MIDAMERICAN ENERGY HOLDINGS CO /NEW/ (Form: 10-K, Received: 03/03/2006 17:18:21)

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, 2005

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

For the transition period from ______ to _______

Commission File No . 001-14881

MIDAMERICAN ENERGY HOLDINGS COMPANY

(Exact name of registrant as specified in its charter)

Iowa		94-2213782
(State or other jurisdiction of		(I.R.S. Employer
incorporation or organization)		Identification No.)

666 Grand Avenue, Des Moines, Iowa		50309
(Address of principal executive offices)		(Zip Code)

(515) 242-4300
(Registrant’s telephone number, including area code)

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 T No o

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 ¨ No T

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, or a non-accelerated filer. See the definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer ¨ Accelerated filer ¨ Non-accelerated filer T

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 March 1, 2006, 50,544,482 shares of common stock were outstanding.

TABLE OF CONTENTS

PART I

Item 1.	Business	4
Item 1A.	Risk Factors	29
Item 1B.	Unresolved Staff Comments	36
Item 2.	Properties	37
Item 3.	Legal Proceedings	39
Item 4.	Submission of Matters to a Vote of Security Holders	39

PART II

Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	40
Item 6.	Selected Financial Data	40
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	41
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	61
Item 8.	Financial Statements and Supplementary Data	65
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	113
Item 9A.	Controls and Procedures	113
Item 9B.	Other Information	113

PART III

Item 10.	Directors and Executive Officers of the Registrant	114
Item 11.	Executive Compensation	115
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	119
Item 13.	Certain Relationships and Related Transactions	120
Item 14.	Principal Accountant Fees and Services	120

PART IV

Item 15.	Exhibits and Financial Statement Schedules	122
Signatures		127
Exhibit Index		128

Disclosure Regarding 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. You can typically identify forward-looking statements by the use of forward-looking words, such as “may,” “will,” “could,” “project,” “believe,” “anticipate,” “expect,” “estimate,” “continue,” “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;

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

governmental, statutory, legislative, regulatory or administrative initiatives, including those relating to the recently enacted Energy Policy Act of 2005 (“Energy Policy Act”), or ratemaking actions affecting the Company or the electric or gas utility, pipeline or power generation industries;

·	the outcome of general rate cases and other proceedings conducted before regulatory authorities;

weather effects on sales and revenue;

·	changes in expected customer growth or usage of electricity or gas;

economic or industry trends that could impact electricity or gas usage;

increased competition in the power generation, electric and gas utility or pipeline industries;

fuel, fuel transportation and power costs and availability;

continued availability of accessible gas reserves;

changes in business strategy, development plans or customer or vendor relationships;

availability, terms and deployment of capital;

availability of qualified personnel;

unscheduled outages or repairs;

risks relating to nuclear generation;

financial or regulatory accounting principles or policies imposed by the Public Company Accounting Oversight Board, the Financial Accounting Standards Board (“FASB”), the U.S. Securities and Exchange Commission (“SEC”), the Federal Energy Regulatory Commission (“FERC”), state public utility commissions and similar entities with regulatory oversight;

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

·	the Company’s ability to consummate the acquisition of PacifiCorp and, following the consummation of such acquisition, to successfully integrate PacifiCorp’s operations into the Company’s business;

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

other business or investment considerations that may be disclosed from time to time in SEC filings or in other publicly disseminated written documents.

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

MidAmerican Energy Holdings Company (“MEHC”) and its subsidiaries (together with MEHC, the “Company”) are organized and managed as seven distinct platforms: MidAmerican Funding, LLC (“MidAmerican Funding”) (which primarily includes MidAmerican Energy Company (“MidAmerican Energy”)), Kern River Gas Transmission Company (“Kern River”), Northern Natural Gas Company (“Northern Natural Gas”), 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 (the subsidiaries owning the Upper Mahiao, Malitbog and Mahanagdong projects (collectively, the “Leyte Projects”) and the Casecnan Project), CalEnergy Generation-Domestic (the subsidiaries owning interests in independent power projects in the United States), and HomeServices of America, Inc. (collectively with its subsidiaries, “HomeServices”). Refer to Note 22 of Notes to Consolidated Financial Statements included in Item 8. Financial Statements and Supplementary Data of this Form 10-K for additional segment information regarding the Company’s platforms. Through these platforms, the Company owns and operates a combined electric and natural gas utility company in the United States, two natural gas pipeline companies in the United States, two electricity distribution companies in Great Britain, a diversified portfolio of domestic and international 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. MEHC’s electric and natural gas utility subsidiaries currently serve approximately 4.4 million electricity customers and approximately 688,000 natural gas customers. MEHC's natural gas pipeline subsidiaries operate interstate natural gas transmission systems that have approximately 18,100 miles of pipeline in operation, a peak delivery capacity of 6.6 billion cubic feet of natural gas per day and transported approximately 7.8% of the total natural gas consumed in the United States in 2005. The Company has interests in 6,740 net owned megawatts of power generation facilities in operation and under construction, including 5,166 net owned megawatts in facilities that are part of the regulated asset base of its electric utility business and 1,574 net owned megawatts in non-utility power generation facilities. Substantially all of the non-utility power generation facilities have long-term contracts for the sale of energy and/or capacity from the facilities.

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 project financing agreements, all or substantially all of the assets of each subsidiary are or may be pledged or encumbered to support or otherwise provide the security for their own project or subsidiary debt. It should not be assumed that any asset of any such subsidiary will be available to satisfy the obligations of MEHC or any of its other such subsidiaries; provided, however, that unrestricted cash or other assets which are available for distribution may, subject to applicable law and the terms of financing arrangements of such parties, be advanced, loaned, paid as dividends or otherwise distributed or contributed to MEHC or affiliates thereof.

On March 14, 2000, MEHC and an investor group including Berkshire Hathaway Inc. (“Berkshire Hathaway”), Walter Scott, Jr., a director of MEHC, David L. Sokol, Chairman and Chief Executive Officer of MEHC, and Gregory E. Abel, President and Chief Operating Officer of MEHC, executed a definitive agreement and plan of merger whereby the investor group acquired all of the outstanding common stock of MEHC (the “Teton Transaction”). As of December 31, 2005 Walter Scott, Jr. (including family members and related entities), Berkshire Hathaway, David L. Sokol and Gregory E. Abel owned 86.2%, 9.7%, 3.5% and 0.6%, respectively, of MEHC’s voting common stock and held diluted ownership interests of 15.3%, 80.5%, 2.9% and 1.3%, respectively.

The principal executive offices of MEHC are located at 666 Grand Avenue, Des Moines, Iowa 50309 and its telephone number is (515) 242-4300. MEHC 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.

Recent Developments Regarding the Pending PacifiCorp Acquisition

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, a regulated electric utility providing service to approximately 1.6 million customers in California, Idaho, Oregon, Utah, Washington and Wyoming. MEHC will purchase all of the outstanding shares of the PacifiCorp common stock for approximately $5.1 billion in cash. The long-term debt and preferred stock of PacifiCorp, which aggregated $4.3 billion at December 31, 2005, will remain outstanding. As of March 1, 2006, all state and federal approvals required for the acquisition were obtained, subject to completion of a "most favored states" process in Wyoming, Washington, Utah, Idaho and Oregon that allows each such state to make applicable to that state any acquisition commitments or conditions accepted in other PacifiCorp states. Subject to the most favored states process and other customary closing conditions, the transaction is expected to close in March 2006. MEHC expects to fund the acquisition of PacifiCorp with the proceeds from an investment by Berkshire Hathaway and other existing shareholders of approximately $3.4 billion in MEHC common stock and the issuance by MEHC of $1.7 billion of either additional common stock to Berkshire Hathaway or long-term senior notes to third parties.

Recent Developments Regarding Berkshire Hathaway

On February 9, 2006, following the effective date of the repeal of the Public Utility Holding Company Act of 1935 (“PUHCA 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. As a consequence, Berkshire Hathaway owns 83.4% (80.5% on a diluted basis) of the outstanding common stock of MEHC, will consolidate the Company in its financial statements as a majority-owned subsidiary, and will include the Company in its consolidated federal U.S. income tax return.

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, and will not be used for the PacifiCorp acquisition or for other future acquisitions.

MidAmerican Energy

MidAmerican Energy, an indirect wholly-owned subsidiary of MEHC, is a public utility company headquartered in Iowa and is principally engaged in the business of generating, transmitting, distributing and selling electric energy 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. As of December 31, 2005, MidAmerican Energy had approximately 706,000 regulated retail electric customers and 688,000 regulated retail and transportation natural gas customers.

In addition to retail sales and natural gas transportation, MidAmerican Energy sells electric energy and natural gas to other utilities, marketers and municipalities. 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. Among the primary industries served by MidAmerican Energy are those that are concerned with food products, the manufacturing, processing and fabrication of primary metals, real estate, farm and other non-electrical machinery, and cement and gypsum products.

MidAmerican Energy also conducts a number of nonregulated business activities, which include a variety of activities outside of the traditional regulated electric and natural gas services.

MidAmerican Energy derived its operating revenues from the following business activities.

	Year Ended December 31,
	2005			2004			2003

Regulated electric		47.9	%		52.7	%		53.9	%
Regulated gas		41.8			37.5			36.5
Nonregulated		10.3			9.8			9.6
		100.0	%		100.0	%		100.0	%

Electric Operations

The percentage of regulated electric revenue by customer class follows:

	Year Ended December 31,
	2005			2004			2003

Residential		21.3	%		19.6	%		19.4	%
Small general service ⁽¹⁾		15.0			14.5			14.0
Large general service ⁽²⁾		27.9			26.7			25.4
Wholesale ⁽³⁾		30.5			34.2			36.4
Other		5.3			5.0			4.8
		100.0	%		100.0	%		100.0	%

(1)	Small general service generally includes commercial and industrial customers with a demand of 200 kilowatts or less.

(2)	Large general service generally includes commercial and industrial customers with a demand of more than 200 kilowatts.

(3)	Wholesale generally includes other utilities, marketers and municipalities to whom electric energy is sold at wholesale for resale to ultimate customers.

The percentage of regulated electric revenue by jurisdiction follows:

	Year Ended December 31,
	2005			2004			2003

Iowa		89.0	%		88.7	%		88.8	%
Illinois		10.1			10.3			10.4
South Dakota		0.9			1.0			0.8
		100.0	%		100.0	%		100.0	%

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 July 20, 2005, retail customer usage of electricity caused a new record hourly peak demand of 4,040 MW on MidAmerican Energy’s electric system, an increase of 105 MW from the previous record of 3,935 MW set in August 2003.

MidAmerican Energy is exposed to fluctuations in energy costs relating to retail sales in Iowa as it does not have an energy adjustment clause. Under its Illinois and South Dakota electric tariffs, MidAmerican Energy is allowed to recover fluctuations in the cost of all fuels and purchased energy used for retail electric generation through a fuel cost adjustment clause.

The following table sets out certain information concerning MidAmerican Energy’s power generation facilities based upon summer 2005 accreditation and expected accredited generating capacity of projects recently completed or under construction:

	Facility Net
	Capacity	Net MW	Energy		Year
Operating Project ⁽¹⁾	(MW) ⁽²⁾	Owned ⁽²⁾	Source	Location	In-Service

Steam Electric Generating Facilities :
Council Bluffs Energy Center Units 1 and 2	133	133	Coal	Iowa	1954, 1958
Council Bluffs Energy Center Unit 3	690	546	Coal	Iowa	1978
Louisa Generation Station	700	616	Coal	Iowa	1983
Neal Generation Station Units 1 and 2	435	435	Coal	Iowa	1964, 1972
Neal Generation Station Unit 3	515	371	Coal	Iowa	1975
Neal Generation Station Unit 4	644	261	Coal	Iowa	1979
Ottumwa Generation Station	673	350	Coal	Iowa	1981
Riverside Generation Station	135	135	Coal	Iowa	1925, 1961
Total steam electric generating facilities	3,925	2,847

Other Facilities :
Combustion Turbines	792	792	Gas/Oil	Iowa	Various ⁽³⁾
Combined Cycle - Greater Des Moines Energy Center	491	491	Gas	Iowa	2003-2004
Quad Cities Generating Station	1,748	437	Nuclear	Illinois	1972
Portable Power Modules	56	56	Oil	Iowa	2000
Wind - Intrepid ⁽⁴⁾	33	33	Wind	Iowa	2005
Moline Water Power	3	3	Water	Illinois	1970
Total other facilities	3,123	1,812
Total accredited generating capacity	7,048	4,659

Projects Recently Completed or Under Construction :
Council Bluffs Energy Center Unit 4	790	479	Coal	Iowa	2007
Wind - Century ⁽⁴⁾	28	28	Wind	Iowa	2005
Total projects recently completed or under construction	818	507
	7,866	5,166

______________

(1)	MidAmerican Energy operates all such power generation facilities other than Quad Cities Generating Station and Ottumwa Generation Station.

(2)

Represents accredited net generating capacity from the summer of 2005 and the expected accredited generating capacity of projects recently completed or under construction. Actual MW may vary depending on operating conditions and plant design for operating projects. Net MW Owned indicates ownership of accredited capacity for the summer of 2005 as approved by the Mid-Continent Area Power Pool (“MAPP”).

(3)	A total of 629 MW were placed in-service between 1966 and 1978 while the three turbines totaling 120 MW at the Pleasant Hill facility were placed in-service between 1990 and 1994.

(4)	MidAmerican Energy owns 360.5 MW (nameplate rating) of wind power facilities. The 61 MW of accredited capacity ratings for these wind power facilities included in the table above are considerably less than the nameplate ratings due to the varying nature of wind.

MidAmerican Energy’s total accredited net generating capability in the summer of 2005 was 5,098 MW. Accredited net generating capability represents the amount of generation available to meet the requirements on MidAmerican Energy’s system and consists of MidAmerican Energy-owned generation of 4,659 MW and the net amount of capacity purchases and sales of 439 MW. Accredited capacity may vary from the nameplate capacity ratings. Additionally, the actual amount of generation capacity available at any time 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 2005, MidAmerican Energy completed construction of its 360.5 MW (nameplate rating) wind power project that consists of facilities located at two sites in north central Iowa. As of December 31, 2004, wind turbines totaling 160.5 MW at the Intrepid site were completed and in service, and in the third quarter of 2005, wind turbines totaling 150 MW at the Century site were placed in service. The remaining 50 MW of wind turbines were completed in December 2005, of which 35 MW are located at the Century site and 15 MW are at the Intrepid site. Generally speaking, accredited capacity ratings for wind power facilities are considerably less than the nameplate ratings due to the varying nature of wind. The current total projected accredited capacity for these wind power facilities is approximately 61 MW. MidAmerican Energy owns and operates these facilities. On December 16, 2005, MidAmerican Energy made a filing with the Iowa Utilities Board (“IUB”) for approval to add up to 545 MW (nameplate rating) of additional wind generation capacity in Iowa.

MidAmerican Energy is currently constructing Council Bluffs Energy Center Unit No. 4 (“CBEC Unit 4”), a 790 MW (based on expected accreditation) super-critical-temperature, low sulfur coal-fired generating plant. MidAmerican Energy will operate the plant and hold an undivided ownership interest as a tenant in common with the other owners of the plant. MidAmerican Energy’s current ownership interest is 60.67%, equating to 479 MW of output. Municipal, cooperative and public power utilities will own the remainder, which is a typical ownership arrangement for large base-load plants in Iowa. The facility will provide service to regulated retail electricity customers. Wholesale sales may also be made from the project to the extent the power is not immediately needed for regulated retail service. MidAmerican Energy has obtained regulatory approval to include the Iowa portion of the actual cost of the generation project in its Iowa rate base as long as the actual cost does not exceed the agreed cap that MidAmerican Energy has deemed to be reasonable. If the cap is exceeded, MidAmerican Energy has the right to demonstrate the prudence of the expenditures above the cap, subject to regulatory review. MidAmerican Energy expects to invest approximately $737 million in CBEC Unit 4, including transmission facilities and excluding allowance for funds used during construction. Through December 31, 2005, MidAmerican Energy has invested $502.0 million in the project, including $121.3 million for MidAmerican Energy’s share of deferred payments allowed by the construction contract.

MidAmerican Energy is interconnected with Iowa utilities and utilities in neighboring states. MidAmerican Energy is also party to an electric generation reserve sharing pool and regional transmission group administered by the MAPP. The 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. The MAPP performs functions including administration of its short-term regional Open Access Transmission Tariff (“OATT”), coordination of regional planning and operations, and operation of the generation reserve sharing pool.

Each MAPP generation reserve participant is required to maintain for emergency purposes a net generating capability reserve of at least 15% above its system peak demand on a 12-month rolling basis. MidAmerican Energy’s reserve margin at peak demand for 2005 was approximately 26%. MidAmerican Energy believes it has adequate electric capacity reserve through 2009, including capacity provided by the generating projects discussed above. However, significantly higher-than-normal temperatures during the cooling season could cause MidAmerican Energy’s reserve to fall below the 15% minimum. If MidAmerican Energy fails to maintain the required minimum reserve, significant penalties could be contractually imposed by the MAPP.

MidAmerican Energy’s transmission system connects its generating facilities with distribution substations and interconnects with 14 other transmission providers in Iowa and five adjacent states. 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 at December 31, 2005, included 911 miles of 345-kV lines and 1,128 miles of 161-kV lines. MidAmerican Energy’s electric distribution system included approximately 227,000 transformers and 400 substations at December 31, 2005.

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 area 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 distributes it to customers through MidAmerican Energy's distribution system.

MidAmerican Energy sells natural gas and transportation services to end-use, or retail, customers and natural gas to other utilities, marketers and municipalities. MidAmerican Energy also transports through its distribution system natural gas purchased independently by a number of end-use customers. During 2005, 46% of total natural gas delivered through MidAmerican Energy's system for end-use customers was under natural gas transportation service.

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

The percentage of regulated natural gas revenue, excluding transportation throughput, by customer class follows:

	Year Ended December 31,
	2005			2004			2003

Residential		37.5	%		40.0	%		44.1	%
Small general service ⁽¹⁾		18.2			19.6			21.0
Large general service ⁽¹⁾		4.1			2.2			1.9
Wholesale ⁽²⁾		40.2			38.0			32.7
Other		-			0.2			0.3
		100.0	%		100.0	%		100.0	%

(1)	Small and large general service customers are classified primarily based on the nature of their business and gas usage. Small general service customers are business customers whose gas usage is principally for heating. Large general service customers are business customers whose principal gas usage is for their manufacturing processes.

(2)	Wholesale generally includes other utilities, marketers and municipalities to whom natural gas is sold at wholesale for eventual resale to ultimate end-use customers.

The percentage of regulated natural gas revenue, excluding transportation throughput, by jurisdiction follows:

	Year Ended December 31,
	2005			2004			2003

Iowa		77.4	%		77.7	%		77.9	%
South Dakota		11.7			11.5			11.3
Illinois		10.0			9.9			10.0
Nebraska		0.9			0.9			0.8
		100.0	%		100.0	%		100.0	%

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 attempts to optimize the value of its regulated assets by engaging in wholesale sales transactions. IUB and South Dakota Public Utilities Commission (“SDPUC”) rulings have allowed MidAmerican Energy to retain 50% of the respective jurisdictional margins earned on wholesale sales of natural gas, with the remaining 50% being returned to customers through the purchased gas adjustment clauses discussed below.

MidAmerican Energy has rights to firm pipeline capacity to transport natural gas to its service territory through direct interconnects to the pipeline systems of Northern Natural Gas (an affiliate company), Natural Gas Pipeline Company of America (“NGPL”), Northern Border Pipeline Company (“Northern Border”) and ANR Pipeline Company (“ANR”). At times, the capacity available through MidAmerican Energy’s firm capacity portfolio may exceed the demand on MidAmerican Energy’s distribution system. Firm capacity in excess of MidAmerican Energy’s system needs can be resold to other companies to achieve optimum use of the available capacity. Past IUB and SDPUC rulings have allowed MidAmerican Energy to retain 30% of the respective jurisdictional margins earned on the resold capacity, with the remaining 70% being returned to customers through the purchased gas adjustment clauses.

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 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 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 withdrawn during periods of peak demand and 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.

In 1995, the IUB gave initial approval of MidAmerican Energy’s Incentive Gas Supply Procurement Program. In November 2004, the IUB extended the program through October 31, 2006. Under the program, as amended, MidAmerican Energy is required to file with the IUB every six months a comparison of its natural gas procurement costs to a reference price. If MidAmerican Energy’s cost of natural gas for the period is less or greater than an established tolerance band around the reference price, then MidAmerican Energy shares a portion of the savings or costs with customers. A similar program is currently in effect in South Dakota through October 31, 2010. Since the implementation of the program, MidAmerican Energy has successfully achieved and shared savings with its natural gas customers.

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 March 1, 2006, MidAmerican Energy’s 2005/2006 winter heating season peak-day delivery of 1,004,109 Dth was reached on February 17, 2006. This peak-day delivery included 74% traditional sales service and 26% 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 at December 31, 2005, included approximately 21,900 miles of gas mains and services pipelines.

Interstate Pipeline Companies

Kern River

Kern River, an indirect wholly-owned subsidiary of MEHC, owns an interstate natural gas transportation pipeline system comprising 1,679 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 a 717-mile expansion project (“2003 Expansion Project”), which increased the design capacity of Kern River’s pipeline system by 885,575 Dth per day to its current 1,755,575 Dth per day. 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 Federal Energy Regulatory Commission (“FERC”) regulated tariff that is designed to allow it an opportunity to recover its costs together with 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 the original 682 miles of 36-inch diameter pipeline, 628 miles of 36-inch diameter loop pipeline related to the 2003 Expansion Project and 68 miles of various laterals that connect to the mainline.

The common facilities consist of a 219-mile section of original pipeline that extends from the point of interconnection with the mainline in Daggett to Bakersfield, California and an additional 82 miles related to the 2003 Expansion Project. The common facilities are jointly owned by Kern River (approximately 76.8% as of December 31, 2005) and Mojave Pipeline Company (“Mojave”), a wholly-owned subsidiary of El Paso Corporation (“El Paso”), (approximately 23.2% as of December 31, 2005) 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.

As of December 31, 2005, Kern River had 1,661,575 Dth per day of capacity under long-term firm natural gas transportation service agreements pursuant to which 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.

With respect to Kern River’s mainline facilities in existence prior to the 2003 Expansion Project, at December 31, 2005, Kern River had 28 long-term firm natural gas transportation service agreements with 16 shippers, for a total of 848,949 Dth per day of capacity. These long-term firm natural gas transportation service agreements expire between September 30, 2011 and April 30, 2018. Several of these shippers are major oil and gas companies or affiliates of such companies. These shippers also include electric generating companies, energy marketing and trading companies, and a natural gas distribution utility which provides services in Nevada and California.

With respect to Kern River’s 2003 Expansion Project, at December 31, 2005, Kern River had 19 long-term firm natural gas transportation service agreements with 16 shippers, for a total of 812,626 Dth per day of capacity from the pipeline’s point of origination near Opal, Wyoming to delivery points primarily in California. Approximately 83% of the 2003 Expansion Project’s capacity is contracted for 15 years, with 14 of the long-term firm natural gas transportation service agreements expiring on April 30, 2018. The remaining 17% of capacity is contracted for 10 years, with five long-term firm natural gas transportation service agreements expiring on April 30, 2013. Over 95% of the 2003 Expansion Project’s capacity has primary delivery points in California, with the flexibility to access secondary delivery points in Nevada and Utah. Kern River has an additional 94,000 Dth per day of available firm capacity associated with the 2003 Expansion Project that was recently sold to a number of shippers at a discounted daily demand rate for the period of April 2006 through September 2008 on a short-term basis. Kern River will continue to market this capacity or use it for any future expansion needs for any period beyond September 2008.

Calpine Corp., including Calpine Energy Services, L.P. (“Calpine”), filed for Chapter 11 bankruptcy protection on December 20, 2005. Calpine holds two 50,000 Dth per day incremental 2003 Expansion Project firm transportation contracts that have termination dates of April 30, 2018. Pursuant to Kern River's credit requirements, Calpine provided approximately $19 million as cash security for the transportation contracts, which is expected to be applied against Calpine's pre-petition invoices. Post-petition, to date, Calpine has continued to nominate on its transportation contracts and pay its post-petition invoices; however, Calpine has indicated that it has not yet determined whether it will assume or reject the transportation contracts.

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 operates approximately 16,400 miles of natural gas pipelines, consisting of approximately 7,000 miles of mainline transmission pipelines and approximately 9,400 miles of lateral pipelines, with a design capacity of 4.6 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 ninth 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 for system operations, 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 FERC regulated tariff that is designed to allow it an opportunity to recover its costs together with a regulated return on equity.

Northern Natural Gas’ system consists of two distinct but operationally integrated markets. Its traditional end-use and distribution market area is at the northern end 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, and the natural gas supply and service area is at the southern end of the system, including Kansas, Oklahoma, Texas and New Mexico, which Northern Natural Gas refers to as the Field Area. Northern Natural Gas’ Field Area is interconnected with many interstate and intrastate pipelines in the national grid system. A majority of Northern Natural Gas’ capacity in both the Market Area and the Field Area is dedicated to Market Area customers under long-term firm transportation contracts. Approximately 54% of Northern Natural Gas’ current firm transportation capacity in the Market Area is contracted beyond 2008 and approximately 38% of such capacity is contracted beyond 2015.

Northern Natural Gas’ pipeline system transports natural gas primarily to end-user and local distribution markets in the Market Area. Customers consist of local distribution companies (“LDCs”), municipalities, other pipeline companies, gas marketers and end-users. While eight large LDCs account for the majority of Market Area volumes, Northern Natural Gas also serves numerous small communities through these large LDCs as well as municipalities or smaller LDCs and directly serves several large end-users. In 2005, over 85% of Northern Natural Gas’ transportation and storage revenue was from capacity charges under firm transportation and storage contracts and approximately 80% of that revenue was from LDCs. In 2005, approximately 71% of Northern Natural Gas’ transportation and storage revenue was generated from Market Area customer contracts.

The Field Area of Northern Natural Gas’ system provides access to natural gas supply from key production areas including the Hugoton, Permian and Anadarko Basins. In each of these areas, Northern Natural Gas has numerous interconnecting receipt and delivery points, with volumes received in the Field Area consisting of both directly connected supply and volumes from interconnections with other pipeline systems. In addition, Northern Natural Gas has the ability to aggregate processable natural gas for deliveries to various gas processing facilities.

In the Field Area, customers holding transportation capacity consist of LDCs, marketers, producers, and end-users. The majority of Northern Natural Gas’ Field Area firm transportation is provided to Northern Natural Gas’ Market Area firm customers under long-term firm transportation contracts with such volumes supplemented by volumes transported on an interruptible basis or pursuant to short-term firm contracts. In 2005, approximately 19% 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 Iowa and Minnesota. The three underground natural gas storage facilities and Northern Natural Gas’ two LNG storage peaking units have a total firm service storage capacity of approximately 59 Bcf and over 1.3 Bcf per day of peak day deliverability. These storage facilities provide Northern Natural Gas with operational flexibility for the daily balancing of its system and providing services to customers for meeting their year-round load requirements. In 2005, approximately 10% 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 high 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, as well as growing supply areas such as the Rocky Mountains, through Trailblazer Pipeline Company, Kinder Morgan Interstate Gas Transmission, Cheyenne Plains Gas Pipeline Company and Colorado Interstate Gas Pipeline Company (“Colorado Interstate”), and from Canadian production areas through Northern Border, 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 LDC revenue by taking advantage of opportunities to provide intermediate transportation through pipeline interconnections for customers in other markets, including Chicago, Illinois and other parts of the Midwest and Texas.

Kern River and Northern Natural Gas 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, location and overall customer service. Industrial end-users often have the ability to choose from alternative fuel sources in addition to natural gas, such as fuel oil and coal. 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 Kern River and Northern Natural Gas influence the price of natural gas.

Kern River competes with various interstate pipelines and its shippers in order to market any unutilized or unsubscribed capacity in 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, Overthrust Pipeline and Questar Pipeline. These interconnections, in addition to the direct interconnections to natural gas supply and 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 into the intrastate 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 is advantaged relative to other competing interstate pipelines because its relatively new pipeline can be economically expanded and will require significantly less capital expenditure to comply with the Pipeline Safety Improvement Act of 2002 (“PSIA”) than other systems. Kern River’s levelized rate structures has been challenged in its 2004 general rate case. Certain parties have advocated converting the system to a traditional, declining rate base rate structure. Kern River’s favorable market position is tied to the availability and favorable price of gas reserves in the Rocky Mountain area, an area that in recent years has attracted considerable interest for increased pipeline capacity serving markets other than California and Nevada. In addition, Kern River’s 2003 Expansion Project relies substantially on long-term transportation service agreements with several electric generation companies, who face significant competitive and financial pressures due to, among other things, the financial stress of energy markets and apparent over-building of electric generation capacity in California and other markets. This condition is expected to ease over time as demand for electric generation in Kern River’s market territory increases and older, less efficient power plants in the region are retired.

Northern Natural Gas has been able to provide cost competitive service because of its access to a variety of relatively low cost gas supply basins, its cost-control measures and its competitive load factor, which lowers the cost per unit of transportation. Although Northern Natural Gas has periodically experienced bypasses of the pipeline system affecting a small percentage of its market, to date Northern Natural Gas has been able to more than offset any load lost to bypass in the Northern Natural Gas Market Area through expansion projects.

Major competitors in the Northern Natural Gas Market Area include; ANR, Northern Border and NGPL. Other competitors include Great Lakes and Viking. In the Field Area, Northern Natural Gas competes with a large number of other competitors. Particularly in the Field Area, a significant amount of Northern Natural Gas’ capacity is used on an interruptible or short-term firm basis. In summer months, Northern Natural Gas’ Market Area customers often release significant amounts of their unused firm capacity to other shippers, which released capacity competes with Northern Natural Gas’ short-term firm or interruptible services.

Although Northern Natural Gas will need to aggressively compete to retain and build load, Northern Natural Gas believes that current and anticipated changes in its competitive environment have created opportunities to serve existing customers more efficiently and to meet certain growing supply needs. While LDCs’ peak day growth is driven by population growth and alternative fuel replacement, new off-peak demand growth is being driven primarily by power and ethanol plant expansions. Off-peak demand growth is important to Northern Natural Gas as this demand can generally be satisfied with little or no requirement for the construction of new facilities. Northern Natural Gas has been successful in competing for a significant amount of the increased demand related to electric generation and ethanol plants. Over the last five years, Northern Natural Gas has contracted approximately 319 MMcf per day of firm volume on its system from such new facilities, of which approximately 255 MMcf per day is currently in service and approximately 64 MMcf per day is scheduled to begin service in 2006. The recent passage of the Energy Policy Act has continued to encourage ethanol development and has had a positive effect of increasing demand on Northern Natural Gas’ system.

Kern River has one customer who accounts for greater than 10% of its revenue. Northern Natural Gas has two customers who each account for greater than 10% of its revenue. Northern Natural Gas has agreements to retain the vast majority of both of these customers’ volumes through at least 2017. The loss of any one or more of these customers, if not replaced, could have a material adverse effect on Kern River’s and Northern Natural Gas’ respective businesses.

Development Project

MEHC and a subsidiary, Alaska Gas Transmission Company, LLC (“Alaska Gas”), were two of several other parties, including existing producers of oil from Alaska’s North Slope, involved in a competitive selection process to develop and construct a proposed 745-mile natural gas pipeline that would extend from the North Slope area near Prudhoe Bay, Alaska south to the Alaska-Yukon border near Beaver Creek, Alaska. Due to unfavorable developments, MEHC and Alaska Gas ceased discussions with the state of Alaska in 2005.

CE Electric UK

CE Electric UK, an indirect wholly-owned subsidiary of MEHC, owns, primarily, two companies that distribute electricity in Great Britain, Northern Electric and Yorkshire Electricity. Northern Electric and Yorkshire Electricity, together, constitute the third largest distributor of electricity in Great Britain, serving more than 3.7 million customers in an area of approximately 10,000 square miles.

Electricity Distribution

Northern Electric and Yorkshire Electricity receive electricity from the national grid transmission system and distribute it to their customers’ premises using their network of transformers, switchgear and cables. Substantially all of the end users in Northern Electric’s and Yorkshire Electricity’s distribution services areas are connected to the Northern Electric and Yorkshire Electricity networks and electricity can only be delivered to such end users through their distribution system, thus providing Northern Electric and Yorkshire Electricity with distribution volume that is relatively stable from year to year. Northern Electric and Yorkshire Electricity charge fees for the use of the distribution system 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 Use of System Agreement”, which Northern Electric and Yorkshire Electricity separately entered into with the various suppliers of electricity in their respective distribution services areas. One such supplier, RWE Npower PLC (“Npower”) and certain of its affiliates, represented approximately 44% of the total distribution revenues of Northern Electric and Yorkshire Electricity in 2005.

At December 31, 2005, Northern Electric’s and Yorkshire Electricity’s electricity distribution network (excluding service connections to consumers) on a combined basis included approximately 33,000 kilometers of overhead lines and approximately 65,000 kilometers of underground cables. In addition to the circuits referred to above, at December 31, 2005, Northern Electric’s and Yorkshire Electricity’s distribution facilities also included approximately 60,000 transformers and approximately 700 primary substations. Substantially all substations are owned, with the balance being leased from third parties and mostly having remaining terms of at least 10 years.

Utility Services

Integrated Utility Services Limited, CE Electric UK's indirect wholly-owned subsidiary, is an engineering contracting company whose main business is providing electrical connection services for Northern Electric and Yorkshire Electricity and providing electrical infrastructure contracting services to third parties.

Gas Exploration and Production

CalEnergy Gas (Holdings) Limited (“CE Gas”), CE Electric UK’s indirect wholly-owned subsidiary, is a gas exploration and production company that is focused on developing integrated upstream gas projects in Australia, the United Kingdom and Poland. Its upstream gas business consists of exploration, development and production projects, resulting in the sale of gas to third parties.

In Australia, CE Gas has construction and development projects in the Bass, Otway and Perth Basins. The Yolla construction project in the Bass Basin is a gas and gas liquids project in which CE Gas holds a 15% interest. The project, operated by Origin Energy Limited of Australia, is nearing completion and includes an approximately 145 kilometer sub-sea pipeline across the Bass Strait off southern Victoria. The Bass Project is expected to be fully operational in 2006. The gas from the project will be sold to Origin Energy Limited’s retail affiliate, the liquefied petroleum gas will be sold to Elgas Limited, the largest marketer of liquefied petroleum gas in Australia, and the condensate will be sold to The Shell Company of Australia Limited. The Otway project, in which CE Gas holds a 5% interest, is operated by Woodside Exploration Limited of Australia. This project received construction approval during 2004. Construction has now commenced with first production expected around mid-2006.

In the United Kingdom, CE Gas continues to retain its 5% interest in the Victor Field, which is a gas field, located in the Southern North Sea. CE Gas is also developing certain new exploration in the North Sea.

CalEnergy Generation-Foreign

The CalEnergy Generation-Foreign platform consists of MEHC’s indirect ownership of the Leyte Projects, which are geothermal power plants located on the island of Leyte in the Philippines, and a combined irrigation and hydroelectric power generation project located in the central part of the island of Luzon in the Philippines (the “Casecnan Project”). Each plant possesses an operating margin that allows for production in excess of the amount listed below. Utilization of this operating margin is based upon a variety of factors and can be expected to vary between calendar quarters under normal operating conditions.

The following table sets out certain information concerning CalEnergy Generation-Foreign’s non-utility power projects in operation as of December 31, 2005:

	Facility
	Net				Power
	Capacity	Net MW	Energy	Contract	Purchaser/
Project ⁽¹⁾	(MW) ⁽²⁾	Owned ⁽²⁾	Source	Expiration	Guarantor ⁽³⁾

Upper Mahiao	119	119	Geo	June 2006	PNOC-EDC/ROP
Mahanagdong	154	150	Geo	July 2007	PNOC-EDC/ROP
Malitbog	216	216	Geo	July 2007	PNOC-EDC/ROP
Casecnan ⁽⁴⁾	150	150	Water	December 2021	NIA/ROP
Total	639	635

(1)	All projects are located in the Philippines and carry political risk insurance.

(2)	Actual MW may vary depending on operating, geothermal reservoir and water flow conditions, as well as plant design. Facility Net Capacity (MW) represents the contract capacity for the facility. Net MW Owned indicates current legal ownership, but, in some cases, does not reflect the current allocation of distributions.

(3)	Philippine National Oil Company-Energy Development Corporation (“PNOC-EDC”), Republic of the Philippines (“ROP”), and National Irrigation Administration (“NIA”). NIA also pays CE Casecnan Water and Energy Company, Inc. (“CE Casecnan”), an indirect subsidiary of MEHC, for the delivery of water and electricity by CE Casecnan. Separate sovereign performance undertakings of the ROP support PNOC-EDC’s obligations for the Leyte Projects. The ROP has also provided a performance undertaking under which NIA’s obligations under the Casecnan Project agreement, as supplemented by the Supplemental Agreement, are guaranteed by the full faith and credit of the ROP.

(4)	Net MW Owned of approximately 150 MW is subject 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 15% of the project. Refer to Item 3. Legal Proceedings of this Form 10-K for additional information.

PNOC-EDC’s and NIA’s obligations under the project agreements are substantially denominated in U.S. dollars and are the Leyte Projects’ and 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 obligations under the project agreements 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.

The Upper Mahiao project is a 119 net MW geothermal power project owned and operated by CE Cebu Geothermal Power Company, Inc. (“CE Cebu”), a Philippine corporation that is 100% indirectly owned by MEHC. On June 25, 2006, the end of the 10-year cooperation period, the Upper Mahiao facility will be transferred to PNOC-EDC at no cost on an “as-is” basis.

The Upper Mahiao project takes geothermal steam and fluid, provided by PNOC-EDC at no cost, and converts its thermal energy into electrical energy which is sold to PNOC-EDC, which in turn sells the power to the National Power Corporation (“NPC”), the government-owned and controlled corporation that is the primary supplier of electricity in the Philippines, for distribution on the island of Cebu. PNOC-EDC pays CE Cebu a fee based on the plant capacity. Pursuant to an amendment to the Upper Mahiao energy conversion agreement dated August 31, 2003, CE Cebu and PNOC-EDC agreed that the plant capacity for purposes of the fee would equal the contractually specified level of 118.5 MW. PNOC-EDC also pays CE Cebu a fee based on the electricity actually delivered to PNOC-EDC (approximately 2% of total contract revenue). Payments under the Upper Mahiao agreement are denominated in U.S. dollars, or computed in U.S. dollars and paid in pesos at the then-current exchange rate, except for the energy fee.

The Mahanagdong project is a 154 net MW geothermal power project owned and operated by CE Luzon Geothermal Power Company, Inc. (“CE Luzon”), a Philippine corporation of which MEHC indirectly owns 100% of the common stock. Another industrial company owns an approximate 3% preferred equity interest in the Mahanagdong project. The Mahanagdong project sells 100% of its capacity to PNOC-EDC, which in turn sells the power to the NPC for distribution on the island of Luzon.

The terms of the Mahanagdong energy conversion agreement are substantially similar to those of the Upper Mahiao agreement. On July 25, 2007, the end of the 10-year cooperation period, the Mahanagdong facility will be transferred to PNOC-EDC at no cost on an “as-is” basis. PNOC-EDC pays CE Luzon a fee based on the plant capacity. Pursuant to an amendment to the Mahanagdong energy conversion agreement dated August 31, 2003, CE Luzon and PNOC-EDC agreed that the plant capacity would equal the contractually specified level, which declines from approximately 154 MW in 2005 to approximately 153 MW in the last year of the cooperation period. The capacity fees are approximately 99% of total revenue at the contractually agreed capacity levels and the energy fees are approximately 1% of such total revenue.

The Malitbog project is a 216 net MW geothermal project owned and operated by Visayas Geothermal Power Company (“VGPC”), a Philippine general partnership that is indirectly wholly owned by MEHC. VGPC sells 100% of its capacity on substantially the same basis as described above for the Upper Mahiao project to PNOC-EDC, which sells the power to the NPC for distribution on the islands of Cebu and Luzon.

The Malitbog energy conversion agreement 10-year cooperation period expires on July 25, 2007, at which time the facility will be transferred to PNOC-EDC at no cost on an “as-is” basis. Capacity payments under the agreement equal 100% of total revenue. Pursuant to an amendment to the Malitbog energy conversion agreement dated August 31, 2003, VGPC and PNOC-EDC agreed that the plant capacity would equal the contractually specified level of 216 MW. A substantial majority of the capacity payments are required to be made by PNOC-EDC in U.S. dollars. The portion of capacity payments payable to PNOC-EDC in pesos is expected to vary over the term of the Malitbog project energy conversion agreement from 10% of VGPC’s revenue in the early years of the cooperation period to 23% of VGPC’s revenue at the end of the cooperation period. Payments made in pesos are generally made to a peso-denominated account and are used to pay peso-denominated expenses with respect to the Malitbog project.

The Casecnan Project is a combined irrigation and hydroelectric power generation project. The Casecnan Project consists generally of diversion structures in the Casecnan and Taan rivers that capture and divert excess water in the Casecnan watershed by means of concrete, in-stream diversion weirs and transfer that water through a transbasin tunnel of approximately 23 kilometers. During the water transfer, the elevation differences between the two watersheds allows electrical energy to be generated at an approximately 150 MW rated capacity power plant, which is located in an underground powerhouse cavern at the end of the transbasin water tunnel. A tailrace discharge tunnel then delivers water to the existing underutilized water storage reservoir at Pantabangan, providing additional water for irrigation and increasing the potential electrical generation at two existing downstream hydroelectric facilities of NPC. Once in the reservoir at Pantabangan, the water is under the control of NIA.

CE Casecnan owns and operates the Casecnan Project under the terms of the Project Agreement between CE Casecnan and NIA, which was modified by a Supplemental Agreement between CE Casecnan and NIA effective on October 15, 2003 (the “Supplemental 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 dependant 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 may have a material impact on 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 (described below) can produce significant variability in revenue between reporting periods.

Under the Supplemental Agreement, CE Casecnan is paid a fee for the delivery of water and a fee for the generation of electricity. With respect to water deliveries, the water delivery fee is payable in a fixed monthly payment based upon an average annual water delivery of 801.9 million cubic meters, pro-rated to approximately 66.8 million cubic meters per month, multiplied by the applicable per cubic meter rate through December 25, 2008. For each contract year starting from December 25, 2003, and ending on December 25, 2008, a water delivery credit (deferred revenue) is computed equal to 801.9 million cubic meters minus the greater of actual water deliveries or 700.0 million cubic meters - the minimum threshold. The water delivery credit at the end of the contract year is available to be earned in the succeeding contract years ending December 25, 2008. The cumulative water delivery credit at December 25, 2008, if any, shall be amortized from December 25, 2008 through December 25, 2013. Accordingly, in recognizing revenue, the water delivery fees are recorded each month pro-rated to approximately 58.3 million cubic meters per month until the minimum threshold has been reached for the contract year. Subsequent water delivery fees within the contract year are based on actual water delivered.

With respect to electricity, CE Casecnan is paid a guaranteed energy delivery fee each month equal to the product obtained by multiplying 19 GWh times $0.1596 per kWh. The guaranteed energy delivery fee is payable regardless of the amount of energy actually generated and delivered by CE Casecnan in any month. NIA also pays CE Casecnan an excess energy delivery fee, which is a variable amount based on actual electrical energy, if any, delivered in each month in excess of 19 GWh multiplied by (i) $0.1509 per kWh through the end of 2008 and (ii) commencing in 2009, $0.1132 (escalating at 1% per annum thereafter) per kWh, provided that any deliveries of energy in excess of 490 GWh but less than 550 GWh per year are paid for at a rate of 1.3 pesos per kWh and deliveries in excess of 550 GWh per year are at no cost to NIA. Within each contract year, no variable energy fees are payable until energy in excess of the cumulative 19 GWh per month for the contract year to date has been delivered. If the Casecnan Project is not dispatched up to 150 MW whenever water is available, NIA will pay for energy that could have been generated but was not as a result of such dispatch constraint.

In connection with the signing of the Supplemental Agreement, CE Casecnan received written confirmation from the Private Sector Assets and Liabilities Management Corporation that the issues with respect to the Casecnan Project that had been raised by the interagency review of independent power producers in the Philippines or that may have existed with respect to the project under certain provisions of the Electric Power Industry Reform Act of 2001 (“EPIRA”), which authorized the ROP to seek to renegotiate certain contracts such as the Project Agreement, have been satisfactorily addressed by the Supplemental Agreement.

CalEnergy Generation-Domestic

The subsidiaries comprising the Company's CalEnergy Generation-Domestic platform own interests in 15 operating 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, 2005:

Facility

Power

Net

Purchase

Capacity

Energy

Agreement

Power

Operating Project

(MW) ⁽¹⁾

Owned ⁽¹⁾

Source

Location

Expiration

Purchaser ⁽²⁾

Cordova

537

Gas

Illinois

2019

Constellation

Roosevelt Hot Springs

Geo

Utah

2020

PacifiCorp

CE Generation: ⁽³⁾

Geothermal -

Salton Sea I

Geo

California

2017

Edison

Salton Sea II

Geo

California

2020

Edison

Salton Sea III

Geo

California

2019

Edison

Salton Sea IV

Geo

California

2026

Edison

Salton Sea V

Geo

California

Varies

Various

Vulcan

Geo

California

2016

Edison

Elmore

Geo

California

2018

Edison

Leathers

Geo

California

2019

Edison

Del Ranch

Geo

California

2019

Edison

CE Turbo

Geo

California

2029

APS

327

164

Natural-Gas Fired -

Saranac

240

Gas

New York

2009

NYSE&G

Power Resources

212

106

Gas

Texas

N/A

Market sales

Yuma

Gas

Arizona

2024

SDG&E

502

221

829

385

Total ⁽⁴⁾

1,389

939

(1)	Represents nominal net generating capability (accredited for Cordova and contract capacity for most others). Actual MW may vary depending on operating and reservoir conditions and plant design. Net MW Owned indicates current legal ownership, but, in some cases, does not reflect the current allocation of partnership distributions.

(2)	Constellation Energy Commodities Group (“Constellation”); Southern California Edison Company (“Edison”); Arizona Public Service (“APS”) 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 affiliates currently operate ten geothermal plants in the Imperial Valley of California (the “Imperial Valley Projects”) and three natural gas-fired power generation facilities.

(4)	The totals do not include MEHC’s 50% ownership of the Wailuku hydroelectric project (facility net capacity of 10 MW), which was obtained on February 17, 2006.

Cordova Energy owns a 537 MW gas-fired power plant in the Quad Cities, Illinois area (the “Cordova Project”). CalEnergy Generation Operating Company, an indirect wholly owned subsidiary of MEHC, operates the Cordova Project which commenced commercial operations in June 2001. On July 6, 1999, Cordova Energy entered into a power purchase agreement with a unit of El Paso, under which El Paso was obligated to purchase all of the capacity and energy generated from the project until December 31, 2019. Effective January 1, 2006, El Paso assigned all of its rights and obligations under the power purchase agreement to Constellation. In connection with the assignment, Constellation Energy Group, Inc., the ultimate parent of Constellation, issued a limited guarantee of Constellation’s obligations under the power purchase agreement. The contract year under the power purchase agreement extends from May 15th in a year to May 14th in the subsequent year. For each contract year, Cordova Energy has an option to recall 50% of the output of the Cordova Project.

Each of the Imperial Valley Projects, excluding the Salton Sea V and CE Turbo projects, sells electricity to Edison pursuant to a separate Standard Offer No. 4 Agreement (“SO4 Agreement”) or a negotiated power purchase agreement. Each power purchase agreement is independent of the others, and the performance requirements specified within one such agreement apply only to the project subject to the agreement. The power purchase agreements provide for capacity payments, capacity bonus payments and energy payments. Edison makes fixed annual capacity payments and capacity bonus payments to the applicable projects to the extent that capacity factors exceed certain benchmarks. The price for capacity is fixed for the life of the SO4 Agreements and is significantly higher in the months of June through September.

Energy payments under the original SO4 Agreements were based on the cost that Edison avoids by purchasing energy from the project instead of obtaining the energy from other sources (“Avoided Cost of Energy”). In June and November 2001, the Imperial Valley Projects (except the Salton Sea IV project, which remained on Edison’s Avoided Cost of Energy) which receive Edison’s Avoided Cost of Energy entered into agreements that provide for amended energy payments under the SO4 Agreements. The amendments provide for fixed energy payments per kWh in lieu of Edison’s Avoided Cost of Energy. The fixed energy payment was 3.25 cents per kWh from December 1, 2001 through April 30, 2002 and is 5.37 cents per kWh from May 1, 2002 through April 30, 2007. Beginning May 1, 2007, the energy payments revert back to Edison’s Avoided Cost of Energy. For the years ended December 31, 2005, 2004 and 2003, Edison’s average Avoided Cost of Energy was 7.7 cents per kWh, 5.9 cents per kWh and 5.4 cents per kWh, respectively. Estimates of Edison’s future Avoided Cost of Energy vary substantially from year to year primarily based on the future cost of natural gas and may be impacted by regulatory proceedings and other commodity factors.

The Saranac project is a 240 net MW natural gas-fired cogeneration facility located in Plattsburgh, New York owned by the Saranac Partnership, which is indirectly owned by subsidiaries of CE Generation, Osaka Gas Energy America Corporation and General Electric Capital Corporation. Osaka Gas Energy America Corporation acquired ArcLight Capital Holdings’ interest in the project on December 15, 2005. The Saranac project has entered into a 15-year power purchase agreement with NYSE&G, 15-year steam purchase agreements with Georgia-Pacific Corporation and Pactiv Corporation and a 15-year natural gas supply contract with Coral Energy to supply 100% of the Saranac project’s fuel requirements. Each of the power purchase agreement, the steam purchase agreements and the natural gas supply contract contains rates that are fixed for the respective contract terms and expire in June 2009.

The Power Resources project is a 212 net MW natural gas-fired cogeneration project owned by Power Resources Ltd. (“Power Resources”), an indirect wholly-owned subsidiary of CE Generation. On August 5, 2003, Power Resources entered into a Tolling Agreement with ONEOK Energy, Marketing and Trading Company, L.P. The agreement commenced October 1, 2003 and expired on December 31, 2005.

Power Resources currently operates as a merchant power plant and is subject to electricity and gas markets to economically dispatch its output. Power Resources entered into a one-year Energy Management Service Agreement with Mpower Trade and Marketing (“Mpower”) effective January 1, 2006. Mpower is engaged to provide energy services required to manage the electrical generation, steam, and ancillary services capacity and related natural gas requirements of the plant. Mpower is due 10% of all net margins generated and Mpower’s credit is used in all transactions with no credit assurance required from Power Resources.

The Yuma project is a 50 net MW natural gas-fired cogeneration project in Yuma, Arizona owned by Yuma Cogeneration Associates (“YCA”), providing its electricity to SDG&E under an existing 30-year power purchase contract which commenced in May 1994 (the “Yuma Contract”). MEHC has guaranteed all of the obligations of YCA under the Yuma Contract or any other agreement with SDG&E relating to or arising out of the Yuma Contract. YCA also has executed steam sales contracts with Queen Carpet, Inc. to act as its thermal host.

Development Project

MEHC’s indirect wholly-owned subsidiary, CE Obsidian Energy LLC (“Obsidian”), has evaluated the development of a 185 net MW geothermal facility in the Imperial Valley of California. Substantially all of the output of the facility would be sold to the Imperial Irrigation District pursuant to a power purchase agreement. Due to current unfavorable project economics, MEHC and Obsidian are not actively developing this project.

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 and mortgage banking, primarily through joint ventures, title and closing services and other 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 in 18 states under the following brand names: Carol Jones REALTORS, CBSHOME Real Estate, Champion Realty, Edina Realty Home Services, Esslinger-Wooten-Maxwell REALTORS, First Realty/GMAC, HOME Real Estate, Iowa Realty, Jenny Pruitt and Associates REALTORS, Long Realty, Prudential California Realty, Prudential Carolinas 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, Iowa; Omaha and Lincoln, Nebraska; Birmingham, Auburn and Mobile, Alabama; Tucson, Arizona; Winston-Salem and Charlotte, North Carolina; Louisville and Lexington, Kentucky; Annapolis, Maryland; Atlanta, Georgia; and Miami, Florida.

In 2005, HomeServices separately acquired three real estate companies for an aggregate purchase price of $5.1 million, net of cash acquired, plus working capital and certain other adjustments. For the year ended December 31, 2004, these real estate companies had combined revenue of $21.8 million on approximately 3,400 closed sides representing $0.8 billion of sales volume. In 2004, HomeServices separately acquired six real estate companies for an aggregate purchase price of $30.7 million, net of cash acquired, plus working capital and certain other adjustments. For the year ended December 31, 2003, these real estate companies had combined revenue of $95.7 million on approximately 15,000 closed sides representing $3.2 billion of sales volume. In 2003, HomeServices separately acquired four real estate companies for an aggregate purchase price of $36.7 million, net of cash acquired, plus working capital and certain other adjustments. For the year ended December 31, 2002, these real estate companies had combined revenue of $102.9 million on approximately 16,000 closed sides representing $3.6 billion of sales volume.

Regulatory Matters

General Regulation

The Company’s businesses are subject to a number of federal, state, local and international regulations. In addition to the discussion contained herein, refer to Note 19 of Notes to Consolidated Financial Statements included in Item 8. Financial Statements and Supplementary Data of this Form 10-K for additional regulatory matter information regarding the Company’s businesses.

MidAmerican Energy

MidAmerican Energy is subject to comprehensive regulation by the FERC as well as utility regulatory agencies in Iowa, Illinois and South Dakota that significantly influences the operating environment and the recoverability of costs from utility customers. Except for Illinois, that regulatory environment has to date, in general, given MidAmerican Energy an exclusive right to serve electricity customers within its service territory and, in turn, the obligation to provide electric service to those customers. In Illinois, all customers are free to choose their electricity provider 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 from MidAmerican Energy’s existing regulated Illinois rates.

In conjunction with the March 1999 approval by the IUB of the MidAmerican Energy acquisition and March 2000 affirmation as part of the Company’s acquisition by a private investor group, MidAmerican Energy committed to the IUB to use commercially reasonable efforts to maintain an investment grade rating on its long-term debt and to maintain its common equity level above 42% of total capitalization unless circumstances beyond its control result in the common equity level decreasing to below 39% of total capitalization. MidAmerican Energy must seek the approval of the IUB of a reasonable utility capital structure if MidAmerican Energy’s common equity level decreases below 42% of total capitalization, unless the decrease is beyond the control of MidAmerican Energy. MidAmerican Energy is also required to seek the approval of the IUB if MidAmerican Energy’s equity level decreases to below 39%, even if the decrease is due to circumstances beyond the control of MidAmerican Energy. If MidAmerican Energy’s common equity level were to drop below the required thresholds, MidAmerican Energy’s ability to issue debt and declare dividends could be restricted.

Under a series of settlement agreements between MidAmerican Energy, the Iowa Office of Consumer Advocate (“OCA”) and other interveners approved by the IUB, MidAmerican Energy has agreed not to seek a general increase in electric rates to become effective prior to January 1, 2012 unless its Iowa jurisdictional electric return on equity for any year falls below 10%. These settlement agreements further provide that earnings exceeding a return on equity of 12% through December 31, 2005 and 11.75% for January 1, 2006 through December 31, 2011, will be recorded as a regulatory liability and shared with ratepayers. 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 seek any decrease in MidAmerican Energy’s Iowa electric rates prior to January 1, 2012. 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 portions of revenues associated with Iowa retail electric returns on equity within specified ranges will be recorded as a regulatory liability.

Under Iowa law, there are two options for temporary collection of higher rates following the filing of a request for a rate increase. Collection can begin, subject to refund, either within 10 days of filing, without IUB review, or 90 days after filing, with approval by the IUB. If the 10-day option is selected, Iowa law provides that if the utility is required to make refunds, the refunds may be based on overpayments made by each customer class, group or rate zone of the difference between final rates and the rates that would have been collected if temporary rates had been based upon prior regulatory principles. If the 90-day option is selected, Iowa law provides that the IUB shall prescribe the manner of refunding the difference between final rates and the rates based on prior ratemaking principles and a rate of return on common equity previously approved by the IUB. In either case, if the IUB has not issued a final order within ten months after the filing date, the temporary rates become final and any difference between the requested rate increase and the temporary rates may then be collected subject to refund until receipt of a final order. Exceptions to the ten-month limitation provide for extensions due to a utility's lack of due diligence in the rate proceeding, judicial appeals and situations involving new generating units being placed in service. MidAmerican Energy's cost of gas is collected in its Iowa gas rates through the Iowa Uniform Purchased Gas Adjustment Clause, which is updated monthly to reflect changes in actual costs.

South Dakota law authorizes the SDPUC to suspend new rates for up to six months during the pendency of rate proceedings; however, the rates are permitted to be implemented after six months subject to refund pending a final order in the proceeding.

Under Illinois law, new rates may become effective 45 days after filing with the ICC, or on such earlier date as the ICC may approve, subject to its authority to suspend the proposed new rates, subject to hearing, for a period not to exceed approximately eleven months after filing. Under Illinois electric tariffs, MidAmerican Energy's Fuel Cost Adjustment Clause reflects changes in the cost of all fuels used for retail electric generation, including certain fuel transportation costs, nuclear fuel disposition costs and the cost of energy purchased from other utilities. MidAmerican Energy's cost of gas is reflected in its Illinois gas rates through the Illinois Uniform Purchased Gas Adjustment Clause. Both of the adjustment clauses are updated on a monthly basis to reflect changes in actual costs.

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 ICC and transitions portions of the traditional electric services to a competitive environment. In general for the transition period that extends through 2006, the law allows for certain limits on the ICC’s regulatory authority over a utility’s generation and also relaxes its regulatory authority over many corporate transactions, such as the transfer of generation assets to affiliates. Special authority and limitations of authority apply during the transition to a competitive marketplace. Also, the law permits utilities to eliminate their fuel adjustment clauses and incorporates provisions by which earnings in excess of allowed amounts are either partially refunded to customers or are used to accelerate a company's asset recovery. Electric rates in Illinois are frozen until January 1, 2007, subject to certain exceptions allowing for increases, at which time bundled rates are subject to cost-based ratemaking.

The FERC regulates MidAmerican Energy’s rates charged to wholesale customers for energy and transmission services. 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. The FERC conducts a triennial review of MidAmerican Energy’s market-based pricing authority. Margins earned on wholesale sales have historically been included as a component of retail cost of service upon which retail rates are based.

On July 22, 2005, MidAmerican Energy made a filing with the FERC requesting its approval to establish a transmission service coordinator (“TSC”). The TSC would be a third party administrator of various MidAmerican Energy OATT functions for transmission service. On December 16, 2005, the FERC issued an order conditionally accepting MidAmerican Energy’s request to establish a TSC. The order requires MidAmerican Energy to make modifications to the draft TSC agreement filed with the FERC as part of the request and to file a final executed TSC agreement with the FERC for its review prior to the agreement becoming effective. MidAmerican Energy has entered into a contract with a third-party vendor to administer MidAmerican Energy’s OATT. MidAmerican Energy does not believe that the incremental costs will have a material impact on its results of operations, financial position or cash flows. Subject to FERC approval, the TSC is scheduled to commence operations in the third quarter of 2006. Under the contract, the vendor would provide its tariff administration and planning services into the fall of 2009.

On June 3, 2004, the FERC’s Division of Operational Investigations of the Office of Market Oversight and Investigations (“OMOI”) informed MidAmerican Energy that it was commencing an audit to determine whether and how MidAmerican Energy and its subsidiaries and affiliates are complying with (1) requirements of the standards of conduct and open access same-time information system of the FERC’s regulations, and (2) codes of conduct. In addition, OMOI sought to review MidAmerican Energy’s transmission practices. The FERC commenced several such audits of utilities in 2003 and 2004. On September 29, 2005, the FERC approved the audit findings and MidAmerican Energy agreed to take certain corrective actions. Accordingly, MidAmerican Energy will build $9.2 million in previously unscheduled transmission system upgrades. That capital expenditure will be excluded from MidAmerican Energy’s rate base for six years during which time MidAmerican Energy will not earn a return on the transmission upgrades. In addition, MidAmerican Energy has agreed to accelerate $14.7 million of scheduled transmission system upgrades. MidAmerican Energy has implemented a compliance plan to address certain aspects of the audit findings relating to transmission practices and the administration of the OATT.

On July 13, 2004, the FERC issued an order requiring MidAmerican Energy to conduct a study to determine whether MidAmerican Energy or its affiliates possess generation market power. MidAmerican Energy is being required to show the absence of generation market power in order to be allowed to continue to sell wholesale electric power at market-based rates. The FERC order is intended to have MidAmerican Energy conform to what has become the FERC’s general practice for utilities given authorization to make wholesale market-based sales. Under this general practice, utilities authorized to make market-based electric sales must submit a new market power study to the FERC every three years. MidAmerican Energy filed the required study on October 29, 2004. On June 1, 2005, the FERC issued an order setting for investigation the reasonableness of MidAmerican Energy’s market-based rates within its control area. The order also terminated the previously established November 1, 2004 refund date and instead required that market-based sales made by MidAmerican Energy within its control area beginning August 7, 2005 be subject to refund until the matter is resolved. The FERC also required MidAmerican Energy to file additional information by July 1, 2005, and August 1, 2005. In its August 1, 2005 filing, MidAmerican Energy filed a proposed cost-based sales tariff applicable to sales made within its control area to replace its market-based sales tariff. The FERC is currently reviewing the proposed tariff. MidAmerican Energy does not expect the outcome of this issue to have a material effect on its results of operations, financial position or cash flows.

Kern River and Northern Natural Gas

Kern River and Northern Natural Gas are subject to regulation by various federal and state agencies. As owners of interstate natural gas pipelines, Northern Natural Gas’ and Kern River’s rates, services and operations are subject to regulation by the FERC. The FERC administers, among other things, the Natural Gas Act and the Natural Gas Policy Act of 1978. Additionally, interstate pipeline companies are subject to regulation by the United States Department of Transportation (“DOT”) pursuant to the Natural Gas Pipeline Safety Act of 1968 (“NGPSA”), which establishes safety requirements in the design, construction, operations and maintenance of interstate natural gas transmission facilities, and the PSIA, which implemented additional safety and pipeline integrity regulations for high consequence areas.

The FERC has jurisdiction over, among other things, 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. The FERC also has jurisdiction over the rates and charges and terms and conditions of service for the transportation of natural gas in interstate commerce.

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. We cannot predict when or if any new proposals might be implemented or, if so, how Kern River and Northern Natural Gas might be affected.

The Company’s pipeline operations are subject to regulation by the DOT under the NGPSA relating to design, installation, testing, construction, operation and management of its pipeline systems. 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 aging pipeline infrastructure in the United States has led to heightened regulatory and legislative scrutiny of pipeline safety and integrity practices. The NGPSA was amended by the Pipeline Safety Act of 1992 to require the DOT’s Office of Pipeline Safety to consider protection of the environment when developing minimum pipeline safety regulations. In addition, the amendments require that the DOT issue pipeline regulations concerning, among other issues, the circumstances under which emergency flow restriction devices should be required, training and qualification standards for personnel involved in maintenance and operation, and requirements for periodic integrity inspections, as well as periodic inspection of facilities in navigable waters that pose a hazard to navigation or public safety. In addition, the amendments narrowed the scope of the exemption for gas pipelines from the underground storage tank requirements under the Resource Conservation and Recovery Act. The Company believes its pipeline systems comply in all material respects with the NGPSA.

The PSIA requires major new programs in the areas of operator qualification, risk analysis and integrity management. The PSIA requires the periodic inspection or testing of pipelines in areas where the potential consequences of a gas pipeline accident may be significant or may do considerable harm to people and their property, which are referred to as High Consequence Areas. Pursuant to the PSIA, the DOT promulgated new regulations, effective February 14, 2004, that require interstate pipeline operators to (i) develop comprehensive integrity management programs, (ii) identify applicable threats to pipeline segments that could impact High Consequence Areas, (iii) assess these segments, and (iv) provide ongoing mitigation and monitoring. The Company believes its pipeline operations comply in all material respects with the PSIA.

Energy Policy Act

On August 8, 2005, the Energy Policy Act was signed into law. That law potentially impacts many segments of the energy industry. The law will result in expanding the FERC’s regulatory authority in areas such as mandatory electric system reliability standards, electric transmission expansion incentives and pricing, regulation of utility holding companies, and gives the FERC enforcement authority to issue substantial civil penalties. 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 repealed PUHCA 1935 and enacted the Public Utility Holding Company Act of 2005 (“PUHCA 2005”), effective February 8, 2006. PUHCA 1935 extensively regulated and restricted the activities of registered public utility holding companies and their subsidiaries. PUHCA 2005 and the rules issued by the FERC to implement PUHCA 2005 require, among other things, public utility holding companies to permit access by the FERC to the books and records of the holding company and its affiliates transacting business with the public utility, unless such requirement is exempted or waived, and to comply with the FERC’s record retention requirements. The repeal of PUHCA 1935 enabled Berkshire Hathaway to convert all of its outstanding no par, zero-coupon convertible preferred stock into an equal number of shares of MEHC’s common stock thereby becoming the majority owner of MEHC.

The Energy Policy Act also substantially amended the Public Utility Regulatory Policies Act of 1978 (“PURPA”). PURPA and the regulations issued thereunder affected MEHC and certain of its subsidiaries’ operations by providing to qualifying facilities (“QF”) certain exemptions from federal and state laws and regulations, including organizational, rate and financial regulation. New Section 210(m) eliminates the requirement that public utilities purchase the capacity and energy of QFs if the FERC determines that the requisite competitive market criteria are satisfied. In January 2006, the FERC instituted a rulemaking process to implement this section of the Energy Policy Act. The Energy Policy Act removed the 50% limitation on electric utility and electric utility holding company ownership of QFs. The Energy Policy Act does not authorize the termination of any existing contract and the Company does not expect the amendments to PURPA to have an adverse effect on the Company.

CE Electric UK

Since 1990, the electricity generation, transmission, supply and distribution industries in Great Britain have been privatized, and competition has been introduced in generation and supply, and, to a much more limited extent, in some aspects of distribution such as new connections and metering. Electricity is produced by generators, transmitted through the national grid transmission system and distributed to customers by the fourteen Distribution License Holders (“DLHs”) in their respective distribution services areas.

Under the Utilities Act 2000, the public electricity supply license created pursuant to the Electricity Act 1989 was replaced by two separate licenses - the electricity distribution license and the electricity supply license. When the relevant provision of the Utilities Act 2000 became effective on October 1, 2001, the public electricity supply licenses formerly held by Northern Electric plc (“NE”) and Yorkshire Electricity Group plc (“YE”) were split so that separate subsidiaries held licenses for electricity distribution and electricity supply. In order to comply with the Utilities Act 2000 and to facilitate this license splitting, NE and YE (and each of the other holders of the former public electricity supply licenses) each made a statutory transfer scheme that was approved by the Secretary of State for Trade and Industry. These schemes provided for the transfer of certain assets and liabilities to the licensed subsidiaries. This occurred on October 1, 2001, a date set by the Secretary of State for Trade and Industry. As a consequence of these schemes, the electricity distribution businesses of NE and YE were transferred to Northern Electric and Yorkshire Electricity, respectively. Northern Electric and Yorkshire Electricity are each a DLH. The residual elements of the electricity supply licenses were transferred to Innogy Holdings plc (“Innogy”), the predecessor of Npower, in connection with the sale of NE’s electricity and gas supply business to Innogy and the purchase by NE of YE’s electricity distribution business from Innogy on September 21, 2001.

Each of the DLHs is required to offer terms for connection to its distribution system and for use of its distribution system to any person. In providing the use of its distribution system, a DLH must not discriminate between users, nor may its charges differ except where justified by differences in cost.

Under the Utilities Act 2000, the Gas and Electricity Markets Authority (“GEMA”) is able to impose financial penalties on license holders who contravene (or have in the past contravened) any of their license duties or certain of their duties under the Electricity Act 1989, as amended, or who are failing (or have in the past failed) to achieve a satisfactory performance in relation to the individual standards of performance prescribed by GEMA. Any penalty imposed must be reasonable and may not exceed 10% of the licensee’s revenue.

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 British electricity regulatory body and was last reset on April 1, 2005. The distribution price control formula is generally reviewed and reset at five-year intervals. Through March 31, 2010, the change in revenue is expected to be mainly influenced by the rate of inflation in the United Kingdom, system losses, the number of customers connected to the network and customer service performance. The Office of Gas and Electricity Markets (“Ofgem”) completed the process of reviewing the existing price control formula for Northern Electric and Yorkshire Electricity in November 2004. As a result of the review, the allowed revenue of Northern Electric’s and Yorkshire Electricity’s distribution businesses were reduced by 4% and 9%, respectively, in real terms, effective April 1, 2005.

CalEnergy Generation-Foreign

The Philippine Congress has passed 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 have an impact on the Company’s future operations in the Philippines and the Philippine power industry as a whole, the effect of which is not yet determinable or estimable.

In connection with the signing of the Supplemental Agreement, CE Casecnan received written confirmation from the Private Sector Assets and Liabilities Management Corporation that the issues with respect to the Casecnan Project that had been raised by the interagency review of independent power producers in the Philippines or that may have existed with respect to the project under certain provisions of EPIRA, which authorized the ROP to seek to renegotiate certain contracts such as the Project Agreement, have been satisfactorily addressed by the Supplemental Agreement.

CalEnergy Generation-Domestic

Each of the domestic power facilities in the CalEnergy Generation-Domestic platform, excluding Cordova Energy and Power Resources, meets the requirements promulgated under PURPA to be a QF. Prior to passage of the Energy Policy Act, QF status under PURPA provided two primary benefits. First, regulations under PURPA exempted QFs from PUHCA 1935, the FERC rate regulation under Sections 205 and 206 of the Federal Power Act and the state laws concerning rates of electric utilities and financial and organization regulations of electric utilities. Second, the FERC’s regulations promulgated under PURPA required that (1) electric utilities purchase electricity generated by QFs, the construction of which commenced on or after November 9, 1978, at a price based on the purchasing utility’s Avoided Cost of Energy, (2) electric utilities sell back-up, interruptible, maintenance and supplemental power to QFs on a non-discriminatory basis, and (3) electric utilities interconnect with QFs in their service territories. Following the effective date of repeal of PUHCA 1935, the exemption from PUHCA 1935 is no longer relevant, but QFs remain exempt from the accounting and reporting requirements of PUHCA 2005. QF sales that occur pursuant to existing contracts will continue to be exempt from FERC rate regulation under Sections 205 and 206 of the Federal Power Act. However, with respect to new contracts, QFs are no longer exempt from FERC’s regulation of rates under Sections 205 and 206 of the Federal Power Act, unless the relevant sales are made pursuant to a state regulatory authority’s implementation of PURPA,

In addition, in January 2006, the FERC issued a notice of proposed rulemaking to implement a provision of the Energy Policy Act, which eliminates the electric utilities’ mandatory purchase obligation under PURPA if the FERC determines that certain conditions regarding QF access to transmission facilities and competitive markets are satisfied. Although the proposed rule does not permit electric utilities to terminate existing agreements, such as those now in place with CalEnergy Generation-Domestic, if the final rule is adopted substantially as proposed, the effect on the Company when the existing agreements terminate could be adverse. QF owners are required to provide notice to the FERC of a “material change” in facts in an application for recertification or notice of self-recertification. Subsequent notices of self-recertification for the same QF need only refer to changes which have occurred with respect to the facility since the prior notice or the prior FERC certification.

In another rulemaking proceeding to implement part of the Energy Policy Act, the FERC stated that exempt wholesale generators (“EWG”) like Cordova Energy and Power Resources are not considered to be an electric utility company for the limited purpose of the FERC’s access to the books and records of holding company systems under PUHCA 2005. As such, a EWG is permitted to sell capacity and electricity in the wholesale markets, but not in the retail markets. If a EWG is subject to a “material change” in facts that might affect its continued eligibility for EWG status, within 60 days of such material change, the EWG must (1) file a written explanation of why the material change does not affect its EWG status, (2) file a new application for EWG status, or (3) notify the FERC that it no longer wishes to maintain EWG status.

HomeServices

HomeServices is subject to regulations promulgated by the U.S. Department of Housing and Urban Development (“HUD”) as well as regulatory agencies in the states within which it operates that significantly influence its operating environment. The House Committee on Financial Services, the Senate Committee on Banking, Housing and Urban Affairs and HUD each had indicated that reforming the Real Estate Settlement and Procedures Act (“RESPA”) regulation was a priority in 2005. On June 27, 2005, HUD announced their plan to hold six roundtables to discuss with the industry what provisions a new RESPA reform rule should contain. Those roundtables were held across the country in July and August 2005. HUD stated that it would publish its RESPA proposal in late 2005 and the Final Rule in 2006. As of December 31, 2005, HUD did not publish a RESPA proposal and has not indicated when a Final Rule will be issued in 2006. It is believed that this delay has been caused, in part, by the damage caused by hurricanes Katrina and Wilma. It is unknown whether a proposed rule will be introduced or finalized in 2006. Accordingly, the Company is presently unable to quantify the likely impact of any proposed rule, if issued.

Environmental Regulation

Domestic

The Company’s domestic operations are subject to a number of federal, state and local environmental and environmentally related laws and regulations affecting many aspects of its present and future operations in the United States. Such laws and regulations generally require the Company’s domestic operations to obtain and comply with a wide variety of licenses, permits and other approvals. The Company believes that its operating power facilities and natural gas pipeline operations are currently in material compliance with all applicable federal, state and local laws and regulations. However, no guarantee can be given that in the future the Company’s domestic operations will be in material compliance with all applicable environmental statutes and regulations or that all necessary permits will be obtained or approved. In addition, the construction of new power facilities and natural gas pipeline operations is a costly and time-consuming process requiring a multitude of complex environmental permits and approvals prior to the start of construction that may create the risk of expensive delays or material impairment of project value if projects cannot function as planned due to changing regulatory requirements or local opposition. The Company cannot provide assurance that existing regulations will not be revised or that new regulations will not be adopted or become applicable to it which could have an adverse impact on its capital or operating costs or its operations.

Under various federal, state and local environmental laws and regulations, a current or previous owner or operator of any facility may be required to investigate and remediate past releases or threatened releases of hazardous or toxic substances or petroleum products located at the facility, and may be held liable to a governmental entity or to third parties for property damage, personal injury and investigation and remediation costs incurred by a party in connection with certain releases or threatened releases. In certain cases liability for damages to natural resources may also be assessed. These laws, including the Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended by the Superfund Amendments and Reauthorization Act of 1986, impose liability without regard to whether the owner knew of or caused the release of the hazardous substances, and courts have interpreted liability under such laws to be strict and joint and several. The cost of investigation, remediation or removal of substances may be substantial. In connection with the Company’s ownership and operation of its power facilities and pipeline systems, the Company may become liable for such costs. Given the use of hazardous substances and/or petroleum products within its power facilities and pipeline systems, often within areas that have a long history of industrial use, it is possible that the Company will discover currently unknown contamination or that future spills or other causes of contamination will occur. As a result, even at those sites where the Company is not presently aware of any contamination that currently requires remediation, it is possible that the Company may become liable for additional remediation costs.

Clean Air Standards

MidAmerican Energy is subject to applicable provisions of the Clean Air Act and related air quality standards promulgated by the United States Environmental Protection Agency (“EPA”). The Clean Air Act provides the framework for regulation of certain air emissions and permitting and monitoring associated with those emissions. MidAmerican Energy believes it is in material compliance with current air quality requirements. In addition to the discussion contained herein, refer to Note 20 of Notes to Consolidated Financial Statements included in Item 8. Financial Statements and Supplementary Data of this Form 10-K for additional clean air standards information regarding MidAmerican Energy’s operations.

On February 16, 2005, the Kyoto Protocol became effective, requiring 35 developed countries to reduce greenhouse gas emissions by approximately 5% between 2008 and 2012. While the United States did not ratify the protocol, the ratification and implementation of its requirements in other countries has resulted in increased attention to the climate change issue in the United States. In 2005, the Senate adopted a “sense of the Senate” resolution that puts the Senate on record that Congress should enact a comprehensive and effective national program of mandatory, market-based limits and incentives on emissions of greenhouse gases that slow, stop, and reverse the growth of such emissions at a rate and in a manner that will not significantly harm the United States economy; and will encourage comparable action by other nations that are major trading partners and key contributors to global emissions. It is anticipated that the resolution may be further addressed by Congress in 2006. While debate continues at the national level over the direction of domestic climate policy, several states are developing state-specific or regional legislative initiatives to reduce greenhouse gas emissions. In December 2005, the states of Connecticut, Delaware, Maine, New Hampshire, New Jersey, New York and Vermont signed a mandatory regional pact to reduce greenhouse gas emissions. 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 public nuisance suit, holding that such critical issues affecting the United States such as greenhouse gas emissions reductions are not the domain of the court and should be resolved by the Executive Branch 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 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 results of operations.

The EPA’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 MidAmerican’s facilities in particular, such actions could significantly impact the Company’s fossil-fueled facilities and, therefore, its results of operations.

Clean Water Standards

Section 316(b) of the Clean Water Act requires that cooling water intake structures reflect the best technology available for minimizing "adverse environmental impacts" to aquatic organisms. On February 16, 2004, EPA Administrator Michael Leavitt signed the final Phase II rule for existing electric generating facilities. The rule sets significant new national technology-based performance standards 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. MidAmerican Energy has completed a review of its historical Section 316(b) studies, as well as filed Proposals for Information Collection describing MidAmerican Energy’s plans for conducting biological field studies adjacent to its cooling water intake structures over the next two years. Although the impact of the MidAmerican Energy intake structures on aquatic organisms is unknown at this time, the previous Section 316(b) studies suggest that the impingement impact at the facility intake structures is minimal and that little if any intake structure expenditures will be necessary to meet the Section 316(b) impingement standard. Because of the high flow rate of the Missouri and Mississippi Rivers as compared to the withdrawal rates of the intake structures, the entrainment criteria of the Section 316(b) rule is not applicable to the MidAmerican Energy facilities. However, should the new impingement studies show that the intakes are impacting the fish species, the intake structures may need to be modified to meet best technology standards. This could include significant expenditures involved with limiting the amount of water withdrawn from the Missouri or Mississippi Rivers, and restrictions on the intake flow velocity.

Nuclear Regulation

MidAmerican Energy is subject to the jurisdiction of the NRC with respect to its license and 25% ownership interest in Quad Cities Station Units 1 and 2. Exelon Generation Company, LLC (“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 regulations control the granting of permits and licenses for the construction and operation of nuclear generating stations and subject such stations to continuing review and regulation. On October 29, 2004, the NRC granted renewed licenses for both Quad Cities Station Unit 1 and Unit 2 that provide for operation until December 14, 2032, which is in effect a 20-year extension of the licenses. 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.

The NRC also regulates the decommissioning of nuclear power plants including the planning and funding for the eventual decommissioning of the plants. In accordance with these regulations, MidAmerican Energy submits a report to the NRC every two years providing reasonable assurance that funds will be available to pay the costs of decommissioning its share of Quad Cities Station.

Under the Nuclear Waste Policy Act of 1982 (“NWPA”), the U.S. Department of Energy (“DOE”) is responsible for the selection and development of repositories for, and the permanent disposal of, spent nuclear fuel and high-level radioactive wastes. Exelon Generation, as required by the NWPA, signed a contract with the DOE under which the DOE was to receive spent nuclear fuel and high-level radioactive waste for disposal beginning not later than January 1998. The DOE did not begin receiving spent nuclear fuel on the scheduled date and remains unable to receive such fuel and waste. The earliest the DOE currently is expected to be able to receive such fuel and waste is 2010. The costs to be incurred by the DOE for disposal activities are being financed by fees charged to owners and generators of the waste. In 2004, Exelon Generation reached a settlement with the DOE concerning the DOE’s failure to begin accepting spent nuclear fuel in 1998. As a result, Quad Cities Station will be billing the DOE, and the DOE will be obligated to reimburse the station for all station costs incurred due to the DOE’s delay. Exelon Generation has completed construction of an interim spent fuel storage installation (“ISFSI”) at Quad Cities Station to store spent nuclear fuel in dry casks in order to free space in the storage pool. The first pad at the ISFSI is expected to facilitate storage of casks to support operations at Quad Cities Station until at least 2017. The first storage in dry cask commenced in November 2005. In the 2017 to 2022 timeframe, Exelon Generation plans to add a second pad to the ISFSI to accommodate storage of spent nuclear fuel through the end of operations at Quad Cities Station.

MidAmerican Energy has established trusts for the investment of funds collected for nuclear decommissioning associated with Quad Cities Station. Electric tariffs currently in effect include provisions for annualized collection of estimated decommissioning costs at Quad Cities Station. In Iowa, estimated Quad Cities Station decommissioning costs are reflected in base rates. MidAmerican Energy’s cost related to decommissioning funding in 2005 was $8.3 million.

United Kingdom

CE Electric UK’s businesses are subject to a number of United Kingdom regulations with respect to the protection of the environment. The principal legislation behind these regulations in relation to CE Electric UK activities is the Water Resources Act of 1991 and the Environmental Protection Act of 1990. The most relevant regulatory requirement is the Hazardous Waste (England and Wales) Regulations, which came into force in July 2005. These regulations widened the scope of hazardous waste and have reclassified many waste products as hazardous that were previously regarded as non-hazardous waste. The cost of compliance with these requirements has been immaterial and the Company expects the ongoing cost of compliance will not have a material impact on the Company.

Philippines

On June 23, 1999, the Philippine Congress enacted the Philippine Clean Air Act of 1999 (the “Philippine Clean Air Act”). The related implementing rules and regulations were adopted in November 2000. The law as written would require the Leyte Projects to comply with a maximum discharge of 200 grams of hydrogen sulfide per gross MWh of output by June 2004. On November 13, 2002, the Secretary of the Philippine Department of Environment and Natural Resources issued a Memorandum Circular (“MC”) designating geothermal areas as “special airsheds.” PNOC-EDC has advised the Leyte Projects that the MC exempts the Mahanagdong and Malitbog plants from the need to comply with the point-source emission standards of the Philippine Clean Air Act. CE Cebu and PNOC-EDC have constructed a gas dispersion facility for the Upper Mahiao project which is designed to ensure compliance with the emission standards of the Philippine Clean Air Act. The gas dispersion project was put into commercial operation in December 2003.

Employees

At December 31, 2005, the Company employed approximately 11,400 people, of which approximately 3,900 are covered by union contracts. MidAmerican Energy’s union contract with International Brotherhood of Electrical Workers locals 109 and 499 was set to expire on February 28, 2006, and covers approximately 1,700 employee members. On February 10, 2006, the contract terms with locals 109 and 499 were extended through April 30, 2006, and the parties agreed to a 30-day notice of strike or lockout.

Item 1A. Risk Factors .

Risks Associated with the Company’s Corporate and Financial Structure

MEHC is a holding company that depends on distributions from its subsidiaries and joint ventures to meet its needs.

MEHC is a holding company and derives substantially all of its income and cash flow from its subsidiaries and joint ventures. MEHC expects that future development and acquisition efforts will be similarly structured to involve operating subsidiaries and joint ventures. MEHC is dependent on the earnings and cash flows of, and dividends, loans, advances or other distributions from, its subsidiaries and joint ventures to generate the funds necessary to meet its obligations. All required payments on debt and preferred stock at subsidiary levels will be made before funds from subsidiaries are available to MEHC. The availability of distributions from such entities is also subject to:

	Ÿ	their earnings and capital requirements;
	Ÿ	the satisfaction of various covenants and conditions contained in financing documents by which they are bound or in their organizational documents; and
	Ÿ	in the case of MEHC’s regulated utility subsidiaries, regulatory restrictions which restrict their ability to distribute profits to MEHC.

MEHC’s subsidiaries and joint ventures are separate and distinct legal entities and have no obligation, contingent or otherwise, to pay any of MEHC’s obligations or to make any funds available, whether by dividends, loans or other payments, for payment of MEHC’s obligations, and do not guarantee the payment of MEHC’s obligations.

The Company is substantially leveraged, the terms of MEHC’s senior and subordinated debt do not restrict its ability or its subsidiaries’ ability to incur additional indebtedness that could have an adverse impact on the Company’s financial condition and MEHC’s senior and subordinated debt is structurally subordinated to the indebtedness of its subsidiaries.

The Company’s substantial leverage level presents the risk that it might not generate sufficient cash to service its indebtedness or that the Company’s leveraged capital structure could limit its ability to finance future acquisitions, develop additional projects, compete effectively and operate successfully under adverse economic conditions. At December 31, 2005, MEHC’s outstanding senior indebtedness was approximately $2.8 billion and MEHC’s outstanding subordinated indebtedness was approximately $1.6 billion. These amounts exclude MEHC’s guarantees and letters of credit in respect of subsidiary and equity investment indebtedness aggregating approximately $90.9 million as of December 31, 2005. The Company expects to incur additional indebtedness in the future, including approximately $1.7 billion of MEHC long-term senior debt.

MEHC’s subsidiaries also have significant amounts of indebtedness. At December 31, 2005, MEHC’s consolidated subsidiaries had outstanding indebtedness totaling approximately $7.2 billion. This amount does not include (i) any trade debt or preferred stock obligations of MEHC’s subsidiaries, (ii) its subsidiaries’ letters of credit in respect of their indebtedness, (iii) MEHC’s share of the outstanding indebtedness of its and its subsidiaries’ equity investments, or (iv) the outstanding indebtedness and preferred stock of PacifiCorp, which was approximately $4.3 billion at December 31, 2005.

The terms of MEHC’s senior and subordinated debt do not limit its ability or the ability of its subsidiaries or joint ventures to incur additional debt or issue additional preferred stock. Accordingly, MEHC or its subsidiaries or joint ventures could enter into acquisitions, refinancings, recapitalizations or other highly leveraged transactions that could significantly increase MEHC’s or their total amount of outstanding debt. The interest payments needed to service this increased level of indebtedness could have a material adverse effect on MEHC’s or its subsidiaries’ operating results. A highly leveraged capital structure could also impair MEHC’s or its subsidiaries’ overall credit quality, making it more difficult for the Company to finance its operations or issue future indebtedness on favorable terms, and could result in a downgrade in the ratings of the Company’s indebtedness by credit rating agencies. Further, if any of MEHC’s or its subsidiaries’ indebtedness is accelerated due to an event of default under such indebtedness and such acceleration results in an event of default under some or all of the Company’s other indebtedness, the Company may not have sufficient funds to repay all of the accelerated indebtedness.

Claims of creditors of MEHC’s subsidiaries and joint ventures have priority over the claims of MEHC’s senior and subordinated debt holders with respect to the assets and earnings of MEHC’s subsidiaries and joint ventures. In addition, the stock or assets of substantially all of MEHC’s operating subsidiaries and joint ventures is directly or indirectly pledged to secure their financings and, therefore, may be unavailable as potential sources of repayment of MEHC’s senior and subordinated debt.

MEHC’s majority stockholder, Berkshire Hathaway, could exercise control over the Company in a manner that would benefit Berkshire Hathaway to the detriment of the Company’s creditors.

MEHC became a majority owned subsidiary of Berkshire Hathaway on February 9, 2006, and, therefore, Berkshire Hathaway has control over the decision of all matters submitted for shareholder approval, including the election of MEHC’s directors who oversee its management and affairs. In circumstances involving a conflict of interest between Berkshire Hathaway, on the one hand, and MEHC’s creditors, on the other, Berkshire Hathaway could exercise its control in a manner that would benefit Berkshire Hathaway to the detriment of MEHC’s creditors.

Risks Associated with the Company’s Business

The Company’s growth has been achieved, in significant part, through strategic acquisitions, and additional acquisitions may not be successful.

The Company’s growth has been achieved, in significant part, through strategic acquisitions. The Company intends to continue to pursue selected opportunities for acquisitions of assets and businesses, as well as business combinations, within the Company’s industries for the foreseeable future. The Company investigates opportunities that it believes may increase shareholder value and build on existing businesses. The Company has participated in the past, and the Company’s security holders may assume that at any time the Company may be participating, in bidding or other negotiations for such transactions. This participation may or may not result in a transaction for the Company. Any transaction that does take place may involve consideration in the form of cash, debt or equity securities.

Since 1996, the Company has completed several significant acquisitions, including the acquisitions of Northern Electric, Yorkshire Electricity, MidAmerican Energy, Kern River and Northern Natural Gas. In May 2005, MEHC announced that it had reached a definitive agreement with ScottishPower to acquire its wholly-owned indirect subsidiary, PacifiCorp, a regulated electric utility for a cash purchase price of approximately $5.1 billion. Subject to the most favored states process with the regulatory authorities in certain states where PacifiCorp has operations and other customary closing conditions, MEHC expects this transaction to close in March 2006.

The successful integration of any businesses the Company may acquire in the future will entail numerous risks, including, among others, the risk of diverting management’s attention from day-to-day operations, the risk that the acquired businesses will require substantial capital and financial investments and the risk that the investments will fail to perform in accordance with expectations. Any substantial diversion of management attention and any substantial difficulties encountered in the transition and integration process could have a material adverse effect on the Company’s revenues, levels of expenses and operating results.

In addition, it has been publicly reported over the past several years that many of the participants in the United States energy industry, including the prior owners of Kern River and Northern Natural Gas and potentially including other industry participants from whom the Company may choose to purchase additional businesses in the future, have had or may have liquidity, creditworthiness and other financial difficulties. As a consequence, there can be no assurance that any such sellers will not enter into bankruptcy or insolvency proceedings or that they will otherwise be able, required or willing to perform on their indemnification obligations to the Company if it should elect to pursue any such claims the Company may have against any of them under our acquisition agreements in the future. If the Company’s due diligence efforts were or are unsuccessful in identifying and analyzing all material liabilities relating to acquired companies and if there were to be any material undisclosed liabilities, or if there were to be other unexpected consequences from any such bankruptcy or insolvency proceeding, such as a successful challenge as to whether the prices paid by the Company constituted reasonably equivalent value within the meaning of the relevant bankruptcy laws, then any such bankruptcy or insolvency, or failure by any of these sellers to perform their indemnification obligations to the Company, could have a material adverse effect on the Company’s business, financial condition, results of operations and the market prices and rates for the Company’s securities.

The Company cannot provide assurance that future acquisitions, if any, or any related integration efforts will be successful, or that the Company’s ability to repay its debt will not be adversely affected by any future acquisitions.

The Company is actively pursuing, developing and constructing new or expanded facilities, the completion and expected cost of which is subject to significant risk.

Through MEHC’s operating subsidiaries, the Company is continuing to develop, construct, own and operate new or expanded facilities, including new electric generating projects in Iowa. The Company also expects that its existing subsidiaries and PacifiCorp will make substantial annual capital expenditures relating to new or expanded facilities over the next five years. MEHC is under no contractual obligation to provide capital to any of its subsidiaries. If MEHC does not provide any required funding to any of its subsidiaries, such subsidiaries may be unable to fund required capital requirements and may need to postpone or cancel planned capital expenditures. Any such postponement or cancellation of planned capital expenditures could result in system reliability issues, environmental issues, penalties for outages or noncompliance with laws and the inability to earn a return on amounts expended.

In the future the Company expects to pursue the development, construction, ownership and operation of additional new or expanded energy projects (including, without limitation, generation, distribution, transmission, exploration/production, storage and supply projects and related activities, infrastructure and services), both domestically and internationally. The completion of any or all of these pending, proposed or future projects is subject to substantial risk and may expose the Company to significant costs. The Company cannot assure you that its development or construction efforts on any particular project or the Company’s efforts generally, will be successful. If the Company is unable to complete the development or construction of any such project, or if it decides to delay or cancel a project, the Company may not be able to recover its investment in that project.

Also, a proposed expansion or new project may cost more than planned to complete, and such excess costs, if related to a regulated asset and found to be imprudent, may not be recoverable in rates. The inability to successfully and timely complete a project or avoid unexpected costs may require the Company to perform under guarantees, and the inability to avoid unsuccessful projects or to recover any excess costs may materially affect the Company’s ability to service its obligations.

MEHC’s subsidiaries are subject to certain operating uncertainties which may adversely affect the Company’s financial position, results of operation and ability to service MEHC’s senior and subordinated debt.

The operation of complex electric and natural gas utility (including transmission and distribution) systems, pipelines or power generating facilities which are spread over a large geographic area involves many risks associated with operating uncertainties and events beyond the Company’s control. These risks 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, transmission and distribution system constraints or outages, fuel shortages or interruptions, performance below expected levels of output, capacity or efficiency, operator error and catastrophic events such as severe storms, fires, earthquakes or explosions. A casualty occurrence might result in injury or loss of life, extensive property damage or environmental damage. The realization of any of these risks could significantly reduce or eliminate MEHC’s affiliates’ revenues or significantly increase MEHC’s affiliates’ expenses, thereby adversely affecting the ability to receive distributions from subsidiaries and joint ventures. For example, if MEHC’s affiliates cannot operate their electric or natural gas facilities at full capacity due to restrictions imposed by environmental regulations, their revenues could decrease due to decreased wholesale sales and their expenses could increase due to the need to obtain energy from higher cost sources. Any reduction of revenues for such reason, or any other reduction of MEHC’s affiliates’ revenues or increase in their expenses resulting from the risks described above, could decrease the Company’s net cash flow and provide the Company with fewer funds with which to service MEHC’s senior and subordinated debt.

Further, the Company cannot provide assurance that its current and future insurance coverage will be sufficient to replace lost revenue or cover repair and replacement costs, especially in light of the recent catastrophic events in the insurance markets that make it more difficult or costly to obtain certain types of insurance.

Acts of sabotage and terrorism aimed at the Company’s facilities, the facilities of the Company’s fuel suppliers or customers, or at regional transmission facilities could adversely affect the Company’s business.

Since the September 11, 2001 terrorist attacks, the United States government has issued warnings that energy assets, specifically our nation’s pipeline and electric utility infrastructure, may be the future targets of terrorist organizations. These developments have subjected the Company’s operations to increased risks. Damage to the assets of the Company’s fuel suppliers, the assets of the Company’s customers or the Company’s own assets or at regional transmission facilities inflicted by terrorist groups or saboteurs could result in a significant decrease in revenues and significant repair costs, force the Company to increase security measures, cause changes in the insurance markets and cause disruptions of fuel supplies, energy consumption and markets, particularly with respect to natural gas and electric energy. Any of these consequences of acts of terrorism could materially affect the Company’s results of operations and decrease the amount of funds the Company has available to make payments on MEHC’s senior and subordinated debt. Instability in the financial markets as a result of terrorism or war could also materially adversely affect the Company’s ability to raise capital.

The Company is subject to energy regulation, legislation and political risks and changes in regulations and rates or legislative developments may adversely affect the Company’s business, financial condition, results of operations and ability to service MEHC’s senior and subordinated debt.

The Company is subject to comprehensive governmental regulation, including regulation in the United States by various federal, state and local regulatory agencies, regulation in the United Kingdom and regulation in the Philippines, all of which significantly influences the Company’s operating environment, its rates, its capital structure, its costs and its ability to recover the Company’s costs from customers. These regulatory agencies include, among others, the FERC, the EPA, the Nuclear Regulatory Commission (“NRC”), the DOT, the IUB, the ICC, the SDPUC, other state utility boards, numerous local agencies, the GEMA, which in discharging certain of its powers acts through its staff within Ofgem, in the United Kingdom, and various other governmental agencies in the United States, the United Kingdom and the Philippines. Changes in regulations or the imposition of additional regulations by any of these entities or new legislation could have a material adverse impact on the Company’s results of operations. For example, such changes could result in increased retail competition in MidAmerican Energy’s service territory, the acquisition by a municipality (by negotiation or condemnation) of the Company’s distribution facilities or a negative impact on the Company’s current transportation and cost recovery arrangements.

The Company also conducts its business in conformance with a multitude of federal, state and foreign laws, which are subject to significant changes at any time. Changes in regulations or the imposition of additional regulations by any of these entities or new legislation could have a material adverse impact on the Company’s results of operations. For example, such changes could result in increased retail competition in MidAmerican Energy’s service territory, encouragement of investments in renewable or lower-emission generation, the acquisition by a municipality or other quasi-governmental body of MidAmerican Energy’s distribution facilities (by negotiation, legislation or condemnation) or a negative impact on MidAmerican Energy’s current transportation and cost recovery arrangements.

On August 8, 2005, the Energy Policy Act was signed into law. That law potentially impacts many segments of the energy industry. The law will result in the FERC issuing new regulations and regulatory decisions in areas such as electric system reliability, electric transmission expansion and pricing, regulation of utility holding companies, and enforcement authority. 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 PUHCA 1935, and enacted PUHCA 2005, effective February 8, 2006. PUHCA 1935 extensively regulated and restricted the activities of registered public utility holding companies and their subsidiaries. PUHCA 2005 and the rules issued by the FERC to implement PUHCA 2005 require, among other things, public utility holding companies to permit access by the FERC to the books and records of the holding company and its affiliates transacting business with the public utility, unless such requirement is exempted or waived, and to comply with the FERC’s record retention requirements.

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. The implementation of such measures could result in the imposition of more comprehensive or stringent requirements on MEHC or its subsidiaries or other industry participants, which would result in increased compliance costs and could have a material adverse effect on the Company’s business, financial condition, results of operations and ability to service its obligations.

The Company is subject to environmental, health, safety and other laws and regulations which may adversely impact the Company.

Through MEHC’s subsidiaries and joint ventures, it is subject to a number of environmental, health, safety and other laws and regulations affecting many aspects of the Company’s present and future operations, both domestic and foreign, including air emissions, water quality, wastewater discharges, solid wastes, hazardous substances and safety matters. The Company may incur substantial costs and liabilities in connection with its operations as a result of these regulations. In particular, the cost of future compliance with federal, state and local clean air laws, such as those that require certain generators, including some of MEHC’s subsidiaries’ electric generating facilities, to limit nitrogen oxide emissions, sulfur dioxide, carbon dioxide, mercury emissions and other potential pollutants or emissions, may require the Company to make significant capital expenditures which may not be recoverable through future rates. In addition, these costs and liabilities may include those relating to claims for damages to property and persons resulting from the Company’s operations. The implementation of regulatory changes imposing more comprehensive or stringent requirements on the Company, to the extent such changes would result in increased compliance costs or additional operating restrictions, could have a material adverse effect on the Company’s business, financial condition, results of operations and ability to service its obligations.

In addition, regulatory compliance for existing facilities and the construction of new facilities is a costly and time-consuming process, and intricate and rapidly changing environmental regulations may require major expenditures for permitting and create the risk of expensive delays or material impairment of value if projects cannot function as planned due to changing regulatory requirements or local opposition.

PSIA and its implementing rules that became effective on February 14, 2004, require interstate pipeline operators to develop comprehensive integrity management programs, take measures to protect pipeline segments located in ‘‘high-consequence areas’’ and provide ongoing mitigation and monitoring. The Company believes its pipeline operations currently comply in all material respects with PSIA and related rules. However, in the future, the Company may incur unexpected capital costs and/or operating costs in order to maintain compliance. Moreover, regulatory agencies and the public continue to focus on pipeline safety issues which may result in additional inspection, monitoring, testing, reporting and other requirements being implemented in the future that could increase the Company’s operating costs and/or capital costs. The Company’s FERC-approved tariffs or competition from other energy sources may not allow the Company to recover these increased costs of compliance.

In addition to operational standards, environmental laws also impose obligations to clean up or remediate contaminated properties or to pay for the cost of such remediation, often upon parties that did not actually cause the contamination. Accordingly, the Company may become liable, either contractually or by operation of law, for remediation costs even if the contaminated property is not presently owned or operated by the Company, or if the contamination was caused by third parties during or prior to the Company’s ownership or operation of the property. Given the nature of the past industrial operations conducted by the Company and others at its properties, there can be no assurance that all potential instances of soil or groundwater contamination have been identified, even for those properties where an environmental site assessment or other investigation has been conducted. Although the Company has accrued reserves for its known remediation liabilities, 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 which may be material. Any failure to recover increased environmental, health or safety costs incurred by the Company may have a material adverse effect on the Company’s business, financial condition, results of operations and ability to service its obligations.

One of MEHC’s indirect wholly owned subsidiaries, MidAmerican Energy, is subject to the unique risks associated with nuclear generation.

Regulatory requirements applicable in the future to nuclear generating facilities could adversely affect the results of operations of MEHC and, in particular, MidAmerican Energy. The Company is subject to certain generic risks associated with utility nuclear generation, which include the following:

	Ÿ	the potential harmful effects on the environment and human health resulting from the operation of nuclear facilities and the storage, handling and disposal of high-level and low-level radioactive materials;
	Ÿ	limitations on the amounts and types of insurance commercially available in respect of losses that might arise in connection with nuclear operations; and
	Ÿ	uncertainties with respect to the technological and financial aspects of decommissioning nuclear plants at the end of their licensed lives.

The NRC has broad authority under federal law to impose licensing and safety-related requirements for the operation of nuclear generating facilities. In the event of noncompliance, the NRC has the authority to impose fines or shut down a unit, or both, depending upon its assessment of the severity of the situation, until compliance is achieved. Revised safety requirements promulgated by the NRC have, in the past, necessitated substantial capital expenditures at nuclear plants, including the facility in which MidAmerican Energy has an ownership interest, and additional expenditures could be required in the future. In addition, although the Company has no reason to anticipate a serious nuclear incident at the facility in which MidAmerican Energy has an interest, if an incident did occur, it could have a material but presently undeterminable adverse effect on the Company’s financial position, results of operations and ability to service its obligations.

Increased competition resulting from legislative, regulatory and restructuring efforts could have a significant financial impact on the Company and its utility subsidiaries and consequently decrease the Company’s revenue.

The wholesale generation segment of the electric industry has been and will continue to be significantly impacted by competition. Competition in the wholesale market has resulted in a proliferation of power marketers and a substantial increase in market activity. Many of these marketers have experienced financial difficulties and the market continues to be volatile. Margins from wholesale electric transactions have a material impact on the Company’s results of operations. Accordingly, significant changes in the wholesale electric markets could have a material adverse effect on the Company’s financial position, results of operations and the ability to service its obligations.

As a result of FERC orders, including Order 636, the FERC’s policies favoring competition in natural gas markets, the expansion of existing pipelines and the construction of new pipelines, the interstate pipeline industry has experienced some failure to renew, or turn back, of firm capacity, as existing transportation service agreements expire and are terminated. LDCs and end-use customers have more choices in the new, more competitive environment and may be able to obtain service from more than one pipeline to fulfill their natural gas delivery requirements. If a pipeline experiences capacity turn back and is unable to remarket the capacity, the pipeline or its remaining customers may have to bear the costs associated with the capacity that is turned back. Any new pipelines that are constructed could compete with the Company’s pipeline subsidiaries for customers’ service needs. Increased competition could reduce the volumes of gas transported by the Company’s pipeline subsidiaries or, in cases where they do not have long-term fixed rate contracts, could force the Company’s pipeline subsidiaries to lower their rates to meet competition. This could adversely affect the Company’s pipeline subsidiaries’ financial results.

A significant decrease in demand for natural gas in the markets served by the Company’s subsidiaries’ pipeline and distribution systems would significantly decrease the Company’s revenue and thereby adversely affect the Company’s business, financial condition, results of operations and ability to service its obligations.

A sustained decrease in demand for natural gas in the markets served by the Company’s subsidiaries’ pipeline and distribution systems would significantly reduce the Company’s revenues and adversely affect the Company’s ability to service its obligations. Factors that could lead to a decrease in market demand include:

	Ÿ	a recession or other adverse economic condition that results in a lower level of economic activity or reduced spending by consumers on natural gas;
	Ÿ	an increase in the market price of natural gas or a decrease in the price of other competing forms of energy, including electricity, coal and fuel oil;
	Ÿ	higher fuel taxes or other governmental or regulatory actions that increase, directly or indirectly, the cost of natural gas or that limit the use of natural gas;
	Ÿ	a shift by consumers to more fuel-efficient or alternative fuel machinery or an improvement in fuel economy, whether as a result of technological advances by manufacturers, pending legislation proposing to mandate higher fuel economy, or otherwise; and
	Ÿ	a shift by the Company’s pipeline and distribution customers to the use of alternate fuels, such as fuel oil, due to price differentials or other incentives.

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

MEHC’s subsidiary, HomeServices, has experienced strong revenue growth and increases in net income in each of the years ended December 31, 2005, 2004 and 2003. 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 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 revenues and profitability:

·	rising interest rates or unemployment rates;

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

·	decreasing home affordability; and

·	declining demand for residential real estate as an investment.

Failure of the Company’s significant power purchasers, pipeline customers and British retail suppliers to pay amounts due under their contracts or other commitments could reduce the Company’s revenues materially.

MEHC’s subsidiaries’ non-utility generating facilities and both of the Company’s pipeline subsidiaries are dependent upon a relatively small number of customers for a significant portion of their revenues. In addition, the Company’s utility distribution businesses in Great Britain are dependent upon a relatively small number of retail suppliers, including one retail supplier who represents approximately 44% of the total revenues of our utility distribution businesses in Great Britain. As a result, the Company’s profitability and ability to make payments under its obligations generally will depend in part upon the continued financial performance and creditworthiness of these customers. Accordingly, failure of one or more of the Company’s most significant customers to pay for contracted electric generating capacity, pipeline capacity reservation charges or distribution system use charges, as applicable, for reasons related to financial distress or otherwise, could reduce the Company’s revenues materially if the Company is not able to make adequate alternate arrangements on a timely basis, such as adequate replacement contracts. The replacement of any of the Company’s existing long-term contracts or British retail suppliers, should it become necessary, will depend on a number of factors beyond the Company’s control, including:

the availability of economically deliverable natural gas for transport through the Company’s pipeline system, including in particular continued availability of adequate supplies from the Rocky Mountains, Hugoton, Permian, Anadarko and Western Canadian supply basins currently accessible to the Company’s pipeline subsidiaries;

·	existing competition to deliver natural gas to the upper Midwest and southern California;

·	new pipelines or expansions potentially serving the same markets as the Company’s pipelines;

·	the growth in demand for natural gas in the upper Midwest, southern California, Nevada and Utah;

·	whether transportation of natural gas pursuant to long-term contracts continues to be market practice;

·	the actions of regulators, including the electricity regulator in Great Britain;

·	the availability and financial condition of replacement British retail suppliers; and

·	whether the Company’s business strategy, including its expansion strategy, continues to be successful.

Any failure to replace a significant portion of these contracts on adequate terms or to make other adequate alternate arrangements, should it become necessary, may have a material adverse effect on the Company’s business, financial condition, results of operations and ability to service its obligations.

The Company’s utility and non-utility energy businesses are subject to power and fuel price fluctuations, other weather risks, commodity price risks and credit risks that could adversely affect the Company’s results of operations.

The Company is exposed to commodity price risks, energy transmission price risks and credit risks in MEHC’s subsidiaries’ generation, retail distribution and pipeline operations. Specifically, such possible risks include commodity price changes, market supply shortages, interest rate changes and counterparty defaults, all of which could have an adverse effect on the Company’s financial condition, results of operations and ability to service its obligations. In addition, the sale of electric power and natural gas is generally a seasonal business, which seasonality results in competitive price fluctuations. The Company’s revenues are negatively impacted by low commodity prices resulting from low demand for electricity. Demand for electricity often peaks during the hottest summer months and coldest winter months and declines during the other months. As a result of these variations in demand and resulting price fluctuations, the Company’s overall operating results in the future may fluctuate substantially on a seasonal basis. The Company has historically earned less income when weather conditions are milder. The Company expects that unusually mild weather in the future could decrease its revenues and provide the Company with fewer funds available to service its obligations.

Also, in Iowa, MidAmerican Energy does not have an ability to pass through fuel price increases in its rates (an energy adjustment clause), so any significant increase in fuel costs or purchased power costs for electricity generation could have a negative impact on MidAmerican Energy, despite the Company’s efforts to minimize this negative impact through the use of hedging instruments. The impact of these risks could result in MidAmerican Energy’s inability to fulfill contractual obligations, significantly higher energy or fuel costs relative to corresponding sales contracts or increased interest expense. Any of these consequences could decrease the Company’s net cash flow and impair its ability to make payments on its obligations.

The Company has significant operations outside the United States which may be subject to increased risk because of the economic or political conditions of the country in which they operate.

The Company has a number of operations outside of the United States. The acquisition, ownership and operation of businesses outside the United States entails significant political and financial risks (including, without limitation, uncertainties associated with privatization efforts, inflation, currency exchange rate fluctuations, currency repatriation restrictions, changes in law or regulation, changes in government policy, political instability, civil unrest and expropriation) and other risk/structuring issues that have the potential to cause material impairment of the value of the business being operated, which the Company may not be capable of fully insuring against. The risk of doing business outside of the United States could be greater than in the United States because of specific economic or political conditions of each country. The uncertainty of the legal environment in certain foreign countries in which the Company operates or may acquire projects or businesses could make it more difficult for the Company to enforce its rights under agreements relating to such projects or businesses. The Company’s international projects may be subject to the risk of being delayed, suspended or terminated by the applicable foreign governments or may be subject to the risk of contract abrogation, expropriations or other uncertainties resulting from changes in government policy or personnel or changes in general political or economic conditions affecting the country or otherwise. In addition, the laws and regulations of certain countries may limit the Company’s ability to hold a majority interest in some of the projects or businesses that it may acquire. Furthermore, the central bank of any such country may have the authority in certain circumstances to suspend, restrict or otherwise impose conditions on foreign exchange transactions or to restrict distributions to foreign investors. Although the Company may structure certain project revenue and other agreements to provide for payments to be made in, or indexed to, U.S. dollars or a currency freely convertible into U.S. dollars, there can be no assurance that the Company will be able to obtain sufficient U.S. dollars or other hard currency or that available U.S. dollars will be allocated to pay such obligations.

The Company faces exchange rate risk.

Payments from some of the Company’s foreign investments, including without limitation CE Electric UK, are made in a foreign currency and any dividends or distributions of earnings in respect of such investments may be significantly affected by fluctuations in the exchange rate between the U.S. dollar and the sterling or other applicable foreign currency, which could adversely affect the Company’s financial condition and results of operations. Although the Company may enter into certain transactions to hedge risks associated with exchange rate fluctuations, there can be no assurance that such transactions will be successful in reducing such risks.

Item 1B. Unresolved Staff Comments.

Not applicable.

Item 2. Properties .

The Company’s utility properties consist of physical assets necessary and appropriate to render electric and gas service in its service territories. Electric property consists primarily of generation, transmission and distribution facilities and related rights-of-way. Gas property consists primarily of distribution plants, natural gas pipelines, related rights-of-way, compressor stations and meter stations. It is the opinion of management that the principal depreciable properties owned by the Company are in good operating condition and well maintained. Pursuant to separate financing agreements, substantially all or most of the properties of each subsidiary (except CE Electric UK and Northern Natural Gas) are pledged or encumbered to support or otherwise provide the security for their own project or subsidiary debt. Refer to Item 1. Business and Note 4 and Note 22 of Notes to Consolidated Financial Statements included in Item 8. Financial Statements and Supplementary Data of this Form 10-K for additional information about the Company’s properties.

The right to construct and operate the pipelines across certain property was obtained through negotiations and through the exercise of the power of eminent domain, where necessary. Kern River and Northern Natural Gas continue to have the power of eminent domain in each of the states in which they operate their respective pipelines, but they 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 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 pipelines falls into two basic categories: (1) parcels that are owned in fee, such as certain of the compressor stations, measurement stations and district 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 pipelines. MEHC believes that Kern River and Northern Natural Gas each have satisfactory title to all of the real property making up their respective pipelines 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 financial position, results of operations or cash flows. See Item 1. Business and Item 8. Financial Statements and Supplementary Data of this Form 10-K for details relative to environmental matters affecting the Company.

Pipeline Litigation

In 1998, the United States Department of Justice informed the then current owners of Kern River and Northern Natural Gas 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 Kern River and Northern Natural Gas. 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 April 9, 1999, the United States Department of Justice announced that it declined to intervene in any of the Grynberg qui tam cases, including the actions filed against Kern River and Northern Natural Gas in the United States District Court for the District of Colorado. On October 21, 1999, the Panel on Multi-District Litigation transferred the Grynberg qui tam cases, including the ones filed against Kern River and Northern Natural Gas, to the United States District Court for the District of Wyoming for pre-trial purposes. On October 9, 2002, the United States District Court for the District of Wyoming dismissed Grynberg’s royalty valuation claims. On November 19, 2002, the United States District Court for the District of Wyoming denied Grynberg’s motion for clarification and dismissed his royalty valuation claims. Grynberg appealed this dismissal to the United States Court of Appeals for the Tenth Circuit and on May 13, 2003, the Tenth Circuit Court dismissed his appeal. On May 17, 2005, Kern River and Northern Natural Gas each received a Special Master’s Report and Recommendations in which the Special Master recommended that the action against Kern River and Northern Natural Gas be dismissed for lack of subject matter jurisdiction. Grynberg and the coordinated defendants each filed motions relating to the Special Master’s Report and Recommendations on June 27, 2005. Oral arguments on the parties’ motions were held on December 9, 2005, and the parties are awaiting a ruling from the court regarding this report. In connection with the purchase of Kern River from The Williams Companies, Inc. (“Williams”) in March 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 August 2002. The Company believes that the Grynberg cases filed against Kern River and Northern Natural Gas 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.

On June 8, 2001, a number of interstate pipeline companies, including Kern River and Northern Natural Gas, were named as defendants in a nationwide class action lawsuit which had been pending in the 26th Judicial District, District Court, Stevens County Kansas, Civil Department against other defendants, generally pipeline and gathering companies, since May 20, 1999. 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. On May 12, 2003, the plaintiffs filed a motion for leave to file a fourth amended petition alleging a class of gas royalty owners in Kansas, Colorado and Wyoming. The court granted the motion for leave to amend on July 28, 2003. Kern River was not a named defendant in the amended complaint and has been dismissed from the action. Northern Natural Gas filed an answer to the fourth amended petition on August 22, 2003. On January 4, 2005, the plaintiffs filed their class certification motion and brief in support of that motion. Northern Natural Gas filed its joint brief and expert affidavits in opposition to class certification on February 22, 2005. The plaintiffs filed their reply brief in support of class certification on March 18, 2005. Northern Natural Gas believes that this claim is without merit.

Similar to the June 8, 2001 matter referenced above, the plaintiffs in that matter have filed a new companion action against a number of parties, including Northern Natural Gas but excluding Kern River, in a Kansas state district court for damages for mismeasurement of British thermal unit content, resulting in lower royalties. The action was filed on May 12, 2003. On January 4, 2005, the plaintiffs filed their class certification motion and brief in support of that motion. Northern Natural Gas filed its joint brief and expert affidavits in opposition to class certification on February 22, 2005. The plaintiffs filed their reply brief in support of class certification on March 18, 2005. Northern Natural Gas believes that this claim is without merit.

MidAmerican Energy

Natural Gas Commodity Litigation

MidAmerican Energy is one of dozens of companies named as defendants in a January 20, 2004 consolidated class action lawsuit filed in the United States District Court for the Southern District of New York. The suit alleges that the defendants have engaged in unlawful manipulation of the prices of natural gas futures and options contracts traded on the New York Mercantile Exchange (“NYMEX”) during the period January 1, 2000 to December 31, 2002. MidAmerican Energy is mentioned as a company that has engaged in wash trades on Enron Online (an electronic trading platform) that had the effect of distorting prices for gas trades on the NYMEX. The plaintiffs to the class action do not specify the amount of alleged damages. On September 9, 2005, MidAmerican Energy and counsel for the plaintiffs executed a stipulation and agreement of settlement, which, upon final approval by the court following notice to all class members, MidAmerican Energy will be dismissed from the lawsuit. The settlement was filed with the court on February 2, 2006 and approved by the court on a preliminary basis on February 8, 2006. If finally accepted by the court, the settlement will not have a material impact upon MidAmerican Energy. Additionally, the court issued an order on September 29, 2005, granting the plaintiffs’ motion for class certification.

Other

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 allegedly provided gas service in Ramsey, Minnesota at the time of the original installation of the pipeline in 1980. In 1993, a predecessor of CenterPoint Resources Corp. (“CenterPoint”) acquired all of the Minnesota gas properties owned by the MidAmerican Energy predecessor company.

As a result of the explosion and fire, MidAmerican Energy and CenterPoint have received settlement demands which total $15.5 million. MidAmerican Energy’s exposure, if any, to these demands are covered under its liability insurance coverage to which a $2.0 million retention applies. In addition, counsel for CenterPoint stated that a replacement program has been initiated for the purpose of locating and replacing all mechanical couplings in the former North Central Public Service Company properties located in Minnesota. Counsel for CenterPoint has represented that it is anticipated that the value of the replacement claim may be in the range of $35-$45 million.

On February 8, 2006, MidAmerican Energy was served with a Third Party Complaint filed in U.S. District Court, District of Minnesota by CenterPoint. The Third Party Complaint seeks contribution and indemnity on a wrongful death claim filed by the estate of one of the decedents and all sums associated with CenterPoint’s replacement program. An additional compliant filed by the estate of one of the decedents seeks damages from MEHC and other defendants, including CenterPoint, on a wrongful death claim arising from this incident. MEHC and MidAmerican Energy intend to vigorously defend their position in these claims and believe their ultimate outcome will not have a material impact on their results of operations, financial position or cash flows.

Philippines

Pursuant to the share ownership adjustment mechanism in the CE Casecnan stockholder agreement, which is based upon pro forma 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 stockholder 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., KEIL Casecnan Ltd. (“KE”), a former stockholder, 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. On January 21, 2004, CE Casecnan Ltd., LPG and CE Casecnan entered into a status quo agreement pursuant to which the parties agreed to set aside certain distributions related to the shares subject to the LPG dispute and CE Casecnan agreed not to take any further actions with respect to such distributions without at least 15 days prior notice to LPG. Accordingly, 15% of the CE Casecnan dividend distributions declared in 2004 and 2005, totaling $17.6 million, was set aside in a separate bank account in the name of CE Casecnan and is shown as restricted cash and short-term investments and other current liabilities in the accompanying consolidated balance sheets included in Item 8. Financial Statements and Supplementary Data of this Form 10-K.

On August 4, 2005, the court issued a decision, ruling in favor of LPG on five of the eight disputed issues in the first phase of the litigation. On September 12, 2005, LPG filed a motion seeking the release of the funds which have been set aside pursuant to the status quo agreement referred to above. MEHC and CE Casecnan Ltd. filed an opposition to the motion on October 3, 2005, and at the hearing on October 26, 2005, the court denied LPG’s motion. On January 3, 2006, the court entered a judgment in favor of LPG against CE Casecnan Ltd. and KE. According to the judgment LPG would retain its ownership of 15% of the shares of CE Casecnan and distributions of the amounts deposited into escrow plus interest at 9% per annum. On February 28, 2006, CE Casecnan Ltd. and KE filed an appeal of this judgment and the August 4, 2005 decision. The appeal is expected to be resolved sometime in 2007. The impact, if any, of this litigation on the Company cannot be determined at this time.

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. 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. The motion was heard on October 21, 2005, and the court took the matter under advisement. 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 Casecnan, that it is the rightful owner of such shares, and that it is due all dividends paid on such shares. 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.

Mirant Americas Energy Marketing (“Mirant”) Claim

Mirant was one of the shippers that entered into a 15-year, 2003 Expansion Project, firm gas transportation contract (90,000 Dth per day) with Kern River (the “Mirant Agreement”) and provided a letter of credit equivalent to 12 months of reservation charges as security for its obligations thereunder. In July 2003, Mirant filed for Chapter 11 bankruptcy protection and Kern River subsequently drew on the letter of credit and held the proceeds thereof, $14.8 million, as cash collateral. Kern River claimed $210.2 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 $74.4 million in addition to the $14.8 million cash collateral. In January 2006, Mirant emerged from bankruptcy and on February 6, 2006, a stipulated judgment was entered that allowed Kern River to receive a pro rata amount of shares of new Mirant stock determined by Kern River’s allowed claim amount plus interest in relation to the unsecured creditor class of over $6 billion. On February 10, 2006, Kern River received an initial distribution of such shares in payment of the majority of its allowed claim.

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 equity securities have been owned by Berkshire Hathaway, Walter Scott, Jr. and his family interests, David L. Sokol and Gregory E. Abel and have 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.

Item 6. Selected Financial Data.

The following table sets forth selected financial data, which should be read in conjunction with Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations and with the Company’s consolidated financial statements and the related notes to those statements included in Item 8. Financial Statements and Supplementary Data appearing elsewhere in this Form 10-K. The selected financial data has been derived from the Company’s historical consolidated financial statements.

	Year Ended December 31,
	2005		2004			2003			2002 ⁽¹⁾			2001
Statement of Operations Data:
Operating revenue	$	7,115.5	$	6,553.4		$	5,965.6		$	4,795.2		$	4,696.8
Income from continuing operations		557.5		537.8			442.7			397.4			148.4
Income (loss) from discontinued operations, net of tax ⁽²⁾		5.1		(367.6	)		(27.1	)		(17.4	)		(5.7	)
Net income	$	562.6	$	170.2		$	415.6		$	380.0		$	142.7

	As of December 31,
		2005		2004			2003			2002 ⁽¹⁾			2001
Balance Sheet Data:
Total assets	$	20,193.0	$	19,903.6		$	19,145.0		$	18,434.9		$	12,994.6
Parent company senior debt ⁽³⁾		2,776.2		2,772.0			2,777.9			2,323.4			1,834.5
Parent company subordinated debt ⁽³⁾		1,354.1		1,585.8			1,772.1			-			-
Company-obligated mandatory redeemable preferred securities of subsidiary trusts		-		-			-			2,063.4			788.2
Subsidiary and project debt ⁽³⁾		6,836.6		6,304.9			6,674.6			7,077.1			4,754.8
Subsidiary-obligated mandatorily redeemable preferred securities of subsidiary trusts		-		-			-			-			100.0
Preferred securities of subsidiaries		88.4		89.5			92.1			93.3			121.2
Total stockholders’ equity	$	3,385.3	$	2,971.2		$	2,771.4		$	2,294.3		$	1,708.2

(1)	Reflects the acquisitions of Kern River on March 27, 2002 and Northern Natural Gas on August 16, 2002.

(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 $340.3 million being recorded to write-off the Zinc Recovery Project, rights to quantities of extractable minerals, and allocated goodwill (collectively, the “Mineral Assets”). The charge and related activity of the Mineral Assets, including the reclassification of such activity for the years ended December 31, 2003, 2002 and 2001, are classified separately as discontinued operations.

(3)	Excludes current portion.

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

The following discussion and analysis should be read in combination with the selected financial data and the consolidated financial statements included in Item 6. Selected Financial Data and Item 8. Financial Statements and Supplementary Data of this Form 10-K.

Executive Summary

MEHC, through its subsidiaries, owns and operates a combined electric and natural gas utility company in the United States, two natural gas interstate pipeline companies in the United States, two electricity distribution companies in Great Britain, a diversified portfolio of domestic and international independent power projects and the second largest residential real estate brokerage firm in the United States. These businesses are organized and managed as seven distinct platforms: MidAmerican Energy, Kern River, Northern Natural Gas, CE Electric UK (which includes Northern Electric and Yorkshire Electricity), CalEnergy Generation-Foreign, CalEnergy Generation-Domestic, and HomeServices.

MEHC’s energy subsidiaries generate, transmit, store, distribute and supply energy. MEHC’s electric and natural gas utility subsidiaries currently serve approximately 4.4 million electricity customers and approximately 688,000 natural gas customers. MEHC's natural gas pipeline subsidiaries operate interstate natural gas transmission systems that have approximately 18,100 miles of pipeline in operation, a peak delivery capacity of 6.6 Bcf of natural gas per day and transported approximately 7.8% of the total natural gas consumed in the United States in 2005. The Company has interests in 6,740 net owned MW of power generation facilities in operation and under construction, including 5,166 net owned MW in facilities that are part of the regulated asset base of its electric utility business and 1,574 net owned MW in non-utility power generation facilities. Substantially all of the non-utility power generation facilities have long-term contracts for the sale of energy and/or capacity from the facilities.

The following significant events occurred during the years ended December 31, 2005, 2004 and 2003, respectively, as discussed in more detail herein and in Item 1. Business of this Form 10-K, that highlight some of the factors which affected, or may affect in the future, the Company’s financial condition, results of operations and liquidity:

In May 2005, MEHC reached a definitive agreement with ScottishPower and its subsidiary, PacifiCorp Holdings, Inc., to acquire 100% of the common stock of ScottishPower’s wholly-owned indirect subsidiary, PacifiCorp, a regulated electric utility, for approximately $5.1 billion in cash. Subject to the most favored states process and other customary closing conditions, the transaction is expected to close in March 2006. MEHC expects to fund the acquisition of PacifiCorp with the proceeds from an investment by Berkshire Hathaway and other existing shareholders of approximately $3.4 billion in MEHC common stock and the issuance by MEHC of $1.7 billion of either additional common stock to Berkshire Hathaway or long-term senior notes to third parties. According to PacifiCorp’s most recent Form 10-Q filed with the SEC, PacifiCorp had total assets of $12.8 billion as of December 31, 2005, and had $2.7 billion of operating revenue and $213.6 million of net income, respectively, for the nine months ended December 31, 2005.

On February 9, 2006, following the effective date of the repeal of PUHCA 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. As a consequence, Berkshire Hathaway owns 83.4% (80.5% on a diluted basis) of the outstanding common stock of MEHC, will consolidate the Company in its financial statements as a majority-owned subsidiary, and will include the Company in its consolidated federal U.S. income tax return.

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 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, and will not be used for the PacifiCorp acquisition or for other future acquisitions.

MidAmerican Energy has continued its construction of electric generation facilities in Iowa by placing in-service 900.5 MW (nameplate rating) of capacity during 2005, 2004 and 2003. Projects completed include the 540 MW (nameplate rating) combined-cycle Greater Des Moines Energy Center in 2003 and 2004 and 360.5 MW (nameplate rating) of wind turbines in 2005 and 2004. Additionally, MidAmerican Energy is currently constructing CBEC Unit 4, a 790 MW (expected accreditation) super-critical-temperature, low sulfur coal-fired generating plant of which MidAmerican Energy’s share is 479 MW, and has made a filing with the IUB for approval to add up to 545 MW (nameplate rating) of additional wind generation capacity.

·	Kern River completed construction of its 2003 Expansion Project in May 2003 at a total cost of $1.2 billion.

Indirect wholly-owned subsidiaries of MEHC own the rights to commercial quantities of extractable minerals from elements in solution in the geothermal brine and fluids utilized at the Imperial Valley Projects and a zinc recovery plant constructed near the Imperial Valley Projects designed to recover zinc from the geothermal brine through an ion exchange, solvent extraction, electrowinning and casting process (the “Zinc Recovery Project”). On September 10, 2004, management made the decision to cease operations of the Zinc Recovery Project. Implementation of the decommissioning plan began in September 2004 and as of December 31, 2005, the dismantling, decommissioning, and sale of remaining assets of the Zinc Recovery Project was completed.

MidAmerican Energy issued $300.0 million of 5.75%, 30-year, medium-term notes on November 1, 2005, and $350.0 million of 4.65%, 10-year, medium-term notes on October 1, 2004. The proceeds from each offering are being used to support construction of its electric generation projects and for general corporate purposes.

On May 5, 2005, certain subsidiaries of CE Electric UK collectively issued £350.0 million of 5.125% senior bonds due 2035. The proceeds from the offerings are being invested and used for general corporate purposes. Proceeds from the maturing investments will be used to repay certain long-term debt of subsidiaries of CE Electric UK in 2007 and 2008.

·	In February 2004, MEHC issued $250.0 million of 5.00% senior notes due February 15, 2014. The proceeds were used to satisfy a demand made by an affiliate on MEHC’s guarantee of certain debt related to the Zinc Recovery Project and for general corporate purposes.

·	Northern Natural Gas reached agreement with its customers in June 2005 on a FERC approved rate settlement covering its consolidated rate case related to filings for rate increases made with the FERC in May 2003 and January 2004.

Ofgem completed the process of reviewing the existing price control formula for Northern Electric and Yorkshire Electricity in November 2004. As a result of the review, the allowed revenue of Northern Electric’s and Yorkshire Electricity’s distribution businesses were reduced by 4% and 9%, respectively, in real terms, effective April 1, 2005.

Kern River filed for a rate increase with the FERC in April 2004, with the new rates being effectuated on November 1, 2004, subject to refund. The general rate case hearing concluded in August 2005 and Kern River is awaiting an initial decision on the case. The final resolution of the rate case is dependent on receiving a final, non-appealable decision on the case from the FERC, or approval of a settlement of the case by the FERC, and is not expected at the earliest until late 2006 or early 2007.

CE Casecnan reached an arbitration settlement with the NIA effective during the fourth quarter of 2003. In exchange for the receipt of approximately $18 million of cash and a $97.0 million ROP Note, CE Casecnan agreed to modify certain provisions of its project agreement, the most significant being the elimination of the tax compensation portion of the water delivery fee and modification of the threshold volume of water used to calculate the guaranteed water delivery fee.

Results of Operations

Summary

Operating results for the years ended December 31, 2005, 2004 and 2003 are summarized in the following table (in millions):

	Year Ended December 31,
	2005			2004			2003

Operating revenue	$	7,115.5		$	6,553.4		$	5,965.6

Operating income	$	1,528.7		$	1,525.4		$	1,449.8
Interest expense		(891.0	)		(903.2	)		(761.0	)
Other income, net		127.2			177.0			169.2
Income tax expense		(244.7	)		(265.0	)		(270.3	)
Minority interest and preferred dividends of subsidiaries		(16.0	)		(13.3	)		(183.2	)
Equity income		53.3			16.9			38.2
Income from continuing operations		557.5			537.8			442.7
Income (loss) from discontinued operations, net of tax		5.1			(367.6	)		(27.1	)
Net income available to common and preferred stockholders	$	562.6		$	170.2		$	415.6

In 2005, MEHC’s income from continuing operations was $557.5 million versus $537.8 million in 2004. In 2005, MEHC benefited from favorable comparative results at most of its domestic businesses and from gains on sales of certain non-strategic assets and investments. These improvements were partially offset by lower earnings from CE Electric UK, primarily associated with the distribution businesses. In the fourth quarter of 2004, MEHC realized an after-tax gain of $43.7 million from the realization of certain Enron-related bankruptcy claims. Ignoring the effect of this one-time event, MEHC’s income from continuing operations was $494.1 million, which, when compared to 2003 results, reflects improved results at most of MEHC’s major operating platforms.

During the third quarter of 2004, the Company recorded an after-tax charge, which is reflected in discontinued operations, of $340.3 million to write down certain assets of the Zinc Recovery Project.

Segment Results

The reportable segment financial information includes all necessary adjustments and eliminations needed to conform to the Company’s significant accounting policies. The differences between the segment amounts and the consolidated amounts, described as “Corporate/other,” relate principally to corporate functions including administrative costs, intersegment eliminations and fair value adjustments relating to acquisitions. Additionally, the activity of the Company’s Mineral Assets, which was previously reported in the CalEnergy Generation-Domestic reportable segment, is presented as discontinued operations within the consolidated financial statements included in Item 8. Financial Statements and Supplementary Data of this Form 10-K.

A comparison of operating revenue and operating income for the Company’s reportable segments for the years ended December 31, 2005, 2004, and 2003 follows (in millions):

	Year Ended December 31,
	2005			2004			2003
Operating revenue:
MidAmerican Energy	$	3,166.1		$	2,701.7		$	2,600.2
Kern River		323.6			316.1			260.2
Northern Natural Gas		569.1			544.8			486.9
CE Electric UK		884.1			936.4			830.0
CalEnergy Generation-Foreign		312.3			307.4			326.4
CalEnergy Generation-Domestic		33.8			39.0			45.2
HomeServices		1,868.5			1,756.4			1,476.6
Total reportable segments		7,157.5			6,601.8			6,025.5
Corporate/other		(42.0	)		(48.4	)		(59.9	)
Total operating revenue	$	7,115.5		$	6,553.4		$	5,965.6

Operating income:
MidAmerican Energy	$	381.1		$	355.9		$	367.9
Kern River		204.5			204.8			181.0
Northern Natural Gas		208.8			190.3			175.8
CE Electric UK		483.9			497.4			445.8
CalEnergy Generation-Foreign		185.0			188.5			197.5
CalEnergy Generation-Domestic		15.1			21.5			21.4
HomeServices		125.3			112.9			92.9
Total reportable segments		1,603.7			1,571.3			1,482.3
Corporate/other		(75.0	)		(45.9	)		(32.5	)
Total operating income	$	1,528.7		$	1,525.4		$	1,449.8

MidAmerican Energy

MidAmerican Energy owns a public utility headquartered in Iowa that is principally engaged in the business of generating, transmitting, distributing and selling electric energy and in distributing, selling and transporting natural gas. Nonregulated affiliates within the MidAmerican Energy platform also conduct a number of nonregulated business activities. MidAmerican Energy’s operating revenue and operating income for the years ended December 31, 2005, 2004, and 2003 are summarized as follows (in millions):

	Year Ended December 31,
	2005		2004		2003
Operating revenue:
Regulated electric	$	1,513.2	$	1,421.7	$	1,398.0
Regulated gas		1,322.7		1,010.9		947.4
Nonregulated		330.2		269.1		254.8
Total operating revenue	$	3,166.1	$	2,701.7	$	2,600.2

Operating income:
Regulated electric	$	334.9	$	304.4	$	307.8
Regulated gas		31.7		36.4		45.9
Nonregulated		14.5		15.1		14.2
Total operating income	$	381.1	$	355.9	$	367.9

Regulated Electric Operations

The operating results of MidAmerican Energy’s regulated electric business for the years ended December 31, 2005, 2004, and 2003 are summarized as follows (in millions, except for average number of customers):

	Year Ended December 31,
	2005		2004		2003

Retail	$	1,222.0	$	1,136.7	$	1,113.2
Wholesale		291.2		285.0		284.8
Total operating revenue		1,513.2		1,421.7		1,398.0
Cost of fuel, energy and capacity		468.1		398.6		396.3
Margin		1,045.1		1,023.1		1,001.7
Operating expense		472.9		483.5		444.4
Depreciation and amortization		237.3		235.2		249.5
Operating income	$	334.9	$	304.4	$	307.8

Sales (gigawatt-hours):
Retail		19,044		17,865		17,422
Wholesale		8,378		9,260		9,963
		27,422		27,125		27,385

Average number of customers		701,111		691,984		684,124

MidAmerican Energy’s regulated electric retail revenue for 2005 increased $85.3 million, or 7.5%, to $1,222.0 million compared to 2004. Electric retail sales volumes increased 6.6% compared to 2004. Higher average temperatures during 2005 compared to 2004 resulted in a $43.4 million increase in electric retail revenue. A growing retail customer base in 2005 improved electric retail revenue by $17.7 million compared to 2004, while electricity usage factors not dependent on weather, such as the size of homes, technology changes and the use of multiple appliances, increased electric revenue by $9.1 million. Additionally, transmission revenue increased $7.9 million.

MidAmerican Energy’s regulated electric retail revenue for 2004 increased $23.5 million, or 2.1%, to $1,136.7 million compared to 2003, and related sales volumes increased 2.5%. Electricity usage factors not dependent on weather, such as the size of homes, technology changes and the use of multiple appliances, improved electric revenue by $21.6 million compared to 2003, and an increase in the average number of electric retail customers increased electric retail revenue by $20.7 million. Lower average temperatures during 2004 compared to 2003 resulted in a $26.9 million decrease in electric retail revenue.

In addition to retail sales, MidAmerican Energy sells electric energy to other utilities, marketers and municipalities. These sales are referred to as wholesale sales. MidAmerican Energy’s wholesale revenue for 2005 increased $6.2 million, or 2.2%, to $291.2 million compared to 2004. The effect of higher electric energy prices, offset partially by a higher proportion of lower-priced, off-peak sales, increased wholesale energy revenue in 2005 by $33.3 million. Wholesale units for 2005 decreased 9.5% from 2004, resulting in a $27.1 million decrease in revenue. The primary reason for the decrease in wholesale sales volumes for 2005 was the timing of planned generation outages for the Louisa Generating Station and the loss of generating capacity at the Ottumwa Generating Station Unit No. 1 (“OGS Unit No. 1”), which experienced a failure of its step-up transformer on February 20, 2005. OGS Unit No. 1 returned to service on May 3, 2005.

MidAmerican Energy’s wholesale revenue for 2004 increased $0.2 million, or 0.1%, to $285.0 million compared to 2003. Wholesale energy revenue in 2004 increased by $20.3 million due to the impact of higher average wholesale prices. This was largely offset by a decrease in wholesale units of 7.1% from 2003, which resulted in a $20.1 million decrease in revenue.

Cost of fuel, energy and capacity for 2005 increased $69.5 million, or 17.4%, compared to 2004 due principally to the cost of replacement power in connection with the generating station outages previously discussed and the increased use of gas-fired generation, primarily from the Greater Des Moines Energy Center. Cost of fuel, energy and capacity for 2004 increased $2.3 million, or 0.6%, compared to 2003. The increase was principally due to the cost of replacement power as a result of generating stations taken out of service for preventive maintenance in 2004.

Regulated electric operating expense for 2005 decreased $10.6 million compared to 2004 due principally to the timing of generating plant maintenance and lower postretirement benefit costs, partially offset by higher distribution and transmission operations costs. Regulated electric operating expense for 2004 increased $39.1 million compared to 2003 due primarily to the timing of generating plant maintenance and increased generating plant operations expense. Additionally, electric distribution maintenance and operations expense and transmission operations expense were higher in 2004 compared to 2003.

Regulated electric depreciation and amortization expense for 2005 increased $2.1 million compared to 2004 as a result of an $11.1 million increase in electric utility plant depreciation and amortization due primarily to assets being placed in-service, the most significant being the second phase of the Greater Des Moines Energy Center and 160.5 MW of wind power facilities in December 2004 and, to a lesser extent, an additional 200 MW of wind power facilities in late 2005. The increase in utility plant depreciation was partially offset by a $9.9 million decrease in regulatory expense pursuant to a revenue sharing arrangement with the state of Iowa due to lower Iowa electric equity returns. Regulated electric depreciation and amortization expense for 2004 decreased $14.3 million compared to 2003 due to a $9.8 million decrease related to the revenue sharing arrangements with the states of Illinois and Iowa. Additionally, electric utility plant depreciation and amortization decreased due in part to software assets that became fully depreciated in 2003.

Regulated Natural Gas Operations

Regulated natural gas revenue includes purchased gas adjustment clauses through which MidAmerican Energy is allowed to recover the cost of gas sold from its retail gas utility customers. Consequently, fluctuations in the cost of gas sold do not affect gross margin or operating income because revenues reflect comparable fluctuations through the purchased gas adjustment clauses. Compared to 2004, MidAmerican Energy’s average per-unit cost of gas sold increased 32.8%, resulting in a $271.6 million increase in revenue and cost of gas sold for 2005. The remainder of the increase in cost of gas sold and gas revenues was primarily due to an increase in wholesale sales volumes. Additionally, an increase in the average number of retail customers contributed to the increase in gas revenues for 2005.

MidAmerican Energy’s average per-unit cost of gas sold for 2004 increased 7.4%, resulting in a $54.3 million increase in revenue and cost of gas sold compared to 2003. The remainder of the increase in cost of gas sold and gas revenues was due to an increase in wholesale sales volumes. A decrease in gas retail sales volumes, in part due to milder temperature conditions in 2004 compared to 2003, reduced gas revenues for 2004. An increase in the average number of retail customers partially offset the decrease due to retail sales volumes.

Kern River

Operating revenue at Kern River is principally derived by providing firm or interruptible transportation services under long-term transportation service agreements related to its interstate natural gas transportation pipeline system. On May 1, 2003, Kern River placed into service a $1.2 billion, 717-mile expansion project (“2003 Expansion Project”), which increased the design capacity of Kern River’s pipeline system by 885,575 Dth per day to its current 1,755,575 Dth per day.

Operating income remained relatively flat in 2005 compared to 2004 and increased $23.8 million, or 13.1%, in 2004 compared to 2003. The increase in 2004 was primarily due to higher capacity reservation charges earned in connection with the completion of the 2003 Expansion Project.

Operating revenue for 2005 increased $7.5 million, or 2.4%, to $323.6 million from the comparable period in 2004. The increase in operating revenue resulted from higher demand and commodity transportation revenues of $14.0 million due mainly to higher rates, subject to refund, for the current rate proceeding which became effective on November 1, 2004. This increase was partially offset by lower interruptible transportation revenue of $5.9 million. Operating revenue for 2004 increased $55.9 million, or 21.5%, to $316.1 million from the comparable period in 2003. The increase in operating revenue resulted primarily from higher demand and commodity transportation revenues, net of revenue sharing, of $52.2 million, associated with the full-year effect of higher capacity reservation charges on the additional capacity from the 2003 Expansion Project.

Depreciation and amortization expense for 2005 increased $9.1 million to $62.4 million from the comparable period in 2004 due to higher depreciation rates in connection with the current rate proceeding. Operating expenses and depreciation and amortization for 2004 increased $15.7 million, or 36.9%, and $16.5 million, or 44.8%, respectively, from the comparable period in 2003 due to the completion of the 2003 Expansion Project.

Northern Natural Gas

Operating revenue at Northern Natural Gas is principally derived by providing firm or interruptible transportation and storage services under long-term transportation storage service agreements related to its interstate natural gas transportation pipeline system.

Operating income for 2005 increased $18.5 million, or 9.7%, to $208.8 million from the comparable period in 2004. Northern Natural Gas recognized net benefits, due to the settlement of its consolidated rate case proceeding and its SLA settlement, to operating income during the year ended December 31, 2005 of $15.7 million reflecting final settlement adjustments and the ongoing operating impact of lower depreciation and amortization expense due to changes in the useful lives of its transmission, storage and intangible assets, partially offset by higher regulatory amortization of the remaining SLA balance.

Operating revenue for 2005 increased $24.3 million, or 4.5%, to $569.1 million from the comparable period in 2004. The increase was mainly due to higher gas and liquids sales of $25.6 million, due to higher sales of gas from operational storage utilized to manage physical flows on the pipeline system, and higher transportation and storage revenues of $8.3 million, due to changes in the composition of transportation contracts. These increases were partially offset by the net effects of the consolidated rate case and SLA settlements, which decreased operating revenue by $11.5 million.

Operating expenses for 2005 also increased $12.4 million from the comparable period in 2004 due to a $29.0 million long-lived asset impairment charge for West Hugoton recognized in the fourth quarter of 2005, partially offset by a gain of $19.7 million recognized in the second quarter of 2005 from the sale of an idled section of pipeline in Oklahoma and Texas. Northern Natural Gas entered into separate purchase and sale agreements (“PSA”) relative to the West Hugoton and Beaver non-strategic sections of its interstate pipeline system in the fourth quarter of 2005. No impairment charge was needed for the Beaver pipeline as the sale price agreed to in the Beaver PSA exceeded the carrying value of the Beaver pipeline. The sales of the West Hugoton and Beaver assets are expected to close in mid to late 2006.

Operating income for 2004 increased $14.5 million, or 8.2%, to $190.3 million from the comparable period in 2003. Northern Natural Gas’ operating revenue for 2004, which reflects the effectuation of rate increases on November 1, 2004 and 2003, and higher gas and liquids sales, increased $57.9 million, or 11.9%, to $544.8 million from the comparable period in 2003. In 2004 and 2003, gas and liquids sales were subject to a regulatory tracking procedure and, therefore, any fluctuations in the amount of such sales had a corresponding effect on cost of sales. Depreciation and amortization for 2004 increased $15.2 million compared to 2003 due primarily to higher depreciation rates included in the filed rate cases.

CE Electric UK

CE Electric UK owns two electricity distribution companies which operate in Great Britain, Northern Electric and Yorkshire Electricity. The distribution companies’ main income is earned from charges for the use of their electrical infrastructure levied on supply companies. CE Electric UK also owns an engineering contracting company, a gas exploration and production company and various other more minor subsidiaries.

Operating income for 2005 decreased $13.5 million, or 2.7%, to $483.9 million compared with 2004. Operating revenue for 2005 decreased $52.3 million, or 5.6%, to $884.1 million compared with 2004 due primarily to $37.0 million of lower distribution revenues, $9.1 million of lower contracting revenues and a $6.9 million adverse impact of the exchange rate. Cost of sales for 2005 decreased $7.5 million due mainly to lower contracting work and exit charges from the National Grid Company. Operating expenses for 2005 decreased $29.4 million due mainly to $13.3 million of gains recognized on the partial disposal of certain CE Gas Australian assets and lower costs of $11.2 million associated with the withdrawal from the metering market.

Operating income for 2004 increased $51.6 million, or 11.6%, to $497.4 million compared with 2003. Operating revenue for 2004 increased $106.4 million, or 12.8%, to $936.4 million compared with 2003 due primarily as a result of the weaker U.S. dollar and increased contracting revenue. Cost of sales for 2004 increased $16.7 million mainly due to increased contracting activity and the weaker U.S. dollar, partially offset by lower exit charges from the National Grid Company at both Northern Electric and Yorkshire Electricity. Operating expenses for 2004 increased $16.5 million due to higher pension costs and the weaker U.S. dollar in 2004, and a gain on the sale of a local operational dispatch facility in 2003. Depreciation and amortization for 2004 increased $12.7 million primarily due to the weaker U.S. dollar.

CalEnergy Generation-Foreign

The CalEnergy Generation-Foreign platform consists of MEHC’s indirect ownership of the Upper Mahiao, Mahanagdong and Malitbog projects (collectively, the “Leyte Projects”), and a combined irrigation and hydroelectric power generation project located in the central part of the island of Luzon in the Philippines (the “Casecnan Project”).

Operating income for 2005 decreased $3.5 million, or 1.9%, to $185.0 million compared with 2004. Operating revenue for 2005 increased $4.9 million, or 1.6%, to $312.3 million compared with 2004. The increase in operating revenue was mainly due to higher capacity prices at the Leyte Projects and higher water delivery fees at the Casecnan Project pursuant to contractual escalation factors.

Operating income for 2004 decreased $9.0 million, or 4.6%, to $188.5 million compared with 2003. Operating revenue for 2004 decreased $19.0 million, or 5.8%, to $307.4 million compared with 2003. Each decrease was primarily due to lower water delivery fees in 2004 resulting from the NIA arbitration settlement at CE Casecnan, partially offset by higher contractually-specified capacity and water delivery prices in 2004 and by the reversal of accrued revenue in connection with the settlement of various disputes between the Leyte Projects and the PNOC-EDC in 2003.

HomeServices

HomeServices’ operating revenue and cost of sales consists mainly of commission revenue from real estate brokerage transactions and associated commissions on the transactions. HomeServices separately acquired 13 real estate companies for an aggregate purchase price of $78.5 million throughout 2005, 2004 and 2003.

Operating income for 2005 increased $12.4 million, or 11.0%, to $125.3 million from the comparable period in 2004. Operating revenue for 2005 increased $112.1 million, or 6.4%, to $1,868.5 million and cost of sales increased $78.2 million from the comparable period in 2004. The increase in operating revenue was due to growth from existing businesses totaling $62.1 million reflecting primarily higher average sales prices and acquisitions not included in the comparable 2004 period totaling $49.4 million.

Operating expenses for 2005 increased $24.5 million from the comparable period in 2004 mainly due to $12.8 million related to acquisitions not included in the comparable 2004 period and $11.7 million in higher operating expense at existing businesses due primarily to higher marketing and occupancy expenses. Depreciation and amortization for 2005 was $3.1 million lower than the comparable period in 2004 due primarily to lower amortization of acquisition related costs in 2005 as compared to the same period in 2004.

Operating income for 2004 increased $20.0 million, or 21.5%, to $112.9 million from the comparable period in 2003. Operating revenue for 2004 increased $279.8 million, or 18.9%, to $1,756.4 million and cost of sales increased $211.8 million from the comparable period in 2003. The increase in operating revenue was due to growth from existing businesses totaling $154.7 million reflecting primarily higher average sales prices and acquisitions not included in the comparable 2003 period totaling $125.1 million.

Operating expenses for 2004 increased $44.8 million from the comparable period in 2003 mainly due to $27.8 million related to acquisitions not included in the comparable 2003 period and $17.0 million in higher operating expense at existing businesses due primarily to higher salaries and employee benefits, marketing and occupancy expenses. Depreciation and amortization for 2004 was $3.3 million higher than the comparable period in 2003 due primarily to higher amortization of acquisition related costs in 2004 as compared to the same period in 2003.

Consolidated Other Income and Expense Items

Interest Expense

Interest expense for 2005 decreased $12.2 million to $891.0 million from $903.2 million for the same period in 2004. Interest expense was lower in 2005 due to maturities of and principal repayments on parent company senior and subordinated debt and subsidiary and project debt, partially offset by additional interest expense on the £350.0 million of 5.125% bonds issued by certain indirect wholly-owned subsidiaries of CE Electric UK in May 2005 and MidAmerican Energy’s 4.65%, $350.0 million notes issued in October 2004 and 5.75%, $300.0 million notes issued in November 2005. Additionally, in the first quarter of 2005, the Company incurred a $10.2 million charge to exercise the call option on the £155.0 million Variable Rate Reset Trust Securities at CE Electric UK.

Interest expense for 2004 increased $142.2 million to $903.2 million from $761.0 million for the same period in 2003. On October 1, 2003, the Company adopted FIN 46R related to certain finance subsidiaries. The adoption required that amounts previously recorded in minority interest and preferred dividends of subsidiaries be recorded prospectively as interest expense in the accompanying consolidated statement of operations. For the year ended December 31, 2004 and the three-month period ended December 31, 2003, the Company recorded $196.9 million and $49.8 million, respectively, of interest expense related to these finance subsidiaries. In accordance with the requirements of FIN 46R, no amounts prior to adoption on October 1, 2003 were reclassified. The amount included in minority interest and preferred dividends of subsidiaries related to these finance subsidiaries for the nine-month period ended September 30, 2003, was $170.2 million. Other interest expense decreased $4.9 million. The Company incurred lower interest expense of $42.9 million due mainly to the Company's scheduled redemption of $215.0 million of 6.96% senior notes in September 2003, redemption in full of the outstanding shares of the Yorkshire Capital Trust I, 8.08% trust securities in June 2003, and reductions in subsidiary project debt. The Company incurred additional interest expense, totaling $38.0 million, on the Company’s debt issuances of $450.0 million of 3.5% senior notes in May 2003 and $250.0 million of 5.0% senior notes in February 2004 and the effects of the weaker U.S. dollar.

Other Income, Net

Other income, net for the years ended December 31, 2005, 2004, and 2003 is summarized as follows (in millions):

	Year Ended December 31,
	2005			2004			2003

Capitalized interest	$	16.7		$	20.0		$	30.5
Interest and dividend income		58.1			38.9			47.9
Other income		74.5			128.2			96.7
Other expense		(22.1	)		(10.1	)		(5.9	)
Total other income, net	$	127.2		$	177.0		$	169.2

Capitalized interest for 2005 decreased due to lower capitalization at Northern Electric and Yorkshire Electricity, partially offset by higher capitalized interest at MidAmerican Energy associated with an increase in the construction of generation facilities. Capitalized interest for 2004 decreased $10.5 million to $20.0 million from $30.5 million for the same period in 2003. Kern River capitalized $17.2 million of interest in 2003 related to its 2003 Expansion Project. This was partially offset by increased construction activity at MidAmerican Energy’s generation projects.

Interest and dividend income for 2005 increased $19.2 million to $58.1 million from $38.9 million for the same period in 2004 mainly due to earnings on guaranteed investment contracts (£100.0 million at 4.75% and £200.0 million at 4.73%) purchased by certain indirect wholly-owned subsidiaries of CE Electric UK in May 2005 as well as earnings on higher cash balances and higher short-term interest rates.

Interest and dividend income for 2004 decreased $9.0 million to $38.9 million from $47.9 million for the same period in 2003. The decrease was mainly due to dividend income received in 2003 from the Company’s investment in Williams Cumulative Convertible Preferred Stock that was sold in June 2003, partially offset by higher interest income at CE Electric UK resulting from higher cash balances.

Other income for 2005 decreased $53.7 million from the comparable period in 2004, which increased $31.5 million from the comparable period in 2003. Refer to Note 16 of Notes to Consolidated Financial Statements included in Item 8. Financial Statements and Supplementary Data of this Form 10-K for additional information regarding the components of other income. In 2005, the Company realized gains from sales of certain non-strategic investments at MidAmerican Funding of $13.4 million and CE Electric UK of $8.4 million. In 2004, the Company recognized a $72.2 million gain on Northern Natural Gas’ sale of the Enron Note Receivable and a $14.8 million gain on amounts collected by Kern River on its claim for damages against Mirant. In 2003, the Company recognized a $31.9 million gain in connection with the NIA arbitration settlement and a $13.8 million gain on the sale of Williams Cumulative Convertible Preferred Stock. Additionally, the allowance for equity funds used during construction for 2005 increased $5.7 million compared to 2004 due to increased levels of capital project expenditures at MidAmerican Energy, while the allowance for equity funds used during construction for 2004 decreased $6.2 million compared to 2003 due primarily to the completion of Kern River’s 2003 Expansion Project in May 2003.

Included in other expense for 2005 are losses for other-than-temporary impairments of MidAmerican Funding’s investments in commercial passenger aircraft leased to major domestic airlines, which are accounted for as leveraged leases, of $15.8 million. These impairments result from MidAmerican Funding’s evaluation of these investments in light of the continued deterioration of the airline industry and the bankruptcy filings of two major airline carriers during 2005. The remaining carrying values of MidAmerican Funding’s commercial aircraft leveraged leases are not material.

Income Tax Expense

Income tax expense for 2005 decreased $20.3 million to $244.7 million from $265.0 million for the same period in 2004. The effective tax rate was 32.0% and 33.2% for 2005 and 2004, respectively. The lower effective tax rate in 2005 was mainly due to the effects of production tax credits related to energy produced by MidAmerican Energy’s wind facilities, the first of which were placed in service on December 31, 2004, and lower income taxes on foreign earnings in 2005, partially offset by a change in the state of Iowa’s income tax laws in 2004 related to bonus depreciation that lowered income tax expense and benefits from CE Electric UK’s settlement of various positions with the Inland Revenue department.

Income tax expense for 2004 decreased $5.3 million to $265.0 million from $270.3 million for the same period in 2003. The effective tax rate was 33.2% and 31.5% for 2004 and 2003, respectively. The increase in the effective tax rate in 2004 was mainly due to the effect of the $170.2 million of tax deductible interest on subordinated debt not included in income from continuing operations before income tax expense, minority interest and preferred dividends of subsidiaries and equity income in 2003, partially offset by the $24.4 million tax payment made in connection with the NIA arbitration settlement at CE Casecnan in 2003, CE Electric UK’s settlement of various positions with the Inland Revenue department and a change in the state of Iowa’s income tax laws in 2004 related to bonus depreciation that lowered income tax expense.

Equity Income

Equity income for 2005 increased $36.4 million to $53.3 million compared with $16.9 million for the same period in 2004. The increase is mainly due to higher earnings at CE Generation due to higher energy rates, partially offset by higher fuel costs, mainly at its natural gas-fired generation facilities and increased production at the Imperial Valley Projects due to the timing and length of scheduled outages and lower major maintenance costs, partially offset by higher fuel costs. Additionally, 2004 results included MEHC’s $16.8 million after-tax portion of a charge as a result of the partial impairment of the carrying value of CE Generation’s Power Resources project.

Equity income for 2004 decreased $21.4 million to $16.9 million compared with $38.3 million for the same period in 2003, mainly due to MEHC’s $16.8 million after-tax portion of the Power Resources project impairment. Additionally, HomeServices’ mortgage joint ventures had lower income due to lower refinancing activity.

Discontinued Operations

On September 10, 2004, management made the decision to cease operations of the Zinc Recovery Project. In connection with ceasing operations, the Zinc Recovery Project’s assets have been dismantled and sold and certain employees of the operator of the Zinc Recovery Project were paid one-time termination benefits. Implementation of the decommissioning plan began in September 2004 and, as of December 31, 2005, the dismantling, decommissioning, and sale of remaining assets of the Zinc Recovery Project was completed.

The income from discontinued operations, net of income tax, of $5.1 million for the year ended December 31, 2005 reflects the proceeds received from the sale of assets, partially offset by the disposal costs incurred, in connection with the September 2004 decision to cease the operations of the Zinc Recovery Project. The loss from discontinued operations, net of income tax, of $367.6 million for the year ended December 31, 2004 consists primarily of a $340.3 million impairment charge recognized in connection with ceasing the operations of the Zinc Recovery Project. The $27.1 million loss from discontinued operations, net of income tax, for the year ended December 31, 2003 reflects losses incurred from operating the Zinc Recovery Project.

Liquidity and Capital Resources

In May 2005, MEHC reached a definitive agreement with ScottishPower and its subsidiary, PacifiCorp Holdings, Inc., to acquire 100% of the common stock of ScottishPower’s wholly-owned indirect subsidiary, PacifiCorp, a regulated electric utility providing service to approximately 1.6 million customers in California, Idaho, Oregon, Utah, Washington and Wyoming. MEHC will purchase all of the outstanding shares of the PacifiCorp common stock for approximately $5.1 billion in cash. The long-term debt and preferred stock of PacifiCorp, which aggregated $4.3 billion at December 31, 2005, will remain outstanding. As of March 1, 2006, all state and federal approvals required for the acquisition were obtained, subject to the completion of a “most favored states” process in Wyoming, Washington, Utah, Idaho and Oregon that allows each such state to make applicable to that state any acquisition commitments or conditions accepted in other PacifiCorp states. Subject to the most favored states process and other customary closing conditions, the transaction is expected to close in March 2006. MEHC expects to fund the acquisition of PacifiCorp with the proceeds from an investment by Berkshire Hathaway and other existing shareholders of approximately $3.4 billion in MEHC common stock and the issuance by MEHC of $1.7 billion of either additional common stock to Berkshire Hathaway or long-term senior notes to third parties.

The applications filed with the public utility commissions in the six states where PacifiCorp has retail customers propose a number of regulatory commitments by MEHC and PacifiCorp upon which approval of the transaction would be conditioned, 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 investments, generally to be made over several years following the purchase, in emissions reduction technology for PacifiCorp’s existing coal plants and in PacifiCorp’s transmission and distribution system of approximately $812 million and $520 million, respectively. PacifiCorp generally expects at least $1.0 billion per year in capital expenditures over the next five years, including the regulatory commitments described above. Capital expenditure needs are reviewed regularly by management and may change significantly as a result of such reviews.

On February 9, 2006, following the effective date of the repeal of PUHCA 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. As a consequence, Berkshire Hathaway owns 83.4% (80.5% on a diluted basis) of the outstanding common stock of MEHC, will consolidate the Company in its financial statements as a majority-owned subsidiary, and will include the Company in its consolidated federal U.S. income tax return.

In addition to the Berkshire Equity Commitment, the Company has available a variety of sources of liquidity and capital resources, both internal and external. 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 or indirect subsidiaries is organized as a legal entity separate and apart from MEHC and its other subsidiaries. Pursuant to separate financing agreements at each subsidiary, the assets of each subsidiary may be pledged or encumbered to support or otherwise provide the security for their own project or subsidiary debt. It should not be assumed that any asset of any subsidiary of MEHC will be available to satisfy the obligations of MEHC or any of its other subsidiaries; provided, however, that unrestricted cash or other assets which are available for distribution may, subject to applicable law and the terms of financing 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 and short-term investments, which consist primarily of auction rate securities that are used in the Company’s cash management program, were $396.2 million at December 31, 2005, compared to $960.9 million at December 31, 2004. In addition, the Company recorded separately, in restricted cash and short-term investments and in deferred charges and other assets, restricted cash and investments of $136.7 million and $164.5 million at December 31, 2005 and 2004, respectively. The restricted cash balance is mainly composed of amounts deposited in restricted accounts relating to (i) the Company’s debt service reserve requirements relating to certain projects, (ii) customer deposits held in escrow, (iii) custody deposits, and (iv) unpaid dividends declared obligations. The debt service funds are restricted by their respective project debt agreements to be used only for the related project.

Cash Flows from Operating Activities

The Company generated cash flows from operations of $1,310.8 million for the year ended December 31, 2005, compared with $1,424.6 million for the same period in 2004. The decrease was mainly due to the receipt of a $79.0 million federal tax refund in 2004, related to additional tax depreciation, partially offset by higher earnings, changes in other working capital and a $33.6 million reduction in 2005 of cash used at the Zinc Recovery Project’s discontinued operations.

Cash Flows from Investing Activities

Cash flows used in investing activities for the years ended December 31, 2005 and 2004 were $1,551.3 million and $1,098.1 million, respectively. The increase was mainly due to the purchase, with the majority of the proceeds of the issuance of £350.0 million of 5.125% bonds due in 2035, of two guaranteed investment contracts by certain indirect wholly-owned subsidiaries of CE Electric UK totaling $556.6 million and the collection of the $97.0 million ROP Note and $72.2 million from the Enron Note Receivable in 2004, partially offset by higher proceeds from sale of non-strategic investments and assets in 2005 totaling $94.2 million.

Capital Expenditures, Construction and Other Development Costs

Capital expenditures, construction and other development costs were $1,196.2 million for the year ended December 31, 2005, compared with $1,179.4 million for the same period in 2004. The following table summarizes the expenditures by business segment (in millions):

	Year Ended December 31,
	2005		2004
Capital expenditures:
MidAmerican Energy	$	701.0	$	633.8
Northern Natural Gas		124.7		138.8
CE Electric UK		342.6		334.5
Other reportable segments		27.4		53.6
Segment capital expenditures		1,195.7		1,160.7
Corporate/other		0.5		18.7
Total capital expenditures	$	1,196.2	$	1,179.4

Forecasted capital expenditures, construction and other development costs for fiscal 2006 are approximately $1.3 billion, which does not include any amounts for the planned acquisition of PacifiCorp. Capital expenditure needs are reviewed regularly by management and may change significantly as a result of such reviews. The Company expects to meet these capital expenditures with cash flows from operations and the issuance of debt. Capital expenditures relating to operating projects, consisting of recurring expenditures and the funding of growing load requirements, were $796.3 million for the year ended December 31, 2005. Construction and other development costs were $399.9 million for the year ended December 31, 2005. These costs consist mainly of expenditures for large scale, generation projects as follows:

MidAmerican Energy anticipates a continuing increase in demand for electricity from its regulated customers. To meet anticipated demand and ensure adequate electric generation in its service territory, MidAmerican Energy is currently constructing CBEC Unit 4, a 790-MW (expected accreditation) super-critical-temperature, coal-fired generating plant. MidAmerican Energy will operate the plant and hold an undivided ownership interest as a tenant in common with the other owners of the plant. MidAmerican Energy’s current ownership interest is 60.67%, equating to 479 MW of output. Municipal, cooperative and public power utilities will own the remainder, which is a typical ownership arrangement for large base-load plants in Iowa. The facility will provide service to regulated retail electricity customers. Wholesale sales may also be made from the facility to the extent the power is not immediately needed for regulated retail service. MidAmerican Energy has obtained regulatory approval to include the Iowa portion of the actual cost of the generation project in its Iowa rate base as long as the actual cost does not exceed the agreed cap that MidAmerican Energy has deemed to be reasonable. If the cap is exceeded, MidAmerican Energy has the right to demonstrate the prudence of the expenditures above the cap, subject to regulatory review. MidAmerican Energy expects to invest approximately $737 million in CBEC Unit 4, including transmission facilities and excluding allowance for funds used during construction. Through December 31, 2005, MidAmerican Energy has invested $502.0 million in the project, including $121.3 million for MidAmerican Energy’s share of deferred payments allowed by the construction contract.

On December 16, 2005, MidAmerican Energy filed with the IUB a settlement agreement between MidAmerican Energy and the OCA regarding ratemaking principles for up to 545 MW (nameplate rating) of additional wind generation capacity in Iowa. Generally speaking, accredited capacity ratings for wind power facilities are considerably less than the nameplate ratings due to the varying nature of wind. The settlement agreement is subject to approval by the IUB.

Put of ROP Note and Receipt of Cash

On January 14, 2004, CE Casecnan exercised its right to put the ROP Note to the ROP and, in accordance with the terms of the put option, CE Casecnan received $99.2 million (representing $97.0 million par value plus accrued interest) from the ROP on January 21, 2004.

Sale of Enron Note Receivable and Receipt of Cash

Northern Natural Gas had a note receivable of approximately $259.0 million (the “Enron Note Receivable”) with Enron. As a result of Enron filing for bankruptcy on December 2, 2001, Northern Natural Gas filed a bankruptcy claim against Enron seeking to recover payment of the Enron Note Receivable. As of December 31, 2001, Northern Natural Gas had written-off the note. By stipulation, Enron and Northern Natural Gas agreed to a value of $249.0 million for the claim and received approval of the stipulation from Enron’s Bankruptcy Court on August 26, 2004. On November 23, 2004, Northern Natural Gas sold its stipulated general, unsecured claim against Enron of $249.0 million to a third party investor for $72.2 million, which was recorded as other income in the fourth quarter of 2004.

HomeServices’ Acquisitions

In 2005, HomeServices separately acquired three real estate companies for an aggregate purchase price of $5.1 million, net of cash acquired, plus working capital and certain other adjustments. For the year ended December 31, 2004, these real estate companies had combined revenue of $21.8 million on approximately 3,400 closed sides representing $0.8 billion of sales volume. In 2004, HomeServices separately acquired six real estate companies for an aggregate purchase price of $30.7 million, net of cash acquired, plus working capital and certain other adjustments. For the year ended December 31, 2003, these real estate companies had combined revenue of $95.7 million on approximately 15,000 closed sides representing $3.2 billion of sales volume. Additionally in 2004, HomeServices paid an earnout related to its 2003 acquisition of $6.0 million based on 2004 financial performance measures. These purchases were financed using HomeServices’ cash balances.

Cash Flows from Financing Activities

Cash flows used in financing activities for the year ended December 31, 2005 were $219.1 million. Uses of cash totaled $1,331.2 million and consisted primarily of $875.4 million for repayments of subsidiary and project debt and $448.5 million for repayments of parent company senior and subordinated debt. Sources of cash totaled $1,112.1 million and consisted of $1,050.6 million of proceeds from the issuance of subsidiary and project debt and $51.0 million of net proceeds from MEHC’s revolving credit facility.

Cash flows used in financing activities for the year ended December 31, 2004 were $105.4 million. Uses of cash totaled $730.5 million and consisted mainly of $504.8 million for repayments of subsidiary and project debt, including $136.4 million of cash flows from discontinued operations, $100.0 million for repayments of parent company subordinated debt and $43.9 million of net repayments of subsidiary short-term debt. Sources of cash totaled $625.1 million and consisted of $375.3 million of proceeds from the issuance of subsidiary and project debt and $249.8 million of proceeds from the issuance of parent company senior debt.

Recent Debt Issuances, Redemptions and Maturities

In addition to the debt issuances, redemption and maturities discussed herein, MEHC and its subsidiaries made scheduled repayments on parent company subordinated debt and subsidiary and project debt totaling approximately $565 million during the year ended December 31, 2005.

In February 2005, a subsidiary of CE Electric UK exercised a call option to purchase, and then cancelled, its £155.0 million Variable Rate Reset Trust Securities, due in 2020. A charge to exercise the call option of $10.2 million was recognized in interest expense in the accompanying consolidated statement of operations.

On February 15, 2005, MidAmerican Energy’s 7% series of mortgage bonds, totaling $90.5 million, were repaid upon maturity.

On April 4, 2005, CE Electric UK and certain of its subsidiaries entered into a variable rate, five-year, £100.0 million committed revolving credit facility.

On April 14, 2005, Northern Natural Gas issued $100.0 million of 5.125% senior notes due May 1, 2015. The proceeds were used by Northern Natural Gas to repay its outstanding $100.0 million 6.875% senior notes due May 1, 2005.

On May 5, 2005, Northern Electric Finance plc, an indirect wholly-owned subsidiary of CE Electric UK, issued £150.0 million of 5.125% bonds due 2035, guaranteed by Northern Electric and guaranteed as to scheduled payments of principal and interest by Ambac. Additionally, on May 5, 2005, Yorkshire Electricity, a wholly-owned subsidiary of CE Electric UK, issued £200.0 million of 5.125% bonds due 2035, guaranteed as to scheduled payments of principal and interest by Ambac. The proceeds from the offerings are being invested and used for general corporate purposes. Investments include a £100.0 million, 4.75%, fixed rate guaranteed investment contract maturing in December 2007 and a £200.0 million, 4.73%, fixed rate guaranteed investment contract maturing in February 2008. The proceeds from the maturing guaranteed investment contracts will be used to repay certain long-term debt of subsidiaries of CE Electric UK. In connection with the issuance of such bonds, CE Electric UK entered into agreements amending certain terms and conditions of its £200.0 million 7.25% bonds due 2022.

On August 26, 2005, MEHC entered into a $400.0 million, variable rate (LIBOR or a base rate plus a margin), credit facility pursuant to a credit agreement. The credit agreement is unsecured and has a termination date of August 26, 2010. As of December 31, 2005, the outstanding balance and amount of letters of credit issued under the credit agreement totaled $51.0 million and $41.9 million, respectively. The interest rate on the balance outstanding under the facility at December 31, 2005 was 4.85%.

On September 15, 2005, MEHC’s 7.23% senior notes, totaling $260.0 million, were repaid upon maturity.

On November 1, 2005, MidAmerican Energy issued $300.0 million of 5.75% medium-term notes due in 2035. The proceeds are being used to support construction of its electric generation projects and for general corporate purposes.

The Energy Policy Act

On August 8, 2005, the Energy Policy Act was signed into law. That law potentially impacts many segments of the energy industry. A tax provision extended the federal production tax credit for new renewable electricity generation projects through December 31, 2007. In part as a result of that portion of the law, MidAmerican Energy began development efforts to add additional wind generation. The law also results in expanding the FERC’s regulatory authority in areas such as mandatory electric system reliability standards, electric transmission expansion incentives and pricing, regulation of utility holding companies, and enforcement authority to issue substantial civil penalties.

CalEnergy Generation-Foreign

The 10-year cooperation periods for the Leyte Projects end in June 2006 and July 2007, respectively, at which time each project will be transferred to the PNOC-EDC at no cost on an “as-is” basis. For the year ended December 31, 2005, the Upper Mahiao Project’s financial results represented 0.6%, 1.7% and 2.3%, respectively, and the Mahanagdong and Malitbog Projects’ combined financial results represented 2.1%, 7.9% and 7.4%, respectively, of MEHC’s total consolidated operating revenue, income from continuing operations and operating cash flows from continuing operations. Additionally, the net properties, plants and equipment and the project debt of the Leyte Projects represented less than 1%, respectively, of MEHC’s total consolidated net properties, plants and equipment and subsidiary and project debt at December 31, 2005.

Credit Ratings

Debt and preferred securities of MEHC and its subsidiaries may be 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 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 its risk management activities, MidAmerican Energy must meet credit quality standards as required by counterparties. In accordance with industry practice, master agreements that govern MidAmerican Energy’s energy supply and marketing activities either specifically require it 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 MidAmerican Energy’s creditworthiness. If one or more of MidAmerican Energy’s credit ratings decline below investment grade, 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 March 1, 2006, MidAmerican Energy’s credit ratings from the three recognized credit rating agencies were investment grade; however if the ratings fell below investment grade, MidAmerican Energy’s estimated potential collateral requirements totaled approximately $267 million. MidAmerican Energy’s collateral requirements could fluctuate considerably due to seasonality, market price volatility, and a loss of key MidAmerican Energy generating facilities or other related factors.

Yorkshire Power Group Limited (“YPGL”), a subsidiary of CE Electric UK, has in effect certain currency rate swap agreements for its Yankee bonds with three large multi-national financial institutions. The swap agreements effectively convert the U.S. dollar fixed interest rate to a fixed rate in sterling for $281.0 million of 6.496% Yankee bonds outstanding at December 31, 2004. The agreements extend until February 25, 2008 and convert the U.S. dollar interest rate to a fixed sterling rate ranging from 7.3175% to 7.3450%. The estimated fair value of these swap agreements at December 31, 2005 was $63.8 million 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. Certain of these counterparties have the option to terminate the swap agreements and demand payment of the fair value of the swaps if YPGL’s credit ratings from the three recognized credit rating agencies decline below investment grade. As of March 1, 2006, YPGL’s credit ratings from the three recognized credit rating agencies were investment grade; however, if the ratings fell below investment grade, payment requirements would have been $29.8 million.

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 parent company and subsidiary long-term debt and notes payable, operating leases 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, 2005, which do not include any amounts associated with the pending acquisition of PacifiCorp, are as follows (in millions):

	Payments Due By Periods
			<		2-3		4-5		>5
	Total		1 Year		Years		Years		Years

Contractual Cash Obligations:
Parent company senior debt	$	2,775.0	$	-	$	1,550.0	$	-	$	1,225.0
Parent company subordinated debt		1,663.8		234.0		468.0		422.5		539.3
Subsidiary and project debt		7,052.4		313.7		945.4		399.2		5,394.1
Interest payments on long-term debt ⁽¹⁾		8,168.4		785.4		1,377.4		1,001.3		5,004.3
Coal, electricity and natural gas contract commitments ⁽²⁾		742.3		181.1		248.6		118.3		194.3
Operating leases ⁽²⁾		376.8		74.8		124.8		81.0		96.2
Deferred costs on construction contract ⁽³⁾		200.0		-		200.0		-		-
Total contractual cash obligations	$	20,978.7	$	1,589.0	$	4,914.2	$	2,022.3	$	12,453.2

	Commitment Expiration per Period
			<		2-3		4-5		>5
	Total		1 Year		Years		Years		Years
Other Commercial Commitments:
Unused revolving credit facilities and lines of credit -
Parent company revolving credit facility	$	307.1	$	-	$	-	$	307.1	$	-
Subsidiary revolving credit facilities and lines of credit		612.6		21.3		-		591.3		-
Total unused revolving credit facilities and lines of credit	$	919.7	$	21.3	$	-	$	898.4	$	-

Parent company letters of credit outstanding	$	43.0	$	41.9	$	1.1	$	-	$	-

______________

(1)	Excludes interest payments on variable rate long-term debt.

(2)	The coal, electricity and natural gas contract commitments and operating leases are not reflected on the consolidated balance sheets.

(3)	MidAmerican Energy is allowed to defer up to $200.0 million in payments to the contractor under its contract to build CBEC Unit 4. Approximately 39.3% of this commitment is expected to be funded by the joint owners of CBEC Unit 4.

The Company has other types of commitments that are subject to change and relate primarily to the items listed below. For additional information, refer, where applicable, to the respective referenced note of Notes to Consolidated Financial Statements included in Item 8. Financial Statements and Supplemental Data of this Form 10-K.

Debt service reserve guarantees (see Note 13)

Asset retirement obligations (see Note 14)

Nuclear decommissioning costs (see Note 20)

Residual guarantees on operating leases (see Note 20)

·	Pension and postretirement commitments (see Note 21)

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 balance sheet 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, 2005, the Company’s investments which are accounted for under the equity method had $745.8 million of debt and $87.0 million in outstanding letters of credit. As of December 31, 2005, the Company’s pro-rata share of such debt and outstanding letters of credit, which is all non-recourse to MEHC except for a $23.1 million outstanding letter of credit (included in the Obligations and Commitments table), was $368.3 million and $41.4 million, respectively.

As noted above, MEHC is generally not required to support the debt service obligations of its equity investments. However, default with respect to this non-recourse debt could result in a loss of invested equity.

New Accounting Pronouncements

In December 2004, the FASB issued Statement of Financial Accounting Standards (“SFAS”) No. 123R, “Share-Based Payment” (“SFAS 123R”), which replaces SFAS No. 123, “Accounting for Stock-Based Compensation,” and supersedes Accounting Principles Board Opinion No. 25, “Accounting for Stock Issued to Employees.” SFAS 123R establishes standards for the accounting for transactions in which an entity exchanges its equity instruments for goods or services, primarily focusing on the accounting for transactions in which an entity obtains employee services in share-based payment transactions. SFAS 123R requires entities to measure compensation costs for all share-based payments, including stock options, at fair value and expense such payments over the service period. Since MEHC is considered a nonpublic entity under the criteria of SFAS 123R, this standard is effective for annual periods beginning after December 15, 2005. Adoption of this standard will not have an effect on the Company’s financial position, results of operations or cash flows as all of the Company’s outstanding stock options were fully vested at the date of issuance of SFAS 123R. Modifications to outstanding stock options after the effective date of the standard may result in additional compensation expense pursuant to the provisions of SFAS 123R.

Critical Accounting Policies

The preparation of financial statements and related documents in conformity with GAAP requires management to make judgments, assumptions and estimates that affect the amounts reported in the consolidated financial statements and accompanying notes. Note 2 to the consolidated financial statements for the year ended December 31, 2005 included in this annual report describes the significant accounting policies and methods used in the preparation of the consolidated financial statements. Estimates are used for, but not limited to, the accounting for the effects of certain types of regulation, impairment of long-lived assets and goodwill, accrued pension and post-retirement expense, income taxes and revenue. Actual results could differ from these estimates. 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

MidAmerican Energy, Kern River and Northern Natural Gas prepare their financial statements in accordance with the provisions of SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation (“SFAS 71”), which differs in certain respects from the application of GAAP by non-regulated businesses. In general, SFAS 71 recognizes that accounting for rate-regulated enterprises should reflect the economic effects of regulation. As a result, a regulated utility is required to defer the recognition of costs (a regulatory asset) or the recognition of obligations (a regulatory liability) if it is probable that, through the rate-making process, there will be a corresponding increase or decrease in future rates. Accordingly, MidAmerican Energy, Kern River and Northern Natural Gas have deferred certain costs and accrued certain obligations, which will be amortized over various future periods. The Company periodically evaluates the applicability of SFAS 71 and considers factors such as regulatory changes and the impact of competition. If cost-based regulation ends or competition increases, the Company may have to reduce its asset balances to reflect a market basis less than cost and write-off the associated regulatory assets and liabilities.

Management continually assesses whether the regulatory assets are probable of future recovery by considering factors such as applicable regulatory environment changes, recent rate orders received by other regulated entities, and the status of any pending or potential deregulation legislation. Based upon this continual assessment, management believes the existing regulatory assets are probable of recovery. This assessment reflects the current political and regulatory climate at the state and federal levels, and is subject to change in the future. If future recovery of costs ceases to be probable, the asset and liability write-offs would be required to be recognized in operating income. Total regulatory assets were $441.1 million and $451.8 million as of December 31, 2005 and 2004, respectively. Total regulatory liabilities were $773.9 million and $682.8 million as of December 31, 2005 and 2004, respectively. Refer to Note 5 of Notes to Consolidated Financial Statements included in Item 8. Financial Statements and Supplementary Data of this Form 10-K for additional information regarding the Company’s regulatory assets and liabilities.

Impairment of Long-Lived Assets and Goodwill

The Company’s long-lived assets consist primarily of properties, plants and equipment. Depreciation is generally computed using the straight-line method based on economic lives or regulatorily mandated recovery periods. The Company periodically evaluates long-lived assets, including properties, plants and equipment, when events or changes in circumstances indicate that the carrying value of these assets may not be recoverable. Upon the occurrence of a triggering event, the carrying amount of a long-lived asset is reviewed to assess whether the recoverable amount has declined below its carrying amount. The recoverable amount is the estimated net future cash flows that the Company expects to recover from the future use of the asset, undiscounted and without interest, plus the asset’s residual value on disposal. Where the recoverable amount of the long-lived asset is less than the carrying value, an impairment loss is recognized to write down the asset to its fair value that is based on discounted estimated cash flows from the future use of the asset.

The estimate of cash flows arising from future use of the asset that are used in the impairment analysis requires judgment regarding what the Company would expect to recover from future use of the asset. Any changes in the estimates of cash flows arising from future use of the asset or the residual value of the asset on disposal based on changes in the market conditions, changes in the use of the asset, management’s plans, the determination of the useful life of the asset and technology changes in the industry could significantly change the calculation of the fair value or recoverable amount of the asset and the resulting impairment loss, which could significantly affect the results of operations. The determination of whether impairment has occurred is primarily based on an estimate of undiscounted cash flows attributable to the assets, as compared to the carrying value of the assets. An impairment analysis of generating facilities requires estimates of possible future market prices, load growth, competition and many other factors over the lives of the facilities. A resulting impairment loss is highly dependent on these underlying assumptions.

The Company evaluates the impairment of goodwill under SFAS No. 142, “Goodwill and Other Intangible Assets.” The majority of the Company’s goodwill at December 31, 2005, relates to the Teton Transaction completed in 2000. The remainder relates to the acquisitions of Yorkshire Electricity in 2001, Kern River and Northern Natural Gas in 2002 and various acquisitions at HomeServices. The Company performs an annual goodwill impairment test and updates the test if events or circumstances occur that would more likely than not reduce the fair value of a reporting unit below its carrying value. Key assumptions used in the analysis include, but are not limited to, the use of an appropriate discount rate and estimated future cash flows. Estimated future cash flows are impacted by, among other factors, assumptions regarding comprehensive energy regulation, changes in regulations and rates, and estimates of future commodity prices. In estimating cash flows, the Company incorporates current market information, as well as, historical factors. During 2005 and 2004, the Company recognized impairments on several of its long-lived assets and goodwill. For additional discussion of these impairments refer to Notes 4, 7 and 17 of Notes to Consolidated Financial Statements included in Item 8. Financial Statements and Supplementary Data of this Form 10-K.

The Company records goodwill adjustments for (i) changes in the estimates of 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.

Accrued Pension and Postretirement Expense

The Company sponsors pension and other retirement and postretirement benefit plans in various forms covering all employees who meet eligibility requirements. The Company accounts for these benefits under SFAS No. 87, “Employers’ Accounting for Pensions” and SFAS No. 106, “Employers’ Accounting for Postretirement Benefits Other Than Pensions,” respectively. Refer to Note 21 of Notes to Consolidated Financial Statements included in Item 8. Financial Statements and Supplementary Data of this Form 10-K for additional disclosures regarding the Company’s pension and postretirement commitments. The measurement of the pension and postretirement obligations, costs and liabilities is dependent on a variety of assumptions used by the actuaries and the Company. The critical assumptions used in developing the required estimates include the following key factors:

·	discount rate;

·	expected return on plan assets; and

·	health care cost trend rates.

Other assumptions, such as retirement, mortality, and turnover, are evaluated periodically and updated to reflect actual experience.

For its pension and other postretirement plans, the Company assumed that its plans’ assets would generate an expected return on plan assets of 7.0% for its domestic and United Kingdom plans as of December 31, 2005. These assets are maintained in master trusts. The investment objective of the master trusts is to achieve reasonable returns on trust assets, subject to a prudent level of portfolio risk, for the purpose of enhancing the security of benefits for plan participants. The asset allocation targets were set after considering the investment objectives and the risk profiles with respect to each trust. Equity securities, debt securities, real estate and other securities are held for return potential and diversification benefits. Investments within asset classes are to be diversified to achieve broad market participation and reduce the impact of individual managers or investments. The Company regularly reviews its actual asset allocations and periodically rebalances its investments to its targeted allocations when considered appropriate.

For its pension and other postretirement plans, the Company assumed a discount rate of 5.75% in determining the benefit obligations and benefit costs for its domestic plans as of and for the year ended December 31, 2005. Discount rates of 4.75% and 5.25%, respectively, were used in determining the benefit obligations and benefit costs for the Company’s United Kingdom plan as of and for the year ended December 31, 2005. Advice from the actuaries and current market conditions were used to determine discount rates. The discount rates used for all plans approximate the discount rates of hypothetical bond portfolios that match the Company’s expected payment obligations.

The actuarial assumptions used may differ materially from actual results due to changing market and economic conditions, higher or lower withdrawal rates or longer or shorter life spans of participants. These differences may result in a significant impact to the amount of pension and postretirement benefit expense recorded. If a 100 basis point change were to occur for the following assumptions, the approximate effect on the financial statements would be as follows:

	Domestic Plans
						Other Postretirement					United Kingdom
	Pension Plans					Benefit Plans					Pension Plan
	+1.0%			-1.0%		+1.0%			-1.0%		+1.0%			-1.0%
						(in millions)
Effect on December 31, 2005,
Benefit Obligations:
Discount rate	$	(62.1	)	$	75.2	$	(28.7	)	$	35.7	$	(220.3	)	$	280.5
Health care trend rate		N/A			N/A		(26.4	)		21.4		N/A			N/A

Effect on 2005 Periodic Cost:
Discount rate	$	(4.1	)	$	1.9	$	(2.1	)	$	2.1	$	(16.4	)	$	18.2
Health care trend rate		N/A			N/A		(2.4	)		1.9		N/A			N/A
Expected return on assets		(5.6	)		5.6		(1.4	)		1.4		(14.6	)		14.6

Income Taxes

The Company recognizes deferred tax assets and liabilities based on the difference between the financial statement and tax basis of assets and liabilities using estimated tax rates in effect for the year in which the differences are expected to reverse. Based on existing regulatory precedent, MidAmerican Energy is not allowed to recognize deferred income tax expense related to certain temporary differences resulting from accelerated tax depreciation and other property related basis differences. For these differences, MidAmerican Energy establishes deferred tax liabilities and regulatory assets on the consolidated balance sheets since MidAmerican Energy is allowed to recover the increased tax expense when these differences turn around.

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. These earnings related to ongoing operations and were approximately $600 million at December 31, 2005. 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.

In preparing the Company’s tax returns, management is required to interpret complex tax laws and regulations. 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 Internal Revenue Service has closed examination of the Company’s income tax returns through 1998. Although the ultimate resolution of the Company’s tax examinations is uncertain, the Company believes it has made adequate provisions for income tax payables 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 condition, results of operations or cash flows. Tax contingency reserves are included in accrued property and other taxes and other long-term accrued liabilities, as appropriate, in the accompanying consolidated balance sheets.

Revenue Recognition - Unbilled Revenue

Unbilled revenues were $199.4 million and $185.5 million, respectively, at December 31, 2005 and 2004.

Electric and Natural Gas Retail Revenues and Electric Distribution Revenues

Revenue is recorded based upon services rendered and electricity and natural gas delivered, distributed or supplied to the end of the period. MidAmerican Energy records unbilled revenue representing the estimated amounts customers will be billed between the meter reading dates in a particular month and the end of that month. The distribution businesses in Great Britain record unbilled revenue representing the estimated amounts that customers will be billed for electricity distributed during the period based upon information received from the national settlement system.

For MidAmerican Energy, the determination of sales to individual customers is based on the reading of their meters, which is performed on a systematic basis throughout the month. At the end of each month, amounts of electricity and natural gas delivered to customers since the date of their last meter readings are estimated and the corresponding unbilled revenue accrual is then recorded. This estimate is reversed in the following month and actual revenue is recorded based on meter readings.

The monthly estimate for unbilled revenues is calculated by MidAmerican Energy using a number of inputs, including the estimation of total energy provided during the period, line losses, total energy billed, and the average rate per customer class. The estimate of total energy provided and unbilled volumes can vary from period to period depending on seasonal weather patterns, customer usage, production levels due to economic activity, and changes in the composition of customer classes or other variables. The distribution businesses in Great Britain follow a similar process in the determination of revenue, except that the information regarding units distributed through the systems is received from the national settlement system. Differences between the actual and estimated amounts have historically been immaterial.

Natural Gas Transportation and Storage

The majority of the pipelines’ transportation and storage revenues are derived from firm reservation charges which are fixed based on contractual quantities and rates. The remaining revenue, consisting primarily of commodity charges, is based on contractual rates and actual or estimated usage based on scheduled quantities and is subject to volume estimates including estimates of meter reading and loss and unaccounted for volumes. Amounts are generally billed on or before the ninth business day of the following month. Historically, any differences between estimated quantities and actual quantities have been immaterial.

Item 7A. Quantitative and Qualitative Disclosures About Market Risk.

The Company is exposed to market risks associated with electric and natural gas prices, foreign currency exchange rates, interest rates, and credit risks. Risk is an inherent part of MEHC’s business and activities. 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. To assist in managing the risk, management enters into various transactions, including derivative transactions, consistent with these established procedures. These activities are generally described below. Notes 2 and 14 of Notes to Consolidated Financial Statements included in Item 8. Financial Statements and Supplementary Data of this Form 10-K contain additional information regarding the accounting for derivative contracts pursuant to Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activities” (“SFAS 133”), at the Company’s platforms.

As of December 31, 2005, the Company held derivative instruments with the following fair values (in millions):

	Commodity
				Northern						Foreign			Interest
	MidAmerican			Natural						Exchange			Rate
	Energy			Gas			Other			Swaps			Locks		Total

Maturity:
2006	$	(9.0	)	$	1.2		$	(6.0	)	$	-		$	-	$	(13.8	)
2007 - 2009		(5.2	)		(6.7	)		(4.8	)		(77.5	)		-		(94.2	)
After 2009		-			(0.6	)		-			-			-		(0.6	)
Total	$	(14.2	)	$	(6.1	)	$	(10.8	)	$	(77.5	)	$	-	$	(108.6	)

Commodity Price Risk

MidAmerican Energy - Gas

Under the current regulatory framework, MidAmerican Energy is allowed to recover its cost of gas from all of its regulated gas customers through a purchased gas adjustment clause included in revenue. Accordingly, MidAmerican Energy’s regulated gas customers, although ensured of the availability of gas supplies, retain the risk associated with market price volatility. In order to mitigate a portion of the market price risk retained by its regulated gas customers through the purchased gas adjustment clause, MidAmerican Energy uses natural gas futures, options and over-the-counter agreements. The realized gains and losses on these derivative instruments are assigned to regulated gas customers through the purchased gas adjustment clause.

MidAmerican Energy - Electric

MidAmerican Energy is exposed to variations in the price of fuel for generation and the price of wholesale power to be purchased or sold. Under typical operating conditions, MidAmerican Energy has sufficient generation to supply its regulated retail electric needs, but may, at times, need to purchase electric power. MidAmerican Energy may incur a loss if the costs of fuel for generation or purchases of electric power are higher than MidAmerican Energy is permitted to recover from its customers under current electric rates. MidAmerican Energy uses physical and financial forward contracts to mitigate these regulated electric price risks.

Derivative instruments are used to economically hedge both committed and forecasted energy purchases and sales. Realized gains and losses on all hedges are recognized in income as operating revenues, cost of fuel, energy and capacity; or cost of gas sold, depending upon the nature of the item being hedged. Net unrealized gains and losses on hedges utilized for regulated purposes are recorded as regulatory assets or liabilities.

Northern Natural Gas

On an annual basis, Northern Natural Gas enters into equivalent volume forward transactions at negotiated fixed prices that generally provide for the sale of gas in the first six months of the year and the purchase of equivalent volumes in the final six months of the year to lock in the cash flows relating to anticipated near-term index-based sales and purchases of operational storage volumes. Since these sale and purchase transactions are a normal and recurring method of managing seasonal changes in operational storage volumes and are expected to result in physical deliveries, such transactions are deemed to be normal sales and purchases that qualify for the exemption from fair value accounting under SFAS 133.

Northern Natural Gas has also entered into longer term natural gas commodity swaps of equivalent volume transactions at negotiated fixed prices to hedge the cash flows of anticipated longer term operational gas sales and purchases. These agreements are designated as cash flow hedges under SFAS 133.

Additionally, Northern Natural Gas has entered into natural gas commodity swaps to hedge the cash flows of anticipated future preferred delivery storage contracts. The objective of these transactions is to lock in the cash flows relating to the price spreads of natural gas storage contracts that are sensitive to gas commodity prices. These agreements are also designated as cash flow hedges under SFAS 133.

Currency Exchange Rate Risk

CE Electric UK

MEHC is exposed to foreign currency risk from investments in businesses owned and operated by CE Electric UK. At December 31, 2005, MEHC’s primary foreign currency rate exposures were with the sterling. A 10% devaluation in the currency exchange rate would result in the Company’s consolidated balance sheet being negatively impacted by a $132.3 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 $21.0 million in 2005.

CE Electric UK has entered into certain currency rate swap agreements for its senior notes and Yankee bonds with large multi-national financial institutions. The swap agreements effectively convert the U.S. dollar fixed interest rate to a fixed rate in sterling for $237.0 million of 6.995% senior notes and $281.0 million of 6.496% Yankee bonds outstanding at December 31, 2005. The agreements extend until December 30, 2007 and February 25, 2008, respectively. The estimated fair value of these swap agreements at December 31, 2005 and 2004, was $77.5 million and $131.8 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.

A 10% devaluation of the U.S. dollar versus sterling from the value at December 31, 2005 would increase the amount owed by the Company if these swap agreements were terminated by approximately $62.0 million.

CalEnergy Generation-Foreign

CalEnergy Generation-Foreign has mitigated a significant portion of its foreign currency risk as PNOC-EDC’s and NIA’s obligations under the project agreements are substantially denominated in U.S. dollars.

Interest Rate Risk

At December 31, 2005, the Company had fixed-rate long-term debt of $11,348.0 million in aggregate principal amount and having a fair value of $12,066.0 million. These instruments are fixed-rate and therefore 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 $434 million if interest rates were to increase by 10% from their levels at December 31, 2005. 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.

At December 31, 2004, the Company had fixed-rate long-term debt of $11,503.4 million in aggregate principal amount and having a fair value of $12,416.2 million. These instruments were fixed-rate and therefore did not expose the Company to the risk of earnings loss due to changes in market interest rates.

At December 31, 2005, the Company had floating-rate obligations of $166.7 million that expose the Company to the risk of increased interest expense in the event of increases in short-term interest rates. These obligations are not hedged; however, any increase in floating rates would not have a material effect on the Company’s consolidated interest expense.

At December 31, 2004, the Company had floating-rate obligations of $493.4 million that exposed the Company to the risk of increased interest expense in the event of increases in short-term interest rates. These obligations were not hedged.

The Company may enter into contractual agreements to hedge exposure to interest rate risk. Changes in fair value of interest rate “locks” used as cash flow hedges are reported in accumulated other comprehensive income to the extent the hedge is effective until the forecasted transaction occurs, at which time they are recorded as adjustments to interest expense over the term of the related debt issuance. In May 2005, MEHC entered into a treasury rate lock agreement in the notional amount of $1.6 billion to protect against a rise in interest rates related to the anticipated financing of the PacifiCorp acquisition. At December 31, 2005, the market value of this agreement was zero.

Credit Risk

Domestic Regulated Operations

MidAmerican Energy’s utility operations grant unsecured credit to its retail electric and gas customers, substantially all of whom are local businesses and residents, which totaled $186.0 million at December 31, 2005. MidAmerican Energy also extends unsecured credit to other utilities, energy marketers, financial institutions and certain commercial and industrial end-users in conjunction with wholesale energy marketing activities. MidAmerican Energy analyzes the financial condition of each significant counterparty before entering into any transactions, establishes limits on the amount of unsecured credit to be extended to each counterparty, and evaluates the appropriateness of unsecured credit limits on a daily basis. MidAmerican Energy seeks to negotiate contractual arrangements with wholesale counterparties to provide for net settlement of monthly accounts receivable and accounts payable and net settlement of contracts for future performance in the event of default. At December 31, 2005, 84.4% of MidAmerican Energy’s credit exposure, net of collateral, from wholesale operations was with counterparties having “investment grade” credit ratings from Moody’s or Standard & Poor’s, while an additional 7.4% of MidAmerican Energy’s credit exposure, net of collateral, from wholesale operations was with counterparties having financial characteristics deemed equivalent to “investment grade” by 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 electric generating companies and energy marketing and trading companies in the western United States. 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 or traders and sell the electricity to end-use customers, use Northern Electric’s and Yorkshire Electricity’s distribution networks pursuant to an industry standard “Distribution 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. Northern Electric’s and Yorkshire Electricity’s customers are concentrated in a small number of electricity supply businesses with Npower accounting for approximately 44% of distribution revenues in 2005. Ofgem has determined a framework which sets credit limits for each supply business 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 cover must be 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

PNOC-EDC’s and NIA’s obligations under the project agreements are the Leyte Projects’ and 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 obligations under the project agreements 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 CalEnergy Generation-Foreign was $312.3 million for the year ended December 31, 2005. The Leyte Projects’ agreements expire in June 2006 and July 2007, respectively, while the Casecnan Project’s agreement expires in December 2021.

Item 8. Financial Statements and Supplementary Data.

Report of Independent Registered Public Accounting Firm	66

Consolidated Balance Sheets as of December 31, 2005 and 2004	67

Consolidated Statements of Operations for the Years Ended December 31, 2005, 2004 and 2003	68

Consolidated Statements of Stockholders’ Equity for the Years Ended December 31, 2005, 2004 and 2003	69

Consolidated Statements of Cash Flows for the Years Ended December 31, 2005, 2004 and 2003	70

Notes to Consolidated Financial Statements	71

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders

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, 2005 and 2004, and the related consolidated statements of operations, stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2005. 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, 2005 and 2004, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2005, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedules, when considered in relation to the basic consolidated financial statements taken as a whole, present fairly in all material respects the information set forth therein.

/s/ Deloitte & Touche LLP

Des Moines, Iowa

March 3, 2006

MIDAMERICAN ENERGY HOLDINGS COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Amounts in thousands)

	As of December 31,
	2005			2004
ASSETS
Current assets:
Cash and cash equivalents	$	357,845		$	837,353
Short-term investments		38,393			123,550
Restricted cash and short-term investments		102,900			129,316
Accounts receivable, net		802,599			695,761
Amounts held in trust		108,546			111,708
Inventories		128,184			125,079
Other current assets		194,131			141,194
Total current assets		1,732,598			2,163,961
Properties, plants and equipment, net		11,915,413			11,607,264
Goodwill		4,156,180			4,306,751
Regulatory assets		441,098			451,830
Other investments		798,683			261,575
Equity investments		236,209			216,935
Deferred charges and other assets		912,779			895,246
Total assets	$	20,192,960		$	19,903,562

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	523,602		$	410,319
Accrued interest		198,263			197,813
Accrued property and other taxes		189,099			166,639
Amounts held in trust		108,546			111,708
Other liabilities		451,018			420,452
Short-term debt		70,066			9,090
Current portion of long-term debt		313,661			1,145,598
Current portion of parent company subordinated debt		234,021			188,543
Total current liabilities		2,088,276			2,650,162
Other long-term accrued liabilities		2,226,904			2,171,616
Parent company senior debt		2,776,211			2,771,957
Parent company subordinated debt		1,354,106			1,585,810
Subsidiary and project debt		6,836,626			6,304,923
Deferred income taxes		1,361,874			1,281,833
Total liabilities		16,643,997			16,766,301
Deferred income		53,931			62,443
Minority interest		21,419			14,119
Preferred securities of subsidiaries		88,362			89,540

Commitments and contingencies (Note 20)

Stockholders’ equity:
Zero coupon convertible preferred stock - authorized 50,000 shares, no par value; 41,263 shares issued and outstanding		-			-
Common stock - authorized 60,000 shares, no par value; 9,281 and 9,081 shares issued and outstanding at December 31, 2005 and 2004, respectively		-			-
Additional paid-in capital		1,963,343			1,950,663
Retained earnings		1,719,497			1,156,843
Accumulated other comprehensive loss, net		(297,589	)		(136,347	)
Total stockholders’ equity		3,385,251			2,971,159
Total liabilities and stockholders’ equity	$	20,192,960		$	19,903,562

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

MIDAMERICAN ENERGY HOLDINGS COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(Amounts in thousands)

	Year Ended December 31,
	2005			2004			2003

Operating revenue	$	7,115,539		$	6,553,388		$	5,965,630

Costs and expenses:
Cost of sales		3,284,876			2,751,856			2,400,536
Operating expense		1,693,783			1,637,922			1,512,345
Depreciation and amortization		608,198			638,209			602,934
Total costs and expenses		5,586,857			5,027,987			4,515,815

Operating income		1,528,682			1,525,401			1,449,815

Other income (expense):
Interest expense		(890,979	)		(903,217	)		(760,956	)
Capitalized interest		16,716			20,040			30,494
Interest and dividend income		58,070			38,889			47,908
Other income		74,516			128,205			96,643
Other expense		(22,127	)		(10,125	)		(5,913	)
Total other income (expense)		(763,804	)		(726,208	)		(591,824	)
Income from continuing operations before income tax expense, minority interest and preferred dividends of subsidiaries and equity income		764,878			799,193			857,991
Income tax expense		244,709			264,986			270,276
Minority interest and preferred dividends of subsidiaries		15,962			13,301			183,203
Income from continuing operations before equity income		504,207			520,906			404,512
Equity income		53,313			16,861			38,224
Income from continuing operations		557,520			537,767			442,736
Income (loss) from discontinued operations, net of tax (Note 17)		5,134			(367,561	)		(27,118	)
Net income available to common and preferred stockholders	$	562,654		$	170,206		$	415,618

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

MIDAMERICAN ENERGY HOLDINGS COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDERS ’ EQUITY

FOR THE THREE YEARS ENDED DECEMBER 31, 2005

(Amounts in thousands)

												Accumulated
	Outstanding					Additional						Other
	Common			Common		Paid-in			Retained			Comprehensive
	Shares			Stock		Capital			Earnings			Loss			Total

Balance, January 1, 2003		9,281		$	-	$	1,956,509		$	584,009		$	(246,235	)	$	2,294,283
Net income		-			-		-			415,618			-			415,618
Other comprehensive income:
Foreign currency translation adjustment		-			-		-			-			58,148			58,148
Fair value adjustment on cash flow hedges, net of tax of $7,202		-			-		-			-			16,769			16,769
Minimum pension liability adjustment, net of tax of $(6,425)		-			-		-			-			(14,989	)		(14,989	)
Unrealized gains on securities, net of tax of $566		-			-		-			-			848			848
Total comprehensive income																476,394
Other equity transactions		-			-		768			-			-			768
Balance , December 31, 2003		9,281			-		1,957,277			999,627			(185,459	)		2,771,445
Net income		-			-		-			170,206			-			170,206
Other comprehensive income:
Foreign currency translation adjustment		-			-		-			-			107,370			107,370
Fair value adjustment on cash flow hedges, net of tax of $(6,069)		-			-		-			-			(12,270	)		(12,270	)
Minimum pension liability adjustment, net of tax of $(19,898)		-			-		-			-			(46,429	)		(46,429	)
Unrealized gains on securities, net of tax of $294		-			-		-			-			441			441
Total comprehensive income																219,318
Common stock purchase		(200	)		-		(7,010	)		(12,990	)		-			(20,000	)
Other equity transactions		-			-		396			-			-			396
Balance, December 31, 2004		9,081			-		1,950,663			1,156,843			(136,347	)		2,971,159
Net income		-			-		-			562,654			-			562,654
Other comprehensive income:
Foreign currency translation adjustment		-			-		-			-			(186,156	)		(186,156	)
Fair value adjustment on cash flow hedges, net of tax of $(9,828)		-			-		-			-			(19,541	)		(19,541	)
Minimum pension liability adjustment, net of tax of $17,994		-			-		-			-			43,724			43,724
Unrealized gains on securities, net of tax of $487		-			-		-			-			731			731
Total comprehensive income																401,412
Exercise of common stock options		200			-		5,801			-			-			5,801
Tax benefit from exercise of common stock options		-			-		6,236			-			-			6,236
Other equity transactions		-			-		643			-			-			643
Balance, December 31, 2005		9,281		$	-	$	1,963,343		$	1,719,497		$	(297,589	)	$	3,385,251

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

MIDAMERICAN ENERGY HOLDINGS COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Amounts in thousands)

	Year Ended December 31,
	2005			2004			2003
Cash flows from operating activities:
Income from continuing operations	$	557,520		$	537,767		$	442,736
Adjustments to reconcile income from continuing operations to cash flows from continuing operations:
Distributions less income on equity investments		(18,927	)		20,022			40,160
Gain on other items, net		(6,338	)		(71,757	)		(29,264	)
Depreciation and amortization		608,198			638,209			602,934
Amortization of regulatory assets and liabilities		38,725			(1,586	)		(14,363	)
Amortization of deferred financing costs		16,110			20,875			27,748
Provision for deferred income taxes		129,964			176,591			220,136
Other		(37,690	)		16,981			8,211
Changes in other items:
Accounts receivable and other current assets		(136,013	)		(43,600	)		(25,900	)
Accounts payable and other accrued liabilities		167,351			171,457			(17,835	)
Deferred income		(7,832	)		(6,465	)		(9,344	)
Net cash flows from continuing operations		1,311,068			1,458,494			1,245,219
Net cash flows from discontinued operations		(262	)		(33,846	)		(27,296	)
Net cash flows from operating activities		1,310,806			1,424,648			1,217,923
Cash flows from investing activities:
Capital expenditures relating to operating projects		(796,319	)		(778,300	)		(616,804	)
Construction and other development costs		(399,918	)		(401,090	)		(602,564	)
Purchases of available-for-sale securities		(2,842,392	)		(2,819,701	)		(1,937,834	)
Proceeds from sale of available-for-sale securities		2,913,060			2,737,999			1,900,152
Purchase of other investments		(556,590	)		-			-
Proceeds from sale of other investments		-			-			288,750
Acquisitions, net of cash acquired		(10,247	)		(36,706	)		(54,263	)
Proceeds from sale of assets		102,825			8,602			13,113
Proceeds from notes receivable		-			169,210			-
Proceeds from (purchase of) affiliate notes		4,391			14,118			(32,406	)
(Increase) decrease in restricted cash and investments		26,652			(18,455	)		(60,426	)
Other		775			25,257			19,976
Net cash flows from continuing operations		(1,557,763	)		(1,099,066	)		(1,082,306	)
Net cash flows from discontinued operations		6,423			966			(11,666	)
Net cash flows from investing activities		(1,551,340	)		(1,098,100	)		(1,093,972	)
Cash flows from financing activities:
Proceeds from subsidiary and project debt		1,050,578			375,351			1,157,649
Proceeds from parent company senior debt		-			249,765			449,295
Repayments of subsidiary and project debt		(875,433	)		(368,417	)		(1,490,986	)
Repayments of parent company senior and subordinated debt		(448,544	)		(100,000	)		(412,551	)
Net proceeds from (repayment of) subsidiary short-term debt		10,443			(43,949	)		(31,750	)
Net proceeds from parent company revolving credit facility		51,000			-			-
Purchase and retirement of common stock		-			(20,000	)		-
Other		(7,193	)		(60,868	)		(28,306	)
Net cash flows from continuing operations		(219,149	)		31,882			(356,649	)
Net cash flows from discontinued operations		-			(137,297	)		(1,407	)
Net cash flows from financing activities		(219,149	)		(105,415	)		(358,056	)
Effect of exchange rate changes		(19,825	)		28,531			27,364
Net change in cash and cash equivalents		(479,508	)		249,664			(206,741	)
Cash and cash equivalents at beginning of period		837,353			587,689			794,430
Cash and cash equivalents at end of period	$	357,845		$	837,353		$	587,689

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”) and its subsidiaries (together with MEHC, the “Company”) are organized and managed as seven distinct platforms: MidAmerican Funding, LLC (“MidAmerican Funding”) (which primarily includes MidAmerican Energy Company (“MidAmerican Energy”)), Kern River Gas Transmission Company (“Kern River”), Northern Natural Gas Company (“Northern Natural Gas”), 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 (the subsidiaries owning the Upper Mahiao, Malitbog and Mahanagdong Projects (collectively the “Leyte Projects”) and the Casecnan Project), CalEnergy Generation-Domestic (the subsidiaries 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 a combined electric and natural gas utility company in the United States, two natural gas pipeline companies in the United States, two electricity distribution companies in Great Britain, a diversified portfolio of domestic and international independent power projects and the second largest residential real estate brokerage firm in the United States.

In connection with the Teton Transaction, MEHC issued 34.6 million shares of no par, zero-coupon convertible preferred stock valued at $1,211.4 million to Berkshire Hathaway. In connection with the Kern River acquisition and the purchase of $275.0 million of The Williams Companies, Inc. (“Williams”) preferred stock, MEHC issued 6.7 million shares of no par, zero-coupon convertible preferred stock valued at $402.0 million to Berkshire Hathaway. 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. Additionally, the prior approval of the holders of convertible preferred stock was required for certain fundamental transactions by MEHC. Such transactions include, among others: (a) significant asset sales or dispositions; (b) merger transactions; (c) significant business acquisitions or capital expenditures; (d) issuances or repurchases of equity securities; and (e) the removal or appointment of the Chief Executive Officer.

In these notes to consolidated financial statements, 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 gigawatts 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.

2.	Summary of Significant Accounting Policies

Principles of Consolidation

The consolidated financial statements include the accounts of MEHC and its wholly-owned subsidiaries, except for certain trusts formed to hold trust preferred securities which were deconsolidated under Financial Accounting Standards Board (“FASB”) Interpretation No. 46R, “Consolidation of Variable Interest Entities, an interpretation of Accounting Research Bulletin No. 51” (“FIN 46R”). Subsidiaries which are less than 100% owned but greater than 50% owned are consolidated with a minority interest. Subsidiaries that are 50% owned or less, but where the Company has the ability to exercise significant influence, are accounted for under the equity method of accounting. Investments where the Company’s ability to influence is limited are accounted for under the cost method of accounting. All inter-enterprise transactions and accounts have been eliminated. The results of operations of the Company include the Company’s proportionate share of results of operations of entities acquired from the date of each acquisition for purchase business combinations.

For the Company’s foreign operations whose functional currency is not the U.S. dollar, the assets and liabilities are translated into U.S. dollars at current exchange rates. Resulting translation adjustments are reflected as other comprehensive income in stockholders’ equity. Revenue and expenses are translated at average exchange rates for the period. Transaction gains and losses that arise from exchange rate fluctuations on transactions denominated in a currency other than the functional currency are included in the results of operations as incurred.

Reclassifications

Certain amounts in the fiscal 2004 and 2003 consolidated financial statements and supporting note disclosures have been reclassified to conform to the fiscal 2005 presentation, including the reclassifications of changes in restricted cash and investments and auction rate securities. Such reclassifications did not impact previously reported net income or retained earnings.

The accompanying consolidated statements of cash flows for the years ended December 31, 2004 and 2003 reflect a reclassification of changes in restricted cash and investments from a financing activity to an investing activity. This reclassification resulted in an increase in cash used in investing activities and a corresponding decrease in cash used in financing activities totaling $17.4 million and $68.3 million for the years ended December 31, 2004 and 2003, respectively.

The accompanying consolidated balance sheet as of December 31, 2004, reflects a reclassification of instruments used in the Company’s cash management program from cash and cash equivalents to short-term investments of $123.6 million. This reclassification is to present certain auction rate securities as short-term investments rather than as cash equivalents due to the stated maturities of these investments. Additionally, in the accompanying consolidated statements of cash flows, cash and cash equivalents were reduced by $123.6 million, $72.5 million and $50.0 million at December 31, 2004, 2003 and 2002, respectively, to reflect the reclassification of these instruments from cash and cash equivalents to short-term investments.

Use of Estimates

Preparation of the consolidated financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenue and expenses during the period. Management believes the most complex and sensitive judgments, because of their significance to the consolidated financial statements, result primarily from the need to make estimates about the effects of matters that are inherently uncertain. Actual results could differ materially from management’s estimates.

Accounting for the Effects of Certain Types of Regulation

MidAmerican Energy, Kern River and Northern Natural Gas 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 71”), which differs in certain respects from the application of generally accepted accounting principles by non-regulated businesses. In general, SFAS 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 (a regulatory asset) or the recognition of obligations (a regulatory liability) if it is probable that, through the rate-making process, there will be a corresponding increase or decrease in future rates. Accordingly, MidAmerican Energy, Kern River and Northern Natural Gas have deferred certain costs and accrued certain obligations, which will be amortized over various future periods. The Company periodically evaluates the applicability of SFAS 71 and considers factors such as regulatory changes and the impact of competition. If cost-based regulation ends or competition increases, the Company may have to reduce its asset balances to reflect a market basis less than cost and write-off the associated regulatory assets and liabilities.

Revenue Recognition

Electric and Natural Gas Retail Revenues and Electric Distribution Revenues

In the distribution businesses in Great Britain, revenue is not recognized when billings for electric distribution services exceed the maximum related amounts available under the regulatory formula. This over recovered amount is deducted from revenue and included in other liabilities and is available to be earned throughout the remainder of the current or future regulatory periods. Where there is an under recovered position (billings are less than the maximum related amounts available under the regulatory formula), no anticipation of any potential future recovery is made and revenue is recognized based upon the estimated billed amounts.

Natural Gas Transportation and Storage

Kern River and Northern Natural Gas are subject to the Federal Energy Regulatory Commission’s (“FERC”) regulations and, accordingly, certain revenue collected may be subject to possible refunds upon final orders in pending rate proceedings. Kern River and Northern Natural Gas may record revenue that is subject to refund based on their best estimates of the final outcomes of these proceedings and other third party regulatory proceedings, advice of counsel and estimated total exposure, as well as collection and other risks. Estimates of any refunds are recorded in other current liabilities in the accompanying consolidated balance sheets.

Philippine Contracts

The Company invoices its customers, which consist of the Philippine National Oil Company-Energy Development Corporation (“PNOC-EDC”) for the Leyte Projects and the Philippine National Irrigation Administration (“NIA”) for the Casecnan Project, on a monthly basis for the delivery of electricity and water pursuant to the provisions of their respective project agreements. The project agreements are accounted for as arrangements that contain both an operating lease and a service contract to operate the projects. The project agreements were classified as operating leases due to significant uncertainties that existed at the inception of the leases regarding both the collection of future amounts and the amount of unreimbursable costs yet to be incurred mainly due to the existence of political, economic and other uncertainties associated with the Philippines. The Leyte Projects’ primary source of revenue is from capacity fees recognized on a straight-line basis over the cooperation periods and subject to semi-annual adjustment pursuant to changes in the United States producer price index.

Additionally, for the Casecnan Project, the annual water delivery revenue is recorded on the basis of the contractual minimum guaranteed water delivery threshold for the respective contract year. If and when actual cumulative deliveries within a contract year exceed the minimum threshold, additional revenue is recognized and calculated as the product of the water deliveries in excess of the minimum threshold and the applicable unit price up to the maximum contractually allowed water delivery volume. The Company defers revenue recognition on the difference between the actual water delivery fees earned and water delivery fees invoiced pursuant to the project agreement. Revenue from electricity consists of guaranteed energy fees, recognized on a straight-line basis over the cooperation period, and a variable energy fee. The variable energy fee is recognized when deliveries of energy exceed the guaranteed energy in any contract year.

Retail 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 the closing. Loan origination and commitment fees received in connection with the origination of mortgage loans and certain direct loan origination costs are deferred until such loans are sold to investors. Fees related to brokered loan originations are recognized at closing, which is when services have been provided.

Short-term Investments

As of December 31, 2005 and 2004, the Company had $38.4 million and $123.6 million, respectively, of short-term investments consisting primarily of auction rate securities. These instruments are classified as available-for-sale securities as management does not intend to hold them to maturity nor are they bought and sold with the objective of generating profits on short-term differences in price. The carrying value of these instruments approximates their fair value.

Restricted Cash and Investments

The restricted cash and investments balance recorded separately in restricted cash and short-term investments and in deferred charges and other assets, was $136.7 million and $164.5 million at December 31, 2005 and 2004, respectively, and includes commercial paper and money market securities. The balance is mainly composed of amounts deposited in restricted accounts relating to (i) the Company’s debt service reserve requirements relating to certain projects, (ii) customer deposits held in escrow, (iii) custody deposits, and (iv) unpaid dividends declared obligations. The debt service funds are restricted by their respective project debt agreements to be used only for the related project.

Investments which the Company has the positive intent and ability to hold to maturity are classified as held-to-maturity and carried at amortized cost. The carrying amount of held-to-maturity investments approximates their fair value. Investments which the Company intends to hold indefinitely, but not necessarily to maturity, are classified as available-for-sale and carried at fair value. Unrealized gains and losses on available-for-sale securities are reported as a separate component of stockholders’ equity, net of deferred taxes and reclassification adjustments, except for those available-for-sale securities that comprise MidAmerican Energy’s nuclear decommissioning trust funds, which are reported as an adjustment to regulatory assets or regulatory liabilities.

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 outcome of pending disputes, arbitrations and the ability of customers to pay the amounts owed to the Company. At December 31, 2005 and 2004, the allowance for doubtful accounts totaled $21.4 million and $26.0 million, respectively.

Amounts Held in Trust

Amounts held in trust consist of separately designated trust accounts for homebuyers’ earnest money and other deposits. The Company holds such funds until sold properties are closed and subsequently disburses amounts in accordance with the settlement instructions. The Company does not earn or pay interest on the amounts held in trust.

Inventories

Inventories consist mainly of materials and supplies, coal stocks, gas in storage and fuel oil, which are valued at the lower of cost, determined primarily using average cost, or market.

Properties, Plants and Equipment, Net

Properties, plants and equipment are recorded at historical cost. The Company capitalizes all construction related material and direct labor costs as well as indirect construction costs. Indirect construction costs include general engineering, taxes and costs of funds used during construction. The cost of major additions and betterments are capitalized, while replacements, maintenance, and repairs that do not improve or extend the lives of the respective assets are expensed. Depreciation is generally computed using the straight-line method based on economic lives or regulatorily mandated recovery periods. The Company believes the useful lives assigned to the depreciable assets, which generally range from 3 to 67 years, are reasonable.

When the Company retires its regulated properties, plant and equipment, it charges the original cost plus the cost of retirement, less salvage value, to the cost of removal accrued regulatory liability. When it sells entire regulated, or retires or sells non-regulated, properties, plant and equipment, the original cost is removed from the property accounts and the related accumulated depreciation and amortization accounts are reduced. Any gain or loss is recorded as income, unless otherwise required by the applicable regulatory body.

The Company recognizes an asset retirement obligation (“ARO”) in accordance with SFAS No. 143, “Accounting for Asset Retirement Obligations” (“SFAS 143”), for legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or normal use of the assets. SFAS 143 requires that the fair value of a liability for an ARO be 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. The difference between the ARO liability, the corresponding ARO net asset and amounts recovered from regulated customers to satisfy such liabilities is recorded as a regulatory asset or liability.

Impairment of Long-Lived Assets

The Company periodically evaluates long-lived assets, including properties, plants and equipment, when events or changes in circumstances indicate that the carrying value of these assets may not be recoverable. Upon the occurrence of a triggering event, the carrying amount of a long-lived asset is reviewed to assess whether the recoverable amount has declined below its carrying amount. The recoverable amount is the estimated net future cash flows that the Company expects to recover from the future use of the asset, undiscounted and without interest, plus the asset’s residual value on disposal. Where the recoverable amount of the long-lived asset is less than the carrying value, an impairment loss is recognized to write down the asset to its fair value that is based on discounted estimated cash flows from the future use of the asset.

Goodwill

The provisions of SFAS No. 142, “Goodwill and Other Intangible Assets” (“SFAS 142”), which establishes the accounting for acquired goodwill and other intangible assets, and provides that goodwill and indefinite-lived intangible assets will not be amortized, requires allocating goodwill to each reporting unit and testing for impairment using a two-step approach. The goodwill impairment test is performed annually or whenever an event has occurred that would more likely than not reduce the fair value of a reporting unit below its carrying amount. The Company completed its annual review pursuant to SFAS 142 for its reporting units as of October 31, 2005 primarily using a discounted cash flow methodology. No impairment was indicated as a result of these assessments.

Deferred Financing Costs

The Company capitalizes costs associated with financings, as deferred financing costs, and amortizes the amounts over the terms of the related financings using the effective interest method.

Accruals for Loss Contingencies

The Company establishes accruals for estimated loss contingencies, such as environmental, legal and regulatory matters, when it is management’s assessment that a loss is probable and the amount of the loss can be reasonably estimated. If the information available indicates that the amount of loss can only be estimated as a range of possible amounts with some amount within the range appearing to be a better estimate than any other amount within the range, that amount is accrued. If no specific amount within the range represents the most likely amount of loss, the minimum amount of the range is accrued. Accruals for loss contingencies are recorded in the period in which different facts or information become known or circumstances change that affect the previous assumptions with respect to the likelihood or amount of loss. Accruals for loss contingencies and subsequent revisions are reflected in income when accruals are recorded or as regulatory treatment dictates. Accruals for loss contingencies are based upon management’s assumptions and estimates, and advice of legal counsel or other third parties regarding the probable outcomes of the matter. Should the outcomes differ from the assumptions and estimates, revisions to the estimated accruals for loss contingencies would be required.

Risk Management and Hedging Activities

The Company employs a number of different derivative and non-derivative instruments in connection with its electric and natural gas, foreign currency exchange rate and interest rate risk management activities, including forward contracts, futures, swaps and options. All derivative instruments not designated and qualifying for the normal purchases and normal sales exceptions under SFAS 133, “Accounting for Derivative Instruments and Hedging Activities” (“SFAS 133”), as amended, are recorded on the consolidated balance sheet at their fair values as either assets or liabilities.

For all hedge contracts, the Company provides formal documentation of the hedge in accordance with SFAS 133. In addition, at inception and on a quarterly basis the Company formally assesses whether the hedge contract is highly effective in offsetting changes in cash flows or fair values of 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 statement of stockholders’ equity and comprehensive income as accumulated other comprehensive income (“AOCI”) until the hedged item is realized. 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 income. Gains and losses related to discontinued hedges that were previously accumulated in AOCI will remain in AOCI until the hedged item is realized, unless it is no longer probable that the hedged forecasted transaction will occur at which time associated deferred amounts in AOCI are immediately recognized in current earnings.

Derivative contracts for commodities used in the Company’s 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 provided by SFAS 133. Recognition of these contracts in revenue or cost of sales in the consolidated statement of operations occurs when the contracts settle.

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 valuation techniques or models.

Fair Value of Financial Instruments

The fair value of a financial instrument is the amount at which the instrument could be exchanged in a current transaction between willing parties, other than in a forced sale or liquidation. Although management uses its best judgment in estimating the fair value of these financial instruments, there are inherent limitations in any estimation technique. Therefore, the fair value estimates presented herein are not necessarily indicative of the amounts that the Company could realize in a current transaction.

The methods and assumptions used to estimate fair value are as follows:

Investments - The fair value of all investments is primarily based on quoted market prices as provided by the third-party financial institution holding the investments.

Short-term debt - Due to the short-term nature of the short-term debt, the fair value approximates the carrying value.

Debt instruments - The fair value of all debt instruments has been estimated based upon quoted market prices as supplied by third-party broker dealers, where available, or at the present value of future cash flows discounted at rates consistent with comparable maturities with similar credit risks.

Other financial instruments - All other financial instruments of a material nature are short-term and the fair value approximates the carrying amount.

Income Taxes

MEHC and its subsidiaries file a consolidated U.S. federal income tax return and other state and federal jurisdictional returns as required. Deferred tax assets and liabilities are recognized based on the difference between the financial statement and tax basis of assets and liabilities using estimated tax rates in effect for the year in which the differences are expected to reverse. Based on existing regulatory precedent, MidAmerican Energy is not allowed to recognize state deferred income tax expense related to certain temporary differences resulting from accelerated tax depreciation and other property related basis differences. For these differences, MidAmerican Energy establishes deferred tax liabilities and regulatory assets on the consolidated balance sheets since MidAmerican Energy is allowed to recover the increased tax expense when these differences turn around. Investment tax credits have been deferred and are being amortized over the estimated useful lives of the related properties.

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. These earnings related to ongoing operations and were approximately $600 million at December 31, 2005. 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.

Allowance for Funds Used During Construction

Allowance for funds used during construction (“AFUDC”) represents the approximate net composite interest cost of borrowed funds and a reasonable return on the equity funds used for construction. Although AFUDC increases both properties, plants and equipment and earnings, it is realized in cash through depreciation provisions included in rates for MidAmerican Energy, Kern River and Northern Natural Gas, the subsidiaries that apply SFAS 71. AFUDC for subsidiaries that apply SFAS 71 are capitalized as a component of construction in progress and will be amortized over the assets’ estimated useful lives.

Other Comprehensive Income

The differences between net income and total comprehensive income for the Company are due to foreign currency translation adjustments, minimum pension liability adjustments, unrealized holding gains and losses of marketable securities during the periods, and the effective portion of net gains and losses of derivative instruments classified as cash flow hedges. Reclassification adjustments resulting from gains and losses on sales of marketable securities and cash flow hedges included in net income for the years ended December 31, 2005, 2004 and 2003 were not material.

Consolidated Statements of Cash Flows

The Company considers all investment instruments purchased with an original maturity of three months or less to be cash equivalents. Investments other than restricted cash are primarily commercial paper and money market securities. Restricted cash is not considered a cash equivalent.

The supplemental disclosures to the accompanying consolidated statements of cash flows were as follows (in thousands):

	Year Ended December 31,
	2005		2004			2003

Interest paid, net of interest capitalized	$	844,719	$	855,399		$	656,152
Income taxes (refunded) paid	$	60,483	$	(16,616	)	$	9,911
Non-cash transaction - ROP note received in NIA Arbitration Settlement	$	-	$	-		$	97,000

For the year ended December 31, 2003, $170.2 million of preferred dividends of subsidiaries was not included in cash paid for interest as the Company adopted and applied the provisions of FIN 46R, related to certain finance subsidiaries, as of October 1, 2003. The adoption required the deconsolidation of certain finance subsidiaries, which resulted in amounts that were previously recorded as minority interest and preferred dividends of subsidiaries being prospectively recorded as interest expense in the accompanying consolidated statements of operations. For the years ended December 31, 2005 and 2004, and the three-month period ended December 31, 2003, the Company has recorded $184.4 million, $196.9 million and $49.8 million, respectively, of interest expense related to these securities. In accordance with the requirements of FIN 46R, no amounts prior to adoption of FIN 46R on October 1, 2003 have been reclassified.

New Accounting Pronouncements

In December 2004, the FASB issued SFAS No. 123R, “Share-Based Payment” (“SFAS 123R”), which replaces SFAS No. 123, “Accounting for Stock-Based Compensation,” and supersedes Accounting Principles Board Opinion No. 25, “Accounting for Stock Issued to Employees.” SFAS 123R establishes standards for the accounting for transactions in which an entity exchanges its equity instruments for goods or services, primarily focusing on the accounting for transactions in which an entity obtains employee services in share-based payment transactions. SFAS 123R requires entities to measure compensation costs for all share-based payments, including stock options, at fair value and expense such payments over the service period. Since MEHC is considered a nonpublic entity under the criteria of SFAS 123R, this standard is effective for annual period beginning after December 15, 2005. Adoption of this standard will not have an effect on the Company’s financial position, results of operations or cash flows as all of the Company’s outstanding stock options were fully vested at the date of issuance of SFAS 123R. Modifications to outstanding stock options after the effective date of the standard may result in additional compensation expense pursuant to the provisions of SFAS 123R.

3.	Recent Developments Involving PacifiCorp and Berkshire Hathaway

On March 2, 2006, MEHC amended its Articles of Incorporation to (i) increase the amount of its common stock authorized for issuance to 115.0 million shares and (ii) no longer provide for the authorization to issue any preferred stock of MEHC.

4.	Properties, Plants and Equipment, Net

Properties, plants and equipment, net comprise the following at December 31 (in thousands):

	Depreciation
	Life		2005			2004

Utility generation and distribution system		10-50 years	$	10,499,120		$	10,230,628
Interstate pipelines’ assets		3-67 years		3,700,073			3,566,578
Independent power plants		10-30 years		1,384,553			1,384,660
Other assets		3-30 years		476,488			472,744
Total operating assets				16,060,234			15,654,610
Accumulated depreciation and amortization				(4,992,431	)		(4,620,007	)
Net operating assets				11,067,803			11,034,603
Construction in progress				847,610			572,661
Properties, plants and equipment, net			$	11,915,413		$	11,607,264

The utility generation and distribution system and interstate pipelines’ assets are the regulated assets of MidAmerican Energy, Kern River, Northern Natural Gas and CE Electric UK. At December 31, 2005 and 2004, accumulated depreciation and amortization related to the Company’s regulated assets totaled $4.1 billion and $3.8 billion, respectively. Additionally, substantially all of the construction in progress at December 31, 2005 and 2004 relates to the construction of regulated assets.

Northern Natural Gas entered into a purchase and sale agreement (“PSA”) relative to the West Hugoton non-strategic section of its interstate pipeline system in the fourth quarter of 2005. As a result of entering into the PSA, Northern Natural Gas recognized a non-cash impairment charge of $29.0 million ($17.5 million after-tax), in accordance with SFAS No. 144, “Accounting for the Impairment of Long-Lived Assets” (“SFAS 144”), to write down the carrying value of the West Hugoton pipeline to its fair value. The fair value was determined based on the sale price agreed to in the PSA. The impairment charge is recorded in operating expense in the accompanying consolidated statement of operations for the year ended December 31, 2005.

5.	Regulatory Assets and Liabilities

The components of the Company’s regulatory assets consist of the following as of December 31 (in thousands):

	As of December 31,
	Weighted Average
	Remaining Life		2005		2004

Deferred income taxes, net		27 years	$	173,864	$	160,662
Computer systems development costs ^(1) (2)		6 years		54,446		63,637
Unrealized loss on regulated hedges		1 year		45,431		36,794
System levelized account ^(1) (2)		2 years		26,543		53,576
Pipe recoating and reconditioning costs ⁽¹⁾		67 years		23,256		22,406
Asset retirement obligations		8 years		20,979		20,875
Postretirement benefit costs		7 years		20,066		22,933
Debt refinancing costs		8 years		11,998		15,365
Minimum pension liability adjustment		17 years		11,694		18,203
Migration and pipeline system upgrade costs ⁽¹⁾		9 years		10,508		10,480
Nuclear generation assets ⁽¹⁾		14 years		6,487		6,727
Environmental costs		1 year		4,907		9,284
Other		Various		30,919		10,888
Total			$	441,098	$	451,830

(1) These regulatory assets are included in rate base and earn a return.

(2) The return earned on these regulatory assets is less than the stipulated return.

The components of the Company’s regulatory liabilities, which are included in other long-term accrued liabilities in the accompanying consolidated balance sheets, consist of the following as of December 31 (in thousands):

	As of December 31,
	Weighted Average
	Remaining Life		2005		2004

Cost of removal accrual ⁽¹⁾		27 years	$	448,493	$	428,719
Iowa electric settlement accrual ⁽¹⁾		2 years		213,135		181,188
Asset retirement obligations ⁽¹⁾		32 years		65,966		53,259
Unrealized gain on regulated hedges		1 year		29,648		7,462
Other		Various		16,616		12,139
Total			$	773,858	$	682,767

(1) These regulatory liabilities are deducted from rate base or otherwise accrue a carrying cost.

Refer to Note 12 for a discussion of the cost of removal accrual and asset retirement obligations and to Note 19 regarding the Iowa electric settlement accrual.

6.	Other Investments

Other investments are classified as non-current in the accompanying consolidated balance sheets as management does not intend to use them in current operations. Gross unrealized gains and losses of other investments are not material at December 31, 2005 and 2004. Other investments consist of the following (in thousands):

	2005		2004
Guaranteed investment contracts	$	516,330	$	-
Nuclear decommissioning trust fund		228,070		207,464
CE Generation, LLC ("CE Generation") and Salton Sea Funding Corporation bonds		23,244		27,641
Other		31,039		26,470
Total other investments	$	798,683	$	261,575

In May 2005, certain indirect wholly-owned subsidiaries of CE Electric UK purchased £300.0 million of fixed rate guaranteed investment contracts (£100.0 million at 4.75% and £200.0 million at 4.73%) with a portion of the proceeds of the issuance of £350.0 million of 5.125% bonds due in 2035. These guaranteed investment contracts mature in December 2007 (£100.0 million) and February 2008 (£200.0 million), respectively, the proceeds of which will be used to repay certain long-term debt of subsidiaries of CE Electric UK. The guaranteed investment contracts are reported at cost.

MidAmerican Energy has established trusts for the investment of funds for decommissioning the Quad Cities Station. These investments in debt and equity securities are classified as available-for-sale and are reported at fair value. An amount equal to the net unrealized gains and losses on those investments is recorded as an adjustment to regulatory assets or regulatory liabilities in the accompanying consolidated balance sheets. Funds are invested in the trust in accordance with applicable federal investment guidelines and are restricted for use as reimbursement for costs of decommissioning MidAmerican Energy’s Quad Cities Station. As of December 31, 2005, approximately 55.5% of the fair value of the trusts’ funds was invested in domestic common equity securities, 12.3% in domestic corporate debt and the remainder in investment grade municipal and U.S. Treasury bonds. As of December 31, 2004, approximately 55.3% of the fair value of the trusts’ funds was invested in domestic common equity securities, 14.4% in domestic corporate debt and the remainder in investment grade municipal and U.S. Treasury bonds.

7. Equity Investments

Equity investments consist mainly of MEHC’s 50% investment in CE Generation and HomeServices’ equity investments in various entities that generally conduct title and mortgage activities primarily related to the real estate brokerage business. Equity investments and related equity income consist of the following (in thousands):

	As of December 31,
	2005		2004

MEHC’s investment in CE Generation	$	207,794	$	188,670
HomeServices’ equity investments		18,739		19,047
Other		9,676		9,218
Total equity investments	$	236,209	$	216,935

	Year Ended December 31,
		2005		2004			2003

MEHC’s investment in CE Generation	$	32,313	$	(1,542	)	$	17,437
HomeServices’ equity investments		19,971		17,858			23,138
Other		1,029		545			(2,351	)
Total equity income	$	53,313	$	16,861		$	38,224

The following is summarized financial information for CE Generation as of and for the years ended December 31 (in thousands):

	2005		2004			2003

Operating revenue	$	483,956	$	439,866		$	483,397
Income (loss) before cumulative effect of change in accounting principle		64,626		(3,084	)		37,341
Net income (loss)		64,626		(3,084	)		34,874
Current assets		151,363		127,853
Total assets		1,418,099		1,450,507
Current liabilities		120,888		118,623
Long-term debt, including current portion		653,037		722,650

CE Generation determined on December 9, 2004 that a portion of the carrying value of the Power Resources project’s long-lived assets was no longer recoverable. As a result, CE Generation recognized a non-cash impairment charge of $54.5 million ($33.5 million after-tax), in accordance with SFAS 144, to write down the long-lived assets to their fair value. The fair value was determined based on discounted estimated cash flows from the future use of the long-lived assets. The impairment charge will not result in any current or future cash expenditures. MEHC’s $16.8 million after-tax portion of the Power Resources impairment is reflected in income on equity investments in the accompanying consolidated statement of operations for the year ended December 31, 2004.

The following is summarized financial information for HomeServices’ equity investees as of and for the years ended December 31 (in thousands):

	2005		2004		2003

Revenue	$	167,247	$	156,959	$	168,446
Operating expense		88,311		80,997		83,284
Net income		40,347		36,473		46,719
Current assets		52,749		35,957
Total assets		134,146		170,888
Current liabilities		44,317		27,444
Total liabilities		101,034		137,207

8.	Short-Term Debt

Short-term debt consists of the following at December 31 (in thousands):

	2005		2004
MEHC	$	51,000	$	-
CE Electric UK		10,361		38
HomeServices		8,705		9,052
Total short-term debt	$	70,066	$	9,090

Parent Company Revolving Credit Facilities

In the second quarter of 2005, the Company terminated its $100.0 million credit facility. On August 26, 2005, the Company closed on a new unsecured $400.0 million revolving credit facility which expires on August 26, 2010. The facility supports letters of credit for the benefit of certain subsidiaries and affiliates of which $41.9 million were outstanding at December 31, 2005. Borrowings of $51.0 million were outstanding at December 31, 2005, and no borrowings were outstanding on the prior facility at December 31, 2004. The facility carries a variable interest rate based on LIBOR or a base rate, at MEHC’s option, plus a margin. The interest rate on the balance outstanding under the facility at December 31, 2005 was 4.85%. The prior facility was not drawn on during 2004. As of December 31, 2005, MEHC was in compliance with all covenants related to its revolving credit facility.

MidAmerican Energy Revolving Credit Facilities and Short-Term Debt

As of December 31, 2005, MidAmerican Energy has in place a $425.0 million revolving credit facility expiring on November 18, 2009, which supports its $304.6 million commercial paper program and its variable rate pollution control revenue obligations. 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 as of the last day of any quarter. In addition, MidAmerican Energy has a $5.0 million line of credit, which expires July 1, 2006. As of December 31, 2005 and 2004, MidAmerican Energy had no commercial paper or bank notes outstanding, and the full amount of the revolving credit facility and line of credit was available. As of December 31, 2005, MidAmerican Energy was in compliance with all covenants related to its short-term borrowings. At December 31, 2005, the credit facility had a variable interest rate based on LIBOR plus 0.40% and the line of credit had a variable interest rate based on LIBOR plus 0.25%.

CE Electric UK Revolving Credit Facilities

On April 4, 2005, CE Electric UK closed on a new £100.0 million revolving credit facility which expires on April 4, 2010. The facility carries a variable interest rate based on sterling LIBOR plus a margin. Borrowings of $10.4 million were outstanding at December 31, 2005, at an interest rate of 5.14%. CE Electric UK also has a total of £35.0 million in uncommitted, variable rate, lines of credit, none of which were drawn on, at December 31, 2005.

HomeServices Revolving Credit Facilities and Short-Term Debt

HomeServices entered into a new $125.0 million senior revolving credit facility in December 2005, which expires in December 2010. This credit facility replaced the existing $125.0 million facility, which expired in November 2005. Amounts outstanding under the new revolving credit facility are unsecured and bear interest, at HomeServices’ option, at the prime lending rate or LIBOR plus a fixed spread of 0.5% to 1.125%, which varies based on HomeServices’ total debt ratio. The spread was 0.5% at December 31, 2005. No borrowings were outstanding at December 31, 2005 or, under the prior facility, at December 31, 2004.

Additionally, in 2005, HomeServices has in place a mortgage warehouse line of credit totaling $25.0 million, which expires in April 2006 and bears interest at LIBOR plus a margin ranging from 1.75% to 2.00% depending on the type of mortgage loan funded. The balance outstanding on this mortgage warehouse line of credit at December 31, 2005 was $8.7 million at a weighted average interest rate of 6.14%. In 2004, HomeServices had in place two mortgage warehouse lines of credit totaling $20.0 million, which expired in 2005. The balance outstanding on these mortgage warehouse lines of credit at December 31, 2004, totaled $9.1 million at weighted average interest rates of 4.54% and 4.21%, respectively.

9.	Parent Company Senior Debt

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

	Par Value		2005		2004
7.23% Senior Notes, due 2005	$	-	$	-	$	258,797
4.625% Senior Notes, due 2007		200,000		199,622		199,403
7.63% Senior Notes, due 2007		350,000		347,354		346,000
3.50% Senior Notes, due 2008		450,000		449,638		449,497
7.52% Senior Notes, due 2008		450,000		444,539		442,828
7.52% Senior Notes, due 2008 (Series B)		100,000		100,789		101,037
5.875% Senior Notes, due 2012		500,000		499,915		499,906
5.00% Senior Notes, due 2014		250,000		249,800		249,797
8.48% Senior Notes, due 2028		475,000		484,554		484,692
Total Parent Company Senior Debt	$	2,775,000	$	2,776,211	$	3,031,957

10.

Parent Company Subordinated Debt

MEHC has organized special purpose Delaware business trusts (collectively, the “Trusts”) pursuant to their respective amended and restated declarations of trusts (collectively, the “Declarations”).

The financial terms of MEHC’s various subordinated debentures held by such Trusts are essentially identical to the corresponding terms of the mandatorily redeemable preferred securities issued by such Trusts (the “Trust Securities”).

Pursuant to Preferred Securities Guarantee Agreements (collectively, the “Guarantees”), between MEHC and a trustee, MEHC has agreed irrevocably to pay to the holders of the Trust 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 Securities. MEHC owns all of the common securities of the Trusts. The CalEnergy Capital and MidAmerican Capital Trust Securities have liquidation preferences of $50 and $25 each, respectively, (plus accrued and unpaid dividends thereon to the date of payment) and represent undivided beneficial ownership interests in each of the Trusts. The assets of the Trusts consist solely of Subordinated Debentures of MEHC (collectively, the “Junior Debentures”) issued pursuant to their respective indentures. The indentures include agreements by MEHC to pay expenses and obligations incurred by the Trusts. Considered together, the undertakings contained in the Declarations, Junior Debentures, Indentures and Guarantees constitute full and unconditional guarantees on a subordinated basis by MEHC of the Trusts’ obligations under the Trust Securities.

Parent company subordinated debt consists of the following, including fair value adjustments, at December 31 (in thousands):

	Par Value		2005		2004
CalEnergy Capital Trust II - 6.25%, due 2012	$	104,645	$	92,724	$	91,328
CalEnergy Capital Trust III - 6.5%, due 2027		269,980		206,175		205,253
MidAmerican Capital Trust I - 11%, due 2010		409,295		409,295		454,772
MidAmerican Capital Trust II - 11%, due 2011		600,000		600,000		700,000
MidAmerican Capital Trust III - 11%, due 2012		279,933		279,933		323,000
Total Parent Company Subordinated Debt	$	1,663,853	$	1,588,127	$	1,774,353

Prior to the Teton Transaction, each Trust Security issued by CalEnergy Capital Trust II and III with a par value of $50 was convertible at the option of the holder at any time into shares of MEHC’s common stock based on a specified conversion rate. As a result of the Teton Transaction, in lieu of shares of MEHC’s common stock, upon any conversion, holders of Trust Securities will receive $35.05 for each share of common stock it would have been entitled to receive on conversion.

Distributions on the Trust Securities (and Junior Debentures) are cumulative, accrue from the date of initial issuance and are payable quarterly in arrears. The Junior Debentures are subordinated in right of payment to all senior indebtedness of the Company and the Junior Debentures are subject to certain covenants, events of default and optional and mandatory redemption provisions, all as described in the Junior Debenture indentures.

The indentures relating to the CalEnergy Trusts II and III Trust Securities give MEHC the option to defer the interest payments due on the respective Junior Debentures for up to 20 consecutive quarters during which time the corresponding distributions on the respective Trust Securities are deferred (but continue to accumulate and accrue interest). The indentures relating to the MidAmerican Capital Trust I, II and III Trust Securities give MEHC the option to defer the interest payment on the respective Junior Debentures for up to 10 consecutive semi-annual periods during which time the corresponding 11% distributions on the respective Trust Securities are deferred (but continue to accumulate and accrue interest at the rate of 13% per annum). In addition, each declaration of trust establishing the MidAmerican Capital Trusts I, II and III Trust Securities and each of the related subscription agreements contains a provision prohibiting Berkshire Hathaway and its affiliates, who are the holders of all of the respective Trust Securities issued by such Trusts, from transferring such Trust Securities to a non-affiliated person absent an event of default.

11.

Subsidiary and Project Debt

The restrictions on distributions at these separate legal entities include various covenants including, but not limited to, leverage ratios, interest coverage ratios and debt service coverage ratios. As of December 31, 2005, the separate legal entities were in compliance with all applicable 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, at December 31 (in thousands):

	Par Value		2005		2004
MidAmerican Funding	$	700,000	$	648,390	$	645,926
MidAmerican Energy		1,637,118		1,631,760		1,422,527
CE Electric UK		2,346,459		2,507,533		2,571,889
Kern River		1,157,256		1,157,256		1,214,808
Northern Natural Gas		800,000		799,560		799,614
CE Casecnan		142,345		140,635		194,660
Leyte Projects		42,630		42,630		105,664
Cordova Funding		198,787		196,210		203,995
HomeServices		27,788		26,313		31,438
Total Subsidiary and Project Debt	$	7,052,383	$	7,150,287	$	7,190,521

MidAmerican Funding

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

	Par Value		2005		2004
6.339% Senior Notes, due 2009	$	175,000	$	167,903	$	166,053
6.75% Senior Notes, due 2011		200,000		200,000		200,000
6.927% Senior Bonds, due 2029		325,000		280,487		279,873
Total MidAmerican Funding	$	700,000	$	648,390	$	645,926

The subsidiaries of MidAmerican Funding 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 its common equity level above 42% of total capitalization unless circumstances beyond its control result in the common equity level decreasing to below 39% of total capitalization. MidAmerican Energy must seek approval from the IUB of a reasonable utility capital structure if MidAmerican Energy’s common equity level decreases below 42% of total capitalization, unless the decrease is beyond the control of MidAmerican Energy. MidAmerican Energy is also required to seek the approval of the IUB if MidAmerican Energy’s equity level decreases to below 39%, even if the decrease is due to circumstances beyond the control of MidAmerican Energy.

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, at December 31 (in thousands):

	Par Value		2005		2004
Mortgage bonds, 7% Series, due 2005	$	-	$	-	$	90,497
Pollution control revenue obligations:
6.1% Series, due 2007		1,000		1,000		1,000
5.95% Series, due 2023, secured by general mortgage bonds		29,030		29,030		29,030
Variable rate series:
Due 2016 and 2017, 3.59% and 2.05%		37,600		37,600		37,600
Due 2023, secured by general mortgage bonds, 3.59% and 2.05%		28,295		28,295		28,295
Due 2023, 3.59% and 2.05%		6,850		6,850		6,850
Due 2024, 3.59% and 2.05%		34,900		34,900		34,900
Due 2025, 3.59% and 2.05%		12,750		12,750		12,750
Notes:
6.375% Series, due 2006		160,000		159,969		159,893
5.125% Series, due 2013		275,000		274,581		274,521
4.65% Series, due 2014		350,000		349,721		349,689
6.75% Series, due 2031		400,000		395,628		395,459
5.75% Series, due 2035		300,000		299,743		-
Other		1,693		1,693		2,043
Total MidAmerican Energy	$	1,637,118	$	1,631,760	$	1,422,527

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, at December 31 (in thousands):

	Par Value		2005		2004
Variable Rate Reset Trust Securities, due 2020, 5.88%	$	-	$	-	$	308,361
8.625% Bearer Bonds, due 2005		-		-		193,688
6.995% Senior Notes, due 2007		237,000		232,547		230,572
6.496% Yankee Bonds, due 2008		281,000		281,061		281,113
8.875% Bearer Bonds, due 2020 ⁽¹⁾		172,110		208,912		230,215
9.25% Eurobonds, due 2020 ⁽¹⁾		344,220		429,501		485,654
7.25% Sterling Bonds, due 2022 ⁽¹⁾		344,220		371,457		411,287
7.25% Eurobonds, due 2028 ⁽¹⁾		319,264		338,370		378,202
5.125% Bonds, due 2035 ⁽¹⁾		344,220		342,528		-
5.125% Bonds, due 2035 ⁽¹⁾		258,165		256,897		-
CE Gas Credit Facility, 6.86% and 6.36% ⁽¹⁾		46,260		46,260		52,797
Total CE Electric UK	$	2,346,459	$	2,507,533	$	2,571,889

(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.

Pursuant to a call option exercised in February 2005, at a cost of $17.5 million, a subsidiary of CE Electric UK purchased, and then cancelled, its variable rate reset trust securities, due in 2020, at a par value of £155.0 million. Accordingly, the Company included the entire principal amount of these securities in its current portion of long-term debt in the accompanying consolidated balance sheet at December 31, 2004.

On May 5, 2005, Northern Electric Finance plc, an indirect wholly-owned subsidiary of CE Electric UK, issued £150.0 million of 5.125% bonds due 2035, guaranteed by Northern Electric and guaranteed as to scheduled payments of principal and interest by Ambac Assurance UK Limited (“Ambac”). Additionally, on May 5, 2005, Yorkshire Electricity, an indirect wholly-owned subsidiary of CE Electric UK, issued £200.0 million of 5.125% bonds due 2035, guaranteed as to scheduled payments of principal and interest by Ambac. The proceeds from the offerings are being invested and used for general corporate purposes. Investments include a £100.0 million 4.75% fixed rate guaranteed investment contract maturing December 2007 and a £200.0 million 4.73% fixed rate guaranteed investment contract maturing February 2008.

Kern River

The components of Kern River’s term notes consist of the following at December 31 (in thousands):

	Par Value		2005		2004
6.676% Senior Notes, due 2016	$	415,167	$	415,167	$	439,000
4.893% Senior Notes, due 2018		742,089		742,089		775,808
Total Kern River	$	1,157,256	$	1,157,256	$	1,214,808

Northern Natural Gas

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

	Par Value		2005		2004
6.875% Senior Notes, due 2005	$	-	$	-	$	99,963
6.75% Senior Notes, due 2008		150,000		150,000		150,000
7.00% Senior Notes, due 2011		250,000		250,000		250,000
5.375% Senior Notes, due 2012		300,000		299,688		299,651
5.125% Senior Notes, due 2015		100,000		99,872		-
Total Northern Natural Gas	$	800,000	$	799,560	$	799,614

CE Casecnan

CE Casecnan Water and Energy Company, Inc.’s (“CE Casecnan”) term notes and bonds consist of the following, including fair value adjustments, at December 31 (in thousands):

	Par Value		2005		2004
11.45% Senior Secured Series A Notes, due in 2005	$	-	$	-	$	47,432
11.95% Senior Secured Series B Bonds, due in 2010		142,345		140,635		147,228
Total CE Casecnan	$	142,345	$	140,635	$	194,660

Leyte Projects

The Leyte Projects’ term loans consist of the following at December 31 (in thousands):

	Par Value		2005		2004
Mahanagdong Project 6.92% Term Loan, due 2007	$	30,922	$	30,922	$	51,537
Mahanagdong Project 7.60% Term Loan, due 2007		6,857		6,857		11,428
Malitbog Project 4.99% and 3.67%, due 2005		-		-		11,866
Malitbog Project 9.176% Term Loan, due 2005		-		-		6,580
Upper Mahiao Project 5.95% Term Loan, due 2006		4,851		4,851		24,253
Total Leyte Projects	$	42,630	$	42,630	$	105,664

MEHC provides debt service reserve letters of credit in amounts equal to the next semi-annual principal and interest payments due on the loans which were equal to $18.8 million and $44.6 million at December 31, 2005 and 2004, 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, at December 31 (in thousands):

	Par Value		2005		2004
8.48% Senior Secured Bonds, due 2019	$	11,269	$	11,269	$	11,716
8.64% Senior Secured Bonds, due 2019		82,620		80,457		83,655
8.79% Senior Secured Bonds, due 2019		27,661		27,247		28,328
8.82% Senior Secured Bonds, due 2019		51,350		51,350		53,384
9.07% Senior Secured Bonds, due 2019		25,887		25,887		26,912
Total Cordova Funding	$	198,787	$	196,210	$	203,995

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 $37.0 million. MEHC has also issued a debt service reserve guarantee, the maximum amount of which is equal at any given time to the difference between the next succeeding debt service payment ($11.0 million as of December 31, 2005) and the amount then on deposit in the debt service reserve fund ($9.0 million at December 31, 2005).

As of December 31, 2005, Cordova Funding is currently prohibited from making distributions by the terms of its indenture due to its failure to meet its debt service coverage ratio requirement.

HomeServices

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

	Par Value		2005		2004
7.12% Senior Notes, due 2010	$	25,000	$	23,525	$	28,475
Other		2,788		2,788		2,963
Total HomeServices	$	27,788	$	26,313	$	31,438

Annual Repayments of Long-Term Debt

The annual repayments of parent company and subsidiary and project debt for the years beginning January 1, 2006 and thereafter, excluding fair value adjustments and unamortized premiums and discounts, are as follows (in thousands):

	2006		2007		2008		2009		2010		Thereafter		Total
Parent company senior debt	$	-	$	550,000	$	1,000,000	$	-	$	-	$	1,225,000	$	2,775,000
Parent company subordinated debt		234,021		234,021		234,021		234,021		188,543		539,226		1,663,853
MidAmerican Funding		-		-		-		175,000		-		525,000		700,000
MidAmerican Energy		160,509		1,651		448		32		32		1,474,446		1,637,118
CE Electric UK		5,190		251,481		291,326		8,208		5,763		1,784,491		2,346,459
Kern River		71,360		69,472		72,816		74,906		78,668		790,034		1,157,256
Northern Natural Gas		-		-		150,000		-		-		650,000		800,000
CE Casecnan		36,015		37,730		37,730		13,720		17,150		-		142,345
Leyte Projects		30,037		12,593		-		-		-		-		42,630
Cordova Funding		4,500		4,163		4,725		6,412		9,000		169,987		198,787
HomeServices		6,050		5,855		5,409		5,156		5,152		166		27,788
Totals	$	547,682	$	1,166,966	$	1,796,475	$	517,455	$	304,308	$	7,158,350	$	11,491,236

Fair Value

At December 31, 2005, the Company had fixed-rate long-term debt of $11,348.0 million in principal amount and having a fair value of $12,066.0 million. In addition, at December 31, 2005, the Company had floating-rate obligations of $166.7 million that expose the Company to the risk of increased interest expense in the event of increases in short-term interest rates. The fair value of the floating-rate obligations and the short-term debt approximates their carrying amounts.

At December 31, 2004, the Company had fixed-rate long-term debt of $11,503.4 million in principal amount and having a fair value of $12,416.2 million. In addition, at December 31, 2004, the Company had floating-rate obligations of $493.4 million. The fair value of the floating-rate obligations and the short-term debt approximates their carrying amounts.

12. Asset Retirement Obligations

On December 31, 2005, the Company adopted FASB Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations, an interpretation of FASB Statement No. 143” (“FIN 47”). FIN 47 clarifies that the term conditional asset retirement obligation as used in SFAS 143 refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity. Accordingly, the Company is required to recognize a liability for the fair value of a conditional ARO if the fair value of the liability can be reasonably estimated. Uncertainty about the timing or method of settlement of a conditional ARO should be factored into the measurement of the liability when sufficient information exists.

In conjunction with the adoption of FIN 47, the Company recorded $11.4 million of ARO liabilities; $0.8 million of associated ARO assets, net of accumulated depreciation; and a $10.6 million reduction of regulatory liabilities. Adoption of FIN 47 did not impact net income.

The change in the balance of the ARO liability, which is included in other long-term accrued liabilities in the accompanying consolidated balance sheets, for the years ended December 31 is summarized as follows (in thousands):

	2005			2004

Balance, January 1	$	185,781		$	284,377
Adoption of FIN 47		11,422			-
Revisions		1,120			(120,098	)
Additions		3,897			5,602
Retirements		(4,331	)		-
Accretion		10,659			15,900
Balance, December 31	$	208,548		$	185,781

At December 31, 2005, $163.0 million of the total ARO liability pertained to the decommissioning of Quad Cities Station. Assets of $228.1 million, reflected in other investments in the accompanying consolidated balance sheet, are restricted for satisfying the Quad Cities Station ARO liability.

Revisions for the year ended December 31, 2004 include a revision to the nuclear decommissioning ARO liability as a result of a change in the assumed life of Quad Cities Station pursuant to a 20-year extension to the operating license of the plant by the NRC in October 2004 and its impact on the timing of related cash flows.

The total ARO liability, computed on a pro forma basis as if FIN 47 had been applied during each of the periods presented in the consolidated financial statements, would have been as follows (in millions):

As of January 1, 2003	$	300.4
As of December 31, 2003		295.2
As of December 31, 2004		197.0

In addition to the ARO liabilities, MidAmerican Energy has accrued for the cost of removing other electric and natural gas assets through its depreciation rates, in accordance with accepted regulatory practices. These accruals, totaling $448.5 million and $428.7 million at December 31, 2005 and 2004, respectively, are reflected as regulatory liabilities and included in other long-term accrued liabilities in the accompanying consolidated balance sheets.

13. Preferred Securities of Subsidiaries

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 $31.1 million. The aggregate total the holders of all preferred securities outstanding at December 31, 2005, are entitled to upon involuntary bankruptcy is $30.3 million plus accrued dividends. The total annual dividend requirements for all preferred securities outstanding at December 31, 2005 were $1.2 million.

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 $56.0 million as of December 31, 2005 and 2004, respectively.

14. Risk Management and Hedging Activities

The Company is directly exposed to the impact of market fluctuations in the prices of natural gas and electricity as a result of its ownership of MidAmerican Energy, Northern Natural Gas and CE Electric UK. Exposure to foreign currency risk exists from investment in businesses, primarily CE Electric UK, operated in foreign countries. The Company is exposed to interest rate risk as a result of the issuance of fixed rate debt. 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 , swaps and options. 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.

As of December 31, 2005, the Company held derivative instruments with the following fair values (in millions):

	Commodity
				Northern						Foreign			Interest
	MidAmerican			Natural						Exchange			Rate
	Energy			Gas			Other			Swaps			Locks		Total

Maturity:
2006	$	(9.0	)	$	1.2		$	(6.0	)	$	-		$	-	$	(13.8	)
2007 - 2009		(5.2	)		(6.7	)		(4.8	)		(77.5	)		-		(94.2	)
After 2009		-			(0.6	)		-			-			-		(0.6	)
Total	$	(14.2	)	$	(6.1	)	$	$(10.8	)	$	(77.5	)	$	-	$	(108.6	)

Commodity Cash Flow Hedges

Some of MEHC’s subsidiaries are exposed to market price fluctuations of various commodities related to their ongoing power generation and natural gas gathering, distribution, processing and marketing activities. The Company closely monitors the potential impacts of commodity price changes and, where appropriate, enters into contracts to lock-in prices for a portion of the future sales, generation revenue and fuel expenses.

Certain derivative electric and gas contracts utilized by the regulated operations of MidAmerican Energy are recoverable through retail rates. Accordingly, unrealized changes in fair value of these contracts are deferred as regulatory assets or liabilities pursuant to SFAS 71. At December 31, 2005, $32.7 million of derivative assets and $47.6 million of derivative liabilities were used for regulated purposes.

Other MEHC subsidiaries use derivative instruments such as swaps, futures, forwards and options as cash flow hedges for natural gas and other transactions.

Currency Exchange Rate Risk

Interest Rate Hedges

The Company may enter into contractual agreements to hedge exposure to interest rate risk. Changes in fair value of interest rate “locks” used as cash flow hedges are reported in accumulated other comprehensive income to the extent the hedge is effective until the forecasted transaction occurs, at which time they are recorded as adjustments to interest expense over the term of the related debt issuance. In May 2005, MEHC entered into a treasury rate lock agreement in the notional amount of $1.6 billion to protect against a rise in interest rates related to the anticipated financing of the PacifiCorp acquisition. For the year ended December 31, 2005, the amount of the deferred gain included in other comprehensive income was $ - million.

Credit Risk

Domestic Regulated Operations

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 an industry standard “Distribution 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. 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 44% of distribution revenues in 2005. The Office of Gas and Electricity Markets (“Ofgem”) has determined a framework which sets credit limits for each supply business 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 cover must be 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

15.

Income Taxes

Income tax expense on continuing operations consists of the following (in thousands):

	Year Ended December 31,
	2005		2004			2003
Current:
Federal	$	35,535	$	18,794		$	(48,911	)
State		5,366		(9,862	)		10,901
Foreign		73,844		79,463			88,150
		114,745		88,395			50,140
Deferred:
Federal		52,944		112,719			141,795
State		9,959		607			10,833
Foreign		67,061		63,265			67,508
		129,964		176,591			220,136
Total	$	244,709	$	264,986		$	270,276

A reconciliation of the federal statutory tax rate to the effective tax rate on continuing operations applicable to income before income tax expense follows:

	2005			2004			2003
Federal statutory rate		35.0	%		35.0	%		35.0	%
General business tax credits		(2.0	)		(0.6	)		(0.5	)
State taxes, net of federal tax effect		1.5			2.2			1.8
Equity income		2.4			0.7			1.6
Dividends on preferred securities of subsidiaries		-			-			(6.9	)
Tax effect of foreign income		(2.0	)		0.3			0.5
Dividends received deduction		(1.3	)		-			(1.1	)
Effects of ratemaking		(0.8	)		(0.9	)		0.9
Other items, net		( 0.8	)		(3.5	)		0.2
Effective tax rate		32.0	%		33.2	%		31.5	%

The net deferred tax liability consists of the following at December 31 (in thousands):

	2005		2004
Deferred tax assets:
Minimum pension liability adjustment	$	145,767	$	163,761
Revenue sharing accruals		92,040		80,220
Accruals not currently deductible for tax purposes		80,798		54,402
Deferred income		20,050		34,458
Nuclear reserve and decommissioning		14,962		27,112
Net operating loss (“NOL”) and credit carryforwards		265,408		267,051
Other		4,551		16,569
Total deferred tax assets		623,576		643,573

Deferred tax liabilities:
Properties, plants and equipment, net		1,756,340		1,700,884
Income taxes recoverable through future rates		176,108		163,108
Employee benefits		40,632		51,509
Fuel cost recoveries		9,897		6,028
Reacquired debt		2,473		3,877
Total deferred tax liabilities		1,985,450		1,925,406
Net deferred tax liability	$	1,361,874	$	1,281,833

At December 31, 2005, the Company has available unused NOL and credit carryforwards that may be applied against future taxable income and that expire at various intervals between 2007 and 2026.

16.

Other Income and Expense

Other income for the years ending December 31 consists of the following (in thousands):

	2005		2004		2003

Allowance for equity funds used during construction	$	26,170	$	20,476	$	26,708
Gains on sales of non-strategic assets and investments		23,298		3,609		4,183
Gains on Enron note receivable and other claims		6,358		72,210		-
Corporate-owned life insurance income		5,150		5,447		6,317
Gain on Mirant bankruptcy claim		-		14,750		-
Gain on CE Casecnan settlement		-		-		31,889
Gain on Williams preferred stock		-		-		13,750
Other		13,540		11,713		13,796
Total other income	$	74,516	$	128,205	$	96,643

Non-Strategic Assets and Investments

Included in gains on sales of non-strategic assets and investments for the year ended December 31, 2005, are gains from sales of certain non-strategic, passive investments at MidAmerican Funding of $13.4 million and CE Electric UK of $8.4 million.

Enron Note Receivable and Other Claims

Mirant Americas Energy Marketing (“Mirant”) Claim

Mirant was one of the shippers that entered into a 15-year, 2003 Expansion Project, firm gas transportation contract (90,000 Dth per day) with Kern River and provided a letter of credit equivalent to 12 months of reservation charges as security for its obligations thereunder. In July 2003, Mirant filed for Chapter 11 bankruptcy protection and Kern River subsequently drew on the letter of credit and held the proceeds thereof, $14.8 million, as cash collateral. The bankruptcy court ultimately determined that Kern River was entitled to the $14.8 million cash collateral which resulted in Kern River recognizing such amount as other income.

CE Casecnan Arbitration Settlement

On October 15, 2003, CE Casecnan, an indirect, majority-owned subsidiary of the Company, closed a transaction settling the arbitration, which arose from a Statement of Claim made on August 19, 2002, by CE Casecnan against the Republic of the Philippines (“ROP”) NIA. As a result of the agreement, CE Casecnan recorded $31.9 million of other income and $24.4 million of associated income taxes. In connection with the settlement, the NIA delivered to CE Casecnan a $97.0 million 8.375% ROP Note due 2013 (the “ROP Note”), which contained a put provision granting CE Casecnan the right to put the ROP Note to the ROP for a price of par plus accrued interest for a 30-day period commencing on January 14, 2004. On January 14, 2004, CE Casecnan exercised its right to put the ROP Note to the ROP and, in accordance with the terms of the put, CE Casecnan received $99.2 million (representing $97.0 million par value plus accrued interest) from the ROP on January 21, 2004.

Williams Preferred Stock

On March 27, 2002, the Company invested $275.0 million in Williams in exchange for shares of 9.875% cumulative convertible preferred stock of Williams. Dividends on the Williams preferred stock were received quarterly, commencing July 1, 2002. On June 10, 2003, Williams repurchased, for $288.8 million, plus accrued dividends, all of the shares of its 9.875% Cumulative Convertible Preferred Stock originally acquired by the Company in March 2002 for $275.0 million. The Company recorded a pre-tax gain of $13.8 million on the transaction.

Other Expense

The Company’s other expense totaled $22.1 million, $10.1 million and $5.9 million, respectively, for the years ended December 31, 2005, 2004 and 2003. MidAmerican Funding has investments in commercial passenger aircraft leased to major domestic airlines, which are accounted for as leveraged leases. During 2005, the airline industry continued to deteriorate and two major airline carriers filed for bankruptcy. MidAmerican Funding evaluated its investments in commercial passenger aircraft and recognized losses totaling $15.6 million for other-than-temporary impairments of those investments.

17.

Discontinued Operations - Zinc Recovery Project and Mineral Assets

Indirect wholly-owned subsidiaries of MEHC own the rights to commercial quantities of extractable minerals from elements in solution in the geothermal brine and fluids utilized at certain geothermal energy generation facilities located in the Imperial Valley of California and a zinc recovery plant constructed near the geothermal energy generation facilities designed to recover zinc from the geothermal brine through an ion exchange, solvent extraction, electrowinning and casting process (the “Zinc Recovery Project”).

The Zinc Recovery Project began limited production during December 2002 and continued limited production until September 10, 2004. On September 10, 2004, management made the decision to cease operations of the Zinc Recovery Project. Based on this decision, a non-cash, after-tax impairment charge of $340.3 million was recorded to write-off the Zinc Recovery Project, rights to quantities of extractable minerals, and allocated goodwill (collectively, the “Mineral Assets”). The charge and the related activity of the Mineral Assets are classified separately as discontinued operations in the accompanying consolidated statements of operations and include the following (in thousands):

	Year Ended December 31.
	2005			2004			2003

Operating revenue	$	-		$	3,401		$	659

Losses from discontinued operations	$	-		$	(42,695	)	$	(46,423	)
Proceeds from (costs of) disposal activities, net		7,634			(4,134	)		-
Asset impairment charges		-			(479,233	)		-
Goodwill impairment charges		-			(52,776	)		-
Income tax (expense) benefit		(2,500	)		211,277			19,305
Income (loss) from discontinued operations, net of tax	$	5,134		$	(367,561	)	$	(27,118	)

In connection with ceasing operations, the Zinc Recovery Project’s assets have been dismantled and sold and certain employees of the operator of the Zinc Recovery Project were paid one-time termination benefits. Implementation of the decommissioning plan began in September 2004 and, as of December 31, 2005, the dismantling, decommissioning, and sale of remaining assets of the Zinc Recovery Project was completed. Proceeds from the sale of the Zinc Recovery Project’s assets exceeded the cost of disposal activities during the year ended December 31, 2005. Salvage proceeds were recognized in the period earned. Costs were recognized in the period in which the related liability was incurred. Cash expenditures of approximately $4.1 million, consisting of pre-tax disposal costs, termination benefit costs and property taxes, were made through December 31, 2004.

18. Stock Transactions

On January 6, 2004, the Company purchased a portion of the shares of common stock owned by Mr. Sokol for an aggregate purchase price of $20.0 million.

There were no common stock options granted, forfeited or allowed to expire during each of the three years in the period ended December 31, 2005. Common stock options exercised during each of the three years in the period ended December 31, 2005 consisted solely of 200,000 in 2005 held by Mr. Sokol 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 at December 31, 2005. 1,145,000 of the outstanding and exercisable common stock options have 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 have 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 at December 31, 2004, 2003 and 2002.

19.

Regulatory Matters

MidAmerican Energy

Under a series of settlement agreements between MidAmerican Energy, the Iowa Office of Consumer Advocate (“OCA”) and other interveners approved by the IUB, MidAmerican Energy has agreed not to seek a general increase in electric rates to become effective prior to January 1, 2012 unless its Iowa jurisdictional electric return on equity for any year falls below 10%. 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 seek any decrease in MidAmerican Energy’s Iowa electric rates prior to January 1, 2012. 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 portions of revenues associated with Iowa retail electric returns on equity within specified ranges will be recorded as a regulatory liability.

Under a settlement agreement approved by the IUB on December 31, 2001, which was effective through December 31, 2005, an amount equal to 50% of revenues associated with returns on equity between 12% and 14%, and 83.33% of revenues associated with returns on equity above 14%, in each year was recorded as a regulatory liability. A settlement agreement, which was filed in conjunction with MidAmerican Energy’s application for ratemaking principles on its 2004/2005 wind power project and approved by the IUB on October 17, 2003, provided that during the period January 1, 2006 through December 31, 2010, an amount equal to 40% of revenues associated with returns on equity between 11.75% and 13%, 50% of revenues associated with returns on equity between 13% and 14%, and 83.3% of revenues associated with returns on equity above 14%, in each year will be recorded as a regulatory liability.

A settlement agreement approved by the IUB on January 31, 2005, in conjunction with MidAmerican Energy’s 2005 expansion of its wind power project extended through 2011 MidAmerican Energy’s commitment not to seek a general increase in electric rates unless its Iowa jurisdictional electric return on equity falls below 10%. It also extended the revenue sharing mechanism through 2011, and the OCA agreed not to seek any decrease in Iowa electric base rates to become effective before January 1, 2012.

On December 16, 2005, MidAmerican Energy filed with the IUB a settlement agreement between MidAmerican Energy and the OCA regarding ratemaking principles for up to 545 MW of additional wind generation capacity in Iowa, based on nameplate ratings. The settlement agreement, which is subject to IUB approval, extends through 2012 MidAmerican Energy’s commitment not to seek a general increase in electric rates unless its Iowa jurisdictional electric return on equity for the calendar year 2011 falls below 10%. Additionally, the revenue sharing mechanism is extended through 2012, and the OCA agrees not to seek any decrease in Iowa electric base rates to become effective prior to January 1, 2013.

The regulatory liabilities created by the settlement agreements are recorded as a regulatory charge in depreciation and amortization expense when the liability is accrued. Additionally, interest expense is accrued on the portion of the regulatory liability balance recorded in prior years. The regulatory liabilities created for the years through 2010 are expected to be reduced as they are credited against plant in service associated with generating plant additions. As a result of the credit applied to generating plant balances from the reduction of the regulatory liabilities, future depreciation will be reduced. The regulatory liability accrued for 2011 and 2012, if any, will be credited to customer bills in 2012 and 2013, respectively.

Kern River

Kern River’s tariff rates are designed to give it an opportunity to recover all actually and prudently incurred operations and maintenance costs of its pipeline system, taxes, interest, depreciation and amortization and a regulated equity return. 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. If the Kern River system is converted to a traditional rate design as a result of the 2004 general rate case, the depreciation of Kern River’s transmission system would be calculated on a straight-line basis over the expected economic life of its facilities. Under the traditional methodology, transportation rates do not remain constant over the lives of the shipper contracts, but rather are adjusted in each rate case to reflect current operating costs, updated depreciation rates and the rate base investment then in effect.

Kern River was required to file its 2004 general rate case no later than May 1, 2004 pursuant to the terms of its 1998 FERC Docket No. RP99-274 rate case settlement. Kern River filed its rate case on April 30, 2004, which supports an annual revenue increase of $40.1 million representing a 13% increase from its existing cost of service and a proposed overall cost of service of $347.4 million. The rate increase became effective on November 1, 2004, subject to refund. Since its previous rate case, Kern River increased the capacity of its system from 724,500 Dth per day to 1,755,575 Dth per day at a cost of approximately $1.2 billion. The filing employed the levelized rate methodology.

The Kern River 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. Briefs on exceptions will be due on April 3, 2006, and briefs opposing exceptions are due April 26, 2006. The administrative law judge’s initial decision is non-binding and after briefing, the FERC will issue its initial decision on the case. The initial FERC decision, which may result in rate refunds, typically becomes binding on all parties while rehearing requests on the FERC decision and/or court appeals are pending. The initial FERC decision is not expected until late 2006 or early 2007. The final resolution of the rate case is dependent on receiving a final, non-appealable decision on the case from the FERC, or approval of a settlement of the case by the FERC.

Northern Natural Gas

Northern Natural Gas continues to use a straight fixed variable rate design which provides that all fixed costs assignable to firm capacity customers, including a return on equity, are to be recovered through fixed monthly demand or capacity reservation charges which are not a function of throughput volumes.

On May 1, 2003, Northern Natural Gas filed a general rate case proceeding for increased rates with the FERC and filed an additional rate case proceeding on January 30, 2004 to reflect further cost increases. The FERC consolidated the 2003 and 2004 rate cases due to the similarity of issues in both cases and the updated costs. On March 25, 2005, as modified on April 22, 2005, Northern Natural Gas filed a stipulation and agreement with the FERC (the “Settlement”) resolving the consolidated rate cases. On June 20, 2005, the FERC approved the Settlement without modification. The Settlement represents the agreement Northern Natural Gas reached with its customers to settle the base tariff rates and related tariff issues in the consolidated cases. The Settlement provided for, among other things, rates designed to generate revenues on an annual basis above the base rates which were in effect as of October 31, 2003, as follows: $48 million for the period November 1, 2003 through October 31, 2004, $53 million for the period November 1, 2004 through October 31, 2005, $58 million for the period November 1, 2005 through October 31, 2006, and $62 million beginning November 1, 2006. Northern Natural Gas provided refunds including interest of $71.5 million to its customers in the third quarter of 2005 consistent with the terms of the Settlement, generally reflecting the difference between the rate increases implemented on November 1, 2003 and November 1, 2004 and the revenue generated using the Settlement rates.

In April 2004, Northern Natural Gas also filed tariff sheets with the FERC in relation to its system levelized account (“SLA”) (an imbalance recovery mechanism) with the new rates going into effect on June 1, 2004, subject to refund. On February 14, 2005, Northern Natural Gas received FERC approval of the SLA settlement. The SLA settlement provides for recovery of the final SLA balance as of December 31, 2004, over a forty-eight month period beginning November 1, 2003. Under the SLA settlement, Northern Natural Gas is responsible for the financial impacts of managing operational storage volumes.

CE Electric UK

Most of the revenue of the DLHs in Great Britain is controlled by a distribution price control formula which is set out in the license of each DLH. It has been the practice of Ofgem (and its predecessor body, the Office of Electricity Regulation), to review and reset the formula at five-year intervals, although the formula has been, and may be, further reviewed at other times at the discretion of the regulator. Any such resetting of the formula requires the consent of the DLH. If the DLH does not consent to the formula reset, it is reviewed by the British competition commission, whose recommendations can then be given effect by license modifications made by Ofgem.

The current formula requires that regulated distribution income per unit is increased or decreased each year by RPI-Xd where RPI means the Retail Prices Index, reflecting the average of the 12-month inflation rates recorded for each month in the previous July to December period. The Xd factor in the formula was established by Ofgem at the price control review effective in April 2005 (and through March 31, 2010, is expected to continue to be set) at 0%. The formula also takes account of a variety of other factors including the changes in system electrical losses, the number of customers connected and the voltage at which customers receive the units of electricity distributed. The distribution price control formula determines the maximum average price per unit of electricity distributed (in pence per kWh) which a DLH is entitled to charge. The distribution price control formula permits DLHs to receive additional revenue due to increased distribution of units and the increase in the number of end users. The price control does not seek to constrain the profits of a DLH from year to year. It is a control on revenue that operates independently of most of the DLH’s costs. During the term of the price control, cost savings or additional costs have a direct impact on income and cash flow.

The procedure and methodology adopted at a price control review are at the reasonable discretion of Ofgem. Generally, Ofgem’s judgment of the future allowed revenue of licensees has been based upon, among other things:

the actual operating costs of each of the licensees;

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

·	the taxes that each licensee is expected to pay;

the regulatory value to be ascribed to each of the licensees’ distribution network assets;

the allowance for depreciation of the distribution network assets of each of the licensees;

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

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

As a result of the review concluded in 2004, the allowed revenue of Northern Electric’s distribution business was reduced by 4%, in real terms, and the allowed revenue of Yorkshire Electricity’s distribution business was reduced by 9%, in real terms, with effect from April 1, 2005. Ofgem indicated that during the period 2005 to 2010, the retention of the benefits of any out-performance from the operating cost assumptions made by Ofgem 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.

The triennial process of valuing the UK pension plan’s assets and liabilities, which valued the plan assets and liabilities as of March 31, 2004, was completed in 2005. This valuation set a revised level of contributions for the next three years. The report of the actuaries conducting the valuation showed a funding deficiency of £190.3 million. Based on this valuation, CE Electric UK will contribute £23.1 million to the pension plan each year in respect of the existing funding deficiency. The amount in respect of the funding deficiency has been calculated based on eliminating the funding deficiency over 12 years commencing April 1, 2005. In setting the allowed revenue of Northern Electric and Yorkshire Electricity (and all other DLHs) with effect from April 1, 2005, Ofgem made a specific allowance for an amount in respect of each DLH’s pension costs, which reflects recovery of a significant portion of the deficiency payments.

With effect from April 1, 2005, a number of incentive schemes operate to encourage DLHs to provide an appropriate quality of service. Payments in respect of each failure to meet a prescribed standard of service are set out in regulations. The aggregate of payments that may be due is uncapped, although payments are excused in certain force majeure circumstances. In storm conditions the obligations relating to the period within which supplies should be restored are relaxed and the overall, annual exposure under the restoration standard in storm conditions is limited to 2% of a DLH’s allowed revenue. There also is a discretionary reward scheme of up to £1 million per annum, and other incentive schemes pursuant to which a DLH’s allowed revenue may increase by up to 3.3% or decrease by up to 3.5% in any year.

20.

Commitments and Contingencies

MidAmerican Energy, Kern River, Northern Natural Gas, CE Electric UK, CalEnergy Generation-Domestic and HomeServices have non-cancelable operating leases primarily for computer equipment, office space and rail cars. Rental payments on non-cancelable operating leases totaled $77.4 million for 2005, $71.1 million for 2004, and $65.8 million for 2003. The minimum payments under these leases are $74.8 million, $67.8 million, $57.0 million, $45.7 million, and $35.3 million for the years 2006 through 2010, respectively, and $96.2 million for the total of the years thereafter.

MidAmerican Energy

Fuel and Energy Commitments

MidAmerican Energy has coal supply and related transportation contracts for its fossil-fueled generating stations. As of December 31, 2005, the contracts, with expiration dates ranging from 2006 to 2010, require minimum payments of $87.4 million, $70.0 million, $35.6 million, $35.2 million and $16.1 million for the years 2006 through 2010, respectively. MidAmerican Energy expects to supplement these coal contracts with additional contracts and spot market purchases to fulfill its future fossil fuel needs. Additionally, MidAmerican Energy has a transportation contract for a natural gas-fired generating plant. The contract, which expires in 2012, requires minimum annual payments of $6.0 million.

MidAmerican Energy also has contracts to purchase electric capacity. As of December 31, 2005, the contracts, with expiration dates ranging from 2006 to 2028, require minimum payments of $26.2 million, $27.5 million, $35.7 million, $28.9 million and $9.4 million for the years 2006 through 2010, respectively, and $165.3 million for the total of the years thereafter.

MidAmerican Energy has various natural gas supply and transportation contracts for its gas operations. As of December 31, 2005, the contracts, with expiration dates ranging from 2006 to 2017, require minimum payments of $61.5 million, $51.0 million, $16.7 million, $10.9 million and $5.7 million for the years 2006 through 2010, respectively, and $16.9 million for the total of the years thereafter.

MidAmerican Energy is the lessee on operating leases for coal railcars that contain guarantees of the residual value of such equipment throughout the term of the leases. Events triggering the residual guarantees include termination of the lease, loss of the equipment or purchase of the equipment. Lease terms are for five years with provisions for extensions. As of December 31, 2005, the maximum amount of such guarantees specified in these leases totaled $29.4 million. These guarantees are not reflected in the accompanying consolidated balance sheets.

On February 12, 2003, MidAmerican Energy executed a contract with Mitsui & Co. Energy Development, Inc. (“Mitsui”) for engineering, procurement and construction of a 790 MW (based on expected accreditation) coal-fired generating plant expected to be completed in the summer of 2007. MidAmerican Energy currently holds a 60.67% individual ownership interest as a tenant in common with the other owners of the plant. Under the contract, MidAmerican Energy is allowed to defer payments, including the other owners’ shares, for up to $200.0 million of billed construction costs through the end of the project. Deferred payments as of December 31, 2005 and 2004, totaled $200.0 million and $152.3 million, respectively, and are reflected in other long-term accrued liabilities in the accompanying consolidated balance sheets.

An asset representing the other owners’ share of the deferred payments is reflected in deferred charges and other assets in the accompanying consolidated balance sheets and totaled $78.7 million and $59.9 million, respectively, as of December 31, 2005 and 2004. MidAmerican Energy will bill each of the other owners for its share of the deferred payments when payment is made to Mitsui.

Air Quality

The EPA has in recent years implemented more stringent national ambient air quality standards for ozone and new standards for fine particulate matter. These standards set the minimum level of air quality that must be met throughout the United States. Areas that achieve the standards, as determined by ambient air quality monitoring, are characterized as being in attainment of the standard. Areas that fail to meet the standard are designated as being nonattainment areas. Generally, once an area has been designated as a nonattainment area, sources of emissions that contribute to the failure to achieve the ambient air quality standards are required to make emissions reductions. The EPA has concluded that the entire state of Iowa, where MidAmerican Energy’s major emission sources are located, is in attainment of the ozone standards and the fine particulate matter standards.

On December 20, 2005, the EPA proposed strengthening the ambient air quality standard for fine particulates, suggesting a range of prospective new levels for fine particulate matter and suggesting maintaining the annual standard at the current level while reducing the 24-hour standard. The EPA established a 90-day public comment period on its plan, which closes on April 17, 2006, and final rules are anticipated to be issued in September 2006 . Until the public comment period closes and the EPA takes final action on the proposal, the impact of the proposed rules on MidAmerican Energy cannot be determined.

On March 10, 2005, the EPA released the final Clean Air Interstate Rule (“CAIR”), calling for reductions of sulfur dioxide (“SO ₂ ”) and nitrogen oxides (“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 is implementing rules that exercise the option of the market-based cap and trade system. While the state of Iowa has been determined to be in attainment of the 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 final CAIR, the first phase reductions of SO ₂ emissions are effective on January 1, 2010, with the second phase reductions effective January 1, 2015. For NO _x , the first phase emissions reductions are effective January 1, 2009, and the second phase reductions are effective January 1, 2015. The CAIR calls for overall reductions of SO ₂ and NO _x in Iowa of 68% and 67%, respectively, by 2015. The CAIR will impact the operation of MidAmerican Energy’s generating facilities and will require MidAmerican Energy to either reduce emissions from those facilities through the installation of emission controls or purchase additional emission allowances, or some combination thereof.

On March 15, 2005, the EPA released the final Clean Air Mercury Rule (“CAMR”). The CAMR utilizes a market-based cap and trade mechanism to reduce mercury emissions from coal-burning power plants from the current nationwide level of 48 tons to 15 tons at full implementation. The CAMR’s two-phase reduction program requires initial reductions of mercury emission in 2010 and an overall reduction in mercury emissions from coal-burning power plants of 70% by 2018. The CAMR will impact MidAmerican Energy’s coal-burning generating facilities and will require MidAmerican Energy to either reduce emissions from those facilities through the installation of emission controls or purchase additional emission allowances, or some combination thereof.

The CAIR or the CAMR could, in whole or in part, be superseded or made more stringent by one of a number of multi-pollutant emission reduction proposals currently under consideration at the federal level, including pending legislative proposals that contemplate 70% to 90% reductions of SO2, NOX and mercury, as well as possible new federal regulation of carbon dioxide and other gases that may affect global climate change. In addition to any federal legislation that could be enacted by Congress to supersede the CAIR and the CAMR, the rules could be changed or overturned as a result of litigation. The sufficiency of the standards established by both the CAIR and the CAMR has been legally challenged in the United States District Court for the District of Columbia. Until the court makes a determination regarding the merits of the challenges to the CAIR and the CAMR, the full impact of the rules on MidAmerican Energy cannot be determined.

MidAmerican Energy has implemented a planning process that forecasts the site-specific controls and actions that may be required to meet emissions reductions as promulgated by the EPA. In accordance with an Iowa law passed in 2001, MidAmerican Energy has on file with the IUB its current multi-year plan and budget for managing SO2 and NOX from its generating facilities in a cost-effective manner. The plan, which is required to be updated every two years, provides specific actions to be taken at each coal-fired generating facility and the related costs and timing for each action. On July 17, 2003, the IUB issued an order that affirmed an administrative law judge’s approval of the initial plan filed on April 1, 2002, as amended. On October 4, 2004, the IUB issued an order approving MidAmerican Energy’s second biennial plan as revised in a settlement MidAmerican Energy entered into with the OCA. That plan covers the time period from April 1, 2004 through December 31, 2006. Neither IUB order resulted in any changes to electric rates for MidAmerican Energy. The effect of the orders is to approve the prudence of expenditures made consistent with the plans. Pursuant to an unrelated rate settlement agreement approved by the IUB on October 17, 2003, if, prior to January 1, 2011, capital and operating expenditures to comply with environmental requirements cumulatively exceed $325 million, then MidAmerican Energy may seek to recover the additional expenditures from customers.

Under the existing New Source Review (“NSR”) provisions of the Clean Air Act, a utility 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 facility that potentially increases 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.

In recent years, the EPA has requested from several utilities information and supporting documentation regarding their capital projects for various generating plants. The requests were issued as part of an industry-wide investigation to assess compliance with the NSR and the New Source Performance Standards of the Clean Air Act. In December 2002 and April 2003, MidAmerican Energy received requests from the EPA to provide documentation related to its capital projects from January 1, 1980, to April 2003 for a number of its generating plants. MidAmerican Energy has submitted information to the EPA in responses to these requests, and there are currently no outstanding data requests pending from the EPA. MidAmerican Energy cannot predict the outcome of these requests at this time.

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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, until such time as the legal challenges are resolved and the rules are effective, MidAmerican Energy will continue to manage projects at its generating plants in accordance with the rules in effect prior to 2002. On June 24, 2005, the Washington D.C. Circuit Court upheld portions of the EPA’s 2002 NSR rule but invalidated other portions. On October 13, 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 modifications to existing power plants and opened a public comment period, which ended on February 17, 2006. The impact of these proposed changes on MidAmerican Energy cannot be determined until after the rule is finalized and implemented.

Nuclear Decommissioning Costs

Expected nuclear decommissioning costs for Quad Cities Station have been developed based on a site-specific decommissioning study that includes decontamination, dismantling, site restoration, dry fuel storage cost and an assumed shutdown date. Quad Cities Station nuclear decommissioning costs are included in base rates in Iowa tariffs.

MidAmerican Energy’s share of estimated decommissioning costs for Quad Cities Station as of December 31, 2005, was $163.0 million and is the ARO liability for Quad Cities Station. MidAmerican Energy has established trusts for the investment of funds for decommissioning the Quad Cities Station. The fair value of the assets held in the trusts was $228.1 million at December 31, 2005 and is reflected in other investments in the accompanying consolidated balance sheets.

Nuclear Insurance

MidAmerican Energy maintains financial protection against catastrophic loss associated with its interest in Quad Cities Station through a combination of insurance purchased by Exelon Generation Company, LLC (“Exelon Generation”) (the operator and joint owner of 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. The general types of coverage are: nuclear liability, property coverage and nuclear worker liability.

Exelon Generation purchases private market nuclear liability insurance for Quad Cities Station in the maximum available amount of $300.0 million, which includes coverage for MidAmerican Energy’s ownership. In accordance with the Price-Anderson Amendments Act of 1988, as amended and extended by the Energy Policy Act, excess liability protection above that amount is provided by a mandatory industry-wide Secondary Financial Protection program under which the licensees of nuclear generating facilities could be assessed for liability incurred due to a serious nuclear incident at any commercial nuclear reactor in the United States. Currently, MidAmerican Energy’s aggregate maximum potential share of an assessment for Quad Cities Station is approximately $50.3 million per incident, payable in installments not to exceed $7.5 million annually.

The property insurance covers property damage, stabilization and decontamination of the facility, disposal of the decontaminated material and premature decommissioning arising out of a covered loss. For Quad Cities Station, Exelon Generation purchases primary and excess property insurance protection for the combined interests in Quad Cities Station, with coverage limits totaling $2.1 billion. MidAmerican Energy also directly purchases extra expense coverage for its share of replacement power and other extra expenses in the event of a covered accidental outage at Quad Cities Station. The property and related coverages purchased directly by MidAmerican Energy and by Exelon Generation, which includes the interests of MidAmerican Energy, are underwritten by an industry mutual insurance company and contain provisions for retrospective premium assessments should two or more full policy-limit losses occur in one policy year. Currently, the maximum retrospective amounts that could be assessed against MidAmerican Energy from industry mutual policies for its obligations associated with Quad Cities Station total $9.0 million.

The master nuclear worker liability coverage, which is purchased by Exelon Generation for Quad Cities Station, is an industry-wide guaranteed-cost policy with an aggregate limit of $300 million for the nuclear industry as a whole, which is in effect to cover tort claims of workers in nuclear-related industries.

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Legal Matters

CalEnergy Generation-Foreign

Pursuant to the share ownership adjustment mechanism in the CE Casecnan stockholder agreement, which is based upon pro forma 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 stockholder 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., KEIL Casecnan Ltd. (“KE”), a former stockholder, 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 On January 21, 2004, CE Casecnan Ltd., LPG and CE Casecnan entered into a status quo agreement pursuant to which the parties agreed to set aside certain distributions related to the shares subject to the LPG dispute and CE Casecnan agreed not to take any further actions with respect to such distributions without at least 15 days prior notice to LPG. Accordingly, 15% of the CE Casecnan dividend distributions declared in 2004 and 2005, totaling $17.6 million, was set aside in a separate bank account in the name of CE Casecnan and is shown as restricted cash and short-term investments and other current liabilities in the accompanying consolidated balance sheets.

21.

Pension and Postretirement Commitments

Domestic Operations

MidAmerican Energy sponsors a noncontributory defined benefit pension plan covering substantially all employees of MEHC and its domestic energy subsidiaries. Benefit obligations under the plan are based on a cash balance arrangement for salaried employees and certain union employees and final average pay formulas for most union employees. Funding to the established trust is based upon the actuarially determined costs of the plan and the requirements of the Internal Revenue Code and the Employee Retirement Income Security Act. The Company also maintains noncontributory, nonqualified defined benefit supplemental executive retirement plans for active and retired participants.

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MidAmerican Energy also sponsors certain postretirement health care and life insurance benefits covering substantially all retired employees of MEHC and its domestic energy subsidiaries. Under the plans, covered employees may become eligible for these benefits if they reach retirement age while working for the Company. On July 1, 2004, the postretirement benefit plan was amended for non-union participants. As a result, non-union employees hired July 1, 2004, and after are no longer eligible for postretirement benefits other than pensions. The plan, as amended, establishes 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. The Company retains the right to change these benefits anytime, subject to provisions in its collective bargaining agreements.

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. Net periodic pension benefit cost, including supplemental retirement, and postretirement benefit cost included the following components for MEHC and its domestic energy subsidiaries for the years ended December 31:

	Pension Cost									Postretirement Cost
	2005			2004			2003			2005			2004			2003
	(in thousands)

Service cost	$	25,840		$	25,568		$	24,693		$	6,669		$	7,842		$	8,175
Interest cost		36,518			35,159			34,533			13,455			15,716			16,065
Expected return on plan assets		(38,188	)		(38,258	)		(38,396	)		(9,611	)		(8,437	)		(6,008	)
Amortization of net transition obligation		-			(792	)		(2,591	)		2,403			3,283			4,110
Amortization of prior service cost		2,766			2,758			2,761			-			296			593
Amortization of prior year (gain) loss		1,271			1,569			1,483			1,554			3,299			3,716
Regulatory expense		-			-			3,320			-			-			-
Net periodic benefit cost	$	28,207		$	26,004		$	25,803		$	14,470		$	21,999		$	26,651

Weighted-average assumptions used to determine benefit obligations at December 31:

	2005	2004	2003	2005	2004	2003
Discount rate	5.75%	5.75%	5.75%	5.75%	5.75%	5.75%
Rate of compensation increase	5.00%	5.00%	5.00%	Not applicable

Weighted-average assumptions used to determine net benefit cost for the years ended December 31:

	2005	2004	2003	2005	2004	2003
Discount rate	5.75%	5.75%	5.75%	5.75%	5.75%	5.75%
Expected return on plan assets	7.00%	7.00%	7.00%	7.00%	7.00%	7.00%
Rate of compensation increase	5.00%	5.00%	5.00%	Not applicable

Assumed health care cost trend rates at December 31:

	2005	2004
Health care cost trend rate assumed for next year	9.00%	10.00%
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	2010	2010

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Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plans. A one-percentage-point change in assumed health care cost trend rates would have the following effects (in thousands):

	Increase (Decrease) in Expense
	One Percentage-		One Percentage-
	Point Increase		Point Decrease
Effect on total service and interest cost	$	2,418	$	(1,891	)
Effect on postretirement benefit obligation	$	26,434	$	(21,350	)

The following table presents a reconciliation of the beginning and ending balances of the benefit obligation, fair value of plan assets and the funded status of the aforementioned plans to the net amounts measured and recognized in the accompanying consolidated balance sheets as of December 31 (in thousands):

	Pension Benefits						Postretirement Benefits
	2005			2004			2005			2004
Reconciliation of the fair value of plan assets:
Fair value of plan assets at beginning of year	$	591,628		$	551,568		$	179,375		$	157,849
Employer contributions		5,786			5,083			16,615			23,782
Participant contributions		-			-			9,096			7,733
Actual return on plan assets		46,966			63,151			5,958			9,698
Benefits paid		(31,551	)		(28,174	)		(20,144	)		(19,687	)
Fair value of plan assets at end of year		612,829			591,628			190,900			179,375

Reconciliation of benefit obligation:
Benefit obligation at beginning of year		657,406			620,048			256,044			297,433
Service cost		25,840			25,568			6,669			7,841
Interest cost		36,518			35,159			13,455			15,716
Participant contributions		-			-			9,096			7,733
Plan amendments		(3,184	)		-			(421	)		(19,219	)
Actuarial (gain) loss		(6,917	)		4,805			(15,141	)		(33,773	)
Benefits paid		(31,551	)		(28,174	)		(20,144	)		(19,687	)
Benefit obligation at end of year		678,112			657,406			249,558			256,044

Funded status		(65,283	)		(65,778	)		(58,658	)		(76,669	)
Amounts not recognized in consolidated balance sheets:
Unrecognized net (gain) loss		(51,285	)		(34,319	)		29,725			42,768
Unrecognized prior service cost		9,207			15,157			-			-
Unrecognized net transition obligation (asset)		-			-			16,820			19,641
Net amount recognized in the consolidated balance sheets	$	(107,361	)	$	(84,940	)	$	(12,113	)	$	(14,260	)

Net amount recognized in the consolidated balandce sheets consists of:
Accrued benefit liability	$	(135,506	)	$	(117,357	)	$	(12,113	)	$	(14,260	)
Intangible assets		11,939			14,653			-			-
Regulatory assets		11,694			17,764			-			-
Accumulated other comprehensive income		4,512			-			-			-
Net amount recognized	$	(107,361	)	$	(84,940	)	$	(12,113	)	$	(14,260	)

The portion of the pension projected benefit obligation, included in the table above, related to the supplemental executive retirement plan was $105.7 million and $106.5 million as of December 31, 2005 and 2004, respectively. The supplemental executive retirement plan has no assets, and accordingly, the fair value of its plan assets was zero as of December 31, 2005 and 2004. The accumulated benefit obligation for all defined benefit pension plans was $608.4 million and $585.4 million at December 31, 2005 and 2004, respectively. Of these amounts, the supplemental executive retirement plan accumulated benefit obligation totaled $102.2 million and $102.3 million for 2005 and 2004, respectively.

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Although the supplemental executive retirement plan had no assets as of December 31, 2005, the Company has Rabbi trusts that hold corporate-owned life insurance and other investments to provide funding for the future cash requirements. Because this plan is nonqualified, the assets in the Rabbi trusts are not considered plan assets. The cash surrender value of the policies included in the Rabbi trusts plus the fair market value of other Rabbi trust investments was $102.9 million and $98.8 million at December 31, 2005 and 2004, respectively.

Plan Assets

The Company’s investment policy for its domestic pension and postretirement plans is to balance risk and return through a diversified portfolio of high-quality equity and fixed income securities. Equity targets for the pension and 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 the Company’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.

The Company’s pension plan asset allocations at December 31, 2005 and 2004 are as follows:

	Percentage of
	Plan Assets
	at December 31		Target
	2005	2004	Range
Asset Category
Equity securities	66%	71%	65-75%
Debt securities	26%	22%	20-30%
Real estate	6%	6%	0-10%
Other	2 %	1 %	0-5%
Total	100 %	100 %

The Company’s postretirement benefit plan asset allocations at December 31, 2005 and 2004 are as follows:

	Percentage of
	Plan Assets
	at December 31		Target
	2005	2004	Range
Asset Category
Equity securities	50%	49%	45-55%
Debt securities	48%	47%	45-55%
Other	2 %	4 %	0-10%
Total	100 %	100 %

Cash Flows

The Company’s expected benefit payments to participants for its pension and postretirement plans for 2006 through 2010 and for the five years thereafter are summarized below (in thousands):

			Postretirement Benefits
	Pension Benefits		Gross		Medicare Subsidy		Net of Subsidy

2006	$	32,545	$	14,054	$	2,350	$	11,704
2007		34,771		15,336		2,533		12,803
2008		37,347		16,434		2,719		13,715
2009		41,125		17,419		2,888		14,531
2010		45,030		18,525		3,032		15,493
2011-2015		275,118		107,131		17,728		89,403

105

Employer contributions to the domestic pension and postretirement plans are currently expected to be $6.7 million and $14.5 million, respectively, for 2006. The Company’s policy is to contribute the minimum required amount to the pension plan and the amount expensed to its postretirement plans.

The Company sponsors defined contribution pension plans (401(k) plans) covering substantially all domestic 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. The Company’s total contributions were $17.3 million, $17.1 million and $15.5 million for 2005, 2004 and 2003, respectively.

In December 2003, the President signed into law the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (“Medicare Act”). The Medicare Act introduces a prescription drug benefit under Medicare as well as a subsidy to sponsors of retiree health care plans that provide a benefit to participants that is at least actuarially equivalent to Medicare Part D. Detailed regulations pertaining to the Medicare Act were promulgated in 2004 resulting in a $23.8 million subsidy to the Company to be used for any valid business purpose. The subsidy is reflected as an actuarial gain in benefit obligation in 2004 in the table above. The impact of the Medicare Act on the net periodic postretirement benefit expense is reflected in 2005.

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 substantially all employees of CE Electric UK’s certain wholly-owned subsidiaries.

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. Net periodic pension benefit cost included the following components for CE Electric UK for the years ended December 31:

	2005			2004			2003
Service cost	$	15,292		$	12,100		$	9,485
Interest cost		76,460			73,515			62,632
Expected return on plan assets		(96,849	)		(98,448	)		(89,124	)
Amortization of prior service cost		1,890			1,915			1,472
Amortization of loss		22,761			12,742			537
Net periodic expense (benefit)	$	19,554		$	1,824		$	(14,998	)

Weighted-average assumptions used to determine benefit obligations at December 31:

	2005	2004	2003
Discount rate	4.75%	5.25%	5.50%
Rate of compensation increase	2.75%	2.75%	2.75%

Weighted-average assumptions used to determine net benefit cost for years ended December 31:

	2005	2004	2003
Discount rate	5.25%	5.50%	5.75%
Expected return on plan assets	7.00%	7.00%	7.00%
Rate of compensation increase	2.75%	2.75%	2.50%

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The following table presents a reconciliation of the beginning and ending balances of the benefit obligation, fair value of plan assets and the funded status of the UK Plan to the net amounts measured and recognized in the accompanying consolidated balance sheets as of December 31 (in thousands):

	2005			2004
Reconciliation of the fair value of plan assets:
Fair value of plan assets at beginning of year	$	1,364,722		$	1,206,216
Employer contributions		55,663			17,600
Participant contributions		6,190			6,417
Actual return on plan assets		211,723			106,515
Benefits paid		(67,176	)		(65,265	)
Foreign currency exchange rate changes		(151,559	)		93,239
Fair value of plan assets at end of year		1,419,563			1,364,722

Reconciliation of benefit obligation:
Benefit obligation at beginning of year		1,571,579			1,334,587
Service cost		15,292			12,100
Interest cost		76,460			73,515
Participant contributions		6,190			6,417
Benefits paid		(67,176	)		(65,265	)
Experience loss and change of assumptions		127,617			104,315
Foreign currency exchange rate changes		(170,645	)		105,910
Benefit obligation at end of year		1,559,317			1,571,579

Funded status		(139,754	)		(206,857	)
Unrecognized net loss		561,050			614,182
Net amount recognized in the consolidated balance sheets	$	421,296		$	407,325

Amounts recognized in the consolidated balance sheets consist of:
Prepaid benefit cost	$	421,296		$	407,325
Accrued benefit liability		(492,550	)		(561,988	)
Intangible assets		12,908			16,119
Accumulated other comprehensive income		479,642			545,869
Net amount recognized	$	421,296		$	407,325

The accumulated benefit obligation for the defined benefit pension plan was $1.5 billion at December 31, 2005 and 2004, respectively.

The Company recorded a minimum pension liability as of December 31, 2005 and 2004 in the amount of $479.6 million and $545.9 million, respectively. The pension liability is primarily due to the decline in market value of the pension plan assets during 2002 combined with the effects of lower discount rates and higher rates of compensation increases used to value the plan’s liabilities in 2005 and 2004, as well as, mortality assumption changes which increased the liability. As of December 31, 2005 and 2004, the minimum pension liability is measured as the amount of the plan’s accumulated benefit obligation that is in excess of the plan’s market value of assets at December 31, 2005 and 2004 plus the prepaid asset balance. A charge equal to the excess was recorded to the Company’s stockholders’ equity, net of income tax benefits, as a component of comprehensive loss in the amount of $(46.4) million and $46.4 million in 2005 and 2004, respectively. This adjustment does not impact current year earnings, or the funding requirements of the plan.

Plan Assets

CE Electric UK’s investment policy for its pension and postretirement plans is to balance risk and return through a diversified portfolio of high-quality equity and fixed income securities. Maturities for fixed income securities are managed such that sufficient liquidity exists to meet near-term benefit payment obligations. The plans retain outside investment advisors to manage plan investments within the parameters outlined by the Benefits Committee of subsidiaries of CE Electric UK. The weighted average return on assets assumption is based on historical performance for the types of assets in which the plans invest.

107

CE Electric UK’s pension plan asset allocation consists of the following at December 31:

	Percentage of
	Plan Assets
	at December 31 ,
	2005	2004	Target
Asset Category
Equity securities	51%	49%	50%
Debt securities	37%	39%	40%
Real estate	11%	11%	10%
Other	1 %	1 %	-%
Total	100 %	100 %	100 %

Cash Flows

CE Electric UK's expected benefit payments relative to the UK Plan for 2006 through 2010 and for the five years thereafter are summarized below (in millions):

2006	$	66.2
2007		67.1
2008		67.7
2009		70.2
2010		70.7
2011-2015		378.9

The triennial process of valuing the UK Plan's assets and liabilities, which valued the plan assets and liabilities as of March 31, 2004, was completed in 2005. This valuation set a revised level of contributions for the next three years. The report of the actuaries conducting the valuation showed a funding deficiency of £190.3 million. Based on this valuation, CE Electric UK will contribute £23.1 million to the UK Plan each year in respect of the existing funding deficiency. The amount in respect of the funding deficiency has been calculated based on eliminating the funding deficiency over 12 years commencing April 1, 2005. Employer contributions to the UK Plan for the year ended December 31, 2005 totaled $55.7 million and consisted of $24.6 million to fund ongoing liabilities and $31.1 million in respect of the existing funding deficiency. Employer contributions to the UK Plan, including the £23.1 million deficiency funding, are currently expected to be £35.0 million for 2006.

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22.

Segment Information

The Company has identified seven reportable segments: MidAmerican Energy, Kern River, Northern Natural Gas, CE Electric UK, CalEnergy Generation-Foreign, CalEnergy Generation-Domestic and HomeServices. The Company’s determination of reportable segments considers the strategic units under which the Company is 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. The reportable segment financial information includes all necessary adjustments and eliminations needed to conform to the Company’s significant accounting policies including the allocation of goodwill. Additionally, the activity of the Company’s Mineral Assets, which was previously reported in the CalEnergy Generation-Domestic reportable segment, is presented as discontinued operations within the accompanying consolidated financial statements. Information related to the Company’s reportable segments is shown below (in thousands):

	Year Ended December 31,
	2005			2004			2003
Operating revenue:
MidAmerican Energy	$	3,166,084		$	2,701,700		$	2,600,239
Kern River		323,561			316,131			260,182
Northern Natural Gas		569,055			544,822			486,878
CE Electric UK		884,115			936,364			829,993
CalEnergy Generation-Foreign		312,346			307,395			326,454
CalEnergy Generation-Domestic		33,825			38,960			45,154
HomeServices		1,868,495			1,756,454			1,476,569
Total reportable segments		7,157,481			6,601,826			6,025,469
Corporate/other ⁽¹⁾		(41,942	)		(48,438	)		(59,839	)
Total operating revenue	$	7,115,539		$	6,553,388		$	5,965,630

Depreciation and amortization:
MidAmerican Energy	$	269,142		$	266,409		$	281,001
Kern River		62,365			53,250			36,771
Northern Natural Gas		30,351			67,913			52,716
CE Electric UK		135,731			137,746			125,000
CalEnergy Generation-Foreign		90,391			90,328			87,928
CalEnergy Generation-Domestic		8,748			8,721			8,882
HomeServices		17,774			20,827			17,560
Total reportable segments		614,502			645,194			609,858
Corporate/other ⁽¹⁾		(6,304	)		(6,985	)		(6,924	)
Total depreciation and amortization	$	608,198		$	638,209		$	602,934

Interest expense:
MidAmerican Energy	$	137,658		$	125,189		$	123,395
Kern River		73,158			76,671			79,272
Northern Natural Gas		52,590			53,100			56,008
CE Electric UK		217,909			202,067			180,207
CalEnergy Generation-Foreign		31,302			42,696			59,603
CalEnergy Generation-Domestic		18,266			18,971			19,736
HomeServices		2,442			2,837			3,864
Total reportable segments		533,325			521,531			522,085
Corporate/other ⁽¹⁾		173,210			184,811			189,083
Parent company subordinated debt ⁽²⁾		184,444			196,875			49,788
Total interest expense	$	890,979		$	903,217		$	760,956

109

	Year Ended December 31,
	2005			2004			2003
Operating income:
MidAmerican Energy	$	381,084		$	355,947		$	367,868
Kern River		204,488			204,776			180,978
Northern Natural Gas		208,848			190,337			175,770
CE Electric UK		483,935			497,358			445,803
CalEnergy Generation-Foreign		184,986			188,529			197,527
CalEnergy Generation-Domestic		15,059			21,468			21,403
HomeServices		125,321			112,928			92,874
Total reportable segments		1,603,721			1,571,343			1,482,223
Corporate/other ⁽¹⁾		(75,039	)		(45,942	)		(32,408	)
Total operating income		1,528,682			1,525,401			1,449,815
Interest expense		(890,979	)		(903,217	)		(760,956	)
Capitalized interest		16,716			20,040			30,494
Interest and dividend income		58,070			38,889			47,908
Other income		74,516			128,205			96,643
Other expense		(22,127	)		(10,125	)		(5,913	)
Total income from continuing operations before income tax expense, minority interest and preferred dividends of subsidiaries and equity income	$	764,878		$	799,193		$	857,991

Income tax expense:
MidAmerican Energy	$	91,371		$	87,336		$	110,078
Kern River		50,421			54,148			51,319
Northern Natural Gas		70,549			84,423			50,599
CE Electric UK		92,766			80,211			91,539
CalEnergy Generation-Foreign		55,855			62,548			62,130
CalEnergy Generation-Domestic		(995	)		1,217			1,078
HomeServices		56,359			52,996			43,587
Total reportable segments		416,326			422,879			410,330
Corporate/other ⁽¹⁾		(171,617	)		(157,893	)		(140,054	)
Total income tax expense	$	244,709		$	264,986		$	270,276

Capital expenditures:
MidAmerican Energy	$	700,954		$	633,807		$	346,449
Kern River		7,367			26,936			433,125
Northern Natural Gas		124,739			138,747			104,400
CE Electric UK		342,585			334,458			301,896
CalEnergy Generation-Foreign		562			4,633			8,497
CalEnergy Generation-Domestic		574			1,341			6,619
HomeServices		18,874			20,786			18,311
Total reportable segments		1,195,655			1,160,708			1,219,297
Corporate/other ⁽¹⁾		582			18,682			71
Total capital expenditures	$	1,196,237		$	1,179,390		$	1,219,368

110

	As of December 31,
	2005			2004			2003

Total assets:
MidAmerican Energy	$	8,003,423		$	7,274,999		$	6,596,849
Kern River		2,099,625			2,135,265			2,200,201
Northern Natural Gas		2,245,308			2,200,846			2,167,621
CE Electric UK		5,742,718			5,794,887			5,038,880
CalEnergy Generation-Foreign		643,130			767,465			951,155
CalEnergy Generation-Domestic		555,078			553,741			1,113,172
HomeServices		814,280			737,085			567,736
Total reportable segments		20,103,562			19,464,288			18,635,614
Corporate/other ⁽¹⁾		89,398			439,274			509,338
Total assets	$	20,192,960		$	19,903,562		$	19,144,952

Long-lived assets:
MidAmerican Energy	$	4,447,509		$	3,892,031		$	3,385,056
Kern River		1,891,027			1,945,094			1,976,213
Northern Natural Gas		1,585,029			1,491,428			1,430,475
CE Electric UK		3,501,218			3,691,459			3,227,723
CalEnergy Generation-Foreign		430,590			520,406			621,674
CalEnergy Generation-Domestic		241,701			256,429			738,296
HomeServices		62,292			59,827			53,518
Total reportable segments		12,159,366			11,856,674			11,432,955
Corporate/other ⁽¹⁾		(243,953	)		(249,410	)		(251,976	)
Total long-lived assets	$	11,915,413		$	11,607,264		$	11,180,979

(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, (ii) intersegment eliminations and (iii) fair value adjustments relating to acquisitions.

(2)	The Company adopted and applied the provisions of FIN 46R, related to certain finance subsidiaries, as of October 1, 2003. The adoption required the deconsolidation of certain finance subsidiaries, which resulted in amounts that were previously recorded as minority interest and preferred dividends of subsidiaries being prospectively recorded as interest expense in the accompanying consolidated statements of operations. For the years ended December 31, 2005 and 2004, and the three-month period ended December 31, 2003, the Company has recorded $184.4 million, $196.9 million and $49.8 million, respectively, of interest expense related to these securities. In accordance with the requirements of FIN 46R, no amounts prior to adoption of FIN 46R on October 1, 2003 have been reclassified. The amount included in minority interest and preferred dividends of subsidiaries related to these securities for the nine-month period ended September 30, 2003 was $170.2 million.

111

The following table shows the change in the carrying amount of goodwill by reportable segment for the years ended December 31, 2005 and 2004 (in thousands):

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

Balance, January 1, 2004	$	2,139,223		$	33,900	$	379,148		$	1,261,583		$	126,308		$	365,481		$	4,305,643
Goodwill from acquisitions during the year		-			-		-			-			-			32,120			32,120
Foreign currency translation adjustment		-			-		-			72,218			-			-			72,218
Impairment losses ⁽¹⁾		-			-		-			-			(52,776	)		-			(52,776	)
Other goodwill adjustments ⁽²⁾		(18,098	)		-		(24,236	)		(4,010	)		(1,038	)		(3,072	)		(50,454	)
Balance, December 31, 2004		2,121,125			33,900		354,912			1,329,791			72,494			394,529			4,306,751
Goodwill from acquisitions during the year		-			-		-			-			-			3,630			3,630
Foreign currency translation adjustment		-			-		-			(106,354	)		-			-			(106,354	)
Other goodwill adjustments ⁽²⁾		(3,489	)		-		(27,808	)		(16,229	)		(151	)		(170	)		(47,847	)
Balance, December 31, 2005	$	2,117,636		$	33,900	$	327,104		$	1,207,208		$	72,343		$	397,989		$	4,156,180

(1)	Impairment losses relate to the write-off of the Mineral Assets - see Note 17.

(2)	Other goodwill adjustments include primarily income tax adjustments.

112

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.

None.

Item 9A. Controls and Procedures.

An evaluation was performed under the supervision and with the participation of the Company’s management, including the chief executive officer and chief financial officer, regarding 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) as of December 31, 2005. Based on that evaluation, the Company’s management, including the chief executive officer and chief financial officer, concluded that the Company’s disclosure controls and procedures were effective. There have been no changes during the fourth quarter of 2005 in the Company’s internal control over financial reporting that has materially affected, or is reasonably likely to materially affect, the Company’s internal control over financial reporting.

Item 9B. Other Information.

Effective March 1, 2006, Messrs. W. David Scott, Edgar D. Aronson, John K. Boyer, Stanley J. Bright and Richard R. Jaros resigned from the Board of Directors of MEHC. Mr. Jaros was a member of MEHC’s Audit Committee.

On November 16, 2005, MEHC issued 200,000 shares of its common stock, no par value, to Mr. David L. Sokol, its Chairman and Chief Executive Officer, upon the exercise by Mr. Sokol of 200,000 of his outstanding common stock options. The common stock options were exercisable at a price of $29.01 per share and the aggregate exercise price paid by Mr. Sokol was $5.8 million. The issuance was pursuant to a private placement and was exempt from the registration requirements of the Securities Act of 1933, as amended.

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PART III

Item 10. Directors and Executive Officers of the Registrant.

MEHC’s management structure is organized functionally and the current executive officers and directors of MEHC and their positions are as follows:

Name	Position

David L. Sokol	Chairman of the Board of Directors and Chief Executive Officer
Gregory E. Abel	President, Chief Operating Officer and Director
Patrick J. Goodman	Senior Vice President and Chief Financial Officer
Douglas L. Anderson	Senior Vice President, General Counsel and Corporate Secretary
Maureen E. Sammon	Senior Vice President, Human Resources, Information Technology and Insurance
Keith D. Hartje	Senior Vice President, Communications, General Services and Safety Audit and Compliance
Warren E. Buffett	Director
Walter Scott Jr.	Director
Marc D. Hamburg	Director

Officers are elected annually by the Board of Directors. There are no family relationships among the executive officers, nor any arrangements or understanding between any officer and any other person pursuant to which the officer was appointed.

Set forth below is certain information, as of March 1, 2006, with respect to each of the foregoing officers and directors:

DAVID L. SOKOL, 49, Chairman of the Board of Directors and Chief Executive Officer. Mr. Sokol has been the Chief Executive Officer since April 19, 1993 and served as President of MEHC from April 19, 1993 until January 21, 1995. Mr. Sokol has been Chairman of the Board of Directors since May 1994 and a director since March 1991. Formerly, among other positions held in the independent power industry, Mr. Sokol served as President and Chief Executive Officer of Kiewit Energy Company, which at that time was a wholly owned subsidiary of Peter Kiewit & Sons’, Inc., and Ogden Projects, Inc.

GREGORY E. ABEL, 43, President, Chief Operating Officer and Director. Mr. Abel joined MEHC in 1992 and initially served as Vice President and Controller. Mr. Abel is a Chartered Accountant and from 1984 to 1992 was employed by PricewaterhouseCoopers. As a Manager in the San Francisco office of PricewaterhouseCoopers, he was responsible for clients in the energy industry.

PATRICK J. GOODMAN, 39, Senior Vice President and Chief Financial Officer. Mr. Goodman joined MEHC in 1995 and has served in various financial positions including Chief Accounting Officer. Prior to joining MEHC, Mr. Goodman was a financial manager for National Indemnity Company and a senior associate at PricewaterhouseCoopers.

DOUGLAS L. ANDERSON, 47, Senior Vice President, General Counsel and Corporate Secretary. Mr. Anderson joined MEHC in February 1993 and has served in various legal positions including General Counsel of the Company’s independent power affiliates. Prior to that, Mr. Anderson was a corporate attorney in private practice.

MAUREEN E. SAMMON, 42, Senior Vice President, Human Resources, Information Technology and Insurance. Ms. Sammon has been with MidAmerican Energy and its predecessor companies since 1986. In that time, she has held several positions, including Manager of Benefits and Vice President, Human Resources and Insurance.

KEITH D. HARTJE, 56, Senior Vice President, Communications, General Services and Safety Audit and Compliance. Mr. Hartje has been with MidAmerican Energy and its predecessor companies since 1973. In that time, he has held a number of positions, including General Counsel and Corporate Secretary, District Vice President for southwest Iowa operations, and Vice President, Corporate Communications.

WARREN E. BUFFETT, 75, Director. Mr. Buffett has been a director of MEHC since March 2000. He is Chairman of the Board and Chief Executive Office of Berkshire Hathaway. Mr. Buffett is a Director of the Coca Cola Company and The Washington Post Company.

114

WALTER SCOTT, JR., 74, Director. Mr. Scott has been a director of MEHC since June 1991. Mr. Scott was the Chairman and Chief Executive Officer of MEHC from January 8, 1992 until April 19, 1993. For more than five years, he has been Chairman of the Board of Directors of Level 3 Communications, Inc., a successor to certain businesses of Peter Kiewit & Sons’, Inc. Mr. Scott is a director of Peter Kiewit & Sons’, Inc., Berkshire Hathaway, Burlington Resources, Inc., Valmont Industries, Inc. and Commonwealth Telephone Enterprises, Inc.

MARC D. HAMBURG, 56, Director. Mr. Hamburg has been a director of MEHC since March 2000. He has served as Vice President - Chief Financial Officer of Berkshire Hathaway since October 1, 1992 and Treasurer since June 1, 1987, his date of employment with Berkshire Hathaway.

Audit Committee Members and Financial Experts

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. Mr. Hamburg is not independent within the meaning of Item 7(d)(3)(iv) of Schedule 14A under the Exchange Act.

Code of Ethics

MEHC has adopted a code of ethics that applies to its principal executive officer, its principal financial officer, its chief accounting officer and certain other covered officers. The code of ethics is filed as an exhibit to this annual report on Form 10-K.

Item 11. Executive Compensation.

The following table sets forth the compensation of MEHC’s Chief Executive Officer and its four other most highly compensated executive officers who were employed as of December 31, 2005, which MEHC refers to as its Named Executive Officers. Information is provided regarding its Named Executive Officers for the last three fiscal years during which they were its executive officers, if applicable.

Name and Principal Positions	Year Ended Dec. 31		Salary ⁽¹⁾		Bonus ⁽¹⁾		Other Annual Comp ⁽²⁾		LTIP Payouts		All Other Comp ⁽³⁾
David L. Sokol		2005	$	850,000	$	13,750,000	$	103,929	$	-	$	10,290
Chairman and Chief		2004		800,000		2,500,000		131,644		-		9,995
Executive Officer		2003		800,000		2,750,000		141,501		-		9,800

Gregory E. Abel		2005		740,000		13,450,000		-		-		10,290
President and		2004		720,000		2,200,000		80,424		-		9,995
Chief Operating Officer		2003		700,000		2,200,000		87,162		-		9,800

Patrick J. Goodman		2005		297,500		325,000		-		107,212		67,269
Senior Vice President and		2004		290,000		295,000		-		257,694		88,391
Chief Financial Officer		2003		275,000		285,000		-		-		108,631

Douglas L. Anderson		2005		275,000		265,000		-		87,769		60,456
Senior Vice President and		2004		270,000		240,000		-		151,585		77,145
General Counsel		2003		260,000		240,000		-		-		83,703

Maureen E. Sammon		2005		175,000		110,000		-		-		39,397
Senior Vice President, Human Resources,		2004		165,000		80,000		-		-		42,236
Information Technology and Insurance		2003		147,500		65,000		-		-		35,223

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______________

(1)	Includes amounts voluntarily deferred by the executive, if applicable. Pursuant to MEHC’s Executive Incremental Profit Sharing Plan, Messrs. Sokol and Abel each received a profit sharing award of $11.25 million based upon achieving the specified adjusted diluted earnings per share target for the year ended December 31, 2005. Messrs. Sokol and Abel are each eligible to receive additional profit sharing awards of $7.5 million or $26.25 million based upon achieving specified adjusted diluted earnings per share targets for any calendar year 2006 and 2007. In 2005, Messrs. Goodman and Anderson and Ms. Sammon each received a performance award related to the pending acquisition of PacifiCorp.

(2)	Consists of perquisites and other benefits if the aggregate amount of such benefits exceeds the lesser of either $50,000 or 10% of the total of salary and bonus reported for the Named Executive Officer. The amounts shown include the personal use of aircraft for 2005 for Mr. Sokol of $76,811.

(3)	Consists of the 2005 earnings on the MEHC Long-Term Incentive Partnership Plan (“LTIP”) awards not paid out in 2005 and 401(k) plan contributions. For 2005, LTIP earnings on awards not paid out in 2005 were $56,979 for Mr. Goodman, $50,166 for Mr. Anderson and $29,457 for Ms. Sammon. Messrs. Sokol and Abel are not participants in the LTIP. Additionally, the amounts shown include company 401(k) contributions for 2005 for Messrs. Sokol, Abel, Goodman and Anderson of $10,290 and for Ms. Sammon of $9,940.

Option Grants in Last Fiscal Year

MEHC did not grant any options during 2005.

Aggregated Option Exercises in Last Fiscal Year and Fiscal Year End Option Values

The following table sets forth the option exercises and the number of securities underlying exercisable and unexercisable options held by each of its Named Executive Officers at December 31, 2005.

	Shares Acquired		Value		Underlying Unexercised				Value of Unexercised
	On Exercise		Realized		Options Held (#)				In-the-money Options ($) ⁽¹⁾
Name	(#)		($)		Exercisable		Unexercisable		Exercisable		Unexercisable

David Sokol		200,000	$	16,798,740		1,199,277		-	$	134,652,051		N/A
Gregory E. Abel		-		-		649,052		-	$	76,518,336		N/A
Patrick J. Goodman		-		-		-		-		-		-
Douglas L. Anderson		-		-		-		-		-		-
Maureen E. Sammon		-		-		-		-		-		-

______________

(1)

On March 14, 2000, MEHC was acquired by a private investor group and on February 9, 2006, became a majority-owned subsidiary of Berkshire Hathaway. As a privately held company, MEHC has no publicly traded equity securities. The value shown is based on an assumed fair market value of the common stock of $145 per share as of December 31, 2005, as agreed to by MEHC stockholders.

116

Long-Term Incentive Plans - Awards in Last Fiscal Year

Number of Shares,

Performance or

Units or Other

Other Period Until

Threshold

Target

Maximum

Name

Rights (#)

Maturation or Payout

($) ⁽¹⁾

Patrick J. Goodman

N/A

December 31, 2009

446,250

N/A

Douglas L. Anderson

N/A

December 31, 2009

404,406

N/A

Maureen E. Sammon

N/A

December 31, 2009

262,500

N/A

______________

(1)

The awards shown in the foregoing table are made pursuant to the LTIP. The amounts shown are dollar amounts credited to an investment account for the benefit of the named executive officers and such amounts vest equally over five years (starting with year 2005) with any unvested balances forfeited upon termination of employment. Vested balances (including any investment performance profits or losses thereon) are paid to the participant at the time of termination. Once an award is fully vested, the participant may elect to defer or receive payment of part or the entire award. Awards are credited or reduced with annual interest or loss based on a composite of funds or indices. Because the amounts to be paid out may increase or decrease depending on investment performance, the ultimate benefits are undeterminable and the payouts do not have a “target” or “maximum” amount.

Compensation of Directors

Directors are not paid any fees for serving as directors. All directors are reimbursed for their expenses incurred in attending Board meetings.

Retirement Plans

The MidAmerican Energy Company Supplemental Retirement Plan for Designated Officers (the “SERP”), provides additional retirement benefits to designated participants, as determined by the Board of Directors. Messrs. Sokol, Abel and Goodman are participants in the SERP. The SERP provides annual retirement benefits up to sixty-five percent of a participant’s Total Cash Compensation in effect immediately prior to retirement, subject to a $1 million maximum retirement benefit. “Total Cash Compensation” means the highest amount payable to a participant as monthly base salary during the five years immediately prior to retirement multiplied by 12 plus the average of the participant’s last three years awards under an annual incentive bonus program and 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. Participants must be credited with five years of service to be eligible to receive benefits under the SERP. Each of the Messrs. Sokol, Abel and Goodman has five years of credited service with the Company and will be eligible to receive benefits under the SERP. A participant who elects early retirement is entitled to reduced benefits under the SERP, however, in accordance with their respective employment agreements, Messrs. Sokol and Abel are eligible to receive the maximum retirement benefit at age 47. 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, the Company maintains 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. The SERP benefit will be reduced by the amount of the participant’s regular retirement benefit under the MidAmerican Energy Company Cash Balance Retirement Plan (the “MidAmerican Retirement Plan”), which became effective January 1, 1997.

The MidAmerican Retirement Plan replaced retirement plans of predecessor companies that were structured as traditional, defined benefit plans. Under the MidAmerican Retirement Plan, each participant has an account, for record keeping purposes only, to which credits are allocated annually based upon a percentage of the participant’s salary paid in the plan year. In addition, all balances in the accounts of participants 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. At retirement, or other termination of employment, an amount equal to the vested balance then credited to the account is payable to the participant in the form of a lump sum or a form of annuity for the entire benefit under the MidAmerican Retirement Plan. The estimated annual benefit payable upon normal retirement age (65) for Mr. Anderson is $89,109 and for Ms. Sammon is $141,535. These estimates assume an interest credit rate of 6.0 percent and conversion to a life annuity using plan mortality and 6.0 percent interest. Mr. Anderson and Ms. Sammon are not participants in the SERP.

117

The table below shows the estimated aggregate combined annual benefits payable under the SERP and the MidAmerican Retirement Plan. The amounts exclude Social Security and are based on a straight life annuity and retirement at ages 55, 60 and 65. Federal law limits the amount of benefits payable to an individual through the tax qualified defined benefit and contribution plans, and benefits exceeding such limitation are payable under the SERP.

Total Cash	Estimated Annual Benefit
Compensation	Age of Retirement
at Retirement ($)	55		60		65

$ 400,000	$	220,000	$	240,000	$	260,000
500,000		275,000		300,000		325,000
600,000		330,000		360,000		390,000
700,000		385,000		420,000		455,000
800,000		440,000		480,000		520,000
900,000		495,000		540,000		585,000
1,000,000		550,000		600,000		650,000
1,250,000		687,500		750,000		812,500
1,500,000		825,000		900,000		975,000
1,750,000		962,500		1,000,000		1,000,000
2,000,000 and greater		1,000,000		1,000,000		1,000,000

Employment Agreements

Pursuant to his employment agreement, Mr. Sokol serves as Chairman of MEHC’s Board of Directors and Chief Executive Officer. The employment agreement provides that Mr. Sokol is to receive an annual base salary of not less than $750,000, senior executive employee benefits and annual bonus awards that shall not be less than $675,000. The agreement is currently scheduled to expire on August 21, 2006, but renews automatically from year to year subject to Mr. Sokol’s election to decline renewal at least 120 days prior to such date or termination by MEHC.

The employment agreement provides that MEHC may terminate the employment of Mr. Sokol with cause, in which case MEHC is to pay to him any accrued but unpaid salary and a bonus of not less than the minimum annual bonus, or due to death, permanent disability or other than for cause, including a change in control, in which case Mr. Sokol is entitled to receive an amount equal to three times the sum of his annual salary then in effect and the greater of his minimum annual bonus or his average annual bonus for the two preceding years, as well as three years of accelerated option vesting plus continuation of his senior executive employee benefits (or the economic equivalent thereof) for three years. If Mr. Sokol resigns, MEHC is to pay to him any accrued but unpaid 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.

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 salary plus an amount equal to the aggregate annual 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, (ii) the immediate vesting of all of his options, and (iii) the continuation of his senior executive employee benefits (or the economic equivalent thereof) through such fifth anniversary. 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 salary then in effect and the greater of his minimum annual bonus or his average annual bonus for the two preceding years, as well as two years of accelerated option vesting.

118

Under the terms of separate employment agreements with MEHC, each of Messrs. Abel and Goodman is entitled to receive two years base salary continuation, payments in respect of average bonuses for the prior two years and two years continued option vesting in the event MEHC terminates his employment other than for cause. If such persons were terminated without cause, Messrs. Sokol, Abel and Goodman would currently be entitled to be paid approximately $10,050,000, $5,880,000 and $1,215,000, respectively, without giving effect to any tax-related provisions.

Compensation Committee Interlocks and Insider Participation

The compensation committee of the Board of Directors is comprised of Messrs. Warren E. Buffett and Walter Scott, Jr. Mr. Walter Scott, Jr. is a former officer of the Company. See also Item 13. Certain Relationships and Related Transactions of this Form 10-K.

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.

The following table sets forth certain information regarding beneficial ownership of the shares of MEHC’s common stock and certain information with respect to the beneficial ownership of each director, its Named Executive Officers and all directors and executive officers as a group as of March 1, 2006.

	Number of Shares	Percentage
Name and Address of Beneficial Owner ⁽¹⁾	Beneficially Owned ⁽²⁾	Of Class ⁽²⁾
Common Stock:
Berkshire Hathaway ⁽³⁾	42,164,337	83.42%
Walter Scott, Jr. ⁽⁴⁾	4,972,000	9.84%
David L. Sokol ⁽⁵⁾	1,523,482	2.94%
Gregory E. Abel ⁽⁶⁾	704,992	1.38%
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)	7,200,474	13.74%

______________

(1)	Unless otherwise indicated, each address is c/o MEHC 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)	Such beneficial owner’s address is 1440 Kiewit Plaza, Omaha, Nebraska 68131.

(4)	Excludes 3,000,000 shares held by family members and family controlled trusts and corporations (“Scott Family Interests”) as to which Mr. Scott disclaims beneficial ownership. Such beneficial owner’s address is 1000 Kiewit Plaza, Omaha, Nebraska 68131.

(5)	Includes options to purchase 1,199,277 shares of common stock that are exercisable within 60 days.

(6)	Includes options to purchase 649,052 shares of common stock which are exercisable within 60 days. Excludes 10,041 shares reserved for issuance pursuant to a deferred compensation plan.

(7)	Excludes 42,164,337 shares of common stock held by Berkshire Hathaway of which beneficial ownership of such shares is disclaimed.

119

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, Walter Scott, Jr. 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 MEHC’s common stock for shares of Berkshire Hathaway common stock.

Item 13. Certain Relationships and Related Transactions.

Under a subscription agreement with MEHC, which expires in March 2007, Berkshire Hathaway has agreed to purchase, under certain circumstances, additional 11% trust issued mandatorily redeemable preferred securities in the event that certain outstanding trust preferred securities of MEHC which were outstanding prior to the closing of its acquisition by a private investor group on March 14, 2000 are tendered for conversion to cash by the current holders.

In order to finance its acquisition of Northern Natural Gas, on August 16, 2002, MEHC sold to Berkshire Hathaway $950.0 million in aggregate principal amount of the 11% mandatorily redeemable trust issued preferred securities Series A, of its subsidiary trust, MidAmerican Capital Trust II, due August 31, 2012. The transaction was a private placement pursuant to Section 4(1) of the Securities Act and did not involve any underwriters, underwriting discounts or commissions. Scheduled principal payments began in August 2003. Messrs. Warren E. Buffett and Walter Scott, Jr. are members of the Board of Directors of Berkshire Hathaway. Messrs. Buffett and Marc D. Hamburg are executive officers of Berkshire Hathaway.

The Energy Policy Act became law on August 8, 2005 and included the repeal of PUHCA 1935 effective February 8, 2006. On February 9, 2006, 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 and, upon conversion, has an 83.4% (80.5% on a diluted basis) voting interest in MEHC.

Item 14. Principal Accountant Fees and Services.

Aggregate fees billed to the Company as a consolidated entity during the fiscal years ending December 31, 2005 and 2004 by the Company’s principal accounting firm, Deloitte & Touche LLP, the member firms of Deloitte Touche Tohmatsu, and their respective affiliates (collectively, the “Deloitte Entities”), are set forth below. The audit committee has considered whether the provision of the non-audit services described below is compatible with maintaining the principal accountant’s independence and concluded that these are not independence impairing services.

	Year Ended December 31,
	2005		2004
	(in millions)
Audit Fees ⁽¹⁾	$	2.6	$	2.3
Audit-Related Fees ⁽²⁾		0.1		0.1
Tax Fees ⁽³⁾		0.2		0.4
All Other Fees ⁽⁴⁾		-		-
Total aggregate fees billed	$	2.9	$	2.8

______________

(1)

Includes the aggregate fees billed for each of the last two fiscal years for professional services rendered by the Deloitte Entities for the audit of the Company’s annual financial statements and the review of financial statements included in the Company’s Form 10-Q or for services that are normally provided by the Deloitte Entities in connection with statutory and regulatory filings or engagements for those fiscal years.

(2)

Includes the aggregate fees billed in each of the last two fiscal years for assurance and related services by the Deloitte Entities that are reasonably related to the performance of the audit or review of the Company’s financial statements. Services included in this category include audits of benefit plans, due diligence for possible acquisitions and consultation pertaining to new and proposed accounting and regulatory rules.

120

(3)	Includes the aggregate fees billed in each of the last two fiscal years for professional services rendered by the Deloitte Entities for tax compliance, tax advice, and tax planning.

(4)	Includes the aggregate fees billed in each of the last two fiscal years for products and services provided by the Deloitte Entities, other than the services reported as “Audit Fees,” “Audit-Related Fees,” or “Tax Fees.”

The audit committee reviewed the non-audit services rendered by the Deloitte Entities in and for fiscal 2005 as set forth in the above table and concluded that such 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 are approved in advance by the audit committee 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 audit committee may delegate authority to pre-approve audit and non-audit services to any member of the audit committee, but may not delegate such authority to management.

121

PART IV

Item 15. Exhibits and Financial Statement Schedules.

(a)	Financial Statements and Schedules

	(i)	Financial Statements

		Financial Statements are included in Item 8 of this Form 10-K.

	(ii)	Financial Statement Schedules

		See Schedule I on page 123.
		See Schedule II on page 126.

		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.

122

Schedule I

MidAmerican Energy Holdings Company

Parent Company Only

Condensed Balance Sheets

As of December 31, 2005 and 2004

(Amounts in thousands)

	2005			2004
ASSETS
Current assets:
Cash and cash equivalents	$	2,019		$	265,639
Short-term investments		-			84,050
Other current assets		6,611			21,720
Total current assets		8,630			371,409
Investments in and advances to subsidiaries and joint ventures		6,565,651			6,129,526
Equipment, net		43,916			51,248
Goodwill		1,297,245			1,299,560
Notes receivable - affiliate		54,283			31,500
Deferred charges and other assets		120,343			120,741
Total assets	$	8,090,068		$	8,003,984

LIABILITIES AND STOCKHOLDERS ’ EQUITY

Current liabilities:
Accounts payable and other liabilities	$	133,271		$	80,083
Short-term debt		51,000			-
Current portion of senior debt		-			260,000
Current portion of subordinated debt		234,021			188,543
Total current liabilities		418,292			528,626
Other long-term accrued liabilities		45,166			35,800
Notes payable - affiliate		76,000			76,000
Senior debt		2,776,211			2,771,957
Subordinated debt		1,354,106			1,585,810
Total liabilities		4,669,775			4,998,193

Deferred income		27,833			30,229
Minority interest		7,209			4,403

Stockholders’ equity:
Zero coupon convertible preferred stock - authorized 50,000 shares, no par value; 41,263 shares issued and outstanding		-			-
Common stock - authorized 60,000 shares, no par value; 9,281 and 9,081 shares issued and outstanding at December 31, 2005 and 2004, respectively		-			-
Additional paid in capital		1,963,343			1,950,663
Retained earnings		1,719,497			1,156,843
Accumulated other comprehensive loss, net		(297,589	)		(136,347	)
Total stockholders’ equity		3,385,251			2,971,159
Total liabilities and stockholders ’ equity	$	8,090,068		$	8,003,984

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

123

Schedule I

MidAmerican Energy Holdings Company

Parent Company Only (continued)

Condensed Statements of Operations

For the three years ended December 31, 2005

(Amounts in thousands)

	2005			2004			2003

Revenues:
Equity in undistributed earnings of subsidiary companies and joint ventures	$	547,122		$	103,968		$	380,293
Dividends and distributions from subsidiary companies and joint ventures		256,674			330,678			318,665
Interest and other income		19,474			14,404			13,894
Total revenues		823,270			449,050			712,852

Costs and expenses:
General and administration		50,931			30,438			33,864
Depreciation and amortization		5,955			5,219			5,225
Interest, net of capitalized interest		387,499			401,867			250,225
Total costs and expenses		444,385			437,524			289,314
Income before income taxes		378,885			11,526			423,538
Income tax benefit		(185,024	)		(159,461	)		(162,552	)
Income before minority interest and preferred dividends of subsidiaries		563,909			170,987			586,090
Minority interest and preferred dividends of subsidiaries		1,255			781			170,472
Net income available to common and preferred stockholders	$	562,254		$	170,206		$	415,618

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

124

Schedule I

MidAmerican Energy Holdings Company

Parent Company Only (continued)

Condensed Statements of Cash Flows

For the three years ended December 31, 2005

(Amounts in thousands)

	2005			2004			2003

Cash flows from operating activities	$	(154,247	)	$	(196,397	)	$	(266,529	)

Cash flows from investing activities:
Decrease in advances to and investments in subsidiaries and joint ventures		204,200			142,954			301,959
Purchases of available-for-sale securities		(1,666,721	)		(1,778,331	)		(1,371,126	)
Proceeds from sale of available-for-sale securities		1,750,535			1,758,184			1,341,477
Other, net		17,710			(12,339	)		(32,407	)
Net cash flows from investing activities		305,724			110,468			239,903
Cash flows from financing activities:
Purchase and retirement of common stock		-			(20,000	)		-
Repayment of subordinated debt		(188,544	)		(100,000	)		(198,958	)
Proceeds from senior debt		-			249,765			449,295
Repayments of senior debt		(260,000	)		-			(215,000	)
Net proceeds from revolving credit facility		51,000			-			-
Net repayment of affiliate notes		(22,783	)		(31,095	)		(19,200	)
Other		5,230			(3,328	)		(3,914	)
Net cash flows from financing activities		(415,097	)		95,342			12,223

Net change in cash and cash equivalents		(263,620	)		9,413			(14,403	)
Cash and cash equivalents at beginning of year		265,639			256,226			270,629
Cash and cash equivalents at end of year	$	2,019		$	265,639		$	256,226

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

125

Schedule II

MIDAMERICAN ENERGY HOLDINGS COMPANY

CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS

FOR THE THREE YEARS ENDED DECEMBER 31, 2005

(Amounts in thousands)

	Column B		Column C					Column E
	Balance at		Charged					Balance
Column A	Beginning		to		Column D			at End
Description	of Year		Income		Deductions			of Year

Reserves Deducted From Assets To Which They Apply:

Reserve for uncollectible accounts receivable:
Year ended 2005	$	26,033	$	13,069	$	(17,672	)	$	21,430
Year ended 2004	$	26,004	$	15,304	$	(15,275	)	$	26,033
Year ended 2003	$	39,742	$	13,620	$	(27,358	)	$	26,004

Reserves Not Deducted From Assets ^(1):
Year ended 2005	$	10,848	$	4,019	$	(2,386	)	$	12,481
Year ended 2004	$	17,417	$	4,048	$	(10,617	)	$	10,848
Year ended 2003	$	10,981	$	10,527	$	(4,091	)	$	17,417

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

(1)	Reserves not deducted from assets relate primarily to estimated liabilities for losses retained by MEHC for workers compensation, public liability and property damage claims.

126

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 3 ^rd day of March 2006.

	MIDAMERICAN ENERGY HOLDINGS COMPANY

	/s/ David L. Sokol*
	David L. Sokol
	Chairman of the Board and Chief 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,	March 3, 2006
David L. Sokol	Chief Executive Officer, and Director


/s/ Gregory E. Abel*	President, Chief Operating Officer	March 3, 2006
Gregory E. Abel	and Director


/s/ Patrick J. Goodman	Senior Vice President and	March 3, 2006
Patrick J. Goodman	Chief Financial Officer


/s/ Walter Scott, Jr.*	Director	March 3, 2006
Walter Scott, Jr.


/s/ Marc D. Hamburg*	Director	March 3, 2006
Marc D. Hamburg


/s/ Warren E. Buffett*	Director	March 3, 2006
Warren E. Buffett


* By: /s/ Douglas L. Anderson	Attorney-in-Fact	March 3, 2006
Douglas L. Anderson

127

EXHIBIT INDEX

Exhibit No.

3.1	Second Amended and Restated Articles of Incorporation of MidAmerican Energy Holdings Company effective March 2, 2006.

3.2	Amended and Restated Bylaws of MidAmerican Energy Holdings Company.

4.1	Indenture, dated as of October 4, 2002, by and between MidAmerican Energy Holdings Company and The Bank of New York, relating to the 4.625% Senior Notes due 2007 and the 5.875% Senior Notes due 2012 (incorporated by reference to Exhibit 4.1 of MidAmerican Energy Holdings Company’s 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, relating to the 4.625% Senior Notes due 2007 and the 5.875% Senior Notes due 2012 (incorporated by reference to Exhibit 4.2 of MidAmerican Energy Holdings Company’s 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, relating to the 3.50% Senior Notes due 2008 (incorporated by reference to Exhibit 4.3 of 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, relating to the 5.00% Senior Notes due 2014 (incorporated by reference to Exhibit 4.4 of MidAmerican Energy Holdings Company’s Registration Statement No. 333-113022 dated February 23, 2004).

4.5	Indenture for the 6 1/4% Convertible Junior Subordinated Debentures due 2012, dated as of February 26, 1997, between MidAmerican Energy Holdings Company, as issuer, and the Bank of New York, as Trustee (incorporated by reference to Exhibit 10.129 to MidAmerican Energy Holdings Company’s Annual Report on Form 10-K for the year ended December 31, 1995).

4.6	Indenture, dated as of October 15, 1997, among MidAmerican Energy Holdings Company and IBJ Schroder Bank & Trust Company, as Trustee (incorporated by reference to Exhibit 4.1 to MidAmerican Energy Holdings Company’s Current Report on Form 8-K dated October 23, 1997).

4.7	Form of First Supplemental Indenture for the 7.63% Senior Notes in the principal amount of $350,000,000 due 2007, dated as of October 28, 1997, among MidAmerican Energy Holdings Company and IBJ Schroder Bank & Trust Company, as Trustee (incorporated by reference to Exhibit 4.2 to MidAmerican Energy Holdings Company’s Current Report on Form 8-K dated October 23, 1997).

4.8	Form of Second Supplemental Indenture for the 6.96% Senior Notes in the principal amount of $215,000,000 due 2003, 7.23% Senior Notes in the principal amount of $260,000,000 due 2005, 7.52% Senior Notes in the principal amount of $450,000,000 due 2008, and 8.48% Senior Notes in the principal amount of $475,000,000 due 2028, dated as of September 22, 1998 between MidAmerican Energy Holdings Company and IBJ Schroder Bank & Trust Company, as Trustee (incorporated by reference to Exhibit 4.1 to MidAmerican Energy Holdings Company’s Current Report on Form 8-K dated September 17, 1998.)

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

128

Exhibit No.

4.10	Indenture, dated as of March 14, 2000, among MidAmerican Energy Holdings Company and the Bank of New York, as Trustee (incorporated by reference to Exhibit 4.9 to MidAmerican Energy Holdings Company’s Annual Report on Form 10-K/A for the year ended December 31, 1999).

4.11	Indenture, dated as of March 12, 2002, between MidAmerican Energy Holdings Company and the Bank of New York, as Trustee (incorporated by reference to Exhibit 4.11 to MidAmerican Energy Holdings Company’s Annual Report on Form 10-K for the year ended December 31, 2001).

4.12	Amended and Restated Declaration of Trust of MidAmerican Capital Trust III, dated as of August 16, 2002 (incorporated by reference to Exhibit 4.14 of MidAmerican Energy Holdings Company’s Registration Statement No. 333-101699 dated December 6, 2002).

4.13	Amended and Restated Declaration of Trust of MidAmerican Capital Trust II, dated as of March 12, 2002 (incorporated by reference to Exhibit 4.15 of MidAmerican Energy Holdings Company’s Registration Statement No. 333-101699 dated December 6, 2002).

4.14	Amended and Restated Declaration of Trust of MidAmerican Capital Trust I, dated as of March 14, 2000 (incorporated by reference to Exhibit 4.16 of MidAmerican Energy Holdings Company’s Registration Statement No. 333-101699 dated December 6, 2002).

4.15	Indenture, dated as of August 16, 2002, between MidAmerican Energy Holdings Company and the Bank of New York, as Trustee (incorporated by reference to Exhibit 4.17 of MidAmerican Energy Holdings Company’s Registration Statement No. 333-101699 dated December 6, 2002).

4.16	Shareholders Agreement, dated as of March 14, 2000 (incorporated by reference to Exhibit 4.19 of MidAmerican Energy Holdings Company’s Registration Statement No. 333-101699 dated December 6, 2002).

4.17	Amendment No. 1 to Shareholders Agreement, dated December 7, 2005.

10.1	Amended and Restated Employment Agreement between MidAmerican Energy Holdings Company and David L. Sokol, dated May 10, 1999 (incorporated by reference to Exhibit 10.1 to MidAmerican Energy Holdings Company’s Annual Report on Form 10-K/A for the year ended December 31, 1999).

10.2	Amendment No. 1 to the Amended and Restated Employment Agreement between MidAmerican Energy Holdings Company and David L. Sokol, dated March 14, 2000 (incorporated by reference to Exhibit 10.2 to MidAmerican Energy Holdings Company’s Annual Report on Form 10-K/A for the year ended December 31, 1999).

10.3	Non-Qualified Stock Option Agreements of David L. Sokol, dated March 14, 2000 (incorporated by reference to Exhibit 10.3 of MidAmerican Energy Holdings Company’s Registration Statement No. 333-101699 dated December 6, 2002).

10.4	Amended and Restated Employment Agreement between MidAmerican Energy Holdings Company and Gregory E. Abel, dated May 10, 1999 (incorporated by reference to Exhibit 10.3 to MidAmerican Energy Holdings Company’s Annual Report on Form 10-K/A for the year ended December 31, 1999).

10.5	Non-Qualified Stock Option Agreements of Gregory E. Abel, dated March 14, 2000 (incorporated by reference to Exhibit 10.5 of MidAmerican Energy Holdings Company’s Registration Statement No. 333-101699 dated December 6, 2002).

129

Exhibit No.

10.6	Employment Agreement between MidAmerican Energy Holdings Company and Patrick J. Goodman, dated April 21, 1999 (incorporated by reference to Exhibit 10.5 to MidAmerican Energy Holdings Company’s Annual Report on Form 10-K/A for the year ended December 31, 1999).

10.7	125 MW Power Plant-Upper Mahiao Agreement, dated September 6, 1993, between Philippine National Oil Company-Energy Development Corporation and Ormat, Inc. as amended by the First Amendment to 125 MW Power Plant Upper Mahiao Agreement, dated as of January 28, 1994, the Letter Agreement dated February 10, 1994, the Letter Agreement dated February 18, 1994 and the Fourth Amendment to 125 MW Power Plant-Upper Mahiao Agreement, dated as of March 7, 1994 (incorporated by reference to Exhibit 10.95 to MidAmerican Energy Holdings Company’s Annual Report on Form 10-K for the year ended December 31, 1993).

10.8	Credit Agreement, dated as of April 8, 1994, between CE Cebu Geothermal Power Company, Inc., Export-Import Bank of the United States (incorporated by reference to Exhibit 10.97 to MidAmerican Energy Holdings Company’s Annual Report on Form 10-K for the year ended December 31, 1993).

10.9	180 MW Power Plant-Mahanagdong Agreement, dated September 18, 1993, between Philippine National Oil Company-Energy Development Corporation and CE Philippines Ltd. and the Company, as amended by the First Amendment to Mahanagdong Agreement, dated June 22, 1994, the Letter Agreement dated July 12, 1994, the Letter Agreement dated July 29, 1994, and the Fourth Amendment to Mahanagdong Agreement, dated March 3, 1995 (incorporated by reference to Exhibit 10.1 00 to MidAmerican Energy Holdings Company’s Annual Report on Form 10-K for the year ended December 31, 1993).

10.10	Credit Agreement, dated as of June 30, 1994, between CE Luzon Geothermal Power Company, Inc. and Export-Import Bank of the United States (incorporated by reference to Exhibit 10.102 to MidAmerican Energy Holdings Company’s Annual Report on Form 10-K for the year ended December 31, 1993).

10.11	Finance Agreement, dated as of June 30, 1994, between CE Luzon Geothermal Power Company, Inc. and Overseas Private Investment Corporation (incorporated by reference to Exhibit 10.103 to MidAmerican Energy Holdings Company’s Annual Report on Form 10-K for the year ended December 31, 1993).

10.12	Overseas Private Investment Corporation Contract of Insurance, dated July 29, 1994, between Overseas Private Investment Corporation and the Company, CE International Ltd., CE Mahanagdong Ltd. and American Pacific Finance Company and Amendment No. 1, dated August 3, 1994 (incorporated by reference to Exhibit 10.105 to MidAmerican Energy Holdings Company’s Annual Report on Form 10-K for the year ended December 31, 1993).

10.13	231 MW Power Plant-Malitbog Agreement, dated September 10, 1993, between Philippine National Oil Company-Energy Development Corporation and Magma Power Company and the First and Second Amendments thereto, dated December 8, 1993 and March 10, 1994, respectively (incorporated by reference to Exhibit 10.106 to MidAmerican Energy Holdings Company’s Annual Report on Form 10-K for the year ended December 31, 1993).

10.14	Trust Indenture, dated as of November 27, 1995, between the CE Casecnan Water and Energy Company, Inc. and Chemical Trust Company of California (incorporated by reference to Exhibit 4.1 to CE Casecnan Water and Energy Company, Inc.’s Registration Statement on Form S-4 dated January 25, 1996).

10.15	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 CE Casecnan Water and Energy Company, Inc.’s Registration Statement on Form S-4 dated January 25, 1996).

10.16	Supplemental Agreement between CE Casecnan Water and Energy Company, Inc. and the Philippines National Irrigation Administration dated as of September 29, 2003 (incorporated by reference to Exhibit 98.1 to MidAmerican Energy Holdings Company's Current Report on Form 8-K dated October 15, 2003).

130

Exhibit No.

10.17	Indenture and First Supplemental Indenture, dated March 11, 1999, between MidAmerican Funding LLC and IBJ Whitehall Bank & Trust Company and the First Supplement thereto relating to the $700 million Senior Notes and Bonds (incorporated by reference to MidAmerican Energy Holdings Company’s Annual Report on Form 10-K for the year ended December 31, 1998).

10.18	Second Supplemental Indenture, dated as of March 1, 2001, by and between MidAmerican Funding, LLC and The Bank of New York, as Trustee (incorporated by reference to Exhibit 4.4 to MidAmerican Funding LLC’s Registration Statement on Form S-3, Registration No. 333-56624).

10.19	General Mortgage Indenture and Deed of Trust, dated as of January 1, 1993, 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).

10.20	First Supplemental Indenture, dated as of January 1, 1993, 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).

10.21	Second Supplemental Indenture, dated as of January 15, 1993, 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).

10.22	Third Supplemental Indenture, dated as of May 1, 1993, 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).

10.23	Fourth Supplemental Indenture, dated as of October 1, 1994, 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).

10.24	Fifth Supplemental Indenture, dated as of November 1, 1994, 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).

10.25	Sixth Supplemental Indenture, dated as of July 1, 1995, 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).

10.26	Indenture dated as of December 1, 1996, between MidAmerican Energy Company and the First National Bank of Chicago, as Trustee (incorporated by reference to Exhibit 4(1) to MidAmerican Energy Company’s Registration Statement on Form S-3, Registration No. 333-15387).

10.27	First Supplemental Indenture, dated as of February 8, 2002, by and between MidAmerican Energy Company and The Bank of New York, as Trustee (incorporated by reference to Exhibit 4.3 to MidAmerican Energy Company’s Annual Report on Form 10-K for the year ended December 31, 2004, Commission File No. 333-15387).

131

Exhibit No.

10.28	Second Supplemental Indenture, dated as of January 14, 2003, by and between MidAmerican Energy Company and The Bank of New York, as Trustee (incorporated by reference to Exhibit 4.2 to MidAmerican Energy Company’s Annual Report on Form 10-K for the year ended December 31, 2004, Commission File No. 333-15387).

10.29	Third Supplemental Indenture, dated as of October 1, 2004, by and between MidAmerican Energy Company and The Bank of New York, as Trustee (incorporated by reference to Exhibit 4.1 to MidAmerican Energy Company’s Annual Report on Form 10-K for the year ended December 31, 2004, Commission File No. 333-15387).

10.30	Fourth Supplemental Indenture, dated November 1, 2005, by and between MidAmerican Energy Company and the Bank of New York Trust Company, NA, as 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).

10.31	Sixth Amendment to 180 MW Power Plant-Mahanagdong Agreement, dated August 31, 2003, between Philippine National Oil Company-Energy Development Corporation and CE Luzon Geothermal Power Company, Inc. (incorporated by reference to Exhibit 10.44 to MidAmerican Energy Holdings Company’s Annual Report on Form 10-K for the year ended December 31, 2003).

10.32	Third Amendment to 231 MW Power Plant-Malitbog Agreement, dated August 31, 2003, between Philippine National Oil Company-Energy Development Corporation and Visayas Geothermal Power Company, Inc. (incorporated by reference to Exhibit 10.45 to MidAmerican Energy Holdings Company’s Annual Report on Form 10-K for the year ended December 31, 2003).

10.33	Seventh Amendment to 125 MW Power Plant-Upper Mahiao Agreement, dated August 31, 2003, between Philippine National Oil Company-Energy Development Corporation and CE Cebu Geothermal Power Company, Inc. (incorporated by reference to Exhibit 10.46 to MidAmerican Energy Holdings Company’s Annual Report on Form 10-K for the year ended December 31, 2003).

10.34	Fiscal Agency Agreement, dated as of October 15, 2002, 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 MidAmerican Energy Holdings Company’s Annual Report on Form 10-K for the year ended December 31, 2003).

10.35	Trust Indenture, dated as of August 13, 2001, among Kern River Funding Corporation, Kern River Gas Transmission Company and the JP Morgan Chase Bank, as 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 MidAmerican Energy Holdings Company's Annual Report on Form 10-K for the year ended December 31, 2003).

10.36	Third Supplemental Indenture, dated as of May 1, 2003, among Kern River Funding Corporation, Kern River Gas Transmission Company and JPMorgan Chase Bank, as 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 MidAmerican Energy Holdings Company's Annual Report on Form 10-K for the year ended December 31, 2003).

10.37	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 of MidAmerican Energy Holdings Company’s Registration Statement No. 333-101699 dated December 6, 2002).

10.38	MidAmerican Energy Holdings Company Executive Voluntary Deferred Compensation Plan (incorporated by reference to Exhibit 10.51 of MidAmerican Energy Holdings Company’s Registration Statement No. 333-101699 dated December 6, 2002).

132

Exhibit No.

10.39	MidAmerican Energy Company First Amended and Restated Supplemental Retirement Plan for Designated Officers dated as of May 10, 1999 (incorporated by reference to Exhibit 10.52 of MidAmerican Energy Holdings Company’s Registration Statement No. 333-101699 dated December 6, 2002).

10.40	MidAmerican Energy Company Restated Executive Deferred Compensation Plan (incorporated by reference to Exhibit 10.6 to MidAmerican Energy Holdings Company’s Annual Report on Form 10-K/A for the year ended December 31, 1999).

10.41	MidAmerican Energy Holdings Company Restated Deferred Compensation Plan-Board of Directors (incorporated by reference to Exhibit 10 to MidAmerican Energy Holdings Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 1999).

10.42	MidAmerican Energy Company Combined Midwest Resources/Iowa Resources Restated Deferred Compensation Plan-Board of Directors (incorporated by reference to Exhibit 10.63 to MidAmerican Energy Holdings Company’s Annual Report on Form 10-K/A for the year ended December 31, 1999).

10.43	MidAmerican Energy Holdings Company Executive Incremental Profit Sharing Plan (incorporated by reference to Exhibit 10.2 of MidAmerican Energy Holdings Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2003.)

10.44	Trust Deed between CE Electric UK Funding Company, AMBAC Insurance UK Limited and The Law Debenture Trust Corporation, p.l.c. dated December 15, 1997 (incorporated by reference to Exhibit 99.1 to MidAmerican Energy Holdings Company’s Current Report on Form 8-K dated March 30, 2004).

10.45	Insurance and Indemnity Agreement between CE Electric UK Funding Company and AMBAC Insurance UK Limited dated December 15, 1997 (incorporated by reference to Exhibit 99.2 to MidAmerican Energy Holdings Company’s Current Report on Form 8-K dated March 30, 2004).

10.46	Supplemental Agreement to Insurance and Indemnity Agreement between CE Electric UK Funding Company and AMBAC Insurance UK Limited dated September 19, 2001 (incorporated by reference to Exhibit 99.3 to MidAmerican Energy Holdings Company’s Current Report on Form 8-K dated March 30, 2004).

10.47	Fiscal Agency Agreement, dated as of September 4, 1998, 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 MidAmerican Energy Holdings Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2004).

10.48	Fiscal Agency Agreement, dated as of May 24, 1999, 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 MidAmerican Energy Holdings Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2004).

10.49	Trust Indenture, dated as of September 10, 1999, 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 MidAmerican Energy Holdings Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2004).

10.50	Indenture, dated as of December 15, 1997, among CE Electric UK Funding Company, The Bank of New York, as Trustee, and Banque Internationale A Luxembourg S.A., as Paying Agent (incorporated by reference to Exhibit 10.72 to MidAmerican Energy Holdings Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2004).

133

Exhibit No.

10.51	First Supplemental Indenture, dated as of December 15, 1997, among CE Electric UK Funding Company, The Bank of New York, Trustee, and Banque Internationale A Luxembourg S.A., Paying Agent, relating to the $125,000,000 in principal amount of the 6.853% Senior Notes due 2004 and to the $237,000,000 in principal amount of the 6.995% Senior Notes due 2007 (incorporated by reference to Exhibit 10.73 to MidAmerican Energy Holdings Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2004).

10.52	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 MidAmerican Energy Holdings Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2004).

10.53	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 MidAmerican Energy Holdings Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2004).

10.54	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 MidAmerican Energy Holdings Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2004).

10.55	Indenture, dated as of February 1, 1998, and Second Supplemental Indenture, dated as of February 25, 1998, each among Yorkshire Power Finance Limited, Yorkshire Power Group Limited, The Bank of New York, Trustee, and Banque Internationale du Luxembourg S.A., Paying Agent, relating to the $300,000,000 in principal amount of the 6.496% Notes due 2008 (incorporated by reference to Exhibit 10.77 to MidAmerican Energy Holdings Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2004).

10.56	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 MidAmerican Energy Holdings Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2004).

10.57	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 8.625% Guaranteed Bonds due 2005 and to the £100,000,000 in principal amount of the 8.875% Guaranteed Bonds due 2020 (incorporated by reference to Exhibit 10.81 to MidAmerican Energy Holdings Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2004).

10.58	Trust Deed, dated as of January 17, 1995, 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 MidAmerican Energy Holdings Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2004).

10.59	Master Trust Deed, dated as of October 16, 1995, among 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 8.625% Guaranteed Bonds due 2005 and to the £100,000,000 in principal amount of the 8.875% Guaranteed Bonds due 2020 (incorporated by reference to Exhibit 10.70 to MidAmerican Energy Holdings Company’s Annual Report on Form 10-K for the year ended December 31, 2004).

134

Exhibit No.

10.60	MidAmerican Energy Holdings Company Amended and Restated Long-Term Incentive Partnership Plan dated as of January 1, 2004 (incorporated by reference to Exhibit 10.71 to MidAmerican Energy Holdings Company’s Annual Report on Form 10-K for the year ended December 31, 2004).

10.61	Fiscal Agency Agreement, dated April 14, 2005, by and between Northern Natural Gas Company, as issuer, and J.P. Morgan Trust Company, National Association, as 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 MidAmerican Energy Holdings Company’s Current Report on Form 8-K dated April 18, 2005).

10.62	£100,000,000 Facility Agreement dated 4 April 2005 made between 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 MidAmerican Energy Holdings Company’s Current Report on Form 8-K dated April 20, 2005).

10.63	Trust Deed made on 5 May 2005 between 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 MidAmerican Energy Holdings Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2005).

10.64	Reimbursement and Indemnity Agreement dated 5 May 2005 between Northern Electric Finance plc, Northern Electric Distribution Limited and Ambac Assurance UK Limited (incorporated by reference to Exhibit 99.2 to MidAmerican Energy Holdings Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2005).

10.65	Trust Deed made on 5 May 2005 between Yorkshire Electricity Distribution plc, Ambac Assurance UK Limited and HSBC Trustee (C.I.) Limited (incorporated by reference to Exhibit 99.3 to MidAmerican Energy Holdings Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2005).

10.66	Reimbursement and Indemnity Agreement dated 5 May 2005 between Yorkshire Electricity Distribution plc and Ambac Assurance UK Limited (incorporated by reference to Exhibit 99.4 to MidAmerican Energy Holdings Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2005).

10.67	Supplemental Trust Deed made on 5 May 2005 between CE Electric UK Funding Company, Ambac Assurance UK Limited and The Law Debenture Trust Corporation plc (incorporated by reference to Exhibit 99.5 to MidAmerican Energy Holdings Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2005).

10.68	Second Supplemental Agreement to Insurance and Indemnity Agreement made on 5 May 2005 between CE Electric UK Funding Company and Ambac Assurance UK Limited (incorporated by reference to Exhibit 99.6 to MidAmerican Energy Holdings Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2005).

10.69	Stock Purchase Agreement, dated as of May 23, 2005, by and among Scottish Power plc, PacifiCorp Holdings, Inc. and MidAmerican Energy Holdings Company (incorporated by reference to exhibit 99.1 to MidAmerican Energy Holdings Company’s Current Report on Form 8-K dated May 24, 2005).

10.70	Credit Agreement, dated August 26, 2005, 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 MidAmerican Energy Holdings Company’s Current Report on Form 8-K dated September 1, 2005).

135

Exhibit No.

10.71	Credit Agreement among MidAmerican Energy Company, the Lending Institutions Party Hereto, as Banks, Union Bank of California, N.A., as Syndication Agent, and JPMorgan Chase Bank, N.A. as Administrative Agent, dated as of November 18, 2004 Union Bank of California, N.A. and J.P.Morgan Securities, Inc. Co-Lead Arrangers and Co-Book Runners (incorporated by reference to Exhibit 10.1 to the MidAmerican Energy Company Annual Report on Form 10-K for the year ended December 31, 2005).

10.72	Equity Commitment Agreement, dated as of March 1, 2006, between Berkshire Hathaway, Inc. and MidAmerican Energy Holdings Company.

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 MidAmerican Energy Holdings Company’s Annual Report on Form 10-K for the year ended December 31, 2003).

21.1	Subsidiaries of the Registrant.

24.1	Power of Attorney.

31.1	Chief Executive Officer’s Certificate Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2	Chief Financial Officer’s Certificate Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.1	Chief Executive Officer’s Certificate Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32.2	Chief Financial Officer’s Certificate Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

136

EXHIBIT 3.1

SECOND AMENDED AND RESTATED ARTICLES OF INCORPORATION

MIDAMERICAN ENERGY HOLDINGS COMPANY

TO THE SECRETARY OF STATE

OF THE STATE OF IOWA:

Pursuant to the provisions of Division X of the Iowa Business Corporation Act (the “Act”), the undersigned corporation hereby adopts the following Second Amended and Restated Articles of Incorporation (“Articles of Incorporation”).

ARTICLE I.

The name of the corporation is “MidAmerican Energy Holdings Company” (hereinafter sometimes called the “Corporation”) and its registered office shall be located at 666 Grand Avenue, Des Moines, Iowa 50309 with the right to establish and maintain branch offices at such other points within and without the State of Iowa as the Board of Directors of the Corporation (the “Board of Directors”) may, from time to time, determine. The name of the Corporation’s registered agent at such registered office is Margaret A. Roy.

ARTICLE II.

The nature of the business or purposes to be conducted or promoted is to engage in any or all lawful act or activity for which a corporation may be incorporated under the Act.

ARTICLE III.

A. The aggregate number of shares which the Corporation shall have authority to issue is 115,000,000 shares of Common Stock, no par value (“Common Stock”).

B. The shares of authorized Common Stock shall be identical in all respects and shall have equal rights and privileges. For all purposes, each registered holder of Common Stock shall, at each meeting of shareholders, be entitled to one vote for each share of Common Stock held, either in person or by proxy duly authorized in writing. Except to the extent required by law or as permitted by these Articles of Incorporation, as amended from time to time, the registered holders of the shares of Common Stock shall have exclusive voting rights.

C. The Board of Directors, at any time or from time to time, may, and is hereby authorized to, issue and dispose of any of the authorized and unissued shares of Common Stock and any issued but not outstanding shares for such kind and amount of consideration and to such persons, firms or corporations, as may be determined by the Board of Directors, subject to any provisions of law then applicable. The holders of Common Stock shall have no preemptive rights to acquire or subscribe to any shares, or securities convertible into shares, of Common Stock.

D. The Board of Directors, at any time or from time to time may, and is hereby authorized to, create and issue, whether or not in connection with the issue and sale of any shares of its Common Stock or other securities of the Corporation, warrants, rights and/or options entitling the holders thereof to purchase from the Corporation any shares of its Common Stock or other securities of the Corporation. Such warrants, rights, or options shall be evidenced by such instrument or instruments as shall be approved by the Board of Directors. The terms upon which, the time or times (which may be limited or unlimited in duration) at or within which, and the price or prices (which shall be not less than the minimum amount prescribed by law, if any) at which any such shares or other securities may be purchased from the Corporation upon the exercise of any such warrant, right or option shall be fixed and stated in the resolution or resolutions of the Board of Directors providing for the creation and issue of such warrants, rights or options. The Board of Directors is hereby authorized to create and issue any such warrants, rights or options from time to time for such consideration, if any, and to such persons, firms or corporations, as the Board of Directors may determine.

E. The Corporation may authorize the issue of some or all of the shares of any or all of the classes of its capital stock without certificates.

F. The Corporation shall not be required to issue certificates representing any fraction or fractions of a share of stock of any class but may issue in lieu thereof one or more non-dividend bearing and non-voting scrip certificates in such form or forms as shall be approved by the Board of Directors, each scrip certificate representing a fractional interest in one share of stock of any class. Such scrip certificates upon presentation together with similar scrip certificates representing in the aggregate an interest in one or more full shares of stock of any class shall entitle the holders thereof to receive one or more full shares of stock of such class. Such scrip certificates may contain such terms and conditions as shall be fixed by the Board of Directors and may become void and of no effect after a period to be determined by the Board of Directors and to be specified in such scrip certificates.

G. The Corporation shall be entitled to treat the person in whose name any share of Common Stock is registered as the owner thereof for all purposes and shall not be bound to recognize any equitable or other claim to, or interest in, such share on the part of any person, whether or not the Corporation shall have notice thereof except as may be expressly provided otherwise by the laws of the State of Iowa.

ARTICLE IV.

The term of corporate existence of the Corporation shall be perpetual.

ARTICLE V.

The private property of the shareholders of the Corporation shall be exempt from all corporate debts.

ARTICLE VI.

A. A director of the Corporation shall not be personally liable to the Corporation or its shareholders for monetary damages for breach of fiduciary duty as a director, except for liability:

(i) for any action not in good faith or which the director did not reasonably believe to be in the best interests of the Corporation; or

(ii) for any receipt of a financial benefit to which the director was not entitled; or

(iii) for any breach of the director’s duty of fair dealing with the Corporation or its shareholders; or

(iv) under Section 490. 831, or a successor provision, of the Act.

B. If, after the date these Articles of Incorporation are filed with the Iowa Secretary of State, the Act is amended to authorize corporate action further eliminating or limiting the personal liability of directors, then the liability of a director of the Corporation shall be deemed eliminated or limited to the fullest extent permitted by the Act, as so amended. Any repeal or modification of Section A or this Section B of this Article VI by the shareholders of the Corporation shall be prospective only and shall not adversely affect any right or protection of a director of the Corporation existing at the time of such repeal or modification.

ARTICLE VII.

A. Each person who was or is a party or is threatened to be made a party to or is involved in any action, suit or proceeding, whether civil, criminal, administrative, investigative or arbitration and whether formal or informal (“proceeding”), by reason of the fact that he or she, or a person of whom he or she is the legal representative, is or was a director, officer or employee, of the Corporation or is or was serving at the request of the Corporation as a director, officer, partner, trustee or employee of another corporation or of a partnership, joint venture, trust or other enterprise, including service with respect to employee benefit plans, whether the basis of such proceeding is alleged action in an official capacity while serving as a director, officer or employee or in any other capacity while serving as a director, officer or employee, shall be indemnified and held harmless by the Corporation to the fullest extent authorized by the Act, as the same exists or may hereafter be amended (but, in the case of any such amendment, only to the extent that such amendment permits the Corporation to provide broader indemnification rights than the Act permitted the Corporation to provide prior to such amendment), against all reasonable expenses, liability and loss (including without limitation attorneys’ fees, all costs, judgments, fines, Employee Retirement Income Security Act excise taxes or penalties and amounts paid or to be paid in settlement) reasonably incurred or suffered by such person in connection therewith. Such right shall be a contract right and shall include the right to be paid by the Corporation expenses incurred in defending any such proceeding in advance of its final disposition; provided, however, that the payment of such expenses incurred by a director, officer or employee in his or her capacity as a director, officer or employee (and not in any other capacity in which service was or is rendered by such person while a director, officer or employee including, without limitation, service to an employee benefit plan) in advance of the final disposition of such proceeding, shall be made only upon due authorization by a majority of disinterested directors or shareholders of the Corporation and upon delivery to the Corporation of (i) a written undertaking, by or on behalf of such director, officer or employee, to repay all amounts so advanced if it should be determined ultimately that such director, officer or employee is not entitled to be indemnified under this Article VII or otherwise, or (ii) a written affirmation by or on behalf of such director, officer or employee that, in such person’s good faith belief, such person has met the standards of conduct set forth in the Act.

B. If a claim under Section A is not paid in full by the Corporation within 30 days after a written claim has been received by the Corporation, the claimant may at any time thereafter bring suit against the Corporation to recover the unpaid amount of the claim and, if successful in whole or in part, the claimant shall be entitled to be paid also the expenses of prosecuting such claim. It shall be a defense to any such action that the claimant has not met the standards of conduct which make it permissible under the Act for the Corporation to indemnify the claimant for the amount claimed, but the burden of proving such defense shall be on the Corporation. The failure of the Corporation (including its Board of Directors, independent legal counsel or its shareholders) to have made a determination prior to the commencement of such action that indemnification of the claimant is proper in the circumstances because he or she has met the applicable standard of conduct set forth in the Act, shall not be a defense to the action or create a presumption that the claimant had not met the applicable standard of conduct.

C. Indemnification provided hereunder shall, in the case of the death of the person entitled to indemnification, inure to the benefit of such person’s heirs, executors or other lawful representatives. The invalidity or unenforceability of any provision of this Article VII shall not affect the validity or enforceability of any other provision of this Article VII.

D. Any action taken or omitted to be taken by any director, officer or employee in good faith and in compliance with or pursuant to any order, determination, approval or permission made or given by a commission, board, official or other agency of the United States or of any state or other governmental authority with respect to the property or affairs of the Corporation or any such business corporation, not-for-profit corporation, joint venture, trade association or other entity over which such commission, board, official or agency has jurisdiction or authority or purports to have jurisdiction or authority shall be presumed to be in compliance with the standard of conduct set forth in Section 490.851 (or any successor provision) of the Act whether or not it may thereafter be determined that such order, determination, approval or permission was unauthorized, erroneous, unlawful or otherwise improper.

E. Unless finally determined, the termination of any litigation, whether by judgment, settlement, conviction or upon a plea of nolo contendere , or its equivalent, shall not create a presumption that the action taken or omitted to be taken by the person seeking indemnification did not comply with the standard of conduct set forth in Section 490.851 (or any successor provision) of the Act.

F. The rights conferred on any person by this Article VII shall not be exclusive of any other right which any person may have or hereafter acquire under any statute, provision of the Articles of Incorporation, Bylaws, agreement, vote of shareholders or disinterested directors or otherwise.

G. The Corporation may maintain insurance, at its expense, to protect itself and any such director, officer, employee or agent of the Corporation or another corporation, partnership, joint venture, trust or other enterprise against any such expense, liability or loss, whether or not the Corporation would have the power to indemnify such person against such expense, liability or loss under the Act.

ARTICLE VIII.

These Articles of Incorporation may be amended, repealed, changed or modified at any annual meeting of shareholders of the Corporation or at a special meeting being called for that purpose or by written consent, in compliance with the applicable statutes of the State of Iowa.

The Second Amended and Restated Articles of Incorporation supersede the Restated Articles of Incorporation requiring shareholder approval. The Second Amended and Restated Articles of Incorporation were approved by the shareholders by unanimous written consent. The designation, number of outstanding shares, number of votes entitled to be cast by each voting group entitled to vote separately on the Second Amended and Restated Articles of Incorporation, and the number of votes of each voting group indisputably represented are as follows:

		Votes Entitled	Votes Represented
Designation	Shares	To Be Cast On	By Unanimous
Of Group	Outstanding	Restated Articles	Consent

Common Stock	50,544,482	50,544,482	50,544,482

The total number of undisputed votes cast for and against the Second Amended and Restated Articles of Incorporation by each voting group entitled to vote separately on the Second Amended and Restated Articles of Incorporation are as follows:

Voting Group	Votes For	Votes Against

Common Stock	50,544,482	0

The number of votes cast for the Second and Amended Restated Articles of Incorporation by each voting group was sufficient for approval by that voting group.

These Second Amended and Restated Articles of Incorporation are to be effective on March 2, 2006.


	MidAmerican Energy Holdings Company

	/s/	Paul J. Leighton
		Paul J. Leighton, Vice President and
		Assistant Secretary

EXHIBIT 3.2

AMENDED AND RESTATED BYLAWS

MIDAMERICAN ENERGY HOLDINGS COMPANY

ARTICLE I

OFFICES

Section 1. Principal Office . The principal office of the corporation shall be in the City of Des Moines, Polk County, Iowa. The corporation may also have an office or offices at such other place or places either within or without the State of Iowa as the Board of Directors may from time to time determine or the business of the corporation may require.

Section 2. Registered Office . The registered office of the corporation required by the Iowa Business Corporation Act to be maintained in the State of Iowa may be, but need not be, the same as the principal office of the corporation in the State of Iowa, and the address of the registered office may be changed from time to time by the Board of Directors.

ARTICLE II

SHAREHOLDERS' MEETINGS

Section 1. Place . All meetings of the shareholders shall be held in the City of Des Moines, Iowa, at the principal office of the corporation or such other place as determined by the Board of Directors or Chairman.

Section 2. Annual Meetings . The annual meeting of shareholders shall be held at such date and time determined by the Board of Directors or Chairman, when they shall elect the Board of Directors and transact such other business as may properly be brought before the meeting.

Section 3. Special Meetings . Special meetings of the shareholders for any purpose or purposes may be called by the President, or by a Vice President (under such conditions as are prescribed in these bylaws), or by the Chairman of the Board of Directors (if there be one), or by the Board of Directors, or by the holders of not less than one-tenth of all the shares entitled to vote at the meeting.

Section 4. Notice . Notice, in accordance with the Iowa Business Corporation Act, stating the place, day and hour of the annual meeting and of any special meeting, and in the case of a special meeting, the purpose or purposes for which the meeting is called, shall be given so that it is effective not less than ten (10) nor more than sixty (60) days before the date of the meeting, by or at the direction of the President, or the Secretary, or the officer or persons calling the meeting, to each shareholder of record entitled to vote at such meeting.

Section 5. Right to Vote . Except as provided in Sections 8 and 9 of this Article II, only shareholders owning shares of stock of a class entitled to vote as required by the Iowa Business Corporation Act or as provided in the Articles of Incorporation of record on the books of the corporation on the day fixed by the Board of Directors for the closing of the stock transfer books of the corporation prior to any meeting of the shareholders, or, if the stock transfer books be not closed, of record on the books of the corporation at the close of business on the day fixed by the Board of Directors as the record date for the determination of the shareholders entitled to vote at such meeting, shall be entitled to notice of and shall have the right to vote (either in person or by proxy) at such meeting.

Section 6. Closing of Transfer Books or Fixing of Record Date . For the purpose of determining shareholders entitled to notice of or to vote at any meeting of shareholders or any adjournment thereof, or entitled to receive payment of any dividend, or in order to make a determination of shareholders for any other proper purpose, the Board of Directors of the corporation may provide that the stock transfer books shall be closed for a stated period but not to exceed, in any case, seventy (70) days. If the stock transfer books shall be closed for the purpose of determining shareholders entitled to notice of or to vote at a meeting of shareholders, such books shall be closed for at least ten (10) days immediately preceding such meeting. In lieu of closing the stock transfer books, the Board of Directors may fix in advance a date as the record date for any such determination of shareholders, such date in any case to be not more than seventy (70) days prior to the date on which the particular action requiring such determination of shareholders is to be taken. Except as provided in the Articles of Incorporation establishing one or more classes or series of Preferred Stock, if the stock transfer books are not closed and no record date is fixed for the determination of shareholders entitled to notice of or to vote at a meeting of shareholders, or shareholders entitled to receive payment of a dividend, the date on which notice of the meeting is mailed or the date on which the resolution of the Board of Directors declaring such dividend is adopted, as the case may be, shall be the record date for such determination of shareholders. When a determination of shareholders entitled to vote at any meeting of shareholders has been made as provided in this Section 6, such determination shall apply to any adjournment thereof, except that the Board of Directors must fix a new record date if the meeting is adjourned to a date more than one hundred twenty (120) days after the date fixed for the original meeting.

Section 7. Shareholders’ List . The officer having charge of the stock transfer books for shares of stock of the corporation shall make a complete list of the shareholders entitled to vote at a meeting of shareholders or any adjournment thereof, arranged in alphabetical order, with the registered address of and the number of shares held by each, which list shall be kept on file at the office of the corporation and shall be subject to inspection by any shareholder at any time during usual business hours beginning two business days after notice of such meeting is given for which such list was prepared. Such list shall also be produced and kept open at the time and place of the meeting and shall be subject to the inspection of any shareholder during the whole time of the meeting. The original stock transfer books shall be prima facie evidence as to who are the shareholders entitled to examine such list or transfer books or to vote at any meeting of shareholders. Failure to comply with the requirement of this Section 7 shall not affect the validity of any action taken at any such meeting.

Section 8. Voting of Shares by Certain Holders . Shares standing in the name of another corporation, domestic or foreign, may be voted by such officer, agent or proxy as the bylaws of such corporation may prescribe, or, in the absence of such provision, as the board of directors of such corporation may determine.

Shares held by a person who is an administrator, executor, guardian or conservator may be voted by such person, either in person or by proxy, without the transfer of such shares into the name of such person. Shares standing in the name of a trustee may be voted by such trustee, either in person or by proxy, but no trustee shall be entitled to vote shares held by such trustee without a transfer of such shares into the name of such trustee.

Shares held in the name of a receiver may be voted by such receiver, and shares held by or under the control of a receiver may be voted by such receiver without the transfer thereof into the name of such receiver if authority so to do is contained in an appropriate order of the court by which such receiver was appointed.

A shareholder whose shares are pledged shall be entitled to vote such shares until the shares have been transferred into the name of the pledgee, and thereafter the pledgee shall be entitled to vote the shares so transferred.

On and after the date on which written notice of redemption of redeemable shares has been mailed to the holders thereof and a sum sufficient to redeem such shares has been deposited with a bank or trust company with irrevocable instruction and authority to pay the redemption price to the holders thereof upon surrender of certificates therefor, such shares shall not be entitled to vote on any matter and shall not be deemed to be outstanding shares.

Shares of the corporation are not entitled to be voted if they are owned, directly or indirectly, by a second corporation, and the corporation owns, directly or indirectly, a majority of the shares entitled to vote for the election of directors of such second corporation, nor shall any such shares be counted in determining the total number of outstanding shares at any given time.

At all meetings of shareholders, a shareholder may vote either in person or by proxy executed in writing by the shareholder or by the duly authorized attorney-in-fact of such shareholder. Such proxy and any revocation thereof shall be filed with the Secretary of the corporation. No proxy shall be valid after eleven (11) months from the date of its execution, unless otherwise provided in the proxy.

Section 9. Proxies . When a valid proxy is filed with the Secretary of the corporation, the proxy named therein (or the duly appointed substitute of such proxy, if the proxy authority permits the appointment of a substitute) shall be entitled to enter and be present at the shareholders' meeting designated in the proxy appointment, and to exercise the power granted to such proxy under such proxy appointment, notwithstanding that the shareholder who gave the proxy appointment is personally present at the meeting, unless and until such proxy appointment is revoked by a written instrument of revocation, stating the time and date of revocation of the proxy appointment, duly signed by the shareholder who executed the proxy appointment, and filed with the Secretary of the corporation. Subject to any express limitation or restriction in any such proxy appointment contained, a vote, consent or action taken by a proxy prior to revocation thereof, as hereinbefore provided, shall be valid and binding on the shareholder who gave the proxy appointment. Each proxy appointment, and also each instrument of revocation thereof, shall be retained by the Secretary of the corporation as required by regulatory authorities.

Section 10. Quorum . The holders of a majority of the votes of the shares entitled to vote thereat, represented in person or by proxy, shall constitute a quorum for the transaction of business at all meetings of the shareholders except as otherwise provided by the Iowa Business Corporation Act, the Articles of Incorporation or these bylaws. The holders of a majority of the votes of the shares present in person or by proxy at any meeting and entitled to vote thereat shall have power successively to adjourn the meeting to a specified date whether or not a quorum be present. The time and place to which any such adjournment is taken shall be publicly announced at the meeting, and no further notice thereof shall be necessary. At any such adjourned meeting at which a quorum shall be present or represented, any business may be transacted which might have been transacted at the meeting as originally called.

Section 11. Manner of Votin g. Upon demand of any shareholder entitled to vote thereon, the vote on any question before the meeting shall be by ballot. If a quorum is present, the affirmative vote of the majority of the votes of the shares represented at the meeting and entitled to vote on the subject matter shall be the act of the shareholders, unless the vote of a greater number or voting by classes is required by the Iowa Business Corporation Act or the Articles of Incorporation.

Section 12. Officers of the Meeting-Powers . The Chairman of the Board of Directors (if there be one), or in the absence of the Chairman of the Board, the President of the corporation shall call meetings of the shareholders to order and shall act as chairman thereof. The Board of Directors may appoint any shareholder to act as chairman of any meeting in the absence of the Chairman of the Board of Directors and the President, and in the case of the failure of the Board of Directors to appoint a chairman, the shareholders present at the meeting shall elect a chairman who shall be either a shareholder or a proxy of a shareholder.

The Secretary of the corporation shall act as secretary at all meetings of shareholders. In the absence of the Secretary at any meeting of shareholders, the chairman may appoint any person to act as secretary of the meeting.

Section 13. Power of Chairman . The chairman of any shareholders' meeting shall have power to determine the eligibility of votes, and may reject votes, whether cast in person or by proxy, as irregular, unauthorized or not cast in accordance with the Articles of Incorporation or these bylaws. The decisions of such chairman as to such matters shall be final unless challenged from the floor, immediately after being announced, and overruled by the vote of the holders of a majority of the shares represented at the meeting. Such chairman may appoint inspectors of election to count ballots, whenever voting is by ballot. Such chairman shall have power to order any unauthorized persons to leave the meeting and to enforce such orders, and shall have and exercise all power and authority, and perform all duties customarily possessed and performed by the presiding officer of such a meeting.

Section 14. Action Without Meeting . Any action required or permitted to be taken at any annual or special meeting of shareholders may be taken without a meeting, without prior notice and without a vote, if a consent or consents in writing, setting forth the action so taken, shall be signed by the holders of outstanding shares having not less than ninety percent (90%) of the votes entitled to vote at the meeting at which all shares entitled to vote on the action were present and voted and shall be delivered to the corporation by delivery to its registered office in the State of Iowa, its principal place of business, or an officer or agent of the corporation having custody of the book in which proceedings of meetings of shareholders are recorded. Delivery made to the corporation's registered office shall be by hand or by certified or registered mail, return receipt requested. Prompt notice of the taking of the corporate action without a meeting by less than unanimous written consent shall be given to those shareholders who have not consented in writing.

ARTICLE III

BOARD OF DIRECTORS

Section 1. Powers . The business and affairs of the corporation shall be managed by the Board of Directors.

Section 2. Number and Qualification of Directors . The Board of Directors shall consist of not more than ten and not less than three members who shall be elected at the annual meeting of shareholders. A director may but need not be a shareholder or a resident of the State of Iowa. Each director shall be elected to serve until the next annual meeting of shareholders and until the successor of such director shall be elected or appointed as provided in Section 3 of this Article III, and shall have qualified.

Section 3. Vacancies . If a vacancy in the Board of Directors shall occur by reason of death, resignation, retirement, disqualification, removal from office, an increase in the number of members, or otherwise, a majority of the remaining directors, though less than a quorum, may appoint a director to fill such vacancy, who shall hold office for the unexpired term of the directorship in respect of which such vacancy occurred or for the full term of any new directorship caused by any increase in the number of members.

Section 4. Time and Place of Meetings . A regular meeting of the Board of Directors shall be held, without notice other than this bylaw, immediately after, and at the same place as, the annual meeting of shareholders. The Board of Directors may provide, by resolution, the time and place, either within or without the State of Iowa, for the holding of additional regular meetings without other notice than such resolution.

Section 5. Special Meetings . Special meetings of the Board of Directors for any purpose or purposes may be called by the Chairman of the Board of Directors (if there be one) or by the President or a majority of the Board of Directors, and shall be held at such place as may be fixed by the person or persons calling such meeting and as shall be specified in the notice of such meeting. The Secretary or an assistant secretary shall give not less than two (2) days' notice of the date, time and place of each such meeting to each director in the manner provided in Section 6 of this Article III. Neither the business to be transacted at, nor the purpose of, any special meeting of the Board of Directors need be specified in the notice given, or waiver of notice obtained, of such meeting as provided in Section 7 or 8, as the case may be, of this Article III.

Section 6. Manner of Giving Notice of Meetings . Notice of any special meeting of the Board of Directors may be given to any director by telephone, facsimile or by telegram addressed to such director at such address as last appears in the records of the Secretary of the corporation or by mail by depositing the same in the post office or letter box in a postpaid, sealed envelope addressed to such director at such address.

It shall be the duty of every director to furnish the Secretary of the corporation with the post office address of such director and to notify the Secretary of any change therein.

Section 7. Waiver of Notice . Whenever any notice is required to be given to directors under the provisions of the Iowa Business Corporation Act or of the Articles of Incorporation or these bylaws, a waiver thereof in writing signed by the director entitled to such notice, whether before, at or after the time stated therein, shall be deemed equivalent thereto. Attendance of a director at a meeting shall constitute a waiver of notice of such meeting, except where a director attends a meeting for the express purpose of objecting to the transaction of any business because the meeting is not lawfully called or convened.

Section 8. Quorum . At all meetings of the Board of Directors, a majority of the number of directors fixed by these bylaws shall constitute a quorum for the transaction of business. The act of a majority of the directors present at any meeting at which a quorum is present shall be the act of the Board of Directors, except as may be otherwise specifically provided by the Iowa Business Corporation Act or by the Articles of Incorporation or by these bylaws. If a quorum shall not be present at any meeting of directors, the director or directors present may adjourn the meeting to a specified time, without notice other than announcement at the meeting.

Section 9. Conduct of Meetings . The Chairman of the Board of Directors (if there be one), or in the absence of the Chairman of the Board of Directors, the President of the corporation shall act as the presiding officer at Board of Directors meetings, and the Secretary or an assistant secretary of the corporation shall act as the secretary of the meeting. In the absence of the Chairman of the Board of Directors (if there be one) and the President, the Board of Directors may appoint one of its number to act as the presiding officer. The presiding officer at Board of Director meetings shall be entitled to vote as a director on all questions.

Minutes of all meetings of the Board shall be permanently kept by the Secretary, and all minutes shall be signed by the presiding officer and attested by the secretary of the meeting.

The Board of Directors shall have power to formulate rules and regulations governing the conduct of Board of Directors meetings and the procedure thereat.

Section 10. Executive and Other Committees . The Board of Directors may, by resolution adopted by a majority of the number of directors fixed in accordance with Article III, Section 2 of these bylaws, designate from among its members an executive committee and one or more other committees each of which, to the extent provided in such resolution and permitted by the Iowa Business Corporation Act, shall have and may exercise all the authority of the Board of Directors.

Section 11. Compensation of Directors . The Board of Directors shall have the authority to fix the compensation of directors. Any director may serve the corporation in any other capacity and receive compensation therefor.

Section 12. Indemnification of Directors, Officers and Employees .

(a) Right to Indemnification . Each person who was or is a party or is threatened to be made a party to or is involved in any action, suit or proceeding, whether civil, criminal, administrative or investigative or arbitration and whether formal or informal ("proceeding"), by reason of the fact that he or she, or a person of whom he or she is the legal representative, is or was a director, officer or partner, trustee employee of the corporation or is or was serving at the request of the corporation as a director, officer or employee of another corporation or of a partnership, joint venture, trust or other enterprise, including service with respect to employee benefit plans, whether the basis of such proceeding is alleged action in an official capacity while serving as a director, officer or employee or in any other capacity while serving as a director, officer or employee, shall be indemnified and held harmless by the corporation to the fullest extent authorized by the Iowa Business Corporation Act, as the same exists or may hereafter be amended, (but, in the case of any such amendment, only to the extent that such amendment permits the corporation to provide broader indemnification rights than the Iowa Business Corporation Act permitted the corporation to provide prior to such amendment), against all reasonable expenses, liability and loss(including, without limitation, attorneys' fees, all costs, judgments, fines, Employee Retirement Income Security Act excise taxes or penalties and amounts paid or to be paid in settlement) reasonably incurred or suffered by such person in connection therewith. Such right shall be a contract right and shall include the right to be paid by the corporation expenses incurred in defending any such proceeding in advance of its final disposition; provided, however, that, the payment of such expenses incurred by a director, officer or employee in his or her capacity as a director, officer or employee (and not in any other capacity in which service was or is rendered by such person while a director, officer or employee including, without limitation, service to an employee benefit plan) in advance of the final disposition of such proceeding, shall be made only upon due authorization by a majority of disinterested directors or shareholders of the corporation and upon delivery to the corporation of (i) a written undertaking, by or on behalf of such director, officer or employee to repay all amounts so advanced if it should be determined ultimately that such director, officer or employee is not entitled to be indemnified under this Section or otherwise, or (ii) a written affirmation by or on behalf of such director, officer or employee that, in such person's good faith belief, such person has met the standards of conduct set forth in the Iowa Business Corporation Act.

(b) Right of Claimant to Bring Suit . If a claim under paragraph (a) is not paid in full by the corporation within thirty (30) days after a written claim has been received by the corporation, the claimant may at any time thereafter bring suit against the corporation to recover the unpaid amount of the claim and, if successful in whole or in part, the claimant shall be entitled to be paid also the expenses of prosecuting such claim. It shall be a defense to any such action that the claimant has not met the standards of conduct which make it permissible under the Iowa Business Corporation Act for the corporation to indemnify the claimant for the amount claimed, but the burden of proving such defense shall be on the corporation. The failure of the corporation (including its Board of Directors, independent legal counsel, or its shareholders) to have made a determination prior to the commencement of such action that indemnification of the claimant is proper in the circumstances because he or she has met the applicable standard of conduct set forth in the Iowa Business Corporation Act, shall not be a defense to the action or create a presumption that claimant had not met the applicable standard of conduct.

(c) Benefit . Indemnification provided hereunder shall, in the case of the death of the person entitled to indemnification, inure to the benefit of such person's heirs, executors or other lawful representatives. The invalidity or unenforceability of any provision of this Section 12 shall not affect the validity or enforceability of any other provision of this Section 12.

(d) Certain Actions; Presumption of Standard of Conduct . Any action taken or omitted to be taken by any director, officer or employee in good faith and in compliance with or pursuant to any order, determination, approval or permission made or given by a commission, board, official or other agency of the United States or of any state or other governmental authority with respect to the property or affairs of the corporation or any such business corporation, not-for-profit corporation, joint venture, trade association or other entity over which such commission, board, official or agency has jurisdiction or authority or purports to have jurisdiction or authority shall be presumed to be in compliance with the standard of conduct set forth in Section 490.851 (or any successor provision) of the Iowa Business Corporation Act whether or not it may thereafter be determined that such order, determination, approval or permission was unauthorized, erroneous, unlawful or otherwise improper.

(e) Litigation; Presumption of Standard of Conduct . Unless finally determined, the termination of any litigation, whether by judgment, settlement, conviction or upon a plea of nolo contendere, or its equivalent, shall not create a presumption that the action taken or omitted to be taken by the person seeking indemnification did not comply with the standard of conduct set forth in Section 490.851 (or successor provision) of the Iowa Business Corporation Act.

(f) Non-Exclusivity of Rights . The rights conferred on any person by this Section 12 shall not be exclusive of any other right which any person may have or hereafter acquire under any statute, provision of the Articles of Incorporation, as amended, bylaws, agreement, vote of shareholders or disinterested directors or otherwise.

(g) Insurance . The corporation may maintain insurance, at its expense, to protect itself and any such director, officer or employee of the corporation or another corporation, partnership, joint venture, trust or other enterprise against any such expense, liability or loss, whether or not the corporation would have the power to indemnify such person against such expense, liability or loss under the Iowa Business Corporation Act.

Section 13. Action by Directors Without a Meeting . Any action required to be taken at a meeting of the Board of Directors or a committee of directors and any other action which may be taken at a meeting of the Board of Directors or a committee of directors may be taken without a meeting if a consent in writing, setting forth the action so taken, shall be signed by all of the directors or all of the members of the committee of directors, as the case may be, entitled to vote with respect to the subject matter thereof.

ARTICLE IV

OFFICERS

At the first regular meeting of the Board of Directors following each annual meeting of the shareholders, the Board of Directors shall elect a President, a Secretary and a Treasurer; and the Board of Directors may at any meeting elect or appoint a Chairman of the Board of Directors, vice presidents and other officers or assistants to officers.

The Chairman of the Board of Directors (if there be one) shall be selected from among the members of the Board of Directors. Other officers may be, but are not required to be, directors. An officer may be, but need not be, a shareholder of the corporation.

Subject to the power of the Board of Directors to remove any officer from office at any time when in its judgment the best interests of the corporation will be served thereby, each officer shall serve until the successor of such officer is elected or appointed, unless his tenure of office is otherwise fixed by the Board of Directors by resolution, contract or agreement for a different period of time.

The Board of Directors shall have power to fix the compensation of each officer, to decrease or increase such compensation, to prescribe the duties of such officer, to change the nature of such duties, or to remove such officer from office and elect or appoint the successor of such officer, in each case subject to the terms of any agreement between such officer and the corporation.

Section 1. Chairman of the Board of Directors . The Chairman of the Board of Directors (if there be one) shall preside at all meetings of the shareholders and of the directors, at which the Chairman is present. The Chairman shall perform all duties incident to the office of Chairman of the Board of Directors and such other duties as, from time to time, may be assigned to the Chairman by the Board of Directors, and, if so designated by an appropriate resolution of the Board of Directors or an agreement between the Chairman and the corporation, shall be the chief executive officer of the corporation, subject, however, to the right of the Board of Directors to delegate any specific power to any other officer or officers of the corporation; and the Chairman shall see that all orders and resolutions of the Board of Directors are carried into effect.

Section 2. President . The President of the corporation shall have general and active management of and exercise general supervision of the business and affairs of the corporation and, if so designated by an appropriate resolution of the Board of Directors, or an agreement between the President and the corporation, shall be the chief operating officer of the corporation, subject, however, to the right of the Board of Directors to delegate any specific power to any other officer or officers of the corporation; and the President shall see that all orders and resolutions of the Board of Directors are carried into effect. The President shall have concurrent power with the Chairman of the Board of Directors to sign bonds, mortgages, certificates for shares, and other contracts and documents, except in cases where the signing and execution thereof shall be expressly delegated by law, by the Board of Directors, or by these bylaws to some other officer of the corporation. In the absence of the Chairman of the Board of Directors or in the event of the disability or refusal of the Chairman to act, the President shall have such other powers as are vested in the Chairman of the Board of Directors. In general, the President shall perform the duties incident to the office of President and such other duties as may be prescribed by the Board of Directors from time to time.

Section 3. Vice Presidents . The vice presidents shall perform such of the duties and exercise such of the powers of the President as shall be assigned to them from time to time by the Board of Directors or the President, and shall perform such other duties as the Board of Directors or the President shall from time to time prescribe. Any vice president may sign certificates for shares of the corporation and any deeds, mortgages, bonds, contracts or other instruments which the Board of Directors has authorized to be executed, which authorizations may be either specific or general. In case of the death, disability or absence of the Chairman of the Board of Directors (if there be one) and the President, then a vice president shall perform the duties of the President, including interim duties, and when so acting shall have all the powers of and be subject to all restrictions upon the President.

Section 4. Secretary . The Secretary shall attend all meetings of the shareholders and of the Board of Directors and shall keep the minutes of such meetings. The Secretary shall perform like duties for the standing committees of the Board of Directors when required. Except as otherwise provided by these bylaws or by the Iowa Business Corporation Act, the Secretary shall give, or cause to be given, notice of all meetings of the shareholders and of the Board of Directors, and shall perform such other duties as may be prescribed by the Board of Directors or the Chairman of the Board of Directors (if there be one) or the President.

The Secretary shall have custody of the minute books, containing the minutes of shareholders' and directors' meetings, of the stock books of the corporation, and of all corporate records. The Secretary shall have the duty to see that the books, reports, statements, certificates and all other documents and reports of the corporation required by law are properly prepared, kept and filed. The Secretary shall, in general, perform all duties incident to the office of Secretary.

Section 5. Assistant Secretaries . The assistant secretaries shall perform such of the duties and exercise such of the powers of the Secretary as shall be assigned to them from time to time by the Board of Directors or the Chairman of the Board of Directors (if there be one) or the President or the Secretary, and shall perform such other duties as the Board of Directors or the Chairman of the Board of Directors (if there be one) or the President shall from time to time prescribe.

Section 6. Treasurer . The Treasurer shall have the custody of all moneys, stocks, bonds and other securities of the corporation, and of all other papers on which moneys are to be received and of all papers which relate to the receipt or delivery of the stocks, bonds, notes and other securities of the corporation in the possession of the Treasurer. The Treasurer is authorized to receive and receipt for stocks, bonds, notes and other securities belonging to the corporation or which are received for its account, and to place and keep the same in safety deposit vaults rented for the purpose, or in safes or vaults belonging to the corporation. The Treasurer is authorized to collect and receive all moneys due the corporation and to receipt therefor, and to endorse all checks, drafts, vouchers or other instruments for the payment of money payable to the corporation when necessary or proper and to deposit the same to the credit of the corporation in such depositaries as the Treasurer may designate for the purpose, and the Treasurer may endorse all commercial documents for or on behalf of the corporation. The Treasurer is authorized to pay interest on obligations when due and dividends on stock when duly declared and payable. The Treasurer shall, when necessary or proper, disburse the funds of the Corporation, taking proper vouchers for such disbursements. The Treasurer shall cause to be kept in the office of the Treasurer true and full accounts of all receipts and disbursements, and shall render to the Board of Directors and the Chairman of the Board of Directors (if there be one) or the President, whenever they may require it, an account of all the transactions as Treasurer and of the financial condition of the corporation. The Treasurer shall also perform such other duties as may be prescribed by the Board of Directors or the Chairman of the Board of Directors (if there be one) or the President. The Treasurer shall, in general, perform all duties usually incident to the office of Treasurer.

Section 7. Assistant Treasurers . The assistant treasurers shall perform such of the duties and exercise such of the powers of the Treasurer as shall be assigned to them from time to time by the Board of Directors or the Chairman of the Board of Directors (if there be one) or the President or the Treasurer, and shall perform such other duties as the Board of Directors or the Chairman of the Board of Directors (if there be one) or the President shall from time to time prescribe.

ARTICLE V

STOCK CERTIFICATES

Section 1. Registrars and Transfer Agents . The Board of Directors shall determine the form of and provide for the issue, registration and transfer of the stock certificates of the corporation, and may appoint registrars and transfer agents, who may be natural persons or corporations. The office of any transfer agent or registrar may be maintained within or without the State of Iowa.

Section 2. Signatures . Stock certificates issued by the corporation shall bear the signatures of the Chairman of the Board of Directors (if there be one) or the President or any Vice President and of the Secretary or any assistant secretary and such officers are hereby authorized and empowered to sign such certificates when the issuance thereof has been duly authorized by the Board of Directors; provided, however, that if certificates representing shares of any class or series of stock issued by the corporation are countersigned by manual signature by a transfer agent, other than the corporation or its employee, or registered by manual signature by a registrar, other than the corporation or its employee, any other signature on such certificate may be a facsimile, engraved, stamped or printed. In case any officer who has signed or whose facsimile signature has been placed upon such certificate for the corporation shall cease to be such officer of the corporation before such certificate is issued, such certificate may be issued by the corporation with the same effect as if he were such officer at the date of its issue.

Section 3. Transfers . Transfers of shares shall be made on the books of the corporation only by the registered owner thereof (or the legal representative of such owner, upon satisfactory proof of authority therefor), or by the attorney of such owner lawfully constituted in writing by documents filed with the Secretary or transfer agent of the corporation, and only upon surrender of the certificate to be transferred, or delivery of an order of such owner if such shares are not represented by a certificate, and payment of applicable taxes with respect to such transfer, unless otherwise ordered by the Board of Directors.

Section 4. Lost or Destroyed Certificates . New certificates may be issued to replace lost, stolen or destroyed certificates, upon such terms and conditions as the Board of Directors may prescribe.

Section 5. Rights of Registered Owners . The corporation shall be entitled to recognize the exclusive right of a person registered or shown on its books as the owner of shares of its stock to receive dividends or any other distribution thereon, or to vote such shares, and to treat such person as the owner of such shares for all purposes and the corporation shall not be bound to recognize any equitable or other claim to or interest in its shares on the part of any person other than the registered or record owner thereof, whether or not it shall have notice thereof.

ARTICLE VI

GENERAL PROVISIONS

Section 1. Instruments Affecting Real Estate . Deeds, mortgages and other instruments affecting real estate owned by the corporation, the execution of which has been duly authorized by the Board of Directors, shall be signed on behalf of the corporation by the Chairman of the Board of Directors (if there be one) or the President or any vice president and by the Secretary or any assistant secretary. Leases, contracts to purchase, and other instruments whereby the corporation acquires, in the ordinary course of business, an interest in real estate owned by others may be executed on behalf of the corporation by the Chairman of the Board of Directors (if there be one), the President or by any officer or employee of the corporation thereunto authorized by the Chairman of the Board of Directors (if there be one) or the President, without obtaining specific authorization therefor from the Board of Directors.

Section 2. Other Instruments . Bonds, notes and other secured or unsecured obligations of the corporation, when duly authorized by the Board of Directors, may be executed on behalf of the corporation by the Chairman of the Board of Directors (if there be one) or the President or any vice president, or by any other officer or officers thereunto duly authorized by the Board of Directors and the signature of any such officer may, if the Board of Directors shall so determine, be a facsimile. Contracts and other instruments executed in the ordinary course of business may be signed on behalf of the corporation by the Chairman of the Board of Directors (if there be one) or the President or by any officer or employee of the corporation thereunto authorized by the Chairman of the Board of Directors (if there be one) or the President, without obtaining specific authorization therefor from the Board of Directors.

Section 3. Fiscal Year . The fiscal year of the corporation shall be the calendar year.

Section 4. No Corporate Seal . The corporation shall have no corporate seal.

Section 5. Stock in Other Corporations . Unless otherwise ordered by the Board of Directors, the Chairman of the Board of Directors (if there be one) or the President or any vice president of the corporation (i) shall have full power and authority to act and vote, in the name and on behalf of this corporation, at any meeting of shareholders of any corporation in which this corporation may hold stock, and at any such meeting shall possess and may exercise any and all of the rights and powers incident to the ownership of such stock, and (ii) shall have full power and authority to execute, in the name and on behalf of this corporation, proxies authorizing any suitable person or persons to act and to vote at any meeting of shareholders of any corporation in which this corporation may hold stock, and at any such meeting the person or persons so designated shall possess and may exercise any and all of the rights and powers incident to the ownership of such stock.

ARTICLE VII

AMENDMENTS

These bylaws may be altered, amended or repealed and new bylaws may be adopted by vote of a majority of the Board of Directors at any regular or special meeting of the Board of Directors.

EXHIBIT 4.17

Execution Copy

AMENDMENT NO. 1 TO

SHAREHOLDERS AGREEMENT

This Amendment No. 1, dated as of December 7, 2005 (this “Amendment”) to the Shareholders Agreement, dated as of March 14, 2000 (the “Agreement”), by and among Berkshire Hathaway Inc., a Delaware corporation (“Berkshire”); Walter Scott, Jr. (“Scott”), Sandra Scott Parker, Amy Lynn Scott Trust #3, Karen Ann Scott Trust #3, Sandra Sue Scott Trust #3, Walter David Scott Trust #3, Amy Lynn Scott Wyoming Trust, W. David Scott Wyoming Trust, Karen Ann Dixon Wyoming Trust, Double Eight Land Corporation (the “Scott Family Entities”) and David L. Sokol and Gregory E. Abel (the “Management Investors,” and, together with Berkshire, Scott and the Scott Family Entities, the “Investors”); and MidAmerican Energy Holdings Company, an Iowa corporation (formerly named Teton Acquisition Corp., and hereinafter referred to as the “Company”).

WHEREAS, Scott and the holders of a majority in interest of the Scott Family Entities’ Securities have agreed to eliminate their existing right under Section 4(c) of the Agreement to require the payment of cash by Berkshire upon any exercise of the Scott Put, but will retain their existing right under Section 4(c) to receive shares of Berkshire common stock upon any exercise of the Scott Put;

WHEREAS, Berkshire has agreed to grant to the Management Investors a similar right to put their shares of Common Stock, no par value, of the Company (“Common Stock”) to Berkshire in exchange for shares of Berkshire common stock;

WHEREAS, the Management Investors have agreed to grant to Berkshire a right of first refusal in respect of the Securities owned by them;

WHEREAS, the parties hereto desire to clarify that all puts of Common Stock to Berkshire in exchange for Berkshire common stock made at any time after Berkshire owns in excess of 80% of the vote and value of the Company are intended to qualify as a tax-free reorganization within the meaning of Section 368(a)(1)(B) of the Internal Revenue Code of 1986 (the “Code”) and the parties further intend that the Agreement, as amended, constitutes a “plan of reorganization” within the meaning of Treasury Regulation Section 1.368-2(g) as to such puts and that each such exchange of Common Stock for Berkshire common stock will be pursuant to such plan of reorganization; and

WHEREAS, the parties hereto desire to amend the Agreement to effect the foregoing changes and other related changes, all as further set forth herein.

NOW, THEREFORE, in consideration of the mutual covenants and agreements herein contained, the parties hereto agree as follow:

1. SECTION 2(a) . Section 2(a) of the Agreement is hereby deleted in its entirety and replaced by a new Section 2(a) to read as follows:

“(a) Resale of Management Investors' Securities. Except as otherwise provided in Section 3, and except for Permitted Management Transfers (as defined below), no Management Investor shall Transfer any Securities, or any beneficial interest therein, other than to (i) such Management Investor's spouse, or his or her ancestors, lineal descendants, siblings or estate, (ii) any trusts for the benefit of such Management Investor or any of the persons or entities described in subpart (i) hereof, (iii) any limited liability company, partnership or corporation controlled by, and substantially entirely owned by, such Management Investor and/or any of the persons or entities described in subpart (i) hereof and (iv) charitable foundations or trusts which are controlled by such Management Investor and/or any of the persons described in subpart (i) hereof (collectively, “Management Permitted Transferees”). As used herein, “Permitted Management Transfers” shall mean (v) Transfers between or among such Management Investor's and/or his spouse's Management Permitted Transferees, (w) Transfers between Management Investors, (x) Transfers at any time in compliance with Sections 2(d) through 2(k) hereof, (y) Transfers made at any time pursuant to the Management Put described in Section 4(a), the Management Call described in Section 4(b) or the Management Exchange Put described in Section 4(d) and (z) other Transfers agreed upon by such Management Investor and Berkshire from time to time. For the avoidance of doubt, this Section 2(a) is not intended to diminish any transfer restrictions contained in any option agreement governing the Options. The Transfer restrictions contained in this Section 2 shall terminate upon a Berkshire Majority Transfer.”

2. SECTION 2(d). Section 2(d) of the Agreement is hereby amended by deleting the word “unless” contained therein and by replacing it with the following words: “and, except as otherwise permitted by Section 2(a) hereof, no Management Investor shall Transfer any Securities, unless, in any such case,”.

3. SECTION 2(e). Section 2(e) of the Agreement is hereby amended by deleting the words “shares of Common Stock” in both places where they appear therein and by replacing them in both such places with the words, “applicable Securities”.

4. SECTION 4(a) . Section 4(a) of the Agreement is hereby amended by adding a new proviso at the end of the first sentence thereof, to read as follows: “; and provided further that a Management Investor may not exercise his or her Management Put at any time that, and for so long as, the Company notifies the Management Investors that, in its good faith judgment after consultation with outside counsel experienced in tax matters, there is a meaningful risk that the exercise of a Management Put at that time could reasonably be expected to cause any exchange pursuant to a Scott Exchange Put or a Management Exchange Put to fail to qualify as a tax-free reorganization within the meaning of Section 368(a)(1)(B) of the Code.”

5. SECTION 4(b ). Section 4(b) of the Agreement is hereby amended by inserting the words “subject to the provisions contained in the last sentence of Section 4(f)(ii) hereof,” immediately after the words “At any time after the earlier of the third anniversary of the date hereof or a Berkshire Majority Transfer,” contained in the first sentence of Section 4(b). Section 4(b) of the Agreement is hereby further amended by deleting the words “only once” contained in the proviso to the first sentence thereof and replacing such words with the words “no more than twice”.

6. EXISTING SECTIONS 4(c), 4(d) AND 4(e). Sections 4(c), 4(d) and 4(e) of the Agreement shall be eliminated in their entirety and replaced by new Sections 4(c), 4(d) and 4(e) to read as follows:

“(c) The Scott Exchange Put. At any time following the date of Amendment No. 1 to this Agreement, and provided in any such case that Berkshire is then an Eligible Purchaser, Scott, any or all of the Scott Entities and any or all of the Scott Family Entities shall have the right to require Berkshire to purchase, upon the terms and subject to the conditions of this Agreement, any or all of the shares of Common Stock owned by such persons and entities (the “Scott Exchange Put”) in exchange for shares of Berkshire common stock (“Berkshire Shares”) equal in value to the Final Agreed Purchase Price or Final Appraised Purchase Price, as applicable. For purposes of any such purchase and exchange, the value of each Berkshire Share to be received in the exchange shall be equal to the closing price quoted for such Berkshire Shares on the New York Stock Exchange on the day immediately preceding the closing of such exchange. In the event that Scott, any of the Scott Entities or any of the Scott Family Entities elect to exercise the Scott Exchange Put, then such person or entity shall provide a written exchange put notice to Berkshire specifying the number of shares of Common Stock to be put and exchanged by them (a “Scott Exchange Put Notice”). The Scott Exchange Put shall terminate upon a Berkshire Majority Transfer. Berkshire shall register all Berkshire Shares issued upon any exercise of a Scott Exchange Put for resale by promptly filing an S-3 Registration Statement (or, when applicable, a prospectus supplement) with respect to such shares if the value thereof exceeds $15 million and, in connection therewith, Berkshire shall, if eligible, request automatic effectiveness under Rule 415 (“Rule 415”) promulgated pursuant to the Securities Act of 1933, as amended. Notwithstanding anything contained in this Agreement to the contrary, Berkshire shall have no obligation to register any such Berkshire Shares (or, following a registration of such Berkshire Shares, to maintain the effectiveness of the applicable Registration Statement) if all such Berkshire Shares may be sold in a single sale without any limitation as to volume under Rule 144(e) of the Securities Act by virtue of Rule 144(k) thereunder. In addition, if any registration of such Berkshire Shares should not be made or continued because it would require Berkshire to disclose in a registration statement information not otherwise then required by law to be publicly disclosed (without regard to any existing registration statement filed in connection with this Agreement) and Berkshire has a bona fide purpose for delaying such disclosure (a “Valid Business Reason”), then Berkshire may postpone filing the registration statement or, if a registration statement has already been filed, may (upon prompt notice to the selling stockholders) postpone amending or supplementing such registration statement, until such Valid Business Reason no longer exists, provided that Berkshire agrees to use all reasonable efforts to minimize the duration and frequency of any such delays to the extent consistent with Berkshire’s financial, strategic, and other business priorities and provided further that any such postponement or postponements shall not exceed an aggregate of ninety (90) days during any consecutive period of one hundred and eighty (180) days..

(d) The Management Exchange Put. At any time following the date of Amendment No. 1 to this Agreement, and provided in any such case that Berkshire is then an Eligible Purchaser, any or all of the Management Investors shall have the right to require Berkshire to purchase, upon the terms and subject to the conditions of this Agreement, any or all of the shares of Common Stock owned by such persons (the “Management Exchange Put”) in exchange for Berkshire Shares equal in value to the Final Agreed Purchase Price or Final Appraised Purchase Price, as applicable; provided, however, that a Management Investor may exercise a Management Exchange Put as to his or her Common Stock only once in any twelve month period. For purposes of any such purchase and exchange, the value of each Berkshire Share to be received in the exchange shall be equal to the closing price quoted for such Berkshire Shares on the New York Stock Exchange on the day immediately preceding the closing of such exchange. In the event that any of the Management Investors elect to exercise the Management Exchange Put, then such person shall provide a written exchange put notice to Berkshire specifying the number of shares of Common Stock to be put and exchanged by them (a “Management Exchange Put Notice”). The Management Exchange Put shall terminate upon a Berkshire Majority Transfer. Berkshire shall register all Berkshire Shares issued upon any exercise of a Management Exchange Put for resale by promptly filing an S-3 Registration Statement (or, when applicable, a prospectus supplement) with respect to such shares if the value thereof exceeds $15 million and, in connection therewith, Berkshire shall, if eligible, request automatic effectiveness under Rule 415. Notwithstanding anything contained in this Agreement to the contrary, Berkshire shall have no obligation to register any such Berkshire Shares (or, following a registration of such Berkshire Shares, to maintain the effectiveness of the applicable Registration Statement) if all such Berkshire Shares may be sold in a single sale without any limitation as to volume under Rule 144(e) of the Securities Act by virtue of Rule 144(k) thereunder. In addition, if Berkshire determines, in its good faith judgment, that any registration of such Berkshire Shares should not be made or continued because of a Valid Business Reason, then Berkshire may postpone filing the registration statement or, if a registration statement has already been filed, may (upon prompt notice to the selling stockholders) postpone amending or supplementing such registration statement, until such Valid Business Reason no longer exists, provided that Berkshire agrees to use all reasonable efforts to minimize the duration and frequency of any such delays to the extent consistent with Berkshire’s financial, strategic, and other business priorities and provided further that any such postponement or postponements shall not exceed an aggregate of ninety (90) days during any consecutive period of one hundred and eighty (180) days.

(e) The Purchase Price The purchase price payable pursuant to Section 4(a) or 4(b) above shall be payable in cash and the purchase price (also sometimes referred to as the exchange price) payable pursuant to Section 4(c) or 4(d) above shall be payable in Berkshire Shares. Any purchase and exchange effected pursuant to Section 4(c) or 4(d) above at a time when Berkshire owns more than 80% in vote and value of the Company shall be deemed to have been implemented in a plan of reorganization within the meaning of Treasury Regulation section 1.368-2(g). With respect to any shares of Common Stock subject to any Management Put, Management Call, Scott Exchange Put or Management Exchange Put, the purchase price (or exchange price) shall equal the applicable number of shares of Common Stock multiplied by the purchase price per share, which shall be the fair market value of a share of Common Stock assuming the Company is valued on a going-concern basis as though it were a publicly traded company with reasonable liquidity in the market for its shares and without a controlling shareholder and without attributing any change of control premium to the sale of such share, and taking into account all aspects of the Company's capital structure including all outstanding options. With respect to any Options subject to a Management Put, the purchase price shall be determined as if the Options had been exercised, with the purchase price per share determined as described above, and reduced by the applicable exercise price or prices. With respect to any Options subject to a Management Call, the purchase price determined as described in the immediately preceding sentence shall be increased to the extent required to reflect the loss of the remaining time value of the Options. The applicable purchase price (or exchange price, as applicable) as determined pursuant to this Section 4(e) is referred to as the “Purchase Price” and the applicable “Final Agreed Purchase Price,” “Final Appraised Purchase Price” and “Final Purchase Price” shall be determined pursuant to the applicable procedures set forth in Sections 4(f) and 4(g) below.”

7. EXISTING SECTIONS 4(f) AND 4(g) AND NEW SECTION 4(f). Sections 4“(f)” and 4“(g)” of the Agreement are amended by recaptioning such sections as Sections 4“(g)” and 4“(h)”, respectively, and by inserting a new Section 4(f) immediately before such recaptioned section 4(g), with such new Section 4(f) to read in its entirety as follows:

“(f) Determination of the Purchase Price for the Management Put or Management Call or for the Management Exchange Put. (i) As soon as reasonably practicable, but in any event within fifteen (15) days, following the delivery of a Management Put Notice or a Management Call Notice, the Company shall prepare and deliver to each selling Management Investor a statement setting forth the good faith calculation of the Purchase Price as of the date of the notice, together with detail reasonably sufficient for such Management Investor(s) to evaluate the accuracy of such calculation (the “Purchase Price Statement”). Unless any selling Management Investor, within fifteen (15) days after receipt of the Purchase Price Statement, delivers to the Company a notice (the “Dispute Notice”): (i) objecting in good faith to such Purchase Price Statement, (ii) setting forth in reasonable detail the items being disputed and the reasons therefor and (iii) specifying such selling Management Investor's preliminary calculation of the Purchase Price as of the date of the Put Notice or the Call Notice, as applicable, such Purchase Price Statement shall be deemed to be final, and the Purchase Price set forth therein shall be deemed to be the applicable “Final Agreed Purchase Price”. If a selling Management Investor delivers a Dispute Notice and if the Company and such selling Management Investor(s) are unable to agree upon a Final Agreed Purchase Price within thirty (30) days of the date of the Dispute Notice, then any such selling Management Investor or the Company may elect to submit the calculation of the Purchase Price to an independent appraiser who shall be a member of a reputable valuation firm or investment bank which is designated jointly by the Company and such Management Investor(s); provided, however, that the Company and the Management Investors (as a group) may each only exercise their respective rights to seek an appraisal under this Section 4(f)(i) or, in the case of the Management Investors, Section 4(f)(ii) only once in any twelve (12) month period. Such appraiser shall determine the Purchase Price as of the date of the Management Put Notice or Management Call Notice, as applicable, and such Purchase Price shall be deemed to be the applicable “Final Appraised Purchase Price”. If the appraisal results from a Management Put Notice or a Management Call Notice, within thirty (30) days of the determination of the Final Appraised Purchase Price by the appraiser, (i) any Management Investor, including the Management Investor giving the original Management Put Notice, may elect to exercise or withdraw its Management Put to sell Securities to the Company for the applicable Final Appraised Purchase Price and (ii) the Company may elect to exercise or withdraw the Management Call to purchase Securities from any Management Investor, including the Management Investor giving the original Management Put Notice, for the applicable Final Appraised Purchase Price. If the Management Put is exercised pursuant to the preceding sentence by any Management Investor, then the Management Investors (as a group) shall have no further right to request an appraisal under this Section 4(f)(i) or under Section 4(f)(ii) below for a twelve (12) month period in connection with a Management Put or Management Call or a Management Exchange Put, and if the Management Call is exercised pursuant to the preceding sentence, then the Company shall have no further right to request an appraisal for a twelve (12) month period in connection with a Management Put or Management Call.

(ii) As soon as reasonably practicable, following the delivery of a Management Exchange Put Notice, Berkshire shall prepare and deliver to each Management Investor who delivered such a notice a Purchase Price Statement. Unless any such Management Investor, within fifteen (15) days after receipt of the Purchase Price Statement, delivers to Berkshire a Dispute Notice (i) objecting in good faith to such Purchase Price Statement, (ii) setting forth in reasonable detail the items being disputed and the reasons therefore and (iii) specifying such Management Investor’s preliminary calculation of the Purchase Price as of the date of the Management Exchange Put Notice, such Purchase Price Statement shall be deemed to be final, and the Purchase Price set forth therein shall be deemed to be the applicable “Final Agreed Purchase Price”. If a Management Investor delivers a Dispute Notice and if Berkshire and such Management Investor(s) are unable to agree upon a Final Agreed Purchase Price within thirty (30) days of the date of the Dispute Notice, then any such Management Investor(s) or Berkshire may elect to submit the calculation of the Purchase Price to an independent appraiser who shall be a member of a reputable valuation firm or investment bank which is designated jointly by Berkshire and such Management Investor(s); provided, however, that Berkshire and the Management Investors (as a group) may each only exercise their respective rights to seek an appraisal under this Section 4(f)(ii) or, in the case of the Management Investors, under Section 4(f)(i) only once in any twelve (12) month period. Such appraiser shall determine the Purchase Price as of the date of the Management Exchange Put Notice and such Purchase Price shall be deemed to be the applicable “Final Appraised Purchase Price”. Notwithstanding anything to the contrary contained in Section 4(b) or elsewhere in this Agreement, from and after the date of delivery of a Management Exchange Put Notice by any Management Investor, the Company shall have no right to exercise its Management Call as to any shares of Common Stock that are the subject of a Management Exchange Put.”

8. SECTION 4(g) . Recaptioned Section 4(g) of the Agreement is hereby amended by deleting the words “ten (10) days” in the second sentence thereof and replacing them with the words “fifteen (15) days”.

9. SECTION 4(h). Recaptioned Section 4(h) of the Agreement is hereby amended by inserting the words “(or Final Agreed Purchase Price or Final Appraised Purchase Price, as applicable)” immediately after the words “Final Purchase Price” in the first sentence thereof and by deleting the last two sentences of such section and by replacing them with three new sentences to read as follows:

“The purchase price shall be paid in cash or Berkshire Shares, as applicable, at the closing. At the closing, the selling or exchanging Investor(s) shall deliver to the purchasing party the certificates evidencing the Securities to be conveyed, duly endorsed and in negotiable form with all requisite documentary stamps affixed thereto. In addition, if the closing relates to an exercise of a Scott Exchange Put or a Management Exchange Put, then Berkshire shall deliver to the exchanging Investor(s) duly authorized and executed certificates evidencing the applicable Berkshire Shares at the closing.”

10. THE WORDS “SCOTT PUT” AND “SCOTT PUT NOTICE”. The words “Scott Put” and “Scott Put Notice” shall be replaced with the words “Scott Exchange Put” and “Scott Exchange Put Notice”, respectively, in each and every place that they appear in the Agreement.

11. CERTAIN SECTION REFERENCES. All references to “4(d)” and “4(e)” contained within the defined terms set forth in Section 7(a) of the Agreement shall be amended to read “4(e)” and “4(f)”, respectively.

12. DEFINITION OF “TRANSFER”. The definition of the term “Transfer” contained in Section 7(a) of the Agreement shall be amended by adding the words “Management Exchange Put” immediately after the words “Management Put” contained therein.

13. SECTION 8(d). Section 8(d) of the Agreement is amended by changing the reference to “4(a), (b), (d), (e) and (g)” contained therein to read “4(a), 4(b), 4(d), 4(e), 4(f) and 4(h)”. Section 8(d) is further amended by changing the reference to “4(c)-(g)” contained therein to read “4(c), 4(e), 4(f), 4(g) or 4(h)”.

14. NO OTHER AMENDMENTS. Except as expressly set forth in this Amendment, there shall be no other changes to the Agreement and all other provisions of the Agreement shall remain in full force and effect.

15. GOVERNING LAW. This Amendment shall be governed by and construed in accordance with the laws of the State of Iowa applicable to contracts made and to be performed entirely within such State.

16. SECTION HEADINGS. The headings of sections in this Amendment are inserted for convenience only and shall not be deemed to constitute a part hereof.

17. COUNTERPARTS . This Agreement may be executed in one or more counterparts, each of which shall be deemed an original and all of which together shall be considered one and the same agreement.

IN WITNESS WHEREOF, the parties hereto have executed this Amendment as of the date first above written.


	MIDAMERICAN ENERGY HOLDINGS COMPANY

	By:	/s/ Douglas L. Anderson
		Name: Douglas L. Anderson
		Title:


	/s/ Walter Scott, Jr.
	Walter Scott, Jr.

	MANAGEMENT INVESTORS

	/s/ David L. Sokol
	David L. Sokol

	/s/ Gregory E. Abel
	Gregory E. Abel


	BERKSHIRE HATHAWAY, INC.

	By:	/s/ Marc D. Hamburg
		Name: Marc D. Hamburg
		Title:

[SIGNATURE PAGE 1 OF SHAREHOLDERS AGREEMENT]


	AMY LYNN SCOTT TRUST #3

	By:	U.S. BANK NATIONAL ASSOCIATION, as trustee

	By:	/s/ Kathleen Sites
		Name: Kathleen Sites
		Title: VP


	KAREN ANN SCOTT TRUST #3

	By:	U.S. BANK NATIONAL ASSOCIATION, as trustee

	By:	/s/ Kathleen Sites
		Name: Kathleen Sites
		Title: VP


	SANDRA SUE SCOTT TRUST #3

	By:	U.S. BANK NATIONAL ASSOCIATION, as trustee

	By:	/s/ Kathleen Sites
		Name: Kathleen Sites
		Title: VP


	WALTER DAVID SCOTT TRUST #3
	By:	U.S. BANK NATIONAL ASSOCIATION, as trustee

	By:	/s/ Kathleen Sites
		Name: Kathleen Sites
		Title: VP

[SIGNATURE PAGE 2 OF SHAREHOLDERS AGREEMENT]

		/s/ Sandra Scott Parker
		Sandra Scott Parker


	AMY LYNN SCOTT WYOMING TRUST

	By:	THE WASHINGTON COMPANY, a Wyoming
		corporation, successor trustee

	By:	/s/ John K. Boyer
		Name: John K. Boyer
		Title:


	W. DAVID SCOTT WYOMING TRUST

	By:	THE WASHINGTON COMPANY, a Wyoming
		corporation, successor trustee

	By:	/s/ John K. Boyer
		Name: John K. Boyer
		Title:


	KAREN ANN DIXON WYOMING TRUST
	By:	THE WASHINGTON COMPANY, a Wyoming
		corporation, successor trustee

	By:	/s/ John K. Boyer
		Name: John K. Boyer
		Title:


	DOUBLE EIGHT LAND CORPORATION

	By:	/s/ Walter Scott, Jr.
		Name: Walter Scott, Jr.
		Title:

[SIGNATURE PAGE 3 OF SHAREHOLDERS AGREEMENT]

EXHIBIT 10.72

Execution Copy

EQUITY COMMITMENT AGREEMENT

EQUITY COMMITMENT AGREEMENT (“Agreement”), dated as of March 1, 2006, between BERKSHIRE HATHAWAY INC., a corporation duly organized and validly existing under the laws of the State of Delaware (“ Berkshire ”), and MIDAMERICAN ENERGY HOLDINGS COMPANY, a corporation duly organized and validly existing under the laws of the State of Iowa (“ MEHC ”).

RECITALS

WHEREAS, it is necessary from time to time for MEHC to fund the capital requirements of its various subsidiaries; and

WHEREAS, Berkshire, as the owner of certain of the equity interests in MEHC, anticipates that it will benefit from MEHC’s funding of such capital requirements; and

WHEREAS, Berkshire desires to provide for equity contributions to MEHC for the express purpose of funding such capital requirements;

AGREEMENT

NOW THEREFORE, in consideration of the foregoing recitals and the covenants and agreements as hereinafter set forth, and for other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, each of the parties hereto hereby agrees as follows:

Section 1. Definitions . The following terms shall have the following meanings when used in this Agreement:

“Common Stock Valuation ” means the per share value of MEHC’s common stock on a given date, as mutually agreed to by MEHC and the Equity Contributor, or if MEHC and the Equity Contributor cannot agree on such per share value, the amount determined pursuant to the appraisal procedure specified in Section 2(b) .

“ Equity Contribution ” means a capital contribution to MEHC required to be made, or caused to be made, by Berkshire in accordance with Section 2 hereof.

“ Equity Contributor ” means Berkshire and any successor and assign as permitted by this Agreement.

“ Equity Requisition Certificate ” means a certificate substantially in the form of Exhibit A hereto.

“ Equivalent Common Shares ” means, with respect to any given Equity Contribution, the closest whole number of duly authorized, validly issued, fully paid and non-assessable shares of MEHC’s common stock calculated by dividing the amount of such Equity Contribution by the Common Stock Valuation on the date of such Equity Contribution.

“ Maximum Equity Amount ” means $3,500,000,000.

Section 2. Equity Contributions . (a) From and after the date hereof until February 28, 2011 (the “Termination Date”), the Equity Contributor shall contribute, or cause to be contributed, to MEHC from time to time, on or prior to the date specified in the Equity Requisition Certificate referred to below, any Equity Contribution (in an amount equal to $250,000,000 or any integral multiple thereof) requested by MEHC in an Equity Requisition Certificate duly authorized by the MEHC Board of Directors and received by the Equity Contributor at least 180 calendar days prior to such date; provided , however , that such Equity Contribution, together with the aggregate amount of all previous Equity Contributions made by Berkshire and other MEHC equity holders pursuant to this Section 2 shall not exceed the Maximum Equity Amount. Equity Contributor shall not be required to contribute, or cause to be contributed, any Equity Contribution unless Equity Contributor shall have received and not previously satisfied an appropriately completed Equity Requisition Certificate for the amount of such contribution from MEHC at least 180 calendar days prior to the date on which such Equity Contribution is to be made. MEHC shall evidence each Equity Contribution by issuing in the name of the Equity Contributor or its designee the Equivalent Common Shares associated with such Equity Contribution and any such Equity Contribution shall be made simultaneously with and conditioned upon issuance to the Equity Contributor of the Equivalent Common Shares.

(b) In the event that MEHC and the Equity Contributor cannot agree on the Common Stock Valuation associated with any given Equity Contribution, then the Common Stock Valuation shall be the fair market value of a share of MEHC’s common stock assuming MEHC is valued on a going-concern basis as though it were a publicly traded company and without a controlling shareholder and without attributing any change of control premium to the sale of such share, and taking into account all aspects of MEHC’s capital structure including all outstanding options, determined as follows:

(i) As soon as reasonably practicable, but in any event within fifteen (15) days, following the delivery of an Equity Requisition Certificate, MEHC shall prepare and deliver to Berkshire a statement setting forth the good faith calculation of the Common Stock Valuation as of the date of the Equity Requisition Certificate, together with detail reasonably sufficient for Berkshire to evaluate the accuracy of such calculation (the “Valuation Statement”).

(ii) Unless Berkshire, within fifteen (15) days after receipt of the Valuation Statement, delivers to MEHC a notice (the “Dispute Notice”) objecting in good faith to the Valuation Statement, the Valuation Statement shall be deemed to be final, and the Common Stock Valuation set forth therein shall be deemed to be the “Final Common Stock Valuation”.

(iii) If Berkshire delivers a Dispute Notice and if MEHC and Berkshire are unable to agree upon a Final Common Stock Valuation within thirty (30) days of the date of the Dispute Notice, then either Berkshire or MEHC may elect to submit the calculation of the Common Stock Valuation to an independent appraiser who shall be a member of a reputable valuation firm or investment bank which is designated jointly by Berkshire and MEHC. Such appraiser shall determine the Common Stock Valuation at the date of the Equity Requisition Certificate, and such Common Stock Valuation shall be deemed to be the Final Common Stock Valuation with respect to such Equity Requisition Certificate.

(c) Submission of an Equity Requisition Certificate shall be at MEHC’s discretion and this Agreement does not create any obligation requiring MEHC to request an Equity Contribution. MEHC shall use its reasonable best efforts to fund the obligations of MEHC and its subsidiaries and minimize or avoid requests for an Equity Contribution.

(d) Contemporaneous with the delivery of any Equity Requisition Certificate to Berkshire under this Agreement, MEHC shall also deliver a copy of such Equity Requisition Certificate to the then current holders of record of each share of MEHC’s common stock. Within one (1) business day of the determination of the Common Stock Valuation associated with such Equity Requisition Certificate, MEHC shall also send a notice thereof to each such holder (a “Common Stock Valuation Notice”). If any such holder sends a written notice to MEHC and Berkshire within thirty (30) calendar days of the date of such Common Stock Valuation Notice (or such lesser number of days as may be remaining prior to the date specified in the Equity Requisition Certificate) of such holder’s irrevocable commitment to participate in such Equity Contribution, then Berkshire’s portion of the Equity Contribution shall be reduced by an amount equal to the product of (i) the Equity Contribution and (ii) the ratio of (A) the aggregate number of shares of MEHC’s common stock then held by such holder determined on a diluted basis over (B) the total number of shares of MEHC’s common stock determined on a diluted basis (a “Proportionate Reduction”). MEHC and Berkshire hereby agree to permit such holder to participate in the Equity Contribution in an amount equal to the Proportionate Reduction and receive the Equivalent Common Shares associated therewith. If any such holder fails to timely fund such irrevocable commitment, Berkshire shall provide such portion of the Equity Contribution and the applicable Equivalent Common Shares shall be issued to Berkshire, without prejudice to MEHC’s rights to seek damages for breach of any holder’s irrevocable commitment.

Section 3. Use of Equity Contribution . MEHC shall use the proceeds of an Equity Contribution only for the purpose of (a) paying when due MEHC debt obligations and (b) funding the general corporate purposes and capital requirements of MEHC’s regulated subsidiaries.

Section 4. Obligations Unconditional; Waivers . (a) The obligations of the Equity Contributor under Section 2 shall be absolute, unconditional and irrevocable under any and all circumstances, and shall be performed (to the fullest extent permitted by applicable law) by the Equity Contributor regardless of:

(i) the existence of any indebtedness owing by MEHC or any affiliate thereof to the Equity Contributor or of any setoff, abatement, counterclaim, recoupment, defense or other right or claim which the Equity Contributor may have against MEHC, any affiliate thereof or any other person; or

(ii) the availability of other possible funding sources to MEHC or any of its subsidiaries.

(b) The obligation of the Equity Contributor to make or cause to be made an Equity Contribution as provided in Section 2 shall not be affected by (to the fullest extent permitted by applicable law) any abatement, reduction, limitation, impairment, termination, setoff, defense, counterclaim or recoupment whatsoever or any right to any thereof, and shall not be released, discharged or in any way affected by any reorganization, arrangement, compromise or plan affecting MEHC or any affiliate thereof.

(c) In respect of the obligation of the Equity Contributor to make or cause to be made Equity Contributions as provided in Section 2 , the Equity Contributor hereby unconditionally (to the fullest extent permitted by applicable law):

(i) waives notice of acceptance hereof and of any defaults by MEHC or any affiliate thereof in the payment of any amounts due, protest, presentment, or any other act or omission or thing or delay to do any other act or thing which might in any manner or to any extent vary the risk of such Equity Contributor, but does not waive the conditions set forth in Section 2(a);

(ii) agrees that this Agreement shall remain in full force and effect without regard to, and shall not be affected or impaired by, any invalidity, irregularity or unenforceability in whole or in part of any other document;

(iii) agrees that no failure or delay on the part of MEHC or any other person in exercising any right, power or privilege hereunder or under any other document and no course of dealing between such Equity Contributor on the one hand, and MEHC, any affiliate thereof on the other hand, shall operate as a waiver thereof, nor shall any single or partial exercise of any right, power or privilege hereunder preclude any other or further exercise thereof or the exercise of any other right, power or privilege hereunder;

(iv) agrees that the rights and remedies herein provided are cumulative and not exclusive of any rights or remedies which MEHC would otherwise have; and

(v) agrees that this Agreement shall be discharged only by complete performance and payment in full of the obligations contained herein or by occurrence of the Termination Date (so long as no Equity Requisition Certificate remains outstanding and unsatisfied) and that the Equity Contributor shall have no right to withhold or set-off against any payments due for any reason.

Section 5. Representations and Warranties : Berkshire hereby represents and warrants that:

(a) it is a corporation duly formed, validly existing and in good standing under the laws of the State of Delaware, and it is duly qualified and authorized to do business and is in good standing as a foreign corporation in each jurisdiction in which it owns or leases real property or in which the nature of its business requires it to be so qualified, except where the failure to be so qualified and authorized to do business and in good standing would not reasonably be expected to materially adversely affect its ability to perform its obligations under this Agreement;

(b) it has all necessary power and authority to execute and deliver this Agreement and to perform all of its obligations hereunder, and its execution, delivery and performance of this Agreement have been duly authorized by all necessary action on its part and do not require any approval or consent of any holder (or any trustee for or agent of any holder) of any indebtedness or other obligation of it or any other person or entity, other than approvals or consents which have previously been obtained and which are in full force and effect;

(c) it has duly executed and delivered this Agreement and this Agreement constitutes the valid and binding obligation of it enforceable against it in accordance with its terms, except as enforceability may be limited by general equitable principles and applicable bankruptcy, insolvency, reorganization, moratorium or other similar laws affecting the rights of creditors generally;

(d) the execution and delivery by it of the Agreement and the performance by it of its obligations hereunder do not (i) conflict with its certificate of incorporation or bylaws, (ii) conflict with or result in any breach of any of the terms, covenants, conditions or provisions of, or constitute a default under, any indenture, mortgage, deed of trust, agreement or other material instrument to which it is a party or by which it or any of its material properties or assets is bound, or (iii) conflict with any applicable laws, or any order, writ, injunction or decree of any court or governmental authority binding on it or its material properties or assets, except in the case of clauses (ii) and (iii) any such conflict, breach or default which would not reasonably be expected to materially adversely affect its ability to perform its obligations under this Agreement;

(e) no governmental approvals or other consents or approvals are required in connection with the execution, delivery and performance by it of this Agreement, other than governmental approvals which the failure to obtain would not reasonably be expected to materially adversely affect its ability to perform under this Agreement;

(f) it is in compliance with all applicable laws except to the extent that the failure to comply therewith would not reasonably be expected to materially adversely affect its ability to perform its obligations under this Agreement; and

(g) no litigation, investigation or proceeding of or before any arbitrator or governmental authority is pending or, to the best of its knowledge, threatened against it or any of its properties, rights, revenues or assets which would reasonably be expected to materially adversely affect its ability to perform its obligations under this Agreement.

Section 6. Expenses . Each of MEHC and Equity Contributor hereby agrees to pay all of its respective costs, including reasonable attorneys' fees, incurred with respect to the enforcement of the provisions of this Agreement.

Section 7. Miscellaneous .

a) Notices . All notices to be given hereunder shall be in writing (including by telecopy), and shall be deemed to have been duly given or made when delivered by hand, or, in the case of telecopy notice, when confirmation is received, at the following addresses:

Berkshire:	Berkshire Hathaway Inc. 1440 Kiewit Plaza Omaha, Nebraska 68131
	Telephone: ( 402) 978-5423 Fax: (402) 346-3375 Attn: Chief Financial Officer

MEHC:	MidAmerican Energy Holdings Company 302 South 32 ^nd Street Omaha, Nebraska 68131
	Telephone: (402) 231-1642 Fax: (402) 231-1658 Attn: General Counsel

Each of Berkshire’s and MEHC’s address for notice hereunder may be changed at any time upon notice to the other party given in accordance with this clause (a).

b) Counterparts . This Agreement may be executed in separate counterparts, each of which when so executed and delivered shall be an original but all such counterparts shall constitute one and the same instrument.

c) Amendments, etc.; Termination . No termination of, or amendment or waiver of any provision of, this Agreement, or consent to any departure by Berkshire therefrom, shall be effective unless the same shall be in writing and signed by each of the parties hereto. Any such waiver or consent shall be effective only in the specific instance and for the specific purpose for which given. Notwithstanding the foregoing, (i) this Agreement will automatically terminate on the Termination Date; provided, however , that notwithstanding such termination, Equity Contributor shall have the obligation as set forth in Section 2 to make any Equity Contribution validly requested by MEHC pursuant to this Agreement prior to the Termination Date and (ii) the provisions of Sections 4, 6 and 7 shall survive such termination.

d) Successors and Assigns . This Agreement shall not be assignable by either Equity Contributor or MEHC without the prior written consent of the other party.

e) No Third Party Beneficiaries . Except as provided in clause (d) of this Section 7 , nothing herein contained shall confer any right upon any person other than the parties hereto.

f) Headings Descriptive . The headings of the several sections of this Agreement are inserted for convenience only and shall not in any way affect the meaning or construction of any provision of this Agreement.

g) Survival . All agreements, statements, representations and warranties made by the Equity Contributor herein or in any certificate or other instrument delivered by the Equity Contributor or on its behalf under this Agreement shall survive the execution and delivery of this Agreement until the satisfaction in full by the Equity Contributor of its obligations hereunder.

h) Consent to Jurisdiction . Any legal action or proceeding by or against the Equity Contributor with respect to or arising out of this Agreement may be brought in or removed to the courts of the State of Nebraska, or of the United States of America located in the State of Nebraska. By execution and delivery of this Agreement, each Equity Contributor accepts, for itself and in respect of its property, generally and unconditionally, the jurisdiction of the aforesaid courts for legal proceedings arising out of or in connection with this Agreement. The Equity Contributor hereby waives any right to stay or dismiss any action or proceeding under or in connection with this Agreement brought before the foregoing courts on the basis of forum non-conveniens or improper venue.

i) Waiver of Jury Trial . EACH OF THE EQUITY CONTRIBUTOR AND MEHC HEREBY KNOWINGLY, VOLUNTARILY AND INTENTIONALLY WAIVES ANY RIGHTS IT MAY HAVE TO A TRIAL BY JURY IN RESPECT OF ANY LITIGATION BASED HEREON, OR ARISING OUT OF, UNDER OR IN CONNECTION WITH, THIS AGREEMENT, OR ANY COURSE OF CONDUCT, COURSE OF DEALING, STATEMENTS (WHETHER VERBAL OR WRITTEN) OR ACTIONS OF THE OTHER PARTIES HERETO.

j) Reinstatement . This Agreement shall continue to be effective or be reinstated, as the case may be, if at any time any amount received by MEHC hereunder or pursuant hereto is rescinded and repaid to the Equity Contributor or is otherwise restored or returned to the Equity Contributor by MEHC upon the insolvency, bankruptcy, dissolution, liquidation or reorganization of the Equity Contributor, MEHC or any affiliate thereof or upon the appointment of any intervenor or conservator of, or trustee or similar official for, the Equity Contributor, MEHC or any affiliate thereof, or any substantial part of the Equity Contributor's, MEHC's or any such affiliate's assets, or upon the entry of an order by any court avoiding the payment of such amount, all as though such payments had not been made.

k) Entire Agreement . This Agreement constitutes the entire agreement and understanding of Berkshire and MEHC relating to the subject matter hereof and supersedes all prior agreements and understandings among Berkshire and MEHC, whether written or oral, relating to the subject matter hereof.

l) Severability . In case any provision of or obligation under this Agreement shall be invalid, illegal or unenforceable in any jurisdiction, the validity, legality and enforceability of the remaining provisions or obligations, or of such provision or obligation in any other jurisdiction, shall not in any way be affected or impaired thereby.

m) Governing Law . This Agreement shall be governed by and construed in accordance with the laws of the State of Nebraska without regard to the conflict of law rules thereof.

n) Limitation of Liability . Notwithstanding anything else in this Agreement or any other document, Berkshire’s liability in respect of this Agreement is limited to the Maximum Equity Amount. No shareholder, officer, employee, controlling person, executive, director, agent or affiliate of Berkshire shall be liable for any payments under this Agreement or any other obligations of Berkshire due to MEHC.

IN WITNESS WHEREOF, the parties hereto have caused their duly authorized officers to execute and deliver this Equity Commitment Agreement as of the date first above written.


	BERKSHIRE HATHAWAY INC.

	By:	/s/ Marc D. Hamburg
		Name: Marc D. Hamburg
		Title: Vice President


	MIDAMERICAN ENERGY HOLDINGS COMPANY

	By:	/s/ Douglas L. Anderson
		Name: Douglas L. Anderson
		Title: Senior Vice President

EXHIBIT A

FORM OF EQUITY REQUISITION CERTIFICATE

[DATE]

Berkshire Hathaway Inc.

1440 Kiewit Plaza

3555 Farnam Street

Omaha, NE 68131

Attention:

Ladies and Gentlemen:

This Equity Requisition Certificate is delivered to you pursuant to Section 2 of that certain Equity Commitment Agreement, dated as of ________________, 2006 (the " Equity Commitment Agreement "), by and among you and MEHC. This request has been authorized by the MEHC Board of Directors. Capitalized terms used herein but not otherwise defined herein shall have the meanings assigned to them in the Equity Commitment Agreement.

We hereby request that, in exchange for issuance of Equivalent Common Shares, you contribute an Equity Contribution to MEHC in the amount and on or prior to the date set forth below:

Amount of Equity Contribution: $_________________

Date of Equity Contribution: _____________________

Very truly yours,

MIDAMERICAN ENERGY HOLDINGS COMPANY

By:

_________________________

Name:

Title:

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
InterCoast Energy Company	Delaware
InterCoast Power Company	Delaware
IWG Co. 8	Delaware
MHC Investment Company	South Dakota
MWR Capital Inc.	South Dakota
TTP, Inc. of South Dakota	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
Integrated Utility Services Limited	England
Integrated Utility Services Limited	Republic of Ireland
Kings Road Developments Limited	England
Northern Electric plc	England
Northern Electric Distribution Limited	England
Northern Electric Finance plc	England
Northern Electric & Gas Limited	England
Northern Electric GenCo Limited	England
Northern Electric Generation (Peaking) Limited	England
Northern Electric Generation (TPL) Limited	England
Northern Electric Properties Limited	England
Northern Transport Finance Limited	England
Vehicle Lease and Service Limited	England
Yorkshire Cayman Holding Limited	Cayman Islands
Yorkshire Electricity Distribution plc	England
Yorkshire Electricity Distribution Services Limited	England
Yorkshire Electricity Group plc	England
Yorkshire Holdings plc	England
Yorkshire Power Finance Limited	Cayman Islands

Yorkshire Power Finance 2 Limited	Cayman Islands
Yorkshire Power Group Limited	England
YPG Holdings LLC	Delaware
HomeServices of America, Inc.	Delaware
Academy of Real Estate, Inc.	Alabama
Allerton Capital, LTD.	Iowa
Allied Title Services, LLC	Nebraska
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 Insurance Services, Inc.	Maryland
Chancellor Title Services, Inc.	Maryland
Columbia Title of Florida, Inc.	Florida
Community Diversified Investments, Inc.	Alabama
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
First Capital Group, LP	California
First Realty, Ltd.	Iowa
First Reserve Insurance, Inc.	Florida
FMLC Mortgage, LLC	Delaware
For Rent, Inc.	Arizona
HMSV Financial Services, Inc.	Delaware
HMSV-USB Lending, LLC	Delaware
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.	Delaware
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
IMO Co., Inc.	Missouri
Iowa Realty Co., Inc.	Iowa
Iowa Realty Insurance Agency, Inc.	Iowa
Iowa Title Company	Iowa
Iowa Title Linn County LLC	Iowa
Iowa Title Linn County II, LLC	Iowa

J.D. Reece Mortgage Company	Kansas
J.P. & A. Inc.	Georgia
Jenny Pruitt & Associates, Inc.	Georgia
Jenny Pruitt Insurance Services, LLC	Georgia
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
Lincoln Title Company, LLC	Nebraska
Long Title Agency, LLC	Arizona
Meridian Title Services, LLC	Georgia
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
Property I.D. Golden State, LLC	California
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
Roberts Holding Company, Incorporated	Alabama
Roy H. Long Realty Co., Inc.	Arizona
San Diego PCRE, Inc.	California
Semonin Realtors, Inc.	Delaware
Seward Title, LLC	Nebraska
Southwest Relocation, LLC	Arizona
The Escrow Firm, Inc.	California
The Referral Company	Iowa
TITLE INFO NOW, LLC	Minnesota
TitleSouth, LLC	Alabama
Trinity Mortgage Affiliates	Minnesota
Trinity Mortgage Partners, Inc.	Georgia
United Settlement Services, LC	Iowa
Woods Bros. Realty, Inc.	Nebraska
CE Generation, LLC	Delaware
Big Spring Pipeline Company	Texas
CalEnergy Operating Corporation	Delaware
California Energy Development Corporation	Delaware
California Energy Yuma Corporation	Utah
CE Salton Sea Inc.	Delaware

CE Texas Energy LLC

Delaware

CE Texas Fuel, LLC	Delaware
CE Texas Gas LP	Delaware
CE Texas Pipeline, LLC	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 LLC	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
American Pacific Finance Company	Delaware
BE Energy Holding LLC	Delaware
BE Energy LLC	Delaware
CalEnergy Capital Trust II	Delaware
CalEnergy Capital Trust III	Delaware
CalEnergy Company Inc.	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.	New York

CE Electric, Inc.	Delaware
CE Exploration Company	Delaware
CE Geothermal LLC	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 LLC	Delaware
CE Power, Inc.	Delaware
CE Resource LLC	Delaware
Cordova Energy Company, LLC	Delaware
Cordova Funding Corporation	Delaware
Intermountain Geothermal Company	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 Energy Machining Services, LLC	Delaware
NNGC Acquisition, LLC	Delaware
Northern Natural Gas Company	Delaware
PPW Holdings LLC	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 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 Form 10-K Annual Report for the fiscal year ending December 31, 2005 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 March 3, 2006

/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 officers 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)) for the registrant and we 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)	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

	c)	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 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 officers 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 registrant’s board of directors (or persons performing the equivalent function):

	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: March 3, 2006	/s/ David L. Sokol
	David L. Sokol
	Chairman and Chief 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 officers 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)) for the registrant and we 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)	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

	c)	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 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 officers 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 registrant’s board of directors (or persons performing the equivalent function):

	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: March 3, 2006	/s/ Patrick J. Goodman
	Patrick J. Goodman
	Senior Vice President and Chief 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, 2005 (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 result of operations of the Company.

Date: March 3, 2006	/s/ David L. Sokol
	David L. Sokol
	Chairman and Chief 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, 2005 (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 result of operations of the Company.

Date: March 3, 2006	/s/ Patrick J. Goodman
	Patrick J. Goodman
	Senior Vice President and Chief Financial Officer