UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

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

For the fiscal year ended December 31, 2008

or

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

For the transition period from ______ to _______

Commission	Exact name of registrant as specified in its charter;	IRS Employer
File Number	State or other jurisdiction of incorporation or organization	Identification No.
001-14881	MIDAMERICAN ENERGY HOLDINGS COMPANY	94-2213782
	(An Iowa Corporation)
	666 Grand Avenue, Suite 500
	Des Moines, Iowa 50309-2580
	515-242-4300
Securities registered pursuant to Section 12(b) of the Act:  None
Securities registered pursuant to Section 12(g) of the Act:  None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.

Yes 0 No T

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.

Yes 0 No T

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes T No 0

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of the registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. T

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

Large accelerated filer  0 Accelerated filer  0 Non-accelerated filer  T Smaller reporting company  0

Indicate by check mark whether the registrant is a shell company (as defined in rule 12b-2 of the Exchange Act).Yes 0 No T

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

TABLE OF CONTENTS

PART I
Item 1.	Business	5
Item 1A.	Risk Factors	39
Item 1B.	Unresolved Staff Comments	51
Item 2.	Properties	52
Item 3.	Legal Proceedings	52
Item 4.	Submission of Matters to a Vote of Security Holders	53
PART II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	54
Item 6.	Selected Financial Data	54
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	55
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	77
Item 8.	Financial Statements and Supplementary Data	81
Item 9.	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure	132
Item 9A(T).	Controls and Procedures	132
Item 9B.	Other Information	132
PART III
Item10.	Directors, Executive Officers and Corporate Governance	133
Item 11.	Executive Compensation	134
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	146
Item 13.	Certain Relationships and Related Transactions, and Director Independence	148
Item 14.	Principal Accountant Fees and Services	149
PART IV
Item 15.	Exhibits and Financial Statement Schedules	150
Signatures		156
Exhibit Index		158

2 

Forward-Looking Statements

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

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

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

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

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

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

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

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

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

· changes in business strategy or development plans;

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

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

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

· risks relating to nuclear generation;

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

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

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

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

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

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

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

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

Further details of the potential risks and uncertainties affecting the Company are described in MEHC’s filings with the SEC, including Item 1A and other discussions contained in this Form 10-K. 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.

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PART I

Item 1. Business

General

MidAmerican Energy Holdings Company (“MEHC”) is a holding company which owns subsidiaries that are 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, Mr. David L. Sokol, MEHC’s Chairman, and Mr. Gregory E. Abel, MEHC’s President and Chief Executive Officer. As of January 31, 2009, Berkshire Hathaway, Mr. Scott (along with family members and related entities), Mr. Sokol and Mr. Abel owned 88.2%, 11.0%, -% and 0.8%, respectively, of MEHC’s voting common stock and held diluted ownership interests of 87.4%, 10.9%, 0.7% and 1.0%, respectively.

On March 1, 2006, MEHC and Berkshire Hathaway entered into an Equity Commitment Agreement (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. 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 each 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’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”). Refer to Note 23 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for additional segment information regarding MEHC’s platforms. Through these platforms, MEHC owns and operates an electric utility company in the Western United States, a combined 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.

MEHC’s energy subsidiaries generate, transmit, store, distribute and supply energy. Approximately 95% of the Company’s operating income in 2008 was generated from rate-regulated businesses. As of December 31, 2008, MEHC’s electric and natural gas utility subsidiaries served 6.2 million electricity customers and end users and 0.7 million natural gas customers. MEHC’s natural gas pipeline subsidiaries operate interstate natural gas transmission systems that transported approximately 9% of the total natural gas consumed in the United States in 2008. These pipeline subsidiaries have approximately 17,000 miles of pipeline in operation and a design capacity of 7.0 billion cubic feet (“bcf”) of natural gas per day. As of December 31, 2008, the Company had interests in approximately 18,000 net owned megawatts (“MW”) of power generation facilities in operation and under construction, including approximately 17,000 net owned MW in facilities that are part of the regulated asset base of its electric utility businesses and approximately 1,000 net owned MW in non-utility power generation facilities. The majority of the Company’s non-utility power generation facilities have long-term contracts for the sale of energy or capacity from the facilities.

MEHC’s principal executive offices are located at 666 Grand Avenue, Suite 500, Des Moines, Iowa 50309-2580 and its telephone number is (515) 242-4300. MEHC was initially incorporated in 1971 under the laws of the state of Delaware and reincorporated in 1999 in Iowa, which resulted in a change of its name from CalEnergy Company, Inc. to MidAmerican Energy Holdings Company.

5 

PacifiCorp

On March 21, 2006, a wholly owned subsidiary of MEHC acquired 100% of the common stock of PacifiCorp, a public utility company, from a wholly owned subsidiary of Scottish Power plc (“ScottishPower”) for a cash purchase price of $5.12 billion, including direct transaction costs. The results of PacifiCorp’s operations are included in the Company’s results beginning March 21, 2006. In connection with the 2006 acquisition of PacifiCorp, PacifiCorp and MEHC agreed to certain regulatory commitments as discussed in Note 18 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K.

General

PacifiCorp is a United States regulated electric company serving 1.7 million retail customers in portions of Utah, Oregon, Wyoming, Washington, Idaho and California. The combined service territory’s diverse regional economy ranges from rural, agricultural and mining areas to urban, manufacturing and government service centers. No single segment of the economy dominates the service territory, which helps mitigate PacifiCorp’s exposure to economic fluctuations.

In the eastern portion of the service territory, mainly consisting of Utah, Wyoming and southeast Idaho, the principal industries are manufacturing, health services, recreation, agriculture and mining or extraction of natural resources. In the western portion of the service territory, mainly consisting of Oregon, southeastern Washington and northern California, the principal industries are agriculture and manufacturing, with forest products, food processing, technology and primary metals being the largest industrial sectors. In addition to retail sales, PacifiCorp sells electric energy to other utilities, municipalities and marketers. These sales are referred to as wholesale sales.

PacifiCorp’s regulated electric operations are conducted under franchise agreements, certificates, permits and licenses obtained from federal, state and local authorities. The average term of these franchise agreements is approximately 30 years, although their terms range from five years to indefinite. PacifiCorp generally has an exclusive right to serve electric customers within its service territories and, in turn, has an obligation to provide electric service to those customers. In return the state utility commissions have established rates on a cost-of-service basis, which are designed to allow PacifiCorp an opportunity to recover its costs of providing services and to earn a reasonable return on its investment.

On May 10, 2006, the PacifiCorp Board of Directors elected to change PacifiCorp’s fiscal year-end from March 31 to December 31. Therefore, in the following pages, the nine-month period ended December 31, 2006 information covers the transition period beginning April 1, 2006 and ending December 31, 2006.

Regulated Electric Operations

Customers

The percentages of electricity sold to retail and wholesale customers, by class of customer, total gigawatt hours (“GWh”) sold and the average number of retail customers were as follows:

							Nine-Month
	Year Ended			Year Ended			Period Ended
	December 31,			December 31,			December 31,
	2008			2007			2006
Residential		24	%		24	%		22	%
Commercial		24			24			24
Industrial		32			31			32
Other		1			1			1
Total retail		81			80			79
Wholesale		19			20			21
Total retail and wholesale		100	%		100	%		100	%
Total GWh sold		66,707			67,114			49,313
Total average retail customers (in millions)		1.7			1.7			1.7

6

PacifiCorp has historically experienced growth in loads; however, beginning in the fourth quarter of 2008, certain customer usage levels began to decline due to the effects of current economic conditions in the United States and around the world. The declining usage trend may continue in 2009.

The percentages of electricity sold to retail customers by jurisdiction were as follows:

							Nine-Month
	Year Ended			Year Ended			Period Ended
	December 31,			December 31,			December 31,
	2008			2007			2006
Utah		42	%		42	%		41	%
Oregon		26			26			26
Wyoming		17			16			16
Washington		7			8			8
Idaho		6			6			7
California		2			2			2
		100	%		100	%		100	%

Peak customer demand is typically highest in the summer across PacifiCorp’s service territory when air-conditioning and irrigation systems are heavily used. The service territory also has a winter peak, which is typically lower than the summer peak and is primarily due to heating requirements.

Customer growth, weather conditions and increased installation and use of central air conditioning systems have contributed to increased summer peak load growth over the past few years. During the year ended December 31, 2008, PacifiCorp’s peak load was 9,501 MW in the summer and 9,176 MW in the winter. Peak load represents the highest load on a given day and at a given hour.

Power and Fuel Supply

The following table shows the percentage of PacifiCorp’s total energy supplied by energy source:

							Nine-Month
	Year Ended			Year Ended			Period Ended
	December 31,			December 31,			December 31,
	2008			2007			2006
Coal		65	%		64	%		62	%
Natural gas		12			11			7
Hydroelectric		5			5			6
Other		2			1			1
Total energy generated		84			81			76
Energy purchased-long-term contracts		5			5			7
Energy purchased-short-term contracts and other		11			14			17
		100	%		100	%		100	%

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The percentage of PacifiCorp’s energy requirements generated by energy source varies from year to year and is subject to numerous operational and economic factors such as planned and unplanned outages, fuel availability, price and transportation costs, weather-related impacts, environmental considerations and the market price of electricity. When factors for one source of generation are unfavorable, PacifiCorp may place more reliance on the other sources of generation. For example, the amount of electricity PacifiCorp is able to generate from its hydroelectric facilities depends on a number of factors, including snow-pack in the mountains upstream of its hydroelectric facilities, reservoir storage, precipitation in its watersheds, generating unit availability and restrictions imposed by oversight bodies due to competing water management objectives. When these factors are favorable, PacifiCorp can generate more electricity using its low cost hydroelectric facilities. When these factors are unfavorable, PacifiCorp must increase its reliance on more expensive coal and natural gas-fired facilities and purchased electricity. PacifiCorp manages certain risks relating to its natural gas supply requirements and its wholesale transactions by entering into various financial derivative instruments, including forward purchases and sales, swaps and options. Refer to Item 7A included in this Form 10-K for a discussion of commodity price risk and derivative instruments.

Recoverable coal reserves as of December 31, 2008, based on PacifiCorp’s most recent engineering studies, were as follows (in millions):

Location	Plant Served	Mining Method	Recoverable Tons
Craig, CO	Craig	Surface	47	(1)
Huntington & Castle Dale, UT	Huntington and Hunter	Underground	35	(2)
Rock Springs, WY	Jim Bridger	Surface	84	(3)
Rock Springs, WY	Jim Bridger	Underground	53	(3)
			219

(1)	These coal reserves are leased and mined by Trapper Mining, Inc., a Delaware non-stock corporation operated on a cooperative basis, in which PacifiCorp has an ownership interest of 21%.
(2)	These coal reserves are leased by PacifiCorp and mined by a wholly owned subsidiary of PacifiCorp.
(3)	These coal reserves are leased and mined by Bridger Coal Company, a joint venture between Pacific Minerals, Inc. (“PMI”) and a subsidiary of Idaho Power Company. PMI, a wholly owned subsidiary of PacifiCorp, has a two-thirds interest in the joint venture. The amounts included above represents only PacifiCorp’s two-thirds interest in the coal reserves.

Mines owned or leased by PacifiCorp supplied 31% of PacifiCorp’s total coal requirements during each of the years ended December 31, 2008 and 2007 and the nine-month period ended December 31, 2006. The remaining coal requirements are acquired through long- and short-term third party contracts. PacifiCorp’s mines are located adjacent to many of its coal-fired generating facilities, which significantly reduces overall transportation costs included in fuel expense.

Coal reserve estimates are subject to adjustment as a result of the development of additional engineering and geological data, new mining technology and changes in regulation and economic factors affecting the utilization of such reserves. PacifiCorp believes that the coal reserves available to the Craig, Huntington, Hunter and Jim Bridger coal-fired generating facilities, together with coal available under both long- and short-term contracts with external suppliers to supply its remaining generating facilities, will be substantially sufficient to provide these facilities with fuel for their currently expected useful lives. To meet applicable standards, PacifiCorp blends coal mined from its owned mines with contracted coal and utilizes electricity plant technologies for controlling sulfur dioxide and other emissions.

Recoverability by surface mining methods typically ranges from 90% to 95%. Recoverability by underground mining techniques ranges from 50% to 70%. Most of PacifiCorp’s coal reserves are held pursuant to leases from the federal government through the Bureau of Land Management and from certain states and private parties. The leases generally have multi-year terms that may be renewed or extended only with the consent of the lessor and require payment of rents and royalties.

PacifiCorp uses natural gas as fuel for its combined- and simple-cycle natural gas-fired generating facilities. Oil and natural gas are also used for igniter fuel and to fuel generation for transmission support and standby purposes. These sources are presently in adequate supply and available to meet PacifiCorp’s needs.

8 

PacifiCorp operates the majority of its hydroelectric generating portfolio under long-term licenses from the Federal Energy Regulatory Commission (“FERC”) with terms of 30 to 50 years. For a further discussion of PacifiCorp’s hydroelectric relicensing and decommissioning activities, including updated information regarding the Klamath River System, refer to Note 18 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K.

PacifiCorp is pursuing renewable resources as a viable, economical and environmentally prudent means of generating electricity, achieving emission reduction targets and for compliance with renewable portfolio standards. The benefits of energy from renewable resources include low to no emissions and typically little or no fossil fuel requirements. The intermittent nature of some renewable resources, such as wind, is complemented by PacifiCorp’s other generating resources, wholesale transactions and wind-powered generating resource curtailment capabilities, which are important to integrating intermittent wind resources into the electric system. PacifiCorp has qualifying wind-powered facilities that are eligible for federal renewable electricity production tax credits (“PTCs”) for ten years from the date that the facilities were placed in-service. In February 2009, legislation was passed extending the date by which such facilities must be placed in service to be eligible for PTCs to December 31, 2012.

In addition to its portfolio of generating facilities, PacifiCorp purchases electricity in the wholesale markets to meet its retail load and long-term wholesale sales obligations for system balancing requirements and to enhance the efficient use of its generating capacity over the long-term. Generation can vary with the levels of outages, hydroelectric and wind-powered generating conditions, operational factors and transmission constraints. Retail load can vary with the weather, distribution system outages, consumer trends and the level of economic activity. In addition, PacifiCorp purchases electricity in the wholesale markets when it is more economical than generating it at its own facilities. PacifiCorp may also sell into the wholesale market excess electricity arising from imbalances between generation and retail load obligations, subject to pricing and transmission constraints. Many of PacifiCorp’s purchased electricity contracts have fixed-price components, which provide some protection against price volatility.

Historically, PacifiCorp has been able to purchase electricity from utilities in the Western United States for its own requirements. Delivery of these purchases is conducted through PacifiCorp and third-party transmission systems, which connect with market hubs in the Pacific Northwest to provide access to normally low-cost hydroelectric and wind-powered generation, and in the Southwestern United States to provide access to normally higher-cost fossil-fuel generation. The transmission system is available for common use consistent with open-access regulatory requirements.

9 

The following table presents certain information concerning PacifiCorp’s owned power generating facilities as of December 31, 2008:

					Facility
					Net Capacity		Net MW
	Location	Energy Source	Installed		(MW) (1)		Owned (1)
COAL:
Jim Bridger	Rock Springs, WY	Coal		1974-1979		2,120		1,414
Hunter Nos. 1, 2 and 3	Castle Dale, UT	Coal		1978-1983		1,320		1,122
Huntington	Huntington, UT	Coal		1974-1977		895		895
Dave Johnston	Glenrock, WY	Coal		1959-1972		762		762
Naughton	Kemmerer, WY	Coal		1963-1971		700		700
Cholla No. 4	Joseph City, AZ	Coal	1981			380		380
Wyodak	Gillette, WY	Coal	1978			335		268
Carbon	Castle Gate, UT	Coal		1954-1957		172		172
Craig Nos. 1 and 2	Craig, CO	Coal		1979-1980		856		165
Colstrip Nos. 3 and 4	Colstrip, MT	Coal		1984-1986		1,480		148
Hayden Nos. 1 and 2	Hayden, CO	Coal		1965-1976		446		78
						9,466		6,104
NATURAL GAS:
Lake Side	Vineyard, UT	Natural gas/Steam	2007			548		548
Currant Creek	Mona, UT	Natural gas/Steam		2005-2006		540		540
Chehalis	Chehalis, WA	Natural gas/Steam	2003			520		520
Hermiston	Hermiston, OR	Natural gas/Steam	1996			474		237
Gadsby Steam	Salt Lake City, UT	Natural gas		1951-1952		235		235
Gadsby Peakers	Salt Lake City, UT	Natural gas	2002			120		120
Little Mountain	Ogden, UT	Natural gas	1972			14		14
						2,451		2,214
HYDROELECTRIC:
Lewis River System	WA	Hydroelectric		1931-1958		578		578
North Umpqua River System	OR	Hydroelectric		1950-1956		200		200
Klamath River System	CA, OR	Hydroelectric		1903-1962		170		170
Bear River System	ID, UT	Hydroelectric		1908-1984		105		105
Rogue River System	OR	Hydroelectric		1912-1957		52		52
Minor hydroelectric facilities	Various	Hydroelectric		1895-1986		53		53
						1,158		1,158
WIND:
Marengo	Dayton, WA	Wind	2007			140		140
Leaning Juniper I	Arlington, OR	Wind	2006			101		101
Glenrock	Glenrock, WY	Wind	2008			99		99
Seven Mile Hill I	Medicine Bow, WY	Wind	2008			99		99
Goodnoe Hills	Goldendale, WA	Wind	2008			94		94
Marengo II	Dayton, WA	Wind	2008			70		70
Foote Creek	Arlington, WY	Wind	1997			41		33
Seven Mile Hill II	Medicine Bow, WY	Wind	2008			20		20
						664		656
OTHER:
Blundell	Milford, UT	Geothermal		1984, 2007		34		34
Camas Co-Gen	Camas, WA	Black liquor	1996			22		22
						56		56
Total Available Generating Capacity						13,795		10,188
PROJECTS UNDER CONSTRUCTION/DEVELOPMENT(2):
High Plains	McFadden, WY	Wind	2009			99		99
Rolling Hills	Glenrock, WY	Wind	2009			99		99
Glenrock III	Glenrock, WY	Wind	2009			39		39
						14,032		10,425

(1) Facility Net Capacity (MW) represents (except for wind-powered generation facilities, which are nameplate ratings) the total capability of a generating unit as demonstrated by actual operating or test experience, less power generated and used for auxiliaries and other station uses, and is determined using average annual temperatures. Net MW Owned indicates current legal ownership.

(2) Facility Net Capacity (MW) and Net MW Owned for projects under construction/development each represent the estimated nameplate ratings (MW). A generator’s nameplate rating is its full-load capacity under normal operating conditions as defined by the manufacturer. In January 2009, the 99-MW Rolling Hills and 39-MW Glenrock III wind-powered generating plants were placed in service.

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Future Generation

PacifiCorp prepares and files with the state regulatory commissions a biennial Integrated Resource Plan (“IRP”), a long-term view of expected future resource needs, the associated risk-adjusted optimal resource mix and a description of the prudent future actions to help ensure that PacifiCorp continues to provide reliable and cost-effective electric service to its customers. In the 2007 IRP, PacifiCorp identified a need for approximately 3,171 MW of additional resources by summer 2016 to satisfy the difference between projected retail load obligations and owned or contracted resources. PacifiCorp plans to meet this need through demand-side management programs, the construction or purchase of additional renewable energy, combined heat and power, and thermal generation capacity, and wholesale electricity transactions. In 2008, PacifiCorp submitted to the state regulatory commissions a 2007 IRP update report reflecting an adjusted need of 3,202 MW of additional resources by 2016 with heavier reliance on energy efficiency measures. This need was reduced by 509 MW due to the September 2008 acquisition of the Chehalis plant. PacifiCorp’s 2008 IRP is scheduled to be filed in Spring 2009, which will take into account recent declines in load and growth expectations.

In addition to new generation resources, substantial transmission investments will be required to deliver energy to PacifiCorp’s growing customer base and to enhance system reliability. Refer to “Transmission and Distribution” below.

Demand-side Management

PacifiCorp has provided a comprehensive set of demand-side management programs to its customers since the 1970s. The programs are designed to reduce energy consumption and more effectively manage when energy is used, including management of seasonal peak loads. Current programs offer services to customers such as energy engineering audits and information on how to improve the efficiency of their homes and businesses. To assist customers in investing in energy efficiency, PacifiCorp offers rebates or incentives encouraging the purchase and installation of high-efficiency equipment such as lighting, heating and cooling equipment, weatherization, motors, process equipment and systems, as well as incentives for efficient construction. Incentives are also paid to solicit participation in load management programs by residential, business and agricultural customers through programs such as PacifiCorp’s residential and small commercial air conditioner load control program and irrigation equipment load control programs. Subject to random prudence reviews, state regulations allow for contemporaneous recovery of costs incurred for retail customer demand-side management programs and services through state-specific energy efficiency service charges paid by all retail electric customers. In addition to these retail customer demand-side management programs, PacifiCorp has load curtailment contracts with a number of large industrial customers that deliver up to 342 MW of load reduction when needed. Recovery for the costs associated with the large industrial load management program is determined through PacifiCorp’s general rate case process. In 2008, $77 million was expended on the demand-side management programs in PacifiCorp’s six-state service area, resulting in an estimated 395,000 megawatt hours (“MWh”) of first-year energy savings and 338 MW of peak load management. Total demand-side load available for control in 2008, including both load management from the large industrial curtailment contracts and retail customer demand-side management programs, was approximately 680 MW.

Transmission and Distribution

PacifiCorp operates two balancing authority areas in its service territory, a geographic area with electric systems that control generation to maintain schedules with other balancing authority areas and ensure reliable operations. In operating the balancing authority areas, PacifiCorp is responsible for continuously balancing electric supply and demand by dispatching generating resources and interchange transactions so that generation internal to the balancing authority area, plus net imported power, matches customer loads. PacifiCorp also schedules deliveries of energy over its transmission system in accordance with FERC requirements.

PacifiCorp’s transmission system is part of the Western Interconnection, the regional grid principally located along and west of the Rocky Mountains that includes the interconnected transmission systems of 14 western states, two Canadian provinces and parts of Mexico that make up the Western Electric Coordinating Council (“WECC”). PacifiCorp’s transmission system, together with contractual rights on other transmission systems, enables PacifiCorp to integrate and access generation resources to meet its customer load requirements. The electric transmission system of PacifiCorp included approximately 16,000 miles of transmission lines and approximately 900 substations as of December 31, 2008.

PacifiCorp has an investment plan, the Energy Gateway Transmission Expansion Project, to build approximately 2,000 miles of new high-voltage transmission lines primarily in Wyoming, Utah, Idaho, Oregon and the desert Southwest. The plan, with an estimated cost exceeding $6.1 billion, includes projects that will address customer load growth, improve system reliability and deliver energy from new wind-powered and other renewable generating resources throughout PacifiCorp’s six-state service area and the Western United States. Certain transmission segments associated with this plan are expected to be placed in service beginning 2010, with other segments placed in service through 2018, depending on siting, permitting and construction schedules.

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MidAmerican Energy

General

MidAmerican Energy, an indirect wholly owned subsidiary of MEHC, is a public utility company headquartered in Iowa, which serves 0.7 million regulated retail electric customers in portions of Iowa, Illinois and South Dakota and 0.7 million regulated retail and transportation natural gas customers in portions of Iowa, Illinois, Nebraska and South Dakota. MidAmerican Energy is principally engaged in the business of generating, transmitting, distributing and selling electricity and in distributing, selling and transporting natural gas. MidAmerican Energy has a diverse customer base consisting of residential, agricultural and a variety of commercial and industrial customer groups. Some of the larger industrial groups served by MidAmerican Energy include the processing and sales of food products; the manufacturing, processing and fabrication of primary metals; farm and other non-electrical machinery; real estate; and cement and gypsum products. In addition to retail sales and natural gas transportation, MidAmerican Energy sells electric energy to markets operated by regional transmission organizations (“RTOs”) and electric energy and natural gas to other utilities, municipalities and marketers. These sales are referred to as wholesale sales.

MidAmerican Energy’s regulated electric and gas operations are conducted under numerous franchise agreements, certificates, permits and licenses obtained from federal, state and local authorities. The franchise agreements, with various expiration dates, are typically for 25-year terms. MidAmerican Energy generally has an exclusive right to serve electric customers within its service territories and, in turn, has an obligation to provide electric service to those customers. In return the state utility commissions have established rates on a cost-of-service basis, which are designed to allow MidAmerican Energy an opportunity to recover its costs of providing services and to earn a reasonable return on its investment.

MidAmerican Energy also conducts a number of nonregulated business activities outside the traditional regulated electric and natural gas services, including nonregulated electric and natural gas sales and gas income-sharing arrangements. MidAmerican Energy’s nonregulated retail electric marketing services provide electric supply services to retail customers predominantly in Illinois. During 2007, MidAmerican Energy’s nonregulated retail electric marketing services expanded significantly in Illinois as a result of that market becoming fully open to competition. Effective January 1, 2007, the major electric distribution companies in Illinois began increasing their purchases of energy on the open market as their existing contracts expired. MidAmerican Energy’s nonregulated gas marketing services operate in Iowa, Illinois, Michigan, South Dakota and Nebraska. MidAmerican Energy purchases gas from producers and third party marketers and sells it directly to commercial and industrial end-users, as well as wholesalers. In addition, MidAmerican Energy manages gas supplies for a number of smaller commercial end-users, which includes the sale of gas to these customers to meet their supply requirements.

MidAmerican Energy’s operating revenues were derived from the following business activities during the years ended December 31:

	2008			2007			2006
Regulated electric		43	%		45	%		52	%
Regulated gas		29			28			32
Nonregulated		28			27			16
		100	%		100	%		100	%

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Regulated Electric Operations

Customers

The percentages of electricity sold to retail and wholesale customers, by class of customer, total GWh sold and the average number of retail customers as of and for the years ended December 31 were as follows:

	2008			2007			2006
Residential		17	%		18	%		18	%
Commercial		12			12			13
Industrial		25			27			28
Other		4			5			5
Total retail		58			62			64
Wholesale		42			38			36
Total retail and wholesale		100	%		100	%		100	%
Total GWh sold		36,061			33,614			30,999
Total average retail customers (in millions)		0.7			0.7			0.7

The percentages of electricity sold to retail customers by jurisdiction for the years ended December 31 were as follows:

	2008			2007			2006
Iowa		90	%		90	%		90	%
Illinois		9			9			9
South Dakota		1			1			1
		100	%		100	%		100	%

There are seasonal variations in MidAmerican Energy’s electric business that are principally related to the use of electricity for air conditioning. Typically, 35-40% of MidAmerican Energy’s regulated electric revenues are reported in the months of June, July, August and September.

The annual hourly peak demand on MidAmerican Energy’s electric system usually occurs as a result of air conditioning use during the cooling season. On August 13, 2007, retail customer usage of electricity caused a record hourly peak demand of 4,240 MW on MidAmerican Energy’s electric system. For 2008, MidAmerican Energy recorded an hourly peak demand of 4,210 MW on July 31.

Power and Fuel Supply

The following table shows the percentage of MidAmerican Energy’s total energy supplied by energy source for the years ended December 31:

	2008			2007			2006
Coal		59	%		56	%		55	%
Nuclear		10			10			11
Natural gas		3			3			3
Other		6			5			3
Total energy generated		78			74			72
Energy purchased-long-term contracts		8			7			7
Energy purchased-short-term contracts and spot market		14			19			21
		100	%		100	%		100	%

The percentage of MidAmerican Energy’s energy requirements generated by its facilities will vary from year to year and is determined by factors such as planned and unplanned outages, the availability and price of fuels, weather, environmental considerations and the market price of electricity.

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MidAmerican Energy is exposed to fluctuations in energy costs relating to retail sales in Iowa and Illinois as it does not have an energy adjustment mechanism in those jurisdictions. In Illinois, base rates were adjusted to include recoveries at average 2004/2005 energy cost levels beginning January 1, 2007, and rate case approval is required for any base rate changes. MidAmerican Energy may not petition for reinstatement of the Illinois fuel adjustment clause until November 2011.

All of the coal-fired generating stations operated by MidAmerican Energy are fueled by low-sulfur, western coal from the Powder River Basin in northeast Wyoming and southeast Montana. MidAmerican Energy’s coal supply portfolio includes multiple suppliers and mines under short-term and multi-year agreements of varying terms and quantities. MidAmerican Energy’s coal supply portfolio has a substantial majority of its expected 2009 requirements under fixed-price contracts. MidAmerican Energy regularly monitors the western coal market for opportunities to enhance its coal supply portfolio.

MidAmerican Energy has a long-term coal transportation agreement with Union Pacific Railroad Company (“Union Pacific”). Under this agreement, Union Pacific delivers coal directly to MidAmerican Energy’s George Neal and Walter Scott, Jr. Energy Centers and to an interchange point with the Iowa, Chicago & Eastern Railroad Corporation for short-haul delivery to the Louisa and Riverside Energy Centers. MidAmerican Energy has the ability to use BNSF Railway Company for delivery of a small amount of coal to the Walter Scott, Jr., Louisa and Riverside Energy Centers should the need arise.

MidAmerican Energy is a 25% joint owner of Quad Cities Generating Station Units 1 and 2 (“Quad Cities Station”), a nuclear power plant. Exelon Generation Company, LLC (“Exelon Generation”), the 75% joint owner and the operator of Quad Cities Station, is a subsidiary of Exelon Corporation. Approximately one-third of the nuclear fuel assemblies in each reactor core at the Quad Cities Station is replaced every 24 months. MidAmerican Energy has been advised by Exelon Generation that the following requirements for the Quad Cities Station can be met under existing supplies or commitments: uranium requirements through 2010 and partial requirements through 2016; uranium conversion requirements through 2010 and partial requirements through 2011; enrichment requirements through 2010 and partial requirements through 2028; and fuel fabrication requirements through 2019. MidAmerican Energy has been advised by Exelon Generation that it does not anticipate it will have difficulty in contracting for uranium, uranium conversion, enrichment or fabrication of nuclear fuel needed to operate Quad Cities Station during these time periods.

MidAmerican Energy uses natural gas and oil as fuel for intermediate and peak demand electric generation, igniter fuel, transmission support and standby purposes. These sources are presently in adequate supply and available to meet MidAmerican Energy’s needs.

MidAmerican Energy continues to pursue renewable resources as a viable, economical and environmentally prudent means of generating electricity and reaching emission reduction targets. The benefits of energy from renewable resources include low to no emissions and typically little or no fossil fuel requirements. The intermittent nature of some renewable resources, such as wind, is complemented by MidAmerican Energy’s other generating resources and wholesale transactions, which are important to integrating intermittent wind resources into the electric system. MidAmerican Energy has qualifying wind-powered facilities that are eligible for federal renewable electricity PTCs for ten years from the date the facilities were placed in-service. In February 2009, legislation was passed extending the date by which such facilities must be placed in service to be eligible for PTCs to December 31, 2012.

In addition to its portfolio of generating facilities, MidAmerican Energy purchases electricity in the wholesale markets to meet its retail load and long-term wholesale sales obligations, for system balancing requirements and to enhance the efficient use of its generating capacity over the long-term. Generation can vary with the levels of outages, generation conditions, operational factors and transmission constraints. Retail load can vary with the weather, distribution system outages, consumer trends and the level of economic activity. In addition, MidAmerican Energy purchases electricity in the wholesale markets when it is more economical than generating it at its own facilities. MidAmerican Energy may also sell into the wholesale market excess electricity arising from imbalances between generation and retail load obligations, subject to pricing and transmission constraints. Many of MidAmerican Energy’s purchased electricity contracts have fixed-price components, which provide some protection against price volatility.

MidAmerican Energy manages certain risks relating to its supply of electricity and fuel requirements by entering into various financial derivative instruments, including forward purchases and sales, futures, swaps and options. Refer to Item 7A included in this Form 10-K for a discussion of commodity price risk and derivative instruments.

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The following table presents certain information concerning MidAmerican Energy’s owned power generating facilities as of December 31, 2008:

					Facility Net
					Capacity		Net MW
	Location	Energy Source	Installed		(MW)(1)		Owned(1)
COAL:
George Neal Unit No. 1	Sergeant Bluff, IA	Coal	1964			135		135
George Neal Unit No. 2	Sergeant Bluff, IA	Coal	1972			289		289
George Neal Unit No. 3	Sergeant Bluff, IA	Coal	1975			515		371
George Neal Unit No. 4	Salix, IA	Coal	1979			644		261
Louisa	Muscatine, IA	Coal	1983			745		656
Ottumwa	Ottumwa, IA	Coal	1981			710		369
Riverside Unit No. 3	Bettendorf, IA	Coal	1925			5		5
Riverside Unit No. 5	Bettendorf, IA	Coal	1961			130		130
Walter Scott, Jr. Unit No. 1	Council Bluffs, IA	Coal	1954			45		45
Walter Scott, Jr. Unit No. 2	Council Bluffs, IA	Coal	1958			88		88
Walter Scott, Jr. Unit No. 3	Council Bluffs, IA	Coal	1978			690		546
Walter Scott, Jr. Unit No. 4	Council Bluffs, IA	Coal	2007			800		477
						4,796		3,372
NATURAL GAS:
Greater Des Moines	Pleasant Hill, IA	Natural gas		2003-2004		494		494
Coralville	Coralville, IA	Natural gas	1970			64		64
Electrifarm	Waterloo, IA	Natural gas/Oil		1975-1978		198		198
Moline	Moline, IL	Natural gas	1970			64		64
Parr	Charles City, IA	Natural gas	1969			32		32
Pleasant Hill	Pleasant Hill, IA	Natural gas/Oil		1990-1994		160		160
River Hills	Des Moines, IA	Natural gas		1966-1967		117		117
Sycamore	Johnston, IA	Natural gas/Oil	1974			149		149
28 portable power modules	Various	Oil	2000			56		56
						1,334		1,334
NUCLEAR:
Quad Cities Unit No. 1	Cordova, IL	Uranium	1972			872		218
Quad Cities Unit No. 2	Cordova, IL	Uranium	1972			868		217
						1,740		435
WIND:
Adair	Adair, IA	Wind	2008			175		175
Carroll	Carroll, IA	Wind	2008			150		150
Century	Blairsburg, IA	Wind		2005-2008		200		200
Charles City	Charles City, IA	Wind	2008			75		75
Intrepid	Schaller, IA	Wind		2004-2005		176		176
Pomeroy	Pomeroy, IA	Wind		2007-2008		256		256
Victory	Westside, IA	Wind	2006			99		99
Walnut	Walnut, IA	Wind	2008			153		153
						1,284		1,284
OTHER:
Moline Unit Nos. 1-4	Moline, IL	Mississippi River	1941			3		3
Total Available Generating Capacity						9,157		6,428

(1) Facility Net Capacity (MW) represents (except for wind-powered generation facilities, which are nameplate ratings) total plant accredited net generating capacity from the summer of 2008 based on MidAmerican Energy’s accreditation approved by the Mid-Continent Area Power Pool (“MAPP”). The 2008 summer accreditation of the wind-powered generation facilities in service at that time totaled 97 MW and is considerably less than the nameplate ratings due to the varying nature of wind. Additionally, the Adair, Carroll and Walnut wind-powered generation facilities and 58 MW of the Pomeroy wind-powered generation facility were placed in service subsequent to the 2008 summer accreditation. Net MW Owned indicates MidAmerican Energy’s ownership of Facility Net Capacity.

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Transmission and Distribution

MidAmerican Energy operates a balancing authority area in its service territory, a geographic area with electric systems that control generation to maintain schedules with other balancing authority areas and ensure reliable operations. In operating the balancing authority area, MidAmerican Energy is responsible for continuously balancing electric supply and demand by dispatching generating resources and interchange transactions so that generation internal to the balancing authority area, plus net imported power, matches customer loads. MidAmerican Energy also schedules deliveries of energy over its transmission system in accordance with FERC requirements.

MidAmerican Energy is interconnected with utilities in Iowa and neighboring states and is part of the Eastern Interconnection. MidAmerican Energy is also a party to an electric generation reserve sharing pool and regional transmission group administered by MAPP. MAPP is a voluntary association of electric utilities doing business in Minnesota, Nebraska, North Dakota and the Canadian provinces of Saskatchewan and Manitoba and portions of Iowa, Montana, South Dakota and Wisconsin. Its membership also includes power marketers, regulatory agencies and independent power producers. MAPP performs functions including administration of its short-term regional Open Access Transmission Tariff (“OATT”), coordination of regional planning and operations, and operation of the generation reserve sharing pool. As a MAPP member, MidAmerican Energy conducts transmission and wholesale power transactions using MAPP member interconnected facilities with the MAPP OATT and participates in the generation reserve sharing pool to support its operations.

MidAmerican Energy can transact with a substantial number of parties through its participation in MAPP and through its direct interconnections to the Midwest Independent Transmission System Operator, Inc., Southwest Power Pool, Inc. and PJM Interconnection, L.L.C. RTOs and several other major transmission-owning utilities in the region. Under normal operating conditions, MidAmerican Energy’s transmission system has adequate capacity to deliver energy to MidAmerican Energy’s distribution system and to export and import energy with other interconnected systems. The electric transmission system of MidAmerican Energy included approximately 2,200 miles of transmission lines and 400 substations as of December 31, 2008.

Regulated Natural Gas Operations

MidAmerican Energy is engaged in the procurement, transportation, storage and distribution of natural gas for customers in the Midwest. MidAmerican Energy purchases natural gas from various suppliers, transports it from the production areas to MidAmerican Energy’s service territory under contracts with interstate pipelines, stores it in various storage facilities to manage fluctuations in system demand and seasonal pricing, and delivers it to customers through MidAmerican Energy’s distribution system. MidAmerican Energy sells natural gas and transportation services to end-use customers and natural gas to other utilities, municipalities and marketers. MidAmerican Energy also transports natural gas through its distribution system for a number of end-use customers who have independently secured their supply of natural gas. During 2008, 44% of the total natural gas delivered through MidAmerican Energy’s system for end use customers was under natural gas transportation service.

The percentages of natural gas sold to retail and wholesale customers by class of customer for the years ended December 31 were as follows:

	2008			2007			2006
Residential		42	%		40	%		37	%
Commercial(1)		21			19			18
Industrial(1)		4			4			4
Total retail		67			63			59
Wholesale(2)		33			37			41
		100	%		100	%		100	%

(1)	Small and large general service customers are classified primarily based on the nature of their business and natural gas usage. Commercial customers are business customers whose natural gas usage is principally for heating. Industrial customers are business customers whose principal natural gas usage is for their manufacturing processes.
(2)	Wholesale generally includes other utilities, municipalities and marketers to whom natural gas is sold at wholesale for eventual resale to ultimate end-use customers.

16 

The percentages of natural gas sold to retail customers by jurisdiction for the years ended December 31 were as follows:

	2008			2007			2006
Iowa		77	%		77	%		77	%
South Dakota		12			12			12
Illinois		10			10			10
Nebraska		1			1			1
		100	%		100	%		100	%

There are seasonal variations in MidAmerican Energy’s natural gas business that are principally due to the use of natural gas for heating. Typically, 45-55% of MidAmerican Energy’s regulated natural gas revenues are reported in the months of January, February, March and December.

On January 15, 2009, MidAmerican Energy recorded its all-time highest peak-day delivery of 1,147,599 decatherms (“Dth”). This peak-day delivery consisted of approximately 75% traditional sales service and 25% transportation service of customer-owned gas.

Fuel Supply and Capacity

MidAmerican Energy is allowed to recover its cost of natural gas from all of its regulated natural gas customers through purchased gas adjustment clauses (“PGA”). Accordingly, as long as MidAmerican Energy is prudent in its procurement practices, MidAmerican Energy’s regulated natural gas customers retain the risk associated with the market price of natural gas. MidAmerican Energy uses several strategies designed to reduce the market price risk for its natural gas customers while maintaining system reliability, including a geographically diverse supply portfolio of producers and third party marketers, the use of storage gas and peak-shaving facilities, sharing arrangements to share savings and costs with customers and short-and long-term financial and physical gas purchase agreements.

MidAmerican Energy has rights to firm pipeline capacity to transport natural gas to its service territory through direct interconnects to the pipeline systems of several interstate natural gas pipeline systems, including Northern Natural Gas, an affiliate company.

MidAmerican Energy utilizes leased gas storage to meet peak day requirements and to manage the daily changes in demand due to changes in weather. The storage gas is typically replaced during off-peak months when the demand for natural gas is historically lower than during the heating season. In addition, MidAmerican Energy also utilizes three liquefied natural gas (“LNG”) plants and two propane-air plants to meet peak day demands in the winter. The storage and peak shaving facilities reduce MidAmerican Energy’s dependence on natural gas purchases during the volatile winter heating season. MidAmerican Energy can deliver approximately 50% of its design day sales requirements from its storage and peak shaving supply sources.

Natural gas property consists primarily of natural gas mains and services pipelines, meters, and related distribution equipment, including feeder lines to communities served from natural gas pipelines owned by others. The gas distribution facilities of MidAmerican Energy as of December 31, 2008 included approximately 22,000 miles of gas mains and service pipelines. In addition, natural gas property includes three liquefied natural gas plants and two propane-air plants.

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Demand-side Management

MidAmerican Energy has provided a comprehensive set of demand-side management programs to its Iowa electric and gas customers since 1990 and, beginning in 2008, its Illinois electric and gas customers. The programs are designed to reduce energy consumption and more effectively manage when energy is used, including management of seasonal peak loads. Current programs offer services to customers such as energy engineering audits and information on how to improve the efficiency of their homes and businesses. To assist customers investing energy efficiency, MidAmerican Energy offers rebates or incentives encouraging the purchase and installation of high-efficiency equipment such as lighting, heating and cooling equipment, weatherization, motors, process equipment and systems, as well as incentives for efficient construction. Incentives are also paid to solicit participation in load management programs by residential and business customers through programs such as MidAmerican Energy’s residential and large commercial and industrial air conditioner load control programs. Subject to random prudence reviews, state regulation allows for contemporaneous recovery of costs incurred for the demand-side management programs through state-specific energy efficiency service charges paid by all retail electric and gas customers. In 2008, $48 million was expended on the demand-side management programs resulting in an estimated 318 MW of electric and 5,598 Dth/day of gas peak load management.

Interstate Pipeline Companies

Northern Natural Gas

Northern Natural Gas, an indirect wholly owned subsidiary of MEHC, owns one of the largest interstate natural gas pipeline systems in the United States, which reaches from southern Texas to Michigan’s Upper Peninsula. Northern Natural Gas primarily transports and stores natural gas for utilities, municipalities, other pipeline companies, gas marketers, industrial and commercial users and other end users. Northern Natural Gas’ system consists of approximately 15,200 miles of natural gas pipelines, including approximately 6,400 miles of mainline transmission pipelines and approximately 8,800 miles of branch and lateral pipelines, with a Market Area design capacity of 5.3 Bcf per day and a Field Area delivery capacity of 2.0 Bcf per day to the Market Area. Based on a review of relevant industry data, the Northern Natural Gas system is believed to be the largest single pipeline in the United States as measured by pipeline miles and the seventh-largest as measured by throughput. In 2008, Northern Natural Gas’ transportation and storage revenue accounted for 93% of its total operating revenue, of which 84% was generated from reservation charges under firm transportation and storage contracts. About 50% of the charges under the firm and transportation and storage contracts were from utilities. Except for quantities of natural gas owned and managed for operational and system balancing purposes, Northern Natural Gas does not own the natural gas that is transported through its system. The sale of natural gas for operational and system balancing purposes accounts for the majority of the remaining 7% of its 2008 revenue. Northern Natural Gas’ transportation and storage operations are subject to a regulated tariff that is on file with the FERC. The tariff rates are designed to allow Northern Natural Gas to recover its costs and generate a regulated return on equity.

Northern Natural Gas’ pipeline system, which is interconnected with many interstate and intrastate pipelines in the national grid system, consists of two distinct but operationally integrated markets. Its traditional end-use and distribution market area is at the northern part of the system, including points in Michigan, Illinois, Iowa, Minnesota, Nebraska, Wisconsin and South Dakota, which Northern Natural Gas refers to as the Market Area. Its natural gas supply and delivery service area is at the southern part of the system, including Kansas, Oklahoma, Texas and New Mexico, which Northern Natural Gas refers to as the Field Area.

Northern Natural Gas’ pipeline system provides its customers access to natural gas from key production areas, including the Hugoton, Permian, Anadarko and Rocky Mountain basins in its Field Area and, through interconnections with other pipelines, the Rocky Mountain and Canadian basins in its Market Area. In each of these areas, Northern Natural Gas has numerous interconnecting receipt and delivery points.

Northern Natural Gas transports natural gas primarily to end-user and local distribution markets in the Market Area. In 2008, 64% of Northern Natural Gas’ transportation and storage revenue was generated from Market Area customer transportation contracts. Its Market Area customers consist primarily of utilities and end-use customers. Northern Natural Gas directly serves 77 utilities, including MidAmerican Energy, and no one utility accounted for greater than 10% of its transportation and storage revenue in 2008. In turn, these utilities serve numerous residential, commercial and industrial customers. A majority of Northern Natural Gas’ capacity in the Market Area is committed to customers under firm transportation contracts. As of December 31, 2008, 90% of Northern Natural Gas’ customers’ entitlement in the Market Area is contracted beyond 2009, and 49% is contracted beyond 2015. The weighted average remaining contract term for Northern Natural Gas’ Market Area transportation contracts is approximately seven years as of December 31, 2008.

18

Northern Natural Gas’ Northern Lights expansion project is concentrated primarily in the Twin Cities area of Minnesota and is expected to serve incremental load due to residential and commercial growth in natural gas demand, gas-fired power plants and ethanol facilities. Northern Natural Gas has commitments to two of its largest customers to meet minimum levels of incremental capacity requests through 2026. The project is designed to deliver volumes needed to meet those commitments. The project is expected to add approximately 650,000 Dth per day of capacity to its Market Area by November 1, 2011, of which approximately 500,000 Dth per day has been added as of December 31, 2008. In total, the Northern Lights expansion project is expected to require over $350 million in capital expenditures through 2011 of which $228 million has been incurred through December 31, 2008.

In the Field Area, customers holding contracted firm transportation capacity, or entitlement, consist primarily of marketers, power generators and producers. The majority of this entitlement is contracted on a seasonal and annual basis, principally by marketers and producers. Northern Natural Gas expects short-term contracting to continue in the foreseeable future, since Market Area customers presently need to purchase gas that is delivered from the production basins connected to its Field Area in order to meet their growing demand requirements. Market Area demand cannot presently be met without the purchase of supplies from the Field Area. Supplies from the Field Area have historically been less expensive than the supply alternatives available from other sources that bring Canadian supply to Northern Natural Gas’ system in the Market Area. In 2008, 23% of Northern Natural Gas’ transportation and storage revenue was generated from Field Area customer transportation contracts.

Northern Natural Gas’ storage services are provided through the operation of one underground natural gas storage field in Iowa, two underground natural gas storage facilities in Kansas and two LNG storage peaking units, one in Garner, Iowa and one in Wrenshall, Minnesota. The three underground natural gas storage facilities and two LNG storage peaking units have a total firm service cycle capacity of approximately 73 Bcf and over 2.0 Bcf of peak day delivery capability. These storage facilities provide Northern Natural Gas with operational flexibility for the daily balancing of its system and provide services to customers to meet their winter peaking and year-round load swing requirements. In 2008, 13% of Northern Natural Gas’ transportation and storage revenue was generated from storage services.

Since June 2006, Northern Natural Gas has added 14 Bcf of firm storage cycle capacity through investments and modifications made at its Cunningham, Kansas and Redfield, Iowa storage facilities. This capacity was sold to local distribution companies (“LDC”) for terms of 20-21 years.

Northern Natural Gas’ system experiences significant seasonal swings in demand, with the highest demand typically occurring during the months of November through March. This seasonality provides Northern Natural Gas with opportunities to deliver additional value-added services, such as firm and interruptible storage services. Because of its location and multiple interconnections with interstate and intrastate pipelines, Northern Natural Gas is able to access natural gas from both traditional production areas, such as the Hugoton, Permian and Anadarko Basins, and growing supply areas, such as the Rocky Mountains, through Trailblazer Pipeline Company, Kinder Morgan Interstate Gas Transmission, Cheyenne Plains Pipeline, Colorado Interstate Gas Pipeline Company (“Colorado Interstate”) and Rockies Express Pipeline, as well as from Canadian production areas through Northern Border Pipeline Company, (“Northern Border”), Great Lakes Gas Transmission Limited Partnership (“Great Lakes”) and Viking Gas Transmission Company (“Viking”). This supply diversity provides significant flexibility to Northern Natural Gas’ system and customers. As a result of Northern Natural Gas’ geographic location in the middle of the United States and its many interconnections with other pipelines, Northern Natural Gas augments its steady end-user and LDC revenue by capitalizing on opportunities for shippers to reach additional markets, such as Chicago, Illinois, other parts of the Midwest, and Texas, through interconnects.

Kern River

Kern River, an indirect wholly owned subsidiary of MEHC, owns an interstate natural gas transportation pipeline system consisting of approximately 1,700 miles of pipeline, with a design capacity of 1,755,575 Dth per day, extending from supply areas in the Rocky Mountains to consuming markets in Utah, Nevada and California. Except for quantities of natural gas owned for system operations, Kern River does not own the natural gas that is transported through its system. Kern River’s transportation operations are subject to a regulated tariff that is on file with the FERC. The tariff rates are designed to allow it an opportunity to recover its costs and generate a regulated return on equity.

In June 2008, Kern River filed an application with the FERC for a certificate of public convenience and necessity to construct its 2010 Expansion Project that will add an additional 145,000 Dth per day of capacity in November 2010. Kern River also plans to file an application for another expansion project that will add an incremental 266,000 Dth per day of capacity in November 2011. Both expansion projects require approval from the FERC.

19 

Kern River’s pipeline consists of two sections: the 1,400 mile mainline section and 300 miles of common facilities. Kern River owns the entire mainline section, which extends from the pipeline’s point of origination near Opal, Wyoming, through the Central Rocky Mountains area into Daggett, California. The mainline section consists of approximately 1,300 miles of 36-inch diameter pipeline and approximately 100 miles of various laterals that connect to the mainline.

The common facilities are jointly owned by Kern River (77% as of December 31, 2008) and Mojave Pipeline Company (“Mojave”), a wholly owned subsidiary of El Paso Corporation, as tenants-in-common. Kern River’s ownership percentage in the common facilities will increase or decrease pursuant to the capital contributions made by the respective joint owners. Kern River has exclusive rights to approximately 1,570,600 Dth per day of the common facilities’ capacity, and Mojave has exclusive rights to 400,000 Dth per day of capacity. Operation and maintenance of the common facilities are the responsibility of Mojave Pipeline Operating Company, an affiliate of Mojave.

Kern River has year-round long-term firm natural gas transportation service agreements for 1,755,575 Dth per day of capacity. Pursuant to these agreements, the pipeline receives natural gas on behalf of shippers at designated receipt points, transports the natural gas on a firm basis up to each shipper’s maximum daily quantity and delivers thermally equivalent quantities of natural gas at designated delivery points. Each shipper pays Kern River the aggregate amount specified in its long-term firm natural gas transportation service agreement and Kern River’s tariff, with such amount consisting primarily of a fixed monthly reservation fee based on each shipper’s maximum daily quantity and a commodity charge based on the actual amount of natural gas transported.

These year-round, long-term firm natural gas transportation service agreements expire between September 30, 2011 and April 30, 2018, and have a weighted-average remaining contract term of almost eight years. Shippers on the pipeline include major oil and gas companies or affiliates of such companies, electric generating companies, energy marketing and trading companies, financial institutions and natural gas distribution utilities which provide services in Utah, Nevada and California. As of December 31, 2008, over 92% of the firm capacity has primary delivery points in California, with the flexibility to access secondary delivery points in Nevada and Utah.

Northern Natural Gas and Kern River Competition

Pipelines compete on the basis of cost (including both transportation costs and the relative costs of the natural gas they transport), flexibility, reliability of service and overall customer service. Industrial end-users often have the ability to choose from alternative fuel sources, such as fuel oil and coal, in addition to natural gas. Natural gas competes with other forms of energy, including electricity, coal and fuel oil, primarily on the basis of price. Legislation and governmental regulations, the weather, the futures market, production costs and other factors beyond the control of Northern Natural Gas and Kern River influence the price of natural gas.

Historically, Northern Natural Gas has been able to provide competitively priced services because of its access to a variety of relatively low cost supply basins, its cost control measures and its relatively high load factor throughput, which lowers the per unit cost of transportation. To date, Northern Natural Gas has avoided any significant pipeline system bypasses or turn-back of firm entitlement. In recent years, Northern Natural Gas has retained and signed long-term contracts with customers such as CenterPoint Energy Minnesota Gas (“CenterPoint”), Xcel Energy Inc. (“Xcel Energy”) and Metropolitan Utilities District, which in some cases, because of competition, resulted in lower reservation charges relative to the contracts being replaced.

Northern Natural Gas’ major competitors in the Market Area include ANR Pipeline Company, Northern Border and Natural Gas Pipeline Company of America LLC. Other competitors of Northern Natural Gas include Great Lakes and Viking. In the Field Area, Northern Natural Gas competes with a large number of interstate and intrastate pipeline companies where the vast majority of Northern Natural Gas’ capacity is used for transportation services provided on a short-term firm basis. Northern Natural Gas’ tariff rates are competitive with the market alternative and provide value to the shippers holding the firm capacity.

Although it needs to compete aggressively to retain and build load, Northern Natural Gas believes that current and anticipated changes in its competitive environment have created opportunities to serve its existing customers more efficiently and to meet certain growing supply needs. Northern Natural Gas has been successful in competing for a significant amount of the increased demand related to residential and commercial needs and the construction of new power plants through its Northern Lights expansion project. The growth related to utilities is driven by population growth and increased commercial and industrial needs. The new power plant growth originates from re-powering coal-fired generation as well as new combustion and combined-cycle gas-fired generation. The growth also supports the continued sale of Northern Natural Gas’ storage services and Field Area transportation services.

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Kern River competes with various interstate pipelines and its shippers in order to market any unutilized or unsubscribed capacity serving the southern California, Las Vegas, Nevada and Salt Lake City, Utah market areas. Kern River provides its customers with supply diversity through pipeline interconnections with Northwest Pipeline Corporation, Colorado Interstate, Overland Trails Pipeline, Questar Pipeline Company and Questar Overthrust Pipeline Company. These interconnections, in addition to the direct interconnections to natural gas processing facilities, allow Kern River to access natural gas reserves in Colorado, northwestern New Mexico, Wyoming, Utah and the Western Canadian Sedimentary Basin.

Kern River is the only interstate pipeline that presently delivers natural gas directly from a gas supply basin to end users in the California market. This enables direct connect customers to avoid paying a “rate stack” (i.e., additional transportation costs attributable to the movement from one or more interstate pipeline systems to an intrastate system within California). Kern River believes that its historic levelized rate structure and access to upstream pipelines/storage facilities and to economic Rocky Mountain gas reserves increases its competitiveness and attractiveness to end-users. Kern River believes it has an advantage relative to other competing interstate pipelines because its relatively new pipeline can be economically expanded and will require significantly less capital expenditures to comply with the Pipeline Safety Improvement Act of 2002 (“PSIA”) than other systems. Kern River’s favorable market position is tied to the availability and relatively favorable price of gas reserves in the Rocky Mountain area, an area that in recent years has attracted considerable expansion of pipeline capacity serving markets other than California and Nevada.

In 2008, Northern Natural Gas had no customers that accounted for greater than 10% of its revenue and its ten largest customers accounted for 51% of its system-wide transportation and storage revenue. Northern Natural Gas has agreements to retain the vast majority of its two largest customers’ volumes through at least 2017. Kern River had two customers who each accounted for greater than 10% of its revenue. The loss of any of these significant customers, if not replaced, could have a material adverse effect on Northern Natural Gas’ and Kern River’s respective businesses.

CE Electric UK

General

CE Electric UK, an indirect wholly owned subsidiary of MEHC, is a holding company which owns, primarily, two companies that distribute electricity in Great Britain, Northern Electric and Yorkshire Electricity. Northern Electric and Yorkshire Electricity operate in the north-east of England from North Northumberland through Tyne and Wear, County Durham, Tees Valley and Yorkshire to North Lincolnshire, an area covering approximately 10,000 square miles, and serve 3.8 million end users. The principal function of Northern Electric and Yorkshire Electricity is to build, maintain and operate the electricity distribution network through which the end user receives a supply of electricity. In addition to building and maintaining the electricity distribution network, CE Electric UK also owns an engineering contracting business that provides electrical infrastructure contracting services to third parties and a hydrocarbon exploration and development business that is focused on developing integrated upstream gas projects in Australia, the United Kingdom and Poland.

Electricity Distribution

Northern Electric and Yorkshire Electricity receive electricity from the national grid transmission system and distribute it to end users’ premises using their networks of transformers, switchgear and distribution lines and cables. Substantially all of the end users in Northern Electric’s and Yorkshire Electricity’s distribution service areas are connected to the Northern Electric and Yorkshire Electricity networks and electricity can only be delivered to these end users through their distribution systems, thus providing Northern Electric and Yorkshire Electricity with distribution volume that is relatively stable from year to year. Northern Electric and Yorkshire Electricity each charge fees for the use of their distribution systems to the suppliers of electricity. The suppliers, which purchase electricity from generators and sell the electricity to end user customers, use Northern Electric’s and Yorkshire Electricity’s distribution networks pursuant to an industry standard “Distribution Connection and Use of System Agreement,” which Northern Electric and Yorkshire Electricity separately entered into with the various suppliers of electricity in their respective distribution service areas. One such supplier, RWE Npower PLC and certain of its affiliates, represented approximately 37% of the total combined distribution revenues of Northern Electric and Yorkshire Electricity in 2008.

The service territory geographically features a diverse economy with no dominant sector. The mix of rural, agricultural, urban and industrial areas covers a broad customer base ranging from domestic usage through farming and retail to major industry including automotives, chemicals, mining, steelmaking and offshore marine construction. The industry within the area is concentrated around the principal centers of Newcastle, Middlesbrough and Leeds.

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The price controlled revenues of the regulated distribution companies are set out in the special conditions of the licenses of the companies. The licenses are enforced by the regulator, the Office of Gas and Electricity Markets (“Ofgem”) and limit increases (or may require decreases) based upon the rate of inflation, other specified factors and other regulatory action. Changes to the price controls can be made only by agreement between a distribution company and the regulator or, if there is no agreement, following a report on a reference by the regulator to the Competition Commission. It has been the convention in the United Kingdom for regulators to conduct periodic regulatory reviews before making proposals for any changes to the price controls. The price controls have conventionally been based upon a 5-year price control period, with the current price control period commencing April 1, 2005.

Electricity distributed to end users and the total number of end users as of and for the years ended December 31 were as follows:

	2008		2007		2006
Electricity distributed (in GWh):
Northern Electric		16,563		16,977		17,203
Yorkshire Electricity		24,047		24,281		25,025
		40,610		41,258		42,228
Number of end users (in millions):
Northern Electric		1.6		1.6		1.6
Yorkshire Electricity		2.2		2.2		2.2
		3.8		3.8		3.8

As of December 31, 2008, Northern Electric’s and Yorkshire Electricity’s electricity distribution network on a combined basis included approximately 18,000 miles of overhead lines, approximately 39,000 miles of underground cables and approximately 700 major substations.

CalEnergy Generation-Foreign

The CalEnergy Generation-Foreign platform consists of MEHC’s indirect ownership of the Casecnan project, which is a 150 MW combined irrigation and hydroelectric power generation project located on the Casecnan and Taan Rivers on the Philippine island of Luzon. The Company’s net owned capacity for the Casecnan project is 135 MW and is subject to a dispute with respect to repurchase rights of up to 15% ownership of the project by an initial minority shareholder and a separate dispute with the other initial minority shareholder regarding an additional 5% ownership of the project. Refer to Item 3 of this Form 10-K for additional information.

The Casecnan project’s sole customer is the Republic of the Philippines (“ROP”). The ROP has provided a performance undertaking under which the Philippine National Irrigation Administration’s (“NIA”) obligations under the Casecnan Project Agreement, as modified (the “Project Agreement”), are guaranteed by the full faith and credit of the ROP. NIA also pays CE Casecnan Water and Energy Company, Inc. (“CE Casecnan”) for delivery of water and electricity by CE Casecnan. The Casecnan project carries political risk insurance.

Under the terms of the Project Agreement, CE Casecnan will own and operate the project for a 20-year cooperation period which commenced on December 11, 2001, the start of the Casecnan project’s commercial operations, after which ownership and operation of the project will be transferred to NIA at no cost on an “as-is” basis. The Casecnan project is dependent upon sufficient rainfall to generate electricity and deliver water. Rainfall varies within the year and from year to year, which is outside the control of CE Casecnan, and impacts the amount of electricity generated and water delivered by the Casecnan project. Rainfall has historically been highest from June through December and lowest from January through May. The contractual terms for water delivery fees and variable energy fees can produce variability in revenue between reporting periods. NIA’s payment obligation under the project agreement is substantially denominated in U.S. dollars and is the Casecnan project’s sole source of operating revenue.

On June 25, 2006, the Upper Mahiao project’s and on July 25, 2007, the Malitbog and Mahanagdong projects’ separate 10-year cooperation periods ended and the projects, representing a total of 485 MW of net owned contract capacity, were transferred to PNOC-Energy Development Corporation by the Company at no cost on an “as-is” basis.

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CalEnergy Generation-Domestic

The subsidiaries comprising the Company’s CalEnergy Generation-Domestic platform own interests in 15 non-utility power projects in the United States. The following table sets out certain information concerning CalEnergy Generation-Domestic’s non-utility power projects in operation as of December 31, 2008:

	Facility
	Net or						Power
	Contract		Net				Purchase
Operating	Capacity		MW		Energy		Agreement		Power
Project	(MW)(1)		Owned(1)		Source	Location	Expiration		Purchaser(2)
CE Generation(3):
Natural-Gas Fired -
Saranac		240		90	Natural Gas	New York	2009		NYSE&G
Power Resources		212		106	Natural Gas	Texas	2009		CECG
Yuma		50		25	Natural Gas	Arizona	2024		SDG&E
Total Natural-Gas Fired		502		221
Imperial Valley Projects		327		164	Geothermal	California		(4)		(4)
Total CE Generation		829		385
Cordova		537		537	Natural Gas	Illinois	2019		CECG
Wailuku		10		5	Wailuku River	Hawaii	2023		HELCO
Total CalEnergy-Domestic		1,376		927

(1)	Facility Net or Contract Capacity (MW) represents total plant accredited net generating capacity from the summer of 2008 as approved by MAPP for Cordova and contract capacity for most other projects. Net MW Owned indicates legal ownership of the Facility Net Capacity or Contract Capacity.
(2)	Constellation Energy Commodities Group, Inc. (“CECG”); Hawaii Electric Company (“HELCO”); New York State Electric & Gas Corporation (“NYSE&G”); and San Diego Gas & Electric Company (“SDG&E”).
(3)	MEHC has a 50% ownership interest in CE Generation, LLC (“CE Generation”) whose subsidiaries currently operate ten geothermal plants in the Imperial Valley of California (the “Imperial Valley Projects”) and three natural gas-fired power generation facilities.
(4)	Approximately 82% of the Company’s interests in the Imperial Valley Projects’ Contract Capacity (MW) are sold to Southern California Edison Company under long-term power purchase agreements expiring in 2016 through 2026.

HomeServices

HomeServices, a majority-owned subsidiary of MEHC, is the second largest full-service residential real estate brokerage firm in the United States. In addition to providing traditional residential real estate brokerage services, HomeServices offers other integrated real estate services, including mortgage originations, primarily through joint ventures, title and closing services, property and casualty insurance, home warranties and other home-related services. HomeServices’ real estate brokerage business is subject to seasonal fluctuations because more home sale transactions tend to close during the second and third quarters of the year. As a result, HomeServices’ operating results and profitability are typically higher in the second and third quarters relative to the remainder of the year. HomeServices currently operates approximately 300 broker offices in 19 states with 16,000 agents under 21 brand names. The U.S. residential real estate brokerage business is highly competitive and consists of numerous local brokers and agents in each market seeking to represent sellers and buyers in residential real estate transactions.

Other Investments

BYD Company Limited

In September 2008, MEHC reached a definitive agreement with BYD Company Limited (“BYD”) to purchase 225 million shares, representing approximately a 10% interest in the company, at a price of Hong Kong (“HK”) $8 per share or HK$1.8 billion (approximately $230 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 closing remains subject to approval by the China Securities Regulatory Commission and the filing of amendments to BYD’s articles of association. In the event that the conditions precedent are not fulfilled by March 26, 2009 the parties are not bound to proceed with the transaction. MEHC expects the transaction to close in 2009.

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Electric Transmission Joint Ventures

In December 2007, approval was received from the Public Utility Commission of Texas (“PUCT”) to establish Electric Transmission Texas, LLC’s (“ETT”) as a 50:50 joint venture company, owned by American Electric Power Company, Inc. (“AEP”) and MEHC, to own and operate electric transmission assets in the Electric Reliability Council of Texas (“ERCOT”) footprint. The PUCT order also approved initial rates based on a 9.96% after tax rate of return on equity and a debt to equity capital structure of 60:40. Following an appeal by intervenors, in October 2008, the Travis County District Court ruled that the PUCT exceeded its authority by approving ETT’s application for a certificate of convenience and necessity to operate as a stand alone transmission utility (i) without an indentified service area and (ii) under the wrong section of the relevant statute. This decision does not automatically invalidate the CCN. Until such time as there is an adverse ruling by the Texas Court of Appeals that is not subsequently appealed, or a decision by the Texas Supreme Court, the PUCT order granting ETT a CCN and initial rates remains legally valid. ETT believes the issue will ultimately be resolved in its favor, but cannot predict the outcome of this proceeding or its future effect on ETT’s financial results. As of December 31, 2008, the Company’s net investment in ETT was $16 million.

In July 2008, the PUCT voted to approve a $4.9 billion transmission plan to integrate significant wind resources located in Competitive Renewable Energy Zones (“CREZ”) throughout Texas, into the ERCOT grid. Along with this announcement, they initiated a proceeding to select transmission providers to the construct the lines. In January 2009, the PUCT voted to assign approximately $800 million of transmission investment in support of CREZ to ETT. The final order on this vote is expected in first quarter of 2009.

In September 2007, subsidiaries of AEP and MEHC formed Electric Transmission America, LLC (“ETA”), a 50:50 joint venture to pursue transmission opportunities outside of ERCOT. During the second quarter of 2008, ETA formed joint ventures with Westar Energy, Inc. and a subsidiary of OGE Energy Corp. to build and own new electric transmission assets within the Southwest Power Pool (“SPP”). The Westar Energy, Inc. project includes approximately 230 miles of extra-high voltage 765-kilovolt transmission in Kansas, while the OGE Energy Corp. project includes approximately 170 miles of extra-high voltage 765-kilovolt transmission in Oklahoma. The combined projects encompass two phases of the extra-high voltage overlay study plan released March 3, 2007, by SPP. Both projects received necessary approvals from the FERC in December 2008 including a return on equity, inclusive of incentives, of 12.3%. The completion of these projects is subject to receipt of regional rate treatment by SPP and obtaining necessary state regulatory approvals.

Neither ETT nor ETA is consolidated with MEHC for financial reporting purposes.

Employees

As of December 31, 2008, the Company had approximately 16,800 employees, of which approximately 7,600 are covered by union contracts. The majority of the union employees are employed by PacifiCorp and MidAmerican Energy and are represented by the International Brotherhood of Electrical Workers, the Utility Workers Union of America, the International Brotherhood of Boilermakers and the United Mine Workers of America. These collective bargaining agreements have expiration dates ranging through January 2013. HomeServices’ residential real estate agents are independent contractors and not employees.

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General Regulation

MEHC’s subsidiaries are subject to comprehensive governmental regulation which significantly influences their operating environment, prices charged to customers, capital structure, costs and their ability to recover costs. In addition to the following discussion, refer to “Liquidity and Capital Resources” in Item 7 and Note 6 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K.

Domestic Regulated Public Utility Subsidiaries

MEHC’s domestic regulated public utility subsidiaries, PacifiCorp and MidAmerican Energy, are subject to comprehensive regulation by state utility commissions, federal agencies, and other state and local regulatory agencies. The more significant aspects of this regulatory framework are described below.

State Regulation

Historically, state utility commissions have established rates on a cost-of-service basis, which is designed to allow a utility an opportunity to recover its costs of providing services and to earn a reasonable return on its investment. A utility’s cost-of-service generally reflects its allowed operating expenses, including operation and maintenance expense, depreciation expense and taxes. Some portion of margins earned on wholesale activities for electricity and capacity and gas transportation service have historically been included to reduce the retail cost of service upon which retail rates are based. State utility commissions may adjust rates pursuant to a review of (i) a utility’s revenues and expenses during a defined test period and (ii) such utility’s level of investment. State utility commissions typically have the authority to review and change rates on their own initiative. States may also initiate reviews at the request of a utility customer, a governmental agency or a representative of a group of customers. The utility and such parties, however, may agree with one another not to request a review of or changes to rates for a specified period of time.

The electric rates of PacifiCorp and MidAmerican Energy are generally based on the cost of providing traditional bundled services, including generation, transmission and distribution services. Historically, the state regulatory framework in the service areas of PacifiCorp’s and MidAmerican Energy’s systems reflected specified power and fuel costs as part of bundled rates or incorporated power or fuel adjustment clauses in the utility’s rates and tariffs. In states where power and fuel adjustment clauses exist, permitted periodic adjustments to cost recovery from customers provide protection to utilities against exposure to power and fuel cost changes.

Except for Oregon, Washington and Illinois, PacifiCorp and MidAmerican Energy have an exclusive right to serve electricity customers within their service territories and, in turn, have the obligation to provide electric service to those customers. Under Oregon law, PacifiCorp has the exclusive right and obligation to provide electric distribution services to all customers within its allocated service territory; however, nonresidential customers have the right to choose alternative electricity service suppliers. The impact of these programs on the Company’s financial results has not been material. In Washington, state law does not provide for exclusive service territory allocation. PacifiCorp’s service territory in Washington is surrounded by other public utilities with whom PacifiCorp has from time to time entered into service area agreements under the jurisdiction of the Washington Utilities and Transportation Commission (“WUTC”). In Illinois, a law changed how and what electric services are regulated by the Illinois Commerce Commission (“ICC”) and transitioned portions of the traditional electric services to a competitive environment. Electric base rates in Illinois were generally frozen until January 1, 2007, and are now subject to cost-based ratemaking. All Illinois customers are free to choose their electricity service supplier and MidAmerican Energy has an obligation to serve customers at regulated rates that leave MidAmerican Energy’s system, but later choose to return. To date, there has been no significant loss of customers in Illinois.

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PacifiCorp

The following table illustrates the current rate case status in each state jurisdiction in which PacifiCorp operates:

State Regulator	Base Rate Test Period	Adjustment Mechanism(1)
Utah Public Service Commission (“UPSC”)	Forecasted or historical with known and measurable changes(2)	No separate recovery mechanisms.
Oregon Public Utility Commission (“OPUC”)	Forecasted	Annual transition adjustment mechanism, a mechanism for annual rate adjustments for forecasted net variable power costs; no true-up to actual net variable power costs.
		Renewable adjustment clause to recover the revenue requirement of new renewable resources and associated transmission that are not reflected in general rates.
		Annual Oregon Senate Bill 408 (“SB 408”) true-up of taxes authorized to be collected in rates compared to taxes paid by PacifiCorp, as defined by Oregon statute and administrative rules.
Wyoming Public Service Commission (“WPSC”)	Forecasted or historical with known and measurable changes(2)	Power cost adjustment mechanism based on forecasted net power costs, later trued-up to actual net power costs. Subject to dead bands and customer sharing.
Washington Utilities and Transportation Commission (“WUTC”)	Historical with known and measurable changes	Deferral mechanism of costs for up to 24 months of new base load generation resources that qualify under the state’s emissions performance standard and are not reflected in general rates.
Idaho Public Utilities Commission (“IPUC”)	Historical	PacifiCorp has requested approval of an energy cost adjustment mechanism to recover the difference between base power costs set during a general rate case and actual power costs. The application is currently pending before the Commission.
California Public Utilities Commission (“CPUC”)	Forecasted	Post test-year adjustment mechanism for major capital additions, a mechanism that allows for rate adjustments outside of the context of a traditional rate case for the revenue requirement associated with capital additions exceeding $50 million on a total-company basis. Filed as eligible capital additions are placed into service.
		Post test-year adjustment mechanism for attrition, a mechanism that allows for an annual adjustment to costs other than net variable power costs tied to the Consumer Price Index minus a 0.5% productivity offset.
		Energy cost adjustment clause that allows for an annual update to actual and forecasted net variable power costs.

(1)	Margins earned on wholesale sales for energy and capacity have historically been included as a component of retail cost of service upon which retail rates are based.
(2)	The Company has relied on both historical test periods with known and measurable adjustments and forecasted test periods. The WPSC has never issued a final ruling on its preference between a historical or forecasted test period.

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MidAmerican Energy

The Iowa Utilities Board (“IUB”) has approved over the past several years a series of electric settlement agreements between MidAmerican Energy, the Office of Consumer Advocate (“OCA”) and other intervenors under which MidAmerican Energy has agreed not to seek a general increase in electric base rates to become effective prior to January 1, 2014, unless its Iowa jurisdictional electric return on equity for any year covered by the applicable agreement falls below 10%, computed as prescribed in each respective agreement. Prior to filing for a general increase in electric rates, MidAmerican Energy is required to conduct 30 days of good faith negotiations with the signatories to the settlement agreements to attempt to avoid a general increase in rates. As a party to the settlement agreements, the OCA has agreed not to request or support any decrease in MidAmerican Energy’s Iowa electric base rates to become effective prior to January 1, 2014. The settlement agreements specifically allow the IUB to approve or order electric rate design or cost of service rate changes that could result in changes to rates for specific customers as long as such changes do not result in an overall increase in revenues for MidAmerican Energy. Additionally, the settlement agreements also each provide that revenues associated with Iowa retail electric returns on equity within specified ranges will be shared with customers. The following table summarizes the ranges of Iowa electric returns on equity subject to revenue sharing under each of the remaining settlement agreements, the percent of revenues within those ranges to be assigned to customers, and the method by which the liability to customers will be settled.

		Range of
		Iowa Electric	Customers’
		Return on	Share of
Date Approved	Years	Equity Subject	Revenues	Method to be Used to
by the IUB	Covered	to Sharing	Within Range	Settle Liability to Customers
October 17, 2003	2006 - 2010	11.75% - 13%	40%	Credits against the cost of new generation plant in Iowa
		13% - 14%	50%
		Above 14%	83.3%
January 31, 2005	2011	Same	Same	Credits to customer bills in 2012
April 18, 2006	2012	Same	Same	Credits to customer bills in 2013
July 27, 2007	2013	Same	Same	Credits against the cost of wind-powered generation projects covered by this agreement

(1) If a rate case is filed pursuant to the 10% threshold, as discussed above, the revenue sharing arrangement for 2013 is changed such that the amount to be shared with customers will be 83.3% of revenues associated with Iowa electric operating income in excess of returns on equity allowed by the IUB as a result of the rate case.

MidAmerican Energy does not have an electric fuel and purchased power adjustment clause in Iowa. A monthly purchased gas cost adjustment clause combined with an Incentive Gas Supply Procurement Plan provides protection from market changes in gas costs while offering financial incentives for MidAmerican Energy to minimize the cost of its gas supply portfolio.

Effective January 2007, MidAmerican Energy and the ICC have eliminated the monthly adjustment clause for recovery of fuel for electric generation and purchased power costs in Illinois. Base rates have been adjusted effective January 1, 2007 to include recoveries at average 2004/2005 cost levels. The elimination of the fuel adjustment clause exposes MidAmerican Energy to monthly market price changes for fuel and purchased power costs in Illinois, with rate case approval required for any base rate changes. With the elimination of the fuel adjustment clause, MidAmerican Energy may not petition for its reinstatement until November 2011. A monthly adjustment clause remains in effect for MidAmerican Energy’s purchased gas costs.

MidAmerican Energy’s cost of gas is collected in its gas rates through a uniform PGA for each jurisdiction, which is updated monthly to reflect changes in actual costs. Subject to prudence reviews, the PGA accomplishes a pass-through of MidAmerican Energy’s cost of gas to its customers and, accordingly, has no direct effect on net income. MidAmerican Energy’s Iowa and Illinois energy efficiency program costs are collected through separately established rates that are adjusted annually based on actual and expected costs, as approved by the IUB and ICC, respectively. As such, recovery of energy efficiency program costs have an insignificant impact on net income.

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Federal Regulation

The FERC is an independent agency with broad authority to implement provisions of the Federal Power Act, the Energy Policy Act and other federal statutes. The FERC regulates rates for interstate sales of electricity at wholesale, transmission of electric power, including pricing and expansion of the transmission system, electric system reliability, utility holding companies, accounting, securities issuances and other matters, including construction and operation of hydroelectric projects, and has the enforcement authority to assess civil penalties of up to $1 million per day for violations of rules, regulations and orders issued under the Federal Power Act. PacifiCorp and MidAmerican Energy have implemented programs to be fully compliant with the FERC regulations described below, including having instituted compliance monitoring procedures. MidAmerican Energy is also subject to regulation by the Nuclear Regulatory Commission (“NRC”) pursuant to the Atomic Energy Act of 1954, as amended (“Atomic Energy Act”), with respect to the operation of the Quad Cities Station.

Wholesale Electricity and Capacity

The FERC regulates PacifiCorp’s and MidAmerican Energy’s rates charged to wholesale customers for electricity, electric generation capacity and transmission services. Most of PacifiCorp’s and MidAmerican Energy’s electric wholesale sales and purchases take place under market-based rate pricing allowed by the FERC and are therefore subject to market volatility.

The FERC conducts a triennial review of PacifiCorp’s and MidAmerican Energy’s market-based rate pricing authority in accordance with the schedule established in FERC Order No. 697. Each utility must demonstrate the lack of generation market power in order to charge market-based rates for sales of wholesale electricity and electric generation capacity in their respective balancing authority areas. PacifiCorp’s next triennial filing is due in June 2010 and MidAmerican Energy’s are due in June and December 2011. Under the FERC’s market-based rules, PacifiCorp and MidAmerican Energy must also file a notice of change in status upon the ownership or control of 100 MW of incremental generation. Following the filing by PacifiCorp of a change in status notice relating to new generation, the FERC in November 2007 confirmed that PacifiCorp does not have market power and may continue to charge market-based rates. PacifiCorp filed a change in status notice related to its acquisition of the 520-MW Chehalis natural gas-fired generating facility and the expected commercial operation of several new wind-powered generating facilities in October 2008, which is pending. In June 2008, MidAmerican Energy made its scheduled triennial filing which the FERC accepted in October 2008 and confirmed that MidAmerican Energy is authorized to sell at market-based rates outside of its balancing authority area. MidAmerican Energy made another required triennial filing combined with a change in status notice relating to new generation in December 2008, which is pending.

Transmission

The FERC regulates PacifiCorp’s and MidAmerican Energy’s wholesale transmission services. PacifiCorp and MidAmerican Energy are required each to provide open access transmission service at cost-based rates. The FERC also regulates unbundled transmission service to retail customers. These services are offered on a non-discriminatory basis, meaning that all potential customers are provided an equal opportunity to access the transmission system. The Company’s transmission businesses are managed and operated independently from its wholesale marketing businesses in accordance with the FERC Standards of Conduct.

In FERC Order Nos. 890, 890-A and 890-B, the FERC adopted rules designed to strengthen the pro-forma OATT by providing greater specificity and increasing transparency. The most significant revisions to the pro forma OATT relate to the development of more consistent methodologies for calculating available transfer capability, changes to the transmission planning process, changes to the pricing of certain generator and energy imbalances to encourage efficient scheduling behavior and changes regarding long-term point-to-point transmission service, including the addition of conditional firm long-term point-to-point transmission service, and generation redispatch. As transmission providers with an OATT on file with the FERC, PacifiCorp and MidAmerican Energy are required to comply with the requirements of the new rule and each have made a series of compliance filings as required by the orders, some of which are still pending approval from the FERC, amending their respective OATT to implement the provisions of the new rule. The new rule is not anticipated to have a significant impact on PacifiCorp’s or MidAmerican Energy’s financial results or their transmission operations, planning and wholesale marketing functions.

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The FERC has approved 88 reliability standards developed by the North American Electric Reliability Corporation (the “NERC”) and 8 regional variations developed by the WECC. Responsibility for compliance and enforcement of these standards has been given to the WECC for PacifiCorp and the Midwest Reliability Organization (the “MRO”) for MidAmerican Energy. The 88 standards comprise over 600 requirements and sub-requirements with which PacifiCorp and MidAmerican Energy must comply. PacifiCorp and MidAmerican Energy expect that these standards will change as a result of modifications, guidance and clarification following industry implementation and ongoing audits and enforcement. In January 2008, the FERC approved eight additional cyber security and critical infrastructure protection standards proposed by the NERC. The additional standards became mandatory and enforceable in April 2008. The Company cannot predict the effect that these standards will have on its consolidated financial results; however, they will likely require increased expenditures for cyber security and other systems for PacifiCorp’s and MidAmerican Energy’s critical assets and may have a significant impact on transmission operations and resource planning functions. During 2007, the WECC audited PacifiCorp’s compliance with several of the approved reliability standards. In April 2008, PacifiCorp received a 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. In November 2008, the FERC took over processing certain aspects of the WECC’s 2007 audit. PacifiCorp is analyzing the preliminary results of the audit and the preliminary results of the non-public investigation and, at this time, cannot predict the impact of the audit or the non-public investigation, if any, on its consolidated financial results. In September 2008, the MRO issued a public report to the NERC stating MidAmerican Energy was found to be 100% compliant with the 47 audited NERC and MRO standards based on a MRO on-site audit conducted in August 2008.

Neither PacifiCorp nor MidAmerican Energy is part of a RTO. PacifiCorp, along with other private utilities and public power organizations throughout the Pacific Northwest and Western United States, is a member of the Northern Tier Transmission Group, which initially will conduct reliability and economic planning coordination for its members. MidAmerican Energy has hired an independent transmission system coordinator to administer various MidAmerican Energy OATT functions for transmission service and is evaluating participating in a RTO market.

Hydroelectric Relicensing

PacifiCorp’s Klamath hydroelectric system is the remaining hydroelectric generating facility actively engaged in the relicensing process with the FERC. PacifiCorp also has requested the FERC to allow decommissioning of certain hydroelectric systems. Most of PacifiCorp’s hydroelectric generating facilities are licensed by the FERC as major systems under the Federal Power Act, and certain of these systems are licensed under the Oregon Hydroelectric Act. Refer to Note 18 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for additional information regarding hydroelectric relicensing, and specifically related to the Klamath hydroelectric system.

Northwest Power Act

The Northwest Power Act, through the Residential Exchange Program, provides access to the benefits of low-cost federal hydroelectricity to the residential and small-farm customers of the region’s investor-owned utilities. The program is administered by the Bonneville Power Administration (the ÒBPAÓ) in accordance with federal law. Pursuant to agreements between the BPA and PacifiCorp, benefits from the BPA are passed through to PacifiCorp’s Oregon, Washington and Idaho residential and small-farm customers in the form of electricity bill credits. The Residential Exchange Program has been the subject of recent litigation and, as a result, has been modified by the BPA. PacifiCorp currently has authority from the OPUC to participate in the Residential Exchange Program through September 2011. Because these credits are passed through to PacifiCorp's customers, they do not significantly affect the Company's consolidated financial results.

Nuclear Regulatory Commission

MidAmerican Energy is subject to the jurisdiction of the NRC with respect to its license and 25% ownership interest in the Quad Cities Station. Exelon Generation, the operator and 75% owner of Quad Cities Station, is under contract with MidAmerican Energy to secure and keep in effect all necessary NRC licenses and authorizations.

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The NRC regulates the granting of permits and licenses for the construction and operation of nuclear generating stations and regularly inspects such stations for compliance with applicable laws, regulations and license terms. Current licenses for the Quad Cities Station provide for operation until December 14, 2032. The NRC review and regulatory process covers, among other things, operations, maintenance, and environmental and radiological aspects of such stations. The NRC may modify, suspend or revoke licenses and impose civil penalties for failure to comply with the Atomic Energy Act, the regulations under such Act or the terms of such licenses.

Federal regulations provide that any nuclear operating facility may be required to cease operation if the NRC determines there are deficiencies in state, local or utility emergency preparedness plans relating to such facility, and the deficiencies are not corrected. Exelon Generation has advised MidAmerican Energy that an emergency preparedness plan for Quad Cities Station has been approved by the NRC. Exelon Generation has also advised MidAmerican Energy that state and local plans relating to Quad Cities Station have been approved by the Federal Emergency Management Agency.

MidAmerican Energy maintains financial protection against catastrophic loss associated with its interest in the Quad Cities Station through a combination of insurance purchased by Exelon Generation (the operator and joint owner of the Quad Cities Station), insurance purchased directly by MidAmerican Energy, and the mandatory industry-wide loss funding mechanism afforded under the Price-Anderson Amendments Act of 1988, which was amended and extended by the Energy Policy Act of 2005. The general types of coverage are: nuclear liability, property coverage and nuclear worker liability.

U.S. Mine Safety

PacifiCorp’s mining operations are regulated by the federal Mine Safety and Health Administration (“MSHA”), which administers federal mine safety and health laws, regulations and state regulatory agencies. The Mine Improvement and New Emergency Response Act of 2006 (“MINER Act”), enacted in June 2006, amended previous mine safety and health laws to improve mine safety and health and accident preparedness. PacifiCorp is required to develop a written emergency response plan specific to each underground mine they operate. These plans must be updated and re-certified by MSHA every six months. It also requires every mine to have at least two rescue teams located within one hour, and it limits the legal liability of rescue team members and the companies that employ them. The MINER Act also increases civil and criminal penalties for violations of federal mine safety standards and gives MSHA the ability to institute a civil action for relief, including a temporary or permanent injunction, restraining order or other appropriate order against a mine operator who fails to pay the penalties or fines.

U.S. Interstate Pipeline Subsidiaries

The natural gas pipeline and storage operations of the Company’s U.S. interstate pipeline subsidiaries are regulated by the FERC, which administers, most significantly, the Natural Gas Act and the Natural Gas Policy Act of 1978. Under this authority, the FERC regulates, among other items, (i) rates, charges, terms and conditions of service, and (ii) the construction and operation of U.S. pipelines, storage and related facilities, including the extension, expansion or abandonment of such facilities.

Northern Natural Gas continues to use a modified straight fixed variable rate design methodology, whereby substantially all fixed costs, including a return on invested capital and income taxes, are collected through reservation charges, which are paid by firm transportation and storage customers regardless of volumes shipped. Commodity charges, which are paid only with respect to volumes actually shipped, are designed to recover the remaining, primarily variable, cost. Kern River’s rates have historically been set using a “levelized cost-of-service” methodology so that the rate is constant over the contract period; however, rate design is the subject of Kern River’s current rate case before the FERC and may be subject to change as a result of the rate case outcome. This levelized cost of service has been achieved by using a FERC-approved depreciation schedule in which depreciation increases as interest expense decreases.

FERC regulations also restrict each pipeline’s marketing affiliates’ access to U.S. interstate pipeline natural gas transmission customer data and place certain conditions on services provided by the U.S interstate pipelines to their marketing affiliates.

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U.S. interstate natural gas pipelines are also subject to regulations by a federal agency within the United States Department of Transportation (“DOT”), pursuant to the Natural Gas Pipeline Safety Act of 1968, as amended (the “NGPSA”), which establishes safety requirements in the design, construction, operation and maintenance of interstate natural gas transportation facilities, and the PSIA, which implemented additional safety and pipeline integrity regulations for high consequence areas. The regulation also requires Northern Natural Gas and Kern River to complete certain inspections of their pipeline systems by December 17, 2012. Each pipeline is scheduled to have this work completed by December 2011.

In addition to FERC and DOT regulation, certain operations are subject to oversight by state regulatory commissions.

U.K. Electricity Distribution Companies

Northern Electric and Yorkshire Electricity, as holders of electricity distribution licenses, are subject to regulation by the Gas and Electricity Markets Authority (“GEMA”). GEMA discharges certain of its powers through its staff within Ofgem. Each of fourteen licensed distribution network operators (“DNO”) distributes electricity from the national grid system to end use customers within their respective distribution service areas.

DNOs are subject to price controls, enforced by Ofgem, that limit the revenues that may be recovered and retained from their electricity distribution activities. The regulatory regime that has been applied to electricity distributors in the UK encourages companies to look for efficiency gains in order to improve profits. The distribution price control formula also adjusts the revenue received by DNOs to reflect the rate of inflation (as measured by the retail price index), an increase or decrease in the number of units distributed and the number of end users, the quality of service delivered by the licensee’s distribution system and system losses (i.e., the difference between the number of units entering and leaving the licensee’s system). Currently, price controls are established every five years, although the formula has been, and may be, reviewed at the regulator’s discretion. The procedure and methodology adopted at a price control review are at the reasonable discretion of Ofgem. Historically, Ofgem’s judgment of the future allowed revenue of licensees has been based upon, among other things:

·   actual operating costs of each of the licensees;

·   pension deficiency payments of each of the licensees;

·   operating costs which each of the licensees would incur if it were as efficient as, in Ofgem’s judgment, the more efficient licensees;

·   taxes that each licensee is expected to pay;

·   regulatory value ascribed to and the allowance for depreciation related to the distribution network assets;

·   rate of return to be allowed on investment in the distribution network assets by all licensees; and

·   financial ratios of each of the licensees and the license requirement for each licensee to maintain an investment grade status.

The current electricity distribution price control was agreed in December 2004, became effective April 2005 and is expected to continue through March 2010. Ofgem’s review of the formula to be applied from April 1, 2010 is currently underway.

A number of incentive schemes also operate within the current price control period to encourage DNOs to provide an appropriate quality of service to end users with specified payments to be made for failures to meet prescribed standards of service. The aggregate of these payments is uncapped, but may be excused in certain prescribed circumstances that are generally beyond the control of the DNO.

Ofgem also monitors DNO compliance with license conditions and enforces the remedies resulting from any breach of condition. License conditions include the prices and terms of service, financial strength of the DNO, the provision of information to Ofgem and the public, as well as maintaining transparency, non-discrimination and avoidance of cross-subsidy in the provision of such services. Ofgem also monitors and enforces certain duties of a DNO set out in the Electricity Act of 1989 including the duty to develop and maintain an efficient, coordinated and economical system of electricity distribution. Under the Utilities Act 2000, the regulators are able to impose financial penalties on DNOs who contravene any of their license duties or certain of their duties under the Electricity Act 1989, as amended, or who are failing to achieve a satisfactory performance in relation to the individual standards prescribed by GEMA. Any penalty imposed must be reasonable and may not exceed 10% of the licensee’s revenue.

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Independent Power Projects

Foreign

The Philippine Congress has passed the Electric Power Industry Reform Act of 2001 (“EPIRA”), which is aimed at restructuring the Philippine power industry, privatizing the National Power Corporation and introducing a competitive electricity market, among other initiatives. The implementation of EPIRA may impact the Company’s future operations in the Philippines and the Philippine power industry as a whole, the effect of which is not yet known as changes resulting from EPIRA are ongoing.

Domestic

Both the Cordova and Power Resources Projects are Exempt Wholesale Generators (“EWG”) under the Energy Policy Act while the remaining domestic projects are currently certified as Qualifying Facilities (“QF”) under the Public Utility Regulatory Policies Act of 1978 (“PURPA”). Both EWGs and QFs are generally exempt from compliance with extensive federal and state regulations that control the financial structure of an electric generating plant and the prices and terms at which electricity may be sold by the facilities. In addition, both Cordova and Yuma Cogeneration Associates have obtained authority from the FERC to sell their power using market-based rates.

EWGs are permitted to sell capacity and electricity only in the wholesale markets, not to end users. Additionally, utilities are required to purchase electricity produced by QFs at a price that does not exceed the purchasing utility’s “avoided cost” and to sell back-up power to the QFs on a non-discriminatory basis. Avoided cost is defined generally as the price at which the utility could purchase or produce the same amount of power from sources other than the QF on a long-term basis. The Energy Policy Act eliminated the purchase requirement for utilities with respect to new contracts under certain conditions. New QF contracts are also subject to FERC rate filing requirements, unlike QF contracts entered into prior to the Energy Policy Act. FERC regulations also permit QFs and utilities to negotiate agreements for utility purchases of power at rates other than the utilities’ avoided cost.

Residential Real Estate Brokerage Company

HomeServices is regulated by the U.S. Department of Housing and Urban Development (“HUD”), most significantly under the Real Estate Settlement Procedures Act (“RESPA”), and by state agencies where it operates. RESPA primarily governs the real estate settlement process by mandating all parties fully inform borrowers about all closing costs, lender servicing and escrow account practices, and business relationships between closing service providers and other parties to the transaction. In November 2008, as a result of a rulemaking proceeding initiated earlier in the year the HUD adopted a new RESPA rule that updated procedures and forms, enhanced notice and communication requirements and further clarified the scope of business relationships among closing service providers. The Company does not believe the new rule will materially affect HomeServices’ ability to do business.

Environmental Regulation

MEHC and its energy subsidiaries, like other energy companies, are subject to federal, state, local, and foreign laws and regulations with regard to air and water quality, renewable portfolio standards, climate change, hazardous and solid waste disposal and other environmental matters and are subject to zoning and other regulation by local authorities. These laws and regulations are subject to a range of interpretation which may ultimately be resolved by the courts. In addition to imposing continuing compliance obligations, these laws and regulations authorize the imposition of substantial penalties for noncompliance including fines, injunctive relief and other sanctions. The Company believes it is in material compliance with all laws and regulations. The most significant environmental laws and regulations affecting the Company include:

·   The federal Clean Air Act, as well as state laws and regulations impacting air emissions, including State Implementation Plans (“SIPs”) related to existing and new national ambient air quality standards. Rules issued by the United States Environmental Protection Agency (“EPA”) and certain states require substantial reductions in sulfur dioxide (“SO2”) and nitrogen oxide (“NOx”) emissions beginning in 2009 and extending through 2018. The Company has already installed certain emission control technology and is taking other measures to comply with required reductions. Refer to the Clean Air Standards section below for additional discussion regarding this topic.

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·   The federal Water Pollution Control Act (“Clean Water Act”) and individual state clean water laws regulate cooling water intake structures and discharges of wastewater, including storm water runoff. The Company believes that it currently has, or has initiated the process to receive, all required water quality permits. Refer to the Water Quality Standards section below for additional discussion regarding this topic.

·   The federal Comprehensive Environmental Response, Compensation and Liability Act and similar state laws, which may require any current or former owners or operators of a disposal site, as well as transporters or generators of hazardous substances sent to such disposal site, to share in environmental remediation costs. Refer to Note 18 of Notes to Consolidated Financial Statements included in Item 8 of this Form 10-K for additional information regarding environmental contingencies.

·   The Nuclear Waste Policy Act of 1982, under which the U.S. Department of Energy is responsible for the selection and development of repositories for, and the permanent disposal of, spent nuclear fuel and high-level radioactive wastes. The federal Surface Mining Control and Reclamation Act of 1977 and similar state statutes establish operational, reclamation and closure standards that must be met during and upon completion of mining activities. Refer to Note 14 of Notes to Consolidated Financial Statements included in Item 8 of this Form 10-K for additional information regarding nuclear decommissioning and mine reclamation obligations.

·   The FERC oversees the relicensing of existing hydroelectric systems and is also responsible for the oversight and issuance of licenses for new construction of hydroelectric systems, dam safety inspections and environmental monitoring. Refer to Note 18 of Notes to Consolidated Financial Statements included in Item 8 of this Form 10-K for additional information regarding the relicensing of certain of PacifiCorp’s existing hydroelectric facilities.

Refer to the Liquidity and Capital Resources section of Item 7 of this Form 10-K for additional information regarding planned capital expenditures related to environmental regulation.

Clean Air Standards

The Clean Air Act provides a framework for protecting and improving the nation’s air quality and controlling mobile and stationary sources of air emissions. The major Clean Air Act programs, which most directly affect the Company’s electric generating facilities, are briefly described below. Many of these programs are implemented and administered by the states, which can impose additional, more stringent requirements.

National Ambient Air Quality Standards

The EPA implements national ambient air quality standards for ozone and fine particulate matter, as well as for other criteria pollutants that set the minimum level of air quality for the United States. Areas that achieve the standards, as determined by ambient air quality monitoring, are characterized as being in attainment, while those that fail to meet the standards are designated as being nonattainment areas. Generally, sources of emissions in a nonattainment area are required to make emissions reductions. A new, more stringent standard for fine particulate matter became effective in December 2006. This standard was appealed to the United States Court of Appeals for the District of Columbia Circuit (“D.C. Circuit”). On February 24, 2009, the D.C. Circuit ruled that the EPA had failed to adequately explain why the annual fine particulate matter standard set at 15 micrograms per cubic meter was sufficiently protective of public health and remanded the rule for further review of the standard. The existing rule will remain in place until the EPA takes further action. Air quality modeling and preliminary air quality monitoring data indicate the counties in Washington, Oregon, Montana, Wyoming, Colorado, Utah and Arizona, where PacifiCorp’s major emission sources are located, are in attainment of the current ambient air quality standards. In December 2008, the EPA notified the state of Iowa that portions of Scott County, where MidAmerican Energy’s Riverside coal-fired generating facility is located, and Muscatine County, adjacent to Louisa County, where MidAmerican Energy’s Louisa coal-fired generating facility is located, did not meet the December 2006 24-hour fine particulate matter standard based on monitoring data from 2005 to 2007; however, based on monitoring data from 2006 to 2008, the 24-hour fine particulate matter standard was met. The Iowa Department of Natural Resources will be required to develop and implement a plan to reduce the emissions that form fine particulates. Until such time as the Iowa Department of Natural Resources develops the plan, it cannot be determined what impact the non-attainment designation may have on the operation of MidAmerican Energy’s facilities.

In March 2008, the EPA issued final rules to strengthen the national ambient air quality standard for ground level ozone, lowering the standard to 0.075 parts per million from 0.08 parts per million. States have until March 2009 to characterize their attainment status, and the EPA’s determinations regarding non-attainment will be made by March 2010 with SIPs due in 2013. Until the EPA makes its final attainment designations, the impact of any new standards on PacifiCorp and MidAmerican Energy will not be known.

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Regulated Air Pollutants

In 2005, the EPA promulgated the Clean Air Mercury Rule (“CAMR”) which would have regulated mercury emissions from coal-fired power plants through the use of a cap-and-trade system beginning in 2010, with reductions of approximately 70% when fully implemented in 2018. The CAMR was overturned by the United States Court of Appeals for the District of Columbia Circuit in February 2008. The EPA petitioned the United States Supreme Court for review of the lower court’s decision in October 2008. On February 6, 2009, the EPA withdrew its petition for review before the United States Supreme Court and on February 23, 2009, the Supreme Court dismissed the petition. The EPA has indicated it plans to propose a new mercury rule that will require coal-fired power plants to utilize Maximum Achievable Control Technology, rather than a cap-and-trade mechanism, to reduce mercury emissions. As a result, PacifiCorp’s and MidAmerican Energy’s coal-fired facilities may be required to install controls to reduce mercury emissions at each of their facilities rather than making cost-effective mercury emission reductions through a combination of controls and allowances. Depending on the scope and timing of these reduction requirements, as well as the availability and effectiveness of controls, the new rules could impose additional costs on PacifiCorp and MidAmerican Energy for control of mercury emissions above the costs anticipated under the CAMR.

In March 2005, the EPA released the final Clean Air Interstate Rule (“CAIR”), calling for reductions of SO2 and NOx emissions in the Eastern United States through, at each state’s option, a market-based cap-and-trade system, emission reductions, or both because of contributions to downwind nonattainment of the fine particulate matter and ozone standards. The SO2 and NOx emissions reductions were planned to be accomplished in two phases, in 2009-2010 and 2015. However, in July 2008, the D.C. Circuit held that the CAIR was fatally flawed and vacated the rule, remanding it to the EPA to consider which states are included in CAIR based on their contribution to nonattainment and neighboring states’ emission reductions to contributions to nonattainment in addition to distributing allowances appropriately. In September 2008, the EPA and others filed a petition for rehearing to the full court of the CAIR. In December 2008, the court granted the EPA’s petition to remand the matter without vacating the rule to the EPA to conduct further proceedings consistent with its prior opinion that the CAIR is fatally flawed and must be revised. The court concluded that, notwithstanding the flaws of the CAIR, it should remain in effect until it is replaced by a new rule. As a result of the court’s ruling, MidAmerican Energy and other utilities in the Eastern United States have an obligation to comply with the NOx provisions of the CAIR effective on January 1, 2009, and with the SO2 provisions of the CAIR effective January 1, 2010, until such time as the EPA promulgates a new rule. PacifiCorp’s generation facilities are not subject to the CAIR. Under the CAIR, a market for trading SO2 and NOx emission credits had developed. As a result of the uncertainties created by the court’s ruling and the indefinite nature of the existing CAIR, the cost and availability of NOx allowances is subject to market conditions.

Emissions reductions could be made more stringent by current or future regulatory and legislative proposals at the federal or state levels that would result in significant reductions of SO2, NOX and mercury, as well as carbon dioxide and other gases that may affect global climate change.

Regional Haze

The EPA has initiated a regional haze program intended to improve visibility at specific federally protected areas. Some of PacifiCorp’s and MidAmerican Energy’s generating facilities meet the threshold applicability criteria under the Clean Air Visibility Rules. In accordance with the federal requirements, states were required to submit SIPs by December 2007 to demonstrate reasonable progress toward achieving natural visibility conditions in certain Class I areas by requiring emission controls, known as best available retrofit technology, on sources with emissions that are anticipated to cause or contribute to impairment of visibility. Iowa submitted its SIP to the EPA and suggested that the emission reductions already made by MidAmerican Energy and additional reductions that will be made under the CAIR place the state in the position that no further reductions should be required. Wyoming has not yet submitted its SIP and is continuing to review the planned emission reductions at PacifiCorp’s Wyoming generating facilities. Utah submitted its SIP and suggested that the emission reduction projects planned by PacifiCorp are sufficient to meet its initial emission reduction requirements. In January 2009, the EPA made a finding that 37 states, including Wyoming, had failed to file a SIP that met some or all of the basic program requirements under the regional haze program. As a result, Wyoming has two years from January 2009 to file and obtain EPA approval of a SIP that meets all of the regional haze program requirements or the state will be subject to a federal implementation plan, with the EPA administering the regional haze program. PacifiCorp believes that its planned emission reduction projects will satisfy the regional haze requirements in Utah and Wyoming; however, it is possible that some additional controls may be required once the respective SIPs have been submitted or that the timing of the installation of planned controls could be changed.

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New Source Review

Under existing New Source Review (“NSR”) provisions of the Clean Air Act, any facility that emits regulated pollutants is required to obtain a permit from the EPA or a state regulatory agency prior to (1) beginning construction of a new major stationary source of an NSR-regulated pollutant, or (2) making a physical or operational change to an existing stationary source of such pollutants that increases certain levels of emissions, unless the changes are exempt under the regulations (including routine maintenance, repair and replacement of equipment). In general, projects subject to NSR regulations are subject to pre-construction review and permitting under the Prevention of Significant Deterioration (“PSD”) provisions of the Clean Air Act. Under the PSD program, a project that emits threshold levels of regulated pollutants must undergo a “best available control technology” analysis and evaluate the most effective emissions controls. These controls must be installed in order to receive a permit. Violations of NSR regulations, which may be alleged by the EPA, states and environmental groups, among others, potentially subject a utility to material fines and other sanctions and remedies including requiring installation of enhanced pollution controls and funding supplemental environmental projects.

As part of an industry-wide investigation to assess compliance with the NSR and PSD provisions, the EPA has requested from numerous utilities information and supporting documentation regarding their capital projects for various generating facilities. Between 2001 and 2003, PacifiCorp and MidAmerican Energy responded to requests for information relating to their capital projects at their generating facilities. PacifiCorp has been engaged in periodic discussions with the EPA over several years regarding PacifiCorp’s historical projects and their compliance with NSR and PSD provisions. There are currently no outstanding data requests at MidAmerican Energy pending from the EPA. An NSR enforcement case against another utility has been decided by the United States Supreme Court, holding that an increase in the annual emissions of a generating facility, when combined with a modification (i.e., a physical or operational change), may trigger NSR permitting. PacifiCorp cannot predict the outcome of its discussions with the EPA at this time; however, PacifiCorp could be required to install additional emissions controls, and incur additional costs and penalties, in the event it is determined that PacifiCorp’s historic projects did not meet all regulatory requirements.

Numerous changes have been proposed to the NSR rules and regulations over the last several years. These changes, withdrawals of proposed changes, differing interpretations by the EPA and the courts, and the recent change in administration, create risk and uncertainty for regulated entities in complying with NSR requirements when permitting new projects and installing emission controls at existing facilities. MEHC's subsidiaries monitor these changes and interpretations to ensure permitting activities are conducted in accordance with the applicable requirements.

Renewable Portfolio Standards

The renewable portfolio standards (“RPS”) described below could significantly impact the Company’s financial results. Resources that meet the qualifying electricity requirements under the RPS vary from state-to-state. Each state’s RPS requires some form of compliance reporting and the Company can be subject to penalties in the event of non-compliance.

In November 2006, Washington voters approved a ballot initiative establishing a RPS requirement for qualifying electric utilities, including PacifiCorp. The requirements are 3% of retail sales by January 1, 2012 through 2015, 9% of retail sales by January 1, 2016 through 2019 and 15% of retail sales by January 1, 2020. The WUTC has adopted final rules to implement the initiative. The Company expects to be able to recover its costs of complying with the RPS, either through rate cases or an adjustment mechanism.

In June 2007, the Oregon Renewable Energy Act (the “OREA”) was adopted, providing a comprehensive renewable energy policy for Oregon. Subject to certain exemptions and cost limitations established in the OREA, PacifiCorp and other qualifying electric utilities must meet minimum qualifying electricity requirements for electricity sold to retail customers of at least 5% in 2011 through 2014, 15% in 2015 through 2019, 20% in 2020 through 2024, and 25% in 2025 and subsequent years. As required by the OREA, the OPUC has approved an automatic adjustment clause to allow an electric utility, including PacifiCorp, to recover prudently incurred costs of its investments in renewable energy generating facilities and associated transmission costs. The OPUC and the Oregon Department of Energy have undertaken additional rulemaking proceedings to further implement the initiative. The Company expects to be able to recover its costs of complying with the RPS through the automatic adjustment mechanism.

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California law requires electric utilities to increase their procurement of renewable resources by at least 1% of their annual retail electricity sales per year so that 20% of their annual electricity sales are procured from renewable resources by no later than December 31, 2010. In May 2008, PacifiCorp and other small multi-jurisdictional utilities (“SMJU”) received further guidance from the CPUC on the treatment of SMJUs in the California RPS program. In August 2008, concurrent with its annual RPS compliance filing, PacifiCorp, joined by another SMJU, filed a Joint Motion for Review of the decision, including banking of RPS procurement made while it awaited further guidance from the CPUC on the treatment of SMJUs during the 2004-2006 period. PacifiCorp noted, among other things, on this filing that its interpretation is consistent with the CPUC guidance and best serves the interests of its customers by recognizing past, good faith efforts to comply with California’s RPS program beginning January 1, 2004. PacifiCorp is currently awaiting the CPUC’s response to the Joint Motion for Review. Absent further direction from the CPUC on treatment of SMJUs, the Company cannot predict the impact of the California RPS on its financial results.

In March 2008, Utah’s governor signed Utah Senate Bill 202, “Energy Resource and Carbon Emission Reduction Initiative.” Among other things, this law provides that, beginning in the year 2025, 20% of adjusted retail electric sales of all Utah utilities be supplied by renewable energy, if it is cost effective. Retail electric sales will be adjusted by deducting the amount of generation from sources that produce zero or reduced carbon emissions, and for sales avoided as a result of energy efficiency and demand-side management programs. Qualifying renewable energy sources can be located anywhere in the WECC areas, and renewable energy credits can be used. PacifiCorp expects to be able to recover its costs of complying with the law, either through rate cases or adjustment mechanisms.

Climate Change

As a result of increased attention to global climate change in the United States, there are significant future environmental regulations under consideration to increase the deployment of clean energy technologies and regulate emissions of greenhouse gas at the state, regional and federal levels. Congress and federal policy makers are considering climate change legislation and a variety of national climate change policies. President Obama has expressed support for an economy-wide greenhouse gas cap-and-trade program that would reduce emissions 80% below 1990 levels by 2050. Alternatively, or in conjunction with a cap, policy makers have discussed the possibility of imposing a tax on greenhouse gas emissions. Given the strong interest and support in reducing greenhouse gas emissions, the Company’s electric generating facilities are likely to be subject to regulation of greenhouse gas emissions within the next several years.

In addition, nongovernmental organizations have become more active in initiating citizen suits under existing environmental and other laws and the EPA issued an advanced notice of proposed rulemaking in 2008 to consider issues associated with regulating greenhouse gas emissions under the Clean Air Act. The United States Supreme Court has ruled that the EPA has the authority under the Clean Air Act to regulate emissions of greenhouse gases from motor vehicles and that the EPA must make a determination relating to the danger posed by greenhouse gas emissions. Furthermore, pending cases that address the potential public nuisance from greenhouse gas emissions from electricity generators and the EPA’s failure to regulate greenhouse gas emissions from new and existing coal-fired generating facilities are expected to become active. While debate continues at the national level over the direction of domestic climate policy, several states have developed state-specific laws or regional legislative initiatives to reduce greenhouse gas emissions that are expected to impact PacifiCorp, MidAmerican Energy, and other MEHC energy subsidiaries, including:

·   The Western Regional Climate Action Initiative (“Western Climate Initiative”), a comprehensive regional effort to reduce greenhouse gas emissions by 15% below 2005 levels by 2020 through a cap-and-trade program that includes the electricity sector. The Western Climate Initiative includes the states of Arizona, California, Montana, New Mexico, Oregon, Utah and Washington and the provinces of British Columbia, Manitoba, Ontario and Quebec. The state and provincial partners have agreed to begin reporting greenhouse gas emissions in 2011 for emissions that occur in 2010. The first phase of the cap-and-trade program will begin on January 1, 2012.

·   An executive order signed by California’s governor in June 2005 would reduce greenhouse gas emissions in that state to 2000 levels by 2010, to 1990 levels by 2020 and 80% below 1990 levels by 2050. In addition, California has adopted legislation that imposes a greenhouse gas emission performance standard to all electricity generated within the state or delivered from outside the state that is no higher than the greenhouse gas emission levels of a state-of-the-art combined-cycle natural gas-fired generating facility, as well as legislation that adopts an economy-wide cap on greenhouse gas emissions to 1990 levels by 2020.

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·   The Washington and Oregon governors enacted legislation in May 2007 and August 2007, respectively, establishing economy-wide goals for the reduction of greenhouse gas emissions in their respective states. Washington’s goals seek to, (i) by 2020, reduce emissions to 1990 levels; (ii) by 2035, reduce emissions to 25% below 1990 levels; and (iii) by 2050, reduce emissions to 50% below 1990 levels, or 70% below Washington’s forecasted emissions in 2050. Oregon’s goals seek to, (i) by 2010, cease the growth of Oregon greenhouse gas emissions; (ii) by 2020, reduce greenhouse gas levels to 10% below 1990 levels; and (iii) by 2050, reduce greenhouse gas levels to at least 75% below 1990 levels. Each state’s legislation also calls for state government developed policy recommendations in the future to assist in the monitoring and achievement of these goals. The impact of the enacted legislation on the Company cannot be determined at this time.

·   In Iowa, legislation enacted in 2007 requires the Iowa Climate Change Advisory Council (“ICCAC”), a 23-member group appointed by the Iowa governor, to develop scenarios designed to reduce statewide greenhouse gas emissions, including one scenario that would reduce emissions by 50% by 2050, and submit its recommendations to the legislature. The ICCAC also developed a second scenario to reduce greenhouse gas emissions by 90% with reductions in both scenarios from 2005 emission levels. In January 2009, the ICCAC presented to the Iowa governor and legislature 56 policy options to consider to achieve greenhouse gas reductions, including enhanced energy efficiency programs and increased renewable generation.

·   In November 2007, the Iowa governor signed the Midwest Greenhouse Gas Accord and the Energy Security and Climate Stewardship Platform for the Midwest. The signatories to the platform were other Midwestern states that agreed to implement a regional cap-and-trade system for greenhouse gas emissions by May 2010. Current advisory group recommendations include the assessment of 2020 emission reduction targets of 15%, 20% and 25% below 2005 levels and a 2050 target of 60% to 80% below 2005 levels. In addition, the accord calls for the participating states to collectively meet at least 2% of regional annual retail sales of natural gas and electricity through energy efficiency improvements by 2015 and continue to achieve an additional 2% in efficiency improvements every year thereafter.

·   The Regional Greenhouse Gas Initiative, a mandatory, market-based effort to reduce greenhouse gas emissions in ten Northeastern and Mid-Atlantic states and requires, beginning in 2009, the reduction of CO2 emissions from the power sector by 10% by 2018.

In addition to pending legislative proposals to regulate greenhouse gas emissions, in July 2008, the EPA issued an advance notice of proposed rulemaking presenting information relevant to, and soliciting public comment on, how to respond to the United States Supreme Court’s decision in Massachusetts v. EPA in which the United States Supreme Court ruled that the Clean Air Act authorizes regulation of greenhouses gases because they meet the definition of an air pollutant under the Clean Air Act, given the potential ramifications of a decision to regulate such emissions under the existing Clean Air Act framework.

MEHC’s energy subsidiaries are currently subject to specific greenhouse gas-related requirements, including the requirement for CalEnergy’s natural gas-fueled Saranac facility to hold and submit allowances for its greenhouse gas emissions in accordance with the Regional Greenhouse Gas Initiative. Certain company facilities are subject to mandatory greenhouse gas reporting requirements in California, Washington and Oregon. California, Washington and Oregon also require the consideration of greenhouse gas emissions in new resource decisions through the establishment of greenhouse gas emissions performance standards and the requirement for mitigation of greenhouse gas emissions in conjunction with the addition of new emitting resources.

MEHC’s subsidiaries believe in implementing public policy to address climate change in a manner that informs all constituents of cost ramifications and attempts to minimize such costs. The Company believes that research and development must be undertaken on a large scale and in a coordinated manner to obtain technologies that reduce carbon emissions while still providing reasonably priced energy and that the development and deployment of low-carbon electricity technologies must precede the imposition of significant emission reduction requirements or taxes or fees on emissions. MEHC subsidiaries continue to add renewable and low-carbon electric capacity to their generation portfolios in an effort to reduce the carbon intensity of their generating capacity. From 2005 to 2008, through the addition of lower-carbon and renewable generation resources, PacifiCorp reduced the CO2 intensity of its combined electricity generation portfolio by 11% while increasing the number of MWh generated by 17%. From 2000 to 2008, through the addition of lower-carbon and renewable generation resources, MidAmerican Energy, reduced the CO2 intensity of its combined electricity generation portfolio by 14% while increasing the number of MWh generated by 43%. In addition, PacifiCorp and MidAmerican Energy have engaged in several voluntary programs designed to reduce or avoid greenhouse gas emissions, including the EPA’s sulfur hexafluoride reduction program, refrigerator recycling programs, and the EPA landfill methane outreach program. PacifiCorp is a member of the California Climate Action Registry and The Climate Registry, under which it reports and certifies its greenhouse gas emissions. MidAmerican Energy and Northern Natural Gas are also founding members of The Climate Registry under which they will voluntarily report their greenhouse gas emissions.

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Climate change may cause physical and financial risk through, among other things, sea level rise, changes in precipitation and extreme weather events. Energy needs may increase or decrease, based on overall changes in weather. Availability of resources to generate electricity, such as water for hydroelectric production and cooling purposes, may also be impacted by climate change and could influence the Company’s existing and future electricity generation portfolio. These issues may have a direct impact on the costs of electricity production and increase the price paid by customers for electricity.

Legislative and regulatory responses to climate change have the potential to create financial risk. Adoption of early and stringent limits on greenhouse gas emissions could significantly adversely impact the Company’s current and future fossil-fueled facilities, and therefore, its financial results. To the extent that PacifiCorp and MidAmerican Energy are not allowed by their regulators or cannot otherwise recover the costs incurred to comply with climate change requirements, these requirements could have a material adverse impact on the Company’s financial results. Costs of compliance with environmental and other regulatory requirements are historically recovered in rates but risk regulatory lag. Although the Company does not make policy and does not take a position on the scientific aspects of climate change, it supports an informed dialogue on climate change and intends to implement actions to comply with any new legislation or regulation. The impact of any pending judicial proceedings and any pending or enacted federal and state climate change legislation and regulation cannot be determined at this time; however, adoption of stringent limits on greenhouse gas emissions could significantly adversely impact the Company’s current and future fossil-fueled generating facilities, and, therefore, its financial results.

Water Quality Standards

The Clean Water Act establishes the framework for maintaining and improving water quality in the United States through a program that regulates, among other things, discharges to and withdrawals from waterways. The Clean Water Act requires that cooling water intake structures reflect the “best technology available for minimizing adverse environmental impact” to aquatic organisms. In July 2004, the EPA established significant new national technology-based performance standards for existing electric generating facilities that take in more than 50 million gallons of water per day. These rules are aimed at minimizing the adverse environmental impacts of cooling water intake structures by reducing the number of aquatic organisms lost as a result of water withdrawals. In response to a legal challenge to the rule, in January 2007, the United States Court of Appeals for the Second Circuit (“Second Circuit”) remanded almost all aspects of the rule to the EPA, leaving companies with cooling water intake structures uncertain regarding compliance with these requirements. Petitions for certiorari are pending before the United States Supreme Court regarding the Second Circuit’s decision to remand the rule to the EPA. The United States Supreme Court will consider whether §316(b) of the Clean Water Act authorizes the EPA to compare costs with benefits in determining “best technology available for minimizing adverse environmental impact” at cooling water intake structures. Compliance and the potential costs of compliance, therefore, cannot be ascertained until such time as the United States Supreme Court’s decision is rendered or further action is taken by the EPA. Currently, PacifiCorp’s Dave Johnston Plant and all of MidAmerican Energy’s coal-fired generating facilities, except Louisa, Ottumwa and Walter Scott, Jr. Unit 4, which have water cooling towers, exceed the 50 million gallons of water per day intake threshold. In the event that PacifiCorp’s or MidAmerican Energy’s existing intake structures require modification or alternative technology required by new rules, expenditures to comply with these requirements could be significant.

Ash Disposal

In December 2008, an ash impoundment dike at the Tennessee Valley Authority’s Kingston power plant collapsed after heavy rain, releasing a significant amount of fly ash and bottom ash, coal combustion byproducts, and water to the surrounding area. In light of this incident, federal and state officials have called for greater regulation of coal combustion storage and disposal. PacifiCorp and MidAmerican Energy operate coal ash impoundments and, in January 2008, made voluntary commitments under an industry action plan to disposal restrictions, monitoring and reporting of coal combustion products that exceed requirements under current law. These ash impoundments could be impacted by additional regulation and could pose additional costs associated with ash management and disposal activities at the Company’s coal-fired generating facilities. The impact of any new regulations on coal combustion products cannot be determined at this time.

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Item 1A. Risk Factors

We are subject to certain risks in our business operations which are described below. Careful consideration of these risks, together with all of the other information included in this annual report and the other public information filed by us, should be made before making an investment decision. The risks and uncertainties described below are not the only ones we face. Additional risks and uncertainties not presently known or that are currently deemed immaterial may also impair our business operations.

Our Corporate and Financial Structure Risks

We are a holding company and depend on distributions from subsidiaries, including joint ventures, to meet our obligations.

We are a holding company with no material assets other than the stock of our subsidiaries and joint ventures, collectively referred to as our subsidiaries. Accordingly, cash flows and the ability to meet our obligations are largely dependent upon the earnings of our subsidiaries and the payment of such earnings to us in the form of dividends, loans, advances or other distributions. Our subsidiaries are separate and distinct legal entities and have no obligation, contingent or otherwise, to pay amounts due pursuant to our senior and subordinated debt securities or to make funds available to us, whether by dividends, loans or other payments, for payment of our other obligations, and they do not guarantee the payment of any of our obligations. Distributions from subsidiaries may also be limited by:

·   their respective earnings, capital requirements, and required debt and preferred stock payments;

·   the satisfaction of certain terms contained in financing, ring-fencing or organizational documents; and

·   regulatory restrictions which limit the ability of our regulated utility subsidiaries to distribute profits.

We are substantially leveraged, the terms of our senior and subordinated debt do not restrict the incurrence of additional indebtedness by us or our subsidiaries, and our senior and subordinated debt is structurally subordinated to the indebtedness of our subsidiaries, each of which could have an adverse impact on our financial results.

A significant portion of our capital structure is debt and we expect to incur additional indebtedness in the future to fund acquisitions, capital investments or the development and construction of new or expanded facilities. As of December 31, 2008, we had the following outstanding obligations:

·   senior indebtedness of $5.12 billion;

·   subordinated indebtedness of $1.32 billion, consisting of $234 million of trust preferred securities held by third parties and $1.09 billion held by Berkshire Hathaway and its affiliates; and

·   guarantees and letters of credit in respect of subsidiary and equity investment indebtedness aggregating $91 million.

Our consolidated subsidiaries also have significant amounts of outstanding indebtedness, which totaled $12.95 billion as of December 31, 2008. These amounts exclude (i) trade debt or preferred stock obligations, (ii) letters of credit in respect of subsidiary indebtedness, and (iii) our share of the outstanding indebtedness of our own or our subsidiaries’ equity investments.

Given our substantial leverage, we may not generate sufficient cash to service our debt. Our leverage could also limit our ability to finance future acquisitions, develop and construct additional projects, or operate successfully under adverse conditions, including those brought on by declining national and global economies and unfavorable financial markets, such as those experienced in the United States in 2008. Our leverage could also impair our credit quality or the credit quality of our subsidiaries, making it more difficult to finance operations or issue future indebtedness on favorable terms, and could result in a downgrade in debt ratings by credit rating agencies.

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The terms of our senior and subordinated debt do not limit our ability or the ability of our subsidiaries to incur additional debt or issue preferred stock. Accordingly, we or our subsidiaries could enter into acquisitions, new financings, refinancings, recapitalizations or other highly leveraged transactions that could significantly increase our or our subsidiaries’ total amount of outstanding debt. The interest payments needed to service this increased level of indebtedness could adversely affect our financial results. Further, if an event of default accelerates a repayment obligation and such acceleration results in an event of default under some or all of our other indebtedness, we may not have sufficient funds to repay all of the accelerated indebtedness, and the other risks described under “Our Corporate and Financial Structure Risks” may be magnified as well.

Because we are a holding company, the claims of our senior and subordinated debt holders are structurally subordinated with respect to the assets and earnings of our subsidiaries. Therefore, the rights of our creditors to participate in the assets of any subsidiary in the event of a liquidation or reorganization are subject to the prior claims of the subsidiary’s creditors and preferred shareholders. In addition, a significant amount of the stock or assets of our operating subsidiaries is directly or indirectly pledged to secure their financings and, therefore, may be unavailable as potential sources of repayment of our senior and subordinated debt.

A downgrade in our credit ratings or the credit ratings of our subsidiaries could negatively affect our or our subsidiaries’ access to capital, increase the cost of borrowing or raise energy transaction credit support requirements.

Our senior unsecured long-term debt is rated investment grade by various rating agencies. We cannot assure that our senior unsecured long-term debt will continue to be rated investment grade in the future. Although none of our outstanding debt has rating-downgrade triggers that would accelerate a repayment obligation, a credit rating downgrade would increase our borrowing costs and commitment fees on the revolving credit agreements, perhaps significantly. In addition, we would likely be required to pay a higher interest rate in future financings, and the potential pool of investors and funding sources would likely decrease. Further, access to the commercial paper market, the principal source of short-term borrowings, could be significantly limited resulting in higher interest costs.

Similarly, any downgrade or other event negatively affecting the credit ratings of our subsidiaries could make their costs of borrowing higher or access to funding sources more limited, which in turn could cause us to provide liquidity in the form of capital contributions or loans to such subsidiaries, thus reducing our and our subsidiaries’ liquidity and borrowing capacity.

Most of our large customers, suppliers and counterparties require sufficient creditworthiness in order to enter into transactions, particularly in the wholesale energy markets. If our credit ratings or the credit ratings of our subsidiaries were to decline, especially below investment grade, operating costs would likely increase because counterparties may require a letter of credit, collateral in the form of cash-related instruments or some other security as a condition to further transactions with us or our subsidiaries.

Our majority shareholder, Berkshire Hathaway, could exercise control over us in a manner that would benefit Berkshire Hathaway to the detriment of our creditors.

Berkshire Hathaway is our majority owner and has control over all decisions requiring shareholder approval, including the election of our directors. In circumstances involving a conflict of interest between Berkshire Hathaway and our creditors, Berkshire Hathaway could exercise its control in a manner that would benefit Berkshire Hathaway to the detriment of our creditors.

Our Business Risks

Much of our growth has been achieved through acquisitions, and additional acquisitions may not be successful.

Much of our growth has been achieved through acquisitions. Future acquisitions may range from buying individual assets to the purchase of entire businesses. We will continue to investigate and pursue opportunities for future acquisitions that we believe may increase shareholder value and expand or complement existing businesses. We may participate in bidding or other negotiations at any time for such acquisition opportunities which may or may not be successful. Any transaction that does take place may involve consideration in the form of cash, debt or equity securities.

Completion of any acquisition entails numerous risks, including, among others, the:

·   failure to complete the transaction for various reasons, such as the inability to obtain the required regulatory approvals, materially adverse developments in the potential acquiree’s business or financial condition or successful intervening offers by third parties;

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·   failure of the combined business to realize the expected benefits or to meet regulatory commitments; and

·   need for substantial additional capital and financial investments.

An acquisition could cause an interruption of, or loss of momentum in, the activities of one or more of our businesses. The diversion of management’s attention and any delays or difficulties encountered in connection with the approval and integration of the acquired operations could adversely affect our combined businesses and financial results and could impair our ability to realize the anticipated benefits of the acquisition.

We cannot assure that future acquisitions, if any, or any related integration efforts will be successful, or that our ability to repay our obligations will not be adversely affected by any future acquisitions.

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

We and our businesses are subject to numerous regulations and laws enforced by regulatory agencies. In the United States, these regulatory agencies include, among others, the FERC, the EPA, the NRC, and the DOT. In addition, our domestic utility subsidiaries are subject to state utility regulation in each state in which they operate. In the United Kingdom, these regulatory agencies include, among others, GEMA, which discharges certain of its powers through its staff within Ofgem.

Regulations affect almost every aspect of our business and limit our ability to independently make and implement management decisions regarding, among other items, business combinations, constructing, acquiring or disposing of operating assets, setting rates charged to customers, establishing capital structures and issuing debt or equity securities, engaging in transactions between our domestic utilities and other subsidiaries and affiliates, and paying dividends. Regulations are subject to ongoing policy initiatives and we cannot predict the future course of changes in laws, regulations and orders, or the ultimate effect that regulatory changes may have on us. However, such changes could materially impact our financial results. For example, such changes could result in, but are not limited to, increased retail competition within our subsidiaries’ service territories; new environmental requirements, including the implementation of RPS and greenhouse gas emission reduction goals; implementation of energy efficiency mandates; the acquisition by a municipality of our subsidiaries’ distribution facilities (by negotiation, legislation or condemnation or by a vote in favor of a public utility district under Oregon law); or a negative impact on our subsidiaries’ current transportation and cost recovery arrangements, including income tax recovery.

Federal and state energy regulation changes are one of the more challenging aspects of managing utility operations. New and expanded regulations imposed by policy makers, court systems, and industry restructuring have imposed changes on the industry. The following are examples of changes to our regulatory environment that have impacted us:

·   Energy Policy Act of 2005 - In the United States, the Energy Policy Act impacts many segments of the energy industry. The U.S. Congress granted the FERC additional authority in the Energy Policy Act which expanded its role from a regulatory body to an enforcement agency. To implement the law, the FERC adopted new regulations and issued regulatory decisions addressing electric system reliability, electric transmission planning, operation, expansion and pricing, regulation of utility holding companies, and enforcement authority, including the ability to assess civil penalties of up to $1 million per day per violation for non-compliance. The FERC has essentially completed its implementation of the Energy Policy Act and the emphasis of its recent decisions is on reporting and compliance. In that regard, the FERC has vigorously exercised its enforcement authority by imposing significant civil penalties for violations of its rules and regulations. For example, as a result of past events affecting electric reliability, the Energy Policy Act requires federal agencies, working together with non-governmental organizations charged with electric reliability responsibilities, to adopt and implement measures designed to ensure the reliability of electric transmission and distribution systems. Since the adoption of the Energy Policy Act, the FERC has approved numerous electric reliability, cyber security and critical infrastructure protection standards developed by the NERC. A transmission owner’s reliability compliance issues with these and future standards could result in financial penalties. In FERC Order No. 693, the FERC implemented its authority to impose penalties of up to $1 million per day per violation for failure to comply with electric reliability standards. The adoption of these and future electric reliability standards has imposed more comprehensive and stringent requirements on us and our public utility subsidiaries, which has increased compliance costs. It is possible that the cost of complying with these and any additional standards adopted in the future could adversely affect our financial results.

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·   FERC Orders – The FERC has issued a series of orders to encourage competition in natural gas markets, the expansion of existing pipelines and the construction of new pipelines and to foster greater competition in wholesale power markets by reducing barriers to entry in the provision of transmission service. As a result of FERC Order Nos. 636 and 637, in the natural gas markets, LDCs and end-use customers have additional choices in this more competitive environment and may be able to obtain service from more than one pipeline to fulfill their natural gas delivery requirements. Any new pipelines that are constructed could compete with our pipeline subsidiaries to service customer needs. Increased competition could reduce the volumes of gas transported by our pipeline subsidiaries or, in the absence of long-term fixed rate contracts, could force our pipeline subsidiaries to lower their rates to remain competitive. This could adversely affect our pipeline subsidiaries’ financial results. In FERC Order Nos. 888, 889, 890, 890-A and 890-B, the FERC required electric utilities to adopt a proforma OATT by which transmission service would be provided on a just, reasonable and not unduly discriminatory or preferential basis. The rules adopted by these orders promote transparency and consistency in the administration of the OATT, increase the ability of customers to access new generating resources and promote efficient utilization of transmission by requiring an open, transparent and coordinated transmission planning process. Together with the increased reliability standards required of transmission providers, the costs of operating the transmission system and providing transmission service have increased and, to the extent such increased costs are not recovered in rates charged to customers, they could adversely affect our financial results.

·   Hydroelectric Relicensing – Currently, the Klamath hydroelectric system, whose operating license has expired and is operating on annual licenses, is engaged in the FERC relicensing process. Through negotiations with relicensing stakeholders, disposition of the relicensing process and a path toward dam transfer and removal by a third party may occur as an alternative to relicensing. Hydroelectric relicensing is a political and public regulatory process involving sensitive resource issues and uncertainties. We cannot predict with certainty the requirements (financial, operational or otherwise) that may be imposed by relicensing, the economic impact of those requirements, and whether new licenses will ultimately be issued or whether PacifiCorp will be willing to meet the relicensing requirements to continue operating its hydroelectric generating facilities. Loss of hydroelectric resources or additional commitments arising from relicensing could adversely affect our financial results.

In addition to the foregoing examples, the new Obama administration has stated that many aspects of energy and the environment, including renewable resources and climate change, will be a key component of its policy agenda. We cannot predict what actions the administration may take, the laws or regulations that may be adopted or the ultimate effect that any of these may have on us, however, such effect could materially impact our financial results.

Our subsidiaries are subject to numerous environmental, health, safety and other laws, regulations and other requirements that could adversely affect our financial results.

Operational Standards

Our subsidiaries are subject to numerous environmental, health, safety and other laws, regulations and requirements affecting many aspects of their present and future operations, including, among others:

·   the EPA’s CAIR, which established cap-and-trade programs to reduce SO2, and NOx, emissions starting in 2009 to address alleged contributions to downwind non-attainment with the revised National Ambient Air Quality Standards;

·   the implementation of federal and state renewable portfolio standards;

·   other laws or regulations that establish or could establish standards for greenhouse gas emissions, water quality, wastewater discharges, solid waste and hazardous waste;

·   the DOT regulations, effective in 2004, that establish mandatory inspections for all natural gas transmission pipelines in high-consequence areas within 10 years. These regulations require pipeline operators to implement integrity management programs, including more frequent inspections, and other safety protections in areas where the consequences of potential pipeline accidents pose the greatest risk to life and property; and

·   the provisions of the Mine Improvement and New Emergency Response Act of 2006 to improve underground coal mine safety and emergency preparedness.

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These and related laws, regulations and orders generally require our subsidiaries to obtain and comply with a wide variety of environmental licenses, permits, inspections and other approvals.

Compliance with environmental, health, safety, and other laws, regulations and other requirements can require significant capital and operating expenditures, including expenditures for new equipment, inspection, cleanup costs, damages arising out of contaminated properties, and fines, penalties and injunctive measures affecting operating assets for failure to comply with environmental regulations. Compliance activities pursuant to regulations could be prohibitively expensive. As a result, some facilities may be required to shut down or alter their operations. Further, our subsidiaries may not be able to obtain or maintain all required environmental regulatory approvals for their operating assets or development projects. Delays in or active opposition by third parties to obtaining any required environmental or regulatory permits, failure to comply with the terms and conditions of the permits or increased regulatory or environmental requirements may increase costs or prevent or delay our subsidiaries from operating their facilities, developing new facilities, expanding existing facilities or favorably locating new facilities. If our subsidiaries fail to comply with all applicable environmental requirements, they may be subject to penalties and fines or other sanctions. The costs of complying with current or new environmental, health, safety and other laws, regulations and other requirements could adversely affect our financial results. Not being able to operate existing facilities or develop new electric generating facilities to meet customer energy needs could require our subsidiaries to increase their purchases of power from the wholesale markets which could increase market and price risks and adversely affect our financial results. Proposals for voluntary initiatives and mandatory controls are being discussed both in the United States and worldwide to reduce so-called ‘‘greenhouse gases’’ such as carbon dioxide (a by-product of burning fossil fuels), methane (the primary component of natural gas) and methane leaks from pipelines. These actions could result in increased costs to (i) operate and maintain our facilities, (ii) install new emission controls on our facilities and (iii) administer and manage any greenhouse gas emissions program. These actions could also increase the demand for natural gas, causing increased natural gas prices, thereby adversely affecting our operations.

Site Clean-up and Contamination

Environmental, health, safety and other laws, regulations and requirements also impose obligations to remediate contaminated properties or to pay for the cost of such remediation, often by parties that did not actually cause the contamination. Our subsidiaries are generally responsible for on-site liabilities, and in some cases off-site liabilities, associated with the environmental condition of their assets, including power generating facilities and electric and natural gas transmission and distribution assets that our subsidiaries have acquired or developed, regardless of when the liabilities arose and whether they are known or unknown. In connection with acquisitions, we or our subsidiaries may obtain or require indemnification against some environmental liabilities. If our subsidiaries incur a material liability, or the other party to a transaction fails to meet its indemnification obligations, our subsidiaries could suffer material losses. Our subsidiaries have established reserves to recognize their estimated obligations for known remediation liabilities, but such estimates may change materially over time. PacifiCorp is required to fund its portion of the costs of mine reclamation at its coal mining operations, which include principally site restoration. Also, MidAmerican Energy is required to fund its portion of the costs of decommissioning the Quad Cities Station, when it is retired from service, which may include site remediation or decontamination. In addition, future events, such as changes in existing laws or policies or their enforcement, or the discovery of currently unknown contamination, may give rise to additional remediation liabilities that may be material.

Recovery of costs by our regulated subsidiaries is subject to regulatory review and approval, and the inability to recover costs may adversely affect their financial results.

Public Utility Subsidiaries – State Rate Proceedings

Two of our regulated subsidiaries, PacifiCorp and MidAmerican Energy, establish rates for their regulated retail service through state regulatory proceedings. These proceedings typically involve multiple parties, including government bodies and officials, consumer advocacy groups and various consumers of energy, who have differing concerns, but who generally have the common objective of limiting rate increases. Decisions are subject to appeal, potentially leading to additional uncertainty associated with the approval proceedings.

Each state sets retail rates based in part upon the state utility commission’s acceptance of an allocated share of total utility costs. When states adopt different methods to calculate interjurisdictional cost allocations, some costs may not be incorporated into rates of any state. Rate making is also generally done on the basis of estimates of normalized costs, so if a given year’s realized costs are higher than normalized costs, rates will not be sufficient to cover those costs. Each state utility commission generally sets rates based on a test year established in accordance with that commission’s policies. Certain states use a future test year or allow for escalation of historical costs, while other states use a historical test year. Use of a historical test year may cause regulatory lag, which results in our utilities incurring costs, including significant new investments, for which recovery through rates is delayed. State regulatory commissions also decide the allowed rate of return we will be given an opportunity to earn on our equity investment. In addition, they also decide the allowed levels of expense and investment that they deem is just and reasonable in providing service. The state regulatory commissions may disallow recovery in rates for any costs that do not meet such standard.

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In Iowa, MidAmerican Energy has agreed not to seek a general increase in electric base rates to become effective prior to January 1, 2014 unless its Iowa jurisdictional electric return on equity for any year falls below 10%. MidAmerican Energy expects to continue to make significant capital expenditures to maintain and improve the reliability of its generation, transmission and distribution facilities, to reduce emissions and to support new business and customer growth. As a result, MidAmerican Energy’s financial results may be adversely affected if it is not able to deliver electricity in a cost-efficient manner and is unable to offset inflation and the cost of infrastructure investments with costs savings or additional sales.

In certain states, PacifiCorp and MidAmerican Energy are not permitted to pass through energy cost increases in their electric rates without a general rate case. Any significant increase in fuel costs for electricity generation or purchased power costs could have a negative impact on PacifiCorp or MidAmerican Energy, despite efforts to minimize this impact through future general rate cases or the use of hedging instruments. Any of these consequences could adversely affect our financial results.

While rate regulation is premised on providing a fair opportunity to obtain a reasonable rate of return on invested capital, the state regulatory commissions do not guarantee that we will be able to realize a reasonable rate of return.

Public Utility Subsidiaries – FERC Jurisdiction

The FERC establishes cost-based tariffs under which both PacifiCorp and MidAmerican Energy provide transmission services to wholesale markets and retail markets in states that allow retail competition. The FERC also has responsibility for approving both cost- and market-based rates under which both these companies sell electricity at wholesale and has licensing authority over most of PacifiCorp’s hydroelectric generating facilities. The FERC may impose price limitations, bidding rules and other mechanisms to address some of the volatility of these markets or may (pursuant to pending or future proceedings) revoke or restrict the ability of our public utility subsidiaries to sell electricity at market-based rates, which could adversely affect our financial results. The FERC may also impose substantial civil penalties for any non-compliance with the Federal Power Act and the FERC’s rules and orders.

Interstate Pipelines

The FERC also has jurisdiction over the construction and operation of pipelines and related facilities used in the transportation, storage and sale of natural gas in interstate commerce, including the modification or abandonment of such facilities and rates, charges and terms and conditions of service for the transportation of natural gas in interstate commerce. The FERC was granted expanded market transparency authority under § 23 of the Natural Gas Act (the “NGA”), a section added to the NGA by the Energy Policy Act of 2005. The FERC has adopted additional reporting and internet posting requirements for natural gas pipelines and buyers and sellers of natural gas, including revisions to the FERC Form No. 2 and the new FERC Form 552, an annual report of aggregate volumes of gas sales and purchases at wholesale. The FERC has closed an inquiry into the methodology for rate recovery by natural gas pipelines of fuel and lost and unaccounted-for gas costs and while not taking any action, the FERC expressed its support for an amendment to the NGA that would provide it with the authority to order refunds in connection with its review of interstate pipeline transportation rates.

Rates established for our U.S. interstate natural gas transmission and storage operations at Northern Natural Gas and Kern River are subject to the FERC’s regulatory authority. The rates the FERC authorizes these companies to charge their customers may not be sufficient to cover the costs incurred to provide services in any given period. These pipelines, from time to time, have in effect rate settlements approved by the FERC which prevent them or third parties from modifying rates, except for allowed adjustments, for certain periods. These settlements do not preclude the FERC from initiating a separate proceeding under the NGA to modify the rates. It is not possible to determine at this time whether any such actions would be instituted or what the outcome would be, but such proceedings could result in rate adjustments.

U.K. Electricity Distribution

Northern Electric and Yorkshire Electricity, as holders of electricity distribution licenses, are subject to regulation by GEMA. Most of the revenue of the electricity DNO is controlled by a distribution price control formula set out in the electricity distribution license. The price control formula does not directly constrain profits from year to year, but is a control on revenue that operates independently of most of the DNO’s costs. It has been the practice of Ofgem, to review and reset the formula at five-year intervals, although the formula has been, and may be, reviewed at other times at the discretion of Ofgem. The current five-year cost control period became effective on April 1, 2005. A resetting of the formula requires the consent of the DNO; however, license modifications may be unilaterally imposed by Ofgem without such consent following review by the British competition commission. GEMA is able to impose financial penalties on DNOs who contravene any of their electricity distribution license duties or certain of their duties under British law, or fail to achieve satisfactory performance of individual standards prescribed by GEMA. Any penalty imposed must be reasonable and may not exceed 10% of the DNO’s revenue. During the term of the price control, additional costs have a direct impact on the financial results of Northern Electric and Yorkshire Electricity.

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Through subsidiaries and joint ventures, we are actively pursuing, developing and constructing new or expanded facilities, the completion and expected cost of which is subject to significant risk, and our subsidiaries and joint ventures have significant funding needs related to their planned capital expenditures.

Through subsidiaries and joint ventures, we are continuing to develop and construct new or expanded facilities. We expect that these subsidiaries and joint ventures will incur substantial annual capital expenditures over the next several years. Expenditures could include, among others, amounts for new coal-fired, natural gas, nuclear and wind powered electric generating facilities, electric transmission or distribution projects, environmental control and compliance systems, gas storage facilities, new or expanded pipeline systems, as well as the continued maintenance of the installed asset base.

Development and construction of major facilities are subject to substantial risks, including fluctuations in the price and availability of commodities, manufactured goods, equipment, labor and other items over a multi-year construction period, as well as the economic viability of our suppliers. These risks may result in higher than expected costs to complete an asset and place it in service. Such costs may not be recoverable in the regulated rates or market prices our subsidiaries are able to charge their customers. It is also possible that additional generation needs may be obtained through power purchase agreements, which could increase long-term purchase obligations and force reliance on the operating performance of a third party. The inability to successfully and timely complete a project, avoid unexpected costs or to recover any such costs could adversely affect our financial results.

Furthermore, our subsidiaries and joint ventures depend upon both internal and external sources of liquidity to provide working capital and to fund capital requirements. If we do not provide needed funding to our subsidiaries and joint ventures and the subsidiaries and joint ventures are unable to obtain funding from external sources, they may need to postpone or cancel planned capital expenditures.

Failure to construct these planned projects could limit opportunities for revenue growth, increase operating costs and adversely affect the reliability of electric service to our customers. For example, if PacifiCorp is not able to expand its existing generating facilities it may be required to enter into long-term electricity procurement contracts or procure electricity at more volatile and potentially higher prices in the spot markets to support growing retail loads.

The current disruptions in the financial markets could affect our and our subsidiaries’ ability to obtain debt financing, draw upon or renew existing credit facilities and have other adverse effects on us and our subsidiaries.

The U.S. and global credit markets have experienced historic dislocations and liquidity disruptions that have caused financing to be unavailable in many cases. These circumstances have materially impacted liquidity in the bank and capital debt markets, making financing terms less attractive for borrowers who are able to find financing, and in many cases have resulted in the unavailability of certain types of debt financing. In addition, many large financial institutions have experienced financial difficulties with some unable to survive as independent institutions and others filing for bankruptcy protection. These conditions may continue to impact the number of financial institutions able to provide credit. It is also possible that these financial institutions may not be able to provide previously arranged funding under revolving credit facilities or other arrangements like those that we and our subsidiaries have established as potential sources of liquidity for working capital and to fund capital requirements. For example, several of our revolving credit facility agreements have been reduced due to the Lehman Brothers Holdings Inc. bankruptcy filing in September 2008. Continued uncertainty in the credit markets may negatively impact our and our subsidiaries’ ability to access funds on favorable terms or at all. If we or our subsidiaries were to need to access funds but are unable to do so, that failure could have a material adverse effect on our financial condition and results of operations.

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Our subsidiaries are exposed to credit risk of counterparties with whom they do business and failure of their significant customers to perform under or to renew their contracts, or failure to obtain new customers for expanded capacity, could adversely affect our financial results.

Certain of our subsidiaries are dependent upon a relatively small number of customers for a significant portion of their revenues. For example:

·   a significant portion of our pipeline subsidiaries’ capacity is contracted under long-term agreements, and our pipeline subsidiaries are dependent upon relatively few customers for a substantial portion of their revenues;

·   PacifiCorp and MidAmerican Energy rely on their wholesale customers to fulfill their commitments and pay for energy delivered to them on a timely basis;

·   our U.K. utility electricity distribution businesses are dependent upon a relatively small number of retail suppliers; and

·   generally, a single power purchaser takes energy from each of our non-utility generating facilities.

Adverse economic conditions or other events affecting counterparties with whom our subsidiaries conduct business could impair the ability of these counterparties to pay for services or fulfill their contractual obligations, or cause them to delay or reduce such payments to our subsidiaries. Our subsidiaries depend on these counterparties to remit payments on a timely basis. Some suppliers and customers have been experiencing deteriorating credit quality over the course of 2008, and we continue to monitor these parties to attempt to reduce the impact of any potential counterparty default. Any delay or default in payment or limitation on the subsidiaries to negotiate alternative arrangements could adversely affect our financial results.

Our subsidiaries also have certain long-term arrangements for which if they are unable to renew, remarket, or find replacements, our and their sales volumes and revenues would be exposed to reduction and increased volatility. For example, without the benefit of long-term transportation agreements, we cannot assure that our pipeline subsidiaries will be able to transport gas at efficient capacity levels. Similarly, without long-term power purchase agreements, we cannot assure that our regulated subsidiaries and our unregulated power generators will be able to operate profitably. Failure to maintain existing long-term agreements or secure new long-term agreements could adversely affect our financial results.

The replacement of any existing long-term agreements depends on market conditions and other factors that may be beyond our subsidiaries’ control.

 A significant decrease in demand for natural gas or electricity in the markets served by our subsidiaries’ pipeline and gas distribution systems would significantly decrease our operating revenues and thereby adversely affect our business and financial results.

A sustained decrease in demand for natural gas or electricity in the markets served by our subsidiaries would significantly reduce our operating revenue and adversely affect our financial results. Factors that could lead to a decrease in market demand include, among others:

·   a recession or other adverse economic condition, including the significant adverse changes in the economy and credit markets in 2008 which may continue into future periods, that results in a lower level of economic activity or reduced spending by consumers on natural gas or electricity;

·   an increase in the market price of natural gas or electricity or a decrease in the price of other competing forms of energy;

·   efforts by customers, legislators and regulators to reduce consumption of energy through various conservation and energy efficiency measures and programs;

·   higher fuel taxes or other governmental or regulatory actions that increase, directly or indirectly, the cost of natural gas or the fuel source for electricity generation or that limit the use of natural gas or the generation of electricity from fossil fuels; and

·   a shift to more energy-efficient or alternative fuel machinery or an improvement in fuel economy, whether as a result of technological advances by manufacturers, legislation mandating higher fuel economy or lower emissions, price differentials, incentives or otherwise.

46

Our subsidiaries are subject to market risk, counterparty performance risk and other risks associated with wholesale energy markets.

In general, wholesale market risk is the risk of adverse fluctuations in the market price of wholesale electricity and fuel, including natural gas and coal, which is compounded by volumetric changes affecting the availability of or demand for electricity and fuel. PacifiCorp and MidAmerican Energy purchase electricity and fuel in the open market or pursuant to short-term or variable-priced contracts as part of their normal operating businesses. If market prices rise, especially in a time when larger than expected volumes must be purchased at market or short-term prices, PacifiCorp or MidAmerican Energy may incur significantly greater expense than anticipated. Likewise, if electricity market prices decline in a period when PacifiCorp or MidAmerican Energy is a net seller of electricity in the wholesale market, PacifiCorp or MidAmerican Energy will earn less revenue.

Wholesale electricity prices in PacifiCorp’s service areas are influenced primarily by factors throughout the Western United States relating to supply and demand. Those factors include the adequacy of generating capacity, scheduled and unscheduled outages of generating facilities, hydroelectric generation levels, prices and availability of fuel sources for generation, disruptions or constraints to transmission facilities, weather conditions, economic growth and changes in technology. Volumetric changes are caused by unanticipated changes in generation availability and/or changes in customer loads due to the weather, electricity prices, the economy, regulations or customer behavior. Although PacifiCorp plans for resources to meet its current and expected retail and wholesale load obligations, PacifiCorp is a net buyer of electricity during peak periods and therefore, its energy costs may be adversely impacted by market risk. In addition, PacifiCorp may not be able to timely recover all, if any, of those increased costs unless the state regulators authorize such recovery.

MidAmerican Energy’s total accredited net generating capability exceeds its historical peak load. As a result, in comparison to PacifiCorp, which relies to a significant extent on purchased power to satisfy its peak load, MidAmerican Energy has less exposure to wholesale electricity market price fluctuations. The actual amount of generation capacity available at any time, however, may be less than the accredited capacity due to regulatory restrictions, transmission constraints, contractual commitments to third parties, fuel restrictions and generating units being temporarily out of service for inspection, maintenance, refueling, modifications or other reasons. In such circumstances, MidAmerican Energy may need to purchase energy in the wholesale markets and it may not recover in rates all of the additional costs that may be associated with such purchases. Most of MidAmerican Energy’s electric wholesale sales and purchases take place under market-based pricing allowed by the FERC and are therefore subject to market volatility, including price fluctuations.

PacifiCorp and MidAmerican Energy are also exposed to risks related to performance of contractual obligations by wholesale suppliers and customers. These risks have increased as a result of the current recessionary environment and many companies’ weakened financial condition. Each utility relies on suppliers to deliver commodities, primarily natural gas, coal and electricity, in accordance with short- and long-term contracts. Failure or delay by suppliers to provide these commodities pursuant to existing contracts could disrupt the delivery of electricity and require the utilities to incur additional expenses to meet customer needs. In addition, when these contracts terminate, the utilities may be unable to purchase the commodities on terms equivalent to the terms of current contracts.

PacifiCorp and MidAmerican Energy rely on wholesale customers to take delivery of the energy they have committed to purchase and to pay for the energy on a timely basis. Failure of customers to take delivery may require these subsidiaries to find other customers to take the energy at lower prices than the original customers committed to pay. At certain times of the year, prices paid by PacifiCorp and MidAmerican Energy for energy needed to satisfy their customers’ energy needs may exceed the amounts they receive through rates from these customers. If our wholesale customers are unable to pay us for energy or hedging transactions, it may have a significant adverse impact on our cash flows. If the strategy used to minimize these risk exposures is ineffective or if PacifiCorp’s or MidAmerican Energy’s wholesale customers’ financial condition deteriorates as a result of recent economic conditions causing them to be unable to pay them, significant losses could result.

The deterioration in the credit quality of certain wholesale suppliers and customers of PacifiCorp and MidAmerican Energy as a result of the adverse economic changes experienced in 2008 could have an adverse impact on their ability to perform their contractual obligations and which in turn could have an adverse impact on our financial results.

Inflation and changes in commodity prices and fuel transportation costs may adversely affect our financial results.

Inflation may affect our businesses by increasing both operating and capital costs. As a result of existing rate agreements and competitive price pressures, our subsidiaries may not be able to pass the costs of inflation on to their customers. If our subsidiaries are unable to manage cost increases or pass them on to their customers, our financial results could be adversely affected.

47

Our subsidiaries have a multitude of long-term agreements of varying duration that are material to the operation of their businesses, such as power purchase, coal and gas supply and transportation contracts, and the failure to maintain, renew or replace these agreements on similar terms and conditions could increase our exposure to changes in prices, thereby increasing the volatility of our financial results. For example, each of our electric utilities currently has contracts of varying durations for the supply and transportation of coal for much of their existing generation capacity, although PacifiCorp obtains some of its coal supply from mines owned or leased by it. When these contracts expire or if they are not honored, we may not be able to purchase or transport coal on terms as favorable as the current contracts. We have similar exposures regarding the market price of natural gas. Changes in the cost of coal or natural gas supply and transportation and changes in the relationship between such costs and the market price of power will affect our financial results. Since the sales price we receive for power may not change at the same rate as our coal or natural gas supply and transportation costs, we may be unable to pass on the changes in costs to our customers. In addition, the overall prices we charge our retail customers in some jurisdictions are capped and our fuel recovery mechanisms in other states are frozen for various periods of time or have been eliminated.

Our public utility subsidiaries’ financial results may be adversely affected if they are unable to obtain adequate, reliable and affordable access to transmission service.

Our public utility subsidiaries depend on transmission facilities owned and operated by other utilities to transport electricity and natural gas to both wholesale and retail markets, as well as natural gas purchased to supply some of our subsidiaries’ electric generating facilities. If adequate transmission is unavailable, our subsidiaries may be unable to purchase and sell and deliver products. Such unavailability could also hinder our subsidiaries from providing adequate or economical electricity or natural gas to their wholesale and retail electric and gas customers and could adversely impact their financial results.

The different regional power markets have varying and dynamic regulatory structures, which could affect our businesses’ growth and performance. In addition, the independent system operators who oversee the transmission systems in regional power markets have imposed in the past, and may impose in the future, price limitations and other mechanisms to counter volatility in the power markets. These types of price limitations and other mechanisms may adversely impact the financial results of our utilities.

Our operating results may fluctuate on a seasonal and quarterly basis and may be adversely affected by weather.

The sale of electric power and natural gas are generally seasonal businesses. In most parts of the United States and other markets in which our subsidiaries operate, demand for electricity peaks during the hot summer months when cooling needs are higher. Market prices for electric supply also generally peak at that time. In other areas, demand for electricity peaks during the winter. In addition, demand for gas and other fuels generally peaks during the winter when heating needs are higher. This is especially true in Northern Natural Gas’ market area and MidAmerican Energy’s retail gas business. Further, extreme weather conditions such as heat waves or winter storms could cause these seasonal fluctuations to be more pronounced. Periods of low rainfall or snow-pack may also impact electric generation at PacifiCorp’s hydroelectric systems.

As a result, the overall financial results of our subsidiaries may fluctuate substantially on a seasonal and quarterly basis. We have historically sold less power, and consequently earned less income, when weather conditions are mild. Unusually mild weather in the future may adversely affect our financial results through lower revenues or margins. Conversely, unusually extreme weather conditions could increase our costs to provide power and could adversely affect our financial results. Furthermore, during or following periods of low rainfall or snowpack, PacifiCorp may obtain substantially less electricity from hydroelectric generating facilities and must purchase greater amounts of electricity from the wholesale market or from other sources at market prices. Additionally, both PacifiCorp and MidAmerican Energy have added substantial wind-powered generation capacity which is a climate dependent resource resulting in a variable production output that may at times affect the amount of energy available for sale or purchase. The extent of fluctuation in financial results may change depending on a number of factors related to our subsidiaries’ regulatory environment and contractual agreements, including their ability to recover power costs, the existence of revenue sharing provisions and terms of the power sale contracts.

Our subsidiaries are subject to operating uncertainties that could adversely affect our financial results.

The operation of complex electric and gas utility (including generation, transmission and distribution) systems, pipelines or power generating facilities that are spread over large geographic areas involves many operating uncertainties and events beyond our control. These potential events include the breakdown or failure of power generation equipment, compressors, pipelines, transmission and distribution lines or other equipment or processes, unscheduled generating facility outages, strikes, lockouts or other labor-related actions, shortage of qualified labor, transmission and distribution system constraints or outages, fuel shortages or interruptions, unavailability of critical equipment, materials and supplies, low water flows and other weather-related impacts, performance below expected levels of output, capacity or efficiency, operator error and catastrophic events such as severe storms, fires, earthquakes, explosions or mining accidents. A casualty occurrence might result in injury or loss of life, extensive property damage or environmental damage. Any of these risks or other operational risks could significantly reduce or eliminate our subsidiaries’ revenues or significantly increase their expenses, thereby reducing the availability of distributions to us. For example, if our subsidiaries cannot operate their electric or natural gas facilities at full capacity due to damage caused by a catastrophic event, their revenues could decrease due to decreased sales and their expenses could increase due to the need to obtain energy from more expensive sources. Further, we self-insure many risks and current and future insurance coverage may not be sufficient to replace lost revenue or cover repair and replacement costs. Any reduction of revenues for such reason, or any other reduction of our subsidiaries’ revenues or increase in their expenses resulting from the risks described above could adversely affect our financial results.

48

Potential terrorist activities or military or other actions could adversely affect our financial results.

The continued threat of terrorism since September 11, 2001 and the impact of military and other actions by the United States and its allies has led to increased political, economic and financial market instability and has subjected our subsidiaries’ operations to increased risks. The United States government has issued warnings that energy assets, specifically pipeline, nuclear generation and other electric utility infrastructure are potential targets for terrorist organizations. Political, economic or financial market instability or damage to the operating assets of our subsidiaries, customers or suppliers may result in business interruptions, lost revenue, higher commodity prices, disruption in fuel supplies, lower energy consumption and unstable markets, particularly with respect to natural gas and electric energy, increased security, repair or other costs that may materially adversely affect us and our subsidiaries in ways that cannot be predicted at this time. Any of these risks could materially affect our financial results. Furthermore, instability in the financial markets as a result of terrorism or war could also materially adversely affect our ability and the ability of our subsidiaries to raise capital.

The insurance industry may change to reflect increased instability in the political, economic and financial markets. As a result, insurance covering risks we and our subsidiaries typically insure against may decrease in scope and availability and we may elect to self-insure against many such risks. In addition, the available insurance may have higher deductibles, higher premiums and more restrictive policy terms.

MidAmerican Energy is subject to the unique risks associated with nuclear generation.

The ownership and operation of nuclear power plants, such as MidAmerican Energy’s 25% ownership interest in the Quad Cities Station involves certain risks. These risks include, among other items, mechanical or structural problems, inadequacy or lapses in maintenance protocols, the impairment of reactor operation and safety systems due to human error, the costs of storage, handling and disposal of nuclear materials, limitations on the amounts and types of insurance coverage commercially available, and uncertainties with respect to the technological and financial aspects of decommissioning nuclear facilities at the end of their useful lives. The prolonged unavailability of the Quad Cities Station could materially adversely affect MidAmerican Energy’s financial results, particularly when the cost to produce power at the plant is significantly less than market wholesale power prices. The following are among the more significant of these risks:

·   Operational Risk - Operations at any nuclear power plant could degrade to the point where the plant would have to be shut down. If such degradations were to occur, the process of identifying and correcting the causes of the operational downgrade to return the plant to operation could require significant time and expense, resulting in both lost revenue and increased fuel and purchased power expense to meet supply commitments. Rather than incurring substantial costs to restart the plant, the plant could be shut down. Furthermore, a shut-down or failure at any other nuclear plant could cause regulators to require a shut-down or reduced availability at the Quad Cities Station.

·   Regulatory Risk - The NRC may modify, suspend or revoke licenses and impose civil penalties for failure to comply with the Atomic Energy Act of 1954, as amended, applicable regulations or the terms of the licenses of nuclear facilities. Unless extended, the NRC operating licenses for the Quad Cities Station will expire in 2032. Changes in regulations by the NRC could require a substantial increase in capital expenditures or result in increased operating or decommissioning costs.

·   Nuclear Accident Risk - Accidents and other unforeseen problems have occurred at nuclear facilities other than the Quad Cities Station, both in the United States and elsewhere. The consequences of an accident can be severe and include loss of life and property damage. Any resulting liability from a nuclear accident could exceed MidAmerican Energy’s resources, including insurance coverage.

49

We own investments and projects located in foreign countries that are exposed to increased economic, regulatory and political risks.

We own and may acquire significant energy-related investments and projects outside of the United States. In addition to the current disruption in the global financial markets, the economic, regulatory and political conditions in some of the countries where we have operations or are pursuing investment opportunities may present increased risks related to, among others, inflation, currency exchange rate fluctuations, currency repatriation restrictions, nationalization, renegotiation, privatization, availability of financing on suitable terms, customer creditworthiness, construction delays, business interruption, political instability, civil unrest, guerilla activity, terrorism, expropriation, trade sanctions, contract nullification and changes in law, regulations or tax policy. We may not be capable of either fully insuring against or effectively hedging these risks.

We are exposed to risks related to fluctuations in currency rates.

Our business operations and investments outside the United States increase our risk related to fluctuations in currency rates, primarily the British pound and the Philippine peso. Our principal reporting currency is the United States dollar, and the value of the assets and liabilities, earnings, cash flows and potential distributions from our foreign operations changes with the fluctuations of the currency in which they transact. We may selectively reduce some foreign currency risk by, among other things, requiring contracted amounts be settled in United States dollars, indexing contracts to the United States dollar or hedging through foreign currency derivatives. These efforts, however, may not be effective and could negatively affect our financial results. We attempt, in many circumstances, to structure foreign transactions to provide for payments to be made in, or indexed to, United States dollars or a currency freely convertible into United States dollars. We may not be able to obtain sufficient dollars or other hard currency or available dollars may not be allocated to pay such obligations, which could adversely affect our financial results.

Cyclical fluctuations in the residential real estate brokerage and mortgage businesses could adversely affect HomeServices.

The residential real estate brokerage and mortgage industries tend to experience cycles of greater and lesser activity and profitability and are typically affected by changes in economic conditions, including the current downturn in the U.S. housing market, which are beyond HomeServices’ control. Any of the following are examples of items that could have a material adverse effect on HomeServices’ businesses by causing a general decline in the number of home sales, sale prices or the number of home financings which, in turn, would adversely affect its financial results:

·   rising interest rates or unemployment rates, including the recent significant rise in unemployment in the United States which may continue into future periods;

·   periods of economic slowdown or recession in the markets served, including the significant adverse changes in the economy in 2008 which may continue into future periods;

·   decreasing home affordability;

·   lack of available mortgage credit for potential homebuyers, including the reduced availability of credit generally in 2008 which may continue into future periods;

·   declining demand for residential real estate as an investment;

·   nontraditional sources of new competition; and

·   changes in applicable tax law.

50 

Poor performance of plan and fund investments and other factors impacting pensions, postretirement benefits plans, nuclear decommissioning and mine reclamation costs could unfavorably impact our cash flows and liquidity.

Costs of providing our non-contributory defined benefit pension and postretirement benefits plans depend upon a number of factors, including the rates of return on plan assets, the level and nature of benefits provided, discount rates, the interest rates used to measure required minimum funding levels, changes in benefit design, changes in laws and government regulation and our required or voluntary contributions made to the plans. Some of our pension and postretirement benefits plans are in underfunded positions. The recent declines in the global financial markets have exacerbated these plans’ underfunded positions. Even with sustained growth in the investments over future periods to increase the value of these plans’ assets, we will likely be required to make significant cash contributions to fund these plans. Furthermore, the recently enacted Pension Protection Act of 2006 may result in more volatility in the amount and timing of future contributions. Similarly, funds dedicated to nuclear decommissioning and mine reclamation are also invested in equity and fixed income securities and poor performance of these investments will reduce the amount of funds available for their intended purpose which would require us to make additional cash contributions. Such cash funding obligations, which are also impacted by the other factors described above, could have a material impact on our liquidity by reducing our cash flows.

We and our subsidiaries are involved in numerous legal proceedings, the outcomes of which are uncertain and could adversely affect our financial results.

We and our subsidiaries are party to numerous legal proceedings. Litigation is subject to many uncertainties, and we cannot predict the outcome of individual matters. It is possible that the final resolution of some of the matters in which we and our subsidiaries are involved could result in additional payments in excess of established reserves over an extended period of time and in amounts that could have a material adverse effect on our financial results. Similarly, it is also possible that the terms of resolution could require that we or our subsidiaries change business practices and procedures, which could also have a material adverse effect on our financial results. Further, litigation could result in the imposition of financial penalties or injunctions which could limit our ability to take certain desired actions or the denial of needed permits, licenses or regulatory authority to conduct our business, including the siting or permitting of facilities. Any of these outcomes could adversely affect our financial results.

Potential changes in accounting standards might cause us to revise our financial results and disclosure in the future, which may change the way analysts measure our business or financial performance.

Accounting irregularities discovered in the past few years in various industries have caused regulators and legislators to take a renewed look at accounting practices, financial disclosures and companies’ relationships with their independent auditors. Because it is still unclear what laws or regulations will ultimately develop, we cannot predict the ultimate impact of any future changes in accounting regulations or practices in general with respect to public companies or the energy industry or in our operations specifically. In addition, the Financial Accounting Standards Board (“FASB”), the FERC or the SEC could enact new or revised accounting standards or FERC orders that might impact how we are required to record revenues, expenses, assets and liabilities.

Item 1B. Unresolved Staff Comments

Not applicable.

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Item 2. Properties

The Company’s energy properties consist of the physical assets necessary to generate, transmit, store, distribute and supply energy and consist mainly of electric generation, transmission and distribution facilities, gas distribution facilities, natural gas pipelines, storage facilities, compressor stations and meter stations, along with the related rights-of-way. It is the opinion of the Company’s management that the principal depreciable properties owned by the Company are in good operating condition and are well maintained. Pursuant to separate financing agreements, substantially all or most of the properties of each of the Company’s subsidiaries (except CE Electric UK, MidAmerican Energy and Northern Natural Gas) are pledged or encumbered to support or otherwise provide the security for their own subsidiary debt. For additional information regarding the Company’s energy properties, refer to Item 1 of this Form 10-K and Notes 4, 5 and 23 of Notes to Consolidated Financial Statements included in Item 8 of this Form 10-K.

The right to construct and operate the Company’s electric transmission and distribution facilities and pipelines across certain property was obtained in most circumstances through negotiations and, where necessary, through the exercise of the power of eminent domain. PacifiCorp, MidAmerican Energy, Northern Natural Gas and Kern River in the United States and Northern Electric and Yorkshire Electricity in the United Kingdom continue to have the power of eminent domain in each of the jurisdictions in which they operate their respective facilities, but the United States utilities do not have the power of eminent domain with respect to Native American tribal lands. Although the main Kern River pipeline crosses the Moapa Indian Reservation, all facilities in the Moapa Indian Reservation are located within a utility corridor that is reserved to the United States Department of Interior, Bureau of Land Management.

With respect to real property, each of the electric transmission and distribution facilities and pipelines fall into two basic categories: (1) parcels that are owned in fee, such as certain of the generation stations, electric substations, compressor stations, measurement stations and office sites; and (2) parcels where the interest derives from leases, easements, rights-of-way, permits or licenses from landowners or governmental authorities permitting the use of such land for the construction, operation and maintenance of the electric transmission and distribution facilities and pipelines. The Company believes that each of its energy subsidiaries have satisfactory title to all of the real property making up their respective facilities in all material respects.

Item 3. Legal Proceedings

In addition to the proceedings described below, the Company is currently party to various items of litigation or arbitration in the normal course of business, none of which are reasonably expected by the Company to have a material adverse effect on its consolidated financial results.

Regulated Utility Companies

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.

52 

Independent Power Projects

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 NIA 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 was 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, which are also being litigated. The remaining issues are fully briefed and pending before the court. 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 October 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.

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

Not applicable.

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PART II

Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

MEHC’s common stock is owned by Berkshire Hathaway, Mr. Walter Scott, Jr. and certain of his family members and family controlled trusts and corporations, and Mr. Gregory E. Abel, its President and Chief Executive Officer, and has not been registered with the SEC pursuant to the Securities Act of 1933, as amended, listed on a stock exchange or otherwise publicly held or traded. MEHC has not declared or paid any cash dividends on its common stock during the last two fiscal years and does not presently anticipate that it will declare any dividends on its common stock in the foreseeable future.

For a discussion of regulatory restrictions that limit PacifiCorp’s and MidAmerican Energy’s ability to pay dividends on their common stock to MEHC, refer to Note 19 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K.

Item 6. Selected Financial Data

The following table sets forth the Company’s selected consolidated historical financial data, which should be read in conjunction with the information included in Item 7 of this Form 10-K and with the Company’s historical Consolidated Financial Statements and notes thereto included in Item 8 of this Form 10-K. The selected consolidated historical financial data has been derived from the Company’s audited historical Consolidated Financial Statements and notes thereto (in millions).

	Years Ended December 31,
	2008		2007		2006(1)		2005		2004
Consolidated Statement of Operations Data:
Operating revenue	$	12,668	$	12,376	$	10,301	$	7,116	$	6,553
Income from continuing operations(2)		1,850		1,189		916		558		538
Income (loss) from discontinued operations, net of tax(3)		-		-		-		5		(368	)
Net income(2)		1,850		1,189		916		563		170
	As of December 31,
	2008		2007		2006(1)		2005		2004
Consolidated Balance Sheet Data:
Total assets	$	41,441	$	39,216	$	36,447	$	20,371	$	19,904
MEHC senior debt(4)		5,121		5,471		4,479		2,776		3,032
MEHC subordinated debt(4)		1,321		1,125		1,357		1,588		1,775
Subsidiary debt(4)		12,954		13,097		11,614		7,150		7,191
Preferred securities of subsidiaries		128		128		128		88		90
Total shareholders’ equity		10,207		9,326		8,011		3,385		2,971

(1)	Reflects the acquisition of PacifiCorp on March 21, 2006.
(2)	Reflects the $646 million after-tax gain recognized on the termination of the Constellation Energy Merger Agreement on December 17, 2008.
(3)	Reflects MEHC’s decision to cease operations of the Zinc Recovery Project effective September 10, 2004, which resulted in a non-cash, after-tax impairment charge of $340 million being recorded to write-off the Zinc Recovery Project, rights to quantities of extractable minerals, and allocated goodwill (collectively, the “Mineral Assets”).
(4)	Includes current portion.

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Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following is management’s discussion and analysis of certain significant factors that have affected the financial condition and results of operations of 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 Item 6 of this Form 10-K and with the Company’s historical Consolidated Financial Statements and the notes thereto included in Item 8 of this Form 10-K. The Company’s actual results in the future could differ significantly from the historical results.

Results of Operations

Overview

Net income for 2008 was $1.85 billion, an increase of $661 million, or 56%, compared to 2007, which included after-tax benefits totaling $646 million related to the termination fee and profit from our $1.0 billion investment in Constellation Energy. Excluding the $646 million, net income increased $15 million, or 1%, from the comparable period in 2007. Net income was impacted by favorable operating results at Northern Natural Gas, MidAmerican Energy and PacifiCorp, $30 million of after-tax gains on the sale of non-strategic assets at Northern Natural Gas and favorable changes in Kern River’s current rate proceeding estimate. Net income was unfavorably impacted by lower earnings at HomeServices due to the continuing weak United States housing market and at Kern River due to lower revenue from less favorable market conditions. Net income was also lower in 2008 compared to 2007 due to the impact of the foreign currency exchange rate of $25 million, the transfer of two geothermal projects to the Philippine government in July 2007, a $58 million deferred income tax benefit recognized in 2007 as a result of the reduction in the United Kingdom corporate income tax rate from 30% to 28% and higher taxes on foreign earnings in 2008.

Net income for 2007 was $1.19 billion, an increase of $273 million, or 30%, compared to 2006. PacifiCorp, which was acquired on March 21, 2006, contributed an additional $235 million of net income in 2007 compared to 2006. Also contributing to the increase in net income were favorable operating results at the Company’s other domestic energy businesses, largely as a result of improved margins from favorable market conditions and additional generation assets being placed in service, a $58 million deferred income tax benefit recognized in the United Kingdom and the favorable impact from the foreign currency exchange rate. Net income decreased due to lower earnings at the Company’s foreign energy businesses, which included the transfer of the Upper Mahiao project in June 2006 and the Malitbog and Mahanagdong projects in July 2007 to the Philippine government, lower earnings at HomeServices due to the general slowdown in the United States housing market, $73 million of after tax gains on sales of available-for-sale securities in 2006 and higher interest expense as a result of debt issuances at MEHC and the domestic energy businesses.

Segment Results

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

55 

A comparison of operating revenue and operating income for the Company’s reportable segments for the years ended December 31 follows (in millions):

	2008			2007			Change					2007			2006			Change
Operating revenue:
PacifiCorp	$	4,498		$	4,258		$	240		6	%	$	4,258		$	2,939		$	1,319		45	%
MidAmerican Funding		4,715			4,267			448		10			4,267			3,453			814		24
Northern Natural Gas		769			664			105		16			664			634			30		5
Kern River		443			404			39		10			404			325			79		24
CE Electric UK		993			1,079			(86	)	(8	)		1,079			928			151		16
CalEnergy Generation-Foreign		138			220			(82	)	(37	)		220			336			(116	)	(35	)
CalEnergy Generation-Domestic		30			32			(2	)	(6	)		32			32			-		-
HomeServices		1,133			1,500			(367	)	(24	)		1,500			1,702			(202	)	(12	)
Corporate/other		(51	)		(48	)		(3	)	(6	)		(48	)		(48	)		-		-
Total operating revenue	$	12,668		$	12,376		$	292		2		$	12,376		$	10,301		$	2,075		20
Operating income:
PacifiCorp	$	952		$	917		$	35		4	%	$	917		$	528		$	389		74	%
MidAmerican Funding		590			514			76		15			514			421			93		22
Northern Natural Gas		457			308			149		48			308			269			39		14
Kern River		305			277			28		10			277			217			60		28
CE Electric UK		514			555			(41	)	(7	)		555			516			39		8
CalEnergy Generation-Foreign		103			142			(39	)	(27	)		142			230			(88	)	(38	)
CalEnergy Generation-Domestic		15			12			3		25			12			14			(2	)	(14	)
HomeServices		(58	)		33			(91	)	*			33			55			(22	)	(40	)
Corporate/other		(50	)		(70	)		20		29			(70	)		(130	)		60		46
Total operating income	$	2,828		$	2,688		$	140		5		$	2,688		$	2,120		$	568		27

* Not meaningful

PacifiCorp

Operating revenue increased $240 million for 2008 compared to 2007. Retail revenue increased $198 million due to higher prices approved by regulators of $129 million to recover increased costs due to assets placed in service and higher net power costs. Retail volumes increased 2% due to growth in the average number of residential and commercial customers and higher customer usage totaling $69 million. Wholesale and other revenue increased $42 million due to higher average wholesale prices, partially offset by lower wholesale volumes, and higher contract prices for transmission services. Overall, sales volumes were relatively flat for 2008 compared to 2007.

Operating income increased $35 million for 2008 compared to 2007. The higher revenue was partially offset by higher energy costs and operating expenses, partially offset by lower depreciation and amortization expense. The increase in energy costs consisted of the following (in millions):

	Increase
	(Decrease)
Energy costs:
Cost of natural gas, coal and other fuel	$	180
Purchased electricity		(5	)
Changes in the fair value of energy purchase contracts accounted for as derivatives		7
Transmission and other		15
	$	197

56 

The cost of fuel increased due to higher average prices for both natural gas and coal. The addition of the Lake Side plant in 2007, the Chehalis plant acquired in 2008 and other sources of owned generation resulted in lower volumes of purchased electricity, which was largely offset by higher average unit costs of purchased electricity. Transmission and other costs were higher due to new transmission contracts.

Operating expenses increased by $14 million due to higher levels of assessable property from new owned generation placed in service and increased spending on demand-side management projects, which are recovered in rates. Depreciation and amortization expense decreased by $6 million due to a recent depreciation study, substantially offset by new generation placed in service.

On March 21, 2006, MEHC acquired 100% of the common stock of PacifiCorp. Operating revenue for 2007 and 2006 consisted of retail revenue of $3.25 billion and $2.33 billion, respectively, and wholesale and other revenue of $1.01 billion and $610 million, respectively. PacifiCorp’s operating income was favorably impacted by higher retail revenues as a result of higher prices approved by regulators as well as continued growth in the number of customers and usage, higher net margins on wholesale activities due to higher average prices on sales and lower purchased electricity volumes and lower employee expense. These improvements were partially offset by higher fuel costs due to increased volumes of natural gas consumed in PacifiCorp’s generation plants and higher prices for coal, natural gas and purchased electricity.

MidAmerican Funding

MidAmerican Funding’s operating revenue and operating income for the years ended December 31 are summarized as follows (in millions):

	2008		2007		Change					2007		2006		Change
Operating revenue:
Regulated electric	$	2,030	$	1,934	$	96		5	%	$	1,934	$	1,779	$	155	9	%
Regulated natural gas		1,377		1,174		203		17			1,174		1,112		62	6
Nonregulated and other		1,308		1,159		149		13			1,159		562		597	106
Total operating revenue	$	4,715	$	4,267	$	448		10		$	4,267	$	3,453	$	814	24
Operating income:
Regulated electric	$	470	$	398	$	72		18	%	$	398	$	372	$	26	7	%
Regulated natural gas		66		53		13		25			53		36		17	47
Nonregulated and other		54		63		(9	)	(14	)		63		13		50	385
Total operating income	$	590	$	514	$	76		15		$	514	$	421	$	93	22

Regulated electric revenue increased $96 million for 2008 compared to 2007. Wholesale revenue increased $101 million due to a 20% increase in volumes resulting from increased generation available from the addition of owned generation and scheduled outages in 2007, partially offset by lower average wholesale prices. Retail revenue decreased $6 million due to lower sales volumes to residential customers resulting from the mild temperatures experienced in the service territory during the 2008 cooling season, partially offset by an increase in the average number of retail customers. Total sales volumes increased 7% for 2008 compared to 2007. Regulated electric operating income increased $72 million for 2008 compared to 2007 due to higher wholesale volumes resulting from the availability of lower-cost base load generation and a lower average price for purchased power, partially offset by an increase in depreciation and amortization as a result of Walter Scott Energy Center Unit 4 (“WSEC Unit 4”) being placed in service in June 2007 and new wind-powered generating facilities being placed in service during 2007 and 2008, partially offset by a decrease in regulatory expense related to revenue sharing in connection with the lower Iowa electric equity returns and higher maintenance costs.

Regulated natural gas revenue increased $203 million for 2008 compared to 2007 due primarily to a higher average per-unit cost of gas sold, which was passed on to customers, and higher retail sales volumes of 12% as a result of colder temperatures, partially offset by lower wholesale sales volumes. Regulated natural gas operating income increased $13 million due to the higher retail sales volumes.

Nonregulated and other revenue increased $149 million for 2008 compared to 2007 due primarily to higher gas revenue as a result of higher average prices and a 9% increase in volumes. Nonregulated and other operating income decreased $9 million due primarily to lower margins on electric retail sales due to higher average prices and a 7% decrease in volumes.

57

Regulated electric revenue increased $155 million for 2007 compared to 2006. Wholesale revenue increased $103 million due to higher sales volumes, as a result of new generating assets placed in service during 2007 and improved market opportunities, and prices. Retail revenue increased $52 million due to growth in retail demand, an increase in the average number of retail customers and favorable weather conditions in 2007. Regulated electric operating income increased $26 million for 2007 compared to 2006 as a result of higher gross margins of $86 million from both retail and wholesale sales and lower depreciation and amortization of $7 million, partially offset by higher operating expenses of $67 million. Depreciation and amortization was lower in 2007 due to a $25 million decrease in regulatory expense related to a revenue sharing arrangement in Iowa as a result of lower Iowa electric equity returns, partially offset by higher depreciation as a result of new generation assets placed in service in 2007. Operating expenses were higher due to maintenance costs incurred for restoration of facilities damaged by storms, new generation assets placed in service during 2007 and the timing of maintenance for natural gas-fueled generating facilities.

Regulated natural gas revenue increased $62 million for 2007 compared to 2006 due to higher retail sales volumes of 11% and an increase in the average per-unit cost of gas sold, which was passed on to customers, partially offset by lower wholesale sales volumes. Regulated natural gas operating income increased $17 million due to higher gross margins on the revenue increases.

Nonregulated and other revenue increased $597 million for 2007 compared to 2006 due to increases in electric retail sales volumes and prices driven by improved market opportunities, partially offset by decreases in gas sales volumes and prices. Nonregulated and other operating income increased $50 million due to higher gross margins on the revenue increases.

Northern Natural Gas

Operating revenue increased $105 million for 2008 compared to 2007 due primarily to higher transportation revenue of $88 million due to stronger market conditions and the additional capacity available as a result of the Northern Lights expansion project and higher storage revenue of $12 million due to an expansion of its Redfield storage facilities and higher interruptible storage activity. Operating income increased $149 million for 2008 compared to 2007 due to the higher transportation and storage revenues and pre-tax gains on the sale of non-strategic assets of $50 million in 2008.

Operating revenue increased $30 million for 2007 compared to 2006 due to higher transportation and storage revenues of $47 million on higher rates and volumes from favorable market conditions, partially offset by lower volumes of gas and condensate liquids sales of $17 million, which are both utilized in the operation and balancing of the pipeline system. Operating income increased $39 million for 2007 compared to 2006 due primarily to the increase in transportation and storage revenues, partially offset by a $6 million asset impairment charge.

Kern River

Operating revenue increased $39 million for 2008 compared to 2007 due to an increase of $55 million related to Kern River’s current rate proceeding estimate, partially offset by $20 million of lower revenue as a result of strong market conditions in 2007. Operating income increased $28 million for 2008 compared to 2007 due to the higher revenue, partially offset by a $6 million sales and use tax refund received in 2007 and higher depreciation.

Operating revenue increased $79 million for 2007 compared to 2006. Kern River earned higher revenue as a result of more favorable market conditions in 2007. Additionally, Kern River received a FERC order in 2006 that resulted in a $34 million reduction to operating revenue for rate case estimated refunds. Operating income increased $60 million for 2007 compared to 2006 due primarily to the increase in revenue. The $34 million decrease in revenue related to the FERC order received in 2006 was largely offset by a corresponding $28 million adjustment that also lowered depreciation and amortization expense. Also contributing to the increase in operating income for 2007 compared to 2006 was $8 million of lower depreciation and amortization expense due mainly to changes in the expected depreciation rates in connection with the current rate proceeding and a $6 million sales and use tax refund received in 2007.

58 

CE Electric UK

Operating revenue decreased $86 million for 2008 compared to 2007 due to the impact of the foreign currency exchange rate of $83 million and lower contracting activity of $22 million, partially offset by higher distribution revenue of $11 million and higher gas production at CE Gas of $8 million. Operating income decreased $41 million for 2008 compared to 2007 due primarily to the impact of the foreign currency exchange rate. A non-recurring gain of $17 million realized in 2007 on the sale of certain CE Gas assets was mostly offset by higher gross margins on distribution and gas production revenues in 2008.

Operating revenue increased $151 million for 2007 compared to 2006 due primarily to a $79 million favorable impact from the foreign currency exchange rate, higher distribution revenue of $33 million, due primarily to tariff increases, and higher revenue of $32 million at CE Gas from higher gas production. Operating income increased $39 million for 2007 compared to 2006 due primarily to higher gross margins on distribution and gas production revenues totaling $60 million and the favorable impact from the foreign currency exchange rate of $43 million, partially offset by higher costs and expenses of $62 million. Costs and expenses were higher for 2007 due primarily to higher depreciation and amortization expense of $37 million primarily associated with distribution assets, higher distribution costs of $18 million due mainly to higher maintenance and restoration costs, and the write-off of an unsuccessful exploration well at CE Gas, partially offset by a realized gain on the sale of certain CE Gas assets in 2007.

CalEnergy Generation-Foreign

Operating revenue decreased $82 million for 2008 compared to 2007 due to the transfer of the Malitbog and Mahanagdong projects on July 25, 2007 to the Philippine government, which reduced operating revenue by $95 million, partially offset by higher operating revenue of $13 million at the Casecnan project principally on higher variable energy fees earned on increased generation from higher water flows. Operating income decreased $39 million for 2008 compared to 2007 due to the lower revenue, partially offset by lower operating expense of $13 million and lower depreciation and amortization of $30 million as the projects were transferred.

Operating revenue decreased $116 million for 2007 compared to 2006 as the Malitbog and Mahanagdong projects were transferred on July 25, 2007, and the Upper Mahiao project was transferred on June 25, 2006, to the Philippine government, which reduced operating revenue by $92 million. Additionally, operating revenue at the Casecnan project was lower by $24 million as a result of lower water flows and related energy production. Operating income decreased $88 million for 2007 compared to 2006 due to the lower revenue, partially offset by lower depreciation and amortization expense of $30 million as the projects were transferred.

HomeServices

Operating revenue decreased $367 million for 2008 compared to 2007. Brokerage transactions declined by 20% and the average home sales price declined by 8% reflecting the continuing weak United States housing market. HomeServices had an operating loss of $58 million in 2008, a $91 million decrease compared to 2007 due to the lower revenue and $39 million of expenses taken in 2008 related to office closures, partially offset by lower commissions and operating expenses.

Operating revenue decreased $202 million for 2007 compared to 2006. Brokerage transactions declined by 15%, while the average home sales price increased by 3%. Operating income decreased $22 million due to the lower revenue, partially offset by lower commissions, operating expenses and depreciation and amortization expense.

59 

Consolidated Other Income and Expense Items

Interest Expense

Interest expense for the years ended December 31 is summarized as follows (in millions):

	2008		2007		Change					2007		2006		Change
Subsidiary debt	$	850	$	858	$	(8	)	(1	)%	$	858	$	722	$	136		19	%
MEHC senior debt and other		348		326		22		7			326		269		57		21
MEHC subordinated debt-Berkshire		111		108		3		3			108		134		(26	)	(19	)
MEHC subordinated debt-other		24		28		(4	)	(14	)		28		27		1		4
Total interest expense	$	1,333	$	1,320	$	13		1		$	1,320	$	1,152	$	168		15

Interest expense increased $13 million for 2008 compared to 2007 due to debt issuances at domestic energy businesses and at MEHC, including the issuance of $1 billion of 11% mandatory redeemable preferred securities to affiliates of Berkshire Hathaway in September 2008 in connection with the purchase of the CEG 8% Preferred Stock, partially offset by the impact of the foreign currency exchange rate of $17 million, debt retirements and scheduled principal repayments.

Interest expense increased $168 million for 2007 compared to 2006 due to the acquisition of PacifiCorp, debt issuances at domestic energy businesses and at MEHC, and the higher exchange rate. Interest expense was higher by $90 million in 2007 as a result of the acquisition of PacifiCorp. The increase in interest expense for 2007 was partially offset by debt retirements and scheduled principal repayments.

Other Income, Net

Other income, net for the years ended December 31 is summarized as follows (in millions):

	2008		2007		Change					2007		2006		Change
Capitalized interest	$	54	$	54	$	-		-	%	$	54	$	40	$	14		35	%
Interest and dividend income		75		105		(30	)	(29	)		105		73		32		44
Other, net		1,188		112		1,076		*			112		226		(114	)	(50	)
Total other income, net	$	1,317	$	271	$	1,046		*		$	271	$	339	$	(68	)	(20	)

* Not meaningful

Other, net increased $1.08 billion due to the termination of the merger agreement with Constellation Energy, which resulted in the receipt of a $175 million termination fee and the conversion of the CEG 8% Preferred Stock into $418 million of cash and 19.9 million shares of Constellation Energy common stock valued at $499 million. Other, net decreased $114 million for 2007 compared to 2006. Other, net for 2006 included Kern River’s $89 million of gains from the sale of Mirant stock and $47 million of gains at MidAmerican Funding from the sales of other non-strategic investments. Partially offsetting the decrease for 2007 compared to 2006 was higher equity allowance for funds used during construction (“AFUDC”) of $28 million due to increased levels of capital project expenditures.

Interest and dividend income decreased $30 million for 2008 compared to 2007 due to the maturities of guaranteed investment contracts in December 2007 and February 2008 that were used to retire debt maturing at CE Electric UK and lower average cash balances and interest rates, partially offset by dividends received from the CEG 8% Preferred Stock. Interest and dividend income increased $32 million for 2007 compared to 2006 due primarily to more favorable cash positions at MEHC and certain subsidiaries as a result of 2007 debt issuances as well as $9 million resulting from the acquisition of PacifiCorp.

Capitalized interest increased $14 million for 2007 compared to 2006 due primarily to the acquisition of PacifiCorp and increased levels of capital project expenditures at MidAmerican Energy.

60 

Income Tax Expense

Income tax expense increased $526 million, or 115%, for 2008 compared to 2007. The effective tax rates were 35% and 28% for 2008 and 2007, respectively. The increases in income tax expense and the effective tax rate were due to higher pre-tax income, the recognition of $58 million of deferred income tax benefits in 2007 due to a reduction in the United Kingdom corporate income tax rate from 30% to 28% and higher United States taxes on foreign earnings, partially offset by the benefit of additional production tax credits.

Income tax expense increased $49 million, or 12%, for 2007 compared to 2006. The effective tax rates were 28% and 31% for 2007 and 2006, respectively. The increase in income tax expense is due primarily to higher pretax earnings, partially offset by the recognition of $58 million of deferred income tax benefits due to a reduction in the United Kingdom corporate income tax rate from 30% to 28%. Adjusting for the effect of the change in the United Kingdom corporate income tax rate, the 2007 effective tax rate was 31%.

Minority Interest and Preferred Dividends of Subsidiaries

Minority interest and preferred dividends of subsidiaries decreased $9 million to $21 million for 2008 compared to 2007 due to additional expense in 2007 related to the minority ownership of the Casecnan project.

Equity Income

Equity income increased $5 million to $41 million for 2008 compared to 2007 and decreased $7 million to $36 million for 2007 compared to 2006 due primarily to the sale and write-off of an investment in a mortgage joint venture at HomeServices in 2007.

Liquidity and Capital Resources

Each of MEHC’s direct and indirect subsidiaries is organized as a legal entity separate and apart from MEHC and its other subsidiaries. Pursuant to separate financing agreements, the assets of each subsidiary may be pledged or encumbered to support or otherwise provide the security for its own subsidiary debt. It should not be assumed that any asset of any subsidiary of MEHC’s will be available to satisfy the obligations of MEHC or any of its other subsidiaries’ obligations. However, unrestricted cash or other assets which are available for distribution may, subject to applicable law, regulatory commitments and the terms of financing and ring-fencing arrangements for such parties, be advanced, loaned, paid as dividends or otherwise distributed or contributed to MEHC or affiliates thereof. Refer to Note 19 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for further discussion regarding the limitation of distributions from MEHC’s subsidiaries.

61 

As of December 31, 2008, the Company’s total net liquidity available was $5.8 billion. The components of total net liquidity available are as follows (in millions):

										Other
							MidAmerican			Reporting
	MEHC			PacifiCorp			Funding			Segments			Total(1)
Cash and cash equivalents	$	6		$	59		$	10		$	205		$	280
Available revolving credit facilities	$	835		$	1,395		$	904		$	271		$	3,405
Less:
Short-term borrowings and issuance of commercial paper		(216	)		(85	)		(457	)		(78	)		(836	)
Tax-exempt bond support, letters of credit and other		(43	)		(258	)		(195	)		(94	)		(590	)
Net revolving credit facilities available	$	576		$	1,052		$	252		$	99		$	1,979
Net liquidity available before Berkshire Equity Commitment	$	582		$	1,111		$	262		$	304		$	2,259
Berkshire Equity Commitment(2)		3,500												3,500
Total net liquidity available	$	4,082											$	5,759
Unsecured revolving credit facilities:
Maturity date(3)		2009, 2013			2012, 2013			2009, 2013		2010
Largest single bank commitment as a % of total(4)		30	%		15	%		36	%		27	%

(1)	The above table does not include unused revolving credit facilities and letters of credit for investments that are accounted for under the equity method. As of December 31, 2008, the Company’s pro rata share of unsecured revolving credit facilities was $126 million and the Company’s pro rata share of available unsecured revolving credit facilities was $105 million.
(2)	On March 1, 2006, MEHC and Berkshire Hathaway entered into the Berkshire Equity Commitment pursuant to which Berkshire Hathaway has agreed to purchase up to $3.5 billion of MEHC’s common equity upon any requests authorized from time to time by MEHC’s Board of Directors.The proceeds of any such equity contribution shall only be used for the purpose of (i) paying when due MEHC’s debt obligations and (ii) funding the general corporate purposes and capital requirements of MEHC’s regulated subsidiaries. The Berkshire Equity Commitment expires on February 28, 2011.
(3)	MEHC and MidAmerican Energy each have a $250 million credit facility expiring in 2009. For further discussion regarding the Company’s credit facilities, refer to Note 10 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K.
(4)	An inability of financial institutions to honor their commitments could adversely affect the Company’s short-term liquidity and ability to meet long-term commitments.

The Company’s cash and cash equivalents were $280 million as of December 31, 2008, compared to $1.18 billion as of December 31, 2007. The Company recorded separately in other current assets, restricted cash and investments as of December 31, 2008 and 2007 of $85 million and $73 million, respectively. The restricted cash and investments balance is mainly composed of current amounts deposited in restricted accounts relating to (i) the Company’s debt service reserve requirements relating to certain projects, (ii) trust funds related to 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. Additionally, the Company has restricted cash and investments recorded in deferred charges, investments and other of $310 million and $425 million as of December 31, 2008 and 2007, respectively, that principally relate to trust funds held for nuclear decommissioning and mine reclamation costs.

Cash Flows from Operating Activities

Cash flows generated from operations for the years ended December 31, 2008 and 2007 were $2.59 billion and $2.34 billion, respectively. The increase was mainly due to higher customer collections, lower income taxes paid, mainly due to benefits from federal bonus depreciation, and the termination fee received from Constellation Energy, partially offset by higher fuel costs, the timing of payments, greater disbursements for interest, higher net margin deposits and the transfer in 2007 of two geothermal projects to the Philippine government.

62 

Cash Flows from Investing Activities

Cash flows used in investing activities for the years ended December 31, 2008 and 2007 were $4.34 billion and $3.25 billion, respectively. In September 2008, the Company made a $1 billion investment in CEG 8% Preferred Stock and also acquired Chehalis Power Generation, LLC for $308 million. In December 2008, upon termination of the Merger Agreement with Constellation Energy, the Company converted the CEG 8% Preferred Stock into $1 billion of 14% Senior Notes due from Constellation Energy, 19.9 million shares of Constellation Energy common stock and cash totaling $418 million. Refer to Notes 3 and 8 of Notes to Consolidated Financial Statements included in Item 8 of this Form 10-K for further discussion regarding these transactions. In February 2008 and December 2007, the Company received proceeds from the maturity of guaranteed investment contracts of $393 million and $201 million, respectively. Capital expenditures increased $425 million due primarily to higher capital expenditures associated with the construction of additional wind-powered generation, partially offset by significant generation placed in-service in 2007 described below.

Capital Expenditures

Capital expenditures by reportable segment for the years ended December 31 are summarized as follows (in millions):

	2008		2007
Capital expenditures*:
PacifiCorp	$	1,789	$	1,518
MidAmerican Energy		1,473		1,300
Northern Natural Gas		196		225
CE Electric UK		440		422
Other reportable segments and corporate/other		39		47
Total capital expenditures	$	3,937	$	3,512

* Excludes amounts for non-cash equity AFUDC.

Capital expenditures consisted mainly of the following:

In 2008:

·   Combined, PacifiCorp and MidAmerican Energy spent $1.81 billion during 2008 on wind-powered generation. During 2008, 1,005 MW (nameplate ratings) were placed in service, with an additional 237 MW (nameplate ratings) that are expected to be placed in service during 2009.

·   Combined, PacifiCorp and MidAmerican Energy spent $287 million on emissions control equipment.

·   PacifiCorp spent $130 million for transmission system expansion and upgrades.

·   Projects mainly for distribution, transmission, generation, mining and other infrastructure needed to serve existing and growing demand.

In 2007:

·   MidAmerican Energy completed construction of the Walter Scott, Jr. Energy Center Unit No. 4, a 800-MW supercritical, coal-fired generating plant in June 2007 at a total cost of $776 million.

·   PacifiCorp completed construction of the Lake Side plant, a 548-MW combined cycle, natural gas-fired generating plant in September 2007 at a total cost of $326 million.

·   Combined, PacifiCorp and MidAmerican Energy placed 341 MW of wind-powered generating facilities in service and began construction of an additional 923 MW of wind-powered generating facilities in 2007 with costs totaling $1.14 billion.

·   Combined, PacifiCorp and MidAmerican Energy spent $277 million on emissions control equipment.

·   Northern Natural Gas spent $151 million on its Northern Lights Expansion project.

·   Projects mainly for distribution, transmission, generation, mining and other infrastructure needed to serve existing and growing demand.

63

Cash Flows from Financing Activities

Cash flows generated from financing activities for the year ended December 31, 2008 were $866 million. Sources of cash totaled $3.87 billion and consisted mainly of proceeds from the issuance of MEHC senior and subordinated debt totaling $1.65 billion, proceeds from the issuance of subsidiary debt totaling $1.5 billion, the net proceeds from subsidiary short-term debt totaling $509 million and the net proceeds from MEHC’s revolving credit facility totaling $216 million. Uses of cash totaled $3.01 billion and consisted mainly of repayments of MEHC senior and subordinated debt totaling $1.8 billion, repayments of subsidiary debt totaling $1.08 billion and a $99 million payment of hedging instruments related to the maturity of United States dollar denominated debt at CE Electric UK.

Cash flows from financing activities for the year ended December 31, 2007 were $1.75 billion. Sources of cash totaled $3.55 billion and consisted primarily of proceeds from the issuance of subsidiary debt totaling $2 billion and proceeds from the issuance of MEHC senior debt totaling $1.54 billion. Uses of cash totaled $1.8 billion and consisted primarily of repayments of MEHC senior and subordinated debt totaling $784 million, repayments of subsidiary debt totaling $549 million, net repayments of subsidiary short-term debt totaling $269 million and net repayments of MEHC’s revolving credit facility totaling $152 million.

Short-term Debt and Revolving Credit Facilities

MEHC had outstanding borrowings of $216 million under its unsecured revolving credit facilities as of December 31, 2008 and no outstanding borrowings as of December 31, 2007. Borrowings by MEHC’s subsidiaries under their commercial paper programs and unsecured revolving credit facilities increased $490 million during 2008 due mainly to an $85 million increase at PacifiCorp and a $371 million increase at MidAmerican Funding due mainly to capital expenditures and scheduled debt maturities, partially offset by net cash from operating activities. Continued disruptions in the credit markets may result in increased costs of commercial paper and limit the ability of PacifiCorp and MidAmerican Funding to issue commercial paper, which may lead to a higher reliance on their respective unsecured revolving credit facilities and the related financial institutions for short-term liquidity purposes.

2008 Long-term Debt Transactions and Agreements

In addition to the debt issuances discussed herein, MEHC and its subsidiaries made scheduled repayments on and purchases of MEHC senior and subordinated debt and subsidiary debt totaling $3.23 billion during the year ended December 31, 2008.

·   On September 19, 2008, a wholly-owned subsidiary trust of MEHC issued $1.0 billion of 11% mandatory redeemable preferred securities to affiliates of Berkshire Hathaway due in August 2015 and MEHC issued $1.0 billion of 11% subordinated debt to the trust. The proceeds were used to purchase a $1.0 billion investment in CEG 8% Preferred Stock.

·   On July 17, 2008, PacifiCorp issued $500 million of 5.65% first mortgage bonds due July 15, 2018 and $300 million of 6.35% first mortgage bonds due July 15, 2038. The net proceeds were used for general corporate purposes.

·   On July 15, 2008, Northern Natural Gas issued $200 million of 5.75% senior notes due July 15, 2018. The net proceeds were used to repay at maturity its $150 million, 6.75% senior notes due September 15, 2008 and the remainder is being used for general corporate purposes.

·   On July 1, 2008, the Iowa Finance Authority issued $45 million of variable-rate tax-exempt bonds due July 1, 2038, the proceeds of which were loaned to MidAmerican Energy and are restricted for the payment of qualified environmental construction costs. Also on July 1, 2008, the Iowa Finance Authority issued $57 million of variable-rate tax-exempt bonds due May 1, 2023 to refinance $57 million of pollution control revenue refunding bonds issued on behalf of MidAmerican Energy in 1993. These variable-rate tax-exempt bonds are remarketed and the interest rates reset on a weekly basis.

·   On March 28, 2008, MEHC issued $650 million of 5.75% senior notes due April 1, 2018. The net proceeds were used for general corporate purposes.

·   On March 25, 2008, MidAmerican Energy issued $350 million of 5.3% senior notes due March 15, 2018. The proceeds were used by MidAmerican Energy to pay construction costs, including costs for its wind-powered generation projects in Iowa, repay short-term indebtedness and for general corporate purposes.

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2007 Long-term Debt Transactions and Agreements

In addition to the debt issuances and unsecured revolving credit facilities discussed herein, MEHC and its subsidiaries made scheduled repayments on MEHC senior and subordinated debt and subsidiary debt totaling $1.33 billion during the year ended December 31, 2007.

·   On October 23, 2007, PacifiCorp entered into a new unsecured revolving credit facility with total bank commitments of $700 million. The facility supports PacifiCorp’s commercial paper program and terminates on October 23, 2012. Terms and conditions, including borrowing rates, are substantially similar to PacifiCorp’s existing revolving credit facility.

·   On October 3, 2007, PacifiCorp issued $600 million of 6.25% First Mortgage Bonds due October 15, 2037. The proceeds were used by PacifiCorp to repay its short-term debt and for general corporate purposes.

·   On August 28, 2007, MEHC issued $1.0 billion of 6.50% Senior Bonds due September 15, 2037. The proceeds were used by MEHC to repay at maturity its 3.50% senior notes due in May 2008 in an aggregate principal amount of $450 million and its 7.52% senior notes due in September 2008 in an aggregate principal amount of $550 million.

·   On June 29, 2007, MidAmerican Energy issued $400 million of 5.65% Senior Notes due July 15, 2012, and $250 million of 5.95% Senior Notes due July 15, 2017. The proceeds were used by MidAmerican Energy to pay construction costs of its interest in WSEC Unit 4 and its wind projects in Iowa, to repay short-term indebtedness and for general corporate purposes.

·   On May 11, 2007, MEHC issued $550 million of 5.95% Senior Bonds due May 15, 2037. The proceeds were used by MEHC to repay at maturity its 4.625% senior notes due in October 2007 in an aggregate principal amount of $200 million and its 7.63% senior notes due in October 2007 in an aggregate principal amount of $350 million.

·   On March 14, 2007, PacifiCorp issued $600 million of 5.75% First Mortgage Bonds due April 1, 2037. The proceeds were used by PacifiCorp to repay its short-term debt and for general corporate purposes.

·   On February 12, 2007, Northern Natural Gas issued $150 million of 5.8% Senior Bonds due February 15, 2037. The proceeds were used by Northern Natural Gas to fund capital expenditures and for general corporate purposes.

The Company may from time to time seek to acquire its outstanding securities through cash purchases in the open market, privately negotiated transactions or otherwise. Any debt securities repurchased by the Company may be reissued or resold by the Company from time to time and will depend on prevailing market conditions, the Company’s liquidity requirements, contractual restrictions and other factors. The amounts involved may be material.

2009 Long-term Debt Transactions

In January 2009, PacifiCorp issued $350 million of its 5.50% First Mortgage Bonds due January 15, 2019 and $650 million of its 6.00% First Mortgage Bonds due January 15, 2039.

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 on September 19, 2008.

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Future Uses of Cash

The Company has available a variety of sources of liquidity and capital resources, both internal and external, including cash flows from operations, 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.

In the U.S., the U.K. and most other economies around the world, market and economic conditions have been unprecedented and challenging with more restrictive credit conditions and slowing or contracting growth during 2008. Continued concerns about the availability and cost of credit, the U.S. mortgage market and a declining real estate market in the U.S. and the U.K. have contributed to increased market volatility and diminished expectations for the U.S. and U.K. economies. In 2008, a number of large financial institutions were unable to survive as independent institutions and others were forced to file for bankruptcy. Other surviving institutions required multibillion dollar capital infusions. Furthermore, a number of large financial institutions’ senior unsecured debt was downgraded and placed on credit watch with negative implications by credit rating agencies.In 2008, the U.S. federal government enacted emergency legislation in an attempt to stabilize the economy, increased the federal deposit insurance, invested billions of dollars in financial institutions and took other steps to infuse liquidity into the economy. More recently, the federal government enacted the American Recovery and Reinvestment Act. The global nature of this credit crisis led other governments to institute similar measures.

As a result of these market conditions, the cost and availability of credit has been and may continue to be adversely affected by illiquid credit markets and significantly wider credit spreads. Concern about the general stability of the markets and the credit strength of counterparties has led many lenders and institutional investors to reduce, and in some cases, cease to provide funding to borrowers. Continued turbulence in the U.S. and international markets and economies may adversely affect our liquidity and financial condition, and the liquidity and financial condition of our customers. Recently, PacifiCorp and other investment grade utilities have been able to issue debt in the capital markets. If these poor market conditions continue, it may limit the Company’s ability to access the bank and debt markets to meet liquidity and capital expenditure needs, resulting in adverse effects on the timing and amount of the Company’s capital expenditures, financial condition and results of operations.

Capital Expenditures

The Company has significant future capital requirements. Capital expenditure needs are reviewed regularly by management and may change significantly as a result of these reviews, which may consider, among other factors, changes in rules and regulations, including environmental and nuclear, changes in income tax laws, general business conditions, load projections, system reliability standards, the cost and efficiency of construction labor, equipment and materials, and the cost and availability of capital. Expenditures for compliance-related items such as pollution-control technologies, replacement generation, mine reclamation, nuclear decommissioning, hydroelectric relicensing, hydroelectric decommissioning and associated operating costs are generally incorporated into MEHC’s energy subsidiaries’ regulated retail rates. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered from the Company’s customers, either through regulated rates, long-term arrangements or market prices and the inability to recover these costs could adversely affect the Company’s future financial results. For additional discussion regarding capital commitments, refer to Note 18 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K.

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Forecasted capital expenditures for the years ended December 31 are as follows (in millions):

	2009		2010		2011
Forecasted capital expenditures*:
Construction and other development projects	$	1,314	$	1,043	$	805
Operating projects		1,946		2,047		2,116
Total	$	3,260	$	3,090	$	2,921

* Excludes amounts for non-cash equity AFUDC.

Construction and other development projects consist mainly of large scale projects at PacifiCorp and MidAmerican Energy. Included in the 2009 through 2011 forecasted capital expenditures are PacifiCorp’s anticipated costs of $1.39 billion for the Energy Gateway Transmission Expansion Project, an investment plan to build approximately 2,000 miles of new high-voltage transmission lines primarily in Wyoming, Utah, Idaho, Oregon and the desert Southwest. The plan, with an estimated cost exceeding $6.1 billion, includes projects that will address customer load growth, improve system reliability and deliver energy for new wind-powered and other renewable generation resources throughout PacifiCorp’s six-state service area and the Western United States. Certain transmission segments associated with this plan are expected to be placed in service beginning 2010, with other segments placed in service through 2018, depending on siting, permitting and construction schedules. In July 2008, PacifiCorp filed a petition for declaratory order with the FERC to confirm incentive rate treatment for the Energy Gateway Transmission Expansion Project. In October 2008, the FERC granted a 200 basis point (two percentage point) incentive rate adder to PacifiCorp’s base return on equity for seven of the eight project segments. The FERC did not preclude PacifiCorp from filing for incentive rate treatment for the remaining segment at a future date. Also included in the above estimates are PacifiCorp’s commitments for transmission and distribution investments resulting from MEHC’s acquisition of PacifiCorp as discussed further in Note 18 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K.

Combined, PacifiCorp and MidAmerican Energy anticipate spending $1.06 billion for emissions control equipment, which includes equipment to meet anticipated air quality and visibility targets and the reduction of sulfur dioxide emissions, and $375 million on additional wind-powered generation facilities between 2009 and 2011. Evaluation and development efforts are in progress related to additional prospective wind-powered generating facilities scheduled for completion after 2009.

Capital expenditures related to operating projects consist of recurring expenditures for distribution, transmission, generation, mining and other infrastructure needed to serve existing and growing demand.

The Company is subject to federal, state, local and foreign laws and regulations with regard to air and water quality, renewable portfolio standards, hazardous and solid waste disposal and other environmental matters. 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. In particular, future mandates, including those associated with addressing the issue of global climate change, may impact the operation of the Company’s domestic generating facilities and may require PacifiCorp, MidAmerican Energy and other company-owned generation assets to reduce emissions at their facilities through the installation of additional emission control equipment or to purchase additional emission allowances or offsets in the future. The Company is not aware of any proven commercially available technology that eliminates or captures and stores carbon dioxide emissions from coal-fired and gas-fired generation 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 this Form 10-K for a detailed discussion of the topic.

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Acquisitions and Joint Ventures

Constellation Energy

On September 19, 2008, MEHC, Constellation Energy Group, Inc. (“Constellation Energy”) and MEHC Merger Sub Inc. signed an Agreement and Plan of Merger (the “Merger Agreement”), under which Constellation Energy would have become an indirect wholly-owned subsidiary of MEHC. In addition, the Company purchased a $1 billion investment in CEG 8% Preferred Stock. On December 17, 2008, MEHC and Constellation Energy entered into a termination agreement, pursuant to which, among other things, the parties agreed to terminate the Merger Agreement. As a result of the termination, the Company received a termination fee of $175 million and converted the $1 billion of CEG 8% Preferred Stock into $1 billion of 14% Senior Notes due from Constellation Energy, 19.9 million shares of Constellation Energy common stock and cash totaling $418 million. On January 12, 2009, the Company received $1 billion, plus accrued interest, in full satisfaction of the 14% Senior Notes from Constellation Energy. The Company sold 5.1 million of its common shares in Constellation Energy for $137 million in the first two months of 2009.

BYD Company Limited

In September 2008, MEHC reached a definitive agreement with BYD to purchase 225 million shares, representing approximately a 10% interest in the company, at a price of HK$8 per share or HK$1.8 billion (approximately $230 million). MEHC will finance the investment from general corporate funds. Refer to Note 3 of Notes to Consolidated Financial Statements included in Item 8 of this Form 10-K for additional discussion regarding the proposed transaction.

Investment Trust Valuation

The Company sponsors defined benefit pension plans and postretirement benefit plans (the “Plans”) that cover the majority of its employees. During the year ended December 31, 2008, the funded status of the Plans declined by $670 million. The actual loss on plan assets for the year ended December 31, 2008 was $861 million, or 21% of the $4.1 billion fair value of plan assets held as of December 31, 2007. Changes in the fair value of plan assets did not have an impact on the Company’s earnings for 2008; however, the poor performance contributed to an after-tax reduction of shareholders’ equity of $72 million and an increase of $552 million in net regulatory assets related to amounts not yet recognized as components of net periodic benefit costs. The net regulatory asset represents amounts recoverable from customers in the future. Reduced benefit plan assets will result in increased benefit costs in future years and will increase the amount and accelerate the timing of required future funding contributions.

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Contractual Obligations

The Company has contractual obligations that may affect its financial condition. Contractual obligations to make future payments arise from MEHC and subsidiary long-term debt and notes payable, operating leases, purchase obligations and power and fuel purchase contracts. Other obligations and commitments arise from unused lines of credit and letters of credit. Material obligations as of December 31, 2008 are as follows (in millions):

	Payments Due By Periods
						2010-		2012-	2014 and
	Total		2009		2011		2013		After
Contractual Cash Obligations:
MEHC senior debt	$	5,125	$	-	$	-	$	500	$	4,625
MEHC subordinated debt		1,370		734		332		114		190
Subsidiary debt		12,890		421		1,256		1,497		9,716
Interest payments on long-term debt(1)		18,671		1,168		2,160		1,868		13,475
Short-term debt		836		836		-		-		-
Coal, electricity and natural gas contract commitments(1)		7,602		1,284		1,922		926		3,470
Purchase obligations(1)		1,738		999		533		78		128
Owned hydroelectric commitments(1)		72		3		6		4		59
Operating leases(1)		597		96		153		93		255
Minimum pension funding requirements		329		84		68		68		109
Total contractual cash obligations	$	49,230	$	5,625	$	6,430	$	5,148	$	32,027

(1) Not reflected in the Consolidated Balance Sheets.

The Company has other types of commitments that arise primarily from unused lines of credit, letters of credit or relate to construction and other development costs (Liquidity and Capital Resources included within this Item 7), debt guarantees (Note 13), asset retirement obligations (Note 14) and uncertain tax positions (Note 16) which have not been included in the above tables because the amount and timing of the cash payments are not certain. Refer, where applicable, to the respective referenced note in Notes to Consolidated Financial Statements included in Item 8 of this Form 10-K for additional information.

Regulatory Matters

MEHC’s domestic regulated public utility subsidiaries, PacifiCorp and MidAmerican Energy, are subject to comprehensive regulation by state utility commissions, federal agencies, and other state and local regulatory agencies. The more significant aspects of this regulatory framework are described below. In addition to the discussion contained herein regarding state regulatory matters, refer to Item 1 of this Form 10-K for further discussion regarding regulatory and environmental matters.

PacifiCorp

PacifiCorp is subject to comprehensive regulation by the UPSC, the OPUC, the WPSC, the WUTC, the IPUC and the CPUC. PacifiCorp pursues a regulatory program in all states, with the objective of keeping rates closely aligned to ongoing costs. PacifiCorp has separate power cost recovery mechanisms in Oregon, Wyoming and California. The following discussion provides a state-by-state update.

Utah

In December 2007, PacifiCorp filed a general rate case with the UPSC requesting an annual increase of $161 million, or an average price increase of 11% based on a test period ended June 2009. The increase was primarily due to increased capital spending and net power costs, both of which are driven by load growth. In March 2008, PacifiCorp filed supplemental testimony reducing the requested rate increase to $100 million. The decrease was primarily a result of a UPSC-ordered change in the test period to the year ended December 2008 and reductions associated with recent UPSC orders on depreciation rate changes and two deferred accounting requests. Subsequently, hearings were held on the revenue requirement portion of the case and PacifiCorp filed additional testimony. In August 2008, the UPSC issued its revenue requirement order in the case, increasing rates by $36 million, or 3%. The new rates became effective August 13, 2008. In September 2008, PacifiCorp filed a petition for reconsideration of several elements of the order. In October 2008, the UPSC issued an order on the reconsideration petition allowing PacifiCorp to recover an additional $3 million, bringing the total rate increase to $39 million. A settlement that provides for an equal percentage increase to all tariff customers was reached in the rate-design phase of the case and was approved by the UPSC.

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In July 2008, PacifiCorp filed a general rate case with 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 December 2007 case described above. 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 proposes an increase of $116 million, or an average price increase of 8%. The UPSC issued an order resetting the beginning of the 240-day statutory time period required to process the case to the date of the September 2008 supplemental filing. Based on the new time period, the new rates, if approved, will become effective in May 2009. In February 2009, a settlement agreement was reached among the parties who had filed testimony in the cost of capital phase of the rate case. A stipulation was filed with the UPSC requesting that the UPSC set the weighted cost of capital at 8.4%.

Oregon

In April 2008, PacifiCorp made its first annual renewable adjustment clause (“RAC”) filing to recover the revenue requirement related to eligible new renewable resources and associated transmission under the OREA that are not reflected in general rates. PacifiCorp requested an annual increase of $39 million on an Oregon-allocated basis, or an average price increase of 4%. In November 2008, the OPUC issued an order approving the RAC request with certain modifications. The OPUC excluded Oregon’s share of the costs for the 99-MW Rolling Hills wind-powered generating plant from the request on the basis that PacifiCorp failed to prove the resource was prudently acquired. The OPUC’s finding was primarily based on the conclusion that the capacity factor was less favorable compared to other Wyoming wind-powered generating projects. In December 2008 and January 2009, PacifiCorp submitted compliance filings consistent with the OPUC order that together reduced the requested increase by $8 million to $31 million, or an average price increase of 3%. The commission approved $25 million, or 2% to go into effect on January 1, 2009. The commission approved an additional $6 million, or 1%, to go into effect on January 21, 2009 for the 99-MW Seven Mile Hill wind-powered generating plant.

In July 2008, as part of its annual transition adjustment mechanism (“TAM”), PacifiCorp filed updated forecasted net power costs for 2009. PacifiCorp proposed a net power cost increase of $57 million on an Oregon-allocated basis, or an average price increase of 6%. In September 2008, PacifiCorp filed a stipulation agreement reducing the proposed net power cost increase to $34 million on an Oregon-allocated basis, or an average price increase of 2%. The stipulation agreement was approved by the OPUC in November 2008. The forecasted net power costs were updated again in November 2008 for OPUC-ordered changes, changes to the forward price curve and new wholesale sales and purchases. In December 2008, PacifiCorp submitted a compliance filing in the TAM proceeding that reflected final forecasted net power costs and direct access transition adjustments for 2009. The compliance filing reduced PacifiCorp’s request by an additional $15 million on an Oregon-allocated basis, which resulted in an increase of $9 million, or an average price increase of 1%, after adjusting for load growth. The compliance filing was approved in December 2008 and the new rates became effective January 1, 2009.

For a discussion of SB 408, refer to Note 6 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K.

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Wyoming

In June 2007, PacifiCorp filed a general rate case with the WPSC requesting an annual increase of $36 million, or an average price increase of 8%. In addition, PacifiCorp requested approval of a new renewable resource recovery mechanism and a marginal cost pricing tariff to better reflect the cost of adding new generation. In January 2008, PacifiCorp reached a settlement in principle with parties to the case. The settlement provided for an annual rate increase of $23 million, or an average price increase of 5%. In addition, the parties also agreed to modify the current power cost adjustment mechanism (“PCAM”) to use forecasted power costs in the future and to terminate the PCAM by April 2011, unless a continuation is specifically applied for by PacifiCorp and approved by the WPSC. PacifiCorp’s marginal cost pricing tariff proposal will not be implemented, but will be the subject of a collaborative process to seek a new pricing proposal. Also as part of the settlement, PacifiCorp agreed to withdraw from this filing its request for a renewable resource recovery mechanism. The stipulation was approved by the WPSC in March 2008. The new rates were effective May 1, 2008.

In February 2008, PacifiCorp filed its annual PCAM application with the WPSC for costs incurred during the period December 1, 2006 through November 30, 2007. In March 2008, the WPSC approved PacifiCorp’s request on an interim basis effective April 1, 2008, resulting in a rate increase of $31 million, or an average price increase of 8%, to recover deferred power costs over a one-year period. In August 2008, PacifiCorp reached an agreement with parties to the case to adjust the rate increase to $29 million. In November 2008, the WPSC issued an order approving the stipulation agreement. The interim rates were revised to reflect the $29 million increase approved in the stipulation agreement and became effective October 15, 2008.

In July 2008, PacifiCorp filed a general rate case with the WPSC requesting an annual increase of $34 million, or an average price increase of 7%, with an effective date in May 2009. Power costs have been excluded from the filing and will be addressed separately in PacifiCorp’s annual PCAM application 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 February 2009, PacifiCorp filed its annual PCAM application with the WPSC. Pursuant to tariff changes made in the 2007 general rate case, the 2009 PCAM application includes a request to recover $27 million of deferred net power costs during the period December 1, 2007 through November 30, 2008 and to establish a new forecast base net power cost using the test period December 1, 2008 through November 30, 2009. The net effect of the deferred and forecast base net power costs is an increase in Wyoming rates of $19 million, or 4%. The tariff governing the power cost adjustment mechanism requires an effective date of April 1, 2009.

Washington

In February 2008, PacifiCorp filed a general rate case with the WUTC for an annual increase of $35 million, or an average price increase of 15%. In August 2008, PacifiCorp filed with the WUTC an all-party settlement agreement in which the parties agreed to an overall rate increase of $20 million, or 9%. The settlement was approved by the WUTC in October 2008 with the new rates effective October 15, 2008. The increase is composed of an $18 million increase to base rates, as well as a $2 million annual surcharge for approximately three years related to recovery of higher power costs incurred in 2005 due to poor hydroelectric conditions. PacifiCorp agreed to drop the current proposal for a generation cost adjustment mechanism and further committed not to propose such a mechanism in the next general rate case.

In February 2009, PacifiCorp filed a general rate case with the WUTC for an annual increase of $39 million, or an average price increase of 15%. The expected effective date for the rate change is January 11, 2010. The filing includes a deferral request for costs associated with the 520-MW Chehalis natural gas-fired generating plant prior to its inclusion in rate base beginning in January 2010. The associated costs are estimated at $16 million. PacifiCorp has proposed to recover these costs through an extension in the hydroelectric deferral mechanism and thereby not affecting current customer rates.

Idaho

In September 2008, PacifiCorp filed a general rate case with the IPUC for an annual increase of $6 million, or an average price increase of 4%. The increase is primarily due to increased capital spending and net power costs. If approved, the new rates will become effective April 18, 2009. 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 the following: PacifiCorp’s acquisition of the Chehalis, Washington plant was prudent and the investment should be included in PacifiCorp’s revenue requirement; PacifiCorp has demonstrated that its demand-side management programs are prudent; and a base level of net power costs is established for any future energy cost adjustment mechanism calculations if a mechanism is adopted in Idaho. In February 2009, parties to the stipulation will file supporting testimony recommending the IPUC approve the stipulation as filed. Public hearings are scheduled in March 2009.

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In October 2008, PacifiCorp filed a request with the IPUC for approval of an annual energy cost adjustment mechanism (“ECAM”) to defer for later recovery in rates the difference between base net power costs set during a general rate case and actual net power costs incurred by PacifiCorp. If approved, PacifiCorp would file an application with the IPUC annually to adjust the ECAM surcharge rate to refund or collect the ECAM deferred balance from the end of the prior calendar year.

Credit Ratings

As of January 31, 2009, MEHC’s senior unsecured debt credit ratings were as follows: Moody’s Investor Service, “Baa1/stable;” Standard & Poor’s, “BBB+/watch negative;” 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.

A change in PacifiCorp’s or MidAmerican Energy’s credit rating could result in the requirement to post cash collateral, letters of credit or other similar credit support under certain agreements related to their procurement or sale of electricity, natural gas, coal, transportation and other supplies. In accordance with industry practice, PacifiCorp’s and MidAmerican Energy’s agreements may either specifically provide bilateral rights to demand cash or other security if credit exposures on a net basis exceed certain ratings-dependent threshold levels or provide the right for counterparties to demand “adequate assurances” in the event of a material adverse change in PacifiCorp’s or MidAmerican Energy’s creditworthiness. As of December 31, 2008, PacifiCorp’s and MidAmerican Energy’s credit ratings from the three recognized credit rating agencies were investment grade; however, if the ratings fell one rating below investment grade, PacifiCorp’s and MidAmerican Energy’s collateral requirements would increase by approximately $356 million and $350 million, respectively. Additional collateral requirements would be necessary if ratings fell further than one rating below investment grade. The collateral requirements could fluctuate considerably due to seasonality, market price volatility, a loss of key generating facilities or other related factors.

Inflation

Inflation has not had a significant impact on the Company’s costs.

Off-Balance Sheet Arrangements

The Company has certain investments that are accounted for under the equity method in accordance with accounting principles generally accepted in the United States of America (“GAAP”). Accordingly, an amount is recorded on the Company’s Consolidated Balance Sheets as an equity investment and is increased or decreased for the Company’s pro-rata share of earnings or losses, respectively, less any dividend distribution from such investments.

As of December 31, 2008, the Company’s investments that are accounted for under the equity method had short- and long-term debt, unused revolving credit facilities and letters of credit outstanding of $558 million, $210 million and $77 million, respectively. As of December 31, 2008, the Company’s pro-rata share of such short- and long-term debt, unused revolving credit facilities and outstanding letters of credit was $278 million, $105 million and $38 million, respectively. The entire amount of the Company’s pro-rata share of the outstanding short- and long-term debt and unused revolving credit facilities is non-recourse to the Company. $32 million of the Company’s pro-rata share of the outstanding letters of credit is recourse to the Company. Although the Company is generally not required to support debt service obligations of its equity investees, default with respect to this non-recourse short- and long-term debt could result in a loss of invested equity.

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New Accounting Pronouncements

For a discussion of new accounting pronouncements affecting the Company, refer to Note 2 of Notes to Consolidated Financial Statements included in Item 8 of this Form 10-K.

Critical Accounting Policies

Certain accounting policies require management to make estimates and judgments concerning transactions that will be settled several years in the future. Amounts recognized in the Consolidated Financial Statements from such estimates are necessarily based on numerous assumptions involving varying and potentially significant degrees of judgment and uncertainty. Accordingly, the amounts currently reflected in the Consolidated Financial Statements will likely increase or decrease in the future as additional information becomes available. The following critical accounting policies are impacted significantly by judgments, assumptions and estimates used in the preparation of the Consolidated Financial Statements.

Accounting for the Effects of Certain Types of Regulation

PacifiCorp, MidAmerican Energy, Northern Natural Gas and Kern River (the “Domestic Regulated Businesses”) prepare their financial statements in accordance with the provisions of Statement of Financial Accounting Standards (“SFAS”) No. 71, “Accounting for the Effects of Certain Types of Regulation” (“SFAS No. 71”), which differs in certain respects from the application of GAAP by non-regulated businesses. In general, SFAS No. 71 recognizes that accounting for rate-regulated enterprises should reflect the economic effects of regulation. As a result, a regulated entity is required to defer the recognition of costs or income if it is probable that, through the rate-making process, there will be a corresponding increase or decrease in future rates. Accordingly, the Domestic Regulated Businesses have deferred certain costs and income that will be recognized in earnings over various future periods.

Management continually evaluates the applicability of SFAS No. 71 and assesses whether its regulatory assets are probable of future recovery by considering factors such as a change in the regulator’s approach to setting rates from cost-based ratemaking to another form of regulation, other regulatory actions or the impact of competition which could limit the Domestic Regulated Businesses’ ability to recover their costs. Based upon this continual assessment, management believes the application of SFAS No. 71 continues to be appropriate and its existing regulatory assets are probable of recovery. The assessment reflects the current political and regulatory climate at both the state and federal levels and is subject to change in the future. If it becomes no longer probable that these costs will be recovered, the related regulatory assets and regulatory liabilities would be written off and recognized in operating income. Total regulatory assets were $2.16 billion and total regulatory liabilities were $1.51 billion as of December 31, 2008. Refer to Note 6 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for additional information regarding the Domestic Regulated Businesses’ regulatory assets and liabilities.

Derivatives

The Company is exposed to the impact of market fluctuations in commodity prices, principally natural gas and electricity, interest rate risk and foreign currency exchange rate risk. The Company employs established policies and procedures to manage its risks associated with these market fluctuations using various commodity and financial derivative instruments, including forward contracts, futures, options, swaps and other agreements.

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Measurement Principles

Derivative instruments are recorded in the Consolidated Balance Sheets as either assets or liabilities and are stated at fair value unless they are designated as normal purchases and normal sales and qualify for the exemption afforded by GAAP. The fair value of derivative instruments is determined using unadjusted quoted prices for identical instruments on the applicable exchange in which the Company transacts, when available, or forward price curves. Forward price curves represent the Company’s estimates of the prices at which a buyer or seller could contract today for delivery or settlement at future dates. The Company bases its forward price curves upon market price quotations, when available, or internally developed and commercial models, with internal and external fundamental data inputs. Market price quotations are obtained from independent brokers, exchanges, direct communication with market participants and actual transactions executed by the Company. Market price quotations for certain major electricity and natural gas trading hubs are generally readily obtainable for the first six years, and therefore, the Company’s forward price curves for those locations and periods reflect observable market quotes. For market price quotations for other electricity and natural gas trading points that are not as readily obtainable for the first six years or if the instrument is not actively traded, the Company uses forward price curves derived from internal models based on perceived pricing relationships to major trading hubs that are based on significant unobservable inputs. The fair value of these derivative instruments is a function of underlying forward commodity prices, interest rates, currency rates, related volatility, counterparty creditworthiness and duration of contracts. The assumptions used in these models are critical, since any changes in assumptions could have a significant impact on the fair value of the contracts.

Classification and Recognition Methodology

Almost all of the Company’s derivative contracts are probable of recovery in rates or are accounted for as cash flow hedges. Therefore, changes in fair value are recorded as a net regulatory asset or liability or accumulated other comprehensive income (loss) (“AOCI”), respectively. Accordingly, amounts are generally not recognized in earnings until the contracts are settled. As of December 31, 2008, the Company had $446 million recorded as net regulatory assets and $89 million recorded as AOCI, before tax, related to these contracts in the Consolidated Balance Sheets. If it becomes no longer probable that a contract will be recovered in rates, the regulatory asset will be written-off and recognized in earnings. For contracts designated in hedge relationships (“hedge contracts”), the Company discontinues hedge accounting prospectively when it has determined that a derivative no longer qualifies as an effective hedge, or when it is no longer probable that the hedged forecasted transaction will occur. When hedge accounting is discontinued because the derivative no longer qualifies as an effective hedge, future changes in the value of the derivative are charged to earnings. Gains and losses related to discontinued hedges that were previously recorded in AOCI will remain in AOCI until the hedged item is realized, unless it is probable that the hedged forecasted transaction will not occur at which time associated deferred amounts in AOCI are immediately recognized in earnings.

Impairment of Long-Lived Assets and Goodwill

The Company evaluates long-lived assets for impairment, including property, plant and equipment, when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable, or the assets meet the criteria of held for sale. Upon the occurrence of a triggering event, the asset is reviewed to assess whether the estimated undiscounted cash flows expected from the use of the asset plus the residual value from the ultimate disposal exceeds the carrying value of the asset. If the carrying value exceeds the estimated recoverable amounts, the asset is written down to the estimated discounted present value of the expected future cash flows from using the asset. For regulated assets, any impairment charge is offset by the establishment of a regulatory asset to the extent recovery in rates is probable. Substantially all property, plant and equipment was used in regulated businesses as of December 31, 2008. For all other assets, any resulting impairment loss is reflected in the Consolidated Statements of Operations.

The estimate of cash flows arising from the future use of the asset that are used in the impairment analysis requires judgment regarding what the Company would expect to recover from the future use of the asset. Changes in judgment that could significantly alter the calculation of the fair value or the recoverable amount of the asset may result from, but are not limited to, significant changes in the regulatory environment, the business climate, management’s plans, legal factors, market price of the asset, the use of the asset or the physical condition of the asset. An impairment analysis of generating facilities or pipelines requires estimates of possible future market prices, load growth, competition and many other factors over the lives of the facilities. Any resulting impairment loss is highly dependent on the underlying assumptions and could significantly affect the Company’s results of operations.

74

The Company’s Consolidated Balance Sheet as of December 31, 2008 includes goodwill of acquired businesses of $5.0 billion. Goodwill is allocated to each reporting unit and is tested at least annually for impairments using a variety of methods, principally discounted projected future net cash flows, with any impairments charged to earnings. The Company completed its annual review as of October 31 and no indicators of impairment were identified as of December 31, 2008. A significant amount of judgment is required in performing goodwill impairment tests. Key assumptions used in the testing include, but are not limited to, the use of estimated future cash flows, earnings before interest, taxes, depreciation and amortization (“EBITDA”) multiples and an appropriate discount rate. Estimated future cash flows are impacted by, among other factors, growth rates, changes in regulations and rates, ability to renew contracts and estimates of future commodity prices. In estimating cash flows, the Company incorporates current market information as well as historical factors.

Accrued Pension and Postretirement Expense

The Company sponsors defined benefit pension and other postretirement benefit plans that cover the majority of its employees. The Company recognizes the funded status of its defined benefit pension and other postretirement benefit plans in the Consolidated Balance Sheets. Funded status is the fair value of plan assets minus the benefit obligation as of the measurement date. As of December 31, 2008, the Company recognized a net liability totaling $938 million for the under-funded status for the Company’s defined benefit pension and other postretirement benefit plans. As of December 31, 2008, amounts not yet recognized as components of net periodic benefit cost and that were included in net regulatory assets totaled $653 million.

The expense and benefit obligations relating to these pension and other postretirement benefit plans are based on actuarial valuations. Inherent in these valuations are key assumptions, including discount rates, expected long-term rate of return on plan assets and health care cost trend rates. These actuarial assumptions are reviewed annually and modified as appropriate. The Company believes that the assumptions utilized in recording obligations under the plans are reasonable based on prior experience and market conditions. Refer to Note 15 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for disclosures about the Company’s pension and other postretirement benefit plans, including the key assumptions used to calculate the funded status and net periodic benefit cost for these plans as of and for the year ended December 31, 2008.

In establishing its assumption as to the expected long-term rate of return on plan assets, the Company reviews the expected asset allocation and develops return assumptions for each asset class based on historical performance and forward-looking views of the financial markets. Pension and other postretirement benefit expenses increase as the expected long-term rate of return on plan assets decreases. The Company regularly reviews its actual asset allocations and periodically rebalances its investments to its targeted allocations when considered appropriate.

The Company chooses a discount rate based upon high quality fixed-income investment yields in effect as of the measurement date that corresponds to the expected benefit period. The pension and other postretirement benefit liabilities, as well as expenses, increase as the discount rate is reduced.

The Company chooses a health care cost trend rate that reflects the near and long-term expectations of increases in medical costs and corresponds to the expected benefit payment periods. The health care cost trend rate gradually declines to 5% in 2010 through 2016 at which point the rate is assumed to remain constant. Refer to Note 15 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for health care cost trend rate sensitivity disclosures.

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The actuarial assumptions used may differ materially from period to period due to changing market and economic conditions. These differences may result in a significant impact to the amount of pension and other postretirement benefit expense recorded and the funded status. If changes were to occur for the following assumptions, the approximate effect on the financial statements would be as follows (in millions):

	Domestic Plans
							Other Postretirement						United Kingdom
	Pension Plans						Benefit Plans						Pension Plan
		+0.5	%		-0.5	%		+0.5	%		-0.5	%		+0.5	%		-0.5	%
Effect on December 31, 2008
Benefit Obligations:
Discount rate	$	(87	)	$	94		$	(40	)	$	44		$	(94	)	$	107
Effect on 2008 Periodic Cost:
Discount rate	$	(8	)	$	9		$	(2	)	$	3		$	(13	)	$	13
Expected rate of return on plan assets		(8	)		8			(3	)		3			(9	)		9

A variety of factors affect the funded status of the plans, including asset returns, discount rates, plan changes and the plan funding practices of the Company. Specifically, the Pension Protection Act of 2006 imposed generally more stringent funding requirements for defined benefit pension plans, particularly for those significantly under-funded, and allowed for greater tax deductible contributions to such plans than previous rules permitted under the Employee Retirement Income Security Act of 1974. As a result, the Company may be required to increase future contributions to its domestic pension plans and there may be more volatility in annual contributions than historically experienced, which could have a material impact on financial results. Refer to “Future Uses of Cash” for additional discussion regarding investment trust valuations.

Income Taxes

In determining the Company’s income taxes, management is required to interpret complex tax laws and regulations. In preparing tax returns, the Company is subject to continuous examinations by federal, state, local and foreign tax authorities that may give rise to different interpretations of these complex laws and regulations. Due to the nature of the examination process, it generally takes years before these examinations are completed and these matters are resolved. The U.S. Internal Revenue Service has closed examination of the Company’s income tax returns through 2003. In the U.K., each legal entity is subject to examination by HM Revenue and Customs (“HMRC”), the U.K. equivalent of the U.S. Internal Revenue Service. HMRC has closed examination of income tax returns for all entities through 2006. In addition, state jurisdictions have closed examination of the Company’s income tax returns through at least 2002, except for PacifiCorp where the examinations have been closed through 1993 in most cases. The Company’s income tax returns in the Philippines, the most significant other foreign jurisdiction, have been closed through at least 2003. Although the ultimate resolution of the Company’s federal, state and foreign tax examinations is uncertain, the Company believes it has made adequate provisions for these tax positions and the aggregate amount of any additional tax liabilities that may result from these examinations, if any, will not have a material adverse impact on the Company’s financial results. Assets and liabilities are established for uncertain tax positions taken or positions expected to be taken in income tax returns when such positions are judged to not meet the “more-likely-than-not” threshold based on the technical merits of the position.

Both PacifiCorp and MidAmerican Energy are required to pass income tax benefits related to certain property-related basis differences and other various differences on to their customers in most state jurisdictions. These amounts were recognized as a net regulatory asset totaling $607 million as of December 31, 2008, and will be included in rates when the temporary differences reverse. Management believes the existing regulatory assets are probable of recovery. If it becomes no longer probable that these costs will be recovered, the assets would be written-off and recognized in earnings.

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The Company has not provided U.S. Federal deferred income taxes on its currency translation adjustment or the cumulative earnings of international subsidiaries that have been determined by management to be reinvested indefinitely. The cumulative earnings related to ongoing operations determined to be reinvested indefinitely were approximately $1.0 billion as of December 31, 2008. Because of the availability of U.S. foreign tax credits, it is not practicable to determine the U.S. federal income tax liability that would be payable if such earnings were not reinvested indefinitely. Deferred taxes are provided for earnings of international subsidiaries when the Company plans to remit those earnings. The Company periodically evaluates its cash requirements in the U.S. and abroad and evaluates its short- and long-term operational and fiscal objectives in determining whether the earnings of its foreign subsidiaries are indefinitely invested outside the U.S. or will be remitted to the U.S. within the foreseeable future.

Revenue Recognition - Unbilled Revenue

Unbilled revenue was $444 million as of December 31, 2008. Revenue from energy business customers is recognized as electricity or natural gas is delivered or services are provided. The determination of sales to individual customers is based on a systematic reading of meters, fixed reservation charges based on contractual quantities and rates or, in the case of the U.K. distribution businesses, when information is received from the national settlement system. At the end of each month, amounts of energy provided to customers since the date of the last meter reading are estimated, and the corresponding unbilled revenue is recorded. Factors that can impact the estimate of unbilled energy include, but are not limited to, seasonal weather patterns, historical trends, volumes, line losses, economic impacts and composition of customer class. Estimates are generally reversed in the following month and actual revenue is recorded based on subsequent meter readings. Historically, any differences between the actual and estimated amounts have been immaterial.

Item 7A. Quantitative and Qualitative Disclosures About Market Risk

The Company’s Consolidated Balance Sheets include assets and liabilities with fair values that are subject to market risks. The Company’s significant market risks are primarily associated with commodity prices, foreign currency exchange rates and interest rates. The following sections address the significant market risks associated with the Company’s business activities. The Company also has established guidelines for credit risk management. The recent unprecedented volatility in the capital and credit markets has developed rapidly and may create additional risks in the future. Refer to Notes 2 and 9 of Notes to Consolidated Financial Statements included in Item 8 of this Form 10-K for additional information regarding the Company’s accounting for derivative contracts.

Commodity Price Risk

MEHC is subject to significant commodity risk, particularly through its ownership of PacifiCorp and MidAmerican Energy. Exposures include variations in the price of wholesale electricity that is purchased and sold, fuel costs to generate electricity, and natural gas supply for regulated retail gas customers. Electricity and natural gas prices are subject to wide price swings as demand responds to, among many other unpredictable items, changing weather, energy supply and demand, generating facility performance, limited storage, transmission and transportation constraints, and lack of alternative supplies from other areas. To mitigate a portion of the risk, our subsidiaries use derivative instruments, including forward contracts, futures, options, swaps and other agreements, to effectively secure future supply or sell future production at fixed prices. The settled cost of these contracts 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, that are probable of recovery in rates, are recorded as net regulatory assets or regulatory liabilities. Financial results may be negatively impacted if the costs of wholesale electricity, fuel or natural gas are higher than what is permitted to be recovered in rates. MidAmerican Energy also uses futures, options and swap agreements to economically hedge gas and electric commodity prices for physical delivery to non-regulated customers. The Company does not engage in a material amount of proprietary trading activities.

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The table that follows summarizes the Company’s commodity risk on energy derivative contracts, excluding collateral netting of $129 million, as of December 31, 2008 and shows the effects of a hypothetical 10% increase and a 10% decrease in forward market prices by the expected volumes for these contracts as of that date. The selected hypothetical change does not reflect what could be considered the best or worst case scenarios (dollars in millions):

	Fair Value – Asset (Liability)			Hypothetical Price Change	Estimated Fair Value after Hypothetical Change in Price
As of December 31, 2008	$	(528	)	10% increase	$	(474	)
				10% decrease		(582	)

Foreign Currency Risk

MEHC’s business operations and investments outside the United States increase its risk related to fluctuations in foreign currency rates primarily in relation to the British pound. Our principal reporting currency is the United States dollar, and the value of the assets and liabilities, earnings, cash flows and potential distributions from our foreign operations changes with the fluctuations of the currency in which they transact.

CE Electric UK’s functional currency is the British pound. At December 31, 2008, a 10% devaluation in the British pound to the United States dollar would result in MEHC’s Consolidated Balance Sheet being negatively impacted by a $176 million cumulative translation adjustment in accumulated other comprehensive income. A 10% devaluation in the average currency exchange rate would have resulted in lower reported earnings for CE Electric UK of $25 million in 2008.

Interest Rate Risk

The following table summarizes the Company’s fixed-rate long-term debt totaling $18.60 billion and $18.96 billion as of December 31, 2008 and 2007, respectively and the estimated effects of hypothetical increases and decreases in interest rates based on rates in effect as of December 31, 2008. Because of their fixed interest rates, these instruments do not expose the Company to the risk of earnings loss due to changes in market interest rates. In general, such increases and decreases in fair value would impact earnings and cash flows only if the Company were to reacquire all or a portion of these instruments prior to their maturity. It is assumed that the changes occur immediately and uniformly to each debt instrument. The hypothetical changes in market interest rates do not reflect what could be deemed best or worst case scenarios. Variations in market interest rates could produce significant changes in the timing of repayments due to prepayment options available. For these reasons, actual results might differ from those reflected in the table (dollars in millions).

			Estimated Fair Value after
			Hypothetical Change in
			Interest Rates
				100 bp		100 bp
(bp = basis points)	Fair Value		decrease		increase
December 31, 2008	$	18,598	$	20,318	$	17,126
December 31, 2007	$	19,796	$	21,603	$	18,267

As of December 31, 2008 and 2007, the Company had floating-rate obligations totaling $798 million and $729 million, respectively, that expose the Company to the risk of increased interest expense in the event of increases in short-term interest rates. This market risk is not hedged; however, if floating interest rates were to increase by 10% from December 31 levels, it would not have a material effect on the Company’s consolidated annual interest expense in either year. The carrying value of the floating-rate obligations approximates fair value as of December 31, 2008 and 2007.

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Credit Risk

Domestic Regulated Operations

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 non-performance 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 such 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.

As of December 31, 2008, 69% of PacifiCorp’s credit exposure from wholesale activities, net of collateral, was with counterparties having investment grade credit ratings from Moody’s and Standard & Poor’s. An additional 4% of PacifiCorp’s credit exposure from wholesale activities, net of collateral, was from counterparties having financial characteristics deemed equivalent to investment grade based on internal review. Two counterparties comprise 35% of PacifiCorp’s aggregate credit exposure from wholesale activities, net of collateral, as of December 31, 2008. One counterparty is rated investment grade by Moody’s and Standard & Poor’s and PacifiCorp is not aware of any factors that would likely result in a downgrade of the counterparty’s credit ratings to below investment grade over the remaining term of transactions outstanding as of December 31, 2008. The other counterparty has non-investment grade credit ratings from an internal review as of December 31, 2008.

As of December 31, 2008, 77% of MidAmerican Energy’s credit exposure from wholesale activities, net of collateral, was with counterparties having investment grade credit ratings from Moody’s or Standard & Poor’s, while an additional 23% of MidAmerican Energy’s credit exposure from wholesale activities, net of collateral, was with counterparties having financial characteristics deemed equivalent to investment grade based on internal review. A single counterparty comprises 18% of MidAmerican Energy’s aggregate credit exposure from wholesale activities, net of collateral, as of December 31, 2008 and is rated investment grade by Moody’s and Standard & Poor’s. MidAmerican Energy is not aware of any factors that would likely result in a downgrade of the counterparty’s credit ratings to below investment grade over the remaining term of transactions outstanding as of December 31, 2008.

Northern Natural Gas’ primary customers include regulated local distribution companies in the upper Midwest. Kern River’s primary customers are major oil and gas companies or affiliates of such companies, electric generating companies, energy marketing and trading companies and natural gas distribution utilities which provide services in Utah, Nevada and California. As a general policy, collateral is not required for receivables from creditworthy customers. Customers’ financial condition and creditworthiness are regularly evaluated, and historical losses have been minimal. In order to provide protection against credit risk, and as permitted by the separate terms of each of Northern Natural Gas’ and Kern River’s tariffs, the companies have required customers that lack creditworthiness, as defined by the tariffs, to provide cash deposits, letters of credit or other security until their creditworthiness improves.

CE Electric UK

Northern Electric and Yorkshire Electricity charge fees for the use of their electrical infrastructure levied on supply companies. The supply companies, which purchase electricity from generators and traders and sell the electricity to end-use customers, use Northern Electric’s and Yorkshire Electricity’s distribution networks pursuant to the multilateral “Distribution Connection and Use of System Agreement.” Northern Electric’s and Yorkshire Electricity’s customers are concentrated in a small number of electricity supply businesses with RWE Npower PLC accounting for approximately 37% of distribution revenues in 2008. Ofgem has determined a framework which sets credit limits for each supply business based on its credit rating or payment history and requires them to provide credit cover if their value at risk (measured as being equivalent to 45 days usage) exceeds the credit limit. Acceptable credit typically is provided in the form of a parent company guarantee, letter of credit or an escrow account. Ofgem has indicated that, provided Northern Electric and Yorkshire Electricity have implemented credit control, billing and collection in line with best practice guidelines and can demonstrate compliance with the guidelines or are able to satisfactorily explain departure from the guidelines, any bad debt losses arising from supplier default will be recovered through an increase in future allowed income. Losses incurred to date have not been material.

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CalEnergy Generation-Foreign

NIA’s obligations under the Casecnan project agreement is CE Casecnan’s sole source of operating revenue. Because of the dependence on a single customer, any material failure of the customer to fulfill its obligations under the project agreement and any material failure of the ROP to fulfill its obligation under the performance undertaking would significantly impair the ability to meet existing and future obligations, including obligations pertaining to the outstanding project debt. Total operating revenue for the Casecnan project was $138 million for the year ended December 31, 2008. The Casecnan project agreement expires in December 2021.

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Item 8. Financial Statements and Supplementary Data

Report of Independent Registered Public Accounting Firm	82
Consolidated Balance Sheets as of December 31, 2008 and 2007	83
Consolidated Statements of Operations for the Years Ended December 31, 2008, 2007 and 2006	85
Consolidated Statements of Shareholders’ Equity for the Years Ended December 31, 2008, 2007 and 2006	86
Consolidated Statements of Cash Flows for the Years Ended December 31, 2008, 2007 and 2006	87
Notes to Consolidated Financial Statements	88

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders

MidAmerican Energy Holdings Company

Des Moines, Iowa

We have audited the accompanying consolidated balance sheets of MidAmerican Energy Holdings Company and subsidiaries (the “Company”) as of December 31, 2008 and 2007, and the related consolidated statements of operations, shareholders’ equity, and cash flows for each of the three years in the period ended December 31, 2008. Our audits also included the financial statement schedules listed in the Index at Item 15. These financial statements and financial statement schedules are the responsibility of the Company’s management. Our responsibility is to express an opinion on the financial statements and financial statement schedules based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of MidAmerican Energy Holdings Company and subsidiaries as of December 31, 2008 and 2007, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2008, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedules, when considered in relation to the basic consolidated financial statements taken as a whole, present fairly in all material respects the information set forth therein.

/s/       Deloitte & Touche LLP

Des Moines, Iowa

February 27, 2009

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MIDAMERICAN ENERGY HOLDINGS COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Amounts in millions)

	As of December 31,
	2008		2007
ASSETS
Current assets:
Cash and cash equivalents	$	280	$	1,178
Trade receivables, net		1,310		1,406
Inventories		566		476
Derivative contracts		227		170
Investments		1,505		397
Other current assets		529		687
Total current assets		4,417		4,314
Property, plant and equipment, net		28,454		26,221
Goodwill		5,023		5,339
Regulatory assets		2,156		1,503
Derivative contracts		97		227
Deferred charges, investments and other		1,294		1,612
Total assets	$	41,441	$	39,216

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

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MIDAMERICAN ENERGY HOLDINGS COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (continued)

(Amounts in millions)

	As of December 31,
	2008			2007
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	1,240		$	1,063
Accrued interest		340			341
Accrued property, income and other taxes		561			230
Derivative contracts		183			266
Short-term debt		836			130
Current portion of long-term debt		421			1,966
Current portion of MEHC subordinated debt		734			234
Other current liabilities		578			816
Total current liabilities		4,893			5,046
Regulatory liabilities		1,506			1,629
Derivative contracts		546			499
MEHC senior debt		5,121			4,471
MEHC subordinated debt		587			891
Subsidiary debt		12,533			12,131
Deferred income taxes		3,949			3,595
Other long-term liabilities		1,829			1,372
Total liabilities		30,964			29,634
Minority interest		142			128
Preferred securities of subsidiaries		128			128
Commitments and contingencies (Note 18)
Shareholders’ equity:
Common stock - 115 shares authorized, no par value, 75 shares issued and outstanding		-			-
Additional paid-in capital		5,455			5,454
Retained earnings		5,631			3,782
Accumulated other comprehensive (loss) income, net		(879	)		90
Total shareholders’ equity		10,207			9,326
Total liabilities and shareholders’ equity	$	41,441		$	39,216

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

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MIDAMERICAN ENERGY HOLDINGS COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(Amounts in millions)

	Years Ended December 31,
	2008			2007			2006
Operating revenue:
Energy	$	11,535		$	10,876		$	8,599
Real estate		1,133			1,500			1,702
Total operating revenue		12,668			12,376			10,301
Operating costs and expenses:
Energy:
Cost of sales		5,170			4,649			3,417
Operating expense		2,369			2,442			2,142
Depreciation and amortization		1,110			1,130			975
Real estate		1,191			1,467			1,647
Total operating costs and expenses		9,840			9,688			8,181
Operating income		2,828			2,688			2,120
Other income (expense):
Interest expense		(1,333	)		(1,320	)		(1,152	)
Capitalized interest		54			54			40
Interest and dividend income		75			105			73
Other, net		1,188			112			226
Total other income (expense)		(16	)		(1,049	)		(813	)
Income before income tax expense, minority interest and preferred dividends of subsidiaries and equity income		2,812			1,639			1,307
Income tax expense		982			456			407
Minority interest and preferred dividends of subsidiaries		21			30			27
Equity income		(41	)		(36	)		(43	)
Net income	$	1,850		$	1,189		$	916

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

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MIDAMERICAN ENERGY HOLDINGS COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY

FOR THE THREE YEARS ENDED DECEMBER 31, 2008

(Amounts in millions)

												Accumulated
												Other
						Additional						Comprehensive
	Common					Paid-in			Retained			Income (Loss),
	Shares			Stock		Capital			Earnings			net			Total
Balance, January 1, 2006		9		$	-	$	1,963		$	1,720		$	(298	)	$	3,385
Net income		-			-		-			916			-			916
Other comprehensive income:
Foreign currency translation adjustment		-			-		-			-			263			263
Fair value adjustment on cash flow hedges, net of tax of $32		-			-		-			-			54			54
Minimum pension liability adjustment, net of tax of $146		-			-		-			-			338			338
Unrealized gains on marketable securities, net of tax of $2		-			-		-			-			3			3
Total comprehensive income																1,574
Adjustment to initially apply FASB Statement No. 158, net of tax of $(160)		-			-		-			-			(367	)		(367	)
Preferred stock conversion to common stock		41			-		-			-			-			-
Exercise of common stock options		1			-		22			-			-			22
Tax benefit from exercise of common stock options		-			-		34			-			-			34
Common stock issuances		35			-		5,110			-			-			5,110
Common stock purchases		(12	)		-		(1,712	)		(38	)		-			(1,750	)
Other equity transactions		-			-		3			-			-			3
Balance, December 31, 2006		74			-		5,420			2,598			(7	)		8,011
Adoption of FASB Interpretation No. 48		-			-		-			(5	)		-			(5	)
Net income		-			-		-			1,189			-			1,189
Other comprehensive income:
Foreign currency translation adjustment		-			-		-			-			30			30
Fair value adjustment on cash flow hedges, net of tax of $17		-			-		-			-			28			28
Unrecognized amounts on retirement benefits, net of tax of $32		-			-		-			-			38			38
Unrealized gains on marketable securities, net of tax of $1		-			-		-			-			1			1
Total comprehensive income																1,286
Exercise of common stock options		1			-		10			-			-			10
Tax benefit from exercise of common stock options		-			-		21			-			-			21
Other equity transactions		-			-		3			-			-			3
Balance, December 31, 2007		75			-		5,454			3,782			90			9,326
Net income		-			-		-			1,850			-			1,850
Other comprehensive income:
Foreign currency translation adjustment		-			-		-			-			(802	)		(802	)
Fair value adjustment on cash flow hedges, net of tax of $(41)		-			-		-			-			(64	)		(64	)
Unrecognized amounts on retirement benefits, net of tax of $(28)		-			-		-			-			(72	)		(72	)
Unrealized losses on marketable securities, net of tax of $(20)		-			-		-			-			(31	)		(31	)
Total comprehensive income																881
Other equity transactions		-			-		1			(1	)		-			-
Balance, December 31, 2008		75		$	-	$	5,455		$	5,631		$	(879	)	$	10,207

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

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MIDAMERICAN ENERGY HOLDINGS COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Amounts in millions)

	Years Ended December 31,
	2008			2007			2006
Cash flows from operating activities:
Net income	$	1,850		$	1,189		$	916
Adjustments to reconcile net income to net cash flows
from operating activities:
Gain on other items, net		(918	)		(12	)		(145	)
Depreciation and amortization		1,129			1,150			1,007
Amortization of regulatory assets and liabilities		(23	)		(16	)		26
Provision for deferred income taxes		766			129			260
Other		(22	)		(59	)		69
Changes in other operating assets and liabilities, net of effects from acquisitions:
Trade receivables and other assets		(90	)		(265	)		3
Derivative contract assets and liabilities		(120	)		10			(42	)
Contributions to company-sponsored postretirement plans, net		(98	)		(43	)		(68	)
Accounts payable and other accrued liabilities		113			252			(103	)
Net cash flows from operating activities		2,587			2,335			1,923
Cash flows from investing activities:
Capital expenditures		(3,937	)		(3,512	)		(2,423	)
PacifiCorp acquisition, net of cash acquired		-			-			(4,932	)
Other acquisitions, net of cash acquired		(308	)		-			(74	)
Purchases of available-for-sale securities		(203	)		(1,641	)		(1,504	)
Proceeds from sale of available-for-sale securities		216			1,586			1,606
Proceeds from maturity of guaranteed investment contracts		393			201			-
Proceeds from conversion of CEG 8% preferred stock		418			-			-
Purchase of CEG 8% preferred stock		(1,000	)		-			-
Proceeds from sale of assets		93			65			30
(Increase) decrease in restricted cash		(21	)		75			(32	)
Other		5			(24	)		8
Net cash flows from investing activities		(4,344	)		(3,250	)		(7,321	)
Cash flows from financing activities:
Proceeds from MEHC senior and subordinated debt		1,649			1,539			1,699
Repayments of MEHC senior and subordinated debt		(1,803	)		(784	)		(234	)
Proceeds from subsidiary debt		1,498			2,000			718
Repayments of subsidiary debt		(1,077	)		(549	)		(516	)
Net (payment of) proceeds from hedging instruments		(99	)		(18	)		53
Net borrowings (repayments) on MEHC revolving credit facility		216			(152	)		101
Net borrowings (repayments) of subsidiary short-term debt		509			(269	)		196
Proceeds from issuances of common stock		-			10			5,132
Purchases of common stock		-			-			(1,750	)
Other		(27	)		(30	)		(22	)
Net cash flows from financing activities		866			1,747			5,377
Effect of exchange rate changes		(7	)		3			6
Net change in cash and cash equivalents		(898	)		835			(15	)
Cash and cash equivalents at beginning of period		1,178			343			358
Cash and cash equivalents at end of period	$	280		$	1,178		$	343

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

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MIDAMERICAN ENERGY HOLDINGS COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(1) Organization and Operations

MidAmerican Energy Holdings Company (“MEHC”) is a holding company which owns subsidiaries that are principally engaged in energy businesses (collectively with its subsidiaries, the “Company”). MEHC is a consolidated subsidiary of Berkshire Hathaway Inc. (“Berkshire Hathaway”). The Company is organized and managed as eight distinct platforms: PacifiCorp (which was acquired on March 21, 2006), 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, a combined 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.

(2) Summary of Significant Accounting Policies

Basis of Consolidation

The Consolidated Financial Statements include the accounts of MEHC and its subsidiaries in which it holds a controlling financial interest as of the financial statement date. The Consolidated Statements of Operations include the revenues and expenses of an acquired entity from the date of acquisition. Intercompany accounts and transactions have been eliminated. Certain amounts in the prior year Consolidated Financial Statements have been reclassified to conform to the current year presentation. Such reclassifications did not impact previously reported operating income, net income or retained earnings.

Use of Estimates in Preparation of Financial Statements

The preparation of the Consolidated Financial Statements in conformity with accounting principles generally accepted in the United States of America (“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 revenues and expenses during the period. These estimates include, but are not limited to, unbilled revenue, valuation of certain financial assets and liabilities, effects of regulation, long-lived asset recovery, goodwill impairment, accounting for contingencies, including environmental, regulatory and income tax matters, asset retirement obligations, and certain assumptions made in accounting for pension and other postretirement benefits. Actual results may differ from the estimates used in preparing the Consolidated Financial Statements.

Cash Equivalents and Restricted Cash and Investments

Cash equivalents consist of funds invested in commercial paper, money market accounts and in other investments with a maturity of three months or less when purchased. Cash and cash equivalents exclude amounts where availability is restricted by legal requirements, loan agreements or other contractual provisions. Restricted amounts are included in other current assets and deferred charges, investments and other in the Consolidated Balance Sheets.

Investments

The Company’s management determines the appropriate classifications of investments in debt and equity securities at the acquisition date and re-evaluates the classifications at each balance sheet date.

Available-for-sale securities are carried at fair value with realized gains and losses, as determined on a specific identification basis, recognized in earnings and unrealized gains and losses recognized in accumulated other comprehensive income (“AOCI”), net of tax. Realized and unrealized gains and losses on certain trust funds related to the decommissioning of nuclear generation assets and the final reclamation of leased coal mining property are recorded as net regulatory assets or liabilities since the Company expects to recover costs for these activities through rates. Trading securities are carried at fair value with realized and unrealized gains and losses recognized in earnings. Held-to-maturity securities are carried at amortized cost, reflecting the Company’s ability and intent to hold the securities to maturity.

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If in management’s judgment a decline in the fair value of an available-for-sale or held-to-maturity investment below cost is other than temporary, the cost of the investment is written down to fair value. Factors considered in judging whether an impairment is other than temporary include: the financial condition, business prospects and creditworthiness of the issuer, the length of time that fair value has been less than cost, the relative amount of the decline and the Company’s ability and intent to hold the investment until the fair value recovers.

The Company utilizes the equity method of accounting with respect to investments where it exercises significant influence, but not control, over the operating and financial policies of the investee. The equity method of accounting is normally applied where the Company has a voting interest of more than 20% and less than 50%. In applying the equity method, investments are recorded at cost and subsequently increased or decreased by the Company’s proportionate share of the net earnings or losses and other comprehensive income of the investee. Dividends or other equity distributions are recorded as a reduction of the investment. Equity investments are required to be tested for impairment when it is determined that an other-than-temporary loss in value below the carrying amount has occurred.

Accounting for the Effects of Certain Types of Regulation

PacifiCorp, MidAmerican Energy, Northern Natural Gas and Kern River (the “Domestic Regulated Businesses”) prepare their financial statements in accordance with the provisions of Statement of Financial Accounting Standards (“SFAS”) No. 71, “Accounting for the Effects of Certain Types of Regulation” (“SFAS No. 71”), which differs in certain respects from the application of GAAP by non-regulated businesses. In general, SFAS No. 71 recognizes that accounting for rate-regulated enterprises should reflect the economic effects of regulation. As a result, a regulated entity is required to defer the recognition of costs or income if it is probable that, through the rate-making process, there will be a corresponding increase or decrease in future rates. Accordingly, the Domestic Regulated Businesses have deferred certain costs and income that will be recognized in earnings over various future periods.

Management continually evaluates the applicability of SFAS No. 71 and assesses whether its regulatory assets are probable of future recovery by considering factors such as a change in the regulator’s approach to setting rates from cost-based ratemaking to another form of regulation, other regulatory actions or the impact of competition which could limit the Domestic Regulated Businesses’ ability to recover their costs. Based upon this continual assessment, management believes the application of SFAS No. 71 continues to be appropriate and its existing regulatory assets are probable of recovery. The assessment reflects the current political and regulatory climate at both the state and federal levels and is subject to change in the future. If it becomes no longer probable that these costs will be recovered, the related regulatory assets and regulatory liabilities would be written off and recognized in operating income.

Allowance for Doubtful Accounts

The allowance for doubtful accounts is based on the Company’s assessment of the collectibility of payments from its customers. This assessment requires judgment regarding the ability of customers to pay the amounts owed to the Company or the outcome of any pending disputes. As of December 31, 2008 and 2007, the allowance for doubtful accounts totaled $24 million and $22 million, respectively, and is included in trade receivables, net in the Consolidated Balance Sheets.

Derivatives

The Company employs a number of different commodity and financial derivative instruments, including forward contracts, futures, options, swaps and other agreements, to manage commodity price, for example natural gas and electricity volatility, foreign currency exchange rate and interest rate risks. Derivative instruments are recorded in the Consolidated Balance Sheets as either assets or liabilities and are stated at fair value unless they are designated as normal purchases or normal sales and qualify for the exemption afforded by GAAP. Derivative balances reflect reductions permitted under master netting arrangements with counterparties and cash collateral paid or received under such agreements. Cash collateral received from or paid to counterparties to secure derivative contract assets or liabilities in excess of amounts offset is included in other current assets in the Consolidated Balance Sheets.

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Derivative contracts for commodities used in normal business operations that are settled by physical delivery, among other criteria, are eligible for and may be designated as normal purchases and normal sales pursuant to the exemption. Contracts that qualify and are designated as normal purchases or normal sales are not marked to market. Recognition of these contracts in operating revenue or cost of sales in the Consolidated Statements of Operations occurs when the contracts settle.

For contracts designated in hedge relationships (“hedge contracts”), the Company formally assesses, at inception and thereafter, whether the hedge contracts are highly effective in offsetting changes in the hedged items. The Company formally documents hedging activity by transaction type and risk management strategy.

Changes in the fair value of a derivative designated and qualified as a cash flow hedge, to the extent effective, are included in the Consolidated Statements of Shareholders’ Equity as AOCI, net of tax, until the hedged item is recognized in earnings. The Company discontinues hedge accounting prospectively when it has determined that a derivative no longer qualifies as an effective hedge, or when it is no longer probable that the hedged forecasted transaction will occur. When hedge accounting is discontinued because the derivative no longer qualifies as an effective hedge, future changes in the value of the derivative are charged to earnings. Gains and losses related to discontinued hedges that were previously recorded in AOCI will remain in AOCI until the hedged item is realized, unless it is probable that the hedged forecasted transaction will not occur at which time associated deferred amounts in AOCI are immediately recognized in earnings.

Certain derivative electric and natural gas contracts utilized by the regulated operations of PacifiCorp and MidAmerican Energy are recoverable through rates. Accordingly, unrealized changes in fair value of these contracts are deferred as net regulatory assets or liabilities pursuant to SFAS No. 71.

Inventories

Inventories consist mainly of material and supplies totaling $310 million and $275 million as of December 31, 2008 and 2007, respectively, and fuel, which includes coal stocks, gas in storage and fuel oil, totaling $256 million and $201 million as of December 31, 2008 and 2007, respectively. Inventories are stated at the lower of cost or market. The cost of materials and supplies, coal stocks and fuel oil is determined primarily using average cost. The cost of gas in storage is determined using the last-in-first-out (“LIFO”) method. With respect to inventories carried at LIFO cost, the replacement cost would be $51 million and $73 million higher as of December 31, 2008 and 2007, respectively.

Property, Plant and Equipment, Net

General

Property, plant and equipment is recorded at historical cost. The Company capitalizes all construction related material, direct labor and contract services, as well as indirect construction costs, which include capitalized interest and equity allowance for funds used during construction (“AFUDC”). The cost of major additions and betterments are capitalized, while costs for replacements, maintenance and repairs that do not improve or extend the lives of the respective assets are charged to operating expense. Depreciation and amortization are generally computed by applying the composite or straight-line method based on estimated economic lives or regulatorily mandated recovery periods. Periodic depreciation studies are performed to determine the appropriate group lives, net salvage and group depreciation rates. These studies are reviewed and approved by the various regulatory bodies.

Generally when the Company retires or sells its domestic regulated property, plant and equipment, it charges the original cost to accumulated depreciation. Any net cost of removal is charged against the cost of removal regulatory liability that was established through depreciation rates. Net salvage is recorded in the related accumulated depreciation and amortization accounts and is considered in determining future deprecation rates. Any gain or loss on disposals of all other assets is recorded in income or expense.

The Domestic Regulated Businesses record AFUDC, which represents the estimated costs of debt and equity funds necessary to finance the construction of domestic regulated facilities. AFUDC is capitalized as a component of property, plant and equipment, with offsetting credits to the Consolidated Statements of Operations. After construction is completed, the Company is permitted to earn a return on these costs by their inclusion in rate base, as well as recover these costs through depreciation expense over the useful life of the related assets.

90 

Asset Retirement Obligations

The Company recognizes legal asset retirement obligations (“ARO”), mainly related to the decommissioning of nuclear generation assets and the final reclamation of leased coal mining property. The fair value of an ARO liability is recognized in the period in which it is incurred, if a reasonable estimate of fair value can be made, and is added to the carrying amount of the associated asset, which is then depreciated over the remaining useful life of the asset. Subsequent to the initial recognition, the ARO liability is adjusted for any revisions to the expected value of the retirement obligation (with corresponding adjustments to property, plant and equipment) and for accretion of the ARO liability due to the passage of time. The difference between the ARO liability, the corresponding ARO asset included in property, plant and equipment and amounts recovered in rates to satisfy such liabilities is recorded as a regulatory asset or liability. Estimated removal costs that PacifiCorp and MidAmerican Energy recover through approved depreciation rates, but that do not meet the requirements of a legal ARO, are accumulated in asset retirement removal costs within regulatory liabilities in the Consolidated Balance Sheets.

Impairment

The Company evaluates long-lived assets for impairment, including property, plant and equipment, when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable, or the assets meet the criteria of held for sale. Upon the occurrence of a triggering event, the asset is reviewed to assess whether the estimated undiscounted cash flows expected from the use of the asset plus the residual value from the ultimate disposal exceeds the carrying value of the asset. If the carrying value exceeds the estimated recoverable amounts, the asset is written down to the estimated discounted present value of the expected future cash flows from using the asset. For regulated assets, any impairment charge is offset by the establishment of a regulatory asset to the extent recovery in rates is probable. For all other assets, any resulting impairment loss is reflected in the Consolidated Statements of Operations.

Goodwill

Goodwill represents the difference between purchase cost and the fair value of net assets acquired in business acquisitions. Goodwill is allocated to each reporting unit and is tested at least annually for impairments using a variety of methods, principally discounted projected future net cash flows, with any impairments charged to earnings. The Company completed its annual review as of October 31. Key assumptions used in the testing include, but are not limited to, the use of estimated future cash flows, earnings before interest, taxes, depreciation and amortization (“EBITDA”) multiples and an appropriate discount rate. In estimating cash flows, the Company incorporates current market information as well as historical factors. During 2008, 2007 and 2006, the Company did not record any goodwill impairments.

The Company records goodwill adjustments for (i) changes in the estimates or the settlement of tax bases of acquired assets, liabilities and carryforwards and items relating to acquired entities’ prior income tax returns, (ii) the tax benefit associated with the excess of tax-deductible goodwill over the reported amount of goodwill, and (iii) changes to the purchase price allocation prior to the end of the allocation period, which is generally one year from the acquisition date.

Revenue Recognition

Energy Businesses

Revenue from energy business customers is recognized as electricity or natural gas is delivered or services are provided. Revenue recognized includes unbilled, as well as billed, amounts. As of December 31, 2008 and 2007, unbilled revenue was $444 million and $480 million, respectively, and is included in trade receivables, net in the Consolidated Balance Sheets.

Rates charged by the domestic regulated energy businesses are subject to federal and state regulation. When preliminary rates are permitted to be billed prior to final approval by the applicable regulator, certain revenue collected may be subject to refund and a provision for estimated refunds is accrued. Electric distribution revenues in the U.K. are limited to amounts allowed under their regulatory formula, while under-recoveries are not recognized in revenue. Over- or under-recoveries of amounts allowed under the regulatory formula are either refunded to customers or recovered through adjustments in future rates.

The Company records sales, franchise and excise taxes, which are collected directly from customers and remitted directly to the taxing authorities, on a net basis in the Consolidated Statements of Operations.

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Real Estate Commission Revenue and Related Fees

Commission revenue from real estate brokerage transactions and related amounts due to agents are recognized when a real estate transaction is closed. Title fee revenue from real estate transactions and related amounts due to the title insurer are recognized at closing.

Unamortized Debt Premiums, Discounts and Financing Costs

Premiums, discounts and financing costs incurred during the issuance of long-term debt are amortized over the term of the related financing using the effective interest method.

Foreign Currency

The accounts of foreign-based subsidiaries are measured in most instances using the local currency as the functional currency. Revenue and expenses of these businesses are translated into U.S. dollars at the average exchange rate for the period. Assets and liabilities are translated at the exchange rate as of the end of the reporting period. Gains or losses from translating the financial statements of foreign-based operations are included in shareholders’ equity as a component of AOCI. Gains or losses arising from other transactions denominated in a foreign currency are included in the Consolidated Statements of Operations.

Income Taxes

Berkshire Hathaway commenced including the Company in its U.S. federal income tax return in 2006 as a result of converting its convertible preferred stock of MEHC into shares of MEHC common stock on February 9, 2006. The Company’s provision for income taxes has been computed on a stand-alone basis. Prior to the conversion, the Company filed a consolidated U.S. federal income tax return.

Deferred tax assets and liabilities are based on differences between the financial statements and tax bases of assets and liabilities using the estimated tax rates in effect for the year in which the differences are expected to reverse. Changes in deferred income tax assets and liabilities that are associated with components of other comprehensive income are charged or credited directly to other comprehensive income. Changes in deferred income tax assets and liabilities that are associated with income tax benefits related to certain property-related basis differences and other various differences that PacifiCorp and MidAmerican Energy are required to pass on to their customers in most state jurisdictions are charged or credited directly to a regulatory asset or regulatory liability. These amounts were recognized as a net regulatory asset totaling $607 million and $606 million as of December 31, 2008 and 2007, respectively, and will be included in rates when the temporary differences reverse. Other changes in deferred income tax assets and liabilities are included as a component of income tax expense. Valuation allowances have been established for certain deferred tax assets where management has judged that realization is not likely.

Investment tax credits are generally deferred and amortized over the estimated useful lives of the related properties or as prescribed by various regulatory jurisdictions.

The Company has not provided U.S. federal deferred income taxes on its currency translation adjustment or the cumulative earnings of international subsidiaries that have been determined by management to be reinvested indefinitely. The cumulative earnings related to ongoing operations determined to be reinvested indefinitely were approximately $1 billion as of December 31, 2008. Because of the availability of U.S. foreign tax credits, it is not practicable to determine the U.S. federal income tax liability that would be payable if such earnings were not reinvested indefinitely. Deferred taxes are provided for earnings of international subsidiaries when the Company plans to remit those earnings.

In determining the Company’s income taxes, management is required to interpret complex tax laws and regulations. In preparing tax returns, the Company is subject to continuous examinations by federal, state, local and foreign tax authorities that may give rise to different interpretations of these complex laws and regulations. Due to the nature of the examination process, it generally takes years before these examinations are completed and these matters are resolved. The U.S. Internal Revenue Service has closed examination of the Company’s income tax returns through 2003. In the U.K., each legal entity is subject to examination by HM Revenue and Customs (“HMRC”), the U.K. equivalent of the U.S. Internal Revenue Service. HMRC has closed examination of income tax returns for all entities through 2006. In addition, state jurisdictions have closed examination of the Company’s income tax returns through at least 2002, except for PacifiCorp where the examinations have been closed through 1993 in most cases. The Company’s income tax returns in the Philippines, the most significant other foreign jurisdiction, have been closed through at least 2003. Although the ultimate resolution of the Company’s federal, state and foreign tax examinations is uncertain, the Company believes it has made adequate provisions for these tax positions and the aggregate amount of any additional tax liabilities that may result from these examinations, if any, will not have a material adverse affect on the Company’s financial results. Assets and liabilities are established for uncertain tax positions taken or positions expected to be taken in income tax returns when such positions are judged to not meet the “more-likely-than-not” threshold based on the technical merits of the position. The Company’s unrecognized tax benefits are primarily included in other long-term liabilities in the Consolidated Balance Sheets. The Company recognizes interest and penalties, if any, related to income taxes in income tax expense in the Consolidated Statements of Operations.

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New Accounting Pronouncements

In December 2008, the Financial Accounting Standards Board (the “FASB”) issued Staff Position (“FSP”) No. 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 the 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 position, financial performance and cash flows. SFAS No. 161 is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008, with early application encouraged. The Company is currently evaluating the impact of adopting SFAS No. 161 on its disclosures included within the Notes to Consolidated Financial Statements.

In December 2007, the FASB issued SFAS No. 141(R), “Business Combinations” (“SFAS No. 141(R)”). SFAS No. 141(R) applies to all transactions or other events in which an entity obtains control of one or more businesses. SFAS No. 141(R) establishes how the acquirer of a business should recognize, measure and disclose in its financial statements the identifiable assets and goodwill acquired, the liabilities assumed and any noncontrolling interest in the acquired business. SFAS No. 141(R) is applied prospectively for all business combinations with an acquisition date on or after the beginning of the first annual reporting period beginning on or after December 15, 2008, with early application prohibited. SFAS No. 141(R) will not have an impact on the Company’s historical Consolidated Financial Statements and will be applied to business combinations completed, if any, on or after January 1, 2009.

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. SFAS No. 160 requires entities to report noncontrolling interests as a separate component of shareholders’ equity in the consolidated financial statements. The amount of earnings attributable to the parent and to the noncontrolling interests should be clearly identified and presented on the face of the consolidated statements of operations. Additionally, SFAS No. 160 requires any changes in a parent’s ownership interest of its subsidiary, while retaining its control, to be accounted for as equity transactions. SFAS No. 160 is effective for fiscal years beginning on or after December 15, 2008 and interim periods within those fiscal years. The Company is currently evaluating the impact of adopting SFAS No. 160 on its consolidated financial position and results of operations.

In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements” (“SFAS No. 157”). SFAS No. 157 defines fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements. SFAS No. 157 does not impose fair value measurements on items not already accounted for at fair value; rather it applies, with certain exceptions, to other accounting pronouncements that either require or permit fair value measurements. Under SFAS No. 157, fair value refers to the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants in the principal or most advantageous market. The standard clarifies that fair value should be based on the assumptions market participants would use when pricing the asset or liability. In February 2008, the FASB issued FSP No. 157-2, “Effective Date of FASB Statement No. 157” (“FSP FAS 157-2”), which delays the effective date of SFAS No. 157 for all non-financial assets and liabilities, except those that are recognized or disclosed at fair value in the consolidated financial statements on a recurring basis, until fiscal years beginning after November 15, 2008. These non-financial items include assets and liabilities such as non-financial assets and liabilities assumed in a business combination, reporting units measured at fair value in a goodwill impairment test and AROs initially measured at fair value. In October 2008, the FASB issued FSP No. 157-3, “Determining the Fair Value of a Financial Asset When the Market for That Asset Is Not Active” (“FSP FAS 157-3”), which clarifies the application of SFAS No. 157 in a market that is not active and provides an example to illustrate key considerations in determining the fair value of a financial asset when the market for that financial asset is not active. FSP FAS 157-3 was effective upon issuance, including prior periods for which financial statements had not been issued. The Company applied the guidance of FSP FAS 157-3 when determining the fair value of its auction rate securities. The Company adopted the provisions of SFAS No. 157 for assets and liabilities recognized at fair value on a recurring basis effective January 1, 2008. The partial adoption of SFAS No. 157 did not have a material impact on the Company’s Consolidated Financial Statements. Refer to Note 7 for additional discussion.

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(3) Acquisitions

PacifiCorp

In May 2005, MEHC reached a definitive agreement with Scottish Power plc (“ScottishPower”) and its subsidiary, PacifiCorp Holdings, Inc., to acquire 100% of the common stock of ScottishPower’s wholly-owned indirect subsidiary, PacifiCorp. On March 21, 2006, a wholly owned subsidiary of MEHC acquired 100% of the common stock of PacifiCorp from a wholly owned subsidiary of ScottishPower for a cash purchase price of $5.11 billion, which was funded through the issuance of common stock (see Note 19). MEHC also incurred $10 million of direct transaction costs associated with the acquisition, which consisted principally of investment banker commissions and outside legal and accounting fees, resulting in a total purchase price of $5.12 billion. As a result of the acquisition, MEHC controls substantially all of PacifiCorp’s voting securities, which include both common and preferred stock. The results of PacifiCorp’s operations are included in the Company’s results beginning March 21, 2006.

Pro Forma Financial Information

The following pro forma condensed consolidated results of operations assume that the acquisition of PacifiCorp was completed as of January 1, 2006, and provides information for the year ended December 31, 2006 (in millions):

Operating revenue	$	11,453
Net income	$	1,060

The pro forma financial information represents the historical operating results of the combined company with adjustments for purchase accounting and is not necessarily indicative of the results of operations that would have been achieved if the acquisition had taken place at the beginning of the period presented.

Chehalis Power Generating, LLC

On September 15, 2008, after having received the required regulatory approvals, PacifiCorp acquired from TNA Merchant Projects, Inc., an affiliate of Suez Energy North America, Inc., 100% of the equity interests of Chehalis Power Generating, LLC, an entity owning a 520-MW natural gas-fired generating plant located in Chehalis, Washington. The total cash purchase price was $308 million and the estimated fair value of the acquired entity was primarily allocated to the generating plant. Chehalis Power Generating, LLC was merged into PacifiCorp immediately following the acquisition. The results of the plant’s operations have been included in the Company’s Consolidated Financial Statements since the acquisition date.

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BYD Company Limited

In September 2008, MEHC reached a definitive agreement with BYD Company Limited (“BYD”) to purchase 225 million shares, representing approximately a 10% interest in the company, at a price of Hong Kong (“HK”) $8 per share or HK$1.8 billion (approximately $230 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 closing remains subject to approval by the China Securities Regulatory Commission and the filing of amendments to BYD’s articles of association. In the event that the conditions precedent are not fulfilled by March 26, 2009 the parties are not bound to proceed with the transaction. MEHC expects the transaction to close in 2009.

(4) Property, Plant and Equipment, Net

Property, plant and equipment, net consist of the following as of December 31 (in millions):

	Depreciation
	Life	2008			2007
Regulated assets:
Utility generation, distribution and transmission system	5-85 years	$	32,795		$	30,369
Interstate pipeline assets	3-67 years		5,649			5,484
			38,444			35,853
Accumulated depreciation and amortization			(12,456	)		(12,280	)
Regulated assets, net			25,988			23,573
Non-regulated assets:
Independent power plants	10-30 years		681			680
Other assets	3-30 years		547			650
			1,228			1,330
Accumulated depreciation and amortization			(430	)		(427	)
Non-regulated assets, net			798			903
Net operating assets			26,786			24,476
Construction in progress			1,668			1,745
Property, plant and equipment, net		$	28,454		$	26,221

Substantially all of the construction in progress as of December 31, 2008 and 2007 relates to the construction of regulated assets.

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(5) Jointly Owned Utility Facilities

Under joint facility ownership agreements with other utilities, both PacifiCorp and MidAmerican Energy, as tenants in common, have undivided interests in jointly owned generation and transmission facilities. The Company accounts for its proportional share of each facility, and each joint owner has provided financing for its share of each generating facility or transmission line. Operating costs of each facility are assigned to joint owners based on ownership percentage or energy purchased, depending on the nature of the cost. Operating costs and expenses in the Consolidated Statements of Operations include the Company’s share of the expenses of these facilities.

The amounts shown in the table below represent the Company’s share in each jointly owned facility as of December 31, 2008 (dollars in millions):

						Accumulated		Construction
	Company			Facility in		Depreciation/		Work-in-
	Share			Service		Amortization		Progress
PacifiCorp:
Jim Bridger Nos. 1-4		67	%	$	996	$	481	$	29
Wyodak		80			333		172		4
Hunter No. 1		94			305		150		8
Colstrip Nos. 3 and 4		10			244		121		2
Hunter No. 2		60			194		90		10
Hermiston(1)		50			173		41		-
Craig Nos. 1 and 2		19			168		79		-
Hayden No. 1		25			45		21		1
Foote Creek		79			37		15		-
Hayden No. 2		13			28		14		1
Other transmission and distribution facilities	Various				83		19		-
Total PacifiCorp					2,606		1,203		55
MidAmerican Energy:
Walter Scott, Jr. Unit No. 4		60	%		656		28		-
Louisa Unit No. 1		88			758		355		-
Walter Scott, Jr. Unit No. 3		79			349		239		156
Quad Cities Unit Nos. 1 and 2		25			335		153		22
Ottumwa Unit No. 1		52			265		154		4
George Neal Unit No. 4		41			170		129		-
George Neal Unit No. 3		72			146		112		2
Transmission facilities	Various				170		48		-
Total MidAmerican Energy					2,849		1,218		184
Total				$	5,455	$	2,421	$	239

(1) PacifiCorp has contracted to purchase the remaining 50% of the output of the Hermiston plant.

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(6) Regulatory Matters

Regulatory Assets and Liabilities

Regulatory assets represent costs that are expected to be recovered in future rates. The Company’s regulatory assets reflected in the Consolidated Balance Sheets consist of the following as of December 31 (in millions):

	Weighted
	Average
	Remaining Life	2008		2007
Deferred income taxes(1)	29 years	$	675	$	680
Employee benefit plans(2)	11 years		663		274
Unrealized loss on regulated derivatives(3)	6 years		498		276
Other	Various		320		273
Total		$	2,156	$	1,503

(1)	Amounts represent income tax benefits related to state accelerated tax depreciation and certain property-related basis differences that were previously flowed through to customers and will be included in rates when the temporary differences reverse.
(2)	Represents amounts not yet recognized as components of net periodic benefit cost that will be recovered in rates when recognized.
(3)	Amounts represent net unrealized losses related to derivative contracts included in rates.

The Company had regulatory assets not earning a return or earning less than the stipulated return as of December 31, 2008 and 2007 of $1.9 billion and $1.3 billion, respectively.

Regulatory liabilities represent income to be recognized or amounts to be returned to customers in future periods. The Company’s regulatory liabilities reflected in the Consolidated Balance Sheets consist of the following as of December 31 (in millions):

	Weighted
	Average
	Remaining Life	2008		2007
Cost of removal accrual(1) (2)	30 years	$	1,265	$	1,198
Asset retirement obligations(1)	30 years		90		148
Unrealized gain on regulated derivatives	1 year		52		-
Employee benefit plans(3)	14 years		10		173
Other	Various		89		110
Total		$	1,506	$	1,629

(1)	Amounts are deducted from rate base or otherwise accrue a carrying cost.
(2)	Amounts represent the remaining estimated costs, as accrued through depreciation rates and exclusive of ARO liabilities, of removing assets in accordance with accepted regulatory practices.
(3)	Represents amounts not yet recognized as components of net periodic benefit cost that are to be returned to customers in future periods when recognized in net periodic benefit cost.

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Rate Matters

Iowa Electric Revenue Sharing

The Iowa Utilities Board (“IUB”) has approved a series of settlement agreements between MidAmerican Energy, the Iowa Office of Consumer Advocate (“OCA”) and other intervenors, under which MidAmerican Energy has agreed not to seek a general increase in electric base rates to become effective prior to January 1, 2014, unless its Iowa jurisdictional electric return on equity for any year covered by the applicable agreement falls below 10%, computed as prescribed in each respective agreement. As a party to the settlement agreements, the OCA has agreed not to request or support any decrease in MidAmerican Energy’s Iowa electric base rates to become effective prior to January 1, 2014.

The settlement agreements also each provide that revenues associated with Iowa retail electric returns on equity above 11.75% will be shared with customers in the form of credits against either the cost of new generation plant in Iowa or as a credit to their bills. The portion shared with customers is recorded as a regulatory liability and charged to depreciation and amortization expense when accrued. Credits are applied to the cost of new generation when the related facility is placed in service and depreciation expense is reduced over the life of the facility.

Kern River Rate Case

Kern River’s 2004 general rate case hearing concluded in August 2005. On March 2, 2006, Kern River received an initial decision on the case from the administrative law judge. On October 19, 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. The order also affirmed the rejection of certain issues included in Kern River’s filed position, including the 95% load factor for vintage shippers and a 3% inflation factor for operating and maintenance costs. Kern River and other parties filed their requests for rehearing of the initial order on November 20, 2006. On April 18, 2008, the FERC issued an order denying rehearing on the issues raised by Kern River and other parties to the proceeding except Kern River’s request to include master limited partnerships in the proxy group for determining the allowed rate of return on equity. The grant of rehearing on this issue is consistent with the FERC’s April 17, 2008 adoption of a policy statement that addresses the inclusion of master limited partnerships in the proxy group used to determine a pipeline’s allowed return on equity. The FERC reopened the record for a paper hearing to determine Kern River’s return on equity in accordance with the policy statement.

On September 30, 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, representing 93% of Kern River’s contracted entitlement. In accordance with the terms of the Settlement, those shippers that agreed to support the Settlement were charged the lower Settlement rates beginning October 1, 2008. On January 15, 2009, the FERC issued an order that rejected the Settlement, finding that the 12.5% return on equity was excessive and would result in unjust and unreasonable rates. The FERC determined that Kern River’s allowed return on equity should be 11.55%. The FERC directed Kern River to make a revised compliance filing by March 2, 2009. Comments are due March 31, 2009 and reply comments on April 15, 2009.

Kern River was permitted to bill the requested rate increase prior to final approval by the FERC, subject to refund, beginning effective November 1, 2004. Kern River has recorded a provision for rate refunds totaling $25 million and $191 million as of December 31, 2008 and 2007, respectively. Pursuant to the terms of the Settlement, Kern River paid rate refunds of $179 million to shippers that supported the Settlement, subject to a “keep whole” provision in the Settlement that allows Kern River to recover all refunds paid, with interest. Kern River will propose in the March 2, 2009, compliance filing to true-up the early refunds with other amounts owed between Kern River and its shippers upon the final order from the FERC following the compliance procedure ordered by the FERC’s January 15, 2009 order.

Oregon Senate Bill 408

In October 2007, PacifiCorp filed its tax report for 2006 under Oregon Senate Bill 408 (“SB 408”), which was enacted in September 2005. SB 408 requires that PacifiCorp and other large regulated, investor-owned utilities that provide electric or natural gas service to Oregon customers file a report annually 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 filing indicated that for the 2006 tax year, PacifiCorp paid $33 million more in federal, state and local taxes than was collected in rates from its retail customers. PacifiCorp proposed to recover $27 million of the deficiency over a one-year period starting June 1, 2008 and to defer any excess into a balancing account for future disposition. During the review process, PacifiCorp updated its filing to address the OPUC’s staff recommendations, which increased the initial request by $2 million for a total of $35 million. In April 2008, the OPUC approved PacifiCorp’s revised request with $27 million 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 June 2008, PacifiCorp recorded a $27 million regulatory asset and associated revenues representing the amount that PacifiCorp will collect from its Oregon retail customers over the one-year period that began on June 1, 2008.

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In May 2008, the Industrial Customers of Northwest Utilities (“ICNU”) filed a petition with the Court of Appeals of the State of Oregon seeking judicial review of the final order with regards to PacifiCorp’s 2006 SB 408 tax report. In December 2008, ICNU filed their opening brief. PacifiCorp and the OPUC have until March 27, 2009 to file their response briefs. PacifiCorp believes the outcome of the judicial review will not have a material impact on its consolidated financial results.

In October 2008, PacifiCorp filed its tax report for 2007 under SB 408. PacifiCorp’s filing indicated that for the 2007 tax year, PacifiCorp paid $4 million more in federal, state and local taxes than was collected in rates from its retail customers.

(7) Fair Value Measurements

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

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

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

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

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

	Input Levels for Fair Value Measurements
Description	Level 1			Level 2			Level 3			Other(1)			Total
Assets(2):
Investments in available-for-sale securities	$	216		$	123		$	37		$	-		$	376
Investments in trading securities		499			-			-			-			499
Commodity derivatives		2			549			136			(363	)		324
	$	717		$	672		$	173		$	(363	)	$	1,199
Liabilities:
Commodity derivatives	$	(55	)	$	(632	)	$	(505	)	$	469		$	(723	)
Interest rate swap		-			(6	)		-			-			(6	)
	$	(55	)	$	(638	)	$	(505	)	$	469		$	(729	)

(1)	Primarily represents netting under master netting arrangements and cash collateral requirements.
(2)	Does not include investments in either pension or other postretirement plan assets.

99

The Company’s investments in debt and equity securities are classified as either available-for-sale or trading 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 in a readily observable market, the fair value is determined using pricing models based on observable market inputs and quoted market prices of securities with similar characteristics. The fair value of the Company’s investments in auction rate securities, where there is no current liquid market, is determined using pricing models based on available observable market data and the Company’s judgment about the assumptions, including liquidity and nonperformance risks, which market participants would use when pricing the asset.

The Company uses various derivative instruments, including forward contracts, futures, options, swaps and other agreements. The fair value of derivative instruments is determined using unadjusted quoted prices for identical instruments on the applicable exchange in which the Company transacts. When quoted prices for identical instruments 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, and 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 the instrument is not actively traded. Given that limited market data exists for these instruments, 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.

The following table reconciles the beginning and ending balance of the Company’s assets and liabilities measured at fair value on a recurring basis using significant Level 3 inputs (in millions):

	Investments
	In Available-
	For-Sale			Commodity
	Securities			Derivatives
Balance, January 1, 2008	$	73		$	(311	)
Changes included in earnings(1)		(5	)		38
Unrealized gains (losses) included in other comprehensive income		(31	)		-
Unrealized gains (losses) included in regulatory assets and liabilities		-			(100	)
Purchases, sales, issuances and settlements		-			(9	)
Net transfers into Level 3		-			13
Balance, December 31, 2008	$	37		$	(369	)

(1) Changes included in earnings are reported as other, net for investments in available-for-sale securities or operating revenues for commodity derivatives in the Consolidated Statement of Operations. Included in earnings for the year ended December 31, 2008 were realized losses of $5 million related to investments in available-for-sale securities and unrealized gains of $8 million related to commodity derivatives held at December 31, 2008.

The Company’s long-term debt and current maturities of long-term debt are 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 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, including the current portion, as of December 31 (in millions):

	2008				2007
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt	$	19,396	$	19,396	$	19,693	$	20,525

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(8) Investments

Investments consist of the following as of December 31 (in millions):

	2008		2007
Constellation Energy 14% Senior Notes	$	1,000	$	-
Constellation Energy common stock		499		-
Nuclear decommissioning trust funds		223		276
Mine reclamation trust funds		78		112
Guaranteed investment contract		-		397
Auction rate securities		37		73
Other		38		52
Total investments	$	1,875	$	910
Reflected as:
Investments	$	1,505	$	397
Other current assets		15		13
Deferred charges, investments and other		355		500
	$	1,875	$	910

Noncurrent investments are included in deferred charges, investments and other in the Consolidated Balance Sheets as management does not intend to use them in current operations. Gross unrealized and realized gains and losses of investments are not material as of December 31, 2008 and 2007 and for the three years in the period ended December 31, 2008, respectively, except as discussed below related to Constellation Energy.

On September 19, 2008, MEHC, Constellation Energy Group, Inc. (“Constellation Energy”) and MEHC Merger Sub Inc. signed an Agreement and Plan of Merger (the “Merger Agreement”), under which Constellation Energy would have become an indirect wholly-owned subsidiary of MEHC. In addition, the Company purchased a $1 billion investment in CEG 8% Preferred Stock. On December 17, 2008, MEHC and Constellation Energy entered into a termination agreement, pursuant to which, among other things, the parties agreed to terminate the Merger Agreement. As a result of the termination, the Company received $175 million, which is recorded in other, net in the Consolidated Statement of Operations and converted the $1 billion of CEG 8% Preferred Stock into $1 billion of 14% Senior Notes due from Constellation Energy, 19.9 million shares of Constellation Energy common stock and cash totaling $418 million. The 19.9 million common shares had a fair value of $499 million as of December 31, 2008, which included $41 million of unrealized holding gains recognized in other, net in the Consolidated Statement of Operations. The investment in the 14% Senior Notes is classified as held to maturity and is reported at cost, which approximates fair value as of December 31, 2008. On January 12, 2009, the Company received $1 billion, plus accrued interest, in full satisfaction of the 14% Senior Notes from Constellation Energy.

MidAmerican Energy has established trusts for the investment of funds for decommissioning the Quad Cities Nuclear Station Units 1 and 2. These investments in debt and equity securities are classified as available-for-sale and are reported at fair value. Funds are invested in the trust in accordance with applicable federal investment guidelines and are restricted for use as reimbursement for costs of decommissioning the Quad Cities Station. As of December 31, 2008, 46% of the fair value of the trusts’ funds was invested in domestic common equity securities, 12% in domestic corporate debt securities and the remainder in investment grade municipal and U.S. Treasury bonds. As of December 31, 2007, 54% of the fair value of the trusts’ funds was invested in domestic common equity securities, 13% in domestic corporate debt securities and the remainder in investment grade municipal and U.S. Treasury bonds.

PacifiCorp has established a trust for the investment of funds for final reclamation of a leased coal mining property. These investments in debt and equity securities are classified as available-for-sale and are reported at fair value. Amounts funded are based on estimated future reclamation costs and estimated future coal deliveries. As of December 31, 2008 and 2007, 46% and 52%, respectively, of the fair value of the trust’s funds was invested in equity securities with the remainder invested in debt securities.

101 

In May 2005, certain indirect wholly owned subsidiaries of CE Electric UK purchased £300 million of fixed rate guaranteed investment contracts (£100 million at 4.75% and £200 million at 4.73%) from a portion of the proceeds of the issuance of £350 million of 5.125% bonds due in 2035. These guaranteed investment contracts matured in December 2007 (£100 million) and February 2008 (£200 million) and the proceeds were used to repay certain long-term debt of subsidiaries of CE Electric UK. The guaranteed investment contracts were reported at cost.

The Company has interest bearing auction rate securities with a par value of $73 million and remaining maturities of 8 to 28 years. These securities have historically provided liquidity through an auction process that reset the applicable interest rate at predetermined calendar intervals, usually every 28 days or less. The securities held have experienced multiple failed auctions and the failures resulted in the interest rate on these investments resetting at higher levels. Interest has been paid on the scheduled auction dates. The Company considers the securities to be temporarily impaired, except for an other-than-temporary decline in the fair value of $5 million recorded in the fourth quarter of 2008, and has recorded unrealized losses on the securities of $31 million, before tax, in AOCI. The Company has the intent and ability to hold the securities until the remaining principal investment is collected.

(9) Risk Management and Hedging Activities

The Company is exposed to the impact of market fluctuations in commodity prices, principally natural gas and electricity, particularly through its ownership of PacifiCorp and MidAmerican Energy. Interest rate risk exists on variable rate debt, commercial paper and future debt issuances. The Company is also exposed to foreign currency risk primarily due to its business operations and investments in Great Britain. The Company employs established policies and procedures to manage its risks associated with these market fluctuations using various commodity and financial derivative instruments, including forward contracts, futures, options, swaps and other agreements. The risk management process established by each business platform is designed to identify, assess, monitor, report, manage, and mitigate each of the various types of risk involved in its business. The Company does not engage in a material amount of proprietary trading activities.

The following table summarizes the various derivative mark-to-market positions included in the Consolidated Balance Sheet as of December 31, 2008 (in millions):

									Net		Accumulated
									Regulatory		Other
	Net Derivative Assets (Liabilities)(1)								Assets		Comprehensive
	Assets		Liabilities			Total			(Liabilities)		(Income) Loss(2)
Commodity	$	324	$	(723	)	$	(399	)	$	446	$	83
Interest rate		-		(6	)		(6	)		-		6
	$	324	$	(729	)	$	(405	)	$	446	$	89
Current	$	227	$	(183	)	$	44
Non-current		97		(546	)		(449	)
Total	$	324	$	(729	)	$	(405	)

(1)	Net derivative assets (liabilities) include $129 million of a net asset for cash collateral.
(2)	Before income taxes.

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The following table summarizes the various derivative mark-to-market positions included in the Consolidated Balance Sheet as of December 31, 2007 (in millions):

									Net			Accumulated
									Regulatory			Other
	Net Derivative Assets (Liabilities)								Assets			Comprehensive
	Assets		Liabilities			Total			(Liabilities)			(Income) Loss(1)
Commodity	$	396	$	(659	)	$	(263	)	$	277		$	(15	)
Foreign currency		1		(106	)		(105	)		(1	)		106
	$	397	$	(765	)	$	(368	)	$	276		$	91
Current	$	170	$	(266	)	$	(96	)
Non-current		227		(499	)		(272	)
Total	$	397	$	(765	)	$	(368	)

(1) Before income taxes.

Commodity Price Risk

The Company is subject to significant commodity risk particularly through its ownership of PacifiCorp and MidAmerican Energy. Exposures include variations in the price of wholesale electricity that is purchased and sold, fuel costs to generate electricity, and natural gas supply for regulated retail gas customers. Electricity and natural gas prices are subject to wide price swings as demand responds to, among many other items, changing weather, limited storage, transmission and transportation constraints, and lack of alternative supplies from other areas. To mitigate a portion of the risk, the Company uses derivative instruments, including forward contracts, futures, options, swaps and other agreements, to effectively secure future supply or sell future production at fixed prices. The settled cost of these contracts 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, that are probable of recovery in rates, are recorded as net regulatory assets or regulatory liabilities.

MidAmerican Energy uses futures, options, forward physical supply contracts and swap agreements to economically hedge electricity and natural gas commodity prices for physical delivery to nonregulated customers. Nonregulated retail physical electricity contracts are considered normal purchases or normal sales, and gains and losses on such contracts are recognized when settled. All other nonregulated gas and electric contracts are recorded at fair value. Other MEHC subsidiaries use derivative instruments such as swaps, future, forwards and options principally as cash flow hedges for spring operational sales, natural gas storage and other transactions.

Realized gains and losses on all hedges and hedge ineffectiveness are recognized in income as operating revenue, cost of sales or operating expenses depending upon the nature of the item being hedged. Net unrealized gains and losses on hedges utilized for regulatory purposes are generally recorded as regulatory assets and regulatory liabilities. As of December 31, 2008, the Company had cash flow hedges with expiration dates through December 2022. For the years ended December 31, 2008, 2007 and 2006, hedge ineffectiveness was insignificant. As of December 31, 2008, $43 million of pre-tax net unrealized losses are forecasted to be reclassified from AOCI into earnings over the next twelve months as contracts settle.

Foreign Currency Risk

MEHC selectively reduces its foreign currency risk by hedging through foreign currency derivatives. As of December 31, 2007, CE Electric UK had a currency rate swap agreement with a large multi-national financial institution for its U.S. dollar denominated $281 million 6.496%Yankee bonds. The swap agreement effectively converted the U.S. dollar fixed interest rate to a fixed rate in sterling. The estimated fair value of the swap agreement as of December 31, 2007 was a liability of $106 million based on quotes from the counterparties to these instruments and represented the estimated amount that the Company would expect to pay if these agreements had terminated. The swap agreement for $281 million of Yankee bonds expired with the maturity of the Yankee bonds on February 25, 2008.

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(10) Short-Term Debt and Revolving Credit Facilities

Short-term debt consists of the following as of December 31 (in millions):

	2008		2007
MEHC	$	216	$	-
PacifiCorp		85		-
MidAmerican Energy		457		86
CE Electric UK		78		44
Total short-term debt	$	836	$	130

MEHC

MEHC has an unsecured credit facility with $585 million available through July 2011 and then reducing to $479 million through July 2013 and a $250 million unsecured credit facility expiring in November 2009. The credit facilities have variable interest rates based on the London Interbank Offered Rate (“LIBOR”) plus a spread, which varies based on MEHC’s credit ratings for its senior unsecured long-term debt securities, or a base rate, at MEHC’s option. These facilities are for general corporate purposes and also support letters of credit for the benefit of certain subsidiaries and affiliates. As of December 31, 2008, MEHC had $216 million of borrowings outstanding under its credit facilities at an average rate of 3.05% and had letters of credit issued under the credit agreements totaling $43 million. As of December 31, 2007, MEHC had no borrowings outstanding under its credit facilities and had letters of credit issued under the credit agreements totaling $46 million. Each revolving credit agreement requires that MEHC’s ratio of consolidated debt to total capitalization, including current maturities, not exceed 0.70 to 1.0 as of the last day of any quarter.

PacifiCorp

PacifiCorp has a $635 million unsecured credit facility expiring in October 2012 and an unsecured credit facility with $760 million available through July 2011 and then reducing to $630 million through July 2013. The credit facilities have variable interest rates based on LIBOR plus a spread, which varies based on PacifiCorp’s credit ratings for its senior unsecured long-term debt securities, or a base rate, at PacifiCorp’s option. These facilities support PacifiCorp’s commercial paper program and its unenhanced variable-rate tax-exempt bond obligations. As of December 31, 2008, PacifiCorp had letters of credit issued under the credit agreements totaling $220 million to support variable-rate tax-exempt bond obligations and had no borrowings outstanding under its credit facilities. In addition, the credit facilities supported $85 million of commercial paper borrowings, at an average rate of 0.95%, and $38 million of unenhanced variable-rate tax-exempt bond obligations outstanding as of December 31, 2008. As of December 31, 2007, PacifiCorp had no borrowings outstanding under its credit facilities. Each revolving credit agreement requires that PacifiCorp’s ratio of consolidated debt to total capitalization, including current maturities, at no time exceed 0.65 to 1.0.

MidAmerican Energy

MidAmerican Energy has an unsecured credit facility with $645 million available through July 2012 and then reducing to $530 million through July 2013 and a $250 million unsecured credit facility expiring in October 2009. The $645 million credit facility has a variable interest rate based on LIBOR plus a spread, which varies based on MidAmerican Energy’s credit ratings for its senior unsecured long-term debt securities, or a base rate, at MidAmerican Energy’s option. The $250 million credit facility has a variable interest rate based on LIBOR plus 50% of the credit default swap CDX index, with a minimum of LIBOR plus 0.50% and a maximum of LIBOR plus 1.0%. These facilities support MidAmerican Energy’s commercial paper program and its variable-rate tax-exempt bond obligations. As of December 31, 2008, MidAmerican Energy had issued $457 million of commercial paper borrowings, at an average rate of 1.13%, had $195 million of variable-rate tax-exempt bond obligations outstanding as of December 31, 2008 and had no borrowings outstanding under its credit facilities. As of December 31, 2007, MidAmerican Energy had issued $86 million of commercial paper borrowings at an average rate of 4.46% and had no borrowings outstanding under its credit facilities. Each revolving credit agreement requires that MidAmerican Energy’s ratio of consolidated debt to total capitalization, including current maturities, not exceed 0.65 to 1.0 as of the last day of any quarter.

104 

CE Electric UK

CE Electric UK has a £100 million unsecured credit facility expiring in April 2010. The facility has a variable interest rate based on sterling LIBOR plus a spread that varies based on its credit ratings. As of December 31, 2008 and 2007, CE Electric UK had $78 million, at an interest rate of 2.40%, and $44 million, at an interest rate of 5.96%, respectively, of borrowings outstanding under its credit facility. The revolving credit agreement requires that CE Electric UK’s ratio of consolidated senior net debt to regulated asset value, including current maturities, not exceed 0.8 to 1.0 at CE Electric UK and 0.65 to 1.0 at Northern Electric and Yorkshire Electricity as of June 30 and December 31. Additionally, CE Electric UK’s interest coverage ratio shall not be less than 2.5 to 1.0.

HomeServices

HomeServices has a $125 million unsecured credit facility expiring in December 2010. The facility has a variable interest rate based on the prime lending rate or LIBOR, at HomeServices’ option, plus a spread that varies based on HomeServices’ total debt ratio. There were no borrowings outstanding under the facility as of December 31, 2008 and 2007. The revolving credit agreement requires that HomeServices’ ratio of consolidated total debt to earnings before interest, taxes, depreciation and amortization (“EBITDA”) not exceed 3.0 to 1.0 at the end of any fiscal quarter and its ratio of EBITDA to interest can not be less than 2.5 to 1.0 at the end of any fiscal quarter. Therefore, as of December 31, 2008, the availability under the credit facility was $31 million.

(11) MEHC Senior Debt

MEHC senior debt represents unsecured senior obligations of MEHC and consists of the following, including fair value adjustments and unamortized premiums and discounts, as of December 31 (in millions):

	Par Value		2008		2007
3.50% Senior Notes, due 2008	$	-	$	-	$	450
7.52% Senior Notes, due 2008		-		-		550
5.875% Senior Notes, due 2012		500		500		500
5.00% Senior Notes, due 2014		250		250		250
5.75% Senior Notes, due 2018		650		649		-
8.48% Senior Notes, due 2028		475		484		483
6.125% Senior Notes, due 2036		1,700		1,699		1,699
5.95% Senior Notes, due 2037		550		547		547
6.50% Senior Notes, due 2037		1,000		992		992
Total MEHC Senior Debt	$	5,125	$	5,121	$	5,471

(12) MEHC Subordinated Debt

MEHC subordinated debt consists of the following, including fair value adjustments, as of December 31 (in millions):

	Par Value		2008		2007
CalEnergy Capital Trust II-6.25%, due 2012	$	92	$	86	$	96
CalEnergy Capital Trust III-6.5%, due 2027		191		148		208
MidAmerican Capital Trust I-11%, due 2010		136		136		227
MidAmerican Capital Trust II-11%, due 2012		151		151		194
MidAmerican Capital Trust III-11%, due 2011		300		300		400
MidAmerican Capital Trust IV-11%, due 2015(1)		500		500		-
Total MEHC Subordinated Debt	$	1,370	$	1,321	$	1,125

(1) MEHC repaid $500 million on each of December 22, 2008 and January 13, 2009, 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 on September 19, 2008.

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The Capital Trusts were formed for the purpose of issuing trust preferred securities to holders and investing the proceeds received in subordinated debt issued by MEHC. The terms of the MEHC subordinated debt are substantially identical to those of the trust preferred securities. The MEHC subordinated debt associated with the CalEnergy Trusts is callable at the option of MEHC at any time at par value plus accrued interest. The MEHC subordinated debt associated with the MidAmerican Capital Trusts is not callable by MEHC except upon the limited occurrence of specified events. Distributions on the MEHC subordinated debt are payable either quarterly or semi-annually, depending on the issue, in arrears, and can be deferred at the option of MEHC for up to five years. During the deferral period, interest continues to accrue on the CalEnergy Capital Trusts at their stated rates, while interest accrues on the MidAmerican Capital Trusts at 13% per annum. The CalEnergy Capital Trust preferred securities are convertible any time into cash at the option of the holder for an aggregate amount of $216 million.

The MidAmerican Capital Trust preferred securities are held by Berkshire Hathaway and its affiliates, which are prohibited from transferring the securities absent an event of default to non-affiliated persons. Interest expense to Berkshire Hathaway for the years ended December 31, 2008, 2007 and 2006 was $111 million, $108 million and $134 million, respectively. Interest expense on the CalEnergy Capital Trusts for the years ended December 31, 2008, 2007 and 2006 was $24 million, $28 million and $27 million, respectively.

The MEHC subordinated debt is subordinated to all senior indebtedness of MEHC and is subject to certain covenants, events of default and optional and mandatory redemption provisions, all described in the indenture. Upon involuntary liquidation, the holder is entitled to par value plus any distributions in arrears. MEHC has agreed to pay to the holders of the trust preferred securities, to the extent that the applicable Trust has funds available to make such payments, quarterly distributions, redemption payments and liquidation payments on the trust preferred securities.

(13) Subsidiary Debt

MEHC’s direct and indirect subsidiaries are organized as legal entities separate and apart from MEHC and its other subsidiaries. Pursuant to separate financing agreements, substantially all or most of the properties of each of the Company’s subsidiaries (except CE Electric UK, MidAmerican Energy and Northern Natural Gas) are pledged or encumbered to support or otherwise provide the security for their own subsidiary debt. It should not be assumed that the assets of any subsidiary will be available to satisfy MEHC’s obligations or the obligations of its other subsidiaries. However, unrestricted cash or other assets 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. The long-term debt of subsidiaries may include provisions that allow MEHC’s subsidiaries to redeem it in whole or in part at any time. These provisions generally include make-whole premiums.

Distributions at these separate legal entities are limited by various covenants including, among others, leverage ratios, interest coverage ratios and debt service coverage ratios. As of December 31, 2008, all subsidiaries were in compliance with their covenants. However, Cordova Energy’s 537 MW gas-fired power plant in the Quad Cities, Illinois area is currently prohibited from making distributions by the terms of its indenture due to its failure to meet its debt service coverage ratio requirement.

Long-term debt of subsidiaries consists of the following, including fair value adjustments and unamortized premiums and discounts, as of December 31 (in millions):

	Par Value		2008		2007
PacifiCorp	$	5,576	$	5,568	$	5,167
MidAmerican Funding		700		657		654
MidAmerican Energy		2,872		2,865		2,471
Northern Natural Gas		1,000		1,000		950
Kern River		944		944		1,016
CE Electric UK		1,575		1,700		2,562
Cordova Funding		185		183		188
CE Casecnan		31		30		68
HomeServices		7		7		21
Total Subsidiary Debt	$	12,890	$	12,954	$	13,097

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PacifiCorp

The components of PacifiCorp’s long-term debt consist of the following, including unamortized premiums and discounts, as of December 31 (dollars in millions):

	Par Value		2008		2007
First mortgage bonds:
4.3% to 9.2%, due through 2013	$	977	$	976	$	1,390
5.0% to 8.7%, due 2014 to 2018		721		720		221
6.7% to 8.5%, due 2021 to 2023		324		324		324
6.7% due 2026		100		100		100
7.7% due 2031		300		299		299
5.3% to 6.4%, due 2034 to 2038		2,350		2,345		2,046
Tax-exempt obligations:
Variable-rate series (2008-0.7% to 2.6%, 2007-3.5% to 3.8%):
Due 2013, secured by first mortgage bonds		41		41		41
Due 2014 to 2025		325		325		325
Due 2024, secured by first mortgage bonds		176		176		176
3.4% to 5.7%, due 2014 to 2025, secured by first mortgage bonds		184		184		183
6.2%, due 2030		13		13		13
Capital lease obligations – 8.8% to 14.8%, due through 2036		65		65		49
Total PacifiCorp	$	5,576	$	5,568	$	5,167

In January 2009, PacifiCorp issued $350 million of its 5.50% First Mortgage Bonds due January 15, 2019 and $650 million of its 6.00% First Mortgage Bonds due January 15, 2039.

As of December 31, 2008, PacifiCorp had letters of credit available to provide credit enhancement and liquidity support for its variable-rate tax-exempt bond obligations totaling $517 million, of which $504 million is supporting principal payments and $13 million is supporting interest payments. These committed bank arrangements were fully available at December 31, 2008 and expire periodically through May 2012.

MidAmerican Funding

The components of MidAmerican Funding’s long-term debt consist of the following, including fair value adjustments, as of December 31 (dollars in millions):

	Par Value		2008		2007
6.339% Senior Notes, due 2009	$	175	$	174	$	172
6.75% Senior Notes, due 2011		200		200		200
6.927% Senior Bonds, due 2029		325		283		282
Total MidAmerican Funding	$	700	$	657	$	654

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MidAmerican Energy

The components of MidAmerican Energy’s mortgage bonds, pollution control revenue obligations and notes consist of the following, including unamortized premiums and discounts, as of December 31 (dollars in millions):

	Par Value		2008		2007
Tax-exempt obligations:
5.95% Series, due 2023, secured by general mortgage bonds	$	-	$	-	$	29
Variable-rate series (2008-1.14%, 2007-3.51%), due 2016-2038		195		195		121
Notes:
5.65% Series, due 2012		400		400		400
5.125% Series, due 2013		275		275		275
4.65% Series, due 2014		350		350		350
5.95% Series, due 2017		250		249		249
5.3% Series, due 2018		350		349		-
6.75% Series, due 2031		400		396		396
5.75% Series, due 2035		300		300		300
5.80% Series, due 2036		350		349		349
Other		2		2		2
Total MidAmerican Energy	$	2,872	$	2,865	$	2,471

Northern Natural Gas

The components of Northern Natural Gas’ long-term debt consist of the following, including unamortized premiums and discounts, as of December 31 (dollars in millions):

	Par Value		2008		2007
6.75% Senior Notes, due 2008	$	-	$	-	$	150
7.00% Senior Notes, due 2011		250		250		250
5.375% Senior Notes, due 2012		300		300		300
5.125% Senior Notes, due 2015		100		100		100
5.75% Senior Notes, due 2018		200		200		-
5.80% Senior Notes, due 2037		150		150		150
Total Northern Natural Gas	$	1,000	$	1,000	$	950

Kern River

The components of Kern River’s long-term debt, which is due in monthly installments, consist of the following as of December 31 (dollars in millions):

	Par Value		2008		2007
6.676% Senior Notes, due 2016	$	335	$	335	$	361
4.893% Senior Notes, due 2018		609		609		655
Total Kern River	$	944	$	944	$	1,016

Kern River provides a debt service reserve letter of credit in amounts equal to the next six months of principal and interest payments due on the loans which were equal to $64 million as of December 31, 2008 and 2007.

108 

CE Electric UK

The components of CE Electric UK and its subsidiaries’ long-term debt consist of the following, including fair value adjustments and unamortized premiums and discounts, as of December 31 (dollars in millions):

	Par Value(1)		2008		2007
6.496% Yankee Bonds, due 2008	$	-	$	-	$	281
8.875% Bearer Bonds, due 2020		146		178		232
9.25% Eurobonds, due 2020		293		349		481
7.25% Sterling Bonds, due 2022		293		320		425
7.25% Eurobonds, due 2028		270		285		388
5.125% Bonds, due 2035		293		289		391
5.125% Bonds, due 2035		219		218		296
CE Gas Credit Facility, 4.84% and 7.94%, due 2012		61		61		68
Total CE Electric UK	$	1,575	$	1,700	$	2,562

(1) Except for the Yankee bonds, which were denominated in U.S. dollars, the par values for these debt instruments are denominated in sterling and have been converted to U.S. dollars at the applicable exchange rate.

Cordova Funding

Cordova Funding Corporation (“Cordova Funding”) has senior secured bonds with interest rates ranging from 8.48% to 9.07%, due in semi-annual installments through 2019, having a total par value of $185 million. The outstanding balance of these bonds, including fair value adjustments, as of December 31, 2008 and 2007 was $183 million and $188 million, respectively.

MEHC has issued a limited guarantee of a specified portion of the final scheduled principal payment on December 15, 2019, on the Cordova Funding senior secured bonds in an amount up to a maximum of $37 million.

Annual Repayments of Long-Term Debt

The annual repayments of MEHC and subsidiary debt for the years beginning January 1, 2009 and thereafter, excluding fair value adjustments and unamortized premiums and discounts, are as follows (in millions):

	2009		2010		2011		2012		2013		Thereafter		Total
MEHC senior debt	$	-	$	-	$	-	$	500	$	-	$	4,625	$	5,125
MEHC subordinated debt		734		189		143		114		-		190		1,370
PacifiCorp		144		17		588		18		267		4,542		5,576
MidAmerican Funding		175		-		200		-		-		325		700
MidAmerican Energy		-		-		-		400		275		2,197		2,872
Northern Natural Gas		-		-		250		300		-		450		1,000
Kern River		75		79		81		81		80		548		944
CE Electric UK		-		-		6		55		-		1,514		1,575
Cordova Funding		6		9		9		10		11		140		185
CE Casecnan		14		17		-		-		-		-		31
HomeServices		7		-		-		-		-		-		7
Totals	$	1,155	$	311	$	1,277	$	1,478	$	633	$	14,531	$	19,385

(14) Asset Retirement Obligations

The Company estimates its ARO liabilities based upon detailed engineering calculations of the amount and timing of the future cash spending for a third party to perform the required work. Spending estimates are escalated for inflation and then discounted at a credit-adjusted, risk-free rate. Changes in estimates could occur for a number of reasons including plan revisions, inflation and changes in the amount and timing of expected work.

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The Company does not recognize liabilities for AROs for which the fair value cannot be reasonably estimated. Due to the indeterminate removal date, the fair value of the associated liabilities on certain transmission, distribution and other assets cannot currently be estimated and no amounts are recognized in the Consolidated Financial Statements other than those included in the regulatory removal cost liability established via approved depreciation rates.

The change in the balance of the total ARO liability, which is included in other long-term liabilities in the Consolidated Balance Sheets, is summarized as follows (in millions):

	2008			2007
Balance, January 1	$	422		$	423
Change in estimated costs		19			19
Additions		8			6
Retirements		(28	)		(49	)
Accretion		24			23
Balance, December 31	$	445		$	422

The Company’s most significant ARO liabilities related to the decommissioning of nuclear power plants at MidAmerican Energy and the reclamation of mine property at PacifiCorp.

The Nuclear Regulatory Commission (“NRC”) regulates the decommissioning of nuclear power plants, which includes the planning and funding for the decommissioning. In accordance with these regulations, MidAmerican Energy submits a biennial report to the NRC providing reasonable assurance that funds will be available to pay for its share of the Quad Cities Station decommissioning. The decommissioning costs are included in base rates in MidAmerican Energy’s Iowa tariffs. MidAmerican Energy’s share of estimated Quad Cities Station decommissioning costs was $159 million and $150 million as of December 31, 2008 and 2007, respectively, and is the asset retirement obligation for the Quad Cities Station. MidAmerican Energy has established trusts for the investment of decommissioning funds. The fair value of the assets held in the trusts was $230 million and $276 million as of December 31, 2008 and 2007, respectively, and is reflected in deferred charges, investments and other in the Consolidated Balance Sheets.

PacifiCorp’s coal mining operations are subject to the Surface Mining Control and Reclamation Act of 1977 and similar state statutes that establish operational, reclamation and closure standards that must be met during and upon completion of mining activities. These mandate that mining property be restored consistent with specific standards and the approved reclamation plan. PacifiCorp incurs expenditures for both ongoing and final reclamation. PacifiCorp’s ARO liabilities consist principally of mine reclamation obligations for its Jim Bridger mine that were $84 million and $110 million as of December 31, 2008 and 2007, respectively. PacifiCorp, by contract with Idaho Power Company, the minority owner of the Bridger Coal Company, maintains a trust for final reclamation of the Jim Bridger mine. The fair value of the assets held in trusts was $79 million and $117 million as of December 31, 2008 and 2007, respectively, and is reflected in other current assets and deferred charges, investments and other, including the minority interest joint-owner portions, in the Consolidated Balance Sheets.

Certain of the Company’s decommissioning and reclamation obligations relate to jointly-owned facilities and mine sites. As part of the joint facility ownership agreements, each subsidiary is committed to pay either a proportionate share of decommissioning costs based upon its ownership percentage or, in the case of mine reclamation obligations, PacifiCorp has committed to pay a proportionate share of mine reclamation costs based on the amount of coal purchased by PacifiCorp. In the event of a default by any of the other joint participants, the respective subsidiary may be obligated to absorb, directly, or by paying additional sums to the entity, a proportionate share of the defaulting party’s liability. The Company’s share of the decommissioning and reclamation obligations are recorded as ARO liabilities.

In addition to the ARO liabilities, the Company has accrued for the cost of removing other electric and gas assets through its depreciation rates, in accordance with accepted regulatory practices. These accruals are reflected as regulatory liabilities and total $1.27 billion and $1.20 billion as of December 31, 2008 and 2007, respectively.

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(15) Employee Benefit Plans

Domestic Operations

PacifiCorp sponsors defined benefit pension plans that cover the majority of its employees. PacifiCorp’s pension plans include a noncontributory defined benefit pension plan, a supplemental executive retirement plan (“SERP”) and certain joint trust union plans to which PacifiCorp contributes on behalf of certain bargaining units. MidAmerican Energy sponsors defined benefit pension plans covering substantially all employees of MEHC and its domestic energy subsidiaries other than PacifiCorp. MidAmerican Energy’s pension plans include a noncontributory defined benefit pension plan and a SERP. PacifiCorp and MidAmerican Energy also provide certain postretirement health care and life insurance benefits through various plans for eligible retirees.

Changes to the Company’s domestic defined benefit and other postretirement plans include the following:

·   In August 2008, non-union employee participants in the PacifiCorp-sponsored and MidAmerican Energy-sponsored noncontributory defined benefit pension plans were offered the option to continue to receive pay credits in their current cash balance pension plan or receive equivalent fixed contributions to the PacifiCorp-sponsored and MidAmerican Energy-sponsored 401(k) plans. The election was effective January 1, 2009, and resulted in the recognition of a $43 million curtailment gain. The Company recorded $41 million of the curtailment gain as a reduction to regulatory assets as of December 31, 2008, representing the amount to be returned to customers in rates.

·   Non-union employees hired on or after January 1, 2008, are not eligible to participate in the PacifiCorp-sponsored or MidAmerican Energy-sponsored noncontributory defined benefit pension plans. These non-union employees are eligible to receive enhanced benefits under the PacifiCorp-sponsored and MidAmerican Energy-sponsored 401(k) plans.

·   Effective December 31, 2007, Local Union No. 659 of the International Brotherhood of Electrical Workers (“Local 659”) elected to cease participation in the PacifiCorp-sponsored noncontributory defined benefit pension plan and participate only in the PacifiCorp-sponsored 401 (k) plan with enhanced benefits. As a result of this election, the Local 659 participants’ benefits were frozen as of December 31, 2007. This change resulted in a $2 million curtailment gain that was recorded as a reduction to regulatory assets as of December 31, 2008, based on the requirement to return the amount to customers in rates. Also as a result of this change, regulatory assets and PacifiCorp’s pension liability each decreased by $13 million.

·   Effective June 1, 2007, PacifiCorp switched from a traditional final-average-pay formula for its noncontributory defined benefit pension plan to a cash balance formula for its non-union employees. As a result of the change, benefits under the traditional final-average-pay formula were frozen as of May 31, 2007 for non-union employees, and PacifiCorp’s pension liability and regulatory assets each decreased by $111 million.

PacifiCorp adopted the measurement date provisions of SFAS No. 158 at December 31, 2008, which requires that an employer measure plan assets and benefit obligations at the end of the employer’s fiscal year. Effective December 31, 2008, PacifiCorp changed its measurement date from September 30 to December 31 and recorded a $14 million transitional adjustment, which included a $12 million increase to regulatory assets for the portion considered probable of recovery in rates and a $2 million pre-tax reduction in retained earnings. Also as a result of this transitional adjustment, PacifiCorp’s pension and other postretirement liabilities increased by $8 million and regulatory assets decreased by $6 million.

Net Periodic Benefit Cost

For purposes of calculating the expected return on pension plan assets, a market-related value is used. The market-related value of plan assets is calculated by spreading the difference between expected and actual investment returns over a five-year period beginning after the first year in which they occur. In addition, as differences between expected and actual investment returns are admitted into the market-related value of plan assets, the corresponding gains or losses are then amortized and included in the net amortization component of net periodic benefit cost.

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Combined net periodic benefit cost for the pension and other postretirement benefits plans included the following components for the years ended December 31 (in millions):

	Pension									Other Postretirement
	2008			2007			2006			2008			2007			2006
Service cost	$	53		$	55		$	49		$	12		$	14		$	14
Interest cost		108			111			97			47			47			40
Expected return on plan assets		(117	)		(112	)		(95	)		(43	)		(40	)		(30	)
Net amortization		8			28			27			16			21			20
Curtailment gains		(2	)		-			-			-			-			-
Net periodic benefit cost	$	50		$	82		$	78		$	32		$	42		$	44

Funded Status

The following table is a reconciliation of the combined fair value of plan assets as of December 31 (in millions):

	Pension						Other Postretirement
	2008			2007			2008			2007
Plan assets at fair value, beginning of year	$	1,638		$	1,548		$	603		$	532
Employer contributions		76			86			51			58
Participant contributions		-			-			24			20
Actual return on plan assets		(395	)		175			(154	)		56
Benefits paid		(172	)		(171	)		(68	)		(63	)
Plan assets at fair value, end of year	$	1,147		$	1,638		$	456		$	603

The following table is a reconciliation of the combined benefit obligations as of December 31 (in millions):

	Pension						Other Postretirement
	2008			2007			2008			2007
Benefit obligation, beginning of year	$	1,813		$	2,038		$	793		$	824
Service cost(1)		60			55			14			14
Interest cost(1)		124			111			55			47
Participant contributions		-			-			24			20
Plan amendments		(7	)		(130	)		(13	)		-
Curtailments		(18	)		-			-			-
Actuarial gain		(55	)		(90	)		(92	)		(49	)
Benefits paid, net of Medicare subsidy		(172	)		(171	)		(64	)		(63	)
Benefit obligation, end of year	$	1,745		$	1,813		$	717		$	793
Accumulated benefit obligation, end of year	$	1,675		$	1,702

(1) Included in the pension and other postretirement liabilities increase in connection with PacifiCorp’s measurement date change in 2008 was additional service cost of $7 million and $2 million and additional interest cost of $16 million and $8 million for the pension and other postretirement benefit plans, respectively.

112 

The combined funded status of the plans and the amounts recognized in the Consolidated Balance Sheets as of December 31 are as follows (in millions):

	Pension						Other Postretirement
	2008			2007			2008			2007
Plan assets at fair value, end of year	$	1,147		$	1,638		$	456		$	603
Less – Benefit obligations, end of year		1,745			1,813			717			793
Funded status		(598	)		(175	)		(261	)		(190	)
Contributions after the measurement date but before year-end		-			-			-			12
Amounts recognized in the Consolidated Balance Sheets	$	(598	)	$	(175	)	$	(261	)	$	(178	)
Amounts recognized in the Consolidated Balance Sheets:
Other current assets	$	-		$	-		$	1		$	-
Deferred charges, investments and other assets		-			77			-			-
Other current liabilities		(12	)		(11	)		-			-
Other long-term accrued liabilities		(586	)		(241	)		(262	)		(178	)
Amounts recognized	$	(598	)	$	(175	)	$	(261	)	$	(178	)

The SERPs have no plan assets; however the Company has Rabbi trusts that hold corporate-owned life insurance and other investments to provide funding for the future cash requirements of the SERPs. The cash surrender value of all of the policies included in the Rabbi trusts, net of amounts borrowed against the cash surrender value, plus the fair market value of other Rabbi trust investments, was $140 million and $159 million as of December 31, 2008 and 2007, respectively. These assets are not included in the plan assets in the above table, but are reflected in the Consolidated Balance Sheets. The portion of the pension plans’ projected benefit obligations related to the SERPs was $148 million and $155 million as of December 31, 2008 and 2007, respectively. PacifiCorp’s noncontributory defined benefit pension plan’s accumulated benefit obligation exceeded the fair value of the plan’s assets by $46 million as of December 31, 2007.

Unrecognized Amounts

The portion of the combined funded status of the plans not yet recognized in combined net periodic benefit cost as of December 31 is as follows (in millions):

	Pension						Other Postretirement
	2008			2007			2008			2007
Amounts not yet recognized as components of net periodic benefit cost:
Net loss	$	550		$	108		$	182		$	70
Prior service cost (credit)		(64	)		(109	)		(2	)		13
Net transition obligation		-			3			47			63
Regulatory deferrals(1)		(37	)		-			6			-
Total	$	449		$	2		$	233		$	146

(1) Consists of amounts related to the portion of the curtailment gains and the measurement date change transitional adjustment that are considered probable of inclusion in rates.

113 

A reconciliation of the amounts not yet recognized as components of combined net periodic benefit cost for the years ended December 31, 2008 and 2007 is as follows (in millions):

							Accumulated
							Other
	Regulatory			Regulatory			Comprehensive
	Asset			Liability			Loss			Total
Pension
Balance, January 1, 2007	$	423		$	(122	)	$	14		$	315
Net gain arising during the year		(123	)		(26	)		(6	)		(155	)
Prior service credit arising during the year		(129	)		-			(1	)		(130	)
Net amortization		(25	)		-			(3	)		(28	)
Total		(277	)		(26	)		(10	)		(313	)
Balance, December 31, 2007		146			(148	)		4			2
Net (gain) loss arising during the year		326			148			(1	)		473
Prior service credit arising during the year		(7	)		-			-			(7	)
Curtailment gains		(15	)		-			-			(15	)
Measurement date change		6			-			-			6
Net amortization(1)		(9	)		-			(1	)		(10	)
Total		301			148			(2	)		447
Balance, December 31, 2008	$	447		$	-		$	2		$	449

										Accumulated
							Deferred			Other
	Regulatory			Regulatory			Income			Comprehensive
	Asset			Liability			Taxes			Loss		Total
Other Postretirement
Balance, January 1, 2007	$	190		$	(25	)	$	71		$	-	$	236
Net gain arising during the year		(54	)		-			(15	)		-		(69	)
Net amortization		(21	)		-			-			-		(21	)
Total		(75	)		-			(15	)		-		(90	)
Balance, December 31, 2007		115			(25	)		56			-		146
Net (gain) loss arising during the year		116			15			(18	)		1		114
Prior service credit arising during the year		(13	)		-			-			-		(13	)
Measurement date change		6			-			-			-		6
Net amortization(1)		(20	)		-			-			-		(20	)
Total		89			15			(18	)		1		87
Balance, December 31, 2008	$	204		$	(10	)	$	38		$	1	$	233

(1) Included in the regulatory assets decrease in connection with PacifiCorp’s measurement date change in 2008 was additional amortization of $2 million and $4 million for the pension and other postretirement benefit plans, respectively.

The net loss, prior service credit, net transition obligation and regulatory deferrals that will be amortized in 2009 into combined net periodic benefit cost are estimated to be as follows (in millions):

	Net		Prior Service			Net Transition		Regulatory
	Loss		Credit			Obligation		Deferrals			Total
Pension	$	15	$	(5	)	$	-	$	(9	)	$	1
Other postretirement		2		-			13		1			16
Total	$	17	$	(5	)	$	13	$	(8	)	$	17

114 

Plan Assumptions

Assumptions used to determine benefit obligations as of December 31 and combined net periodic benefit cost for the years ended December 31 were as follows:

	Pension			Other Postretirement
	2008	2007	2006	2008	2007	2006
	%	%	%	%	%	%
Benefit obligations as of the measurement date:
PacifiCorp-sponsored plans -
Discount rate	6.90	6.30	5.85	6.90	6.45	6.00
Rate of compensation increase	3.50	4.00	4.00	N/A	N/A	N/A
MidAmerican Energy-sponsored plans -
Discount rate	6.50	6.00	5.75	6.50	6.00	5.75
Rate of compensation increase	4.00	4.50	4.50	N/A	N/A	N/A
Net periodic benefit cost for the years ended December 31:
PacifiCorp-sponsored plans -
Discount rate	6.30	5.76	5.75	6.45	6.00	5.75
Expected return on plan assets	7.75	8.00	8.50	7.75	8.00	8.50
Rate of compensation increase	4.00	4.00	4.00	N/A	N/A	N/A
MidAmerican Energy-sponsored plans -
Discount rate	6.00	5.75	5.75	6.00	5.75	5.75
Expected return on plan assets	7.50	7.50	7.00	7.50	7.50	7.00
Rate of compensation increase	4.50	4.50	5.00	N/A	N/A	N/A

	2008	2007
Assumed health care cost trend rates as of the measurement date:
PacifiCorp-sponsored plans -
Health care cost trend rate assumed for next year – under 65	8.00%	9.00%
Health care cost trend rate assumed for next year – over 65	6.00%	7.00%
Rate that the cost trend rate gradually declines to	5.00%	5.00%
Year that the rate reaches the rate it is assumed to remain at – under 65	2012	2012
Year that the rate reaches the rate it is assumed to remain at – over 65	2010	2010
MidAmerican Energy-sponsored plans -
Health care cost trend rate assumed for next year	8.50%	9.00%
Rate that the cost trend rate gradually declines to	5.00%	5.00%
Year that the rate reaches the rate it is assumed to remain at	2016	2016

A one percentage-point change in assumed health care cost trend rates would have the following effects (in millions):

	Increase (Decrease)
	One Percentage-Point	One Percentage-Point
	Increase	Decrease
Effect on total service and interest cost	$                 4	$            (3)
Effect on other postretirement benefit obligation	44	(37)

Contributions and Benefit Payments

Employer contributions to the pension and other postretirement plans are expected to be $62 million and $39 million, respectively, for 2009. The Company’s policy is to contribute the minimum required amount to its pension plans and an amount equal to the sum of the net periodic benefit cost and the expected Medicare subsidy to its other postretirement plans. Funding to the established pension trust is based upon the actuarially determined costs of the plan and the requirements of the Internal Revenue Code, the Employee Retirement Income Security Act of 1974 and the Pension Protection Act of 2006, as amended.

115

The expected benefit payments to participants in the Company’s domestic pension and other postretirement plans for 2009 through 2013 and for the five years thereafter are summarized below (in millions):

	Projected Benefit Payments
			Other Postretirement
	Pension		Gross		Medicare Subsidy			Net of Subsidy
2009	$	143	$	52	$	(5	)	$	47
2010		134		56		(6	)		50
2011		139		57		(7	)		50
2012		143		59		(7	)		52
2013		150		61		(8	)		53
2014-18		803		346		(50	)		296

Investment Policy and Asset Allocation

The Company’s investment policy for its pension and other postretirement plans is to balance risk and return through a diversified portfolio of equity securities, fixed income securities and other alternative investments. Asset allocation for the pension and other postretirement plans are as indicated in the tables below. Maturities for fixed income securities are managed to targets consistent with prudent risk tolerances. Sufficient liquidity is maintained to meet near-term benefit payment obligations. The plans retain outside investment advisors to manage plan investments within the parameters outlined by each plan’s Pension and Employee Benefits Plans Administrative Committee (“Administrative Committee”). The weighted-average return on assets assumption is based on historical performance for the types of assets in which the plans invest.

PacifiCorp’s pension plan trust includes a separate account that is used to fund benefits for the other postretirement plan. In addition to this separate account, the assets for other postretirement benefits are held in two Voluntary Employees’ Beneficiaries Association (“VEBA”) Trusts, each of which has its own investment allocation strategies. PacifiCorp’s asset allocation (percentage of plan assets) as of December 31 was as follows:

	Pension and Other Postretirement						VEBA Trusts
	2008		2007		Target		2008		2007		Target
	%		%		%		%		%		%
Equity securities		49		56		53-57		64		64		63-67
Debt securities		40		35		33-37		36		36		33-37
Other		11		9		8-12		-		-		-
Total		100		100				100		100

MidAmerican Energy’s asset allocation (percentage of plan assets) as of December 31 was as follows:

	Pension						Other Postretirement
	2008		2007		Target		2008		2007		Target
	%		%		%		%		%		%
Equity securities		65		69		65-75		64		52		60-80
Debt securities		27		24		20-30		33		46		25-35
Other		8		7		0-10		3		2		0-5
Total		100		100				100		100

New target ranges for MidAmerican Energy’s other postretirement benefit plan assets were approved by MidAmerican Energy’s Administrative Committee in December 2007. No rebalancing took place before December 31, 2007; however, asset allocations were impacted by the highly volatile capital markets in the second half of 2008.

116 

Defined Contribution Plans

The Company sponsors defined contribution pension plans (401(k) plans) covering substantially all employees. The Company’s contributions vary depending on the plan, but are based primarily on each participant’s level of contribution and cannot exceed the maximum allowable for tax purposes. Total Company contributions to these plans were $41 million, $36 million and $34 million for 2008, 2007 and 2006, respectively.

United Kingdom Operations

Certain wholly-owned subsidiaries of CE Electric UK participate in the Northern Electric group of the United Kingdom industry-wide Electricity Supply Pension Scheme (the “UK Plan”), which provides pension and other related defined benefits, based on final pensionable pay, to the majority of the employees of CE Electric UK.

Net Periodic Benefit Cost

For purposes of calculating the expected return on pension plan assets, a market-related value is used. Market-related value is equal to fair value except for gains and losses on equity investments, which are amortized into market-related value on a straight-line basis over five years. The components of the net periodic benefit cost for the UK Plan for the years ended December 31 were as follows (in millions):

	2008			2007			2006
Service cost	$	21		$	24		$	18
Interest cost		98			95			78
Expected return on plan assets		(118	)		(118	)		(101	)
Net amortization		21			31			34
Net periodic benefit cost	$	22		$	32		$	29

Funded Status

The following table is a reconciliation of the fair value of plan assets as of December 31 (in millions):

	2008			2007
Plan assets at fair value, beginning of year	$	1,905		$	1,795
Employer contributions		89			71
Participant contributions		6			7
Actual return on plan assets		(312	)		87
Benefits paid		(76	)		(79	)
Foreign currency exchange rate changes		(440	)		24
Plan assets at fair value, end of year	$	1,172		$	1,905

The following table is a reconciliation of the benefit obligation as of December 31 (in millions):

	2008			2007
Benefit obligation, beginning of year	$	1,820		$	1,813
Service cost		21			24
Interest cost		98			95
Participant contributions		6			7
Benefits paid		(76	)		(79	)
Actuarial gain		(162	)		(64	)
Foreign currency exchange rate changes		(456	)		24
Benefit obligation, end of year	$	1,251		$	1,820
Accumulated benefit obligation, end of year	$	1,202		$	1,725

117

The funded status of the plan and the amounts recognized in the Consolidated Balance Sheets as of December 31 is as follows (in millions):

	2008			2007
Plan assets at fair value, end of year	$	1,172		$	1,905
Less – Benefit obligation, end of year		1,251			1,820
Funded status	$	(79	)	$	85
Amounts recognized in the Consolidated Balance Sheets:
Deferred charges, investments and other assets	$	-		$	85
Other long-term accrued liabilities		(79	)		-
Amounts recognized	$	(79	)	$	85

Unrecognized Amounts

The portion of the funded status of the plan not yet recognized in net periodic benefit cost as of December 31 is as follows (in millions):

	2008		2007
Amounts not yet recognized as components of net periodic benefit cost:
Net loss	$	547	$	442
Prior service cost		7		11
Total	$	554	$	453

A reconciliation of the amounts not yet recognized as components of net periodic benefit cost, which are included in accumulated other comprehensive income (loss) in the Consolidated Balance Sheets, for the years ended December 31is as follows (in millions):

	2008			2007
Balance, beginning of year	$	453		$	513
Net (gain) loss arising during the year		269			(34	)
Net amortization		(21	)		(31	)
Foreign currency exchange rate changes		(147	)		5
Total		101			(60	)
Balance, end of year	$	554		$	453

The net loss and prior service cost that will be amortized from accumulated other comprehensive income (loss) in 2009 into net periodic benefit cost is estimated to be $12 million and $1 million, respectively.

118 

Plan Assumptions

Assumptions used to determine benefit obligations as of December 31 and net periodic benefit cost for the years ended December 31 are as follows:

	2008		2007		2006
	%		%		%
Benefit obligations as of December 31:
Discount rate		6.40		5.90		5.20
Rate of compensation increase		3.25		3.45		3.25

Net benefit cost for the years ended December 31:
Discount rate	5.90	5.20	4.75
Expected return on plan assets	7.00	7.00	7.00
Rate of compensation increase	3.45	3.25	2.75

Contributions and Benefit Payments

The expected benefit payments to participants in the UK Plan for 2009 through 2013 and for the five years thereafter using the foreign currency exchange rate as of December 31, 2008 are summarized below (in millions):

2009	$	57
2010		59
2011		60
2012		62
2013		63
2014-2018		340

Employer contributions to the UK Plan are currently expected to be £44 million for 2009.

Investment Policy and Asset Allocation

CE Electric UK’s investment policy for its pension plan is to balance risk and return through a diversified portfolio of equity securities, fixed income securities and real estate. Maturities for fixed income securities are managed such that sufficient liquidity exists to meet near-term benefit payment obligations. The plan retains outside investment advisors to manage plan investments within the parameters set by the trustees of the UK Plan in consultation with CE Electric UK. The return on assets assumption is based on a weighted average of the expected historical performance for the types of assets in which the plans invest.

CE Electric UK’s pension plan asset allocation as of December 31 was as follows:

	Percentage of Plan Assets
	2008		2007		Target
	%		%		%
Equity securities		40		41		45
Debt securities		51		46		45
Other		9		13		10
Total		100		100

119 

(16) Income Taxes

Income tax expense consists of the following for the years ended December 31 (in millions):

	2008			2007			2006
Current:
Federal	$	63		$	147		$	6
State		74			38			5
Foreign		79			141			135
		216			326			146
Deferred:
Federal		681			188			249
State		45			(6	)		-
Foreign		46			(41	)		21
		772			141			270
Investment tax credit, net		(6	)		(11	)		(9	)
Total	$	982		$	456		$	407

A reconciliation of the federal statutory income tax rate to the effective income tax rate applicable to income before income tax expense for the years ended December 31 follows:

	2008			2007			2006
Federal statutory tax rate		35	%		35	%		35	%
Income tax credits		(3	)		(3	)		(3	)
State taxes, net of federal tax effect		3			2			2
Tax effect of foreign income		-			(2	)		(2	)
Change in UK corporate income tax rate		-			(4	)		-
Other items, net		-			-			(1	)
Effective income tax rate		35	%		28	%		31	%

In 2007, the Company recognized $58 million of deferred income tax benefits upon the enactment of the reduction in the United Kingdom corporate income tax rate from 30% to 28% to be effective April 1, 2008.

120 

The net deferred tax liability consists of the following as of December 31 (in millions):

	2008			2007
Deferred tax assets:
Regulatory liabilities	$	613		$	662
Employee benefits		408			161
Foreign tax credit carryforwards		333			112
Net unrealized losses		159			110
Asset retirement obligations		137			120
Federal and state carryforwards		83			104
Nuclear reserve and decommissioning		25			24
Revenue subject to refund		9			72
Other		319			319
Total deferred tax assets		2,086			1,684
Valuation allowance		(10	)		(12	)
Total deferred tax assets, net		2,076			1,672
Deferred tax liabilities:
Property, plant and equipment, net		(4,197	)		(3,881	)
Regulatory assets		(1,316	)		(1,074	)
Unremitted foreign earnings		(346	)		(86	)
Other		(78	)		(64	)
Total deferred tax liabilities		(5,937	)		(5,105	)
Net deferred tax liability	$	(3,861	)	$	(3,433	)
Reflected as:
Current assets	$	117		$	162
Current liabilities		(29	)		-
Non-current liabilities		(3,949	)		(3,595	)
	$	(3,861	)	$	(3,433	)

As of December 31, 2008, the Company has available $333 million of foreign tax credit carryforwards that expire 10 years after the date the foreign earnings are repatriated through actual or deemed dividends. As of December 31, 2008, the statute of limitation had not begun on the foreign tax credit carryforwards. As of December 31, 2008, the Company has available $83 million of state carryforwards, principally for net operating losses, that expire at various intervals between 2011 and 2027.

The Company adopted FIN 48 effective January 1, 2007 and had $117 million of net unrecognized tax benefits. Of this amount, the Company recognized a net increase in the liability for unrecognized tax benefits of $22 million as a cumulative effect of adopting FIN 48, which was offset by reductions in beginning retained earnings of $5 million, deferred income tax liabilities of $31 million and goodwill of $15 million and an increase in regulatory assets of $1 million in the Consolidated Balance Sheet. The remaining $95 million had been previously accrued under SFAS No. 5, “Accounting for Contingencies,” or SFAS No. 109, “Accounting for Income Taxes.”

As of December 31, 2008 and 2007, net unrecognized tax benefits totaled $169 million and $127 million, respectively, which included $99 million and $104 million, respectively, of tax positions that, if recognized, would have an impact on the effective tax rate. The remaining unrecognized tax benefits relate to positions for which ultimate deductibility is highly certain but for which there is uncertainty as to the timing of such deductibility. Recognition of these tax benefits, other than applicable interest and penalties, would not affect the Company’s effective tax rate.

121 

(17) Preferred Securities of Subsidiaries

The total outstanding preferred stock of PacifiCorp, which does not have mandatory redemption requirements, was $41 million as of December 31, 2008 and 2007 and accrues annual dividends at varying rates between 4.52% to 7.0%. Generally, this preferred stock is redeemable at stipulated prices plus accrued dividends, subject to certain restrictions. In the event of voluntary liquidation, all preferred stock is entitled to stated value or a specified preference amount per share plus accrued dividends. Upon involuntary liquidation, all preferred stock is entitled to stated value plus accrued dividends. Dividends on all preferred stock are cumulative. Holders also have the right to elect members to the PacifiCorp board of directors in the event dividends payable are in default in an amount equal to four full quarterly payments.

The total outstanding cumulative preferred securities of MidAmerican Energy are not subject to mandatory redemption requirements and may be redeemed at the option of MidAmerican Energy at prices which, in the aggregate, total $31 million. The securities accrue annual dividends at varying rates between 3.30% to 4.80%. The aggregate total the holders of all preferred securities outstanding as of December 31, 2008 and 2007 are entitled to upon involuntary bankruptcy was $30 million plus accrued dividends.

The total outstanding 8.061% cumulative preferred securities of a subsidiary of CE Electric UK, which are redeemable in the event of the revocation of the subsidiary’s electricity distribution license by the Secretary of State, was $56 million as of December 31, 2008 and 2007.

(18) Commitments and Contingencies

Legal Matters

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

PacifiCorp

In February 2007, the Sierra Club and the Wyoming Outdoor Council filed a complaint against PacifiCorp in the federal district court in Cheyenne, Wyoming, alleging violations of the Wyoming state opacity standards at PacifiCorp’s Jim Bridger plant in Wyoming. Under Wyoming state requirements, which are part of the Jim Bridger plant’s Title V permit and are enforceable by private citizens under the federal Clean Air Act, a potential source of pollutants such as a coal-fired generating facility must meet minimum standards for opacity, which is a measurement of light that is obscured in the flue of a generating facility. The complaint alleges thousands of violations of asserted six-minute compliance periods and seeks an injunction ordering the Jim Bridger plant’s compliance with opacity limits, civil penalties of $32,500 per day per violation, and the plaintiffs’ costs of litigation. The court granted a motion to bifurcate the trial into separate liability and remedy phases. In 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.

CalEnergy Generation-Foreign

In February 2002, pursuant to the share ownership adjustment mechanism in the CE Casecnan shareholder agreement, MEHC’s indirect wholly owned subsidiary, CE Casecnan Ltd., advised the minority shareholder of CE Casecnan, LaPrairie Group Contractors (International) Ltd. (“LPG”) that MEHC’s indirect ownership interest in CE Casecnan had increased to 100% effective from commencement of commercial operations. In July 2002, LPG filed a complaint in the Superior Court of the State of California, City and County of San Francisco against CE Casecnan Ltd. and MEHC. LPG’s complaint, as amended, seeks compensatory and punitive damages arising out of CE Casecnan Ltd.’s and MEHC’s alleged improper calculation of the proforma financial projections and alleged improper settlement of the NIA 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 was 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, which are also being litigated. The remaining issues are fully briefed and pending before the court. The Company intends to vigorously defend and pursue the remaining claims.

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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 October 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.

Environmental Matters

The Company is subject to federal, state, local and foreign laws and regulations regarding air and water quality, hazardous and solid waste disposal and other environmental matters that have the potential to impact the Company’s current and future operations. The Company believes it is in material compliance with current environmental requirements.

Accrued Environmental Costs

The Company is fully or partly responsible for environmental remediation at various contaminated sites, including sites that are or were part of the Company’s operations and sites owned by third parties. The Company accrues environmental remediation expenses when the expenses are believed to be probable and can be reasonably estimated. The quantification of environmental exposures is based on many factors, including changing laws and regulations, advancements in environmental technologies, the quality of available site-specific information, site investigation results, expected remediation or settlement timelines, the Company’s proportionate responsibility, contractual indemnities and coverage provided by insurance policies. The liability recorded as of December 31, 2008 and 2007 was $33 million and $38 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 associated with the retirement of those assets are separately accounted for as asset retirement obligations.

Hydroelectric Relicensing

PacifiCorp’s hydroelectric portfolio consists of 47 generating facilities with an aggregate facility net owned capacity of 1,158 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. In April 2008 and June 2008, the FERC issued new licenses for the Prospect and the Lewis River hydroelectric systems, respectively. PacifiCorp’s Klamath hydroelectric system is currently undergoing relicensing with the FERC. PacifiCorp’s Klamath hydroelectric system is the remaining hydroelectric generating facility actively engaged in the relicensing process with the FERC.

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 on a final agreement have begun and the AIP states that a final agreement is expected no later than June 30, 2009. As provided in the AIP, PacifiCorp’s support for a definitive settlement will depend on the inclusion of protection for PacifiCorp and its customers from dam removal costs and liabilities.

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The AIP includes provisions to:

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

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

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

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

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

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 additional environmental requirements. PacifiCorp had incurred $57 million and $89 million in costs as of December 31, 2008 and 2007, respectively, for ongoing hydroelectric relicensing, including $57 million and $48 million, respectively, related to the relicensing of the Klamath hydroelectric system. These costs are included in construction in progress and reflected in property, plant and equipment, net on the Consolidated Balance Sheets. 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.

Unconditional Purchase Obligations

The Company has the following unconditional purchase obligations as of December 31, 2008 (in millions) which are not reflected in the Consolidated Balance Sheet:

	Minimum payments required for
											2014 and
	2009		2010		2011		2012		2013		After		Total
Contract type:
Coal, electricity and natural gas contract commitments	$	1,284	$	1,163	$	759	$	526	$	400	$	3,470	$	7,602
Purchase obligations		999		417		116		57		21		128		1,738
Operating leases, easements and maintenance contracts		96		83		70		53		40		255		597
Other		3		2		4		2		2		59		72
	$	2,382	$	1,665	$	949	$	638	$	463	$	3,912	$	10,009

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Coal, Electricity and Natural Gas Contract Commitments

PacifiCorp and MidAmerican Energy have fuel supply and related transportation contracts for their coal-fired and gas generating facilities. PacifiCorp and MidAmerican Energy expect to supplement these contracts with additional contracts and spot market purchases to fulfill their future fossil fuel needs. PacifiCorp and MidAmerican Energy acquire a portion of their electricity through long-term purchases and exchange agreements. Included in the purchased electricity payments are any power purchase agreements that meet the definition of an operating lease.

Purchase Obligations

The Company has purchase obligations for an ongoing construction program to meet increased electricity usage, customer growth and system reliability objectives. Additionally, the Company has various other purchase obligations that are non-cancelable or cancelable only under certain conditions related to equipment maintenance and various other service and maintenance agreements. The amounts included in the table above relate to firm commitments. The following discussion describes the Company’s overall commitments and includes amounts that the Company is not yet firmly committed through a purchase order or other agreement.

The Company has significant future capital requirements. Through its operating platforms, the Company has approved plans for, or has committed to incur, significant future capital expenditures to develop incremental generating capacity, foster the use of renewable resources, enhance transmission capabilities and mitigate environmental impacts through the installation of emission reduction technology. Capital expenditure needs are reviewed regularly by management and may change significantly as a result of such reviews. Estimates may change significantly at any time as a result of, 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.

As part of the March 2006 acquisition of PacifiCorp, MEHC and PacifiCorp made a number of commitments to the state regulatory commissions in all six states in which PacifiCorp has retail customers. These commitments are generally being implemented over several years following the acquisition and are subject to subsequent regulatory review and approval. Outstanding commitments as of December 31, 2008 include:

·   Approximately $812 million in investments in emissions reduction technology for PacifiCorp’s existing coal-fired generating facilities. Through December 31, 2008, PacifiCorp had spent a total of $496 million, including non-cash equity AFUDC, on these emissions reduction projects, and expects to spend in excess of the original commitment due to higher commodity inflation experienced on the planned investments.

·   Approximately $520 million in investments (including both capital and operating expense commitments) in PacifiCorp’s transmission and distribution system that would enhance reliability, facilitate the receipt of renewable resources and enable further system optimization. Through December 31, 2008, PacifiCorp had spent a total of $224 million in capital expenditures, including non-cash equity AFUDC, in support of this commitment, and has announced the transmission expansion project discussed below.

The Energy Gateway Transmission Expansion Project is an investment plan to build approximately 2,000 miles of new high-voltage transmission lines, primarily in Wyoming, Utah, Idaho, Oregon and the desert Southwest. The plan, with an estimated cost exceeding $6.1 billion, includes projects that will address customer load growth, improve system reliability and deliver energy from new wind-powered and other renewable generation resources throughout PacifiCorp’s six-state service area and the Western United States. Certain transmission segments associated with this plan are expected to be placed in service beginning in 2010, with other segments placed in service through 2018, depending on siting, permitting and construction schedules.

Operating Leases, Easements and Maintenance Contracts

The Company has non-cancelable operating leases primarily for computer equipment, office space, certain operating facilities, land and rail cars. These leases generally require the Company to pay for insurance, taxes and maintenance applicable to the leased property. Certain leases contain renewal options for varying periods and escalation clauses for adjusting rent to reflect changes in price indices. The Company also has non-cancelable easements for land on which its wind-farm turbines are located, as well as non-cancelable maintenance contracts for the turbines. Rent expense on non-cancelable operating leases totaled $115 million for 2008, $122 million for 2007 and $117 million for 2006.

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Guarantees

The Company has entered into guarantees as part of the normal course of business and the sale of certain assets. These guarantees are not expected to have a material impact on the Company’s consolidated financial results. PacifiCorp and MidAmerican Energy are generally required to obtain state regulatory commission approval prior to guaranteeing debt or obligations of other parties.

(19) Shareholders’ Equity

Preferred Stock

As of December 31, 2005, Berkshire Hathaway owned 41,263,395 shares of MEHC’s no par zero-coupon convertible preferred stock. Each share of preferred stock was convertible at the option of the holder into one share of MEHC’s common stock subject to certain adjustments as described in MEHC’s Amended and Restated Articles of Incorporation. The convertible preferred stock was convertible into common stock only upon the occurrence of specified events, including modification or elimination of the Public Utility Holding Company Act of 1935 (“PUHCA 1935”) so that holding company registration would not be triggered by conversion. On February 9, 2006, following the effective date of the repeal of the Public Utility Holding Company Act of 1935, Berkshire Hathaway converted its 41,263,395 shares of MEHC’s no par zero-coupon convertible preferred stock into an equal number of shares of MEHC’s common stock.

Common Stock

On March 14, 2000, and as amended on December 7, 2005, MEHC’s shareholders entered into a Shareholder Agreement that provides specific rights to certain shareholders. One of these rights allows certain shareholders the ability to put their common shares back to MEHC at the then current fair value dependent on certain circumstances controlled by MEHC.

In March 2006, MEHC repurchased 12,068,412 shares of common stock for an aggregate purchase price of $1.75 billion.

On March 21, 2006, Berkshire Hathaway and certain other of MEHC’s existing shareholders and related companies invested $5.11 billion, in the aggregate, in 35,237,931 shares of MEHC’s common stock in order to provide equity funding for the PacifiCorp acquisition. The per-share value assigned to the shares of common stock issued, which were effected pursuant to a private placement and were exempt from the registration requirements of the Securities Act of 1933, as amended, was based on an assumed fair market value as agreed to by MEHC’s shareholders.

Common Stock Options

There were no common stock options granted, forfeited or that expired during each of the three years in the period ended December 31, 2008. There were no common stock options exercised during the year ended December 31, 2008. There were 703,329 common stock options outstanding and exercisable with an exercise price of $35.05 per share and a remaining contractual life of 1.25 years as of December 31, 2008.

There were 370,000 common stock options exercised during the year ended December 31, 2007 having a weighted-average exercise price of $26.99 per share. There were 703,329 common stock options outstanding and exercisable with an exercise price of $35.05 per share and a remaining contractual life of 2.25 years as of December 31, 2007.

There were 775,000 common stock options exercised during the year ended December 31, 2006 having a weighted-average exercise price of $28.65 per share. There were 1,073,329 common stock options outstanding and exercisable with a weighted-average exercise price of $32.27 per share as of December 31, 2006. As of December 31, 2006, 370,000 of the outstanding and exercisable common stock options had exercise prices ranging from $24.22 to $34.69 per share, a weighted-average exercise price of $26.99 per share and a remaining contractual life of 1.25 years. The remaining 703,329 outstanding and exercisable common stock options had an exercise price of $35.05 per share and a remaining contractual life of 3.25 years.

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Restricted Net Assets

In connection with the 2006 acquisition of PacifiCorp by MEHC, MEHC and PacifiCorp have made commitments to the state commissions that limit the dividends PacifiCorp can pay to either MEHC or MEHC’s wholly owned subsidiary, PPW Holdings LLC. As of December 31, 2008, the most restrictive of these commitments prohibits PacifiCorp from making any distribution to MEHC or its affiliates without prior state regulatory approval to the extent that it would reduce PacifiCorp’s common stock equity below 48.25% of its total capitalization, excluding short-term debt and current maturities of long-term debt. After December 31, 2008, this minimum level of common equity declines annually to 44% after December 31, 2011. As of December 31, 2008, PacifiCorp’s actual common stock equity percentage, as calculated under this measure, exceeded the minimum threshold.

These commitments also restrict PacifiCorp from making any distributions to either MEHC or MEHC’s wholly owned subsidiary, PPW Holdings LLC, if PacifiCorp’s unsecured debt rating is BBB- or lower by Standard & Poor’s Rating Services or Fitch Ratings or Baa3 or lower by Moody’s Investor Service, as indicated by two of the three rating services. At December 31, 2008, PacifiCorp’s unsecured debt rating was A- by Standard & Poor’s Rating Services, BBB+ by Fitch Ratings and Baa1 by Moody’s Investor Service.

In conjunction with the March 1999 acquisition of MidAmerican Energy by MEHC, MidAmerican Energy committed to the IUB to use commercially reasonable efforts to maintain an investment grade rating on its long-term debt and to maintain its common equity level above 42% of total capitalization unless circumstances beyond its control result in the common equity level decreasing to below 39% of total capitalization. MidAmerican Energy must seek the approval from the IUB of a reasonable utility capital structure if MidAmerican Energy’s common equity level decreases below 42% of total capitalization, unless the decrease is beyond the control of MidAmerican Energy. MidAmerican Energy is also required to seek the approval of the IUB if MidAmerican Energy’s common equity level decreases to below 39%, even if the decrease is due to circumstances beyond the control of MidAmerican Energy. As of December 31, 2008, MidAmerican Energy’s common equity ratio exceeded the minimum threshold computed on a basis consistent with its commitment.

As a result of these regulatory commitments, MEHC had restricted net assets of $7.1 billion as of December 31, 2008.

(20) Components of Accumulated Other Comprehensive (Loss) Income, Net

Accumulated other comprehensive (loss) income, net is included in the Consolidated Balance Sheets in shareholders’ equity, and consists of the following components as of December 31 (in millions):

	2008			2007
Unrecognized amounts on retirement benefits, net of tax of $(156) and $(128)	$	(401	)	$	(329	)
Foreign currency translation adjustment		(446	)		356
Fair value adjustment on cash flow hedges, net of tax of $(3) and $38		(7	)		57
Unrealized (losses) gains on marketable securities, net of tax of $(16) and $4		(25	)		6
Total accumulated other comprehensive income (loss), net	$	(879	)	$	90

Upon conversion of the CEG 8% Preferred Stock, the Company reclassified unrealized gains from AOCI to earnings totaling $271 million, net of tax of $187 million. The unrealized gain and reclassification of the gain is presented net in Consolidated Statements of Shareholders’ Equity.

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(21) Other, Net

Other, net, as shown on the Consolidated Statements of Operations, for the years ending December 31 consists of the following (in millions):

	2008			2007		2006
Gain on Constellation Energy merger termination fee and investment	$	1,092		$	-	$	-
Allowance for equity funds used during construction		73			85		57
Gains on sales of non-strategic assets and investments		1			1		55
Corporate-owned life insurance (expense) income		(13	)		12		13
Gain on Mirant bankruptcy claim		-			3		89
Other		35			11		12
Total other, net	$	1,188		$	112	$	226

Gain on Constellation Energy Merger Termination Fee and Investment

On December 17, 2008, MEHC and Constellation Energy terminated the Merger Agreement, which resulted in the receipt of a $175 million termination fee and the conversion of the CEG 8% Preferred Stock into $418 million of cash and 19.9 million shares of Constellation Energy common stock valued at $499 million as of December 31, 2008.

Gain on Mirant Americas Energy Marketing (“Mirant”) Bankruptcy Claim

Mirant was one of the shippers that entered into a 15-year, 2003 Expansion Project, firm gas transportation contract with Kern River (the “Mirant Agreement”) and provided a letter of credit equivalent to 12 months of reservation charges as security for its obligations thereunder. In July 2003, Mirant filed for Chapter 11 bankruptcy protection and the bankruptcy court ultimately determined that Kern River was entitled to a general unsecured claim of $74 million in addition to $15 million of cash collateral. In January 2006, Mirant emerged from bankruptcy. In February 2006, Kern River received an initial distribution of such shares in payment of the majority of its allowed claim. Kern River sold all of the shares of new Mirant stock received from its allowed claim amount plus interest in the first quarter of 2006 and recognized a gain from those sales of $89 million.

(22) Supplemental Cash Flows Information

The summary of supplemental cash flows information for the years ending December 31 follows (in millions):

	2008			2007		2006
Interest paid, net of amounts capitalized	$	1,218		$	1,176	$	1,036
Income taxes (received) paid(1)	$	(140	)	$	287	$	132
Supplemental disclosure of non-cash investing transactions:
Property, plant and equipment additions in accounts payable	$	570		$	309	$	238
Conversion of CEG 8% Preferred Stock(2)	$	1,458		$	-	$	-

(1)	Includes $266 million of income taxes received from Berkshire Hathaway in 2008, $133 million of income taxes paid to Berkshire Hathaway in 2007 and $20 million of income taxes received from Berkshire Hathaway in 2006.
(2)	In December 2008, MEHC converted its $1 billion investment in CEG 8% Preferred Stock into $1 billion 14% of Senior Notes due from Constellation Energy and 19.9 million shares of Constellation Energy common stock.

During 2008, the Company purchased $354 million of its MEHC senior and subsidiary debt. Of the total, $216 million was subsequently re-marketed during 2008 and the remainder matured.

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(23) Segment Information

MEHC’s reportable segments were determined based on how the Company’s strategic units are managed. The Company’s foreign reportable segments include CE Electric UK, whose business is principally in Great Britain, and CalEnergy Generation-Foreign, whose business is in the Philippines. Intersegment eliminations and adjustments, including the allocation of goodwill, have been made. Information related to the Company’s reportable segments is shown below (in millions):

	Years Ended December 31,
	2008			2007			2006
Operating revenue:
PacifiCorp	$	4,498		$	4,258		$	2,939
MidAmerican Funding		4,715			4,267			3,453
Northern Natural Gas		769			664			634
Kern River		443			404			325
CE Electric UK		993			1,079			928
CalEnergy Generation-Foreign		138			220			336
CalEnergy Generation-Domestic		30			32			32
HomeServices		1,133			1,500			1,702
Corporate/other(1)		(51	)		(48	)		(48	)
Total operating revenue	$	12,668		$	12,376		$	10,301
Depreciation and amortization:
PacifiCorp	$	490		$	496		$	368
MidAmerican Funding		282			269			275
Northern Natural Gas		60			58			57
Kern River		86			80			56
CE Electric UK		179			187			138
CalEnergy Generation-Foreign		22			50			80
CalEnergy Generation-Domestic		8			8			8
HomeServices		19			20			32
Corporate/other(1)		(17	)		(18	)		(7	)
Total depreciation and amortization	$	1,129		$	1,150		$	1,007
Operating income:
PacifiCorp	$	952		$	917		$	528
MidAmerican Funding		590			514			421
Northern Natural Gas		457			308			269
Kern River		305			277			217
CE Electric UK		514			555			516
CalEnergy Generation-Foreign		103			142			230
CalEnergy Generation-Domestic		15			12			14
HomeServices		(58	)		33			55
Corporate/other(1)		(50	)		(70	)		(130	)
Total operating income		2,828			2,688			2,120
Interest expense		(1,333	)		(1,320	)		(1,152	)
Capitalized interest		54			54			40
Interest and dividend income		75			105			73
Other, net		1,188			112			226
Total income before income tax expense, minority interest and preferred dividends of subsidiaries and equity income	$	2,812		$	1,639		$	1,307

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	Years Ended December 31,
	2008			2007			2006
Interest expense:
PacifiCorp	$	343		$	314		$	224
MidAmerican Funding		207			179			155
Northern Natural Gas		61			58			50
Kern River		67			75			74
CE Electric UK		186			241			215
CalEnergy Generation-Foreign		8			13			20
CalEnergy Generation-Domestic		17			17			18
HomeServices		2			2			2
Corporate/other(1)		442			421			394
Total interest expense	$	1,333		$	1,320		$	1,152
Income tax expense:
PacifiCorp	$	239		$	240		$	139
MidAmerican Funding		107			111			94
Northern Natural Gas		157			106			85
Kern River		90			78			87
CE Electric UK		82			47			100
CalEnergy Generation-Foreign		48			56			68
CalEnergy Generation-Domestic		1			-			1
HomeServices		(20	)		15			30
Corporate/other(1)		278			(197	)		(197	)
Total income tax expense	$	982		$	456		$	407
Capital expenditures:
PacifiCorp	$	1,789		$	1,518		$	1,114
MidAmerican Funding		1,473			1,300			758
Northern Natural Gas		196			225			122
Kern River		24			15			3
CE Electric UK		440			422			404
CalEnergy Generation-Foreign		1			1			2
HomeServices		12			26			18
Corporate/other(1)		2			5			2
Total capital expenditures	$	3,937		$	3,512		$	2,423

	As of December 31,
	2008			2007			2006
Property, plant and equipment, net:
PacifiCorp	$	13,824		$	11,849		$	10,810
MidAmerican Funding		6,942			5,737			5,034
Northern Natural Gas		1,978			1,856			1,655
Kern River		1,722			1,772			1,843
CE Electric UK		3,612			4,606			4,266
CalEnergy Generation-Foreign		282			303			352
CalEnergy Generation-Domestic		213			223			230
HomeServices		66			76			67
Corporate/other(1)		(185	)		(201	)		(218	)
Total property, plant and equipment, net	$	28,454		$	26,221		$	24,039

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	As of December 31,
	2008		2007		2006
Total assets:
PacifiCorp	$	18,339	$	16,049	$	14,970
MidAmerican Funding		10,632		9,377		8,651
Northern Natural Gas		2,595		2,488		2,277
Kern River		1,910		1,943		2,057
CE Electric UK		4,921		6,802		6,561
CalEnergy Generation-Foreign		442		479		559
CalEnergy Generation-Domestic		550		544		545
HomeServices		674		709		795
Corporate/other(1)		1,378		825		32
Total assets	$	41,441	$	39,216	$	36,447

(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 table shows the change in the carrying amount of goodwill by reportable segment for the years ended December 31, 2008 and 2007 (in millions):

							Northern					CE			CalEnergy
				MidAmerican			Natural			Kern		Electric			Generation		Home-
	PacifiCorp			Funding			Gas			River		UK			Domestic		Services			Total
Balance, January 1, 2007	$	1,118		$	2,108		$	301		$	34	$	1,328		$	71	$	385		$	5,345
Acquisitions(1)		22			-			-			-		-			-		9			31
Adoption of FIN 48		(10	)		(4	)		-			-		(1	)		-		-			(15	)
Foreign currency translation adjustment		-			-			-			-		14			-		-			14
Other(2)		(5	)		4			(26	)		-		(6	)		-		(3	)		(36	)
Balance, December 31, 2007		1,125			2,108			275			34		1,335			71		391			5,339
Acquisitions		-			-			-			-		-			-		1			1
Foreign currency translation adjustment		-			-			-			-		(276	)		-		-			(276	)
Other(2)		1			(6	)		(26	)		-		(9	)		-		(1	)		(41	)
Balance, December 31, 2008	$	1,126		$	2,102		$	249		$	34	$	1,050		$	71	$	391		$	5,023

(1)	The $22 million adjustment to PacifiCorp’s goodwill was due to the completion of the purchase price allocation in the first quarter of 2007.
(2)	Relates primarily to income tax adjustments.

131 

Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure

None.

Item 9A(T). Controls and Procedures

Disclosure Controls and Procedures

At the end of the period covered by this Annual Report on Form 10-K, 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 the 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 December 31, 2008 that has materially affected, or is reasonably likely to materially affect, the Company’s internal control over financial reporting.

Management’s Report on Internal Control over Financial Reporting

Management of the Company is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in the Securities Exchange Act of 1934 Rule 13a-15(f). 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), the Company’s management conducted an evaluation of the effectiveness of the Company’s internal control over financial reporting as of December 31, 2008 as required by the Securities Exchange Act of 1934 Rule 13a-15(c). In making this assessment, the Company’s management used the criteria set forth in the framework in “Internal Control - Integrated Framework” issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on the evaluation conducted under the framework in “Internal Control - Integrated Framework,” the Company’s management concluded that the Company’s internal control over financial reporting was effective as of December 31, 2008.

This report does not include an attestation report of the Company’s registered public accounting firm regarding internal control over financial reporting. Management’s report was not subject to attestation by the Company’s registered public accounting firm pursuant to temporary rules of the SEC that permit the Company to provide only management’s report in this Annual Report on Form 10-K.

MidAmerican Energy Holdings Company

February 20, 2009

Item 9B. Other Information

On February 16, 2009, David L. Sokol, Chairman of MEHC, and on February 10, 2009, Gregory E. Abel, President and Chief Executive Officer of MEHC, each executed an Incremental Profit Sharing Plan (“IPSP”) effective January 1, 2009. Each IPSP is filed as an exhibit to this Annual Report on Form 10-K.

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PART III

Item 10. Directors, Executive Officers and Corporate Governance

The Board of Directors appoints executive officers annually. There are no family relationships among the executive officers, nor, except as set forth in employment agreements, any arrangements or understandings between any executive officer and any other person pursuant to which the executive officer was appointed. Set forth below is certain information, as of January 31, 2009, with respect to the current directors and executive officers of MEHC:

DAVID L. SOKOL, 52, Chairman of the Board of Directors since 1994, Chief Executive Officer from 1993 to 2008 and a director since 1991. Mr. Sokol joined MEHC in 1991.

GREGORY E. ABEL, 46, President since 1998, Chief Executive Officer since 2008, director since 2000 and Chief Operating Officer from 1998 to 2008. Mr. Abel joined MEHC in 1992. Mr. Abel is also a director of PacifiCorp.

PATRICK J. GOODMAN, 42, Senior Vice President and Chief Financial Officer since 1999. Mr. Goodman joined MEHC in 1995. Mr. Goodman is also a director of PacifiCorp.

DOUGLAS L. ANDERSON, 50, Senior Vice President, General Counsel and Corporate Secretary since 2001. Mr. Anderson joined MEHC in 1993. Mr. Anderson is also a director of PacifiCorp.

MAUREEN E. SAMMON, 45, Senior Vice President and Chief Administrative Officer since 2007. Ms. Sammon has been employed by MidAmerican Energy and its predecessor companies since 1986 and has held several positions, including Manager of Benefits and Vice President, Human Resources and Insurance.

WARREN E. BUFFETT, 78, Director. Mr. Buffett has been a director of MEHC since 2000 and has been Chairman of the Board of Directors and Chief Executive Officer of Berkshire Hathaway for more than five years. Mr. Buffett is also a director of The Washington Post Company.

WALTER SCOTT, JR., 77, Director. Mr. Scott has been a director of MEHC since 1991 and has been Chairman of the Board of Directors of Level 3 Communications, Inc., a successor to certain businesses of Peter Kiewit & Sons’, Inc., for more than five years. Mr. Scott is also a director of Peter Kiewit & Sons’, Inc., Berkshire Hathaway and Valmont Industries, Inc.

MARC D. HAMBURG, 59, Director. Mr. Hamburg has been a director of MEHC since 2000 and has been Vice President-Chief Financial Officer and Treasurer of Berkshire Hathaway for more than five years.

Audit Committee and Audit Committee Financial Expert

The audit committee of the Board of Directors is comprised of Mr. Marc D. Hamburg. The Board of Directors has determined that Mr. Hamburg qualifies as an “audit committee financial expert,” as defined by SEC rules, based on his education, experience and background. Based on the standards of the New York Stock Exchange Inc., on which the common stock of MEHC’s majority owner, Berkshire Hathaway, is listed, MEHC’s Board of Directors has determined that Mr. Hamburg is not independent because of his employment by Berkshire Hathaway.

Code of Ethics

MEHC has adopted a code of ethics that applies to its principal executive officer, its principal financial and accounting officer, or persons acting in such capacities, and certain other covered officers. The code of ethics is incorporated by reference in the exhibits to this Annual Report on Form 10-K.

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Item 11. Executive Compensation

Compensation Discussion and Analysis

Compensation Philosophy and Overall Objectives

We believe that the compensation paid to each of our President and Chief Executive Officer, or CEO, our Chief Financial Officer, or CFO, and our three other most highly compensated executive officers, to whom we refer collectively as our Named Executive Officers, or NEOs, should be closely aligned with our overall performance, and each NEO’s contribution to that performance, on both a short- and long-term basis, and that such compensation should be sufficient to attract and retain highly qualified leaders who can create significant value for our organization. Our compensation programs are designed to provide our NEOs with meaningful incentives for superior corporate and individual performance. Performance is evaluated on a subjective basis within the context of both financial and non-financial objectives that we believe contribute to our long-term success, among which are financial strength, customer service, operational excellence, employee commitment and safety, environmental respect and regulatory integrity.

How is Compensation Determined

Our Compensation Committee is comprised of Messrs. Warren E. Buffett and Walter Scott, Jr. The Compensation Committee is responsible for the establishment and oversight of our compensation policy. Approval of compensation decisions for our NEOs is made by the Compensation Committee, unless specifically delegated. Although the Compensation Committee reviews each NEO’s complete compensation package at least annually, it has delegated to the Chairman of the Board of Directors, or Chairman, and the CEO authority to approve off-cycle pay changes, performance awards and participation in other employee benefit plans and programs.

Our criteria for assessing executive performance and determining compensation in any year is inherently subjective and is not based upon specific formulas or weighting of factors. Given the uniqueness of each NEO’s duties, we do not specifically use other companies as benchmarks when establishing our NEOs’ initial compensation. Subsequently, the Compensation Committee reviews peer company data when making annual base salary and incentive recommendations for the Chairman and the CEO. The peer companies for 2008 were American Electric Power Company, Inc., Consolidated Edison, Inc., Dominion Resources, Inc., Duke Energy Corporation, Edison International, Energy Future Holdings Corp., Entergy Corporation, Exelon Corporation, FirstEnergy Corp., FPL Group, Inc., PG&E Corporation, Progress Energy, Inc., Public Service Enterprise Group Incorporated, Sempra Energy, The Southern Company and Xcel Energy Inc.

Discussion and Analysis of Specific Compensation Elements

Base Salary

We determine base salaries for all our NEOs by reviewing our overall performance and each NEO’s performance, the value each NEO brings to us and general labor market conditions. While base salary provides a base level of compensation intended to be competitive with the external market, the annual base salary adjustment for each NEO is determined on a subjective basis after consideration of these factors and is not based on target percentiles or other formal criteria. The Chairman and CEO together make recommendations regarding the other NEOs’ base salaries. The Chairman makes recommendations regarding the CEO’s base salary, and the Compensation Committee sets our Chairman’s base salary. All merit increases are approved by the Compensation Committee and take effect on January 1 of each year. Base salaries for all NEOs increased on average by 12.4% effective January 1, 2008. An increase or decrease in base salary may also result from a promotion or other significant change in a NEO’s responsibilities during the year. Mr. Sokol’s base salary was reduced to $750,000, as specified in his employment agreement, on April 16, 2008, when he relinquished his role as CEO, but retained his role as Chairman. There were no other base salary changes for our NEOs during the year after the January 1, 2008 merit increase.

Short-Term Incentive Compensation

The objective of short-term incentive compensation is to reward the achievement of significant annual corporate goals while also providing NEOs with competitive total cash compensation.

134

Performance Incentive Plan

Under our Performance Incentive Plan, or PIP, all NEOs are eligible to earn an annual discretionary cash incentive award, which is determined on a subjective basis and is not based on a specific formula or cap. Awards paid to a NEO under the PIP are based on a variety of measures linked to our overall performance and each NEO’s contribution to that performance. An individual NEO’s performance is measured against defined objectives that commonly include financial measures (e.g., net income and cash flow) and non-financial measures (e.g., customer service, operational excellence, employee commitment and safety, environmental respect and regulatory integrity), as well as the NEO’s response to issues and opportunities that arise during the year. The Chairman and the CEO together recommend annual incentive awards for the other NEOs to the Compensation Committee prior to the last committee meeting of each year, held in the fourth quarter. The Chairman recommends the annual incentive award for the CEO, and the Compensation Committee determines the Chairman’s award. If approved by the Compensation Committee, awards are paid prior to year-end.

Performance Awards

In addition to the annual awards under the PIP, we may grant cash performance awards periodically during the year to one or more NEOs to reward the accomplishment of significant non-recurring tasks or projects. These awards are discretionary and are approved by the CEO, as delegated by the Chairman and the Compensation Committee. In December 2008, awards were granted to Messrs. Goodman and Anderson and Ms. Sammon in recognition of their efforts related to certain merger and acquisition activities, primarily the investment in and proposed acquisition of Constellation Energy. Although both Messrs. Sokol and Abel are eligible for performance awards, neither has been granted an award in the past five years.

Special Achievement Bonus

Mr. Sokol received a one-time special achievement bonus of $8,500,000 upon his relinquishment of the CEO position and his offer to remain employed as Chairman, all in accordance with his employment agreement. This special achievement bonus was calculated as two times the sum of his annual base salary then in effect and his average annual bonus for the two preceding years.

Long-Term Incentive Compensation

The objective of long-term incentive compensation is to retain NEOs, reward their exceptional performance and motivate them to create long-term, sustainable value. Our current long-term incentive compensation program is cash-based. We have not issued stock options or other forms of equity-based awards since March 2000. All stock options held by Messrs. Sokol and Abel are fully vested.

Long-Term Incentive Partnership Plan

The MidAmerican Energy Holdings Company Long-Term Incentive Partnership Plan, or LTIP, is designed to retain key employees and to align our interests and the interests of the participating employees. Messrs. Goodman and Anderson and Ms. Sammon, as well as 83 other employees, participate in this plan, while our Chairman and our CEO do not. Our LTIP provides for annual awards based upon significant accomplishments by the individual participants and the achievement of the financial and non-financial objectives previously described. The goals are developed with the objective of being attainable with a sustained, focused and concerted effort and are determined and communicated in January of each plan year. Participation is discretionary and is determined by the Chairman and the CEO who recommend awards to the Compensation Committee annually in the fourth quarter. Except for limited situations of extraordinary performance, awards are capped at 1.5 times base salary and finalized in the first quarter of the following year. These cash-based awards are subject to mandatory deferral and equal annual vesting over a five-year period starting in the performance year. Participants allocate the value of their deferral accounts among various investment alternatives, which are determined by a vote of all participants. Gains or losses may be incurred based on investment performance. Participating NEOs may elect to defer all or a part of the award or receive payment in cash after the five-year mandatory deferral and vesting period. Vested balances (including any investment profits or losses thereon) of terminating participants are paid at the time of termination.

135 

Other Employee Benefits

Supplemental Executive Retirement Plan

The MidAmerican Energy Company Supplemental Retirement Plan for Designated Officers, or SERP, provides additional retirement benefits to participants. We include the SERP as part of the participating NEO’s overall compensation in order to provide a comprehensive, competitive package and as a key retention tool. Messrs. Sokol, Abel and Goodman participate, and the plan is currently closed to any new participants. The SERP provides annual retirement benefits of up to 65% of a participant’s total cash compensation in effect immediately prior to retirement, subject to an annual $1 million maximum retirement benefit. Total cash compensation means (i) the highest amount payable to a participant as monthly base salary during the five years immediately prior to retirement multiplied by 12, plus (ii) the average of the participant’s annual awards under an annual incentive bonus program during the three years immediately prior to the year of retirement and (iii) special, additional or non-recurring bonus awards, if any, that are required to be included in total cash compensation pursuant to a participant’s employment agreement or approved for inclusion by the Board of Directors. All participating NEOs have met the five-year service requirement under the plan. Mr. Goodman’s SERP benefit will be reduced by the amount of his regular retirement benefit under the MidAmerican Energy Company Retirement Plan and ratably for retirement between ages 55 and 65.

Deferred Compensation Plan

The MidAmerican Energy Holdings Company Executive Voluntary Deferred Compensation Plan, or DCP, provides a means for all NEOs to make voluntary deferrals of up to 50% of base salary and 100% of short-term incentive compensation awards. The deferrals and any investment returns grow on a tax-deferred basis. Amounts deferred under the DCP receive a rate of return based on the returns of any combination of eight investment options offered under the DCP and selected by the participant, and the plan allows participants to choose from three forms of distribution. While the plan allows us to make discretionary contributions, we have not made contributions to date. We include the DCP as part of the participating NEO’s overall compensation in order to provide a comprehensive, competitive package.

Financial Planning and Tax Preparation

This benefit provides NEOs with financial planning and tax preparation services. The value of the benefit is included in the NEO’s taxable income. It is offered both as a competitive benefit itself and also to help ensure our NEOs best utilize the other forms of compensation we provide to them.

Executive Life Insurance

We provide universal life insurance to Messrs. Sokol, Abel and Goodman, having a death benefit of two times annual base salary during employment, reducing to one times annual base salary in retirement. The value of the benefit is included in the NEO’s taxable income. We include the executive life insurance as part of the participating NEO’s overall compensation in order to provide a comprehensive, competitive package.

Impact of Accounting and Tax

Compensation paid under our executive compensation plans has been reported as an expense in our historical Consolidated Financial Statements. We are entitled to a statutory exemption from the deductibility limitations of executive compensation under Section 162(m) of the Internal Revenue Code as we are a non-publicly held affiliate of a consolidated taxpayer, Berkshire Hathaway.

Potential Payments Upon Termination

Certain NEOs are entitled to post-termination payments in the event their employment is terminated under certain circumstances. We believe these post-termination payments are an important component of the competitive compensation package we offer to these NEOs.

136 

Compensation Committee Report

The Compensation Committee, consisting of Messrs. Buffett and Scott, has reviewed and discussed the Compensation Discussion and Analysis with management and, based on this review and discussion, has recommended to the Board of Directors that the Compensation Discussion and Analysis be included in this Annual Report on Form 10-K.

Summary Compensation Table

The following table sets forth information regarding compensation earned by each of our NEOs during the years indicated:

								Change in
								Pension
								Value and
						Non-Equity		Nonqualified
						Incentive		Deferred		All
Name and		Base				Plan		Compensation		Other
Principal		Salary		Bonus(1)		Compensation(2)		Earnings(3)		Compensation(4)		Total(5)
Position	Year	($)		($)		($)		($)		($)		($)
David L. Sokol, Chairman of	2008	$	822,917	$	13,000,000	$	-	$	-	$	424,749	$	14,247,666
the Board of Directors	2007		850,000		4,000,000		-		-		213,038		5,063,038
	2006		850,000		2,500,000		26,250,000		344,000		281,735		30,225,735
Gregory E. Abel, President and	2008		1,000,000		5,000,000		-		369,000		437,792		6,806,792
Chief Executive Officer	2007		775,000		4,000,000		-		-		370,624		5,145,624
	2006		760,000		2,200,000		26,250,000		234,000		265,386		29,709,386
Patrick J. Goodman, Senior Vice	2008		330,000		673,081		-		18,000		45,631		1,066,712
President and Chief Financial	2007		320,000		889,306		-		51,000		47,868		1,308,174
Officer	2006		307,500		1,025,453		-		89,000		51,248		1,473,201
Douglas L. Anderson, Senior Vice	2008		300,000		558,397		-		28,000		31,536		917,933
President and General Counsel	2007		291,500		788,705		-		20,000		29,372		1,129,577
	2006		283,000		802,560		-		28,000		45,101		1,158,661
Maureen E. Sammon, Senior Vice	2008		215,000		250,930		-		31,000		20,159		517,089
President and Chief	2007		196,659		452,903		-		17,000		20,291		686,853
Administrative Officer	2006		185,000		434,035		-		29,000		20,207		668,242

______________

(1) Consists of annual cash incentive awards earned pursuant to the PIP for our NEOs, performance awards earned related to non-routine projects, special achievement bonuses and the vesting of LTIP awards and associated earnings for Messrs. Goodman and Anderson and Ms. Sammon. The breakout for 2008 is as follows:

	PIP		Performance Award		Special Achievement Bonus		LTIP
David L. Sokol	$	4,500,000	$	-	$	8,500,000	$	-
Gregory E. Abel		5,000,000		-		-		-
Patrick J. Goodman		375,000		100,000		-		198,081	($346,419 in investment losses)
Douglas L. Anderson		330,000		100,000		-		128,397	($262,835 in investment losses)
Maureen E. Sammon		160,000		20,000		-		70,930	($172,370 in investment losses)

137 

The ultimate payouts of LTIP awards are undeterminable as the amounts to be paid out may increase or decrease depending on investment performance. Net income, the net income target goal and the matrix below were used in determining the gross amount of the LTIP award available to the group. Net income is subject to discretionary adjustment by the Chairman, CEO and Compensation Committee. In 2008, the gross award and per-point value were adjusted to eliminate the net income benefits for the termination fee from the proposed acquisition of Constellation Energy and the profits from the investment in Constellation Energy.

Net Income	Award
Less than or equal to net income target goal	None
Exceeds net income target goal by 0.01% - 3.25%	15% of excess
Exceeds net income target goal by 3.251% - 6.50%	15% of the first 3.25% excess;
	25% of excess over 3.25%
Exceeds net income target goal by more than 6.50%	15% of the first 3.25% excess;
	25% of the next 3.25% excess;
	35% of excess over 6.50%

	A pool of up to 100,000 points in aggregate is allocated between plan participants either as initial points or year-end performance points. A nominating committee recommends the point allocation, subject to approval by the Chairman and the CEO, based upon a discretionary evaluation of individual achievement of financial and non-financial goals previously described herein. A participant’s award equals his or her allocated points multiplied by the final per-point value, capped at 1.5 times base salary except in extraordinary circumstances.
(2)	Amounts consist of cash awards earned pursuant to the 2003 Incremental Profit Sharing Plan, or 2003 IPSP, for Messrs. Sokol and Abel. While the initial 2003 IPSP performance period ended in 2007, the adjusted diluted earnings per share target of $12.37 was achieved in 2006 and Messrs. Sokol and Abel received the remaining full awards under the plan in 2006.
(3)	Amounts are based upon the aggregate increase in the actuarial present value of all qualified and nonqualified defined benefit plans, which include our cash balance and SERP, as applicable. Amounts are computed using assumptions consistent with those used in preparing the related pension disclosures included in our Notes to Consolidated Financial Statements included in Item 8 of this Form 10-K and are as of the pension plans’ measurement dates. No participant in our DCP earned “above-market” or “preferential” earnings on amounts deferred.
(4)	Amounts consist of vacation payouts, life insurance premiums and defined contribution plan matching and profit-sharing contributions we paid on behalf of the NEOs, as well as perquisites and other personal benefits related to the personal use of corporate aircraft and financial planning and tax preparation that we paid on behalf of Messrs. Sokol, Abel, Goodman and Anderson. The personal use of corporate aircraft represents our incremental cost of providing this personal benefit determined by applying the percentage of flight hours used for personal use to our variable expenses incurred from operating our corporate aircraft. All other compensation is based upon amounts paid by us. Items required to be reported and quantified are as follows: Mr. Sokol - life insurance premiums of $58,715, personal use of corporate aircraft of $278,986 and vacation payouts of $69,228; Mr. Abel - life insurance premiums of $64,103, personal use of corporate aircraft of $344,995, and tax gross-ups of $11,249; Mr. Goodman - life insurance premiums of $19,149; and Mr. Anderson - vacation payouts of $18,461.
(5)	Any amounts voluntarily deferred by the NEO, if applicable, are included in the appropriate column in the summary compensation table.

138 

Outstanding Equity Awards at Fiscal Year-End

The following table sets forth information regarding outstanding equity awards held by each of our NEOs at December 31, 2008:

					Equity incentive
					plan awards:
	Number of		Number of		Number of securities
	securities underlying		securities underlying		underlying unexercised		Option
	unexercised options		unexercised options		unearned options		exercise price		Option
Name	(#) Exercisable(1)		(#) Unexercisable			(#)	($)		Expiration Date
David L. Sokol		549,277		-		-	$	35.05	March 14, 2010
Gregory E. Abel		154,052		-		-		35.05	March 14, 2010

______________

(1) We have not issued stock options or other forms of equity-based awards since March 2000. All outstanding stock options relate to previously granted options held by Messrs. Sokol and Abel and were fully vested prior to 2008. Accordingly, we have omitted the Stock Awards columns from the Outstanding Equity Awards at Fiscal Year-End Table. Neither Mr. Sokol nor Mr. Abel exercised any stock options in 2008.

Pension Benefits

The following table sets forth certain information regarding the defined benefit pension plan accounts held by each of our NEOs at December 31, 2008:

		Number of
		years		Present value		Payments
		credited		of accumulated		during last
		service(1)		benefit(2)		fiscal year
Name	Plan name		(#)	($)		($)
David L. Sokol	SERP		n/a	$	5,437,000	$	-
	MidAmerican Energy Company Retirement Plan		n/a		214,000		-
Gregory E. Abel	SERP		n/a		4,066,000		-
	MidAmerican Energy Company Retirement Plan		n/a		206,000		-
Patrick J. Goodman	SERP	14 years			420,000		-
	MidAmerican Energy Company Retirement Plan	10 years			199,000		-
Douglas L. Anderson	MidAmerican Energy Company Retirement Plan	10 years			204,000		-
Maureen E. Sammon	MidAmerican Energy Company Retirement Plan	22 years			230,000		-

______________

(1)

The pension benefits for Messrs. Sokol and Abel do not depend on their years of service, as both have already reached their maximum benefit levels based on their respective ages and previous triggering events described in their employment agreements. Mr. Goodman’s credited years of service includes ten years of service with us and, for purposes of the SERP only, four additional years of imputed service from a predecessor company.

(2)

Amounts are computed using assumptions consistent with those used in preparing the related pension disclosures included in our Notes to Consolidated Financial Statements included in Item 8 of this Form 10-K and are as of December 31, 2008, the plans’ measurement date. The present value of accumulated benefits for the SERP was calculated using the following assumptions: (1) Mr. Sokol – a 100% joint and survivor annuity; (2) Mr. Abel – a 100% joint and survivor annuity; and (3) Mr. Goodman – a 66 2/3% joint and survivor annuity. The present value of accumulated benefits for the MidAmerican Energy Company Retirement Plan was calculated using a lump sum payment assumption. The present value assumptions used in calculating the present value of accumulated benefits for both the SERP and the MidAmerican Energy Company Retirement Plan were as follows: a cash balance interest crediting rate of 4.20% in 2008, 1.77% in 2009 and 5.75% thereafter; cash balance conversion rates of 4.90% in 2008, 5.30% in 2009, 5.70% in 2010, 6.10% in 2011, and 6.50% in 2012 and thereafter; a discount rate of 6.50%; an expected retirement age of 65; postretirement mortality using the RP-2000 M/F tables; and cash balance conversion mortality using the Revenue Ruling 2008-85 tables.

139

The SERP also provides annual retirement benefits up to 65% of a participant’s total cash compensation in effect immediately prior to retirement, subject to an annual $1 million maximum retirement benefit. Total cash compensation means (i) the highest amount payable to a participant as monthly base salary during the five years immediately prior to retirement multiplied by 12, plus (ii) the average of the participant’s awards under an annual incentive bonus program during the three years immediately prior to the year of retirement and (iii) special, additional or non-recurring bonus awards, if any, that are required to be included in total cash compensation pursuant to a participant’s employment agreement or approved for inclusion by the Board of Directors. Mr. Goodman’s SERP benefit will be reduced by the amount of his regular retirement benefit under the MidAmerican Energy Company Retirement Plan and ratably for retirement between ages 55 and 65. A survivor benefit is payable to a surviving spouse under the SERP. Benefits from the SERP will be paid out of general corporate funds; however, through a Rabbi trust, we maintain life insurance on the participants in amounts expected to be sufficient to fund the after-tax cost of the projected benefits. Deferred compensation is considered part of the salary covered by the SERP.

Under the MidAmerican Energy Company Retirement Plan, each NEO has an account, for record-keeping purposes only, to which credits are allocated annually based upon a percentage of the NEO’s base salary and incentive paid in the plan year. In addition, all balances in the accounts of NEOs earn a fixed rate of interest that is credited annually. The interest rate for a particular year is based on the one-year constant maturity Treasury yield plus seven-tenths of one percentage point. Each NEO is vested in the MidAmerican Energy Company Retirement Plan. At retirement, or other termination of employment, an amount equal to the vested balance then credited to the account is payable to the NEO in the form of a lump sum or an annuity.

Nonqualified Deferred Compensation

The following table sets forth certain information regarding the nonqualified deferred compensation plan accounts held by each of our NEOs at December 31, 2008:

											Aggregate
	Executive		Registrant		Aggregate			Aggregate			balance as of
	contributions		contributions		earnings			withdrawals/			December 31,
	in 2008(1)		in 2008		in 2008			distributions			2008(2)
Name	($)		($)		($)			($)			($)
David L. Sokol	$	-	$	-	$	-		$	-		$	-
Gregory E. Abel		250,000		-		(286,709	)		(227,204	)		741,741
Patrick J. Goodman		-		-		(366,165	)		(58,471	)		836,563
Douglas L. Anderson		47,595		-		(340,790	)		-			1,140,923
Maureen E. Sammon		44,000		-		(196,945	)		-			453,522

______________

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(1)

The contribution amounts shown for Mr. Abel and Ms. Sammon are included in the 2008 total compensation reported for them in the Summary Compensation Table and are not additional earned compensation. The contribution amount shown for Mr. Anderson includes $20,727 earned toward his 2004 LTIP award prior to 2008 and thus is not included in the 2008 total compensation reported for him in the Summary Compensation Table.

(2)

Excludes the value of 10,041 shares of our common stock reserved for issuance to Mr. Abel. Mr. Abel deferred the right to receive the value of these shares pursuant to a legacy nonqualified deferred compensation plan.

Eligibility for our DCP is restricted to select management and highly compensated employees. The plan provides tax benefits to eligible participants by allowing them to defer compensation on a pretax basis, thus reducing their current taxable income. Deferrals and any investment returns grow on a tax-deferred basis, thus participants pay no income tax until they receive distributions. The DCP permits participants to make a voluntary deferral of up to 50% of base salary and 100% of short-term incentive compensation awards. All deferrals are net of social security taxes. Amounts deferred under the DCP receive a rate of return based on the returns of any combination of eight investment options offered by the plan and selected by the participant. Gains or losses are calculated daily, and returns are posted to accounts based on participants’ fund allocation elections. Participants can change their fund allocations as of the end of any calendar day on which the market is open.

The DCP allows participants to maintain three accounts based upon when they want to receive payments: retirement distribution, in-service distribution and education distribution. Both the retirement and in-service accounts can be distributed as lump sums or in up to 10 annual installments. The education account is distributed in four annual installments. If a participant leaves employment prior to retirement (age 55) all amounts in the participant’s account will be paid out in a lump sum as soon as administratively practicable. Participants are 100% vested in their deferrals and any investment gains or losses recorded in their accounts.

Participants in our LTIP also have the option of deferring all or part of those awards after the five-year mandatory deferral and vesting period. The provisions governing the deferral of LTIP awards are similar to those described for the DCP above.

Potential Payments Upon Termination

We have entered into employment agreements with Messrs. Sokol, Abel and Goodman that provide for payments following termination of employment under various circumstances, which do not include change-in-control provisions.

Mr. Sokol’s employment will terminate upon his resignation, permanent disability, death, termination by us with or without cause, or our failure to provide Mr. Sokol with the compensation or to maintain the job responsibilities set forth in his employment agreement. A termination of employment of either Messrs. Abel or Goodman will occur upon his resignation (with or without good reason), permanent disability, death, or termination by us with or without cause. The employment agreements for Messrs. Sokol and Abel also include provisions specific to the calculation of their respective SERP benefits.

Neither Mr. Anderson nor Ms. Sammon has an employment agreement. Where a NEO does not have an employment agreement, or in the event that the agreements for Messrs. Sokol, Abel and Goodman do not address an issue, payments upon termination are determined by the applicable plan documents and our general employment policies and practices as discussed below.

The following discussion provides further detail on post-termination payments.

David L. Sokol

As described above, Mr. Sokol’s relinquishment of the CEO role was contemplated in his employment agreement, which provided for his corresponding reduction in annual salary and receipt of a special achievement award. The provisions described below factor in such position change as of April 16, 2008, and apply to his position as Chairman.

Mr. Sokol’s employment agreement provides that in the event Mr. Sokol has relinquished his position as CEO and is subsequently terminated as Chairman of the Board due to death, disability or other than for cause, he is entitled to (i) any accrued but unpaid base salary plus an amount equal to the aggregate annual base salary that would have been paid to him through the fifth anniversary of the date he commenced his employment solely as Chairman of the Board and (ii) the continuation of his senior executive employee benefits (or the economic equivalent thereof) through such fifth anniversary.

141

Payments made in accordance with the employment agreement are contingent on Mr. Sokol complying with the confidentiality and post-employment restrictions described therein. The term of the agreement isthe period of time beginning on the date Mr. Sokol relinquished his position as CEO, April 16, 2008, and ending on the fifth anniversary of such date, April 16, 2013, unless earlier terminated pursuant to the agreement.

The following table sets forth the estimated enhancements to payments pursuant to the termination scenarios described above. Payments or benefits that are not enhanced in form or amount upon the occurrence of a particular termination scenario, which include 401(k) account balances and those portions of life insurance benefits and cash balance pension amounts that would have otherwise been paid, are not included herein. All estimated payments reflected in the table below assume termination on December 31, 2008, and are payable as lump sums unless otherwise noted.

	Cash				Life				Benefits
Termination Scenario	Severance(1)		Incentive		Insurance(2)		Pension(3)		Continuation(4)		Excise Tax(5)
Retirement	$	-	$	-	$	-	$	8,711,000	$	-	$	-
Involuntary Without Cause, Company		3,218,750		-		-		8,711,000		132,446		-
Breach and Disability
Death		3,218,750		-		1,451,764		8,066,000		132,446		-

______________

(1)	The cash severance payments are determined in accordance with Mr. Sokol’s employment agreement.
(2)	Life insurance benefits are equal to two times base salary, as of the preceding June 1, less the benefits otherwise payable in all other termination scenarios, which are equal to the total cash value of the policies less cumulative premiums paid by us.
(3)	Pension values represent the excess of the present value of benefits payable under each termination scenario over the amount already reflected in the Pension Benefits Table. Mr. Sokol’s death scenario is based on a 100% joint and survivor with 15-year certain annuity commencing immediately. Mr. Sokol’s other termination scenarios are based on a 100% joint and survivor annuity commencing immediately.
(4)	Includes health and welfare, life insurance and financial planning and tax preparation benefits for five years. The health and welfare benefit amounts are estimated using the rates we currently charge employees terminating employment but electing to continue their medical, dental and vision insurance after termination. These amounts are grossed-up for taxes and then reduced by the amount Mr. Sokol would have paid if he had continued his employment. The life insurance benefit amounts are based on the cost of individual policies offering benefits equivalent to our group coverage and are grossed-up for taxes. These amounts also assume benefit continuation for the entire five year period, with no offset by another employer. We will also continue to provide financial planning and tax preparation reimbursement, or the economic equivalent thereof, for five years or pay a lump sum cash amount to keep Mr. Sokol in the same economic position on an after-tax basis. The amount included is based on an annual estimated cost using the most recent three-year average annual reimbursement. If it is determined that benefits paid with respect to the extension of medical and dental benefits to Mr. Sokol would not be exempt from taxation under the Internal Revenue Code, we shall pay to Mr. Sokol a lump sum cash payment following separation from service to allow him to obtain equivalent medical and dental benefits and which would put him in the same after-tax economic position.
(5)	As provided in Mr. Sokol’s employment agreement, should it be deemed under Section 280G of the Internal Revenue Code that termination payments constitute excess parachute payments subject to an excise tax, we will gross up such payments to cover the excise tax and any additional taxes associated with such gross-up. Based on computations prescribed under Section 280G and related regulations, we do not believe that any of the termination scenarios are subject to an excise tax.

Gregory E. Abel

Mr. Abel’s employment agreement entitles him to receive two years base salary continuation and payments in respect of average bonuses for the prior two years in the event we terminate his employment other than for cause. The payments are to be paid as a lump sum with no discount for present valuation.

142

In addition, if Mr. Abel’s employment is terminated due to death, permanent disability or other than for cause, he is entitled to continuation of his senior executive employee benefits (or the economic equivalent thereof) for two years. If Mr. Abel resigns, we must pay him any accrued but unpaid base salary, unless he resigns for good reason, in which case he will receive the same benefits as if he were terminated other than for cause.

Payments made in accordance with the employment agreement are contingent on Mr. Abel complying with the confidentiality and post-employment restrictions described therein. The term of the agreement effectively expires on August 6, 2013, and is extended automatically for additional one year terms thereafter subject to Mr. Abel’s election to decline renewal at least 365 days prior to the August 6 that is four years prior to the current expiration date (or by August 6, 2009 for the agreement not to extend to August 6, 2014).

The following table sets forth the estimated enhancements to payments pursuant to the termination scenarios indicated. Payments or benefits that are not enhanced in form or amount upon the occurrence of a particular termination scenario, which include 401(k) and nonqualified deferred compensation account balances and those portions of life insurance benefits and cash balance pension amounts that would have otherwise been paid, are not included herein. All estimated payments reflected in the table below assume termination on December 31, 2008, and are payable as lump sums unless otherwise noted.

	Cash				Life				Benefits
Termination Scenario	Severance(1)		Incentive		Insurance(2)		Pension(3)		Continuation(4)		Excise Tax(5)
Retirement, Voluntary and Involuntary	$	-	$	-	$	-	$	10,504,000	$	-	$	-
With Cause
Involuntary Without Cause, Disability and		11,000,000		-		-		10,504,000		50,324		-
Voluntary With Good Reason
Death		11,000,000		-		1,970,073		10,631,000		50,324		-

______________

(1)	The cash severance payments are determined in accordance with Mr. Abel’s employment agreement.
(2)	Life insurance benefits are equal to two times base salary, as of the preceding June 1, less the benefits otherwise payable in all other termination scenarios, which are equal to the total cash value of the policies less cumulative premiums paid by us.
(3)	Pension values represent the excess of the present value of benefits payable under each termination scenario over the amount already reflected in the Pension Benefits Table. Mr. Abel’s death scenario is based on a 100% joint and survivor with 15-year certain annuity commencing immediately. Mr. Abel’s other termination scenarios are based on a 100% joint and survivor annuity commencing immediately.
(4)	Includes health and welfare, life insurance and financial planning and tax preparation benefits for two years. The health and welfare benefit amounts are estimated using the rates we currently charge employees terminating employment but electing to continue their medical, dental and vision insurance after termination. These amounts are grossed-up for taxes and then reduced by the amount Mr. Abel would have paid if he had continued his employment. The life insurance benefit amounts are based on the cost of individual policies offering benefits equivalent to our group coverage and are grossed-up for taxes. These amounts also assume benefit continuation for the entire two year period, with no offset by another employer. We will also continue to provide financial planning and tax preparation reimbursement, or the economic equivalent thereof, for two years or pay a lump sum cash amount to keep Mr. Abel in the same economic position on an after-tax basis. The amount included is based on an annual estimated cost using the most recent three-year average annual reimbursement. If it is determined that benefits paid with respect to the extension of medical and dental benefits to Mr. Abel would not be exempt from taxation under the Internal Revenue Code, we shall pay to Mr. Abel a lump sum cash payment following separation from service to allow him to obtain equivalent medical and dental benefits and which would put him in the same after-tax economic position.
(5)	As provided in Mr. Abel’s employment agreement, should it be deemed under Section 280G of the Internal Revenue Code that termination payments constitute excess parachute payments subject to an excise tax, we will gross up such payments to cover the excise tax and any additional taxes associated with such gross-up. Based on computations prescribed under Section 280G and related regulations, we believe that none of the termination scenarios are subject to any excise tax.

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Patrick J. Goodman

Mr. Goodman’s employment agreement entitles him to receive two years base salary continuation and payments in respect of average bonuses for the prior two years in the event we terminate his employment other than for cause. The payments are to be paid as a lump sum with no discount for present valuation.

In addition, if Mr. Goodman’s employment is terminated due to death, permanent disability or other than for cause, he is entitled to continuation of his senior executive employee benefits (or the economic equivalent thereof) for one year. If Mr. Goodman resigns, we must pay him any accrued but unpaid base salary, unless he resigns for good reason, in which case he will receive the same benefits as if he were terminated other than for cause.

Payments made in accordance with the employment agreement are contingent on Mr. Goodman complying with the confidentiality and post-employment restrictions described therein. The term of the agreement expires on April 21, 2010, but is extended automatically for additional one year terms thereafter subject to Mr. Goodman’s election to decline renewal at least 365 days prior to the then current expiration date or termination.

The following table sets forth the estimated enhancements to payments pursuant to the termination scenarios indicated. Payments or benefits that are not enhanced in form or amount upon the occurrence of a particular termination scenario, which include 401(k) and nonqualified deferred compensation account balances and those portions of long-term incentive payments, life insurance benefits and cash balance pension amounts that would have otherwise been paid, are not included herein. All estimated payments reflected in the table below assume termination on December 31, 2008, and are payable as lump sums unless otherwise noted.

	Cash				Life				Benefits
Termination Scenario	Severance(1)		Incentive(2)		Insurance(3)		Pension(4)		Continuation(5)		Excise Tax(6)
Retirement and Voluntary	$	-	$	-	$	-	$	511,000	$	-	$	-
Involuntary With Cause		-		-		-		-		-		-
Involuntary Without Cause and Voluntary		3,000,000		-		-		511,000		15,124		1,151,256
With Good Reason
Death		3,000,000		1,254,330		651,929		3,832,000		15,124		-
Disability		3,000,000		1,254,330		-		1,575,000		15,124		-

______________

(1)	The cash severance payments are determined in accordance with Mr. Goodman’s employment agreement.
(2)	Amounts represent the unvested portion of Mr. Goodman’s LTIP account, which becomes 100% vested upon his death or disability.
(3)	Life insurance benefits are equal to two times base salary, as of the preceding June 1, less the benefits otherwise payable in all other termination scenarios, which are equal to the total cash value of the policies less cumulative premiums paid by us.
(4)	Pension values represent the excess of the present value of benefits payable under each termination scenario over the amount already reflected in the Pension Benefits Table. Mr. Goodman’s voluntary termination, retirement, involuntary without cause, and change in control termination scenarios are based on a 66 2/3% joint and survivor annuity commencing at age 55 (reductions for termination prior to age 55 and commencement prior to age 65). Mr. Goodman’s disability scenario is based on a 66 2/3% joint and survivor annuity commencing at age 55 (no reduction for termination prior to age 55, reduced for commencement prior to age 65). Mr. Goodman’s death scenario is based on a 100% joint and survivor with 15-year certain annuity commencing immediately (no reduction for termination prior to age 55 and commencement prior to age 65).
(5)	Includes health and welfare, life insurance and financial planning and tax preparation benefits for one year. The health and welfare benefit amounts are estimated using the rates we currently charge employees terminating employment but electing to continue their medical, dental and vision insurance after termination. These amounts are grossed-up for taxes and then reduced by the amount Mr. Goodman would have paid if he had continued his employment. The life insurance benefit amounts are based on the cost of individual policies offering benefits equivalent to our group coverage and are grossed-up for taxes. These amounts also assume benefit continuation for the entire one year period, with no offset by another employer. We will also continue to provide financial planning and tax preparation reimbursement, or the economic equivalent thereof, for one year or pay a lump sum cash amount to keep Mr. Goodman in the same economic position on an after-tax basis. The amount included is based on an annual estimated cost using the most recent three-year average annual reimbursement.
(6)	As provided in Mr. Goodman’s employment agreement, should it be deemed under Section 280G of the Internal Revenue Code that termination payments constitute excess parachute payments subject to an excise tax, we will gross up such payments to cover the excise tax and any additional taxes associated with such gross-up. Based on computations prescribed under Section 280G and related regulations, we believe that only the Involuntary Without Cause and Voluntary With Good Reason termination scenarios are subject to any excise tax.

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Douglas L. Anderson

The following table sets forth the estimated enhancements to payments pursuant to the termination scenarios indicated. Payments or benefits that are not enhanced in form or amount upon the occurrence of a particular termination scenario, which include 401(k) and nonqualified deferred compensation account balances and those portions of long-term incentive payments and cash balance pension amounts that would have otherwise been paid, are not included herein. All estimated payments reflected in the table below assume termination on December 31, 2008, and are payable as lump sums unless otherwise noted.

	Cash				Life				Benefits
Termination Scenario	Severance		Incentive(1)		Insurance		Pension(2)		Continuation		Excise Tax
Retirement, Voluntary and Involuntary With or	$	-	$	-	$	-	$	31,000	$	-	$	-
Without Cause
Death and Disability		-		869,822		-		31,000		-		-

______________

(1)	Amounts represent the unvested portion of Mr. Anderson’s LTIP account, which becomes 100% vested upon his death or disability.
(2)	Pension values represent the excess of the present value of benefits payable under each termination scenario over the amount already reflected in the Pension Benefits Table.

Maureen E. Sammon

The following table sets forth the estimated enhancements to payments pursuant to the termination scenarios indicated. Payments or benefits that are not enhanced in form or amount upon the occurrence of a particular termination scenario, which include 401(k) and nonqualified deferred compensation account balances and those portions of long-term incentive payments and cash balance pension amounts that would have otherwise been paid, are not included herein. All estimated payments reflected in the table below assume termination on December 31, 2008, and are payable as lump sums unless otherwise noted.

	Cash				Life				Benefits
Termination Scenario	Severance		Incentive(1)		Insurance		Pension(2)		Continuation		Excise Tax
Retirement, Voluntary and Involuntary With or	$	-	$	-	$	-	$	45,000	$	-	$	-
Without Cause
Death and Disability		-		521,155		-		45,000		-		-

______________

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(1)	Amounts represent the unvested portion of Ms. Sammon’s LTIP account, which becomes 100% vested upon her death or disability.
(2)	Pension values represent the excess of the present value of benefits payable under each termination scenario over the amount already reflected in the Pension Benefits Table.

Director Compensation

Our directors are not paid any fees for serving as directors. All directors are reimbursed for their expenses incurred in attending Board of Directors meetings.

Compensation Committee Interlocks and Insider Participation

Mr. Buffett is the Chairman of the Board of Directors and Chief Executive Officer of Berkshire Hathaway, our majority owner. Mr. Scott is a former officer of ours. Based on the standards of the New York Stock Exchange, Inc. on which the common stock of our majority owner, Berkshire Hathaway, is listed, our Board of Directors has determined that Messrs. Buffett and Scott are not independent because of their ownership of our common stock. None of our executive officers serves as a member of the compensation committee of any company that has an executive officer serving as a member of our Board of Directors. None of our executive officers serves as a member of the board of directors of any company that has an executive officer serving as a member of our Compensation Committee. See also Item 13 of this Form 10-K.

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

Beneficial Ownership

We are a consolidated subsidiary of Berkshire Hathaway. The remainder of our common stock is owned by a private investor group comprised of Messrs. Scott and Abel. The following table sets forth certain information regarding beneficial ownership of our shares of common stock held by each of our directors, executive officers and all of our directors and executive officers as a group as of January 31, 2009:

	Number of Shares
Name and Address of Beneficial Owner (1)	Beneficially Owned(2)		Percentage Of Class(2)
Berkshire Hathaway(3)		66,063,061		88.25	%
Walter Scott, Jr.(4)		4,700,000		6.28	%
David L. Sokol(5)		549,277		0.73	%
Gregory E. Abel(6)		749,992		1.00	%
Douglas L. Anderson		-		-
Warren E. Buffett(7)		-		-
Patrick J. Goodman		-		-
Marc D. Hamburg(7)		-		-
Maureen E. Sammon		-		-
All directors and executive officers as a group (8 persons)		5,999,269		7.94	%

(1)	Unless otherwise indicated, each address is c/o MidAmerican Energy Holdings Company at 666 Grand Avenue, 29th Floor, Des Moines, Iowa 50309.
(2)	Includes shares of which the listed beneficial owner is deemed to have the right to acquire beneficial ownership under Rule 13d-3(d) under the Securities Exchange Act, including, among other things, shares which the listed beneficial owner has the right to acquire within 60 days.
(3)	Such beneficial owner’s address is 1440 Kiewit Plaza, Omaha, Nebraska 68131.
(4)	Excludes 3,500,000 shares held by family members and family controlled trusts and corporations, or Scott Family Interests, as to which Mr. Scott disclaims beneficial ownership. Mr. Scott’s address is 1000 Kiewit Plaza, Omaha, Nebraska 68131.
(5)	Includes options to purchase 549,277 shares of common stock that are presently exercisable or become exercisable within 60 days.
(6)	Includes options to purchase 154,052 shares of common stock that are presently exercisable or become exercisable within 60 days.
(7)	Excludes 66,063,061 shares of common stock held by Berkshire Hathaway as to which Messrs. Buffett and Hamburg disclaim beneficial ownership.

146

The following table sets forth certain information regarding beneficial ownership of Class A and Class B shares of Berkshire Hathaway’s common stock held by each of our directors, executive officers and all of our directors and executive officers as a group as of January 31, 2009:

Name and Address of Beneficial Owner (1)	Number of Shares Beneficially Owned (2)		Percentage Of Class (2)
Walter Scott, Jr.(3)(4)
Class A		100		*
Class B		-		-
David L. Sokol(4)
Class A		1,135		*
Class B		85		*
Gregory E. Abel(4)
Class A		1		*
Class B		14		*
Douglas L. Anderson
Class A		4		*
Class B		4		*
Warren E. Buffett(5)
Class A		350,000		33.08	%
Class B		2,018,997		13.70	%
Patrick J. Goodman
Class A		2		*
Class B		3		*
Marc D. Hamburg
Class A		-		-
Class B		-		-
Maureen E. Sammon
Class A		-		-
Class B		26		*
All directors and executive officers as a group (8 persons)
Class A		351,242		33.20	%
Class B		2,019,129		13.70	%
* Less than 1%

(1)	Unless otherwise indicated, each address is c/o MidAmerican Energy Holdings Company at 666 Grand Avenue, 29th Floor, Des Moines, Iowa 50309.
(2)	Includes shares which the listed beneficial owner is deemed to have the right to acquire beneficial ownership under Rule 13d-3(d) under the Securities Exchange Act, including, among other things, shares which the listed beneficial owner has the right to acquire within 60 days.
(3)	Does not include 10 Class A shares owned by Mr. Scott’s wife. Mr. Scott’s address is 1000 Kiewit Plaza, Omaha, Nebraska 68131.
(4)	In accordance with a shareholders agreement, as amended on December 7, 2005, based on an assumed value for our common stock and the closing price of Berkshire Hathaway common stock on January 31, 2009, Mr. Scott and the Scott Family Interests and Messrs. Sokol and Abel would be entitled to exchange their shares of our common stock and their shares acquired by exercise of options to purchase our common stock for either 19,240, 1,289 and 1,760, respectively, shares of Berkshire Hathaway Class A stock or 576,112, 38,591 and 52,693, respectively, shares of Berkshire Hathaway Class B stock. Assuming an exchange of all available MEHC shares into either Berkshire Hathaway Class A shares or Berkshire Hathaway Class B shares, Mr. Scott and the Scott Family Interests would beneficially own 1.80% of the outstanding shares of Berkshire Hathaway Class A stock or 3.76% of the outstanding shares of Berkshire Hathaway Class B stock, and each of Messrs. Sokol and Abel would beneficially own less than 1% of the outstanding shares of either class of stock.
(5)	Mr. Buffett’s address is 1440 Kiewit Plaza, Omaha, Nebraska 68131.

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Other Matters

Mr. Sokol’s employment agreement gives him the right during the term of his employment to serve as a member of the Board of Directors and to nominate two additional directors.

Pursuant to a shareholders agreement, as amended on December 7, 2005, Mr. Scott or any of the Scott Family Interests and Messrs. Sokol and Abel are able to require Berkshire Hathaway to exchange any or all of their respective shares of our common stock for shares of Berkshire Hathaway common stock. The number of shares of Berkshire Hathaway stock to be exchanged is based on the fair market value of our common stock divided by the closing price of the Berkshire Hathaway stock on the day prior to the date of exchange.

Item 13. Certain Relationships and Related Transactions, and Director Independence

Certain Relationships and Related Transactions

The Berkshire Hathaway Inc. Code of Business Conduct and Ethics and the MEHC Code of Business Conduct, or the Codes, which apply to all of our directors, officers and employees and those of our subsidiaries, generally govern the review, approval or ratification of any related-person transaction. A related-person transaction is one in which we or any of our subsidiaries participate and in which one or more of our directors, executive officers, holders of more than five percent of our voting securities or any of such persons’ immediate family members have a direct or indirect material interest.

Under the Codes, all of our directors and executive officers (including those of our subsidiaries) must disclose to our legal department any material transaction or relationship that reasonably could be expected to give rise to a conflict with our interests. No action may be taken with respect to such transaction or relationship until approved by the legal department. For our chief executive officer and chief financial officer, prior approval for any such transaction or relationship must be given by Berkshire Hathaway’s audit committee. In addition, prior legal department approval must be obtained before a director or executive officer can accept employment, offices or board positions in other for-profit businesses, or engage in his or her own business that raises a potential conflict or appearance of conflict with our interests. Transactions with Berkshire Hathaway require the approval of our Board of Directors.

At December 31, 2008 and 2007, Berkshire Hathaway and its affiliates held 11% mandatorily redeemable preferred securities due from certain of our wholly owned subsidiary trusts with liquidation preferences of $1.09 billion and $821 million, respectively. Principal repayments and interest expense on these securities totaled $734 million and $111 million, respectively, during 2008. We repaid an additional $500 million of the 11% mandatorily redeemable preferred securities held by affiliates of Berkshire Hathaway on January 12, 2009.

Director Independence

Based on the standards of the New York Stock Exchange, Inc., on which the common stock of our majority owner, Berkshire Hathaway, is listed, our Board of Directors has determined that none of our directors are considered independent because of their employment by Berkshire Hathaway or us or their ownership of our common stock.

148 

Item 14. Principal Accountant Fees and Services

The following table shows the Company’s fees paid or accrued for audit and audit-related services and fees paid for tax and all other services rendered by Deloitte & Touche LLP, the member firms of Deloitte Touche Tohmatsu, and their respective affiliates (collectively, the “Deloitte Entities”) for each of the last two years (in millions):

	2008		2007
Audit fees(1)	$	5.9	$	5.3
Audit-related fees(2)		1.1		0.5
Tax fees(3)		0.1		0.3
All other fees		-		-
Total aggregate fees billed	$	7.1	$	6.1

(1)	Audit fees include fees for the audit of the Company’s consolidated financial statements and interim reviews of the Company’s quarterly financial statements, audit services provided in connection with required statutory audits of certain of MEHC’s subsidiaries and comfort letters, consents and other services related to SEC matters.
(2)	Audit-related fees primarily include fees for assurance and related services for any other statutory or regulatory requirements, audits of certain subsidiary employee benefit plans and consultations on various accounting and reporting matters.
(3)	Tax fees include fees for services relating to tax compliance, tax planning and tax advice. These services include assistance regarding federal, state and international tax compliance, tax return preparation and tax audits.

The audit committee reviewed and approved the services rendered by the Deloitte Entities in and for fiscal 2008 as set forth in the above table and concluded that the non-audit services were compatible with maintaining the principal accountant’s independence. Under the Sarbanes-Oxley Act of 2002, all audit and non-audit services performed by the principal accountant require the approval in advance by the audit committee in order to assure that such services do not impair the principal accountant’s independence from the Company. Accordingly, the audit committee has an Audit and Non-Audit Services Pre-Approval Policy (the “Policy”) that sets forth the procedures and the conditions pursuant to which services to be performed by the principal accountant are to be pre-approved. Pursuant to the Policy, certain services described in detail in the Policy may be pre-approved on an annual basis together with pre-approved maximum fee levels for such services. The services eligible for annual pre-approval consist of services that would be included under the categories of Audit Fees, Audit-Related Fees and Tax Fees. If not pre-approved on an annual basis, proposed services must otherwise be separately approved prior to being performed by the principal accountant. In addition, any services that receive annual pre-approval but exceed the pre-approved maximum fee level also will require separate approval by the audit committee prior to being performed. The Policy does not delegate to management the audit committee’s responsibilities to pre-approve services performed by the principal accountant.

149 

PART IV

Item 15. Exhibits and Financial Statement Schedules

(a)	Financial Statements and Schedules
	(i)	Financial Statements
		Consolidated Financial Statements are included in Item 8.
	(ii)	Financial Statement Schedules
		See Schedule I on page 151.
		See Schedule II on page 155.
		Schedules not listed above have been omitted because they are either not applicable, not required or the information required to be set forth therein is included in the Consolidated Financial Statements or notes thereto.
(b)	Exhibits
	The exhibits listed on the accompanying Exhibit Index are filed as part of this Annual Report.
	Financial statements required by Regulation S-X, which are excluded from the Annual Report by Rule 14a-3(b).
	Not applicable.

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Schedule I

MidAmerican Energy Holdings Company

Parent Company Only

Condensed Balance Sheets

As of December 31, 2008 and 2007

(Amounts in millions)

	2008			2007
ASSETS
Current assets:
Cash and cash equivalents	$	6		$	765
Other current assets		5			4
Total current assets		11			769
Investments in and advances to subsidiaries and joint ventures		15,783			13,995
Equipment, net		32			34
Goodwill		1,268			1,278
Deferred charges, investments and other		111			135
Total assets	$	17,205		$	16,211
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable and other current liabilities	$	226		$	167
Short-term debt		216			-
Current portion of senior debt		-			1,000
Current portion of subordinated debt		734			234
Total current liabilities		1,176			1,401
Senior debt		5,121			4,471
Subordinated debt		587			891
Other long-term liabilities		111			121
Total liabilities		6,995			6,884
Minority interest		3			1
Shareholders’ equity:
Common stock - 115 shares authorized, no par value, 75 shares issued and outstanding		-			-
Additional paid-in capital		5,455			5,454
Retained earnings		5,631			3,782
Accumulated other comprehensive (loss) income, net		(879	)		90
Total shareholders’ equity		10,207			9,326
Total liabilities and shareholders’ equity	$	17,205		$	16,211

The notes to the consolidated MEHC financial statements are an integral part of this financial statement schedule.

151 

Schedule I

MidAmerican Energy Holdings Company

Parent Company Only (continued)

Condensed Statements of Operations

For the three years ended December 31, 2008

(Amounts in millions)

	2008			2007			2006
Revenues:
Equity in undistributed earnings of subsidiary companies and joint ventures	$	1,770		$	970		$	664
Dividends and distributions from subsidiary companies and joint ventures		304			483			592
Interest and other income		226			27			13
Total revenues		2,300			1,480			1,269
Costs and expenses:
General and administration		34			15			107
Depreciation and amortization		-			2			5
Interest		487			459			427
Other		16			-			-
Total costs and expenses		537			476			539
Income before income tax benefit and minority interest		1,763			1,004			730
Income tax benefit		(87	)		(185	)		(187	)
Minority interest		-			-			1
Net income	$	1,850		$	1,189		$	916

The notes to the consolidated MEHC financial statements are an integral part of this financial statement schedule.

152 

Schedule I

MidAmerican Energy Holdings Company

Parent Company Only (continued)

Condensed Statements of Cash Flows

For the three years ended December 31, 2008

(Amounts in millions)

	2008			2007			2006
Cash flows from operating activities	$	(147	)	$	(204	)	$	(250	)
Cash flows from investing activities:
(Increase) decrease in advances to and investments in subsidiaries and joint ventures		(660	)		317			(4,708	)
Purchases of available-for-sale securities		(8	)		(407	)		(148	)
Proceeds from sale of available-for-sale securities		3			399			140
Other, net		-			19			-
Net cash flows from investing activities		(665	)		328			(4,716	)
Cash flows from financing activities:
Proceeds from senior and subordinated debt		1,649			1,539			1,699
Repayments of senior and subordinated debt		(1,803	)		(784	)		(234	)
Purchases of senior debt		(138	)		-			-
Proceeds from previously purchased senior debt		137			-			-
Net borrowings (repayments) on revolving credit facility		216			(152	)		101
Proceeds from issuances of common stock		-			10			5,132
Purchases of common stock		-			-			(1,750	)
Net repayment of affiliate notes		-			-			(22	)
Other, net		(8	)		25			41
Net cash flows from financing activities		53			638			4,967
Net change in cash and cash equivalents		(759	)		762			1
Cash and cash equivalents at beginning of year		765			3			2
Cash and cash equivalents at end of year	$	6		$	765		$	3

The notes to the consolidated MEHC financial statements are an integral part of this financial statement schedule.

153 

Schedule I

MIDAMERICAN ENERGY HOLDINGS COMPANY

NOTES TO CONDENSED FINANCIAL STATEMENTS

Incorporated by reference are MEHC and Subsidiaries Consolidated Statements of Shareholders’ Equity for the three years ended December 31, 2008 in Part II, Item 8.

Basis of Presentation - The condensed financial information of MidAmerican Energy Holdings Company’s (“MEHC”) investments in subsidiaries are presented under the equity method of accounting. Under this method, the assets and liabilities of subsidiaries are not consolidated. The investments in and advances to subsidiaries and joint ventures are recorded in the Condensed Balance Sheets. The income from operations of the subsidiaries and joint ventures is reported on a net basis as equity in undistributed earnings of subsidiary companies and joint ventures in the Condensed Statements of Operations.

Interest and other income - On December 17, 2008, MEHC and Constellation Energy Group, Inc. (“Constellation Energy”) entered into a termination agreement, pursuant to which, among other things, the parties agreed to terminate the September 19, 2008 merger agreement. As a result of the termination, MEHC received a $175 million termination fee.

See the notes to the consolidated MEHC financial statements in Part II, Item 8 for other disclosures.

154 

Schedule II

MIDAMERICAN ENERGY HOLDINGS COMPANY

CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS

FOR THE THREE YEARS ENDED DECEMBER 31, 2008

(Amounts in millions)

	Column B		Column C							Column E
	Balance at		Charged							Balance
Column A	Beginning		to		Acquisition		Column D			at End
Description	of Year		Income		Reserves(1)		Deductions			of Year
Reserves Deducted From Assets To Which They Apply:
Reserve for uncollectible accounts receivable:
Year ended 2008	$	22	$	32	$	-	$	(30	)	$	24
Year ended 2007		30		24		-		(32	)		22
Year ended 2006		21		19		11		(21	)		30
Reserves Not Deducted From Assets(2):
Year ended 2008	$	12	$	2	$	-	$	(5	)	$	9
Year ended 2007		12		3		-		(3	)		12
Year ended 2006		12		3		-		(3	)		12

The notes to the consolidated MEHC financial statements are an integral part of this financial statement schedule.

(1)	Acquisition reserves represent the reserves recorded at PacifiCorp at the date of acquisition.
(2)	Reserves not deducted from assets relate primarily to estimated liabilities for losses retained by MEHC for workers compensation, public liability and property damage claims.

155 

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized on this 27th day of February 2009.

MIDAMERICAN ENERGY HOLDINGS COMPANY

/s/ Gregory E. Abel*

Gregory E. Abel

President and Chief Executive Officer

(principal executive officer)

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

Signature	Title	Date
/s/ David L. Sokol*	Chairman of the Board and Director	February 27, 2009
David L. Sokol
/s/ Gregory E. Abel*	President, Chief Executive Officer and	February 27, 2009
Gregory E. Abel	Director
	(principal executive officer)
/s/ Patrick J. Goodman*	Senior Vice President and	February 27, 2009
Patrick J. Goodman	Chief Financial Officer
	(principal financial and accounting
	officer)
/s/ Walter Scott, Jr.*	Director	February 27, 2009
Walter Scott, Jr.
/s/ Marc D. Hamburg*	Director	February 27, 2009
Marc D. Hamburg
/s/ Warren E. Buffett*	Director	February 27, 2009
Warren E. Buffett
*    By: /s/ Douglas L. Anderson	Attorney-in-Fact	February 27, 2009
Douglas L. Anderson

156 

SUPPLEMENTAL INFORMATION TO BE FURNISHED WITH REPORTS FILED PURSUANT TO SECTION 15(D) OF THE ACT BY REGISTRANTS WHICH HAVE NOT REGISTERED SECURITIES PURSUANT TO SECTION 12 OF THE ACT

No annual report to security holders covering MidAmerican Energy Holdings Company’s last fiscal year or proxy material has been sent to security holders.

157 

EXHIBIT INDEX

Exhibit No.	Description
3.1	Second Amended and Restated Articles of Incorporation of MidAmerican Energy Holdings Company effective March 2, 2006 (incorporated by reference to Exhibit 3.1 to the MidAmerican Energy Holdings Company Annual Report on Form 10-K for the year ended December 31, 2005).
3.2	Amended and Restated Bylaws of MidAmerican Energy Holdings Company (incorporated by reference to Exhibit 3.2 to the MidAmerican Energy Holdings Company Annual Report on Form 10-K for the year ended December 31, 2005).
4.1	Indenture, dated as of October 4, 2002, by and between MidAmerican Energy Holdings Company and The Bank of New York, Trustee, relating to the 5.875% Senior Notes due 2012 (incorporated by reference to Exhibit 4.1 to the MidAmerican Energy Holdings Company Registration Statement No. 333-101699 dated December 6, 2002).
4.2	First Supplemental Indenture, dated as of October 4, 2002, by and between MidAmerican Energy Holdings Company and The Bank of New York, Trustee, relating to the 5.875% Senior Notes due 2012 (incorporated by reference to Exhibit 4.2 to the MidAmerican Energy Holdings Company Registration Statement No. 333-101699 dated December 6, 2002).
4.3	Third Supplemental Indenture, dated as of February 12, 2004, by and between MidAmerican Energy Holdings Company and The Bank of New York, Trustee, relating to the 5.00% Senior Notes due 2014 (incorporated by reference to Exhibit 4.4 to the MidAmerican Energy Holdings Company Registration Statement No. 333-113022 dated February 23, 2004).
4.4	Fourth Supplemental Indenture, dated as of March 24, 2006, by and between MidAmerican Energy Holdings Company and The Bank of New York Trust Company, N.A., Trustee, relating to the 6.125% Senior Bonds due 2036 (incorporated by reference to Exhibit 4.1 to the MidAmerican Energy Holdings Company Current Report on Form 8-K dated March 28, 2006).
4.5	Fifth Supplemental Indenture, dated as of May 11, 2007, by and between MidAmerican Energy Holdings Company and The Bank of New York Trust Company, N.A., Trustee, relating to the 5.95% Senior Bonds due 2037 (incorporated by reference to Exhibit 4.1 to the MidAmerican Energy Holdings Company Current Report on Form 8-K dated May 11, 2007).
4.6	Sixth Supplemental Indenture, dated as of August 28, 2007, by and between MidAmerican Energy Holdings Company and The Bank of New York Trust Company, N.A., Trustee, relating to the 6.50% Senior Bonds due 2037 (incorporated by reference to Exhibit 4.1 to the MidAmerican Energy Holdings Company Current Report on Form 8-K dated August 28, 2007).
4.7	Seventh Supplemental Indenture, dated as of March 28, 2008, by and between MidAmerican Energy Holdings Company and The Bank of New York Trust Company, N.A., as Trustee, relating to the 5.75% Senior Notes due 2018 (incorporated by reference to Exhibit 4.1 to the MidAmerican Energy Holdings Company Current Report on Form 8-K dated March 28, 2008).
4.8	Indenture dated as of February 26, 1997, by and between MidAmerican Energy Holdings Company and the Bank of New York, Trustee relating to the 6¼% Convertible Junior Subordinated Debentures due 2012 (incorporated by reference to Exhibit 10.129 to the MidAmerican Energy Holdings Company Annual Report on Form 10-K for the year ended December 31, 1995).
4.9	Indenture, dated as of October 15, 1997, by and between MidAmerican Energy Holdings Company and IBJ Schroder Bank & Trust Company, Trustee (incorporated by reference to Exhibit 4.1 to the MidAmerican Energy Holdings Company Current Report on Form 8-K dated October 23, 1997).

158 

Exhibit No. Description

4.10	Form of Second Supplemental Indenture, dated as of September 22, 1998 by and between MidAmerican Energy Holdings Company and IBJ Schroder Bank & Trust Company, Trustee, relating to the 8.48% Senior Notes in the principal amount of $475,000,000 due 2028 (incorporated by reference to Exhibit 4.1 to the MidAmerican Energy Holdings Company Current Report on Form 8-K dated September 17, 1998).
4.11	Indenture, dated as of March 14, 2000, by and between MidAmerican Energy Holdings Company and the Bank of New York, Trustee (incorporated by reference to Exhibit 4.9 to the MidAmerican Energy Holdings Company Annual Report on Form 10-K/A for the year ended December 31, 1999).
4.12	Indenture, dated as of March 12, 2002, by and between MidAmerican Energy Holdings Company and the Bank of New York, Trustee (incorporated by reference to Exhibit 4.11 to the MidAmerican Energy Holdings Company Annual Report on Form 10-K for the year ended December 31, 2001).
4.13	Amended and Restated Declaration of Trust of MidAmerican Capital Trust III, dated as of August 16, 2002 (incorporated by reference to Exhibit 4.14 to the MidAmerican Energy Holdings Company Registration Statement No. 333-101699 dated December 6, 2002).
4.14	Amended and Restated Declaration of Trust of MidAmerican Capital Trust II, dated as of March 12, 2002 (incorporated by reference to Exhibit 4.15 to the MidAmerican Energy Holdings Company Registration Statement No. 333-101699 dated December 6, 2002).
4.15	Amended and Restated Declaration of Trust of MidAmerican Capital Trust I, dated as of March 14, 2000 (incorporated by reference to Exhibit 4.16 to the MidAmerican Energy Holdings Company Registration Statement No. 333-101699 dated December 6, 2002).
4.16	Indenture, dated as of August 16, 2002, by and between MidAmerican Energy Holdings Company and the Bank of New York, Trustee (incorporated by reference to Exhibit 4.17 to the MidAmerican Energy Holdings Company Registration Statement No. 333-101699 dated December 6, 2002).
4.17	Amended and Restated Credit Agreement, dated as of July 6, 2006, by and among MidAmerican Energy Holdings Company, as Borrower, The Banks and Other Financial Institutions Parties Hereto, as Banks, JPMorgan Chase Bank, N.A., as L/C Issuer, Union Bank of California, N.A., as Administrative Agent, The Royal Bank of Scotland PLC, as Syndication Agent, and ABN Amro Bank N.V., JPMorgan Chase Bank, N.A. and BNP Paribas as Co-Documentation Agents (incorporated by reference to Exhibit 99.1 to the MidAmerican Energy Holdings Company Quarterly Report on Form 10-Q for the quarter ended June 30, 2006).
4.18	Trust Indenture, dated as of November 27, 1995, by and between CE Casecnan Water and Energy Company, Inc. and Chemical Trust Company of California, Trustee (incorporated by reference to Exhibit 4.1 to the CE Casecnan Water and Energy Company, Inc. Registration Statement on Form S-4 dated January 25, 1996).
4.19	Indenture and First Supplemental Indenture, dated March 11, 1999, by and between MidAmerican Funding, LLC and IBJ Whitehall Bank & Trust Company, Trustee, relating to the $700 million Senior Notes and Bonds (incorporated by reference to the MidAmerican Energy Holdings Company Annual Report on Form 10-K for the year ended December 31, 1998).
4.20	Second Supplemental Indenture, dated as of March 1, 2001, by and between MidAmerican Funding, LLC and The Bank of New York, Trustee (incorporated by reference to Exhibit 4.4 to the MidAmerican Funding, LLC Registration Statement on Form S-3, Registration No. 333-56624).
4.21	Indenture dated as of December 1, 1996, by and between MidAmerican Energy Company and the First National Bank of Chicago, Trustee (incorporated by reference to Exhibit 4(1) to the MidAmerican Energy Company Registration Statement on Form S-3, Registration No. 333-15387).

  159

Exhibit No. Description

4.22	First Supplemental Indenture, dated as of February 8, 2002, by and between MidAmerican Energy Company and The Bank of New York, Trustee (incorporated by reference to Exhibit 4.3 to the MidAmerican Energy Company Annual Report on Form 10-K for the year ended December 31, 2004, Commission File No. 333-15387).
4.23	Second Supplemental Indenture, dated as of January 14, 2003, by and between MidAmerican Energy Company and The Bank of New York, Trustee (incorporated by reference to Exhibit 4.2 to the MidAmerican Energy Company Annual Report on Form 10-K for the year ended December 31, 2004, Commission File No. 333-15387).
4.24	Third Supplemental Indenture, dated as of October 1, 2004, by and between MidAmerican Energy Company and The Bank of New York, Trustee (incorporated by reference to Exhibit 4.1 to the MidAmerican Energy Company Annual Report on Form 10-K for the year ended December 31, 2004, Commission File No. 333-15387).
4.25	Fourth Supplemental Indenture, dated November 1, 2005, by and between MidAmerican Energy Company and the Bank of New York Trust Company, NA, Trustee (incorporated by reference to Exhibit 4.1 to the MidAmerican Energy Company Annual Report on Form 10-K for the year ended December 31, 2005).
4.26	Fiscal Agency Agreement, dated as of October 15, 2002, by and between Northern Natural Gas Company and J.P. Morgan Trust Company, National Association, Fiscal Agent, relating to the $300,000,000 in principal amount of the 5.375% Senior Notes due 2012 (incorporated by reference to Exhibit 10.47 to the MidAmerican Energy Holdings Company Annual Report on Form 10-K for the year ended December 31, 2003).
4.27	Trust Indenture, dated as of August 13, 2001, among Kern River Funding Corporation, Kern River Gas Transmission Company and JP Morgan Chase Bank, Trustee, relating to the $510,000,000 in principal amount of the 6.676% Senior Notes due 2016 (incorporated by reference to Exhibit 10.48 to the MidAmerican Energy Holdings Company Annual Report on Form 10-K for the year ended December 31, 2003).
4.28	Third Supplemental Indenture, dated as of May 1, 2003, among Kern River Funding Corporation, Kern River Gas Transmission Company and JPMorgan Chase Bank, Trustee, relating to the $836,000,000 in principal amount of the 4.893% Senior Notes due 2018 (incorporated by reference to Exhibit 10.49 to the MidAmerican Energy Holdings Company Annual Report on Form 10-K for the year ended December 31, 2003).
4.29	Trust Deed, dated December 15, 1997 among CE Electric UK Funding Company, AMBAC Insurance UK Limited and The Law Debenture Trust Corporation, p.l.c., Trustee (incorporated by reference to Exhibit 99.1 to the MidAmerican Energy Holdings Company Current Report on Form 8-K dated March 30, 2004).
4.30	Insurance and Indemnity Agreement, dated December 15, 1997 by and between CE Electric UK Funding Company and AMBAC Insurance UK Limited (incorporated by reference to Exhibit 99.2 to the MidAmerican Energy Holdings Company Current Report on Form 8-K dated March 30, 2004).
4.31	Supplemental Agreement to Insurance and Indemnity Agreement, dated September 19, 2001, by and between CE Electric UK Funding Company and AMBAC Insurance UK Limited (incorporated by reference to Exhibit 99.3 to the MidAmerican Energy Holdings Company Current Report on Form 8-K dated March 30, 2004).
4.32	Fiscal Agency Agreement, dated as of July 15 2008, by and between Northern Natural Gas Company and The Bank New York Mellon Trust Company, National Association, Fiscal Agent, relating to the $200,000,000 in principal amount of the 5.75% Senior Notes due 2018.
4.33	Fiscal Agency Agreement, dated as of May 24, 1999, by and between Northern Natural Gas Company and Chase Bank of Texas, National Association, Fiscal Agent, relating to the $250,000,000 in principal amount of the 7.00% Senior Notes due 2011 (incorporated by reference to Exhibit 10.70 to the MidAmerican Energy Holdings Company Quarterly Report on Form 10-Q for the quarter ended March 31, 2004).

  160

Exhibit No. Description

4.34	Trust Indenture, dated as of September 10, 1999, by and between Cordova Funding Corporation and Chase Manhattan Bank and Trust Company, National Association, Trustee, relating to the $225,000,000 in principal amount of the 8.75% Senior Secured Bonds due 2019 (incorporated by reference to Exhibit 10.71 to the MidAmerican Energy Holdings Company Quarterly Report on Form 10-Q for the quarter ended March 31, 2004).
4.35	Trust Deed, dated as of February 4, 1998 among Yorkshire Power Finance Limited, Yorkshire Power Group Limited and Bankers Trustee Company Limited, Trustee, relating to the £200,000,000 in principal amount of the 7.25% Guaranteed Bonds due 2028 (incorporated by reference to Exhibit 10.74 to the MidAmerican Energy Holdings Company Quarterly Report on Form 10-Q for the quarter ended March 31, 2004).
4.36	First Supplemental Trust Deed, dated as of October 1, 2001, among Yorkshire Power Finance Limited, Yorkshire Power Group Limited and Bankers Trustee Company Limited, Trustee, relating to the £200,000,000 in principal amount of the 7.25% Guaranteed Bonds due 2028 (incorporated by reference to Exhibit 10.75 to the MidAmerican Energy Holdings Company Quarterly Report on Form 10-Q for the quarter ended March 31, 2004).
4.37	Third Supplemental Trust Deed, dated as of October 1, 2001, among Yorkshire Electricity Distribution plc, Yorkshire Electricity Group plc and Bankers Trustee Company Limited, Trustee, relating to the £200,000,000 in principal amount of the 9.25% Bonds due 2020 (incorporated by reference to Exhibit 10.76 to the MidAmerican Energy Holdings Company Quarterly Report on Form 10-Q for the quarter ended March 31, 2004).
4.38	Indenture, dated as of February 1, 2000, among Yorkshire Power Finance 2 Limited, Yorkshire Power Group Limited and The Bank of New York, Trustee (incorporated by reference to Exhibit 10.78 to the MidAmerican Energy Holdings Company Quarterly Report on Form 10-Q for the quarter ended March 31, 2004).
4.39	First Supplemental Trust Deed, dated as of September 27, 2001, among Northern Electric Finance plc, Northern Electric plc, Northern Electric Distribution Limited and The Law Debenture Trust Corporation p.l.c., Trustee, relating to the £100,000,000 in principal amount of the 8.875% Guaranteed Bonds due 2020 (incorporated by reference to Exhibit 10.81 to the MidAmerican Energy Holdings Company Quarterly Report on Form 10-Q for the quarter ended March 31, 2004).
4.40	Trust Deed, dated as of January 17, 1995, by and between Yorkshire Electricity Group plc and Bankers Trustee Company Limited, Trustee, relating to the £200,000,000 in principal amount of the 9 1/4% Bonds due 2020 (incorporated by reference to Exhibit 10.83 to the MidAmerican Energy Holdings Company Quarterly Report on Form 10-Q for the quarter ended March 31, 2004).
4.41	Master Trust Deed, dated as of October 16, 1995, by and between Northern Electric Finance plc, Northern Electric plc and The Law Debenture Trust Corporation p.l.c., Trustee, relating to the £100,000,000 in principal amount of the 8.875% Guaranteed Bonds due 2020 (incorporated by reference to Exhibit 10.70 to the MidAmerican Energy Holdings Company Annual Report on Form 10-K for the year ended December 31, 2004).
4.42	Fiscal Agency Agreement, dated April 14, 2005, by and between Northern Natural Gas Company and J.P. Morgan Trust Company, National Association, Fiscal Agent, relating to the $100,000,000 in principal amount of the 5.125% Senior Notes due 2015 (incorporated by reference to Exhibit 99.1 to the MidAmerican Energy Holdings Company Current Report on Form 8-K dated April 18, 2005).
4.43	£100,000,000 Facility Agreement, dated April 4, 2005 among CE Electric UK Funding Company, the subsidiaries of CE Electric UK Funding Company listed in Part 1 of Schedule 1, Lloyds TSB Bank plc and The Royal Bank of Scotland plc (incorporated by reference to Exhibit 99.1 to the MidAmerican Energy Holdings Company Current Report on Form 8-K dated April 20, 2005).

 161

Exhibit No. Description

4.44	Trust Deed dated May 5, 2005 among Northern Electric Finance plc, Northern Electric Distribution Limited, Ambac Assurance UK Limited and HSBC Trustee (C.I.) Limited (incorporated by reference to Exhibit 99.1 to the MidAmerican Energy Holdings Company Quarterly Report on Form 10-Q for the quarter ended March 31, 2005).
4.45	Reimbursement and Indemnity Agreement dated May 5, 2005 among Northern Electric Finance plc, Northern Electric Distribution Limited and Ambac Assurance UK Limited (incorporated by reference to Exhibit 99.2 to the MidAmerican Energy Holdings Company Quarterly Report on Form 10-Q for the quarter ended March 31, 2005).
4.46	Trust Deed, dated May 5, 2005 among Yorkshire Electricity Distribution plc, Ambac Assurance UK Limited and HSBC Trustee (C.I.) Limited (incorporated by reference to Exhibit 99.3 to the MidAmerican Energy Holdings Company Quarterly Report on Form 10-Q for the quarter ended March 31, 2005).
4.47	Reimbursement and Indemnity Agreement, dated May 5, 2005 between Yorkshire Electricity Distribution plc and Ambac Assurance UK Limited (incorporated by reference to Exhibit 99.4 to the MidAmerican Energy Holdings Company Quarterly Report on Form 10-Q for the quarter ended March 31, 2005).
4.48	Supplemental Trust Deed, dated May 5, 2005 among CE Electric UK Funding Company, Ambac Assurance UK Limited and The Law Debenture Trust Corporation plc (incorporated by reference to Exhibit 99.5 to the MidAmerican Energy Holdings Company Quarterly Report on Form 10-Q for the quarter ended March 31, 2005).
4.49	Second Supplemental Agreement to Insurance and Indemnity Agreement, dated May 5, 2005 by and between CE Electric UK Funding Company and Ambac Assurance UK Limited (incorporated by reference to Exhibit 99.6 to the MidAmerican Energy Holdings Company Quarterly Report on Form 10-Q for the quarter ended March 31, 2005).
4.50	Amended and Restated Credit Agreement, dated as of July 6, 2006, among MidAmerican Energy Company, the Lending Institutions Party Hereto, as Banks, Union Bank of California, N.A., as Syndication Agent, JPMorgan Chase Bank, N.A.., as Administrative Agent, and The Royal Bank of Scotland plc, ABN AMRO Bank N.V. and BNP Paribas as Co-Documentation Agents (incorporated by reference to Exhibit 10.1 to the MidAmerican Energy Company Quarterly Report on Form 10-Q for the quarter ended June 30, 2006).
4.51	Shareholders Agreement, dated as of March 14, 2000 (incorporated by reference to Exhibit 4.19 to the MidAmerican Energy Holdings Company Registration Statement No. 333-101699 dated December 6, 2002).
4.52	Amendment No. 1 to Shareholders Agreement, dated December 7, 2005 (incorporated by reference to Exhibit 4.17 to the MidAmerican Energy Holdings Company Annual Report on Form 10-K for the year ended December 31, 2005).
4.53	Equity Commitment Agreement, dated as of March 1, 2006, by and between Berkshire Hathaway Inc. and MidAmerican Energy Holdings Company (incorporated by reference to Exhibit 10.72 to the MidAmerican Energy Holdings Company Annual Report on Form 10-K for the year ended December 31, 2005).
4.54	Fiscal Agency Agreement, dated February 12, 2007, by and between Northern Natural Gas Company and Bank of New York Trust Company, N.A., Fiscal Agent, relating to the $150,000,000 in principal amount of the 5.80% Senior Bonds due 2037 (incorporated by reference to Exhibit 99.1 to the MidAmerican Energy Holdings Company Current Report on Form 8-K dated February 12, 2007).

4.55 Indenture, dated as of October 1, 2006, by and between MidAmerican Energy Company and the Bank of New York Trust Company, N.A., Trustee (incorporated by reference to Exhibit 4.1 to the MidAmerican Energy Company Quarterly Report on Form 10-Q for the quarter ended September 30, 2006).

162 

Exhibit No. Description

4.56	First Supplemental Indenture, dated as of October 6, 2006, by and between MidAmerican Energy Company and the Bank of New York Trust Company, N.A., Trustee (incorporated by reference to Exhibit 4.2 to the MidAmerican Energy Company Quarterly Report on Form 10-Q for the quarter ended September 30, 2006).
4.57	Second Supplemental Indenture, dated June 29, 2007, by and between MidAmerican Energy Company and The Bank of New York Trust Company, N.A., Trustee (incorporated by reference to Exhibit 4.1 to the MidAmerican Energy Company Current Report on Form 8-K dated June 29, 2007).
4.58	Third Supplemental Indenture, dated March 25, 2008, by and between MidAmerican Energy Company and The Bank of New York Trust Company, Trustee, relating to the 5.3% Notes due 2018 (incorporated by reference to Exhibit 4.1 to MidAmerican Energy Company Current Report on Form 8-K dated March 25, 2008).
4.59	Mortgage and Deed of Trust dated as of January 9, 1989, between PacifiCorp and The Bank of New York Mellon Trust Company, N.A. (formerly known as JP Morgan Chase Bank and The Chase Manhattan Bank), Trustee, incorporated by reference to Exhibit 4-E to PacifiCorp’s Form 8-B, File No. 1-5152, as supplemented and modified by 23 Supplemental Indentures, each incorporated by reference, as follows:

Exhibit Number	PacifiCorp File Type	File Date	File Number
(4)(b)	SE	November 2, 1989	33-31861
(4)(a)	8-K	January 9, 1990	1-5152
(4)(a)	8-K	September 11, 1991	1-5152
4(a)	8-K	January 7, 1992	1-5152
4(a)	10-Q	Quarter ended March 31, 1992	1-5152
4(a)	10-Q	Quarter ended September 30, 1992	1-5152
4(a)	8-K	April 1, 1993	1-5152
4(a)	10-Q	Quarter ended September 30, 1993	1-5152
(4)b	10-Q	Quarter ended June 30, 1994	1-5152
(4)b	10-K	Year ended December 31, 1994	1-5152
(4)b	10-K	Year ended December 31, 1995	1-5152
(4)b	10-K	Year ended December 31, 1996	1-5152
(4)b	10-K	Year ended December 31, 1998	1-5152
99(a)	8-K	November 21, 2001	1-5152
4.1	10-Q	Quarter ended June 30, 2003	1-5152
99	8-K	September 8, 2003	1-5152
4	8-K	August 24, 2004	1-5152
4	8-K	June 13, 2005	1-5152
4.2	8-K	August 14, 2006	1-5152
4	8-K	March 14, 2007	1-5152
4.1	8-K	October 3, 2007	1-5152
4.1	8-K	July 17, 2008	1-5152
4.1	8-K	January 8, 2009	1-5152

4.60	$700,000,000 Credit Agreement dated as of October 23, 2007 among PacifiCorp, The Banks Party thereto, The Royal Bank of Scotland plc, as Syndication Agent, and Union Bank of California, N.A., as Administrative Agent (incorporated by reference to Exhibit 99 to the PacifiCorp Quarterly Report on Form 10-Q for the quarter ended September 30, 2007).
4.61	$800,000,000 Amended and Restated Credit Agreement dated as of July 6, 2006 among PacifiCorp, The Banks Party thereto, The Royal Bank of Scotland plc, as Syndication Agent, and JP Morgan Chase Bank, N.A., as Administrative Agent (incorporated by Reference to Exhibit 99 to the PacifiCorp Quarterly Report on Form 10-Q for the quarter ended June 30, 2006).

163 

Exhibit No. Description

10.1	Amended and Restated Employment Agreement, dated February 25, 2008, by and between MidAmerican Energy Holdings Company and David L. Sokol (incorporated by reference to Exhibit 10.1 to the MidAmerican Energy Holdings Company Annual Report on Form 10-K for the year ended December 31, 2007).
10.2	Non-Qualified Stock Option Agreements of David L. Sokol, dated March 14, 2000 (incorporated by reference to Exhibit 10.3 to the MidAmerican Energy Holdings Company Registration Statement No. 333-101699 dated December 6, 2002) and the related 2000 Stock Option Plan attached as Exhibit A thereto (incorporated by reference to Exhibit 10.3 of MidAmerican Energy Holdings Company’s Registration Statement No. 333-143286 dated May 25, 2007).
10.3	Incremental Profit Sharing Plan, dated February 16, 2009, by and between MidAmerican Energy Holdings Company and David L. Sokol.
10.4	Amended and Restated Employment Agreement, dated February 25, 2008, by and between MidAmerican Energy Holdings Company and Gregory E. Abel (incorporated by reference to Exhibit 10.3 to the MidAmerican Energy Holdings Company Annual Report on Form 10-K for the year ended December 31, 2007).
10.5	Non-Qualified Stock Option Agreements of Gregory E. Abel, dated March 14, 2000 (incorporated by reference to Exhibit 10.5 to the MidAmerican Energy Holdings Company Registration Statement No. 333-101699 dated December 6, 2002) and the related 2000 Stock Option Plan attached as Exhibit A thereto (incorporated by reference to Exhibit 10.5 of MidAmerican Energy Holdings Company’s Registration Statement No. 333-143286 dated May 25, 2007).
10.6	Incremental Profit Sharing Plan, dated February 10, 2009, by and between MidAmerican Energy Holdings Company and Gregory E. Abel.
10.7	Amended and Restated Employment Agreement, dated February 25, 2008, by and between MidAmerican Energy Holdings Company and Patrick J. Goodman (incorporated by reference to Exhibit 10.5 to the MidAmerican Energy Holdings Company Annual Report on Form 10-K for the year ended December 31, 2007).
10.8	Amended and Restated Casecnan Project Agreement, dated June 26, 1995, between the National Irrigation Administration and CE Casecnan Water and Energy Company Inc. (incorporated by reference to Exhibit 10.1 to the CE Casecnan Water and Energy Company, Inc. Registration Statement on Form S-4 dated January 25, 1996).
10.9	Supplemental Agreement, dated as of September 29, 2003, by and between CE Casecnan Water and Energy Company, Inc. and the Philippines National Irrigation Administration (incorporated by reference to Exhibit 98.1 to the MidAmerican Energy Holdings Company Current Report on Form 8-K dated October 15, 2003).
10.10	CalEnergy Company, Inc. Voluntary Deferred Compensation Plan, effective December 1, 1997, First Amendment, dated as of August 17, 1999, and Second Amendment effective March 14, 2000 (incorporated by reference to Exhibit 10.50 to the MidAmerican Energy Holdings Company Registration Statement No. 333-101699 dated December 6, 2002).
10.11	MidAmerican Energy Holdings Company Executive Voluntary Deferred Compensation Plan restated effective as of January 1, 2007 (incorporated by reference to Exhibit 10.9 to the MidAmerican Energy Holdings Company Annual Report on Form 10-K for the year ended December 31, 2007).

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Exhibit No.	Description
10.12	MidAmerican Energy Company First Amended and Restated Supplemental Retirement Plan for Designated Officers dated as of May 10, 1999 amended on February 25, 2008 to be effective as of January 1, 2005 (incorporated by reference to Exhibit 10.10 to the MidAmerican Energy Holdings Company Annual Report on Form 10-K for the year ended December 31, 2007).
10.13	MidAmerican Energy Holdings Company Long-Term Incentive Partnership Plan as Amended and Restated January 1, 2007 (incorporated by reference to Exhibit 10.11 to the MidAmerican Energy Holdings Company Annual Report on Form 10-K for the year ended December 31, 2007).
10.14	Summary of Key Terms of Compensation Arrangements with MidAmerican Energy Holdings Company Named Executive Officers and Directors.
10.15	Termination Agreement, dated December 17, 2008, by and among MidAmerican Energy Holdings Company, MEHC Investment, Inc., MEHC Merger Sub, Inc., Constellation Energy Group, Inc., CER Generation II, LLC, Constellation Power Source Generation, Inc. and Electricité De France International, SA (incorporated by reference to Exhibit 2.1 to the MidAmerican Energy Holdings Company Current Report on Form 8-K dated December 17, 1008).
14.1	MidAmerican Energy Holdings Company Code of Ethics for Chief Executive Officer, Chief Financial Officer and Other Covered Officers (incorporated by reference to Exhibit 14.1 to the MidAmerican Energy Holdings Company Annual Report on Form 10-K for the year ended December 31, 2003).
21.1	Subsidiaries of the Registrant.
23.1	Consent of Deloitte & Touche LLP.
24.1	Power of Attorney.
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.

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