As of
	September 30,		December 31,
	2009		2008
Total assets:
PacifiCorp	$	19,635	$	18,339
MidAmerican Funding		10,566		10,632
Northern Natural Gas		2,637		2,595
Kern River		1,846		1,910
CE Electric UK		5,516		4,921
CalEnergy Generation-Foreign		482		442
CalEnergy Generation-Domestic		582		550
HomeServices		671		674
Corporate/other(1)		2,055		1,378
Total assets	$	43,990	$	41,441

(1)

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

Goodwill is allocated to each reportable segment included in total assets above. Goodwill as of December 31, 2008 and the changes for the nine-month period ended September 30, 2009 by reportable segment are as follows (in millions):

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

Goodwill at December 31, 2008	$	1,126	$	2,102	$	249		$	34	$	1,050	$	71	$	391	$	5,023
Foreign currency translation		-		-		-			-		73		-		-		73
Other		-		-		(20	)		-		-		-		-		(20	)
Goodwill at September 30, 2009	$	1,126	$	2,102	$	229		$	34	$	1,123	$	71	$	391	$	5,076

Item 2.

Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following is management’s discussion and analysis of certain significant factors that have affected the financial condition and results of operations of MidAmerican Energy Holdings Company (“MEHC”) and its subsidiaries (collectively, the “Company”) during the periods included herein. Explanations include management’s best estimate of the impact of weather, customer growth and other factors. This discussion should be read in conjunction with the Company’s historical unaudited Consolidated Financial Statements and Notes to Consolidated Financial Statements included in Item 1 of this Form 10-Q. The Company’s actual results in the future could differ significantly from the historical results.

Forward-Looking Statements

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

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

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

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

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

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

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

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

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

changes in business strategy or development plans;

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

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

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

risks relating to nuclear generation;

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

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

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

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

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

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

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

other business or investment considerations that may be disclosed from time to time in MEHC’s filings with the United States Securities and Exchange Commission (the “SEC”) or in other publicly disseminated written documents.

Further details of the potential risks and uncertainties affecting the Company are described in MEHC’s filings with the SEC, including Part II, Item 1A and other discussions contained in this Form 10-Q. The Company undertakes no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. The foregoing review of factors should not be construed as exclusive.

Results of Operations for the Third Quarter and First Nine Months of 2009 and 2008

Overview

Net income attributable to MEHC for the third quarter of 2009 was $376 million, an increase of $26 million, or 7%, and for the first nine months of 2009 was $864 million, a decrease of $48 million, or 5%, compared to 2008. The results for the first nine months of 2009 included an after-tax stock-based compensation charge of $75 million as a result of the purchase of shares of common stock that were issued upon the exercise of stock options and an after-tax gain on the Constellation Energy Group, Inc. (“Constellation Energy”) common stock investment of $22 million. Excluding the impact of these items, net income attributable to MEHC increased $5 million, or 1%, for the first nine months of 2009 compared to 2008. Net income attributable to MEHC for the third quarter and the first nine months of 2009 compared to 2008 increased due to higher net income at PacifiCorp, MidAmerican Funding, CalEnergy Generation-Foreign and HomeServices, partially offset by lower net income at Northern Natural Gas, Kern River and CE Electric UK.

Net income was higher at PacifiCorp as a result of lower energy costs, higher rates approved by regulators and lower income taxes, partially offset by lower retail volumes and higher depreciation and amortization. MidAmerican Funding’s net income increased due to income tax benefits of $55 million for repairs deductions, additional production tax credits and lower maintenance costs as a result of the storm and flood damage in 2008, partially offset by lower regulated electric margins of $11 million for the third quarter and $51 million for the first nine months from lower wholesale revenues and lower retail volumes and higher depreciation and amortization. Net income was higher at CalEnergy Generation-Foreign due to higher rainfall and related revenue earned at the Casecnan project and higher at HomeServices due to lower operating expenses.

Net income at Northern Natural Gas and Kern River was lower as a result of less favorable market conditions, a reduction in Kern River’s customer refund liability in 2008 of $10 million for the third quarter and $22 million for the first nine months and a $16 million after-tax gain on the sale of certain non-strategic operating assets at Northern Natural Gas in the third quarter of 2008. Net income was lower at CE Electric UK due primarily to a stronger United States dollar that reduced net income $7 million for the third quarter and $38 million for the first nine months of 2009 compared to 2008.

Segment Results

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

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

	Third Quarter											First Nine Months
	2009			2008			Change					2009			2008			Change
Operating revenue:
PacifiCorp	$	1,146		$	1,245		$	(99	)	(8	)%	$	3,278		$	3,395		$	(117	)	(3	)%
MidAmerican Funding		812			1,107			(295	)	(27	)		2,711			3,561			(850	)	(24	)
Northern Natural Gas		116			149			(33	)	(22	)		477			520			(43	)	(8	)
Kern River		90			126			(36	)	(29	)		283			340			(57	)	(17	)
CE Electric UK		214			245			(31	)	(13	)		604			773			(169	)	(22	)
CalEnergy Generation-Foreign		51			38			13		34			107			96			11		11
CalEnergy Generation-Domestic		9			8			1		13			24			23			1		4
HomeServices		312			330			(18	)	(5	)		764			913			(149	)	(16	)
Corporate/other		(9	)		(8	)		(1	)	(13	)		(36	)		(33	)		(3	)	(9	)
Total operating revenue	$	2,741		$	3,240		$	(499	)	(15	)	$	8,212		$	9,588		$	(1,376	)	(14	)

Operating income:
PacifiCorp	$	299		$	268		$	31		12	%	$	796		$	717		$	79		11	%
MidAmerican Funding		123			159			(36	)	(23	)		363			438			(75	)	(17	)
Northern Natural Gas		37			95			(58	)	(61	)		238			295			(57	)	(19	)
Kern River		54			99			(45	)	(45	)		174			244			(70	)	(29	)
CE Electric UK		109			115			(6	)	(5	)		306			399			(93	)	(23	)
CalEnergy Generation-Foreign		42			30			12		40			82			72			10		14
CalEnergy Generation-Domestic		4			5			(1	)	(20	)		12			12			-		-
HomeServices		18			1			17		*			16			(10	)		26		*
Corporate/other		(25	)		(1	)		(24	)	*			(165	)		(41	)		(124	)	*
Total operating income	$	661		$	771		$	(110	)	(14	)	$	1,822		$	2,126		$	(304	)	(14	)

*	Not meaningful

PacifiCorp

Operating revenue decreased $99 million for the third quarter of 2009 compared to 2008 due to a decrease in wholesale and other revenue of $78 million and unfavorable changes in the fair value of energy sales contracts accounted for as derivatives of $46 million, partially offset by higher retail revenue of $25 million. The decrease in wholesale and other revenue was due primarily to a 39% decrease in average wholesale prices, partially offset by revenue attributable to PacifiCorp’s majority owned coal mining operations. The increase in retail revenue was due to higher prices approved by regulators totaling $35 million, partially offset by a 3% decrease in retail volumes. The decrease in retail volumes is principally related to lower average customer usage due to the effect of current economic conditions mainly on industrial customers in Wyoming and Oregon, partially offset by growth in the average number of commercial customers. Total retail and wholesale sales volumes decreased 3%.

Operating income increased $31 million for the third quarter of 2009 compared to 2008 due to lower energy costs of $156 million, partially offset by lower revenue of $99 million, higher depreciation and amortization of $17 million due to the addition of new generating facilities and higher operating expenses of $11 million due primarily to costs attributable to PacifiCorp’s majority owned coal mining operations. Energy costs were lower due largely to a 40% decrease in the average cost of purchased electricity, a 13% decrease in the volume of purchased electricity and favorable changes in the fair value of energy purchase contracts accounted for as derivatives of $44 million. The addition of the Chehalis natural gas plant and new wind generating facilities in the second half of 2008 and the first quarter of 2009, along with the 3% decrease in overall sales volumes, allowed PacifiCorp to reduce its need for purchased electricity.

Operating revenue decreased $117 million for the first nine months of 2009 compared to 2008 due a decrease in wholesale and other revenue of $124 million, partially offset by higher retail revenue of $15 million. The decrease in wholesale and other revenue was due primarily to a 26% decrease in average wholesale prices, partially offset by revenue attributable to PacifiCorp’s majority owned coal mining operations. The increase in retail revenue was due to higher prices approved by regulators totaling $76 million, partially offset by a 4% decrease in retail volumes. The decrease in retail volumes is principally related to lower average customer usage due to the effect of current economic conditions mainly on industrial customers across PacifiCorp’s service territories and on residential customers in Oregon, partially offset by growth in the average number of commercial and residential customers mainly in Utah. Total retail and wholesale sales volumes decreased 3%.

Operating income increased $79 million for the first nine months of 2009 compared to 2008 due to lower energy costs of $285 million, partially offset by lower revenue of $117 million, higher depreciation and amortization of $51 million due to the addition of new generating facilities and higher operating expenses of $39 million due primarily to costs attributable to PacifiCorp’s majority owned coal mining operations. Energy costs were lower due largely to a 38% decrease in the average cost of purchased electricity, a 10% decrease in the volume of purchased electricity and favorable changes in the fair value of energy purchase contracts accounted for as derivatives of $22 million, partially offset by the effects of regulatory cost recovery adjustment mechanisms of $26 million. The addition of the Chehalis natural gas plant and new wind generating facilities in the second half of 2008 and the first quarter of 2009, along with the 3% decrease in overall sales volumes, allowed PacifiCorp to reduce its need for purchased electricity.

MidAmerican Funding

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

	Third Quarter											First Nine Months
	2009			2008			Change					2009		2008		Change
Operating revenue:
Regulated electric	$	451		$	552		$	(101	)	(18	)%	$	1,286	$	1,527	$	(241	)	(16	)%
Regulated natural gas		85			192			(107	)	(56	)		591		1,043		(452	)	(43	)
Nonregulated and other		276			363			(87	)	(24	)		834		991		(157	)	(16	)
Total operating revenue	$	812		$	1,107		$	(295	)	(27	)	$	2,711	$	3,561	$	(850	)	(24	)

Operating income:
Regulated electric	$	112		$	148		$	(36	)	(24	)%	$	272	$	353	$	(81	)	(23	)%
Regulated natural gas		(4	)		(5	)		1		20			43		43		-		-
Nonregulated and other		15			16			(1	)	(6	)		48		42		6		14
Total operating income	$	123		$	159		$	(36	)	(23	)	$	363	$	438	$	(75	)	(17	)

Regulated electric operating revenue decreased $101 million for the third quarter of 2009 compared to 2008. Wholesale and other revenue decreased $87 million due to a 43% decrease in average wholesale prices and a 15% decrease in volumes, resulting from reduced demand for electricity due to the current economic conditions and mild temperatures. Retail revenue decreased $14 million on lower volumes of 5% primarily related to mild temperatures experienced throughout the service territory in 2009. Total retail and wholesale sales volumes decreased by 9%.

Regulated electric operating income decreased $36 million for the third quarter of 2009 compared to 2008. The lower revenue was largely offset by a decrease in the cost of energy of $81 million as a result of lower purchased electricity of $70 million and a lower cost of natural gas of $16 million, which were both due to lower average costs and volumes. The addition of new wind generating facilities in 2008 allowed MidAmerican Funding to replace more expensive sources of electricity. Depreciation and amortization increased $25 million, primarily due to the addition of new wind and other generating facilities that increased depreciation and amortization by $14 million and a change in Iowa revenue sharing. Operating expenses decreased $8 million due largely to lower maintenance costs as a result of the storm and flood damage in 2008.

Regulated natural gas operating revenue decreased $107 million for the third quarter of 2009 compared to 2008 due primarily to a reduction in the average per-unit cost of gas sold, which was passed on to customers and resulted in lower cost of sales, and lower sales volumes of 34%, due principally to lower wholesale volumes as a result of fewer market opportunities due to lower price spreads.

Nonregulated and other operating revenue decreased $87 million for the third quarter of 2009 compared to 2008 due to lower gas revenue of $99 million as a result of a 76% decrease in average prices and a 15% decrease in volumes, partially offset by higher electric retail revenue of $16 million due to a 12% increase in volumes, partially offset by a 5% decrease in average prices. Nonregulated and other operating income decreased $1 million for the third quarter of 2009 compared to 2008 as lower cost of sales largely offset the lower revenue.

Regulated electric operating revenue decreased $241 million for the first nine months of 2009 compared to 2008. Wholesale and other revenue decreased $217 million due to a 38% decrease in average wholesale prices and an 11% decrease in volumes, resulting from reduced demand for electricity due to the current economic conditions and mild temperatures. Retail revenue decreased $24 million on lower volumes of 4% primarily related to lower industrial load and mild temperatures experienced throughout the service territory in 2009. Total retail and wholesale sales volumes decreased by 7%.

Regulated electric operating income decreased $81 million for the first nine months of 2009 compared to 2008. The lower revenue was largely offset by a decrease in the cost of energy of $196 million as a result of lower purchased electricity of $157 million and a lower cost of natural gas of $41 million, which were both due to lower average costs and volumes. The addition of new wind generating facilities in 2008 allowed MidAmerican Funding to replace more expensive sources of electricity. Depreciation and amortization increased $40 million due to the addition of new wind and other generating facilities. Operating expenses decreased $4 million due largely to lower maintenance costs as a result of the storm and flood damage in 2008.

Regulated natural gas operating revenue decreased $452 million for the first nine months of 2009 compared to 2008 due primarily to a reduction in the average per-unit cost of gas sold, which was passed on to customers and resulted in lower cost of sales, and lower sales volumes of 10% as a result of mild weather experienced throughout the service territory in 2009 and lower wholesale volumes as a result of fewer market opportunities due to lower price spreads. Regulated natural gas operating income was flat for the first nine months of 2009 compared to 2008 as lower cost of sales and operating expenses offset the lower revenue.

Nonregulated and other operating revenue decreased $157 million for the first nine months of 2009 compared to 2008 due to lower gas revenue of $197 million as a result of a 50% decrease in average prices and a 13% decrease in volumes, partially offset by higher electric retail revenue of $45 million due to a 7% increase in volumes. Nonregulated and other operating income increased $6 million for the first nine months of 2009 compared to 2008 due primarily to higher electric and gas margins.

Northern Natural Gas

Operating revenue decreased $33 million for the third quarter and $43 million for the first nine months of 2009 compared to 2008 due to lower transportation revenue of $31 million and $41 million, respectively, due to lower demand caused by less favorable economic conditions, lower natural gas price spreads and the sale of the Beaver system in 2008. Operating income decreased $58 million for the third quarter and $57 million for the first nine months of 2009 compared to 2008 due to lower transportation revenue and a pre-tax gain on the sale of certain non-strategic operating assets of $26 million in the third quarter of 2008, partially offset by lower operating expenses for the first nine months.

Kern River

Operating revenue decreased $36 million for the third quarter and $57 million for the first nine months of 2009 compared to 2008 due to lower price spreads and a reduction in Kern River’s customer refund liability in 2008, which resulted in lower revenue of $7 million for the third quarter and $27 million for the first nine months. Operating income decreased $45 million for the third quarter and $70 million for the first nine months of 2009 compared to 2008 due to the lower operating revenue and higher depreciation and amortization of $9 million for the third quarter and $14 million for the first nine months.

CE Electric UK

Operating revenue decreased $31 million for the third quarter of 2009 compared to 2008 due to the impact from the foreign currency exchange rate totaling $33 million and lower contracting revenue of $7 million, partially offset by higher distribution revenue. Distribution revenue increased as tariff rates were increased in April 2009 to bill under-recovered amounts under the regulatory formula, partially offset by lower volumes of units distributed due predominantly to the recession, and to a lesser extent the weather. Operating income decreased $6 million for the third quarter of 2009 compared to 2008 due mainly to the impact from the foreign currency exchange rate on operating income totaling $16 million, partially offset by the higher distribution revenue.

Operating revenue decreased $169 million for the first nine months of 2009 compared to 2008 due to the impact from the foreign currency exchange rate totaling $159 million and lower contracting revenue of $19 million, partially offset by higher distribution revenue of $6 million. Operating income decreased $93 million for the first nine months of 2009 compared to 2008 due to the impact from the foreign currency exchange rate on operating income totaling $82 million and higher depreciation and amortization of $14 million reflecting additional capital expenditures, partially offset by the higher distribution revenue.

CalEnergy Generation-Foreign

Operating revenue increased $13 million and operating income increased $12 million for the third quarter and operating revenue increased $11 million and operating income increased $10 million for the first nine months of 2009 compared to 2008 due to higher rainfall and related variable water delivery fees earned in 2009 at the Casecnan project.

HomeServices

Operating revenue decreased $18 million for the third quarter and $149 million for the first nine months of 2009 compared to 2008 due to declines in average home sale prices of 9% and 12%, respectively, and a decline in transaction volumes of 9% for the first nine months of 2009 reflecting the continuing weak United States housing market. Transaction volumes were up slightly for the third quarter of 2009. Operating income increased $17 million for the third quarter and $26 million for the first nine months of 2009 compared to 2008 due to lower commissions, operating expenses and office closure costs, partially offset by the lower revenue.

Corporate/other

Operating income decreased $24 million for the third quarter of 2009 compared to 2008 due to higher deferred compensation and captive insurance claims. Operating income decreased $124 million for the first nine months of 2009 compared to 2008 due mainly to $125 million of stock-based compensation expense, including the Company’s share of payroll taxes, as a result of the purchase of common stock issued by MEHC upon the exercise of the last remaining stock options that had been granted to certain members of management at the time of Berkshire Hathaway Inc.’s (“Berkshire Hathaway”) acquisition of MEHC in 2000.

Consolidated Other Income and Expense Items

Interest Expense

Interest expense is summarized as follows (in millions):

	Third Quarter									First Nine Months
	2009		2008		Change					2009		2008		Change

Subsidiary debt	$	212	$	223	$	(11	)	(5	)%	$	644	$	643	$	1		-	%
MEHC senior debt and other		85		88		(3	)	(3	)		249		267		(18	)	(7	)
MEHC subordinated debt - Berkshire Hathaway		13		22		(9	)	(41	)		47		67		(20	)	(30	)
MEHC subordinated debt - other		6		7		(1	)	(14	)		17		21		(4	)	(19	)
Total interest expense	$	316	$	340	$	(24	)	(7	)	$	957	$	998	$	(41	)	(4	)

Interest expense decreased $24 million for the third quarter and $41 million for the first nine months of 2009 compared to 2008 due to debt retirements, scheduled principal repayments and the impact of the foreign currency exchange rate of $12 million for the third quarter and $32 million for the first nine months. The decreases were partially offset by debt issuances in 2009 at MEHC and 2008 and 2009 at PacifiCorp.

Interest and Dividend Income

Interest and dividend income decreased $8 million for the third quarter and $11 million for the first nine months of 2009 compared to 2008 due to less favorable cash positions in 2009 and dividends in 2008 related to the investment in Constellation Energy 8% preferred stock.

Other, Net

Other, net increased $22 million for the third quarter and $60 million for the first nine months of 2009 compared to 2008 due to higher earnings on deferred compensation investments and higher equity allowance for funds used during construction (“AFUDC”) due primarily to higher average construction in progress at PacifiCorp, partially offset by lower average construction in progress at MidAmerican Funding. Additionally, the first nine months of 2009 increased due to the pre-tax gain on the Constellation Energy common stock investment totaling $37 million.

Income Tax Expense

Income tax expense decreased $110 million for the third quarter and $167 million for the first nine months of 2009 compared to 2008. The effective tax rates were 10% and 31% for the third quarter of 2009 and 2008, respectively, and 20% and 30% for the first nine months of 2009 and 2008, respectively. The decrease in income tax expense was mainly due to $55 million of income tax benefits recognized in the third quarter of 2009 for a change in tax accounting method for repairs deductions and the related regulatory treatment in Iowa, MidAmerican Funding’s largest jurisdiction for rate regulated operations, which requires immediate income recognition of such temporary differences, lower pre-tax income, favorable settlement of certain tax contingencies and additional production tax credits.

Equity Income

Equity income increased $16 million for the first nine months of 2009 compared to 2008 due to higher equity earnings at HomeServices related to refinance activity in its mortgage business and at CE Generation, LLC due mainly to lower fuel and maintenance costs.

Net Income Attributable to Noncontrolling Interests

Net income attributable to noncontrolling interests increased $7 million for the third quarter and $10 million for the first nine months of 2009 compared to 2008 due mainly to higher earnings attributable to PacifiCorp’s majority owned coal mining operations.

Liquidity and Capital Resources

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

As of September 30, 2009, the Company’s total net liquidity available was $6.798 billion. The components of total net liquidity available are as follows (in millions):

										Other
							MidAmerican			Reporting
	MEHC			PacifiCorp			Funding			Segments			Total(1)

Cash and cash equivalents	$	321		$	149		$	8		$	266		$	744

Available revolving credit facilities	$	835		$	1,395		$	654		$	285		$	3,169
Less:
Short-term borrowings and issuances of commercial paper		-			-			-			(120	)		(120	)
Tax-exempt bond support, letters of credit and other		(42	)		(258	)		(195	)		-			(495	)
Net revolving credit facilities available	$	793		$	1,137		$	459		$	165		$	2,554

Net liquidity available before Berkshire Equity Commitment	$	1,114		$	1,286		$	467		$	431		$	3,298
Berkshire Equity Commitment(2)		3,500												3,500
Total net liquidity available	$	4,614											$	6,798
Unsecured revolving credit facilities:
Maturity date(3)		2009, 2013			2012-2013			2013			2010
Largest single bank commitment as a % of total(4)		30	%		15	%		23	%		28	%

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

(2)	On March 1, 2006, MEHC and Berkshire Hathaway entered into the Berkshire Equity Commitment pursuant to which Berkshire Hathaway has agreed to purchase up to $3.5 billion of MEHC’s common equity upon any requests authorized from time to time by MEHC’s Board of Directors. The proceeds of any such equity contribution shall only be used for the purpose of (i) paying when due MEHC’s debt obligations and (ii) funding the general corporate purposes and capital requirements of MEHC’s regulated subsidiaries. The Berkshire Equity Commitment expires on February 28, 2011.

(3)	MEHC had a $250 million credit facility that was terminated by the Company in October 2009 and is included in the above table. MidAmerican Energy had a $250 million credit facility that was terminated by MidAmerican Energy in the third quarter of 2009 and is excluded from the above table. For further discussion regarding the Company’s credit facilities, refer to Note 10 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, 2008.

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

The Company’s cash and cash equivalents were $744 million as of September 30, 2009, compared to $280 million as of December 31, 2008. The Company has restricted cash and investments included in other current assets and investments and other assets on the Consolidated Balance Sheets totaling $420 million and $395 million as of September 30, 2009 and December 31, 2008, respectively, related to (i) the Company’s debt service reserve requirements relating to certain projects, (ii) funds held in trust related to nuclear decommissioning and coal mine reclamation and (iii) unpaid dividends declared obligations. The debt service funds are restricted by their respective project debt agreements to be used only for the related project.

Operating Activities

Net cash flows from operating activities for the nine-month periods ended September 30, 2009 and 2008 were $2.983 billion and $2.005 billion, respectively. Operating cash flows for the nine-month period ended September 30, 2009, include $140 million of net cash flows related to the Constellation Energy transaction, which is comprised of $536 million of proceeds received from the sale of Constellation Energy common stock and $396 million of income tax paid on gains recognized on the termination of the Constellation Energy merger agreement in December 2008 and the sale of stock in 2009. The remaining increase in operating cash flows was due to higher income tax receipts, changes in collateral posted for derivative contracts and working capital, partially offset by the impact from the foreign currency exchange rate. Income tax receipts were higher due primarily to lower pre-tax income, the current repairs deduction and additional production tax credits.

Investing Activities

Net cash flows from investing activities for the nine-month periods ended September 30, 2009 and 2008 were $(1.846) billion and $(3.569) billion, respectively. In February 2008, the Company received proceeds from the maturity of a guaranteed investment contract of $393 million. In September 2008, the Company made a $1.0 billion investment in Constellation Energy’s 8% preferred stock and acquired Chehalis Power Generation, LLC for $308 million. In December 2008, MEHC and Constellation Energy entered into a termination agreement, which resulted in, among other things, the conversion of the $1.0 billion investment in Constellation Energy’s 8% preferred stock into $1.0 billion of 14% Senior Notes due from Constellation Energy. In January 2009, the Company received $1.0 billion, plus accrued interest, in full satisfaction of the 14% Senior Notes from Constellation Energy. In July 2009, the Company purchased 225 million shares, representing approximately a 10% interest, of BYD Company Limited common stock for $232 million. Capital expenditures decreased $86 million due primarily to lower capital expenditures in 2009 associated with the construction of wind-powered generating facilities at MidAmerican Funding, partially offset by higher capital expenditures at PacifiCorp associated with wind-powered generating facilities, including payments for wind-powered facilities placed in-service in December 2008, and transmission system investment.

Capital Expenditures

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

	Nine-Month Periods
	Ended September 30,
	2009		2008
Capital expenditures(1):
PacifiCorp	$	1,766	$	1,111
MidAmerican Funding		348		1,104
Northern Natural Gas		140		112
CE Electric UK		297		328
Other		41		23
Total capital expenditures	$	2,592	$	2,678

(1)	Excludes amounts for non-cash equity AFUDC.

The Company’s capital expenditures relate primarily to PacifiCorp and MidAmerican Energy. Combined, both utilities’ capital expenditures consisted mainly of the following for the nine-month periods ended September 30:

2009:

·	Transmission system investment totaling $573 million, including a major segment of the Energy Gateway Transmission Expansion Project at PacifiCorp.

·	The development and construction of wind-powered generating facilities totaling $391 million. During 2009, PacifiCorp placed in service 265.5 megawatts (“MW”) of wind-powered generating facilities.

·	Emissions control equipment totaling $246 million.

·	Distribution, generation, mining and other infrastructure needed to serve existing and expected growing demand totaling $904 million.

2008:

·	The development and construction of wind-powered generating facilities totaling $1.08 billion.

·	Emissions control equipment totaling $198 million.

·	Transmission system investment totaling $164 million.

·	Distribution, generation, mining and other infrastructure needed to serve existing and expected growing demand totaling $773 million.

Financing Activities

Net cash flows from financing activities for the nine-month period ended September 30, 2009 were $(676) million. Uses of cash totaled $1.918 billion and consisted mainly of $667 million for repayments of MEHC subordinated debt, $506 million for net repayments of subsidiary short-term debt, $383 million for repayments of subsidiary debt, $216 million for net repayments of the MEHC revolving credit facility and $123 million for net purchases of common stock. Sources of cash totaled $1.242 billion and consisted of proceeds from the issuance of subsidiary debt totaling $992 million and proceeds from the issuance of MEHC senior debt totaling $250 million.

Net cash flows from financing activities for the nine-month period ended September 30, 2008 were $920 million. Sources of cash totaled $3.421 billion and consisted mainly of proceeds from the issuance of MEHC senior and subordinated debt totaling $1.649 billion, subsidiary debt totaling $1.498 billion and the net proceeds from subsidiary short-term debt totaling $274 million. Uses of cash totaled $2.501 billion and consisted mainly of $1.213 billion for repayments and purchases of subsidiary debt, $1.167 billion for repayments of MEHC senior and subordinated debt and a $99 million net payment of hedging instruments related to the maturity of United States dollar denominated debt at CE Electric UK.

Long-term Debt

In July 2009, MEHC issued $250 million of its 3.15% Senior Notes due July 15, 2012. The net proceeds are being used for general corporate purposes.

In January 2009, MEHC repaid the remaining $500 million to affiliates of Berkshire Hathaway in full satisfaction of the aggregate amount owed pursuant to the $1 billion of 11% mandatory redeemable trust preferred securities issued by MidAmerican Capital Trust IV to affiliates of Berkshire Hathaway in September 2008.

Future Uses of Cash

The Company has available a variety of sources of liquidity and capital resources, both internal and external, including net cash flows from operating activities, public and private debt offerings, the issuance of commercial paper, the use of unsecured revolving credit facilities, the issuance of equity and other sources. These sources are expected to provide funds required for current operations, capital expenditures, acquisitions, investments, debt retirements and other capital requirements. The availability and terms under which each subsidiary has access to external financing depends on a variety of factors, including its credit rating, investors’ judgment of risk and conditions in the overall capital market, including the condition of the utility industry in general. Additionally, the Berkshire Equity Commitment can be used for the purpose of (i) paying when due MEHC’s debt obligations and (ii) 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. The Berkshire Equity Commitment expires on February 28, 2011.

Capital Expenditures

The Company has significant future capital requirements. Forecasted capital expenditures for 2009, which exclude non-cash equity AFUDC, are approximately $3.4 billion. Capital expenditure needs are reviewed regularly by management and may change significantly as a result of such reviews, which may consider, among other factors, changes in rules and regulations, including environmental and nuclear, changes in income tax laws, general business conditions, load projections, system reliability standards, the cost and efficiency of construction labor, equipment and materials, and the cost and availability of capital.

Forecasted capital expenditures for 2009 include the following:

PacifiCorp expects to spend $524 million for the Energy Gateway Transmission Expansion Project, which includes the construction of a 135-mile, double-circuit, 345-kilovolt transmission line to be built between the Populus substation located in southern Idaho and the Terminal substation located in the Salt Lake City, Utah area, one of the first major segments of the project.

·	Combined, PacifiCorp and MidAmerican Energy anticipate spending $445 million on wind-powered generating facilities.

·	Combined, PacifiCorp and MidAmerican Energy are projecting to spend $392 million for emissions control equipment in 2009.

·	Remaining amounts are for distribution, transmission, generation, mining and other infrastructure needed to serve existing and expected growing demand.

The above estimates also include PacifiCorp’s commitments for investments in emissions reduction technology resulting from MEHC’s acquisition of PacifiCorp as discussed further in Note 18 of Notes to Consolidated Financial Statements in Item 8 of the Company’s Annual Report on Form 10-K. Evaluation and development efforts are in progress related to additional prospective wind-powered generating facilities scheduled for completion during and after 2009.

MidAmerican Energy continues to evaluate additional cost-effective wind-powered generation. In March 2009, MidAmerican Energy filed with the Iowa Utilities Board for its approval of a settlement agreement between MidAmerican Energy and the Iowa Office of Consumer Advocate (“OCA”) in conjunction with MidAmerican Energy’s ratemaking principles application to construct up to 1,001 MW (nameplate ratings) of additional wind-powered generation in Iowa through 2012. MidAmerican Energy has not entered into any material contracts for the development or construction of new wind-powered generation or the purchase of any related wind turbines.

The Company is subject to federal, state, local and foreign laws and regulations with regard to air and water quality, 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 future costs (beyond existing planned capital expenditures) of complying with applicable environmental laws, regulations and rules cannot yet be reasonably estimated but could be material to the Company. The Company is not aware of any proven, commercially available technology that eliminates or captures and stores carbon dioxide emissions from coal-fired and natural gas-fired generating facilities, and the Company is uncertain when, or if, such technology will be commercially available. Refer to the “Environmental Regulation” section of Item 1 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2008, Note 12 of Notes to Consolidated Financial Statements included in Item 1 of this Form 10-Q and the “Environmental Regulation” section of this Form 10-Q for a detailed discussion of environmental matters affecting the Company.

Contractual Obligations

Subsequent to December 31, 2008, there were no material changes outside the normal course of business in contractual obligations from the information provided in Item 7 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2008, other than the 2009 debt issuances previously discussed. Additionally, refer to the “Capital Expenditures” discussion included in “Liquidity and Capital Resources.”

Regulatory Matters

In addition to the updates contained herein regarding updates to regulatory matters based upon material changes that occurred subsequent to December 31, 2008, refer to Note 4 of Notes to Consolidated Financial Statements included in Item 1 of this Form 10-Q for additional regulatory matter updates.

PacifiCorp

Utah

In July 2008, PacifiCorp filed a general rate case with the Utah Public Service Commission (the “UPSC”) requesting an annual increase of $161 million prior to any consideration of the UPSC’s order in the 2007 general rate case. In September 2008, PacifiCorp filed supplemental testimony that reflected then-current revenues and other adjustments based on the August 2008 order in the 2007 general rate case. The supplemental filing reduced PacifiCorp’s request to $115 million. In October 2008, the UPSC issued an order changing the test period from the twelve months ending June 2009 using end-of-period rate base to the forecast calendar year 2009 using average rate base. In December 2008, PacifiCorp updated its filing to reflect the change in the test period. The updated filing proposed an increase of $116 million. In March 2009, a settlement agreement was filed with the UPSC resolving all remaining revenue requirement issues resulting in parties agreeing, among other settlement terms, on an annual increase of $45 million, or an average price increase of 3%, effective May 8, 2009. In April 2009, the UPSC issued its final order approving the revenue requirement settlement agreement.

In March 2009, Utah’s governor signed Senate Bill 75 that provides additional regulatory tools for the UPSC to use in the rate making process. The additional tools provided in the legislation allow for single item cost recovery of major capital investments outside of the general rate case process and allow for, but do not require, the use of an energy balancing account.

In March 2009, PacifiCorp filed for an energy cost adjustment mechanism (“ECAM”) with the UPSC. The filing recommends that the UPSC adopt the ECAM to recover the difference between base net power costs set in the next Utah general rate case and actual net power costs. The UPSC has separated the application into two phases to first address whether the mechanism is in the public interest, and then if it is found to be in the public interest, determine the type of mechanism that should be implemented. The public interest phase is scheduled for completion in January 2010.

In June 2009, PacifiCorp filed a general rate case with the UPSC for an increase of $67 million, or an average price increase of 5%. If approved, rates will be effective February 18, 2010. The forecasted test period is the twelve months ending June 30, 2010.

In June 2009, PacifiCorp filed with the UPSC to increase its demand-side management (“DSM”) cost recovery mechanism in Utah from an average of 2% of a customer’s eligible monthly charges to 6%. In August 2009, a settlement agreement was filed with the UPSC requesting the DSM cost recovery mechanism be adjusted to 5%, representing an estimated annual increase of $35 million, which would enable PacifiCorp to continue to fund ongoing DSM programs and to recover previously incurred DSM expenditures. The UPSC approved the settlement agreement in August 2009, and the 5% DSM cost recovery mechanism became effective September 1, 2009.

Oregon

In March 2009, PacifiCorp made the initial filing for the annual transition adjustment mechanism (“TAM”) with the Oregon Public Utility Commission (“OPUC”) for an annual increase of $21 million to recover the anticipated net power costs for the year beginning January 1, 2010. In August 2009, PacifiCorp filed a revision to its anticipated net power costs for the TAM, reflecting a slight decrease in the overall request to $20 million. In September 2009, PacifiCorp filed a settlement stipulation with the OPUC reducing the requested increase to $4 million, or an average price increase of less than 1%. In October 2009, the OPUC issued an order approving the settlement stipulation. The TAM is subject to updates for the forward price curve and new contracts in November 2009, at which time the final numbers will be determined. The expected effective date for the TAM is January 1, 2010.

In April 2009, PacifiCorp filed a general rate case with the OPUC requesting an annual increase of $92 million. In August 2009, the requested annual increase was reduced to $83 million. In September 2009, PacifiCorp filed a settlement stipulation with the OPUC further reducing the proposed annual increase to $42 million, or an average price increase of 4%. The stipulation agreement also includes three tariff riders to collect an additional $8 million over a three-year period associated with various cost initiatives. If approved, rates will be effective February 2, 2010.

Wyoming

In July 2008, PacifiCorp filed a general rate case with the Wyoming Public Service Commission (the “WPSC”) requesting an annual increase of $34 million with an effective date of May 24, 2009. Power costs were excluded from the filing and were addressed separately in PacifiCorp’s annual power cost adjustment mechanism (“PCAM”) application filed in February 2009. In October 2008, the general rate case request was reduced by $5 million, to $29 million, to reflect a change in the in-service date of the High Plains wind-powered generating facility. In March 2009, a settlement agreement was filed with the WPSC requesting an increase in Wyoming rates of $18 million annually, beginning May 24, 2009, for an average overall price increase of 4%. Following public hearings in March 2009, the WPSC issued a final order approving the stipulation agreement in May 2009.

In February 2009, PacifiCorp filed its annual PCAM application with the WPSC. The PCAM application requested recovery of the difference between actual net power costs and the amount included in base rates, subject to certain limitations, for the period December 1, 2007 through November 30, 2008, and establishes for the first time, an adjustment for the difference between forecasted net power costs and the amount included in base rates for the period December 1, 2008 through November 30, 2009. In the 2009 PCAM application, PacifiCorp requested a $2 million reduction to the current annual surcharge rate based on the results for the twelve-month period ended November 30, 2008, as well as a $16 million increase to the annual surcharge rate for the forecasted twelve-month period ending November 30, 2009, resulting in a net increase to the annual surcharge rate of $14 million on a combined basis. In March 2009, the WPSC approved PacifiCorp’s motion to implement an interim rate increase of $7 million effective April 1, 2009 consistent with the interim PCAM increase agreed to in the 2008 general rate case settlement agreement. In July 2009, a stipulation agreement was signed by the major participants in the case requesting that the April 2009 interim rate increase become the permanent rate for the entire amortization period through March 31, 2010, effectively reducing the net increase of $14 million sought in the application to $7 million, or an average price increase of 1%. In August 2009, the WPSC held a public hearing to consider the stipulation agreement, and after considering the evidence, the WPSC issued a bench decision approving the stipulation effective September 1, 2009.

In October 2009, PacifiCorp filed a general rate case with the WPSC requesting a rate increase of $71 million. Power costs are included in the general rate case which reflects increased coal costs and the expiration of low cost long-term power purchase contracts. The application is based on a test period ending December 31, 2010. Two regulatory policy issues related to the tax treatment of equity AFUDC and the accounting for coal stripping costs are included in the case, which if approved by the WPSC, will reduce the rate increase by $9 million for an overall increase of $62 million, or an average price increase of 12%. The application requests a hearing date in May 2010 and a rate effective date of August 1, 2010.

Washington

In February 2009, PacifiCorp filed a general rate case with the WUTC for an annual increase of $39 million. The filing included a request to begin collection of a deferral for costs associated with the 520 MW Chehalis natural gas-fired generating plant prior to its inclusion in rate base beginning in January 2010. The associated costs are estimated at $15 million. PacifiCorp has proposed to recover these costs through an extension in the hydroelectric deferral mechanism and thereby not affecting current customer rates. In August 2009, PacifiCorp filed an all-party settlement agreement proposing an annual increase of $14 million, or an average price increase of 5%. The WUTC is expected to make a decision in late 2009. If approved, rates will be effective January 1, 2010.

Idaho

In September 2008, PacifiCorp filed a general rate case with the Idaho Public Utilities Commission (the “IPUC”) for an annual increase of $6 million. In February 2009, a settlement signed by PacifiCorp, the IPUC staff and intervening parties was filed with the IPUC resolving all issues in the 2008 general rate case. The agreement stipulates a $4 million increase, or 3% average price increase, for non-contract retail customers in Idaho. As part of the stipulation, intervening parties acknowledged that PacifiCorp’s acquisition of the 520-MW natural gas-fired Chehalis plant was prudent and the investment should be included in PacifiCorp’s revenue requirement, and that PacifiCorp has demonstrated that its demand-side management programs are prudent. The parties also agreed on a base level of net power costs for any future ECAM calculations. In April 2009, the IPUC issued an order approving the stipulation effective April 18, 2009.

In June 2009, an agreement was reached with parties to the ECAM docket allowing for the implementation of an ECAM to recover the difference between power costs recovered in rates and actual costs incurred, subject to the calculation methodology of the mechanism. In September 2009, the IPUC issued an order approving the ECAM stipulation as filed with an effective date of July 1, 2009.

CE Electric UK

Distribution Price Control Review 5

In March 2008, the Office of Gas and Electricity Markets (“Ofgem”) announced the commencement of its next price control review that is expected to be effective April 1, 2010. In February and June 2009, CE Electric UK submitted cost forecasts for Northern Electric and Yorkshire Electricity and has responded to consultation documents issued by Ofgem throughout the period of the review. Industry wide and bilateral meetings have been held to discuss current issues and the cost forecasts. In August 2009, Ofgem issued its initial proposals; although a number of issues, notably treatment of pension costs and cost of capital, have not been fully developed. Final proposals are expected to be issued by Ofgem in late 2009. The impact, if any, of this price review on the Company cannot be determined at this time.

Environmental Regulation

In addition to the updates contained herein, refer to Note 12 of Notes to Consolidated Financial Statements included in Item 1 of this Form 10-Q and Item 1 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2008 for additional information regarding certain environmental matters affecting PacifiCorp’s and MidAmerican Energy’s operations.

Climate Change

As a result of increased attention to global climate change in the United States, there are significant future environmental regulations under consideration to increase the deployment of clean energy technologies and regulate emissions of greenhouse gases at the state, regional and federal levels. Congress and federal policy makers are considering climate change legislation and a variety of national climate change policies, such as the American Clean Energy and Security Act of 2009 (“Waxman-Markey bill”) discussed in Note 12 of Notes to Consolidated Financial Statements. In addition, governmental and nongovernmental organizations and others have become more active in initiating litigation under existing environmental and other laws.

In April 2009, the United States Environmental Protection Agency (the “EPA”) issued a proposed finding, in response to the United States Supreme Court’s 2007 decision in the case of Massachusetts v. EPA, that under Section 202(a) of the Clean Air Act six greenhouse gases – carbon dioxide, methane, nitrous oxide, hydrofluorocarbons, perfluorocarbons, and sulfur hexafluoride – threaten the public health and welfare of current and future generations. The finding does not include any proposed regulations regarding greenhouse gas emissions; however, such regulatory or legislative action could have a significant adverse impact on PacifiCorp’s and MidAmerican Energy’s current and future fossil-fueled generating facilities. In September 2009, in anticipation of the regulation of greenhouse gases under Section 202(a) of the Clean Air Act, the EPA released a proposed greenhouse gas “tailoring” rule which would require new or modified facilities with increased greenhouse gas emissions in excess of 25,000 tons per year of carbon dioxide equivalent emissions to undergo a best available control technology review. In addition, the proposal would require the incorporation of greenhouse gas emissions under Title V operating permits.

In September 2009, the United States Court of Appeals for the Second Circuit (the “Second Circuit”) issued its opinion in the case of Connecticut v. American Electric Power, which remanded to the lower court a nuisance action by eight states and the City of New York against five large utility emitters of carbon dioxide. The United States District Court for the Southern District of New York (the “Southern District of New York”) dismissed the case in 2005, holding that the claims that emissions of greenhouse gases from the defendants’ coal-fueled generating facilities were causing harmful climate change and should be enjoined as a public nuisance under federal common law presented a “political question” that the court lacked jurisdiction to decide. The Second Circuit rejected the Southern District of New York’s conclusion that the plaintiffs’ claims were barred from consideration as a political question and the Southern District of New York was not precluded from determining the case on its merits. The Company cannot predict the outcome of this litigation or its potential impact at this time.

In October 2009, a three judge panel in the United States Court of Appeals for the Fifth Circuit (the “Fifth Circuit”) issued its opinion in the case of Ned Comer, et al. v. Murphy Oil USA, et al., a putative class action lawsuit against insurance, oil, coal and chemical companies, based on claims that the defendants’ emissions of greenhouse gases contributed to global warming that in turn caused a rise in sea levels and added to the ferocity of Hurricane Katrina, which combined to destroy the plaintiff’s private property, as well as public property. In 2007, the United States District Court for the Southern District of Mississippi (the “Southern District of Mississippi”) had dismissed the case based on the lack of standing and further held that the claims were barred by the political question doctrine. The Fifth Circuit reversed the lower court decision and held that the plaintiffs had standing to assert their public and private nuisance, trespass, and negligence claims and concluded that the claims did not present a political question. The case was remanded to the Southern District of Mississippi for further proceedings with the court noting that it had not determined, and would leave to the lower court to analyze, whether the alleged chain of causation satisfies the proximate cause requirement under Mississippi state common law.

In October 2009, the United States District Court for the Northern District of California (the “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’ greenhouse gas 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 with prejudice to their future presentation in an appropriate state court.

Credit Ratings

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

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

In accordance with industry practice, certain agreements, including derivative contracts, contain provisions that require certain of MEHC’s subsidiaries, principally PacifiCorp and MidAmerican Energy, to maintain specific credit ratings on their unsecured debt from one or more of the major credit ratings agencies. These agreements, including derivative contracts, may either specifically provide bilateral rights to demand cash or other security if credit exposures on a net basis exceed specified rating-dependent threshold levels (“credit-risk-related contingent features”) or provide the right for counterparties to demand “adequate assurance” in the event of a material adverse change in the subsidiary’s creditworthiness. These rights can vary by contract and by counterparty. As of September 30, 2009, these subsidiary’s credit ratings from the three recognized credit rating agencies were investment grade. If all credit-risk-related contingent features or adequate assurance provisions for these agreements, including derivative contracts, had been triggered as of September 30, 2009, the Company would have been required to post $557 million of additional collateral. The Company’s collateral requirements could fluctuate considerably due to market price volatility, changes in credit ratings or other factors. Refer to Note 6 of Notes to Consolidated Financial Statements included in Item 1 of this Form 10-Q for a discussion of the Company’s collateral requirements specific to the Company’s derivative contracts.

New Accounting Pronouncements

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

Critical Accounting Policies

Certain accounting policies require management to make estimates and judgments concerning transactions that will be settled several years in the future. Amounts recognized in the Consolidated Financial Statements from such estimates are necessarily based on numerous assumptions involving varying and potentially significant degrees of judgment and uncertainty. Accordingly, the amounts currently reflected in the Consolidated Financial Statements will likely increase or decrease in the future as additional information becomes available. Estimates are used for, but not limited to, the accounting for the effects of certain types of regulation, derivatives, impairment of long-lived assets and goodwill, pension and other postretirement benefits, income taxes and revenue recognition - unbilled revenue. For additional discussion of the Company’s critical accounting policies, see Item 7 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2008. The Company’s critical accounting policies have not changed materially since December 31, 2008.

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, 2008. The Company’s exposure to market risk and its management of such risk has not changed materially since December 31, 2008. Refer to Note 6 of Notes to Consolidated Financial Statements included in Item 1 of this Form 10-Q for disclosure of the Company’s derivative positions as of September 30, 2009.

Item 4(T).

Controls and Procedures

At the end of the period covered by this Quarterly Report on Form 10-Q, the Company carried out an evaluation, under the supervision and with the participation of the Company’s management, including the Chief Executive Officer (principal executive officer) and the Chief Financial Officer (principal financial officer), of the effectiveness of the design and operation of the Company’s disclosure controls and procedures (as defined in Rule 13a-15(e) promulgated under the Securities and Exchange Act of 1934, as amended). Based upon that evaluation, the Company’s management, including the Chief Executive Officer (principal executive officer) and the Chief Financial Officer (principal financial officer), concluded that the Company’s disclosure controls and procedures were effective to ensure that information required to be disclosed by the Company in the reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and is accumulated and communicated to management, including the Company’s Chief Executive Officer (principal executive officer) and Chief Financial Officer (principal financial officer), or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure. There has been no change in the Company’s internal control over financial reporting during the quarter ended September 30, 2009 that has materially affected, or is reasonably likely to materially affect, the Company’s internal control over financial reporting.

PART II

Item 1.

Legal Proceedings

For a description of certain legal proceedings affecting the Company, refer to Item 3 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2008. Refer to Note 12 of Notes to Consolidated Financial Statements included in Part I, Item 1 of this Form 10-Q for material developments since December 31, 2008.

Item 1A.

Risk Factors

Except as discussed below, 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, 2008.

Our regulated businesses are subject to extensive regulations and legislation that affect their operations and costs. These regulations and laws are complex, dynamic and subject to change.

In June 2009, the United States House of Representatives passed the American Clean Energy and Security Act of 2009 (“Waxman-Markey bill”), introduced by Representatives Henry Waxman and Edward Markey. In addition to a federal renewable portfolio standard, which would require utilities to obtain a portion of their energy from certain qualifying renewable sources, and energy efficiency measures, the bill requires a reduction in greenhouse gas emissions beginning in 2012, with emission reduction targets of 3% below 2005 levels by 2012; 17% below 2005 levels by 2020; 42% below 2005 levels by 2030; and 83% below 2005 levels by 2050 under a “cap and trade” program. In September 2009, a similar bill was introduced in the United States Senate by Senators Barbara Boxer and John Kerry, which would require an initial reduction in greenhouse gas emissions beginning in 2012 with emission reduction targets consistent with the Waxman-Markey bill, with the exception of the 2020 target, which requires 20% reduction below 2005 levels. If the Waxman-Markey bill or some other federal comprehensive climate change bill were to pass both Houses of Congress and be signed into law by the President, the impact on our financial performance could be material and would depend on a number of factors, including the required timing and level of greenhouse gas reductions, the price and availability of offsets and allowances used for compliance and our ability to receive revenue from customers for increased costs. The new law would likely result in increased operating costs and expenses, additional capital expenditures and asset retirements and may negatively impact demand for electricity. To the extent that our regulated subsidiaries are not allowed by their regulators to recover or cannot otherwise recover the costs to comply with climate change requirements, these requirements could have a material adverse impact on our consolidated financial results. Additionally, even if such costs are recoverable in rates, if they are substantial and result in rates increasing to levels that substantially reduce customer demand, this could have a material adverse impact on our consolidated financial results.

Item 2.

Unregistered Sales of Equity Securities and Use of Proceeds

Not applicable.

Item 3.

Defaults Upon Senior Securities

Not applicable.

Item 4.

Submission of Matters to a Vote of Security Holders

Not applicable.

Item 5.

Other Information

Not applicable.

Item 6.

Exhibits

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

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 6, 2009	/s/ Patrick J. Goodman
	Patrick J. Goodman
	Senior Vice President and Chief Financial Officer
	(principal financial and accounting officer)

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.

BERKSHIRE HATHAWAY ENERGY CO - FORM 10-Q - November 6, 2009

Attached files

BERKSHIRE HATHAWAY ENERGY CO Reports