mehc10q_63009.htm

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)

We have reviewed the accompanying consolidated balance sheet of MidAmerican Energy Holdings Company and subsidiaries (the “Company”) as of June 30, 2009, and the related consolidated statements of operations for the three-month and six-month periods ended June 30, 2009 and 2008, and of cash flows and changes in equity for the six-month periods ended June 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.

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 FASB Statement No. 160, “Noncontrolling Interests in Consolidated Financial Statements – an amendment of ARB No. 51” (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.

	As of
	June 30,		December 31,
	2009		2008
ASSETS

Current assets:
Cash and cash equivalents	$	875	$	280
Trade receivables, net		1,039		1,310
Inventories		552		566
Derivative contracts		165		227
Income tax receivable		174		11
Investments		10		1,505
Other current assets		544		518
Total current assets		3,359		4,417

Property, plant and equipment, net		29,987		28,454
Goodwill		5,106		5,023
Regulatory assets		1,951		2,156
Derivative contracts		87		97
Investments and other assets		1,348		1,294

Total assets	$	41,838	$	41,441

	As of
	June 30,			December 31,
	2009			2008

LIABILITIES AND EQUITY

Current liabilities:
Accounts payable	$	888		$	1,240
Accrued interest		351			340
Accrued property, income and other taxes		288			561
Derivative contracts		116			183
Short-term debt		314			836
Current portion of long-term debt		259			421
Current portion of MEHC subordinated debt		234			734
Other current liabilities		703			578
Total current liabilities		3,153			4,893

Regulatory liabilities		1,525			1,506
Derivative contracts		459			546
MEHC senior debt		5,121			5,121
MEHC subordinated debt		522			587
Subsidiary debt		13,778			12,533
Deferred income taxes		4,283			3,949
Other long-term liabilities		1,778			1,829
Total liabilities		30,619			30,964

Commitments and contingencies (Note 11)

Equity:
MEHC shareholders’ equity:
Common stock - 115 shares authorized, no par value, 75 shares issued and outstanding		-			-
Additional paid-in capital		5,455			5,455
Retained earnings		6,119			5,631
Accumulated other comprehensive loss, net		(622	)		(879	)
Total MEHC shareholders’ equity		10,952			10,207
Noncontrolling interests		267			270
Total equity		11,219			10,477

Total liabilities and equity	$	41,838		$	41,441

	Three-Month Periods						Six-Month Periods
	Ended June 30,						Ended June 30,
	2009			2008			2009			2008

Operating revenue:
Energy	$	2,223		$	2,650		$	5,019		$	5,765
Real estate		279			342			452			583
Total operating revenue		2,502			2,992			5,471			6,348

Operating costs and expenses:
Energy:
Cost of sales		779			1,178			1,943			2,634
Operating expense		607			613			1,310			1,205
Depreciation and amortization		307			287			603			560
Real estate		262			331			454			594
Total operating costs and expenses		1,955			2,409			4,310			4,993

Operating income		547			583			1,161			1,355

Other income (expense):
Interest expense		(323	)		(330	)		(641	)		(658	)
Capitalized interest		9			12			18			23
Interest and dividend income		13			13			28			31
Other, net		122			23			78			40
Total other income (expense)		(179	)		(282	)		(517	)		(564	)

Income before income tax expense and equity income		368			301			644			791
Income tax expense		111			82			172			229
Equity income		(19	)		(6	)		(28	)		(9	)
Net income		276			225			500			571
Net income attributable to noncontrolling interests		5			5			12			9
Net income attributable to MEHC	$	271		$	220		$	488		$	562

	Six-Month Periods
	Ended June 30,
	2009			2008

Cash flows from operating activities:
Net income	$	500		$	571
Adjustments to reconcile net income to net cash flows from operating activities:
Depreciation and amortization		611			570
Stock-based compensation		123			-
Changes in regulatory assets and liabilities		8			(43	)
Provision for deferred income taxes		295			272
Other, net		(16	)		(4	)
Changes in other operating assets and liabilities:
Trade receivables and other assets		338			107
Derivative collateral, net		79			(79	)
Trading securities		499			-
Contributions to pension and other postretirement benefit plans, net		(55	)		(80	)
Accounts payable and other liabilities		(600	)		(22	)
Net cash flows from operating activities		1,782			1,292

Cash flows from investing activities:
Capital expenditures		(1,693	)		(1,576	)
Purchases of available-for-sale securities		(213	)		(126	)
Proceeds from sales of available-for-sale securities		203			128
Proceeds from investments		1,000			393
Other, net		(11	)		16
Net cash flows from investing activities		(714	)		(1,165	)

Cash flows from financing activities:
Proceeds from MEHC senior debt		-			649
Repayments of MEHC senior and subordinated debt		(567	)		(517	)
Purchases of MEHC senior debt		-			(99	)
Proceeds from subsidiary debt		992			397
Repayments of subsidiary debt		(230	)		(572	)
Net repayments of MEHC revolving credit facility		(216	)		-
Net repayments of subsidiary short-term debt		(315	)		(66	)
Net payment of hedging instruments		-			(99	)
Net purchases of common stock		(123	)		-
Other, net		(18	)		2
Net cash flows from financing activities		(477	)		(305	)

Effect of exchange rate changes		4			2

Net change in cash and cash equivalents		595			(176	)
Cash and cash equivalents at beginning of period		280			1,178
Cash and cash equivalents at end of period	$	875		$	1,002

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

Balance, January 1, 2008		75		$	-	$	5,454		$	3,782	$	90		$	256		$	9,582
Net income		-			-		-			562		-			9			571
Other comprehensive income		-			-		-			-		25			-			25
Contributions		-			-		-			-		-			21			21
Distributions		-			-		-			-		-			(17	)		(17	)
Other equity transactions		-			-		-			-		-			(5	)		(5	)
Balance, June 30, 2008		75		$	-	$	5,454		$	4,344	$	115		$	264		$	10,177

Balance, January 1, 2009		75		$	-	$	5,455		$	5,631	$	(879	)	$	270		$	10,477
Net income		-			-		-			488		-			12			500
Other comprehensive income		-			-		-			-		257			-			257
Stock-based compensation		-			-		123			-		-			-			123
Exercise of common stock options		1			-		25			-		-			-			25
Common stock purchases		(1	)		-		(148	)		-		-			-			(148	)
Contributions		-			-		-			-		-			17			17
Distributions		-			-		-			-		-			(43	)		(43	)
Other equity transactions		-			-		-			-		-			11			11
Balance, June 30, 2009		75		$	-	$	5,455		$	6,119	$	(622	)	$	267		$	11,219

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 a private investor group comprised of Mr. Walter Scott, Jr. (along with family members and related entities), who is a member of MEHC’s Board of Directors, and Mr. Gregory E. Abel, MEHC’s President and Chief Executive Officer. As of June 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 is organized and managed as eight distinct platforms: PacifiCorp, MidAmerican Funding, LLC (“MidAmerican Funding”) (which primarily includes MidAmerican Energy Company (“MidAmerican Energy”)), Northern Natural Gas Company (“Northern Natural Gas”), Kern River Gas Transmission Company (“Kern River”), CE Electric UK Funding Company (“CE Electric UK”) (which primarily includes Northern Electric Distribution Limited (“Northern Electric”) and Yorkshire Electricity Distribution plc (“Yorkshire Electricity”)), CalEnergy Generation-Foreign (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, the Company owns and operates an electric utility company in the Western United States, an electric and natural gas utility company in the Midwestern United States, two interstate natural gas pipeline companies in the United States, two electricity distribution companies in Great Britain, a diversified portfolio of independent power projects and the second largest residential real estate brokerage firm in the United States.

The unaudited Consolidated Financial Statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) for interim financial information and the United States Securities and Exchange Commission’s rules and regulations for Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the disclosures required by GAAP for annual financial statements. Management believes the unaudited Consolidated Financial Statements contain all adjustments (consisting only of normal recurring adjustments) considered necessary for the fair presentation of the Consolidated Financial Statements as of June 30, 2009 and for the three- and six-month periods ended June 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 six-month periods ended June 30, 2009 are not necessarily indicative of the results to be expected for the full year. The Company has evaluated subsequent events through August 7, 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 six-month period ended June 30, 2009.

In June 2009, the Financial Accounting Standards Board (the “FASB”) issued Statement of Financial Accounting Standards (“SFAS”) No. 167, “Amendments to FASB Interpretation No. 46(R)” (“SFAS No. 167”). SFAS No. 167 amends FASB Interpretation No. 46(R), “Consolidation of Variable Interest Entities – an interpretation of ARB No. 51” (“FIN 46(R)”), to require a primarily qualitative analysis to determine if an enterprise is the primary beneficiary of a variable interest entity. This analysis should be 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, SFAS No. 167 requires enterprises 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, SFAS No. 167 amends guidance for consolidation or deconsolidation of a variable interest entity and enhances disclosure requirements about an enterprise’s involvement with a variable interest entity. SFAS No. 167 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 SFAS No. 167 on its consolidated financial results and disclosures included within Notes to Consolidated Financial Statements.

In April 2009, the FASB issued Staff Position (“FSP”) No. FAS 107-1 and APB 28-1, “Interim Disclosures about Fair Value of Financial Instruments” (“FSP FAS 107-1”). FSP FAS 107-1 requires publicly traded companies to include the annual fair value disclosures required for all financial instruments within the scope of SFAS No. 107, “Disclosures about Fair Value of Financial Instruments,” in interim financial statements. The Company adopted FSP FAS 107-1 on April 1, 2009 and included the required disclosures within Notes to Consolidated Financial Statements.

In April 2009, the FASB issued FSP No. FAS 115-2 and FAS 124-2, “Recognition and Presentation of Other-Than-Temporary Impairments” (“FSP FAS 115-2”). FSP FAS 115-2 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. The existing other-than-temporary impairment models for equity securities will continue to apply. In addition, FSP FAS 115-2 addresses whether an other-than-temporary impairment should be recognized in earnings, other comprehensive income or some combination thereof. FSP FAS 115-2 also expands the already required annual disclosures about other-than-temporary impairment for debt and equity securities and requires companies to include these expanded disclosures in interim financial statements. The Company adopted FSP FAS 115-2 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 FSP No. FAS 157-4, “Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly” (“FSP FAS 157-4”). FSP FAS 157-4 clarifies the application of SFAS No. 157, “Fair Value Measurements,” (“SFAS No. 157”) in determining when a market is not active and if a transaction is not orderly. In addition, FSP FAS 157-4 amends SFAS No. 157 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. FSP FAS 157-4 also amends SFAS No. 157 to define “major categories” to be consistent with those described in SFAS No. 115, “Accounting for Certain Investments in Debt and Equity Securities.” The Company adopted FSP FAS 157-4 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 FSP No. FAS 132(R)-1, “Employers’ Disclosures about Postretirement Benefit Plan Assets” (“FSP FAS 132(R)-1”). FSP FAS 132(R)-1 is intended to improve financial reporting about plan assets of defined benefit pension and other postretirement plans by requiring enhanced disclosures to enable investors to better understand how investment allocation decisions are made and the major categories of plan assets. FSP FAS 132(R)-1 also 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. In addition, FSP FAS 132(R)-1 establishes disclosure requirements for significant concentrations of risk within plan assets. FSP FAS 132(R)-1 is effective for financial statements issued after December 15, 2009, with early application permitted. The Company is currently evaluating the impact of adopting FSP FAS 132(R)-1 on its disclosures included within Notes to Consolidated Financial Statements.

In March 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities - an amendment of FASB Statement No. 133” (“SFAS No. 161”). SFAS No. 161 is intended to improve financial reporting about derivative instruments and hedging activities by requiring enhanced disclosures 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 SFAS No. 161 on January 1, 2009 and included the required disclosures within Notes to Consolidated Financial Statements.

In December 2007, the FASB issued SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements – an amendment of ARB No. 51” (“SFAS No. 160”). SFAS No. 160 establishes accounting and reporting standards for the noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary. The Company adopted SFAS No. 160 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.

		As of
	Depreciation	June 30,			December 31,
	Life	2009			2008

Regulated assets:
Utility generation, distribution and transmission system	5-85 years	$	34,654		$	32,795
Interstate pipeline assets	3-67 years		5,657			5,649
			40,311			38,444
Accumulated depreciation and amortization			(13,011	)		(12,456	)
Regulated assets, net			27,300			25,988

Non-regulated assets:
Independent power plants	10-30 years		677			681
Other assets	3-30 years		583			547
			1,260			1,228
Accumulated depreciation and amortization			(470	)		(430	)
Non-regulated assets, net			790			798

Net operating assets			28,090			26,786
Construction in progress			1,897			1,668
Property, plant and equipment, net		$	29,987		$	28,454

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. Comments and protests on Kern River’s March 2009 compliance filing have been submitted and a decision from the FERC is expected in 2009.

SB 408 requires that PacifiCorp and other large regulated, investor-owned utilities that provide electric or natural gas service to Oregon customers file an annual 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 $27 million of the deficiency associated with PacifiCorp’s 2006 tax report to be recovered over a one-year period beginning June 1, 2008 and the remainder to be 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, associated with PacifiCorp’s 2006 tax report and 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 (“Court of Appeals”) seeking judicial review of the April 2008 order. In December 2008, ICNU filed their opening brief. In March 2009, a notice of withdrawal of the April 2008 order in judicial review was filed in 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 their challenge of the April 2008 order by filing an amended petition for judicial review with the Court of Appeals. PacifiCorp believes the outcome of these proceedings will not have a material impact on its consolidated financial results.

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 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).

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

Assets(2):
Commodity derivatives	$	5		$	619		$	43		$	(415	)	$	252
Investments in available-for-sale securities:
Money market mutual funds(3)		770			-			-			-			770
Debt securities		64			85			38			-			187
Equity securities		200			7			-			-			207
	$	1,039		$	711		$	81		$	(415	)	$	1,416

Liabilities:
Commodity derivatives	$	(10	)	$	(607	)	$	(403	)	$	449		$	(571	)
Interest rate derivative		-			(4	)		-			-			(4	)
	$	(10	)	$	(611	)	$	(403	)	$	449		$	(575	)

(1)	Primarily represents a net cash collateral receivable of $34 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.

	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.

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 or if the contract is not actively traded. Given that limited market data exists for these contracts, 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 debt and equity securities, including certain cash equivalents, are accounted for as either available-for-sale or trading securities and are stated at fair value. When available, the quoted market price or net asset value of an identical security in the principal market is used to record the fair value. In the absence of a quoted market price or net asset value in a readily observable and active market, 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.

	2009					2008
	Commodity			Debt		Commodity			Debt
	Derivatives			Securities		Derivatives			Securities

Beginning balance	$	(402	)	$	38	$	(325	)	$	66
Changes included in earnings(1)		1			-		(10	)		-
Unrealized gains (losses) included in other comprehensive income		1			-		-			(5	)
Unrealized gains included in regulatory assets and liabilities		36			-		120			-
Purchases, sales, issuances and settlements		6			-		(17	)		-
Net transfers into or out of Level 3		(2	)		-		-			-
Ending balance	$	(360	)	$	38	$	(232	)	$	61

	2009					2008
	Commodity			Debt		Commodity			Debt
	Derivatives			Securities		Derivatives			Securities

Beginning balance	$	(369	)	$	37	$	(311	)	$	73
Changes included in earnings(1)		19			-		(22	)		-
Unrealized gains (losses) included in other comprehensive income		1			1		1			(12	)
Unrealized gains included in regulatory assets and liabilities		34			-		134			-
Purchases, sales, issuances and settlements		(22	)		-		(34	)		-
Net transfers into or out of Level 3		(23	)		-		-			-
Ending balance	$	(360	)	$	38	$	(232	)	$	61

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):

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 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 costs 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.

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

Not Designated as Hedging Contracts(1)(2):
Commodity assets	$	449		$	127		$	36		$	33		$	645
Commodity liabilities		(143	)		(31	)		(225	)		(480	)		(879	)
Total		306			96			(189	)		(447	)		(234	)

Designated as Hedging Contracts(1):
Commodity assets		13			2			7			-			22
Commodity liabilities		(12	)		(2	)		(74	)		(53	)		(141	)
Interest rate liability		-			-			-			(4	)		(4	)
Total		1			-			(67	)		(57	)		(123	)

Total derivatives		307			96			(256	)		(504	)		(357	)
Cash collateral receivable (payable)		(142	)		(9	)		140			45			34
Total derivatives - net basis	$	165		$	87		$	(116	)	$	(459	)	$	(323	)

(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 June 30, 2009, a net regulatory asset of $247 million was recorded related to the net derivative liabilities of $234 million.

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 or liabilities. 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):

For the Company’s commodity derivatives not designated as hedging contracts and 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 costs 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 Statement 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):

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 June 30, 2009 (in millions):

Realized gains and losses on all hedges and hedge ineffectiveness are recognized in income as operating revenue or costs of sales and operating expense depending upon the nature of the item being hedged. For the three- and six-month periods ended June 30, 2009 and 2008, hedge ineffectiveness was insignificant. As of June 30, 2009, the Company had cash flow hedges with expiration dates extending through December 2022 and $65 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.

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 of 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.

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 June 30, 2009, each 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 $701 million as of June 30, 2009, for which the Company had posted collateral of $185 million. If all credit-risk-related contingent features for derivative contracts in liability positions had been triggered as of June 30, 2009, the Company would have been required to post $257 million of additional collateral. The Company’s collateral requirements could fluctuate considerably due to market price volatility, changes in credit ratings or other factors.

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 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. For the three- and six-month periods ended June 30, 2009, the Company recognized gains on Constellation Energy common stock totaling $93 million and $37 million, respectively, which are included in other, net on the Consolidated Statement 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.

As of June 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 $520 million and $1.09 billion, respectively. Interest expense on these securities totaled $16 million and $22 million for the three-month periods ended June 30, 2009 and 2008, respectively, and $34 million and $45 million for the six-month periods ended June 30, 2009 and 2008, respectively. Accrued interest totaled $12 million and $27 million as of June 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.

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.

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 March 2008, the court indefinitely postponed the date for the liability-phase trial. The remedy-phase trial has not yet been scheduled. The court also has before it a number of motions on which it has not yet ruled. 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.

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 are subject to appeal. In June 2009, LPG exercised its buy-up rights with respect to the remaining 5% ownership interest. 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 November 2009. The impact, if any, of this litigation on the Company cannot be determined at this time. The Company intends to vigorously defend the counterclaims.

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 June 30, 2009 and December 31, 2008 was $25 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.

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. Similar bills seeking to create “cap and trade” systems for greenhouse gas emissions have also been introduced in the United States Senate. 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 asset retirements 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.

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 lays 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. Negotiations have begun and a final agreement is expected in September 2009. 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.

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, approximately $180 million is to 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 $62 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 June 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.

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, if any, on its consolidated financial results at this time.

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 six-month period ended June 30, 2009, which is included in operating expense on the Consolidated Statement of Operations.

	Three-Month Periods						Six-Month Periods
	Ended June 30,						Ended June 30,
	2009			2008			2009			2008

Net income attributable to MEHC	$	271		$	220		$	488		$	562
Other comprehensive income attributable to MEHC:
Unrecognized amounts on retirement benefits, net of tax of $(18), $1, $(14) and $2		(47	)		3			(37	)		6
Foreign currency translation adjustment		352			14			304			16
Fair value adjustment on cash flow hedges, net of tax of $18, $1, $(8) and $9		27			2			(13	)		14
Unrealized losses on marketable securities, net of tax of $2, $(3), $2 and $(8)		3			(3	)		3			(11	)
Total other comprehensive income attributable to MEHC		335			16			257			25

Comprehensive income attributable to MEHC	$	606		$	236		$	745		$	587

	As of
	June 30,			December 31,
	2009			2008

Unrecognized amounts on retirement benefits, net of tax of $(170) and $(156)	$	(438	)	$	(401	)
Foreign currency translation adjustment		(142	)		(446	)
Fair value adjustment on cash flow hedges, net of tax of $(11) and $(3)		(20	)		(7	)
Unrealized losses on marketable securities, net of tax of $(14) and $(16)		(22	)		(25	)
Total accumulated other comprehensive loss attributable to MEHC, net	$	(622	)	$	(879	)

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						Six-Month Periods
	Ended June 30,						Ended June 30,
	2009			2008			2009			2008

Operating revenue:
PacifiCorp	$	1,016		$	1,055		$	2,132		$	2,150
MidAmerican Funding		763			1,081			1,899			2,454
Northern Natural Gas		120			139			361			371
Kern River		96			104			193			214
CE Electric UK		197			243			390			528
CalEnergy Generation-Foreign		33			29			56			58
CalEnergy Generation-Domestic		7			8			15			15
HomeServices		279			342			452			583
Corporate/other(1)		(9	)		(9	)		(27	)		(25	)
Total operating revenue	$	2,502		$	2,992		$	5,471		$	6,348

Depreciation and amortization:
PacifiCorp	$	141		$	124		$	275		$	241
MidAmerican Funding		84			77			166			149
Northern Natural Gas		15			14			31			29
Kern River		24			22			48			43
CE Electric UK		41			46			77			90
CalEnergy Generation-Foreign		5			6			11			11
CalEnergy Generation-Domestic		2			2			4			4
HomeServices		4			5			8			10
Corporate/other(1)		(5	)		(4	)		(9	)		(7	)
Total depreciation and amortization	$	311		$	292		$	611		$	570

Operating income:
PacifiCorp	$	237		$	218		$	497		$	449
MidAmerican Funding		84			104			240			279
Northern Natural Gas		42			52			201			200
Kern River		59			69			120			145
CE Electric UK		95			117			197			284
CalEnergy Generation-Foreign		24			21			40			42
CalEnergy Generation-Domestic		4			4			8			7
HomeServices		17			11			(2	)		(11	)
Corporate/other(1)		(15	)		(13	)		(140	)		(40	)
Total operating income		547			583			1,161			1,355
Interest expense		(323	)		(330	)		(641	)		(658	)
Capitalized interest		9			12			18			23
Interest and dividend income		13			13			28			31
Other, net		122			23			78			40
Total income before income tax expense and equity income	$	368		$	301		$	644		$	791

	Three-Month Periods				Six-Month Periods
	Ended June 30,				Ended June 30,
	2009		2008		2009		2008
Interest expense:
PacifiCorp	$	109	$	80	$	208	$	164
MidAmerican Funding		49		53		100		101
Northern Natural Gas		15		14		30		29
Kern River		14		18		28		36
CE Electric UK		36		46		70		97
CalEnergy Generation-Foreign		1		2		2		4
CalEnergy Generation-Domestic		4		5		8		9
HomeServices		-		1		-		1
Corporate/other(1)		95		111		195		217
Total interest expense	$	323	$	330	$	641	$	658

(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.

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.

The Company’s operations are organized and managed as eight distinct platforms: PacifiCorp, MidAmerican Funding, LLC (“MidAmerican Funding”) (which primarily includes MidAmerican Energy Company (“MidAmerican Energy”)), Northern Natural Gas Company (“Northern Natural Gas”), Kern River Gas Transmission Company (“Kern River”), CE Electric UK Funding Company (“CE Electric UK”) (which primarily includes Northern Electric Distribution Limited (“Northern Electric”) and Yorkshire Electricity Distribution plc (“Yorkshire Electricity”)), CalEnergy Generation-Foreign (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.

This report contains statements that do not directly or exclusively relate to historical facts. These statements are “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. 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:

·	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;

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.

Net income attributable to MEHC for the second quarter of 2009 was $271 million, an increase of $51 million, or 23%, and for the first six months of 2009 was $488 million, a decrease of $74 million, or 13%, compared to 2008. The results for the first six 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. The results for the second quarter and for the first six months of 2009 included an after-tax gain on the Constellation Energy Group, Inc. (“Constellation Energy”) common stock investment of $55 million and $22 million, respectively. Additionally, the stronger United States dollar resulted in decreased net income from CE Electric UK for the second quarter and for the first six months of 2009 compared to 2008 of $12 million and $30 million, respectively. Excluding the impact of these items, net income attributable to MEHC increased $8 million, or 4%, for the second quarter and $9 million, or 2%, for the first six months of 2009 compared to 2008.

Net income attributable to MEHC was higher for both periods due to increased operating income at PacifiCorp and HomeServices and higher equity income. Operating income was higher at PacifiCorp due to higher margins as a result of lower energy costs and higher rates approved by regulators, partially offset by lower retail volumes, lower average wholesale prices, higher operating expense and higher depreciation and amortization expense. HomeServices’ improved results were due to lower operating expenses. Equity income increased due to higher equity earnings at CE Generation, LLC due mainly to lower fuel and maintenance costs and at HomeServices related to refinance activity in its mortgage business.

Net income attributable to MEHC was unfavorably impacted by lower operating income at MidAmerican Funding, Northern Natural Gas and Kern River for the second quarter and at MidAmerican Funding, CE Electric UK and Kern River for the first six months of 2009 compared to 2008. MidAmerican Funding’s operating income was lower due to lower regulated electric margins from lower wholesale revenues and higher depreciation associated with new wind generating facilities, partially offset by the timing of maintenance and higher nonregulated electric retail margins. Operating income at both Northern Natural Gas and Kern River was lower for the second quarter as a result of less favorable market conditions and was lower at Kern River for the first six months due to benefits from a 2008 reduction in the customer rate case refund liability. Operating income in pounds sterling at CE Electric UK was lower for the first six months due to higher depreciation and amortization expense reflecting additional capital expenditures and higher operating expense due primarily to insurance recoveries received in 2008.

	Second Quarter											First Six Months
	2009			2008			Change					2009			2008			Change
Operating revenue:
PacifiCorp	$	1,016		$	1,055		$	(39	)	(4	)%	$	2,132		$	2,150		$	(18	)	(1	)%
MidAmerican Funding		763			1,081			(318	)	(29	)		1,899			2,454			(555	)	(23	)
Northern Natural Gas		120			139			(19	)	(14	)		361			371			(10	)	(3	)
Kern River		96			104			(8	)	(8	)		193			214			(21	)	(10	)
CE Electric UK		197			243			(46	)	(19	)		390			528			(138	)	(26	)
CalEnergy Generation-Foreign		33			29			4		14			56			58			(2	)	(3	)
CalEnergy Generation-Domestic		7			8			(1	)	(13	)		15			15			-		-
HomeServices		279			342			(63	)	(18	)		452			583			(131	)	(22	)
Corporate/other		(9	)		(9	)		-		-			(27	)		(25	)		(2	)	(8	)
Total operating revenue	$	2,502		$	2,992		$	(490	)	(16	)	$	5,471		$	6,348		$	(877	)	(14	)

Operating income:
PacifiCorp	$	237		$	218		$	19		9	%	$	497		$	449		$	48		11	%
MidAmerican Funding		84			104			(20	)	(19	)		240			279			(39	)	(14	)
Northern Natural Gas		42			52			(10	)	(19	)		201			200			1		1
Kern River		59			69			(10	)	(14	)		120			145			(25	)	(17	)
CE Electric UK		95			117			(22	)	(19	)		197			284			(87	)	(31	)
CalEnergy Generation-Foreign		24			21			3		14			40			42			(2	)	(5	)
CalEnergy Generation-Domestic		4			4			-		-			8			7			1		14
HomeServices		17			11			6		55			(2	)		(11	)		9		82
Corporate/other		(15	)		(13	)		(2	)	(15	)		(140	)		(40	)		(100	)	*
Total operating income	$	547		$	583		$	(36	)	(6	)	$	1,161		$	1,355		$	(194	)	(14	)

Operating revenue decreased $39 million for the second quarter of 2009 compared to 2008 due to a decrease in wholesale and other revenue of $33 million and lower retail revenue of $24 million, partially offset by favorable changes in the fair value of energy sales contracts accounted for as derivatives of $18 million. The decrease in wholesale and other revenue was due primarily to a 20% decrease in average prices and a 5% decrease in wholesale volumes, partially offset by revenue attributable to PacifiCorp’s majority owned coal mining operations. The decrease in retail revenue was due to a 7% decrease in retail volumes totaling $38 million principally related to lower average customer usage due to the effect of current economic conditions and cooler than normal weather in Utah. Additionally, revenue related to Oregon Senate Bill 408 was $15 million lower in 2009. Partially offsetting the lower retail revenue were higher prices approved by regulators totaling $28 million. Overall, sales volumes decreased by 6%.

Operating income increased $19 million for the second quarter of 2009 compared to 2008 due to lower energy costs of $91 million, partially offset by lower revenue of $39 million, higher depreciation and amortization of $17 million due to the addition of new generating facilities and higher operating expenses of $16 million due primarily to costs attributable to PacifiCorp’s majority owned coal mining operations. Energy costs were lower due largely to a 47% decrease in the average cost of purchased electricity and a decrease in the volume of purchased electricity, partially offset by the effects of regulatory cost recovery adjustment mechanisms of $16 million and unfavorable changes in the fair value of energy purchase contracts accounted for as derivatives of $13 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 6% decrease in overall sales volumes, allowed PacifiCorp to reduce its need for purchased electricity.

Operating revenue decreased $18 million for the first six months of 2009 compared to 2008 due to a decrease in wholesale and other revenue of $46 million and lower retail revenue of $10 million, partially offset by favorable changes in the fair value of energy sales contracts accounted for as derivatives of $38 million. The decrease in wholesale and other revenue was due primarily to a 19% decrease in average prices, partially offset by revenue attributable to PacifiCorp’s majority owned coal mining operations and an increase in wholesale volumes of 2%. The decrease in retail revenue was due to a 5% decrease in retail volumes totaling $53 million principally related to lower average customer usage due to the effect of current economic conditions, partially offset by growth in the average number of commercial and residential customers. Additionally, revenue related to Oregon Senate Bill 408 was $15 million lower in 2009. Partially offsetting the lower retail revenue were higher prices approved by regulators totaling $56 million. Overall, sales volumes decreased by 4%.

Operating income increased $48 million for the first six months of 2009 compared to 2008 due to lower energy costs of $129 million, partially offset by lower revenue of $18 million, higher depreciation and amortization of $34 million due to the addition of new generating facilities and higher operating expenses of $29 million due primarily to costs attributable to PacifiCorp’s majority owned coal mining operations. Energy costs were lower due largely to a 31% decrease in the average cost of purchased electricity and a decrease in the volume of purchased electricity, partially offset by the effects of regulatory cost recovery adjustment mechanisms of $31 million and unfavorable changes in the fair value of energy purchase contracts accounted for as derivatives of $21 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 4% decrease in overall sales volumes, allowed PacifiCorp to reduce its need for purchased electricity.

	Second Quarter									First Six Months
	2009		2008		Change					2009		2008		Change
Operating revenue:
Regulated electric	$	391	$	492	$	(101	)	(21	)%	$	835	$	975	$	(140	)	(14	)%
Regulated natural gas		118		280		(162	)	(58	)		506		851		(345	)	(41	)
Nonregulated and other		254		309		(55	)	(18	)		558		628		(70	)	(11	)
Total operating revenue	$	763	$	1,081	$	(318	)	(29	)	$	1,899	$	2,454	$	(555	)	(23	)

Operating income:
Regulated electric		63		89	$	(26	)	(29	)%		160		205	$	(45	)	(22	)%
Regulated natural gas		4		3		1		33			47		48		(1	)	(2	)
Nonregulated and other		17		12		5		42			33		26		7		27
Total operating income	$	84	$	104	$	(20	)	(19	)	$	240	$	279	$	(39	)	(14	)

Regulated electric operating revenue decreased $101 million for the second quarter of 2009 compared to 2008. Wholesale revenue decreased $95 million due to a 44% decrease in average prices and a 26% decrease in volumes, which reflects reduced demand for electricity due to the current economic conditions. Retail revenue decreased $6 million on lower volumes of 4% primarily related to lower industrial load in 2009. Overall, sales volumes decreased by 13%. Regulated electric operating income decreased $26 million for the second quarter of 2009 compared to 2008. The lower revenue was largely offset by a decrease in the cost of energy of $75 million as a result of lower purchased electricity of $64 million, due to lower average costs and volumes, and a lower average cost of natural gas. The addition of new wind generating facilities in 2008 allowed MidAmerican Funding to replace more expensive sources of electricity. Operating expenses decreased $8 million due to the timing of scheduled maintenance and lower storm damage restoration costs. Depreciation and amortization increased $5 million due to new wind generating facilities placed in service in 2008, partially offset by lower Iowa revenue sharing accruals.

Regulated natural gas operating revenue decreased $162 million for the second 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 lower wholesale and retail sales volumes of 22% and 7%, respectively, as a result of fewer market opportunities due to lower price spreads and mild weather experienced throughout the service territory in 2009. Regulated natural gas operating income increased $1 million for the second quarter of 2009 compared to 2008 due mainly to lower maintenance costs as a result of the storm and flood damage in 2008.

Nonregulated and other operating revenue decreased $55 million for the second quarter of 2009 compared to 2008 due to lower gas revenue of $73 million as a result of a 63% decrease in average prices and a 17% decrease in volumes, partially offset by higher electric revenue of $18 million due to a 7% increase in volumes and a 2% increase in average prices. Nonregulated and other operating income increased $5 million for the second quarter of 2009 compared to 2008 due primarily to higher electric margins.

Regulated electric operating revenue decreased $140 million for the first six months of 2009 compared to 2008. Wholesale revenue decreased $130 million due to a 35% decrease in average prices and a 9% decrease in volumes, which reflects reduced demand for electricity due to the current economic conditions. Retail revenue decreased $10 million on lower volumes of 4% primarily related to lower industrial load in 2009. Overall, sales volumes decreased by 6%. Regulated electric operating income decreased $45 million for the first six months of 2009 compared to 2008. The lower revenue was largely offset by a decrease in the cost of energy of $115 million as a result of lower purchased electricity of $87 million and a lower cost of natural gas of $26 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 $16 million due to new wind generating facilities placed in service in 2008, partially offset by lower Iowa revenue sharing of $12 million.

Regulated natural gas operating revenue decreased $345 million for the first six 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 lower retail sales volumes of 8% as a result of mild weather experienced throughout the service territory in 2009, partially offset by higher wholesale volumes of 5%. Regulated natural gas operating income decreased $1 million for the first six months of 2009 compared to 2008 due mainly to lower retail volumes, partially offset by lower maintenance costs as a result of the storm and flood damage in 2008.

Nonregulated and other operating revenue decreased $70 million for the first six months of 2009 compared to 2008 due to lower gas revenue of $99 million as a result of a 36% decrease in average prices and a 12% decrease in volumes, partially offset by higher electric revenue of $29 million due to a 4% increase in average prices and a 3% increase in volumes. Nonregulated and other operating income increased $7 million for the first six months of 2009 compared to 2008 due primarily to higher electric and gas margins.

Operating revenue decreased $19 million for the second quarter and $10 million for the first six months of 2009 compared to 2008 due to lower transportation revenue of $17 million and $10 million, respectively, due to less favorable market conditions, in part due to the current economic climate, and the sale of the Beaver system in 2008. Operating income decreased $10 million for the second quarter of 2009 compared to 2008 due to lower transportation revenue, partially offset by lower operating expenses of $5 million. Operating income increased $1 million for the first six months of 2009 compared to 2008 as the lower transportation revenue was more than offset by lower operating expenses.

Operating revenue decreased $8 million for the second quarter of 2009 compared to 2008 due primarily to lower price spreads and $21 million for the first six months of 2009 compared to 2008 due to a reduction in Kern River’s customer refund liability recognized in 2008 related to the rate proceeding estimate. Operating income decreased $10 million for the second quarter and $25 million for the first six months of 2009 compared to 2008 due to the lower operating revenue and higher depreciation and amortization of $2 million for the second quarter and $4 million for the first six months.

Operating revenue decreased $46 million for the second quarter of 2009 compared to 2008 due to the impact from the foreign currency exchange rate totaling $54 million, partially offset by higher distribution revenue of $11 million. 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 $22 million for the second quarter 2009 compared to 2008 due mainly to the impact from the foreign currency exchange rate on operating income totaling $26 million. Higher distribution revenue was partially offset by higher depreciation and amortization of $5 million reflecting additional capital expenditures.

Operating revenue decreased $138 million for the first six months of 2009 compared to 2008 due to the impact from the foreign currency exchange rate totaling $126 million and lower contracting revenue of $12 million. Operating income decreased $87 million for the first six months of 2009 compared to 2008 due to the impact from the foreign currency exchange rate on operating income totaling $64 million, higher depreciation and amortization expense of $11 million reflecting additional capital expenditures and higher operating expense of $7 million due primarily to insurance recoveries received in 2008.

Operating revenue increased $4 million and operating income increased $3 million for the second quarter of 2009 compared to 2008 due to higher variable energy fees earned in 2009 at the Casecnan project as a result of higher than normal water flow, partially offset by lower prices. Operating revenue and operating income each decreased $2 million for the first six months of 2009 compared to 2008 due to lower variable energy fees earned in 2009 at the Casecnan project as a result of lower prices, partially offset by higher water flows.

Operating revenue decreased $63 million for the second quarter and $131 million for the first six months of 2009 compared to 2008 due to declines in transaction volumes and average home sale prices of 11% and 13%, respectively, for the second quarter and 15% and 14%, respectively, for the first six months reflecting the continuing weak United States housing market. Operating income increased $6 million for the second quarter and $9 million for the first six months of 2009 compared to 2008 due to lower commissions and operating expenses, partially offset by the lower revenue.

Operating income decreased $100 million for the first six 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, partially offset by expense in 2008 for executive compensation and the nuclear project.

	Second Quarter									First Six Months
	2009		2008		Change					2009		2008		Change

Subsidiary debt	$	222	$	208	$	14		7	%	$	432	$	420	$	12		3	%
MEHC senior debt and other		80		93		(13	)	(14	)		164		179		(15	)	(8	)
MEHC subordinated debt - Berkshire Hathaway		16		22		(6	)	(27	)		34		45		(11	)	(24	)
MEHC subordinated debt - other		5		7		(2	)	(29	)		11		14		(3	)	(21	)
Total interest expense	$	323	$	330	$	(7	)	(2	)	$	641	$	658	$	(17	)	(3	)

Interest expense decreased $7 million for the second quarter and $17 million for the first six months of 2009 compared to 2008 due to debt retirements, scheduled principal repayments and the impact of the foreign currency exchange rate of $10 million for the second quarter and $23 million for the first six months. The decreases were partially offset by debt issuances in 2008 and 2009 at PacifiCorp.

Income tax expense increased $29 million to $111 million for the second quarter of 2009 compared to 2008 as a result of higher pre-tax income primarily from the gain on the Constellation Energy common stock investment. The effective tax rates were 30% and 27% for the second quarter of 2009 and 2008, respectively. The increase in the effective tax rate was due mainly to the components of pre-tax income and the benefits recognized in 2008 for tax settlements, partially offset by the benefit of additional production tax credits and the effects of rate making at PacifiCorp and MidAmerican Funding.

Income tax expense decreased $57 million to $172 million for the first six months of 2009 compared to 2008. The effective tax rates were 27% and 29% for the first six months of 2009 and 2008, respectively. The decrease in the effective tax rate was due mainly to the benefit of additional production tax credits and the effects of rate making at PacifiCorp and MidAmerican Funding, partially offset by a favorable foreign tax ruling in 2008.

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.

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

Cash and cash equivalents	$	117		$	552		$	12		$	194		$	875

Available revolving credit facilities	$	835		$	1,395		$	904		$	290		$	3,424
Less:
Short-term borrowings and issuance of commercial paper		-			-			(207	)		(107	)		(314	)
Tax-exempt bond support, letters of credit and other		(42	)		(258	)		(195	)		(37	)		(532	)
Net revolving credit facilities available	$	793		$	1,137		$	502		$	146		$	2,578

Net liquidity available before Berkshire Equity Commitment	$	910		$	1,689		$	514		$	340		$	3,453
Berkshire Equity Commitment(3)		3,500												3,500
Total net liquidity available	$	4,410											$	6,953
Unsecured revolving credit facilities:
Maturity date(4)		2009, 2013			2012-2013			2009, 2013			2010
Largest single bank commitment as a % of total(5)		30	%		15	%		35	%		28	%

(1)	In July 2009, MEHC issued $250 million of its 3.15% Senior Notes due July 15, 2012.

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

(3)	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.

(4)	MEHC and MidAmerican Energy each have a $250 million credit facility expiring in November and October 2009, respectively. 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.

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

The Company’s cash and cash equivalents were $875 million as of June 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 $391 million and $395 million as of June 30, 2009 and December 31, 2008, respectively, related to (i) the Company’s debt service reserve requirements relating to certain projects, (ii) trust funds 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.

Net cash flows from operating activities for the six-month periods ended June 30, 2009 and 2008 were $1.782 billion and $1.292 billion, respectively. The increase was mainly due to proceeds of $536 million received from the sale of Constellation Energy common stock, partially offset by income taxes paid on gains recognized on the termination of the Constellation Energy merger agreement in December 2008. Additionally, net cash flows from operating activities increased due to working capital and changes in collateral posted for derivative contracts, partially offset by the impact from the foreign currency exchange rate.

Net cash flows from investing activities for the six-month periods ended June 30, 2009 and 2008 were $(714) million and $(1.165) billion, respectively. In January 2009, the Company received $1 billion, plus accrued interest, in full satisfaction of the 14% Senior Notes from Constellation Energy. In February 2008, the Company received proceeds from the maturity of a guaranteed investment contract of $393 million. Capital expenditures increased $117 million due primarily to higher capital expenditures at PacifiCorp associated with wind-powered generating facilities, including payments for wind-powered generating facilities placed in service in December 2008, transmission expansion, system upgrades and scheduled maintenance, partially offset by lower spending in 2009 associated with the construction of wind-powered generating facilities at MidAmerican Funding.

Net cash flows from financing activities for the six-month period ended June 30, 2009 were $(477) million. Uses of cash totaled $1.469 billion and consisted mainly of $567 million for repayments of MEHC subordinated debt, $315 million for net repayments of subsidiary short-term debt, $230 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 $992 million and consisted of proceeds from the issuance of subsidiary debt.

Net cash flows from financing activities for the six-month period ended June 30, 2008 were $(305) million. Uses of cash totaled $1.353 billion and consisted mainly of $616 million for repayments and purchases of MEHC senior and subordinated debt, $572 million for repayments of subsidiary debt, $99 million net payment of hedging instruments related to the maturity of United States dollar denominated debt at CE Electric UK and $66 million of net repayments of subsidiary short-term debt. Sources of cash totaled $1.048 billion and consisted mainly of proceeds from the issuance of MEHC senior debt totaling $649 million and subsidiary debt totaling $397 million.

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 us in exchange for additional shares of MEHC’s common stock. The Berkshire Equity Commitment expires on February 28, 2011.

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.

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 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 11 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.

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.”

In July 2008, PacifiCorp filed a general rate case with the Utah Public Service Commission (the “UPSC”) requesting an annual increase of $161 million, or an average price increase of 11%, prior to any consideration for 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, or an average price increase of 8%. 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 a $45 million, or 3%, rate increase effective May 8, 2009. In April 2009, the UPSC issued its final order approving the revenue requirement settlement agreement without modification.

In March 2009, Utah’s governor signed United States 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 a power cost mechanism. 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 December 2009 and the design phase is scheduled for completion in March 2010, shortly after the conclusion of the 2009 general rate case.

In March 2009, PacifiCorp made the initial filing for the annual transition adjustment mechanism (“TAM”) with the OPUC for an annual increase of $21 million, or 2%, to recover the anticipated net power costs for the year beginning January 1, 2010. The expected effective date for the TAM is January 1, 2010. In April 2009, PacifiCorp filed a general rate case for an increase of $92 million, or 9%. If approved, rates will be effective no later than February 3, 2010.

In July 2008, PacifiCorp filed a general rate case with the Wyoming Public Service Commission (the “WPSC”) requesting an annual increase of $34 million, or an average price increase of 7%, 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 plant. 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 increase of 4%. The WPSC held and completed public hearings on the 2008 general rate case in March 2009. In May 2009, the final order was issued by the WPSC approving the stipulation agreement.

In February 2009, PacifiCorp filed its annual PCAM application with the WPSC. The PCAM application requests 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 docket, PacifiCorp is requesting a $2 million reduction to the current annual surcharge rate based on the results for the twelve-month period ending 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, or 3%, 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 interim rate increase implemented in April 2009 be made permanent. A public hearing to consider the stipulation agreement is scheduled for August 2009.

In September 2008, PacifiCorp filed a general rate case with the Idaho Public Utilities Commission (the “IPUC”) for an annual increase of $6 million, or an average price increase of 4%. 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 rate 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 if a mechanism is adopted in Idaho. In February 2009, parties to the stipulation filed supporting testimony recommending the IPUC approve the stipulation as filed. Public hearings were held in March 2009 for the IPUC to hear evidence in support of the settlement and associated price increase. In April 2009, the IPUC issued an order approving the stipulation effective April 18, 2009.

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.

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.

MEHC’s senior unsecured debt credit ratings are as follows: Moody’s Investor 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 MEHC’s subsidiaries 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 June 30, 2009, each 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 June 30, 2009, the Company would have been required to post $530 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.

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.

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 June 30, 2009 and December 31, 2008.

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 June 30, 2009 that has materially affected, or is reasonably likely to materially affect, the Company’s internal control over financial reporting.

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. Similar bills seeking to create “cap and trade” systems for greenhouse gas emissions have also been introduced in the United States Senate. 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.

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.

PART I - FINANCIAL INFORMATION

Item 1.	Financial Statements	3

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	27

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	42

Item 4.	Controls and Procedures	42

PART II - OTHER INFORMATION

Item 1.	Legal Proceedings	43

Item 1A	Risk Factors	43

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	43

Item 3.	Defaults Upon Senior Securities	43

Item 4.	Submission of Matters to a Vote of Security Holders	43

Item 5.	Other Information	43

Item 6.	Exhibits	43

Signatures		44

Exhibit Index		45

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

Long-term debt	$	19,914	$	20,753	$	19,396	$	19,396

	Unit of	As of
	Measure	June 30, 2009
Commodity contracts:
Electricity sales	Megawatt hours		(17	)
Natural gas purchases	Decatherms		272
Fuel purchases	Gallons		8
Interest rate derivative – variable to fixed swap	Australian dollars		59

	MIDAMERICAN ENERGY HOLDINGS COMPANY
	(Registrant)



Date: August 7, 2009	/s/ Patrick J. Goodman
	Patrick J. Goodman
	Senior Vice President and Chief Financial Officer
	(principal financial and accounting officer)

	Three-Month			Six-Month
	Period Ended			Period Ended
	June 30, 2009			June 30, 2009

Beginning balance	$	315		$	446
Changes in fair value recognized in net regulatory assets		(96	)		(197	)
Gains reclassified to earnings - operating revenue		77			169
Losses reclassified to earnings - cost of sales		(49	)		(171	)
Ending balance	$	247		$	247

	Commodity			Interest Rate
	Derivatives			Derivative			Total

Beginning balance	$	148		$	6		$	154
Gains recognized in OCI		(13	)		(2	)		(15	)
Losses reclassified to earnings - revenue		(1	)		-			(1	)
Losses reclassified to earnings - cost of sales		(30	)		-			(30	)
Ending balance	$	104		$	4		$	108

Other Postretirement:
Service cost	$	2		$	2		$	4		$	6
Interest cost		10			12			21			24
Expected return on plan assets		(10	)		(11	)		(19	)		(22	)
Net amortization		1			5			6			9
Net periodic benefit cost	$	3		$	8		$	12		$	17

					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		-		-		-			-		96		-		-		96
Other		-		-		(13	)		-		-		-		-		(13	)
Goodwill at June 30, 2009	$	1,126	$	2,102	$	236		$	34	$	1,146	$	71	$	391	$	5,106