MIDAMERICAN ENERGY HOLDINGS CO /NEW/ (Form: 10-K, Received: 02/29/2008 16:30:16)

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, 2007

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

For the transition period from ______ to _______

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

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

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

Securities registered pursuant to Section 12(b) of the Act: N/A
Securities registered pursuant to Section 12(g) of the Act: N/A

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

Yes  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  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 

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 definitions of “large accelerated filer,” “accelerated filer,” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer 

Accelerated filer 

Non-accelerated filer T

Smaller reporting company 

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

All of the shares of common equity of MidAmerican Energy Holdings Company are privately held by a limited group of investors. As of January 31, 2008, 74,859,001 shares of common stock were outstanding.

TABLE OF CONTENTS

	PART I

Item 1.	Business	4
Item 1A.	Risk Factors	40
Item 1B.	Unresolved Staff Comments	52
Item 2.	Properties	53
Item 3.	Legal Proceedings	54
Item 4.	Submission of Matters to a Vote of Security Holders	57

	PART II

Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	58
Item 6.	Selected Financial Data	59
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	60
Item 7A.	Quantitative and Qualitative Disclosures	76
Item 8.	Financial Statements and Supplementary Data	79
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	129
Item 9A(T).	Controls and Procedures	129
Item 9B.	Other Information	129

	PART III

Item 10.	Directors, Executive Officers and Corporate Governance	130
Item 11.	Executive Compensation	131
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	145
Item 13.	Certain Relationships and Related Transactions, and Director Independence	147
Item 14.	Principal Accountant Fees and Services	148

	PART IV
Item 15.	Exhibits and Financial Statement Schedules	149
Signatures		154
Exhibit Index		156

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 are located;

·	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 and/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;

·	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 energy costs;

·	financial condition and creditworthiness of significant customers and suppliers;

·	changes in business strategy or development plans;

·	availability, terms and deployment of capital;

·	performance of generation facilities, including unscheduled outages or repairs;

·	risks relating to nuclear generation;

·	the impact of derivative instruments used to mitigate or manage volume and price risk and interest rate risk 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, changes in interest rates, mortality, morbidity and investment performance on pension and other postretirement benefits expense, as well as the impact of changes in legislation on funding requirements;

·	changes in MidAmerican Energy Holdings Company’s (“MEHC”) and its subsidiaries’ credit ratings;

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

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

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

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

·	other business or investment considerations that may be disclosed from time to time in filings with the United States Securities and Exchange Commission (“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.

PART I

Item 1. Business

General

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 (a) paying when due MEHC’s debt obligations and (b) funding the general corporate purposes and capital requirements of MEHC’s regulated subsidiaries. Berkshire Hathaway will have up to 180 days to fund any such request in minimum 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 will expire 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 consists of Northern Electric Distribution Limited (“Northern Electric”) and Yorkshire Electricity Distribution plc (“Yorkshire Electricity”)), CalEnergy Generation-Foreign (owning a majority interest in the Casecnan project in the Philippines), CalEnergy Generation-Domestic (owning 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 included in Item 8 of this Form 10-K for additional segment information regarding the Company’s platforms. 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.

MEHC’s energy subsidiaries generate, transmit, store, distribute and supply energy. Approximately 91% of the Company’s operating income in 2007 was generated from rate-regulated businesses. As of December 31, 2007, MEHC’s electric and natural gas utility subsidiaries served approximately 6.2 million electricity customers and end users and approximately 0.7 million natural gas customers. MEHC’s natural gas pipeline subsidiaries operate interstate natural gas transmission systems that transported approximately 8% of the total natural gas consumed in the United States in 2007. These pipeline subsidiaries have approximately 17,000 miles of pipeline in operation and a design capacity of 6.9 billion cubic feet of natural gas per day. As of December 31, 2007, the Company had interests in approximately 17,000 net owned megawatts (“MW”) of power generation facilities in operation and under construction, including approximately 16,000 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 and/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, at which time it changed its name from CalEnergy Company, Inc. to MidAmerican Energy Holdings Company.

In this annual report, references to “U.S. dollars,” “dollars,” “$” or “cents” are to the currency of the United States, references to “pounds sterling,” “£,” “sterling,” “pence” or “p” are to the currency of Great Britain and references to “pesos” are to the currency of the Philippines. References to kW means kilowatts, MW means megawatts, GW means gigawatts, kWh means kilowatt hours, MWh means megawatt hours, GWh means gigawatt hours, kV means kilovolts, MMcf means million cubic feet, Bcf means billion cubic feet, Tcf means trillion cubic feet and Dth means decatherms or one million British thermal units.

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, which includes 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 Item 7 of this Form 10-K.

General

PacifiCorp serves approximately 1.7 million regulated retail electric customers in its service territories in portions of the states 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 state and local authorities. The average term of these franchise agreements is approximately 30 years, although their terms range from five years to indefinite.

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.

Electric Operations

Customers

The percentages of electricity sold (measured in MWh) to retail and wholesale customers, by class of customer, and the average number of retail customers (in millions) were as follows:

		Nine-Month
	Year Ended	Period Ended	Year Ended
	December 31,	December 31,	March 31,
	2007	2006	2006

Residential	24%	22%	23%
Commercial	24	24	24
Industrial	31	32	31
Wholesale	20	21	21
Other	1	1	1
	100 %	100 %	100 %

Total average retail customers	1.7	1.7	1.6

The percentages of retail electric operating revenue, by jurisdiction, were as follows:

		Nine-Month
	Year Ended	Period Ended	Year Ended
	December 31,	December 31,	March 31,
	2007	2006	2006

Utah	43%	42%	41%
Oregon	29	29	29
Wyoming	13	13	13
Washington	7	8	9
Idaho	6	6	6
California	2	2	2
	100 %	100 %	100 %

Customer demand is typically highest in the summer across PacifiCorp’s service territory when air-conditioning and irrigation systems are heavily used. Customer demand also peaks in the winter months in the western portion of PacifiCorp’s service territory primarily due to heating requirements and in the eastern portion due to other electricity demands.

For residential customers, within a given year, weather conditions are the dominant cause of usage variations from normal seasonal patterns. Strong Utah residential growth over the last several years and increasing installations of central air conditioning systems have contributed to increased summer peak load growth. During the year ended December 31, 2007, PacifiCorp’s peak load was 9,775 MW in the summer and 8,650 MW in the winter. During the year ended December 31, 2007, PacifiCorp’s average load was 7,185 MW for the summer and 7,028 MW for the winter.

Power and Fuel Supply

The estimated percentages of PacifiCorp’s total energy requirements supplied by its generation facilities and through long- and short-term contracts or spot market purchases were as follows:

		Nine-Month
	Year Ended	Period Ended	Year Ended
	December 31,	December 31,	March 31,
	2007	2006	2006

Coal	64%	62%	68%
Natural gas	11	7	4
Hydroelectric	5	6	6
Other	1	1	-
Total energy generated	81	76	78
Energy purchased-long-term contracts	5	7	9
Energy purchased-short-term contracts and other	14	17	13
	100 %	100 %	100 %

The percentage of PacifiCorp’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 coal and natural gas, precipitation and snowpack levels, other weather-related impacts, environmental considerations and the market price of 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.

Mines owned or leased by PacifiCorp supplied 31% of PacifiCorp’s total coal requirements during the year ended December 31, 2007 and the nine-month period ended December 31, 2006, compared to 32% during the year ended March 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. In an effort to lower costs and obtain better quality coal, the Jim Bridger mine developed an underground mine to access 57 million tons of PacifiCorp’s coal reserves. Sustained operations at the underground mine commenced in March 2007 and production continues at its surface operations. The life of the underground mine is expected to be approximately 15 years.

Recoverable coal reserves as of December 31, 2007, 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	45	(2)
Rock Springs, WY	Jim Bridger	Surface/Underground	140	(3)
			232

(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 amount included above represents only PacifiCorp’s two-thirds interest in the coal reserves.

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 plants, together with coal available under both long- and short-term contracts with external suppliers to supply its remaining plants, will be substantially sufficient to provide these plants 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 plants. 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.

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. Several of PacifiCorp’s long-term operating licenses have expired and they are operating under temporary annual licenses issued by the FERC until new long-term operating licenses are issued. The amount of electricity PacifiCorp is able to generate from its hydroelectric plants depends on a number of factors, including snowpack in the mountains upstream of its hydroelectric plants, reservoir storage, precipitation in its watersheds, plant 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 hydroelectric plants. When these factors are unfavorable, PacifiCorp must increase its reliance on more expensive thermal plants and purchased electricity.

PacifiCorp is pursuing renewable resources as a viable, economic and environmentally prudent means of generating electricity. 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, which are important to integrating intermittent wind resources into the electric system.

In addition to its portfolio of generating plants, PacifiCorp purchases electricity in the wholesale markets to meet its retail load and long-term wholesale obligations, for system balancing requirements and to enhance the efficient use of its generating capacity over the long-term. PacifiCorp enters into wholesale purchase and sale transactions to balance its electricity supply when generation and retail loads are higher or lower than expected. Generation can vary with the levels of outages, hydroelectric and wind 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 plants. 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.

PacifiCorp’s wholesale transactions are integral to its retail business, providing for a balanced and economically hedged position and enhancing the efficient use of its generating capacity over the long term. 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 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.

The following table sets out certain information concerning PacifiCorp’s power generating facilities as of December 31, 2007:

				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
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
Hunter No. 1	Castle Dale, UT	Coal	1978		430		403
Hunter No. 2	Castle Dale, UT	Coal	1980		430		259
Hunter No. 3	Castle Dale, UT	Coal	1983		460		460
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 No. 1	Hayden, CO	Coal	1965-1976		184		45
Hayden No. 2	Hayden, CO	Coal	1965-1976		262		33
					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
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
					1,931		1,694
HYDROELECTRIC:
Swift No. 1	Cougar, WA	Lewis River	1958		264		264
Merwin	Ariel, WA	Lewis River	1931-1958		151		151
Yale	Amboy, WA	Lewis River	1953		163		163
Five North Umpqua Plants	Toketee Falls, OR	N. Umpqua River	1950-1956		141		141
John C. Boyle	Keno, OR	Klamath River	1958		83		83
Copco Nos. 1 and 2	Hornbrook, CA	Klamath River	1918-1925		62		62
Clearwater Nos. 1 and 2	Toketee Falls, OR	Clearwater River	1953		49		49
Grace	Grace, ID	Bear River	1908-1923		33		33
Prospect No. 2	Prospect OR	Rogue River	1928		36		36
Cutler	Collingston, UT	Bear River	1927		29		29
Oneida	Preston, ID	Bear River	1915-1920		28		28
Iron Gate	Hornbrook, CA	Klamath River	1962		19		19
Soda	Soda Springs, ID	Bear River	1924		14		14
28 minor hydroelectric plants	Various	Various	1895-1990		86		86
					1,158		1,158
WIND:
Foote Creek	Arlington, WY	Wind	1997		41		33
Leaning Juniper 1	Arlington, OR	Wind	2006		101		101
Marengo	Dayton, WA	Wind	2007		140		140
					282		274
OTHER:
Camas Co-Gen	Camas, WA	Black liquor	1996		22		22
Blundell	Milford, UT	Geothermal	1984, 2007		34		34
					56		56

Total Available Generating Capacity					12,893		9,286

PROJECTS UNDER CONSTRUCTION/DEVELOPMENT (2) :
Various wind projects	Various	Wind	2008		461		461
					13,354		9,747

(1)

Facility Net Capacity (MW) represents 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 each represent the estimated nameplate ratings. A generator’s nameplate rating is its full-load capacity under normal operating conditions as defined by the manufacturer. The estimated installation date for the projects is by the end of 2008.

Future Generation

As required by certain state regulations, PacifiCorp uses an Integrated Resource Plan (“IRP”) to develop a long-term view of prudent future actions required to help ensure that PacifiCorp continues to provide reliable and cost-effective electric service to its customers. The IRP process identifies the amount and timing of PacifiCorp’s expected future resource needs and an associated optimal future resource mix that accounts for planning uncertainty, risks, reliability impacts and other factors. The IRP is a coordinated effort with stakeholders in each of the six states where PacifiCorp operates. When the IRP is filed, each state commission with IRP adequacy rules judges whether the IRP reasonably meets its standards and guidelines. PacifiCorp requests “acknowledgement” of its IRP filing from the Utah Public Service Commission (“UPSC”), the Oregon Public Utility Commission (“OPUC”), Idaho Public Utility Commission (“IPUC”) and the Washington Utilities and Transportation Commission (“WUTC”) pursuant to those states’ IRP adequacy rules. The IRP can be used as evidence by parties in rate-making or other regulatory proceedings. PacifiCorp files its IRP on a biennial basis. Additionally, PacifiCorp is required to file draft requests for proposals with the UPSC, the OPUC and the WUTC prior to issuance to the market.

In May 2007, PacifiCorp released its 2007 IRP. The 2007 IRP identified a need for approximately 3,171 MW of additional resources by summer 2016 to satisfy the difference between projected retail load obligations and available resources. PacifiCorp plans to meet this need through demand response and energy efficiency programs; the construction or purchase of additional generation, including cost-effective renewable energy, combined heat and power, and thermal generation; and wholesale electricity transactions to make up for the remaining difference between retail load obligations and available resources. PacifiCorp is currently seeking acknowledgement of its 2007 IRP from state regulators and expects the acknowledgement process to be complete in 2008.

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 growth in peak load and energy consumption. Current programs offer customers services such as energy engineering and audits, as well as rebates for high efficiency equipment such as lighting, heating and cooling equipment, weatherization, motors and process equipment and systems; new construction; and load management (curtailment) programs for large commercial and industrial customers and residential customers whose central air conditioners are controlled during summer peak load periods. Subject to random prudence reviews, state regulations allow for contemporaneous recovery of costs incurred for demand-side management programs and services through the energy efficiency service charges to all retail electric customers. In 2007, $53 million was expended on the demand-side management programs in PacifiCorp’s six-state service area, resulting in an estimated 300,000 MWh of first year energy savings and 170 MW of peak load management.

Transmission and Distribution

PacifiCorp operates one balancing authority area in the western portion of its service territory, and one balancing authority area in the eastern portion of its service territory. A balancing authority area is 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 over its transmission system in accordance with FERC requirements.

PacifiCorp’s transmission system is part of the Western Interconnection, the regional grid in the West. The Western Interconnection 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.

PacifiCorp’s wholesale transmission services are regulated by the FERC under cost-based regulation subject to PacifiCorp’s Open Access Transmission Tariff (“OATT”). In accordance with the OATT, PacifiCorp offers several transmission services to wholesale customers:

·	Network transmission service (guaranteed service that integrates generating resources to serve retail loads);

·	Long- and short-term firm point-to-point transmission service (guaranteed service with fixed delivery and receipt points); and

·	Non-firm point-to-point service (“as available” service with fixed delivery and receipt points).

These services are offered on a non-discriminatory basis, which means that all potential customers are provided an equal opportunity to access the transmission system. PacifiCorp’s transmission business is managed and operated independently from the generating and marketing business in accordance with the FERC Standards of Conduct. Transmission costs are not separated from, but rather are “bundled” with, generation and distribution costs in retail rates approved by state regulatory commissions.

The electric transmission system of PacifiCorp as of December 31, 2007 included approximately 15,700 miles of transmission lines. As of December 31, 2007, PacifiCorp owned approximately 900 substations.

In May 2007, PacifiCorp announced plans to build in excess of 1,200 miles of new high-voltage transmission lines primarily in Wyoming, Utah, Idaho, Oregon and the desert Southwest. The estimated $4.1 billion investment plan includes projects that will address customers’ increasing electric energy use, improve system reliability and deliver wind and other renewable generation resources to more customers throughout PacifiCorp’s six-state service area and the Western United States. These transmission lines are expected to be placed into service beginning 2010 and continuing through 2014. PacifiCorp is also collaborating with other utilities to address transmission needs, including new development and system reliability.

MidAmerican Energy

General

MidAmerican Energy, an indirect wholly owned subsidiary of MEHC, is a public utility company headquartered in Iowa, which serves approximately 0.7 million regulated retail electric customers and approximately 0.7 million regulated retail and transportation natural gas customers. 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 distributes electricity at retail in Council Bluffs, Des Moines, Fort Dodge, Iowa City, Sioux City and Waterloo, Iowa; the Quad Cities (Davenport and Bettendorf, Iowa and Rock Island, Moline and East Moline, Illinois); and a number of adjacent communities and areas. It also distributes natural gas at retail in Cedar Rapids, Des Moines, Fort Dodge, Iowa City, Sioux City and Waterloo, Iowa; the Quad Cities; Sioux Falls, South Dakota; and a number of adjacent communities and areas. Additionally, MidAmerican Energy transports natural gas through its distribution system for a number of end-use customers who have independently secured their supply of natural gas. In addition to retail sales and natural gas transportation, MidAmerican Energy sells 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 franchise agreements, certificates, permits and licenses obtained from state and local authorities. The franchise agreements, with various expiration dates, are typically for 25-year terms.

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.

MidAmerican Energy also conducts a number of nonregulated business activities in addition to its 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, but also in Michigan and Maryland. 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 increased their purchases of energy on the open market due to the expiration of contracts associated with electric industry restructuring in Illinois. 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. 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:

	2007	2006	2005

Regulated electric	45%	52%	48%
Regulated gas	28	32	42
Nonregulated	27	16	10
	100 %	100 %	100 %

Electric Operations

Customers

The percentages of electricity sold (measured in MWh) to retail and wholesale customers, by class of customer, and the average number of retail customers (in millions) as of and for the years ended December 31 were as follows:

	2007	2006	2005

Residential	18%	18%	21%
Commercial	12	13	15
Industrial	27	28	28
Wholesale	38	36	31
Other	5	5	5
	100 %	100 %	100 %

Total average retail customers	0.7	0.7	0.7

The percentages of electricity sold (measured in MWh), by jurisdiction, for the years ended December 31 were as follows:

	2007	2006	2005

Iowa	90%	90%	89%
Illinois	9	9	10
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. In general, 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 new record hourly peak demand of 4,240 MW on MidAmerican Energy’s electric system, an increase of 104 MW from the previous record set in 2006.

Power and Fuel Supply

The estimated percentages of MidAmerican Energy’s total energy requirements supplied by its generation plants and through long- and short-term contracts or spot market purchases for the years ended December 31 were as follows:

	2007	2006	2005

Coal	56%	55%	63%
Nuclear	10	11	12
Natural gas	3	3	2
Other	5	3	2
Total energy generated	74	72	79
Energy purchased-long-term contracts	7	7	8
Energy purchased-short-term contracts and spot market	19	21	13
	100 %	100 %	100 %

The share of MidAmerican Energy’s energy requirements generated by its plants 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.

MidAmerican Energy is exposed to fluctuations in energy costs relating to retail sales in Iowa and, effective January 1, 2007, in Illinois as it does not have fuel adjustment clauses 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 2008 requirements under fixed-price contracts. MidAmerican Energy regularly monitors the western coal market looking 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 2015; uranium conversion requirements through 2010 and partial requirements through 2011; enrichment requirements through 2010 and partial requirements through 2017; and fuel fabrication requirements through 2015. MidAmerican Energy has been advised by Exelon Generation that it does not anticipate that it will have difficulty in contracting for uranium, uranium conversion, enrichment or fabrication of nuclear fuel needed to operate Quad Cities Station during this time.

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 manages a portion of its natural gas supply 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.

MidAmerican Energy is pursuing renewable resources as a viable, economic and environmentally prudent means of generating electricity. 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, which are important to integrating intermittent wind resources into the electric system.

The following table sets out certain information concerning MidAmerican Energy’s power generating facilities as of December 31, 2007:

				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		700		616
Ottumwa	Ottumwa, IA	Coal	1981		672		349
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		790		471
					4,703		3,306
NATURAL GAS:
Greater Des Moines	Pleasant Hill, IA	Natural gas	2003-2004		497		497
Coralville	Coralville, IA	Natural gas	1970		64		64
Electrifarm	Waterloo, IA	Natural gas/Oil	1975-1978		199		199
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		161		161
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
					1,339		1,339
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:
Century	Blairsburg, IA	Wind	2005/2007		189		189
Intrepid	Schaller, IA	Wind	2004-2005		176		176
Pomeroy	Pomeroy, IA	Wind	2007		197		197
Victory	Westside, IA	Wind	2006		99		99
					661		661
OTHER:
Moline Unit Nos. 1-4	Moline, IL	Mississippi River	1941		3		3

Total Available Generating Capacity					8,446		5,744

PROJECTS UNDER CONSTRUCTION/DEVELOPMENT (2) :
Various wind projects	Various	Wind	2008		462		462
					8,908		6,206

(1)

Facility Net Capacity (MW) represents total plant accredited net generating capacity from the summer 2007 based on MidAmerican Energy’s accreditation approved by the Mid-Continent Area Power Pool (“MAPP”), except for wind-powered generation facilities, which are nameplate ratings. The 2007 summer accreditation of the wind-powered generation facilities in service at that time totaled 67 MW and is considerably less than the nameplate ratings due to the varying nature of wind. Additionally, the Pomeroy wind-powered generation facility and 15 MW of the Century wind-powered generation facility were placed in service in the fourth quarter of 2007, which was after the 2007 summer accreditation. Net MW Owned indicates MidAmerican Energy’s ownership of Facility Net Capacity.


(2)	Facility Net Capacity (MW) and Net MW Owned represent the estimated nameplate ratings (MW) for wind-powered generation projects under construction.

Future Generation

On April 18, 2006, the Iowa Utilities Board (“IUB”) approved a settlement agreement between MidAmerican Energy and the Iowa Office of Consumer Advocate (“OCA”) regarding ratemaking principles for additional wind-powered generation capacity in Iowa to be installed in 2006 and 2007. A total of 222 MW (nameplate ratings) of wind-powered generation was placed in service in 2006 and 2007 subject to that agreement, including 123 MW (nameplate ratings) in the fourth quarter of 2007. On July 27, 2007, the IUB approved a settlement agreement between MidAmerican Energy and the OCA in conjunction with MidAmerican Energy’s ratemaking principles application for up to 540 MW (nameplate ratings) of additional wind-powered capacity in Iowa to be placed in service on or before December 31, 2013. MidAmerican Energy placed 78 MW (nameplate ratings) of wind-powered generation into service in the fourth quarter of 2007 subject to the 2007 settlement agreement. Currently, MidAmerican Energy has 462 MW (nameplate ratings) under development or construction that it expects will be placed in service by December 31, 2008. MidAmerican Energy continues to pursue additional cost effective wind-powered generation.

Demand-side Management

MidAmerican Energy has provided a comprehensive set of demand-side management programs to its Iowa electric and gas customers since 1990. The programs are designed to reduce growth in peak load and energy consumption. Current Iowa programs offer customers incentives for energy audits and weatherization; rebates or below market financing for high efficiency equipment such as lighting, heating and cooling equipment, insulation, motors and process equipment and systems; new construction; and load management (curtailment) programs for large commercial and industrial customers and residential customers whose central air conditioners are controlled during summer peak load periods. Subject to random prudence reviews, Iowa regulation allows for contemporaneous recovery of costs incurred for the demand-side management plan through an energy charge to all retail electric and gas customers. In 2007, $51 million was expended on the demand-side management programs in Iowa resulting in an estimated 268 MW and 5,464 Dth/day of electric and gas peak demand reduction, respectively. MidAmerican Energy Company plans to offer similar or comparable programs to Illinois customers in 2008.

Transmission and Distribution

MidAmerican Energy is interconnected with utilities in Iowa and neighboring states. 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 OATT, coordination of regional planning and operations, and operation of the generation reserve sharing pool.

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. regional transmission organizations (“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 as of December 31, 2007, included approximately 2,200 miles of transmission lines. MidAmerican Energy’s electric distribution system included approximately 400 substations as of December 31, 2007.

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 through its distribution system natural gas purchased independently by a number of end-use customers. During 2007, 46% of total natural gas delivered through MidAmerican Energy’s system for end use customers was under natural gas transportation service.

The percentages of regulated natural gas Dth, excluding transportation throughput, by class of customer, for the years ended December 31 were as follows:

	2007	2006	2005

Residential	40%	37%	38%
Commercial (1)	19	18	18
Industrial (1)	4	4	4
Wholesale (2)	37	41	40
	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.

The percentages of regulated natural gas Dth, excluding transportation throughput, by jurisdiction, for the years ended December 31 were as follows:

	2007	2006	2005

Iowa	77%	77%	77%
South Dakota	12	12	12
Illinois	10	10	10
Nebraska	1	1	1
	100 %	100 %	100 %

MidAmerican Energy is allowed to recover its cost of natural gas from all of its regulated natural gas customers through purchased gas adjustment clauses. 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, including the use of storage gas and peak-shaving facilities, sharing arrangements to share savings and costs with customers and short-term and long-term financial and physical gas purchase agreements.

MidAmerican Energy purchases natural gas supplies from producers and third-party marketers. To enhance system reliability, a geographically diverse supply portfolio with varying terms and contract conditions is utilized for the natural gas supplies. 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).

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 revenue is reported in the months of January, February, March and December.

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.

On February 2, 1996, MidAmerican Energy had its highest peak-day delivery of 1,143,026 Dth. This peak-day delivery consisted of 88% traditional sales service and 12% transportation service of customer-owned gas. As of January 31, 2008, MidAmerican Energy’s 2007/2008 winter heating season peak-day delivery of 1,019,111 Dth was reached on January 29, 2008. This peak-day delivery included 73% traditional sales service and 27% transportation service.

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, 2007 included approximately 21,800 miles of gas mains and service pipelines. In addition, natural gas property includes three liquefied natural gas plants and two propane-air plants.

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. It reaches from Texas to Michigan’s Upper Peninsula and is engaged in the transmission and storage of natural gas for utilities, municipalities, other pipeline companies, gas marketers, industrial and commercial users and other end users. Northern Natural Gas owns and operates approximately 15,700 miles of natural gas pipelines, consisting of approximately 6,700 miles of mainline transmission pipelines and approximately 9,000 miles of branch and lateral pipelines, with a Market Area design capacity of 5.1 Bcf per day. 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. Northern Natural Gas’ revenue is derived from the interstate transportation and storage of natural gas for third parties. 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. 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 it an opportunity 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 delivery 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, 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 2007, 66% of Northern Natural Gas’ transportation and storage revenue was generated from Market Area customer transportation contracts. Its Market Area customers consist of utilities, other pipeline companies, gas marketers and end-users. Northern Natural Gas directly serves 76 utilities, with seven large utilities, including MidAmerican Energy, accounting for the majority of its Market Area transportation revenues in 2007. In turn, these large utilities serve numerous residential, commercial and industrial customers. In 2007, 85% of Northern Natural Gas’ transportation and storage revenue for the Field and Market Areas was generated from reservation charges under firm transportation and storage contracts and 67% of that revenue was from utilities.

A majority of Northern Natural Gas’ capacity in the Market Area is dedicated to Market Area customers under firm transportation contracts. As of December 31, 2007, 90% of Northern Natural Gas’ contracted firm transportation capacity in the Market Area is contracted beyond 2009, and 45% is contracted beyond 2015.

Northern Natural Gas has commenced the Northern Lights expansion project, which is expected to add approximately 650,100 Dth per day capacity to its Market Area. This load is concentrated primarily in the Twin Cities area of Minnesota. The majority of service for the first phase began in November 2007 with entitlement consisting of approximately 422,900 Dth per day. Service for the second phase is expected to begin by November 2008 with entitlement consisting of approximately 91,200 Dth per day. Service for the next phase is expected to begin by November 2009 with entitlement consisting of approximately 136,000 Dth per day. A portion of Northern Lights consists of service for new ethanol plants in the Market Area. Northern Natural Gas is geographically well situated to serve the expanding ethanol industry and serves approximately 31% of the nation’s ethanol manufacturing capacity. All of the Northern Lights entitlement, except for 24,600 Dth per day in 2007 and 13,000 Dth per day in 2008, is associated with new service. All phases of Northern Lights are entirely supported by executed precedent agreements and contracts, the majority of which (91% by volume) have terms ranging from five to twenty years. In total, the current Northern Lights expansion projects are expected to require over $336 million in capital expenditures of which $169 million has been incurred through December 31, 2007.

In the Field Area, customers holding transportation capacity currently consist primarily of marketers and producers. The majority of Northern Natural Gas’ Field Area firm transportation was previously conducted under long-term firm transportation contracts, the majority of which expired on October 31, 2007, with such volumes supplemented by volumes transported on a short-term firm and interruptible basis. The majority of this entitlement has been recontracted as of November 1, 2007 by marketers and producers, although the contracts are generally for less than one year. Northern Natural Gas expects recontracting to continue since Market Area customers need to purchase gas 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. In 2007, 21% 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 storage field in Iowa, two underground storage facilities in Kansas and one LNG storage peaking unit each in Garner, Iowa and Wrenshall, Minnesota. The three underground natural gas storage facilities and two LNG storage peaking units have a total firm service cycle capacity of approximately 65 Bcf and over 1.9 Bcf per day of FERC-certificated peak 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 2007, 13% of Northern Natural Gas’ transportation and storage revenue was generated from storage services.

Northern Natural Gas’ system experiences significant seasonal swings in demand, with the highest demand occurring during the months of November through March. This seasonality provides Northern Natural Gas opportunities to deliver value-added services, such as firm and interruptible storage services, as well as no-notice services, particularly during the lower demand months. Because of its location and multiple interconnections with other 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, beginning in 2008, Rockies Express Pipeline as well as from Canadian production areas through Northern Border Pipeline Company, Great Lakes Gas Transmission Limited Partnership (“Great Lakes”) and Viking Gas Transmission Company (“Viking”). 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 local distribution companies (“LDCs”) revenue by capitalizing on opportunities for shippers to reach additional markets, such as Chicago, Illinois, other parts of the Midwest, and Texas, through interconnections.

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 an approximate 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. On May 1, 2003, Kern River placed into service approximately 700-miles for an expansion project (the “2003 Expansion Project”), which increased the design capacity of Kern River’s pipeline system by 885,575 Dth per day to its current capacity. 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.

Kern River’s pipeline consists of two sections: the mainline section and the 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 700 miles of the original 36-inch diameter pipeline, approximately 600 miles of 36-inch diameter loop pipeline related to the 2003 Expansion Project and approximately 100 miles of various laterals that connect to the mainline.

The common facilities consist of approximately 200-miles of the original pipeline that extends from the point of interconnection with the mainline in Daggett to Bakersfield, California and an additional approximately 100 miles related to the 2003 Expansion Project. The common facilities are jointly owned by Kern River (approximately 77% as of December 31, 2007) and Mojave Pipeline Company (“Mojave”), a wholly owned subsidiary of El Paso Corporation, (approximately 23% as of December 31, 2007), 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 1,570,500 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 nine 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, 2007, over 95% 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. 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 Pipeline Company and Natural Gas Pipeline Company of America. 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. Particularly in the Field Area, 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 alternatives 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. While peak day delivery growth of LDCs is driven by population growth and alternative fuel replacement, new baseload or off-peak demand growth is being driven primarily by power and ethanol plant expansion. This baseload or off-peak demand growth is important to Northern Natural Gas as this demand provides revenues year round and allows Northern Natural Gas to utilize facilities on a year-round basis. The additional Market Area load growth also supports the continued sale of Northern Natural Gas’ storage services and Field Area transportation services. Northern Natural Gas has been successful in competing for a significant amount of the increased demand related to the construction of new power and ethanol plants.

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, Colorado Interstate, Overland Trail 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 addition, Kern River’s 2003 Expansion Project has several long-term transportation service agreements with electric generation companies, whose long-term competition and financial prospects are now improving as demand for electric generation in Kern River’s market territory increases and older, less efficient power plants in the region are retired.

In 2007, Northern Natural Gas had two customers who each accounted for greater than 10% of its revenue and its seven largest customers accounted for 52% of its systemwide transportation and storage revenues. Northern Natural Gas has agreements to retain the vast majority of its two largest customers’ volumes through at least 2017. Kern River had three 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 Durham, Tyne and Wear, Tees Valley and Yorkshire to North Lincolnshire, an area covering approximately 10,000 square miles, and serve approximately 3.8 million end users.

The principal function of Northern Electric and Yorkshire Electricity is to build and maintain the electricity distribution network to serve the end user. 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.

The price controlled revenues of the regulated distribution companies are agreed with the regulator, Office of Gas and Electricity Markets (“Ofgem”), based around 5-year price control periods, with the current price control period commencing April 1, 2005.

In addition to building and maintaining the electricity distribution network, CE Electric UK also owns an engineering contracting business and a hydrocarbon exploration and development business.

Electricity Distribution

Northern Electric’s and Yorkshire Electricity’s operations consist primarily of the distribution of electricity in Great Britain. Northern Electric and Yorkshire Electricity receive electricity from the national grid transmission system and distribute it to their customers’ 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 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 40% of the total combined distribution revenues of Northern Electric and Yorkshire Electricity in 2007. The fees that may be charged by Northern Electric and Yorkshire Electricity for use of their distribution systems are controlled by a formula prescribed by the United Kingdom’s electricity regulatory body that limits increases (and may require decreases) based upon the rate of inflation, other factors and other regulatory action.

Electricity distributed (in GWh) to end users and the total number of end users (in millions) as of and for the years ended December 31 were as follows:

	2007		2006		2005
Electricity distributed:
Northern Electric		16,977		17,203		17,207
Yorkshire Electricity		24,281		25,025		24,781
		41,258		42,228		41,988
Number of end users:
Northern Electric		1.6		1.6		1.5
Yorkshire Electricity		2.2		2.2		2.2
		3.8		3.8		3.7

As of December 31, 2007, Northern Electric’s and Yorkshire Electricity’s electricity distribution network on a combined basis included approximately 29,000 kilometers of overhead lines, approximately 63,000 kilometers of underground cables and approximately 700 major substations.

Utility Services

Integrated Utility Services Limited, CE Electric UK’s indirect wholly-owned subsidiary, is an engineering contracting company providing electrical infrastructure contracting services to third parties.

Hydrocarbon Exploration and Development

CalEnergy Gas (Holdings) Limited (“CE Gas”), CE Electric UK’s indirect wholly owned subsidiary, is a hydrocarbon exploration and development company that is focused on developing integrated upstream gas projects in Australia, the United Kingdom and Poland. Its upstream gas business consists of full or partial ownership in exploration, construction and production projects, which, if successful, result in the sale of gas and other hydrocarbon products to third parties.

CalEnergy Generation-Foreign

The CalEnergy Generation-Foreign platform consists of MEHC’s indirect ownership of the Casecnan project, which is a combined irrigation and hydroelectric power generation project located in the central part of the island of Luzon in the Philippines.

The following table sets out certain information concerning the Casecnan project as of December 31, 2007:

Power

Contract

Energy

Contract

Purchaser/

Capacity

Net MW

Project (1)

Location

Source

Expiration

Guarantor

(MW) (2)

Owned (2)

Casecnan

Philippines

Casecnan and Taan Rivers

December 2021

NIA/ROP

150

135

(1)	The Republic of the Philippines (“ROP”) has provided a performance undertaking under which the Philippine National Irrigation Administration’s (“NIA”) obligations under the Casecnan Project Agreement, which was modified by a Supplemental Agreement between CE Casecnan Water and Energy Company, Inc. (“CE Casecnan”) and the NIA effective on October 15, 2003 (the “Project Agreement”), are guaranteed by the full faith and credit of the ROP. NIA also pays CE Casecnan for the delivery of water and electricity by CE Casecnan. The Casecnan project carries political risk insurance.

(2)	Contract Capacity (MW) represents the contract capacity for the facility. Net MW Owned indicates legal ownership of Contract Capacity. The Net MW Owned is subject to a dispute with respect to repurchase rights of up to 15% of the project by an initial minority shareholder and a dispute with the other initial minority shareholder regarding an additional 5% of the project. Refer to Item 3 of this Form 10-K for additional information.

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. Because of the dependence on a single customer, any material failure of the customer to fulfill its obligation 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 of the relevant project company, including obligations pertaining to the outstanding project debt.

CE Casecnan owns and operates the Casecnan project 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 will impact the amounts 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.

On June 25, 2006 the Upper Mahiao project 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 (“PNOC-EDC”) by the Company at no cost on an “as-is” basis.

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, 2007:

Facility

Net or

Power

Contract

Net

Purchase

Operating

Capacity

Energy

Agreement

Power

Project

(MW) (1)

Owned (1)

Source

Location

Expiration

Purchaser (2)

CE Generation (3) :

Natural-Gas Fired -

Saranac

240

Natural Gas

New York

2009

NYSE&G

Power Resources

212

106

Natural Gas

Texas

2009

Constellation

Yuma

Natural Gas

Arizona

2024

SDG&E

Total Natural-Gas Fired

502

221

Imperial Valley Projects

327

164

Geothermal

California

(4)

Total CE Generation

829

385

Cordova

537

Natural Gas

Illinois

2019

Constellation

Wailuku

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 2007 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. (“Constellation”); 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) is sold to Southern California Edison Company under long-term power purchase agreements expiring in 2016 through 2026.

HomeServices

HomeServices 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 more than 370 broker offices in 19 states with almost 19,000 agents under the following 20 brand names: Carol Jones REALTORS, CBSHOME Real Estate, Champion Realty, Edina Realty Home Services, EWM REALTORS, Harry Norman Realtors, HOME Real Estate, Huff Realty, Iowa Realty, Jenny Pruitt and Associates REALTORS, Long Realty Company, Prudential California Realty, Prudential Carolinas Realty, Prudential First Realty, RealtySouth, Rector-Hayden REALTORS, Reece & Nichols, Roberts Brothers, Inc., Semonin REALTORS and Woods Bros. Realty. HomeServices generally occupies the number one or number two market share position in each of its major markets based on aggregate closed transaction sides. HomeServices’ major markets consist of the following metropolitan areas: Minneapolis and St. Paul, Minnesota; Los Angeles and San Diego, California; Kansas City, Kansas; Kansas City and Springfield, Missouri; Des Moines and Cedar Rapids, Iowa; Atlanta, Georgia; Omaha and Lincoln, Nebraska; Birmingham, Auburn and Mobile, Alabama; Tucson, Arizona; Winston-Salem, Raleigh-Durham and Charlotte, North Carolina; Louisville and Lexington, Kentucky; Annapolis, Maryland; Cincinnati, Ohio; and Miami, Florida. 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.

Electric Transmission Joint Ventures

In December 2007, approval was received from the Public Utility Commission of Texas (“PUCT”) to establish Electric Transmission Texas, LLC (“ETT”), as a joint venture company to fund, own and operate electric transmission assets in the Electric Reliability Council of Texas (“ERCOT”) market. The PUCT order also approved initial rates based on a 9.96% return on equity and a debt to equity capital structure of 60:40. In December 2007, AEP Texas Central Company contributed $70 million of transmission assets to ETT. Through a series of transactions, a subsidiary of American Electric Power Company, Inc. (“AEP”) then sold, at net book value, a 50% equity ownership interest in ETT to a wholly-owned subsidiary of MEHC. ETT intends to invest in additional transmission projects in ERCOT over the next several years. Future projects will be evaluated on a case-by-case basis. Two immediate sources of new projects include (a) the assignment of AEP Texas Central Company and AEP Texas North Company projects, and (b) potential projects within the ERCOT Competitive Renewable Energy Zones (“CREZ”).

In February 2007, ETT filed a proposal with the PUCT that addresses the CREZ initiative of the Texas Legislature, which outlines opportunities for additional significant investment in transmission assets in Texas. The PUCT issued an interim order in August 2007 that directed ERCOT to perform studies by April 2008 to determine the necessary transmission upgrades to accommodate between 10,000 and 22,800 MW of wind development from CREZ across the Texas panhandle and central West Texas. The PUCT also indicated in its interim order that it plans to select transmission construction designees in the first quarter of 2008.

In September 2007, subsidiaries of AEP and MEHC formed Electric Transmission America, LLC (“ETA”) to pursue transmission opportunities outside of ERCOT. MEHC also holds a 50% equity ownership in ETA. Neither ETT nor ETA is consolidated with MEHC for financial reporting purposes.

Employees

As of December 31, 2007, the Company employed approximately 17,200 people, of which approximately 7,700 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 May 2012. HomeServices’ residential real estate agents are independent contractors and not employees.

General Regulation

MEHC’s energy 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.

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 service 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 sales for electricity and capacity and gas transmission service has historically been included as a component of 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 service rates on their own initiative. Some states may 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 service, 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. Power and fuel adjustment clauses permit periodic adjustments to cost recovery from customers and therefore provide protection against exposure to 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, certain commercial and industrial customers have the right to choose alternative electric suppliers. The impact of these programs on the Company’s financial results has not been material. In Washington, the state statute 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 WUTC. In Illinois, all customers are free to choose their electricity 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.

PacifiCorp

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

State Regulator	Base Rate (1)	Power Costs (1)

Utah Public Service Commission (“UPSC”)	December 2006 stipulation resulted in an annual increase of $115 million, or 10% overall, with $85 million effective in December 2006 and the remaining $30 million effective in June 2007. In December 2007, PacifiCorp filed a general rate case requesting an increase of $161 million, or 11% overall, with an effective date of August 2008. In February 2008, the UPSC issued an order determining that the proper test period should end December 2008. PacifiCorp is currently determining the reduction to the originally requested amount that will result from the change in the test period.	No separate power cost recovery mechanism.
Oregon Public Utility Commission (“OPUC”)	September 2006 settlement agreement resulted in an annual increase for non-power costs of $33 million effective in January 2007 (2) .	Uses an annual transition adjustment mechanism, resulting in a $10 million increase in January 2007. In December 2007, the OPUC issued an order approving an increase of $22 million effective January 1, 2008 related to forecasted power costs. In December 2007, the OPUC approved a renewable adjustment clause (“RAC”) mechanism with an effective date of January 1, 2008 to recover revenue requirements of new renewable resources between rate cases. Under the RAC mechanism, PacifiCorp will submit a filing on April 1 of each year, with rates to become effective January 1 of the following year to recover the revenue requirement of new renewable resources and associated transmission that are not reflected in general rates.
Wyoming Public Service Commission (“WPSC”)	In June 2007, PacifiCorp filed for a rate increase of $36 million, or 8% overall, to be effective May 1, 2008. In January 2008, PacifiCorp reached a settlement with all parties to this case for an annual increase of $23 million, or 5% overall, subject to final stipulation and approval by the WPSC.	The January 2008 rate case settlement allows for a one time forecast period for the existing power cost mechanism. The power cost adjustment mechanism terminates in April 2011. In February 2008, PacifiCorp filed its annual deferred net power cost adjustment application with the WPSC for $31 million of costs incurred during the period December 1, 2006 through November 30, 2007.
Washington Utilities and Transportation Commission (“WUTC”)	In June 2007, the WUTC approved a rate increase of $14 million, or 6% overall, effective June 27, 2007 and accepted PacifiCorp’s proposed western balancing authority area cost allocation methodology for a five-year pilot period. In February 2008, PacifiCorp filed a general rate case with the WUTC for an annual increase of $35 million, or 15% overall, with an effective date no later than January 2009.	No separate power cost recovery mechanism.
Idaho Public Utilities Commission (“IPUC”)	In December 2007, the IPUC approved a settlement of PacifiCorp’s general rate case, resulting in a $12 million, or 6% overall, base rate increase effective January 2008. The settlement also provides for rate increases effective January 1, 2009 and 2010 for PacifiCorp’s two special contract industrial customers and no additional rate changes for those two special contract customers effective prior to January 1, 2011. Additional rate increases for the remaining customer classes may be requested if needed to maintain cost of service coverage.	No separate power cost recovery mechanism.
California Public Utilities Commission (“CPUC”)	The CPUC approved a $1 million, or 1% overall, increase effective January 1, 2008 to reflect changes to the post test-year adjustment mechanism, which allows for annual rate adjustments for changes in operating costs and plant additions outside of the context of a traditional rate case.	In December 2007, the CPUC approved a $5 million, or 7% overall, increase effective January 1, 2008 to reflect the new level of net power costs.

(1)	Margins earned on net 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)	Refer to Note 6 of Notes to Consolidated Financial Statements included in Item 8 of this Form 10-K for additional information regarding Oregon Senate Bill 408.

MidAmerican Energy

Iowa

The IUB has approved over the past several years a series of electric settlement agreements between MidAmerican Energy, the OCA and other interveners 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. Refer to Note 6 of Notes to the Consolidated Financial Statements included in Item 8 of this Form 10-K for additional discussion regarding these settlements.

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.

Illinois

In December 1997, Illinois enacted a law to restructure Illinois’ electric utility industry. The 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.

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.

Federal Regulation

The FERC is an independent agency with broad authority to implement provisions of the Federal Power Act and the Energy Policy Act. 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.

Federal Power Act

Under the Federal Power Act, the FERC regulates rates for interstate sales of electricity at wholesale, transmission of electric power, accounting, securities issuances and other matters, including construction and operation of hydroelectric projects. Margins earned on wholesale sales for electricity and capacity and transmission service have historically been included as a component of retail cost of service upon which retail rates are based.

Wholesale Electricity and Capacity

The FERC regulates PacifiCorp’s and MidAmerican Energy’s rates charged to wholesale customers for electricity, 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. A December 2006 decision of the Ninth Circuit changed the interpretation of the relevant standard that the FERC should apply when reviewing wholesale contracts for electricity or capacity from a stringent “public policy” standard to a broader “just and reasonable” standard making contracts more vulnerable to challenge. The decision raises some concerns regarding the finality of contract prices, particularly from the sellers’ side of the transactions. The U.S. Supreme Court is reviewing the case on appeal and the outcome of its ruling cannot be predicted at this time. All sellers subject to the FERC’s jurisdiction, including PacifiCorp and MidAmerican Energy, are currently subject to increased risk as a result of this decision.

The FERC conducts a triennial review of PacifiCorp’s and MidAmerican Energy’s market-based rate pricing authority. Each utility must demonstrate the lack of generation market power in order to charge market-based rates for sales of wholesale electricity and capacity in their respective balancing authority areas. Under the FERC’s market-based rules, PacifiCorp and MidAmerican Energy must file a notice of change in status when 100 MW of incremental generation becomes operational. Following separate filings by PacifiCorp of a change in status notice relating to new generation, the FERC in February and November 2007, confirmed that PacifiCorp does not have market power and may continue to charge market-based rates. In accordance with the filing schedule established by the FERC in Order No. 697, PacifiCorp’s next triennial review will occur in 2010. MidAmerican Energy’s most recent review, which began in October 2004, is complete pending the FERC’s final ruling on certain sales made within MidAmerican Energy’s balancing authority area for delivery outside the balancing authority area. MidAmerican Energy has FERC authorization to sell at market-based rates outside of its balancing authority area. Based on its estimate of MidAmerican Energy’s potential refund obligation, the Company does not believe the ultimate resolution of this issue will have a material impact on MidAmerican Energy’s financial results. Following a change in status notice relating to new generation filed by MidAmerican Energy in October 2007, the FERC confirmed that MidAmerican Energy is authorized to sell at market-based rates outside of its balancing authority area and directed that MidAmerican submit its next required triennial review in accordance with the schedule established in Order No. 697. Unless the FERC determines otherwise in response to a pending request for clarification, MidAmerican Energy’s next triennial filings will occur in June and December 2008.

Transmission

The FERC regulates PacifiCorp’s and MidAmerican Energy’s wholesale transmission services. The regulation requires 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 generating and wholesale marketing businesses in accordance with the FERC Standards of Conduct.

In January 2007, the FERC approved a settlement with PacifiCorp regarding PacifiCorp’s use of its transmission system while conducting wholesale power transactions with third parties. PacifiCorp discovered possible violations of its FERC-approved tariff during an internal review of its compliance with certain FERC regulations shortly before MEHC’s acquisition of PacifiCorp. Upon completion of the acquisition, PacifiCorp self-reported the potential violations to the FERC. The potential violations primarily related to the way PacifiCorp used its own transmission system to transmit energy using “network service” instead of “point-to-point” service as the FERC believes is required by PacifiCorp’s tariff. This use of transmission service neither enriched PacifiCorp’s shareholders nor harmed its retail customers. As part of the settlement, PacifiCorp voluntarily refunded $1 million to other transmission customers in April 2006 and paid a $10 million fine to the U.S. Treasury in January 2007.

On February 16, 2007, the FERC adopted a final rule in Order No. 890 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 to exempt intermittent generators, 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. The first compliance filing, which amends the OATT, was filed on July 13, 2007. Certain details related to the precise methodology that will be used to calculate available transfer capability were filed with the FERC on September 11, 2007. A number of parties to the proceeding, including PacifiCorp and MidAmerican Energy, have requested rehearing or clarification of various portions of the final rule. In December 2007, the FERC issued Order No. 890-A generally affirming the provisions of the final rule as adopted in Order No. 890 with certain limited clarifications. Although PacifiCorp has requested a limited clarification of Order No. 890-A, the final rule as revised is not anticipated to have a significant impact on PacifiCorp’s or MidAmerican Energy’s financial results, but it will likely have a significant impact on their transmission operations, planning and wholesale marketing functions.

In March 2007, the FERC issued Order No. 693, Mandatory Reliability Standards for the Bulk-Power System, which imposes penalties of up to $1 million per day per violation for failure to comply with new electric reliability standards. The FERC approved 83 reliability standards developed by the North American Electric Reliability Corporation (the “NERC”). Responsibility for compliance and enforcement of these standards has been given to the WECC for PacifiCorp and the Midwest Reliability Organization for MidAmerican Energy. The 83 standards comprise over 600 requirements and sub-requirements with which PacifiCorp and MidAmerican Energy must comply. On June 18, 2007, the standards became mandatory and enforceable under federal law. PacifiCorp and MidAmerican Energy expect that the existing standards will change as a result of modifications, guidance and clarification following industry implementation and ongoing audits and enforcement. On January 18, 2008, the FERC approved eight additional cyber security and critical infrastructure protection standards proposed by the NERC. The additional standards will become effective on April 7, 2008. MEHC cannot predict the effect that these standards will have on its consolidated financial results, however, they will likely have a significant impact on PacifiCorp’s and MidAmerican Energy’s transmission operations and resource planning functions. Also during 2007, the WECC audited PacifiCorp’s compliance with several of the reliability standards approved by the FERC. PacifiCorp is analyzing the preliminary results of the audit and, at this time, cannot predict the impact of potential penalties, if any, on its consolidated financial results.

Neither PacifiCorp nor MidAmerican Energy is part of a RTO, but 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. 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.

Hydroelectric Relicensing

PacifiCorp’s hydroelectric portfolio consists of 47 plants 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. Several of PacifiCorp’s hydroelectric plants are in some stage of relicensing with the FERC. Hydroelectric relicensing and the related environmental compliance requirements and litigation are subject to uncertainties. PacifiCorp expects that future costs relating to these matters may be significant and will consist primarily of additional relicensing costs, operations and maintenance expense, and capital expenditures. Electricity generation reductions may result from the additional environmental requirements. Refer to Note 18 of Notes to Consolidated Financial Statements included in Item 8 of this Form 10-K for additional information regarding hydroelectric relicensing.

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 “BPA”) 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. Several publicly owned utilities, cooperatives and the BPA’s direct-service industry customers filed lawsuits against the BPA with the United States Ninth Circuit Court of Appeals (the “Ninth Circuit”) seeking review of certain aspects of the BPA’s Residential Exchange Program, as well as challenging the level of benefits previously paid to investor-owned utility customers under the agreements. In May 2007, the Ninth Circuit issued two decisions, which resulted in the BPA suspending payment of the benefits under the agreements. This has resulted in increases to PacifiCorp’s residential and small-farm customers’ electric bills in Oregon, Washington and Idaho. In February 2008, the BPA initiated a rate proceeding under section 7(i) of the Northwest Power Act to reconsider the level of benefits for the years 2002 through 2006 consistent with the Ninth Circuit’s decision to re-establish the level of benefits for years 2007 and 2008 and to set the level of benefits for years 2009 and beyond. Because the benefit payments from the BPA are passed through to PacifiCorp’s customers, the outcome of this matter is not expected to have a significant effect on the Company’s consolidated financial results.

Energy Policy Act

On August 8, 2005, the Energy Policy Act was signed into law and has significantly impacted the energy industry. In particular, the law expanded the FERC’s regulatory authority in areas such as electric system reliability, electric transmission expansion and pricing, regulation of utility holding companies, and enforcement authority to issue civil penalties of up to $1 million per day. While the FERC has now issued rules and decisions on multiple aspects of the Energy Policy Act, the full impact of those decisions remains uncertain.

The Energy Policy Act also repealed the Public Utility Holding Company Act of 1935 (“PUHCA 1935”) and enacted the Public Utility Holding Company Act of 2005 (“PUHCA 2005”), effective February 8, 2006. PUHCA 2005 eliminated the substantive requirements and restrictions previously applicable to holding companies under PUHCA 1935. Its repeal enabled Berkshire Hathaway to convert its shares of MEHC’s no par, zero-coupon non-voting convertible preferred stock into an equal number of shares of MEHC’s voting common stock. As a consequence, MEHC became a consolidated subsidiary of Berkshire Hathaway. PUHCA 2005 also increased the FERC’s authority over utility mergers, provides the FERC with access to books and records and requires holding companies to comply with its record retention requirements.

The Energy Policy Act also gives the FERC “backstop” transmission siting authority and directs the FERC to oversee the establishment of mandatory transmission reliability standards as discussed above. The Energy Policy Act also extended the federal production tax credit for new renewable electricity generation projects through December 31, 2007, with subsequent legislation extending the credit to December 31, 2008. Partly as a result of that portion of the law, PacifiCorp and MidAmerican Energy began development efforts to add additional wind-powered generation facilities.

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 is the operator of Quad Cities Station and is under contract with MidAmerican Energy to secure and keep in effect all necessary NRC licenses and authorizations.

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. 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 assignable to firm transportation and storage customers, including a return on invested capital and income taxes, are to be recovered through fixed monthly demand reservation charges 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.

Additional proposals and proceedings that might affect the interstate natural gas pipeline industry are considered from time to time by Congress, the FERC, state regulatory bodies and the courts. The Company cannot predict when or if any new proposals might be implemented or, if so, how Northern Natural Gas and Kern River might be affected.

U.S. interstate natural gas pipelines are also subject to the regulations of the Pipeline & Hazardous Material Safety Administration (“PHMSA”) division of the Department of Transportation (“DOT”) pursuant to the Natural Gas Pipeline Safety Act of 1968 (“NGPSA”), which establishes safety requirements in the design, construction, operation and maintenance of interstate natural gas transmission facilities, and the PSIA, which implemented additional safety and pipeline integrity regulations for high consequence areas.

The NGPSA requires any entity that owns or operates pipeline facilities to comply with applicable safety standards, to establish and maintain inspection and maintenance plans and to comply with such plans. The Company’s pipeline operations conduct internal audits of their major facilities at least every four years, with more frequent reviews of those it deems of higher risk. The DOT also routinely audits these pipeline facilities. Compliance issues that arise during these audits or during the normal course of business are addressed on a timely basis.

The PSIA, as amended by the Pipeline Safety Act of 2002 and the Pipeline Inspection, Protection, Enforcement, and Safety Act of 2006, established mandatory inspections for all natural gas pipelines in high-consequence areas. These regulations require pipeline operators to implement integrity management programs, including more frequent inspections, and other safety protection in areas where the consequences of potential pipeline accidents pose the greatest risk to life and property. The Company believes its pipeline operations comply in all material respects to this regulation. The regulation also requires Northern Natural Gas and Kern River to complete certain modifications to their pipeline systems by December 17, 2012. Each pipeline is scheduled to have this work completed by December 2011.

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

U.S. Mine Safety

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. The MINER Act, portions of which are not yet fully implemented, requires operators of underground coal mines to develop a written emergency response plan specific to each 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.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 distribution license holders (“DLH”) distributes electricity from the national grid system to end use customers within their respective distribution service areas.

Given the absence of an effective competitive market in the distribution of electricity, the amount of revenue that can be collected from customers by a DLH is controlled by a distribution price control formula. This encourages companies to look for efficiency gains in order to improve profits. The distribution price control formula also adjusts the revenue received by DLHs to reflect an increase or decrease in distribution of units and number of end users. 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. Prices during this 5-year period will be allowed to increase by no more than the rate of inflation (based upon the retail price index). Ofgem also indicated that during the current price control period, the retention of any actual reductions in operating costs from the assumptions used in setting the new price control might depend on the successful implementation of revised cost reporting guidelines prescribed by Ofgem and to be applied by all DLHs.

A number of incentive schemes also operate within the current price control period to encourage DLHs to provide an appropriate quality of service 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 DLH. There are also incentive schemes pursuant to which allowed revenue may increase by up to 3.3% or decrease by up to 3.5% in any year.

Ofgem also monitors DLH 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 DLH, 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 DLH 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 DLHs 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.

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 NPC 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.

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 late 2007, HUD initiated the process to revise the RESPA regulation, however, it is unknown whether a proposed rule will be introduced or finalized in 2008. Accordingly, the Company is presently unable to quantify the likely impact of a final rule, if adopted.

Environmental Regulation

MEHC and its energy subsidiaries 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. 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 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 (“SO 2 ”) and nitrogen oxide (“NO x ”) 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.

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 12 of Notes to Consolidated Financial Statements included in Item 8 of this Form 10-K for additional information regarding the nuclear decommissioning and mine reclamation obligations.

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.

The FERC oversees the relicensing of existing hydroelectric projects and is also responsible for the oversight and issuance of licenses for new construction of hydroelectric projects, 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. The counties in Washington, Idaho, Montana, Wyoming, Colorado, Utah and Arizona, where PacifiCorp’s major emission sources are located, and the entire state of Iowa, where MidAmerican Energy’s major emission sources are located, are in attainment of the current ambient air quality standards. A new, more stringent standard for fine particulate matter became effective on December 18, 2006, but is under legal challenge in the United States Court of Appeals for the District of Columbia Circuit. Air quality modeling and preliminary air quality monitoring data indicate that portions of the states in which PacifiCorp and MidAmerican Energy have major emission sources may not meet the new standards. Until three years of data are collected and attainment designations under the new fine particulate standard are made, the impact of these new standards on PacifiCorp and MidAmerican Energy will not be known.

In July 2007, the EPA proposed revisions to the primary and secondary national ambient air quality standards for ozone, including lowering the current level of the 8-hour standard from 0.08 parts per million to a range of 0.070 and 0.075 parts per million. The EPA also solicited public comments through October 9, 2007 on alternative levels between 0.060 parts per million and the current 8-hour standard. Final action on the standards must be completed by March 12, 2008. States will then have until June 2009 to characterize their attainment status, with the EPA’s determinations regarding non-attainment made by June 2010 and state implementation plans due in 2013. Until the EPA makes its final determination on the revised standards and attainment designations are made, the impact of any new standards on PacifiCorp and MidAmerican Energy will not be known.

Regulated Air Pollutants

In March 2005, the EPA released the final Clean Air Mercury Rule (“CAMR”), a two-phase program that utilizes a market-based cap and trade mechanism to reduce mercury emissions from coal-burning power plants from the 1999 nationwide level of 48 tons to 15 tons. The CAMR required initial reductions of mercury emission in 2010 and an overall reduction in mercury emissions from coal-burning power plants of 70% by 2018. The individual states in which PacifiCorp and MidAmerican Energy operate facilities regulated under the CAMR submitted state implementation plans reflecting their regulations relating to state mercury control programs. On February 8, 2008, the United States Court of Appeals for the District of Columbia Circuit held that the EPA improperly removed electricity generating units from Section 112 of the Clean Air Act and, thus, that the CAMR was improperly promulgated under Section 111 of the Clean Air Act. The court vacated the CAMR’s new source performance standards and remanded the matter to the EPA for reconsideration. In light of this decision, it is not known the extent to which future mercury rules may impact PacifiCorp’s and MidAmerican Energy’s current plans to reduce mercury emissions at their coal-fired facilities.

In March 2005, the EPA released the final Clean Air Interstate Rule (“CAIR”), calling for reductions of SO 2 and NO x emissions in the Eastern United States through, at each state’s option, a market-based cap and trade system, emission reductions, or both. The state of Iowa has adopted rules implementing the market-based cap and trade system. While the state of Iowa has been determined to be in attainment of the existing ozone and fine particulate standards, Iowa has been found to significantly contribute to nonattainment of the fine particulate standard in Cook County, Illinois; Lake County, Indiana; Madison County, Illinois; St. Clair County, Illinois; and Marion County, Indiana. The EPA has also concluded that emissions from Iowa significantly contribute to ozone nonattainment in Kenosha and Sheboygan counties in Wisconsin and Macomb County, Michigan. Under the CAIR, the first phase of NO x emissions reductions are effective January 1, 2009, and the first phase of SO 2 emissions reductions are effective January 1, 2010. For both NO x and SO 2 , the second-phase reductions are effective January 1, 2015. The CAIR requires overall reductions by 2015 of SO 2 and NO x in Iowa of 68% and 67%, respectively, from 2003 levels. PacifiCorp’s generation facilities are not subject to the CAIR.

The CAIR could, in whole or in part, be superseded or made more stringent by current or future regulatory and legislative proposals at the federal or state levels that would result in significant reductions of SO 2 , NO X and mercury, as well as carbon dioxide and other gases that may affect global climate change. In addition to any federal rules or legislation that could be enacted, the CAIR could be changed or overturned as a result of litigation. The sufficiency of the standards established by the CAIR has been legally challenged in the United States Circuit Court of Appeals for the District of Columbia.

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 plants meet the threshold applicability criteria under the Clean Air Visibility Rules. In accordance with the federal requirements, states were required to submit state implementation plans 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 state implementation plan to the EPA by December 2007 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 state implementation plan and is continuing to review the results of analyses relating to planned emission reductions at PacifiCorp’s Wyoming generating plants. Utah has not yet submitted its state implementation plan, but expects to do so in the near term. 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 state implementation plans have been submitted.

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 expenses for 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 plants. Between 2001 and 2003, PacifiCorp and MidAmerican Energy responded to requests for information relating to their capital projects at their generating plants. PacifiCorp has been engaged in periodic discussions with the EPA over several years regarding this matter. 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 Supreme Court, holding that an increase in the annual emissions of a facility, when combined with a modification (i.e., a physical or operational change), may trigger NSR permitting. PacifiCorp and MidAmerican Energy cannot predict the outcome of the EPA’s review of the data they have submitted at this time.

In 2002 and 2003, the EPA proposed various changes to its NSR rules that clarify what constitutes routine repair, maintenance and replacement for purposes of triggering NSR requirements. These changes have been subject to legal challenge and in March 2006, a panel of the United States Court of Appeals for the District of Columbia Circuit invalidated portions of the EPA’s new NSR rules, holding that they conflicted with the wording of the statute. However, the EPA has asked the Supreme Court to review portions of the case. Until such time as the legal challenges are resolved and the revised rules are effective, PacifiCorp and MidAmerican Energy will continue to manage projects at their generating plants in accordance with the rules in effect prior to 2002, except for pollution-control projects, which are now subject to permitting under the PSD program. In 2005, the EPA proposed a rule that would change or clarify how emission increases are to be calculated for purposes of determining the applicability of the NSR permitting program for existing power plants. The EPA also proposed additional changes to the NSR rules in September 2006 that are intended to simplify the permitting process and allow facilities to undertake activities that improve their safety, reliability and efficiency without triggering NSR requirements. In April 2007, the EPA issued a supplemental notice of proposed rulemaking to the October 2005 proposed rulemaking to determine emissions increases for electric generating units, proposing to use both hourly and annual emissions tests to determine whether utilities trigger the NSR permitting program when an existing power plant makes a physical or operational change. The supplemental proposal was issued three weeks after the U.S. Supreme Court issued a unanimous opinion in Environmental Defense v. Duke Energy that the EPA was correct in applying an annual emissions test to determine NSR compliance.

Refer to Note 18 of Notes to Consolidated Financial Statements included in Item 8 of this Form 10-K for additional information regarding commitments and litigation related to air quality standards.

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 “Act”) was adopted, providing a comprehensive renewable energy policy for Oregon. Subject to certain exemptions and cost limitations established in the Act, 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 Act, 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 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.

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. However, PacifiCorp and other small multi-jurisdictional utilities (“SMJU”) are currently awaiting further guidance from the CPUC on the treatment of SMJUs in the California RPS program. PacifiCorp has filed comments requesting SMJU rules for flexible compliance with annual targets. PacifiCorp expects rules governing the treatment of SMJUs and any specific flexible compliance mechanisms to be released by CPUC staff for public review in early 2008. Absent further direction from the CPUC on treatment of SMJUs, the Company cannot predict the impact of the California RPS on its financial results.

Climate Change

As a result of increased attention to global climate change in the United States, numerous bills have been introduced in the current session of the United States Congress that would reduce greenhouse gas emissions in the United States. Congressional leadership has made climate change legislation a priority, and many congressional observers expect to see the passage of climate change legislation within the next several years. The Lieberman-Warner Climate Security Act of 2007 (S. 2191), was passed by the United States Senate Environment and Public Works Committee on December 5, 2007. The bill would impose an economy-wide cap on greenhouse gas emissions to reduce emissions 70% from 2005 levels by 2050. Included within the bill’s definition of a covered facility is any facility that uses more than 5,000 tons of coal in a calendar year, which includes all of PacifiCorp’s and MidAmerican Energy’s coal-fired generating plants. In addition, nongovernmental organizations have become more active in initiating citizen suits under existing environmental and other laws. In April 2007, a United States Supreme Court decision concluded that the EPA has the authority under the Clean Air Act to regulate emissions of greenhouse gases from motor vehicles. 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 plants 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, including:

In February 2007, the governors of California, Arizona, New Mexico, Oregon and Washington signed the Western Regional Climate Action Initiative (the “Western Climate Initiative”) that directed their respective states to develop a regional target for reducing greenhouse gases by August 2007. Utah joined the Western Climate Initiative in May 2007. The states in the Western Climate Initiative announced a target of reducing greenhouse gas emissions by 15% below 2005 levels by 2020, with Utah establishing its reduction goal by August 2008. By August 2008, they are expected to devise a market-based program, such as a load-based cap-and-trade program for the electricity sector, to reach the target. The Western Climate Initiative participants also have agreed to participate in a multi-state registry to track and manage greenhouse gas emissions in the region.

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 generation facility, as well as legislation that adopts an economy-wide cap on greenhouse gas emissions to 1990 levels by 2020.

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, 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 Iowa Climate Change Advisory Council has determined that it will also develop a second scenario to reduce greenhouse gas emissions by 90% with reductions in both scenarios from 2005 emission levels.

On November 15, 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 after establishing emissions reduction targets by July 2008 and adopting a model rule by November 2008. 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.

PacifiCorp and MidAmerican Energy continue to add renewable electricity capacity to their generation portfolios. In addition, PacifiCorp and MidAmerican Energy have engaged in several voluntary programs designed to either 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.

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 impact the Company’s current and future fossil-fueled 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 a 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 Second Circuit Court of Appeals 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 U.S. Supreme Court regarding the Second Circuit’s decision. Compliance and the potential costs of compliance, therefore, cannot be ascertained until such time as 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 in-take threshold. In the event that PacifiCorp’s or MidAmerican Energy’s existing intake structures require modification or alternative technology is required by new rules, expenditures to comply with these requirements could be significant.

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 facing us. 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 make funds available, whether by dividends, loans or other payments, for payment of our obligations, and 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 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, 2007, we had the following outstanding obligations:

·	senior indebtedness of $5.47 billion;

·	subordinated indebtedness of $1.13 billion, consisting of $304 million of trust preferred securities held by third parties and $821 million held by Berkshire Hathaway and its affiliates; and

·	guarantees and letters of credit in respect of subsidiary and equity investment indebtedness aggregating $84 million.

Our consolidated subsidiaries also have outstanding indebtedness, which totaled $13.10 billion as of December 31, 2007. 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 which could limit our ability to finance future acquisitions, develop and construct additional projects, or operate successfully under adverse economic conditions. It 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.

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, 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 have a material adverse effect on our or our subsidiaries’ 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.

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.

Our growth has been achieved largely through acquisitions, including, since 2002, those of Kern River, Northern Natural Gas, PacifiCorp and various residential real estate brokerage businesses. 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 or 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;

·	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.

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

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 regulatory 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 emissions reduction goals; the acquisition by a municipality or other quasi-governmental body 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 emerging as 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 current or recent changes to our regulatory environment that may impact 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 regulatory role from a regulatory body to an enforcement agency. To implement the law, the FERC has and will continue to issue new regulations and 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 infraction for non-compliance. The full impact of those decisions remains uncertain however, the FERC has vigorously exercised its enforcement authority by imposing significant civil penalties for violations of its rules and regulations. In addition, 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 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 will impose more comprehensive and stringent requirements on our public utility subsidiaries, which could result in increased compliance costs and could adversely affect our financial results.

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 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 Order Nos. 888, 889, 890 and 890-A, 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 cost of operating the transmission system and providing transmission service has increased and, to the extent such increased costs are not recovered in rates charged to customers, it could adversely affect our financial results.

Hydroelectric Relicensing - Several of PacifiCorp’s hydroelectric projects whose operating licenses have expired or will expire in the next several years are in some stage of the FERC relicensing process. 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 projects. Loss of hydroelectric resources or additional commitments arising from relicensing could adversely affect our financial results.

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

State Rate Proceedings - Public Utility Subsidiaries

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. Ratemaking is also generally done on the basis of estimates of normalized costs, so if a given year’s realized costs are higher than normal, 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 commissions also decide the allowed rate of return we will be permitted to earn on our equity investment. They also decide the allowed levels of expense and investment that they deem is just and reasonable in providing service. The state commissions may disallow recovery in rates for any costs that do not meet such standard.

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 or purchased power costs for electricity generation 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.

FERC Jurisdiction - Public Utility Subsidiaries

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 generation 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.

Rates established for our U.S. interstate 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 Natural Gas Act 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 DLH is controlled by a distribution price control formula set out in the electricity distribution license. The price control formula does not constrain profits from year to year, but is a control on revenue that operates independently of most of the electricity distribution license holder’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 electricity distribution license holder; 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 electricity distribution companies 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 electricity distribution license holder’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.

Through energy subsidiaries, 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 electric utility subsidiaries have significant funding needs related to their planned capital expenditures.

Through energy subsidiaries, we are continuing to develop and construct new or expanded facilities. We expect that these subsidiaries 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. These risks may result in higher than expected costs to complete an asset and place it into 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 our subsidiaries to rely 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 may materially affect our financial results.

Furthermore, our energy subsidiaries 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 the subsidiaries are unable to obtain funding from external sources, they may need to postpone or cancel planned capital expenditures. Failure to construct these 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 bilateral long-term electricity procurement contracts or procure electricity at more volatile and potentially higher prices in the spot markets to support growing retail loads.

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

Operational Standards

Our subsidiaries are subject to numerous environmental, health, safety, and other laws, regulations and other 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 sulfur dioxide, or SO 2 , and nitrous oxide, or NO x , emissions starting in 2009 to address alleged contributions to downwind non-attainment with the revised National Ambient Air Quality Standards;

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;

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

·	the implementation of federal and state renewable portfolio standards; and

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

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 impact the consumption of natural gas, thereby affecting our operations.

Further, the regulatory rate structure or long-term customer contracts may not necessarily allow our regulated subsidiaries to recover all costs incurred to comply with new environmental requirements. Although we believe that, in most cases, our regulated subsidiaries are legally entitled to recover these kinds of costs, the inability to fully recover such costs in a timely manner could adversely affect our financial results.

Site Clean-up and Contamination

Environmental, health, safety, and other laws, regulations and other 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 generation facilities, and electric and natural gas transmission and distribution assets which 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.

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 could reduce our operating revenues materially.

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 arrangements, 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. In particular, one supplier, RWE Npower PLC and certain of its affiliates represented approximately 40% of the total distribution revenues of our U.K. distribution companies in 2007; and

·	generally, a single power purchaser takes energy from 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. Any delay or default in payment or limitation on the subsidiaries to negotiate alternative arrangements could adversely affect our financial results.

If our subsidiaries are unable to renew, remarket, or find replacements for their long-term arrangements, our sales volume and revenue would be exposed to increased volatility. For example, without the benefit of long-term transportation, transmission or power purchase agreements, we cannot assure that our pipeline subsidiaries will be able to transport gas at efficient capacity levels, our regulated subsidiaries’ will be able to operate profitably, or our unregulated power generators will be able to sell the power generated by the non-utility generating facilities. Failure to secure these long-term arrangements could adversely affect our financial results.

The replacement of any existing long-term customer arrangements depends on market conditions and other factors that are beyond our subsidiaries’ control.

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

Inflation affects our businesses through increased operating costs and increased capital costs for plant and equipment. 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.

We are also exposed to changes in prices and availability of coal and natural gas and the transportation of coal and natural gas because a substantial portion of our generation capacity utilizes these fossil fuels. 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.

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 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 to reduce their 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.

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 generation 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 affect 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 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, 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, 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. 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 the strategy used to minimize these risk exposures is ineffective, significant losses could result.

Our operating results may fluctuate on a seasonal and quarterly basis.

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 projects.

As a result, the overall financial results of our energy 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 adversely affect our financial results. Furthermore, during or following periods of low rainfall or snowpack, PacifiCorp may obtain substantially less electricity from hydroelectric projects and must purchase greater amounts of electricity from the wholesale market or from other sources at market prices. 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 may 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 plant outages, work stoppages, 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, 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 revenues 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.

Potential terrorist activities or military or other actions could adversely affect us.

The continued threat of terrorism since September 11, 2001 and the impact of military and other actions by the United States and its allies may lead to increased political, economic and financial market instability and subject our subsidiaries’ operations to increased risk of acts of terrorism. 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 changed in response to these events. 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 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, 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.

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. 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 to 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 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;

·	periods of economic slowdown or recession in the markets served;

·	decreasing home affordability;

·	lack of available mortgage credit for potential homebuyers;

·	declining demand for residential real estate as an investment; and

·	nontraditional sources of new competition.

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

We and our subsidiaries are parties 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 have a material adverse effect on 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, companies’ relationships with their independent auditors and retirement plan practices. 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 U.S. Securities and Exchange Commission (“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.

Item 2.

Properties

The Company’s energy properties consist of the physical assets necessary and appropriate to generate, transmit, store, distribute and supply energy and consist mainly of electric generation, transmission and distribution facilities and gas distribution plants, 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, all of MidAmerican Energy’s gas and non-Iowa electric utility properties and Northern Natural Gas) are pledged or encumbered to support or otherwise provide the security for their own project or subsidiary debt. For additional information regarding the Company’s energy properties, refer to Item 1 of this Form 10-K and Notes 4 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 May 2004, PacifiCorp was served with a complaint filed in the United States District Court for the District of Oregon by the Klamath Tribes of Oregon, individual Klamath Tribal members and the Klamath Claims Committee. The complaint generally alleges that PacifiCorp and its predecessors affected the Klamath Tribes’ federal treaty rights to fish for salmon in the headwaters of the Klamath River in southern Oregon by building dams that blocked the passage of salmon upstream to the headwaters beginning in 1911. In September 2004, the Klamath Tribes filed their first amended complaint adding claims of damage to their treaty rights to fish for sucker and steelhead in the headwaters of the Klamath River. The complaint seeks in excess of $1.0 billion in compensatory and punitive damages. In July 2005, the District Court dismissed the case and in September 2005 denied the Klamath Tribes’ request to reconsider the dismissal. In October 2005, the Klamath Tribes appealed the District Court’s decision to the United States Court of Appeals for the Ninth Circuit (the “Ninth Circuit”) and briefing was completed in March 2006. In February 2008, the Ninth Circuit held oral argument on the briefs. PacifiCorp believes the outcome of this proceeding will not have a material impact on its consolidated financial results.

In May 2007, PacifiCorp was served with a complaint filed in the United States District Court for the Northern District of California by Leaf Hillman and Terance J. Supahan (Karuk Tribe Members); Frankie Joe Myers, Howard McConnell and Robert Attebery (Yurok Tribe Members): Michael T. Hudson (a commercial fisherman); Blythe Reis (a resort owner); and the Klamath Riverkeeper (a local environmental group) alleging that toxic algae “introduced” by PacifiCorp into Klamath hydroelectric project reservoirs is released by PacifiCorp to the river downstream of the project, and caused or will cause the plaintiffs physical, property, and economic harm. Plaintiffs allege seven causes of action based on nuisance, trespass, negligence, and unlawful business practices, all under California law. Elevated concentrations of microcystis aeruginosa (blue-green algae), which can generate a toxin called microcystin, have been identified in Klamath River hydroelectric project reservoirs, and now farther downstream on the Klamath River. The algae occur naturally across Oregon, California, and throughout the world. Elevated concentrations tend to appear in areas of slack water that is relatively warm. It has been identified for years on Klamath Lake. Plaintiffs seek unspecified damages and injunctive relief; however, in an order filed by the court in August 2007, the court dismissed plaintiffs’ claims for injunctive relief based on federal preemption under the Federal Power Act. PacifiCorp denies the allegations and is vigorously defending the case, which is currently in the discovery phase.

In December 2007, PacifiCorp was served with a complaint filed in the United States District Court for the Northern District of California by the Klamath Riverkeeper (a local environmental group), Leaf Hillman (a Karuk Tribe member), Howard McConnell and Robert Attebery (Yurok Tribe Members) and Blythe Reis (a resort owner). The complaint alleges that reservoirs behind the hydroelectric dams that PacifiCorp operates on the Klamath River provide an environment for the growth of blue-green algae known as microcystis aeruginosa, which can generate a toxin called microcystin. The complaint alleges that such algae is a “solid waste” under the federal Resource Conservation and Recovery Act, that PacifiCorp “generates” and “stores” such algae in its reservoirs, that PacifiCorp “disposes” of such algae when it passes through the dams, and that such “generation,” “storage” and “disposal” causes or threatens to cause an imminent and substantial endangerment to health and the environment. The complaint seeks a Court order declaring that PacifiCorp is violating the federal Resource Conservation and Recovery Act, enjoining PacifiCorp from storing or disposing of the algae, requiring PacifiCorp to “remediate all contamination of or other damage to health or the environment” from such algae, and requiring PacifiCorp to pay civil penalties of up to $27,500 per day per violation from February 2001 to March 2004, and up to $32,500 per day per violation from March 2004 and thereafter. PacifiCorp believes these claims to be without merit and filed a motion to dismiss on December 20, 2007. In February 2008, a court order was issued conditionally allowing the consolidation of the December 2007 blue-green algae case with the May 2007 blue-green algae case described above. Subsequently, the plaintiffs filed a motion seeking clarification of the order. The plaintiffs have until February 29, 2008 to agree to the conditions of the order, which are to pay for certain of PacifiCorp’s costs and fees associated with any delay caused by the consolidation of the two cases. If the plaintiffs do not agree to pay the delay costs, the December 2007 blue-green algae case will be dismissed.

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 of opacity, which is a measurement of light 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. A five-day trial on the liability phase is scheduled to begin in April 2008. The remedy-phase trial has not yet been set. The court is considering several summary judgment motions filed by the parties, but has not yet ruled on any of them. 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.

On December 28, 2004, an apparent gas explosion and fire resulted in three fatalities, one serious injury and property damage at a commercial building in Ramsey, Minnesota. According to the Minnesota Office of Pipeline Safety, an improper installation of a pipeline connection may have been a cause of the explosion and fire. A predecessor company to MidAmerican Energy provided gas service in Ramsey, Minnesota, at the time of the original installation in 1980. In 1993, a predecessor of CenterPoint Energy, Inc. (“CenterPoint”) acquired all of the Minnesota gas properties owned by the MidAmerican Energy predecessor company.

All of the wrongful death, personal injury and property damage claims arising from this incident have been settled by CenterPoint. MidAmerican Energy’s exposure, if any, to these settlements is covered under its liability insurance to which a $2 million retention applies.

Two lawsuits naming MidAmerican Energy as a third party defendant have been filed by CenterPoint Energy Resources Corp. in the U.S. District Court, District of Minnesota, related to this incident. The complaints seek reimbursement of all sums associated with CenterPoint’s replacement of all service lines in the MidAmerican Energy predecessor company’s properties located in Minnesota at a cost of approximately $39 million according to publicly available reports. MidAmerican Energy filed a motion for summary judgment in both of these actions requesting that CenterPoint’s third party claims based upon misrepresentation and negligent installation and negligent operation and maintenance of the gas pipeline be barred. On March 5, 2007, the U.S. District Court issued an order granting MidAmerican Energy’s motion for summary judgment as to CenterPoint’s misrepresentation and negligent installation claims and denying MidAmerican Energy’s motion for summary judgment as to CenterPoint’s negligent operation and maintenance claims. A court-ordered settlement conference was held September 21, 2007, but the parties did not achieve a settlement. Subsequently, the court ordered the parties to be ready for trial on or after February 1, 2008. Trial has not commenced. MidAmerican Energy intends to vigorously defend its position in these claims and believes their ultimate outcome will not have a material impact on its financial results.

Interstate Pipeline Companies

In 1998, the United States Department of Justice informed the then current owners of Northern Natural Gas and Kern River that Jack Grynberg, an individual, had filed claims in the United States District Court for the District of Colorado under the False Claims Act against such entities and certain of their subsidiaries including Northern Natural Gas and Kern River. Mr. Grynberg has also filed claims against numerous other energy companies and alleges that the defendants violated the False Claims Act in connection with the measurement and purchase of hydrocarbons. The relief sought is an unspecified amount of royalties allegedly not paid to the federal government, treble damages, civil penalties, attorneys’ fees and costs. On October 21, 1999, the Panel on Multi-District Litigation transferred the claims to the United States District Court for the District of Wyoming for pre-trial purposes. Motions to dismiss based on various jurisdictional grounds were filed on June 4, 2004. On May 17, 2005, Northern Natural Gas and Kern River each received a Special Master’s Report and Recommendations which recommended that the action be dismissed for lack of subject matter jurisdiction. On October 20, 2006, the United States District Court for the District of Wyoming affirmed the Special Master’s Report and Recommendation and dismissed Grynberg’s complaint as to all defendants. On November 16, 2006, Grynberg filed 74 separate notices of appeal. In accordance with case management orders issued by the Court of Appeals for the Tenth Circuit, initial appellate briefs were filed by the parties in the second half of 2007 with additional briefs to be filed during the first half of 2008. Oral argument is scheduled for the week of September 22, 2008. In connection with the purchase of Kern River from The Williams Companies, Inc. (“Williams”) in 2002, Williams agreed to indemnify MEHC against any liability for this claim; however, no assurance can be given as to the ability of Williams to perform on this indemnity should it become necessary. No such indemnification was obtained in connection with the purchase of Northern Natural Gas in 2002. The Company believes that the Grynberg cases filed against Northern Natural Gas and Kern River are without merit and that Williams, on behalf of Kern River pursuant to its indemnification, and Northern Natural Gas, intend to defend these actions vigorously and that the ultimate outcome of the Grynberg cases will not have a material impact on their financial results.

On June 8, 2001, Northern Natural Gas, Kern River and other pipeline companies, were named as defendants in a nationwide class action in the 26th Judicial District, District Court, Stevens County Kansas, Civil Department. The plaintiffs allege that the defendants have engaged in mismeasurement techniques that distort the heating content of natural gas, resulting in an alleged underpayment of royalties to the class of producer plaintiffs. With court approval, the plaintiffs filed a fourth amended petition alleging a class of gas royalty owners in Kansas, Colorado and Wyoming on July 28, 2003. Kern River was not a named defendant in the amended petition and has been dismissed from the action. Northern Natural Gas filed an answer to the fourth amended petition on August 22, 2003. After fully briefing the class certification issue, on November 9, 2006, the plaintiffs filed a request for a new briefing schedule on class certification in light of a new Kansas Supreme Court case on class actions which ruled that in that case the trial court failed to engage in properly rigorous analysis of class certification and choice of law issues and remanded a denial of class certification for such an analysis. The plaintiffs hope to use this as grounds for further class certification briefing. On July 31, 2007, both the plaintiffs and Northern Natural Gas, as one of the coordinated defendants, filed their proposed findings of fact and conclusions of law regarding class certification. Northern Natural Gas believes that this claim is without merit and intends to defend these actions vigorously and believes its ultimate outcome will not have a material impact on its financial results.

Similar to the June 8, 2001 matter referenced above, the plaintiffs in that matter filed a new companion action on May 12, 2003 against Northern Natural Gas and other parties, but excluding Kern River, in a Kansas state district court for damages for mismeasurement of British thermal unit content, resulting in lower royalties. After fully briefing the class certification issue, on November 9, 2006, the plaintiffs filed a request for a new briefing schedule on class certification in light of a new Kansas Supreme Court case on class actions which ruled that in that case the trial court failed to engage in properly rigorous analysis of class certification and choice of law issues and remanded a denial of class certification for such an analysis. The plaintiffs hope to use this as grounds for further class certification briefing. On July 31, 2007, both the plaintiff and Northern Natural Gas, as one of the coordinated defendants, filed their proposed findings of fact and conclusion of law regarding class certification. Northern Natural Gas believes that this claim is without merit and intends to defend these actions vigorously and believes its ultimate outcome will not have a material impact on its financial results.

Independent Power Projects

Pursuant to the share ownership adjustment mechanism in the CE Casecnan shareholder agreement, which is based upon proforma financial projections of the Casecnan Project prepared following commencement of commercial operations, in February 2002, 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. On July 8, 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.

On February 21, 2007, the appellate court issued a decision, and as a result of the decision, CE Casecnan Ltd. determined that LPG would retain ownership of 10% of the shares of CE Casecnan, with the remaining 5% ownership being transferred to CE Casecnan Ltd. subject to certain buy-up rights under the shareholder agreement. At a hearing on October 10, 2007, the court determined that LPG was ready, willing and able to exercise its buy-up rights in 2007. Additional hearings were held on October 23 and 24, 2007, regarding the issue of the buy-up price calculation and a written decision was issued on February 4, 2008 specifying the method for determining LPG’s buy-up price. A final judgment has not been issued on the buy-up right and price and when issued will be subject to appeal. LPG waived its request for a jury trial for the breach of fiduciary duty claim and the parties have entered into a stipulation which provides for a trial of such claim by the court based on the existing record of the case. The trial date has been set for March 12, 2008. The Company intends to vigorously defend and pursue the remaining claims.

In February 2003, San Lorenzo Ruiz Builders and Developers Group, Inc. (“San Lorenzo”), an original shareholder substantially all of whose shares in CE Casecnan were purchased by MEHC in 1998, threatened to initiate legal action against the Company in the Philippines in connection with certain aspects of its option to repurchase such shares. The Company believes that San Lorenzo has no valid basis for any claim and, if named as a defendant in any action that may be commenced by San Lorenzo, the Company will vigorously defend such action. On July 1, 2005, MEHC and CE Casecnan Ltd. commenced an action against San Lorenzo in the District Court of Douglas County, Nebraska, seeking a declaratory judgment as to MEHC’s and CE Casecnan Ltd.’s rights vis-à-vis San Lorenzo in respect of such shares. San Lorenzo filed a motion to dismiss on September 19, 2005. Subsequently, San Lorenzo purported to exercise its option to repurchase such shares. On January 30, 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 Cascenan, that it is the rightful owner of such shares and that it is due all dividends paid on such shares. On March 9, 2006, the court granted San Lorenzo’s motion to dismiss, but has since permitted MEHC and CE Casecnan Ltd. to file an amended complaint incorporating the purported exercise of the option. The complaint has been amended and the action is proceeding. Currently, the action is in the discovery phase and a one-week trial has been set to begin on November 3, 2008. The impact, if any, of San Lorenzo’s purported exercise of its option and the Nebraska 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.

PART II

Item 5.

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

Since March 14, 2000, MEHC’s common stock has been owned by Berkshire Hathaway, Mr. Walter Scott, Jr. and certain of his family members and family controlled trusts and corporations, Mr. David L. Sokol, its Chairman and Chief Executive Officer, and Mr. Gregory E. Abel, its President and Chief Operating 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 since March 14, 2000 and does not presently anticipate that it will declare any dividends on its common stock in the foreseeable future.

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, 2007, 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, 2007, 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, 2007, PacifiCorp’s unsecured debt rating was BBB+ by Standard & Poor’s Rating Services and 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 a common equity to total capitalization ratio above 42%, except under circumstances beyond its control. MidAmerican Energy’s common equity to total capitalization ratio is not allowed to decline below 39% for any reason. If the ratio declines below the defined threshold, MidAmerican Energy must seek the approval of a reasonable utility capital structure from the IUB. MidAmerican Energy’s ability to issue debt could also be restricted. As of December 31, 2007, MidAmerican Energy’s common equity to total capitalization ratio, computed on a basis consistent with the commitment, exceeded the minimum threshold.

For further discussion of contractual and regulatory restrictions that limit certain of MEHC’s subsidiaries’ ability to pay dividends on their common stock to MEHC, refer to Note 11 of Notes to Consolidated Financial Statements included in Item 8 of this Form 10-K.

On November 12, 2007, MEHC issued 370,000 shares of its common stock, no par value, to Mr. Abel upon the exercise by Mr. Abel of 370,000 of his outstanding common stock options. The common stock options were exercisable at a weighted-average price of $26.99 per share and the aggregate exercise price paid by Mr. Abel was $10 million. This issuance was pursuant to a private placement and was exempt from the registration requirements of the Securities Act of 1933, as amended.

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,
	2007		2006 (1)		2005		2004			2003
Consolidated Statement of Operations Data:
Operating revenue	$	12,376	$	10,301	$	7,116	$	6,553		$	5,966
Income from continuing operations		1,189		916		558		538			443
Income (loss) from discontinued operations, net of tax (2)		-		-		5		(368	)		(27	)
Net income		1,189		916		563		170			416

	As of December 31,
	2007		2006 (1)		2005		2004			2003
Consolidated Balance Sheet Data:
Total assets	$	39,216	$	36,447	$	20,371	$	19,904		$	19,145
MEHC senior debt (3)		4,471		3,929		2,776		2,772			2,778
MEHC subordinated debt (3)		891		1,123		1,354		1,586			1,772
Subsidiary and project debt (3)		12,131		11,061		6,837		6,305			6,675
Preferred securities of subsidiaries		128		128		88		90			92
Total shareholders’ equity		9,326		8,011		3,385		2,971			2,771

(1)	Reflects the acquisition of PacifiCorp on March 21, 2006.

(2)	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”).

(3)	Excludes current portion.

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 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 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 as a result of the reduction in the United Kingdom corporate income tax rate from 30% to 28% 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 planned turnover to the Philippine government of the Upper Mahiao project in June 2006 and the Malitbog and Mahanagdong projects in July 2007, 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.

Net income for 2006 was $916 million, an increase of $353 million, or 63%, compared to 2005. Net income related to PacifiCorp, which was acquired on March 21, 2006, was $215 million during 2006. Also contributing to the increase in net income were favorable comparative results at most of the Company’s energy businesses and $73 million of after tax gains on sales of available-for-sale securities. These improvements were partially offset by lower earnings at HomeServices and higher interest expense on MEHC senior debt.

Segment Results

The Company’s operations are organized and managed as eight distinct platforms: PacifiCorp, MidAmerican Funding (which primarily includes MidAmerican Energy), Northern Natural Gas, Kern River, CE Electric UK (which primarily includes Northern Electric and Yorkshire Electricity), CalEnergy Generation-Foreign, CalEnergy Generation-Domestic and HomeServices. 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 natural gas interstate pipeline companies in the United States, two electricity distribution companies in Great Britain, a diversified portfolio of independent power projects and the second largest residential real estate brokerage firm in the United States.

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

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

	2007			2006			Change					2006			2005			Change
Operating revenue:
PacifiCorp	$	4,258		$	2,939		$	1,319		45	%	$	2,939		$	-		$	2,939		N/A
MidAmerican Funding		4,267			3,453			814		24			3,453			3,166			287		9	%
Northern Natural Gas		664			634			30		5			634			569			65		11
Kern River		404			325			79		24			325			324			1		-
CE Electric UK		1,079			928			151		16			928			884			44		5
CalEnergy Generation-Foreign		220			336			(116	)	(35	)		336			312			24		8
CalEnergy Generation-Domestic		32			32			-		-			32			34			(2	)	(6	)
HomeServices		1,500			1,702			(202	)	(12	)		1,702			1,868			(166	)	(9	)
Corporate/other		(48	)		(48	)		-		-			(48	)		(41	)		(7	)	(17	)
Total operating revenue	$	12,376		$	10,301		$	2,075		20		$	10,301		$	7,116		$	3,185		45

Operating income:
PacifiCorp	$	917		$	528		$	389		74	%	$	528		$	-		$	528		N/A
MidAmerican Funding		514			421			93		22			421			381			40		10	%
Northern Natural Gas		308			269			39		14			269			209			60		29
Kern River		277			217			60		28			217			204			13		6
CE Electric UK		555			516			39		8			516			484			32		7
CalEnergy Generation-Foreign		142			230			(88	)	(38	)		230			185			45		24
CalEnergy Generation-Domestic		12			14			(2	)	(14	)		14			15			(1	)	(7	)
HomeServices		33			55			(22	)	(40	)		55			125			(70	)	(56	)
Corporate/other		(70	)		(130	)		60		46			(130	)		(74	)		(56	)	(76	)
Total operating income	$	2,688		$	2,120		$	568		27		$	2,120		$	1,529		$	591		39

PacifiCorp

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 revenues 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):

	2007		2006		Change				2006		2005		Change
Operating revenue:
Regulated electric	$	1,934	$	1,779	$	155	9	%	$	1,779	$	1,513	$	266		18	%
Regulated natural gas		1,174		1,112		62	6			1,112		1,323		(211	)	(16	)
Nonregulated and other		1,159		562		597	106			562		330		232		70
Total operating revenue	$	4,267	$	3,453	$	814	24		$	3,453	$	3,166	$	287		9

Operating income:
Regulated electric	$	398	$	372	$	26	7	%	$	372	$	334	$	38		11	%
Regulated natural gas		53		36		17	47			36		39		(3	)	(8	)
Nonregulated and other		63		13		50	385			13		8		5		63
Total operating income	$	514	$	421	$	93	22		$	421	$	381	$	40		10

Regulated electric revenue increased $155 million for 2007 compared to 2006 due to increases in wholesale revenue of $103 million and retail revenue of $52 million. Wholesale revenue increased due primarily 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 due primarily to growth in retail demand, an increase in the average number of retail customers and favorable weather conditions in 2007. Regulated natural gas revenue increased $62 million for 2007 compared to 2006 due primarily to higher retail sales volumes and an increase in the average per-unit cost of gas sold, partially offset by lower wholesale sales volumes. Nonregulated and other revenue increased $597 million for 2007 compared to 2006 due primarily to increases in electric retail sales volumes and prices driven by improved market opportunities, partially offset by decreases in gas sales volumes and prices.

Regulated electric revenue increased $266 million for 2006 compared to 2005 due to increases in wholesale revenue of $219 million and retail revenue of $47 million. Wholesale revenue increased due primarily to higher average electric energy prices and volumes as a result of additional generation placed in service and greater market opportunities. Retail revenue increased due primarily to an increase in retail demand and usage, partially offset by lower revenue due to mild summer temperatures in 2006. Regulated natural gas revenue decreased $211 million for 2006 compared to 2005 due primarily to a decrease in the average per-unit cost of gas sold and lower volumes. Nonregulated and other revenue increased $232 million for 2006 compared to 2005 due primarily to a change in management strategy related to certain end-use natural gas contracts that required the related revenues and cost of sales to be recorded prospectively on a gross, rather than net, basis, partially offset by a decrease in natural gas sales volumes and lower electric and natural gas prices. In 2005, cost of sales totaling $289 million were netted in nonregulated operating revenue for such end-use gas contracts.

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 primarily 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 primarily 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. Operating income for regulated natural gas and nonregulated and other increased $17 million and $50 million, respectively, due primarily to higher gross margins on the aforementioned operating revenue increases.

Regulated electric operating income increased $38 million for 2006 compared to 2005 as a result of higher gross margins of $71 million due to the aforementioned higher sales volumes and prices, partially offset by $28 million of higher operating expenses and $6 million of higher depreciation and amortization expense. The increase in operating expenses was due primarily to higher generating plant operating and maintenance expenses including additional expense for wind generation.

Northern Natural Gas

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 a lower volume of gas and condensate liquids sales of $17 million, which are both utilized in the operation and balancing of the pipeline system. Operating revenue increased $65 million for 2006 compared to 2005 due primarily to higher transportation and storage revenues due to higher rates and volumes from favorable market conditions.

Operating income increased $39 million for 2007 compared to 2006 due primarily to the aforementioned increase in transportation and storage revenues, partially offset by a $6 million asset impairment charge. Operating income increased $60 million for 2006 compared to 2005 due to the aforementioned increase in transportation and storage revenues. Several non-routine events also impacted operating income in 2005, including a $29 million asset impairment charge of a non-contiguous portion of the pipeline system, a gain of $20 million from the sale of an idled section of pipeline in Oklahoma and Texas and the adjustments from two FERC-approved settlements that increased operating income by $16 million.

Kern River

Operating revenue increased $79 million for 2007 compared to 2006. Kern River earned higher market oriented revenue of $50 million 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 revenue increased $1 million for 2006 compared to 2005 as higher market oriented revenue of $34 million due to favorable market conditions was offset by the aforementioned adjustment to Kern River’s provision for estimated refunds.

Operating income increased $60 million for 2007 compared to 2006 due primarily to the aforementioned increase in market oriented 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. Operating income increased $13 million for 2006 compared to 2005 due primarily to lower depreciation and amortization due primarily to changes in the expected rates in connection with the current rate proceeding.

CE Electric UK

Operating revenue increased $151 million for 2007 compared to 2006 due primarily to a $79 million favorable impact from the exchange rate, higher distribution revenue of $33 million at Northern Electric and Yorkshire Electricity, due primarily to tariff increases, and higher revenue of $32 million at CE Gas, primarily from higher gas production. Operating revenue increased $44 million for 2006 compared to 2005 due primarily to higher contracting revenue of $21 million, higher distribution revenues at Northern Electric and Yorkshire Electricity of $14 million due to higher units distributed and the favorable impact of the exchange rate of $12 million.

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 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. Operating income increased $32 million for 2006 compared to 2005 due primarily to the higher distribution revenues and the favorable impact of the exchange rate.

CalEnergy Generation-Foreign

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 revenue increased $24 million for 2006 compared to 2005. Higher revenue at the Casecnan project of $42 million as a result of above normal water flows throughout 2006 was partially offset by lower operating revenue of $18 million due primarily to the aforementioned transfer of the Upper Mahiao project.

Operating income decreased $88 million for 2007 compared to 2006. Lower revenue was partially offset by lower depreciation and amortization expense of $30 million as the projects were transferred. Operating income increased $45 million for 2006 compared to 2005 due primarily to the higher revenue as well as lower operating expenses of $15 million due primarily to the aforementioned transfer of the Upper Mahiao project.

HomeServices

Operating revenue decreased $202 million for 2007 compared to 2006 and $166 million for 2006 compared to 2005 due to the general slowdown in the U.S. housing market and the resulting lower number of brokerage transactions.

Operating income decreased $22 million for 2007 compared to 2006 due mainly to the aforementioned decrease in brokerage transactions, partially offset by lower commissions, operating expenses and depreciation and amortization expense. Operating income decreased $70 million for 2006 compared to 2005 due mainly to the aforementioned decrease in brokerage transactions and higher acquisition related amortization, partially offset by lower operating expenses due primarily to lower salaries and employee benefits expenses.

Consolidated Other Income and Expense Items

Interest Expense

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

	2007		2006		Change					2006		2005		Change

Subsidiary debt	$	899	$	758	$	141		19	%	$	758	$	533	$	225		42	%
MEHC senior debt and other		285		233		52		22			233		173		60		35
MEHC subordinated debt-Berkshire		108		134		(26	)	(19	)		134		158		(24	)	(15	)
MEHC subordinated debt-other		28		27		1		4			27		27		-		-
Total interest expense	$	1,320	$	1,152	$	168		15		$	1,152	$	891	$	261		29

Interest expense increased $168 million for 2007 compared to 2006 and $261 million for 2006 compared to 2005 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 and $224 million in 2006 as a result of the acquisition of PacifiCorp. The increase in interest expense for 2007 and 2006 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):

	2007			2006			Change					2006			2005			Change

Capitalized interest	$	54		$	40		$	14		35	%	$	40		$	17		$	23	135	%
Interest and dividend income		105			73			32		44			73			58			15	26
Other income		122			239			(117	)	(49	)		239			75			164	219
Other expense		(10	)		(13	)		3		23			(13	)		(23	)		10	43
Total other income, net	$	271		$	339		$	(68	)	(20	)	$	339		$	127		$	212	167

Capitalized interest increased $14 million for 2007 compared to 2006 and $23 million for 2006 compared to 2005 due primarily to the acquisition of PacifiCorp and increased levels of capital project expenditures at MidAmerican Energy.

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. Interest and dividend income increased $15 million for 2006 compared to 2005 due primarily to the acquisition of PacifiCorp.

Other income decreased $117 million for 2007 compared to 2006 and increased $164 million for 2006 compared to 2005. Other income 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. Additionally, other income was higher by $27 million for 2006 compared to 2005 as a result of the acquisition of PacifiCorp.

Other expense decreased $10 million for 2006 compared to 2005 due primarily to 2005 losses for other-than-temporary impairments of MidAmerican Funding’s investments in commercial passenger aircraft leased to major domestic airlines.

Income Tax Expense

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%.

Income tax expense increased $162 million, or 66%, for 2006 compared to 2005. The effective tax rates were 31% and 32% for 2006 and 2005, respectively. The increase in income tax expense was due to higher pretax earnings.

Minority Interest and Preferred Dividends of Subsidiaries

Minority interest and preferred dividends of subsidiaries increased $12 million to $27 million for 2006 compared to 2005 due mainly to higher earnings at CE Casecnan and preferred dividends at PacifiCorp.

Equity Income

Equity income 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. Equity income decreased $10 million to $43 million for 2006 compared to 2005 due primarily to lower earnings at CE Generation as a result of higher depreciation and maintenance expenses and lower equity income at HomeServices due to lower refinancing activity at its residential mortgage loan joint ventures.

Liquidity and Capital Resources

The Company has available a variety of sources of liquidity and capital resources, both internal and external, including the Berkshire Equity Commitment. These resources provide funds required for current operations, construction expenditures, debt retirement and other capital requirements. The Company may from time to time seek to retire its outstanding securities through cash purchases in the open market, privately negotiated transactions or otherwise. Such repurchases or exchanges, if any, will depend on prevailing market conditions, the Company’s liquidity requirements, contractual restrictions and other factors. The amounts involved may be material.

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 project or 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.

The Company’s cash and cash equivalents were $1.18 billion as of December 31, 2007, compared to $343 million as of December 31, 2006. The Company recorded separately in other current assets, restricted cash and investments as of December 31, 2007 and 2006 of $73 million and $132 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 costs, (iii) customer deposits held in escrow, (iv) custody deposits, and (v) unpaid dividends declared obligations. The debt service funds are restricted by their respective project debt agreements to be used only for the related project. The Company had a guaranteed investment contract of $397 million that matured in February 2008. Additionally, the Company has restricted cash and investments recorded in deferred charges, investments and other assets as of December 31, 2007 and 2006 that principally relate to trust funds held for mine reclamation and nuclear decommissioning costs. As of December 31, 2007, MEHC had $554 million of availability under its $600 million revolving credit facility with no borrowings outstanding and had letters of credit issued under the credit agreement totaling $46 million.

Cash Flows from Operating Activities

Cash flows generated from operations for the years ended December 31, 2007 and 2006 were $2.34 billion and $1.92 billion, respectively. The increase was mainly due to the acquisition of PacifiCorp on March 21, 2006, which contributed $399 million to the increase in operating cash flows. Higher cash flows from operations at MidAmerican Energy, Kern River and CE Electric UK were largely offset by lower cash flows from operations at CalEnergy Generation-Foreign, as a result of the transfer of the Malitbog and Mahanagdong projects to the Philippine government in 2007, and HomeServices.

Cash Flows from Investing Activities

Cash flows used in investing activities for the years ended December 31, 2007 and 2006 were $3.25 billion and $7.32 billion, respectively. In 2007, a certain wholly owned subsidiary of CE Electric UK received proceeds of $201 million from the maturity of a guaranteed investment contract. Capital expenditures, construction and other development costs increased $1.09 billion for 2007 compared to 2006. Additionally, net purchases and sales of available-for-sale securities resulted in higher cash outflows for 2007 of $157 million due primarily to Kern River’s receipt of $89 million in proceeds from the sale of Mirant stock in 2006 and MidAmerican Funding’s receipt of $28 million in proceeds from the sale of common shares held in an electronic energy and metals trading exchange in 2006. In 2006, MEHC acquired PacifiCorp for $4.93 billion, net of cash acquired.

PacifiCorp Acquisition

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. 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 and expenses, resulting in a total purchase price of $5.12 billion. The results of PacifiCorp’s operations are included in the Company’s results beginning March 21, 2006.

In the first quarter of 2006, the state commissions in all six states where PacifiCorp has retail customers approved the sale of PacifiCorp to MEHC. The approvals were conditioned on a number of regulatory commitments, including expected financial benefits in the form of reduced corporate overhead and financing costs, certain mid- to long-term capital and other expenditures of significant amounts and a commitment not to seek utility rate increases attributable solely to the change in ownership. The capital and other expenditures proposed by MEHC and PacifiCorp include:

Approximately $812 million in investments (generally to be made over several years following the sale and subject to subsequent regulatory review and approval) in emissions reduction technology for PacifiCorp’s existing coal plants, which, when coupled with the use of reduced emissions technology for anticipated new coal-fueled generation, is expected to result in significant reductions in emissions rates of SO 2 , NO x , and mercury and to avoid an increase in the carbon dioxide emissions rate;

Approximately $520 million in investments (to be made over several years following the sale and subject to subsequent regulatory review and approval) in PacifiCorp’s transmission and distribution system that would enhance reliability, facilitate the receipt of renewable resources and enable further system optimization; and

·	The addition of 400 MW of cost-effective new renewable resources to PacifiCorp’s generation portfolio by December 31, 2007, including 100 MW of cost-effective wind resources by March 21, 2007.

As of December 31, 2007, PacifiCorp had incurred $205 million in capital expenditures related to its commitment to invest in emissions reduction technology for its existing coal plants, and $112 million of capital expenditures and $16 million of operating expenses related to its commitment to invest in its transmission and distribution system. PacifiCorp met the requirements of its commitment to bring 100 MW of cost-effective wind resources into service by March 21, 2007 with the completion of the 101-MW Leaning Juniper wind plant, which was placed in service in September 2006. Additionally, PacifiCorp met its commitment to add 400 MW of cost-effective renewable resources to its generation portfolio by December 31, 2007.

Capital Expenditure

Capital expenditures include both those relating to operating projects and to construction and other development costs. Capital expenditures by reportable segment for the years ended December 31 are summarized as follows (in millions):

	2007		2006
Capital expenditures*:
PacifiCorp	$	1,518	$	1,114
MidAmerican Energy		1,300		758
Northern Natural Gas		225		122
CE Electric UK		422		404
Other reportable segments and corporate/other		47		25
Total capital expenditures	$	3,512	$	2,423

* - Excludes amounts for non-cash equity AFUDC.

Capital expenditures relating to operating projects, mainly for distribution, transmission, generation, mining and other infrastructure needed to serve existing and growing demand, totaled $1.69 billion in 2007. Capital expenditures relating to construction and other development costs totaled $1.82 billion in 2007 and consisted primarily of the following:

PacifiCorp completed construction of the Lake Side plant, a 548-MW combined cycle, natural gas-fired generation plant in September 2007. Total project costs were $343 million, including $17 million of non-cash equity AFUDC, and included costs paid in 2007 of $51 million. The Lake Side plant is 100% owned and operated by PacifiCorp.

·	PacifiCorp placed 140 MW of wind-powered generation facilities in service and began construction of an additional 461 MW of wind-powered generation facilities in 2007 with costs totaling $575 million.

MidAmerican Energy completed construction of the Walter Scott, Jr. Energy Center Unit No. 4, 790-MW supercritical, coal-fired generation plant in June 2007 at a total cost of $1.2 billion. MidAmerican Energy operates the plant and holds an undivided ownership interest of approximately 60%, or 471 MW, as a tenant in common with the other owners of the plant. MidAmerican Energy’s share of the total project cost was $840 million, including $64 million of non-cash equity AFUDC, and included costs paid in 2007 of $170 million.

·	MidAmerican Energy placed 201 MW of wind-powered generation facilities in service and began construction of an additional 462 MW of wind-powered generation facilities in 2007 with costs totaling $565 million.

·	PacifiCorp and MidAmerican Energy spent $110 million and $167 million, respectively, on emissions control equipment in 2007.

·	Northern Natural Gas spent $151 million on its Northern Lights Expansion project in 2007.

The Company has significant future capital requirements. Forecasted capital expenditures for fiscal 2008, which exclude non-cash equity AFUDC, are approximately $3.9 billion and consist of $2.0 billion for operating projects mainly for distribution, transmission, generation, mining and other infrastructure needed to serve existing and growing demand, and $1.9 billion for construction and other development projects.

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, the cost and efficiency of construction labor, equipment, and materials, and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered. The Company expects to meet its capital expenditure requirements with cash flows from operations and the issuance of debt. To the extent funds are not available to support capital expenditures, projects may be delayed and operating income may be reduced.

Projected 2008 construction and other development expenditures include the following:

·	Combined, PacifiCorp and MidAmerican Energy anticipate spending $1.26 billion on wind-powered generation facilities of which 923 MW are expected to be placed in service in 2008.

·	Combined, PacifiCorp and MidAmerican Energy are projecting to spend $314 for emissions control equipment in 2008.

In May 2007, PacifiCorp announced plans to build in excess of 1,200 miles of new high-voltage transmission lines primarily in Wyoming, Utah, Idaho, Oregon and the desert Southwest. The estimated $4.1 billion investment plan includes projects that will address customers’ increasing electric energy use, improve system reliability and deliver wind and other renewable generation resources to more customers throughout PacifiCorp’s six-state service area and the western region. These transmission lines are expected to be placed into service beginning 2010 and continuing through 2014. PacifiCorp expects to spend $283 million on new transmission lines in 2008.

The Company is 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. The cost of complying with applicable environmental laws, regulations and rules is expected to be material to the Company. In particular, future mandates may impact the operation of the Company’s domestic generating facilities and may require both PacifiCorp and MidAmerican Energy 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 established technology that reduces the carbon dioxide emissions at coal-fired facilities and the Company is uncertain when, or if, such technology will be commercially available.

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 the routine cost structure of MEHC’s energy subsidiaries. An inability to recover these costs from the Company’s customers, either through regulated rates, long-term arrangements or market prices could adversely affect the Company’s future financial results.

Refer to the Environmental Regulation section of Item 1 of this Form 10-K for a detailed discussion of the topic.

Cash Flows from Financing Activities

Cash flows from financing activities were $1.75 billion for the year ended December 31, 2007. Sources of cash totaled $3.58 billion and consisted primarily of $2 billion of proceeds from the issuance of subsidiary and project debt and $1.54 billion of proceeds from the issuance of MEHC senior debt. Uses of cash totaled $1.83 billion and consisted primarily of $784 million for repayments of MEHC senior and subordinated debt, $599 million for repayments of subsidiary and project debt, $269 million for net repayments of subsidiary short-term debt and $152 million for net repayments of MEHC’s revolving credit facility.

Cash flows from financing activities were $5.38 billion for the year ended December 31, 2006. Sources of cash totaled $7.90 billion and consisted primarily of $5.13 billion of proceeds from the issuance of common stock, $1.70 billion of proceeds from the issuance of MEHC senior debt and $718 million of proceeds from the issuance of subsidiary and project debt. Uses of cash totaled $2.52 billion and consisted primarily of $1.75 billion of repurchases of common stock, $516 million for repayments of subsidiary and project debt and $234 million for repayments of MEHC subordinated debt.

Stock Transactions and Agreements

In 2007, 370,000 common stock options were exercised having a weighted average exercise price of $26.99 per share and in 2006, 775,000 common stock options were exercised having a weighted average exercise price of $28.65 per share.

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 (a) paying when due MEHC’s debt obligations and (b) funding the general corporate purposes and capital requirements of the MEHC’s regulated subsidiaries. Berkshire Hathaway will have up to 180 days to fund any such request. The Berkshire Equity Commitment will expire on February 28, 2011, was not used for the PacifiCorp acquisition and will not be used for future acquisitions.

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.

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

2007 Debt Transactions and Agreements

In addition to the debt issuances discussed herein, MEHC and its subsidiaries made scheduled repayments on MEHC senior and subordinated debt and subsidiary and project debt totaling approximately $1.38 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 will support 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 will be 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. Pending repayment of this indebtedness, the proceeds are being used to repay short-term indebtedness, with the balance invested in short-term securities or used for general corporate purposes.

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.

2006 Debt Transactions and Agreements

In addition to the debt issuances discussed herein, MEHC and its subsidiaries made scheduled repayments on MEHC subordinated debt and subsidiary and project debt totaling approximately $750 million during the year ended December 31, 2006.

·	On March 24, 2006, MEHC completed a $1.70 billion offering of 6.125% unsecured senior bonds due 2036. The proceeds were used to fund MEHC’s exercise of its right to repurchase shares of its common stock previously issued to Berkshire Hathaway.

On July 6, 2006, MEHC entered into a $600 million credit facility pursuant to the terms and conditions of an amended and restated credit agreement. The amended and restated credit agreement remains unsecured, carries a variable interest rate based on LIBOR or a base rate, at MEHC’s option, plus a margin, and the termination date was extended to July 6, 2011. The facility is for general corporate purposes and also continues to support letters of credit for the benefit of certain subsidiaries and affiliates.

·	On August 10, 2006, PacifiCorp issued $350 million of 6.1%, 30-year first mortgage bonds. The proceeds from this offering were used to repay a portion of PacifiCorp’s short-term debt and for general corporate purposes.

On October 6, 2006, MidAmerican Energy completed the sale of $350 million in aggregate principal amount of its 5.8% medium-term notes due October 15, 2036. The proceeds from this offering were used to support construction of MidAmerican Energy’s electric generation projects, to repay a portion of its short-term debt and for general corporate purposes.

Refer to Item 5 of this Form 10-K for further discussion regarding the limitation of distributions from MEHC’s subsidiaries.

Credit Ratings

As of January 31, 2008, MEHC’s senior unsecured debt credit ratings were as follows: Moody’s Investor Service, “Baa1/stable”; Standard and Poor’s, “BBB+/stable”; and Fitch Ratings, “BBB+/stable.”

Debt and preferred securities of MEHC and certain of its subsidiaries are rated by nationally recognized credit rating agencies. Assigned credit ratings are based on each rating agency’s assessment of the rated company’s ability to, in general, meet the obligations of its issued debt or preferred securities. The credit ratings are not a recommendation to buy, sell or hold securities, and there is no assurance that a particular credit rating will continue for any given period of time. Other than the agreements discussed below, MEHC and its subsidiaries do not have any credit agreements that require termination or a material change in collateral requirements or payment schedule in the event of a downgrade in the credit ratings of the respective company’s securities.

In conjunction with their risk management activities, PacifiCorp and MidAmerican Energy must meet credit quality standards as required by counterparties. In accordance with industry practice, master agreements that govern PacifiCorp’s and MidAmerican Energy’s energy supply and marketing activities either specifically require each company to maintain investment grade credit ratings 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. If one or more of PacifiCorp’s or MidAmerican Energy’s credit ratings decline below investment grade, PacifiCorp or MidAmerican Energy may be required to post cash collateral, letters of credit or other similar credit support to facilitate ongoing wholesale energy supply and marketing activities. As of January 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 below investment grade, PacifiCorp’s and MidAmerican Energy’s estimated potential collateral requirements would total approximately $265 million and $225 million, respectively. PacifiCorp’s and MidAmerican Energy’s potential collateral requirements could fluctuate considerably due to seasonality, market price volatility, and a loss of key generating facilities or other related factors.

Inflation

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

Obligations and Commitments

The Company has contractual obligations and commercial commitments 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 and commitments as of December 31, 2007 are as follows (in millions):

	Payments Due By Periods
	Total		2008			2009- 2010		2011- 2012	2013 and After
Contractual Cash Obligations:
MEHC senior debt	$	5,475	$	1,000	$	-	$	500	$	3,975
MEHC subordinated debt		1,196		234		423		269		270
Subsidiary and project debt		13,000		966		561		1,994		9,479
Interest payments on long-term debt		19,379		1,233		2,154		1,939		14,053
Short-term debt		130		130		-		-		-
Coal, electricity and natural gas contract commitments (1)		8,523		1,637		2,289		1,055		3,542
Purchase obligations (1)		602		440		85		26		51
Owned hydroelectric commitments (1)		812		39		109		126		538
Operating leases (1)		549		100		147		94		208
Minimum pension funding requirements		490		112		92		92		194
Total contractual cash obligations	$	50,156	$	5,891	$	5,860	$	6,095	$	32,310

	Commitment Expiration per Period
	Total		2008			2009- 2010		2011- 2012	2013 and After
Other Commercial Commitments:
Unused revolving credit facilities and lines of credit -
MEHC revolving credit facility	$	554	$	-	$	-	$	554	$	-
Subsidiary revolving credit facilities and lines of credit		2,073		-		279		1,794		-
Total unused revolving credit facilities and lines of credit	$	2,627	$	-	$	279	$	2,348	$	-
MEHC letters of credit outstanding	$	47	$	23	$	24	$	-	$	-
Pollution control revenue bond standby letters of credit	$	297	$	-	$	-	$	297	$	-
Pollution control revenue bond standby bond purchase agreements	$	221	$	124	$	-	$	97	$	-
Other standby letters of credit	$	90	$	20	$	6	$	64	$	-

(1)	Not reflected in the Consolidated Balance Sheets.

The Company has other types of commitments that relate primarily to construction and other development costs (Liquidity and Capital Resources included within this Item 7), debt guarantees (Note 11), asset retirement obligations (Note 12) and uncertain tax positions (Note 15) 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.

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, 2007, 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 $616 million, $210 million and $82 million, respectively. As of December 31, 2007, the Company’s pro-rata share of such short- and long-term debt, unused revolving credit facilities and outstanding letters of credit was $306 million, $105 million and $41 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. $34 million of the Company’s pro-rata share of the outstanding letters of credit is recourse to the Company and is included in the Obligations and Commitments table. 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.

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 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 rate making to another form of regulation, other regulatory actions or the impact of competition which could limit the Company’s ability to recover its 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 regulatory assets and regulatory liabilities would be written off and recognized in operating income. Total regulatory assets were $1.50 billion and total regulatory liabilities were $1.63 billion as of December 31, 2007. Refer to Note 6 of Notes to Consolidated Financial Statements included in Item 8 of this Form 10-K for additional information regarding the Company’s regulatory assets and liabilities.

Derivatives

The Company is exposed to variations in the market prices of electricity and natural gas, foreign currency and interest rates and uses derivative instruments, including forward purchases and sales, futures, swaps and options to manage these inherent market price risks.

Measurement Principles

Derivative instruments are recorded in the Consolidated Balance Sheets at fair value as either assets or liabilities unless they are designated and qualifying for the normal purchases and normal sales exemption afforded by GAAP. The fair values of derivative instruments are determined using 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 and uses internally developed, modeled prices when market quotations are unavailable. The fair value of these 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 contracts are probable of recovery in rates, and therefore recorded as a net regulatory asset or liability, or are accounted for as cash flow hedges and therefore changes in fair value are recorded as accumulated other comprehensive income (loss). Accordingly, amounts are generally not recognized in earnings until the contracts are settled. As of December 31, 2007, the Company had $276 million recorded as net regulatory assets and $91 million recorded as accumulated other comprehensive income (loss), 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, future changes in the value of the derivative are charged to earnings. Gains and losses related to discontinued hedges that were previously recorded in accumulated other comprehensive income will remain there 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 accumulated other comprehensive income 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 these 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 of property, plant and equipment was used in regulated businesses as of December 31, 2007. 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.

The Company’s Consolidated Balance Sheet as of December 31, 2007 includes goodwill of acquired businesses of $5.34 billion. Goodwill is allocated to each reporting unit and is tested for impairment using a variety of methods, principally discounted projected future net cash flows, at least annually and impairments, if any, are charged to earnings. The Company completed its annual review as of October 31. 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, 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 postretirement plans in the balance sheet. Funded status is the fair value of plan assets minus the benefit obligation as of the measurement date. As of December 31, 2007, the Company recognized an asset totaling $162 million for the over-funded status and a liability totaling $442 million for the under-funded status for the Company’s defined benefit pension and other postretirement benefit plans.

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 returns 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 19 of Notes to Consolidated Financial Statements included 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 cost for these plans as of and for the period ended December 31, 2007.

In establishing its assumption as to the expected return on 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 rate of return on retirement plan and other postretirement benefit 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 which reflects the near and long-term expectations of increases in medical costs. 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 19 of Notes to Consolidated Financial Statements included in Item 8 of this Form 10-K for health care cost trend rate sensitivity disclosures.

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 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, 2007,
Benefit Obligations:
Discount rate	$(97)	$107	$(45)	$50	$(149)	$167

Effect on 2007 Periodic Cost:
Discount rate	$(9)	$ 10	$ (4)	$ 4	$ (8)	$ 8
Expected return on assets	(7)	7	(3)	3	(8)	8

A variety of factors, including the plan funding practices of the Company, affect the funded status of the plans. 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. As a result of the Pension Protection Act of 2006, the Company does not anticipate any significant changes to the amount of funding previously anticipated through 2008; however, depending on a variety of factors which impact the funded status of the plans, including asset returns, discount rates and plan changes, the Company may be required to accelerate contributions to its domestic pension plans for periods after 2008 and there may be more volatility in annual contributions than historically experienced, which could have a material impact on financial results.

Income Taxes

In determining the Company’s tax liabilities, 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 the separate entities from 2000 to 2005. Most significantly, Northern Electric’s and Yorkshire Electricity’s examinations are closed through 2001. In addition, open tax years related to a number of state and other foreign jurisdictions remain subject to examination. 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, is not expected to have a material adverse affect on the Company’s financial results.

Both PacifiCorp and MidAmerican Energy are required to pass income tax benefits related to certain accelerated tax depreciation and other property-related basis differences on to their customers in most state jurisdictions. These amounts were recognized as a net regulatory asset totaling $606 million as of December 31, 2007, 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.

The Company has not provided U.S. 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 were approximately $1.5 billion as of December 31, 2007. 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-term 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 revenues were $480 million as of December 31, 2007. Historically, any differences between the actual and estimated amounts have been immaterial. Revenue from energy business customers is recognized as electricity or gas is delivered or services are provided. The determination of sales to individual customers is based on the 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. The monthly unbilled revenue is determined by the estimation of unbilled energy provided during the period. Factors that can impact the estimate of unbilled energy provided 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.

Item 7A.

Quantitative and Qualitative Disclosures About Market Risk

The Company’s Consolidated Balance Sheets include assets and liabilities whose fair values 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. Refer to Notes 2 and 14 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 items, changing weather, 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 forwards, futures, options, swaps and other over-the-counter 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 regulatory assets or liabilities. Financial results may be negatively impacted if the costs of wholesale electricity, fuel and 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.

The table that follows summarizes the Company’s commodity risk on energy derivative contracts as of December 31, 2007 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, 2007	$ (263)	10% increase	$ (208)
		10% decrease	(318)

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, 2007, 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 $212 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 $30 million in 2007.

Interest Rate Risk

As of December 31, 2007, The Company had fixed-rate long-term debt totaling $18.96 billion with a total fair value of $19.80 billion. 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. However, the fair value of these instruments would decrease by approximately $917 million if interest rates were to increase by 10% from their levels as of December 31, 2007. Comparatively, as of December 31, 2006, the Company had fixed-rate long-term debt totaling $16.72 billion with a total fair value of $17.57 billion. The fair value of these instruments would have decreased by approximately $733 million if interest rates had increased by 10% from their levels as of December 31, 2006. In general, such a decrease 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.

As of December 31, 2007 and 2006, the Company had floating-rate obligations totaling $729 million and $727 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.

Credit Risk

Domestic Regulated Operations

PacifiCorp and MidAmerican Energy extend unsecured credit to other utilities, energy marketers, financial institutions and certain commercial and industrial end-users in conjunction with wholesale energy 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 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 a daily basis. To mitigate exposure to the financial risks of wholesale counterparties, PacifiCorp and MidAmerican Energy enter into netting and collateral arrangements that 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 receipts. If required, PacifiCorp and MidAmerican Energy exercise rights under these arrangements, including calling on the counterparty’s credit support arrangement.

At December 31, 2007, 71% of PacifiCorp’s and 91% of MidAmerican Energy’s credit exposure, net of collateral, from wholesale operations was with counterparties having externally rated “investment grade” credit ratings, while an additional 9% of PacifiCorp’s and 8% of MidAmerican Energy’s credit exposure, net of collateral, from wholesale operations was with counterparties having financial characteristics deemed equivalent to “investment grade” by PacifiCorp and MidAmerican Energy based on internal review.

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 40% of distribution revenues in 2007. The Office of Gas and Electricity Markets (“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.

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 $125 million for the year ended December 31, 2007. The Casecnan project agreement expires in December 2021.

Item 8.

Financial Statements and Supplementary Data

Report of Independent Registered Public Accounting Firm	80

Consolidated Balance Sheets as of December 31, 2007 and 2006	81

Consolidated Statements of Operations for the Years Ended December 31, 2007, 2006 and 2005	83

Consolidated Statements of Shareholders’ Equity for the Years Ended December 31, 2007, 2006 and 2005	84

Consolidated Statements of Cash Flows for the Years Ended December 31, 2007, 2006 and 2005	85

Notes to Consolidated Financial Statements	86

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, 2007 and 2006, and the related consolidated statements of operations, shareholders’ equity, and cash flows for each of the three years in the period ended December 31, 2007. 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, 2007 and 2006, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2007, 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.

As discussed in Note 2 to the consolidated financial statements, the Company adopted Statement of Financial Accounting Standards No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans - an amendment of FASB Statements No. 87, 88, 106, and 132(R),” as of December 31, 2006.

/s/ Deloitte & Touche LLP

Des Moines, Iowa

February 27, 2008

MIDAMERICAN ENERGY HOLDINGS COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Amounts in millions)

	As of December 31,
	2007		2006

ASSETS

Current assets:
Cash and cash equivalents	$	1,178	$	343
Accounts receivable, net		1,464		1,280
Inventories		476		407
Derivative contracts		170		236
Guaranteed investment contracts		397		196
Other current assets		629		677
Total current assets		4,314		3,139

Property, plant and equipment, net		26,221		24,039
Goodwill		5,339		5,345
Regulatory assets		1,503		1,827
Derivative contracts		227		248
Deferred charges, investments and other assets		1,612		1,849

Total assets	$	39,216	$	36,447

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

MIDAMERICAN ENERGY HOLDINGS COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (continued)

(Amounts in millions)

	As of December 31,
	2007		2006

LIABILITIES AND SHAREHOLDERS’ EQUITY

Current liabilities:
Accounts payable	$	1,063	$	1,049
Accrued interest		341		306
Accrued property and other taxes		230		231
Derivative contracts		266		271
Other current liabilities		816		713
Short-term debt		130		552
Current portion of long-term debt		1,966		1,103
Current portion of MEHC subordinated debt		234		234
Total current liabilities		5,046		4,459

Other long-term accrued liabilities		1,372		1,716
Regulatory liabilities		1,629		1,839
Derivative contracts		499		618
MEHC senior debt		4,471		3,929
MEHC subordinated debt		891		1,123
Subsidiary and project debt		12,131		11,061
Deferred income taxes		3,595		3,449
Total liabilities		29,634		28,194

Minority interest		128		114
Preferred securities of subsidiaries		128		128

Commitments and contingencies (Note 18)

Shareholders’ equity:
Common stock - 115 shares authorized, no par value, 75 shares and 74 shares issued and outstanding as of December 31, 2007 and 2006, respectively		-		-
Additional paid-in capital		5,454		5,420
Retained earnings		3,782		2,598
Accumulated other comprehensive income (loss), net		90		(7	)
Total shareholders’ equity		9,326		8,011

Total liabilities and shareholders’ equity	$	39,216	$	36,447

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

MIDAMERICAN ENERGY HOLDINGS COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(Amounts in millions)

	Years Ended December 31,
	2007			2006			2005

Operating revenue	$	12,376		$	10,301		$	7,116

Costs and expenses:
Cost of sales		5,680			4,587			3,293
Operating expense		2,858			2,587			1,686
Depreciation and amortization		1,150			1,007			608
Total costs and expenses		9,688			8,181			5,587

Operating income		2,688			2,120			1,529

Other income (expense):
Interest expense		(1,320	)		(1,152	)		(891	)
Capitalized interest		54			40			17
Interest and dividend income		105			73			58
Other income		122			239			75
Other expense		(10	)		(13	)		(23	)
Total other income (expense)		(1,049	)		(813	)		(764	)

Income from continuing operations before income tax expense, minority interest and preferred dividends of subsidiaries and equity income		1,639			1,307			765
Income tax expense		(456	)		(407	)		(245	)
Minority interest and preferred dividends of subsidiaries		(30	)		(27	)		(15	)
Equity income		36			43			53
Income from continuing operations		1,189			916			558
Income from discontinued operations, net of tax		-			-			5
Net income	$	1,189		$	916		$	563

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

MIDAMERICAN ENERGY HOLDINGS COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY

FOR THE THREE YEARS ENDED DECEMBER 31, 2007

(Amounts in millions)

												Accumulated
												Other
						Additional						Comprehensive
	Common			Common		Paid-in			Retained			Income (Loss),
	Shares			Stock		Capital			Earnings			net			Total
Balance , January 1, 2005		9		$	-	$	1,951		$	1,157		$	(137	)	$	2,971
Net income		-			-		-			563			-			563
Other comprehensive income:
Foreign currency translation adjustment		-			-		-			-			(186	)		(186	)
Fair value adjustment on cash flow hedges, net of tax of $(10)		-			-		-			-			(20	)		(20	)
Minimum pension liability adjustment, net of tax of $18		-			-		-			-			44			44
Unrealized gains on marketable securities, net of tax of $1		-			-		-			-			1			1
Total comprehensive income																402
Exercise of common stock options		-			-		6			-			-			6
Tax benefit from exercise of common stock options		-			-		6			-			-			6
Balance, December 31, 2005		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

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

MIDAMERICAN ENERGY HOLDINGS COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Amounts in millions)

	Years Ended December 31,
	2007			2006			2005

Cash flows from operating activities:
Income from continuing operations	$	1,189		$	916		$	558
Adjustments to reconcile income from continuing operations to cash flows from continuing operations:
Gain on other items, net		(12	)		(145	)		(6	)
Depreciation and amortization		1,150			1,007			608
Amortization of regulatory assets and liabilities		(16	)		26			39
Provision for deferred income taxes		129			260			130
Other		(102	)		1			(41	)
Changes in other items, net of effects from acquisitions:
Accounts receivable and other current assets		(255	)		(39	)		(136	)
Accounts payable and other accrued liabilities		252			(103	)		159
Net cash flows from operating activities		2,335			1,923			1,311

Cash flows from investing activities:
Capital expenditures relating to operating projects		(1,693	)		(1,684	)		(796	)
Construction and other development costs		(1,819	)		(739	)		(400	)
PacifiCorp acquisition, net of cash acquired		-			(4,932	)		(5	)
Other acquisitions, net of cash acquired		-			(74	)		(5	)
Purchases of available-for-sale securities		(1,641	)		(1,504	)		(2,842	)
Proceeds from sale of available-for-sale securities		1,586			1,606			2,913
Maturity (Purchase) of guaranteed investment contracts		201			-			(557	)
Proceeds from sale of assets		65			30			103
Decrease (increase) in restricted cash		75			(32	)		27
Other		(24	)		8			4
Net cash flows from continuing operations		(3,250	)		(7,321	)		(1,558	)
Net cash flows from discontinued operations		-			-			7
Net cash flows from investing activities		(3,250	)		(7,321	)		(1,551	)

Cash flows from financing activities:
Proceeds from the issuances of common stock		10			5,132			6
Purchases of common stock		-			(1,750	)		-
Proceeds from MEHC senior debt		1,539			1,699			-
Proceeds from subsidiary and project debt		2,000			718			1,051
Repayments of MEHC senior and subordinated debt		(784	)		(234	)		(449	)
Repayments of subsidiary and project debt		(599	)		(516	)		(875	)
Net (repayments of) proceeds from MEHC revolving credit facility		(152	)		101			51
Net (repayments of) proceeds from subsidiary short-term debt		(269	)		196			10
Net proceeds from settlement of treasury rate lock agreements		32			53			-
Other		(30	)		(22	)		(13	)
Net cash flows from financing activities		1,747			5,377			(219	)
Effect of exchange rate changes		3			6			(20	)
Net change in cash and cash equivalents		835			(15	)		(479	)
Cash and cash equivalents at beginning of period		343			358			837
Cash and cash equivalents at end of period	$	1,178		$	343		$	358

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

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. MEHC and its subsidiaries are referred to as 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 (owning a majority interest in the Casecnan project), CalEnergy Generation-Domestic (owning 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. 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.

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 receivables, valuation of energy contracts, the effects of regulation, long-lived asset recovery, goodwill impairment, the accounting for contingencies, including environmental, regulatory and income tax matters, 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 securities and in other investments with a maturity of three months or less when purchased. Cash and cash equivalents exclude amounts where the 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 assets 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. The Company’s investments in debt and equity securities are primarily classified as available-for-sale.

Available-for-sale securities are stated 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 regulatory assets or liabilities since the Company expects to recover costs for these activities through rates.

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 at least 20% and no greater 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 of the investee. The Company also records its proportionate share of other comprehensive income items of the investee as a component of its comprehensive income. 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

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 and the outcome of pending disputes and arbitrations. As of December 31, 2007 and 2006, the allowance for doubtful accounts totaled $22 million and $30 million, respectively.

Derivatives

The Company employs a number of different derivative instruments in connection with its electric and natural gas, foreign currency exchange rate and interest rate risk management activities, including forward purchases and sales, futures, swaps and options. Derivative instruments are recorded in the Consolidated Balance Sheets at fair value as either assets or liabilities unless they are designated and qualify for the normal purchases and normal sales exemption afforded by GAAP. Contracts that qualify as normal purchases or normal sales are not marked to market. 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. 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 maintains formal documentation of the hedge. In addition, at inception and on a quarterly basis, the Company formally assesses whether the hedge contracts are highly effective in offsetting changes in cash flows or fair values of the hedged items. The Company 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 current earnings.

Certain derivative electric and 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.

When available, quoted market prices or prices obtained through external sources are used to measure a contract’s fair value. For contracts without available quoted market prices, fair value is determined based on internally developed modeled prices. The fair value of these instruments is a function of underlying forward commodity prices, interest rates, currency rates, related volatility, counterparty creditworthiness and duration of the contracts.

Inventories

Inventories consist mainly of materials and supplies, coal stocks, gas in storage and fuel oil, which are valued 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 cost determined under the first-in-first-out method would be $73 million and $77 million higher as of December 31, 2007 and 2006, 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 costs 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 and 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 depreciate rates. The Company believes the useful lives assigned to the depreciable assets, which range from 3 to 85 years, are reasonable.

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 the residual gain or loss is deferred and subsequently amortized through future depreciation expense. 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 debt and equity costs of capital funds necessary to finance the construction of domestic regulated facilities. AFUDC is capitalized as a component of property, plant and equipment cost, 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.

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 a liability for a legal ARO is recognized in the period in which it is incurred, if a reasonable estimate of fair value can be made. The fair value of the liability 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 liability is adjusted for any material revisions to the expected value of the retirement obligation (with corresponding adjustments to property, plant and equipment) and for accretion of the 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 these 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 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 for impairment using a variety of methods, principally discounted projected future net cash flows, at least annually and impairments, if any, are 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 an appropriate discount rate and estimated future cash flows. In estimating cash flows, the Company incorporates current market information as well as historical factors. During 2007, 2006 and 2005, 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 electric customers is recognized as electricity is delivered and includes amounts for services rendered. Revenue from the sale, distribution and transportation of natural gas is recognized when either the service is provided or the product is delivered. Revenue recognized includes unbilled as well as billed amounts.

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.

Electricity and water is delivered in the Philippines pursuant to provisions of the respective project agreements which are accounted for as arrangements that contain both a lease and a service contract. The leases are classified as operating due to significant uncertainty regarding the collection of future amounts mainly due to the existence of political, economic and other uncertainties in the Philippines. The majority of the revenue under these arrangements is fixed.

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.

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 $606 million and $581 million as of December 31, 2007 and December 31, 2006, 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 were approximately $1.5 billion as of December 31, 2007. 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 tax liabilities, 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 the separate entities from 2000 to 2005. Most significantly, Northern Electric’s and Yorkshire Electricity’s examinations are closed through 2001. In addition, open tax years related to a number of state and other foreign jurisdictions remain subject to examination. 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. The Company’s unrecognized tax benefits are primarily included in other long-term accrued liabilities in the Consolidated Balance Sheets. The Company recognizes interest and penalties related to unrecognized tax benefits in income tax expense in the Consolidated Statements of Operations.

New Accounting Pronouncements

In July 2006, the Financial Accounting Standards Board (“FASB”) issued FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes - an interpretation of FASB Statement No. 109” (“FIN 48”) . The Company adopted the provisions of FIN 48 effective January 1, 2007. Under FIN 48, tax benefits are recognized only for tax positions that are more likely than not to be sustained upon examination by tax authorities. The amount recognized is measured as the largest amount of benefit that is greater than 50% likely to be realized upon ultimate settlement. Unrecognized tax benefits are tax benefits claimed in the Company’s tax returns that do not meet these recognition and measurement standards. Refer to Note 15 for additional discussion.

In December 2007, the FASB issued Statement of Financial Accounting Standards (“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 February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities - including an amendment of FASB Statement No. 115” (“SFAS No. 159”). SFAS No. 159 permits entities to elect to measure many financial instruments and certain other items at fair value. Upon adoption of SFAS No. 159, an entity may elect the fair value option for eligible items that exist at the adoption date. Subsequent to the initial adoption, the election of the fair value option should only be made at initial recognition of the asset or liability or upon a remeasurement event that gives rise to new-basis accounting. The decision about whether to elect the fair value option is applied on an instrument-by-instrument basis, is irrevocable and is applied only to an entire instrument and not only to specified risks, cash flows or portions of that instrument. SFAS No. 159 does not affect any existing accounting literature that requires certain assets and liabilities to be carried at fair value nor does it eliminate disclosure requirements included in other accounting standards. SFAS No. 159 is effective for fiscal years beginning after November 15, 2007. The Company does not anticipate electing the fair value option for any existing eligible items. However, the Company will continue to evaluate items on a case-by-case basis for consideration of the fair value option.

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. SFAS No. 157 is effective for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. The Company is currently evaluating the impact of adopting SFAS No. 157 on its consolidated financial position and results of operations.

In September 2006, the FASB issued SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans - an amendment of FASB Statements No. 87, 88, 106, and 132(R)” (“SFAS No. 158”). The Company adopted the recognition and related disclosure provisions of SFAS No. 158 as of December 31, 2006. SFAS No. 158 also requires that an employer measure plan assets and obligations as of the end of the employer’s fiscal year, eliminating the option in SFAS No. 87 and SFAS No. 106 to measure up to three months prior to the financial statement date. The requirement to measure plan assets and benefit obligations as of the date of the employer’s fiscal year-end is not required until fiscal years ending after December 15, 2008. As of December 31, 2007, PacifiCorp had not yet adopted the measurement date provisions of the statement. Upon adoption of the measurement date provisions, PacifiCorp will be required to record a transitional adjustment to retained earnings or to a regulatory asset depending on whether the amount is considered probable of being recovered in rates.

(3)	PacifiCorp Acquisition

General

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 17). 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 (the “acquisition date”).

Allocation of Purchase Price

The total purchase price was allocated to PacifiCorp’s net tangible and identified intangible assets acquired and liabilities assumed based on their estimated fair values at the acquisition date. PacifiCorp’s operations are regulated and are accounted for pursuant to SFAS No. 71. PacifiCorp has demonstrated a past history of recovering its costs incurred through its rate making process. Certain adjustments, which were not significant, related to derivative contracts, severance costs and income taxes were made to the purchase price allocation. The following table summarizes the adjusted fair values of the assets acquired and liabilities assumed as of the acquisition date (in millions):

	Fair Value

Current assets, including cash and cash equivalents of $183	$	1,115
Property, plant and equipment, net		10,047
Goodwill		1,140
Regulatory assets		1,307
Other non-current assets		665
Total assets		14,274

Current liabilities, including short-term debt of $184 and current portion of long-term debt of $221		(1,283	)
Regulatory liabilities		(818	)
Pension and postretirement obligations		(830	)
Subsidiary and project debt, less current portion		(3,762	)
Deferred income taxes		(1,606	)
Other non-current liabilities		(855	)
Total liabilities		(9,154	)

Net assets acquired	$	5,120

Certain transition activities, pursuant to established plans, were undertaken as PacifiCorp was integrated into the Company. Costs, relating primarily to employee termination activities, have been incurred associated with such transition activities, which were completed as of March 31, 2007. The finalization of certain integration plans resulted in adjustments to the purchase price allocation for the acquired assets and assumed liabilities of PacifiCorp. Qualifying severance costs accrued during the three-month period ended March 31, 2007, and the period from the acquisition date to December 31, 2006, totaled $7 million and $41 million, respectively. Accrued severance costs were $34 million and $31 million as of March 31, 2007 and December 31, 2006, respectively.

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, 2005, and provides information for the years ended December 31 (in millions):

	2006		2005

Operating revenue	$	11,453	$	10,405

Net income	$	1,060	$	863

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 each period presented.

(4)	Property, Plant and Equipment, Net

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

	Depreciation
	Life	2007			2006

Regulated assets:
Utility generation, distribution and transmission system	5-85 years	$	30,369		$	27,687
Interstate pipeline assets	3-67 years		5,484			5,329
			35,853			33,016
Accumulated depreciation and amortization			(12,280	)		(11,872	)
Regulated assets, net			23,573			21,144

Non-regulated assets:
Independent power plants	10-30 years		680			1,184
Other assets	3-30 years		650			586
			1,330			1,770
Accumulated depreciation and amortization			(427	)		(844	)
Non-regulated assets, net			903			926

Net operating assets			24,476			22,070
Construction in progress			1,745			1,969
Property, plant and equipment, net		$	26,221		$	24,039

Substantially all of the construction in progress as of December 31, 2007 and 2006 relates to the construction of regulated assets.

Northern Natural Gas entered into a purchase and sale agreement for the West Hugoton non-strategic section of its interstate pipeline system in the fourth quarter of 2005. As a result of entering into the purchase and sale agreement, Northern Natural Gas recognized a non-cash impairment charge of $29 million ($18 million after-tax) to write down the carrying value of the asset to its fair value. The fair value was determined based on the agreed sale price. The impairment charge is recorded in operating expense in the accompanying Consolidated Statements of Operations for the year ended December 31, 2005.

(5)	Jointly Owned Utility Plant

Under joint plant 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 plant 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 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, 2007 (dollars in millions):

					Accumulated		Construction
	Company		Plant in		Depreciation/		Work-in-
	Share		Service		Amortization		Progress

PacifiCorp:
Jim Bridger Nos. 1-4	67	%	$	965	$	482	$	13
Wyodak	80			329		168		1
Hunter No. 1	94			304		146		1
Colstrip Nos. 3 and 4	10			243		118		1
Hunter No. 2	60			192		87		1
Hermiston (1)	50			170		37		2
Craig Nos. 1 and 2	19			167		77		1
Hayden No. 1	25			44		20		1
Foote Creek	79			37		13		-
Hayden No. 2	13			27		14		-
Other transmission and distribution plants	Various			80		20		2
Total PacifiCorp				2,558		1,182		23

MidAmerican Energy:
Walter Scott, Jr. Unit No. 4	60	%		634		10		-
Louisa Unit No. 1	88			750		352		1
Walter Scott, Jr. Unit No. 3	79			345		227		86
Quad Cities Unit Nos. 1 and 2	25			320		149		9
Ottumwa Unit No. 1	52			264		147		3
George Neal Unit No. 4	41			169		123		-
George Neal Unit No. 3	72			142		105		2
Transmission facilities	Various			169		46		-
Total MidAmerican Energy				2,793		1,159		101

Total			$	5,351	$	2,341	$	124

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

(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):

	Average
	Remaining Life	2007		2006

Deferred income taxes (1)	31 years	$	680	$	666
Unrealized loss on regulated derivatives (2)	8 years		276		266
Employee benefit plans (3)	11 years		274		625
Asset retirement obligations	15 years		47		46
Computer systems development costs	4 years		36		45
Other	Various		190		179
Total		$	1,503	$	1,827

(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)	Amounts represent net unrealized losses related to derivative contracts included in rates.

(3)	Amounts represent unrecognized components of benefit plans’ funded status that are recoverable in rates when recognized in net periodic benefit cost.

The Company had regulatory assets not earning a return or earning less than the stipulated return as of December 31, 2007 and 2006 of $1.3 billion and $1.7 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):

	Average
	Remaining Life	2007		2006

Cost of removal accrual (1) (2)	31 years	$	1,198	$	1,164
Employee benefit plans (3)	14 years		173		141
Asset retirement obligations (1)	31 years		148		133
Deferred income taxes	33 years		36		48
Iowa electric settlement accrual (1)	1 year		17		259
Unrealized gain on regulated derivatives	1 year		-		22
Other	Various		57		72
Total		$	1,629	$	1,839

(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 electric utility assets in accordance with accepted regulatory practices.

(3)	Amounts represent unrecognized components of benefit plans’ funded status that are to be returned to customers in future periods when recognized in net periodic benefit cost.

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. 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 such 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.

The settlement agreements also each provide that revenues associated with Iowa retail electric returns on equity within specified ranges will be shared with customers and that the portion assigned to customers will be recorded as a regulatory liability. The following table summarizes the ranges of Iowa electric returns on equity subject to revenue sharing under each settlement agreement, 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	Method to be Used to
Date Approved	Years	Equity Subject	Revenues	Settle Liability to
by the IUB	Covered	to Sharing	Within Range	Customers

December 21, 2001	2001 - 2005	12% - 14%	50%	Credits against the cost of new generation plant in Iowa
		Above 14%	83.33%	Credits against the cost of new generation plant in Iowa

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 as 2006 - 2010	Credits to customer bills in 2012

April 18, 2006	2012	Same as 2006 - 2010	Credits to customer bills in 2013

July 27, 2007	2013	Same as 2006 - 2010 (1)	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 operating income in excess of electric returns on equity allowed by the IUB as a result of the rate case.

The regulatory liabilities created by the settlement agreements have been and are currently recorded as a regulatory charge in depreciation and amortization expense when the liability is accrued. As a result of the credits applied to generating plant balances when the related plant is placed in service, depreciation expense is reduced over the life of the plant. On June 1, 2007, WSEC Unit 4 was placed in service. Accordingly, the January 1, 2007 balance of the revenue sharing liability of $264 million, plus the related interest accrued in 2007, was applied against the cost of WSEC Unit 4 in utility generation, distribution and transmission system.

Refund Matters

Kern River

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 load factors to be used in calculating rates for the vintage system. The FERC determined that a 100% load factor should be used in the rate calculation rather than the 95% load factor requested by Kern River. The FERC also rejected a 3% inflation factor for certain operating expenses and a shorter useful life for certain plant. Kern River and other parties filed their requests for rehearing of the initial order on November 20, 2006. Kern River submitted its compliance filing, which sets forth compliance rates in accordance with the initial order, on December 18, 2006. A final order on the request for rehearing and compliance filing is not expected until after the FERC finalizes its proposed policy statement that addresses the inclusion of master limited partnerships in the proxy group used to determine a pipeline’s allowed return on equity. Rate refunds will be due within 30 days after a final order on Kern River’s rate case is issued. 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. Since that time, Kern River has recorded a provision for estimated refunds. As a result of the October 19, 2006 order, additional customer billings and the accrual of interest, the liability for rates subject to refund increased $78 million during 2006 to $107 million as of December 31, 2006. As of December 31, 2007, the liability for rates subject to refund was $191 million.

Oregon Senate Bill 408

In October 2007, PacifiCorp filed its first tax report 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 an annual tax report with the Oregon Public Utility Commission (“OPUC”). PacifiCorp’s filing indicates that in 2006, PacifiCorp paid $33 million more in federal, state and local taxes than was collected in rates from its retail customers. PacifiCorp proposes to amortize $27 million of the surcharge over a one year period, which would result in an average price increase of 3%. If the OPUC issues an order providing for recovery in excess of $27 million and allows the deferral of the excess, the portion not yet recovered will be tracked in a balancing account accruing interest at PacifiCorp’s weighted cost of capital. The deferred amount, if any, would be addressed in a subsequent SB 408 filing. The 2006 tax report is currently being challenged during the 180-day procedural schedule that follows the date of the filing, with rates potentially effective June 2008. PacifiCorp expects to file its 2007 tax report under SB 408 during the fourth quarter of 2008. PacifiCorp has not recorded any amounts related to either the 2006 tax report or the 2007 expected filing.

(7)	Investments

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

	2007			2006

Guaranteed investment contracts	$	397		$	587
Nuclear decommissioning trust funds		276			259
Mine reclamation trust funds		112			110
Auction rate securities		73			26
Other		52			68
		910			1,050
Less current portion		(410	)		(221	)
Total noncurrent investments	$	500		$	829

Noncurrent investments are included in deferred charges, investments and other assets 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, 2007 and 2006 and for the three years in the period ended December 31, 2007, respectively.

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%) with 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.

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, 2007, 54% of the fair value of the trusts’ funds was invested in domestic common equity securities, 22% in domestic corporate debt securities and the remainder in investment grade municipal and U.S. Treasury bonds. As of December 31, 2006, 56% 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, 2007 and 2006, 52% and 56%, respectively, of the fair value of the trust’s funds was invested in equity securities with the remainder invested in debt securities.

The Company has invested in AAA-rated interest bearing auction rate securities with remaining maturities of 9 to 29 years. These auction rate securities normally provide liquidity via an auction process that resets the applicable interest rate at predetermined calendar intervals, usually every 28 days or less. Interest on these securities has been paid on the scheduled auction dates. During the third and fourth quarters of 2007, auctions for the $73 million of the Company’s investments in auction rate securities failed. The failures resulted in the interest rate on these investments resetting at higher levels. Although there is no current liquid market for the auction rate securities, the Company believes the underlying creditworthiness of the repayment sources for these securities’ principal and interest has not materially deteriorated. Therefore, the fair value of these investments approximates the carrying amount as of December 31, 2007.

(8)	Short-Term Borrowings

Short-term borrowings consist of the following as of December 31 (in millions):

	2007		2006
MEHC	$	-	$	152
PacifiCorp		-		397
MidAmerican Energy		86		-
CE Electric UK		44		-
HomeServices		-		3
Total short-term debt	$	130	$	552

MEHC

MEHC has a $600 million unsecured credit facility expiring in July 2012. The credit facility has a variable interest rate based on the London Interbank Offered Rate (“LIBOR”) plus 0.195%, which varies based on MEHC’s credit ratings for its senior unsecured long-term debt securities, or a base rate, at MEHC’s option. The credit facility supports letters of credit for the benefit of certain subsidiaries and affiliates. As of December 31, 2007, MEHC had no borrowings outstanding under its credit facility and had letters of credit issued under the credit agreement totaling $46 million. As of December 31, 2006, the outstanding balance of the credit facility totaled $152 million, at an interest rate of 5.57%, and letters of credit issued under the credit agreement totaled $60 million. The related 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

At December 31, 2007, PacifiCorp had $1.5 billion available under its unsecured revolving credit facilities. During 2007, PacifiCorp entered into an unsecured revolving credit facility with total bank commitments of $700 million available through October 23, 2012. Under PacifiCorp’s previously existing unsecured revolving credit facility, $800 million is available through July 6, 2011 and $760 million is available from July 7, 2011 through July 6, 2012. Each credit facility includes a variable interest rate borrowing option based on LIBOR plus 0.195% that varies based on PacifiCorp’s credit ratings for its senior unsecured long-term debt securities and supports PacifiCorp’s commercial paper program. As of December 31, 2007, PacifiCorp had no borrowings outstanding under either credit facility. As of December 31, 2006, PacifiCorp had $397 million of commercial paper arrangements outstanding at an average interest rate of 5.3% and no borrowings outstanding under its revolving credit agreement. 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 a $500 million unsecured revolving credit facility expiring in July 2012. The credit facility has a variable interest rate based on the LIBOR plus 0.115% that varies based on MidAmerican Energy’s credit ratings for its senior unsecured long-term debt securities and supports MidAmerican Energy’s $380 million commercial paper program and its variable rate pollution control revenue obligations. MidAmerican Energy had $86 million of commercial paper arrangements outstanding as of December 31, 2007, at an average rate of 4.46%, and no borrowings outstanding under its revolving credit agreement as of December 31, 2007 and 2006. The related 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.

CE Electric UK

CE Electric UK has a £100 million unsecured revolving credit facility expiring in April 2010. The facility carries a variable interest rate based on sterling LIBOR plus 0.25% to 0.40% that varies based on its credit ratings. As of December 31, 2007, the outstanding balance of the credit facility totaled $44 million, at an interest rate of 5.961%, and there were no borrowings outstanding under the facility as of December 31, 2006. The related 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 can not exceed 2.5 to 1.0.

100

CE Electric UK also has a £15 million unsecured, uncommitted line of credit, which was not drawn on as of December 31, 2007 and 2006. The interest rate of this uncommitted line of credit as of December 31, 2007 is variable based on sterling LIBOR plus 0.40%.

HomeServices

HomeServices has a $125 million unsecured senior revolving credit facility expiring in December 2010. The facility carries a variable interest rate based on the prime lending rate or LIBOR, at HomeServices’ option, plus 0.5% to 1.125%, that varies based on HomeServices’ total debt ratio. The spread was 0.5% as of December 31, 2007 and 2006. As of December 31, 2007 and 2006 there were no borrowings outstanding under the facility. The related 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.

(9)	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		2007		2006
4.625% Senior Notes, due 2007	$	-	$	-	$	200
7.63% Senior Notes, due 2007		-		-		350
3.50% Senior Notes, due 2008		450		450		450
7.52% Senior Notes, due 2008		550		550		547
5.875% Senior Notes, due 2012		500		500		500
5.00% Senior Notes, due 2014		250		250		250
8.48% Senior Notes, due 2028		475		483		483
6.125% Senior Notes, due 2036		1,700		1,699		1,699
5.95% Senior Notes, due 2037		550		547		-
6.50% Senior Notes, due 2037		1,000		992		-
Total MEHC Senior Debt	$	5,475	$	5,471	$	4,479

(10)	MEHC Subordinated Debt

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

	Par Value		2007		2006
CalEnergy Capital Trust II-6.25%, due 2012	$	105	$	96	$	94
CalEnergy Capital Trust III-6.5%, due 2027		270		208		208
MidAmerican Capital Trust I-11%, due 2010		227		227		318
MidAmerican Capital Trust II-11%, due 2012		194		194		237
MidAmerican Capital Trust III-11%, due 2011		400		400		500
Total MEHC Subordinated Debt	$	1,196	$	1,125	$	1,357

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 $284 million.

101

The MidAmerican Capital Trusts 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, 2007, 2006 and 2005 was $108 million, $134 million and $157 million, respectively. Interest expense on the CalEnergy Capital Trusts for the years ended December 31, 2007, 2006 and 2005 was $28 million, $27 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.

(11)	Subsidiary and Project 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, all of MidAmerican Energy’s gas and non-Iowa electric utility properties and Northern Natural Gas) are pledged or encumbered to support or otherwise provide the security for their own project or 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 and projects 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, 2007, 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 and projects consists of the following, including fair value adjustments and unamortized premiums and discounts, as of December 31 (in millions):

	Par Value		2007		2006
PacifiCorp	$	5,173	$	5,167	$	4,131
MidAmerican Funding		700		654		651
MidAmerican Energy		2,477		2,471		1,821
Northern Natural Gas		950		950		800
Kern River		1,016		1,016		1,091
CE Electric UK		2,403		2,562		2,776
CE Casecnan		69		68		105
Leyte Projects		-		-		19
Cordova Funding		190		188		192
HomeServices		22		21		28
Total Subsidiary and Project Debt	$	13,000	$	13,097	$	11,614

102

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		2007		2006
First mortgage bonds:
4.3% to 9.2%, due through 2012	$	1,169	$	1,169	$	1,294
5.0% to 8.8%, due 2013 to 2017		442		441		441
8.1% to 8.5%, due 2018 to 2022		175		175		175
6.7% to 8.2%, due 2023 to 2026		249		249		249
7.7% due 2031		300		299		299
5.3% to 6.3%, due 2034 to 2037		2,050		2,047		847
Pollution-control revenue obligations:
Variable rate series (2007-3.5% to 3.8%, 2006-3.9% to 4.0%):
Due 2013, secured by first mortgage bonds (1)		41		41		41
Due 2014 to 2025 (1)		325		325		325
Due 2024, secured by first mortgage bonds (1)		176		176		176
3.4% to 5.7%, due 2014 to 2025, secured by first mortgage bonds		184		183		183
6.2%, due 2030		13		13		13
Mandatorily Redeemable Preferred Stock, due 2007		-		-		38
Capital lease obligations - 10.4% to 14.8%, due through 2036		49		49		50
	$	5,173	$	5,167	$	4,131

(1)	Interest rates fluctuate based on various rates, primarily on certificate of deposit rates, interbank borrowing rates, prime rates or other short-term market rates.

As of December 31, 2007, PacifiCorp had $518 million of standby letters of credit and standby bond purchase agreements available to provide credit enhancement and liquidity support for variable-rate pollution-control revenue bond obligations.

MidAmerican Funding

The components of MidAmerican Funding’s senior notes and bonds consist of the following, including fair value adjustments, as of December 31 (dollars in millions):

	Par Value		2007		2006
6.339% Senior Notes, due 2009	$	175	$	172	$	170
6.75% Senior Notes, due 2011		200		200		200
6.927% Senior Bonds, due 2029		325		282		281
Total MidAmerican Funding	$	700	$	654	$	651

MidAmerican Funding’s subsidiaries must make payments on their own indebtedness before making distributions to MidAmerican Funding. The distributions are also subject to utility regulatory restrictions agreed to by MidAmerican Energy in March 1999, whereby it committed to the IUB to use commercially reasonable efforts to maintain an investment grade rating on its long-term debt and to maintain a common equity to total capitalization ratio above 42%, except under circumstances beyond its control. MidAmerican Energy’s common equity to total capitalization ratio is not allowed to decline below 39% for any reason. If the ratio declines below the defined threshold, MidAmerican Energy must seek the approval of a reasonable utility capital structure from the IUB. MidAmerican Energy’s ability to issue debt could also be restricted. As of December 31, 2007, MidAmerican Energy’s common equity to total capitalization ratio, computed on a basis consistent with the commitment, exceeded the minimum threshold.

103

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		2007		2006
Pollution control revenue obligations:
6.10% Series, due 2007	$	-	$	-	$	1
5.95% Series, due 2023, secured by general mortgage bonds		29		29		29
Variable rate series (2007-3.51%, 2006-3.97%):
Due 2016 and 2017		38		38		38
Due 2023, secured by general mortgage bonds		28		28		28
Due 2023		7		7		7
Due 2024		35		35		35
Due 2025		13		13		13
Notes:
5.65% Series, due 2012		400		400		-
5.125% Series, due 2013		275		275		274
4.65% Series, due 2014		350		350		350
5.95% Series, due 2017		250		249		-
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		1
Total MidAmerican Energy	$	2,477	$	2,471	$	1,821

Northern Natural Gas

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

	Par Value		2007		2006
6.75% Senior Notes, due 2008	$	150	$	150	$	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
5.80% Senior Notes, due 2037		150		150		-
Total Northern Natural Gas	$	950	$	950	$	800

Kern River

The components of Kern River’s term notes are due in monthly installments and consist of the following as of December 31 (dollars in millions):

	Par Value		2007		2006
6.676% Senior Notes, due 2016	$	361	$	361	$	389
4.893% Senior Notes, due 2018		655		655		702
Total Kern River	$	1,016	$	1,016	$	1,091

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, 2007 and 2006.

104

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		2007		2006
6.995% Senior Notes, due 2007	$	-	$	-	$	235
6.496% Yankee Bonds, due 2008		281		281		281
8.875% Bearer Bonds, due 2020 (1)		198		232		231
9.25% Eurobonds, due 2020 (1)		397		481		482
7.25% Sterling Bonds, due 2022 (1)		397		425		417
7.25% Eurobonds, due 2028 (1)		368		388		384
5.125% Bonds, due 2035 (1)		397		391		389
5.125% Bonds, due 2035 (1)		297		296		292
CE Gas Credit Facility, 7.94% and 7.62% (1)		68		68		65
Total CE Electric UK	$	2,403	$	2,562	$	2,776

(1)	The par values for these debt instruments are denominated in sterling and have been converted to U.S. dollars at the applicable exchange rate.

CE Casecnan

CE Casecnan Water and Energy Company, Inc. (“CE Casecnan”) has 11.95% Senior Secured Series B Bonds, due in 2010 with a par value of $69 million. The outstanding balance of these bonds, including fair value adjustments, as of December 31, 2007 and 2006 was $68 million and $105 million, respectively.

Cordova Funding

Cordova Funding Corporation’s (“Cordova Funding”) senior secured bonds are due in semi-annual installments and consist of the following, including fair value adjustments, as of December 31 (dollars in millions):

		Par Value				2007				2006
8.48% - 9.07% Senior Secured Bonds, due 2019		$	190			$	188			$	192

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.

HomeServices

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

	Par Value		2007		2006
7.12% Senior Notes, due 2010	$	15	$	14	$	19
Other		7		7		9
Total HomeServices	$	22	$	21	$	28

105

Annual Repayments of Long-Term Debt

The annual repayments of MEHC and subsidiary and project debt for the years beginning January 1, 2008 and thereafter, excluding fair value adjustments and unamortized premiums and discounts, are as follows (in millions):

	2008		2009		2010		2011		2012		Thereafter		Total

MEHC senior debt	$	1,000	$	-	$	-	$	-	$	500	$	3,975	$	5,475
MEHC subordinated debt		234		234		189		143		126		270		1,196
PacifiCorp		414		140		17		589		19		3,994		5,173
MidAmerican Funding		-		175		-		200		-		325		700
MidAmerican Energy		1		-		-		-		400		2,076		2,477
Northern Natural Gas		150		-		-		250		300		250		950
Kern River		73		75		79		81		81		627		1,016
CE Electric UK		281		-		13		9		46		2,054		2,403
CE Casecnan		38		14		17		-		-		-		69
Cordova Funding		4		6		9		9		10		152		190
HomeServices		5		11		5		-		-		1		22
Totals	$	2,200	$	655	$	329	$	1,281	$	1,482	$	13,724	$	19,671

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

	2007			2006

Balance, January 1	$	423		$	208
PacifiCorp acquisition		-			212
Revisions		19			(17	)
Additions		6			4
Retirements		(49	)		(5	)
Accretion		23			21
Balance, December 31	$	422		$	423

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 statutes mandate that mine property be restored consistent with specific standards and the approved reclamation plan. PacifiCorp is incurring expenditures for both ongoing and final reclamation. The fair value of PacifiCorp’s estimated mine reclamation costs, principally the Jim Bridger mine, was $115 million and $141 million as of December 31, 2007 and 2006, respectively, and is the asset retirement obligation for these mines. PacifiCorp has established trusts for the investment of funds for the Jim Bridger mine. The fair value of the assets held in trusts was $117 million and $110 million as of December 31, 2007 and 2006, respectively, and is reflected in other current assets and deferred charges, investments and other assets in the Consolidated Balance Sheets.

106

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. The fair value of MidAmerican Energy’s share of estimated Quad Cities Station decommissioning costs was $150 million and $142 million as of December 31, 2007 and 2006, 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 $276 million and $259 million as of December 31, 2007 and 2006, respectively, and is reflected in deferred charges, investments and other assets in the Consolidated Balance Sheets.

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 $1.20 billion and $1.16 billion as of December 31, 2007 and 2006, respectively.

(13)	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, 2007 and 2006. 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 aggregate total the holders of all preferred securities outstanding as of December 31, 2007 and 2006, are entitled to upon involuntary bankruptcy is $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, 2007 and 2006.

(14)	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 over-the-counter 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.

107

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

												Accumulated
									Regulatory			Other
	Derivative Net Assets (Liabilities)								Net 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.

The following table summarizes the various derivative mark-to-market positions included in the Consolidated Balance Sheet as of December 31, 2006 (in millions):

												Accumulated
									Regulatory			Other
	Derivative Net Assets (Liabilities)								Net Assets			Comprehensive
	Assets		Liabilities			Total			(Liabilities)			(Income) Loss (1)

Commodity	$	467	$	(740	)	$	(273	)	$	247		$	6
Interest rate		13		-			13			-			(13	)
Foreign currency		4		(149	)		(145	)		(3	)		149
	$	484	$	(889	)	$	(405	)	$	244		$	142

Current	$	236	$	(271	)	$	(35	)
Non-current		248		(618	)		(370	)
Total	$	484	$	(889	)	$	(405	)

(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 forwards, futures, options, swap and other over-the-counter 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 regulatory net assets or liabilities.

MidAmerican Energy also uses futures, options and swap agreements to economically hedge gas commodity prices for physical delivery to nonregulated customers. MidAmerican Energy also enters into forward physical supply contracts and swap agreements to economically hedge electricity commodity prices for physical delivery to nonregulated customers. Nonregulated retail physical electricity contracts are considered normal purchases or sales and gains and losses on such contracts are recognized when settled. All other nonregulated gas and electric contracts are recorded at fair value.

108

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. During 2006, CE Gas recognized $14 million of unrealized losses on derivative contracts that became ineffective due to its inability to effectively forecast the associated hedged 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 liabilities. As of December 31, 2007, the Company had cash flow hedges with expiration dates through October 2013. For the year ended December 31, 2007, hedge ineffectiveness was insignificant. As of December 31, 2007, $4 million of pre-tax net unrealized gains 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. CE Electric UK has entered into certain currency rate swap agreements with large multi-national financial institutions for its U.S. dollar denominated senior notes and Yankee bonds. As of December 31, 2006, the swap agreements effectively converted the U.S. dollar fixed interest rate to a fixed rate in sterling for $237 million of 6.995% senior notes and $281 million of 6.496% Yankee bonds outstanding. The swap agreement for $237 million of senior notes expired with the maturity of the senior notes on December 30, 2007, and the swap agreement for $281 million of Yankee bonds expired with the maturity of the Yankee bonds on February 25, 2008. The estimated fair value of these swap agreements as of December 31, 2007 and 2006 was a liability of $106 million and $149 million, respectively, based on quotes from the counterparties to these instruments and represents the estimated amount that the Company would expect to pay if these agreements were terminated.

Interest Rate Risk

The Company may enter into contractual agreements to hedge exposure to interest rate risk. In September 2006, MEHC entered into a treasury rate lock agreement in the notional amount of $1.55 billion to protect against an increase in interest rates on future long-term debt issuances. As of December 31, 2006, the fair value of the treasury rate lock agreement was $12 million. The financings occurred on May 11, 2007 and August 28, 2007, and MEHC received a total of $32 million, which is being amortized as a reduction to interest expense over the term of the related financings. In May 2005, MEHC entered into a treasury rate lock agreement in the notional amount of $1.6 billion to protect against an increase in interest rates on future long-term debt issuances. The financing occurred on March 24, 2006 and MEHC received $53 million, which is being amortized as a reduction to interest expense over the term of the related financing.

(15)	Income Taxes

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

	2007			2006			2005
Current:
Federal	$	147		$	6		$	36
State		38			5			5
Foreign		141			135			74
		326			146			115
Deferred:
Federal		188			249			57
State		(6	)		-			10
Foreign		(41	)		21			67
		141			270			134

Investment tax credit, net		(11	)		(9	)		(4	)
Total	$	456		$	407		$	245

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

	2007		2006		2005

Federal statutory rate	35	%	35	%	35	%
General business tax credits	(3	)	(3	)	(2	)
State taxes, net of federal tax effect	2		2		2
Equity income, net of dividends received deduction	-		-		1
Tax effect of foreign income	(2	)	(2	)	(2	)
Change in UK corporate income tax rate	(4	)	-		-
Effects of ratemaking	-		1		(1	)
Other items, net	-		(2	)	(1	)
Effective tax rate	28	%	31	%	32	%

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.

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

	2007			2006
Deferred tax assets:
Regulatory liabilities	$	473		$	452
Employee benefits		161			362
Accruals not currently deductible for tax purposes		154			141
Net operating loss (“NOL”) and credit carryforwards		130			201
Revenue subject to refund		72			41
Uncertain tax positions		32			-
Nuclear reserve and decommissioning		24			23
Revenue sharing accruals		8			110
Other		223			172
Total deferred tax assets		1,277			1,502
Valuation allowance		(12	)		(20	)
Total deferred tax assets, net		1,265			1,482

Deferred tax liabilities:
Property, plant and equipment, net		(3,654	)		(3,562	)
Regulatory assets		(984	)		(1,095	)
Other		(60	)		(122	)
Total deferred tax liabilities		(4,698	)		(4,779	)
Net deferred tax liability	$	(3,433	)	$	(3,297	)

Reflected as:
Deferred income taxes-current asset	$	162		$	152
Deferred income taxes-non-current liability		(3,595	)		(3,449	)
	$	(3,433	)	$	(3,297	)

As of December 31, 2007, the Company has available unused NOL and credit carryforwards that may be applied against future taxable income and that expire at various intervals between 2008 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.”

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As of December 31, 2007, net unrecognized tax benefits totaled $127 million which included $104 million 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 and tax positions related to acquired companies. Recognition of these tax benefits, other than applicable interest and penalties, would not affect the Company’s effective tax rate.

(16)	Other Income and Expense

Other Income

Other income, as shown on the Consolidated Statements of Operations, for the years ending December 31 consists of the following (in millions):

	2007		2006		2005

Gain on Mirant bankruptcy claim	$	3	$	89	$	-
Allowance for equity funds used during construction		85		57		26
Gains on sales of non-strategic assets and investments		1		55		23
Corporate-owned life insurance income		12		13		5
Other		21		25		21
Total other income	$	122	$	239	$	75

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. Kern River claimed $210 million in damages due to the rejection of the Mirant Agreement. 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.

(17)	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.

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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 common equity of MEHC upon any requests authorized from time to time by the Board of Directors of MEHC. The proceeds of any such equity contribution shall only be used for the purpose of (a) paying when due MEHC’s debt obligations and (b) funding the general corporate purposes and capital requirements of the Company’s regulated subsidiaries. Berkshire Hathaway will have up to 180 days to fund any such request. The Berkshire Equity Commitment will expire on February 28, 2011.

On March 2, 2006, MEHC amended its Articles of Incorporation to (i) increase the amount of its common stock authorized for issuance to 115,000,000 shares and (ii) no longer provide for the authorization to issue any preferred stock of 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 (see Note 3). 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, 2007. 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.

There were 200,000 common stock options exercised during the year ended December 31, 2005 having an exercise price of $29.01 per share. There were 1,848,329 common stock options outstanding and exercisable with a weighted-average exercise price of $30.75 per share as of December 31, 2005. 1,145,000 of the outstanding and exercisable common stock options had exercise prices ranging from $15.94 to $34.69 per share, a weighted-average exercise price of $28.11 per share and a remaining contractual life of 2.25 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 4.25 years. There were 2,048,329 common stock options outstanding and exercisable with a weighted-average exercise price of $30.58 per share as of December 31, 2004.

(18)	Commitments and Contingencies

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 and believes it is in material compliance with current environmental requirements.

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Air Quality

Litigation was filed in the federal district court for the southern district of New York seeking to require reductions of carbon dioxide emissions from generating facilities of five large electric utilities. The court dismissed the suit, ruling that critical issues affecting the United States, like greenhouse gas emissions reductions, are not the domain of the courts and should be resolved by the executive branch of the federal government and the U.S. Congress. This ruling has been appealed to the Second Circuit Court of Appeals. The outcome of climate change litigation and federal and state climate change initiatives cannot be determined at this time; however, adoption of stringent limits on greenhouse gas emissions could significantly impact the Company’s fossil-fueled facilities and, therefore, its financial results.

The Environmental Protection Agency’s regulation of certain pollutants under the Clean Air Act, and its failure to regulate other pollutants, is being challenged by various lawsuits brought by both individual state attorney generals and environmental groups. To the extent that these actions may be successful in imposing additional and/or more stringent regulation of emissions on fossil-fueled facilities in general and PacifiCorp’s and MidAmerican Energy’s facilities in particular, such actions could significantly impact the Company’s fossil-fueled facilities and, therefore, its financial results.

Accrued Environmental Costs

The Company is fully or partly responsible for environmental remediation that results from other than normal operations 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 expense is 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, 2007 and 2006 was $38 million and $50 million, respectively, and is included in other liabilities and other long-term accrued liabilities on the Consolidated Balance Sheets. Environmental remediation liabilities that result from the normal operation of a long-lived asset and that are associated with the retirement of those assets is accounted for as an asset retirement obligation.

Hydroelectric Relicensing

PacifiCorp’s hydroelectric portfolio consists of 47 plants 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. Several of PacifiCorp’s hydroelectric plants are in some stage of relicensing with the FERC. Hydroelectric relicensing and the related environmental compliance requirements and litigation are subject to uncertainties. PacifiCorp expects that future costs relating to these matters may be significant and will consist primarily of additional relicensing costs, operations and maintenance expense, and capital expenditures. Electricity generation reductions may result from the additional environmental requirements. PacifiCorp had incurred $89 million and $79 million in costs as of December 31, 2007 and 2006, respectively, for ongoing hydroelectric relicensing, which are included in construction in progress and reflected in property, plant and equipment, net in the Consolidated Balance Sheet.

In February 2004, PacifiCorp filed with the FERC a final application for a new license to operate the 169 MW (nameplate rating) Klamath hydroelectric project 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 to operate under annual licenses until the new operating license is issued. As part of the relicensing process, the United States Departments of Interior and Commerce filed proposed licensing terms and conditions with the FERC in March 2006, which proposed that PacifiCorp construct upstream and downstream fish passage facilities at the Klamath hydroelectric project’s four mainstem dams. In April 2006, PacifiCorp filed alternatives to the federal agencies’ proposal and requested an administrative hearing to challenge some of the federal agencies’ factual assumptions supporting their proposal for the construction of the fish passage facilities. A hearing was held in August 2006 before an administrative law judge. The administrative law judge issued a ruling in September 2006 generally supporting the federal agencies’ factual assumptions. In January 2007, the United States Departments of Interior and Commerce filed modified terms and conditions consistent with March 2006 filings and rejected the alternatives proposed by PacifiCorp. PacifiCorp is prepared to meet and implement the federal agencies’ terms and conditions as part of the project’s relicensing. However, PacifiCorp expects to continue in settlement discussions with various parties in the Klamath Basin area who have intervened with the FERC licensing proceeding to try to achieve a mutually acceptable outcome for the project.

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Also, as part of the relicensing process, the FERC is required to perform an environmental review. In September 2006, the FERC issued its draft environmental impact statement on the Klamath hydroelectric project license. PacifiCorp filed comments on the draft statement by the close of the public comment period on December 1, 2006. Subsequently, 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 hydroelectric project’s impact on endangered species under the proposed new FERC license. The United States Fish and Wildlife Service asserts the hydroelectric project is currently not covered by previously issued biological opinions, and that consultation under the Endangered Species Act is required by the issuance of annual license renewals. PacifiCorp disputes these assertions, and believes federal case law is clear that consultation on annual FERC licenses is not required. PacifiCorp will need to obtain water quality certifications from Oregon and California prior to the FERC issuing a final license. PacifiCorp currently has applications pending before each state.

In the relicensing of the Klamath hydroelectric project, PacifiCorp had incurred $48 million and $42 million in costs as of December 31, 2007 and 2006, respectively, which are included in construction in progress and reflected in property, plant and equipment, net in 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.

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 compliant 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. A five-day trial on the liability phase is scheduled to begin on April 2008. The remedy-phase trail has not yet been set. 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

114

Unconditional Purchase Obligations

The Company has the following unconditional purchase obligations as of December 31, 2007 (in millions) which are not reflected in the Consolidated Balance Sheet:

	Minimum payments required for
											2013 and
	2008		2009		2010		2011		2012		After		Total
Contract type:
Coal, electricity and natural gas contract commitments	$	1,637	$	1,249	$	1,040	$	656	$	399	$	3,542	$	8,523
Purchase obligations		440		54		31		11		15		51		602
Owned hydroelectric commitments		39		50		59		87		39		538		812
Operating leases, easements and maintenance contracts		100		80		67		54		40		208		549
	$	2,216	$	1,433	$	1,197	$	808	$	493	$	4,339	$	10,486

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 stations. 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/or exchange agreements. Included in the purchased electricity payments are any power purchase agreements that meet the definition of an operating lease.

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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.

Owned Hydroelectric Commitments

As part of the hydroelectric relicensing process, PacifiCorp entered into settlement agreements with various interested parties that resulted in commitments for environmental mitigation and enhancement measures over the life of the licenses.

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 $122 million for 2007, $117 million for 2006 and $79 million for 2005.

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. The Company is generally required to obtain state regulatory commission approval prior to guaranteeing debt or obligations of other parties. The following represent the material indemnification obligations of the Company as of December 31, 2007.

PacifiCorp

PacifiCorp has made certain commitments related to the decommissioning or reclamation of certain jointly owned facilities and mine sites. The decommissioning commitments require PacifiCorp to pay a proportionate share of the decommissioning costs based upon percentage of ownership. The mine reclamation commitments require PacifiCorp to pay the mining entity a proportionate share of the mine’s reclamation costs based on the amount of coal purchased by PacifiCorp. In the event of default by any of the other joint participants, PacifiCorp potentially may be obligated to absorb, directly or by paying additional sums to the entity, a proportionate share of the defaulting party’s liability. PacifiCorp has recorded its estimated share of the decommissioning and reclamation commitments.

(19)	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 multi-employer and joint trust union plans to which PacifiCorp contributes on behalf of certain bargaining units. MidAmerican Energy sponsors defined benefit pension plans that cover substantially all employees of MEHC and its domestic energy subsidiaries other than PacifiCorp. MidAmerican Energy’s pension plans included 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:

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 in 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.

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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 will be eligible to receive enhanced benefits under PacifiCorp’s and MidAmerican Energy’s defined contribution plans.

Effective December 31, 2007, Local Union No. 659 of the International Brotherhood of Electrical Workers (“Local 659”) elected to cease participation in PacifiCorp’s noncontributory defined benefit pension plan and participate only in PacifiCorp’s defined contribution plan with enhanced benefits. As a result of this election, the Local 659 participants’ benefits were frozen as of December 31, 2007.

MidAmerican Energy’s other postretirement benefit plan was amended for non-union employees on July 1, 2004, and substantially all union participants on July 1, 2006. As a result, non-union employees hired after June 30, 2004, and union employees hired after June 30, 2006, are not eligible for postretirement benefits other than pensions. The plan, as amended, provides retiree medical accounts for participants to which the Company makes fixed contributions until the employee’s retirement. Participants will use such accounts to pay a portion of their medical premiums during retirement.

Plan assets and benefit obligations for PacifiCorp-sponsored plans were measured as of September 30, 2007 and MidAmerican Energy-sponsored plans were measured as of December 31, 2007. 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.

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

	Pension									Other Postretirement
	2007			2006			2005			2007			2006			2005

Service cost	$	55		$	49		$	26		$	14		$	14		$	7
Interest cost		111			97			36			47			40			14
Expected return on plan assets		(112	)		(95	)		(38	)		(40	)		(30	)		(10	)
Net amortization		28			27			4			21			20			4
Net periodic benefit cost	$	82		$	78		$	28		$	42		$	44		$	15

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

	Pension						Other Postretirement
	2007			2006			2007			2006

Plan assets at fair value, beginning of year	$	1,548		$	613		$	532		$	191
PacifiCorp acquisition		-			829			-			293
Employer contributions		86			81			58			47
Participant contributions		-			-			20			16
Actual return on plan assets		175			137			56			35
Benefits paid and other		(171	)		(112	)		(63	)		(50	)
Plan assets at fair value, end of year	$	1,638		$	1,548		$	603		$	532

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 $159 million and $148 million as of December 31, 2007 and 2006, respectively. These assets are not included in the plan assets in the above table, but are reflected in the Consolidated Balance Sheet. The portion of the pension projected benefit obligation, included in the table below, related to the SERPs was $155 million and $161 million as of December 31, 2007 and 2006, respectively.

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

	Pension						Other Postretirement
	2007			2006			2007			2006

Benefit obligation, beginning of year	$	2,038		$	678		$	824		$	250
PacifiCorp acquisition		-			1,341			-			581
Service cost		55			49			14			14
Interest cost		111			97			47			40
Participant contributions		-			-			20			16
Plan amendments		(130	)		4			-			(16	)
Actuarial (gain) loss		(90	)		(19	)		(49	)		(11	)
Benefits paid and other		(171	)		(112	)		(63	)		(50	)
Benefit obligation, end of year	$	1,813		$	2,038		$	793		$	824
Accumulated benefit obligation, end of year	$	1,702		$	1,807

PacifiCorp’s noncontributory defined benefit pension plan’s accumulated benefit obligation exceeded the fair value of the plan’s assets by $46 million and $228 million as of December 31, 2007 and 2006, respectively. Additionally, the accumulated benefit obligations related to the SERPs totaled $152 million and $156 million as of December 31, 2007 and 2006, respectively.

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
	2007			2006			2007			2006

Plan assets at fair value, end of year	$	1,638		$	1,548		$	603		$	532
Less - Benefit obligations, end of year		1,813			2,038			793			824
Funded status		(175	)		(490	)		(190	)		(292	)
Contributions after the measurement date but before year-end		-			-			12			27
Amounts recognized in the Consolidated Balance Sheets	$	(175	)	$	(490	)	$	(178	)	$	(265	)

Amounts recognized in the Consolidated Balance Sheets:
Deferred charges, investments and other assets	$	77		$	66		$	-		$	-
Other current liabilities		(11	)		(11	)		-			(1	)
Other long-term accrued liabilities		(241	)		(545	)		(178	)		(264	)
Amounts recognized	$	(175	)	$	(490	)	$	(178	)	$	(265	)

Amounts not yet recognized as components of net periodic benefit cost:
Net loss	$	108		$	292		$	70		$	144
Prior service cost (credit)		(109	)		18			13			16
Net transition obligation		3			5			63			76
Total	$	2		$	315		$	146		$	236

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

							Accumulated
							Other
	Regulatory			Regulatory			Comprehensive
	Asset			Liability			Loss			Total
Pension
Balance, beginning of year	$	423		$	(122	)	$	14		$	315
Net gain arising during the year		(123	)		(26	)		(6	)		(155	)
Prior service cost arising during the year		(129	)		-			(1	)		(130	)
Net amortization		(25	)		-			(3	)		(28	)
Total		(277	)		(26	)		(10	)		(313	)
Balance, end of year	$	146		$	(148	)	$	4		$	2

							Deferred
	Regulatory			Regulatory			Income
	Asset			Liability			Taxes			Total
Other Postretirement
Balance, beginning of year	$	190		$	(25	)	$	71		$	236
Net gain arising during the year		(54	)		-			(15	)		(69	)
Net amortization		(21	)		-			-			(21	)
Total		(75	)		-			(15	)		(90	)
Balance, end of year	$	115		$	(25	)	$	56		$	146

The net loss, prior service cost and net transition obligation that will be amortized in 2008 into net periodic benefit cost are estimated to be as follows (in millions):

	Net		Prior Service			Net Transition
	Loss		Cost			Obligation		Total

Pension benefits	$	15	$	(10	)	$	2	$	7
Other postretirement benefits		1		3			13		17
Total	$	16	$	(7	)	$	15	$	24

119

Plan Assumptions

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

	Pension			Other Postretirement
	2007	2006	2005	2007	2006	2005
	%	%	%	%	%	%
Benefit obligations as of the measurement date:
PacifiCorp-sponsored plans -
Discount rate	6.30	5.85	-	6.45	6.00	-
Rate of compensation increase	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
Rate of compensation increase	4.50	4.50	5.00	N/A	N/A	N/A

Net benefit cost for the years ended December 31:
PacifiCorp-sponsored plans -
Discount rate	5.76	5.75	-	6.00	5.75	-
Expected return on plan assets	8.00	8.50	-	8.00	8.50	-
Rate of compensation increase	4.00	4.00	-	N/A	N/A	N/A
MidAmerican Energy-sponsored plans -
Discount rate	5.75	5.75	5.75	5.75	5.75	5.75
Expected return on plan assets	7.50	7.00	7.00	7.50	7.00	7.00
Rate of compensation increase	4.50	5.00	5.00	N/A	N/A	N/A

	2007	2006
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	9.00%	10.00%
Health care cost trend rate assumed for next year – over 65	7.00%	8.00%
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	9.00%	8.00%
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	2010

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	$ 5	$ (4)
Effect on other postretirement benefit obligation	57	(48)

Contributions and Benefit Payments

Employer contributions to the pension and other postretirement plans are expected to be $77 million and $41 million, respectively, for 2008. The Company’s policy is to contribute the minimum required amount to its pension plans and the net periodic cost to its other postretirement plans. The Pension Protection Act of 2006 changes funding rules beginning in 2008 and may have the effect of making minimum pension funding requirements more volatile than they have been historically. Accordingly, the Company continually evaluates its funding strategies.

120

The Company’s expected benefit payments to participants from its pension and other postretirement plans for 2008 through 2012 and for the five years thereafter are summarized below (in millions):

	Projected Benefit Payments
			Other Postretirement
	Pension		Gross		Medicare Subsidy		Net of Subsidy

2008	$	139	$	54	$	6	$	48
2009		139		57		7		50
2010		133		59		7		52
2011		137		63		7		56
2012		148		64		9		55
2013-17		828		364		53		311

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. The weighted-average return on assets assumption is based on historical performance for the types of assets in which the plans invest.

PacifiCorp’s other postretirement plan assets are composed of three different trust accounts. The 401(h) account is invested in the same manner as the assets of the pension plan. Each of the two Voluntary Employees’ Beneficiaries Association (“VEBA”) Trusts has its own investment allocation strategies. PacifiCorp’s asset allocation as of December 31 was as follows:

	Pension and Other Postretirement			VEBA Trusts
	2007	2006	Target	2007	2006	Target
	%	%	%	%	%	%

Equity securities	56	58	53-57	64	65	63-67
Debt securities	35	35	35	36	35	33-37
Other	9	7	8-12	-	-	-
Total	100	100		100	100

MidAmerican Energy’s asset allocation as of December 31 was as follows:

	Pension			Other Postretirement
	2007	2006	Target	2007	2006	Target
	%	%	%	%	%	%

Equity securities	69	70	65-75	52	52	60-80
Debt securities	24	24	20-30	46	47	25-35
Real estate and other	7	6	0-10	2	1	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.

121

Defined Contribution Plans

The Company sponsors defined contribution pension plans (401(k) plans) and an employee savings plan 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 were $36 million, $34 million and $17 million for 2007, 2006 and 2005, 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.

Plan assets and obligations for the UK Plan are measured as of December 31, 2007. 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 was as follows (in millions):

	2007			2006			2005

Service cost	$	24		$	18		$	15
Interest cost		95			78			77
Expected return on plan assets		(118	)		(101	)		(97	)
Net amortization		31			34			25
Net periodic benefit cost	$	32		$	29		$	20

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

	2007			2006

Plan assets at fair value, beginning of year	$	1,795		$	1,420
Employer contributions		71			66
Participant contributions		7			6
Actual return on plan assets		87			167
Benefits paid		(79	)		(70	)
Foreign currency exchange rate changes		24			206
Plan assets at fair value, end of year	$	1,905		$	1,795

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

	2007			2006

Benefit obligation, beginning of year	$	1,813		$	1,559
Service cost		24			18
Interest cost		95			78
Participant contributions		7			6
Benefits paid		(79	)		(70	)
Experience loss and change of assumptions		(64	)		4
Foreign currency exchange rate changes		24			218
Benefit obligation, end of year	$	1,820		$	1,813
Accumulated benefit obligation, end of year	$	1,725		$	1,724

122

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

	2007		2006

Plan assets at fair value, end of year	$	1,905	$	1,795
Less - Benefit obligation, end of year		1,820		1,813
Funded status	$	85	$	(18	)

Amounts recognized in the Consolidated Balance Sheets:
Deferred charges, investments and other assets	$	85	$	-
Other long-term accrued liabilities		-		(18	)
Amounts recognized	$	85	$	(18	)

Amounts not yet recognized as components of net periodic benefit cost:
Net loss	$	442	$	500
Prior service cost		11		13
Total	$	453	$	513

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 year ended December 31, 2007 is as follows (in millions):

Balance, beginning of year	$	513
Net gain arising during the year		(34	)
Net amortization		(31	)
Foreign currency exchange rate changes		5
Total		(60	)
Balance, end of year	$	453

The net loss and prior service cost that will be amortized from accumulated other comprehensive income (loss) in 2008 into net periodic benefit cost is estimated to be $19 million and $2 million, respectively.

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:

	2007	2006	2005
	%	%	%
Benefit obligations as of December 31:
Discount rate	5.90	5.20	4.75
Rate of compensation increase	3.45	3.25	2.75

Net benefit cost for the years ended December 31:
Discount rate	5.20	4.75	5.25
Expected return on plan assets	7.00	7.00	7.00
Rate of compensation increase	3.25	2.75	2.75

123

Contributions and Benefit Payments

The expected benefit payments to participants in the UK Plan for 2008 through 2012 and for the five years thereafter are summarized below (in millions):

2008	$	80
2009		83
2010		85
2011		87
2012		89
2013-2017		486

Employer contributions to the UK Plan, including £23 million for the funding deficiency, are currently expected to be £48 million for 2008.

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
	2007	2006	Target
	%	%	%

Equity securities	41	52	40
Debt securities	46	37	50
Real estate and other	13	11	10
Total	100	100

(20)	Fair Value of Financial Instruments

The carrying amounts of cash and cash equivalents, short-term investments, receivables, payables, accrued liabilities and short-term borrowings approximates fair value because of the short-term maturity or frequent remarketing of these instruments. Derivative instruments are recorded at their fair values, which are based upon published market indexes as adjusted for other market factors such as location pricing differences or internally developed models. Substantially all investments are carried at their fair values, which are based on quoted market prices.

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):

	2007				2006
	Carrying Amount		Fair Value		Carrying Amount		Fair Value

Long-term debt	$	19,693	$	20,525	$	17,449	$	18,293

124

(21)	Supplemental Cash Flow Information

The summary of supplemental cash flow information for the years ending December 31 follows (in millions):

	2007		2006		2005

Interest paid	$	1,230	$	1,076	$	861
Income taxes paid (1)	$	287	$	132	$	61

(1)	2007 includes $133 million of income taxes paid to Berkshire Hathaway and 2006 is net of $20 million of income taxes received from Berkshire Hathaway.

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

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

	2007			2006

Unrecognized amounts on retirement benefits, net of tax of $(128) and $(160)	$	(329	)	$	(367	)
Foreign currency translation adjustment		356			326
Fair value adjustment on cash flow hedges, net of tax of $38 and $21		57			29
Unrealized gains on marketable securities, net of tax of $4 and $3		6			5
Total accumulated other comprehensive income (loss), net	$	90		$	(7	)

125

(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):

	Year Ended December 31,
	2007			2006			2005
Operating revenue:
PacifiCorp	$	4,258		$	2,939		$	-
MidAmerican Energy		4,267			3,453			3,166
Northern Natural Gas		664			634			569
Kern River		404			325			324
CE Electric UK		1,079			928			884
CalEnergy Generation-Foreign		220			336			312
CalEnergy Generation-Domestic		32			32			34
HomeServices		1,500			1,702			1,868
Corporate/other (1)		(48	)		(48	)		(41	)
Total operating revenue	$	12,376		$	10,301		$	7,116

Depreciation and amortization:
PacifiCorp	$	496		$	368		$	-
MidAmerican Energy		269			275			269
Northern Natural Gas		58			57			30
Kern River		80			56			62
CE Electric UK		187			138			136
CalEnergy Generation-Foreign		50			80			90
CalEnergy Generation-Domestic		8			8			9
HomeServices		20			32			18
Corporate/other (1)		(18	)		(7	)		(6	)
Total depreciation and amortization	$	1,150		$	1,007		$	608

Operating income:
PacifiCorp	$	917		$	528		$	-
MidAmerican Energy		514			421			381
Northern Natural Gas		308			269			209
Kern River		277			217			204
CE Electric UK		555			516			484
CalEnergy Generation-Foreign		142			230			185
CalEnergy Generation-Domestic		12			14			15
HomeServices		33			55			125
Corporate/other (1)		(70	)		(130	)		(74	)
Total operating income		2,688			2,120			1,529
Interest expense		(1,320	)		(1,152	)		(891	)
Capitalized interest		54			40			17
Interest and dividend income		105			73			58
Other income		122			239			75
Other expense		(10	)		(13	)		(23	)
Total income from continuing operations before income tax expense, minority interest and preferred dividends of subsidiaries and equity income	$	1,639		$	1,307		$	765

126

	Year Ended December 31,
	2007			2006			2005
Interest expense:
PacifiCorp	$	314		$	224		$	-
MidAmerican Energy		179			155			138
Northern Natural Gas		58			50			53
Kern River		75			74			73
CE Electric UK		241			215			218
CalEnergy Generation-Foreign		13			20			31
CalEnergy Generation-Domestic		17			18			18
HomeServices		2			2			2
Corporate/other (1)		285			233			173
MEHC subordinated debt		136			161			185
Total interest expense	$	1,320		$	1,152		$	891

Income tax expense:
PacifiCorp	$	240		$	139		$	-
MidAmerican Energy		111			94			91
Northern Natural Gas		106			85			71
Kern River		78			87			50
CE Electric UK		47			100			93
CalEnergy Generation-Foreign		56			68			56
CalEnergy Generation-Domestic		-			1			(1	)
HomeServices		15			30			56
Corporate/other (1)		(197	)		(197	)		(171	)
Total income tax expense	$	456		$	407		$	245

Capital expenditures:
PacifiCorp	$	1,518		$	1,114		$	-
MidAmerican Energy		1,300			758			701
Northern Natural Gas		225			122			125
Kern River		15			3			7
CE Electric UK		422			404			342
CalEnergy Generation-Foreign		1			2			1
CalEnergy Generation-Domestic		-			-			1
HomeServices		26			18			19
Corporate/other (1)		5			2			-
Total capital expenditures	$	3,512		$	2,423		$	1,196

	As of December 31,
	2007			2006			2005
Property, plant and equipment, net:
PacifiCorp	$	11,849		$	10,810		$	-
MidAmerican Energy		5,737			5,034			4,448
Northern Natural Gas		1,856			1,655			1,585
Kern River		1,772			1,843			1,891
CE Electric UK		4,606			4,266			3,501
CalEnergy Generation-Foreign		303			352			431
CalEnergy Generation-Domestic		223			230			242
HomeServices		76			67			62
Corporate/other (1)		(201	)		(218	)		(245	)
Total property, plant and equipment, net	$	26,221		$	24,039		$	11,915

127

	As of December 31,
	2007		2006		2005
Total assets:
PacifiCorp	$	16,049	$	14,970	$	-
MidAmerican Energy		9,377		8,651		8,003
Northern Natural Gas		2,488		2,277		2,245
Kern River		1,943		2,057		2,100
CE Electric UK		6,802		6,561		5,743
CalEnergy Generation-Foreign		479		559		643
CalEnergy Generation-Domestic		544		545		555
HomeServices		709		795		814
Corporate/other (1)		825		32		268
Total assets	$	39,216	$	36,447	$	20,371

(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 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, 2007 and 2006 (in millions):

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

Balance, January 1, 2006	$	-		$	2,118		$	327		$	34	$	1,207		$	72		$	398		$	4,156
Acquisitions		1,118			-			-			-		-			-			34			1,152
Reclassification of intangible assets (1)		-			-			-			-		-			-			(45	)		(45	)
Foreign currency translation adjustment		-			-			-			-		126			-			-			126
Other goodwill adjustments (2)		-			(10	)		(26	)		-		(5	)		(1	)		(2	)		(44	)
Balance, December 31, 2006		1,118			2,108			301			34		1,328			71			385			5,345
Acquisitions (3)		22			-			-			-		-			-			9			31
Adoption of FIN 48		(10	)		(4	)		-			-		(1	)		-			-			(15	)
Foreign currency translation adjustment		-			-			-			-		14			-			-			14
Other goodwill adjustments (2)		(5	)		4			(26	)		-		(6	)		-			(3	)		(36	)
Balance, December 31, 2007	$	1,125		$	2,108		$	275		$	34	$	1,335		$	71		$	391		$	5,339

(1)	During 2006, the Company reclassified $45 million of identifiable intangible assets from goodwill that principally related to trade names at HomeServices that were determined to have finite lives.

(2)	Other goodwill adjustments relate primarily to income tax adjustments.

(3)	The $22 million adjustment to PacifiCorp’s goodwill was due to the completion of the purchase price allocation in the first quarter of 2007.

128

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 are effective in timely alerting them to material information relating to the Company required to be included in the Company’s periodic SEC filings. There has been no change in the Company’s internal control over financial reporting during the quarter ended December 31, 2007 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, 2007 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, 2007.

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 21, 2008

Item 9B.

Other Information

On February 25, 2008, David L. Sokol, Chairman and Chief Executive Officer of MEHC, Gregory E. Abel, President and Chief Operating Officer of MEHC, and Patrick J. Goodman, Senior Vice President and Chief Financial Officer of MEHC, each executed an amended and restated employment agreement effective as of January 1, 2008. Each employment agreement is filed as an exhibit to this Annual Report on Form 10-K.

129

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, 2008, with respect to the current directors and executive officers of MEHC:

DAVID L. SOKOL, 51, Chairman of the Board of Directors and Chief Executive Officer. Mr. Sokol has been the Chief Executive Officer since 1993, the Chairman of the Board of Directors since 1994 and a director since 1991. Mr. Sokol joined MEHC in 1991.

GREGORY E. ABEL, 45, President and Director. Mr. Abel has been the President and Chief Operating Officer since 1998 and a director since 2000. Mr. Abel joined MEHC in 1992. Mr. Abel is also a director of PacifiCorp.

PATRICK J. GOODMAN, 41, 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, 49, 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, 44, 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, 77, 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., 76, 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, 58, 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.

130

Item 11.

Executive Compensation

Compensation Discussion and Analysis

Compensation Philosophy and Overall Objectives

We believe that the compensation paid to each of our Chairman 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 CEO and President and Chief Operating Officer, or President, 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 CEO and the President. The peer companies for 2007 were American Electric Power Company, Inc., Consolidated Edison, Inc., Dominion Resources, Inc., Duke Energy Corporation, Edison International, Energy Future Holdings Corp. (formerly TXU 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 CEO makes recommendations regarding the President’s base salary, the CEO and President together make recommendations regarding the other NEOs’ base salaries, and the Compensation Committee must approve all annual merit increases, which take effect on January 1 of each year. The Compensation Committee alone sets our CEO’s base salary. Base salaries for all NEOs increased on average by 2.5% effective January 1, 2007. An increase or decrease in base pay may also result from a promotion or other significant change in a NEO’s responsibilities during the year. Ms. Sammon received a base pay increase in May 2007 when she was appointed our Chief Administrative Officer. There were no other base salary changes for our NEOs during the year after the January 1, 2007 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.

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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 CEO and President recommend annual incentive awards for the other NEOs to the Compensation Committee prior to the last committee meeting of each year, traditionally held in the fourth quarter. The CEO recommends the annual incentive award for the President, and the Compensation Committee determines the CEO’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 approved by the President, as delegated by the CEO and the Compensation Committee. In 2007, awards were granted to Mr. Anderson and Ms. Sammon in recognition of support provided relative to certain non-routine projects. Although both Messrs. Sokol and Abel are eligible for performance awards, neither has been granted an award in the past five 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 76 other employees, participate in this plan, while our CEO and President 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 CEO and President 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. The value is 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 the 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.

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.

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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.

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.

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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)(6)
Position	Year	($)		($)		($)		($)		($)		($)

David L. Sokol, Chairman and	2007	$	850,000	$	4,000,000	$	-	$	-	$	213,038	$	5,063,038
Chief Executive Officer	2006		850,000		2,500,000		26,250,000		344,000		281,735		30,225,735

Gregory E. Abel, President	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	2007		320,000		889,306		-		51,000		47,868		1,308,174
President and Chief Financial	2006		307,500		1,025,453		-		89,000		51,248		1,473,201
Officer

Douglas L. Anderson, Senior Vice	2007		291,500		788,705		-		20,000		29,372		1,129,577
President and General Counsel	2006		283,000		802,560		-		28,000		45,101		1,158,661

Maureen E. Sammon, Senior Vice	2007		196,659		452,903		-		17,000		20,291		686,853
President and Chief	2006		185,000		434,035		-		29,000		20,207		668,242
Administrative Officer

______________

(1)	Consists of annual cash incentive awards earned pursuant to the PIP for our NEOs, as well as performance awards earned related to non-routine projects and the vesting of LTIP awards and associated earnings for Messrs. Goodman and Anderson and Ms. Sammon. The breakout for 2007 is as follows:

	PIP		Performance Awards		LTIP

David L. Sokol	$	4,000,000	$	-	$	-
Gregory E. Abel		4,000,000		-		-
Patrick J. Goodman		340,000		-		549,306	($101,306 in investment profits)
Douglas L. Anderson		325,000		25,000		438,705	($89,474 in investment profits)
Maureen E. Sammon		155,000		25,000		272,903	($55,353 in investment profits)

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LTIP 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 the 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. Because the amounts to be paid out may increase or decrease depending on investment performance, the ultimate payouts are undeterminable.

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 CEO, President and Compensation Committee. In 2007, the gross award and per-point value were adjusted to eliminate the earnings benefit of a reduction in the United Kingdom corporate income tax rate from 30% to 28% and for failing to achieve certain non-financial performance factors.

	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 CEO and President, 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 Incremental Profit Sharing Plan, or IPSP, for Messrs. Sokol and Abel. While the initial 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 $51,935, personal use of corporate aircraft of $114,981 and vacation payouts of $29,422; Mr. Abel - life insurance premiums of $36,218 and personal use of corporate aircraft of $318,241; Mr. Goodman - life insurance premiums of $19,149 and vacation payouts of $12,384; and Mr. Anderson - vacation payouts of $17,938.

(5)	Any amounts voluntarily deferred by the NEO, if applicable, are included in the appropriate column in the summary compensation table.

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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, 2007:

			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

Patrick J. Goodman	-	-	-		-	-

Douglas L. Anderson	-	-	-		-	-

Maureen E. Sammon	-	-	-		-	-

______________

(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 2007. Accordingly, we have omitted the Stock Awards columns from the Outstanding Equity Awards at Fiscal Year-End Table.

Option Exercises and Stock Vested

The following table sets forth information regarding stock options exercised by Mr. Abel during the year ended December 31, 2007:

	Option Awards (1)
	Number of
	shares acquired	Value realized
	on exercise	on exercise
Name	(#)	($)

Gregory E. Abel	370,000	54,765,332

______________

(1)

We have not issued stock options or other forms of equity-based awards since March 2000. All stock options relate to previously granted options held by Mr. Abel and were fully vested prior to 2007. Accordingly, we have omitted the Stock Awards columns from the Option Exercises and Stock Vested Table.

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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, 2007:

		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	$	5,692,000	$	-
	MidAmerican Energy Company Retirement Plan	n/a		186,000		-

Gregory E. Abel	SERP	n/a		3,727,000		-
	MidAmerican Energy Company Retirement Plan	n/a		176,000		-

Patrick J. Goodman	SERP	13 years		432,000		-
	MidAmerican Energy Company Retirement Plan	9 years		169,000		-

Douglas L. Anderson	MidAmerican Energy Company Retirement Plan	9 years		176,000		-

Maureen E. Sammon	MidAmerican Energy Company Retirement Plan	21 years		199,000		-

______________

(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 nine 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, 2007, 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 15-year certain and life 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 5.71% in 2007, 4.20% in 2008 and 5.00% thereafter; cash balance conversion rates (not applicable in 2007) of 4.75% in 2008, 5.00% in 2009, 5.25% in 2010, 5.50% in 2011 and 5.75% in 2012 and thereafter; a discount rate of 6.00%; an expected retirement age of 65; and postretirement mortality using the RP-2000 M/F tables.

The SERP provides additional retirement benefits to participants. The SERP 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.

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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, 2007:

									Aggregate
	Executive		Registrant		Aggregate		Aggregate		balance as of
	contributions		contributions		earnings		withdrawals/		December 31,
	in 2007 (1)		in 2007		in 2007		distributions		2007 (2)
Name	($)		($)		($)		($)		($)

David L. Sokol	$	-	$	-	$	-	$	-	$	-

Gregory E. Abel		-		-		56,424		329,285		1,005,654

Patrick J. Goodman		140,000		-		59,959		59,457		1,261,200

Douglas L. Anderson		469,024		-		33,886		-		1,434,116

Maureen E. Sammon		162,765		-		3,977		-		606,467

______________

(1)	The contribution amount shown for Mr. Goodman is included in the 2007 total compensation reported for him in the Summary Compensation Table and is not additional earned compensation. The contribution amounts shown for Mr. Anderson and Ms. Sammon include $200,208 and $113,579, respectively, earned towards their 2003 LTIP awards prior to 2007 and thus not included in the 2007 total compensation reported for them 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 due on that bonus or award. 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 monthly, 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 month.

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 a 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.

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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

Mr. Sokol’s employment agreement provides that we may terminate his employment with cause, in which case we must pay him any accrued but unpaid base salary and a bonus of not less than the minimum annual bonus as defined in his employment agreement. If termination is due to death, permanent disability or other than for cause, Mr. Sokol is entitled to receive an amount equal to three times the sum of his annual base salary then in effect and the greater of his minimum annual bonus or his average annual bonus for the two preceding years, plus continuation of his senior executive employee benefits (or the economic equivalent thereof) for three years. If Mr. Sokol resigns, we must pay him any accrued but unpaid base salary and a bonus of not less than the annual minimum bonus, unless he resigns for good reason, in which case he will receive the same benefits as if he were terminated other than for cause.

If Mr. Sokol relinquishes his position as Chief Executive Officer but offers to remain employed as the Chairman of the Board, he is to receive a special achievement bonus equal to two times the sum of his annual base salary then in effect and the greater of his minimum annual bonus or his average annual bonus for the two preceding years. This total payment as of December 31, 2007 is estimated at $8,200,000 (and is not included in the termination scenarios table below). He will also receive an annual salary of $750,000 and will be eligible for an annual bonus.

In the event Mr. Sokol has relinquished his position as Chief Executive Officer 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.

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 expires on August 21, 2009, but is extended automatically for additional one year terms thereafter subject to Mr. Sokol’s election to decline renewal at least 120 days prior to the then current expiration date or termination.

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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, 2007, and are payable as lump sums unless otherwise noted.

	Cash				Life				Benefits
Termination Scenario	Severance (2)		Incentive		Insurance (3)		Pension (4)		Continuation (5)		Excise Tax (6)

Retirement	$	-	$	-	$	-	$	9,390,000	$	-	$	-

Voluntary and Involuntary With Cause		4,000,000		-		-		9,390,000		-		-

Involuntary Without Cause, Company Breach and Disability		12,300,000		-		-		9,390,000		110,252		-


Death		12,300,000		-		1,667,786		8,673,000		110,252		-

Following Change in Position (1)		3,750,000		-		-		9,390,000		183,753		-

______________

(1)	The amounts shown in the Following Change in Position termination scenario are only applicable if the termination is due to death, disability or other than for cause.

(2)	The cash severance payments are determined in accordance with Mr. Sokol’s employment agreement.

(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. 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.

(5)	Includes health and welfare, life insurance and financial planning and tax preparation benefits for three years (five years in the case of termination following a change in position). 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 three year period (five year period in the case of termination following a change in position), with no offset by another employer. We will also continue to provide financial planning and tax preparation reimbursement, or the economic equivalent thereof, for three 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, the Company 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.

(6)	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.

140

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.

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, 2012, 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, 2008 for the agreement not to extend to August 6, 2013).

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, 2007, 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 With Cause	$	-	$	-	$	-	$	9,550,000	$	-	$	-


Involuntary Without Cause, Disability and Voluntary With Good Reason		7,750,000		-		-		9,550,000		38,596		-


Death		7,750,000		-		1,529,784		10,519,000		38,596		-

______________

(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 30-year certain annuity commencing immediately. Mr. Abel’s other termination scenarios are based on a 100% joint and survivor with 15-year certain annuity commencing at age 47.

(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, the Company 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.

141

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, 2009, 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.

142

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, 2007, 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	$	-	$	-	$	-	$	462,000	$	-	$	-

Involuntary With Cause		-		-		-		-		-		-

Involuntary Without Cause and Voluntary With Good Reason		2,771,546		-		-		462,000		14,030		1,099,888


Death		2,771,546		1,174,487		635,155		3,762,000		14,030		-

Disability		2,771,546		1,174,487		-		1,616,000		14,030		-

______________

(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.

143

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, 2007, 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 Without Cause	$	-	$	-	$	-	$	29,000	$	-	$	-


Death and Disability		-		859,086		-		29,000		-		-

______________

(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, 2007, 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 Without Cause	$	-	$	-	$	-	$	45,000	$	-	$	-


Death and Disability		-		538,689		-		45,000		-		-

______________

(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.

144

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, Sokol 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, 2008:

	Number of Shares	Percentage
Name and Address of Beneficial Owner (1)	Beneficially Owned (2)	Of Class (2)

Berkshire Hathaway (3)	66,063,061	88.25	%
Walter Scott, Jr. (4)	4,972,000	6.64	%
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)	6,271,269	8.30	%

(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 3,228,000 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.

145

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, 2008:

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	1,162	*
Class B	103	*
Gregory E. Abel (4)
Class A	-	-
Class B	6	*
Douglas L. Anderson
Class A	3	*
Class B	-	-
Warren E. Buffett (5)
Class A	350,000	32.36	%
Class B	2,564,355	18.30	%
Patrick J. Goodman
Class A	2	*
Class B	3	*
Marc D. Hamburg
Class A	-	-
Class B	-	-
Maureen E. Sammon
Class A	-	-
Class B	21	*
All directors and executive officers as a group (8 persons)
Class A	351,267	32.48	%
Class B	2,564,488	18.30	%

* 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, 2008, 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 12,661, 848 and 1,158, respectively, shares of Berkshire Hathaway Class A stock or 378,461, 25,351 and 34,615, 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 1.17% of the outstanding shares of Berkshire Hathaway Class A stock or 2.63% 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. On January 24, 2008, Mr. Sokol exchanged 629,931 shares of our common stock for 955 Berkshire Hathaway Class A shares and three Berkshire Hathaway Class B shares.

(5)	Mr. Buffett’s address is 1440 Kiewit Plaza, Omaha, Nebraska 68131.

146

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.

Under a subscription agreement with us, which expired in March 2007, Berkshire Hathaway had agreed to purchase, under certain circumstances, additional shares of 11% trust issued mandatorily redeemable preferred securities to be issued by our wholly owned subsidiary trust in the event that certain of our other outstanding trust preferred securities, which were outstanding prior to the closing of our acquisition by a private investor group on March 14, 2000, were tendered for conversion to cash by the current holders.

At December 31, 2007 and 2006, Berkshire Hathaway and its affiliates held 11% mandatorily redeemable preferred securities due from certain of our wholly owned subsidiary trusts with liquidation preferences of $821 million and $1.06 billion, respectively. Principal repayments and interest expense on these securities totaled $234 million and $108 million, respectively, during 2007.

On November 12, 2007, we issued 370,000 shares of our common stock, no par value, to Mr. Abel upon the exercise by Mr. Abel of 370,000 of his outstanding common stock options. The common stock options were exercisable at a weighted-average price of $26.99 per share and the aggregate exercise price paid by Mr. Abel was $10 million. This issuance was pursuant to a private placement and was exempt from the registration requirements of the Securities Act of 1933, as amended.

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 MEHC or their ownership of our common stock.

147

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):

	2007		2006

Audit Fees (1)	$	5.3	$	4.8
Audit-Related Fees (2)		0.5		0.8
Tax Fees (3)		0.3		0.3
All Other Fees		-		-
Total aggregate fees billed	$	6.1	$	5.9

(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 2007 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 Company’s 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”) which 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 the audit committee’s responsibilities to pre-approve services performed by the principal accountant to management.

148

PART IV

Item 15.

Exhibits and Financial Statement Schedules

(a)	Financial Statements and Schedules

	(i)	Financial Statements

		Financial Statements are included in Item 8.

	(ii)	Financial Statement Schedules

		See Schedule I on page 150.
		See Schedule II on page 153.

		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.

(c)	Financial statements required by Regulation S-X, which are excluded from the Annual Report by Rule 14a-3(b).

	Not applicable.

149

Schedule I

MidAmerican Energy Holdings Company

Parent Company Only

Condensed Balance Sheets

As of December 31, 2007 and 2006

(Amounts in millions)

	2007		2006

ASSETS
Current assets:
Cash and cash equivalents	$	765	$	3
Derivative contracts		-		12
Other current assets		4		5
Total current assets		769		20

Investments in and advances to subsidiaries and joint ventures		13,995		12,788
Equipment, net		34		33
Goodwill		1,278		1,276
Deferred charges, investments and other assets		135		145

Total assets	$	16,211	$	14,262

LIABILITIES AND SHAREHOLDERS’ EQUITY

Current liabilities:
Accounts payable and other current liabilities	$	167	$	151
Short-term debt		-		152
Current portion of senior debt		1,000		550
Current portion of subordinated debt		234		234
Total current liabilities		1,401		1,087

Other long-term accrued liabilities		121		104
Senior debt		4,471		3,929
Subordinated debt		891		1,123
Total liabilities		6,884		6,243

Minority interest		1		8

Shareholders’ equity:
Common stock-115 shares authorized, no par value, 75 shares and 74 shares issued and outstanding as of December 31, 2007 and 2006, respectively		-		-
Additional paid in capital		5,454		5,420
Retained earnings		3,782		2,598
Accumulated other comprehensive income (loss), net		90		(7	)
Total shareholders’ equity		9,326		8,011

Total liabilities and shareholders’ equity	$	16,211	$	14,262

The notes to the consolidated MEHC financial statements are an integral part of this financial statement schedule.

150

Schedule I

MidAmerican Energy Holdings Company

Parent Company Only (continued)

Condensed Statements of Operations

For the three years ended December 31, 2007

(Amounts in millions)

	2007		2006			2005

Revenues:
Equity in undistributed earnings of subsidiary companies and joint ventures	$	970	$	664		$	547
Dividends and distributions from subsidiary companies and joint ventures		483		592			257
Interest and other income		27		13			19
Total revenues		1,480		1,269			823

Costs and expenses:
General and administration		15		107			51
Depreciation and amortization		2		5			6
Interest		459		427			387
Total costs and expenses		476		539			444
Income before income taxes and minority interest		1,004		730			379
Income tax benefit		185		187			185
Minority interest		-		(1	)		(1	)
Net income	$	1,189	$	916		$	563

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 Cash Flows

For the three years ended December 31, 2007

(Amounts in millions)

	2007			2006			2005

Cash flows from operating activities	$	(204	)	$	(250	)	$	(154	)

Cash flows from investing activities:
(Increase) decrease in advances to and investments in subsidiaries and joint ventures		317			(4,708	)		204
Purchases of available-for-sale securities		(407	)		(148	)		(1,667	)
Proceeds from sale of available-for-sale securities		399			140			1,750
Other, net		19			-			18
Net cash flows from investing activities		328			(4,716	)		305
Cash flows from financing activities:
Proceeds from the issuances of common stock		10			5,132			-
Purchases of common stock		-			(1,750	)		-
Proceeds from senior debt		1,539			1,699			-
Repayments of subordinated debt		(234	)		(234	)		(189	)
Repayments of senior debt		(550	)		-			(260	)
Net (repayments of) proceeds from revolving credit facility		(152	)		101			51
Net repayment of affiliate notes		-			(22	)		(23	)
Other, net		25			41			6
Net cash flows from financing activities		638			4,967			(415	)

Net change in cash and cash equivalents		762			1			(264	)
Cash and cash equivalents at beginning of year		3			2			266
Cash and cash equivalents at end of year	$	765		$	3		$	2

The notes to the consolidated MEHC financial statements are an integral part of this financial statement schedule.

152

Schedule II

MIDAMERICAN ENERGY HOLDINGS COMPANY

CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS

FOR THE THREE YEARS ENDED DECEMBER 31, 2007

(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 2007	$	30	$	24	$	-	$	(32	)	$	22
Year ended 2006		21		19		11		(21	)		30
Year ended 2005		26		13		-		(18	)		21

Reserves Not Deducted From Assets (2) :
Year ended 2007	$	12	$	3	$	-	$	(3	)	$	12
Year ended 2006		12		3		-		(3	)		12
Year ended 2005		11		4		-		(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.

153

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 29 th day of February 2008.

	MIDAMERICAN ENERGY HOLDINGS COMPANY

	/s/ David L. Sokol*
	David L. Sokol
	Chairman of the Board 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,	February 29, 2008
David L. Sokol	Chief Executive Officer, and Director
	(principal executive officer)

/s/ Gregory E. Abel*	President, Chief Operating Officer and	February 29, 2008
Gregory E. Abel	Director


/s/ Patrick J. Goodman	Senior Vice President and	February 29, 2008
Patrick J. Goodman	Chief Financial Officer
	(principal financial and accounting
	officer)

/s/ Walter Scott, Jr.*	Director	February 29, 2008
Walter Scott, Jr.


/s/ Marc D. Hamburg*	Director	February 29, 2008
Marc D. Hamburg


/s/ Warren E. Buffett*	Director	February 29, 2008
Warren E. Buffett


* By: /s/ Douglas L. Anderson	Attorney-in-Fact	February 29, 2008
Douglas L. Anderson

154

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.

155

EXHIBIT INDEX

Exhibit No.

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	Second Supplemental Indenture, dated as of May 16, 2003, by and between MidAmerican Energy Holdings Company and The Bank of New York, Trustee, relating to the 3.50% Senior Notes due 2008 (incorporated by reference to Exhibit 4.3 to the MidAmerican Energy Holdings Company’s Registration Statement No. 333-105690 dated May 23, 2003).

4.4	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).

4.5	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).

4.6	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).

4.7	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).

4.8	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).

156

Exhibit No.

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 7.52% Senior Notes in the principal amount of $450,000,000 due 2008, and 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	Form of Third Supplemental Indenture, dated as of November 13, 1998, by and between MidAmerican Energy Holdings Company and IBJ Schroder Bank & Trust Company, Trustee, relating to the 7.52% Senior Notes in the principal amount of $100,000,000 due 2008 (incorporated by reference to the MidAmerican Energy Holdings Company Current Report on Form 8-K dated November 10, 1998).

4.12	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).

4.13	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).

4.14	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).

4.15	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).

4.16	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).

4.17	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).

4.18	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).

4.19	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).

4.20	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).

4.21	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).

157

Exhibit No.

4.22	General Mortgage Indenture and Deed of Trust, dated as of January 1, 1993, by and between Midwest Power Systems Inc. and Morgan Guaranty Trust Company of New York, Trustee (incorporated by reference to Exhibit 4(b)-1 to the Midwest Resources Inc. Annual Report on Form 10-K for the year ended December 31, 1992, Commission File No. 1-10654).

4.23	First Supplemental Indenture, dated as of January 1, 1993, by and between Midwest Power Systems Inc. and Morgan Guaranty Trust Company of New York, Trustee (incorporated by reference to Exhibit 4(b)-2 to the Midwest Resources Inc. Annual Report on Form 10-K for the year ended December 31, 1992, Commission File No. 1-10654).

4.24	Second Supplemental Indenture, dated as of January 15, 1993, by and between Midwest Power Systems Inc. and Morgan Guaranty Trust Company of New York, Trustee (incorporated by reference to Exhibit 4(b)-3 to the Midwest Resources Inc. Annual Report on Form 10-K for the year ended December 31, 1992, Commission File No. 1-10654).

4.25	Third Supplemental Indenture, dated as of May 1, 1993, by and between Midwest Power Systems Inc. and Morgan Guaranty Trust Company of New York, Trustee (incorporated by reference to Exhibit 4.4 to the Midwest Resources Inc. Annual Report on Form 10-K for the year ended December 31, 1993, Commission File No. 1-10654).

4.26	Fourth Supplemental Indenture, dated as of October 1, 1994, by and between Midwest Power Systems Inc. and Harris Trust and Savings Bank, Trustee (incorporated by reference to Exhibit 4.5 to the Midwest Resources Inc. Annual Report on Form 10-K for the year ended December 31, 1994, Commission File No. 1-10654).

4.27	Fifth Supplemental Indenture, dated as of November 1, 1994, by and between Midwest Power Systems Inc. and Harris Trust and Savings Bank, Trustee (incorporated by reference to Exhibit 4.6 to the Midwest Resources Inc. Annual Report on Form 10-K for the year ended December 31, 1994, Commission File No. 1-10654).

4.28	Sixth Supplemental Indenture, dated as of July 1, 1995, by and between Midwest Power Systems Inc. and Harris Trust and Savings Bank, Trustee (incorporated by reference to Exhibit 4.15 to the MidAmerican Energy Company Annual Report on Form 10-K for the year ended December 31, 1995, Commission File No. 1-11505).

4.29	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).

4.30	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).

4.31	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).

4.32	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).

158

Exhibit No.

4.33	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).

4.34	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).

4.35	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).

4.36	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).

4.37	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).

4.38	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).

4.39	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).

4.40	Fiscal Agency Agreement, dated as of September 4, 1998, by and between Northern Natural Gas Company and Chase Bank of Texas, National Association, Fiscal Agent, relating to the $150,000,000 in principal amount of the 6.75% Senior Notes due 2008 (incorporated by reference to Exhibit 10.69 to the MidAmerican Energy Holdings Company Quarterly Report on Form 10-Q for the quarter ended March 31, 2004).

4.41	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).

4.42	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).

4.43	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).

159

Exhibit No.

4.44	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).

4.45	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).

4.46	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).

4.47	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).

4.48	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).

4.49	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).

4.50	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).

4.51	£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).

4.52	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).

4.53	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).

160

Exhibit No.

4.54	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).

4.55	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).

4.56	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).

4.57	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).

4.58	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).

4.59	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).

4.60	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).

4.61	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).

4.62	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).

4.63	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).

4.64	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).

4.65	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).

161

Exhibit No.

4.66	Mortgage and Deed of Trust dated as of January 9, 1989, between PacifiCorp and JP Morgan Chase Bank (formerly known as 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 21 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


4.67	$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).

10.1	Amended and Restated Employment Agreement, dated February 25, 2008, by and between MidAmerican Energy Holdings Company and David L. Sokol.

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	Amended and Restated Employment Agreement, dated February 25, 2008, by and between MidAmerican Energy Holdings Company and Gregory E. Abel.

10.4	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).

162

Exhibit No.

10.5	Amended and Restated Employment Agreement, dated February 25, 2008, by and between MidAmerican Energy Holdings Company and Patrick J. Goodman.

10.6	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).

10.7	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).

10.8	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).

10.9	MidAmerican Energy Holdings Company Executive Voluntary Deferred Compensation Plan restated effective as of January 1, 2007.

10.10	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.

10.11	MidAmerican Energy Holdings Company Long-Term Incentive Partnership Plan as Amended and Restated January 1, 2007.

10.12	Summary of Key Terms of Compensation Arrangements with MidAmerican Energy Holdings Company Named Executive Officers and Directors.

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.

163

EXHIBIT 10.1

EXECUTION COPY

AMENDED AND RESTATED EMPLOYMENT AGREEMENT

This Amended and Restated Employment Agreement, dated as of February 25, 2008, amends and restates the employment agreement originally entered into as of August 21, 1995, as amended and restated as of May 10, 1999 and amended by Amendment No. 1 on March 14, 2000, and is by and between MidAmerican Energy Holdings Company (formerly California Energy Company, Inc. (“CalEnergy”), an Iowa corporation (the “Company”), and David L. Sokol (the “Executive”).

RECITALS

The Company desires to employ the Executive as its Chairman and Chief Executive Officer on the terms set forth in this Agreement, and the Executive desires to accept such employment.

Accordingly, the Company and the Executive agree as follows:

AGREEMENT

Section 1. Defined Terms . Terms used but not defined in this Agreement will have the meanings ascribed to them in Exhibit A to this Agreement.

Section 2. Employment .

(a) The Company will employ the Executive as, and the Executive will act as, the Chairman and Chief Executive Officer of the Company upon the terms set forth in this Agreement, for the Term of Employment, except that in the event the Executive relinquishes his position as Chief Executive Officer but offers to remain employed as Chairman of the Board of the Company pursuant to Section 7(c), the Executive will act solely as Chairman of the Board upon the terms set forth in this Agreement for the Term of Employment.

(b) The Executive’s primary place of employment will be Omaha, Nebraska.

(c) For so long as the Executive continues to serve as either Chairman or Chief Executive Officer of the Company, he shall have the right (i) to serve as a member of the Board, and (ii) to designate two other individuals as nominees for election to the Board.

Section 3. Duties .

(a) The Executive (i) will manage the business of the Company and supervise and direct the other officers of the Company and its employees, agents and representatives, and (ii) will perform and discharge such other duties, and will have such other authority, as are customary to his office. In performing such duties, the Executive will report directly to the Board of Directors.

(b) The Board will not reduce the title, office, duties or authority of the Executive in any material respect and will not require the Executive to relocate his residence from Omaha, Nebraska. During the Term of Employment, the Company will use its best efforts to cause the Executive to be nominated and elected to the Company’s Board of Directors.

(c) The Executive will act, without any compensation in addition to the compensation payable pursuant to this Agreement, as an officer of any subsidiary of the Company, or as a member of the board of directors of any subsidiary of the Company, if so appointed or elected.

(d) During the Term of Employment, the Executive (i) will devote his entire time, attention and energies during normal business hours to the business of the Company, and (ii) will not, without the Consent of the Board, perform any services for any other Person or engage in any other business or professional activity; provided, however, that in the event the Executive relinquishes his position as Chief Executive Officer but offers to remain employed as Chairman of the Board of the Company pursuant to Section 7(c), the foregoing items (i) and (ii) shall no longer apply and instead the Executive shall provide services to the Company as reasonably requested by the Chief Executive Officer or the Board and agrees to be available to provide such services for up to forty (40) hours during each month while this Agreement is in effect.

(e) Notwithstanding subsection (d), the Executive, without the Consent of the Board, may (i) perform the consulting duties contemplated in the letter agreement dated October 5, 1990, as it may be amended, by and among the Executive, Ogden Corporation and Ogden Projects, Inc., (ii) purchase securities issued by, or otherwise passively invest his personal or family assets in, any other company or business, and (iii) engage in governmental, political, educational or charitable activities, but only to the extent that those activities (A) are not inconsistent with any direction of the Board or any duties under this Agreement, and (B) do not interfere with the devotion by the Executive of his time, attention and energies during normal business hours to the business of the Company.

Section 4. Compensation .

(a) During the Term of Employment, the Company will pay the Executive a base salary at a minimum annual rate of seven hundred and fifty thousand dollars ($750,000), in substantially equal periodic payments in accordance with the Company’s practices for executive employees. Notwithstanding the foregoing, if the Executive relinquishes his position as Chief Executive Officer but offers to remain employed as Chairman of the Board of the Company pursuant to Section 7(c), the Company shall pay the Executive an annual salary in the amount of seven hundred and fifty thousand dollars ($750,000) for each 12-month period during the Term of Employment, payable in equal monthly installments on the first business day of the Company of each month during the Term of Employment.

(b) The Board will review the salary payable to the Executive at least annually beginning in the fourth fiscal quarter of 2008. The Board, in its discretion, may increase the salary of the Executive from time to time, but may not reduce the salary of the Executive below the amount set forth in subsection (a) above. The Board may issue the Executive stock options from time to time at its discretion.

(c) During the Term of Employment, the Company will pay the Executive an annual bonus, not later than ten calendar days after the end of the preceding fiscal year of the Company in an amount determined by the Board, by reference to the accomplishment by the Executive of goals established by the Board for the related fiscal year. The annual bonus paid to the Executive, however, will not be less than the Minimum Bonus. The Executive shall also be eligible to be paid other bonuses for each fiscal year as determined by the Board. The Executive’s annual bonus, together with all such other bonuses paid or payable for the fiscal year (including any amounts for which receipt is otherwise deferred pursuant to a plan or arrangement with the Company), is referred to herein as “Annual Bonus Compensation.” However, “Annual Bonus Compensation” shall not include the Earnings Per Share bonuses set forth in the letter of March 24, 2003 to Executive.

(d) If the Executive suffers a Disability which continues for more than 60 calendar days, the Company may elect to pay the Executive, for so long as the Disability continues, fifty (50) percent of the salary otherwise payable to the Executive under Section 4(a), and fifty (50) percent of the Minimum Bonus otherwise payable to the Executive pursuant to Section 4(c). Any such election shall be subject to and will not affect the rights of the Company or the Executive under Sections 7(a) (v) and 8(b) hereof.

(e) The Company will reimburse the Executive, subject to compliance by the Executive with the Company’s customary reimbursement practices, for all reasonable and necessary out-of-pocket expenses incurred by the Executive on behalf of the company in the course of its business.

(f) The Company may reduce any payments made to the Executive under this Agreement by any required federal, state or local government withholdings or deductions for taxes or similar charges, or otherwise pursuant to law, regulation or order.

(g) Any base salary payable to the Executive for any period of employment of less than a year during the Term of Employment will be reduced to reflect the actual number of days of employment during the period except as provided in Section 8 (b).

Section 5. Other Benefits .

(a) During the Term of Employment (including the Term of Employment after Executive has relinquished his position as Chief Executive Officer), the Executive and his family may participate in and receive benefits under any employee benefit plan which the Company makes generally available to its employees and their families, including any pension, life insurance, medical benefits, dental benefits or disability plan, but only to the extent that the Executive or his family otherwise satisfies the standards established for participation in the plan.

(b) The Executive may take up to six weeks of vacation during each full calendar year during the Term of employment, without loss of compensation or other benefits under this Agreement.

Section 5A. Supplemental Retirement Benefits .

(a) Effective as of March 12, 1999, the closing date of the merger between the Company and MidAmerican Energy Company, resulting in the creation of MidAmerican Energy Holdings Company (the “Merger Date”), the Executive became a participant in the MidAmerican Energy Company Supplemental Retirement Plan for Designated Officers (the “SERP”).

(b) The Executive shall receive fully vested years of participation credit under the SERP (for all purposes, including vesting and benefit accrual) for all years of service (or portions thereof) performed at the Company prior to the Merger Date, as provided on Exhibit B attached hereto.

(c) The Executive shall be entitled to an Early Retirement Benefit Payment Option under the SERP pursuant to which he shall commence receiving benefits under the SERP after the Executive’s separation from service or disability on or after attaining age 47, which payments shall be calculated pursuant to the SERP but which shall be no less than as provided on Exhibit C hereto (including for purposes of the following sentence). In the event of the Executive’s death, benefits shall be paid pursuant to Section 6.4 of the SERP; provided, however, that any payment due under Section 6.4(a) of the SERP shall continue for the remaining lifetime of the Executive’s surviving “Spouse” (as defined in the SERP) or for 360 months if the Executive dies without a surviving Spouse; and further provided, however, that any payment due under Section 6.4(b) of the SERP shall be payable without regard to the two-thirds and fifty percent limitations contained therein.

(d) In addition, the Executive shall be entitled to the following under the SERP:

(i) for purposes of determining years of participation credit, the Executive shall be credited with additional years of participation (or portions thereof) equal to the difference between age 65 and the Executive’s age (in years or portions thereof) on January 27, 2000, the date of a change in control of the Company, and

(ii) any benefits under the SERP not fully vested on January 27 became fully vested as of such date.

(e) Since a "rabbi trust" has previously been established in order to provide security for the payment of benefits to Executive pursuant to the SERP, the Company shall have a continuing obligation to deposit into the rabbi trust an amount which, with the expected earnings thereon from reasonably prudent and conservative investments (as confirmed by a certificate of a national accounting firm of recognized standing which is independent of the Company) shall be sufficient to satisfy the ultimate benefit obligations to Executive pursuant to the SERP.

(f) A general release of claims under the SERP shall not be required of the Executive in order to receive benefits thereunder.

(g) The Executive’s entitlement to benefits under the SERP shall be nonforfeitable and, Section 6.5 of the SERP notwithstanding, shall not be adversely affected in any way upon termination of the Executive’s employment for Cause.

Section 6. Confidentiality and Post-Employment Restrictions .

(a) The Executive acknowledges that the Company has confidential information and trade secrets, whether written or unwritten, with respect to carrying on its business, including sensitive technology and engineering information and data, names, of past, present and prospective customers and vendors of the Company, methods of pricing contracts and income and expenses associated therewith, negotiated prices and offers outstanding, credit terms and status of accounts and the terms or circumstances of any business arrangements between the Company and any third parties (“Confidential Information and Trade Secrets”). As used in this Agreement, the term Confidential Information and Trade Secrets does not include (i) information which becomes generally available to the public other than as a result of a disclosure by the Executive, (ii) information which becomes available to the Executive on a nonconfidential basis from a source other than the Company, or (iii) information known to the Executive prior to any disclosure to him by the Company. The Executive further acknowledges that the Executive possesses a high degree of knowledge of the geothermal energy industry and, in particular, has committed to a long-standing relationship with the Company as employee, director and officer, which has allowed, and will continue to allow, him access to the Company’s Confidential Information and Trade Secrets. Accordingly, any employment by the Executive with another employer in the geothermal energy industry or participation by him as a substantial investor in any such industry may necessarily involve disclosure of the Company’s Confidential Information and Trade Secrets. Consequently, the Executive agrees that, if he voluntarily resigns his employment with the Company for any reason other than a breach of this Agreement by the Company, he shall not at any time during the two-year period after such resignation, directly or indirectly accept employment by or invest in (except as a passive investor in a public corporation or in a publicly issued partnership interest which, in either event, would not exceed an ownership interest of 3% of the outstanding equity or partnership interest) in any person, firm, corporation, partnership, joint venture or business which is primarily engaged in the production or marketing of electrical energy from geothermal resources. The preceding sentence notwithstanding, Executive shall not be precluded from accepting employment or providing services to Peter Kiewit Sons’, Inc. or any Affiliate thereof.

(b) Without the Consent of the Board, the Executive will not, for two years after the Term of Employment, (i) disclose any Confidential Information and Trade Secrets of the Company or any Affiliate of the Company to any Person (other than the Company, directors, officers or employees of the Company or representatives thereof), or (ii) otherwise make use of any Confidential Information and Trade Secrets other than in connection with authorized dealings with or by the Company.

(c) For a period of two years after the Term of Employment, the Executive shall neither directly nor indirectly solicit, on behalf of another employer, the employment of any person who is then currently employed by the Company, or otherwise induce, on behalf of another employer, such person to leave the employment of the Company without the Company’s prior written approval.

(d) The Executive will hold on behalf of the Company and as the property of the Company, all memoranda, manuals, books, papers, letters, documents, computer software and other similar property obtained during the course of his employment by the Company and relating to the Company’s business, and will return such property to the Company at any time upon demand by the Board and, in any event, within five calendar days after the end of the Term of Employment.

Section 7. Termination of Employment or Change in Employment Status .

(a) The employment of the Executive under this Agreement will terminate on the earliest of: (i) written notice by the Executive of his resignation; (ii) the 30th calendar day after the Company gives to the Executive written notice of termination without Cause; (iii) the fifth calendar day after the Company gives to the Executive written notice of the existence of Cause; (iv) the 30th calendar day after the Executive gives to the Company written notice of (A) the failure by the Company to pay to the Executive, for a material period of time and in a material amount, compensation due and payable by the Company under Section 4(a) or 4(c), or (B) any breach by the Company or the Board of Section 3(b) or Section 4(b); (v) the Permanent Disability of the Executive; or (vi) the death of the Executive.

(b) If the Employment of the Executive is terminated under this Agreement, the obligations of the Executive under Section 6 will remain in full force and effect, and the termination will not abrogate any rights or remedies of the Company or the Executive with respect to any breach of the Agreement, except as expressly provided in Sections 8 and 9.

(c) If the Executive relinquishes his position as Chief Executive Officer but offers to remain employed as Chairman of the Board of the Company, this Agreement will remain in full force and effect, subject to the provisions hereof governing his employment solely as Chairman of the Board. In such event, the first sentence of Section 3(a) and Sections 3(c), (e) and 4(d) shall no longer be applicable.

Section 8. Payment Upon Termination .

(a) If the employment of the Executive is terminated pursuant to subsections (i) or (iii) of Section 7(a), the Company will pay to the Executive, within 30 calendar days, (x) any salary pursuant to Section 4(a) which is accrued but unpaid through the Termination Date, and (y) a bonus payment, in an amount determined by the Board by reference to the performance of the Executive for a portion of the fiscal year of the Company before the Termination Date, which is not less than the Minimum Bonus.

(b) If the employment of the Executive is terminated pursuant to subsections (ii), (iv), (v) or (vi) of Section 7(a), the Company will pay the Executive, on or before the related Termination Date, an amount equal to three times the sum of (1) the annual salary then in effect pursuant to Section 4, and (2) the greater of (x) the Minimum Bonus or (y) an amount equal to the average Annual Bonus Compensation payable to the Executive in respect of the two fiscal years immediately preceding the fiscal year in which the Executive’s employment with the Company terminates. In addition, (x) any portion of the options granted to the Executive which would become vested within the next 36 months (beginning with the month following the month in which the Termination Date occurs) will vest immediately and may be exercised within the remaining term of the options as provided in the applicable option agreements, and (y) the Company shall continue in effect for Executive and his dependents, for a period of 36 months after the Termination Date, the life insurance benefits, medical benefits and dental benefits, the tax preparation and investment advisory services and any other employee benefits made generally available to senior executives of the Company on and after the date hereof through the end of the 36 month post-termination period (except for disability plan benefits), subject to such employee contributions and other terms and conditions as are applicable to active employees generally and subject to subsequent modification or termination of such plans to the extent such subsequent actions are also applicable to active employees generally; provided that such plan benefits shall terminate earlier on the date, if any, that comparable benefits are made available to the Executive by any new employer (the “Continuation of Benefits”). To the degree that any of the above employee benefit programs are not available to Executive on account of his status as a non-employee after termination of employment, the Company shall provide for economically equivalent programs during the 36 month period or pay to executive a lump sum cash amount designed to allow him to obtain economically equivalent benefits or put him in the same economic position on an after tax basis (the “Economic Equivalent”). If it is determined that benefits paid with respect to the extension of medical and dental benefits to Executive would not be exempt from taxation under the Internal Revenue Code, Company shall pay to Executive a lump sum cash payment within 2 ½ months 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.

If the Executive relinquishes his position as Chief Executive Officer but offers to remain employed as Chairman of the Board of the Company pursuant to Section 7(c) and the Executive’s employment is subsequently terminated pursuant to subsection (ii), (iv), (v) or (vi) of Section 7(a), in lieu of the payments described above, the Company shall (i) pay the Executive any due and payable salary pursuant to Section 4(a) for his services rendered to the Company prior to the termination of this Agreement, (ii) reimburse pursuant to Section 4(e) the expenses incurred by the Executive prior to the termination of this Agreement, (iii) pay the Executive the full amount of the aggregate annual salary that would have been paid pursuant to Section 4(a) through the fifth anniversary of the date he commenced his employment solely as Chairman of the Board, (iv) provide for the immediate vesting and exercisability of all options awarded to the Executive by the Company and (iv) provide for the Continuation of Benefits through the fifth anniversary of the date he commenced his employment solely as Chairman of the Board or the Economic Equivalent thereof.

(c) If the employment of the Executive is terminated pursuant to subsections (ii), (iv), (v) or (vi) of Section 7(a), all Performance Accelerated Stock Options (“PASOs”) held by the Executive on the Termination Date will become vested and immediately exercisable on such Termination Date, and shall otherwise remain exercisable for their term in accordance with the terms thereof.

(d) If the employment of the Executive is terminated pursuant to subsections (ii), (iv), (v) or (vi) of Section 7(a), then without further action by the Company, the Board or any committee thereof, the Executive may exercise any vested stock options (including vested PASOs) held by the Executive pursuant to existing procedures approved by the Compensation Committee for cashless exercise, by surrendering previously owned shares, electing to have the Company withhold shares otherwise deliverable upon exercise of such options, or by providing an irrevocable direction to a broker to sell shares and deliver all or a portion of the proceeds to the Company, in any case in an amount equal to the aggregate exercise price and any tax withholding obligation attendant to the exercise.

(e) If the Executive relinquishes his position as Chief Executive Officer but offers to remain employed as the Chairman of the Board of the Company pursuant to Section 7(c), the Company will pay the Executive, on or before the date he relinquishes such position, a special achievement bonus which is equal to two times the sum of (1) the annual salary then in effect pursuant to Section 4, and (2) the greater of (x) the Minimum Bonus or (y) an amount equal to the average Annual Bonus Compensation payable to the Executive in respect of the two fiscal years immediately preceding the fiscal year in which the Executive relinquishes such position. In addition to the foregoing, all options awarded by the Company to the Executive that would become vested and exercisable during the two year period following the date the Executive relinquishes his position as Chief Executive Officer but offers to remain as Chairman of the Board pursuant to Section 7(c) (the “Relinquishment Date”) shall become immediately vested and exercisable as of the Relinquishment Date, and all remaining options that would commence vesting in the period of time subsequent to such two-year period shall commence vesting in accordance with their terms as of the Relinquishment Date.

Section 8A. Certain Additional Payments by the Company.

(a) Anything in this Agreement to the contrary notwithstanding, in the event it shall be determined that any payment, distribution, waiver of Company rights, acceleration of vesting of any stock options or restricted stock, or any other payment or benefit in the nature of compensation to or for the benefit of the Executive, alone or in combination (whether such payment, distribution, waiver, acceleration or other benefit is made pursuant to the terms of this Agreement or any other agreement, plan or arrangement providing payments or benefits in the nature of compensation to or for the benefit of the Executive, but determined without regard to any additional payments required under this Section 8A) (a “Payment”) would be subject to the excise tax imposed by Section 4999 of the Internal Revenue Code of 1986 (the “Code”) (or any successor provision) or any interest or penalties are incurred by the Executive with respect to such excise tax (such excise tax, together with any such interest and penalties, are hereinafter collectively referred to as the “Excise Tax”), then the Executive shall be entitled to receive an additional payment (a “Gross-Up Payment”) in an amount such that after payment by the Executive of all taxes with respect to the Gross-Up Payment (including any interest or penalties imposed with respect to such taxes), including, without limitation, any income taxes (and any interest and penalties imposed with respect thereto) and Excise Tax imposed upon the Gross-Up Payment, the Executive retains an amount of the Gross-Up Payment equal to the Excise Tax imposed upon the Payments. Any Gross-Up Payment made by the Company to the Executive with respect to any Excise Tax paid by the Executive shall be made by the Company as soon as administratively feasible after the determination of such Excise Tax, but in no case later than by the end of the calendar year following the calendar year in which the Executive makes the Excise Tax payment.

(b) Subject to the provisions of Section 8A(c), all determinations required to be made under this Section 8A, including whether and when a Gross-Up Payment is required and the amount of such Gross-Up Payment and the assumptions to be utilized in arriving at such determination, shall be made by Deloitte and Touche LLP, or such other nationally recognized accounting firm then auditing the accounts of the Company (the “Accounting Firm”) which shall provide detailed supporting calculations both to the Company and the Executive within 15 business days of the receipt of notice from the Executive that there has been a Payment, or such earlier time as is requested by the Company. In the event that the Accounting Firm is unwilling or unable to perform its obligations pursuant to this Section 8A, the Executive shall appoint another nationally recognized accounting firm to make the determinations required hereunder (which accounting firm shall then be referred to hereunder as the Accounting Firm). All fees and expenses of the Accounting Firm shall be borne solely by the Company. Any Gross-Up Payment, determined pursuant to this Section 8A, shall be paid by the Company to the Executive within five days of the receipt of the Accounting Firm’s determination. Any determination by the Accounting Firm shall be binding upon the Company and the Executive. The parties hereto acknowledge that, as a result of the potential uncertainty in the application of Section 4999 of the Code (or any successor provision) at the time of the initial determination by the Accounting Firm hereunder, it is possible that the Company will not have made Gross-Up Payments which should have been made consistent with the calculations required to be made hereunder (an “Underpayment”). In the event that the Company exhausts its remedies pursuant to Section 8A(c) and the Executive thereafter is required to make a payment of any Excise Tax, the Accounting Firm shall determine the amount of the Underpayment that has occurred and any such Underpayment shall be promptly paid by the Company to or for the benefit of the Executive.

(c) The Executive shall notify the Company in writing of any claim by the Internal Revenue Service that, if successful, would require the payment by the Company of the Gross-Up Payment. Such notification shall be given as soon as practicable but no later than 20 business days after the Executive is informed in writing of such claim and shall apprise the Company of the nature of such claim and the date on which such claim is requested to be paid. The Executive shall not pay such claim prior to the expiration of the 30-day period following the date on which he gives such notice to the Company (or such shorter period ending on the date that any payment of taxes with respect to such claim is due). If the Company notifies the Executive in writing prior to the expiration of such period that it desires to contest such claim, the Executive shall:

(i) give the Company any information reasonably requested by the Company relating to such claim,

(ii) take such action in connection with contesting such claim as the Company shall reasonably request in writing from time to time, including, without limitation, accepting legal representation with respect to such claim by an attorney reasonably selected by the Company,

(iii) cooperate with the Company in good faith in order effectively to contest such claim, and

(iv) permit the Company to participate in any proceedings relating to such claim;

provided, however, that the Company shall bear and pay directly all costs and expenses (including additional interest and penalties) incurred in connection with such contest and shall indemnify and hold the Executive harmless, on an after-tax basis, for any Excise Tax or income tax (including interest and penalties with respect thereto) imposed as a result of such representation and payment of costs and expenses. Without limiting the foregoing provisions of this Section 8A(c), the Company shall control all proceedings taken in connection with such contest and, at its sole option, may pursue or forgo any and all administrative appeals, proceedings, hearings and conferences with the taxing authority in respect of such claim and may, at its sole option, either direct the Executive to pay the tax claimed and sue for a refund or contest the claim in any permissible manner, and the Executive agrees to prosecute such contest to a determination before any administrative tribunal, in a court of initial jurisdiction and in one or more appellate courts, as the Company shall determine; provided, however, that any extension of the statute of limitations relating to payment of taxes for the taxable year of the Executive with respect to which such contested amount is claimed to be due is limited solely to such contested amount. Furthermore, the Company’s control of the contest shall be limited to issues with respect to which a Gross-Up Payment would be payable hereunder and the Executive shall be entitled to settle or contest, as the case may be, any other issue raised by the Internal Revenue Service or any other taxing authority.

Section 8B. Restrictions on Payment to “Specified Employees” under Section 409A of the Internal Revenue Code. In the event any payment to be made under this Employment Agreement is subject to the provisions of Section 409A of the Internal Revenue Code (and is not otherwise exempt under applicable guidance issued under Section 409A), if such payment is due to the separation from service of the Executive (other than because of death), and if the Executive is a "specified employee" (as defined in Section 409A of the Internal Revenue Code) at the time of separation from service, such payment shall not be made until the date that is 6 months following the date of separation from service. In the event of any such delay in payment, interest shall be added to the delayed payment utilizing the interest rate on 1-year constant maturity U.S. Treasury Notes as published by the Federal Reserve Board (or its successor) in Statistical Release H.15 (or its successor) corresponding to the date that payment would have been made if the delay hereunder had not occurred.

Section 9. Remedies .

(a) The Company will be entitled, if it elects, to enjoin any breach or threatened breach of, or enforce the specific performance of, the obligations of the Executive under Sections 3 or 6, without showing any actual damage or that monetary damages would be inadequate. Any such equitable remedy will not be the sole and exclusive remedy for any such breach, and the Company may pursue other remedies for such a breach.

(b) Any court proceeding to enforce this Agreement may be commenced in federal courts, or in the absence of federal jurisdiction the state courts, located in Omaha, Nebraska. The parties submit to the jurisdiction of such courts and waive any objection which they might have to pursuit of any such proceeding of any such court.

(c) Except to the extent that the Company elects to seek injunctive relief in accordance with subsection (a), any controversy or claim arising out of or relating to this Agreement or the validity, interpretation, enforceability or breach of this Agreement will be submitted to arbitration in Omaha, Nebraska, in accordance with the then existing rules of the American Arbitration Association, and judgment upon the award rendered in any such arbitration may be entered in any court having jurisdiction.

(d) The Company will pay, promptly upon request, any legal fees or expenses incurred by the Executive in connection with any legal proceedings instituted by the company to enforce the provisions of this Agreement against the Executive, but such advances will be reimbursable to the Company, but only to the extent the Company ultimately prevails in the proceeding (after any applicable appeals have been exhausted).

Section 10. Assignment . Neither the Company nor the Executive may sell, transfer or otherwise assign their rights, or delegate their obligations, under this Agreement.

Section 11. Unfunded Benefits . All compensation and other benefits payable to the Executive under this Agreement will be unfunded, and neither the company nor any affiliate of the Company will segregate any assets to satisfy any obligation of the Company under this Agreement. The obligations of the Company to the Executive are not the subject of any guarantee or other assurance of any Person other than the Company.

Section 12. Severability . Should any provision, paragraph, clause or portion thereof of this Agreement be declared or be determined by any court or arbitrator of competent jurisdiction to be illegal, unenforceable or invalid, the validity or enforceability of the remaining parts, terms or provisions shall not be affected thereby and said illegal or invalid part, term or provision shall be deemed not to be a part of this Agreement. Alternatively, the court or arbitrator having jurisdiction shall have the power to modify such illegal, unenforceable or invalid provision so that it will be valid and enforceable, and, in any case, the remaining provisions of this Agreement shall remain in full force and effect.

Section 13. Miscellaneous .

(a) This Agreement may be amended or modified only by a writing executive by the Executive and the Company.

(b) This Agreement will be governed by and construed in accordance with the internal laws of the State of Nebraska.

(c) This Agreement constitutes the entire agreement of the Company and the Executive with respect to the matters set forth in this Agreement and supersedes any and all other agreements between the Company and the Executive relating to those matters.

(d) Any notice required to be given pursuant to this Agreement will be deemed given (i) when delivered in person, or (ii) on the third calendar day after it is sent by facsimile, express delivery service, or registered or certified mail, if to the Company or to the Executive, at 1111 S. 103 rd St., Omaha, Nebraska 68124, fax number (402) 231-1658 or to such other address as may be subsequently designated by the Company or the Executive in writing to the other party.

(e) A waiver by a party of a breach of this Agreement will not constitute a waiver of any other breach, prior or subsequent, of this Agreement.

IN WITNESS WHEREOF, the Company and the Executive have entered into this Agreement as of February 25, 2008.

	MIDAMERICAN ENERGY HOLDINGS COMPANY

	By:	/s/ Douglas L. Anderson
		Douglas L. Anderson
		Senior Vice President and General Counsel

	EXECUTIVE:

	By:	/s/ David L. Sokol
		David L. Sokol

EXHIBIT A

Defined Terms

“Affiliate means, with respect to a Person, (a) any Person directly or indirectly owning, controlling, or holding power to vote 10% or more of the outstanding voting securities of the Person; (b) any Person 10% or more of whose outstanding voting securities are directly or indirectly owned, controlled or held with power to vote by the Person; (c) any Person directly or indirectly controlling, controlled by or under common control with, the Person and (d) any officer or director of the Person, or of any Person directly or indirectly controlling the Person, controlled by the Person or under common control with the Person. As used in this definition, “control” means the possession, directly or indirectly, of the power to direct or cause the direction of the management and policies of a Person.

“Agreement” means this Employment Agreement dated as of August 21, 1995, by and between the Company and the Executive, as it may be amended from time to time in accordance with its terms.

“Board” means the Board of Directors of the Company or, if the context is appropriate, any duly authorized and appointed committee or member of the Board of Directors having authority to act on behalf of the Board of Directors with respect to the matter in question.

“Cause means any or all of the following:

(a)

the willful and continued failure by the Executive to perform substantially the services contemplated by the Agreement (other than any such failure resulting from the Executive’s incapacity due to disability) after a written demand for substantial performance is delivered to the Executive by a member or representative of the Board which specifically identifies the manner in which it is alleged that the Executive has not substantially performed such services;

(b)

the willful engaging by the Executive in gross misconduct which is materially and demonstrably injurious to the Company, provided that, no act, or failure to act, on the Executive’s part shall be considered “willful” unless done, or omitted to be done, in bad faith and without reasonable belief that such action or omission was in, or not opposed to, the best interests of the Company; or

(c)

the gross negligence of the Executive in performing the services contemplated by the Agreement which is materially and demonstrably injurious to the Company.

“Cause” will exist only if the Board has delivered to the Executive a copy of a resolution duly adopted by the affirmative vote of a majority of the entire membership of the Board at a meeting of the Board called and held for that purpose (after reasonable notice to the Executive and an opportunity for the Executive, together with his counsel, to be heard before the Board), finding that, in the good faith judgment of the Board, the Executive was guilty of the conduct constituting such Cause and specifying, the particulars thereof in detail.

“Company” means MidAmerican Energy Holdings Company, an Iowa corporation, and any successor or assign permitted under the Agreement.

“Consent of the Board” means, with respect to an action, the consent of the Board to the action given prior to the action in a resolution duly adopted by the Board, appropriate committee of the Board, or by a member of the Board duly authorized to consent to such action.

“Disability” means, with respect to the Executive, a condition of any medically determinable physical or mental impairment which can be expected to result in death or can be expected to last for a continuous period of not less than 12 months and the Executive (i) is unable to engage in any substantial gainful activity or (ii) has been receiving income replacement benefits for a period of not less than 3 months under a group long term disability insurance policy covering employees of the Company.

“Minimum Bonus” means, with respect to a fiscal year, $750,000; provided, however, in the event the Executive relinquishes his position as Chief Executive Officer but offers to remain employed as Chairman of the Board of the Company pursuant to Section 7(c) of this Agreement, there shall be no Minimum Bonus, but the Board shall retain its discretion to award Annual Bonus Compensation pursuant to Section 4(c) of the Agreement.

“Permanent Disability” means a Disability which has continued for at least six consecutive calendar months.

“Person” means any natural person, general partnership, limited partnership, corporation, joint venture, trust, business trust, or other entity.

“Term of Employment” means the period of time beginning on August 21, 1995, and ending on the fifth anniversary of such date, unless earlier terminated pursuant to Section 7(a) or automatically extended pursuant to the following sentence. The Term of Employment will be automatically extended for one year on each August 21 beginning on August 21, 2000, unless the Executive has given the Company a notice declining automatic extension at least 120 calendar days before the anniversary; provided, however, in the event the Executive relinquishes his position as Chief Executive Officer but offers to remain employed as Chairman of the Board of the Company pursuant to Section 7(c) of this Agreement, the Term of Employment shall mean the period of time beginning on the date the Executive relinquishes his position as Chief Executive Officer of the Company and ending on the fifth anniversary of such date, unless earlier terminated pursuant to Section 7(a).

“Termination Date” means the date of termination of employment of the Executive pursuant to Section 7 of this Agreement.

EXHIBIT B

David L. Sokol

Credited Years of Service as of March 12, 1999: 6 years, 9 months

EXHIBIT C

(Revised January 27, 2000)

David L. Sokol

Minimum Annual SERP benefit payment for retirement or disability payback on attaining age 47: $1,000,000.

EXHIBIT 10.3

EXECUTION COPY

AMENDED AND RESTATED EMPLOYMENT AGREEMENT

This Amended and Restated Employment Agreement, dated as of February 25, 2008, amends and restates the employment agreement originally entered into as of August 6, 1996, as amended, and as restated as of May 10, 1999, and is by and between MidAmerican Energy Holdings Company (formerly CalEnergy Company, Inc. (“CalEnergy”), an Iowa corporation (the “Company”), and Gregory E. Abel (the “Executive”).

RECITALS

The Company desires to employ the Executive as its President and Chief Operating Officer on the terms set forth in this Agreement, and the Executive desires to accept such employment.

Accordingly, the Company and the Executive agree as follows:

AGREEMENT

Section 1. Defined Terms . Terms used but not defined in this Agreement will have the meanings ascribed to them in Exhibit A to this Agreement.

Section 2. Employment.

(a) The Company will employ the Executive as, and the Executive will act as, the President and Chief Operating Officer of the Company, subject to and upon the terms set forth in this Agreement, for the Term of Employment.

(b) The Executive’s primary place of employment will be Des Moines, Iowa.

Section 3. Duties .

(a) The Executive (i) will perform and discharge the duties incident to and consistent with his title of President and Chief Operating Officer, and (ii) will perform and discharge such other duties, and will have such other authority, as are delegated to him by the Chairman of the Board of the Company (hereinafter referred to as the “Chairman of the Board”). In performing such duties, the Executive will report directly to, and be subject to the direction of, the Chairman of the Board.

(b) The Executive will act, without any compensation in addition to the compensation payable pursuant to this Agreement, as an officer or member of the board of directors of any subsidiary of the Company, if so appointed or elected.

(c) During the Term of Employment, the Executive (i) will devote his entire time, attention and energies during normal business hours to the business of the Company and its subsidiaries and (ii) will not, without the written consent of the Chairman of the Board, perform any services for any other Person or engage in any other business or professional activity, whether or not performed or engaged in for profit.

(d) Notwithstanding subsection 3 (c), the Executive, without the consent of the Chairman of the Board, may (i) purchase securities issued by, or otherwise passively invest his personal or family assets in, any other company or business within the constraints imposed by the Company’s Code of Business Conduct and Berkshire Hathaway’s Code of Business Conduct, referred to below, and (ii) engage in governmental, political, educational or charitable activities, but only to the extent that those activities (A) are not inconsistent with any direction of the Chairman of the Board or any duties under this Agreement, and (B) do not interfere with the devotion by the Executive of his entire time, attention and energies during normal business hours to the business of the Company.

Section 4. Compensation .

(a) During the Term of Employment, the Company will pay the Executive a base salary at an annual rate of $350,000, in substantially equal periodic payments in accordance with the Company’s practices for executive employees, as determined from time to time by the Compensation Committee.

(b) The Chairman of the Board will review the salary payable to the Executive at least annually beginning in the fourth fiscal quarter of 2008. The Compensation Committee, in its discretion, may increase the salary of the Executive from time to time, but may not reduce the salary of the Executive below the amount set forth in subsection 4 (a) above.

(c) During the Term of Employment, the Executive shall be eligible for consideration for an annual incentive merit bonus for the Executive’s performance during the fiscal year of the Company in an amount determined by the Compensation Committee, in its discretion, by reference to the accomplishment by the Executive of goals established by the Chairman of the Board for the related fiscal year. The annual bonus paid to the Executive, however, will not be less than the Minimum Bonus. The Executive shall also be eligible to be paid other bonuses for each fiscal year as determined by the Chairman of the Board. The Executive’s annual incentive merit bonus, together with all such other bonuses paid or payable for the fiscal year (including any amounts for which receipt is otherwise deferred pursuant to a plan or arrangement with the Company), is referred to herein as “Annual Bonus Compensation.” However, “Annual Bonus Compensation” shall not include the Earnings Per Share bonuses set forth in the letter of March 24, 2003 to Executive.

(d) The Company will reimburse the Executive, subject to compliance by the Executive with the Company’s customary reimbursement practices, for all reasonable and necessary out-of-pocket expenses incurred by the Executive on behalf of the Company in the course of its business.

(e) The Company may reduce any payments made to the Executive under this Agreement by any required federal, state or local government withholdings or deductions for taxes or similar charges, or otherwise pursuant to law, regulation or order.

(f) Any base salary payable to the Executive for any period of employment of less than one year during the Term of Employment will be reduced to reflect the actual number of days of employment during the period except as provided in Sections 8(b) and 8(c).

Section 5. Other Benefits .

(a) During the Term of Employment, the Executive and his dependents may participate in and receive benefits under any employee benefit plan which the Company makes generally available to its employees and their families, including any pension, life insurance, medical benefits, dental benefits or disability plan, but only to the extent that the Executive or his dependents otherwise satisfies the standards established for participation in the plan. The terms of Executive’s existing option agreements, as amended, remain unaffected hereby, except as set forth in Sections 8(b) and 8(c) hereof.

(b) The Executive may take up to four weeks of vacation during each full calendar year during the Term of Employment at a time mutually convenient to the Executive and the Company, without loss of compensation or other benefits under this Agreement.

Section 5 A. Supplemental Retirement Benefits .

(a) Effective as of March 12, 1999, the closing date of the merger between CalEnergy Company, Inc. and MidAmerican Energy Company, resulting in the creation of MidAmerican Energy Holdings Company (the “Merger Date”), the Executive became a participant in the MidAmerican Energy Company Supplemental Retirement Plan for Designated Officers (the “SERP”).

(b) The Executive shall receive fully vested years of participation credit under the SERP (for all purposes, including vesting and benefit accrual) for all years of service (or portions thereof) performed at CalEnergy Company, Inc. prior to the Merger Date, and for certain additional years of service (or portions thereof) as provided on Exhibit B attached hereto.

(c) The Executive shall be entitled to an Early Retirement Benefit Payment option under the SERP pursuant to which he shall commence receiving benefits under the SERP after the Executive’s separation from service or disability on or after attaining age 47, which payments shall be calculated pursuant to the SERP but which shall be no less than as provided on Exhibit C hereto (including for purposes of the following sentence). In the event of the Executive’s death, benefits shall be paid pursuant to Section 6.4 of the SERP; provided, however, that any payment due under Section 6.4 (a) of the SERP shall continue for the remaining lifetime of the Executive’s surviving “Spouse” (as defined in the SERP) or for 360 months if the Executive dies without a surviving Spouse; and further provided, however, that any payment due under Section 6.4 (b) of the SERP shall be payable without regard to the two-thirds and fifty percent limitations contained therein.

(d) In addition, the Executive shall be entitled to the following under the SERP:

(ii) any benefits under the SERP not fully vested on January 27, 2000 became fully vested as of such date.

(e) Notwithstanding anything herein or in the SERP to the contrary, for purposes of determining any benefit payable to Executive under the SERP, Executive’s annual base salary and annual bonus shall never be less than the base salary referenced in Section 4(a) hereof and that portion of the Annual Bonus Compensation earned by Executive for the 1998 calendar year which the SERP committee has determined shall be included for purposes of calculating the SERP benefit (i.e., $500,000).

(f) Since a "rabbi trust" has previously been established in order to provide security for the payment of benefits to Executive pursuant to the SERP, the Company shall have a continuing obligation to deposit into the rabbi trust an amount which, with the expected earnings thereon from reasonably prudent and conservative investments (as confirmed by a certificate of a national accounting firm of recognized standing which is independent of the Company) shall be sufficient to satisfy the ultimate benefit obligations to Executive pursuant to the SERP.

(g) A general release of claims under the SERP shall not be required of the Executive in order to receive benefits thereunder.

(h) The Executive’s entitlement to benefits under the SERP shall be nonforfeitable and, Section 6.5 of the SERP notwithstanding, shall not be adversely affected in any way upon termination of the Executive’s employment for Cause.

Section 6. Confidentiality and Post-Employment Restrictions.

(a) The Executive acknowledges that the Company and its Affiliates have confidential information and trade secrets, whether written or unwritten, with respect to carrying on their business, including sensitive marketing, bidding, technological and engineering information and data, names of past, present and prospective customers or partners of and vendors or suppliers to the company and its Affiliates, working relationships with governmental agencies and officials, methods of pricing contracts and income and expenses associated therewith, the international business strategy and relative ranking of opportunities in various countries, negotiated prices and offers outstanding, credit terms and status of accounts and the terms of circumstances of any current or prospective business arrangements between the Company and its Affiliates and any third parties (“Confidential Information and Trade Secrets”). As used in this Agreement, the term Confidential Information and Trade Secrets does not include (i) information which becomes generally available to the public other than as a result of a disclosure by the Executive, (ii) information which becomes available to the Executive on a nonconfidential basis from a source other than the Company or its Affiliates, or (iii) information known to the Executive prior to any disclosure to him by the Company or its Affiliates. The Executive further acknowledges that the Executive possesses a high degree of knowledge of the independent energy industry and, in particular, has committed to a long-standing relationship with the Company and its Affiliates as an employee and officer, which has allowed, and will continue to allow, him access to the Company’s Confidential Information and Trade Secrets. Accordingly, any employment by the Executive with another employer in the independent energy industry or participation by him as a substantial investor in any such industry may necessarily involve disclosure of the Company’s Confidential Information and Trade Secrets. Consequently, the Executive agrees that, if he voluntarily resigns his employment with the Company for any reason other than (i) a breach of this Agreement by the Company, or (ii) for Good Reason, he shall not at any time during the two-year period after such resignation, directly or indirectly accept employment by or invest in (except as a passive investor in a public corporation or in a publicly issued partnership interest which, in either event, would not exceed an ownership interest of 2% of the outstanding equity or partnership interest) any person, firm, corporation, partnership, joint venture or business which is primarily engaged in the production or marketing of steam or electrical energy or which otherwise directly competes with the business of the Company or its controlled Affiliates and, further, the Executive agrees that, to avoid the risk of disclosing or improperly using Confidential Information or Trade Secrets, he shall not directly or indirectly, provide consulting or advisory services to any of such independent energy businesses. The preceding sentence notwithstanding, Executive shall not be precluded from accepting employment or providing services to Peter Kiewit Sons’, Inc. or any Affiliate thereof.

(b) Without the written consent of the Chairman of the Board, the Executive will not, during and for three years after the Term of Employment, (i) disclose any Confidential Information and Trade Secrets of the Company or any Affiliate of the Company to any Person (other than the Company, directors, officers or employees of the company, its Affiliates or duly authorized agents, attorneys or other representatives thereof), or (ii) otherwise make use of any Confidential Information and Trade Secrets other than in connection with authorized dealings with or by the Company and its Affiliates.

(c) For a period of three years after the Term of Employment, the Executive shall neither directly nor indirectly solicit, on behalf of another employer, the employment of, or hire or cause another employer to hire, any person who is then currently employed by the company or an Affiliate thereof, or otherwise induce, on behalf of another employer, such person to leave the employment of the Company or an Affiliate thereof without the prior written approval of the Chairman of the Board.

(d) The Executive will hold, on behalf of the Company and its Affiliates and as the property of the Company and its Affiliates, all memoranda, manuals, books, papers, letters, documents, computer discs, data and software and other similar property obtained during the course of his employment by the Company or its Affiliates and relating to the Company’s or its Affiliates business, and will return such property to the Company or its Affiliates at any time upon demand by the Chairman of the Board and, in any event, within five calendar days after the end of the Term of Employment.

(e) During the Term of Employment, Executive agrees to comply in all material respects with the Company’s Code of Business Conduct as in effect on the date hereof. Executive also agrees to comply in all material respects with Berkshire Hathaway’s Code of Business Conduct as is then in effect.

(f) If any of the provisions of, or covenants contained in, this Section 6 are hereafter construed to be invalid or unenforceable in any jurisdiction, the same shall not affect the remainder of the provisions or the enforceability thereof in any other jurisdiction, which shall be given full effect, without regard to the invalidity or unenforceability in such other jurisdiction. If any of the provisions of, or covenants contained in, this Section 6 are held to be unenforceable in any jurisdiction because of the duration or geographical scope thereof, the parties agree that the court making such determination shall have the power to reduce the duration or geographical scope of such provision or covenant and in its reduced form, such provision or covenant shall be enforceable; provided , however , that the determination of such court shall not affect the enforceability of this Section 6 in any other jurisdiction.

Section 7. Termination of Employment .

(a) The employment of the Executive under this Agreement will terminate on the earliest of: (i) written notice by the Executive of his resignation other than for Good Reason; (ii) the day the Company gives to the Executive written notice of termination without Cause; (iii) the day the Company gives to the Executive written notice of termination for Cause; (iv) the Permanent Disability of the Executive; (v) the death of the Executive; or (vi) written notice by the Executive of his resignation for Good Reason.

(b) If the employment of the Executive is terminated under this Agreement for any reason whatsoever, the obligations of the Executive under Section 6 will remain in full force and effect to the extent provided therein, and the termination will not abrogate any rights or remedies of the Company or the Executive with respect to any breach of the Agreement, except as expressly provided in Section 8.

Section 8. Payment Upon Termination .

(a) If the employment of the Executive is terminated pursuant to subsections (i) or (iii) of Section 7(a), the Company will pay to the Executive, within 30 calendar days, any base salary and reimbursable expenses pursuant to Section 4(a) and Section 4(d) which are accrued but unpaid through the Termination Date.

(b) If the employment of the Executive is terminated pursuant to subsections (ii), (iv), (v) or (vi) of Section 7(a), the Company will pay the Executive, subject to the Executive’s compliance in all material respects with his post-termination obligations under Section 6, (i) within 30 calendar days, any base salary and reimbursable expenses which are accrued and unpaid through such date, (ii) a single lump sum equal to twice his annual base salary then in effect pursuant to Section 4 and (iii) a single lump sum equal to two times the greater of (x) the Minimum Bonus or (y) the average Annual Bonus Compensation payable to the Executive in respect of the two fiscal years immediately preceding the year in which the Executive’s employment with the Company terminates (with any such year for which no bonus was payable included in such two year average as a zero). In addition, in the event of any such termination, subject to the Executive’s compliance in all material respects with his post-termination obligations under Section 6, the Company agrees that (x) the Company stock options previously granted to Executive will continue to vest according to their terms within such next 24 months (beginning with the month following the month in which the Termination Date occurs, after which time the unvested remainder will lapse) and such vested options may be exercised within the remaining term of such options as provided in the respective option agreements, and (y) the Company shall continue in effect for Executive, for a period of 24 months after the date of any such termination, the life insurance benefits; medical benefits and dental benefits, the tax preparation and investment advisory services and any other employee benefits made generally available to senior executives of the Company on and after the date hereof through the end of the 24-month post-termination period (except for disability plan benefits), subject to such employee contributions and other terms and conditions as are applicable to active employees generally and subject to subsequent modification or termination of such plans to the extent such subsequent actions are also applicable to active employees generally; provided that such plan benefits shall terminate earlier on the date, if any, that comparable benefits are made available to the executive by any new employer. To the degree that any of the above employee benefit programs are not available to Executive on account of his status as a non-employee after termination of employment, the Company shall provide for economically equivalent programs during the 24-month period or pay to Executive a lump sum cash amount designed to allow him to obtain economically equivalent benefits or put him in the same economic position on an after tax basis. If it is determined that benefits paid with respect to the extension of medical and dental benefits to Executive would not be exempt from taxation under the Internal Revenue Code, Company shall pay to Executive a lump sum cash payment within 2 ½ months 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.

(d) If the employment of the Executive is terminated pursuant to subsections (ii), (iv), (v) or (vi) of Section 7(a), all Performance Accelerated Stock Options (“PASOs”) held by the Executive on the Termination Date will become vested and immediately exercisable on such Termination Date and shall otherwise remain exercisable for their term in accordance with the terms there of.

(e) If the employment of the Executive is terminated for any reason, then without further action by the Company, the Board or any committee thereof, the Executive may exercise any vested stock options (including vested PASOs) held by the Executive pursuant to existing procedures approved by the Compensation Committee for cashless exercise, by surrendering previously owned shares, electing to have the Company withhold shares otherwise deliverable upon exercise of such options, or by providing an irrevocable direction to a broker to sell shares and deliver all or a portion of the proceeds to the Company, in any case in an amount equal to the aggregate exercise price and any tax withholding obligation attendant to the exercise.

Section 8A. Certain Additional Payments by the Company

(a) Anything in this Agreement to the contrary notwithstanding, in the event it shall be determined that any payment, distribution, waiver of Company rights, acceleration of vesting of any stock options or restricted stock, or any other payment or benefit in the nature of compensation to or for the benefit of the Executive, along or in combination (whether such payment, distribution, waiver, acceleration or other benefit is made pursuant to the terms of this Agreement or any other agreement, plan or arrangement providing payments or benefits in the nature of compensation to or for the benefit of the Executive, but determined without regard to any additional payments required under this Section 8A) (a “Payment”) would be subject to the excise tax imposed by Section 4999 of the Code (or any successor provision) or any interest or penalties are incurred by the Executive with respect to such excise tax (such excise tax, together with any such interest and penalties, are hereinafter collectively referred to as the “Excise Tax”), then the Executive shall be entitled to receive an additional payment (a “Gross-Up Payment”) in an amount such that after payment by the Executive of all taxes with respect to the Gross-Up Payment (including any interest or penalties imposed with respect to such taxes), including, without limitation, any income taxes (and any interest and penalties imposed with respect thereto) and Excise Tax imposed upon the Gross-Up Payment, the Executive retains an amount of the Gross-Up Payment equal to the Excise Tax imposed upon the Payments. Any Gross-Up Payment made by the Company to the Executive with respect to any Excise Tax paid by the Executive shall be made by the Company as soon as administratively feasible after the determination of such Excise Tax, but in no case later than by the end of the calendar year following the calendar year in which the Executive makes the Excise Tax payment.

(c) The Executive shall notify the Company in writing of any claim by the Internal Revenue Service that, if successful would require the payment by the Company of the Gross-Up Payment. Such notification shall be given as soon as practicable but no later than 20 business days after the Executive is informed in writing of such claim and shall apprise the Company of the nature of such claim and the date on which such claim is requested to be paid. The Executive shall not pay such claim prior to the expiration of the 30-day period following the date on which he gives such notice to the Company (or such shorter period ending on the date that any payment of taxes with respect to such claim is due). If the Company notifies the Executive in writing prior to the expiration of such period that it desires to contest such claim, the Executive Shall:

(i) give the Company any information reasonably requested by the Company relating to such claim,

(iii) cooperate with the Company in good faith in order to effectively contest such claim, and

(iv) permit the Company to participate in any proceedings relating to such claim;

Section 9. Remedies.

(a) The Company will be entitled, if it elects to enjoin any breach or threatened breach of, or enforce the specific performance of, the obligations of the Executive under Section 3 or 6, without showing any actual damage or that monetary damages would be inadequate. Any such equitable remedy will not be the sole and exclusive remedy for any such breach, and the Company may pursue other remedies for such a breach.

(b) Any court proceeding to enforce this Agreement may be commenced in federal courts, or in the absence of federal jurisdiction the state courts, located in Omaha, Nebraska. The parties submit to the jurisdiction of such courts and waive any objection which they may have to pursuit of any such proceeding in any such court.

(c) Except to the extent that the Company elects to seek injunctive relief in accordance with subsection 9 (a), any controversy or claim arising out of or relating to this Agreement or the validity, interpretation, enforceability or breach of this Agreement will be submitted to arbitration in Omaha, Nebraska, in Accordance with the then existing rules of the American Arbitration Association, and judgment upon the award rendered in any such arbitration may be entered in any court having jurisdiction.

Section 10. Assignment . Neither the Company nor the Executive may sell, transfer or otherwise assign their rights, or delegate their obligations, under this Agreement, provided that the Company shall require any successor to all or substantially all of the business, stock or assets of the Company to expressly assume the Company’s rights and obligations hereunder.

Section 11. Unfunded Benefits . All compensation and other benefits payable to the executive under this Agreement will be unfunded, and neither the Company nor any Affiliate of the Company will segregate any assets to satisfy any obligation of the Company under this Agreement. The obligations of the Company to the Executive are not the subject of any guarantee or other assurance of any Person other than the Company.

Section 12. Severability . Should any provision, paragraph, clause or portion thereof of this Agreement be declared or be determined by any court or arbitrator of competent jurisdiction to be illegal, unenforceable or invalid, the validity or enforceability of the remaining parts, terms or provisions shall not be affected thereby and said illegal or invalid part, term or provision shall be deemed not to be a part of this Agreement. Alternatively, the court or arbitrator having jurisdiction shall have the power to modify such illegal, unenforceable or invalid provision so that it will be valid and enforceable, and, in any case the remaining provisions of this Agreement shall remain in full force and effect.

Section 13. Miscellaneous .

(a) This Agreement may be amended or modified only by a writing executed by the Executive and the Company.

(b) This Agreement will be governed by and construed in accordance with the internal laws of the State of Nebraska.

(d) Any notice required to be given pursuant to this Agreement will be deemed given (i) when delivered in person or by courier or (ii) on the third calendar day after it is sent by facsimile, with written confirmation of receipt, if to the Company, to: Chairman of the Board, MidAmerican Energy Holdings Company at 1111 S. 103rd St.,Omaha, Nebraska 68124, fax number (402) 231-1658, and if to the Executive, at 666 Grand Avenue, Des Moines, Iowa 50309, fax number (515) 242-4031 or to such other address as may be subsequently designated by the Company or the Executive in writing to the other party.

(e) A waiver by a party of a breach of this Agreement will not constitute a waiver of any other breach, prior or subsequent, of this Agreement.

IN WITNESS WHEREOF, the Company and the Executive have entered into this Agreement as of February 25, 2008.

	MIDAMERICAN ENERGY HOLDINGS COMPANY

	By:	/s/ Douglas L. Anderson
		Douglas L. Anderson
		Senior Vice President and General Counsel

	EXECUTIVE:

	By:	/s/ Gregory E. Abel
		Gregory E. Abel

EXHIBIT A

Defined Terms

“Affiliate” means, with respect to a Person, (a) any Person directly or indirectly owning, controlling, or holding power to vote 10% or more of the outstanding voting securities of the Person; (b) any Person 10% or more of whose outstanding voting securities are directly or indirectly owned, controlled or held with power to vote by the Person; (c) any Person directly or indirectly controlling, controlled by or under common control with, the Person; and (d) any officer or director of the Person, or of any Person directly or indirectly controlling the Person, controlled by the Person or under common control with the Person. As used in this definition, “control” means possession, directly or indirectly, of the power to direct or cause the direction of the management and policies of a Person.

“Agreement” means this Employment Agreement dated as of August 6, 1996, by and between the Company and the Executive, as it may be amended from time to time in accordance with its terms.

“Board” means the Board of Directors of the Company.

“Cause” means any or all of the following:

(a)	the willful and continued failure by the Executive to perform substantially the services and duties contemplated by this Agreement (other than any such failure resulting from the Executive’s incapacity due to disability);

(b)	the willful engaging by the Executive in gross misconduct which is injurious to the business or reputation of the Company in any material respect;

(c)	the gross negligence of the Executive in performing the services contemplated by this Agreement which is injurious to the business or reputation of the Company in any material respect; or

(d)	Executive’s conviction of, or pleading guilty or no contest to, a felony involving moral turpitude.

“Code” means the Internal Revenue Code of 1986, as amended.

“Company” means MidAmerican Energy Holdings Company, an Iowa corporation, and any successor or assign permitted under the Agreement.

“Good Reason” means any of the following events: (i) the failure by the Company to pay to the Executive, for a material period of time and in a material amount, compensation due and payable by the Company under Section 4 (a) of this Agreement; (ii) any reduction by the Company of the title, office, duties or authority of the Executive in any material respect; or (iii) any relocation of the Executive’s primary place of employment to a location more than 25 miles from Des Moines, Iowa.

“Minimum Bonus” means, with respect to a fiscal year, $200,000.

“Permanent Disability” means a Disability which has continued for at least six consecutive calendar months.

“Person” means any natural person, general partnership, limited partnership, corporation, joint venture, trust, business trust, or other entity.

“Term of Employment” means the period of time beginning on August 6, 1996, and ending on the eighth anniversary of such date, unless earlier terminated pursuant to Section 7(a) or automatically extended pursuant to the following sentence. The Term of Employment will be automatically extended for one year on each anniversary of the date of this Agreement beginning on the fifth anniversary unless the Executive has given the Company, or the Company has given the Executive, a notice declining automatic extension at least 365 calendar days before the anniversary.

“Termination Date” means the date of termination of employment of the Executive pursuant to Section 7 of this Agreement.

EXHIBIT B

Gregory E. Abel

Credited Years of Service as of March 12, 1999: 11 years, 1 month.

EXHIBIT C

Gregory E. Abel

Minimum Annual SERP benefit payment for retirement or disability payable on or after attaining age 47: $693,333.

EXHIBIT 10.5

EXECUTION COPY

AMENDED AND RESTATED EMPLOYMENT AGREEMENT

This Amended and Restated Employment Agreement, dated as of February 25, 2008, amends and restates the employment agreement originally entered into as of April 21, 1999, and is by and between MidAmerican Energy Holdings Company, an Iowa corporation (the Company”), and Patrick J. Goodman (the Executive).

RECITALS

The Company desires to employ the Executive as its Senior Vice President and Chief Financial Officer on the terms set forth in this Agreement, and the Executive desires to accept such employment.

Accordingly, the Company and the Executive agree as follows:

AGREEMENT

Section 1. Defined Terms. Terms used but not defined in this Agreement will have the meanings ascribed to them in Exhibit A to this Agreement.

Section 2. Emp1oyment.

(a) The Company will employ the Executive as, and the Executive will act as the Senior Vice President and Chief Financial Officer of the Company, subject to and upon the terms set forth in this Agreement, for the Term of Employment.

(b) The Executive’s primary place of employment will be Des Moines, Iowa.

Section 3. Duties.

(a) The Executive (i) will perform and discharge the duties incident to and consistent with his title of Senior Vice President and Chief Financial Officer, and (ii) will perform and discharge such other duties, and will have such other authority, as are delegated to him by the Chairman of the Board of the Company (hereinafter referred to as the “Chairman of the Board”). In performing such duties, the Executive will report directly to, and be subject to the direction of, the Chairman of the Board.

(b) The Executive will act, without any compensation in addition to the compensation payable pursuant to this Agreement, as an officer or member, of the board of directors of any subsidiary of the Company, if so appointed or elected.

(c) During the Term of Employment the Executive (i) will devote his entire time, attention and energies during normal business hours to the business of the Company and its subsidiaries and (ii) will not, without the written consent of the Chairman of the Board, perform any services for any other Person or engage in any other business or professional activity, whether or not performed or engaged in for profit.

(d) Notwithstanding subsection 3(c), the Executive, without the consent of the Chairman of the Board, may (i) purchase securities issued by, or otherwise passively invest his personal or family assets in, any other company or business within the constraints imposed by the Code of Business Conduct referred to below, and (ii) engage in governmental, political, educational or charitable activities, but only to the extent that those activities (A) are not inconsistent with any direction of the Chairman of the Board or any duties under this Agreement, and (B) do not interfere with the devotion by the Executive of his entire time, attention and energies during normal business hours to the business of the Company.

Section 4. Compensation.

(a) During the Term of Employment, the Company will pay the Executive a base salary at an annual rate of $220,000, in substantially equal periodic payments in accordance with the Company’s practices for executive employees, as determined from time to time by the Chairman of the Board.

(b) The Chairman of the Board will review the salary payable to the Executive at least annually beginning in the fourth fiscal quarter of 2007. The Chairman of the Board, in his discretion, may increase the salary of the Executive from time to time, but may not reduce the salary of the Executive below the amount set forth in subsection 4(a) above.

(c) During the Term of Employment, the Executive shall be eligible for consideration for an annual incentive merit bonus, for the Executive’s performance during the fiscal year of the Company in an amount determined by the Chairman of the Board in his discretion, by reference to the accomplishment by the Executive of goals established by the Chairman of the Board for the related fiscal year. The Executive shall also be eligible to be paid other bonuses for each fiscal year as determined by the Chairman of the Board. The Executive’s annual incentive merit bonus, together with all such other bonuses paid or payable for the fiscal year (including any amounts for which receipt is otherwise deferred pursuant to a plan or arrangement with the Company), is referred to herein as “Annual Bonus Compensation.”

Section 5. Other Benefits.

(b) The Executive may take up to three weeks of vacation during each full calendar year during the Term of Employment at a time mutually convenient to the Executive and the Company, without loss of compensation or other benefits under this Agreement.

Section 6. Confidentiality and Post-Employment Restrictions.

(a) The Executive acknowledges that the Company and its Affiliates have confidential information and trade secrets, whether written or unwritten, with respect to carrying on their business, including sensitive marketing, bidding, technological and engineering information and data, names of past, present and prospective customers or partners of and vendors or suppliers to the Company and its Affiliates, working relationships with governmental agencies and officials, methods of pricing contracts and income and expenses associated therewith, the international business strategy and relative ranking of opportunities in various countries, negotiated prices and offers outstanding, credit terms and status of accounts and the terms or circumstances of any current or prospective business arrangements between the Company and its Affiliates and any third parties (“Confidential Information and Trade Secrets”). As used in this Agreement, the term Confidential Information and Trade Secrets does not include (i) information which becomes generally available to the public other than as a result of a disclosure by the Executive, (ii) information which becomes available to the Executive on a nonconfidential basis from a source other than the Company or its Affiliates, or (iii) information known to the Executive prior to any disclosure to him by the Company or its Affiliates. The Executive further acknowledges that the Executive possesses a high degree of knowledge of the independent energy industry and, in particular, has committed to a longstanding relationship with the Company and its Affiliates as an employee and officer, which has allowed, and will continue to allow, him access to the Company’s Confidential Information and Trade Secrets. Accordingly, any employment by the Executive with another employer in the independent energy industry or participation by him as a substantial investor in any such industry may necessarily involve disclosure of the Company’s Confidential Information and Trade Secrets. Consequently, the Executive agrees that, if he voluntarily resigns his employment with the Company for any reason other than (i) a breach of this Agreement by the Company, or (ii) for Good Reason, he shall not at any time during the two-year period after such resignation, directly or indirectly accept employment by or invest in (except as a passive investor in a public corporation or in a publicly issued partnership interest which, in either event, would not exceed an ownership interest of 2% of the outstanding equity or partnership interest) in any person, firm, corporation, partnership, joint venture or business which is engaged in the production or marketing of steam or electrical energy or the distribution or supply of electricity or natural gas (in each case in the States of Iowa, Illinois, Nebraska, South Dakota, Kansas, Missouri, Minnesota or Wisconsin) or which otherwise directly competes with the business of the Company or its Affiliates and, further, the Executive agrees that, to avoid the risk of disclosing or improperly using Confidential Information or Trade Secrets, he shall not directly, or indirectly, provide consulting or advisory services to any of such independent energy or utility businesses which conduct business in such States or otherwise directly compete with the Company or its Affiliates. The preceding sentence notwithstanding, Executive shall not be precluded from accepting employment or providing services to Peter Kiewit Sons’, Inc. or any Affiliate thereof.

(b) Without the written consent of the Chairman of the Board, the Executive will not, during and for three years after the Term of Employment, (i) disclose any Confidential Information and Trade Secrets of the Company or any Affiliate of the Company to any Person (other than the Company, directors, officers or employees of the Company, its Affiliates or duly authorized agents, attorneys or other representatives thereof), or (ii) otherwise make use of any Confidential Information and Trade Secrets other than in connection with authorized dealings with or by the Company and its Affiliates.

(c) For a period of three years after the Term of Employment, the Executive shall neither directly nor indirectly solicit, on behalf of another employer, the employment of, or hire or cause another employer to hire, any person who is then currently employed by the Company or an Affiliate thereof, or otherwise induce, on behalf of another employer, such person to leave the employment of the Company or an Affiliate thereof without the prior written approval of the Chairman of the Board.

(e) During the Term of Employment, Executive agrees to comply in all material respects with the Company’s Code of Business Conduct and Berkshire Hathaway’s Code of Business Conduct and all future amendments and restatements to such policy and to deliver an executed Certificate of Compliance with respect thereto upon request by the Company.

(f) If any of the provisions of, or covenants contained in, this Section 6 are hereafter construed to be invalid or unenforceable in any jurisdiction, the same shall not affect the remainder of the provisions or the enforceability thereof in any other jurisdiction, which shall be given full effect, without regard to the invalidity or unenforceability in such other jurisdiction. If any of the provisions of, or covenants contained in, this Section 6 are held to be unenforceable in any jurisdiction because of the duration or geographical scope thereof, the parties agree that the court making such determination shall have the power to reduce the duration or geographical scope of such provision or covenant and, in its reduced form, such provision or covenant shall be enforceable; provided, however, that the determination of such court shall not affect the enforceability of this Section 6 in any other jurisdiction.

Section 7. Termination of Employment.

Section 8. Payment Upon Termination.

In addition, in the event of any such termination, subject to the Executive’s compliance in all material respects with his post-termination obligations under Section 6, the Company agrees that (x) the Company stock options previously granted to Executive will continue to vest according to their terms within such next 24 months (beginning with the month following the month in which the Termination Date occurs, after which time the unvested remainder will lapse) and such vested options may be exercised within the remaining term of such options as provided in the respective option agreements, and (y) the Company shall continue in effect for Executive, for a period of twelve months after the date of any such termination, the life insurance, medical benefits and dental benefits available to the Executive and his dependents on the date of such termination, subject to such employee contributions and other terms and conditions as are applicable to active employees generally and subject to subsequent modification or termination of such plans to the extent such subsequent actions are also applicable to active employees generally; provided that such plan benefits shall terminate earlier on the date, if any, that comparable benefits are made available to the Executive by any new employer.

(d) If the employment of the Executive is terminated pursuant to subsections (ii) or (vi) of Section 7 (a), any Performance Accelerated Stock Options (“PASOs”) held by the Executive on the Termination Date will become vested and immediately exercisable on such Termination Date and shall otherwise remain exercisable for their term in accordance with the terms thereof.

(e) If the employment of the Executive is terminated for any reason, then without further action by the Company, the Board or any committee thereof, the Executive may exercise any vested stock options (including any vested PASOs) held by the Executive pursuant to existing procedures approved by the Compensation Committee for cashless exercise, by surrendering previously owned shares, electing to have the Company withhold shares otherwise deliverable upon exercise of such options, or by providing an irrevocable direction to a broker to sell shares and deliver all or a portion of the proceeds to the Company, in any case in an amount equal to the aggregate exercise price and any tax withholding obligation attendant to the exercise.

Section 8A. Certain Additional Payments by the Company.

(a) Anything in this Agreement to the contrary notwithstanding, in the event it shall be determined that any payment, distribution, waiver of Company rights, acceleration of vesting of any stock options or restricted stock, or any other payment or benefit in the nature of compensation to or for the benefit of the Executive, alone or in combination (whether such payment, distribution, waiver, acceleration or other benefit is made pursuant to the terms of this Agreement or any other agreement, plan or arrangement providing payments or benefits in the nature of compensation to or for the benefit of the Executive, but determined without regard to any additional payments required under this Section 8A) (a “Payment) would be subject to the excise tax imposed by Section 4999 of the Code (or any successor provision) or any interest or penalties are incurred by the Executive with respect to such excise tax (such excise tax, together with any such interest and penalties, are hereinafter collectively referred to as the “Excise Tax”), then the Executive shall be entitled to receive an additional payment (a “Gross-Up Payment”) in an amount such that after payment by the Executive of all taxes with respect to the Gross-Up Payment (including any interest or penalties imposed with respect to such taxes), including, without limitation, any income taxes (and any interest and penalties imposed with respect thereto) and Excise Tax imposed upon the Gross-up Payment, the Executive retains an amount of the Gross-Up Payment equal to the Excise Tax imposed upon the Payments. Any Gross-Up Payment made by the Company to the Executive with respect to any Excise Tax paid by the Executive shall be made by the Company as soon as administratively feasible after the determination of such Excise Tax, but in no case later than by the end of the calendar year following the calendar year in which the Executive makes the Excise Tax payment.

(i)

give the Company any information reasonably requested by the Company relating to such claim,

(ii)

take such action in connection with contesting such claim as the Company shall reasonably request in writing from time to time, including, without limitation, accepting legal representation with respect to such claim by an attorney reasonably selected by the Company,

(iii)

cooperate with the Company in good faith in order effectively to contest such claim, and

(iv)

permit the Company to participate in any proceedings relating to such claim;

Except as provided herein and to the extent necessary to give full effect to the provisions of this Amendment, the terms of the Employment Agreement shall remain in full force and effect.

Section 9. Remedies.

(c) Except to the extent that the Company elects to seek injunctive relief in accordance with subsection 9(a), any controversy or claim arising out of or relating to this Agreement or the validity, interpretation, enforceability or breach of this Agreement will be submitted to arbitration in Omaha, Nebraska, in accordance with the then existing rules of the American Arbitration Association, and judgment upon the award rendered in any such arbitration may be entered in any court having jurisdiction.

Section 10. Assignment. Neither the Company nor the Executive may sell, transfer or otherwise assign their rights, or delegate their obligations, under this Agreement, provided that the Company shall require any successor to all or substantially all of the business, stock or assets of the Company to expressly assume the Company’s rights and obligations hereunder.

Section 11. Unfunded Benefits. All compensation and other benefits payable to the Executive under this Agreement will be unfunded, and neither the company nor any affiliate of the Company will segregate any assets to satisfy any obligation of the Company under this Agreement. The obligations of the Company to the Executive are not the subject of any guarantee or other assurance of any Person other than the Company.

Section 12. Severability. Should any provision, paragraph, clause or portion thereof of this Agreement be declared or be determined by any court or arbitrator of competent jurisdiction to be illegal, unenforceable or invalid, the validity or enforceability of the remaining parts, terms or provisions shall not be affected thereby and said illegal or invalid part, term or provision shall be deemed not to be a part of this Agreement. Alternatively, the court or arbitrator having jurisdiction shall have the power to modify such illegal, unenforceable or invalid provision so that it will be valid and enforceable, and, in any case, the remaining provisions of this Agreement shall remain in full force and effect.

Section 13. Miscellaneous.

(a) This Agreement may be amended or modified only by a writing executed by the Executive and the Company.

(b) This Agreement will be governed by and construed in accordance with the internal laws of the State of Nebraska.

(d) Any notice required to be given pursuant to this Agreement will be deemed given (i) when delivered in person or by courier or (ii) on the third calendar day after it is sent by facsimile, with written confirmation of receipt, if to the Company, to: Chairman of the Board, MidAmerican Energy Holdings Company at 1111 S. 103 rd St., Omaha, Nebraska 68124, fax number (402) 231-1658, and, if to the Executive, at MidAmerican Energy Holdings Company, 666 Grand Avenue, Des Moines, Iowa 50303, fax number (515) 242-4031 or to such other address as may be subsequently designated by the Company or the Executive in writing to the other party.

(e) A waiver by a party of a breach of this Agreement will not constitute a waiver of any other breach, prior or subsequent, of this Agreement.

IN WITNESS WHEREOF, the Company and the Executive have entered into this Agreement as of February 25, 2008.

	MIDAMERICAN ENERGY HOLDINGS COMPANY

	By:	/s/ Douglas L. Anderson
		Douglas L. Anderson
		Senior Vice President and General Counsel

	EXECUTIVE:

	By:	/s/ Patrick J. Goodman
		Patrick J. Goodman

EXHIBIT A

Defined Terms

“Affiliate” means, with respect to a Person 1 (a) any Person directly or indirectly owning, controlling, or holding power to vote 10% or more of the outstanding voting securities of the Person; (b) any Person 10% or more of whose outstanding voting securities are directly or indirectly owned, controlled or held with power to vote by the Person; (c) any Person directly or indirectly controlling, controlled by or under common control with, the Person; and (d) any officer or director of the Person, or of any Person directly or indirectly controlling the Person, controlled by the Person or under common control with the Person. As used in this definition, “control” means the possession, directly or indirectly, of the power to direct or cause the direction of the management and policies of a Person.

“Agreement” means this Amended and Restated Employment Agreement,dated as of February 25, 2008, amending and restating the employment agreement originally entered into as of April 21, 1999, by and between the Company and the Executive, as it may be amended from time to time in accordance with its terms.

“Board” means the Board of Directors of the Company.

“Cause” means any or all of the following:

(a)	the willful and continued failure by the Executive to perform substantially the services and duties contemplated by this Agreement (other than any such failure resulting from the Executive’s incapacity due to disability);

(b)	the willful engaging by the Executive in gross misconduct which is injurious to the business or reputation of the Company in any material respect;

(c)	the gross negligence of the Executive in performing the services contemplated by this Agreement which is injurious to the business or reputation of the Company in any material respect; or

(d)	Executive’s conviction of, or pleading guilty or no contest to, a felony involving moral turpitude.

“Code” means the Internal Revenue Code of 1986, as amended.

“Company” means MidAmerican Energy Holdings Company, an Iowa corporation, and any successor or assign permitted under the Agreement

“Permanent Disability” means a Disability which has continued for at least six consecutive calendar months.

“Person” means any natural person, general partnership, limited partnership, corporation, joint venture, trust, business trust, or other entity.

“Term of Employment” means the period of time beginning on April 21, 1999, and ending on the fifth anniversary of such date, unless earlier terminated pursuant to Section 7(a) or automatically extended pursuant to the following sentence. The Term of Employment will be automatically extended for one year on each anniversary of the date of this Agreement beginning on the fifth anniversary unless the Executive has given the Company, or the Company has given the Executive, a notice declining automatic extension at least 365 calendar days before the anniversary.

“Termination Date” means the date of termination of employment of the Executive pursuant to Section 7 of this Agreement.

EXHIBIT 10.9

MIDAMERICAN ENERGY HOLDINGS COMPANY

EXECUTIVE VOLUNTARY DEFERRED COMPENSATION PLAN

(Restated effective as of January 1, 2007)

MIDAMERICAN ENERGY HOLDINGS COMPANY

EXECUTIVE VOLUNTARY DEFERRED COMPENSATION PLAN

MidAmerican Energy Holdings Company hereby amends and restates the MidAmerican Energy Holdings Company Executive Voluntary Deferred Compensation Plan (“Plan”) for the benefit of certain Employees. The primary purpose of the Plan is to allow employees to defer compensation. The Employer will pay benefits under the Plan only in accordance with the terms and conditions set forth in the Plan. This Plan is a restated plan effective as of January 1, 2007 (See Section 7.02(A) for good faith compliance as to 409A Amounts during 2005, 2006, 2007 and 2008). The Plan was originally established effective July 1, 1999.

PREAMBLE

Plan Type. The Plan is an unfunded nonqualified deferred compensation plan maintained “primarily for the purpose of providing deferred compensation for a select group of management or highly compensated employees” (“top-hat plan”).

Possible Nonuniformity . The Employer need not provide the same Plan benefits or apply the same Plan terms and conditions to all Participants, even as to Participants who are of similar pay, title and other status with the Employer. The Employer may create a separate exhibit for one or more Participants, specifying such terms and conditions as are applicable to a given Participant. The Employer, in a separate exhibit, may modify any Plan provision with respect to one or more Participants.

I. DEFINITIONS

1.01 “Account” means the account the Employer establishes under the Plan for each Participant and as applicable means a Participant’s Elective Deferral Account, or Employer Contribution Account. An Elective Deferral Account shall consist of subaccounts as selected by the Participant, and which shall be a Retirement Account, an In-Service Account and an Education Account, as described in Section 4.03(A).

1.02 “Accrued Benefit” means the total dollar amount credited to a Participant’s Account.

1.03 “Applicable Guidance” means Treasury Regulations issued pursuant to Code §409A, or other written Treasury or IRS guidance regarding Code §409A, which is in addition to IRS Notice 2005-1 (“Notice 2005-1”).

1.04 “Base Salary” means a Participant’s compensation consisting only of regular annual salary and excluding any other compensation.

1.05 “Beneficiary” means the person or persons entitled to receive Plan benefits in the event of a Participant’s death.

1.06 “Code” means the Internal Revenue Code of 1986, as amended.

1.07 “Compensation” means Base Salary, performance awards, and annual incentive bonuses (other than Employer long-term incentive awards). Inclusion of any other forms of compensation is subject to approval of the Employer.

1.08 “Deferred Compensation” means the Participant’s Account Balance attributable to Elective Deferrals and Employer Contributions and includes Earnings on such amounts. “Compensation Deferred” is Compensation that the Participant or the Employer has deferred under this Plan.

1.09 “Earnings” means the notional earnings, gain and loss applicable to a Participant’s Account as described in Section 5.02.

1.10 “Effective Date” of the Plan as amended and restated is January 1, 2007 (See Section 7.02(A) for good faith compliance as to 409A Amounts during 2005, 2006, 2007 and 2008).

1.11 “Elective Deferral” means Compensation a Participant elects to defer into the Participant’s Account under the Plan.

1.12 “Elective Deferral Account” means the portion of a Participant’s Account attributable to Elective Deferrals and Earnings thereon (and which shall consist of Retirement, In-Service and Education subaccounts).

1.13 “Employee” means a person providing services to the Employer in the capacity of a common law employee of the Employer (other than persons employed by PacifiCorp, HomeServices of America, Inc. or any subsidiary of either corporation).

1.14 “Employer” means MidAmerican Energy Holdings Company, an Iowa corporation, and, with respect to Participants who are employees of an affiliate of MidAmerican Energy Holdings Company, Employer also means any such affiliate; provided, however, that with respect to all matters involving administration of the Plan, including the authority to designate Employees who are Participants in the Plan and to amend and terminate the Plan, Employer shall only mean MidAmerican Energy Holdings Company. With respect to the obligation to make payments to any Participant under the Plan, Employer shall mean MidAmerican Energy Holdings Company and the Employer who employs the Participant, but not any other Employer. For purposes of determining whether there has been a Separation from Service with the Employer, Employer means all entities with whom the Employer would be considered a single employer under Code §§ 414 (b) and (c).

1.15 “Employer Contribution” means amounts, if any, the Employer contributes or credits to an Account under the Plan, excluding Elective Deferrals.

1.16 “Employer Contribution Account” means the portion of a Participant’s Account attributable to Employer Contributions and Earnings thereon.

1.17 “ERISA” means the Employee Retirement Income Security Act of 1974, as amended.

1.18 “ Participant” means an Employee of the Employer who has met the eligibility requirements of Section 2.01 and who has accrued a benefit under the Plan.

1.19 “Performance-Based Compensation” means such amounts described in Applicable Guidance .

1.20 “ Plan” means the MidAmerican Energy Holdings Company Executive Voluntary Deferred Compensation Plan . For purposes of applying Code §409A requirements: (i) this Plan is an account balance plan under Applicable Guidance; (ii) this plan constitutes a separate plan for each Participant; and (iii) except as the Plan otherwise provides, all Deferred Compensation for a Participant is aggregated with that Participant’s deferrals under any other account balance nonqualified deferred compensation plan of the Employer in which the Participant participates. Employer Contribution Accounts are considered to be part of a nonelective account balance plan type and Elective Deferral Accounts are considered to be part of an elective account balance plan type.

1.21 “Retirement Age” means a Participant’s attainment of age 55.

1.22 “Separation from Service” means an Employee’s termination of employment with the Employer or as otherwise defined in Applicable Guidance.

1.23 “Specified Employee” means a Participant described in Code §416(i), disregarding paragraph (5) thereof. However, a Participant is not a Specified Employee unless any stock of the Employer (or of a member of the same group of controlled entities as Employer) is publicly traded on an established securities market or otherwise.

1.24 “Specified Time or Pursuant to a Fixed Schedule” means a specific time or schedule (but not the occurrence of an event) as a Participant payment election may specify, and otherwise as described in Applicable Guidance.

1.25 “ Taxable Year” means the 12 consecutive month period ending each December 31.

1.26 “ Trust” means a trust described in Section 5.01.

1.27 “Unforeseeable Emergency” means: (i) a severe financial hardship to the Participant resulting from a sudden and unexpected illness or accident of the Participant, the Participant’s spouse or a dependent (as defined in Code §152(a)) of the Participant; (ii) loss of the Participant’s property due to casualty; or (iii) other similar extraordinary and unforeseeable circumstances arising as a result of events beyond the Participant’s control. The amount of the distribution may not exceed the amount necessary to satisfy the Unforeseeable Emergency plus taxes reasonably anticipated as a result of the distribution, after taking into account the extent to which the hardship may be relieved through reimbursement or compensation by insurance or otherwise or by liquidation of the Participant’s assets, to the extent that liquidation of such assets would not itself cause severe financial hardship.

1.28 “ Valuation Date” means the last day of each calendar month and such other dates as the Employer may determine.

1.29 “Vested” means Deferred Compensation which is not subject to a Substantial Risk of Forfeiture (as defined in Applicable Guidance) or to a requirement to perform further services for the Employer.

II. PARTICIPATION

2.01 Participant Designated . The President of the Employer shall designate and approve the Employees who are eligible to participate in the Plan, such designation to be either by name, job title or other classification. The President may also notify a Participant that he or she is no longer eligible to make future deferrals into the Plan. Such termination of eligibility shall be effective for compensation earned after January 1 following such written notification to the individual. However, until final distribution has been made to such person from his or her Accounts, for all other purposes under the Plan the person shall still be considered a Participant.

2.02 Elective Deferrals . Participants may make separate Elective Deferrals to their Accounts with respect to Base Salary and Compensation that is not Base Salary. All elections to defer shall terminate upon Separation from Service, Disability (as defined in Applicable Guidance) or a distribution based on an Unforeseeable Emergency.

(A) Limitations . The maximum Elective Deferral for Base Salary is 50%. There is no limit for Compensation that is not Base Salary. The minimum Elective Deferral for any type of Compensation is 1%.

(B) Form and Timing . A Participant must make his/her Elective Deferral election on an election form the Employer provides for that purpose. Unless otherwise provided in this Section 2.02, a Participant must deliver his/her election to the Employer prior to the beginning of the Taxable Year for which it is to go into effect (or at such other time as Applicable Guidance may provide), at which time the election shall become irrevocable.

(C) New Participant . If an Employee first becomes a Participant on a date which is not the first day of a Taxable Year, the Participant must make and deliver his/her Elective Deferral election for that Taxable Year not later than 30 days after the Participant becomes a Participant. The election may apply only to Compensation for services the Participant performs subsequent to the date the Participant delivers the election to the Employer. For Compensation that is earned for a specified performance period, including an annual bonus, and where the new Participant makes an Elective Deferral election after the service period commences, the Employer will pro rate the election by multiplying the performance based Compensation by the ratio of the number of days left in the performance period at the time of the election, over the total number of days in the entire performance period.

(D) Election Duration . A Participant’s Elective Deferral election applies only to the Participant’s Compensation earned in the next Taxable Year following the Taxable Year in which the Participant makes the election. A Participant, subject to Plan requirements regarding election timing, including those in Article VII, may make a new election, or revoke or modify an existing election effective no earlier than for the next Taxable Year.

2.03 Employer Contributions . In each Taxable Year, the Employer may make discretionary Employer Contributions for any or all Participants, which need not be uniform among Participants.

2.04 Allocation Conditions . There are no conditions generally applicable to receive an allocation of Employer Contributions, unless the Employer establishes conditions with respect to a particular discretionary Employer Contribution.

2.05 Timing . The Employer may elect to make any Employer Contribution for a Taxable Year at such times as Code §409A or Applicable Guidance may permit.

2.06 Administration . The Employer will administer all Employer Contributions in the same manner as Elective Deferrals, except as the Plan otherwise provides. The Employer will credit any Elective Deferrals to a Participant’s Account as soon as practicable after the date the amount of the Elective Deferral would otherwise have become due and payable to the Participant and will credit any Employer Contributions to a Participant’s Account as soon as practicable after the date of the amount of the Employer Contribution is determined. Any Employer Contribution is not subject to an immediate Participant right to elect a cash payment in lieu of the Employer Contribution and such amounts are payable only in accordance with the Plan terms.

III. VESTING AND FORFEITURE

3.01 Vesting Schedule . Participants shall always be immediately one hundred percent (100%) Vested in their Elective Deferral Accounts. The Employer may separately establish a vesting schedule for any Employer Contributions.

3.02 Application of Forfeitures . A Participant will forfeit any non-Vested Accrued Benefit upon Separation from Service. The Employer will keep all forfeitures.

IV. BENEFIT PAYMENTS

4.01 Separation from Service or Death . The Employer will pay to the Participant the Vested Accrued Benefit held in the Participant’s Account following the earlier of the Participant’s Separation from Service or death. Payment will commence at the time and payment will be made in the form and method specified under Section 4.03. In the event of the Participant’s death, the Plan will pay to the Participant’s Beneficiary the Participant’s Vested Accrued Benefit or any remaining amount thereof if benefits to the Participant already have commenced, in accordance with the Participant’s election.

(A) Distribution to Specified Employees . Notwithstanding anything to the contrary in the Plan or in a Participant election, the Employer may not distribute to a Specified Employee, based on Separation from Service, earlier than 6 months following Separation from Service (or if earlier, upon the Specified Employee’s death).

4.02 Other Payment Events . In addition to the payment events under Section 4.01, the Employer will pay to a Participant all or any part of the Participant’s Account: (i) at a Specified Time or Pursuant to a Fixed Schedule elected by the Participant with respect to Education and In-Service subaccounts; or (ii) based upon an Unforeseeable Emergency. Payment will commence at the time and payment will be made in the form and method specified under Section 4.03.

4.03 Form, Timing and Method of Payment Election . All distributions will be in cash. Subject to the provisions of this paragraph, a Participant shall make an initial payment election as to the method of payment under Section 4.03(A) and may make a change to an election under Section 4.03(B). Until the Employer completely distributes a Participant’s Vested Accrued Benefit, the Plan will continue to credit the Participant’s Account with Earnings, in accordance with Section 5.02. Except as provided below, a Participant may elect either a lump sum payment or substantially equal annual installments (not to exceed 10) with respect to a Retirement subaccount and an In-Service subaccount. If no election is made as to method, payment shall be made in a lump sum. Distribution from an Education subaccount may only be made in 4 substantially equal annual installments. Distributions from a Retirement Account as a result of Separation from Service after Retirement Age shall be made (or commence) in January of the calendar year following the calendar year in which Separation from Service occurs. Distributions from an In-Service subaccount, an Education subaccount, or a Retirement subaccount, when a Separation from Service occurs prior to Retirement Age (including death prior to Retirement Age), shall be made as soon as administratively feasible following the date of Separation from Service (or death), and shall be made in a lump sum payment (except that payments from the remaining account balance in an Education subaccount or In-Service subaccount, where payments have already commenced prior to Separation from Service, shall continue to be made under the schedule then in effect). If Separation from Service occurs after Retirement Age and before commencement of distribution from an In-Service subaccount or Education subaccount, any such subaccount shall be added to the Retirement subaccount and distributed accordingly. Payments made because of Unforeseeable Emergency shall be made (or commence) as soon as administratively feasible following such event. In the event of death after attaining Retirement Age or after payments from an Account have begun, a lump sum payment to the Beneficiary shall be made as soon as administratively feasible after date of death if the Participant had previously elected a lump sum distribution to the Beneficiary pursuant to Section 4.03(A) (initial payment election) or pursuant to Section 4.03(B)(1) (change to payment election). Disability shall not be treated as a distribution event if Separation from Service has not occurred.

(A) Initial Payment Election . A Participant, as to an In-Service subaccount shall make an initial payment election with respect to a Specified Time and pursuant to a Fixed Schedule at the time of the Participant’s first Elective Deferral election into such subaccount. A Participant, as to an Education subaccount, shall make an initial election with respect to a Specified Time at the time of the Participant’s first Elective Deferral election into such subaccount (the Fixed Schedule being 4 substantially equal annual payments). As to a Retirement subaccount, a Participant shall make an initial payment election as to a method of payment (Fixed Schedule) at the time of his or her first deferred election into such subaccount (the Specified Time being the date following Separation of Service as provided in Section 4.03 above). A Participant shall make any permissible initial payment election on a form the Employer provides for that purpose. At the time of any such first Elective Deferral election into any Account, a Participant may elect to have a lump sum payment made to his or her Beneficiary in lieu of the form of payment that otherwise has been selected for payout during the Participant’s life.

(B) Changes to Payment Election . A Participant may change the Participant’s initial payment election (or change election) as to any or all Deferred Compensation (but only as to timing of start of payments for an Education subaccount and form of payments for a Retirement subaccount), including any Plan default payment applicable in the absence of an election. Any such change election must comply with this Section 4.03(B). A Participant must make any change election on a form the Employer provides for such purpose.

(1) Conditions on Changes to Payment Elections. Any Participant change election: (i) may not take effect until at least 12 months following the date of the change election; (ii) must result in the first payment under the change election being made not earlier than 5 years following the date upon which the originally-elected payment would have been made (except if payment is on account of death, or Unforeseeable Emergency); and (iii) if the change election relates to a Participant’s previous election of a Specified Time or Pursuant to a Fixed Schedule, the Participant must make the change election not less than 12 months prior to the date of the first scheduled payment under the election being changed (or, in the case of installment payments treated as a single payment, 12 months prior to the date the first amount was scheduled to be paid).

(2) Definition of “Payment.” Except as otherwise provided in Section 4.03(B)(3), a “payment” for purposes of applying Section 4.03(B)(1) is each separately identified amount the Employer is obligated to pay to a Participant on a determinable date and includes amounts paid for the benefit of the Participant. An amount is “separately identified” only if the Employer can objectively determine the amount.

(3) Installment Payments . As set forth in Applicable Guidance, and for purposes of making a change to a payment election under this Section 4.03(B), a series of installment payments will be treated as a single payment. For purposes of this Section 4.03(B)(3), a “series of installment payments” means payment of a series of substantially equal periodic amounts to be paid over a predetermined number of years, except to the extent that any increase in the payment amounts reflects reasonable Earnings through the date of payment.

(4) Coordination with Anti-Acceleration Rule . In applying Section 4.03(C), “payment” means as described in Sections 4.03(B)(2) and (3). A Participant under a payment change election may change the form of payment to a more rapid schedule (including a change from installments to a lump-sum payment) without violating Section 4.03(C), provided any such change remains subject to the payment change election provisions under this Section 4.03(B). Accordingly, if the Participant’s payment change election modifies the payment method from installments to a lump-sum payment, a payment change election must satisfy Section 4.03(B)(1) measured from the first installment payment. If a payment change election only modifies the timing of an installment payment, the payment change election must apply to each installment and must satisfy Section 4.03(B) measured from each installment payment.

(C) No Acceleration . Neither the Employer nor the Participant may accelerate the time or schedule of any payment under the Plan except as Applicable Guidance may permit. For this purpose, the following are not an acceleration: (i) a payment required under a domestic relations order under Code §414(p)(1)(B); (ii) a payment required under a certificate of divestiture under Code §1043(b)(2); or (iii) a payment to pay the FICA tax (and income tax withholding related to the FICA) on the Deferred Compensation.

(D) Cash-Out Upon Separation . Notwithstanding a Participant’s payment election or any contrary Plan terms, the Employer will distribute in a single cash payment the entire Vested Accrued Benefit of a Participant who has incurred a Separation from Service where the Participant’s Vested Accrued Benefit does not exceed $50,000 (the amount set forth as the mandatory cash-out limit in the Plan prior to this Plan’s restatement). The Employer will make any payment under this Section 4.03(D) as soon as administratively feasible following Separation from Service.

4.04 Withholding . The Employer that employs the Participant at the time of payment or employed the Participant immediately prior to a Separation from Service (with such Employer including such payment on a Form W-2 issued by the Employer to the Participant) will withhold from any payment made under the Plan and from any amount taxable under Code §409A, all applicable taxes, and any and all other amounts required to be withheld under federal, state or local law, including Notice 2005-1 and Applicable Guidance.

4.05 Administration of Payment Date(s) . The Employer shall pay a Participant’s Vested Accrued Benefit on any date that is administratively feasible following any Plan specified payment date or date of any authorized distribution event or the date specified in any valid payment election, but in no event later than two and one-half (2 ½) months following any such date; and provided further that the Participant shall not be permitted, directly or indirectly, to designate the taxable year of the payment.

V. TRUST ELECTION AND PLAN EARNINGS

5.01 Unfunded Plan/Trust Election . The Employer intends this Plan to be an unfunded plan that is wholly or partially exempt under ERISA. No Participant, Beneficiary or successor thereto has any legal or equitable right, interest or claim to any property or assets of the Employer, including assets held in any Account under the Plan except as the Plan otherwise permits. The Employer’s obligation to pay Plan benefits is an unsecured promise to pay. If the Employer elects to create a Trust, the applicable provisions of the Plan continue to apply, including those of this Section 5.01. The Trustee will pay Plan benefits in accordance with the Plan terms or upon the Employer’s direction consistent with Plan terms. The Employer intends to make notional contributions in lieu of actual contributions to the Plan, and the Employer, therefore, may elect not to invest any Plan contributions. If the Employer elects to invest any Plan contributions, such investments may be held for the Employer’s benefit in providing for the Employer’s obligations under the Plan or for such other purposes as the Employer may determine. Any assets held in Plan Accounts remain subject to claims of the Employer’s general creditors and no Participant’s or Beneficiary’s claim to Plan assets has any priority over any general unsecured creditor of the Employer.

(A) Restriction on Trust Assets . If the Employer establishes, directly or indirectly, a Trust (or any other arrangement Applicable Guidance may describe), the Trust and the Trust assets must be and must remain located within the United States, except with respect to a Participant who performs outside the United States substantially all services giving rise to the Deferred Compensation. The Trust may not contain any provision limiting the Trust assets to the payment of Plan benefits upon a Change in the Employer’s Financial Health (as defined in Applicable Guidance), even if the assets remain subject to claims of the Employer’s general creditors. For this purpose, the Employer, upon a Change in the Employer’s Financial Health, may not transfer Deferred Compensation to the Trust. Any Trust the Employer establishes under this Plan shall be further subject to Applicable Guidance, compliance with which is necessary to avoid the transfer of assets to the Trust being treated as a transfer of property under Code §83.

5.02 Notional Earnings . The Employer, under the Plan, periodically will credit notional Plan contributions with a determinable amount of notional Earnings (at a specified fixed or floating interest rate or other specified index or indices based on established and published financial investment benchmarks) to each Participant’s Account. The Participant has the right to direct the investment of the Participant’s Account pursuant to conditions established by the Employer. This right is limited strictly to investment direction and the Participant will not be entitled to the distribution of any Account asset except as the Plan otherwise permits. Except as otherwise provided in the Plan or Trust, all Plan assets, including all incidents of ownership, at all times will be the sole property of the Employer.

VI. MISCELLANEOUS

6.01 No Assignment . Except with respect to a payment required under a domestic relations order under Code §414(p)(l)(B), no Participant or Beneficiary has the right to anticipate, alienate, assign, pledge, encumber, sell, transfer, mortgage or otherwise in any manner convey in advance of actual receipt, the Participant’s Account. Prior to actual payment, a Participant’s Account is not subject to the debts, judgments or other obligations of the Participant or Beneficiary and is not subject to attachment, seizure, garnishment or other process applicable to the Participant or Beneficiary.

6.02 Not Employment Contract . This Plan is not a contract for employment between an Employer and any Employee who is a Participant. This Plan does not entitle any Participant to continued employment with the Employer, and benefits under the Plan are limited to payment of a Participant’s Vested Accrued Benefit in accordance with the terms of the Plan.

6.03 Amendment and Termination .

(A) Amendment . The Employer reserves the right to amend the Plan at any time to comply with Code §409A, Notice 2005-1, Prop. Treas. Reg. §1.409A and other Applicable Guidance or for any other purpose, provided that such amendment will not result in taxation to any Participant under Code §409A. Except as the Plan and Applicable Guidance otherwise may require, the Employer may make any such amendments effective immediately.

(B) Termination . The Employer, by action of the Board, may terminate, but is not required to terminate, the Plan and distribute Plan Accounts under the following circumstances:

(1) Dissolution/Bankruptcy . The Employer may terminate the Plan within 12 months following a dissolution of a corporate Employer taxable under Code §331 or with approval of a Bankruptcy court under 11 U.S.C. §503(b)(1)(A), provided that the Deferred Compensation is paid to the Participants and is included in the Participants’ gross income in the latest calendar year: (i) in which the plan termination occurs; (ii) in which the amounts no longer are subject to a Substantial Risk of Forfeiture (as defined in Applicable Guidance); or (iii) in which the payment is administratively feasible.

(2) Change in Control . The Employer may terminate the Plan within the 30 days preceding or the 12 months following a Change in Control (as defined in Applicable Guidance) provided the Employer distributes all Plan Accounts (and must distribute the accounts under any substantially similar Employer plan which plan the Employer also must terminate) within 12 months following the Plan termination.

(3) Other . The Employer may terminate the Plan for any other reason in the Employer’s discretion provided that: (i) the Employer also terminates all Aggregated Plans (as defined in Applicable Guidance) in which any Participant also is a participant; (ii) the Employer makes no payments under the Plan in the 12 months following the Plan termination date other than payments the Employer would have made under the Plan irrespective of Plan termination; (iii) the Employer makes all payments under the Plan within 24 months following the Plan termination date; and (iv) the Employer within 3 years following the Plan termination date does not adopt a new plan covering any Participant that would be an Aggregated Plan.

(4) Applicable Guidance and Plan Types . The Employer may terminate the Plan under such other circumstances as Applicable Guidance may permit. In addition, for purposes of plan termination, the portion of the Plan representing Employer Contribution Accounts shall be considered to be a nonelective account balance plan type and the portion of the Plan representing Elective Deferral Accounts shall be considered to be an elective account balance plan type.

(C) Effect on Vesting . Any Plan amendment or termination will not reduce the Vested Accrued Benefit held in any Participant Account at the date of the amendment or termination and also may not accelerate vesting except as may be permitted without subjecting any Participant to taxation under Code §409A.

(D) Cessation of Future Contributions . The Employer may elect at any time to amend the Plan to cease future Elective Deferrals as of the next taxable year. In such event, the Plan remains in effect (except those provisions permitting the frozen contribution type) until all Accounts are paid in accordance with the Plan terms, or, if earlier, upon the Employer’s termination of the Plan.

6.04 Severability . If any provision of the Plan is determined by a proper authority to be invalid, the remaining portions of the Plan will continue in effect and will be interpreted consistent with the elimination of the invalid provision.

6.05 Notice and Elections . Any notice required or permitted under the Plan shall be sufficient if in writing and hand delivered or sent by registered or certified mail. Such notice shall be deemed given as of the date of delivery or, if delivery is made by mail, as of the date shown on the postmark on the receipt for registration or certification. Mailed notice to the Chairman & CEO and the President of the Employer or to the Employer shall be directed to the Employer’s address. Mailed notice to a Participant or Beneficiary shall be directed to the individual’s last known address in the Employer’s records. Any election made under the Plan must be in writing and delivered (electronically, by facsimile, or by mail), to the Employer pursuant to procedures established by the Employer. The Employer will prescribe the form of any Plan notice or election to be given to or made by Participants. Any notice or election will be deemed given or made as of the date of actual receipt, or if given or made by certified mail, as of 3 business days after mailing.

6.06 Administration . The Employer will administer and interpret the Plan, including making a determination of the Vested Accrued Benefit due any Participant or Beneficiary under the Plan. As a condition of receiving any Plan benefit to which a Participant or Beneficiary otherwise may be entitled, a Participant or Beneficiary will provide such information and perform such other acts as the Employer reasonably may request. The Employer may retain agents to assist in the administration of the Plan and may delegate to agents or to an officer of the Employer such duties as it sees fit. The decision of the Employer or its designee concerning the administration of the Plan is final and is binding upon all persons having any interest in the Plan. The Employer will indemnify, defend and hold harmless any Employee designated by the Employer to assist in the administration of the Plan from any and all loss, damage, claims, expense or liability with respect to this Plan (collectively, “claims”) except claims arising from the intentional acts or gross negligence of the Employee.

6.07 Account Statements . The Employer will provide each Participant with a statement of the Participant’s Vested Accrued Benefit at least annually as of the last Valuation Date in the Plan Year. The Employer also will provide Account statements to any Beneficiary of a deceased Participant with a Vested Accrued Benefit remaining in the Plan.

6.08 Accounting . The Employer will maintain for each Participant as is necessary for proper administration of the Plan, an Elective Deferral Account (and Retirement, In-Service and Education subaccounts) and an Employer Contribution Account (if any Employer Contributions are made).

6.09 Costs and Expenses . The Employer will pay the costs, expenses and fees associated with the operation of the Plan, excluding those incurred by Participants or Beneficiaries. The Employer will pay costs, expenses or fees charged by or incurred by the Trustee only as provided in the Trust or other agreement between the Employer and the Trustee.

6.10 Reporting . The Employer employing the Participant will report Deferred Compensation for Participants on Form W-2 in accordance with Notice 2005-1 and Applicable Guidance.

6.11 Claims Procedure .

(A) Claim . Any person or entity claiming a benefit, requesting an interpretation or ruling under the Plan (hereinafter referred to as "Claimant"), or requesting information under the Plan shall present the request in writing to the Employer, which shall respond in writing as soon as practicable.

(B) Denial of Claim . If the claim or request is denied, the written notice of denial shall state:

The reasons for denial, which specific reference to the Plan provisions on which the denial is based;

A description of any additional material or information required and an explanation of why it is necessary; and

An explanation of the Plan's claim review procedure.

(C) Review of Claim Denial . Any Claimant whose claim or request is denied or who has not received a response within sixty (60) days may request a review by notice given in writing to the Employer. Such request must be made within sixty (60) days after receipt by the Claimant of the written notice of denial, or in the event Claimant has not received a response sixty (60) days after receipt by the Employer of Claimant's claim or request. The claim or request shall be reviewed by the President of MidAmerican Energy Holdings Company, who may, but shall not be required to, grant the Claimant a hearing. On review, the Claimant may have representation, examine pertinent documents, and submit issues and comments in writing. If the claim is made by the President of MidAmerican Energy Holdings Company, the claim or request shall be reviewed by the Chairman of the Board of Directors of MidAmerican Energy Holdings Company. If the claim is made by the Chairman of the Board of Directors of MidAmerican Energy Company, the claim or request shall be reviewed by the Compensation Committee of the Board of Directors of MidAmerican Energy Company.

(D) Final Decision . The decision on review shall normally be made within sixty (60) days after the Employer's receipt of Claimant's claim or request. If an extension of time is required for a hearing or other special circumstances, the Claimant shall be notified and the time limit shall be one hundred twenty (120) days. The decision shall be in writing and shall state the reasons and the relevant Plan provisions. All decisions on review shall be final and bind all parties concerned.

6.12 Beneficiary Designation .

(A) Beneficiary Designation . Each Participant shall have the right, at any time, to designate one (1) or more persons or entities as Beneficiary (both primary as well as secondary) to whom benefits under the Plan shall be paid in the event of Participant’s death prior to complete distribution of the Participant’s Incentive Account(s) or Deferred Account balances. Each Beneficiary designation shall be in a written form prescribed by the Company and shall be effective only when filed with the Company during the Participant’s lifetime.

(B) Changing Beneficiary . Any Beneficiary designation may be changed by a Participant without the consent of the previously named Beneficiary by the filing of a new Beneficiary designation with the Company. The filing of a new designation shall cancel all designations previously filed.

(C) Change in Marital Status . If the Participant’s marital status changes after the Participant has designated a Beneficiary, the following shall apply until such time as the Participant submits a revised Beneficiary form.

(1)	If the Participant is married at death but was unmarried when the designation was made, the designation shall be void.

(2)	If the Participant is unmarried at death but was married when the designation was made:

(i)	The designation shall be void if the former spouse was named as Beneficiary.

(ii)	The designation shall remain valid if the spouse was not named and a non-spouse Beneficiary was named.

(3)	If the Participant was married when the designation was made and is married to a different spouse at death:

(i)	The designation shall be void if the former spouse was named as Beneficiary.

(ii)	The designation shall remain valid if the former spouse was not named and a non-spouse Beneficiary was named.

(D) No Beneficiary Designation . If any Participant fails to designate a Beneficiary in the manner provided above, if the designation is void, or if the Beneficiary designated by a deceased Participant dies before the Participant or before complete distribution of the Participant’s benefits, the Participant’s Beneficiary shall be the person in the first of the following classes in which there is a survivor:

(1)

The Participant’s surviving spouse;

(2)

The Participant’s children (including stepchildren) in equal shares, except if any of the children predeceases the Participant but leaves surviving issue, then such issue shall take by right of representation the share the deceased child would have taken if living;

(3)

The Participant’s estate.

(E) Effect of Payment . Payment to the Beneficiary or other proper legal representative of the Beneficiary shall completely discharge the Company’s obligations under the Plan and the Company may require a release to that effect from the Beneficiary or other proper legal representative of the Beneficiary prior to the distribution.

(F) Minor or Incompetent Beneficiary . If a Beneficiary is a minor or otherwise reasonably determined by the Employer to be legally incompetent, the Employer may cause the Plan or Trust to pay the Participant’s Vested Accrued Benefit to a guardian, trustee or other proper legal representative of the Beneficiary.

6.13 Governing Law . The provisions of the Plan shall be construed and interpreted according to the laws of the State of Iowa, except as preempted by federal law.

6.14. Protective Provisions . A Participant will cooperate with the Employer by furnishing any and all information requested by the Employer, in order to facilitate the payment of benefits hereunder.

6.15. Successors and Assigns . The provisions of this Plan shall bind and inure to the benefit of the Employer and its successors and assigns. The term successors as used herein shall include any corporate or other business entity which shall, whether by merger, consolidation, purchase or otherwise acquire all or substantially all of the business and assets of the Employer, and successors of any such corporation or other business entity.

VII. 2005, 2006, 2007 AND 2008 TRANSITION RULES AND PROVISIONS APPLICABLE

BECAUSE PLAN WAS EFFECTIVE BEFORE 2005

7.01 Code §409A Amounts . The terms of this Plan control as to any Deferred Compensation under the Plan, whether vested on or before or after December 31, 2004. There are not “grandfathered amounts” under the Plan pursuant to Applicable Guidance. All Deferred Compensation amounts under the Plan are “409A Amounts”.

7.02 2005, 2006, 2007 and 2008 Operational Rules . The following provisions apply to the Plan during the 2005, 2006, 2007 and 2008 Taxable Years, as specifically provided in each subsection.

(A) Good Faith . As to 409A Amounts, the Employer will operate the Plan during the 2005, 2006, 2007 and 2008 Taxable Years in good faith compliance in accordance with: (i) Notice 2005-1; (ii) Code §409A; and (iii) any Applicable Guidance. The Employer also may operate the Plan consistent with the Prop. Treas. Reg. §1.409A before such regulations become effective and may apply such regulations to the extent that they are inconsistent with Notice 2005-1. Although the Employer intends this Plan document to comply with the provisions of Notice 2005-1 and of Prop. Treas. Reg. §1.409A, the Employer will not apply any Plan provision which is inconsistent therewith and, by December 31, 2008, will amend any such provision to comply with Applicable Guidance. The Employer and the Participants may not exercise discretion under the Plan in a manner that would violate Code §409A.

(B) Participant’s Revised Deferral Election . A Participant, on or before December 31, 2008, may make a new payment election as to any previously deferred 409A Amount, except that a Participant cannot in 2006, 2007 or 2008 change payment elections with respect to payments that the Participant would otherwise receive in the year of the new payment election, or to cause payments to be made in the year of the new payment election that are otherwise scheduled to be made after the year of the new payment election. Any such election must be a permissible election under Section 4.03(A), but an election under this Section 7.02(B) is not treated as a change in the timing or form of distribution and need not comply with Section 4.03(B) as it applies to such changes.

(C) 2005 Deferral Election by March 15, 2005 . Notwithstanding Section 2.02, if the Plan was in existence on or before December 31, 2004 (as described in Notice 2005-1, Q/A 21), a Participant may make an Elective Deferral election as to 409A Amounts earned for service to the Employer through December 31, 2005. A Participant must make an election under this Section 7.02(C) no later than March 15, 2005, and in accordance with the Plan terms as in effect on or before December 31, 2005. The election applies only as to amounts not paid or payable to the Participant at the time of the election. This Section applies only to the 2005 Taxable Year and reflects Amendment No. 1 to the Plan executed December 21, 2005.

(D) Cancellation of Election/Participation . A Participant, on or before December 31, 2005, may elect to cancel any or all existing Elective Deferral elections. The Employer will distribute to an affected Participant all 409A Amounts subject to an election under this 7.02(D) and the Participant will include such amounts in income, in the 2005 Taxable Year, or if later, in the Taxable Year in which such amounts are Vested. This section reflects Amendment No. 1 to the Plan executed December 21, 2005.

7.03 Incorporation of Applicable Guidance . In the event of Applicable Guidance that is contrary to any Plan provision, the Employer, as of the effective date of the Applicable Guidance, will operate the Plan in conformance therewith and will disregard any inconsistent Plan provision. Any such Applicable Guidance is deemed to be incorporated by reference into the Plan and to supersede any contrary provision during any period in which the Employer is permitted to comply operationally with the Applicable Guidance and before a formal Plan amendment is required.

IN WITNESS WHEREOF, MidAmerican Energy Holdings Company has caused this instrument to be signed by its duly authorized officer on this 25th day of February, 2008.

MIDAMERICAN ENERGY HOLDINGS COMPANY

By: /s/ Gregory E. Abel

Gregory E. Abel, President

EXHIBIT 10.10

FIRST AMENDED AND RESTATED

SUPPLEMENTAL RETIREMENT PLAN FOR

DESIGNATED OFFICERS

MidAmerican Energy Company

Amended and Restated as of January 1, 2005

MIDAMERICAN ENERGY COMPANY

FIRST AMENDED AND RESTATED

SUPPLEMENTAL RETIREMENT PLAN FOR DESIGNATED OFFICERS

CONTENTS

		Page

I.	ESTABLISHMENT	1

II.	PURPOSE	1

III.	CONSTRUCTION	1

	Section 3.1. Definitions	1
	Section 3.2. Gender and Number	5
	Section 3.3. Severability	5

IV.	ADMINISTRATION	6

	Section 4.1. The Committee	6
	Section 4.2. Authority of the Committee	6
	Section 4.3. Decisions Binding	6
	Section 4.4. Terms of Participation	6

V.	ELIGIBILITY AND PARTICIPATION	7

	Section 5.1. Participation	7
	Section 5.2. No Employment Guarantee	7

VI.	BENEFITS	7

	Section 6.1. Benefits Upon Normal Retirement	7
	Section 6.2. Benefits Upon Early Retirement	7
	Section 6.3. Benefits Upon Disability	7
	Section 6.4. Benefits Upon Death	7
	Section 6.5. Forfeiture Upon Termination for Cause	8
	Section 6.6. General Payout Restrictions	9
	Section 6.7. General Release	9
	Section 6.8 Distribution to Specified Employees	9
	Section 6.9 General Release	9

VII.	INDIVIDUAL ACCOUNTS AND THE RABBI TRUST	9

	Section 7.1. Establishment of a Rabbi Trust	9
	Section 7.2. Payment of Benefits from the Trust	9

VIII.	BENEFICIARY DESIGNATION	10

	Section 8.1. Designation of Beneficiary	10
	Section 8.2. Payment to a Participant’s Estate	10

IX.	MISCELLANEOUS	10

	Section 9.1. Unfunded Plan	10
	Section 9.2. Withholding	10
	Section 9.3. Costs of the Plan	10
	Section 9.4. Nontransferability	10
	Section 9.5. Successors	11
	Section 9.6. Address of Participant or Beneficiary	11
	Section 9.7. Applicable Law	11
	Section 9.8 Amendment	11
	Section 9.9 Termination	11

X.	CLAIMS PROCEDURE	12

	Section 10.1. Claim	12
	Section 10.2. Denial of Claim	12
	Section 10.3. Review of Claim Denial	12
	Section 10.4. Final Decision	13

MIDAMERICAN ENERGY COMPANY

FIRST AMENDED AND RESTATED

SUPPLEMENTAL RETIREMENT PLAN FOR DESIGNATED OFFICERS

I.	ESTABLISHMENT

MidAmerican Energy Company, an Iowa corporation (the “Company”), and a wholly owned subsidiary of MidAmerican Energy Holdings Company (“Holdings”), hereby adopts the Company’s First Amended and Restated Supplemental Retirement Plan for Designated Officers (the “Plan”), amended and restated effective as of January 1, 2005. The Plan is an amendment and restatement of the Supplemental Retirement Plan for Designated Officers, which was adopted on January 1, 1996, as previously amended and restated as of May 10, 1999.

This Plan, as amended and restated, shall apply only to Plan Participants who have accrued a vested benefit under the Plan after December 31, 2004. As to those Participants, their entire vested benefit under the Plan shall be governed by the terms of the Plan as amended and restated herein. All other Participants (those who have not accrued a vested benefit after December 31, 2004) shall have their benefits and rights under the Plan governed by the terms of the Plan as in effect on December 31, 2004.

The Plan, as amended and restated, is intended to comply with the provisions of Section 409A of the Internal Revenue Code, as amended, and Applicable Guidance. As used in this Plan, the term “Applicable Guidance” means Treasury Regulations issued pursuant to Section 409A of the Internal Revenue Code, or other written Treasury or IRS guidance regarding Section 409A, including IRS Notice 2005-1. In the event of Applicable Guidance that is contrary to any Plan provision, the Company, as of the effective date of the Applicable Guidance, will operate the Plan in conformance therewith and will disregard any inconsistent Plan provision. Any such Applicable Guidance is deemed to be incorporated by reference into the Plan and to supersede any contrary provision during any period in which the Company is permitted to comply operationally with the Applicable Guidance and before a formal Plan amendment is required.

II.

PURPOSE

The purpose of the Plan is to enable the Company, Holdings and their Subsidiaries to attract, retain, and motivate persons of outstanding competence, and to provide appropriate supplemental retirement and survivor benefits to Designated Officers of the Company, Holdings and their Subsidiaries.

III.	CONSTRUCTION

Section 3. 1 . Definitions . Whenever used herein, the following terms shall have the respective meanings set forth below:

	(a)	“Board” means the Board of Directors of the Company.

	(b)	“Cause” means, unless otherwise defined in a Participant’s employment agreement, a Participant’s discharge from the employment of the Company, Holdings or any Subsidiary because such Participant willfully engages in conduct, or lack thereof, that is demonstrably and materially injurious to the Company, Holdings or any Subsidiary or their business reputation or financial structure. Determination of “Cause” shall be made by the Committee in the exercise of good faith and reasonable judgment.

(c)

“Code” means the Internal Revenue Code of 1986, as amended.

(d)

“Committee” means an Administrative Committee comprised of Company employees selected by the President of the Company and approved by the Board to administer the Plan pursuant to Article IV herein.

(e)

“Company” means MidAmerican Energy Company. With respect to the obligation to make payments to any Participant under the Plan, Company shall mean the company who employs the Participant. For purposes of determining whether there has been a Separation from Service with the Company, Company means all entities with whom the Company would be considered a single employer under Code Sections 414 (b) and (c).

(f)

“Designated Officer” means an officer of the Company, Holdings or any Subsidiary who has been approved by the Board or the Committee, as applicable, to participate in the Plan.

(g)

“Disability” means a condition of any medically determinable physical or mental impairment which can be expected to result in death or can be expected to last for a continuous period of not less than 12 months and the Executive (i) is unable to engage in any substantial gainful activity or (ii) has been receiving income replacement benefits for a period of not less than 3 months under a group long term disability insurance policy covering employees of the Company. Such Disability shall be determined by the Committee in the exercise of good faith and reasonable judgment in reliance on competent medical advice from one or more qualified individuals selected by the Committee.

(h)

“Disability Benefit” means, for such Participant, the Normal Retirement Supplemental Benefit or Early Retirement Supplemental Benefit, computed as though the Participant incurred a Separation from Service on the date he or she reaches age 55 or, if the Participant has already reached age 55, on the date of Disability.

(i)

“Early Retirement Total Benefit” means a Normal Retirement Total Benefit reducing the 65% in the formula in Section 3.l(q) at the rate of one percentage point for each full and one percentage point for each fraction of a year that, on the Participants Early Retirement Date, such Participant’s age is less than sixty-five (65) years ( i.e ., 60% at age 60, 55% at age 55).

(j)

“Early Retirement” means, for each Participant, the commencement of benefits after Separation from Service of such Participant other than because of death or Cause, but prior to such Participant reaching Normal Retirement Age.

(k)

“Early Retirement Date” means the first day of the month following the later of (a) Participant’s attainment of age fifty-five (55) or (b) Participant’s date of Separation from Service prior to reaching Normal Retirement Age.

(l)

“Early Retirement Supplemental Benefit” (see subsection (p) below).

(m)

“Effective Date” means January 1, 1996. The Effective Date for the Plan as amended and restated herein means January 1, 2005.

(n)

“ERISA” means the Employee Retirement Income Security Act of 1974, as amended from time to time, or any successor thereto.

(o)

“Normal Retirement Total Benefit” means the annual benefit provided under the Plan on a Participant’s Normal Retirement Date, in the amount of sixty-five percent (65%) of such Participant’s Total Cash Compensation in effect immediately prior to such Participant’s Separation from Service, times a fraction, the numerator being the number of years (including fractions of a year) of participation in this Plan (or participation in a similar supplemental retirement plan of a Predecessor Company) as of the date of Separation from Service, and the denominator being the number of years of participation if the Participant had remained employed to age 55 (the factor shall not exceed 1.0). The Board or the Committee, as applicable, shall have the authority to grant the crediting of service with a former employer of a Participant in the calculation of such Participant’s number of years of participation in the Plan or to provide other credit for service on a case by case basis.

(p)

“Normal Retirement Supplemental Benefit” and “Early Retirement Supplemental Benefit”, respectively, mean the Normal Retirement Total Benefit or Early Retirement Total Benefit, as applicable, reduced by the sum of:

(i)

the annual benefits provided to such Participant under a Tax Qualified Pension Plan (determined as if the Participant elected a joint and 2/3 survivor benefit under such plan and beginning on the same date that payments begin under this Plan);

(ii)

benefits under Iowa-Illinois Gas and Electric Company Supplemental Retirement Plan, the Iowa Resources Inc. and Subsidiaries Supplemental Retirement Income Plan and the Midwest Resources Supplemental Retirement Plan, after converting such benefits to an actuarially equivalent amount, as determined by the Committee in the exercise of good faith and reasonable judgment; and

(iii)

tax qualified defined benefit pension type retirement plan benefits payable to such Participant by other employers of such Participant if service with such other employers is credited as service under the Tax Qualified Pension Plan, after converting such benefits to an actuarially equivalent amount, as determined by the Committee in the exercise of good faith and reasonable judgment;

provided, however, that unless otherwise provided in a Participant’s employment agreement, a Participant’s Normal Retirement Supplemental Benefit and Early Retirement Supplemental Benefit may not exceed $1 million per year. An Early Retirement Supplemental Benefit will not be available to any Participant whose Separation from Service occurs prior to being credited with five (5) Years of Service unless otherwise provided in a Participant’s employment agreement.

(q)

“Normal Retirement Age” means, for each Participant, the attainment of age sixty-five (65) years.

(r)

“Normal Retirement Date” means the first day of the month following the month in which a Participant reaches Normal Retirement Age.

(s)

“Participant” means a Designated Officer of the Company, Holdings or any Subsidiary who has been approved by the Board or the Committee, as applicable, to participate in the Plan, and any retired individual who has a vested accrued benefit under the Plan as specified in Article V.

(t)

“Plan Year” means the calendar year beginning January 1 and ending December 31.

(u)

“Predecessor Company” means CalEnergy Company, Inc., Midwest Resources Inc., Iowa-Illinois Gas and Electric Company, Midwest Energy Company, Iowa Resources Inc., any subsidiaries of any of these companies and any member of the same controlled group of corporations of any of these companies.

(v)

“Rabbi Trust” means a grantor trust, within the meaning of Sections 671-678 of the Code, established by the Company for the benefit of the Participants, both active and retired, and the Participants’ designated beneficiaries, as specified in Article VIII.

(w)

“Separation from Service” means the termination of a Participant’s employment with the Company for any reason, or as otherwise defined in Applicable Guidance.

(x)

“Spouse” means a husband or wife as licensed in marriage by the state.

(y)

“Subsidiary” means a company as to which Holdings or the Company directly or indirectly holds securities representing at least 50% of the total voting power of all voting securities.

(z)

“Survivor’s Benefit” means the benefit payable to a Participant’s surviving Spouse, designated beneficiary or estate under the Plan as specified in Section 6.6 in the event of such Participant’s death.

	(aa)	“Tax Qualified Pension Plan” shall mean the tax qualified defined benefit plan, cash balance plan and money purchase pension plan, if any, maintained by the Company, Holdings or any Subsidiary, but shall not include any profit sharing plans, employee stock ownership plans or qualified salary reduction or cash or deferred plan.

	(bb)	“ Total Cash Compensation” means (i) the highest amount payable to a Participant by the Company, Holdings or any Subsidiary (or a Predecessor Company) as monthly base salary during the five years immediately prior to termination of services (including the year in which termination occurs) multiplied by twelve, plus (ii) the average of the Participant’s Awards during the most recent three year period under the Company’s Key Employee Annual Incentive Plan or its successor plan(s), or bonus awards under a similar annual incentive bonus program for executives of Holdings, a Subsidiary or a Predecessor Company, plus (iii) the prior three-year average annual amount of any other special, additional or non-recurring bonus awards or other compensation, but only if such awards or compensation are (A) required to be included in Total Cash Compensation under a Participant’s employment agreement or (B) approved by the Committee for inclusion in Total Cash Compensation as set forth in written notice to a Participant. Monthly base salary shall include amounts deferred under any § 401(k) plans, § 125 cafeteria plans, nonqualified deferred compensation plans or similar arrangements. If less than three years of bonus awards have been made for the Participation during the most recent three year period prior to termination of employment, the average of the number of bonus awards actually made during such three year period shall be used.

(cc)

“Year of Service” or “Years of Service” means each full twelve months of service with the Company, Holdings, a Subsidiary or a Predecessor Company.

Section 3.2. Gender and Number . Except when otherwise indicated by the context, any masculine term used herein also shall include the feminine; the plural shall include the singular; and the singular shall include the plural.

Section 3.3. Severability . In the event any provision of the Plan shall be held illegal or invalid for any reason, the illegality or invalidity shall not affect the remaining parts of the Plan; and the Plan shall be construed and enforced as if the illegal or invalid provision had not been included.

IV.	ADMINISTRATION

Section 4.1. The Committee . The Plan shall be administered by the Committee which shall be selected by the Board, and unless the Board otherwise directs in writing, the Committee shall possess, in addition to any powers specifically vested in the Committee, any or all of the powers vested in the Board hereunder. The Committee may delegate the responsibility of performing ministerial acts to such administrative agents as it deems advisable or desirable to carry out the purpose of the Plan.

Section 4.2. Authority of the Committee . The Committee shall have the power to construe and interpret the Plan and any agreement or instrument entered into hereunder, to prescribe, amend, or waive rules and regulations for the Plan’s administration; and to make any other determination which may be necessary or advisable for the Plan’s administration. The Committee may correct any defect or supply any omission or reconcile any inconsistency in the Plan in the manner and to the extent reasonable to effect its purpose. The Committee shall have full discretion to administer the Plan as it sees fit. All decisions of the Committee shall be final and binding absent manifest error.

The Company may elect to insure the lives of Participants; in such case, Participants must agree to undergo physical examinations and otherwise cooperate in obtaining such insurance as a condition precedent to participation in the Plan. Any such life insurance policies shall be owned by and be considered a general asset of the Company. Subject to Section 7.2, no Participant or beneficiary shall have any rights to or interest in or shall be entitled to any benefits under such policies.

Section 4.3. Decisions Binding . All determinations and decisions made by the Committee pursuant to the provisions of the Plan, and all related orders or resolutions of the Board shall be final, conclusive, and binding on all persons, including the Company, its shareholders, employees, the Participants and their estates and designated beneficiaries.

The Board or the Committee, as applicable, shall have the full power to amend or terminate the Plan at any time; provided that no such amendment or termination shall adversely affect the vested or accrued rights of any Participant under the Plan without such Participant’s written consent.

Section 4.4. Terms of Participation . The Board or Committee, as applicable, may establish terms of participation in the Plan for any Participant which may differ from the specific terms of the Plan and which may be more favorable than the terms applicable to Participants generally. Without limitation, the Board or the Committee, as applicable, may establish a minimum annual benefit or death benefit for any Participant, on a case-by-case basis, which annual benefit or death benefit may be greater than the annual benefit or death benefit to which such Participant would otherwise be entitled under the benefit formulas set forth in the Plan. However, any such additional terms may not violate the provisions of Section 409A of the Internal Revenue Code or Applicable Guidance.

V.	ELIGIBILITY AND PARTICIPATION

Section 5.1. Participation . Upon approval by the Board or the Committee, as applicable, Designated Officers shall become Participants under the Plan as of the date specified by the Board or the Committee. Retired individuals who have a vested accrued benefit under the Plan will also be considered to be Participants.

Section 5.2. No Employment Guarantee . Neither this Plan nor any action taken hereunder shall be construed as giving a Participant the right to be retained as an employee of the Company, Holdings or any Subsidiary for any period.

VI.

BENEFITS

Section 6.1. Benefits Upon Normal Retirement . Upon a Participant’s Separation from Service on or after reaching Normal Retirement Age, the Company shall pay to such Participant, as compensation for services rendered prior to such date, his or her Normal Retirement Supplemental Benefit in equal monthly installments commencing on the Normal Retirement Date, or, if later, the first day of the month then following Separation from Service, and continuing on the first day of each month thereafter during the lifetime of such Participant.

Section 6.2. Benefits Upon Early Retirement . Upon a Participant’s Separation from Service before reaching Normal Retirement Age, the Company shall pay to the Participant, as compensation for services rendered prior to such date, his or her Early Retirement Supplemental Benefit in equal monthly installments commencing on the Participant’s Early Retirement Date, and, in all cases, continuing on the first day of each month thereafter during the lifetime of such Participant.

Section 6.3. Benefits Upon Disability . Upon a Participant’s Disability prior to reaching Normal Retirement Age, the Company shall begin payment to the Participant on the later of (a) the first day of the month following Disability or (b) the first day of the month following the Participant’s attainment of age 55, as compensation for services rendered prior to such date, his or her Disability Benefit in equal monthly installments and continuing on the first day of each month thereafter during the lifetime of such Participant.

Section 6.4. Benefits Upon Death . Upon a Participant’s death, the Company shall pay to such Participant’s designated beneficiary or estate, as appropriate, the following Survivor’s Benefit:

(a)

Death Prior to Commencement of Benefits . If a Participant dies prior to commencement of the payment of any benefit hereunder, the Company shall pay to such Participant’s designated beneficiary or estate a Survivor’s Benefit equal to the Normal Retirement Supplemental Benefit (without application of the percentage reduction based upon years of participation prior to age 55) in one hundred eighty (180) equal monthly installments commencing on the first date of the month following such date of death and receipt of a death certificate by the Company, and continuing on the first day of each month thereafter until the one hundred eighty (180) payments have been made.

(b)

Death After Commencement of Benefits . If a Participant dies after commencement of the payment of any benefit hereunder, the Company shall pay to the Participant’s surviving Spouse a Survivor’s Benefit commencing on the first day of the month following such date of death and receipt of a death certificate by the Company and continuing on the first day of each month thereafter for the remaining lifetime of the surviving Spouse. The Survivor’s Benefit means a benefit equal to two-thirds of the Normal Retirement Supplemental Benefit, Early Retirement Supplemental Benefit or Disability Benefit, as applicable, that the Participant was receiving immediately prior to death, except that the actuarial value of the total Survivor’s Benefit (and present valued back to the time benefits commenced) shall be limited to fifty percent (50%) of the total benefit based upon the actuarial value of such total benefit at the time benefits commenced. Both calculations shall use the same actuarial assumptions in effect under the MidAmerican Energy Company Retirement Plan (or subsequent replacement plan) at the time benefits commenced.

(c)

Payment by the Company of the benefit in Section 6.4(a) or (b) shall relieve the Company of the obligation to pay a Normal Retirement Supplemental Benefit, an Early Retirement Supplemental Benefit, a Disability Benefit, or any other benefit which the Participant might have otherwise received under the Plan.

(d)

In the event a Participant dies without a surviving Spouse, after commencement of the payment of any benefits hereunder, the Company shall pay to such Participant’s designated beneficiary or estate a Survivor’s Benefit equal to the Normal Retirement Supplemental Benefit, Early Retirement Supplemental Benefit or Disability Benefit, as applicable, that the Participant was receiving immediately prior to death such that a total of one hundred eighty (180) equal monthly installments is paid to the Participant and such Participant’s designated beneficiary or estate. The Survivor’s Benefit portion shall commence on the first day of the month following such date of death and receipt of a death certificate by the Company, and continue on the first day of each month thereafter until a total of one hundred eighty (180) payments have been made.

Section 6.5. Forfeiture Upon Termination for Cause . Unless otherwise provided in a Participant’s employment agreement or otherwise provided by the Committee in writing to a Participant, upon a Participant’s Separation from Service for Cause, such Participant shall immediately forfeit all rights and benefits provided under the Plan, and the Company shall have no further obligation to such Participant under the Plan.

Section 6.6. General Payout Restrictions . No benefits shall be paid under this Plan prior to the actual Separation from Service of a Participant.

Section 6.7. No Acceleration . Neither the Company nor the Participant may accelerate the time or schedule of any Plan payment except as Applicable Guidance may permit. For this purpose, the following are not an acceleration: (i) a payment required under a domestic relations order under Code §414(p)(1)(B); (ii) a payment required under a certificate of divestiture under Code §1043(b)(2); or (iii) a payment to pay the FICA tax (and income tax withholding related to the FICA) on the deferred compensation.

Section 6.8. Distribution to Specified Employees . Notwithstanding anything to the contrary in the Plan or in a Participant payment election, the Plan may not distribute to a Specified Employee, based on Separation from Service, earlier than 6 months following Separation from Service (or if earlier, upon the Specified Employee’s death). A “Specified Employee” means a Participant who is described in Section 416(i) of the Internal Revenue Code, disregarding paragraph (5) thereof. However, a Participant is not a Specified Employee unless any stock of the Company (or of a member of the same group of controlled entities as Company) is publicly traded on an established securities market or otherwise.

Section 6.9. General Release . Unless otherwise provided in a Participant’s employment agreement, the Committee in its discretion may require a Participant to execute a general release of claims, in such form as the Company may prescribe, as a condition to the payment of benefits hereunder.

VII.	INDIVIDUAL ACCOUNTS AND THE RABBI TRUST

Section 7.1. Establishment of a Rabbi Trust . After the Effective Date, the Company shall be authorized, but shall not be required, to establish a revocable Rabbi Trust for the benefit of the Participants, both active and retired. Any such Rabbi Trust shall have an independent trustee, selected by the Company, and, it shall contain restrictions on the Company’s ability to amend or terminate any of the terms thereof after the Rabbi Trust shall become irrevocable as provided in Section 7.2.

All assets held in the Rabbi Trust (while revocable or irrevocable) shall at all times be specifically subject to the claims of the Company’s general creditors in the event of bankruptcy or insolvency; such terms shall be specifically defined within the provisions of the Rabbi Trust, along with a required procedure for notifying the Trustee of any such bankruptcy or insolvency.

Section 7.2. Payment of Benefits from the Trust . The Company shall be primarily obligated to pay all benefits of Participants under the Plan, whether the Rabbi Trust is revocable or irrevocable at the time. In the event the Company fails to fulfill any such obligation hereunder in a timely manner, the Trustee shall be empowered, under the terms of the Rabbi Trust, to either cash in any related life insurance policies or to borrow against the policies, to the extent necessary to pay past due benefits directly from the Trust.

VIII.

BENEFICIARY DESIGNATION

Section 8.1. Designation of Beneficiary . Each Participant shall be entitled to designate one or more beneficiaries by filing a signed, written notice of such designation with the Committee, in a form as the Committee may prescribe. A Participant may revoke or modify a beneficiary designation at any time by filing a new beneficiary designation form with the Committee.

Section 8.2. Payment to a Participant’s Estate . A Participant’s beneficiary designation shall be deemed automatically revoked in the event all designated beneficiaries predecease such Participant or, if the sole beneficiary is such Participant’s Spouse, in the event of dissolution of marriage. In such event, or in the event a Participant does not designate a beneficiary, the benefits under Sections 6.5(a) and 6.5(d) shall be paid to such Participant’s estate.

IX.	MISCELLANEOUS

Section 9.1. Unfunded Plan . This Plan is intended to be an unfunded plan maintained primarily to provide benefits to a “select group of management or highly compensated employees” within the meaning of Sections 201, 301, and 401 of ERISA and, therefore, is further intended to be exempt from the provisions of Parts 2, 3, and 4 of Title I of ERISA. Accordingly, the Committee may terminate the Plan for any or all Participants in order to achieve and maintain this intended result, provided that previously accrued benefits hereunder shall not be reduced or otherwise adversely affected without the written consent of the affected Participants.

Section 9.2. Withholding . The Company shall have the right to require Participants to remit to the Company an amount sufficient to satisfy Federal, state, and local tax withholding requirements, or to deduct from any or all payments made pursuant to the Plan amounts sufficient to satisfy such tax withholding requirements. In the event any FICA, FUTA, Social Security, Medicare or any similar taxes become due on benefits (or the value of such benefits) accrued under this Plan at any time prior to the actual payment of benefits under this Plan, the Company shall be authorized to withhold from the regular salary of such Participant the amount of any such tax payable by the Participant. Withholding shall take place during the same calendar year in which the taxes on such benefits become due, or at such time as may be required by Internal Revenue Service regulations.

Section 9.3. Costs of the Plan . All costs of implementing and administering the Plan shall be borne by the Company.

Section 9.4. Nontransferability . Neither the Participants nor any designated beneficiary shall have the right to sell, assign, transfer, or otherwise convey the right to receive any payment hereunder; nor shall any such payment be subject to attachment, garnishment, levy, pledge, bankruptcy, or any other manner or kind of execution in connection with any claim against the Participants or any designated beneficiary thereof.

Section 9.5. Successors . All obligations of the Company under the Plan shall be binding upon and inure to the benefit of any successor to the Company, whether the existence of such successor is the direct or indirect result of a merger, consolidation, or reorganization involving the Company or the purchase or other acquisition of all or substantially all of the business and/or assets of the Company.

Section 9.6. Address of Participant or Beneficiary . Each Participant shall keep the Company apprised of his or her current address and that of any designated beneficiary during his or her participation in the Plan. Upon the death of a Participant, any beneficiaries entitled to receive benefit payment under the Plan shall keep the Company apprised of their current address until the entire amount to be distributed has been paid.

Section 9.7. Applicable Law . To the extent not preempted by Federal law, the Plan shall be governed by and construed in accordance with the laws of the state of Iowa.

Section 9.8. Amendment . The Company reserves the right to amend the Plan at any time to comply with Code §409A and Applicable Guidance or for any other purpose, provided that such amendment will not result in taxation to any Participant under Code §409A. Except as the Plan and Applicable Guidance otherwise may require, the Company may make any such amendments effective immediately.

Section 9.9. Termination. The Company, by action of the Board, may terminate, but is not required to terminate, the Plan and distribute Plan Accounts under the following circumstances:

(a) Dissolution/Bankruptcy. The Company may terminate the Plan within 12 months following a dissolution of the Company or with approval of a Bankruptcy court under 11 U.S.C. §503(b)(1)(A), provided that the deferred compensation is paid to the Participants and is included in the Participants’ gross income in the latest calendar year: (i) in which the plan termination occurs; (ii) in which the amounts no longer are subject to a Substantial Risk of Forfeiture (as defined in Applicable Guidance); or (iii) in which the payment is administratively practicable.

(b) Change in Control. The Company may terminate the Plan within the 30 days preceding or the 12 months following a Change in Control (as defined in Applicable Guidance) provided the Company distributes all Plan Accounts (and must distribute the accounts under any substantially similar Company plan which plan the Company also must terminate) within 12 months following the Plan termination.

(c) Other. The Company may terminate the Plan for any other reason in the Company’s discretion provided that: (i) the Company also terminates all aggregated plans in which any Participant also is a participant; (ii) the Plan makes no payments in the 12 months following the Plan termination date other than payments the Plan would have made irrespective of Plan termination; (iii) the Plan makes all payments within 24 months following the Plan termination date; and (iv) the Company within 3 years following the Plan termination date does not adopt a new plan covering any Participant that would be an Aggregated Plan.

(d) Applicable Guidance. The Company may terminate the Plan under such other circumstances as Applicable Guidance may permit.

X.	CLAIMS PROCEDURE

Section 10.1. Claim . Any person or entity claiming a benefit, requesting an interpretation or ruling under the Plan (hereinafter referred to as “Claimant”) shall present the request in writing to the Chairman & CEO and the President of MidAmerican Energy Holdings Company (“Chairman & CEO and President”), who shall respond in writing as soon as practical. The decision shall be in writing and shall state the reasons and the relevant Plan provisions. All decisions on review shall be final and bind all parties concerned.

Section 10.2. Denial of Claim . If the claim or request is denied, the written notice of denial shall state:

a)	The reasons for denial, with specific reference to the Plan provisions on which the denial is based;

b)	A description of any additional material or information required and an explanation of why it is necessary; and

c)	An explanation of the Plan’s claim review procedure.

Section 10.3. Review of Claim Denial. Any Claimant whose claim or request is denied or who has not received a response within sixty (60) days may request a review by notice given in writing to the Chairman & CEO and the President. Such request must be made within sixty (60) days after receipt by the Claimant of the written notice of denial, or in the event Claimant has not received a response sixty (60) days after receipt by the Chairman & CEO and the President of Claimant’s claim or request. The claim or request shall be reviewed by the Chairman & CEO and the President, who may, but shall not be required to, grant the Claimant a hearing. On review, the Claimant may have representation, examine pertinent documents, and submit issues and comments in writing.

If the claim is made by the President of MidAmerican Energy Holdings Company, the claim or appeal of the claim shall be reviewed by the Chairman & CEO of MidAmerican Energy Holdings Company. If the claim is made by the Chairman & CEO of MidAmerican Energy Holdings Company, the claim or review of the claim shall be reviewed by the Compensation Committee of MidAmerican Energy Holdings Company.

Section 10.4. Final Decision . The decision on review shall normally be made within sixty (60) days after receipt of Claimant’s claim or request. If an extension of time is required for a hearing or other special circumstances, the Claimant shall be notified and the time limit shall be one hundred twenty (120) days.

Executed this 25th day of February , 2008

	MIDAMERICAN ENERGY COMPANY

	By: /s/ Paul J. Leighton
	Paul J. Leighton
	Vice President

EXHIBIT 10.11

MidAmerican Energy Holdings Company

LONG-TERM INCENTIVE PARTNERSHIP PLAN

As Amended and Restated January 1, 2007

PLAN DOCUMENT

MIDAMERICAN ENERGY HOLDINGS COMPANY

LONG-TERM INCENTIVE PARTNERSHIP PLAN

ARTICLE I – PURPOSE AND EFFECTIVE DATE

1.1

Purpose . The purpose of this Long-Term Incentive Partnership Plan (the “Plan”) is to permit a select group of management employees of MidAmerican Energy Holdings Company and its subsidiaries to share in significant increases in the value of the Company realized through the efforts of these individuals. It is intended that the Plan, by providing this award and deferral opportunity (U.S. only), will assist the Company in retaining and attracting individuals of exceptional ability and will act as an incentive to align their interests with those of the Company. For purposes of Internal Revenue Code Section 409A, Incentive Accounts are considered to be part of a nonelective account balance plan type and Deferral Accounts are considered to be part of an elective account balance plan type.

1.2

Effective Date . The Plan was effective as of March 14, 2000, was subsequently restated as of January 1, 2003 and again restated as of January 1, 2004, with the current restated Plan effective January 1, 2007, (See Section 13.2 for good faith compliance as to 409A Amounts during 2005, 2006, 2007 and 2008).

ARTICLE II – DEFINITIONS

For the purpose of the Plan, the following terms shall have the meanings indicated, unless the context clearly indicates otherwise:

2.1

Base Salary . “Base Salary” means the annual base salary rate payable to a Participant effective January 1 of the calendar year for a particular Award Year. For purposes of the Plan, Base Salary shall be calculated before reduction for any amounts deferred by the Participant pursuant to the Company’s tax qualified plans which may be maintained under Section 401(k) or Section 125 of the Internal Revenue Code of 1986, as amended (the “Code”), or pursuant to the MidAmerican Energy Holdings Company Executive Voluntary Deferred Compensation Plan or any other non-qualified plan which permits the voluntary deferral of compensation. Inclusion of any forms of compensation other than such “wages” and deferred “wages” is subject to approval of the Chairman & CEO and the President.

2.2	Beneficiary . “Beneficiary” means the person, persons or entity, as designated by the Participant, entitled under Article VIII to receive any Plan benefits payable after the Participant’s death.

2.3	Board . “Board” means the Board of Directors of the Company or any duly authorized committee.

2.4

Company . “Company” means MidAmerican Energy Holdings Company, a Des Moines Iowa based corporation, and any directly or indirectly affiliated subsidiary corporations, any other affiliate designated by the Board, or any predecessor or successor to the business of any thereof. However, with respect to all matters involving administration of the Plan, including the authority to amend and terminate the Plan, Company shall mean MidAmerican Energy Holdings Company. With respect to the obligation to make payments to any Participant under the Plan, Company shall mean MidAmerican Energy Holdings Company and the Company who employs the Participant, but not any other Company. For purposes of determining whether there has been a Separation from Service with the Company, Company means all entities with whom the Company would be considered a single employer under Code Sections 414 (b) and (c).

2.5	Determination Date . “Determination Date” means the last business day of each month.

2.6

Disability . “Disability” means a condition of a Participant who by reason of any medically determinable physical or mental impairment which can be expected to result in death or can be expected to last for a continuous period of not less than 12 months: (i) is unable to engage in any substantial gainful activity; or (ii) is receiving income replacement benefits for a period of not less than 3 months under a long term disability plan covering employees of the Company.

2.7

Incentive Account(s) . “Incentive Account(s)” means the account or accounts maintained on the books of the Company with respect to each Incentive Award and used solely to calculate the amount which may be payable to each Participant under the Plan and shall not constitute a separate fund of assets. Participants may have more than one Incentive Account maintained on their behalf.

2.8

Incentive Award(s) . “Incentive Award(s)” means the award determined and allocated under the terms of the Plan. Each Incentive Award(s) shall be designated by the year to which the award relates (the “Award Year”) even though the value of the award may be determined and credited to a Participant’s Incentive Account in a subsequent year. An example: The Year 2007 Incentive Award may relate to the performance of the Company over the calendar year 2007 (the Award Year), even though the Incentive Award will only be determinable in 2008.

2.9

Interest . “Interest” means the amount credited to each Participant’s Incentive Account(s) on each Determination Date. Prior to the start of each calendar year, the Chief Financial Officer of the Company shall select a range of asset allocation models from the Valuation Funds. Participants shall then vote on which asset allocation model shall be used for crediting Interest for the calendar year for all Incentive Accounts of all Participants. Such credits to a Participant’s Incentive Account(s) may be either positive or negative to reflect the increase or decrease in value of the Incentive Account(s) in accordance with the provisions of this Plan.

2.10	Net Income . “Net Income” means the definition as applied under Generally Accepted Accounting Principles. The Chairman & CEO and the President may adjust Net Income for extraordinary and non-recurring events, when appropriate.

2.11	Nomination Committee . “Nomination Committee” means a group of Participants appointed by the Chairman & CEO and the President each plan year for the purposes of recommending the Initial and Performance Allocations.

2.12

Participant . “Participant” means any employee who is eligible, pursuant to Article III, below, to participate in this Plan, and who has been so notified by the Chairman & CEO and the President. Such employee shall remain a Participant in this Plan for any award that has been made until such time as all benefits payable for that specific Award Year have been paid in accordance with the provisions hereof. A Participant may have an Incentive Account(s) or a Deferred Account and not be chosen to participate in a subsequent Award Year. Each Participant may be referred to as either a “Partner” or an “Associate”. Any such designation does not convey any different or additional rights or responsibilities with respect to a Participant and does not affect in any manner the Participant’s employment status with the Employer.

2.13	Plan . “Plan” means this Long-Term Incentive Partnership Plan as amended from time to time.

2.14

Retirement and Retirement Age . “Retirement” for purposes of Section 5.3 means the termination of employment with the Company of the Participant after attaining age fifty-five (55) and five (5) years of service. For all other purposes under the Plan “Retirement” means termination of employment with the Company after attaining age fifty-five (55) and “Retirement Age” means age fifty-five (55).

2.15	Separation from Service. “Separation from Service” or “Separates from Service” means a Participant’s termination of employment with the Company or as otherwise defined in Applicable Guidance (See Section 7.1(a)).

2.16

Valuation Funds . “Valuation Funds” means one or more of the independently established funds or indices that are identified and listed in Exhibit A. These Valuation Funds are used solely to calculate the Interest that is credited to each Incentive Account(s) in accordance with Article V, and do not represent, nor should they be interpreted to convey any beneficial interest on the part of the Participant in any specific asset or other property of the Company. The Chairman & CEO and the President shall select the various Valuation Funds available under the Plan and shall set forth a list of these Valuation Funds attached hereto as Exhibit A, which may be amended from time to time at the discretion of the Chairman & CEO and the President.

2.17	Vest or Vested . “Vest” or “Vested” means deferred compensation which is not subject to a Substantial Risk of Forfeiture (as defined in Applicable Guidance) or to a requirement to perform further services for the Employer.

ARTICLE III – ELIGIBILITY AND PARTICIPATION

3.1

Eligibility . Eligibility to participate in the Plan shall be limited to those select key employees of the Company who are designated by the Chairman & CEO and the President from time to time. The Chairman & CEO and the President of the Company shall not be Participants in the Plan. The Chairman & CEO and the President of the Company may designate certain Participants as Associate Participants to reflect their contributions to the success of the Company. All other Participants shall be considered full Participants (“Partners”). An Associate Participant may later be designated as a Partner.

3.2	Participation . An employee’s participation in the Plan for any Award Year shall be effective upon notification to the employee by the Chairman & CEO and the President.

ARTICLE IV – INCENTIVE AWARD

4.1

Annual Award . Prior to the beginning of each Award Year, the Chairman & CEO and the President shall determine whether an Incentive Award shall be available for such Award Year. If an Incentive Award is made available, the Chairman & CEO and the President will establish the award categories based upon Net Income target goals or such other criteria, as they deem appropriate for the Award Year (including, but not limited to, safety, environmental and risk management goals).

4.2	Allocation of Points . The total amount of the Incentive Award (if the established goals are met for an Award Year) shall be allocated among the eligible Participants based upon a maximum of 100,000 points allocated to Participants in the following manner:

Initial Point Allocation . The Nomination Committee shall make recommendations to the Chairman & CEO and the President to allocate initial points among participants for that year. The Chairman & CEO and the President shall either accept these recommendations or make adjustments that may increase, decrease or eliminate any initial point allocation to any individual Participant. Any points that are not allocated to Participants may be either refunded to the Company or reallocated at a later date as performance points at the discretion of the Chairman & CEO and the President.

Performance Point Allocation . Within sixty (60) days prior to the end of the Award Year, the Nomination Committee shall make recommendations to the Chairman & CEO and the President to allocate all, or a portion of, the remaining points for the Award Year, among the eligible Participants. The Chairman & CEO and the President shall either accept these recommendations or make adjustments that may increase, decrease or eliminate any such remaining point allocation to any individual Participant. Any award that is not allocated to Participants will be returned to the Company as an offset to Plan expenses. The recommendation of the Nomination Committee and the decision of the Chairman & CEO and the President for allocation of points to a Participant based on performance shall be based on subjective performance criteria where the subjective performance criteria relate to the performance of the individual Participant, a group of Participants that includes the Participant, or a business unit for which the Participant provides services.

c)	Value of a Point. The value of a point shall be equal to the total Incentive Award (determined by the results of Company performance as applied to the goals established for the Award Year) divided by the total number of points awarded.

Maximum Allocation . Notwithstanding the above, the dollar value of the sum of the initial and performance point allocations made on behalf of any Participant for any single Award Year shall not exceed one hundred fifty percent (150%) of that Participant’s Base Salary for that Award Year, unless such limit is waived by the Chairman & CEO and the President with respect to a Participant.

4.3

Determination of Annual Awards . The dollar value of any Incentive Award shall be determined by the Chairman & CEO and the President as soon as practical after the close of the Award Year, but in no event shall the dollar value of the Award be determined later than March 1 st of the year following the Award Year.

4.4

Reduction of Awards . The Chairman & CEO and the President may, in their sole discretion, establish certain criteria that must be met for an Incentive Award to be awarded in full. These criteria may include the achievement of certain safety performance goals, environmental, risk management or other goals established by the Chairman & CEO and the President. The determination of whether any applicable goals have been achieved with respect to an Incentive Award shall be determined by the Chairman & CEO and the President, as of the time that the dollar value of that Incentive Award is determined in Section 4.3 above. If any such goal is not met, the Chairman & CEO and the President may reduce the Incentive Award by an amount as they determine in their sole discretion. In addition, with respect to an individual Participant, if the Chairman & CEO and the President, in their sole discretion, determine that the Participant has not performed at a level during the Award Year deemed sufficient to have contributed to the success of the Company, the Participant’s point allocation may be reduced.

ARTICLE V – INCENTIVE ACCOUNT(S)

5.1

Accounts . The Company shall maintain a separate bookkeeping account on behalf of each Participant in the Plan for each Incentive Award. The value of any Incentive Award allocated to each Participant plus any Interest earned thereon shall be added to such Participant’s Incentive Account for the applicable Award Year. Any distribution attributable to an Incentive Account shall reduce the Incentive Account as of the date of distribution. These Incentive Accounts shall be used solely to calculate the amount payable to each Participant under the Plan and shall not constitute a separate fund of assets.

5.2

Timing of Credits . The value of a Participant’s share of any Incentive Award for an Award Year shall be credited to a Participant’s Incentive Account for such Award Year as of the day determined by the Chairman & CEO and the President, but in no event shall the date be later than March 1 st of the year following the Award Year. Each Incentive Account shall be increased or decreased by the Interest credited on each Determination Date as though the balance of that Incentive Account as of the date the Incentive Award is credited to a Participant’s Incentive Account had been invested in the applicable Valuation Funds chosen by the Investment Committee. Any distributions to a Participant shall reduce the Participant’s Incentive Account(s) as of the date of such distribution.

5.3

Vesting of Accounts . Each Participant shall be twenty percent (20%) Vested in his or her Incentive Account on December 31 st of the Award Year and an additional twenty percent (20%) on December 31 of each subsequent year. Participants must be employed on December 31 st to Vest for the year. The Chairman & CEO and the President may accelerate Vesting (but not accelerate payment), or may establish criteria with respect to a Participant (in addition to the passage of time) before Vesting will occur with respect to any Incentive Award; provided, however, that any portion of an Incentive Award that has already Vested with the passage of time shall not be subject to any such additional vesting criteria, and provided further that no additional vesting criteria shall postpone the date of payment of the Incentive Award as provided under Section 6.1. The Participant shall be considered to be one hundred percent (100%) Vested in the event of termination of service as a result of a Disability or death, and shall be considered to be one hundred percent (100%) Vested in the event of Retirement, but only with respect to Incentive Awards granted for years prior to 2004.

5.4	Statement of Accounts . The Company shall give to each Participant a statement showing the balances in the Participant’s Incentive Account(s) no less frequently than on an annual basis.

ARTICLE VI – PLAN BENEFITS

6.1

Normal Benefit . The balance of each Participant’s Incentive Account(s) shall be paid as soon as administratively feasible following the end of the fourth year following the Award Year, but in any event no later than two and one-half (2 ½) months following the end of such fourth year. Unless deferred pursuant to Section 6.3 below, such amount shall be paid in a lump sum.

6.2

Early Termination Benefit . In the event that a Participant Separates from Service with the Company prior to the end of the fourth year following the end of an Award Year, the Participant shall receive the Vested portion of the Incentive Account(s) as of the most recent Determination Date preceding the date of payment, payable in a lump sum; provided, however, that if the Participant has a deferral election on file with respect to an Incentive Account pursuant to Article VII, and incurs a Separation from Service after reaching Retirement Age, payment of the Vested amount of any Incentive Account shall be governed by Article VII with respect to the deferral election made by the Participant. If paid in a lump sum, the amount shall be paid as soon as administratively feasible after the Separation from Service, but in no event later than two and one-half (2 ½) months following the date of Separation from Service. In addition, the provisions of Section 7.2(A) shall apply to distributions under this Section 6.2.

6.3

Deferred Benefit (U.S. only) . With respect to any Incentive Award, the Participant may elect, in a manner acceptable to the Company, to defer the receipt of all or a portion of the value of the Incentive Account due under this Plan by filing an election to do so within 90 (ninety) days after the beginning of the Award Year relating to the Incentive Award to be deferred (and, with respect to the 2008 and later Award Years, by filing an election to defer before the beginning of the Award Year).

The portion of the Incentive Account previously elected to be deferred shall be transferred as of the last day of the fourth year following the end of the Award Year to a Deferred Account (or as soon as administratively feasible following Separation from Service if an appropriate deferral election has previously been made) and shall thereafter be subject to the terms and conditions of Article VII herein (any portion not previously elected to be deferred shall be paid pursuant to the provisions of Section 6.1 above);

b)	Such an election shall comply with the provisions of Section 7.4(A) and shall only permit the deferral of benefits otherwise payable under Section 6.1 above, and the limited circumstance set forth in Section 6.2 in the event of Retirement; and

Such an election shall completely satisfy and discharge all obligations on the part of the Company to the Participant (and the Participant’s Beneficiary) with respect to such Incentive Account, and the Participant’s (and Participant’s Beneficiary’s) rights under the Plan with respect to such Incentive Account shall terminate and shall be governed by the provisions of the Plan dealing with Deferred Accounts.

An example: A Participant may elect to defer the receipt of his 2008 Incentive Award by filing an election to do so prior to December 31, 2007. If such election is in a form acceptable to the Company, the balance of the Vested portion of the 2008 Incentive Account as of December 31, 2012, shall be transferred to a Deferred Account for the Participant as of that date.

6.4

Death Benefit . In the event of the death of a Participant prior to payment of any Incentive Account(s), the Participant’s Beneficiary shall receive the value of the Incentive Account(s) determined as of the date of death. Such amounts shall be paid in a lump sum as soon as administratively feasible after the death of the Participant, but in no event later than two and one-half (2 ½) months following the date of the Participant’s death.

6.5

Withholding and Payroll Taxes . The Company that employs the Participant at the time of payment shall withhold from any payment made pursuant to the Plan, from an Incentive Account, any taxes required to be withheld from such payments under law. A Beneficiary, however, may elect not to have withholding of federal income tax pursuant to Section 3405(a)(2) of the Code, or any successor provision thereto (U.S. only). If FICA/Medicare taxes are due with respect to all or a portion of an Incentive Account prior to payment from the account, the Participant shall make arrangements satisfactory to the Company for payment of the Participant’s share of such taxes, which may include withholding of such taxes from other regular pay of the Participant.

6.6

Payment to Guardian . If a Plan benefit is payable to a minor, a person declared incompetent or a person incapable of handling the disposition of the property, the Company may direct payment to the guardian, legal representative or person having the care and custody of such minor or person. The Company may require proof of incompetence, incapacity or guardianship, as it may deem appropriate prior to distribution. Such distribution shall completely discharge the Company from all liability with respect to such benefit.

6.7

Effect of Payment . The full payment of the applicable benefit under this Article VI shall completely discharge all obligations on the part of the Company to the Participant (and the Participant’s Beneficiary) with respect to the Incentive Account(s), and the Participant’s (and Participant’s Beneficiary’s) rights under the Plan with respect to the Incentive Account(s) shall terminate.

ARTICLE VII – DEFERRED BENEFIT

7.1	Definitions . For the purposes of this Article VII, the following terms shall have the meanings indicated, unless the context clearly indicates otherwise.

a) “ Applicable Guidance ” means Treasury Regulations issued pursuant to Code §409A, or other written Treasury or IRS guidance regarding Code §409A, which is in addition to IRS Notice 2005-1 (“Notice 2005-1”).

b) “ Deferred Account ” means the account established under the Plan for each Participant who elects to defer receipt of benefits under Section 6.3. A Deferred Account shall consist of subaccounts as selected by the Participant, which may be a Retirement Account and an In-Service Account. The Deferred Account is 100% Vested.

c) “ Earnings ” means the notional earnings, gains and losses applicable to a Participant’s Deferred Account as described in Section 7.7.

d) “ Separation From Service ” means a Participant’s termination of employment with the Company or as otherwise defined in Applicable Guidance.

e) “ Specified Employee ” means a Participant who is described in Code §416(i), disregarding paragraph (5) thereof. However, a Participant is not a Specified Employee unless any stock of the Company (or of a member of the same group of controlled entities as Company) is publicly traded on an established securities market or otherwise.

f) “ Specified Time or Pursuant to a Fixed Schedule ” means a specific time or schedule (but not the occurrence of an event) as a Participant payment election may specify, and otherwise as described in Applicable Guidance.

g) “ Unforeseeable Emergency ” means: (i) a severe financial hardship to the Participant resulting from a sudden and unexpected illness or accident of the Participant, the Participant’s spouse or a dependent (as defined in Code §152(a)) of the Participant; (ii) loss of the Participant’s property due to casualty; or (iii) other similar extraordinary and unforeseeable circumstances arising as a result of events beyond the Participant’s control. The amount of the distribution may not exceed the amount necessary to satisfy the Unforeseeable Emergency plus taxes reasonably anticipated as a result of the distribution, after taking into account the extent to which the hardship may be relieved through reimbursement or compensation by insurance or otherwise or by liquidation of the Participant’s assets, to the extent that liquidation of such assets would not itself cause severe financial hardship.

7.2

Separation from Service or Death . The Company will pay to the Participant the balance held in the Participant’s Deferred Account following the earlier of the Participant’s Separation from Service or death. Payment will commence at the time and payment will be made in the form and method specified under Section 7.4. In the event of the Participant’s death, the Plan will pay to the Participant’s Beneficiary the Participant’s Deferred Account balance or any remaining amount thereof if benefits to the Participant already have commenced, in accordance with the Participant’s election.

(A) Distribution to Specified Employees . Notwithstanding anything to the contrary in the Plan or in a Participant payment election, the Company may not distribute to a Specified Employee, based on Separation from Service, earlier than 6 months following Separation from Service (or if earlier, upon the Specified Employee’s death).

7.3

Other Payment Events. In addition to the payment events under Section 7.2, the Company will pay to a Participant all or any part of the Participant’s Deferred Account: (i) at a Specified Time or Pursuant to a Fixed Schedule elected by the Participant with respect to an In-Service subaccount; or (ii) based upon an Unforeseeable Emergency. Payment will commence at the time and payment will be made in the form and method specified under Section 7.4.

7.4

Form, Timing and Method/Payment Election. All distributions will be in cash. Subject to the provisions of this paragraph, a Participant shall make an initial payment election as to the method of payment under Section 7.4(A) and may make a change to an election under Section 7.4(B). If no election to defer payment of an Award has been made by the deadline as set forth in Section 6.3, the timing and method of payment for an Award as set forth in Section 6.1, 6.2 and 6.4 shall be deemed to be the Participant’s initial deferral election for purposes of a change to an election under Section 7.4(B). Until the Company completely distributes a Participant’s Deferred Account, the Plan will continue to credit the Participant’s Deferred Account with Earnings, in accordance with Section 7.7. Except as provided below, a Participant may elect either a lump sum payment or substantially equal annual installments (not to exceed 10) with respect to a Retirement subaccount and an In-Service subaccount. If no election is made as to method, payment shall be made in a lump sum. If no election is made with respect to an In-Service subaccount as to a specified time to begin payments, the date of the regularly scheduled payment for an Incentive Account shall be deemed to be the date to begin payments. Distributions from a Retirement subaccount as a result of Separation from Service after Retirement Age shall be made (or commence) in January following the calendar year in which Separation from Service occurs. Except as provided below, payments from an In-Service subaccount shall commence as soon as administratively feasible following the date selected by the Participant. If Separation from Service occurs after Retirement Age and before commencement of distribution from an In-Service subaccount, the In-Service subaccount shall be added to the Retirement subaccount and distributed accordingly. Distributions from an In-Service subaccount or a Retirement subaccount, when a Separation from Service occurs prior to Retirement Age (including death prior to Retirement Age), shall be made as soon as administratively feasible following the date of Separation from Service (or death) and shall be made in a lump sum payment (except that payments from the remaining account balance in an In-Service subaccount, where payments have already commenced prior to Separation from Service, shall continue to be made under the schedule then in effect). Payments made because of Unforeseeable Emergency shall be made (or commence) as soon as administratively feasible following such event. In the event of death after attaining Retirement Age or after payments from a Deferred Account have begun, a lump sum payment to the Beneficiary shall be made as soon as administratively feasible after date of death if the Participant had previously elected a lump sum distribution to the Beneficiary pursuant to Section 7.4(A) (initial payment election) or pursuant to Section 7.4(B)(1) (change to payment election). Disability shall not be treated as a distribution event if Separation from Service has not occurred.

(A) Initial Payment Election . A Participant, as to an In-Service subaccount shall make an initial payment election with respect to a Specified Time and Pursuant to a Fixed Schedule at the time of the Participant’s first deferred benefit election into such subaccount. As to a Retirement subaccount, a Participant shall make an initial payment election as to a method of payment (Fixed Schedule) at the time of his or her first deferred benefit election into such subaccount (the Specified Time being a date following Separation of Service as provided in Section 7.4 above). A Participant shall make any permissible initial payment election on a form the Company provides for that purpose. At the time of any such first deferred benefit election into any subaccount in his or her Deferred Account, a Participant may elect to have a lump sum payment made to his or her Beneficiary in lieu of the form of payment that otherwise has been selected for payout during the Participant’s life.

(B) Changes to Payment Election . A Participant may change the Participant’s initial payment election (or change election) as to any subaccount in his or her Deferred Account, including any Plan default payment applicable in the absence of an election. Any such change election must comply with this Section 7.4(B). A Participant must make any change election on a form the Company provides for such purpose.

(1) Conditions on Changes to Payment Elections. Any Participant change election: (i) may not take effect until at least 12 months following the date of the change election; (ii) must result in the first payment under the change election being made not earlier than 5 years following the date upon which the originally-elected payment would have been made (except if payment is on account of death, or Unforeseeable Emergency); and (iii) if the change election relates to a Participant’s previous election of a Specified Time or Pursuant to Fixed Schedule, the Participant must make the change election not less than 12 months prior to the date of the first scheduled payment under the election being changed (or, in the case of installment payments treated as a single payment, 12 months prior to the date the first amount was scheduled to be paid).

(2) Definition of “Payment.” Except as otherwise provided in Section 7.4(B)(3), a “payment” for purposes of applying Section 7.4(B)(1) is each separately identified amount the Company is obligated to pay to a Participant on a determinable date and includes amounts paid for the benefit of the Participant. An amount is “separately identified” only if the Company can objectively determine the amount.

(3) Installment Payments. As set forth in Applicable Guidance, and for purposes of making a change to a payment election under this Section 7.4(B), a series of installment payments will be treated as a single payment. For purposes of this Section 7.4(B)(3), a “series of installment payments” means payment of a series of substantially equal periodic amounts to be paid over a predetermined number of years, except to the extent that any increase in the payment amounts reflects reasonable Earnings through the date of payment.

(4) Coordination with Anti-Acceleration Rule. In applying Section 7.4(C), “payment” means as described in Sections 7.4(B)(2) and (3). A Participant under a change payment election may change the form of payment to a more rapid schedule (including a change from installments to a lump-sum payment) without violating Section 7.4(C), provided any such change remains subject to the change payment election provisions under this Section 7.4(B). Accordingly, if the Participant’s payment change election modifies the payment method from installments to a lump-sum payment, a payment change election must satisfy Section 7.4(B)(1) measured from the first installment payment. If a payment change election only modifies the timing of an installment payment, the payment change election must apply to each installment and must satisfy Section 7.4(B) measured from each installment payment.

(C) No Acceleration . Neither the Company nor the Participant may accelerate the time or schedule of any payment under the Plan except as Applicable Guidance may permit. For this purpose, the following are not an acceleration: (i) a payment required under a domestic relations order under Code §414(p)(1)(B); (ii) a payment required under a certificate of divestiture under Code §1043(b)(2); or (iii) a payment to pay the FICA tax (and income tax withholding related to the FICA) on the deferred compensation.

(D) Cash-Out Upon Separation . Notwithstanding a Participant’s payment election or any contrary Plan terms, the Company will distribute in a single cash payment the entire Deferred Account of a Participant who has incurred a Separation from Service where the Participant’s Deferred Account balance does not exceed $10,000. The Company will make any payment under this Section as soon as administratively feasible following Separation from Service.

7.5

Withholding of Income Tax. The Company that employs the Participant at the time of payment or employed the Participant immediately prior to a Separation from Service (with the Company including such payment on a Form W-2 issued by the Company to the Participant) will withhold from any payment made under the Plan from a Deferred Account and from any amount taxable under Code §409A, all applicable taxes, and any and all other amounts required to be withheld under federal, state or local law, including Notice 2005-1 and Applicable Guidance.

7.6

Administration of Payment Date(s). The Company may shall pay a Participant’s Deferred Account balance on any date that is administratively feasible following any Plan specified payment date or date of any authorized distribution event or the date specified in any valid payment election, but in no event later than two and one-half (2 ½) months following any such date; and provided further that the Participant shall not be permitted, directly or indirectly, to designate the taxable year of the payment.

7.7

Notional Earnings. The Company, under the Plan, periodically will credit Deferred Accounts with a determinable amount of notional Earnings (as a specified fixed or floating interest rate or other specified index or indices based on established and published financial investment benchmarks). The Participant has the right to direct the investment of the Participant’s Deferred Account pursuant to conditions established by the Company. This right is limited strictly to investment direction and the Participant will not be entitled to the distribution of any Deferred Account asset except as the Plan otherwise permits. Except as otherwise provided in the Plan or Trust, all Plan assets, including all incidents of ownership, at all times will be the sole property of the Company.

ARTICLE VIII – BENEFICIARY DESIGNATION

8.1

Beneficiary Designation . Each Participant shall have the right, at any time, to designate one (1) or more persons or entities as Beneficiary (both primary as well as secondary) to whom benefits under the Plan shall be paid in the event of Participant’s death prior to complete distribution of the Participant’s Incentive Account(s) or Deferred Account balances. Each Beneficiary designation shall be in a written form prescribed by the Company and shall be effective only when filed with the Company during the Participant’s lifetime.

8.2	Changing Beneficiary . Any Beneficiary designation may be changed by a Participant without the consent of the previously named Beneficiary by the filing of a new Beneficiary designation with the Company. The filing of a new designation shall cancel all designations previously filed.

8.3	Change in Marital Status . If the Participant’s marital status changes after the Participant has designated a Beneficiary, the following shall apply until such time as the Participant submits a revised Beneficiary form.

a)	If the Participant is married at death but was unmarried when the designation was made, the designation shall be void.

b)	If the Participant is unmarried at death but was married when the designation was made:

i)	The designation shall be void if the former spouse was named as Beneficiary.

ii)	The designation shall remain valid if the spouse was not named and a non-spouse Beneficiary was named.

c)	If the Participant was married when the designation was made and is married to a different spouse at death:

i)	The designation shall be void if the former spouse was named as Beneficiary.

ii)	The designation shall remain valid if the former spouse was not named and a non-spouse Beneficiary was named.

8.4

No Beneficiary Designation . If any Participant fails to designate a Beneficiary in the manner provided above, if the designation is void, or if the Beneficiary designated by a deceased Participant dies before the Participant or before complete distribution of the Participant’s benefits, the Participant’s Beneficiary shall be the person in the first of the following classes in which there is a survivor:

a) The Participant’s surviving spouse;

b) T he Participant’s children (including stepchildren) in equal shares, except if any of the children predeceases the Participant but leaves surviving issue, then such issue shall take by right of representation the share the deceased child would have taken if living;

c) T he Participant’s estate.

8.5

Effect of Payment . Payment to Beneficiary or other proper legal representative of the Beneficiary shall completely discharge the Company’s obligations under the Plan and the Company may require a release to that effect from the Beneficiary or other proper legal representative of the Beneficiary prior to the distribution.

8.6	Minor or Incompetent Beneficiary. If a Beneficiary is a minor or otherwise reasonably determined by the Employer to be legally incompetent, the Employer may cause the Plan to pay the Participant’s Vested Accrued Benefit to a guardian, trustee or other proper legal representative of the Beneficiary.

ARTICLE IX – ADMINISTRATION

9.1

Binding Effect of Decisions . Subject to the rights of a Participant under the claims procedure set forth in Article X, the decision or action of the Chairman & CEO and the President with respect to any question arising out of or in connection with the administration, interpretation and application of the Plan and the rules and regulations promulgated hereunder shall be final, conclusive and binding upon all persons having any interest in the Plan.

ARTICLE X – CLAIMS PROCEDURE

10.1

Claim . Any person or entity claiming a benefit, requesting an interpretation or ruling under the Plan (hereinafter referred to as “Claimant”) shall present the request in writing to the Chairman & CEO and the President, who shall respond in writing as soon as practical. The decision shall be in writing and shall state the reasons and the relevant Plan provisions. All decisions on review shall be final and bind all parties concerned.

10.2	Denial of Claim . If the claim or request is denied, the written notice of denial shall state:

a)	The reasons for denial, with specific reference to the Plan provisions on which the denial is based;

b)	A description of any additional material or information required and an explanation of why it is necessary; and

c)	An explanation of the Plan’s claim review procedure.

10.3

Review of Claim Denial. Any Claimant whose claim or request is denied or who has not received a response within sixty (60) days may request a review by notice given in writing to the Chairman & CEO and the President. Such request must be made within sixty (60) days after receipt by the Claimant of the written notice of denial, or in the event Claimant has not received a response sixty (60) days after receipt by the Chairman & CEO and the President of Claimant's claim or request. The claim or request shall be reviewed by the Chairman & CEO and the President, who may, but shall not be required to, grant the Claimant a hearing. On review, the Claimant may have representation, examine pertinent documents, and submit issues and comments in writing.

10.4

Final Decision . The decision on review shall normally be made within sixty (60) days after receipt of Claimant’s claim or request. If an extension of time is required for a hearing or other special circumstances, the Claimant shall be notified and the time limit shall be one hundred twenty (120) days.

ARTICLE XI – AMENDMENT AND TERMINATION OF PLAN

11.1

Amendment . The Company reserves the right to amend the Plan at any time to comply with Code §409A, Notice 2005-1, Prop. Treas. Reg. §1.409A and other Applicable Guidance or for any other purpose, provided that such amendment will not result in taxation to any Participant under Code §409A. Except as the Plan and Applicable Guidance otherwise may require, the Company may make any such amendments effective immediately.

11.2	Termination . The Company, by action of the Board, may terminate, but is not required to terminate, the Plan and distribute Plan Accounts under the following circumstances:

(1) Dissolution/Bankruptcy. The Company may terminate the Plan within 12 months following a dissolution of a corporate Company taxable under Code §331 or with approval of a Bankruptcy court under 11 U.S.C. §503(b)(1)(A), provided that the deferred compensation is paid to the Participants and is included in the Participants’ gross income in the latest calendar year: (i) in which the plan termination occurs; (ii) in which the amounts no longer are subject to a Substantial Risk of Forfeiture; or (iii) in which the payment is administratively practicable.

(2) Change in Control. The Company may terminate the Plan within the 30 days preceding or the 12 months following a Change in Control (as defined in Applicable Guidance) provided the Company distributes all Plan Accounts (and must distribute the accounts under any substantially similar Company plan which plan the Company also must terminate) within 12 months following the Plan termination.

(3) Other. The Company may terminate the Plan for any other reason in the Company’s discretion provided that: (i) the Company also terminates all aggregated plans in which any Participant also is a participant; (ii) the Company makes no payments under the Plan in the 12 months following the Plan termination date other than payments the Company would have made under the Plan irrespective of Plan termination; (iii) the Company makes all payments within 24 months following the Plan termination date; and (iv) the Company within 3 years following the Plan termination date does not adopt a new plan covering any Participant that would be an Aggregated Plan.

(4) Applicable Guidance and Plan Types. The Company may terminate the Plan under such other circumstances as Applicable Guidance may permit. In addition, for purposes of plan termination, the portion of the Plan representing Incentive Accounts shall be considered to be a nonelective account balance plan type and the portion of the Plan representing Deferral Accounts shall be considered to be an elective account balance plan type.

ARTICLE XII – MISCELLANEOUS

12.1

Unfunded Plan . To the extent the Plan is considered an “employee benefit pension plan” under Section 3 (2) the Employee Retirement Income Security Act of 1974, as amended (“ERISA”) with respect to any Participant (because some or all of the payments with respect to a Participant under the Plan have been elected by the Participant to be made from a Retirement Account), the Plan, as to any such Participant, is an unfunded plan maintained primarily to provide deferred compensation benefits for a select group of “management or highly-compensated employees” within the meaning of Sections 201, 301 and 401 of the ERISA, and therefore is exempt from the provisions of Parts 2, 3 and 4 of Title I of ERISA. Accordingly, the Board may terminate the Plan and make no further benefit payments or remove certain employees as Participants if it is determined by the United States Department of Labor, a court of competent jurisdiction, or an opinion of counsel that the Plan constitutes an employee pension benefit plan within the meaning of Section 3 (2) of ERISA (as currently in effect or hereafter amended) which is not so exempt.

12.2	Company Obligation . The obligation to make benefit payments to any Participant under the Plan shall be an obligation solely of the Company.

12.3

Unsecured General Creditor . Notwithstanding any other provision of the Plan, Participants and Participants’ Beneficiaries shall be unsecured general creditors, with no secured or preferential rights to any assets of the Company or any other party for payment of benefits under the Plan. Any property held by the Company for the purpose of generating the cash flow for benefit payments shall remain its general, unpledged and unrestricted assets. The Company’s obligation under the Plan shall be an unfunded and unsecured promise to pay money in the future.

12.4

Trust Fund . The Company shall be responsible for the payment of all benefits provided under the Plan. At its discretion, the Company may establish one (1) or more trusts for the purpose of assisting in the payment of such benefits. Although such a trust shall be irrevocable, its assets shall be held for payment of all the Company’s general creditors in the event of insolvency. To the extent any benefits provided under the Plan are paid from any such trust, the Company shall have no further obligation to pay them. If not paid from the trust, such benefits shall remain the obligation of the Company.

12.5

Nonassignability . Neither a Participant nor any other person shall have any right to commute, sell, assign, transfer, pledge, anticipate, mortgage or otherwise encumber, transfer, hypothecate or convey in advance of actual receipt of the amounts, if any, payable hereunder, or any part thereof, which are, and all rights to which are, expressly declared to be unassignable and non-transferable except only pursuant to the designated Beneficiary in the event of death or Disability or pursuant to a legal will or the laws of intestate succession. No part of the amounts payable shall, prior to actual payment, be subject to seizure or sequestration for the payment of any debts, judgments, alimony or separate maintenance owed by a Participant or any other person, nor be transferable by operation of law in the event of a Participant’s or any other person’s bankruptcy or insolvency.

12.6

Not a Contract of Employment . The Plan shall not constitute a contract of employment between the Company and the Participant. Nothing in the Plan shall give a Participant the right to be retained in the service of the Company or to interfere with the right of the Company to discipline or discharge a Participant at any time.

12.7	Protective Provisions . A Participant will cooperate with the Company by furnishing any and all information requested by the Company, in order to facilitate the payment of benefits hereunder.

12.8	Governing Law . The provisions of the Plan shall be construed and interpreted according to the laws of the State of Iowa, except as preempted by federal law.

12.9	Validity . If any provision of the Plan shall be held illegal or invalid for any reason, said illegality or invalidity shall not affect the remaining parts hereof, but the Plan shall be construed and enforced as if such illegal and invalid provision had never been inserted herein.

12.10

Notice and Elections . Any notice required or permitted under the Plan shall be sufficient if in writing and hand delivered or sent by registered or certified mail. Such notice shall be deemed given as of the date of delivery or, if delivery is made by mail, as of the date shown on the postmark on the receipt for registration or certification. Mailed notice to the Chairman & CEO and the President or to the Company shall be directed to the Company’s address. Mailed notice to a Participant or Beneficiary shall be directed to the individual’s last known address in the Company’s records. Any election made under the Plan must be in writing and delivered (electronically, by facsimile, or my mail) to the Company pursuant to procedures established by the Company. The Employer will prescribe the form of any Plan notice or election to be given to or made by Participants. Any notice or election will be deemed given or made as of the date of actual receipt, or if given or made by certified mail, as of 3 business days after mailing.

12.11

Successors . The provisions of this Plan shall bind and inure to the benefit of the Company and its successors and assigns. The term successors as used herein shall include any corporate or other business entity which shall, whether by merger, consolidation, purchase or otherwise acquire all or substantially all of the business and assets of the Company, and successors of any such corporation or other business entity.

12.12

Account Statements . The Company will provide each Participant with a statement of the Participant’s Incentive Accounts and Deferral Accounts at least annually as of the last day of the most recent calendar year. The Company also will provide account statements to any Beneficiary of a deceased Participant with an Incentive Account or Deferral Account remaining in the Plan.

12.13

Accounting . The Company will maintain for each Participant as is necessary for proper administration of the Plan, an Incentive Account for each Award year and a Deferral Account (and Retirement and In-Service subaccounts).

12.14

Costs and Expenses . The Company will pay the costs, expenses and fees associated with the operation of the Plan, excluding those incurred by Participants or Beneficiaries. The Company will pay costs, expenses or fees charged by or incurred by the Trustee only as provided in the Trust or other agreement between the Company and the Trustee.

12.15

Reporting . The Company will report deferred compensation for Participants on Form W-2 in accordance with Notice 2005-1 and Applicable Guidance.

ARTICLE XIII – TRANSITION RULES AND PROVISIONS

13.1	Code §409A Amounts . The terms of this Plan control as to: (i) any compensation deferred prior to January 1, 2005; and (ii) any compensation deferred in Taxable Years beginning after December 31, 2004. All deferred compensation under this Section 13.1 is a “409A Amount”.

13.2	2005, 2006, 2007 and 2008 Operational Rules. The following provisions apply to the Plan during the 2005, 2006, 2007 and 2008 Taxable Years, as specifically provided in each subsection.

(A) Good Faith . As to 409A Amounts, the Company will operate the Plan during the 2005, 2006, 2007 and 2008 Taxable Years in good faith compliance in accordance with: (i) Notice 2005-1; (ii) Code §409A; and (iii) any Applicable Guidance. The Company also may operate the Plan consistent with the Prop. Treas. Reg. §1.409A before such regulations become effective and may apply such regulations to the extent that they are inconsistent with Notice 2005-1. Although the Company intends this Plan document to comply with the provisions of Notice 2005-1 and of Prop. Treas. Reg. §1.409A, the Company will not apply any Plan provision which is inconsistent therewith and, by December 31, 2008, will amend any such provision to comply with Applicable Guidance. The Company and the Participants may not exercise discretion under the Plan in a manner that would violate Code §409A.

(B) Participant’s Revised Deferral Election . A Participant, on or before December 31, 2008, may make a new payment election as to any previously deferred 409A Amount, except that a Participant cannot in 2006, 2007 or 2008 change payment elections with respect to payments that the Participant would otherwise receive in the year of the new payment election, or to cause payments to be made in the year of the new payment election that are otherwise scheduled to be made after the year of the new payment election. Any such election must be a permissible election under Section 7.4(A), but an election under this Section 13.2(B) is not treated as a change in the timing or form of distribution and need not comply with Section 7.4(B) as it applies to such changes.

13.3

Incorporation of Applicable Guidance. In the event of Applicable Guidance that is contrary to any Plan provision, the Company, as of the effective date of the Applicable Guidance, will operate the Plan in conformance therewith and will disregard any inconsistent Plan provision. Any such Applicable Guidance is deemed to be incorporated by reference into the Plan and to supersede any contrary provision during any period in which the Company is permitted to comply operationally with the Applicable Guidance and before a formal Plan amendment is required.

	MidAmerican Energy Holdings Company

	By:	/s/ Gregory E. Abel
		Gregory E. Abel, President

	Dated:	February 25, 2008

MIDAMERICAN ENERGY HOLDINGS COMPANY

LONG-TERM INCENTIVE PARTNERSHIP PLAN

EXHIBIT A

Following are the Valuation Funds as of January 1, 2005:

· IWD (Russell 1000 Value; Large Cap Value)

· IVV (S&P 500 Index; Large Cap Core)

· IWF (Russell 1000 Growth; Large Cap Growth)

· IWN (Russell 2000 Value; Small Cap Value)

· IWO (Russell 2000 Growth; Small Cap Growth)

· EFA (Morgan Stanley EAFE; International)

· VEMFX (Lehman 1-3 Mo Treas Bill Index)

· Average of the one-year Treasury Bill constant maturity each October 15 (or the preceding business day if a holiday or weekend) of the prior year. (Stable Value)

The Company reserves the right to change the Valuation Funds at any time pursuant to the terms of the Plan.

EXHIBIT 10.12

SUMMARY OF KEY TERMS OF COMPENSATION ARRANGEMENTS

WITH MIDAMERICAN ENERGY HOLDINGS COMPANY

NAMED EXECUTIVE OFFICERS AND DIRECTORS

MidAmerican Energy Holding Company’s (“MEHC”) continuing named executive officers each receive an annual salary and participate in health insurance and other benefit plans on the same basis as other employees, as well as certain other compensation and benefit plans described in MEHC’s Annual Report on Form 10-K.

The named executive officers are also eligible to receive a cash incentive award under MEHC’s Performance Incentive Plan (“PIP”). The PIP provides for a discretionary annual cash award that is determined on a subjective basis and paid in December. In addition to the PIP, the named executive officers are eligible to receive discretionary cash performance awards periodically during the year to reward the accomplishment of significant non-recurring tasks or projects. Messrs. David L. Sokol and Gregory E. Abel have not been granted cash performance awards in the past five years. Messrs. Patrick J. Goodman and Douglas L. Anderson and Ms. Maureen E. Sammon are participants in MEHC’s Long-Term Incentive Partnership Plan (“LTIP”). Messrs. Sokol and Abel do not participate in the LTIP. A copy of the LTIP is attached as Exhibit 10.11 to the MEHC Annual Report on Form 10-K. Base salary for continuing named executive officers for MEHC’s fiscal year ending December 31, 2008, is shown in the following table:

Name and Title	Base Salary

David L. Sokol Chairman and Chief Executive Officer	$1,000,000

Gregory E. Abel President	$1,000,000

Patrick J. Goodman Senior Vice President and Chief Financial Officer	$ 330,000

Douglas L. Anderson Senior Vice President and General Counsel	$ 300,000

Maureen E. Sammon Senior Vice President and Chief Administrative Officer	$ 215,000

Messrs. Sokol and Abel are directors of MEHC, but do not receive additional compensation for their service as directors other than what they receive as employees of MEHC. The other members of the MEHC board of directors do not receive compensation for their service as directors.

EXHIBIT 21.1

MIDAMERICAN ENERGY HOLDINGS COMPANY

SUBSIDIARIES AND JOINT VENTURES

Pursuant to Item 601(b)(21)(ii) of Regulation S-K, we have omitted dormant subsidiaries (all of which, when considered in the aggregate as a single subsidiary, would not constitute a significant subsidiary as of the end of our last fiscal year).

MidAmerican Funding, LLC	Iowa
MHC Inc.	Iowa
MidAmerican Energy Company	Iowa
CBEC Railway Inc.	Iowa
InterCoast Capital Company	Delaware
Cimmred Leasing Company	South Dakota
IWG Co. 8	Delaware
MHC Investment Company	South Dakota
MWR Capital Inc.	South Dakota
Midwest Capital Group, Inc.	Iowa
Dakota Dunes Development Company	Iowa
Two Rivers Inc.	South Dakota
MidAmerican Services Company	Iowa
MEC Construction Services Co.	Iowa
CE Electric UK Funding Company	England
CalEnergy Gas (Holdings) Limited	England
CalEnergy Gas Limited	England
CalEnergy Gas (Australia) Limited	England
CalEnergy Gas (Polska) sp. z.o.o.	Poland
CalEnergy Resources Limited	England
CalEnergy Resources (Poland) sp.z.o.o.	Poland
CE Electric (Ireland) Limited	Republic of Ireland
CE Electric UK Holdings	England
CE Electric UK Limited	England
CE UK Gas Holdings Limited	England
DCUSA Limited	England
ElectraLink Limited	England
Electricity Pensions Trustee Limited	England
ESN Holdings Limited	England
Gemserv Limited	England
Integrated Utility Services Limited	England
Integrated Utility Services Limited	Republic of Ireland
Kings Road Developments Limited	England
MRA Service Company Limited	England
Northern Electric plc	England
Northern Electric Distribution Limited	England
Northern Electric Finance plc	England
Northern Electric & Gas Limited	England
Northern Electric GenCo	England
Northern Electric Generation (Peaking) Limited	England
Northern Electric Properties Limited	England
Northern Electric Retail Limited	England
Northern Transport Finance Limited	England
Selectusonline Limited	England
Vehicle Lease and Service Limited	England
Yorkshire Cayman Holding Limited	Cayman Islands
Yorkshire Electricity Distribution plc	England
Yorkshire Electricity Group plc	England
Yorkshire Holdings plc	England

Yorkshire Power Finance Limited	Cayman Islands
Yorkshire Power Group Limited	England
HomeServices of America, Inc.	Delaware
Allerton Capital, Ltd.	Iowa
Arizona Home Services, LLC	Arizona
Caldwell Mill, LLP	Alabama
California Title Company	California
Capitol Intermediary Company	Nebraska
Capitol Land Exchange, Inc.	Nebraska
Capitol Title Company	Nebraska
CBSHOME Real Estate Company	Nebraska
CBSHOME Real Estate of Iowa, Inc.	Delaware
CBSHOME Relocation Services, Inc.	Nebraska
Champion Realty, Inc.	Maryland
Chancellor Title Services, Inc.	Maryland
Columbia Title of Florida, Inc.	Florida
Cornerstone Title Company, L.L.C.	Georgia
Edina Financial Services, Inc.	Minnesota
Edina Realty, Inc.	Minnesota
Edina Realty Referral Network, Inc.	Minnesota
Edina Realty Relocation, Inc.	Minnesota
Edina Realty Title, Inc.	Minnesota
Esslinger-Wooten-Maxwell, Inc.	Florida
E-W-M Referral Services, Inc.	Florida
FFR, Inc.	Iowa
First Realty, Ltd.	Iowa
First Reserve Insurance, Inc.	Florida
FMLC Mortgage, LLC	Delaware
For Rent, Inc.	Arizona
Heritage Title Services, LLC	Georgia
HMSV Financial Services, Inc.	Delaware
HN Heritage Title Holdings, LLC	Georgia
HN Insurance Holdings, LLC	Georgia
HN Insurance Services, LLC	Georgia
HN Mortgage, LLC	Georgia
HN Real Estate Group, L.L.C.	Georgia
HN Real Estate Group, N.C., Inc.	North Carolina
HN Referral Corporation	Georgia
Home Services Referral Network, LLC	Indiana
HomeServices Financial, LLC	Delaware
HomeServices Financial Holdings, Inc.	Delaware
HomeServices Financial-Iowa, LLC	Delaware
HomeServices Lending, LLC	Delaware
HomeServices Insurance, Inc.	Nebraska
HomeServices of Alabama, Inc.	Delaware
HomeServices of California, Inc.	Delaware
HomeServices of Florida, Inc.	Florida
HomeServices of Iowa, Inc.	Delaware
HomeServices of Kentucky, Inc.	Kentucky
HomeServices of Kentucky Real Estate Academy, LLC	Kentucky
HomeServices of Nebraska, Inc.	Delaware
HomeServices of Nevada, Inc.	Delaware
HomeServices of the Carolinas, Inc.	Delaware
HomeServices Relocation, LLC	Delaware
HSR Equity Funding, Inc.	Delaware
Huff Commercial Group, LLC	Kentucky
Huff-Drees Realty, Inc.	Ohio

IMO Co., Inc.	Missouri
Iowa Realty Co., Inc.	Iowa
Iowa Realty Insurance Agency, Inc.	Iowa
Iowa Title Company	Iowa
Iowa Title Linn County II, LLC	Iowa
JBRC, Inc.	Kentucky
J.D. Reece Mortgage Company	Kansas
J.P. & A. Inc.	Georgia
Jenny Pruitt & Associates, Inc.	Georgia
Jenny Pruitt Insurance Services, LLC	Georgia
Jim Huff Realty, Inc.	Kentucky
JRHBW Realty, Inc.	Alabama
J. S. White & Associates, Inc.	Alabama
Kansas City Title, Inc.	Kansas
Kentucky Residential Referral Services, LLC	Kentucky
Larabee School of Real Estate and Insurance, Inc.	Nebraska
Limestone Springs Holdings, LLC	California
Lincoln Title Company, LLC	Nebraska
Long Title Agency, LLC	Arizona
Meridian Title Services, LLC	Georgia
Mid-America Referral Network, Inc.	Kansas
MidAmerican Commercial Real Estate Services, Inc.	Kansas
Midland Escrow Services, Inc.	Iowa
MortgageSouth, LLC	Alabama
Nebraska Land Title and Abstract Company	Nebraska
Pickford Escrow Company, Inc.	California
Pickford Golden State Member, LLC	California
Pickford Holdings LLC	California
Pickford North County LP	California
Pickford Real Estate, Inc.	California
Pickford Realty, Ltd.	California
Pickford Services Company	California
Plaza Financial Services, LLC	Kansas
Plaza Mortgage Services, LLC	Kansas
Preferred Carolinas Realty, Inc.	North Carolina
Preferred Carolinas Title Agency, LLC	North Carolina
Professional Referral Organization, Inc.	Maryland
Real Estate Links, LLC	Illinois
Real Estate Referral Network, Inc.	Nebraska
Reece & Nichols Alliance, Inc.	Kansas
Reece & Nichols Realtors, Inc.	Kansas
Referral Company of North Carolina, Inc.	North Carolina
RHL Referral Company, LLC	Arizona
Roberts Brothers, Inc.	Alabama
Roy H. Long Realty Co., Inc.	Arizona
San Diego PCRE, Inc.	California
Semonin Realtors, Inc.	Delaware
Southwest Relocation, LLC	Arizona
The Escrow Firm, Inc.	California
The Referral Company	Iowa
TITLE INFO NOW, LLC	Minnesota
TitleSouth, LLC	Alabama
Township Title Services, LLC	Georgia
Traditions Title Agency, LLC	Ohio
Trinity Mortgage Partners, Inc.	Georgia
United Settlement Services, LC	Iowa
CE Generation, LLC	Delaware

CalEnergy Operating Corporation	Delaware
California Energy Development Corporation	Delaware
California Energy Yuma Corporation	Utah
CE Salton Sea Inc.	Delaware
CE Texas Power, LLC	Delaware
CE Texas Resources, LLC	Delaware
CE Turbo LLC	Delaware
Conejo Energy Company	California
Del Ranch, L. P.	California
Desert Valley Company	California
Elmore, L.P.	California
Falcon Power Operating Company	Texas
CE Gen Oil Company	Texas
CE Gen Pipeline Corporation	Texas
CE Gen Power Corporation	Texas
Fish Lake Power LLC	Delaware
FSRI Holdings, Inc	Texas
Imperial Magma LLC	Delaware
Leathers, L.P.	California
Magma Land Company I	Nevada
Magma Power Company	Nevada
Niguel Energy Company	California
North Country Gas Pipeline Corporation	New York
Power Resources, Ltd.	Texas
Salton Sea Brine Processing L. P.	California
Salton Sea Funding Corporation	Delaware
Salton Sea Power Company	Nevada
Salton Sea Power Generation L. P.	California
Salton Sea Power L.L.C.	Delaware
Salton Sea Royalty LLC	Delaware
San Felipe Energy Company	California
Saranac Energy Company, Inc.	Delaware
Saranac Power Partners, LP	Delaware
SECI Holdings, Inc.	Delaware
VPC Geothermal LLC	Delaware
Vulcan Power Company	Nevada
Vulcan/BN Geothermal Power Company	Nevada
Yuma Cogeneration Associates	Arizona
BG Energy Holding LLC	Delaware
BG Energy LLC	Delaware
CalEnergy Capital Trust II	Delaware
CalEnergy Capital Trust III	Delaware
CalEnergy Generation Operating Company	Delaware
CalEnergy Holdings, Inc.	Delaware
CalEnergy International Ltd.	Bermuda
CalEnergy International Services, Inc.	Delaware
CalEnergy Investments C.V.	Netherlands
CalEnergy Minerals Development LLC	Delaware
CalEnergy Minerals, LLC	Delaware
CalEnergy Pacific Holdings Corp.	Delaware
CalEnergy U.K. Inc.	Delaware
CE Casecnan Ltd.	Bermuda
CE Casecnan II, Inc.	Philippines
CE Casecnan Water and Energy Company, Inc.	Philippines
CE Cebu Geothermal Power Company, Inc.	Philippines
CE Electric (NY), Inc.	Delaware
CE Electric, Inc.	Delaware

CE Exploration Company	Delaware
CE Geothermal, Inc.	Delaware
CE Insurance Services Limited	Isle of Man
CE International Investments, Inc.	Delaware
CE Luzon Geothermal Power Company, Inc.	Philippines
CE Mahanagdong II, Inc.	Philippines
CE Mahanagdong Ltd.	Bermuda
CE Obsidian Energy LLC	Delaware
CE Obsidian Holding, LLC	Delaware
CE Philippines II, Inc.	Philippines
CE Philippines Ltd.	Bermuda
CE Power, Inc.	Delaware
Cordova Energy Company, LLC	Delaware
Cordova Funding Corporation	Delaware
Kern River Funding Corporation	Delaware
Kern River Gas Transmission Company	Texas
KR Acquisition 1, LLC	Delaware
KR Acquisition 2, LLC	Delaware
KR Holding, LLC	Delaware
M & M Ranch Acquisition Company, LLC	Delaware
M & M Ranch Holding Company, LLC	Delaware
Magma Netherlands B.V.	Netherlands
MEHC Investment, Inc.	South Dakota
MidAmerican Capital Trust I	Delaware
MidAmerican Capital Trust II	Delaware
MidAmerican Capital Trust III	Delaware
MidAmerican Nuclear Energy Company, LLC	Delaware
MidAmerican Nuclear Energy Holdings Company, LLC	Delaware
MEHC Insurance Services Ltd.	Vermont
MEHC America Transco, LLC	Delaware
MEHC Texas Transco, LLC	Delaware
Electric Transmission America, LLC	Delaware
Electric Transmission Texas, LLC	Delaware
MidAmerican Energy Machining Services LLC	Delaware
NNGC Acquisition, LLC	Delaware
Northern Natural Gas Company	Delaware
Beaver Assets, LLC	Delaware
PPW Holdings LLC	Delaware
PacifiCorp	Oregon
Energy West Mining Company	Utah
PacifiCorp Investment Management, Inc.	Oregon
Glenrock Coal Company	Wyoming
Interwest Mining Company	Oregon
Pacific Minerals, Inc.	Wyoming
PacifiCorp Environmental Remediation Company	Delware
PacifiCorp Future Generations, Inc.	Oregon
Canopy Botanicals, Inc.	Delaware
Canopy Botanicals, SRL	Boliva
Trapper Mining Inc.	Delaware
Quad Cities Energy Company	Iowa
Salton Sea Minerals Corp.	Delaware
S.W. Hydro, Inc.	Delaware
Tongonan Power Investment, Inc.	Philippines
Visayas Geothermal Power Company	Philippines
Wailuku Holding Company, LLC	Delaware
Wailuku River Hydroelectric Power Company	Hawaii
Wailuku River Hydroelectric Limited Partnership	Hawaii

EXHIBIT 23.1

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We consent to the incorporation by reference in Registration Statement No. 333-147957 on Form S-8 of our report dated February 27, 2008 (which report expresses an unqualified opinion and includes an explanatory paragraph relating to the adoption of Statement of Financial Accounting Standards No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans - an amendment of FASB Statements No. 87, 88, 106, and 132(R),” as of December 31, 2006), relating to the financial statements and financial statement schedules of MidAmerican Energy Holdings Company, appearing in this Annual Report on Form 10-K of MidAmerican Energy Holdings Company for the year ended December 31, 2007.

/s/ Deloitte & Touche LLP

Des Moines, Iowa

February 27, 2008

EXHIBIT 24.1

POWER OF ATTORNEY

The undersigned, a member of the Board of Directors or an officer of MIDAMERICAN ENERGY HOLDINGS COMPANY, an Iowa corporation (the “Company”), hereby constitutes and appoints Douglas L. Anderson and Paul J. Leighton and each of them, as his/her true and lawful attorney-in-fact and agent, with full power of substitution and resubstitution, for and in his/her stead, in any and all capacities, to sign on his/her behalf the Company’s Annual Report on Form 10-K for the fiscal year ending December 31, 2007 and to execute any amendments thereto and to file the same, with all exhibits thereto, and all other documents in connection therewith, with the Securities and Exchange Commission and applicable stock exchanges, with the full power and authority to do and perform each and every act and thing necessary or advisable to all intents and purposes as he/she might or could do in person, hereby ratifying and confirming all that said attorney-in-fact and agent, or his/her substitute or substitutes, may lawfully do or cause to be done by virtue hereof.

Executed as of February 29, 2008

/s/ David L. Sokol		/s/ Gregory E. Abel
DAVID L. SOKOL		GREGORY E. ABEL

/s/ Patrick J. Goodman		/s/ Warren E. Buffett
PATRICK J. GOODMAN		WARREN E. BUFFETT

/s/ Marc D. Hamburg		/s/ Walter Scott, Jr.
MARC D. HAMBURG		WALTER SCOTT, JR.

EXHIBIT 31.1

CERTIFICATION PURSUANT TO

SECTION 302 OF THE

SARBANES-OXLEY ACT OF 2002

I, David L. Sokol, certify that:

1.	I have reviewed this annual report on Form 10-K of MidAmerican Energy Holdings Company;

2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.	The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

	a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

	b)	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

	c)	Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

	d)	Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.	The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

	a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

	b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: February 29, 2008	/s/ David L. Sokol
	David L. Sokol
	Chairman and Chief Executive Officer
	(principal executive officer)

EXHIBIT 31.2

CERTIFICATION PURSUANT TO

SECTION 302 OF THE

SARBANES-OXLEY ACT OF 2002

I, Patrick J. Goodman, certify that:

1.	I have reviewed this annual report on Form 10-K of MidAmerican Energy Holdings Company;

2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.	The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

	a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

	b)	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

	c)	Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

	d)	Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.	The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

	a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

	b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: February 29, 2008	/s/ Patrick J. Goodman
	Patrick J. Goodman
	Senior Vice President and Chief Financial Officer
	(principal financial officer)

EXHIBIT 32.1

CERTIFICATION PURSUANT TO

SECTION 906 OF THE

SARBANES-OXLEY ACT OF 2002

I, David L. Sokol, Chairman and Chief Executive Officer of MidAmerican Energy Holdings Company (the “Company”), certify, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, 18 U.S.C. Section 1350, that to the best of my knowledge:

(1)	the Annual Report on Form 10-K of the Company for the annual period ended December 31, 2007 (the “Report”) fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 (15 U.S.C. 78m or 78o(d)); and

(2)	the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date: February 29, 2008	/s/ David L. Sokol
	David L. Sokol
	Chairman and Chief Executive Officer
	(principal executive officer)

EXHIBIT 32.2

CERTIFICATION PURSUANT TO

SECTION 906 OF THE

SARBANES-OXLEY ACT OF 2002

I, Patrick J. Goodman, Senior Vice President and Chief Financial Officer of MidAmerican Energy Holdings Company (the “Company”), certify, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, 18 U.S.C. Section 1350, that to the best of my knowledge:

(1)	the Annual Report on Form 10-K of the Company for the annual period ended December 31, 2007 (the “Report”) fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 (15 U.S.C. 78m or 78o(d)); and

(2)	the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date: February 29, 2008	/s/ Patrick J. Goodman
	Patrick J. Goodman
	Senior Vice President and Chief Financial Officer
	(principal financial officer)